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The EPA Administrator, Lisa P. Jackson, signed the following final rule on 11/15/2012, 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 FDsys 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, this version will be removed from the Internet and replaced with a link to 

the official version. 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 52 

[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: Final rule. 

SUMMARY: EPA is taking final action to approve in part and disapprove in part a portion of 

Arizona’s State Implementation Plan (SIP) submittal for its regional haze program and to 

promulgate a Federal Implementation Plan (FIP) for the disapproved elements of the SIP. The 

State and Federal plans are to implement the regional haze program in Arizona for the first 

planning period through 2018. This final rule 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. Consistent with our proposal, EPA approves in this final 

rule the State’s determination that the three sources are subject to BART, and approves the 
Page 2 of 244

State’s emissions limits for sulfur dioxide (SO2) and particulate matter less than or equal to 10 

micrometers (PM10) at all the units, but disapproves Arizona’s BART emissions limits for 

nitrogen oxides (NOX) at the coal-fired units of the three power plants. We also are promulgating 

a FIP that contains new emissions limits for NOX at these coal-fired units and compliance 

schedules for implementation of BART as well as requirements for equipment maintenance, 

monitoring, recordkeeping and reporting for all units and all pollutants at the three sources. In 

today’s action, we are revising some elements of the proposed FIP in response to comments and 

additional information that we received. 

DATES: Effective date: This rule is effective [insert date 30 days after date of publication in 

the federal register]. 

Compliance dates: The owners/operators of each unit subject to this final rule shall comply by 

the dates specified in the regulatory text. 

ADDRESSES: EPA has established docket number EPA–R09–OAR–2012–0021 for this action. 

Generally, documents in the docket are available electronically at http://www.regulations.gov or 

in hard copy at EPA Region 9, 75 Hawthorne Street, San Francisco, California. Please note that 

while many of the documents in the docket are listed at http://www.regulations.gov, some 

information may not be specifically listed in the index to the docket and may be publicly 

available only at the hard copy location (e.g., copyrighted material, large maps, multi-volume 

reports or otherwise voluminous materials), and some may not be available at either locations 

(e.g., confidential business information). To inspect the hard copy materials, please schedule an 

appointment during normal business hours with the contact listed directly below.
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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: 

Throughout this document, wherever “we,” “us,” or “our,” is used, we mean the United States 

Environmental Protection Agency (EPA). 

Definitions 

For the purpose of this document, we are giving meaning to certain words or initials 

as follows: 

(1) The words or initials CAA or Act mean or refer to the Clean Air Act, unless the 

context indicates otherwise. 

(2) The initials ACC refer to the Arizona Corporation Commission. 

(3) The initials ACCCE mean or refer to American Coalition for Clean Coal Electricity. 

(4) The initials ADEQ mean or refer to the Arizona Department of Environmental 

Quality. 

(5) The initials AEPCO mean or refer to Arizona Electric Power Cooperative. 

(6) The initials AFUDC mean or refer to allowance for funds used during construction. 

(7) The term Apache refers to Apache Generating Station. 

(8) The initials APS mean or refer to Arizona Public Service Company. 

(9) The words Arizona and State mean the State of Arizona. 

(10) The initials BART mean or refer to Best Available Retrofit Technology. 
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(11) The term BART units refers to Apache Generating Station Units 1, 2 and 3; Cholla 

Power Plant Units 2, 3 and 4 and Coronado Generating Station Units 1 and 2. 

(12) The initials CBI mean or refer to Confidential Business Information. 

(13) The initials CCM mean or refer to EPA’s Cost Control Manual. 

(14) The initials CEMS mean or refer to continuous emission monitoring system. 

(15) The term Cholla refers to Cholla Power Plant 

(16) The term Class I area refers to a mandatory Class I Federal area.

1

 

(17) The term coal-fired BART units refers to Apache Generating Station Units 2 and 3; 

Cholla Power Plant Units 2, 3 and 4 and Coronado Generating Station Units 1 and 2. 

(18) The initials COFA mean or refer to close-coupled overfire air. 

(19) The term Coronado refers to Coronado Generating Station. 

(20) The initials CY mean or refer to Calendar Year 

(21) The initials EGU mean or refer to Electric Generating Unit. 

(22) The initials ESPs mean or refer to electrostatic precipitators. 

(23) The words EPA, we, us or our mean or refer to the United States Environmental 

Protection Agency. 

(24) The initials FGD mean or refer to flue gas desulfurization. 

(25) The initials FGR mean or refer to flue gas recirculation. 

(26) The initials FIP mean or refer to Federal Implementation Plan. 

(27) The initials FLMs mean or refer to Federal Land Managers. 

(28) The initials FR mean or refer to the Federal Register. 

(29) The initials GEP mean or refer to Good Engineering Practice. 

 

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.” 
Page 5 of 244

(30) The initials IMPROVE mean or refer to Interagency Monitoring of Protected Visual 

Environments monitoring network. 

(31) The initials IWAQM mean or refer to Interagency Workgroup on Air Quality 

Modeling. 

(32) The initials IPM mean or refer to Integrated Planning Model. 

(33) The initials LNB mean or refer to low-NOX burners. 

(34) The initials LTS mean or refer to Long-Term Strategy. 

(35) The initials MMBtu mean or refer to Million British thermal units. 

(36) The initials MW mean or refer to megawatts. 

(37) The initials MWh mean or refer to megawatt hours.

(38) The initials NEI mean or refer to National Emission Inventory.

(39) The initials NH3 mean or refer to ammonia. 

(40) The initials NOX mean or refer to nitrogen oxides. 

(41) The initials NP mean or refer to National Park. 

(42) The initials NPRM mean or refer to Notice of Proposed Rulemaking. 

(43) The initials O&M mean or refer to operation and maintenance. 

(44) The initials OC mean or refer to organic carbon. 

(45) The initials OFA mean or refer to over fire air. 

(46) The initials PM mean or refer to particulate matter. 

(47) The initials PM10 mean or refer to particulate matter with an aerodynamic diameter of 

less than 10 micrometers (coarse particulate matter). 

(48) The initials PM2.5 mean or refer to fine particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers. 
Page 6 of 244

(49) The initials PNG mean or refer to pipeline natural gas. 

(50) The initials ppm mean or refer to parts per million. 

(51) The initials PSD mean or refer to Prevention of Significant Deterioration. 

(52) The initials RACT mean or refer to Reasonably Available Control Technology. 

(53) The initials RAVI mean or refer to Reasonably Attributable Visibility Impairment. 

(54) The initials RATA mean or refer to relative accuracy test audit. 

(55) The initials RHR mean or refer to the Regional Haze Rule, originally promulgated in 

1999 and codified at 40 CFR 51.301-309. 

(56) The initials RMB refer to RMB Consulting & Research, Inc. 

(57) The initials RMC mean or refer to Regional Modeling Center. 

(58) The initials RP mean or refer to Reasonable Progress. 

(59) The initials RPG or RPGs mean or refer to Reasonable Progress Goal(s). 

(60) The initials RPOs mean or refer to regional planning organizations. 

(61) The initials SCR mean or refer to Selective Catalytic Reduction 

(62) The initials SIP mean or refer to State Implementation Plan. 

(63) The initials SNCR mean or refer to Selective Non-catalytic Reduction. 

(64) The initials SO2 mean or refer to sulfur dioxide. 

(65) The initials SOFA mean or refer to separated over fire air. 

(66) The initials SRP mean or refer to Salt River Project Agricultural Improvement and 

Power District. 

(67) The initials TCI mean or refer to total capital investment. 

(68) The initials tpy mean tons per year. 

(69) The initials TSD mean or refer to Technical Support Document. 
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(70) The initials VOC mean or refer to volatile organic compounds. 

(71) The initials WA mean or refer to Wilderness Area. 

(72) The initials WEP mean or refer to Weighted Emissions Potential. 

(73) The initials WFGD mean or refer to wet flue gas desulfurization. 

(74) The initials WRAP mean or refer to the Western Regional Air Partnership. 

Table of Contents 

I. Background 

 A. Summary of Our Proposed Action 

 B. Legal Basis for Our Final Action 

II. Overview of Final Action 

III. Final BART Determinations 

IV. EPA’s Responses to Comments 

 A. General Comments on ADEQ’s Approach to BART 

 B. Comments on ADEQ’s Individual BART Analyses and Determinations 

 C. General Comments on EPA’s BART FIP Analyses and Determinations 

 D. Source-specific Comments on EPA’s BART Analyses and Determinations 

 E. Comments on Enforceability Requirements in EPA’s BART FIP 

 F. Comments on Legal Issues 

 G. Other Comments 

V. Summary of Final Action 

VI. Statutory and Executive Order Reviews 

I. Background 
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A. Summary of Our Proposed Action 

Our notice of proposed rulemaking (NPRM) was signed on July 2, 2012, and was 

published in the Federal Register on July 20, 2012.2In that notice, we proposed to approve in 

part and disapprove in part a portion of Arizona’s Regional Haze SIP (submitted on February 28, 

2011) and proposed a FIP to address the deficiencies in the disapproved portions of the SIP. The 

proposed rule addressed the BART requirements for eight units at three electric generating 

stations: 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 did 

not propose action on any other part of Arizona’s SIP related to the remaining requirements of 

the Regional Haze Rule (RHR). In summary, we proposed the following: 

Proposed Approval: We proposed to approve Arizona’s determination that the following 

sources and units are subject to BART: Apache Units 1, 2 and 3; Cholla Units 2, 3 and 4; and 

Coronado Units 1 and 2 (collectively “BART units”). We proposed to approve Arizona’s BART 

emissions limits for SO2 and PM10 at all three sources and units and the emissions limit for NOX

at Apache Unit 1. 

Proposed Disapproval: We proposed to disapprove Arizona’s BART emissions limits for 

NOX at all of the coal-fired BART units (i.e., all of the BART units except for Apache Unit 1). 

We also proposed to disapprove the compliance schedules and requirements for equipment 

maintenance and operation, including monitoring, recordkeeping and reporting requirements for 

BART at all of the BART units, since these were not included in the SIP submittal. 

Proposed FIP: The proposed FIP contained BART emissions limits for NOX at all of the 

coal-fired BART units, as well as compliance deadlines and requirements for equipment 

 

2

77 FR 42834. 
Page 9 of 244

maintenance and operation, including monitoring, recordkeeping and reporting, to ensure the 

enforceability of the BART limits for all of the BART units. Because our proposed FIP emission 

limits would likely result in changes in stack conditions from those anticipated in the SIP, we 

invited comment on whether an alternative test method to the one required in the SIP is 

acceptable for PM10. In addition, we specifically sought comment on whether we should require 

lower SO2 emissions limits or removal efficiency requirements for any of the coal-fired BART 

units. Finally, in the regulatory text in our NPRM, we proposed to incorporate by reference into 

the FIP two provisions of the Arizona Administrative Code, R18-2-310 and R18-2-310.01, 

which we characterized as establishing an affirmative defense for excess emissions due to 

malfunctions.3

 B. Legal Basis for Our Final Action 

Our action is based on an evaluation of Arizona’s Regional Haze SIP submitted on 

February 28, 2011, to meet the requirements of Section 308 of the RHR. We evaluated the SIP 

against the requirements of the RHR and Clean Air Act (CAA) sections 169A and 169B. We 

also applied the general SIP requirements in CAA section 110. Our authority for action on 

Arizona’s Regional Haze SIP is based on CAA section 110(k). Our authority to promulgate a FIP 

is based on CAA section 110(c). 

II. Overview of Final Action 

EPA is taking final action to approve in part and disapprove in part a portion of Arizona’s 

SIP for Regional Haze, and to promulgate a FIP for the disapproved elements of the SIP. This 

final rule only addresses the BART requirements for the eight BART units identified above. 

 

3 Those provisions also include an affirmative defense for excess emissions due to startups and shutdowns, which 

we did not intend to incorporate. 
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Most notably, and with the exception of Apache Unit 1, the FIP includes NOX emission limits for 

all the units that are achievable with SCR. At this time, EPA is not taking action on the State’s 

other BART determinations or any other parts of the SIP regarding the remaining requirements 

of the RHR. 

EPA takes very seriously a decision to disapprove any state plan. To approve a state plan, 

EPA must be able to find that the state plan is consistent with the requirements of the CAA and 

EPA’s regulations. Further, EPA’s oversight role requires us to ensure fair implementation of 

CAA 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, for the reasons described in our proposal and in this document, we find that the State’s 

NOX BART determinations for the coal-fired units are not consistent with the applicable 

statutory and regulatory requirements. Furthermore, the Arizona Regional Haze SIP does not 

include the necessary compliance schedules and requirements for equipment maintenance and 

operation, including monitoring, recordkeeping and reporting requirements for BART. As a 

result, EPA believes this final disapproval is the only path that is consistent with the Act at this 

time. 

We encourage the State to submit a revised SIP to replace all portions of our FIP, and are 

ready to work with the State to develop a revised plan. The 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. 
Page 11 of 244

III. Final BART Determinations 

This section is a summary of EPA’s final action on the BART determinations for the 

BART units at Apache, Cholla and Coronado electric generating stations. Please refer to Table 1 

that compares this final rule to the proposal that was published on July 20, 2012. Where EPA has 

modified our proposal to respond to comments or additional information, we explain our analysis 

in the next section titled “EPA’s Responses to Comments.” We have fully considered all 

comments on our proposal, and have concluded that some changes are warranted based on public 

comments and additional information we received in response to questions raised in the proposal. 

Final Approval: EPA is approving Arizona’s determination that the following sources 

and units are subject to BART: Apache Units 1, 2 and 3; Cholla Units 2, 3 and 4; and Coronado 

Units 1 and 2 (collectively “BART units”). We are approving the emissions limits for NOX, 

PM10 and SO2 at Apache Unit 1 as proposed. We are approving the State’s emissions limits for 

PM10 and SO2 for all the units. 

Final Disapproval: Based on our evaluation described in the proposal and in this 

document, we are disapproving the State’s BART emissions limits for NOX at all the BART 

units except for Apache Unit 1, for which the SIP’s BART determination consists of fuel 

switching to pipeline natural gas (PNG). We also are disapproving the compliance schedules and 

requirements for equipment maintenance and operation, including monitoring, recordkeeping 

and reporting requirements for BART at all the BART units since these were not included in the 

Arizona Regional Haze SIP.4

 

4

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)). 
Page 12 of 244

Final Federal Implementation Plan: We are promulgating a FIP that includes emissions 

limitations representing BART for NOX at all the coal-fired BART units. The FIP also includes 

compliance schedules and requirements for equipment maintenance, monitoring, testing, 

recordkeeping and reporting for all the BART units. For PM10 at all units, we allow the use of 

Method 5 as an alternative to Method 201A/202. In addition, the FIP includes a removal 

efficiency requirement for SO2 on Cholla Units 2, 3 and 4, which will ensure that the scrubbers 

on these units are properly operated and maintained. Finally, we are incorporating into the FIP an 

affirmative defense provision for excess emissions due to malfunctions.5 

We have revised certain elements of our proposed FIP based on public comments and 

additional information as follows: 

• Apache Units 2 and 3: The final emissions limit for NOX is 0.070 pounds per million 

British thermal units (lb/MMBtu) determined as an average of the two units, based on a 

rolling 30-boiler-operating-day average. Compared to the proposed emissions limit of 

0.050 lb/MMBtu on each unit, this higher limit and the addition of a two-unit average 

provides an extra margin of compliance to account for periods of startup and shutdown as 

well as additional operational flexibility for Apache given AEPCO’s status as a small 

entity. When either one of the two units is not operating, its emissions from its own 

preceding thirty boiler-operating-days will continue to be included in the two-unit 

average. The final compliance date for this NOX limit remains five years from the date of 

 

5

 In the regulatory text in our NPRM, we proposed to incorporate by reference into the FIP two provisions of the 

Arizona Administrative Code, R18-2-310 and R18-2-310.01, which we characterized as establishing an affirmative 

defense for excess emissions due to malfunctions. However, those provisions also include an affirmative defense for 

excess emissions due to startups and shutdowns, which we did not intend to incorporate. As explained below, the 

emission limits that we are promulgating today include an adequate margin of compliance to account for periods of 

startup and shutdown. Accordingly, as indicated by the title of this provision in our proposed regulatory text 

(“Affirmative Defense for Malfunctions”), we are only incorporating into the FIP the malfunction-related provisions 

of these rules and not the startup and shutdown provisions. Our final regulatory text clarifies this distinction and also 

incorporates the definition of malfunction. 
Page 13 of 244

publication of this final rule. For SO2 and PM10 we are extending the compliance deadline 

to four years from publication of this final rule in order to provide AEPCO with sufficient 

time to implement upgrades to the existing scrubbers and electrostatic precipitators 

(ESPs) at these units. 

• Cholla Units 2, 3 and 4: The final emissions limit for NOX is 0.055 lb/MMBtu 

determined as an average of the three units, based on a rolling 30-boiler-operating-day 

average. Compared to the proposed emissions limit of 0.050 lb/MMBtu on each unit, the 

higher limit and three-unit average provide an extra margin of compliance to account for 

periods of startup and shutdown. When any of the three units is not operating, its 

emissions from its own preceding thirty boiler-operating-days will continue to be 

included in the three-unit average. As proposed, the final compliance date to install and 

operate controls is five years from the date of publication of this final rule. For SO2, we 

are adding a removal efficiency requirement of 95 percent for the scrubbers on Cholla 

Units 2, 3 and 4, in order to ensure that these scrubbers are properly operated and 

maintained, consistent with 40 CFR 51.308(e)(1)(v). We are retaining the other 

compliance deadlines as proposed, except for Cholla Unit 2, where we are extending the 

compliance deadline to April 1, 2016, for both SO2 and PM10 in order to provide APS 

with sufficient time to install a new wet flue gas desulfurization (FGD) system and fabric 

filter on this unit. 

• Coronado Units 1 and 2: The final emissions limit for NOX is 0.065 lb/MMBtu 

determined as an average of the two units, based on a rolling 30-boiler-operating-day 

average. Compared to the proposed emissions limits of 0.050 on Unit 1 and 0.080 on Unit 

2, this new limit based on a two-unit average provides an extra margin of compliance to 
Page 14 of 244

account for startup and shutdown. When either one of the two units is not operating, its 

emissions from its own preceding thirty boiler-operating-days will continue to be 

included in the two-unit average. The final compliance date for the two units is five years 

from the date of publication of this final rule. 

TABLE 1—SUMMARY OF CHANGES FROM PROPOSAL TO FINAL RULE: 

EMISSIONS LIMITS (LB/MMBTU) AND COMPLIANCE DATES IN SIP AND FIP 

Source 

NOX PM10 SO2

Proposal Final Proposal Final Proposal Final 

Apache 

Unit 1 

0.056 

Five years 

0.056 

Five years 

0.0075 

180 days 

0.0075 

180 days 

0.00064 

180 days 

0.00064 

180 days 

Apache 

Unit 2 

0.050 

Five years 

0.070 

(across two 

units) 

Five years

0.03 

180 days 

0.03 

Four years

0.15 

180 days 

0.15 

Four years 

Apache 

Unit 3 

0.050 

Five years 

0.03 

180 days 

0.03 

Four years 

0.15 

180 days 

0.15 

Four years 

Cholla 

Unit 2 

0.050 

Five years 

0.055 

(across three 

units) 

Five years 

0.015 

Jan 1, 2015 

0.015 

Apr 1, 2016

0.15 

180 days 

Add 95 

percent 

efficiency 

Apr 1, 2016

Cholla 

Unit 3 

0.050 

Five years 

0.015 

180 days 

0.015 

180 days 

0.15 

180 days 

Add 95 

percent 

efficiency 

1 year 

Cholla 

Unit 4 

0.050 

Five years 

0.015 

180 days 

0.015 

180 days 

0.15 

180 days 

Add 95 

percent 

efficiency 

1 year 

Coronado 

Unit 1 

0.050 

Five years 

0.065 

(across two 

units) 

Five years 

0.03 

180 days 

0.03 

180 days 

0.08 

180 days 

0.08 

180 days 

Coronado 

Unit 2 

0.080 

June 1, 2014

0.03 

180 days 

0.03 

180 days 

0.08 

180 days 

0.08 

180 days 

IV. EPA’s Responses to Comments 
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We are responding to comments on our proposed rule published on July 20, 2012.6 We 

held an initial public hearing in Phoenix, Arizona, on July 31, 2012. In response to concerns that 

more time was needed to analyze the proposal and develop comments, we added two additional 

public hearings in Holbrook and in Benson, Arizona, on August 14 and 15, respectively, and 

extended the public comment deadline to September 18, 2012.7 The three public hearings were 

attended by hundreds of citizens, local and state government officials, workers and officials from 

the power plants, and representatives from environmental organizations. Testimony and 

comments from the three public hearings are organized in the docket by location and available 

for viewing at www.epa.gov/region9/air/actions/arizona.html and http://www.regulations.gov

We also received a number of written comments, including extensive comments from 

stakeholders and government agencies who offered policy and technical analyses addressing the 

details of our proposed rule. These stakeholders included AEPCO, APS, SRP, PacifiCorp, 

Arizona Utilities Group (AUG), National Park Service (NPS), Arizona Department of 

Environmental Quality (ADEQ), and a consortium of conservation organizations (National Parks 

Conservation Association, Sierra Club, Physicians for Social Responsibility-Arizona Chapter, 

Dine’ Citizens Against Ruining Our Environment, Grand Canyon Trust, and San Juan Citizens 

Alliance) represented by Earthjustice. All of the comments we received along with attached 

technical reports and analyses are available for review in the docket. 

 A. General Comments on ADEQ’s Approach to BART 

 1. ADEQ’s Identification of BART Sources 

Comment: One commenter (Earthjustice) stated that EPA must provide further factual 

support for its determination that Cholla Unit 1 is not BART-eligible. The commenter indicated 

 

6

77 FR 42834. 

7

77 FR 45326 (July 31, 2012). 
Page 16 of 244

that the record lacks the requisite support for this conclusion. Recounting the history of ADEQ’s 

finding that Unit 1 is not BART-eligible, the commenter noted that APS claimed, and ADEQ 

concurred, that Unit 1 is not BART-eligible based on a 50-year-old document entitled “Operating 

Notes For May 1962” which allegedly shows that Unit 1 began operations on May 1, 1962, and 

was thus placed into operation just months before the August 7, 1962, BART-eligibility cut-off. 

The commenter added that EPA apparently approved, without any scrutiny, ADEQ’s 

determination that Cholla Unit 1 is not BART-eligible.

The commenter (Earthjustice) requested that EPA properly analyze the BART-eligibility 

of Cholla Unit 1. Specifically, the commenter requested that EPA identify which “aspects of the 

process by which ADEQ identified its eligible-for-BART and subject-to-BART sources” it 

disagrees with, the basis of each disagreement, and whether any such disagreement implicates 

Cholla Unit 1. In addition, the commenter stated that EPA’s independent analysis of this issue 

must be supported by the following information, which is needed to verify the actual date that 

Cholla Unit 1 began operating: 

• The document entitled “Operating Notes for May 1962” referenced in ADEQ’s SIP; 

• All available 1962 operating records for Cholla Unit 1; 

• All initial CAA construction and operating permits issued to Cholla Unit 1; 

• All emissions data from the year 1962 for Cholla Unit 1;

• Notes of the meeting between ADEQ and APS in August 2007 or any other time ADEQ 

and APS discussed the BART-eligibility of Cholla Unit 1; and 

• Any other documentation that either supports or contradicts whether Cholla Unit 1 was 

placed into commercial operation before August 7, 1962. 
Page 17 of 244

Response: We did not specifically propose to take action on ADEQ’s determination that 

Cholla Unit 1 is not BART-eligible and our statement that “we do not agree with all aspects of 

the process by which ADEQ identified its eligible-for-BART and subject-to-BART sources” was 

not intended to apply to this unit. Nonetheless, we agree with the commenter that it is appropriate 

to give some consideration to this issue in the context of today’s rulemaking action, which covers 

ADEQ’s BART determinations for the other three units at Cholla. 

Contrary to the commenter’s assertion, the WRAP did not find Cholla Unit 1 subject to 

BART. The WRAP document cited by the commenter merely indicates that ADEQ notified APS 

on July 13, 2007 that Cholla Units 1-4 were “Potentially Subject to BART.”8 The WRAP’s 

“Arizona BART Eligibility TSD” further explains that: 

[Cholla] Unit 1 is listed as potentially date eligible as information shows that the 

emissions unit was in service only 2 months prior to the cut-off date. Recommend 

requesting additional supporting documentation for final determination.9 

ADEQ received this additional documentation from APS in August 2007 in the form of a 

document dated May 23, 1962, and entitled “Operating Notes For May 1962.”10 This document 

indicates that, “[o]n Tuesday, May 1, 1962, unit [#1 was] placed into commercial operation.”11

After reviewing this documentation, ADEQ concurred that Unit 1 was not BART eligible.

12

Following the close of the public comment period, we requested and received from APS 

a copy of the “Operating Notes For May 1962” along with additional information concerning the 

operation of Cholla Unit 1.13 We have placed these materials in the docket and, based on our 

initial review, we believe this documentation is sufficient to confirm ADEQ’s determination that 

 

8

 Exhibit 17 to Earthjustice Comments, WRAP BART Clearinghouse (Oct. 24, 2008). 

9

“Supporting Documentation on Emissions Unit Bart Eligibility Analysis”, section 5.1.2. 

10 Arizona Regional Haze SIP at page 155. 

11 Id. 

12 Id. 

13 Email from Sue Kidd, APS, to Colleen McKaughan, EPA (October 10, 2012, 9:17 AM) and attachments. 
Page 18 of 244

this unit is not BART-eligible. However, because this question was not addressed in our 

proposed rulemaking, we are not taking final action on it at this time. We intend to address 

Cholla Unit 1’s BART eligibility when we take action on the remainder of the Arizona Regional 

Haze SIP. 

 2. ADEQ’s BART Control Analyses 

Comment: One commenter (PacifiCorp) states that EPA improperly focuses on only two 

factors, costs and visibility improvement, in rejecting the ADEQ’s entire NOX BART 

determination. The commenter states that EPA inappropriately places more weight on these 

factors. 

Response: EPA disagrees with the comment that we inappropriately focused on costs and 

visibility improvement in our decision to disapprove ADEQ’s NOX BART determinations. As 

outlined in our proposal, we considered ADEQ’s evaluation of the energy and non-air quality 

environmental impacts of compliance of the control technologies, any existing pollution control 

technology in use at each of the sources, and the remaining useful life of each source, to be 

generally reasonable and consistent with the RHR and the BART Guidelines.

14 However, we 

also found that the costs of control were not calculated in accordance with the BART Guidelines, 

and that the visibility impacts were not appropriately evaluated and considered. These findings 

formed part of the basis for our disapproval of ADEQ’s NOX BART determinations.

Comment: Several commenters objected to EPA’s use of non-specific and undefined 

parameter levels for both the “cost-effectiveness” and “sufficient visibility improvement” 

parameters in rejecting ADEQ’s SIP. One commenter (Pacificorp) further noted that states 

cannot meet EPA’s specific targets unless and until those targets are clearly defined.

 

14 See 77 FR 42841. 
Page 19 of 244

Response: The RHR and the BART Guidelines do not require the development of 

specific thresholds, but rather require evaluation of each BART determination on a case-by-case 

basis for each source.15 We have not established a specific cost threshold that makes a particular 

control option BART based on just a dollars per ton number, and there is not a specific target, 

either in terms of cost-effectiveness or visibility improvement, for ADEQ to meet. All five 

factors must be evaluated and weighed to determine the level of control that is BART on a caseby-case basis. 

 a. ADEQ’s Approach to Costs of Compliance 

Comment: One commenter (NPS) agreed with EPA’s conclusions that the costs of control 

were not calculated by ADEQ in accordance with the BART Guidelines and that costs were 

included for items not allowed by EPA Control Cost Manual (CCM or the Manual) (e.g., 

owner’s costs, surcharge, escalation, and Allowance for Funds Utilized During Construction—

AFUDC), which inflates the total cost of compliance and the cost per ton of pollutant reduced. 

According to the commenter, a review of industry data (detailed in Appendix A of the 

commenter’s submission) indicates that the total capital investment (TCI) for SCR retrofits is 

typically about $200/kW, while the TCI estimates for Apache and Cholla equaled or exceeded 

$250/kW. 

The commenter (NPS) noted that the BART Guidelines recommend use of the Manual if 

vendor data are not available. The commenter conducted detailed cost analyses of SCR using an 

approach that the commenter believes is similar to that used by EPA in its evaluation of SCR on 

the Colstrip power plant – using the cost methodologies of the Manual and relying on EPA’s 

Integrated Planning Model (IPM) to reflect the most recent cost levels. The commenter observed 

 

15 See, e.g., BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.5 (“a 0.3 deciview improvement may 

merit a stronger weighting in one case versus another, so one “bright line” may not be appropriate.”) 
Page 20 of 244

that most of the ADEQ SCR cost estimates were based on TCI costs that were relatively high 

ratios of the reported direct capital costs (DCC). The commenter indicated that according to the 

Manual, the ratio of TCI to DCC is 141 percent, while ADEQ’s estimates were as follows: 

• At Apache, TCI is 179 percent of DCC for both units and included $6 million in costs for 

each unit not typically allowed by EPA. 

• At Cholla, TCI is 258 percent of DCC for all three units and included $11 million in costs 

for Units 2 and 3 (each) and $15 million for Unit 4 that are not typically allowed by EPA. 

• At Coronado, data were not sufficient to calculate these values. 

The commenter asserted that this supports EPA’s concern that control costs submitted by the 

utilities either included costs not typically allowed by EPA or were inadequately documented. 

Response: We appreciate the information provided by the National Park Service and are 

in agreement that ADEQ’s cost estimates of SCR are overestimated. As indicated in our 

proposal, our cost estimates for SCR generally produced lower values than those in the Arizona 

Regional Haze SIP, and at a level that we consider cost-effective. Although we recognize that 

NPS’s estimates produce even lower values than those from our proposal, we have not updated 

our own cost estimates to reflect NPS’s comments since we already consider SCR to be costeffective. We do note that in order to address the comments from the utilities, we have performed 

supplemental cost analyses for each facility based on the costs provided by the utilities, and in 

doing so have accounted for those costs not allowed by CCM methodology. 

Comment: Two commenters (ADEQ and AUG) stated that EPA did not and cannot show 

that ADEQ failed to consider relevant cost information in making its BART determination, the 

State fully complied with its CAA obligations, and EPA’s rationale is insufficient to reject 

ADEQ’s cost determinations. AUG asserted that: 
Page 21 of 244

Arizona has expressly stated that it has considered each of the BART factors. 

EPA plainly cannot -- and does not -- demonstrate that Arizona failed to take the 

costs of compliance with BART emission limits into consideration. The state is 

required to do no more than that, and EPA cannot lawfully disapprove the state’s 

determinations on the basis that the Agency would prefer a different form of, or 

format for, explanation of those determinations. 

The commenters further stated that the other reason EPA rejected ADEQ’s cost determinations is 

that EPA believed that ADEQ relied on inadequately documented costs. The commenters 

contended that there is nothing in the CAA or BART rules that requires a state to present any 

particular level of cost documentation or that limits a state’s discretion in its consideration of the 

cost factor in making a BART determination. 

Response: We disagree with this comment. First, while Arizona may have “expressly 

stated” that it considered each of the BART factors, it must do more than “state” that it 

considered a BART factor, but must also provide some type of analysis demonstrating that it 

considered the BART factors.16 Although ADEQ has presented information relevant to each of 

the BART factors, it has not provided an explanation regarding how this information was used to 

develop its BART determinations. Specifically in the case of cost calculations, the Arizona 

Regional Haze SIP includes relevant information for multiple NOX control options, but does not 

provide evidence that this information has been analyzed in any way. In the case of Apache and 

Coronado, the Arizona Regional Haze SIP does not analyze this cost information in even a 

qualitative manner. In the case of Cholla, the terms “least expensive” and “most expensive” are 

used, but only in the context of providing a reference for visibility impacts, and not in the context 

of an evaluation of costs. This does not constitute “consideration,” as it involves little more than 

 

16 See, e.g., BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.2. (“You should provide a justification 

for adopting the technology that you select as the ‘best’ level of control, including an explanation of the CAA 

factors that led you to choose that option over other control levels.”) 
Page 22 of 244

ensuring the presence of cost values, with no judgment, analysis, or interpretation of their 

meaning. 

Second, we disagree with the commenter’s characterization of our disapproval as based 

on a “preference” for a different format or form of explanation for ADEQ’s BART 

determinations. As discussed in the previous paragraph, ADEQ has not discussed its BART 

determination rationale, particularly with regard to costs of compliance, in any format. While 

ADEQ’s RH SIP does include cost information, it provides no explanation regarding how, or 

even if, this cost information was used in arriving at its NOX BART determinations. Although 

we agree that the RHR does provide states significant discretion in their consideration of the 

BART factors, AUG’s comment presupposes that these costs were considered. The Arizona 

Regional Haze SIP does not indicate that they were considered. 

Comment: ADEQ noted that the same principles were used for the PM10 and SO2 BART 

evaluations as were used for the NOX BART evaluation, yet EPA accepted the approach for only 

PM10 and SO2. 

Response: We disagree that we accepted ADEQ’s approach for PM10 and SO2. Although 

we did not disapprove ADEQ’s PM10 and SO2 BART determinations, the absence of a 

disapproval of these determinations should not be construed to represent acceptance of the 

approach by which they were developed. We acknowledge that ADEQ took a similar approach 

in its analyses for PM10 and SO2 as for NOX, and that these analyses exhibit the same 

deficiencies we have noted elsewhere for the NOX BART determinations. However, we did not 

disapprove the PM10 and SO2 determinations because we find that the shortcomings in these 

analyses did not result in unreasonable BART determinations and therefore were generally 

“harmless errors.” 
Page 23 of 244

With regard to PM10, we note that ADEQ determined the most stringent control 

technology (fabric filters) was BART for each of the Cholla units. For Apache and Coronado, 

ADEQ determined that the current control technology (hot-side ESPs) was BART and eliminated 

the most stringent control technology (fabric filters). We note that PM emissions from EGUs 

typically contribute only a small percentage of the modeled visibility impact from EGUs, and 

that controlling their emissions results in very small visibility benefit. For example, CALPUFF 

visibility modeling performed by WRAP indicates that for Apache, the maximum baseline PM10

visibility impact at the most affected Class I area (Chiricahua NM) is 0.04 dv.17 Assuming that a 

more stringent control technology could achieve 100 percent PM control and eliminate this entire 

visibility impact, a more stringent PM10 BART determination would therefore achieve, at most, a 

visibility benefit of 0.04 dv. Although ADEQ did not document its analysis or weighing of the 

five factors in arriving at the PM10 BART determinations for Apache or Coronado, additional 

analysis would not have the potential to result in selection of a more stringent control technology 

in light of the small potential for visibility benefit. 

With regard to SO2, ADEQ selected the most stringent control technology (wet FGD) for 

all units at Apache, Cholla, and Coronado. Although ADEQ did not “take into account the most 

stringent emission control level that the technology is capable of achieving,” correcting for this 

flaw would not have the potential to result in the selection of a more stringent control 

technology, since wet FGD, which is the most stringent control technology, was already selected 

as BART. Further discussion of our evaluation of ADEQ’s BART analyses for PM10 and SO2 is 

provided below. 

Comment: The commenters stated that one of EPA’s reasons for rejecting ADEQ’s cost 

determinations is because the costs are inconsistent with the CCM. The commenters noted that 

 

17 See Docket Item No. B-12, “Summary of WRAP RMC BART Modeling for Arizona.” 
Page 24 of 244

use of the outdated Manual is not required by the CAA or the BART rules and provide 

references in which EPA has stated that the Manual is only one tool that can be used but that 

other cost data should also be considered.

Response: We partially agree with this comment. We acknowledge that our BART 

guidelines state, “In order to maintain and improve consistency, cost estimates should be based 

on the [CCM], where possible” and that “[w]e believe that the [CCM] provides a good reference 

tool for cost calculations, but if there are elements or sources that are not addressed by the 

Control Cost Manual or there are additional cost methods that could be used, we believe that 

these could serve as useful supplemental information.”18 The Manual contains two types of 

information: (1) study level cost estimates of capital and operation and maintenance (O&M) 

costs for certain specific types of pollution control equipment, such as SCR, and (2) a broader 

costing methodology, known as the overnight method. We agree that the language of the BART 

Guidelines does not require strict adherence to the study level equations and cost methods used 

to estimate capital and O&M costs.

We consider the use of the broader costing methodology used by the CCM, the overnight 

method, as crucial to our ability to assess the reasonableness of the costs of compliance.

Evaluation of the cost of compliance factor requires an evaluation of the cost-effectiveness 

associated with the various control options considered for the facility. A proper evaluation of 

cost-effectiveness allows for a reasoned comparison not only of different control options for a 

given facility, but also of the relative costs of controls for similar facilities. If the costeffectiveness of a control technology for a particular facility is outside the range for other similar 

 

18 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.a 
Page 25 of 244

facilities, the control technology may be rejected as not cost-effective.19 In order for this type of 

comparison to be meaningful, the cost estimates for these facilities must be performed in a 

consistent manner. Without an ‘apples-to-apples’ comparison of costs, it is impossible to draw 

rational conclusions about the reasonableness of the costs of compliance for particular control 

options. Use of the CCM methodology is intended to allow a fair comparison of pollution control 

costs between similar applications for regulatory purposes. This is why the BART guidelines 

specify the use of the CCM where possible20 and why it is reasonable for us to insist that the 

CCM methodology be observed in the cost estimate process. However, we note that the 

overnight method has been used for decades for regulatory control technology cost analyses, and 

that its use ensures equitable BART determinations across states and across sources.

Comment: One commenter (SRP) stated that ADEQ appropriately considered the 

“dollars-per-deciview” cost‐effectiveness of different control options, which is reasonable and 

entirely within the broad discretion afforded to the states under the CAA. SRP stated that 

because BART is a component of the CAA’s visibility program, it is more crucial to evaluate 

control costs in relation to the visibility improvements that may be expected using a dollars per 

deciview ($/dv) metric. 

Response: The BART Guidelines require that cost-effectiveness be calculated in terms of 

annualized dollars per ton of pollutant removed, or $/ton, but also list the $/deciview ratio as an 

additional cost-effectiveness measure that can be employed along with $/ton for use in a BART 

evaluation.

21 However, the $/dv metric is only useful to the extent that it reflects appropriately 

calculated costs and visibility benefits. As explained elsewhere in this document, we have 

 

19 See Id. section IV.D.4.f (“A reasonable range [of cost-effectiveness values] would be a range that is consistent 

with the range of cost-effectiveness values used in other similar permit decisions over a period of time.”) 

20 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4. 

21 BART Guidelines sections IV.D.4.c and IV.E. 
Page 26 of 244

determined that ADEQ did not evaluate costs and visibility benefits in a manner consistent with 

the RHR and the BART Guidelines. Therefore, while ADEQ certainly had the discretion to take 

$/dv into consideration as part of its BART analyses, the values that it relied upon in doing so 

were not reasonable. 

 b. ADEQ’s Approach to Energy and Non-air Quality Environmental Impacts 

Comment: One commenter (SRP) stated that EPA inappropriately downplayed the energy 

and non-air quality factor in its review of ADEQ’s BART analysis. Another commenter (ADEQ) 

noted that because fly ash ammonia residues have the potential to contaminate ground and 

surface waters, ADEQ included potential environmental impacts and the economics of disposing 

the fly ash in its BART analysis. 

Response: We do not agree that we inappropriately downplayed the energy and non-air 

quality environmental impacts factor in our review of ADEQ’s BART analyses. ADEQ provided 

only brief consideration of this factor in its BART analyses and did not explain how it weighed 

this factor against the other statutory factors. Because ADEQ’s analysis of this factor was limited 

in scope, our evaluation of this factor in reviewing the SIP was similarly limited. We discuss our 

analysis of this factor in our FIP action below. 

 c. ADEQ’s Approach to Degree of Visibility Improvement 

Comment: Several commenters (American Coalition for Clean Coal Electricity 

(ACCCE), AEPCO, APS, AUG, Navajo Nation, PacifiCorp, SRP) asserted that EPA improperly 

dismissed ADEQ’s visibility impacts analyses. The commenters cited the BART Guidelines (70 

FR 39170) to assert that there is no prescribed method for states to consider and weigh visibility 

impacts and, thus, EPA has no legal grounds for disapproving a SIP based on the method the 

State has chosen to consider visibility impacts or improvements. The commenters added that 
Page 27 of 244

whatever EPA’s preference, it has no discretion to substitute its method or its conclusion for 

those of the State. According to the commenters, it is clear that the BART rules envision – or, at 

a minimum, allow – a visibility improvement analysis that is focused on visibility impacts in the 

most impacted area. 

Regarding ADEQ’s BART determination at Coronado in particular, one commenter 

(SRP) noted that ADEQ evaluated a visibility index derived from an average of modeled 

visibility improvements at the nine Class I areas closest to Coronado. The commenter asserted 

that this approach was well within the State’s discretion to assess visibility under the BART 

rules. Another commenter (AUG) argued this consideration of an average visibility impacts 

index is an even more thorough type of evaluation than that required by the BART rules.

One commenter (AEPCO) added that EPA’s proposal to disapprove ADEQ’s NOX

BART determinations was largely based on its concern with ADEQ’s reliance on the Western 

Regional Air Partnership (WRAP) modeling. 

By contrast, another commenter asserted that since the facilities’ modeling results 

indicated that controls would contribute to visibility improvements in multiple Class I areas, 

ADEQ should consider these benefits rather than looking at the benefits in only a single Class I 

area. The commenter believes that overlooking significant visibility benefits in this way 

considerably understates the overall benefit of controls to improved visibility. The commenter 

contended that the procedure followed by ADEQ is not a sufficient basis for making BART 

determinations for sources with substantial benefits across many Class I areas. 

Response: EPA’s proposed disapproval of ADEQ’s NOx BART determinations was not 

based on any concern with the WRAP modeling protocol, upon which ADEQ relied for its 

BART analyses. On the contrary, we found that the modeling procedures relied upon by ADEQ 
Page 28 of 244

were “in accord with EPA guidance.” 22 However, we noted that ADEQ's use of the results of 

modeling in making BART decisions was “problematic in several respects.”23 In other words, our 

concern with the visibility analysis was not with the technical adequacy of the modeling itself, 

but rather with how ADEQ interpreted the results of this modeling.

In its BART analyses for Apache and Cholla, ADEQ considered visibility improvements 

only at the single Class I area with the greatest modeled impact from a facility. This neglects 

improvements that would occur at other nearby Class I areas, and in general is not adequate for 

assessing the overall visibility benefit from candidate BART controls. As noted by commenters, 

the BART Guidelines provide that, “[i]f the highest modeled impacts are observed at the nearest 

Class I area, [a State] may choose not to analyze the other Class I areas any further and 

additional analyses might be unwarranted.”24 Commenters argued that this language shows that 

Arizona’s exclusive focus on improvements at a single Class I area is allowed under the BART 

Guidelines. However, this language is not intended as an invitation for states to ignore significant 

visibility improvements at multiple Class I areas. Rather, it is intended to provide a way of 

streamlining a complex and difficult modeling exercise where “an analysis may add a significant 

resource burden to a State.”25 For example, when the visibility benefits at the most impacted 

Class I area alone are sufficient to justify the selection of the most stringent control technology 

as BART, then analysis of additional areas would be unnecessary and the state could conserve 

resources by not modeling the impacts on those additional areas. Here, by contrast, ADEQ did 

not perform its own modeling at all, but instead relied on modeling performed by contractors for 

the facilities. This modeling indicated that that the installation of more stringent controls (i.e., 

 

22 77 FR 42841. 

23 Id. 

24 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.5. 

25 See 70 FR 39126 
Page 29 of 244

SNCR or SCR) would result in visibility benefits at multiple Class I areas, yet ADEQ chose to 

consider the benefits only at the most impacted area. Where, as here, the benefits of controls 

have been modeled for a number of surrounding areas and consideration of these benefits is 

useful in determining the appropriate level of controls, EPA does not agree that these benefits 

may be ignored.26

While there may be no single prescribed method to consider and weigh visibility impacts, 

the BART Guidelines do require that certain visibility impacts be included in the considering and 

weighing. EPA disagrees that state flexibility extends to categorically excluding consideration of 

visibility improvements occurring at multiple Class I areas. Considering benefits at multiple 

areas does not necessarily require use of the “cumulative” improvement approach (i.e., the direct 

sum of improvements at all the areas), but does require that improvements at those areas be taken 

into account in some way. For example, one could simply list visibility improvements at the 

various areas, and qualitatively weigh the number of areas and the magnitudes of the 

improvements. However, ADEQ did not do this for any of the sources covered by this action. 

With respect to ADEQ’s consideration of visibility improvements for Coronado, EPA 

agrees that average visibility index used by ADEQ could be acceptable in itself as part of 

assessing multiple area impacts and improvements; indeed it is a variant of the cumulative 

improvement approach. However, without any consideration of particular area improvements, 

the averaging process causes especially large benefits at some individual areas to be diluted or 

lost, effectively discounting some of the more important effects of the controls. In addition, the 

approach is counter to ADEQ’s emphasis elsewhere in the SIP on the importance of considering 

the visibility improvement at the single area having the largest impact from a given facility. 

 

26 See, e.g., 76 FR 52388, 52430 (San Juan Generating Station); 77 FR 51620, 51631-51632 (Four Corners Power 

Plant); and 77 FR 51915, 51922-51923 (Roseton and Danskammer Generating Stations) 
Page 30 of 244

Finally, ADEQ provided no discussion of how the results of the visibility index were weighed 

against the other BART factors. 

In addition, ADEQ considered visibility improvements from controls on only a single 

emitting unit at a time, despite the fact that each of the three sources has multiple BART-eligible 

units. This neglects the full improvement that would result from controls on the facility, with the 

potential for dismissing emitting unit benefits that are individually small, but that collectively 

could have a significant visibility benefit. The RHR requires RH SIPs to include a 

“determination of BART for each BART-eligible source in the State that emits any air pollutant 

which may reasonably be anticipated to cause or contribute to any impairment of visibility in any 

mandatory Class I Federal area.”27 The BART Guidelines explain that, “[i]f the emissions from 

the list of emissions units at a stationary source exceed a potential to emit of 250 tons per year 

for any visibility-impairing pollutant, then that collection of emissions units is a BART-eligible 

source.”28 Therefore, it is that collection of units for which one must make a BART 

determination. The Guidelines state “you must conduct a visibility improvement determination 

for the source(s) as part of the BART determination. . . .”29 This requires consideration of the 

visibility improvement from BART applied to the facility as a whole. 

The RHR and the Guidelines do not preclude consideration of visibility improvement 

from controls on individual units, but that would be in addition to considering the improvement 

from the whole facility. The BART Guidelines clearly allow for the consideration of technical 

feasibility and cost-effectiveness on a unit-by-unit basis where appropriate, but those 

considerations fall under different factors than the assessment of the degree of visibility 

improvement, and do not remove the obligation to consider visibility improvement from BART 

 

27 40 CFR 51.308(e)(1)(ii)(emphasis added). 

28 40 C.F.R. Part 51, Appendix Y, section II.A.4 (emphasis added). 

29 Id. section IV.D.5 (emphasis added). 
Page 31 of 244

applied to the facility as a whole. In sum, while the State has some flexibility in choosing a 

specific procedure to consider these cumulative area and multiple unit benefits, when such 

benefits are significant, it is not reasonable to ignore them altogether as ADEQ did. 

Comment: One commenter (NPS) agrees with EPA that the ammonia background 

concentration assumed by ADEQ for Cholla and Coronado may be too low, ranging from 1 part 

per billion (ppb) down to 0.2 ppb. According to the commenter, EPA guidance recommends the 

use of a 1 ppb ammonia background for areas in the west, absent compelling evidence to the 

contrary. 

Other commenters (APS and AUG) state that the Interagency Workgroup on Air 

Quality Modeling (IWAQM) recommended value of 1ppb is outdated and should not be used 

now that better data have been gathered and since the CALPUFF model was updated to allow for 

monthly, rather than yearly, average ammonia concentrations. APS also noted that EPA Region 9 

has explicitly approved the use of the same monthly-varying background ammonia 

concentrations, which were based on actual field measurements, in running the CALPUFF model 

for two other sites located close to Cholla and that were used by ADEQ in its analysis. These 

values range from 1 ppb during the summertime to 0.2 ppb during cold winter months. EPA has 

also stated in response to comments on the Montana regional haze FIP (77 FR 57864) that “it is 

preferable to use ambient ammonia measurements when such data are available rather than using 

default background ammonia concentrations.” Another commenter (Navajo Nation) agrees that 

EPA should use actual, recorded data wherever possible, especially ammonia background values. 

AUG concludes that EPA has no basis for rejecting the use of refined background ammonia 

concentration values in disapproving the SIP. 
Page 32 of 244

Response: The IWAQM Guidance30 is the only guidance available for choosing 

ammonia background concentrations. Because of the paucity of monitoring data and the 

uncertainty in other ammonia estimation methods, EPA concludes that it is appropriate to use the 

default 1 ppb from the IWAQM Guidance. 

As stated by the commenter, EPA did originally accept monthly varying ammonia values 

of 0.2 to 1.0 ppb for BART analyses performed by AECOM for APS for the Four Corners Power 

Plant (FCPP), and by SRP for the Navajo Generating Station (NGS). However, shortly after that, 

the USDA Forest Service brought to EPA’s attention ammonia monitored in the Four Corners 

area showing concentrations up to 3 ppb, described in a journal paper31 by Mark Sather and 

others. EPA and the Forest Service also estimated ammonia concentrations by “back calculating” 

the amount of ammonia needed to form the ammonium nitrate and ammonium sulfate collected 

at Arizona and New Mexico sites in the IMPROVE monitoring network. This yielded 

concentrations ranging from 0.4 to 1.3 ppb, with winter values considerably higher than the 

AECOM 0.2 ppb recommended by the commenter.32 Since this method accounts only for 

ammonium, and not remaining free gaseous ammonia, the total ammonia originally available to 

form visibility-impairing compounds may actually be higher. Because of uncertainty in the 

“back-calculation” method, and criticism of it, EPA relied on it in the FCPP FIP only as 

corroboration for the IWAQM default of 1 ppb.33 Nevertheless, it supports the idea that winter 

 

30 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

31 Mark E. Sather et al., “Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern 

Oklahoma, USA”. Journal of Environmental Monitoring, 2008, 10, 1319-1325, DOI: 10.1039/b807984f. 

32 See, e.g., Proposed Rule: Source Specific Federal Implementation Plan for Implementing Best 

Available Retrofit Technology for Four Corners Power Plant: Navajo Nation Technical Support Document, pages 

59-61, 65-66, 68-73. 

33 Id. at page 68. 
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ammonia levels in the Class I areas affected by emissions from sources in Arizona are likely 

substantially higher than 0.2 ppb. 

EPA agrees with commenters that it would be preferable to use actual monitoring data to 

determine background ammonia concentrations. However, much of the existing data cited by the 

commenters is from other states, and so is unlikely to be representative for evaluating visibility 

impacts at Arizona’s Class I areas. Further, the data comprises only ammonia itself, and not 

ammonium; or if it does include ammonium, that is not cited by the commenters. Visibilityimpairing ammonium sulfate and ammonium nitrate are formed from ammonia, SO2, and NOX. 

Therefore the ammonium represents part of the pool of ammonia that could be available to 

interact with the SO2 and NOX from a facility and contribute to visibility impacts, and should be 

accounted for in estimating ammonia background concentrations. In several of the research 

papers34 cited by commenter APS, the amount of measured ammonium is comparable to and at 

times much greater than the amount of ammonia. 

New ammonia monitoring data were collected by SRP at several sites between NGS and 

the two nearest Class I areas, Capitol Reef National Park and Grand Canyon National Park, from 

 

34 RoMANS - Rocky Mountain Atmospheric Nitrogen & Sulfur Study, William C. Malm and Jeffrey L. Collett. 

National Park Service, CSU-CIRA, Fort Collins, CO. ISSN 0737-5352-84. October 2009. 

http://www.nature.nps.gov/air/Studies/romans.cfm. Table 3.9 on p.3-38 shows ammonium comparable to or about 

half of ammonia, depending on measurement method. It also shows that the spring time mean and maximum 

ammonium are about 0.22 and 0.57 μg/m3, respectively, or 0.38 and 0.78 ppb; and the mean and maximum 

ammonia are about 0.38 and 1.0 μg/m3or 0.51 and 1.4 ppb. The sum of these means and maxima is 0.81 and 2.2 

ppb, respectively. Figure 4.26 on p.4-26 shows daily sums of ammonium and ammonia, with values of 2.5 – 5 μg/m3

or 3.6 – 7.2 ppb occurring frequently. These are substantially higher than values cited by the commenters. “NH3

Monitoring in the Upper Green River Basin, Wyoming”, by John V. Molenar, H. James Newell, Jeffrey Collett, et 

al. Extended Abstract #70, A&WMA Specialty Conference “Aerosol & Atmospheric Optics: Visual Air Quality and 

Radiation”, Moab, Utah, 28 April - 2 May 2008, p.3 Figure 1 and p.4 Figure 3 show ammonium comparable to 

ammonia in summer and far greater in winter. “Aerosol Ion Characteristics During the Big Bend Regional Aerosol 

and Visibility Observational Study,” Taehyoung Lee, Sonia M. Kreidenweis & Jeffrey L. Collett Jr. Journal of the 

Air & Waste Management Assoc. vol.54, issue 5, 2004, pages 585-592. DOI:10.1080/10473289.2004.10470927, 

Table 1 p. 587 shows ammonium about four times as high as ammonia. 
Page 34 of 244

December 2009 through April 2010. The monitoring report,35 cited by commenter APS, 

describes a surprisingly high spatial variability in ammonia concentrations. The two monitors in 

the Cameron area south of NGS (and east-southeast of the Grand Canyon) showed consistent 

concentration differences despite being less than five miles from each other; this may be due to 

relatively localized ammonia sources. These sites also showed consistently lower measurements 

than the Halls Crossing site, north of NGS (and southwest of Capitol Reef). The range in 

concentrations was comparable to the range seen between the AECOM values at the low end, 

and EPA’s back-calculated values at the high end. Unfortunately, because of the variability and 

its unknown causes, the data collected did not lead to a clear picture of appropriate and 

representative ammonia background concentrations to use with CALPUFF. 

In any case, as mentioned above, some nearby monitored data reported in Sather’s paper 

show considerably higher ammonia than recommended by some commenters, so it is not clear 

that values lower than 1 ppb should be used. EPA concludes that there is not a compelling case 

for using ammonia background concentrations other than the 1 ppb found in the only 

authoritative guidance document available on this topic and supported by the FLMs. 

Comment: Two commenters (APS and AUG) noted that the RHR and BART Guidelines 

are silent regarding whether visibility improvements should be modeled on a unit-by-unit basis 

or a plant-wide basis, and there is no legal requirement that units be modeled aggregately. Given 

that visibility benefits are approximately additive, the commenters contend that it is unreasonable 

for EPA to conclude that ADEQ’s BART analyses failed to consider any significant visibility 

effect merely because ADEQ modeled the units separately. In addition, AUG notes that it is 

necessary to determine the effects of emissions from units individually so that projected visibility 

 

35 “Measurements of Ambient Background Ammonia on the Colorado Plateau and Visibility Modeling 

Implications”, Salt River Project, Dr. Ivar Tombach, Consultant, and Robert Paine, AECOM Environment, 

September 2010 
Page 35 of 244

impacts can be considered in light of costs and other impacts associated with BART-candidate 

controls for that particular unit, and modeling units together could obscure these comparisons. 

Response: Considering the visibility benefits of multiple units together does not preclude 

a state from also considering individual unit benefits, as well as individual unit costs. EPA does 

not agree that modeling the units together obscures these other comparisons. Rather, the benefit 

of controls for an entire BART-eligible source is a factor that should be considered along with 

those other comparisons. In any case, whether considered unit by unit or all units together, 

visibility improvement has no effect on the assessment of cost-effectiveness as measured by 

dollars per ton of reductions. 

 B. Comments on ADEQ’s Individual BART Analyses and Determinations 

 1. ADEQ’s BART Analyses and Determinations for Apache Unit 1 

Comment: One commenter (NPS) concurred with ADEQ’s and EPA’s proposals for 

BART at Apache Unit 1. 

Response: We acknowledge NPS’s concurrence. 

 

 2. ADEQ’s BART Analyses and Determinations for Apache Units 2 and 3 

 a. ADEQ’s BART Analysis and Determination for NOX 

Comment: One commenter (Earthjustice) commended EPA’s decision to disapprove 

ADEQ’s NOX BART determination for Apache Units 2 and 3. The commenter stated that EPA 

correctly concluded that ADEQ’s BART determination for NOX inflated the costs of morestringent NOX controls by including costs not allowed by EPA Cost Control Manual, provided 

little reasoning about the visibility benefits of additional NOX controls, and did not weigh the 

visibility impacts at all nearby Class I areas. The commenter asserted that because ADEQ’s 
Page 36 of 244

BART analysis does not comply with the RHR’s requirements, EPA must disapprove ADEQ’s 

BART determinations for Apache Units 2 and 3.

Response: We agree that ADEQ’s BART analysis for Apache Units 2 and 3 does not 

comply with the RHR’s requirements. As discussed further below, we performed a supplemental 

analysis using the version of AEPCO’s cost estimate that adheres to our assumptions regarding 

costs that are allowed by the CCM (i.e., capital costs for the installation of SCR with LNB and 

OFA of $164.9 million), and we also considered the fact that AEPCO is a small entity under the 

Regulatory Flexibility Act.36 

 b. ADEQ’s BART Analysis and Determination for PM10 

Comment: One commenter (NPS) agreed with ADEQ and EPA that BART for PM10 at 

Apache Units 2 and 3 is upgrades to the existing electrostatic precipitators (ESPs) and a PM10

emissions limit of 0.03 lb/MMBtu. The commenter noted that ADEQ stated that PM10 emissions 

would be measured by conducting EPA Method 201/202 tests. 

In contrast, a second commenter (Earthjustice) disagreed with EPA’s proposal to approve 

ADEQ’s PM10 BART determination for Apache Units 2 and 3. The commenter contended that 

EPA proposed to approve the BART determination despite acknowledging that ADEQ did not 

conduct a full BART analysis for PM10 because it overestimated costs and failed to consider 

upgrades to the existing ESPs. However, the commenter believes that lower emission rates are 

achievable and, as a result, that EPA should disapprove ADEQ’s BART determination, conduct a 

full five-factor BART analysis and set a lower emission limit as BART for PM10. According to 

the commenter, the Sahu report demonstrates that nearly 150 EGUs across the nation with a 

 

36 As explained in our proposal, a firm primarily engaged in the generation, transmission, and/or distribution of 

electric energy for sale is small if, including affiliates, the total electric output for the preceding fiscal year did not 

exceed 4 million megawatt hours. 77 FR 42867. AEPCO sold under 3 million megawatt hours in 2011 and is 

therefore a small entity. 
Page 37 of 244

variety of PM controls achieve emission rates lower than 0.03 lb/MMBtu. The commenter 

asserted that neither ADEQ nor EPA provided any explanation why Apache Units 2 and 3 could 

not similarly meet a lower emission limit. 

Response: As we noted in our proposal, ADEQ's BART analysis did not demonstrate that 

all potential upgrades to the existing ESPs at Apache Units 2 and 3 were fully evaluated or that 

the costs were calculated in compliance with the Control Cost Manual. However, we concluded 

that this was a harmless error because of the relatively small visibility improvement associated 

with PM10 reductions from these units.37 Therefore, we proposed to approve ADEQ’s 

determination that BART for PM10 at Apache Units 2 and 3 is upgrades to the existing ESPs and 

a PM10 emissions limit of 0.03 lb/MMBtu. 

One commenter asserted that this limit is too lenient, since other coal-fired units are 

achieving lower limits, based on test data submitted by various utilities to EPA as part of an 

Information Collection Request (ICR) for the Mercury and Air Toxics (MATS) Rule.38 EPA 

disagrees with this comment. The MATS Rule establishes an emission standard of 0.030 

lb/MMBtu filterable PM (as a surrogate for toxic non-mercury metals) as representing Maximum 

Achievable Control Technology (MACT) for coal-fired EGUs.39 This standard derives from the 

average emission limitation achieved by the best performing 12 percent of existing coal-fired 

EGUs (taking into account the variability in the testing results for these facilities), based upon to 

the same test data referred to by the commenter.40 The BART Guidelines provide that, “unless 

there are new technologies subsequent to the MACT standards which would lead to cost-

 

37 77 FR 42847. 

38 Information Collection Request For National Emission Standards For Hazardous Air Pollutants (NESHAP) for 

Coal- And Oil-Fired Electric Utility Steam Generating Units (OMB Control No. 2060‐0631). See 

http://www.epa.gov/ttn/atw/utility/utilitypg.html for detailed information obtained through this ICR. 

39 77 FR 9304, 9450, 9458 (February 16, 2012) (codified at 40 CFR 60.42Da(a), 60.50Da(b)(1)). 

40 See Memorandum from Jeffrey Cole (RTI International) to Bill Maxwell (EPA) regarding “National Emission 

Standards for Hazardous Air Pollutants (NESHAP) Maximum Achievable Control Technology (MACT) Floor 

Analysis for Coal- and Oil-fired Electric Utility Steam Generating Units for Final Rule” (Dec. 16, 2011). 
Page 38 of 244

effective increases in the level of control, you may rely on the MACT standards for purposes of 

BART.”41 Therefore, we are approving ADEQ’s determination that a PM10 limit of 0.03 

lb/MMBtu represents BART for these units. 

 c. ADEQ’s BART Analysis and Determination for SO2 

Comment: One commenter (Earthjustice) disagreed with EPA’s proposal to approve 

ADEQ’s SO2 BART determination at Apache Units 2 and 3. The commenter states the approval 

is contrary to the RHR because ADEQ’s BART determination is not supported by a valid fivefactor analysis. The commenter states that EPA cannot speculate that it would reach the same 

conclusion as ADEQ, and it must undertake an independent full five-factor BART analysis. The 

commenter argues that an SO2 limit of 0.04 lb/MMBtu is achievable and cost-effective for 

Apache Units 2 and 3 according to the Sahu report. The commenter further asserts that, based on 

this report, scrubber upgrades can achieve SO2 removal efficiencies of 98 percent and should 

have been investigated. 

Another commenter (NPS) noted that that AEPCO’s BART reports indicate that 

uncontrolled SO2 emissions are 0.69 lb/MMBtu, and that the ADEQ BART proposal would 

reduce SO2 emissions by 78 percent down to 0.15 lb/MMBtu. Based on the SO2 control data 

submitted by the commenter, the commenter asserted that other BART upgrades are achieving 

higher removal efficiencies and/or lower SO2 limits. The commenter believes that the existing 

scrubbers can be upgraded to achieve better removal efficiency and lower emission rates than the 

78 percent and 0.15 lb/MMBtu proposed by EPA. The commenter cited various examples of 

upgraded scrubbers achieving limits of less than 0.15 lb/MMBtu or removal rates of greater than 

90 percent. 

 

41 40 CFR Part 51, Appendix Y, Section IV.C. 
Page 39 of 244

By contrast, ADEQ and AEPCO expressed opposition to both a lower limit and a 

removal efficiency requirement. ADEQ asserted that “the limits included in the state SIP 

submittal are acceptable as BART” and “imposing dual-limitations will be unnecessary and 

burdensome for the facility.” AEPCO commented that ADEQ permit conditions, which require 

SO2 absorption systems to be operated and maintained at all times in a manner consistent with 

good air pollution control practices for minimizing emissions, is sufficient, and an additional 

control efficiency limit is not necessary. An efficiency limit would also require modification to 

the monitors to include the capability to measure scrubber inlet SO2 in addition to stack 

emissions, which would require additional capital and O&M expenditures. 

Response: We proposed to approve ADEQ's determination that BART for SO2 at Apache 

Units 2 and 3 is upgrades to the existing scrubbers with an associated emission limit of 0.15 

lb/MMBtu (30-day rolling average). However, we also solicited comment on whether an 

efficiency requirement should be part of the BART requirement, since Apache has the ability to 

use coal from various sources that have varying sulfur content. After reviewing the comments 

received on our proposal, we have concluded that the emission limit set by ADEQ appropriately 

reflects BART for SO2 at these units and that a removal efficiency requirement would not be 

appropriate for these units. 

While new wet scrubbers are capable of achieving 95 percent or better removal of SO2,

42

the Apache scrubbers were manufactured in the 1970s and designed to meet a limit of 0.8 

lb/MMBtu (i.e., a control efficiency of up to 70 percent).43 For such existing scrubbers achieving 

greater than 50 percent control, the BART Guidelines (which are not mandatory for these units) 

 

42 See BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.4. 

43 See Apache Title V Permit Technical Support Document (2007), Table 9; Title V Permit (2007), Attachment B, 

section II.E.1.a. 
Page 40 of 244

do not provide a presumptive limit or removal efficiency, but recommend consideration of costeffective scrubber upgrades designed to improve the system's overall SO2 removal efficiency.

44

 

In August 2009, AEPCO provided information to ADEQ concerning potential scrubber 

upgrades at Apache Units 2 and 3.45 AEPCO noted that it was in the process of upgrading its 

limestone grinding system and described other potential upgrades, such as improving operation 

of the scrubber bypass damper system, upgrading the mist eliminator wash system, adding 

another sieve tray, and modifying the flue gas inlet. The enclosed “Wet FGD Implementation 

Plan” indicated that AEPCO intended to proceed with upgrading the limestone grinding system, 

improving operation of the scrubber bypass damper system, and upgrading the mist eliminator 

wash system, but that “[t]he remaining wet FGD options were not selected on the basis of low 

probability of successfully making a significant difference in scrubber performance and/or high 

cost.”46

Based on this information, we conclude that no further cost-effective scrubber upgrades 

are likely to be feasible for this facility and we are therefore deferring to ADEQ’s determination 

that 0.15 lb/MMBtu represents BART for these units. Given the age of these scrubbers, we find 

that an additional removal efficiency requirement would be unnecessarily burdensome. This 

approach is consistent with our consideration of AEPCO’s status as a small entity in our FIP 

determination. We note that our final FIP includes a requirement to maintain and operate air 

pollution control equipment at all units in “a manner consistent with good air pollution control 

practices for minimizing emissions” at all times. We expect that this requirement will help to 

ensure that the scrubbers on Apache Units 2 and 3 are properly maintained and operated under 

all conditions. 

 

44 See BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.4. 

45 Letter from Michelle Freeark, AEPCO, to Trevor Baggiore, ADEQ (July 8, 2009). 

46 Id. 
Page 41 of 244

 3. ADEQ’s BART Analyses and Determinations for Cholla Units 2, 3 and 4 

Comment: One commenter (APS) remarked that EPA stated that APS’s contractor did not 

provide supporting information for its capital cost estimate, such as detailed equipment lists. The 

commenter argues that detailed equipment lists are typically not necessary for the level of 

accuracy needed for the process selection phase of a project and noted that its contractor used 

vendor quotes for the major pieces of equipment and factors for construction, balance of plant, 

electrical, owner’s costs, surcharges, AFUDC and contingency. 

Response: We do not agree with this comment. The BART Guidelines provide that:

 

You should include documentation for any additional information you used for 

the cost calculations, including any information supplied by vendors that affects 

your assumptions regarding purchased equipment costs, equipment life, 

replacement of major components, and any other element of the calculation that 

differs from the [CCM].47

Thus, detailed cost documentation is necessary to the extent that cost assumptions differ from the 

CCM. In this case, several of ADEQ’s and APS’s cost assumptions for control costs at Cholla 

differed from the CCM, but no such documentation was provided as part of the Arizona Regional 

Haze SIP. 

 a. BART Analysis and Determination for NOX 

Comment: One commenter (Earthjustice) commended EPA’s decision to disapprove 

ADEQ’s NOX BART determination for Cholla Units 2, 3 and 4. The commenter stated that EPA 

correctly concluded that ADEQ’s BART determination for NOX inflated the costs of morestringent NOX controls by including costs not allowed by the Manual, and substantially 

underestimated the visibility benefits of additional NOX controls. The commenter asserted that 

 

47 40 CFR Part 51, Appendix Y, section IV.4.a., note 15. 
Page 42 of 244

because ADEQ’s BART analysis does not comply with the RHR’s requirements, EPA must 

disapprove ADEQ’s BART determinations for Cholla Units 2, 3 and 4. 

Response: As explained in our proposal and elsewhere in this document, we agree that 

ADEQ’s BART analyses and determinations for NOX at Cholla Units 2, 3 and 4 do not comply 

with the requirements of the CAA and RHR. We are therefore disapproving these 

determinations. 

 b. BART Analysis and Determination for PM10 

Comment: One commenter (NPS) agreed with EPA’s proposal to approve ADEQ’s 

BART determination for Cholla Units 2, 3 and 4 of an emission limit of 0.015 lb/MMBtu for 

PM10 based on the use of fabric filters, the most stringent control technology available. In 

contrast, a second commenter (Earthjustice) disagreed with EPA’s proposal to approve ADEQ’s 

PM BART determination for Cholla Units 2, 3 and 4. The commenter contended that EPA 

proposed to approve the BART determination despite acknowledging that ADEQ did not 

conduct a full BART analysis for PM because fabric filters are the most stringent PM control 

technology available and ADEQ’s 0.015 lb/MMBtu emission limit is “consistent” with other 

EGUs employing fabric filters (citing 77 FR 42849). However, the commenter believes that 

lower emission rates are achievable with fabric filters and, as a result, that EPA should 

disapprove ADEQ’s BART determination, conduct a full five-factor BART analysis and set a 

lower emission limit as BART for PM10. According to the commenter, the BART Guidelines’ 

exemption from a full five-factor analysis for the most stringent control technology is not 

applicable in this case because improvements to the fabric filters are possible and a lower 

emission rate is thus achievable. 
Page 43 of 244

The latter commenter (Earthjustice) stated that had EPA conducted the PM10 BART 

analysis required by the RHR, it would show that an emission rate lower than 0.015 lb/MMBtu is 

BART for Cholla. According to the commenter, an expert report accompanying the commenter’s 

submission (the “Sahu report”) demonstrates that upgrades to the fabric filters can achieve a 

lower emission limit and, moreover, that nearly 100 EGUs across the nation with a variety of PM 

controls achieve emission rates lower than 0.015 lb/MMBtu. The commenter asserted that 

neither ADEQ nor EPA provided any explanation why Cholla Units 2, 3 and 4 could not 

similarly meet a lower emission limit. 

Response: We are finalizing our approval of ADEQ’s PM10 BART determination at 

Cholla Units 2, 3 and 4. We find that an emission limit of 0.015 lb/MMBtu represents what can 

be continuously achieved with a properly operated baghouse on these units. The fabric filters 

(i.e., baghouses) at Cholla will all be new since they are scheduled to be installed between 2008 

and 2016. Recent PSD BACT limits for coal-fired EGUs with new baghouses have typically 

ranged from 0.01 to 0.015 lb/MMBtu using Method 5. 

As to the commenter’s position that bag material selection would influence the level of 

PM that could be achieved, EPA notes that there are a number of factors that influence a utility’s 

selection of proper bag material such as bag life, compatibility with exhaust gas stream and 

control of other pollutants such as mercury (Hg) or sulfuric acid mist (H2SO4). In addition, it 

should be noted that the latest revision to the EGU NSPS requires modified units to meet a PM 

limit of 0.015 lb/MMBtu.

48 Also, as noted above, the recent EGU MATS rule sets a PM 

emissions standard of 0.03 lb/MMBtu, and the BART Guidelines provide that, “unless there are 

new technologies subsequent to the MACT standards which would lead to cost-effective 

 

48 77 FR 9450 (February 16, 2012)(codified at 40 CFR 60.42Da). 
Page 44 of 244

increases in the level of control, you may rely on the MACT standards for purposes of BART.”49

Therefore, we are finalizing our proposed approval of ADEQ’s BART determination for PM10 at 

Cholla Units 2, 3 and 4. 

 c. ADEQ’s BART Analysis and Determination for SO2 

Comment: Citing various examples of lower SO2 limits at other coal-fired units, one 

commenter argued that the existing scrubbers at Cholla can be upgraded to achieve lower 

emission rates than the 0.15 lb/MMBtu proposed by EPA. Based on the SO2 control data 

submitted by the commenter, the commenter asserted that other BART upgrades are achieving 

higher removal efficiencies and/or lower SO2 limits. 

Another commenter (Earthjustice) disagreed with EPA’s proposal to approve ADEQ’s 

SO2 BART determination for Cholla Units 2, 3 and 4. The commenter states the approval is 

contrary to the RHR because ADEQ’s BART determination is not supported by a valid fivefactor analysis, which the commenter believes had flaws in its cost and visibility improvement 

analyses. The commenter alleged that EPA proposed to approve the SO2 BART determinations 

based on unsupported speculation that the outcome would be the same if EPA performed the 

BART analysis required by the RHR, although EPA identified nothing in the docket to support 

its claim that a full BART analysis would have yielded the same result. The commenter states 

that EPA cannot speculate that it would reach the same conclusion as ADEQ, and it must 

undertake an independent full five-factor BART analysis. 

The commenter further stated that ADEQ’s SO2 BART analysis for Cholla Units 2, 3 and 

4 is also flawed because ADEQ failed to analyze controls and upgrades that would result in 

emission rates lower than the BART Guidelines’ presumptive BART limits. According to the 

commenter, EPA has recognized multiple times that the presumptive BART limits are merely the 

 

49 40 CFR Part 51, Appendix Y, Section IV.C. 
Page 45 of 244

starting point for the BART determination, not the ending point. Moreover, the commenter 

asserted that the presumptive limits are often outdated with the result that appropriate 

consideration of the five statutory BART factors can result in far lower emission rates than 

presumptive BART. The commenter cited statements by EPA Region 6 (76 FR 64186, 64203, 

October 17, 2011, regarding proposed actions on Arkansas’ RH SIP) and EPA Region 9 (77 FR 

51633 regarding the final RH FIP for the Four Corners Power Plant). 

Earthjustice also presented documentation that the commenter believes to show that 

lower SO2 emission limits are achievable and cost-effective at Cholla Units 2, 3 and 4. 

According to the commenter, a report submitted with the comments (the “Stamper report”)50

shows that a proper BART determination for Cholla would have found that 98 percent SO2

control efficiency achieving a 0.04 lb/MMBtu emission limit is BART for the units, and that 

even with the less-stringent 95 percent SO2 control efficiency that is the basis of ADEQ’s BART 

determinations, ADEQ should have required an SO2 emission limit of 0.10 lb/MMBtu because 

0.15 lb/MMBtu limit does not reflect 95 percent SO2 removal. 

Another commenter (APS) noted that the SO2 content of the coal source for the Cholla 

plant is up to 3.0 lbs/MMBtu, and the maximum rate of removal that will be continuously 

achievable after the plant upgrades its scrubbers is 95 percent. Therefore, the commenter asserts 

that 0.15 lb/MMBtu is the maximum achievable SO2 emissions limit. 

Response: A number of commenters indicated that lower emission levels are being 

achieved at other sources with wet FGDs and western coal. However, none of these examples are 

based on coal with as high a potential SO2 level as the coal that is currently burned at Cholla. 

 

50 Attachment 1 to Earthjustice Comments, Technical Support Document to Comments of 

Conservation Organizations, Proposed Arizona Regional Haze Partial SIP Approval and Partial 

FIP SO2 and NOX BART Determinations for Cholla Units 2, 3 and 4 (September 17, 2012), 

prepared by Victoria Stamper. 
Page 46 of 244

APS historically burned coal from the McKinley mine located on the Navajo Reservation at the 

Cholla units. Following the closure of this mine, APS obtained coal from various sources until 

the company signed a long-term contract for coal from the El Segundo and Lee Ranch mines in 

New Mexico.51 The sulfur content of coal from these two mines is substantially higher than 

Powder River Basin (PRB) coal and also much higher than coal from the former source, the 

McKinley mine.52 The current coal contract for these units indicates that the typical sulfur 

content of this coal is equivalent to 2.4 lb/MMBtu SO2 and can be as high as 3.0 lb/MMBtu.

53

Given that the transition to this coal has already occurred and that company has entered into a 

contract to continue purchasing this coal until 2024, we consider emissions based on this coal 

supply to “represent a realistic depiction of anticipated annual emissions for the source.”54 The 

RHR and the BART Guidelines do not require states to restrict or alter a facility’s selection of 

the coal supply in order to meet a specific limit. 

APS’s comments on the proposal indicate that the company intends to upgrade the 

existing SO2 controls at Unit 2 to a new wet flue gas desulfurization (FGD) system, identical to 

those already installed on Units 3 and 4.55 APS further explained that: 

The coal source for [Cholla] is El Segundo and Lee Ranch coal with an SO2 content 

of up to 3.0 lbs/mmBtu.The maximum rate of removal that will be continuously 

achievable after the scrubber upgrades . . . are performed is 95 percent. If 

compliance is determined on a 30-day rolling average basis, the maximum SO2

emission limit achievable at Cholla on a continuous basis is, therefore, 0.15 

lb/mmBtu.

56

Given this information, EPA finds that the ADEQ BART limit of 0.15 lb/MMBtu 

represents BART for SO2 at these units. As noted by APS, this limit would require a 

 

51 See “Additional APS Cholla BART response”, Appendix B. 

52 See, e.g., “APS Cholla Unit 2 BART report”, Table 2-2. 

53 See “Additional APS Cholla BART response”, Appendix B, Section 6.2. 

54 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d. 

55 “Comments of Arizona Public Service Company”, page 27. 

56 Id. page 63. 
Page 47 of 244

removal efficiency of 95 percent when these units are burning this “worst-case” (highestsulfur) coal (i.e., 3.0 lb/MMBtu). Therefore, we are finalizing our approval of ADEQ’s 

BART limit of 0.15 lb/MMBtu of SO2 for these units. 

However, we remain concerned that this worst case coal is not representative of the 

typical coal that APS will receive from the El Segundo and Lee Ranch mines. APS’s current 

contract for this coal indicates that the minimum sulfur content is equivalent to 1.88 lb/MMBtu 

of SO2 for the El Segundo coal and 1.64 lb/MMBtu of SO2 for the Lee Ranch Coal.57 When 

burning this lower-sulfur coal, the units would only need to achieve 90 to 92 percent control in 

order to meet the BART limit of 0.15 lb/MMBtu of SO2. While APS has stated that the scrubbers 

on Cholla Units 2, 3 and 4 will be able to continuously achieve a removal efficiency of 95 

percent, the Arizona Regional Haze SIP does not include a requirement or procedures to ensure 

that the scrubbers are operated and maintained to achieve this level of control. Therefore, in 

order to ensure that these scrubbers are properly operated and maintained, consistent with 40 

CFR 51.308(e)(1)(v), we are finalizing a removal efficiency requirement for SO2 of 95 percent 

on a 30-day rolling basis for Cholla Units 2, 3 and 4. This requirement is explained further under 

“Comments on Enforceability Requirements in EPA’s BART FIP.” 

 4. ADEQ’s BART Analyses and Determinations for Coronado Units 1 and 2 

 a. ADEQ’s BART Analysis and Determination for NOX 

Comment: One commenter (NPS) agreed with EPA that ADEQ’s BART selection of 

LNB with OFA for Coronado is not adequately supported for the following reasons: 

• ADEQ did not consider the typical visibility metrics of benefit at the area with maximum 

impact, nor benefits summed over the areas. 

 

57 See “Additional APS Cholla BART response”, Appendix B, Section 6.2. 
Page 48 of 244

• Using the default 1 ppb ammonia background concentration would have increased 

estimated impacts and control benefits. 

• There is no weighing of the visibility benefits and visibility cost-effectiveness for the 

various candidate controls and the various Class I areas. 

• ADEQ does not indicate whether it considered any cost thresholds to be reasonable or 

expensive in analyzing the costs of compliance for the various control options. 

Similarly, another commenter (Earthjustice) supported EPA’s disapproval of ADEQ’s NOx

BART determination for Coronado Units 1 and 2. For the reasons discussed by the commenter 

above for Cholla Units 2, 3 and 4, the commenter agreed with what the commenter said was 

EPA’s conclusion that all of ADEQ’s BART determinations are fatally flawed in numerous 

respects (e.g., inflated costs and underestimated visibility benefits). Specific to Coronado, the 

commenter agreed that ADEQ failed to provide detailed and verifiable cost information and to 

properly consider the costs of compliance for each control option in its BART analysis (citing 77 

FR 42851). In addition, the commenter indicated that ADEQ failed to properly evaluate the 

visibility benefits of more-stringent NOX controls at Coronado, used a novel and unapproved 

metric to measure visibility benefits, failed to consider cumulative visibility benefits across all 

affected Class I areas, and used incorrect background ammonia concentrations in its modeling. 

The commenter added that ADEQ also failed to explain how it evaluated the five statutory 

BART factors and selected BART based on the factors. The commenter asserted that because 

ADEQ’s BART analysis does not comply with the RHR’s requirements, EPA properly 

disapproved ADEQ’s NOX BART determinations for Coronado. 

Response: We agree that ADEQ’s BART analysis for NOX at Coronado Units 1 and 2 did 

not comply with the requirements of the CAA and RHR.
Page 49 of 244

Comment: One commenter (SRP) stated that EPA must accept ADEQ’s BART 

determination for NOX because it was a complete and thorough five‐factor analysis conducted in 

accordance with the BART Guidelines and resulted in a reasonable and appropriate 

determination of NOX BART for Coronado. 

Response: We do not agree with this comment. As explained in the NPRM and elsewhere 

in this document, ADEQ’s BART determinations for NOX did not comply with the requirements 

of the RHR or the BART Guidelines. Therefore, we are finalizing our disapproval of these NOX

BART determinations, including the determinations at Coronado Units 1 and 2. 

 b. ADEQ’s BART Analysis and Determination for PM10 

Comment: One commenter (NPS) agreed with EPA’s proposal to approve ADEQ’s PM10

BART determination for Coronado Units 1 and 2, noting that that emissions of PM10 from 

Coronado Units 1 and 2 are currently controlled by hot-side ESPs and that, in terms of the 

consent decree, SRP is required to optimize its ESPs to achieve a PM10 emission rate of 

0.030 lb/MMBtu. 

Another commenter (SRP) stated that EPA’s approval of the Arizona BART 

determination for PM10 is reasonable and appropriate, believing it to be consistent with the CAA 

and supported by the technical record in this rulemaking. The commenter does not believe any 

upgrades to the ESPs are warranted as part of the BART determination, as SRP has in place a 

plan to optimize performance of the existing equipment. The commenter noted that as part of the 

consent decree between SRP and EPA for Coronado, SRP is required to operate the ESPs “at all 

times when the Unit it serves is in operation to maximize PM emission reductions, provided that 

such operation of the ESP is consistent with the technological limitations, manufacturers’ 
Page 50 of 244

specifications, and good engineering and maintenance practices for the ESP,” and this 

requirement also is reflected in Coronado’s current Title V operating permit. 

The commenter also noted that the PM10 limit in the recently promulgated MATS Rule 

will be more stringent than the PM10 limit proposed as BART. The commenter indicated that it 

makes sense for BACT to be more stringent than BART, and it likewise is appropriate for the 

MATS requirements to impose more stringent compliance obligations on utilities than a BART 

determination since MATS is intended to protect the public health from hazardous air pollutants, 

while BART is aimed at aesthetic concerns that Congress intended the states to address very 

gradually. 

In contrast, a third commenter (Earthjustice) disagreed with EPA’s proposal to approve 

ADEQ’s PM10 BART determination for Coronado Units 1 and 2. The commenter contended that 

EPA proposed to approve the BART determination despite acknowledging that ADEQ did not 

conduct a full BART analysis for PM10 because EGUs with ESPs elsewhere have BART limits 

of 0.03 lb/MMBtu. However, the commenter believes that lower emission rates are achievable 

and, as a result, that EPA should disapprove ADEQ’s BART determination, conduct a full fivefactor BART analysis and set a lower emission limit as BART for PM10. According to the 

commenter, the Sahu report demonstrates that nearly 150 EGUs across the nation with a variety 

of PM controls achieve emission rates lower than 0.03 lb/MMBtu. The commenter asserted that 

neither ADEQ nor EPA provided any explanation why Coronado Units 1 and 2 could not 

similarly meet a lower emission limit. 

Response: EPA acknowledges that ADEQ did not perform a rigorous five-factor BART 

analysis for PM10 at Coronado. However, a full five-factor analysis would be very unlikely to 

result in a change of control technology for PM10. Modeling of visibility impacts from direct 
Page 51 of 244

PM10 emissions has shown very small impairment for EGU PM10 emissions in comparison to 

visibility impairment resulting from SO2 and NOX emissions. The existing hotside ESPs at 

Coronado Units 1 and 2 control PM10 by greater than 98 percent. In addition, SRP is required 

under a Consent Decree to optimize the performance of these ESPs and to meet a PM limit of 

0.030 lb/MMBtu as measured by Method 5.58 The consent decree also requires Coronado to 

install and conduct performance specification testing of a particulate matter CEMS (PMCEMS). 

Installing the best control, a baghouse, would result in a cost exceeding $100,000/ton of 

additional PM removed. From a cost and visibility improvement standpoint, it is not justifiable to 

require replacement of controls that can achieve a reasonably low emission level on a continuous 

basis. As noted previously, 0.030 lb/MMBtu is the limit for filterable PM in the recently issued 

EGU MATS rule. Therefore, we are finalizing our approval of ADEQ’s BART determination for 

PM10 at these units. 

 c. ADEQ’s BART Analysis and Determination for SO2 

Comment: One commenter (NPS) noted that the consent decree between EPA and SRP 

requires installation of wet flue gas desulfurization (WFGD) systems on both Coronado units to 

achieve a 30-day rolling average SO2 removal efficiency of at least 95 percent or a 30-day rolling 

average SO2 emissions rate of no greater than 0.080 lb/MMBtu. The commenter added that EPA 

proposed to approve ADEQ’s BART SO2 emission limit of 0.08 lb/MMBtu (30-day rolling 

average) for Coronado Units 1 and 2, which the commenter indicated would be consistent with 

the more stringent limits on WFGD upgrades that the commenter has seen. 

One commenter (SRP) stated that EPA’s approval of ADEQ’s BART determination for 

SO2 is reasonable and appropriate, believing it to be supported by the technical record. In 

response to EPA’s request for comment on whether a lower emission limit may be achievable 

 

58 Consent Decree in United States v. Salt River Project, CV 08-1479-PHX-JAT (entered Dec. 19, 2008). 
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when the units are burning a lower‐sulfur coal, the commenter responded that it is inappropriate 

for EPA to establish a BART limit that would be premised on any restriction of SRP’s fuel 

supply. According to the commenter, this type of restriction would increase unit operating costs 

and reduce operational flexibility, and EPA provides no technical record to support consideration 

of this emissions reduction option. 

Another commenter (Earthjustice) disagreed with EPA’s proposal to approve ADEQ’s 

SO2 BART determination. The commenter states the approval is contrary to the RHR because 

ADEQ’s BART analyses are not supported by a valid five-factor analysis. The commenter states 

that EPA cannot speculate that it would reach the same conclusion as ADEQ, and it must 

undertake an independent full five-factor BART analysis, which the commenter believes would 

result in a SO2 BART limit of 0.04 lb/MMBtu based on a 30-day rolling average. Earthjustice 

further asserted that, according to the Sahu report, WFGD can achieve SO2 removal efficiencies 

of 98 percent and the use of low-sulfur coals, which can further reduce SO2 emissions, also 

should have been investigated. 

Response: EPA does not agree that we should disapprove the ADEQ BART 

determination and set an emission limit as low as 0.04 lb/MMBtu for SO2. EPA does 

acknowledge that while burning some coals, such as from PRB, these limits can be achieved at 

new units (though only achieved continuously over longer than 30-day averages), but EPA does 

not find that this limit would be consistently achievable at Coronado. Coronado receives its coal 

supply by rail line and has access to various sources of coal including PRB, Colorado and New 

Mexico coals. As mentioned previously, the RHR and the BART Guidelines do not require 

emission limits to be set at a level that would restrict the flexibility of EGUs to use available 

coals with varying sulfur content. 
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The consent decree between EPA and SRP described in our proposal requires installation 

of wet flue gas desulfurization (WFGD) systems (i.e., new scrubbers) at both units at Coronado 

by January 1, 2013. These scrubbers are required to achieve either 0.080 lb/MMBtu of SO2 or 95 

percent reduction of SO2 across the FGD, both over a rolling 30-day basis.59 ADEQ has selected 

0.08 lb/MMBtu as the BART emission limit for these units. We find that this is an appropriate 

limit for these units and are finalizing our approval of this determination. 

We also note that the recently promulgated EGU MATS rule, which uses an SO2 limit as 

an acceptable surrogate for limiting the emissions of hazardous acid gases, has set the limit at 

0.20 lb/MMBtu of SO2 for existing EGUs like Coronado Units 1 and 2.60 

 C. General Comments on EPA’s BART FIP Analyses and Determinations 

 1. Selection of Baseline Period

Comment: Several commenters expressed disagreement with our general approach to the 

selection of baseline periods. One commenter (NPS) stated a general preference for the use of a 

baseline period that represents pre-control emissions, as advised in the BART Guidelines, to 

estimate baseline emissions for the purpose of calculating the average cost-effectiveness of the 

complete control system (e.g., combustion controls plus SCR). The commenter believes that this 

avoids any biasing of the calculations by sources that install combustion controls during the 

BART evaluation process. NPCA asserted that the “proper” baseline for BART determinations is 

2001-2004. ADEQ asserted EPA violated the RHR provision in 51.308(d)(2)(i), which specifies 

the period for establishing baseline visibility conditions as 2000-2004, by using the period 

between 2008 and 2011 as a baseline period for EPA’s BART analyses. 

 

59 Consent Decree in United States v. Salt River Project, CV 08-1479-PHX-JAT (entered Dec. 19, 2008).

60 77 FR 9490 (February 16, 2012), codified in Table 2 to Subpart UUUUU of 40 CFR Part 63. 
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Response: We disagree that our use of updated baseline periods for BART determinations 

is inappropriate or inconsistent with the CAA or the RHR. While the RHR specifies 2000-2004 

as the baseline for purposes of measuring reasonable progress at Class I areas during the first 

implementation period,61 neither the RHR nor the BART Guidelines require that this particular 

timeframe be used as the baseline for BART determinations at individual sources. Rather, the 

Guidelines provide that, for purposes of calculating the costs of compliance: 

The baseline emissions rate should represent a realistic depiction of anticipated 

annual emissions for the source. In general, for the existing sources subject to 

BART, you will estimate the anticipated annual emissions based upon actual 

emissions from a baseline period.62

This provision is consistent with the statutory requirement that each BART determination take 

into consideration "any existing pollution control technology in use at the source."63 While the 

Guidelines do not specify particular dates for this “baseline period” for BART analyses, in order 

to “represent a realistic depiction of anticipated annual emissions for the source” the baseline can 

account for controls already installed on the source, or, where appropriate, controls which are 

required to be installed in the near future. 

In many instances, the 2000-2004 time frame was used as a baseline period for BART 

determinations because this time frame reflected existing controls in use at BART sources at the 

time BART analyses were performed, following the issuance of the final BART Guidelines in 

2005. In Arizona’s case, the initial BART analyses were performed in 2007, using baseline 

periods that varied by source: 2002-2007 for Apache; 2001-2003 for Cholla; and 2001-2003 for 

Coronado.64 These periods appear to reflect controls in existence at the time that these BART 

 

61 See 40 CFR 51.308(d)(2)(i). 

62 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d.1 

63 CAA 169A(g)(2), 42 U.S.C. 7491(g)(2); see also 40 CFR 52.308(e)(ii)(A). 

64 See, e.g., SIP Appendix D at 4; Apache Unit 2 BART analysis at 2-2; Cholla 
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analyses were performed. Our proposed disapproval of certain aspects of Arizona’s BART 

determinations was not based on any flaw in the choice of baseline period. 

However, having proposed to disapprove Arizona’s BART determinations for NOX on 

other grounds, we were obligated to conduct our own five-factor BART analyses for NOX for 

these sources. At the time we conducted our analysis in 2011 and 2012, several of these units had 

been retrofitted with additional NOX controls that were not in place between 2000 and 2004. In 

particular, Cholla had installed LNB on Units 2, 3 and 4 in 2008 to 2009, and Coronado had 

installed LNB at Unit 1 in 2009.65 In addition, during this time period, Cholla completed its 

transition to a different coal with much higher potential NOX emissions.66 Thus, in order to take 

into account existing controls and to ensure that the baseline period accurately represented 

anticipated future emissions, we updated the baseline period for each unit to ensure that it 

reflected these changes.67 

With respect to Coronado Unit 2, we also took into account the federally-enforceable 

emissions limits set by a Consent Decree between the United States and SRP, which was entered 

in 2008.68 Again, this is consistent with the BART Guidelines, which provide that: 

When you project that future operating parameters (e.g., limited hours of 

operation or capacity utilization, type of fuel, raw materials or product mix or 

type) will differ from past practice, and if this projection has a deciding effect in 

the BART determination, then you must make these parameters or assumptions 

into enforceable limitations. In the absence of enforceable limitations, you 

calculate baseline emissions based upon continuation of past practice.69

 

65 77 FR 42859, 42861. Although no new NOX controls were installed at Apache during this timeframe, we 

determined that more recent emissions data (2008-2011 rather than 2005-2007) were more likely to represent future 

emissions. 77 FR 42856. 

66 77 FR 42856, 42859, 42861.

67 77 FR 42861.

68 Consent Decree in United States v. Salt River Project, CV 08-1479-PHX-JAT (entered December 19, 2008). 

69 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d.2. 
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Consistent with this provision, for Coronado we used the consent decree-mandated NOX

emission limit of 0.08 lb/MMBtu in order to ensure that the baseline emissions rate would 

represent a realistic depiction of anticipated annual emissions for Unit 2. 

We note that such an “updated baseline” might not be appropriate in all instances. For 

instance, if it appeared that controls had been installed early in order to avoid a more stringent 

BART determination, it would presumably not be appropriate to use a baseline representing 

these new controls. We find no evidence of such intent here. Rather, with respect to Coronado, 

the installation of new NOX and SO2 controls was required by a consent decree. With respect to 

Cholla, the installation of newly installed NOX and SO2 controls coincided with increases in 

potential emissions of these pollutants resulting from a change in coal supply.

70 Therefore, the 

more recent baseline is likely to be more representative of future operating conditions at these 

units. 

Contrary to the assertions of some commenters, use of updated baselines did not unfairly 

penalize those sources that reduced their NOX emissions in advance of a final BART 

determination. Rather, the updated baseline effectively lowered the baseline visibility impacts 

from these sources by reducing the baseline emissions. As a result, the projected benefits of 

additional controls were less than if we had used the original baseline. This approach is 

consistent with the RHR and the BART Guidelines because it accurately reflects controls in 

place at the time we performed our BART analysis. Nonetheless, in order to address 

commenters’ concerns about the effect of the updated baselines on our proposed determinations, 

we have also taken into account the original baseline periods considered by ADEQ, as part of the 

supplemental cost analyses described below. 

 

70 See Docket Item B-09, “Additional APS Cholla BART response”, Appendix B, Section 6.2. 
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Finally, we note that the use of a more recent baseline for purposes of our BART 

analyses does not alter the baseline used for purposes of measuring reasonable progress. As 

noted by several commenters, the RHR specifies that, for purposes of setting RPGs and 

measuring progress: 

The period for establishing baseline visibility conditions is 2000 to 2004. Baseline 

visibility conditions must be calculated, using available monitoring data, by 

establishing the average degree of visibility impairment for the most and least 

impaired days for each calendar year from 2000 to 2004. The baseline visibility 

conditions are the average of these annual values.71 

In its Regional Haze SIP, Arizona used IMPROVE monitoring data from 2000-2004 to 

calculate baseline visibility for the best and worst visibility days for each Class I Area.72

Since these baseline visibility conditions are calculated based on monitored conditions at 

Class I areas, they reflect actual emissions that occurred during the 2000-2004 time 

frame, rather than any subsequently implemented controls. 

In developing its long-term strategy, a state must consider inter alia “[e]missions 

limitations and schedules for compliance to achieve the reasonable progress goal” and the 

“anticipated net effect on visibility due to projected changes in point, area, and mobile source 

emissions over the next 10 years.”73 This would include any reductions in emissions from BART 

sources that are implemented prior to a final BART determination, as well as any reductions 

resulting from such a determination. Thus, in setting its RPGs for 2018, a state may receive 

“credit” for any reductions achieved during the first implementation period, regardless of 

whether or not those reductions are reflected in the “baseline” emissions for a particular BART 

source. 

 

71 40 CFR 51.308(d)(2)(i). 

72 AZ Regional Haze SIP at page 39. 

73 40 CFR 51.308(d)(3)(v)(G). 
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EPA has not yet proposed action on Arizona’s RPGs or long-term strategy. Our 

ultimate action on these elements of the plan will take into consideration all emissions 

reductions achieved during the first implementation period, consistent with the 

requirements of the CAA and the RHR. 

 2. Control Efficiencies and Emission Reductions for Alternative Controls 

Comment: One commenter (NPS) concurred with EPA’s reliance on an SCR level of 

performance of 0.05 lb/MMBtu. The commenter noted that this level is consistent with EPA’s 

determination for the San Juan Generating Station in New Mexico and EPA’s assumptions for 

the Colstrip and Corette power plants in Montana 

Response: We acknowledge the commenter’s concurrence. As described further below, 

information received in comments on our proposal continues to support the use of an SCR level 

of performance of 0.05 lb/MMBtu on an annual average basis. Accordingly, we have retained the 

use of 0.05 lb/MMBtu in our cost calculations (which are based on annual emissions). However, 

in setting emission limits on a 30-day rolling average basis, it is necessary to account for startup 

and shutdown events, which raise the average emission rates over this shorter period of time. 

Therefore, we have revised our proposed emission limits for SCR at each of the sources. As 

explained below, we have also taken into account other site-specific factors in revising the 

emissions limits. In the case of Apache Units 2 and 3, we have performed a supplemental 

analysis using AEPCO’s cost estimates that are allowed by the CCM (capital costs for the 

installation of SCR with LNB and OFA of $164.9 million). We also considered comments, the 

size of the Apache facility, AEPCO’s classification as a small entity, the economic effects of 

requiring the use of SCR on Apache Units 2 and 3, and AEPCO’s arguments regarding an SCR 

emissions limit of 0.07 lb/MMBtu. As discussed below in this preamble, we have concluded that 
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in this case it is appropriate to revise the 30‐day rolling average SCR limit to 0.070 lb/MMBtu, 

with a “bubble” across Apache Units 2 and 3. In the case of Cholla, we have taken into account 

the need to accommodate startup and shutdown events in the 30‐day rolling average and have 

revised the limit to 0.055 lb/MMBtu, with a bubble across Units 2, 3 and 4. Finally, in the case of 

Coronado, we have taken into account both the need to accommodate startup and shutdown 

events, as well as the existing consent decree, which sets an emission limit of 0.080 lb/MMBtu 

for Unit 2. Based on these considerations, we have set a two-unit 30‐day rolling average limit of 

0.065 lb/MMbtu. For each of the three sources, we have established the compliance 

determination method such that when one unit is not operating, the emissions from its own 

preceding thirty boiler-operating-days will continue to be included in the 30-day rolling average. 

In the case of Coronado, for example, during periods when only one unit operates, this method 

allows the one operating unit to average out short-term emission spikes by using the most recent 

thirty boiler-operating-day value from the non-operating unit. Otherwise, averaging across units 

would not be possible during such periods, since the emissions value from the non-operating unit 

would be zero since it is not operating. 

Comment: One commenter (Earthjustice), based on a report submitted with the comments 

(the “Sahu report”), stated that SCR can achieve greater NOX reductions and visibility benefits at 

less cost than EPA’s calculations. According to the commenter, while SCR systems are capable 

of achieving 90 percent or greater removal, EPA’s proposed NOX emission limit of 0.05 

lb/MMBtu represents control levels of less than 90 percent at each of the Apache, Cholla and 

Coronado units. Accordingly, the commenter believes that EPA should have analyzed SCR with 

an emission limit of 0.04 lb/MMBtu because this level is achievable at 90 percent removal. 
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The commenter (Earthjustice), based on a separate report submitted with the comments (the 

“Stamper report”), stated that SCR systems are capable of achieving 90 percent or greater 

removal and EGUs elsewhere are subject to NOX emission limits as low as 0.03 lb/MMBtu. The 

commenter cited several Prevention of Significant Deterioration (PSD) permit limits based on 

BACT determinations, including a 0.03 lb/MMbtu limit at Plant Washington, issued by Georgia 

Environmental Protection Division, and 0.035 lb/MMBtu for Desert Rock, issued by EPA 

Region 9. Accordingly, the commenter believes that EPA should have analyzed SCR with an 

emission limit of 0.04 lb/MMBtu because this level is achievable at 90 percent control for each 

of the units.

Response: We agree with the information provided by the commenters that SCR 

technology has the potential to achieve 90 percent and greater rates of removal, as well as 

achieve emission rates of less than 0.05 lb/MMBtu. However, we disagree with the commenter’s 

assertion that emission limits associated with BART must meet the lowest emission rate 

achieved with that technology at any coal-fired power plant. The RHR provides that:

The determination of BART must be based on an analysis of the best system of 

continuous emission control technology available and associated emission 

reductions achievable for each BART-eligible source that is subject to BART...74

Additionally, the BART Guidelines state that: “[i]n assessing the capability of the control 

alternative, latitude exists to consider special circumstances pertinent to the specific source under 

review, or regarding the prior application of the control alternative”75 and that “[t]o complete the 

BART process, you must establish enforceable emission limits that reflect the BART 

requirements . . .”76 The five-factor BART analysis described in the Guidelines is a case-by-case 

analysis that considers site-specific factors in assessing the best technology for continuous 

 

74 40 CFR 51.308(e)(1)(ii)(A). 

75 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.3. 

76 Id. section V. 
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emission controls. After a technology is determined as BART, the BART Guidelines require 

establishment of an emission limit that reflects the BART requirements, but does not specify that 

the emission limit must represent the maximum level of control achieved by the technology 

selected as BART. While the BART Guidelines and the RHR do not preclude selection of the 

maximum level of control achieved by a given technology as BART, the emission limit set to 

reflect BART must be determined based on a consideration and weighting of the five statutory 

BART factors. Therefore, limits set as BACT during PSD review (e.g., Desert Rock), or 

emission rates achieved from the operation of individual facilities under an emissions trading 

program (e.g., Clean Air Act Interstate Rule (CAIR)) may provide important information, but 

should not be construed to automatically represent the most appropriate BART limit for a given 

technology. 

Comment: Several commenters (APS, AEPCO, SRP, AUG, Pacificorp) note that the 

proposed NOX emission rate, as based on SCR technology, is more stringent than many other 

EPA actions. In its comments, SRP provided a contractor’s report that found that the proposed 

limit is inconsistent with BACT determinations that EPA has approved for new coal‐fired units 

in the following ways: 

• Although there have been several units permitted with similar emissions limits, none of 

these limits are directly equivalent (same numeric limit and averaging time, including 

startup and shutdown periods). 

• These units are based on new construction, which can be designed to optimize NOX

reduction in other aspects of combustion (i.e., pulverizer design, boiler height, etc.). 

• There is inadequate data available to confirm the long‐term achievability of the limits 

because the units have not begun operation or only recently became operational. 
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Other commenters note that, as part of the Cross State Air Pollution Rule (CSAPR), EPA 

concluded that a NOX limit below 0.06 lb/MMBtu is not achievable through retrofit of SCR on 

coal‐fired electric generating units.77 AEPCO and APS also note that based on data from the 

RACT/BACT/LAER Clearinghouse, new coal-fired EGUs with SCR are only required to 

achieve 0.05 lb/MMBtu averaged over 12 months, and it is not appropriate to assume that a 

retrofit coal-fired unit can achieve this limit averaged over 30 days. SRP notes that the proposed 

limit for Coronado Unit 1 is more stringent than the recently promulgated NSPS for electric 

utility steam generating units constructed after May 3, 2011 (40 CFR part 60, subpart Da), which 

establishes a limit of 0.70 lb/MWh (0.077 lb/MMBtu) for new units, and 1.1 lb/MWh (0.11 

lb/MMbtu) for modified units. APS also provided a report, originally prepared by RMB 

Consulting & Research, Inc. (RMB) for comment on the Regional Haze FIP for San Juan 

Generating Station, suggesting that the Subpart Da limits represent the most stringent level of 

available control. The RMB report states that EPA’s Guidelines indicate that state regulatory 

agencies should consider NSPS limits in the BART evaluation except in cases where the NSPS 

might be considered outdated (e.g., “technology determinations from the 1970s or early 1980s”), 

which is not the case for the recently promulgated NSPS Subpart Da.

Response: We do not agree that our consideration of a NOX emission limit of 0.050 

lb/MMBtu was inappropriate. We note that, in its submitted comments, Earthjustice identified 

several recently issued permits that establish emission limits for SCR that are more stringent than 

our proposal. While limits set as BACT during PSD review may provide important information 

about the capabilities of various control technologies, they should not be construed to 

automatically represent (or in this context, constrain) the determination of what the most 

 

77 Citing 76 FR 1109, 1115, January 7, 2011; EPA, Transport Rule Engineering Feasibility Response to Comments, 

Docket ID No. EPA‐HQ‐OAR‐2009‐0491‐4529, at 13, July 6, 2011. 
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appropriate BART limit representative of a given technology is for a given facility. The emission 

limit set to reflect BART must be determined based on a consideration and weighing of the 

statutory BART factors. Although there are some similarities between the top-down BACT 

determination process and the five-step BART determination process, we note that a BACT 

determination is based almost exclusively on cost-effectiveness, and does not, for example, take 

visibility improvement at Class I areas into account.78 

One of the commenters noted that in IPM modeling performed in support of the CSAPR 

rulemaking, we used an SCR emission rate of 0.06 lb/MMBtu for certain retrofit coal-fired 

EGUs, stating that this was the most stringent emission rate assumed achievable for retrofit units.

It is important to note that IPM is a tool that operates using a large number of variables with 

values determined based upon a wide variety of assumptions. These assumptions, and the values 

upon which they are based, will necessarily change based upon the needs and context of the 

project or rulemaking for which IPM is used. It is therefore not appropriate to automatically 

consider a particular assumption or variable value (in this case, SCR emission rate) used in one 

application of IPM to represent a uniform standard or constraint against which all other uses of 

IPM should be compared.

In the case of the CSAPR rulemaking cited by the commenter, IPM was used to set statewide budgets for NOX based on assumptions that would be minimally achievable to a broad array 

of covered sources. The emission data and constraints fed into IPM therefore represented sectorwide modeling assumptions, which is a much different use and context than a BART 

determination, which must “take into account the most stringent emission control level” in order 

 

78 We note that a Class I area impact analysis must be performed by certain PSD projects as part of the permit 

application process. However, the visibility results are not used in the BACT determination, which is typically 

determined prior to performing the visibility modeling, and are not used to determine the appropriate level of control 

except in those cases where the visibility impact is sufficiently high to warrant mitigation measures that end up 

involving additional emission reductions. 
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to establish a source-specific emission limit. As a result, we disagree that the 0.06 lb/MMBtu 

assumption used in the CSAPR rulemaking should be construed to represent the most stringent 

emission control level for SCR.

Similarly, we also disagree that the recently promulgated NSPS Subpart Da represents 

the most stringent emission control level for SCR. First, we acknowledge that while the BART 

Guidelines state that “EPA no longer concludes that the NSPS level of controls automatically 

represents ‘the best these sources can install’”79 this was written in the context of older NSPS 

subparts with technology evaluations that could potentially be outdated and not representative of 

current pollution control technology performance. We also acknowledge that, while the BART 

Guidelines provide for “situations where NSPS standards do not require the most stringent level 

of available control for all sources within a category” and cite NSPS Subpart GG (stationary gas 

turbines) as a subpart that does not consider post-combustion controls,80 the recently 

promulgated NSPS Subpart Da does consider post-combustion controls such as SCR.81

Despite this language, however, we disagree with the commenter’s assertion that NSPS 

Subpart Da represents the most stringent emission control level for SCR, or that an NSPS 

Subpart, even a recently promulgated one, should be treated as a “floor” for establishing BART 

emission limits. While the BART Guidelines provide that, “you may rely on MACT standards 

for purposes of BART,”82 they do not indicate that the same is true for the NSPS standards. An 

NSPS standard must establish an emission rate that is appropriate for all the units within its 

category,

83

which in the case of Subpart Da includes a variety of boiler types, coal types, and 

baseline emission rates that may not be representative of the Apache, Cholla, and Coronado 

 

79 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.1, n. 13. 

80 Id. section IV.D.1. 

81 40 CFR Part 60, Subpart Da. 

82 Id. section IV.C. 

83 Or subcategories, which Subpart Da does not establish except for “new” and “modified” units 
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units. Specifically in the case of the RMB report, which was prepared for the San Juan 

Generating Station, the assertion that the Subpart Da standards represent the most stringent level 

of available control is undermined by the report’s findings that emission modeling indicates that 

the San Juan units could achieve NOX emission rates in the range of 0.047 to 0.068 lb/MMBtu, 

which are emission rates lower than the Subpart Da standards. 

Comment: Multiple commenters (AUG, APS, SRP) stated that EPA must consider 

presumptive BART limits. The commenters asserted that EPA cannot ignore presumptive BART 

limits because, as part of the BART Guidelines, they are binding regulatory presumptions that 

should only be deviated from based on a careful consideration of the BART factors (70 FR 

39171). 

EPA’s Proposed Rule, however, does not reflect any such consideration. Indeed, EPA’s 

Proposed Rule never even mentions the presumptive limits except to note that Arizona 

considered them. (77 FR 42,847). The nature of and basis for EPA-established presumptive NOX

BART limits for the relevant units at Apache, Cholla, and Coronado show that EPA’s 

determination in its proposed FIP that SCR -- a much more costly, post-combustion technology -

- represents BART at these facilities is, at least, presumptively incorrect. Because EPA failed to 

consider the presumptive limits in developing its proposed FIP’s BART limits for NOX, the 

Proposed Rule is flawed and must be withdrawn. 

The commenters also note that the RHR also established presumptive BART emission 

limits for NOX emissions from fossil fuel-fired units through notice-and-comment rulemaking. 

The presumptive NOX emissions limits for coal-fired EGUs vary according to individual source 

characteristics, including fuel firing configuration (tangential/wall-fired, opposed wall-fired, 

cyclone) and type of fuel burned (bituminous, sub-bituminous, lignite, etc.). Commenters also 
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argued that, because EPA shifted the baseline for BART, it did not include combustion controls, 

such as LNB, in its analysis, and only considered higher cost post-combustion controls (SNCR 

and SCR). 

Response: We disagree with the commenters’ assertions that we ignored the presumptive 

BART NOX limits. Because Apache, Cholla and Coronado all have access to and have 

historically burned both bituminous and sub-bituminous coal,84 there is no single presumptive 

NOX limit that applies to any of these units.85 Therefore, rather than rely upon the numerical 

values of the presumptive NOX limits listed in the BART Guidelines, we have considered the 

technological basis for presumptive NOX BART limits, such as the use of combustion control 

technology, boiler type, and coal type, as part of the five-factor analysis we performed for each 

facility. For each source, we considered combustion controls as a potential option for BART.86

We also disagree with commenters’ assertions that our selection of non-presumptive 

BART technology as BART is flawed or presumptively incorrect. In the BART Guidelines EPA 

explained that: 

For coal-fired EGUs greater than 200 MW located at greater than 750 MW power plants 

and operating without post-combustion controls (i.e. SCR or SNCR), we have provided 

presumptive NOX limits, differentiated by boiler design and type of coal burned. You 

may determine that an alternative control level is appropriate based on a careful 

consideration of the statutory factors. For coal-fired EGUs greater than 200 MW located 

at power plants 750 MW or less in size and operating without post-combustion controls, 

you should likewise presume that these same levels are cost-effective. You should require 

such utility boilers to meet the following NOX emission limits, unless you determine that 

an alternative control level is justified based on consideration of the statutory factors.87

 

84 See, e.g., Final Report, Apache Unit 2 BART Analysis, Table 3-1 (December 2007); Cholla Unit 2 BART Report, 

page ES-2; SRP Comments on Proposed Rule (September 2012), RMB Technical Memorandum, page 3. 

85 See BART Guidelines, 40 CFR Part 51, Appendix Y, Table 1. 

86 At Apache Units 2 and 3, we considered combustion controls (LNB plus OFA) as one of the control scenarios. At 

Cholla and Coronado, combustion controls were considered as part of the baseline emission rate and were a 

potential BART option in the event that the five-factor analysis indicated that no additional controls beyond the 

baseline were justified. 

87 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.5. 
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Therefore, the presumptive emission limits in the BART Guidelines are rebuttable, and the five 

statutory factors enumerated in the BART Guidelines provide the mechanism for establishing 

different requirements. Specifically, as explained in the preamble to the BART Guidelines: 

If, upon examination of an individual EGU, a State determines that a different emission 

limit is appropriate based upon its analysis of the five factors, then the State may apply a 

more or less stringent limit. 

88

Thus, the establishment of presumptive BART limits, and the corresponding technology upon 

which those limits are based, does not preclude states or EPA from setting limits that differ from 

those presumptions. The five-factor analysis we performed for these facilities demonstrates that, 

taking into consideration the expected remaining useful life and the existing controls present at 

the facilities, SCR is cost-effective, results in the most visibility improvement of all feasible 

control technologies, and that these factors are not outweighed by SCR’s potential energy and 

non-air quality environmental impacts. As a result, regardless of the appropriateness of SCR as a 

control technology for most units on a national scale, our five-factor analyses establish that NOX

BART limits more stringent than the presumptive limits are appropriate for these units. 

 3. Costs of Compliance 

Comment: Several commenters stated that EPA inappropriately conducted its cost 

analysis using generalized data and a regional model, whereas the CAA requires a BART 

determination to be based, in part, on a site-specific cost evaluation. One commenter (Navajo 

Nation) stated that EPA should justify its use of the IPM and explain why it did not use or 

request line item costs from the facilities to make its analysis more site-specific. This commenter 

also stated that EPA’s reliance on the IPM is misplaced because the model integrates healthbased regulations and not the RHR. 

 

88 70 FR 39132.
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Another commenter (SRP) added that the proposed rule and the TSD say almost nothing 

about how IPM was used to calculate costs, instead directing the public to an EPA contractor 

report for more information. The commenter asserted that no contractor report in the docket for 

the rulemaking supplies additional detail on precisely how IPM was used. The commenter 

believes that this failing renders EPA’s proposed rule inconsistent with the CAA’s public notice 

requirements. 

Response: As described in our proposal, the IPM is a multi-regional linear programming 

model of the U.S. electric power sector. IPM relies upon a very large number of data inputs and 

provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control 

strategies for meeting energy demand and environmental, transmission, dispatch, and reliability 

constraints. EPA has used IPM to evaluate the cost and emissions impacts of proposed policies, 

such as the recent Mercury and Air Toxics Standard (MATS) to limit pollutant emissions from 

the electric power sector. 

We wish to clarify that, for our proposed action on Arizona’s Regional Haze SIP, we did 

not actually run IPM. Rather, we used one component of IPM, specifically, the component that 

develops the costs of air pollution control technologies. Broadly speaking, IPM relies upon 

numerous components and sub-components to specify constraints and variable values that feed 

into the model algorithms used during an actual IPM model run. The air pollution control cost 

development component is just one of these numerous components. We relied upon the cost 

information and equations contained in this component by manually placing them into a 

spreadsheet that calculated the capital and O&M costs associated with pollution control options. 

While we relied upon the results of these spreadsheet calculations, we did not then use those 

results to run IPM, as the type of information generated by an actual IPM model run (e.g., 
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generation dispatch decisions, capacity decisions) is not relevant to our action. We documented 

our use of the equations from IPM’s air pollution control technology cost component by placing 

the raw cost calculation spreadsheet in the docket for our proposal.89 This spreadsheet contained 

the IPM equations, corresponding variable values, selected notes regarding assumptions and 

variable ranges as well as selected tables from IPM Base Case v4.10 documentation. Since we 

did not perform an actual IPM model run, the spreadsheet and contractor’s report in the docket 

for our proposal sufficiently document our use of the cost methodologies from the IPM air 

pollution control cost component. 

We disagree with commenters’ characterization of the cost development methodology 

contained in IPM as generalized or outdated. As noted in the documentation for IPM’s cost 

development methodology for SCR, the cost estimate methodology is based upon two databases 

of actual SCR projects.90 These databases include 2004 and 2006 industry cost estimates 

prepared for the Midwestern Ozone Group (MOG), and a proprietary in-house database 

maintained by engineering firm Sargent & Lundy (S&L). The MOG information was crossreferenced with actual 2009 projects, and escalated accordingly. S&L then used the information 

in these databases to develop the equations described in the cost component taking into account 

the pre-control NOX emission level, degree of reduction, coal type, facility size, and numerous 

other unit-specific factors. While a costly engineering evaluation that included site visits would 

potentially produce a more refined cost estimate that could be considered more site-specific than 

our own, we disagree that our approach has produced cost estimates that are either “generic” or 

“generalized.” 

 

89 Document ID: EPA-R09-OAR-2012-0021-0008, File name: G15_MODELING_FILES_EGU_BART_Costs_Apache_Cholla_Coronado_FINAL2 

90 http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix52A.pdf
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Comment: Several commenters contended that where specific knowledge is available, the 

CCM is oriented to allow and provide for the use of such information. The commenters also note 

that the RHR explicitly provides that the cost analysis should take into account any site-specific 

information that affect the costs of a particular BART technology option, and the Corn Growers

court explained that BART determinations must be made on a source-specific basis. 

Response: While we agree that BART determinations must be made on a source-specific 

basis, we do not agree that site-specific information is required for all aspects of a BART 

analysis. Nonetheless, in order to address commenters’ concerns that our proposal was based on 

cost information that was insufficiently site-specific and that the costs of the SCR with LNB and 

OFA control option, in particular, are not representative of actual installation costs at these 

facilities, we have performed a supplemental cost analysis. The supplemental cost analyses for 

each facility are described in Section IV.D of this document, and incorporate much of the cost 

information provided by the facilities in their comments. In performing this supplemental cost 

analysis, we have adopted a “hybrid” approach that relies on cost estimates provided by the 

facilities for certain line items, but still retains the use of the CCM methodology as described in 

the following response. 

Comment: Several commenters stated that EPA’s cost estimating techniques are flawed 

and its reliance on the outdated EPA CCM led to underestimates of costs. Several of these 

commenters noted that EPA claimed that owner’s costs, surcharges and Allowance for Funds 

Used During Construction (AFUDC) are not allowed by EPA’s CCM and refute that these costs 

are not allowed by the Manual. The commenters state that while the Manual does not have 

specific line items for owner’s costs and surcharges, it discusses some of the items that roll up 

into these categories. APS, for example, states that: 
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Owner’s costs are home office and plant support costs that are charged directly to 

specific projects. These would include costs related to project management, 

engineering, construction support, start-up, training, etc. Surcharges are home 

office costs associated with a project that may not be charged directly to that 

project. These costs would be related to overhead loads, procurement, accounting, 

finance, etc.91 

APS also notes that there is a line item for AFUDC in the Manual but provides that it is 

assumed to be zero percent, but that in its experience AFUDC is a real cost and is never 

zero percent. In addition, the commenters state neither the CAA nor the BART 

Guidelines require the Manual to be used to determine the costs of compliance. 

Response: With regard to owner’s costs and surcharges, we agree with commenters’ 

assertions that the CCM does discuss some of the items that roll up into these line items as they 

have described in comments. For the control option of SCR with LNB and OFA, for example, 

the CCM does provide for “Engineering and Home Office Fees” 92 that could potentially include 

some of the home office and plant support costs described in comments. These types of costs are 

often included in estimates under some type of engineering/procurement/project services line 

item. In the case of the cost estimates provided by the utilities (both those submitted to ADEQ as 

part of the original BART analysis, and those submitted to us in comments on our proposal), we 

note that their cost estimates are not organized to list line item(s) that clearly correspond to 

“Engineering and Home Office Fees,” and do not provide information indicating where these 

costs may be included. As a result, while owner’s costs and surcharge are not line items included 

in the CCM, in this instance, as a conservative assumption, we have included the portion of 

owner’s costs/surcharge in the total cost, up to the value specified for “Engineering and Home 

Office Fees” indicated by the CCM. 

 

91 APS comments, page 12. 

92 As described in Table 2-5 of the CCM, Engineering and Home Office Fees represent 10 percent of purchased 

equipment costs. 
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We disagree with commenters’ assertions that AFUDC is a cost that should be 

incorporated into our cost analysis, as it is inconsistent with CCM methodology. The utility 

industry uses a method known as “levelized costing” to conduct its internal comparisons, which 

is different from the methods specified by the CCM. Utilities use “levelized costing” to allow 

them to recover project costs over a period of several years and, as a result, realize a reasonable 

return on their investment. The CCM uses an approach sometimes referred to as overnight 

costing, which treats the costs of a project as if the project were completed “overnight”, with no 

construction period and no interest accrual. Since assets under construction do not provide 

service to current customers, utilities cannot charge the interest and allowed return on equity 

associated with these assets to customers while under construction. Under the “levelized costing” 

methodology, AFUDC capitalizes the interest and return on equity that would accrue over the 

construction period and adds them to the rate base when construction is completed and the assets 

are used. Although it is included in capital costs, AFUDC primarily represents a tool for utilities 

to capture their cost of borrowing and return on equity during construction periods. AFUDC is 

not allowed as a capitalized cost associated with a pollution control device under CCM’s 

overnight costing methodology, and is specifically disallowed for SCRs (i.e., set to zero) in the 

CCM.93 Therefore, in reviewing other BART determinations, EPA has consistently excluded 

AFUDC.94 

Comment: The ACCCE notes that the Manual specifically states that it does not directly 

address the controls needed to control air pollution at EGUs, citing the following quote from the 

Control Cost Manual: 

 

93 CCM (Tables 1.4 and 2.5 show AFUDC value as zero) 

94 See, e.g., 77 FR 20894, 20916-17 (Apr. 6, 2012) (explaining in support of the North Dakota Regional Haze FIP, 

“we maintain that following the overnight method ensures equitable BART determinations . . . .”); 76 FR 52388, 

52399-400 (August 22, 2011) (explaining in the New Mexico Regional Haze FIP that the Manual does not allow 

AFUDC). 
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... this Manual does not directly address the controls needed to control air 

pollution at electrical generating units (EGUs) because of the differences in 

accounting for utility sources. Electrical utilities generally employ the EPRI 

Technical Assistance Guidance (TAG) as the basis for their cost estimation 

processes. 

Response: We disagree with the commenter’s assertion that the CCM does not address 

control costs needed to control air pollution at EGUs. The quote cited by the commenter contains 

a footnote that reads as follows: 

This does not mean that this Manual is an inappropriate resource for utilities. In 

fact, many power plant permit applications use the Manual to develop their costs. 

However, comparisons between utilities and across the industry generally employ 

a process called “levelized costing” that is different from the methodology used 

here. 

95

The quote is merely a factual observation that electric utilities, in their planning and cost 

estimating for their own purposes, use a different accounting method than required by the CCM. 

The footnote clarifies that the CCM is appropriate for utilities for regulatory purposes. 

 4. Energy and Non-air Environmental Impacts 

Comment: One commenter (ADEQ) stated that EPA should consider the costs associated 

with fly ash ammonia removal in selecting BART. Further, additional problems during disposal 

of fly ash may cause environmental damage and should not be discounted. 

Response: EPA disagrees with this comment. First, we note that ammonia adsorption in 

the fly ash is expected to be minimal from SCR because excess ammonia would likely react with 

sulfuric acid to form particulate ammonium sulfate or ammonium bisulfate, which would not 

pose the same odor problem in fly ash reuse as adsorbed ammonia. Second, the facilities’ own 

BART analyses did not include costs of fly ash disposal or ammonia removal in the cost 

estimates for SCR, which indicates that they do not consider these potential costs to be 

 

95 EPA Air Pollution Cost Control Manual, Sixth Edition page 1-3. 
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significant. Finally, we note that the Arizona Department of Transportation has designated fly 

ash from each of the three sources as approved material.96 As explained in our proposed 

rulemaking and the accompanying TSD, the presence of ammonia does not impact the integrity 

of the use of fly ash in concrete.97 Therefore, we have no information that suggests that 

installation of SCR would result in a change to the facilities’ current fly ash disposal and re-use 

practices. 

Comment: One commenter (SRP) stated that EPA downplayed the energy and non-air 

quality factor its revised BART determination in the proposed FIP, presenting the narrow 

conclusion 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. The commenter asserted 

that this narrow consideration of this factor is not tenable because this factor must be weighed 

and considered in conjunction with the other BART factors in the overall assessment of what 

control option constitutes BART for a particular source. The commenter believes that EPA’s 

approach minimizes the role of this factor in a BART analysis, which is beyond EPA’s 

authority.

98

 

Response: EPA does not agree with this comment. The RHR and the BART Guidelines 

allow the reviewing authority (State, Tribe, or EPA) the discretion to determine how to weigh 

and in what order to evaluate the statutory factors (cost of compliance, the energy and non-air 

quality environmental impacts of compliance, any existing pollution control technology in use at 

the source, the remaining useful life of the source, and the degree of improvement in visibility 

which may reasonably be anticipated to result from the use of such technology), as long as the 

 

96 Approved Materials Source List, Fly Ash, Natural Pozzolan, and Lime, Revised July 10, 2012, available at 

http://www.azdot.gov/Highways/Materials/

97 See 77 FR 42853-4284, TSD at 38. 

98 Citing Corn Growers, 291 F.3d at 6‐7 (finding that EPA’s original 1999 regional haze rules had improperly 

divorced consideration of the BART visibility benefits factor from the other BART factors). 
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reviewing authority justifies its selection of the “best” level of control and explains the CAA 

factors that led the reviewing authority to choose that option over other control levels.99 In this 

case, having disapproved the state’s BART determinations for NOX at several units, “all of the 

rights and duties that would otherwise fall to the State accrue instead to EPA.”100 This includes a 

significant degree of discretion in deciding how to weigh the five factors, so long as that 

weighing is accompanied by reasoned explanation for adopting the technology selected as 

BART, based on the five factors, and in accordance with the BART Guidelines. EPA has 

provided a detailed explanation of our BART evaluation process and five-factor analyses in our 

proposal, TSD and elsewhere in this document. We have weighed the potential energy and 

non‐air environmental quality impacts of the various control options along with the other 

statutory factors in our BART analyses and have concluded that impacts do not warrant 

elimination of any of the otherwise feasible control options for NOX at any of the sources. 101

 5. Remaining Useful Life of the Source 

Comment: One commenter (APS) did not dispute EPA’s assumption of a twenty-year 

useful life of the emission control equipment in its annualized cost calculations. 

Response: EPA agrees with the commenter that this is an appropriate assumption for 

these sources. 

 6. Degree of Improvement in Visibility 

Comment: One commenter (NPS) agreed with EPA that a more complete assessment of 

visibility improvement for candidate BART controls would include consideration of the number 

of areas affected and the degree of improvement expected at all Class I areas rather than focusing 

on a single area. The commenter commended EPA for its reliance on deciview improvement and 

 

100 Central Arizona Water Conservation Dist. v. EPA, 990 F.2d 1531, 1541 (9th Cir. 1993).

101 See 77 FR 42853-4284, TSD at 38. 
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the number of areas showing improvement, plus its consideration of cumulative improvement, 

which provides a supplemental measure that combines information on the number of areas and 

on individual area improvement. 

In contrast, several commenters (ADEQ, AEPCO, APS and AUG) disagreed that EPA’s 

new visibility metric, “cumulative visibility improvement,” is an appropriate metric, asserting 

that this metric incorrectly inflates the estimated visibility improvements of various control 

options and should not be used. The commenters further stated that this metric does not appear 

anywhere in the CAA, RHR or BART Guidelines, and that these rules and guidelines specifically 

give discretion to states to determine how to take into account visibility impacts in a BART 

evaluation. In addition, the RHR (at 70 CFR 39170) supports identifying the single Class I area 

that would have the greatest visibility effects from emission controls and does not support adding 

improvements from multiple Class I areas in determining visibility effects. The commenters 

affirmed that EPA should use a change in deciview at the Class I area with the highest impact as 

its visibility metric, consistent with EPA’s RHR and the method used by other EPA regions and 

states. 

The commenters further stated that to be relevant to the environmental effect that the 

regional haze program addresses, the metric by which visibility improvement is determined for 

purposes of assessing BART for a particular facility must reflect actual human perception of 

visibility. The commenters added that the cumulative impact approach used by EPA has no tie to 

human perception and can only distort a BART analysis. The commenters believe that this 

approach arbitrarily magnifies the benefit that might be associated with emission limitations at a 

single source. 
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Response: EPA agrees with NPS on the need to consider visibility improvements at all 

the nearby Class I areas as part of a comprehensive assessment of the degree of visibility 

improvement due to BART controls. EPA disagrees with some other commenters that 

cumulative improvement over multiple areas is an inappropriate metric, or that examining a 

single Class I area is sufficient. The cumulative improvement metric (i.e., the simple sum of 

impacts or improvements over all the Class I areas) is not intended to correspond to a single 

human’s perception at a given time and place. The approach is simply one way of assessing 

improvements at multiple areas, for consideration along with other visibility metrics. Another 

approach would be to simply list visibility improvements at the various areas, and qualitatively 

weigh the number of areas and the magnitudes of the improvements. The cumulative sum is 

simply an easily understood and objective way of weighing cumulative visibility improvement, 

as part of the overall BART decision. 

Comment: One commenter performed NO2 modeling by scaling tropospheric column 

NO2 derived from satellite measurements, as portrayed in imagery from the Institute of 

Environmental Physics, University of Bremen, Germany. The commenter states that SCR would 

reduce NO2 closer to background levels. 

Response: While the facilities considered for BART control are not the only NOX sources 

in the area, the commenter’s scaling of the concentrations in the satellite images according to the 

reductions expected from SCR can give a rough idea of its NO2 benefit. However, to assess 

visibility impacts, the model used must account for the formation of visibility-impairing 

ammonium nitrate particles. Under the BART Guidelines, CALPUFF is the recommended model 

that incorporates this nitrate chemistry. Alternative models could potentially be used if they had 
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the ability to handle this and other chemical transformations and had undergone a rigorous 

performance evaluation. 

Comment: One commenter (NPS) commended EPA for the thoroughness of its visibility 

modeling analyses and the methodologies used. The commenter noted that EPA used CALPUFF 

methods 6 and 8 and modeled against annual average and 20 percent best natural background 

conditions. The commenter also pointed out that EPA modeled all pollutants while varying NOX

emissions to evaluate the effects of changing this one pollutant. 

Response: EPA acknowledges the comment. It was our intention to estimate visibility 

impacts accurately and transparently so that one could more easily compare results to earlier 

applications of CALPUFF and clearly understand the effect of old versus revised IMROVE 

equations (methods 6 and 8) as well as alternative natural background conditions. We modeled 

all pollutants together in order to account for chemical interactions among the various pollutants 

and also the nonlinear dependence of deciviews upon extinction.

Comment: One commenter (APS) stated that EPA’s proposal noted that it is appropriate 

to use Method 6a, 6b, 8a or 8b in CALPOST within the CALPUFF model, yet EPA 

inappropriately rejected ADEQ’s use of Method 6a in its own analysis and instead used Method 

8b, which yielded higher predicted visibility improvements in Class I areas. 

Response: EPA did not reject ADEQ’s use of visibility method 6a, which remains a 

viable method for past visibility modeling work under an agreed upon protocol. Method 6a 

comprises CALPOST Method 6, the old IMPROVE equation for translating pollutant 

concentration into visibility impacts, and annual average (the “a”) natural background 

concentrations. However, for new visibility modeling, such as EPA performed for the FIP, 

method 8b is preferable. Method 8b comprises CALPOST Method 8, the revised IMPROVE 
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equation, and best 20 percent of days (the “b”) natural backgrounds. The revised IMPROVE 

equation has superior performance for assessing visibility, and is recommended by the Federal 

Land Managers for regional haze assessments performed for New Source Review permitting.102

EPA believes that using the best 20 percent of days as a basis for background concentrations is 

desirable since visibility impacts due to emissions from facilities are most noticeable on the best 

days, that is, most visible to visitors of Class I areas. EPA assessed the results of both methods 

(and also the “6b” and “8a” combinations), but primarily relied on 8b as the most appropriate 

method in the BART context. 

Comment: One commenter (APS) objected to EPA shifting the CAA’s mandate to 

compare costs and benefits under the BART program to an assessment of “cost-effectiveness” 

($/ton) without specifying the threshold level of what is cost-effective. APS also noted that in the 

absence of a specific threshold for cost-effectiveness, the FLMs have referred to a benchmark of 

$20 million per deciview as the upper limit. The commenter also presented data showing the 

incremental costs of going from LNB/OFA to SNCR or SCR to be over $20 million per deciview 

for Cholla. 

Response: The commenter is correct that the BART Guidelines list the $/deciview ratio 

as an additional cost-effectiveness metric that can be employed along with $/ton for use in a 

BART evaluation, and we have included this information in our proposal. While the FLMs have 

indicated that they consider $20 million/dv to be a benchmark for average cost-effectiveness, we 

note that the BART Guidelines do not require the development of a specific threshold. The 

BART Guidelines, however, require that cost-effectiveness be calculated in terms of annualized 

 

102 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. 

http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf 
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dollars per ton of pollutant removed, or $/ton.103 We considered cost of controls by discussing 

the total capital costs, annual costs, $/ton, and incremental $/ton, and considered the degree of 

visibility improvement by discussing the individual and cumulative deciview improvement 

resulting from the various control technology options, as well as the percent change in 

improvement. Our consideration of other metrics in addition to $/dv in no way relegates 

visibility improvement to a secondary role. Finally, we note that the FLMs’ recommended 

“benchmarks” for dollars per deciview are for average dollars per deciview not incremental

dollars per deciview.

104 Neither the BART Guidelines nor the FLMs recommend consideration 

of incremental dollars per deciview. 

Comment: One commenter (NPS) cautioned against any implication in EPA’s analyses 

that visibility improvement must exceed 0.5 dv to be significant. The commenter believes that 

such an approach would be contrary to the BART Guidelines. 

Response: EPA agrees that the 0.5 dv threshold for “contribute to visibility impairment” 

is only for the initial Subject-to-BART screening test and it is a maximum even for that purpose, 

according to the BART Guidelines.105 Smaller improvements from controls should be considered 

in BART determinations, since they can be beneficial in considering effects from controls on 

multiple sources.106 We have used the 0.5 dv level simply as one point of comparison, a 

“benchmark” or “yardstick,” to gauge the magnitude of impacts under various control scenarios. 

Comment: Several commenters (APS, AUG, Navajo Nation, PacifiCorp and SRP) 

asserted that EPA’s proposed NOX BART determination rests on a flawed assessment of 

 

103 BART Guidelines section IV.D.4.c. 

104 See, e.g. National Park Service Comments on Best Available Retrofit Technology for Apache, Cholla, and 

Coronado Power Plants in Arizona (September 17, 2012) at 6. 

105 BART Guidelines, 40 CFR Part 51, Appendix Y, section III.A.1 (“As 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.”) 

106 See, e.g. 70 FR 39129 (“Even though the visibility improvement from an individual source may not be 

perceptible, it should still be considered in setting BART because the contribution to haze may be significant 

relative to other source contributions in the Class I area.”)
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visibility impacts. The commenters made the following arguments to support their contention 

that EPA’s modeling overestimates the visibility benefits associated with BART control options. 

First, EPA used an outdated version of the CALPUFF model (version 5.8) that over‐predicts 

visibility benefits. Based on citations provided by the commenters, CALPUFF version 6.42 has 

been shown to provide better agreement with observed levels of nitrates. The commenters 

provided modeling results using CALPUFF version 6.42 for EPA’s consideration. Second, 

EPA’s outdated use of constant ammonia background concentration of 1.0 ppb over‐predicts 

visibility benefits and fails to account for known monthly or seasonal variations. EPA 

inappropriately rejected ADEQ’s use of variable background concentrations, which was well 

within the state’s discretion. Several of these commenters also noted that a case study107 by 

Terhorst and Berkman based on the 2005 closure of the Mohave Generating Station found 

virtually no evidence that closure resulted in improved visibility at the Grand Canyon. In 

addition, SRP stated that EPA must consider visibility benefits from NOX controls within the 

context of nitrate contributions to regional haze. Studies of visibility impairment on the Colorado 

plateau show that nitrate aerosols contribute only two to five percent to haze. 

Response: EPA disagrees with the commenters that any new CALPUFF version should 

be used for the BART determination. EPA relied on version 5.8 of CALPUFF because it is EPAapproved version in accordance with the Guideline on Air Quality Models (“GAQM”, 40 CFR 

51, Appendix W, section 6.2.1.e). 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. CALPUFF version 5.8 has been thoroughly tested and evaluated, and has been shown to 

 

107 Terhorst, Jonathan and Berkman, Mark, “Effect of Coal-fired Power Generation on Visibility in a 

Nearby National Park”, Atmospheric Environment 44, 2524, 2530 (Apr. 2010). 
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perform consistently with the initial 2003 version in the analytical situations for which 

CALPUFF has been approved. Any other version, and especially one with such fundamental 

differences in its handling of chemistry, would be considered an “alternative model”, subject to 

the provisions of GAQM section 3.2.2(b), requiring full model documentation, peer-review, and 

performance evaluation. No such information for the later CALPUFF versions that meet the 

requirements of section 3.2.2(b) has been submitted to or approved by EPA. Experience has 

shown that when the full evaluation procedure is not followed, errors that are not immediately 

apparent can be introduced along with new model features. For example, changes introduced to 

CALMET to improve simulation of over-water convective mixing heights caused their periodic 

collapse to zero, even over land, so that CALPUFF concentration estimates were no longer 

reliable. 108 

The change from CALPUFF version 5.8 to CALPUFF 6.4 is not a simple model update 

to address minor issues, but a significant change in the model science that requires its own 

rulemaking with public notice and comment before it can be relied on for regulatory purposes. 

Furthermore, it should be noted that the US Forest Service and EPA review of CALPUFF 

version 6.4 results for a limited set of BART applications showed that differences in its results 

from those of version 5.8 are driven by two input assumptions not associated with the chemistry 

changes in 6.4. Use of the so-called “full” ammonia limiting method and finer horizontal grid 

resolution are the primary drivers in the predicted differences in modeled visibility impacts 

between the model versions. These input assumptions have been previously reviewed by EPA 

and the FLMs and have been rejected based on lack of documentation, inadequate peer review, 

and lack of technical justification and validation. 

 

108 “CALPUFF Regulatory Update”, Roger W. Brode, Presentation at Regional/State/Local Modelers Workshop, 

June 10–12, 2008; http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2008/agenda.htm 
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Introducing a new regulatory model is a long process. EPA intends to conduct a 

comprehensive evaluation of the latest CALPUFF version along with other “chemistry” air 

quality models, including a full statistical performance evaluation, verification of its scientific 

basis, and determination of whether the underlying science has been incorporated into the 

modeling system correctly. To accommodate such a model, there would have to be an 

evaluation of the effect on the regulatory framework for its use, including in New Source Review 

permitting, and also changes to the Guideline on Air Quality Models and other modeling 

guidance, in consultation with the FLMs. CALPUFF version 5.8 has already gone through this 

comprehensive evaluation process and remains EPA-approved version, and is thus the 

appropriate version for EPA’s BART determinations of these facilities. 

The ammonia issue has already been addressed above. EPA believes that there is no 

compelling alternative to the use of the default 1 ppb background concentration. 

The Terhorst & Berkman study cited by the commenter is worthy of consideration as the 

Regional Haze program evolves, but one study does not invalidate CALPUFF, which has had 

multiple performance evaluations and has gone through public comment and rulemaking. It also 

does not remove the legal requirement to perform BART determinations for eligible facilities. 

While nitrate appears to be a smaller contributor to visibility impairment than some other 

compounds, section 169A of the Clean Air Act requires BART determinations on BART-eligible 

EGUs regardless of ambient visibility conditions. Application of BART is one means by which 

we can ensure the continuation of downward emission and visibility impairment trends. 

Modeling shows maximum visibility impacts of 1.2 to 4.5 deciviews depending on the facility, 

which are not negligible contributions to visibility impairment. Even if an individual pollutant or 

source category appears small to some commenters, the many segments of the emissions 
Page 84 of 244

inventory taken together do cause visibility impairment, and each must be addressed in order to 

make progress towards the national goal of remedying visibility impairment from man-made 

pollution. EPA identifies stationary sources as an important category to evaluate under the 

Regional Haze program, including a BART analysis. 

Comment: Several commenters argued that the proposed FIP is inconsistent with the goal 

of the RHR, which is to make progress toward natural visibility conditions by the year 2064. 

Another commenter added that Arizona’s energy providers have already invested time and 

money (hundreds of millions of dollars) in order to reach the long-term goal of achieving natural 

background visibility by 2064, and that the accelerated timeline proposed by the rule would 

result in astronomical costs. Another commenter stated that EPA is front-loading as many 

emission reductions as possible in the first five years of this program, while ignoring other 

causes of visibility impairment, such as fires, in its FIP. Other commenters suggested that 

Arizona’s haze is produced by a number of environmental factors, like pollution from wildfires, 

garbage burning along the Mexico/US border, and dust storms. 

Response: We do not agree that we are front-loading emission reductions or that we have 

lost sight of the “end goal.” While the goal of the regional haze program is to achieve natural 

visibility conditions in all mandatory Class I Federal areas by 2064, the requirement for states to 

implement BART applies only during the first planning period ending in 2018.109 Where a State 

has not met the RHR requirements related to BART, EPA is obligated to disapprove that portion 

of the State’s submittal. And, as explained elsewhere in this document, because the FIP clock has 

already expired for the Arizona Regional Haze plan, we are required to promulgate a FIP for any 

disapproved portion of the SIP. Our action fulfills part of this duty. 

 

109 See 40 CFR 51.308(f) (future Regional Haze plans must address reasonable progress and long-term strategy, but 

not BART). 
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We agree that there are various other factors that contribute to haze at Arizona’s Class I 

areas. However, these other factors are not relevant to the BART requirements, which govern 

today’s action. Under the RHR, causes of haze other than BART sources are addressed under 

separate requirements for reasonable progress and a long-term strategy. We will address the 

remaining requirements of the RHR for the first implementation period in Arizona, including 

requirements for reasonable progress toward the 2064 goal, in a separate rulemaking action. 

 D. Source-specific Comments on EPA’s BART Analyses and Determinations 

 1. EPA’s BART Analysis and Determination for NOX at Apache Units 2 and 3 

 a. Control Efficiencies 

Comment: Various commenters (ADEQ, AEPCO and AUG) asserted that EPA’s 

proposed BART determination for Apache Units 2 and 3 was premised on the assumption that 

SCR can achieve an emission limit of 0.050 lb/MMBtu continuously on a 30‐day rolling average, 

including periods of startup, shutdown and equipment malfunctions, but that this limit has not 

been shown to be feasible. They argued that EPA had failed to support either its proposed BART 

determination or its reliance on this limit in its BART analysis. In addition, AEPCO and AUG 

stated that EPA inappropriately relied on vendor information to support an emission rate of 0.050 

lb/MMBtu using SCR. AEPCO also noted that it considered this support anecdotal and stated 

that it cannot form the basis for a BART determination, as BACT rules expressly provide that 

EPA does “not consider a vendor guarantee alone to be sufficient justification that a control 

option will work.” AEPCO requested that if EPA retains the SCR limits, that they be set at 0.07 

lb/MMBtu due to the infeasibility of complying with a lower limit at the Apache station. Also, 

due to the load-following and cycling nature of the units and the need to accommodate startups 

and shutdowns, AEPCO requested that any lower limits be set as an annual average limit. 
Page 86 of 244

Response: We partially agree with this comment. In our proposal, our analysis was based 

on an SCR annual average design value of 0.050 lb/MMBtu, which was subsequently proposed 

as a rolling 30-day average emission limit. We disagree that our use of 0.050 lb/MMBtu as an 

annual average design value is merely anecdotally supported or based on vendor 

literature/guarantees alone. As discussed in our proposal, the ability of SCR to achieve control 

efficiencies in the range of 80 to 90 percent is well established. Although the information 

included in our proposal did include vendor estimates, it also included summaries of SCR control 

efficiencies that were achieved in practice. We have further supplemented the record to include 

more recent examples illustrating that SCR, as a technology, is capable of achieving control 

efficiencies in the range of 80 to 90 percent. For the Apache units, an annual average emission 

rate of 0.050 lb/MMBtu represents 87 to 89 percent control. While these values represent the 

upper range of SCR control and are more stringent than the control efficiencies used in the 

BART analyses prepared by AEPCO,110we reaffirm that these values are appropriate, given that 

they are still within the range of what is achievable with SCR and that the Apache units are 

among the highest baseline NOX emission rate units considered in our proposal. We agree with 

the commenter that, when establishing a 30-day rolling average BART emission limit that would 

apply at all times, it is appropriate to accommodate emissions associated with startup and 

shutdown events in developing the emission limit. SRP raised similar concerns in comments on 

Coronado 1 and 2. As discussed in more detail in our responses on Coronado, SRP submitted 

information suggesting that the Coronado units cannot achieve an SCR emission rate of 0.050 

lb/MMBtu on a rolling 30-day average and could only achieve in the range of 0.053 to 0.072 

 

110 See Docket Items B-03 and B-04, Appendix A. AEPCO’s calculations are based on 83-85 percent SCR control 

efficiency, and 24-hour average emission rates of 0.07 lb/MMBtu 
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lb/MMBtu.

111

 We have reviewed the analyses provided by SRP and note that while the results of 

SRP’s analysis indicate that Coronado could meet a 0.050 lb/MMBtu limit on an annual average 

basis,

112

we agree that the Coronado units cannot achieve an SCR emission rate of 0.050 

lb/MMBtu on rolling 30-day average. As a result, we conclude that 0.050 lb/MMBtu is 

appropriate as annual average design value, but not as 30-day rolling average emission limit at 

the Coronado units. While we acknowledge that Apache 2 and 3 are not identical to the 

Coronado units, we do note the following similarities:

• Both the Apache and Coronado units are of the same boiler type (Riley turbo). 

• Both the Apache and Coronado units were constructed and placed into operation at 

approximately the same time. Construction commenced on the Apache units in 1976, and 

they were placed into operation in 1979. The Coronado units were placed into operation 

in 1979 and 1980. 

• Both the Apache and Coronado units have access to, and could potentially use, a 

bituminous and sub-bituminous coal blend.113

• Although the historical operating profiles of the Apache and Coronado units are not 

identical, both the Apache and Coronado units are cycling units that exhibit a greater 

number of startup and shutdown events than baseload units. 

Based on these similarities, we similarly conclude that the Apache units cannot achieve 

an SCR emission rate of 0.050 lb/MMBtu on a rolling 30-day average, but that use of 0.050 

lb/MMBtu as an annual average design value is appropriate. We agree that when establishing a 

 

111 As discussed in further detail in the responses on Coronado, this range of values corresponds to an SCR unit 

designed to operate during all periods of normal operation and loading conditions 

112 As discussed in further detail in the responses on Coronado, this is specifically in regards to Coronado Unit 1. 

113 The Apache units have access to a number of bituminous and sub-bituminous coal blends. See, e.g., Final Report, 

Apache Unit 2 BART Analysis, Table 3-1 (December 2007). While the Coronado units currently burn 100 percent 

sub-bituminous Powder River Basin coal, they have historically burned a mixture of PRB with bituminous coal. See 

SRP Comments on Proposed Rule (September 2012), RMB Technical Memorandum, page 3. 
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rolling 30-day BART emission limit that is based upon an annual average design value, it is 

appropriate to provide a compliance margin for periods of startup and shutdown. In addition to 

considering the boiler type, age of the units, and coal type to which Apache has access, we also 

note that AEPCO meets the definition of “small entity” as established for electric utility 

companies by the U.S. Small Business Administration.

114 We considered AEPCO’s small entity 

status115 and how to provide AEPCO with operational flexibility consistent with application of 

the five-factor BART analysis. Based on these considerations, we have decided to raise the 

rolling 30-day average emission limit from the proposed level of 0.050 lb/MMBtu to 0.070 

lb/MMBtu. A rolling 30-day average of 0.070 lb/MMBtu represents an upward revision of 40 

percent from an annual average design value of 0.050 lb/MMBtu and corresponds to the upper 

end of the range of lb/MMBtu values considered achievable by SRP’s analysis. We consider this 

magnitude of upward revision appropriate to accommodate emissions from startup and shutdown 

events, as well to provide AEPCO a sufficient measure of operational flexibility as a small 

entity. In addition, in response to comments requesting that emission limits be established across 

units,116 consistent with the BART Guidelines,117we have decided to set the emission limit as a 

“bubble” limit across Apache Units 2 and 3. We are therefore finalizing a 30-day rolling average 

 

114 As noted in our NPRM (77 FR 42867) 

115 See EPA's Action Development Process, Final Guidance for EPA Rulewriters: Regulatory Flexibility Act as 

amended by the Small Business Regulatory Enforcement Fairness Act, November 2006, at 3. This EPA guidance 

document states that prior to the enactment of the Small Business Regulatory Enforcement Fairness Act, EPA 

exceeded the requirements of the Regulatory Flexibility Act (RFA) by preparing a regulatory flexibility analysis for 

every rule that would have any impact on any number of small entities. In view of the changes made by SBREFA, 

however, EPA decided to implement the RFA as written - a regulatory flexibility analysis as specified by the RFA is 

not required simply because the rule has some impact on some number of small entities: “Instead, such analysis will 

be required only in cases where we will not certify that the rule will not have significant economic impact on a 

substantial number of small entities”, but “It remains EPA policy that program offices should 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 the number of small entities affected.” 

116 Although AEPCO did not specifically request this, this comment was made in comments submitted by Arizona 

Utility Group on behalf of all of the utilities. As a result, we are also establishing bubble limits for the Apache units. 

117 BART Guidelines, 40 CFR Part 51, Appendix Y, section V (“You should consider allowing sources to “average” 

emissions across any set of BART-eligible emission units within a fenceline . . . ). 
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BART emission limit of 0.070 lb/MMBtu for Apache Units 2 and 3 as a “bubble” across these 

two units. 

Comment: One commenter (AEPCO) requested that if EPA establishes an SNCR limit, 

that the limits for Apache Units 2 and 3 be set at 0.23 lb/MMBtu. The commenter notes that 

while there are some differences in past utilization, the units are functionally identical and that, 

based on the best information available, a limit of 0.23 lb/MMBtu is likely the best consistently 

achievable limit given the load-following, unit-cycling and startup and shutdown issues that must 

be addressed as part of unit operation. 

Response: Although AEPCO stated in comments that “based on the best information 

available, a limit of 0.23 lb/MMBtu is likely the best achievable limit” and cited unit cycling and 

startup/shutdown issues, AEPCO did not provide any information in its comments documenting 

how or to what extent these issues justify a 0.23 lb/MMBtu emission limit (rolling 30-day 

average). We note that AEPCO’s original BART analysis also identified an SNCR emission 

estimate of 0.23 lb/MMBtu, but did not discuss the extent to which startup, shutdown, and 

malfunction events are accounted for in this emission rate. 

We note, however, that SRP also provided information in its comments regarding SNCR 

performance at Coronado Unit 1. Again, because of the similarities between the Apache units 

and the Coronado units, we consider it useful to examine information provided for the Coronado 

units in evaluating SNCR performance and an appropriate SNCR emission limit for the Apache 

units. As noted in our responses to comments on Coronado, SRP submitted a conceptual design 

estimate for SNCR for Coronado 1 that included a vendor estimate of 25 percent control 

efficiency from LNB emission rates. As noted in our responses for Coronado, while this is less 

stringent than the 30 percent SNCR control efficiency used by our contractor, we consider it a 
Page 90 of 244

reasonable estimate. Based upon 25 percent control efficiency, annual average emission rates for 

the SNCR with LNB and OFA option are presented in Table 2. 

TABLE 2–APACHE: SNCR EMISSION RATE ESTIMATE (ANNUAL AVERAGE) 

Control 

Technology 

Control 

Efficiency 

( percent)1

Apache 2 

(lb/MMBtu)

Apache 3 

(lb/MMBtu) 

Average Across 

Units 

(lb/MMBtu) 

OFA -- 0.37 0.44 0.40 

LNB+OFA 30 percent 0.26 0.31 0.28 

SNCR+LNB+OFA 25 percent 0.19 0.23 0.21 

1

This represents the incremental control efficiency from the previous control option, not the overall control 

efficiency from the baseline case of OFA

If we were to establish a BART emission limit corresponding to the use of SNCR 

technology, we would use the annual average SNCR emission rates presented in Table 2 as our 

basis, rather than our original estimates based on 30 percent SNCR control efficiency. As noted 

in a separate response, when using an annual average design emission rate to establish a rolling 

30-day limit that will apply during periods of startup, shutdown, and malfunction, we consider it 

appropriate to provide some type of measure that provides a compliance margin for such events. 

First, we would set the SNCR emission limit as a “bubble” limit across Apache 2 and 3. As seen 

in Table 2, the annual average SNCR emission rate, averaged across both units, is 0.21 

lb/MMBtu. A 0.23 lb/MMBtu emission limit, as requested by AEPCO, established on a rolling 

30-day average represents an approximate 10 percent increase from the 0.21 lb/MMBtu annual 

average emission rate. We would consider this magnitude of upward revision appropriate to 

accommodate startup, shutdown, and malfunction events as well as the unit cycling nature of the 

Apache units. As a result, if established, we would consider the BART emission limit 

corresponding to the SNCR with LNB and OFA option to be 0.23 lb/MMBtu, established as a 

bubble across both units. 
Page 91 of 244

For the purposes of our cost calculations or visibility modeling, however, we have 

retained the use of our original SNCR emission rates. A less stringent SNCR emission rate 

would, by itself, primarily serve to make the next most stringent control option, SCR, appear to 

remove a greater amount of emissions. This in turn would make the SCR control option appear 

more incrementally cost-effective (i.e., by removing a greater amount of emissions, relative to 

SNCR, for the same cost). As discussed in our proposal and in other responses to comments, we 

already consider SCR to be cost-effective, and it is not determinative to our decision to find that 

SCR is “even more” incrementally cost-effective. 

 b. Costs of Compliance 

Comment: Two commenters (NPS and Earthjustice) conducted their own analyses of the 

cost and cost-effectiveness of SCR with LNB and OFA for reducing emissions of NOX at 

Apache Units 2 and 3. NPS used the cost methodologies of the CCM, relied on the IPM to reflect 

the most recent SCR cost levels, and submitted the detailed calculations as Appendix B to its 

comments. The commenter’s analysis yielded cost-effectiveness values of $2,392/ton to 

$3,144/ton. The commenter noted that EPA’s analysis yielded cost-effectiveness values of 

$2,275/ton to $2,908/ton, which EPA considers cost-effective. According to Earthjustice, when 

the cost-effectiveness of SCR is calculated using more accurate costs and proper baselines, the 

result is a cost-effective SCR investment that reduces NOX at a cost of $2,640/ton at Unit 2 and 

$2,275/ton at Unit 3. 

Response: Based upon a review of the commenters’ calculations, we recognize that there 

are certain aspects of cost calculations that would result in lower $/ton values under different 

assumptions. As noted in our proposal, we already consider the SCR with LNB and OFA control 

option to be cost-effective at $/ton values that are somewhat higher than those calculated by the 
Page 92 of 244

commenters. As a result, we decline to modify our estimates of cost-effectiveness to reflect these 

comments, as it is not in any way determinative to our decision to find that SCR is “even more” 

cost-effective or that the incremental cost-effectiveness value between SCR and SNCR is “even 

more” incrementally cost-effective.

Comment: One commenter (AEPCO) stated EPA underestimated the site-specific costs 

for installing SCR at Apache, due principally to EPA’s substitution of general data used in the 

IPM model for the site-specific data used by ADEQ. The commenter stated that EPA needs to 

reevaluate its numbers in light of AEPCO’s site-specific analysis. For operation and maintenance 

costs, AEPCO estimates total costs of $1,760,000, which is slightly lower than EPA’s estimate of 

$1,822,463, with the main difference due to EPA’s higher allowance for maintenance. For the 

base unit costs, EPA used a 25 percent reduction factor for “low dust” for Unit 3. AEPCO’s 

vendors do not believe there will be any substantial reduction in cost based on “low dust,” and 

estimates that installed costs will be approximately $39,094,000 compared to EPA’s estimate of 

$33,279,000 for this unit. AEPCO estimates that the bare module cost will be near $48,119,000, 

rather than the $25,599,000 that EPA estimates, because EPA only included costs for induced 

draft (ID) fan upgrades and did not account for the additional costs of upgrading existing or 

running new electrical service to support the additional electrical loads required by SCR. The 

commenter also stated that EPA did not include contractor indirect costs and contingency with 

the capital, engineering and construction costs, nor did EPA include any owner’s costs or 

allowance for funds during construction, including interest during construction. AEPCO does not 

believe EPA should disallow these costs. AEPCO’s estimates with these costs are $85,666,000, 

compared with EPA’s estimate of $33,279,000. 
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The commenter stated that based on AEPCO’s estimated installed costs of SCR, the cost 

burden is disproportional to the benefits. Adding the costs of SCR to EPA’s estimate for LNB 

and OFA, the annualized cost is $3,508 per ton and $13.9 million per deciview. 

Another commenter (ACCCE) stated that EPA’s proposal to require SCR at Apache 

Units 2 and 3 must be abandoned due to the high costs of SCR. The commenter notes that 

according to EPA’s estimates, costs of SCR with LNB and OFA would be about $6 million for 

each unit, while the annualized costs of LNB and OFA estimated by ADEQ are only about 

$533,000 per unit. In addition, the commenter notes that the marginal improvement in visibility 

with SCR over LNB and OFA would be less than 1 deciview. 

Response: We disagree with commenters’ assertions that we underestimated the costs of 

SCR, or that the cost of SCR is disproportional to its benefits. In developing our proposed action 

for Apache Units 2 and 3, we examined the cost estimates for the SCR with LNB and OFA 

control option contained in AEPCO’s original BART analysis.118 By comparison, the SCR with 

LNB and OFA cost estimates we developed for our proposed action119 do not differ significantly. 

A comparison of capital cost, total annual cost, and cost-effectiveness for these two estimates are 

summarized in Tables 3 and 4. 

TABLE 3–APACHE UNIT 2: COST COMPARISON OF SCR WITH LNB AND OFA

 

 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Emissions 

Removed 

(tpy) 

Average 

CostEffectiveness

($/ton) 

EPA estimate $44,779,657 $5,869,299 2,019 $2,908 

AEPCO original 

estimate $48,740,300 $6,102,740 3,250 $1,878 

 

118 Docket Item No. B-01, Arizona Regional Haze SIP, Appendix D, page 49. 

119 See 77 FR 42856, Table 16. 
Page 94 of 244

TABLE 4–APACHE UNIT 3: COST COMPARISON OF SCR WITH LNB AND OFA 

 

 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Emissions 

Removed 

(tpy) 

Average 

CostEffectiveness

($/ton) 

EPA estimate $43,812,028 $6,103,078 2,683 $2,275 

AEPCO original estimate $48,740,300 $6,062,302 2,778 $2,182 

We note that while we used a different cost estimation methodology than AEPCO, our estimates 

of capital cost and total annual cost are very similar to the company’s original estimates and 

differ, for example, by only 8 percent and 4 percent (respectively) at Apache Unit 2. More 

importantly, we note that AEPCO’s original estimates for Apache Units 2 and 3 actually show 

lower $/ton values than our own, meaning that AEPCO’s original estimate indicates that SCR 

with LNB and OFA is cost-effective. 

In submitted comments, AEPCO provided multiple analyses comparing our SCR (stand 

alone) cost estimate with revised estimates prepared by engineering firm Burns and 

McDonnell.120 AEPCO provided two sets of revisions: one in which it retained our assumptions 

regarding costs not included in the CCM, such as AFUDC and owner’s costs, and another set in 

which it included those costs. In both cases, these analyses also contained revisions in order to 

reflect capital costs and O&M costs that AEPCO considered more representative and appropriate 

for the Apache units. These revisions included the following: 

• Higher bare module SCR costs, involving the inclusion and upward revision of specific 

constituent cost items (e.g., concrete and piling, ductwork); 

• Use of lower cost reduction for the low-dust SCR design as reflected in bare module cost 

(10 percent cost reduction, compared to a 25 percent cost reduction used in our estimate); 

 

120 The analysis was included in Attachment 1 to AEPCO’s Comments on the page titled “SCR Capital Cost 

Comparison.” 
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• Use of higher capacity factor (0.85 for both units, compared to 0.62 and 0.71); 

• Lower SCR NOX removal efficiency (based on an SCR emission rate of 0.07 lb/MMBtu, 

compared to 0.05 lb/MMBtu); 

• Inclusion of an additional 15 percent engineering, procurement, contracting fee (not 

included in our cost estimate); and 

• And certain other different assumptions regarding O&M costs that result in similar total 

O&M costs. 

AEPCO then included our estimate of LNB and OFA costs with its SCR (standalone) costs to 

arrive at its overall cost estimate for the SCR with LNB and OFA control option. As discussed 

elsewhere in this preamble, we have decided to finalize a 30-day rolling average BART emission 

limit of 0.070 lb/MMBtu for Apache Units 2 and 3, and a “bubble” across these two units to 

provide AEPCO an adequate margin for compliance. Although this 30-day limit accommodates 

the possibility of multiple startups in a given 30-day period, we expect such spikes to be 

smoothed out over the course of a year, so that the annual average remains closer to 0.05 

lb/MMBtu. For the other items noted above, such as bare module SCR costs, we are willing to 

defer to AEPCO’s judgment on these issues in order to address AEPCO’s concerns that our cost 

estimate was insufficiently site-specific. As a supplemental cost estimate, we have used the 

version of AEPCO’s cost estimate that adheres to our assumptions regarding costs that are 

allowed by the CCM. As shown in Table 5, this results in revised SCR with LNB and OFA costeffectiveness values of $3,450/ton and $2,973/ton for Apache 2 and 3, respectively, that are still 

within a range that we consider cost-effective when considered in conjunction with the visibility 

improvement associated with SCR.

TABLE 5 –APACHE 2 AND 3: COST ESTIMATE OF SUPPLEMENTAL SCR WITH LNB AND OFA
Page 96 of 244

Parameter Apache 2 Apache 3 Notes 

SCR Capital Cost ($) $71,938,250 $71,938,250 1 

LNB+OFA Capital Cost ($) $10,543,189 $10,543,189 2 

SCR+LNB+OFA Capital Cost ($) $82,481,439 $82,481,439

Interest Rate (percent) 7.0 per cent 7.0 per cent

Equipment Lifetime (years) 20 20

Capital Recovery Factor 0.094 0.094 2 

Annualized Capital Cost ($/yr) $7,785,664 $7,785,664

Fixed O&M ($/yr) $466,000 $466,000 1 

Variable O&M ($/yr) $1,294,600 $1,294,600 1 

Total Annual O&M ($/yr) $1,760,600 $1,760,600

Total Annual Cost ($/yr) $9,546,264 $9,546,264

Heat Rate (MMBtu/hr) 2,316 2,223 2 

Baseline Emission Rate 

(annual average lb/MMBtu) 

0.371 0.438

SCR Emission Rate 

(annual average lb/MMBtu)) 

0.050 0.050 2 

SCR Control Efficiency (percent) 87 percent 89 percent

Annual Capacity Factor 0.85 0.85 1 

Baseline Emissions (tpy) 3,198 3,625

SCR Emissions (tpy) 431 414

Emissions Removed (tpy) 2,767 3,211

 

Annual Cost ($/yr) $9,546,264 $9,546,264

Emissions Removed (tpy) 2,767 3,211

Average Cost-Effectiveness ($/ton) $3,450 $2,973

Comment: One commenter (AEPCO) stated that according to EPA’s estimates of SNCR 

costs, the incremental costs of SNCR with LNB and OFA compared to LNB and OFA are $3.3 

million with a maximum incremental improvement of 0.47 dv at Chiricahua Wilderness Area. 

The commenter stated that this improvement in deciviews is insignificant compared with cost. 

Response: As described above, EPA is not limited to considering incremental costs and 

benefits in comparing BART alternatives. The visibility benefits of SNCR at Chiricahua are a 

full 1 deciview with an annual cost of $6.6 million and a cost-effectiveness of $2,056 $/ton 

averaged over the two emitting units. In this case, even the incremental cost-effectiveness of 
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$2,837 $/ton is well within the range that we consider cost-effective. The incremental visibility 

benefit of 0.47 dv is also substantial, and additional benefits would occur at multiple Class I 

areas. Considered as a contribution to visibility impairment, EPA disagrees that this 

improvement from SNCR is insignificant. 

Comment: One commenter (AEPCO) stated that the Appendix Y BART Guidelines (40 

CFR 51, App. Y, section IV.E.3.2) provide that the State and EPA must consider the economic 

effects of BART determinations. AEPCO estimates that to install and operate SCR with LNB 

and OFA, rates would need to rise by more than 17.5 percent. Further, the units could have to 

shut down if the cost of power from those units is out of line with the cost of power in the open 

market. Moreover, due to contract expirations, AEPCO has no certainty that even its existing 

147,643 meters will be available to defray costs. AEPCO asserted that these factors are exactly 

the types of circumstances that were designed to be acknowledged in the BART Guidelines. 

One commenter (AEPCO) stated that EPA failed to follow the requirements of CAA 

section 51.308 and Appendix Y in its cost analysis by failing to review the affordability of the 

final cost on AEPCO as a single facility cooperative, but rather examined only the cost per ton 

and the cost per deciview. EPA should also consider the implications of AEPCO’s cooperative 

status and its limitations in obtaining funding for capital improvements. As a single generating 

station, with multiple units subject to BART requirements, the cooperative is unable to spread 

costs over unaffected units, other facilities or a large system of units and ratepayers. Also, as a 

cooperative, AEPCO is owned by its members and cannot sell stock or other equities to raise 

funding, and must seek long-term financing from the Rural Utilities Service, which has a limited 

budget and is being asked to fund efforts for other cooperatives and rural utilities to meet CAIR, 

CSAPR, other SIP initiatives, and the upcoming EGU MACT. In addition, the terms of 
Page 98 of 244

AEPCO’s mortgage agreement would necessitate a rate increase of more than 16 percent to 

accommodate SCR, and it is not certain whether the Arizona Corporation Commission (ACC) 

would grant such a rate increase or what the long term impact would be on AEPCO’s working 

and patronage capital. 

AEPCO also stated that the operating and financing costs are unreasonable for the 

Apache plant. EPA estimates the SCR system alone will have operating and maintenance costs 

of $3.3 million, which is 35 percent of AEPCO’s total net revenue of $9.5 million for 2010 and 

more than the net revenue of $1.9 million for 2011. AEPCO estimates that it will need to 

increase rates by $22.5 million a year over the O&M costs just to finance SCR with LNB and 

OFA on Units 2 and 3. This combined cost is 14 times AEPCO’s net revenues in 2011 and 2.8 

times 2010 net revenues. This cost does not include other expenditures that will be required for 

Units 1, 2 and 3 for BART. With only 147,643 metered customers and with many of these 

customers in low income areas, rate increases for these customers are not trivial. The commenter 

also stated that SNCR also is not affordable due to the operating costs. AEPCO estimates SNCR 

with LNB and OFA operating costs to be $6.8 million, which is three times AEPCO’s net 

revenue 2011 and over two-thirds of net revenues in 2010. 

Another commenter (Earthjustice) stated that SCR costs will not threaten AEPCO’s 

continued viability or have a severe impact on its operations, which are the only two affordability 

conditions allowed to be considered under the BART Guidelines (Appendix Y, Section IV.E.3.). 

The commenter noted that guidance and case law on Reasonably Available Control Technology 

(RACT) and BACT determinations, which make clear that affordability issues are given 

relatively little weight, are instructive for BART determinations due to the similar analysis. For 

RACT and BACT, the commenter explained that Congress intended that all sources in a source 
Page 99 of 244

category bear similar costs for pollution reduction and that sources should not be able to avoid 

cost-effective controls due to poor financial position, as this would reward inefficient or poorlymanaged sources. The commenter cited two cases regarding RACT and BACT economic 

feasibility (Michigan v. Thomas, 805 F.2d 176, 180 (6th Cir. 1986), Nat’l Steel Corp., Great 

Lakes Steel Div. v. Gorsuch, 700 F.2d 314, 324 (6th Cir. 1983)). The commenter also noted that 

detailed economic data is required for sources to raise affordability issues under RACT and 

BACT, and the detailed economic analysis called for in the BART Guidelines should be 

similarly robust where EPA considers affordability issues for “unusual circumstances.” The 

commenter also stated that Apache’s continued viability is not threatened, based on a report by 

Paul Chernick at Resource Insight Inc., which shows that AEPCO’s average operating margin 

over the last four years would cover 185 percent of the annual debt repayment for the SCR 

system, and the current equity capital of $94 million in 2011 would cover the entire cost of 

installation. The report also shows that AEPCO will receive refunds from a settlement with two 

railroads totaling $63 million. The commenter further refuted that AEPCO may not be able to 

borrow sufficient funds for SCR. The commenter stated that RUS loan funds are not raised or 

subsidized by taxpayers, and the RUS does not anticipate any shortage in funding. In addition, 

the commenter claimed that the National Rural Utility Cooperative Finance Corporation 

(NRUCFC) is financed by private investors, and AEPCO should not have any difficulty 

borrowing from the NRUCFC, if necessary. 

Another commenter (ACCCE) stated that the large costs of SCR may adversely impact 

AEPCO and its customers due to AEPCO’s small size, the low income profiles of AEPCO’s 

service area, and AEPCO’s ability to obtain financing. The commenter urges EPA to give full 

consideration to AEPCO’s comments submitted June 29, 2012, on these issues. 
Page 100 of 244

Commenters from AEPCO’s member cooperatives stressed the unique economic and 

engineering challenges they face – low population density, the demands of servicing vast remote 

areas with rugged topography, and transmission grid capacity limitations that make it difficult to 

import power. They noted that the majority of their power comes from the Apache Generating 

Station, so the cost impact of SCR installation would be especially acute, resulting in rate 

increases ranging from an estimated 15 percent to 30 percent. The commenters pointed out that 

their customer base has average incomes well below the national and Arizona averages, and 

would be especially hard hit by large rate increases; many customers struggle to pay their power 

bills as it is. The commenters stated that AEPCO and the associated cooperatives cannot finance 

or absorb the costs of SCR at the Apache Generating Station. The commenters indicated that 

closure of the large, load-following coal-fired units would threaten the reliability of the electrical 

system, particularly with the limited capacity of the local grid to import power from other areas. 

Another commenter (Earthjustice) cited a report by Paul Chernick at Resource Insight 

Inc., which estimates that any rate increases at Apache would be limited to a 2 percent to 5 

percent increase at most, resulting in an average extra cost of $3.28 per month on customer bills. 

The commenter stated that this is reasonable, as average annual increases have been up to 3 

times as high as this increase, and this rate will likely be offset by a settlement award of $63 

million. The commenter also noted that while the incomes of its customer base are relatively 

low, the cost of living in the area is also lower than the national average. The commenter further 

noted that utilities in similarly economically disadvantaged areas have successfully installed 

modern pollution controls costing significantly more than the cost of SCR at Apache. 

Response: It is not EPA's intention to endanger the economic viability of Apache 

Generating Station or to place an undue burden on AEPCO’s customers. EPA has considered the 
Page 101 of 244

comments on these issues very carefully. Regarding the legal basis for our decision, neither the 

CAA nor the RHR requires states or EPA to consider the affordability of controls or ratepayer 

impacts as part of a BART analysis. Rather, the CAA and RHR require consideration of “the 

costs of compliance, the energy and non-air quality environmental impacts of compliance, any 

existing pollution control technology in use at the source, the remaining useful life of the source, 

and the degree of improvement in visibility which may reasonably be anticipated to result from 

the use of such technology.”121 

The BART Guidelines do allow for (but do not require) the consideration of 

“affordability” as part of the “costs of compliance” under certain circumstances, noting that: 

1. 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. 

2. There may be unusual circumstances that justify taking into consideration the 

conditions of the plant and the economic effects of requiring the use of a given 

control technology. These effects would include effects on product prices, the 

market share, and profitability of the source. Where there are such unusual 

circumstances that are judged to affect plant operations, you may take into 

consideration the conditions of the plant and the economic effects of requiring the 

use of a control technology. Where these effects are judged to have a severe 

impact on plant operations you may consider them in the selection process, but 

you may wish to provide an economic analysis that demonstrates, in sufficient 

detail for public review, the specific economic effects, parameters, and 

reasoning... Any analysis may also consider whether other competing plants in 

the same industry have been required to install BART controls if this information 

is available.

122

We interpret the question of affordability as a specific question of whether the 

viability of continued plant operations will be affected by the pollution control 

technology in question. Although one commenter asserted that the costs of SCR with 

LNB and OFA could cause a shutdown of Apache Units 2 and 3 if it causes power costs 

 

121 CAA section 169A(g)(2), 42 U.S.C. 7491(g)(2); 40 CFR 51.308(e)(1)(ii)(A) (emphasis added). 

122 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.3. 
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from those units to be out of line with the cost of power on the open market, the 

commenter did not provide evidence or analysis that supports this assertion. We agree 

that the terms of AEPCO’s mortgage require AEPCO to have sufficient revenue to meet 

the financial metrics of Times Interest Earned Ratio and Debt Service Coverage ratio. But 

AEPCO is eligible to finance additional debt related to air pollution controls, and it has 

not shown that such financing is unavailable to it. Securing a rate increase from ACC 

may be time consuming, and thus supports our decision to grant AEPCO five years for 

installation of such controls. However, the information provided to us does not show that 

installation of SCR would affect the viability of continued plant operations. AEPCO is 

not being treated differently from other competing plants in its industry: many other 

electric utilities, including other rural electric cooperatives, are also being required to 

install BART controls. 

Nonetheless, we performed additional analysis to understand better the impacts of the 

proposed pollution controls on AEPCO as a small entity. As we explained in our proposal, the 

U.S. Small Business Administration (SBA) defines an electric utility company as small if, 

including its affiliates, it is primarily engaged in the generation, transmission and/or distribution 

of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 

4 million megawatt hours (MWh).123 In 2011, AEPCO member cooperatives sold 2,453,272 

MWh of electricity.

124 As explained in the proposal, we conducted an initial assessment of the 

potential adverse impacts on AEPCO of requiring SCR with LNB and OFA. Using publicly 

available information, EPA estimated 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 

 

123 77 FR 42866 - 42867; see also 13 CFR 121.201, footnote 1. 

124 Annual Report for year ending December 31, 2011, from AEPCO to Arizona Corporation Commission. 
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AEPCO’s annual sales. We noted in the NPRM that the projected costs of SCR with LNB and 

OFA are approximately $12 million per year, and that this exceeds AEPCO’s net margins of $9.5 

million in 2010 and $1.9 million in 2011,125 although the report by Paul Chernick at Resource 

Insight Inc., submitted by Earthjustice, notes that AEPCO’s margin in 2008 was $17.4 million. 

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 received a description of plant conditions and potential economic effects before the 

NPRM was published,126 and received additional information during the comment period. We 

noted in the NPRM that if our analysis of this information indicated that installation of SCR 

would have a severe impact on the economics of operating Apache Generating Station, we would 

incorporate such considerations in our selection of BART. 

The BART cost figures provided in this final action do not include other expenditures 

that will be required for Apache Units 1, 2 and 3 to meet the BART emission limits included in 

Arizona’s Regional Haze SIP. Under the CAA, EPA is not permitted to consider economic 

feasibility when taking action on a SIP.127 To the extent these costs are relevant to our FIP 

action, we note that AEPCO did not provide any cost estimates for the required upgrades to the 

existing ESPs and scrubbers at Apache Units 2 and 3 and estimated that the total first year 

annualized cost of the required controls at Apache Unit 1 (LNB and FGR) would be $0.552 

 

125 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

percent20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_Inc.pdf. 

126 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. 

127 Union Electric Co., v. EPA, 427 U.S. 246, 255-66 (1976); 42 U.S.C. 7410(a) (2). 
Page 104 of 244

million.128 These costs are two orders of magnitude lower than the SCR costs described 

elsewhere in this document. Therefore, even if we were to take them into account, they would 

not substantially affect our analyses. 

Regarding the comment that the cost of SCR with LNB and OFA at Apache could be 

covered with funds from AEPCO’s operating margins or legal settlements, while Apache 

Generating Station does have annual operating margins that vary according to various 

conditions, it is not necessarily true that AEPCO can cover the costs of pollution control 

equipment exclusively from these funds, or from the settlement agreement mentioned in the 

comment. Because AEPCO is a member-owned utility, operating margins and other surplus 

funds may be earmarked to be returned to its member cooperatives on a rotating basis. While 

some of these funds may be available for capital expenditures such as pollution controls, we have 

assumed for the purpose of our analysis that financing will be necessary to achieve the pollution 

reductions required by our action. 

For electric utilities, EPA has not customarily analyzed or considered ratepayer impacts 

in BART determinations.129 Nevertheless, we also analyzed ratepayer impacts in an effort to 

assess the potential effects of our action on AEPCO as a small entity. EPA requested an 

electricity rate analysis through our contractor, EC/R Inc., to assist us in evaluating the possible 

electricity rate increases discussed in the comments above. Our contractor noted that AEPCO’s 

analysis appears to place the entire burden of the incremental capital and O&M costs on its 

Member Co-ops and their retail customers. However, the analysis should account for a share of 

 

128 Arizona Regional Haze SIP, Appendix D, Table 10.3; see also Comments of Arizona Electric Power 

Cooperative, Inc., Proposed Disapproval of AZ RH SIP and EPA’s Proposed RH BART FIP (September 18, 2012) 

page 9. In our proposal, we noted that these 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. See 77 FR 4284. 

129 Exceptions include EPA’s Regional Haze FIP for Hawaii, where we analyzed potential rate impacts due to the 

unique energy situation in Hawaii, 77 FR 61478, 61488, and EPA’s BART FIP for Four Corners Power Plant, where 

we examined potential rate impacts as part of tribal consultation, 77 FR 51620, 51625-51626. 
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the SCR cost going to off-system sales volumes and not only allocated to member rates. The 

contractor’s Incremental Cost Model calculated an increment in revenue requirements for 

AEPCO’s member cooperatives of 12.7 percent under the scenario that spreads the incremental 

SCR cost across all kWh produced at Apache, both Member Co-ops and off-system or nonMember sales. Under the alternative scenario that the incremental cost for SCR is covered 

exclusively by member cooperatives, the incremental revenue requirement was 15.4 percent.130

As explained in the preceding responses, this analysis is based on a capital cost for the 

installation of SCR with LNB and OFA of $164.9 million, which matches the costs claimed by 

AEPCO in their comment letter minus certain charges excluded by EPA CCM. This difference in 

the estimated capital cost for SCR also accounts for much of the discrepancy between AEPCO’s 

and Earthjustice’s estimates of electricity rate increases, since Earthjustice’s estimate was based 

on the capital cost estimates originally published in our NPRM. 

AEPCO sells electricity through its member cooperatives, and not directly to 

residential and business customers, but EC/R also analyzed the impact of an increase in 

the cost of electricity generation on the monthly bills of electricity users serviced by 

AEPCO’s Member Co-ops. Table 6 indicates the incremental retail costs of electricity to 

end users under the two scenarios mentioned above. The potential rate increases for 

residential users in 2019, the first full year of incremental capital expenditures for 

pollution controls installed in 2017 (and the year with the largest incremental cost 

impact), range from 4.5 percent, or $5.75 per month over 2011 rates, to 10.6 percent, or 

 

130 Apache Plant: Report on SCR Incremental Cost Assessment. Prepared by Energy Strategies, LLC for EC/R, Inc. 

(November 2012). 
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$10.75 per month over 2011 rates.131 EC/R noted that the assumptions it made in 

constructing its model may cause the impact to rates to be conservatively overstated. 

TABLE 6–INCREMENTAL RETAIL COSTS DUE TO SCR 

(AS 2019 COSTS WOULD IMPACT 2011 RETAIL RATES) 

Scenario 

Range 

of 

Outcomes

Residential Class Only 

Combined Residential, 

Commercial & Industrial 

Percent 

Increase 

Average 

$ per 

Year per 

Customer 

Average 

$ per 

Month 

per 

Customer 

Percent 

Increase 

Average 

$ per 

Year per 

Customer

Average 

$ per 

Month 

per 

Customer

A: 

Members 

Pay all 

SCR Costs 

Low 

5.4% $83 $6.92 5.8% $125 $10.42 

High 10.6% $129 $10.75 12.0% $220 $18.33 

B: 

Members 

Pay Portion 

of SCR 

Costs 

Low 4.5% $69 $5.75 4.8% $103 $8.58 

High 8.8% $107 $8.92 9.9% $182 $15.17 

While these projected rate increases are not trivial, they are comparable to 

average historical rate increases for AEPCO, Arizona, and U.S. ratepayers.132 They are 

also projected to occur seven years in the future. Again, in discussing the limitations of 

this retail rate analysis, EC/R noted that the results of the retail rate assessment should be 

considered conservative by design. 

Regarding the comment that utilities in similarly economically disadvantaged 

areas have successfully installed modern pollution controls costing significantly more 

than the cost of SCR at Apache, we note that none of the installed controls listed in 

 

131 Id.

132 Energy Information Administration (EIA) State Historical Tables for 2011, Released: October 1, 2012. Average 

Price by State by Provider, 1990-2011. http://www.eia.gov/electricity/data/state/avgprice_annual.xls, last accessed 

November 5, 2012. 
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Earthjustice’s comment letter were installed under the RHR. Accordingly, EPA cannot 

rely on them as precedents for the Apache Generating Station BART analysis. 

Regarding the comment on the economic vulnerability of AEPCO’s ratepayer 

population, EPA reviewed the supplemental information on per capita and median 

household incomes. Because electric utility bills are likely paid at the household and not 

individual, or per capita, level, we believe that median household income is an 

appropriate metric for assessment. We used census data to compare household income 

levels in the areas served by AEPCO’s Class A member cooperatives to average 

household incomes in the United States. In 2011 the median income for U.S. households 

was $50,502. Using the supplemental information provided by AEPCO, we calculated 

that the median income for AEPCO’s Member Co-ops’ ratepayers was $49,303. In 

addition, we aggregated the data on median household income by zip code into four 

incomes ranges. Seventy-one percent of the median household incomes by zip code were 

in the $40,000 and above income ranges and twenty-nine percent were in the median 

household income range of $20,000 to $39,999. We found that the household incomes in 

AEPCO’s Member Co-ops’ service area are in the same range as average U.S. household 

income, so an increase in AEPCO’s electricity rates should not cause greater hardship 

than a similar increase elsewhere in the country.

133 EPA’s responsibility under the CAA 

and the RHR is to implement BART at Apache Generating Station. As discussed 

elsewhere in this document, the five-factor analysis indicates SCR with LNB and OFA 

represents BART for NOX at Apache Units 2 and 3. While the analyses conducted by 

EPA and the commenters attempted to project the revenue requirements and possible rate 

 

133 Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic 

Analysis. Memorandum from Larry Sorrels and Robin Langdon, EPA Office of Air Quality Planning and Standards 

(November 5, 2012). 
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increases that would be required if SCR with LNB and OFA are required at Apache, 

BART and other environmental regulatory requirements form only one part of the 

complex business conditions under which utility rate decisions take place, especially over 

extended time periods. It is the responsibility of utility companies to work with the 

appropriate regulatory agencies to implement any necessary rate changes in a manageable 

fashion. 

Accordingly, because neither these projected rate increases nor any submitted 

information or analysis indicate that a requirement to install SCR with LNB and OFA 

will affect the viability of Apache Generating Station, EPA is finalizing its determination 

that this level of control represents BART. However, we are also taking into account 

AEPCO’s status as a small entity as part of our determination. In particular, in its 

comments on our proposal, AEPCO requested that “EPA set the final BART limits in 

terms of lb/MMBtu only and not as a specified technology” to provide AEPCO with 

“maximum flexibility.”134 AEPCO also requested that if EPA decided to finalize 

emission limits consistent with SCR that the limits be set at 0.07 lb/MMBtu.

135 Given the 

unusual status of AEPCO as a small entity and a rural electric cooperative, we believe 

that it is consistent with EPA policy to minimize adverse impact to this small entity to the 

extent that such action is feasible and consistent with our BART analysis. To allow this 

small entity the maximum flexibility that is consistent with our analysis of the five 

factors, we have determined that it is appropriate to set the BART limit as a 30-day 

rolling average 0.070 lb/MMBtu limit, with a five year compliance deadline. As AEPCO 

noted, this approach may allow minor changes in configuration of the optimal system to 

 

134 AEPCO Comments page 18. 

135 Id. 
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allow AEPCO’s compliance at somewhat lower cost. This 30-day rolling average 0.070 

lb/MMBtu limit is also applied as a “bubble” across Units 2 and 3. This approach allows 

for short term emission spikes from startups and provides this small entity with additional 

operational flexibility within the constraints of the BART emissions limit. 

Comment: One commenter (AEPCO) stated that EPA should not consider fuel switching 

from the current mix to all natural gas at Apache Unit 1 to be costless. AEPCO states that if it 

loses the ability to use multiple fuels, its negotiating leverage with natural gas suppliers will be 

greatly reduced, and it will not be able to obtain gas at reasonably competitive rates. AEPCO 

argued that this cost at Apache Unit 1 should be considered by EPA in its overall evaluation of 

the affordability of controls at Apache. 

Response: EPA is approving ADEQ’s emissions limit for Apache Unit 1. As noted by the 

commenter, Tables 6 and 7 of our proposed action (77 FR 42844) listed “fuel switch to PNG” as 

a control option in the context of the PM10 and SO2 BART analyses, in addition to “fuel switch 

to low-sulfur fuel oil.” The annualized costs for both options were listed as zero in both analyses. 

The information contained in Tables 6 and 7 does not represent our analysis for Apache Unit 1, 

but reflects the information contained in ADEQ’s PM10 and SO2 BART analyses. ADEQ’s 

BART analyses for Apache 1 eliminated more stringent control technologies such as fabric 

filters and wet FGD, and determined that a fuel switch to natural gas was BART. Natural gas is a 

commodity, and its price fluctuates due to factors beyond the constraints on AEPCO’s ability to 

use multiple fuels. However, the BART emissions limit we are establishing for Apache Units 2 

and 3 will still allow AEPCO a choice of using multiple fuels across the units at the Apache 

facility.

 b. Visibility Improvement 
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Comment: One commenter (NPS) agreed with EPA’s analysis of the visibility impacts of 

the alternative NOX control options for Apache Units 2 and 3 at the various impacted Class I 

areas, as presented in EPA’s TSD, including EPA’s conclusions that “the improvements from 

SCR are substantially greater than for the other candidate controls” and that “the modeled degree 

of visibility improvement supports SCR as BART for Apache.” The commenter also indicated 

that it compiled BART analyses data from across the United States, which revealed that the 

average cost per deciview proposed by either a state or a BART source is $14 to $18 million. 

The commenter pointed out that for all of the NOX control options at the Apache plant, including 

SCR, both the $/max deciview and the $/cumulative deciview are well below this range. 

Response: We acknowledge the commenter’s agreement with our analysis. Our 

supplemental analysis, discussed in more detail above, was conducted using a capital cost for the 

installation of SCR with LNB and OFA of $164.9 million. For the 0.070 limit on Apache Units 2 

and 3 that we are finalizing in this action, this supplemental analysis found an average cost per 

deciview ($/max deciview) of $12.7 million and a cumulative average cost per deciview 

($/cumulative deciview) of $3.1 million. 

 c. Other Comments 

Comment: One commenter noted that EPA is required by the Executive Order on 

Environmental Justice to consider all potential economic and environmental impacts on 

minorities and low-income populations that its decisions on BART, in this case, will have on 

AEPCO and its customers. The commenter stated that over four in ten of AEPCO’s customers 

are minorities. In similar remarks, another commenter cautioned EPA that such increases would 

impact at-risk populations.
Page 111 of 244

Response: In establishing BART requirements for the facilities in this final rulemaking, 

EPA is increasing the level of environmental protection for all affected populations by requiring 

substantial NOX emission reductions. Thus, EPA does not expect any disproportionately high 

and adverse human health or environmental effects on any population, including any minority or 

low-income population from our final action. Disadvantaged populations also will be able to 

enjoy the visibility improvements in Class I areas anticipated from the emissions reductions 

required by this final rulemaking.

EPA took several steps to ensure transparency and meaningful participation in the rule 

development process for this BART FIP. In response to numerous requests, we extended the 

public comment period on our proposal and increased the number of public hearings in Arizona 

from one to three. In addition, all three hearings had Spanish language interpretation services and 

the hearing on August 14 in Holbrook, Arizona, also offered interpretation in Diné. 

We disagree that Executive Order 12898 requires EPA to consider the economic effects 

of our proposed action on disadvantaged populations. As EPA’s Environmental Appeals Board 

(EAB) has explained: 

Executive Order 12898 instructs federal agencies to address, as appropriate, 

“disproportionately high and adverse human health or environmental effects of [their] 

programs, policies, and activities on minority and low-income populations * * *.”The 

Executive Order, thus, speaks to human health and environmental effects; it does not 

require federal agencies to consider issues regarding cost or rate changes.136 

Therefore, Executive Order 12898 does not require us to consider potential economic effects. 

Nonetheless, as explained elsewhere in this document, in consideration of AEPCO’s status as a 

small entity and consistent with EPA policy encouraging consideration of the potential social and 

 

136 In re: Upper Blackstone Water Pollution Abatement District, Order Denying Review In Part and Remanding In 

Part, NPDES Appeal Nos.08-11 to 08-18 & 09-06. (May 28, 2010) slip op at 105. (internal citation omitted). 
Page 112 of 244

economic impacts of EPA actions,137we have conducted an analysis of the affordability of 

installing SCR at Apache Units 2 and 3. This analysis indicates that installation of SCR would 

not affect the viability of continued plant operations at Apache and would result in an average 

rate increase for residential member utility customers of (at most) $11 per month in 2019 

compared to 2011 rates. 

Comment: One commenter indicated that because AEPCO is a small electric cooperative, 

EPA is required by the Regulatory Flexibility Act to prepare a regulatory flexibility analysis for 

this rulemaking. 

Response: We agree that AEPCO is considered small entity for purposes of the 

Regulatory Flexibility Act (RFA). However, the RFA does not require a regulatory flexibility 

analysis when a rule has an impact on only one small entity (as opposed to a significant impact 

on a substantial number of small entities). Nonetheless, 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. Therefore, we 

gave AEPCO additional opportunities to participate in the rulemaking process. Specifically, prior 

to issuing our proposed rule, we informed AEPCO that our proposed action would address 

BART requirements for units at AEPCO’s Apache facility. We also 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 considered the comments we received concerning AEPCO’s status as a small entity and the 

potential economic impact of our proposed action on AEPCO. Our discussion of affordability 

above includes our response to these comments and delineates the changes we made from our 

 

137 See, e.g., Interim Guidance on Considering Environmental Justice During the Development of an Action page 4, 

footnote 4. 
Page 113 of 244

initial proposal in order to give AEPCO flexibility as a small entity. We have also taken into 

consideration the potential impact of the reporting, recordkeeping, and other compliance 

requirements of this rule, as set forth in the regulatory text. Because AEPCO is an electric utility 

that is already subject to reporting, recordkeeping and other compliance requirements under the 

CAA, AEPCO already has access to the professional skills necessary for the preparation of the 

reports and records necessary for compliance with the FIP. 

 2. Cholla Units 2, 3 and 4 

 a. Selection of Baseline Period 

Comment: Several commenters asserted that EPA incorrectly and inappropriately 

changed the control baseline period in its NOX BART analysis for Cholla. APS and PacifiCorp 

contend that the 2011 NOX emissions were already controlled by LNB and OFA at Cholla Units 

2, 3 and 4, which penalized APS and PacifiCorp for their voluntary use of these controls. In 

addition, since LNB and OFA were already in use, EPA inappropriately only considered higher 

cost post-combustion controls (SCR and SNCR) in its BART analysis. If the baseline remained 

2001-2006, LNB and OFA would also have been considered in the analysis. APS noted that EPA 

concurred with ADEQ’s BART determination for SO2 and PM10 emissions for these same units 

using a baseline of 2001-2006. In addition, one commenter (Earthjustice) asserted the baseline 

period (2008-2011) understates NOX emissions reductions compared to the baseline period of 

2001-2004. 

In contrast, one commenter (NPS) concurred with EPA’s use of 2011 as the baseline 

period for Cholla units 2, 3 and 4 since it represents the first complete calendar year at which it is 

certain that the Cholla plant operated using the full quantity of a higher NOX-emitting coal that 

the plant is committed to purchase under its current coal contract. The commenter submitted a 
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graph of annual NOX emission rates for the units at the Cholla plant, which the commenter 

believes to show the impact of recently added combustion controls and higher-NOX coal. 

Response: As explained in a previous response, we do not agree that use of the updated 

baseline for Cholla was incorrect or inappropriate. Moreover, updating the baseline did not 

eliminate LNB and OFA from consideration as BART, since existing controls can constitute 

BART if additional controls are not warranted based on the five-factor analysis. For example, 

EPA recently approved a determination by Colorado that existing LNB at Comanche Units 1 and 

2 constituted BART where “the State determined that the added expense of achieving lower 

limits through different controls was not reasonable based on the high cost-effectiveness 

[$9,900/ton] coupled with the low visibility improvement (under 0.2 dv) afforded.” 138 In this 

case, by contrast, the cost-effectiveness of post combustion controls is reasonable and the 

expected visibility improvements are substantial, as explained below. Nonetheless, in order to 

address the commenter’s concerns that we did not properly consider LNB and OFA as a potential 

control option and therefore precluded a BART determination of LNB and OFA, we have used a 

baseline period of 2001-2003, which corresponds to the period used in APS’s original BART 

analysis. Our supplemental cost analysis for Cholla is summarized in Table 10.139

 b. Control Efficiencies 

Comment: In arguing against the achievability of EPA’s proposed limit, one commenter 

(APS) noted that according to the study that EPA placed in the docket (IPM Model – Revisions 

to Cost and Performance for APC Technologies, 2010, Sargent & Lundy), the Agency’s 

minimum emissions limit of 0.05 lb/MMBtu is specific to Powder River Basin coal and the 

minimum level for bituminous coal is 0.07 lb/MMBtu. The commenter also stated that because 

 

138 77 FR 18052, 18066 (March 15, 2012) (Proposed Rule); pre-publication version of Final Rule, signed September 

10, 2012, available at: http://www.epa.gov/region8/air/FinalActionOnColoradoRegionalHazePlanSep2012.pdf. 

139 A spreadsheet titled “Supplemental Cost Analysis 2012-11-15.xls” is in the docket. 
Page 115 of 244

this is a minimum emissions level, it is probably too aggressive even for a BART determination 

based on bituminous coal. The commenter also stated that these rates may be appropriate for new 

units under ideal conditions as BACT are not appropriate for BART.

Another commenter (AUG) stated that EPA’s record in support of the putative 

achievability of a 0.050 lb/MMBtu emission limit at Apache, Cholla, and Coronado is extremely 

thin and unpersuasive. AUG states that EPA has not, for instance, demonstrated through the 

development of an SCR conceptual design or some other, similar site specific analysis that SCR 

can achieve this emission rate at any of these particular facilities, and that EPA must 

affirmatively establish that its selected BART rate is in fact achievable at these facilities. 

In addition, AUG asserted that EPA’s proposed limit of 0.050 lb/MMBtu is inconsistent 

with the following EPA actions: 

• As part of CSAPR, EPA concluded that a NOX limit below 0.06 lb/MMBtu is not 

achievable through retrofit of SCR on coal‐fired electric generating units.140

• In EPA’s proposed rule for North Dakota, EPA based its BART analysis on a 

0.05 lb/MMBtu emission rate, but then proposed to adopt a 0.07 lb/MMBtu limit because 

EPA concluded the more stringent rate would not allow a sufficient margin of 

compliance (citing 76 FR 58570, 58610, September 21, 2011). 

• In its final rule for South Dakota, EPA set a NOX limit of 0.10 lb/MMBtu for an electric 

generating plant to allow for an adequate margin of compliance (citing 77 FR 24845, 

24848, 24849, April 26, 2012). 

• In Colorado’s recently approved regional haze SIP, the NOX BART for Craig Station is 

an emission rate of 0.27 lb/MMBtu based on SNCR and SCR for their units and the NOX

 

140 Citing 76 FR 1109, 1115, January 7, 2011; EPA, Transport Rule Engineering Feasibility Response to Comments, 

Docket ID No. EPA‐HQ‐OAR‐2009‐0491‐4529, at 13, July 6, 2011. 
Page 116 of 244

BART for Hayden Station is an emission rate of 0.07 lb/MMBtu for one unit and 0.08 

lb/MMBtu at another unit based on SCR. 

Response: We disagree that the SCR emission rate for the Cholla units should be 

established at 0.07 lb/MMBtu per IPM guidance for bituminous coal. Based on the coal 

information provided in the original Cholla BART analyses

141

, the Lee Ranch/El Segundo Mine 

coal being used at Cholla does exhibit some properties that would fall in the range of bituminous 

coal (nitrogen and moisture content), but also exhibits properties that fall in the range of subbituminous coal (fixed carbon, heat value). As a result, we do not agree that the Lee Ranch/El 

Segundo coal can clearly be classified as a bituminous coal. 

More broadly, we disagree with commenters’ assertion that 0.05 lb/MMBtu (rolling 30-

day average) is an inappropriate SCR emission limit for the Cholla units. Although BART 

determinations are performed on a site-specific basis, the process for establishing the technical 

feasibility of a control technology and its associated emission performance level are described in 

the BART Guidelines as follows: 

It is important, however, 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. 

In assessing the capability of the control alternative, latitude exists to consider special 

circumstances pertinent to the specific source under review, or regarding the prior 

application of the control alternative. However, you should explain the basis for choosing 

the alternate level (or range) of control in the BART analysis. Without a showing of 

differences between the source and other sources that have achieved more stringent 

emissions limits, you should conclude that the level being achieved by those other 

sources is representative of the achievable level for the source being analyzed.142 

 

141 “Additional APS Cholla BART response”, Appendix B. 

142 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.3. 
Page 117 of 244

We therefore disagree with commenters’ assertion that the BART Guidelines require a SCR 

conceptual design or other site specific engineering analysis in order to demonstrate a level of 

performance. The BART Guidelines indicate that one should take into account the most stringent 

emission control level that the technology is capable of achieving and then document any special 

circumstances for selecting an alternate level or range of control in the BART analysis. 

In our proposal, we explained that SCR, as a technology, can achieve a level of 

performance between 80 to 90 percent reduction, even on a retrofit basis, and especially when 

combined with LNB and OFA. Although the commenters indicate that they do not consider our 

support for this position persuasive, they have not specifically disputed the claim that SCR can, 

as a technology, achieve this level of performance. We have included additional documents, 

including vendor experience lists of SCR projects, which indicate that SCR has been capable of 

achieving this level of performance.143 In determining whether special circumstances exist at the 

Cholla units that may justify using a different range of control, we examined the Clean Air 

Markets Database (CAMD) for tangential coal-fired units operating with SCR, either stand alone 

or in conjunction with LNB and OFA, and on a retrofit basis. We identified the 10 best such 

performing units, and have listed them in Table 7. In addition, we have listed their bestperforming annual average emission rate as well as the percent reduction associated with that 

emission rate by comparing it to annual average emission rates from its pre-SCR period of 

operation.

144

 

TABLE 7–BEST PERFORMING TANGENTIAL COAL-FIRED EGUS WITH RETROFIT SCRS

State Facility Name Unit ID SCR Emission Rate Control Control 

 

143 Kurtides, Ted “Lessons Learned from SCR Reactor Retrofit”, Presented at COAL-GEN (August 6-8, 2003); 

Hitachi SCR/NOx catalyst experience (February 2010); Haldor Topsoe SCR catalyst reference list (October 2009); 

Institute of Clean Air Companies, “White Paper – Selective Catalytic Reduction Control of NOX emissions from 

Fossil Fuel-fired Electric Power Plants” (May 2009). 

144 “Tangentially-fired coal unit SCR retrofit emission data.” 
Page 118 of 244

 (lb/MMBtu) YearEfficiency 

(percent) 

Technology 

TX W A Parish WAP7 0.038 2007 73 percent SCR1

TX W A Parish WAP8 0.038 2006 77 percent SCR1

VA

Chesterfield Power 

Station 6 0.041 2009 89 percent

SCR+LNB+ 

COFA/SOFA

NC Marshall 3 0.045 2011 85 percent SCR+LNB+SOFA

TN Kingston 6 0.051 2009 88 percent SCR+LNB+SOFA

TN Kingston 8 0.052 2009 88 percent SCR+LNB+SOFA

TN Kingston 9 0.052 2009 89 percent SCR

TN Kingston 7 0.054 2009 88 percent SCR+LNB+SOFA

MN

Boswell Energy 

Center 3 0.054 2009 86 percent SCR+LNB+SOFA

TX Sandow 4 0.059 2011 83 percent SCR+LNB+SOFA

1

In the case of the Parish units, we note that their <80 percent control efficiency is the result 

of low pre-SCR emission rates 

In the case of the Cholla units, which are also tangential coal-fired EGUs, our estimate of the 

level of performance of the SCR with LNB and OFA control option corresponds to 80 to 85 

percent control efficiency, which is in the low- to mid-range of SCR performance. We used these 

control efficiencies in our cost calculations on an annual average basis, and in our visibility 

modeling on a 24-hour average basis.145 Although the commenters have stated that they disagree 

with this level of control efficiency and the emission rate associated with it, they have not 

submitted information for the Cholla units documenting special circumstances that would justify 

a lower effective range of control efficiency for SCR. In fact, we note that certain aspects of 

APS’s own BART analyses for the Cholla units are based upon control efficiencies in a similar 

range. The original BART analyses performed by APS and submitted to ADEQ included 

visibility modeling indicating that SCR with LNB and OFA can achieve in the range of 83 to 86 

percent control efficiency for Cholla Units 2, 3 and 4. APS calculated these control efficiencies 

based upon the difference between the highest 24-hour average emission rate observed over a 

 

145 See 77 FR 42859, Table 18. 
Page 119 of 244

2001-2003 baseline period and a 24-hour average SCR emission rate of 0.07 lb/MMBtu. This 

information is summarized in Table 8. 

TABLE 8–SCR WITH LNB AND OFA CONTROL EFFICIENCY ESTIMATE

(APS ESTIMATE) 

Unit 

Baseline NOx Emissions 

(24-hour average) 

SCR+LNB+OFA 

Emission Rate 

(lb/MMBtu)1 Control 

Tech Period (lb/MMBtu) Control 

Efficiency

2

Cholla 2 0.503 CCOFA 2001-03 0.07 86 percent 

Cholla 3 0.410 CCOFA 2001-03 0.07 83 percent 

Cholla 4 0.415 CCOFA 2001-03 0.07 83 percent 

1

Per Table 2-1 of the original BART analysis for each unit, Docket Items B-06 

through B-08. 

2

Per Appendix A of the original BART analysis for each unit, Docket Items B06 through B-08. 

APS submitted updated visibility modeling to us as part of comments on our proposal, and with 

the exception of Cholla Unit 2, the baseline emissions and associated SCR control efficiencies do 

not differ from the original analysis.146 We note that APS did not use SCR emission rates 

consistent with these control efficiencies in other aspects of its BART analysis, such as on an 

annual average basis in cost calculations. If the control efficiencies calculated by APS are 

applied to baseline annual average emission rates, the Cholla units can achieve the values in 

Table 9. These values are consistent with our own estimates of SCR with LNB and OFA 

performance, and support the use of a 0.05 lb/MMBtu emission rate, on an annual average basis, 

in our cost calculations.147 

 

146 In the visibility modeling submitted a part of their comments, APS apparently identified a higher maximum 24-

hour average value from the 2001-2003 baseline period than the one identified in Table 8 for Cholla Unit 2. This 

results in an estimated SCR with LNB and OFA control efficiency of 87 percent. 

147 In addition, APS’s comments also included an SNCR design estimate based upon LNB performance of 0.22 

lb/MMBtu. Achieving an SCR emission rate of 0.05 lb/MMBtu from this emission rate would represent only 77 
Page 120 of 244

TABLE 9–SCR WITH LNB AND OFA EMISSION RATE

(PER APS CONTROL EFFICIENCY ESTIMATE) 

Unit Baseline NOX Emissions 

(Annual ave) SCR+LNB+OFA Emission Rate 

(lb/MMBtu) Ctrl Tech Period Control Efficiency (lb/MMBtu)

Cholla 2 0.326 CCOFA 2001-03 86 percent 0.045 

Cholla 3 0.304 CCOFA 2001-03 83 percent 0.052 

Cholla 4 0.296 CCOFA 2001-03 83 percent 0.050 

With regard to establishing the BART emission limit of 0.05 lb/MMBtu on a rolling 30-

day average, the commenters note that in the proposed Regional Haze FIP for North Dakota, we 

stated the following for the Milton R Young Station Unit 1, a coal-fired boiler for which we also 

proposed a NOX BART determination based on the use of SCR technology: 

In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted the annual design 

rate of 0.05 lb/MMBtu upwards to allow for a sufficient margin of compliance for a 30-

day rolling average limit that would apply at all times, including startup, shutdown, and 

malfunction.148 

The commenter also notes that we approved South Dakota’s Regional Haze SIP that established 

a BART emission limit of 0.10 lb/MMBtu (30-day rolling) for Big Stone I, based on the use of 

SCR technology, also citing a need for compliance margin for BART limits that must apply at all 

times including startup, shutdown, and malfunction (77 FR 24849). We agree with the 

commenter that it is appropriate to accommodate startup and shutdown events when establishing 

a rolling 30-day BART emission limit. Since these events, particularly startup, generate elevated 

levels of emissions, the particular day during which such an event occurs will appear as a shortterm “spike.” On an annual average basis, such short-term spikes can be averaged with 365 other 

 

percent control efficiency. This is well within the range of what SCR can achieve, even with a lower inlet NOX

emission rate. 

148 76 FR 58610. 
Page 121 of 244

values that allow them to be “smoothed out.”149 Since the limit was established on a shorter 

averaging period than the design basis (from 365 days to 30 days), there are fewer days (i.e., data 

values) with which such short-term spikes can be “smoothed out.” In the instances noted by the 

commenter, a less stringent value (from 0.05 to 0.07 for MR Young 1) was established for the 

shorter averaging period. 

In order to accommodate emissions from startup and shutdown events, we are finalizing 

two revisions to our proposed emission limit of 0.050 lb/MMBtu (rolling 30-day average). First, 

we are finalizing the limit as a “bubble” limit across Cholla Units 2, 3 and 4. By establishing the 

rolling 30-day limit across all three units, this allows the spike in emissions associated with a 

startup/shutdown event at one unit to be smoothed with the emission values from the other 

operating units. Second, we are also finalizing a less stringent value in order to establish an 

emission limit that accommodates the startup and shutdown events associated with the operating 

profile of the Cholla units. In determining what magnitude of revision is appropriate, we 

examined the emissions of the Cholla units, as reported to CAMD, over a 2001-2003 baseline 

period.150 We calculated annual average emission rates and 30-day rolling average emission rates 

using a calculation methodology corresponding to a bubble limit across all three units.151 Based 

on this methodology, we determined that the maximum annual average emission rate for these 

units was approximately 0.32 lb/MMBtu, while the maximum 30-day rolling average emission 

rate was approximately 0.35 lb/MMBtu. This represents an 8 percent difference between the 

highest rates observed on an annual and 30-day rolling average. We recognize that this 

 

149 The precise method by which such short term spikes will be ‘smoothed out’ over the period of a year will vary 

based upon the precise compliance determination methodology. The suggestion that it would be averaged with the 

other 364 days’ values is just a generic description of one type of averaging process. 

150 “Cholla CAMD emission data (daily) 2001-03” 

151 Please consult the regulatory language in our final action for the NOX compliance determination methodology 

associated with the bubble limit. 
Page 122 of 244

variability between annual average and 24-hour average emission rates is based on operation of 

the Cholla units with LNB and OFA, and may not be directly representative of the variability 

associated with operation of SCR. We are therefore finalizing an emission rate of 0.055 

lb/MMBtu as a bubble limit across Cholla Units 2, 3 and 4, which represents a 10 percent 

upward revision from the annual average design value. When combined with the 3-unit bubble, 

this represents an emission limit that we consider appropriate to ensure design and operation of 

the emission control system to provide the best available retrofit control.

Comment: EPA based LNB/SOFA emission rates on 2011 NOX emissions rates, which is 

not an accurate assessment of the capability of the installed LNB and SOFA. Arizona set the 

BART limit for Cholla Units 2, 3 and 4 at 0.22 lb/MMBtu. All three units were able to meet this 

limit in their acceptance test after LNB and SOFA were retrofitted, and APS believes they can 

meet it long term. In addition, an SNCR design study performed by Black and Veatch indicated 

that an SNCR system could obtain a control efficiency of approximately 25 percent, which 

would correspond to an emission rate of 0.17 lb/MMBtu. EPA’s cost and visibility estimates 

must be updated to reflect these levels. 

Response: We partially agree with this comment. In submitted comments, APS provided 

a conceptual design estimate for SNCR which was based upon 25 percent control efficiency 

(incremental from LNB) and a resulting emission rate of 0.17 lb/MMBtu. While this control 

efficiency is less than the 30 percent control efficiency used by our contractor, we consider it to 

be a reasonable estimate based upon the vendor quotes provided by APS.152 

We disagree with the use of an LNB emission rate of 0.22 lb/MMBtu, as the Cholla units 

have not demonstrated a consistent ability to operate at this emission rate under the current coal 

 

152 Black and Veatch’s report cites lower inlet NOx concentrations to the SNCR system. A lower inlet NOX emission 

rate makes it more difficult to reduce NOX emissions, which makes a lower removal efficiency reasonable. 
Page 123 of 244

contract for Lee Ranch/El Segundo coal. Based upon a review of CAMD emission data since the 

installation of LNB, we acknowledge that the Cholla units have, to varying degrees, operated 

with LNB at emission rates consistent with APS’s assertion of 0.22 lb/MMBtu during this 

period. However, as noted in our proposal, calendar year 2011 represented the first year at which 

the Cholla plant operated at the “full” minimum purchase quantity under its new contract for Lee 

Ranch/El Segundo coal, which is a higher NOX-emitting coal than what was previously used. 

Since the beginning of 2011 to September 2012, Cholla Units 3 and 4 have operated at or below 

an emission rate of 0.22 lb/MMBtu for only five to six months of this 21 month period, and 

Cholla Unit 2 has not operated at or below this emission rate in any month during this period.153

Therefore, an LNB emission rate of 0.22 lb/MMBtu is not supported by the actual recent 

operation of the Cholla units, so it is unlikely to be an appropriate representation of anticipated 

future emissions. 

 c. Costs of Compliance 

Comment: One commenter (APS) stated that, for EPA’s capital costs estimate, no backup material was provided, even when directly requested by APS. This lack of information makes 

it impossible for APS to comment on the validity of EPA’s cost estimates. The commenter also 

stated that EPA has not established its contractor or subcontractor responsible for the costs 

estimates as experienced in the engineering, procurement and construction of utility-scale air 

quality control systems. 

Response: We disagree with the commenter’s assertion that we have not provided 

sufficient information regarding our cost calculations. In the docket for our proposal, we 

included the raw cost calculation spreadsheets that contain the cost calculation equations, 

corresponding variable values, selected notes regarding assumptions and variable ranges, as well 

 

153 “Cholla CAMD emission data (monthly) 2010-12” 
Page 124 of 244

as selected tables from the IPM Base Case v4.10. 154 In addition, web links were also provided 

(both in the raw cost calculation spreadsheet and in our proposal) to the location on the publicly 

available EPA website that contains full IPM documentation. We note that both SRP and 

AEPCO were able to locate this spreadsheet, as both utilities submitted control cost estimates as 

part of their comments that revised certain variable values and assumptions in our contractor’s 

raw calculation spreadsheet. This information was initially developed by EPA contractors155 and 

was reviewed by EPA staff. Following the close of the public comment period on our proposed 

rulemaking, APS provided additional information concerning its own cost estimates. We have 

placed this information to the docket and taken it into account as part of this final rulemaking, as 

explained below. 

Comment: One commenter (APS) stated that EPA’s cost-effectiveness numbers in the 

proposed FIP are incorrect. The commenter stated that EPA used a capital recovery factor of 9.4 

percent, assuming an interest rate of 7 percent, but APS states that a capital recovery factor of 

13.4 percent should be used to account for income and property taxes and the cost of capital 

authorized by ACC in the last rate case. The commenter also stated that EPA analysis uses 

emissions factors for SCR that are not appropriate for the type of coal used, the units, or the 

averaging period. In addition, APS noted the cost values used in the IPM model and EPA’s CCM 

may be outdated, which may also lead to underestimation of the true costs. APS estimates costeffectiveness ranging from $7,719/ton to $8,894/ton, with incremental costs ranging from 

$8,759/ton to $10,329/ton compared to EPA’s estimates of $3,115/ton to $3,473/ton, with 

 

154 Document ID: EPA-R09-OAR-2012-0021-0008, File name: G15_MODELING_FILES_EGU_BART_Costs_Apache_Cholla_Coronado_FINAL2 

155 Specifically, the initial cost estimates were developed by Jim Staudt of Andover Technology Partners. While 

there is no requirement for EPA to establish that its contractors are “experienced in the engineering, procurement, 

and construction of utility-scale air quality control systems,” Dr. Staudt has extensive expertise and experience in 

the field of air pollution control at power plants. See: www.andovertechnology.com/staudt.html. 
Page 125 of 244

incremental costs ranging from $3,257/ton to $3,813/ton. APS included costs for surcharges, 

current AFUDC and fixed charge rates, and emissions factors based on the capability of the 

existing LNB and OFA at the plant, typical SNCR removal rates, and minimum SCR emissions 

for bituminous coal, 

In contrast, one commenter (Earthjustice) stated that SCR at Cholla is more cost-effective 

than EPA’s calculations suggest, in that EPA overestimated the costs by (1) using an 

unjustifiably high 7 percent interest rate; (2) amortizing costs over a 20-year life of the SCR 

system, rather than a more realistic life of 30 years or more; and (3) overestimating the costs of 

the SCR catalyst, reagent, auxiliary power and property taxes and insurance. In addition, the 

commenter asserted that EPA baseline period understates NOX emissions reductions compared to 

the baseline period of 2001-2004. According to the commenter, when the cost-effectiveness of 

SCR is calculated using more accurate costs, proper baselines and appropriate emission rates, the 

result is an even more cost-effective SCR investment that reduces NOX at a cost of $1,901/ton at 

Unit 2, $1,940/ton at Unit 3 and $2,076/ton at Unit 4. 

Response: Although we do not agree that our cost-effectiveness estimates were incorrect, 

we have performed a supplemental analysis using portions of the updated cost estimates 

provided by APS in its comments. In this supplemental analysis, we have generally relied upon 

APS’s estimates of capital costs and operating costs. While we do not find that these estimates 

were sufficiently supported with detailed site-specific information in all instances, we are using 

them as a conservative assumption (i.e., an assumption that would tend to overestimate rather 

underestimate the annualized cost of controls). As discussed in a previous response, we consider 

it appropriate to observe the broader cost methodology used in EPA’s CCM, and have adjusted 

or eliminated certain cost items not allowed by the CCM. A line-by-line comparison of APS’s 
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cost estimate and our revisions can be found in the docket for this rulemaking action.156 A 

summary of cost estimates based on this supplemental analysis is in Table 10, and includes the 

following: 

• Inclusion of APS’s updated cost estimates: We have adopted a ‘hybrid’ approach in 

which we have used APS’s capital cost and O&M cost estimates, while excluding those 

cost items not allowed by CCM methodology. As discussed in a previous comment, we 

have included owner’s costs up to the amount provided for “Engineering and Home 

Office Fees” as described by the CCM. We have excluded surcharge as well as AFUDC, 

which is inconsistent with CCM methodology. 

• Use of a 7 percent interest rate: We have retained the use of a 7 percent interest rate in 

calculating the capital recovery factor, and disagree with APS’s assertion that a 13.4 

percent interest rate is appropriate. For cost analyses related to government regulations, 

an appropriate “social” interest (discount) rate should be used. EPA calculated capital 

recoveries using 3 percent and 7 percent interest rates in determining cost-effectiveness 

for the Regulatory Impact Analysis (RIA) for the BART Guidelines.157,158 We consider 

our use of an interest rate of 7 percent to calculate capital recovery to be a conservative 

approach. 

• Use of original baseline period: As discussed elsewhere in our responses, we consider our 

use of a more recent baseline as consistent with BART Guidelines. However, in order to 

address commenter’s concerns that we did not properly consider LNB and OFA as a 

potential control option and therefore precluded a BART determination of LNB and 

 

156 Docket ID No. EPA-R09-OAR-2012-0021. 

157 Regulatory Impact Analysis for the Final Clean Air Visibility Rule or the Guidelines for Best Available Retrofit 

Technology (BART) Determinations Under the Regional Haze Regulations, EPA-0452/R-05-004 (June 2005). 

158 A 7 percent interest rate is recommended by Office of Management and Budget, Circular A-4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars—a004—a-4/ 
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OFA, we have used a baseline period of 2001-2003, which corresponds to the period used 

in APS’s original BART analysis. This represents a time period prior to the installation of 

LNB, during which the control technology in place on the Cholla units was only OFA. 

TABLE 10–CHOLLA CONTROL COST ESTIMATES

(PER APS COMMENTS, WITH EPA REVISIONS) 

Control Options 

Capital Cost 

($) 

Annualized 

Capital Cost 

($/yr) 

Annual 

O&M Cost 

($/yr) 

Total Annual 

Cost 

($/yr) 

Cholla 2 

LNB+OFA $4,482,254 $423,093 $120,000 $543,093 

SNCR w/ LNB+OFA $16,617,408 $1,568,566 $1,254,500 $2,823,066 

SCR w/ LNB+OFA $87,713,386 $8,279,523 $1,626,683 $9,906,206 

Cholla 3 

LNB+OFA $3,848,807 $363,300 $120,000 $483,300 

SNCR w/ LNB+OFA $19,238,125 $1,815,943 $1,254,500 $3,070,443 

SCR w/ LNB+OFA $83,461,195 $7,878,146 $1,570,766 $9,448,912 

Cholla 4 

LNB+OFA $5,334,618 $503,550 $170,000 $673,550 

SNCR w/ LNB+OFA $24,885,052 $2,348,973 $1,737,393 $4,086,366 

SCR w/ LNB+OFA $119,083,832 $11,240,671 $2,350,182 $13,590,853 

A summary of emission rates and emission reductions associated with each control option 

is in Table 11. As noted previously, these emission estimates are based on a 2001-2003 baseline 

period, during which the Cholla units operated only with OFA. We note that while APS has 

provided emission estimates for this baseline period, the values provided, both in the original 

BART analysis and in submitted comments, appear to represent the highest 24-hour average 

value for modeling purposes. Since control cost estimates are based on an annual average 

($/year), we have calculated annual emission rates for the OFA baseline using the annual average 

emission data reported to CAMD over this 2001-2003 baseline period. Comparing a baseline 

value on a 24-hour average basis (as provided by APS) to a control option value on an annual 

average basis is not an “apples-to-apples” comparison, as some portion of the emission reduction 
Page 128 of 244

in such a comparison would be attributable to the differences between moving from a 24-hour 

average to an annual average basis. 

TABLE 11–CHOLLA EMISSION ESTIMATES

Control Options 

Emission 

Factor 

(lb/MMBtu) 

Heat Rate 

(MMBtu/hr) 

Annual 

Capacity 

Factor 

Emission Rate 

Emissions 

Removed 

(tpy) (lb/hr) (tpy) 

Cholla 2 

OFA (only) 0.326 3,022 0.91 985 3,927 -- 

LNB+OFA 0.295 3,022 0.91 892 3,554 373 

SNCR w/ LNB+OFA 0.207 3,022 0.91 624 2,488 1,440 

SCR w/ LNB+OFA 0.050 3,022 0.91 151 602 3,325 

Cholla 3 

OFA (only) 0.304 3,480 0.86 1058 3,985 -- 

LNB+OFA 0.254 3,480 0.86 885 3,335 650 

SNCR w/ LNB+OFA 0.178 3,480 0.86 620 2,334 1,651 

SCR w/ LNB+OFA 0.050 3,480 0.86 174 655 3,330 

Cholla 4 

OFA (only) 0.296 4,399 0.93 1302 5,304 -- 

LNB+OFA 0.260 4,399 0.93 1144 4,661 643 

SNCR w/ LNB+OFA 0.182 4,399 0.93 801 3,263 2,042 

SCR w/ LNB+OFA 0.050 4,399 0.93 220 896 4,408 

Cost-effectiveness values for each control technology are summarized in Table 12, based on the 

total annual costs and annual emissions removed listed in the previous tables. 

TABLE 12–CHOLLA CONTROL OPTION COST-EFFECTIVENESS

Control Options 

Total Annual 

Cost 

($/yr) 

Emissions 

Removed 

(tpy) 

Cost-Effectiveness 

($/ton) 

Average Increment 

Cholla 2 

OFA (only) -- -- -- -- 

LNB+OFA $543,093 373 $1,454 -- 

SNCR w/ LNB+OFA $2,823,066 1,440 $1,961 $2,138 

SCR w/ LNB+OFA $9,906,206 3,325 $2,979 $3,757 

Cholla 3 
Page 129 of 244

OFA (only) -- -- -- -- 

LNB+OFA $483,300 650 $743 -- 

SNCR w/ LNB+OFA $3,070,443 1,651 $1,860 $2,586 

SCR w/ LNB+OFA $9,448,912 3,330 $2,838 $3,799 

Cholla 4 

OFA (only) -- -- -- -- 

LNB+OFA $673,550 643 $1,047 -- 

SNCR w/ LNB+OFA $4,086,366 2,042 $2,001 $2,441 

SCR w/ LNB+OFA $13,590,853 4,408 $3,083 $4,016 

Even based on cost estimates revised to use APS’s capital and O&M cost estimates, we 

still consider the cost-effectiveness values of SCR, on an average ($2,838 to $3,083/ton) and 

incremental ($3,757 to $4,016/ton) basis, to not be cost-prohibitive. We consider these results 

supportive of our proposed determination that SCR with LNB and OFA is cost-effective. We 

note that while the LNB and OFA option is the least expensive (i.e., lowest annual cost) and is 

the most cost-effective of the control technologies (i.e., has the lowest $/ton value), it is also the 

least effective control option. It removes substantially fewer emissions than either of the other 

two control options, the SNCR- and SCR-based systems. As discussed in our proposed action, 

and in other responses in this document, we have not identified any energy or non-air quality 

impacts that warrant eliminating SCR from consideration for the Cholla units. Combined with 

the modeled visibility improvement associated with this control option, these cost estimates 

continue to support the selection of SCR with LNB and OFA as BART for NOX at the Cholla 

units. 

 d. Visibility Improvement 

Comment: One commenter (NPS) agreed with EPA’s analysis of the visibility impacts of 

the alternative NOX control options for Cholla Units 2, 3 and 4 at the various impacted Class I 

areas, as presented in EPA’s TSD. The commenter also indicated that its estimates of the two 
Page 130 of 244

$/deciview measures of cost-effectiveness were similar to those of EPA. Specifically, the 

commenter’s analysis yielded values of $19.9 million for the “$/max deciview” metric and $3.7 

million for “$/cumulative deciview.” 

Response: We acknowledge the comment. 

Comment: One commenter (APS) hired a contractor to perform modeling with 

CALPUFF version 5.8 and the updated version of 6.42 to measure the sensitivity of various 

emission control scenarios at Cholla Units 2, 3 and 4 including two different background 

ammonia concentrations. The contractor found that regardless of which model version or 

background ammonia value was used, the highest predicted visibility improvement of SNCR or 

SCR, compared to LNB and OFA, is lower than the threshold for human perceptibility of 1.0 

deciview. Moreover, retrofitting SNCR or SCR at Cholla will not lead to any perceptible 

improvement in visibility at any of the 13 Class I areas within 300 km of the Cholla facility. 

Response: EPA disagrees with the ammonia concentration and CALPUFF model version 

used by the commenter for reasons discussed above. Further, we do not agree that the 

consideration of visibility improvement must directly reflect human perception. The CAA and 

the RHR require, as part of each BART analysis, consideration of “the degree of improvement in 

visibility which may reasonably be anticipated to result from the use of such technology.”159 The 

regulations do not require that the improvement anticipated to result from a particular technology 

at a particular source be perceptible by a single human being in order to be relevant as part of a 

BART determination. As EPA explained in the preamble to the BART Guidelines: 

Even though the visibility improvement from an individual source may not be 

perceptible, it should still be considered in setting BART because the contribution 

to haze may be significant relative to other source contributions in the Class I 

area. Thus, we disagree that the degree of improvement should be contingent 

 

159 CAA section 169A(g)(2), 40 CFR 51.308(e)(1)(ii)(A). 
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upon perceptibility.

160

Thus, in our visibility improvement analysis, we have not considered perceptibility as a threshold 

criterion for considering improvements in visibility. Rather, we have considered visibility 

improvement in a holistic manner, taking into account all reasonably anticipated improvements 

in visibility expected to result at all Class I areas within 300 kilometers of each source. 

Improvements smaller than 0.5 dv may be warranted considering the number of Class I areas 

involved, and the fact that in the aggregate, small improvements from controls on multiple 

BART and other sources will contribute to visibility progress.161

In addition, EPA is not obligated to focus on incremental costs and benefits to the 

exclusion of absolute costs and benefits. The BART Guidelines recommend consideration of 

both average and incremental cost-effectiveness,162 but do not expressly require or recommend 

consideration of incremental visibility improvement. Rather, they provide for consideration of 

net visibility improvement (i.e., “the visibility improvement based on the modeled change in 

visibility impacts for the pre-control and post-control emission scenarios” as opposed to the 

change between different control scenarios).163

Comment: One commenter (APS) noted that Cholla Units 2 and 3 have separate flues but 

share a single stack, which EPA failed to recognize in its visibility modeling. The commenter 

also noted that EPA failed to use the appropriate Good Engineering Practice (GEP) stack height 

correction required by EPA’s own rules for modeling. Because these errors result in visibility 

impacts in opposite directions, the net effect is less than 5 percent, based on modeling that APS 

has conducted. 

 

160 70 FR 39129. 

162 BART Guidelines, 40 CFR Part 51, Appendix Y, Section IV.d.4.b. 

163 Id. Section IV.D.5. 
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Response: If the commenter is correct that there were two errors that nearly cancel out, 

then this would appear to have little effect on EPA’s decision. The maximum area benefit of 

SCR was modeled by EPA to be 1.34 dv at Petrified Forest National Park, and 1.06 dv at Grand 

Canyon National Park; a 5 percent reduction in these would still result in substantial visibility 

benefits. EPA’s modeling was based on stack parameters provided by APS in a letter164 that did 

not mention the merged stack, although it was mentioned in APS’s BART analysis165 submitted 

to ADEQ. Stack parameters for Unit 4 provided in the commenter’s modeling do not match 

either of those documents (exit velocity of 77.1 feet/second versus 52 feet/second in APS’s 

letter). In addition, it is unclear how parameters for the merged stack in the commenter’s 

modeling were derived (except that the area of the merged stack used is equal to the sum of the 

areas of the individual stacks cited in the APS letter). Nevertheless EPA acknowledges that Units 

2 and 3 should have been modeled together as a single stack. EPA conducted additional 

modeling to assess this affect, assuming the same total stack exit area and volume flow rate as 

for the individual stacks, and a volume-weighted average of the individual stacks’ absolute exit 

temperatures. EPA found that impacts and improvements decreased by some 11 percent when 

merged stacks are used. The improvement from SCR at Petrified Forest remains over 1.0 dv, 

with continued substantial benefit at Grand Canyon. A merged stack for Units 2 and 3 was also 

assumed in additional modeling EPA performed to address H2SO4 emissions for Cholla, as 

described below. 

EPA’s Guideline on Air Quality Models (40 CFR 51 Appendix W) at section 6.2.2 

requires that facilities be modeled using a stack height consistent with GEP, rather than a higher 

actual stack height, in order to prohibit “stack height credit” from being used in developing 

 

164 “Request for Information Relating to Cholla Power Plant”, letter from Sue Kidd, Director, Corporate 

Environmental Policy and Programs, to Francisco Doñez, EPA, (February 3, 2012). 

165 “BART Analysis for Cholla Unit 2,” Prepared for APS by CH2MHill (January 2008). 
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emission limits.166 By building very tall stacks instead of applying emission controls, facilities 

could avoid violating the NAAQS locally, but would contribute to higher levels of emissions 

regionally, and cause higher total pollutant levels downwind. In short, the requirement to use 

GEP stack height generally results in conservative modeling, thereby removing the incentive to 

build artificially tall stacks to evade controls. Choosing a stack height or taking credit for a stack 

height increase is not at issue in a BART determination. The visibility impacts and 

improvements shown in EPA’s BART modeling are closer to the actual values if actual stack 

heights are used. Insofar as GEP is relevant, using shorter GEP heights would tend to increase 

both pre- and post-control impacts, and to scale up the estimated visibility improvements. The 

overall effect would be to strengthen the case for EPA’s proposed controls. 

Comment: Based on a report submitted with the comments, one commenter (Earthjustice) 

stated that had EPA’s BART analysis included lower emission rates and proper baselines, the 

visibility benefits of SCR at Cholla Units 2, 3 and 4 would be even greater than the 7.21 dv 

cumulative visibility benefit discussed in the proposed rule. 

Response: As explained in the general discussion regarding selection of baseline periods 

above, we do not agree that we used an improper baseline. However, we agree that higher 

baselines and lower post-control emissions would show greater benefits than our modeling 

showed, and would further support our proposal for SCR. 

Comment: One commenter (APS) stated that EPA incorrectly applied H2SO4 mitigation 

factors from an Electric Power Institute (EPRI) report167 in reaching its conclusion that H2SO4 

production is not a problem with SCR at Cholla. The commenter stated that this factor is actually 

 

166 Guideline on Air Quality Models 6.2.2.a. “The use of stack height credit in excess of Good Engineering Practice 

(GEP) stack height or credit resulting from any other dispersion technique is prohibited in the development of 

emission limitations by 40 CFR 51.118 and 40 CFR 51.164.” 

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

Update, Electric Power Research Institute, April 2010) 
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90 percent rather than 99 percent in the report, but that this factor only applies to sub-bituminous 

coal because of the high calcium content in the ash of these coals. The commenter stated that 

testing at the Four Corners Power Plant (FCPP), which has similar coal ash calcium content to 

that at Cholla, indicates that 15 percent removal by the fabric filters would be likely. The 

commenter stated that the H2SO4 emissions created by the SCR will exceed the NSR significance 

level, will result in costs associated with the H2SO4 emissions, and will reduce the improvement 

in visibility anticipated by the retrofitting with SCR. 

Another commenter (ADEQ) also stated that EPA discounts the impact of sulfuric acid 

mist that will be generated by SCR and overestimates the acid mist removal rate. The commenter 

indicated that testing at another facility shows H2SO4 removal to be closer to 57 percent rather 

than EPA’s assumed 99 percent removal. The commenter noted that if H2SO4 emissions increase 

above the PSD significance threshold, a PSD permit and BACT analysis would be required. 

EPA’s BART analysis fails to consider the costs associated with likely BACT requirements of 

low oxidation catalyst, fuel additives or sorbent injection with a polishing baghouse. 

Response: EPA’s decision to discount the increase of H2SO4 caused by oxidation from 

the SCR catalyst was actually based on the 90 percent control figure; we erroneously wrote 99 

percent (which applies to ammonia reduction from a wet scrubber). This figure is from the 0.10 

percent penetration for baghouses, the only one available for baghouses in the EPRI report. It is 

not clear that results from the testing at FCPP referenced by the commenter may be applied 

directly to Cholla given the differences between the facilities. In addition, the full test results 

were not provided, so we cannot rely on the commenter’s figures.

In any case, EPA does not believe that BART is the appropriate context for addressing 

this issue. Actual measurements of baseline sulfuric acid emissions have not yet been determined 
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at Cholla. Moreover, the calculation of projected sulfuric acid emissions after installation and 

operation of SCR using the EPRI methodology is dependent on future decisions made by the 

facility on the type of SCR catalyst and number of layers used, as well as numerous assumptions 

about loss to downstream components (i.e., air preheaters and baghouses), the true values of 

which are currently not yet defined or known for Cholla. An increase in sulfuric acid emissions 

from the installation of SCR may trigger major modification PSD permit requirements at a low 

threshold of seven tons per year.168 Preconstruction permitting review may also be triggered from 

significant emissions increases of PM2.5 from SCR installation at Cholla. If one of these 

pollutants triggers PSD, the permitting authority must provide an Additional Impact Analysis 

under the PSD program. The PSD program also requires the permitting authority to determine 

BACT for pollutants that triggered PSD. For these reasons, Region 9 has determined that for 

Cholla, emission limits and monitoring requirements for sulfuric acid are more appropriately 

reviewed in the preconstruction permitting process. 

Nevertheless, EPA conducted additional CALPUFF modeling to assess the visibility 

effect of increased sulfuric acid due to the SCR catalyst. One scenario used the existing modeling 

for Cholla, but added in SCR sulfate calculated by the method in the EPRI document. Since the 

existing modeling used sulfate calculated using PM speciation spreadsheets provided by the 

National Park Service, this scenario mixes two calculation methods and may not be reliable. The 

sulfate in the existing modeling is so large that the additional SCR sulfate from the EPRI method 

increases total sulfate by only about 5 percent. Visibility benefits only decreased by about three 

percent at Petrified Forest, and by an even smaller fraction at other areas. To assess the SCR 

sulfate effect in a more consistent manner, EPA calculated sulfate using the EPRI method 

throughout the base case for SCNR, and for SCR. All cases used a merged stack for Units 2 and 

 

168 See 40 CFR 52.21(b)(23)(i). 
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3 and consistent speciation for all units (formerly the speciation for Unit 2 differed from the 

others). The sulfate emissions from the EPRI method are much lower than from the NPS 

spreadsheets, but SCR increases that amount by a factor of six (even with the increase the total is 

still far lower than used in the original modeling). The visibility impacts for all cases are 

substantially lower than in the former modeling; the maximum area base case impact is 3.51 dv 

at Petrified Forest compared to 4.53 dv previously. But for some areas the impacts from controls 

declined more than the impacts from the base case, leading to the somewhat surprising result that 

the improvement due to controls actually increased relative to the original modeling. The 

maximum area benefit of SCR in the new modeling is 1.55 dv compared to 1.34 dv in the 

original. The cumulative area benefit decreased very slightly to 7.19 dv compared to 7.21 in the 

original. Based on this improved estimate of sulfate emission based on the EPRI method, the 

case for SCR appears to be strengthened, since the maximum visibility improvement is larger 

than originally estimated. 

 e. Other Comments 

Comment: One commenter (NPS) agreed with EPA’s conclusions on Cholla that the 

visibility improvement associated with the most stringent option (SCR with LNB and OFA) is 

substantial; that SCR with LNB and OFA is 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); 

and 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 the units of 0.050 lb/MMBtu, based on a rolling 30-boileroperating-day average. 

Response: We acknowledge the comment. 
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Comment: One commenter (APS) estimated that EPA’s proposed controls on Cholla 

Units 2 and 3 will cost $248 million and $103 million, respectively, and increase the costs of 

electricity from those units by over 25 percent. The commenter stated that given the current 

market price for natural gas, the proposed BART requirements, expected coal ash regulations, 

and potential future carbon legislation could jeopardize the long-term economic viability of the 

entire plant. The commenter also stated that EPA did not consider the impacts of requiring SCR 

on ratepayers’ monthly bills, which would be about 2 percent to accommodate SCR alone. In 

addition, the commenter is concerned about potential impacts on the transmission grid in 

Arizona, the local economy due to lost jobs, and a reduced diversity in APS’s fuel mix if Cholla 

was to close. 

Response: It is not EPA's intention to endanger the economic viability of Cholla or to 

place an undue burden on APS’s customers. Neither the CAA nor the RHR requires states or 

EPA to consider the affordability of controls, ratepayer impacts or potential job losses as part of 

a BART analysis. Rather, they require consideration of “the costs of compliance, the energy and 

non-air quality environmental impacts of compliance, any existing pollution control technology 

in use at the source, the remaining useful life of the source, and the degree of improvement in 

visibility which may reasonably be anticipated to result from the use of such technology.”169

APS’s comments appear to be based in part on a misunderstanding that an analysis of 

“non-air quality environmental impacts” must include economic effects. In fact, the plain 

language of the statute, as well as the RHR, makes clear that this factor is limited to non-air 

quality environmental impacts.170 The BART Guidelines note that examples of such impacts 

 

169 CAA section 169A(g)(2), 42 U.S.C. § 7491(g)(2); 40 CFR 51.308(e)(1)(ii)(A) (emphasis added). 

170 Id.
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would include “solid or hazardous waste generation and discharges of polluted water from a 

control device.”171 

The BART Guidelines do allow for (but do not require) the consideration of “significant 

economic disruption or unemployment” as part of “energy impacts.” Specifically, the Guidelines 

provide that: 

. . . the energy impacts analysis may consider . . . whether a given alternative 

would result in significant economic disruption or unemployment. For example, 

where two options are equally cost effective and achieve equivalent or similar 

emissions reductions, one option may be preferred if the other alternative results 

in significant disruption or unemployment.172

The Guidelines also allow for consideration of “affordability” as part of the “costs of 

compliance” under certain circumstances: 

1. 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. 

2. There may be unusual circumstances that justify taking into consideration the 

conditions of the plant and the economic effects of requiring the use of a given 

control technology. These effects would include effects on product prices, the 

market share, and profitability of the source. Where there are such unusual 

circumstances that are judged to affect plant operations, you may take into 

consideration the conditions of the plant and the economic effects of requiring the 

use of a control technology. Where these effects are judged to have a severe 

impact on plant operations you may consider them in the selection process, but 

you may wish to provide an economic analysis that demonstrates, in sufficient 

detail for public review, the specific economic effects, parameters, and 

reasoning.173

Thus, only under “unusual circumstances” where a potential control option is expected to 

have a “severe impact on plant operations” or “result in significant economic disruption 

or unemployment” can we consider economic effects as part of a BART determination. In 

this case, APS has provided no evidence to support its assertions that our proposed FIP 

 

171 BART Guidelines section IV.D.4.h 

172 Id. section IV.E.2. 

173 Id. section IV.E.3. 
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would result in significant rate increases, jeopardize the plant’s operations, or result in 

any other economic effects. In the absence of such evidence, APS’s assertions regarding 

plant shutdown, rate increases and job losses are speculative, and we cannot consider 

them as part of our BART determination. 

Comment: One commenter (PacifiCorp) stated that because the regional haze actions in 

Arizona, Wyoming, Colorado and elsewhere will have an impact of $100 million or more on the 

company and its customers, EPA must conduct the regulatory analyses required by the Unfunded 

Mandates Reform Act (UMRA) and Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use (Executive Order 13211) before reaching conclusions 

regarding BART controls or imposing a regional haze FIP. 

Response: The commenter is combining separate regulatory actions. The commenter is 

not correct in aggregating the potential private sector mandate of separate rules to evaluate 

whether UMRA applies. UMRA defines the term ‘Federal private sector mandate’ to mean any 

provision in regulation that would impose an enforceable duty upon the private sector. Under 

UMRA, the term “regulation” or “rule” means any rule for which the agency publishes a general 

notice of proposed rulemaking. The rule being finalized today is limited to addressing the 

obligations of three facilities in Arizona and does not include other regional haze actions 

occurring in separate rulemakings, such as for Wyoming and Colorado. 

Under section 202 of UMRA, before promulgating any final rule for which a general 

notice of proposed rulemaking was published, EPA must prepare a written statement, including a 

cost-benefit analysis, if that rule includes any “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. Under Title II of UMRA, EPA has determined that 
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this rule does not contain a Federal mandate that may result in expenditures that exceed the 

inflation-adjusted UMRA threshold of $100 million (in 1996 dollars) by State, local, or Tribal 

governments or the private sector in any one year. Even using the higher cost estimates in our 

supplemental analysis for the FIP we are finalizing today, we estimate that the total annual costs 

in the aggregate will not exceed $65 million.174 Finally, this rule 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. 

Comment: One commenter (APS) disagreed with EPA’s conclusion that the use of 

anhydrous ammonia does not pose significant additional safety concerns compared to aqueous 

ammonia and urea. The commenter contends that while anhydrous ammonia would be 

transported by rail, safety concerns are not eliminated because the severity of damage in an 

accident can be much greater, if less frequent than truck accidents, and constitutes a much higher 

risk after delivery. Due to the hazards of moving and storing anhydrous ammonia, the 

Department of Homeland Security and EPA have additional requirements for anhydrous 

ammonia that result in additional costs to use it. Urea costs more than anhydrous ammonia, but it 

is safer and less expensive to use and store. Due to these factors the commenter stated that SNCR 

and SCR costs should include the use of urea rather than anhydrous ammonia. 

Response: The BART analyses submitted by APS indicate that the annualized cost of 

urea at each of the Cholla units would be less than the annualized cost of anhydrous ammonia.175

 

174 Using total annual costs from our supplemental analysis, annual aggregate cost equals $64,378,422. This amount 

consists of: $9,906,206 for Cholla Unit 2, $9,448,912 for Cholla Unit 3, and $13,590,853 for Cholla Unit 4 (See 

Table 10 of this NFRM); $12,103,941 for Coronado Unit 1 and $235,982 for Coronado Unit 2 (See Tables 15 and 

13 of this NFRM); and $9,546,264 for each of Apache Units 2 and 3 (See Table 5 of this NFRM). 

175 See BART Analysis for Cholla Unit 2, Appendix A, Economic Analysis, Input Calculations; BART Analysis for 

Cholla Unit 3, Appendix A, Economic Analysis, Input Calculations; BART Analysis for Cholla Unit 4, Appendix A, 

Economic Analysis, Input Calculations. 
Page 141 of 244

In addition, the cost estimates provided by APS in comments are based on the use of urea as a 

reagent. Accordingly, we have used the cost for urea in our supplemental cost analysis. 

Comment: One commenter (APS) noted that Cholla has a long history of installing 

pollution control equipment, has participated in a voluntary emissions reduction project, and has 

spent over $473 million to reduce emissions. While Unit 1 at Cholla is not BART-eligible, it is 

equipped with a wet-tray absorber to control SO2, a fabric filter to control particulates, and LNB 

with OFA to control NOX emissions. Unit 2 is BART-eligible and has a mechanical dust 

collector for particulate control, a wet flooded-disk venturi scrubber and absorbers to control 

SO2, additional particulate controls, and LNB with OFA to control NOX emissions. Units 3 and 4 

have wet open-spray FGD absorber to control SO2, fabric filters to control particulates, and LNB 

with OFA to control NOX emissions. Unit 2 is scheduled to upgrade its SO2 and particulate 

controls to be identical to Units 3 and 4 by January 1, 2016. 

Response: We appreciate that APS has installed various controls on the Cholla units over 

the last several years and we have taken these existing controls into account as part of our BART 

analysis for NOX.

176 However, we note that, even with all of these new controls, emissions from 

Cholla still cause visibility impairment at nine Class I areas and contribute to impairment at an 

additional two areas.177 

Comment: One commenter (APS) requested that EPA allow the flexibility of averaging 

NOX emissions across all the BART-eligible units at the plant. The commenter stated that 

allowing for this flexibility would make no difference from a visibility improvement perspective. 

 

176 77 FR 42854 (noting that “[t]he 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.”) 

177 See 77 FR 42861, Table 20 (showing baseline impacts from Cholla of over 1 dv at nine Class I areas, and impacts 

of over 0.5 dv at eleven areas). 
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Response: We agree with the commenter, and have finalized a single NOX emission limit 

across Cholla Units 2, 3 and 4. 

 3. Comments on Coronado Units 1 and 2 

 a. Selection of Baseline Period 

Comment: Two commenters (ADEQ and SRP) stated that EPA’s selected baseline 

emissions period inappropriately eliminated consideration of LNB with OFA as a viable BART 

control strategy. SRP asserted that EPA’s decision to include LNB with OFA in its baseline NOX

emissions estimate cannot, consistent with the BART rules, foreclose consideration of those 

controls as BART for Coronado, and that EPA’s failure to consider these controls in its BART 

assessment makes the proposed rule invalid. The commenter added that emission reductions 

already achieved at the facility using LNB with OFA should not be ignored in EPA’s analysis 

simply because EPA delayed review of ADEQ’s SIP until 2012. The commenter concluded that 

EPA should give deference to the baseline emissions period selected by the State in its SIP 

analysis and fully consider LNB with OFA as an appropriate basis for BART emission 

limitations for Coronado. 

Another commenter (NPS) preferred the use of a baseline period before the installation of 

LNB with OFA instead of the post-installation period (May 16, 2009 to December 31, 2010) 

used by EPA. For Unit 2, the commenter stated that the federally enforceable limit of 0.080 

lb/MMBtu is a realistic depiction of future emissions even though the required SCR system has 

not yet been installed. 

Response: As explained in the general discussion regarding selection of baseline periods 

above, we disagree that our use of updated baseline periods for BART determinations is 

inappropriate or inconsistent with the CAA or the RHR. Moreover, updating the baseline did not 
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eliminate LNB with OFA from consideration as BART for Coronado Unit 1, since existing 

controls can constitute BART, if additional controls are not warranted based on the five-factor 

analysis. For example, EPA recently approved a determination by Colorado that existing LNB at 

Comanche Units 1 and 2 constituted BART where “the State determined that the added expense 

of achieving lower limits through different controls was not reasonable based on the high costeffectiveness [$9,900/ton] coupled with the low visibility improvement (under 0.2 dv) afforded.”

178 In the case of Coronado, by contrast, the cost-effectiveness of post combustion controls is 

reasonable and the expected visibility improvements are substantial, as explained below. 

Nonetheless, in order to address the commenter’s concerns that we did not properly consider 

LNB with OFA as a potential control option, and therefore precluded a BART determination of 

LNB with OFA, we have used a baseline period of 2001-2003, which corresponds to the period 

used in SRP’s original BART analysis. Our supplemental cost analysis for Coronado is 

summarized in Table 15.179

 b. Control Efficiencies 

Comment: One commenter (SRP) stated that the SNCR NOX emission rate evaluated by 

EPA is incorrect. The commenter cited an SNCR conceptual design estimate prepared by S&L 

(attached to the submission) asserting that, based on an initial review of SNCR implementation 

at Coronado, the expected NOX reductions would be 25 percent and notes that additional studies 

would be needed to guarantee this performance. According to the commenter, this estimate also 

was verified by an independent vendor, FuelTech, whose assessment was also attached to the 

submission. 

 

178 77 FR 18052, 18066 (March 15, 2012) (Proposed Rule); pre-publication version of Final Rule, signed September 

10, 2012, available at: http://www.epa.gov/region8/air/FinalActionOnColoradoRegionalHazePlanSep2012.pdf. 

179 A spreadsheet titled “Supplemental Cost Analysis 2012-11-15.xls” is in the docket. 
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The commenter (SRP) assumed that EPA evaluated an emission limit that is based on a 

higher reduction efficiency (i.e., 30 percent) applied to a starting NOX emission limit of 0.30 

lb/MMBtu. According to the commenter, given Coronado’s current NOX emissions limit of 

0.320 lb/MMBtu following the installation of LNB with OFA on each of the units and an SNCR 

control efficiency of 25 percent, the appropriate NOX emission rate to use in the BART analysis 

would be 0.24 lb/MMBtu, rather than EPA’s assumed value of 0.21 lb/MMBtu. The commenter 

contended that this NOX emission rate (i.e., 0.24 lb/MMBtu) represents a level that can likely be 

achieved on a consistent basis based on input from SRP’s vendors who have specific SNCR 

implementation experience. 

Response: We partially agree with this comment. Coronado Unit 1 currently operates 

with a federally-enforceable NOX emission limit of 0.320 lb/MMBtu.

180 A review of recent 

emission data in CAMD indicates NOX emission levels below this limit. As noted in our 

response to SRP’s comments regarding SCR, we agree that when using an annual average design 

emission rate to establish a rolling 30-day limit that will apply during periods of startup, 

shutdown, and malfunction events, it is appropriate to include some type of measure that 

provides a compliance margin. 

In submitted comments, SRP provided a conceptual design estimate for SNCR which was 

based upon 25 percent control efficiency (incremental from LNB) and a resulting emission rate 

of 0.24 lb/MMBtu. While this control efficiency is less than the 30 percent control efficiency 

used by our contractor, we consider it to be a reasonable estimate based upon the vendor quotes 

provided by SRP.181 When using a control efficiency of 25 percent and our baseline period of 

 

180 See Coronado Title V Permit, Attachment B, section II.E.1.a.ii. 

181 Although the report cites lower NOX concentrations, due to the lower inlet NOX emission rate, removal efficiency 

is also reduced making it more difficult to reduce NOX emissions. 
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LNB performance for Coronado Unit 1, we estimate an annual average SNCR emission rate of 

0.22 lb/MMBtu. 

For the purposes of our cost calculations and visibility modeling, however, we have 

retained the use of our original SNCR emission rate (0.21 lb/MMBtu). A less stringent SNCR 

emission rate, by itself, would primarily make the next most stringent control option, SCR, 

appear to remove a greater amount of emissions. This in turn would make the SCR control 

option appear more incrementally cost-effective by removing a greater amount of emissions, 

relative to SNCR, for the same cost. As discussed in our proposal and in response to comments, 

we already consider SCR to be cost-effective. It is not determinative to our decision to find that 

SCR is “even more” incrementally cost-effective. 

In the context of establishing a BART emission limit consistent with the use of SNCR 

technology, however, we would use the annual average SNCR emission rate of 0.22 lb/MMBtu 

as our basis, rather than our original estimate based on 30 percent SNCR control efficiency. As 

noted in a separate response, when using an annual average design emission rate to establish a 

rolling 30-day limit that would apply during periods of startup, shutdown, and malfunction, we 

consider it appropriate to provide some type of measure that provides a compliance margin for 

such events. A 0.24 lb/MMBtu emission limit, as requested by SRP, established on a rolling 30-

day average represents about a 10 percent increase from the 0.22 lb/MMBtu annual average 

emission rate. We would consider this magnitude of upward revision appropriate to 

accommodate startup, shutdown, and malfunction events as well as the unit cycling nature of 

Coronado Unit 1. As a result, we would consider the BART emission limit corresponding to the 

SNCR with LNB and OFA option to be 0.24 lb/MMBtu. 
Page 146 of 244

Comment: One commenter (SRP) stated that EPA improperly ignored the Coronado 

consent decree in its selection of the proposed BART controls for NOX. The commenter noted 

that ADEQ determined that NOX BART for Coronado Units 1 and 2 is LNB with OFA and a 

corresponding emission limit of 0.320 lb/MMBtu, making Units 1 and 2 currently subject to a 

0.320 lb/MMBtu NOX limit. The commenter added that Unit 2 will be subject to a 0.080 

lb/MMBtu NOX emission limit as soon as the SCR for that unit is installed and operational (i.e., 

by June 1, 2014), pursuant to the consent decree, a limit that is significantly more stringent than 

what the state determined to be BART for Coronado. 

The commenter (SRP) asserted that the consent decree controls are better than BART. 

The commenter pointed out that once SCR is installed on Unit 2, the facility will be subject to a 

plant‐wide emission limit of 7,300 tons of NOX per year under the consent decree which, 

according to the commenter, translates to an effective emission rate of 0.20 lb/MMBtu for 

Coronado as a whole, and is more stringent than the state’s NOX BART determination and 

EPA’s presumptive NOX limits. 

The commenter (SRP) also contended that EPA’s BART rules support the conclusion that 

the existing and currently planned controls are better than NOX BART because those controls 

and emission rates were agreed to by SRP and EPA to resolve allegations of violations of certain 

requirements of the PSD program for both units. According to the commenter, those limits are 

intended to reflect compliance with the PSD program’s BACT requirements. The commenter 

noted that BACT, by definition, reflects the maximum degree of control for new facilities or 

existing facilities undergoing a major modification while BART is to apply to unmodified 

existing sources. So BACT would be expected to be more stringent, and certainly not less 

stringent, than BART. The commenter quoted a recent EPA statement about the Four Corners 
Page 147 of 244

Power Plant indicating that BART need not be equivalent to BACT (citing 77 FR 51620, 51636, 

August 24, 2012). 

The commenter (SRP) asserted that the BART rules reflect this understanding, providing 

that PSD settlement agreements generally satisfy BART requirements (citing 70 FR 39164). 

According to the commenter, EPA recently recognized this principle in its final regional haze 

rule for North Dakota in which EPA concluded that it was appropriate to rely on North Dakota’s 

BACT determination for the two units at the Milton R. Young Station (0.36 lb/MMBtu and 0.35 

lb/MMBtu) to satisfy BART because emissions control technology had not changed appreciably 

since that BACT determination (citing 77 FR 20897). The commenter stated that a similar 

situation is present in the case of Coronado, and the recent PSD consent decree should, pursuant 

to the BART Guidelines, be deemed to satisfy BART. 

Response: We do not agree that we improperly ignored the existing consent decree in our 

proposed BART determination for NOX at Coronado, since we specifically took the consent 

decree into account throughout our NOX BART analysis.182 We also do not agree that the 

Coronado consent decree represents BACT or BART for NOX. While the consent decree 

concerned alleged violations of the PSD provisions of the CAA, it does not indicate that its 

provisions represent either BACT or BART. Rather, it specifically provides that: 

Compliance with the terms of this Consent Decree does not guarantee compliance 

with all applicable federal, state, or local laws or regulations. The emission rates 

and removal efficiencies set forth herein do not relieve SRP from any obligation 

to comply with other state and federal requirements under the Clean Air Act . . .

183

 

182 See 77 FR 42849-42850 (summarizing terms of consent decree), 42861- 42862 (describing consideration of 

consent decree requirements in baseline for Coronado analyses), 42863 (noting potential effect of consent decree 

activities on cost analysis), 42864 (proposing emission limit of 0.080 lb/MMBtu and compliance deadline of June 1, 

2014 at Coronado Unit 2, consistent with the emission limit in the consent decree). 

183 Consent Decree in United States v. Salt River Project, CV 08-1479-PHX-JAT (entered December 19, 2008). 
Page 148 of 244

While the BART Guidelines provide that NSR/PSD settlement agreements may represent BART 

in some instances, they do not establish a presumption that such settlements represent BART, nor 

do they indicate that a BART analysis is unnecessary where such a settlement exists.184 In 

Coronado’s case, we do not agree that the consent decree represents BART for NOx for either 

unit or for the facility as a whole. Nonetheless, we are taking the consent decree into account in 

our BART determination for NOX at Coronado, as described below. 

Comment: In arguing against the achievability of EPA’s proposed limit, two commenters 

(AUG and SRP) cited a report prepared by RMB Consulting & Research, Inc. (RMB) for the San 

Juan Generating Station in New Mexico, which reportedly states that the 0.05 lb/MMBtu limit 

imposed on that facility does not represent a consistently achievable level of emissions for the 

units at the facility. In addition, SRP contracted with RMB and Sargent and Lundy (S&L) to 

review the ability of the Coronado units to achieve the 0.050 lb/MMBtu emission limit proposed 

by EPA using SCR control technology. Their reports were submitted as attachments to the 

commenter’s submission. According to the commenter, both consultants concluded that a NOX

BART limit of 0.050 lb/MMBtu is not achievable at Coronado on a 30‐day rolling average that 

includes periods of startup, shutdown, and malfunction. The commenter made the following 

arguments against the achievability of a limit of 0.050 lb/MMBtu relying first on RMB’s 

analysis and then on S&L’s analysis. 

RMB’s analysis stated that EPA did not adequately consider the impact of startup and 

shutdown emissions or the ability to measure such emissions in its BART determination. RMB 

examined operating data from 2001 to 2011 in order to identify the number of startup events 

(both “cold” and “warm” starts) and shutdown events associated with each unit. RMB’s analysis 

 

184 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.C. 
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shows that the average number of startup/shutdown events for Coronado Units 1 and 2 is one per 

month (each), and that the maximum number of startup/shutdown events is five per month 

(Coronado Unit 1) and six per month (Coronado Unit 2). RMB then developed a computer model 

to estimate the 30-day rolling average the Coronado units could achieve based upon the 

emissions profile of these startup/shutdown events, the maximum number of startup/shutdown 

events, and an assumption of a NOX emission rate of 0.04 lb/MMBtu over the life of the catalyst. 

RMB’s analysis indicates that the maximum 30-day average the units could achieve is well 

above 0.050 lb/MMBtu. 

S&L’s analysis focused on the ability of Coronado Unit 2, which has been designed to 

achieve a 0.08 lb/MMBtu emission rate, to achieve a lower 0.05 lb/MMBtu emission rate. S&L’s 

analysis considered multiple design changes and examined their potential impact on reducing the 

design emission rate, as well as the costs and design/construction time associated with these 

options. S&L concluded that, at a minimum, SRP would be required to install a low load 

temperature control system designed to increase flue gas temperatures at the SCR inlet during 

periods of low load cycling to achieve any additional reduction in average NOX emissions. 

S&L’s analysis concluded that even with a low‐load temperature control system, Unit 2 could 

not consistently achieve the proposed limit when periods of low‐load cycling, startup and 

shutdown are taken into account, and could only achieve within the range of 0.053 to 0.072 

lb/MMBtu. 

Finally, both AUG and SRP noted that the BART Guidelines authorize application of 

BART emission limits on a plant-wide basis, rather than a unit-by-unit basis, and that use of 

plant-wide limits would not affect the expected visibility benefits of controls. Therefore, they 

requested that EPA allow for plant-wide averaging at Coronado. 
Page 150 of 244

Response: We partially agree with this comment. As noted by the commenters, the 

BART Guidelines recommend that states “consider allowing sources to ‘average’ emissions 

across any set of BART-eligible emission units within a fenceline . . .”185 Given that such a 

“bubbling” approach would not diminish the visibility benefits of controls, we have decided to 

finalize a single plant-wide limit across the two Coronado units. 

In analyzing what emission limit would represent BART for NOX on a plant-wide basis, 

we have taken a number of factors into consideration. In our proposal, we used an annual 

average design value for SCR of 0.050 lb/MMBtu at Coronado Unit 1 and proposed an emission 

limit for this same value on a rolling 30-day average. At Coronado Unit 2, we proposed an 

emission limit of 0.080 lb/MMBtu, but solicited comment on whether a more stringent limit 

would be feasible and cost-effective for Unit 2. SRP submitted comments stating that an 

emission rate of 0.05 lb/MMBtu was not achievable by either unit, due to the startup/shutdown 

operating profile of the Coronado units. As noted in other responses, BART limits apply at all 

times including periods of startup, shutdown, and malfunction. As a result, we agree with 

commenters that when establishing a rolling 30-day BART emission limit that is based upon an 

annual average design value, it is appropriate to provide a compliance margin for periods of 

startup and shutdown. Therefore, we have taken into consideration the startup/shutdown 

operating profile of the Coronado units. 

In submitted comments, SRP included reports prepared by S&L and RMB Consulting 

summarizing an analysis performed to determine the rolling 30-day emission rates the units 

could achieve when accounting for startup and shutdown events, as well as the load cycling 

 

185 BART Guidelines, 40 CFR Part 51, Appendix Y, section V. 
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operating profile of the plant.186 The analyses in the two reports were based on slightly different 

assumptions. RMB’s analysis, which examined both Coronado Units 1 and 2, included the 

following assumptions: 

• Five to six startups (1 cold/remainder warm) per month (which is the maximum observed 

based on 2001 to 2011 historical performance); 

• Startup emissions based on the maximum value observed during that startup period; 

• Non-startup periods of operation based on historical load operation, which consists of a 

mixture of low load and high-load cycling operation; 

• Inclusion of a low load temperature control system; and 

• Maintaining the catalyst guarantee of 0.04 lb/MMBtu during full load, steady-state 

operations over the life of the catalyst. 

The analysis performed by S&L examined only Coronado Unit 2, and was one element of S&L’s 

broader analysis examining the ability of Coronado Unit 2 to meet a limit more stringent than the 

0.080 lb/MMBtu limit in the consent decree. The analysis performed by S&L was based on the 

following assumptions: 

• One to three startup events per month; 

• Non-startup periods of operation based entirely on low load cycling scenario (40-100 

percent gross load cycling); 

• Inclusion of a low load temperature control system;187 and 

• Maintaining the catalyst guarantee of 0.04 lb/MMBtu during full load, steady-state 

operations over the life of the catalyst. 

 

186 In addition to the final reports, SRP provided certain supporting spreadsheets upon request. We have placed these 

spreadsheets in the docket. 

187 S&L’s analysis also included emission modeling of Coronado Unit 2 without the low load temperature control 

system, which, as discussed in further detail below, is not part of the current SCR design. 
Page 152 of 244

The results of both of these analyses indicates that the Coronado units could achieve a 

rolling 30-day emission rate in the range of 0.053 to 0.072 lb/MMBtu based on all the 

assumptions listed above. We acknowledge that different assumptions, such as using fewer 

startups per month, or using a load operating profile during non-startup periods that 

corresponded to a greater fraction of high-load cycling operations, could produce a lower range 

of emission values. However, we find that the assumptions used in both analyses are reasonable 

based on the historic performance data supplied by SRP and its consultants. Therefore, we have 

concluded that a 0.050 lb/MMBtu emission rate is not achievable on a rolling 30-day average at 

either of the Coronado units.188 Nonetheless, we note that the results of these analyses 

(particularly those produced by the RMB report) indicate that Coronado Unit 1 could meet a 

0.050 lb/MMBtu limit on an annual average basis. As a result, we conclude that 0.050 lb/MMBtu 

is appropriate as an annual average design value, but not as 30-day rolling average emission limit 

at the Coronado units. 

With respect to Coronado Unit 2, we have also taken into account the fact that Unit 2 is 

already subject to a consent decree limit of 0.080 lb/MMBtu with a compliance deadline of June 

1, 2014. We consider the SCR system that SRP has designed to meet this limit to constitute 

“pollution control equipment in use at the source.” Therefore, consistent with the BART 

Guidelines, we have considered various ways in which the performance of the current SCR 

design for Unit 2 could be improved.189 In its analysis examining whether the SCR system for 

Unit 2 could achieve an emission rate more stringent than the 0.080 lb/MMBtu limit in the 

consent decree for which the SCR was designed, S&L examined a number of different potential 

 

188 Nonetheless, we note that the emission modeling results (particularly those produced by the RMB report) indicate 

that Coronado Unit 1 could meet a 0.050 lb/MMBtu limit on an annual average basis. As a result, we conclude that 

the use of a 0.050 lb/MMBtu as annual average design value in our proposal was appropriate 

189 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.3. 
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measures. One of these measures was the installation of a low load temperature control system, 

which the current SCR design for Unit 2 does not include. 

As described in the S&L report, periods of low load operation generally consist of 

operation between loads of 138 MW to 270 MW (operation above 270 MW can be considered 

“high” load). Broadly speaking, the temperature in the SCR system will fall below 599 degrees 

F during these periods of low load operation, which is the minimum temperature required for 

effective NOX control. A low load temperature control system increases the temperature at the 

SCR inlet in order to maintain 599 degrees F, allowing operation of the SCR system during 

periods of low load.190 Without this control system, the Coronado Unit 2 SCR system will not 

operate during periods of low load. Under EPA’s visibility regulations, “BART means an 

emission limitation based on the degree of reduction achievable through the application of the 

best system of continuous emission reduction ...”191 While SCR represents the most stringent 

technology for NOX control, an SCR system that is designed not to function during a period of 

operation that represents a substantial fraction of the unit’s overall operating profile cannot be 

considered continuous. In examining the installation of a low load temperature control system as 

an upgrade option to Coronado Unit 2, we note that the S&L report estimated the costs for the 

low load temperature control system as shown in Table 13. 

TABLE 13–S&L’S COST ESTIMATES FOR LOW LOAD TEMPERATURE CONTROL SYSTEM

Measure 

Capital Cost1

($) 

Annualized 

Capital Cost2

($/yr) 

Annual 

O&M Costs 

($/yr) 

Total Annual 

Costs 

($/yr) 

Low load temperature $2,500,000 $235,982 -- $235,982 

 

190 We note that this is not an unusual control system, and is commonly included in typical SCR systems. If SCR 

were to be installed on Coronado 1, for example, the information SRP has provided indicates that such a system 

would include a low load temperature control system 

191 40 CFR 51.301 (emphasis added). 
Page 154 of 244

control system 

1 Represents the mid-range value of S&L's estimate of capital costs 

2 Capital costs annualized using a 7 percent interest rate over a 20 year lifetime 

Although it is not clear what annual average emission rate can be achieved by Coronado Unit 2 

with installation of a low load temperature control system, the upper range of rolling 30-day 

emission rates modeled for Coronado Unit 2 is 0.072 lb/MMBtu. We consider this a conservative 

estimate (i.e., a high estimate in this case, as the annual average number will certainly be lower 

than the 30-day value), and have used this emission rate with the cost information contained in 

the S&L report, to calculate the cost-effectiveness value shown in Table 14. Installation of a low 

load temperature controller results in a cost-effectiveness of $1,900/ton, which is in a range that 

we consider cost-effective. 

In addition, SRP stated that it considered the incremental visibility benefit of an emission 

limit more stringent than 0.080 lb/MMBtu to be insignificant. In relation to installation of a low 

load temperature controller, we disagree. Specifically, SRP bases this comment on the visibility 

improvement associated with a 0.080 lb/MMBtu limit and a lower value such as 0.07 or 0.05. 

Visibility modeling, however, is based on the highest emission rate observed on a 24-hour 

average, not on a 30-day or annual average basis. Since Coronado Unit 2 is not equipped with a 

low load temperature controller and therefore cannot operate the SCR during periods of low load 

operation, emissions from Coronado Unit 2 during these periods correspond to operation of LNB 

with OFA. A review of Coronado Unit 2’s operating history since June 2011, which is 

approximately when LNB was installed, indicates several instances in which it operates at low 

load for periods that can exceed a 24-hour calendar day. Based on the Acid Rain Program data 

provided by SRP and included in CAMD, the longest such period of continuous low load 
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operation extended from May 20 to May 22, 2012.192 As a result, although equipped with an 

SCR system, the maximum 24-hour average emission rate for Coronado is more accurately 

represented by an emission rate corresponding to LNB and OFA, and not SCR. 

We consider this distinction crucial. In our base case modeling runs, the maximum 24-

hour average emission rate modeled for Coronado Unit 2 was represented by a NOX emission 

rate of 0.08 lb/MMBtu, corresponding to the emission limit for SCR in the consent decree. 

However, the highest 24-hour average emission rate is more accurately represented by a 24-hour 

period of low load operation, where the SCR system would not be operating. Based on Acid 

Rain Program data reported to CAMD, this corresponds to a NOX emission rate of 0.23 

lb/MMBtu and 13,684 lb/day.

193 By allowing the SCR system to run during all loading periods, 

the installation of a low load temperature control system would result in a decrease in the 

maximum 24-hour average emission rate from 0.21 lb/MMBtu to 0.080 lb/MMBtu. The 

visibility improvement associated with this emission decrease at the single most affected Class I 

area is 0.52 (Gila Wilderness). Cumulatively, across all of the affected Class I areas, this results 

in visibility improvement of 2.64 deciviews. We consider this degree of visibility improvement 

substantial, especially when taking into consideration the cost-effectiveness of installing a low 

load temperature control system. 

 

TABLE 14–CORONADO UNIT 2: COST-EFFECTIVENESS

Emission 

Factor 

(lb/MMBtu) 

Emission Rate1

Removed 

(tpy) 

Annual 

Cost 

($/yr) 

CostEffectiveness

($/ton) (lb/hr) (tpy) 

SCR+LNB+OFA 0.080 319 1,242 -- -- -- 

 

192 We have identified these dates in both sets of data, per “SRP 2 NOX analysis (EPA edits).xls” and “Coronado 2 

2011-12Q3 NOX Emission Data (daily).xls” 

193 This represents the emission rate on April 1, 2012, which is the highest emitting day that consisted of 24 

consecutive hours of low-load operation, as identified in “SRP 2 NOX analysis (EPA edits).xls” and “Coronado 2 

2011-12Q3 NOX Emission Data (daily).xls” 
Page 156 of 244

(no low load temp ctrl sys) 

SCR+LNB+OFA 

(with low load temp ctrl sys) 

0.072 287 1,118 124 235,982 1,900 

1 Emissions calculated based on 3,984 MMBtu/hr and 0.89 capacity factor, as used in the TSD for our proposal 

 

In recognition of the work already performed by SRP to meet the consent decree 

emission limit of 0.080 lb/MMBtu for Unit 2, and to avoid interfering with SRP’s ability to meet 

that requirement by the deadline of June 1, 2014, we have decided not to require a BART 

emission limit for Coronado 2 more stringent than 0.080 lb/MMBtu. Instead, we are finalizing a 

plant-wide NOX emission limit for Coronado of 0.065 lb/MMBtu on a rolling 30-day average, 

which will provide a sufficient compliance margin for startup and shutdown events. We are also 

structuring the compliance determination method so that, when one of the two units is not 

operating, its emissions from the preceding thirty boiler-operating-days will continue to be 

included in the two-unit average. We expect that SRP can meet this limit by installing a low load 

temperature control system on Unit 2 and an SCR system including a low load temperature 

control system on Unit 1. We are setting a compliance deadline for achieving this limit of five 

years from publication of this final rule, which will ensure that SRP has adequate time to design 

and install these controls without interfering with the consent decree deadline of June 1, 2014 for 

operation of SCR on Unit 2. Finally, we are including in the regulatory text of the FIP a 

requirement that pollution control equipment be designed and capable of operating properly to 

minimize emissions during all expected operating conditions, consistent with the regulatory 

definition of BART as “an emission limitation based on the degree of reduction achievable 
Page 157 of 244

through the application of the best system of continuous emission reduction for each pollutant 

which is emitted by an existing stationary facility.”194

Comment: While supporting EPA’s determination that SCR is BART for Coronado Unit 

1, one commenter (Earthjustice) stated that lower NOX emission limits are cost-effective and 

achievable. For Unit 1, the commenter made the following two points based on a report (the 

“Sahu report”) submitted with the comments. First, SCR can achieve even greater NOX

reductions at less cost than EPA’s calculations. EPA failed to analyze whether an emission limit 

lower than 0.05 lb/MMBtu is achievable and cost-effective with SCR at Unit 1 as required under 

the BART Guidelines. Second, the NOX emissions exiting Coronado Unit 1’s boiler could be 

reduced significantly from the current rate of approximately 0.3 lb/MMBtu to a rate of 0.15 to 

0.20 lb/MMBtu, which would result in a lower achievable emission rate. Neither ADEQ nor 

EPA analyzed the various methods of reducing these NOX emissions. 

The commenter (Earthjustice) noted that SRP submitted comments to EPA shortly before 

EPA issued the proposed rule arguing that SCR with a 0.05 lb/MMBtu NOX emission limit is 

unachievable at Unit 1 (and Unit 2).195 According to the commenter, SRP argued that EPA’s 

proposal is not achievable by pointing to BART proposals in other states that required SCR with 

an emission limit less stringent than 0.05 lb/MMBtu. The commenter countered that these BART 

determinations for other sources in other states do not show that EPA’s BART proposal is 

unachievable at Coronado Unit 1, as BART determinations are source-specific. The commenter 

added that SRP’s comments provide no source-specific data explaining why SCR at Unit 1 could 

not achieve a 0.05 lb/MMBtu NOX emission limit. The commenter asserted that, in contrast, the 

 

194 40 CFR 51.301 (emphasis added). See also, CAA section 302(k), 42 U.S.C. § 7602 (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 . . .”) 

195 Citing Docket Item C-16 (SRP Letter to DJordan 06-26-2012). 
Page 158 of 244

Sahu report explains why an even lower 0.04 lb/MMBtu emission limit is achievable at Unit 1. 

Accordingly, the commenter believes that EPA should not weaken its BART proposal as SRP 

requested. 

Response: We disagree with the commenter’s assertion that our BART analysis should 

have examined the potential for lower “boiler-out” NOX emission rates.196 The commenter cites 

several examples of other coal-fired boilers using PRB coal achieving boiler-out NOX emission 

rates in the range of 0.096 to 0.154 lb/MMBtu, and points to these examples as evidence that the 

Apache and Coronado units could attain lower emission rates through the use of combustion 

controls. We note that the best performing units on this list are primarily tangential- or wall-fired 

units, and that none of the units appear to be Riley turbo-fired boilers. Particularly in the case of 

the Apache and Coronado units, which are turbo-fired boilers, we consider this distinction 

crucial when determining the appropriate units with which to compare emission performance. 

The Riley-turbo boiler is a unique wall-fired boiler design that is characterized by a venturishaped lower section (often described as a “pinch” in the boiler wall) with burners located on the 

underside of the pinched wall, tilted slightly downwards.197. It is a relatively uncommon design, 

with only two dozen such units currently in operation.198 The turbo boiler was developed in the 

1960s and, unlike many other wall-fired boilers, was generally able to meet the NOX emission 

limits contained in the 1971 New Source Performance Standards for fossil fuel fired steam 

generators.199 While Babcock Power, which acquired Riley Stoker, has developed new burner 

upgrades to meet more stringent NOX emission standards,the combustion control designs 

 

196 As described by the commenter, the “boiler-out” NOX emission rate refers to the emission rate after including the 

effects of combustion controls such as low NOX burners, over-fire air, neural networks, adaptive controls, etc. 

197 See “Design and Operation of Coal-fired TURBO furnaces for NOx control”, Riley Stoker Corporation, 

November 1978. 

198 Acid Rain Program data indicates 22 turbo units were in operation in 2011 

199 “An Overview of Riley Stoker’s Burner Development Efforts for NOx Control”, Riley Stoker Corporation, April 

7, 1983. 
Page 159 of 244

available for turbo-fired boilers have not been through the same number of design iterations, and 

are therefore not as effective as those for other boiler types.200 We therefore do not consider it 

appropriate to compare the “boiler-out” emission rates of the Riley turbo design with those 

achieved by tangential and more traditional wall-fired units. 

More specifically, combustion controls on Coronado 1 (LNB) were installed in 2009, and 

the commenter has not indicated any design improvements or upgrades that would achieve 

improved performance. We note that the baseline period for our analysis represented the use of 

combustion controls (in the form of LNB with OFA) and that our emission estimate of LNB is 

based on past actual emission data, as reported to CAMD, over the baseline period. As part of the 

supplemental cost analysis we performed, we used a baseline period that predated installation of 

LNB, and consisted of emission rates corresponding to OFA only.

201 Comparing annual average 

emission rates during the periods prior to and following LNB installation, we note that Coronado 

Unit 1 has achieved approximately 25 percent reduction from installing LNB at an emission rate 

of approximately 0.30 lb/MMBtu. We consider these values reasonable, as it is supported by 

actual emission data and represents a control efficiency similar to the 30 percent control 

efficiency assumed by our contractor. 

In addition, we disagree with the commenter’s assertion that 0.04 lb/MMBtu is an 

appropriate SCR emission limit to consider for Coronado Unit 1. As discussed in the previous 

response to SRP’s comments, we have examined the analysis performed by SRP and determined 

that a 0.050 lb/MMBtu emission rate is not achievable by Coronado Unit 1 on a rolling 30-day 

average. Although we note that SRP’s analysis is based on a 0.04 lb/MMBtu emission rate at full 

load, steady state conditions, and that SRP’s analysis indicates Coronado Unit 1 could achieve 

 

200 “Low NOX Combustion System Solutions for Wall Fired,T-Fired, and Turbo Fired Boilers.” Babcock Power, 

August 28-31, 2006

201 Supplemental Cost Analysis 2012-11-15.xls 
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0.050 lb/MMBtu on an annual average basis, we do not consider this emission rate achievable as 

a rolling 30-day limit based on the number of startup and shutdown events associated with its 

operating profile. 

Comment: While supporting EPA’s determination that SCR is BART for Coronado Unit 

2, one commenter (Earthjustice) stated that lower NOX emission limits are cost-effective and 

achievable. For Unit 2, the commenter made four major points. First, the NSR consent decree 

does not exempt Coronado Unit 2 from a NOX BART determination based on a valid five-factor 

BART analysis. Second, contrary to the argument that the 0.08 lb/MMBtu limit on Coronado 

Unit 2 under the consent decree was developed to address BACT obligations, that emission limit 

is not BACT, which requires a top-down analysis that selects the “maximum degree of 

reduction.” There is no BACT analysis in the consent decree and no explanation of how the 0.08 

lb/MMBtu emission limit was selected. In addition, while BACT requires case-by-case analysis, 

the consent decree limit was not specific to Unit 2; it simply required installation of SCR on one 

of the two units. Third, the negotiated limit contained in the NSR consent decree cannot replace 

the required five-factor BART analysis for Coronado Unit 2 because BART is more stringent 

than the consent decree’s emission limit. The Sahu report shows that an emissions limit lower 

than 0.08 lb/MMBtu is cost-effective and achievable at Unit 2. Fourth, the NOX emissions 

exiting Coronado Unit 2’s boiler could be reduced significantly from the current rate of 

approximately 0.33 lb/MMBtu to a rate of 0.15 to 0.20 lb/MMBtu, which would result in a lower 

achievable emission rate. Neither ADEQ nor EPA analyzed the various methods of reducing 

these NOX emissions. SCR with a 0.04 lb/MMBtu emission limit at Coronado Unit 2 is 

achievable with various control methods and is even more cost-effective than EPA‘s calculations 
Page 161 of 244

suggest. Because of this, the commenter requested that EPA revise its BART determination to 

reflect this lower level. 

The commenter (Earthjustice) stated that SRP has claimed that a NOX emission limit of 

0.05 lb/MMBtu is unachievable based on its progress in constructing the SCR unit required by 

the NSR consent decree, but does not explain how construction progress to date would prevent it 

from calibrating the SCR to achieve a 0.05 lb/MMBtu emission limit (or a 0.04 lb/MMBtu limit). 

The commenter noted that EPA requested information concerning whether the amount and 

management of catalyst could be altered to meet a 0.05 lb/MMBtu NOX limit at Unit 2, but 

according to the commenter SRP did not provide any such information. As a result, the 

commenter urged EPA to revise its BART determination to require SCR with an emission limit 

lower than 0.08 lb/MMBtu. 

Response: We disagree with the commenter’s assertion that it is appropriate to consider 

lower “boiler-out” NOX emissions for Coronado Unit 2, for the same reasons we noted in the 

previous response for Coronado Unit 1 on this issue. We also disagree with the commenter’s 

assertion that 0.04 lb/MMBtu is an appropriate SCR emission rate to consider for Coronado Unit 

2 , also for the same reasons we noted in the previous response for Coronado Unit 1 on this issue. 

We agree with the commenter’s assertions that the consent decree is not a replacement 

for a five-factor BART analysis. We also agree that while the consent decree resolved NSR/PSD 

obligations such as BACT, a “top-down” BACT analysis was not performed as part of the 

consent decree negotiations. Based on our review of SRP’s August 24, 2012 letter and submitted 

comments, we do not consider the SCR system for Coronado Unit 2, as currently designed, to 

constitute BART. As noted in the analysis contained in our response to SRP’s comments, we 

consider the installation of a low-load temperature controller to be both cost-effective and to 
Page 162 of 244

result in substantial visibility improvement. We are not, however, finalizing a more stringent 

emission limit for Coronado Unit 2. Instead, we are finalizing a requirement that pollution 

control equipment be designed and capable of operating properly to minimize emissions during 

all expected operating conditions, consistent with the regulatory definition of BART as “an 

emission limitation based on the degree of reduction achievable through the application of the 

best system of continuous emission reduction for each pollutant which is emitted by an existing 

stationary facility.”202

 c. Costs of Compliance 

Comment: One commenter (NPS) agreed with EPA that SRP did not provide ADEQ with 

control cost calculations at a level of detail that allowed for a comprehensive review. The 

commenter conducted analysis of the cost and cost-effectiveness of adding SCR to reduce 

emissions of NOX at Coronado Unit 1 using the cost methodologies of the CCM and relying on 

the IPM to reflect the most recent SCR cost levels, and submitted the detailed calculations as 

Appendix E to its comments. The commenter’s analysis yielded a cost-effectiveness value of 

$2,540/ton. The commenter noted that EPA’s analysis yielded a cost-effectiveness value of 

$2,405/ton, which EPA considers cost-effective. Another commenter (Earthjustice) also asserted 

that SCR at Coronado 1 is cost-effective. When calculated based on an SCR emission rate of 

0.04 lb/MMBtu, and when accurate cost figures and proper baselines are used, the commenter 

asserts that SCR would reduce NOX emissions at a cost of just $2,024/ton of NOX removed. 

NPS commented that it was not able to conduct a cost analysis for Coronado Unit 2, on 

which SRP is installing SCR to meet an emission limit of 0.080 lb/MMBtu under a consent 

 

202 40 CFR 51.301 (emphasis added). See also, CAA section 302(k), 42 U.S.C. § 7602 (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 . . .”) 
Page 163 of 244

decree with EPA. However, the commenter used the CCM to evaluate the differences between an 

SCR on this unit at 0.050 lb/MMBtu versus 0.080 lb/MMBtu. According to the commenter, an 

SCR meeting the more stringent limit would have essentially the same footprint as the less 

effective unit, but would require an additional layer of catalyst and would be seven feet taller. 

The commenter presented basic design parameters for SCR units achieving the two levels of 

control. 

Response: We agree with NPS’s assertion that SRP’s cost figures, as provided in their 

original BART analysis and in the subsequent response to ADEQ’s information request, were not 

sufficiently documented. While we also agree with the commenters’ assertion that SCR with 

LNB and OFA is cost-effective, we decline to modify our estimates of cost- effectiveness to 

reflect the cost items noted in these comments, as it is not in any way determinative to our 

decision to find that SCR is “even more” cost-effective, or that the incremental cost-effectiveness 

value between SCR and SNCR is “even more” incrementally cost-effective.

Comment: One commenter (SRP) argued that EPA’s cost of compliance analysis for 

Coronado is flawed and must be replaced with site‐specific costs. The commenter asserted that 

EPA improperly ignored site‐specific cost estimates for Coronado BART control options by 

substituting its own estimates, and ignored the fact that Arizona has “the lead role in designing 

and implementing [its] regional haze program” and “broad authority over BART determinations” 

(citing Corn Growers, 291 F.3d at 3, 8). The commenter stated that ADEQ fully complied with 

the BART Guidelines and was justified in any deviation from the specific terms of the CCM 

because ADEQ engaged in a reasoned, site-specific cost analysis. The commenter added that 

ADEQ has discretion to conduct and document its cost assessment at a level that it deems 
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appropriate, and that the documentation that supports ADEQ’s BART determination is 

reasonable by any objective standard. 

The commenter (SRP) asserted that EPA improperly ignored site‐specific cost estimates 

for Coronado BART control options, instead using the IPM to calculate the capital costs and 

annual operating costs associated with the various NOX control options that EPA considered. 

Moreover, the commenter added that no cost estimate derived from a model designed to produce 

generalized information about utilities throughout the nation could satisfy the CAA requirement 

that BART be determined based on a site‐specific analysis. SRP provided adjusted inputs for use 

in IPM for unit size, gross heat rate, NOX removal factor, NOX removal efficiency, ammonia 

cost, operating labor rate, bare module costs, urea costs and property taxes and insurance. SRP 

asserted that when these values are used in the model, the IPM outputs validate the site-specific 

costs provided by SRP (based on detailed SCR and SNCR cost comparisons provided in the 

comments), although the adjusted IPM results still under-predict the costs based on site-specific 

considerations. 

The commenter (SRP) stated that its site‐specific costs for SCR are based on the actual 

cost projections associated with the current SCR installation at Unit 2. The commenter stated that 

SRP has already made substantial progress on the Unit 2 SCR installation with more than 40 

percent of the project already complete, with the engineering design effort more than 90 percent 

complete, and the overall procurement efforts more than 75 percent complete. As such, the 

commenter believes that the site‐specific costs are appropriate for use in any evaluation of BART 

controls. 

In addition, the commenter (SRP) indicated that its cost estimates for Unit 1 are 

conservative since they are based on actual costs experienced for Unit 2 for which SCR has been 
Page 165 of 244

designed to achieve an emission limit of 0.080 lb/MMBtu, rather than the 0.050 lb/MMBtu 

assumed by EPA for Unit 1. According to the commenter, there could be additional costs for 

Unit 1 of as much as $117 million for additional catalyst and an increased ammonia emission 

rate, a dry sorbent injection control system to address increased sulfuric acid mist and 

condensable PM emissions, and a fabric filter baghouse and induced draft fans to address 

increased filterable PM emissions. The commenter stated that even without these additional 

costs, the site-specific cost estimate for an SCR system on Unit 1 is almost twice the value used 

by EPA in its BART determination, and for the SCR system on Unit 2, the actual cost incurred 

by SRP is likewise almost twice the value used by EPA in its BART determination. The 

commenter concluded that this documentation demonstrates the importance of using available 

site‐specific cost estimates when conducting a BART determination for Coronado. 

Response: We disagree with the commenter’s assertion that the cost calculations SRP 

provided to ADEQ as part of the original BART analysis, or in the subsequent response to 

ADEQ’s information request, were supported by sufficient documentation. For example, the 

annual O&M costs associated with an SCR system will involve such costs as reagent usage, 

catalyst replacement costs, and labor costs, among others. SRP provided no breakdown of annual 

O&M costs beyond the total annual O&M value. Similarly, SRP’s capital cost estimates consist 

of only a total value, accompanied by a capital recovery factor to determine the corresponding 

annualized cost. This level of detail does not allow us, and could not have allowed ADEQ, to 

evaluate the reasonableness of SRP’s cost estimates for Coronado. As noted in a previous 

response, we have identified several issues with the cost calculations performed for the Apache 

and Cholla units that are inconsistent with the methodology established by EPA’s CCM. SRP’s 
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cost estimates do not provide sufficient detail for us to evaluate if they are consistent with CCM 

methodology.

Although we do not agree that our cost-effectiveness estimates were incorrect, we have 

performed a supplemental analysis for Coronado 1 using portions of the updated cost estimates 

provided by SRP in its comments. Our use of these cost estimates in this supplemental analysis 

should not be construed to represent an acceptance of SRP’s revision to our IPM assumptions. 

Rather, this supplemental analysis represents a conservative estimate of costs (i.e., an assumption 

that would tend to overestimate rather than underestimate the annualized cost of controls). A 

summary of cost estimates based on this supplemental analysis is displayed in Table 15. 

• SRP’s revised SNCR cost estimates: SRP also submitted a conceptual capital cost 

estimate for an SNCR system as part of its comments. This estimate has excluded cost 

items not allowed by the CCM, such as AFUDC, escalation, and owner’s costs, and have 

been included in the supplemental analysis. 

• Original baseline period: As discussed elsewhere in our responses, we consider our use 

of a more recent baseline as consistent with BART Guidelines. However, in order to 

address commenter’s concerns that we did not properly consider LNB and OFA as a 

potential control option and therefore precluded a BART determination of LNB and 

OFA, we have used a baseline period of 2001-2003, which corresponds to the period used 

in SRP’s original BART analysis. This represents a time period prior to the installation of 

LNB, during which the control technology in place on Coronado 1 was OFA-only. 

TABLE 15–CORONADO UNIT 1: CONTROL COST ESTIMATES

(PER SRP WITH EPA REVISIONS) 

Coronado 1 

Control Technology 

Capital Cost 

($) 

Annualized 

Capital Cost 

($/yr) 

Annual 

O&M Cost 

($/yr) 

Total Annual 

Cost 

($/yr) 
Page 167 of 244

LNB+OFA $6,500,000 $613,554 $0 $613,554

SNCR w/ LNB+OFA $14,164,000 $1,336,981 $5,829,800 $7,166,781

SCR w/ LNB+OFA $80,633,219 $7,611,205 $4,492,736 $12,103,941

Regarding SRP’s concern that its own costs for Coronado Unit 1 are conservative (i.e., 

underestimated in this context) because they are based on a Coronado Unit 2 design that achieves 

0.080 lb/MMBtu instead of 0.050 lb/MMBtu, we partially agree. For Coronado Unit 2, SRP 

identified certain additional costs that would be associated with design changes necessary to 

meet an emission rate more stringent than the consent decree limit of 0.080 lb/MMBtu. The two 

most important changes would be increased levels of ammonia injection and additional SCR 

catalyst (in the form of an additional fourth catalyst layer at the time of initial catalyst fill). The 

SCR catalyst is responsible for a certain amount of SO2 to SO3 conversion, which can then form 

sulfuric acid (H2SO4). SRP notes that the additional fourth catalyst layer can be expected to 

result in a collateral increase in sulfuric acid (H2SO4) emissions. A dry sorbent injection (DSI) 

system may be needed to address this increase in sulfuric acid, which itself has the potential to 

increase filterable particulate emissions. Addressing this increase in filterable particulate 

emissions may in turn require installation of a fabric filter baghouse. Of the $117 million in 

capital costs identified by SRP, the majority of these costs ($113 million) are associated with 

construction of the DSI and fabric filter. 

While we agree that designing Coronado Unit 1 to meet an annual average emission limit 

of 0.050 lb/MMBtu will involve greater costs than a system designed to meet 0.080 lb/MMBtu, 

we disagree that the costs for Coronado Unit 1 are of the magnitude of those described above for 

Coronado Unit 2. Based on SRP’s comments, we note that the SCR reactor box for Unit 2 has 

been designed for a “3+1” configuration (i.e., an initial three catalyst layers, with space for a 

fourth layer to be added later in the system’s lifetime to maintain the same level of effectiveness) 
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and has perhaps already been fabricated. As a result, accommodating additional catalyst cannot 

be achieved by increasing the volume of the initial three layers, but must be achieved by 

including the fourth catalyst layer (or some portion of it) during the initial fill. Since each 

catalyst layer is designed for a certain amount of SO2 to SO3 conversion, inclusion of an 

additional layer unavoidably results in an increase in the overall conversion rate. However, since 

an SCR system for Coronado Unit 1 has not been designed, we consider it feasible for SRP to 

specify a design at the outset that accommodates additional volume in the initial catalyst layers, 

thereby achieving a more stringent emission rate without the higher SO2 to SO3 conversion rate 

associated with a fourth catalyst layer. Moreover, even if SRP were required to install a DSI 

system or DSI and a fabric filter, EPA does not agree that these costs should be considered part 

of the cost of compliance for the purposes of a BART determination. EPA cannot anticipate what 

control technology might be required in the future for sulfuric acid mist under PSD or minor 

NSR. The BART Guidelines do not require the inclusion of potential future costs that might be 

associated with permit requirements as part of the cost estimates for a BART determination. 

Therefore, while we acknowledge that there are costs associated with additional catalyst 

and increased ammonia injection, they represent a small fraction ($4 million) of the $117 million 

total identified by SRP. We have used certain elements from SRP’s estimates in preparing our 

supplemental cost analysis for Unit 1, but we have not adjusted SRP’s estimates to reflect these 

factors since the cost estimates provided by SRP do not include a level of detail that would allow 

us to properly make such adjustments. 

A summary of emission rates and emission reductions associated with each control option 

is in Table16. As noted previously, these emission estimates are based on a 2001-2003 baseline 

period, during which the Cholla units operated only with OFA. We have calculated annual 
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emission rates for the OFA baseline using the annual average emission data (lb/MMBtu) 

reported to CAMD over this 2001-2003 baseline period. 

TABLE 16–CORONADO 1: ANNUAL EMISSION ESTIMATES

Coronado 1 

Control Technology 

 

Emission 

Factor 

(lb/MMBtu)1

Heat Rate 

(MMBtu/hr) 

Annual 

Capacity 

Factor 

Emission Rate 

Emissions 

Removed 

(tpy) (lb/hr) (tpy) 

OFA (only) 0.407 4,316 0.84 1756 6,462 -- 

LNB+OFA 0.303 4,316 0.84 1308 4,811 1,651 

SNCR w/ LNB+OFA 0.212 4,316 0.84 915 3,368 3,095 

SCR w/ LNB+OFA 0.050 4,316 0.84 216 794 5,669 

1 Annual average basis 

Cost-effectiveness values for each control technology are summarized in Table 17, and are based 

on the total annual costs and annual emissions removed listed in the previous tables. 

TABLE 17–CORONADO 1: CONTROL OPTION COST-EFFECTIVENESS

Coronado 1 

Control Technology 

Total Annual 

Cost 

($/yr) 

Emissions 

Removed 

(tpy) 

CostEffectiveness 

($/ton) 

Avg. Incr. 

OFA (only) -- -- -- -- 

LNB+OFA $613,554 1,651 $372 -- 

SNCR w/ LNB+OFA $7,166,781 3,095 $2,316 $4,540

SCR w/ LNB+OFA $12,103,941 5,669 $2,135 $1,918

Based on SRP’s capital and O&M cost estimates, we still consider the cost-effectiveness 

values of SCR, on an average ($2,135/ton) and incremental ($1,918/ton) basis, to not be costprohibitive. We consider these results supportive of our proposed determination that SCR with 

LNB and OFA is cost-effective. We note that while the LNB and OFA option is the least 

expensive (i.e., lowest annual cost) and is the most cost-effective of the control technologies (i.e., 

has the lowest $/ton value), it is also the least effective control option (i.e., removes smallest 
Page 170 of 244

quantity of NOX). It removes substantially fewer emissions than either of the other two control 

options, the SNCR- and SCR-based systems. As discussed in our proposed action, and in other 

responses in this document, we have not identified any energy or non-air quality impacts that 

warrant eliminating SCR from consideration for Coronado Unit 1. Combined with the modeled 

visibility improvement associated with the SCR control option, SRP’s cost estimates continue to 

support the selection of SCR with LNB and OFA as BART for Coronado 1. 

Comment: One commenter (SRP) stated that the proposed rule and the TSD say almost 

nothing about how IPM was used to calculate costs, instead directing the public to an EPA 

contractor report for more information. The commenter asserted that no contractor report in the 

docket for the rulemaking supplies additional detail on precisely how IPM was used. The 

commenter added that this failing renders EPA’s proposed rule inconsistent with the CAA’s 

public notice requirements. 

Response: We disagree with the commenter’s assertion that we have not provided 

sufficient information regarding our cost calculations. In the e-docket for our proposal, we 

included the raw cost calculation spreadsheets from our contractor that contain the IPM 

equations, corresponding variable values, selected notes regarding assumptions and variable 

ranges, as well as selected tables from the IPM Base Case v4.10.203 In addition, web links were 

provided (both in the raw cost calculation spreadsheet and in our proposal) to the location on the 

publicly available EPA website that contains full IPM documentation. 

Comment: One commenter (SRP) stated that EPA failed to follow the BART Guidelines 

by not conducting an incremental cost analysis for Coronado. According to the commenter, the 

proposed rule and TSD both provide a single entry for incremental costs for each of the 

 

203 Document ID: EPA-R09-OAR-2012-0021-0008, File name: G15_MODELING_FILES_EGU_BART_Costs_Apache_Cholla_Coronado_FINAL2 
Page 171 of 244

Coronado units that reflect the incremental cost of the most stringent NOX BART control option 

compared to the baseline. The commenter asserted that this is not a complete incremental 

analysis because it ignores incremental comparisons between identified control options. SRP 

contended that in the absence of a proper NOX BART assessment, the proposed rule lacks an 

adequate foundation. The commenter stated that the high incremental costs of post‐combustion 

NOX control technologies when compared to combustion control technologies reinforces the 

conclusion that post‐combustion control technologies cannot be the basis for BART for the units 

at Coronado. 

Response: We disagree with the commenter’s assertion that we did not perform a 

sufficient incremental cost analysis for the Coronado units. In our control cost summaries (Table 

22 in the proposed rule and Table 32 in the TSD), the column labeled “incremental costeffectiveness” represents the $/ton of the control option when compared to the preceding control 

option. The column labeled “average cost-effectiveness”, represents the $/ton of the control 

option when compared to the baseline control. In the case of Coronado Unit 1, we considered 

two control options beyond the baseline: SNCR with LNB and OFA, and SCR with LNB and 

OFA. The “single entry for incremental costs”, as described in the comment, represents the 

incremental cost between the SNCR- and SCR-based options. An incremental cost value was not 

calculated between LNB with OFA (which is the option preceding the SNCR-based option) and 

SNCR because LNB with OFA represented the baseline control in our analysis. The costeffectiveness of moving from LNB with OFA to SNCR with LNB and OFA is therefore 

adequately captured in the “average cost-effectiveness” column. We do note that, in our 

supplemental cost analysis, we have used OFA as the baseline control, and have therefore 

calculated an incremental cost-effectiveness value for moving from LNB with OFA to SNCR 
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with LNB and OFA. These results are described in a previous comment and, as noted in that 

comment, we disagree with the commenter’s assertion that the incremental cost of postcombustion controls is cost-prohibitive. 

 d. Visibility Improvement 

Comment: One commenter (SRP) asserted that EPA is without basis for establishing in 

the proposed rule a 0.5 deciview comparison threshold as a touchstone for analyzing impacts 

from Coronado BART controls, citing the BART Guidelines and associated preamble. 

According to the commenter, even if EPA could impose a 0.5 deciview comparison threshold, it 

is only by substituting its own preferred modeling methodology (which the commenters argued 

is something EPA cannot lawfully do) that EPA can project that requiring SCR at Unit 1 would 

barely yield a projected improvement of more than 0.5 deciview at one area. The commenter also 

noted that 0.5 deciview is below the level of human perceptibility. 

Response: As explained above, we have not used 0.5 dv as a threshold, but as one point 

of comparison such as a “benchmark” or “yardstick” to gauge the magnitude of impacts under 

various control scenarios. 

 e. Other Comments 

Comment: The commenter (NPS) agreed with EPA’s determination that NOX BART for 

Coronado Units 1 and 2 is SCR with LNB and OFA. The commenter noted that EPA proposed 

on Unit 1 an emission limit for NOX of 0.050 lb/MMBtu, based on a rolling 30-boiler-operatingday average, and on Unit 2 an emission limit of 0.080 lb/MMBtu, which is consistent with the 

emission limit in the consent decree. The commenter stated that EPA acknowledged that the 

emission limit for Unit 2 established in the consent decree was not the result of a BART fivefactor analysis, and that the consent decree does not indicate that SCR at 0.080 lb/MMBtu 
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represents BART. The commenter commended EPA for soliciting additional information on the 

feasibility of achieving a more stringent limit. 

Response: We acknowledge the comment. 

Comment: In response to EPA’s proposed BART determination in the proposed FIP, one 

commenter (SRP) performed and submitted an assessment of the critical components of a BART 

analysis for Coronado, including control costs and the visibility improvements associated with 

the control options. The commenter indicated that this analysis shows that even without 

considering other energy and non‐air quality environmental impacts associated with the 

implementation of SNCR or SCR, it is clear that the visibility benefits realized from 

implementation of post‐combustion controls are not justified by the cost. The commenter also 

submitted the results of this analysis using CALPUFF version 6.42 in place of version 5.8. The 

commenter stated that this analysis provides even stronger evidence that selection of postcombustion controls as BART for Coronado is inappropriate. 

Response: We disagree with this comment. As noted in a separate response, we have 

performed a supplemental cost analysis that relies upon many elements of the cost analysis 

provided by the commenter. Even with the higher cost estimates provided by the commenter, we 

consider the costs of post-combustion controls such as SNCR and SCR to be cost-effective on a 

$/ton basis. In addition, as noted in a separate response, we disagree with several assumptions 

used in the commenter’s visibility modeling, such as the use of an unapproved CALPUFF model 

version and treatment of ammonia background concentrations. We therefore disagree that the 

visibility benefits modeled by the commenter are representative of the benefits that will accrue 

with the use of post-combustion controls. The modeling results performed in support of our 

proposal indicate substantial visibility benefits, especially with the SCR control option. As a 
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result, we do not consider it appropriate to eliminate either of the post-combustion controls from 

consideration as BART. Although SCR is the most stringent control option, its associated 

visibility benefits and cost-effectiveness justify this technology as BART. 

 E. Comments on Enforceability Requirements in EPA’s BART FIP 

Comment: One commenter (SRP) made the following points concerning the proposed 

enforceability requirements: 

• EPA must modify the monitoring requirements to be consistent with existing 

requirements. If EPA proceeds to impose additional controls at Coronado beyond those 

specified in the consent decree and already included in the Coronado permit, it must align 

these requirements to eliminate unnecessary and unreasonable compliance burdens. 

• The commenter supports and appreciates the use of the monitoring system certification 

and quality assurance (QA) procedures in 40 CFR Part 75. However, EPA’s proposed 

definition of “valid” data is broader than 40 CFR Part 75, and EPA also should make 

clear that the “bias” adjustment procedures in 40 CFR Part 75 do not apply to data used 

to calculate the 30‐day rolling averages. 

• The commenter objects to the proposed additional relative accuracy requirements. 

Imposing additional relative accuracy test audit (RATA) specifications will not increase 

the accuracy of any monitoring system, but would increase the difficulty and cost of 

testing. It also could result in additional missing data if tests must be repeated to meet the 

specifications. To proceed with combined RATA specifications, EPA also would need to 

either propose (and solicit comment on) alternative low‐emitter combined specifications 

that have been demonstrated to be consistently achievable, or exempt units meeting any 

of the applicable 40 CFR Part 75 low‐emitter thresholds from those specifications. 
Page 175 of 244

• The commenter stated that the proposed data availability requirements are unnecessary 

and too stringent. Source owners and operators already have sufficient incentive to obtain 

valid data in order to avoid the increasingly conservative (and ultimately punitive) 

missing data substitution procedures that apply under 40 CFR Part 75. Regarding 

stringency, if a unit has a significant missing data event during a calendar quarter in 

which it also has a significant period of unit downtime (e.g., as a result of an outage), the 

percent of operating hours during the quarter with valid data could easily be less than 90 

percent. It is in part for this reason that 40 CFR Part 75 measures data availability over 

each 8,760‐operating‐hour period. EPA should either eliminate the unnecessary 

requirement or provide data to justify its proposed requirement that take into account the 

differences described above. 

• EPA must modify the quarterly reporting requirements to be consistent with existing 

requirements. 

• EPA must modify the notification requirements in the proposed rule because they are 

overly broad and overly prescriptive. First, EPA should clarify the proposed provision by 

requiring notice only of new controls that will be required to meet the FIP or regional 

haze SIP. Second, because installation of controls is a complex process, and the point at 

which that process is “complete” may not be immediately clear, EPA must revise the 

requirement to use a more objective term and allow sufficient time for owners and 

operators to comply. Third, because the proposed requirement duplicates reporting 

already required for a new add‐on NOX emission control under 40 CFR Part 75, EPA 

should rely on (and if necessary refer to) the notice required under Part 75. 
Page 176 of 244

Response: We partially agree with this comment and are adjusting the enforceability 

requirements of the final FIP accordingly. EPA agrees that the Part 75 bias adjustment should not 

be applied to the compliance data for the BART rules in this action and is making changes to the 

final rule to address this comment. However, EPA does not agree that only the incentives under 

the Acid Rain Part 75 rules are sufficient to assure adequate valid data for this rule. Part 75 relies 

on progressively punitive data substitution procedures to promote good valid data availability for 

its program. Our rule does not substitute data, so the incentives of the Part 75 rules do not exist. 

Therefore, EPA is requiring that each unit subject to this rule obtain 90 percent valid data, as 

determined under Part 75, for each calendar year. 

It should be noted that the commenter did not submit any data specific to its EGUs 

indicating the difficulty of meeting the proposed valid data availability requirements. Also, the 

other two utility companies affected by this rule did not make any objection to the proposed data 

requirements. However, EPA, as a result of this comment, has reconsidered the additional quality 

assurance and valid data requirements from the proposal. As indicated by the commenter, 

measurement and QA requirements for NOX lb/hour are not currently required by Part 75. In 

addition, EPA recognizes that the calculation of heat input requires the combination of the flow 

and diluent (O2 or CO2) CEMS along with measurements of temperature and estimation of 

moisture. In addition in the final rule, EPA is providing for a multi-unit determination of 

compliance. This would compound the valid data concerns of the commenter. EPA requires 

monitoring data used for compliance determinations to be of known quality as demonstrated 

through Quality Assurance/Quality Control (QA/QC) procedures.204 In place of the requirement 

to validate through RATA testing of the NOX lb/hour measurement and heat input, EPA will 

 

204 See, e.g., 40 CFR 60.13(a) and 40 CFR Appendix F. 
Page 177 of 244

require that all of the CEMS required by Part 75 and used for the compliance demonstrations for 

this action obtain 90 percent valid data (per Part 75 specifications) for each unit over each 

calendar year. In addition, the rule will require the affected units to conduct RATA evaluations 

and calculate the quarterly valid data hours for NOX lb/hour and heat input. EPA will not finalize 

the minimum data requirements in the proposal, but will require these data to be calculated (all 

data for determining the relative accuracy in these units are available when Part 75 RATAs are 

performed) and reported to both EPA and ADEQ to determine if these data are capable of 

meeting more rigorous QA/QC requirements in the future. We also note that the final rule will 

add QA/QC and minimum valid data requirements for the inlet SO2 CEMS that are needed to 

calculate the SO2 removal efficiencies for the Cholla EGUs. Finally, EPA agrees that semiannual 

reporting will be sufficient for this rule, and the final rule will reflect this. 

Comment: One commenter (AEPCO) requested that EPA clarify that AEPCO has longer 

than 180 days to comply with the non-SCR limits. The commenter is particularly concerned 

about the time needed for the ESP and scrubber upgrades and believes a five-year period for all 

BART implementation would be appropriate. ADEQ also commented that the facility will need 

more than 180 days to complete the upgrades needed to meet the SO2 BART limits, and stated 

that a five-year compliance time frame from the time the BART limit is finalized, as specified in 

RHR Appendix Y, is most appropriate. 

Response: EPA agrees that AEPCO would need more than the 180 days in the proposed 

rule. However, we do not agree that five years is necessary to perform the necessary upgrades. 

The final rule will require AEPCO’s two units to meet the SO2 and PM10 limits within four years 

of the effective date of this rule. This time frame will allow AEPCO to perform the upgrades to 

the two units during regularly scheduled maintenance outages. 
Page 178 of 244

Comment: Several commenters (ADEQ, AEPCO, APS, EarthJustice, NPS, SRP) 

provided feedback on test methods. AEPCO supported maintaining the use of EPA Method 

201A to comply with the proposed BART PM10 limits. In contrast, ADEQ and APS only 

supported the use of Methods 201A and 202 if SCR controls are not used. These commenters 

stated that SCR causes an increase in sulfuric acid aerosol mist, which results in an increase in 

condensable particulate matter. APS suggested Methods 1-4 and Method 5 or 5e are appropriate 

where SCR is used. ADEQ suggested Method 5 or 5e where SCR is used, and states that any 

collateral increase in acid mist should be addressed through a permitting process. SRP stated that 

wet scrubbers also render Methods 201 and 201A inapplicable, and requested that EPA specify 

the use of Method 5, 5B, 5I or an approved alternative.

One commenter (NPS) pointed out that use of SCR at these units is expected to result in 

increased condensable particulate matter in the form of sulfuric acid mist (H2SO4), which would 

have the effect of making the emission limit more stringent than intended by ADEQ, and likely 

not be achievable in practice. To address EPA’s request for 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, 

the commenter conducted and submitted an analysis of H2SO4 emissions. According to the 

commenter, H2SO4 emissions will not be significant, contributing less than 10 percent to the 

PM10 limit. The commenter suggested that the 0.030 lb/MMBtu limit proposed by ADEQ for the 

Apache and Coronado units be adjusted to 0.033 lb/MMBtu to reflect the increase in total PM10

attributable to SCR, and that PM10 emissions would be measured by conducting EPA Method 

201A/202 tests consistent with the ADEQ’s SIP. 
Page 179 of 244

In contrast to the previous commenters, one commenter (Earthjustice) stated that EPA 

should approve the test methods in the ADEQ RH SIP (i.e., EPA Methods 201 and 202) and 

ensure that the BART limit includes both filterable and condensable PM fractions. The 

commenter asserted that if EPA allows or requires a test method other than Method 201 and 202, 

the PM10 BART emission limit would effectively be less stringent because it would only apply to 

filterable PM, and not total PM. The commenter indicated that requiring different test methods 

would in effect be proposing an even less-stringent PM10 BART limit, which would require EPA 

to undertake an independent BART analysis that demonstrates that the less-stringent emission 

limit is BART. Consequently, according to the commenter, if EPA requires or allows a different 

test method, it must lower the emission limit to reflect only the filterable PM10 fraction. The 

commenter added that in this case, EPA should ensure that compliance with the filterable PM10

limit is demonstrated with use of CEMS for filterable PM, which is currently available. 

Response: ADEQ selected test methods 201 and 202 for determining compliance with 

this limit. EPA noted in the proposal that the proposed addition of SCR for NOX control would 

likely increase the quantity of PM collected as condensable PM by method 202 due to an 

increase in H2SO4 from the oxidation of SO2 to SO3. EPA requested comment on changing the 

test method from methods 201 and 202 to EPA Method 5 which measures only the filterable PM. 

Method 5 measures all sizes of filterable PM which results in a higher filterable PM value than 

Methods 201 or Method 201A, which only measure filterable PM10. 

In its comments concerning the proposal for Coronado, SRP noted that Method 201A 

cannot be used in a wet exhaust gas stream. We agree with this comment. In promulgating 

amendments to Method 201A and Method 202 in 2010, EPA explained that: 

Method 201A cannot be used to measure emissions from stacks that have 

entrained moisture droplets (e.g., from a wet scrubber stack) since these stacks 
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may have water droplets that are larger than the cut size of the PM10 sizing 

device. The presence of moisture would prevent an accurate measurement of total 

PM10 since any PM10 dissolved in larger water droplets would not be collected by 

the sizing device and would consequently be excluded in determining total PM10 

mass. To measure PM10 in stacks where water droplets are known to exist, EPA’s 

Technical Information Document 09 (Methods 201 and 201A in Presence of 

Water Droplets) recommends use of Method 5 of appendix A–3 to 40 CFR part 

60 (or a comparable method) and consideration of the total particulate catch as 

PM10 emissions.205

It is also true that the rarely used Method 201 cannot be used in a wet exhaust stream (also 

known as a “wet stack”).206

At this time, the three facilities subject to this BART rule have a mix of wet and dry 

stacks. EPA anticipates that the SO2 BART limits set by ADEQ will result in 100 percent of the 

exhaust gas undergoing SO2 scrubbing. Neither ADEQ nor EPA is requiring reheat of the 

exhaust gas stream. Therefore, it is likely that all of the coal-fired units covered by this action 

will have wet stacks. So it is doubtful that any filterable PM10 method would work as the 

compliance method.207 Therefore, EPA is finalizing a decision to allow either Method 5 or 

Methods 201A and 202 for demonstrating compliance with the BART PM10 limits set by ADEQ. 

As noted above, the addition of the SCR to these EGUs for NOX control will likely 

increase the condensable PM that will be measured by Method 202. By offering the option of 

Method 5 or Methods 201A and 202, the facilities can determine which methods are compatible 

with their units’ stack conditions and will best demonstrate the proper operation of their PM 

controls. Any significant increase in H2SO4 and the appropriate control of this visibility 

impairing pollutant will be addressed through the PSD permitting process with a BACT 

 

205 75 FR 80118, 80121. 

206 See EPA’s Technical Information Document 09, “Methods 201 and 201A in Presence of Water Droplets” 

(September 9, 1991).

207See, e.g. 75 FR 80126 (“Monitoring the emission of PM10 or PM2.5 from a wet gas stream is a challenging 

problem that has not been addressed successfully despite considerable effort. A consensus method to provide this 

information has not emerged.”) 
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determination for H2SO4 control. The significance level that triggers permitting for H2SO4 is an 

increase of seven tons per year of this pollutant.208 Coronado has already received a PSD permit 

for H2SO4 that is likely to result from the increase in H2SO4 resulting from the SCR required 

under the consent decree. 

EPA’s AP-42 indicates that approximately one third of the filterable PM emissions from 

EGUs are larger than PM10. This means that the change from Method 201 (or 201A) to Method 5 

as the compliance method will result in this increased measurement of PM. This is offset by the 

elimination of the condensable measurement of Method 202 and as noted above, the utilities will 

have the option of using either testing approach. 

Comment: One commenter (APS) requests that EPA change the compliance date for the 

PM10 limit at Cholla Unit 2 to January 1, 2016, rather than January 1, 2015. The commenter 

explained that EPA misunderstood the language of the ADEQ SIP, which refers to APS’s 

commitment to install a fabric filter by 2015, to mean installment and operation by the first of the 

year, whereas this commitment actually meant by the end of 2015, or December 31, 2015. The 

commenter further requested that this date be extended to April 16, 2016, if the ADEQ approves 

APS’s request for a one-year extension to comply with the Mercury and Air Toxics Standards 

(MATS) before EPA finalizes this BART determination. 

The commenter also requested that EPA change the compliance date with the 0.15 

lb/MMBtu SO2 emissions standard from 180 days after promulgation to January 1, 2016, or 

April 16, 2016, to allow sufficient time to do the necessary upgrades for Unit 2. This unit will 

require scrubber upgrades that need to be done concurrent with the fabric filter installation to 

accommodate the increase in pressure drop that a new fabric filter will impose. ADEQ also 

 

208 See 40 CFR 52.21(b)(23)(i). 
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stated a compliance date of April 1, 2016, would be more appropriate than January 1, 2015, for 

both the PM10 and SO2 limits at Cholla Unit 2. 

Response: EPA agrees with this comment and has changed the compliance date in the 

final rule to April 1, 2016.209 In addition, as explained above, in order to ensure that the wet FGD 

(i.e. scrubbers) on all three units at Cholla are properly operated and maintained, consistent with 

40 CFR 51.308(e)(1)(v), we are finalizing a removal efficiency requirement for SO2 of 95 

percent on a 30-day rolling basis for Cholla Units 2, 3 and 4. Compliance with the efficiency 

requirement will be determined by SO2 continuous emission monitoring systems (CEMS) 

operated at the inlets and outlets of the scrubbers. Units 3 and 4 already have SO2 and CO2

CEMS installed after the scrubbers, and Unit 2 has SO2 and CO2 CEMS installed before the 

scrubbers.210 Therefore, SO2 and diluent CEMS will need to be installed at the inlets to the 

scrubbers on Units 3 and 4. We estimate that the total annualized cost for this installation 

(including ongoing operation and maintenance costs) will be approximately $51,000 per unit.211

We also note that this efficiency requirement will probably result in a slight increase in operation 

and maintenance costs in the form of additional limestone and scrubber waste disposal expenses. 

Even considered collectively, these additional costs are de minimis in comparison to the 

annualized cost of SCR (i.e., $9,906,206 to $13,590,853 per unit at Cholla, according to our 

supplemental cost analysis) or the total cost of installing a new wet FGD system, which APS has 

estimated to be $67.0 to $70.9 million.

212 In order to allow sufficient time for installation of the 

CEMS, the compliance deadline for this removal efficiency requirement at these units will be 

 

209 Although APS requested a deadline of April 16, 2016, this request was contingent upon ADEQ's approval of 

APS’s August 7, 2012 request for a one-year extension to comply with the MATS. ADEQ's comments indicate that 

April 1, 2016 is the appropriate deadline for this requirement, so we have modified the final compliance deadline to 

April 1, 2016. 

210 See Cholla Title V Permit (2012), Table C-3: Continuous Emission Monitors. 

211 We used EPA’s CEMS Cost Model (available at http://www.epa.gov/ttn/emc/cem.html) to estimate the total 

annualized cost of adding inlet CEMS for SO2 and CO2. See “CEMS Cost Calculation.” 

212 APS Comments, Table 3-8. No annualized cost was provided. 
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one year after publication of this final rule for Units 3 and 4. The removal efficiency compliance 

deadline for Unit 2 will coincide with the compliance date for the lb/MMBtu SO2 emission limit 

for this unit (i.e., April 1, 2016). 

Comment: Two commenters requested that EPA implement SCR installation in three 

rather than five years. Earthjustice claimed that the proposed five-year compliance deadline is 

unreasonable and inconsistent with the CAA and RHR requirements, noting that compliance 

before the “outside date” is required whenever earlier compliance is possible. This commenter 

contended that average SCR installations have required 37 to 43 months to implement, and EPA 

has provided no site-specific factors for these plants to require a longer-than-average installation 

time. The commenter notes that ADEQ has an “accelerated permit processing” program, so that 

any PSD permits needed to address sulfuric acid mist increases should not require an extension 

of the compliance deadline to five years. The commenter also requested that EPA obtain and post 

to the docket the outage schedule for these plants, which may provide additional justification for 

a compliance deadline shorter than five years. In contrast, SRP commented that, if EPA finalizes 

a requirement for SCR at Unit 1 “a five‐year compliance period is certainly warranted.” SRP 

noted that it estimated it would require 48 months to install SCR at Coronado Unit 2, and that 

installing SCR on Unit 1 would be even more complicated due to the reduced amount of space 

following the installation on Unit 2. 

Response: We are finalizing a compliance deadline of five years from final publication of 

this notice for all SCR-based emission limits. As explained in our proposal, five years is a 

reasonable time frame for SCR design and installation, particularly where retrofits of multiple 

units at a single facility are required. Granting the full five years for SCR design and installation 

will allow the facilities to tie in the SCR systems during routinely scheduled maintenance 
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outages, which are typically scheduled for every three years. With respect to Coronado in 

particular, the five-year compliance schedule will allow SRP sufficient time to design and install 

the SCR system on Unit 1 and to design and install a low-load temperature controller on Unit 2, 

which likely must be done in the period after the SCR for Unit 2 is placed into operation (June 1, 

2014). 

Comment: One commenter (Earthjustice) stated that EPA should set BART limits for 

PM2.5 and PM10, rather than just PM10. The commenter indicated that the BART Guidelines 

specify that BART should be evaluated and defined for both PM2.5 and PM10 (citing 40 CFR part 

51, Appendix Y, section II.A.3). 

Response: The BART Guidelines do not require states to set BART limits for PM2.5 in 

addition to limits for PM10. The portions of the BART Guidelines cited by commenters (i.e. 

sections II.A.3 and III.A.2) pertain to the identification of sources that are BART-eligible and 

sources that are subject-to-BART, not the actual five-factor analysis or determination of BART 

for a given source, which is described in section IV of the Guidelines. With respect to the fivefactor analysis, the Guidelines provide that, “[m]odeling should be conducted for SO2, NOX and 

direct PM emissions (PM2.5 and/or PM10).”213 The Guidelines thus provide states with the 

flexibility to consider either PM2.5 or PM10 emissions or both, as part of their five-factor analysis. 

Likewise, the Guidelines do not require that the emission limits reflecting BART should include 

separate limits for PM2.5 and PM10.

214 Thus, we are not required by the RHR to set separate 

BART limits for PM2.5. 

 

213 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.5. 

214 Id. Section V. 
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 F. Comments on Legal Issues 

Comment: A number of commenters asserted that EPA has acted in a manner contrary to 

the CAA, under which states are to play the lead role in designing and implementing the regional 

haze program. These commenters typically indicated that EPA is required to defer to the states’ 

judgment regarding BART where the state has considered the five statutory BART factors, and 

has no authority to override a state’s BART determination simply because it disagrees with the 

state’s conclusions. The commenters often stated that the states are empowered by the CAA to 

determine how best to weigh each of the statutory BART factors and that EPA’s only legal role 

in SIP review is to determine whether the state’s plan is consistent with the CAA. The 

commenters generally stated the belief that ADEQ’s BART determinations fully complied with 

the CAA, the Regional Haze Rule and the BART Guidelines. The commenters frequently cited 

American Corn Growers Ass’n. v. EPA, 291 F.3d (D.C. Cir. 2002); EME Homer City 

Generation, L.P. v. EPA, No. 11‐1302, slip op. at 42 (D.C. Cir. Aug. 21, 2012) (“CSAPR 

decision”); Luminant Generation Co. v. EPA, 675 F.3d 917, 921 (5th Cir. 2012); and State of 

Texas, et al., v EPA. 690 F.3d 670 (5th Cir. 2012). 

Several commenters stated that EPA made no finding that Arizona failed to satisfy its 

statutory obligation to consider and weigh the BART factors, and asserted that EPA conceded 

that the state had done so in its FIP proposal (citing 77 FR 42851). Some commenters (AEPCO, 

SRP) stated that EPA proposed to disapprove the SIP, in part, because it is not consistent with 

BART decisions that other states have made (citing 77 FR 42836), and contended that this 

finding is irrelevant to the approvability of ADEQ’s SIP. One commenter (SRP) added that 

ADEQ’s BART determinations are entirely legal and reasonable and, to the extent that other 

states’ BART determinations may be relevant, consistent not only with the action of other states, 
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but with action that EPA has approved or proposed to approve for those states (i.e., combustion 

controls as BART for NOX). 

Two commenters added that EPA purported to defer to ADEQ’s BART determinations 

by indicating that it would prefer to act on a SIP revised to address the deficiencies perceived by 

EPA (citing 77 FR 42839), but the commenters asserted that it is not deference to invite the State 

to submit a SIP that conforms to EPA’s policy choices. The commenters contended that in any 

case, with the court ordered deadline of November 15, 2012, for EPA to finalize the proposed 

FIP, it would be impossible for Arizona to prepare and adopt a revised SIP in time. 

Response: We do not agree that our partial disapproval of the Arizona Regional Haze SIP 

is contrary to the CAA. As noted by several commenters, States have the lead role in determining 

BART for individual sources through SIPs. However, EPA also has a crucial role in reviewing 

SIPs for compliance with the requirements of the CAA and its implementing regulations. 

Pursuant to CAA section 110, States must submit SIPs to EPA for review and EPA must review 

SIPs for consistency with the Act’s requirements and disapprove any SIP revision that “would 

interfere with any applicable requirement” of the Act.215 The CAA also empowers EPA to call 

for SIP revisions “[w]henever [EPA] finds that the applicable implementation plan for any area 

is substantially inadequate to . . . comply with any requirement of this chapter,” and impose 

sanctions when EPA determines they are “reasonable and appropriate for the purpose of ensuring 

that the requirements [of the Act] . . . are met.”216 Furthermore, the Act mandates that EPA 

promulgate a FIP when EPA finds that a State has failed to submit a required SIP to the Agency, 

 

215 CAA section 110(a)(1), (k)(3) and (l), 42 U.S.C. §§ 7410(a)(1), (k)(3) and (l). 

216 See id. 42 U.S.C. § 7410(k)(5), (m). 
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failed to submit a complete SIP, or where EPA disapproves a SIP.217 Thus, the CAA provides 

EPA with a critical oversight role in ensuring that SIPs meet the requirements of the CAA.

Nothing in the CAA indicates that EPA’s role is less important in the context of the 

Regional Haze program than under other CAA programs. On the contrary, CAA section 

110(a)(2)(J) explicitly requires that SIPs “meet the applicable requirements” of Part C of Title I 

of the CAA including the requirements for visibility protection set forth in sections 169A and 

169B.218 Pursuant to section 169A(b), EPA is required to promulgate visibility protection 

regulations that apply to “each applicable implementation plan” (i.e. each SIP or FIP)219 for each 

State containing one or more Class I areas and each State “emissions from which may reasonably 

be anticipated to cause or contribute to any impairment of visibility in any [Class I area].”220 The 

CAA specifies that these regulations (including the RHR) must require each such SIP or FIP to 

“contain such emission limits, schedules of compliance and other measures as may be necessary 

to make reasonable progress toward meeting the national goal,” including implementation of 

BART, as determined by the State (or by EPA in the case of a FIP).221 Moreover, the CAA 

requires that BART for each “fossil-fuel fired generating power plant having a total generating 

capacity in excess of 750 megawatts” must be determined pursuant to the guidelines 

 

217 See id. § 7410(c)(1). 

218 CAA sections 110(a)(2)(J), 169A and 169B 42 U.S.C. §§ 7410(a)(2)(J), 7491 and 7492. 

219 Under the CAA, “applicable implementation plan” is defined as “the portion (or portions) of the implementation 

plan, or most recent revision thereof, which has been approved under [CAA § 110], or promulgated under [CAA § 

110](c) . . . and which implements the relevant requirements of [the CAA].” CAA section 302(q), 42 U.S.C. § 

7602(q). In other words, an “applicable implementation plan” is an EPA-approved SIP or Tribal Implementation 

Plan, or an EPA-promulgated FIP. 

220 42 U.S.C. § 7491(b)(2). In promulgating the RHR, EPA determined that “all States contain sources whose 

emissions are reasonably anticipated to contribute to regional haze in a Class I area and, therefore, must submit 

regional haze SIPs.” 64 FR 35720; see also 40 CFR 51.300(b)(3). 

221 42 U.S.C. § 7491(b)(2). 
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promulgated by EPA (i.e., the BART Guidelines).222 Thus, the statute provides EPA a key 

oversight role in reviewing SIPs for compliance with the RHR and BART requirements. 

The cases cited by commenters do not support an argument that EPA’s role as a reviewer 

is any less critical in the regional haze context than it is in reviewing other SIP components. In 

American Corn Growers v. EPA, the petitioners challenged the original RHR because, among 

other things, the RHR treated one of the five statutory factors differently than the others by 

requiring States to consider the degree of visibility improvement from imposing BART on a 

group of sources rather than on a source-specific basis.223 The court concluded that such a 

requirement could force States to apply BART controls at sources without evidence that the 

individual sources contributed to visibility impairment at a Class I area, which encroached on 

States’ primary authority under the regional haze provisions to determine which individual 

sources are subject to BART and what BART controls are appropriate for each source.

224

Therefore, the court vacated the visibility improvement part of the original RHR as contrary to 

the statute.225 Contrary to some commenters’ suggestions, however, the American Corn Growers 

decision did not address EPA’s authority to reject a State’s BART determinations for failure to 

conform to the CAA, the RHR or the BART Guidelines. 

Commenters also cite Luminant Generation v. EPA, 675 F.3d 917, 921 (5th Cir. 2012) 

and Texas v. EPA, 690 F.3d 670 (5th Cir. 2012). Neither of these cases involves BART or the 

CAA’s regional haze provisions at all. Rather, they involved EPA’s disapprovals of SIP 

revisions involving Texas’s minor new source review (NSR) program. As noted by the Luminant 

 

222 Id. In this case, Cholla and Coronado each have a total generating capacity in excess of 750 megawatts, while 

Apache has a total plant-wide generating capacity of 560 megawatts. Thus, the BART Guidelines are mandatory for 

BART determinations at Cholla and Coronado and serve as non-binding guidance with respect to Apache. 

223 291 F.3d at 5-9. 

224 Id. at 7-8. 

225 EPA revised the RHR to address the court’s decision in American Corn Growers at the same time as we 

promulgated the BART Guidelines. 70 FR 39104 (July 6, 2005). The revised RHR and the Guidelines were upheld 

by the D.C. Circuit in Utility Air Regulatory Group v. EPA, 471 F.3d 1333 (D.C. Cir. 2006). 
Page 189 of 244

court, “because ‘the Act includes no specifics regarding the structure or functioning of minor 

NSR programs’ and because the implementing regulations are ‘very general [,] ... SIP-approved 

minor NSR programs can vary quite widely from State to State.’”226 By contrast, Regional Haze 

SIPs and BART determinations are subject to detailed requirements set forth in CAA sections 

169A, the RHR and the BART Guidelines. While in Luminant and Texas, the Fifth Circuit found 

that EPA had failed to tie its disapproval to any requirement of the CAA or EPA’s implementing 

regulations,227 in this case our disapproval is based on the SIP’s failure to comply with CAA 

sections 110(a)(2) and 169A(b)(2)(A), as implemented through the RHR and the BART 

Guidelines. 

As noted above, CAA section 110(a)(2)(J) requires all SIPs to “meet the applicable 

requirements” of Part C of Title I of the CAA, including the requirement that each source found 

subject-to-BART, “procure, install, and operate, as expeditiously as practicable (and maintain 

thereafter) the best available retrofit technology . . .”228 Section 169A(g)(2) further provides that: 

In determining best available retrofit technology the State (or the Administrator in 

determining emission limitations which reflect such technology) shall take into 

consideration the costs of compliance, the energy and nonair quality environmental 

impacts of compliance, any existing pollution control technology in use at the source, the 

remaining useful life of the source, and the degree of improvement in visibility which 

may reasonably be anticipated to result from the use of such technology.

229

Similarly, the RHR provides that: 

The determination of BART must be based on an analysis of the best system of 

continuous emission control technology available and associated emission 

reductions achievable for each BART-eligible source that is subject to BART 

within the State. In this analysis, the State must take into consideration the 

technology available, the costs of compliance, the energy and nonair quality 

environmental impacts of compliance, any pollution control equipment in use at 

the source, the remaining useful life of the source, and the degree of improvement 

 

226 675 F.3d at 922 (citing 74 FR 51418, 51421 (Oct. 6, 2009). 

227 675 F.3d at 924, 929; 690 F.3d at 679, 682, 686. 

228 CAA section 169A(b)(2)(A)., 42 U.S.C. § 7491(b)(2)(A). 

229 42 U.S.C. § 7491(g)(2). 
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in visibility which may reasonably be anticipated to result from the use of such 

technology.

230

ADEQ’s BART determinations for NOX at Apache Units 2 and 3, Cholla Units 2, 3 and 4 and 

Coronado Units 1 and 2 fall short of these requirements in several respects. 

First, ADEQ did not analyze the “best system of continuous emission control technology 

available and associated emission reductions achievable.” Rather it accepted the source’s own 

assertions about what emissions reductions were achievable with various control technologies. 

For example, in response to comments from the FLMs arguing that SCR could achieve lower 

rates on 30-day-rolling average, ADEQ stated that: 

ADEQ’s BART evaluations were based on site-specific information provided by 

the applicants. It is the Department’s understanding that such information was 

based partially on feedback received from vendors and plant personnel who are 

intimately familiar with the specific equipment that is being considered. In that 

regard, the Department based its BART computations on the emission rates 

proposed by the applicant for the different control technology options.231

While it is certainly reasonable to consider site-specific information provided by the sources as 

part of a BART analysis, it is not reasonable to assume, with no independent analysis, that the 

sources have appropriately identified the emissions reductions achievable with the best available 

controls. ADEQ provided no evidence that the sources’ estimates were based on legitimate sitespecific considerations or that ADEQ undertook any verification of these estimates. Therefore, 

ADEQ has not demonstrated that its BART determinations were “based on an analysis of the 

best system of continuous emission control technology available and associated emission 

reductions achievable.” 

Second, ADEQ has not demonstrated that it actually took into consideration the BART 

factors in making its determinations. In particular, while ADEQ provided information regarding 

 

230 40 CFR 51.308(e)(1)(ii)(A) 

231 Arizona Regional Haze SIP, Appendix E, “Responsiveness Summary” at 13. 
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each of the factors, it gave no explanation or rationale for how it reached a determination based 

on that information. 

Finally, ADEQ did not appropriately consider the “degree of improvement in visibility 

which may reasonably be anticipated” from installation of BART because it did not consider 

visibility benefits at all of the affected Class I areas, nor did it consider the total visibility benefit 

expected to result from the entire BART-eligible source. Overlooking significant visibility 

benefits at additional areas and from multiple BART–eligible units considerably understates the 

overall benefit of controls to improve visibility and is contrary to the very purpose of BART, i.e., 

“eliminating or reducing” visibility impairment at all Class I areas.232 Thus ADEQ’s BART 

determinations for NOX at Apache Units 2 and 3, Cholla Units 2, 3 and 4 and Coronado Units 1 

and 2 do not meet the requirements of CAA section 169A(g)(2) or 40 CFR 51.308(e)(1)(ii)(A). 

In addition, 40 CFR 51.308(e)(1)(ii)(B) provides that: 

The determination of BART for fossil-fuel fired power plants having a total 

generating capacity greater than 750 megawatts must be made pursuant to the 

guidelines in appendix Y of this part (Guidelines for BART Determinations under 

the Regional Haze Rule). 

Cholla and Coronado each have a generating capacity greater than 750 megawatts. Therefore, the 

BART determinations for these BART sources must be made pursuant to the BART Guidelines. 

However, ADEQ’s BART determinations for these sources did not fully comply with the BART 

Guidelines. In particular, as explained more fully above, contrary to the Guidelines’ direction 

that “cost estimates should be based on the OAQPS Control Cost Manual, where possible,” the 

control cost calculations supplied by the utilities and relied upon by ADEQ included line item 

costs not allowed by the Control Cost Manual, such as owner's costs, surcharge, and AFUDC. 

Thus, ADEQ’s consideration of the “cost of compliance” for these units was not consistent with 

 

232 CAA section 169A(b)(2)(A). 
Page 192 of 244

the Guidelines. Furthermore, as explained above, ADEQ’s consideration of visibility benefits 

was inconsistent with the Guidelines because the State did not consider benefits at multiple Class 

I areas and multiple BART-eligible units at each source. In addition, ADEQ failed to provide “a 

justification for adopting the technology [the State selected] as the ‘best’ level of control, 

including an explanation of the CAA factors that led [the State] to choose that option over other 

control levels.”233 Therefore, ADEQ’s BART determinations for NOX at Cholla and Coronado 

do not comply with 40 CFR 51.308(e)(1)(ii)(B). 

Finally, for all pollutants at all units covered by today’s action, ADEQ’s Regional Haze 

SIP does not meet the requirements of 40 CFR 51.308(e)(1)(iii) and (iv) because it lacks the 

following elements: 

(iv) A requirement that each source subject to BART be required to install and 

operate BART as expeditiously as practicable, but in no event later than 5 years 

after approval of the implementation plan revision. 

(v) A requirement that each source subject to BART maintain the control 

equipment required by this subpart and establish procedures to ensure such 

equipment is properly operated and maintained. 

These two requirements are mandatory elements of the RHR and are necessary to ensure that 

BART is procured, installed and operated, as expeditiously as practicable and maintained 

thereafter, as required under CAA section 169A(b)(2)(A). Moreover, CAA section 110(a)(2) 

requires that emissions limits such as BART be “enforceable” and section 302(k) requires 

emissions limits to be met on a continuous basis. Arizona’s Regional Haze SIP lacks 

requirements for monitoring, recordkeeping and reporting sufficient to ensure that the BART 

limits are enforceable and are met on a continuous basis. 

 

233 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.2. 
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Therefore, Arizona’s BART determinations for Apache, Cholla and Coronado do not 

meet several requirements of the CAA, the RHR and the BART Guidelines. Accordingly, we are 

compelled to partially disapprove Arizona’s Regional Haze SIP. 

Finally, several commenters cited EME Homer City Generation v. EPA, No. 11‐1302 

(D.C. Cir. Aug. 21, 2012). In EME Homer City Generation, the D.C. Circuit vacated EPA’s 

“Transport Rule” (also known as the “Cross-State Air Pollution Rule” or “CSAPR”), which was 

promulgated by EPA to address interstate transport of SO2 and NOX under CAA section 

110(a)(2)(D). The court found that the Transport Rule exceeded EPA’s authority under section 

110(a)(2)(D) because the rule had the potential to require upwind States to reduce emissions by 

more than their own significant contributions to downwind nonattainment and because EPA had 

not given states an opportunity to submit SIPs after it quantified their obligations for emissions 

reductions to address transport. Commenters here point to the D.C. Circuit’s statements 

concerning state and federal roles under the CAA and argue that EPA has exceeded its statutorily 

mandated role in proposing to disapprove portions of Arizona’s Regional Haze SIP and 

promulgate a FIP. 

While we agree that the general principles concerning state and federal roles under Title I 

of the CAA apply to our action here, we do not agree that our action here is inconsistent with 

those principles. In this action, we are fulfilling our statutory duty to review Arizona’s Regional 

Haze SIP, including its BART determinations, for compliance with the applicable requirements 

of the CAA and the RHR, and to disapprove any portions of the plan that do not meet those 

requirements. Based on our review of the SIP, we proposed to determine that certain elements of 

Arizona’s Regional Haze SIP did meet the requirements of the CAA and the RHR, and we 

proposed to approve those elements. However, for the reasons explained in detail in our proposal 
Page 194 of 244

and elsewhere in this document, we have concluded that Arizona’s BART determinations for 

NOX at several units did not comply with the requirements of the CAA and the RHR. Based on 

these findings, we are required to disapprove these portions of Arizona’s Regional Haze SIP. 

In some instances, we expressed our findings of non-compliance with the relevant 

requirements in terms of “disagreement” with the state’s analysis. These statements were not 

intended to suggest that our proposed partial disapproval was simply based on policy 

disagreements with the state. Rather we used the term “disagree” as a short hand for our findings 

that specific elements of Arizona’s analyses did not meet the requirements of the CAA and the 

RHR. For example, we noted that, “[w]e disagree with several aspects of the NOX BART 

analysis for Apache Units 2 and 3.”234 We then went on to list the specific deficiencies in the 

state’s analysis, and concluded that “we are proposing to disapprove ADEQ’s BART 

determination for NOX at Apache Units 2 and 3, since it does not comply with 40 CFR 

51.308(e)(1)(ii)(A).”235 We made similar findings with respect to ADEQ’s BART determination 

for NOX at Cholla Units 2, 3 and 4 and Coronado Units 1 and 2.236 We have also described in 

detail, both in our proposal and in this document, the other aspects of the state’s BART 

determinations that do not comply with the CAA and the RHR. 

Finally, some commenters appear to have misunderstood our statement that ADEQ’s 

“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 noted by several 

commenters, the CAA and the RHR provide states with considerable discretion in deciding how 

to weigh the statutory factors as a part of a BART analysis. However, this discretion must be 

reasonably exercised in compliance with the applicable requirements. Consistency with other 

 

234 77 FR 42846. 

235 Id. 

236 77 FR 42849, 42851. 
Page 195 of 244

EPA-approved BART determinations is one marker of reasonableness, as well as compliance 

with the requirements of the RHR. Such consistency is particularly relevant for BART 

determinations at fossil-fuel fired power plants having a capacity in excess of 750 megawatts, 

which must be made pursuant to the BART Guidelines.237 To the extent a BART determination 

for such a power plant is plainly inconsistent with EPA-approved determinations for similar 

sources, it is more likely to be inconsistent with the RHR and the BART Guidelines and 

therefore to warrant greater scrutiny for compliance with the applicable requirements. 

Comment: Several commenters (ACCCE, ADEQ, APS, SRP) asserted that it is contrary 

to the CAA for EPA to propose action on only the portions of ADEQ’s SIP that address the three 

power plants that are the subject of the proposed FIP. One commenter (APS) stated that EPA 

may not ignore all other sources of visibility-impairing pollutants in the state (nor may it ignore 

the other categories of visibility-impairing pollutants by focusing only on nitrates, sulfates and 

PM) and establish BART limitations for the three affected power plants outside the context of 

the long-term strategy and larger reasonable progress requirements of the regional haze program. 

Commenters ACCCE, ADEQ and SRP contended that CAA section 110(k)(3) requires EPA 

either to approve a SIP submittal “as a whole” or to approve that SIP submittal in part and 

disapprove it in part in a single rulemaking that addresses in its entirety “the plan revision.” The 

commenters indicated that this requirement of the CAA is sensible because it is the plan as a 

whole, with all its elements working together, that must ensure that the CAA’s regional 

haze‐related goals are being reached; any other approach to SIP review and approval would fail 

to take into account the full array of regulatory choices that Arizona has made to address regional 

haze. 

 

237 CAA section 169A(b) and 40 CFR 51.308(e)(1)(ii)(B) 
Page 196 of 244

Response: We do not agree that we are required to act on Arizona’s Regional Haze SIP as 

a whole. As noted by some commenters, our action on Arizona’s Regional Haze SIP is governed 

by inter alia, CAA section 110(k)(3), which provides that: 

In the case of any submittal on which the Administrator is required to act under 

paragraph (2), the Administrator shall approve such submittal as a whole if it 

meets all of the applicable requirements of this chapter. If a portion of the plan 

revision meets all the applicable requirements of this chapter, the Administrator 

may approve the plan revision in part and disapprove the plan revision in part. 

The plan revision shall not be treated as meeting the requirements of this chapter 

until the Administrator approves the entire plan revision as complying with the 

applicable requirements of this chapter.238

Some commenters have read this provision as requiring that EPA act on Arizona’s Regional 

Haze SIP as a whole. We disagree that this language addresses the question of whether EPA may 

consider different elements of a State’s plan in separate notice and comment rulemakings. 

However, even assuming that this provision of the Clean Air Act did limit EPA’s ability to act 

sequentially on portions of a SIP submission, the requirement to act on a submittal “as a whole” 

applies only if the submittal meets all of the applicable requirements of the CAA. As explained 

in our proposal and elsewhere in this document, we have determined that the Arizona Regional 

Haze SIP does not meet all of the applicable requirements of the CAA. Specifically, we have 

determined that the submittal as a whole does not meet the requirements of CAA section 

169A(b)(2)(A), as implemented through the RHR and the BART Guidelines. Under these 

circumstances, we are clearly not obligated to act on the plan as a whole, but are given discretion 

to act on distinct portions of the plan.239

While we agree that, as a matter of policy, it is generally preferable to act on plan 

submissions as a whole, we are currently subject to a court-ordered deadline of November 15, 

2012 to act on the BART determinations for Apache Generating Station, Cholla Power Plant and 

 

238 42 U.S.C. § 7410(k)(3). 

239 See Hall v. EPA, 273 F.3d 1146, 1159 (9th Cir. 2001) (section 110(k)(3) “permits the EPA to issue ‘partial 

approvals,’ that is, to approve the States' SIP revisions in piecemeal fashion”). 
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Coronado Generating Station.240 Although these BART determinations are part of the overall 

Regional Haze plan for Arizona, they are also severable from that plan, since BART 

determinations are made on a source-by-source basis and are not dependent upon other elements 

of the plan.

241 Therefore, we are taking action on these BART determinations first and we will 

act on the remainder of the Arizona Regional plan in accordance with the court-ordered 

deadlines for that action. 

Comment: One commenter (ADEQ) asserts that EPA does not have the authority to adopt 

a FIP because none of the three triggering events for a FIP under CAA section 110(c)(1) has 

occurred. Specifically, the commenter states that: 

. . . for EPA to have authority to promulgate a regional haze FIP in Arizona, one 

of three events must have occurred: (1) a finding of failure to submit a regional 

haze SIP, (2) a finding of failure to satisfy the minimum criteria for a complete 

regional haze SIP under section 110(k)(1)(A) or (3) disapproval of a regional haze 

SIP submitted by Arizona. None of these three events has occurred . . . 

With respect to EPA’s January 2009 finding of failure to submit, the commenter argues that: 

Section 110(c)(1) . . . does not allow EPA to treat the omission of elements from a 

SIP submission as a failure to submit a SIP. Section 110(c)(1) is quite specific. If 

EPA believes SIP omissions render a SIP incomplete, the agency may make a 

finding under section 110(k)(1)(A) within the time period required by section 

110(k)(1)(B) and start the FIP clock under the second clause of section 

110(c)(1)(A). If EPA cannot make such a finding or, as in this case, fails to do so, 

the agency may disapprove the SIP, and start the FIP clock under section 

110(c)(1)(B). By treating the alleged omission of elements from a SIP as the 

failure to make a required submission under the first clause of section 

110(c)(1)(A), EPA is circumventing these procedures. 

The commenter adds that if EPA did have the authority to promulgate a regional haze FIP, it 

would only have the authority to address those elements of the SIP that EPA identified as having 

 

240 EPA agreed to this deadline after concluding that litigation would most likely result in a shorter schedule than 

that to which Plaintiffs had agreed in negotiation. See Sierra Club v. Johnson, 444 F.Supp.2d 46, 58 (D.D.C. 2006) 

(“this case devolves to a single issue: whether defendant has met the ‘heavy burden’ of demonstrating that it would 

be impossible to comply with plaintiff's proposed . . .”). 

241 See 40 CFR § 51.308(e)(1)(ii)(A)(“[t]he determination of BART must be based on an analysis of the best system 

of continuous emission control technology available and associated emission reductions achievable for each BARTeligible source that is subject to BART within the State.” (emphasis added)). 
Page 198 of 244

not been submitted, and EPA has never found that Arizona failed to submit a SIP establishing 

BART. 

Response: We do not agree that we lack authority to issue a FIP addressing BART 

requirements for the three sources covered by today’s action. The commenter’s arguments in this 

regard appear to be based on a misunderstanding of the requirements of the CAA and the RHR in 

relation to Arizona’s Regional Haze submittals. 

EPA promulgated the original RHR in 1999.242 As relevant here, section 308 of the RHR 

requires states to submit SIPs that establish reasonable progress goals and long-term strategies 

for achieving those goals and provide for implementation of BART.243 In addition to the general 

requirements of section 308, EPA also adopted specific provisions that gave a handful of states, 

including Arizona, the option of submitting a regional haze SIP based on the recommendations 

of the Grand Canyon Visibility Transport Commission (GCVTC). Under the RHR, a SIP 

approved by EPA as meeting all of the requirements of section 309 would be “deemed to comply 

with the requirements for reasonable progress with respect to the 16 Class I areas [on the 

Colorado Plateau] for the period from approval of the plan through 2018.”244

Arizona made two submittals under section 309 in 2003 and 2004, but never submitted a 

complete 309 SIP.245 Rather, on December 24, 2008, ADEQ sent a letter to EPA re-submitting 

its prior 309 SIP submissions and acknowledging that the submittal did not include provisions to 

address the requirements of 309(d)(4) or 309(g).246 These were not minor omissions: 309(d)(4) 

required the submission of “better than BART” milestones and a trading program for SO2, as 

 

245 We have included a more detailed history of Arizona’s submissions under 309 in the docket for this action 

(Docket No. EPA-R09-OAR-2012-0021). 

246 Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA (Dec. 14, 2008). 
Page 199 of 244

well as BART requirements for stationary source PM and NOX emissions, and 309(g) required 

implementation of any additional measures necessary to demonstrate reasonable progress for the 

additional Class I areas, in compliance with the provisions of §51.308(d)(1) through (4).247 Thus, 

as of 2008, ADEQ’s Regional Haze SIP, by its own admission, did not include provisions 

addressing BART (or for an alternative to BART) for NOX, PM or SO2. On January 15, 2009 

EPA found that 37 states, including Arizona, had failed to make all or part of the required SIP 

submissions to address regional haze.248 We explained that: 

This finding starts the two year clock for the promulgation by EPA of a FIP. EPA 

is not required to promulgate a FIP if the state makes the required SIP submittal 

and EPA takes final action to approve the submittal within two years of EPA's 

finding.249

Under the CAA, any party seeking judicial review of EPA’s finding of failure to submit (“2009 

Finding”) was required to file a petition for review with the appropriate United States Circuit 

Court of Appeals within 60 days of publication of the Finding in the Federal Register.250 No 

party filed such a petition. 

At the time of the 2009 Finding, EPA anticipated that ADEQ would submit a SIP 

revision covering 309(d)(4) and 309(g), which would enable EPA to fully approve ADEQ’s 309 

SIP as meeting all of the requirements of the Regional Haze Rule, thus ending the FIP clock. 

However, ADEQ did not submit a 309 SIP revision to address these two elements, but instead 

decided to develop a 308 SIP, which it submitted to EPA in February 2011. 

In January 2011, EPA received a notice of intent to sue covering dozens of states, 

including Arizona, stating that we had not met the statutory deadline for promulgating Regional 

Haze FIPs and/or approving Regional Haze SIPs. This notice was followed by a lawsuit filed by 

 

247 40 CFR 51.309(d)(4)(i) and (vii), (g)(2). 

248 74 FR 2392. 

249 Id. at 2393 

250 CAA section 307(b). 42 U.S.C. § 7607(b). 
Page 200 of 244

several advocacy groups (Plaintiffs) in August 2011.251 In order to resolve this lawsuit and avoid 

litigation, EPA entered into a Consent Decree with the Plaintiffs, which sets deadlines for action 

for all of the states covered by the lawsuit, including Arizona. This decree was entered and later 

amended by the Federal District Court for the District of Columbia over the opposition of 

Arizona.252 

In opposing the entry of the consent decree, Arizona argued that the 2009 Finding did not 

give EPA authority to promulgate a Regional Haze FIP for Arizona. The court rejected this 

argument, explaining that: 

Arizona contends that the Finding did not constitute a disapproval of the SIPs that 

had previously been submitted because it only notes that Arizona did not submit 

two of Section 309’s required elements. Ariz. Opp. [Dkt. # 24] at 6. The Court 

does not read the 2009 Finding so narrowly. In the Court’s view, the 2009 Finding 

reaches a conclusion that Arizona ‘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.’ 42 U.S.C. § 7410(c)(1). Under the CAA, this triggers the 

EPA’s statutory obligation to promulgate a FIP.253

Under the terms of the Consent Decree, as amended, EPA is currently subject to two sets of 

deadlines for taking action on Arizona’s Regional Haze SIP. Specifically, the CD requires that: 

By the “Proposed Promulgation Deadlines” set forth in Table A below EPA shall 

sign a notice(s) of proposed rulemaking in which it proposes approval of a SIP, 

promulgation of a FIP, partial approval of a SIP and promulgation of a partial FIP, 

or approval of a SIP or promulgation of a FIP in the alternative, for each State 

therein, that collectively meet the regional haze implementation plan requirements 

that were due by December 17, 2007 under EPA’s regional haze regulations. 

By the “Final Promulgation Deadlines” set forth in Table A below, EPA shall sign 

a notice(s) of final rulemaking promulgating a FIP for each State therein to meet 

the regional haze implementation plan requirements that were due by December 

17, 2007 under EPA’s regional haze regulations, except where, by such deadline 

EPA has for a State therein signed a notice of final rulemaking unconditionally 

 

251 National Parks Conservation Association v. Jackson (D.D.C. Case 1:11-cv-01548). 

252 National Parks Conservation Association v. Jackson (D.D.C. Case 1:11-cv-01548), Memorandum Order and 

Opinion (May 25, 2012) and Minute Order (July 2, 2012). 

253 See NPCA v. EPA, (D.D.C. Case 1:11-cv-01548). Dkt # 35, at 3, n. 1. 
Page 201 of 244

approving a SIP, or promulgating a partial FIP and unconditional approval of a 

portion of a SIP, that collectively meet the regional haze implementation plan 

requirements that were due by December 17, 2007 under EPA’s regional haze 

regulations. 

Table A, as revised, sets a proposal deadline for BART determinations for Apache Generating 

Station, Cholla Power Plant and Coronado Generating Station of July 2, 2012 and the final action 

deadline for these three BART determinations of November 15, 2012. The deadline for EPA to 

propose action on the remainder of the Arizona Regional Haze SIP is December 8, 2012, and the 

deadline for final action is July 15, 2013.254 

Thus, pursuant to CAA section 110(c)(1) and the court’s orders entering and amending 

the Consent Decree, we are not only authorized, but are required to issue a FIP for any portion of 

the Arizona SIP that we cannot approve. For the reasons stated in our proposal and elsewhere in 

this document, we have determined that we cannot approve the state’s BART determinations for 

NOX at Apache, Cholla and Coronado, nor can we approve the compliance-related requirements 

that were omitted from the Arizona Regional Haze SIP. Therefore, we are obligated to 

promulgate a FIP to address these requirements. 

Comment: Several commenters (AUG, EEI, PacifiCorp, SRP) stated that EPA cannot 

propose or finalize a NOX BART FIP for these Arizona plants until it has taken final action 

(following notice-and-comment rulemaking) on ADEQ’s Regional Haze SIP. According to the 

commenters, EPA’s authority to propose and then take final action to promulgate a FIP comes 

into existence only when a state has not submitted a SIP or when EPA has made a final 

determination that that a submitted SIP is not approvable (citing Train v. NRDC, 421 U.S. 60, 79 

(1975)). The commenters believe this principle is confirmed by CAA sections 307(d)(1)(B), (3) 

 

254 On November 13, 2012, the D.C. District Court granted a motion by EPA to modify the Consent Decree to 

extend the deadlines for promulgation of a FIP for any remaining elements of the SIP that are disapproved. Under 

the revised deadlines, EPA will propose any necessary FIP elements by March 8, 2013, and finalize such elements 

by October 15, 2013. 
Page 202 of 244

and (6) because EPA cannot present the relevant factual, legal, and policy information and 

rationale necessary to justify a proposed or final FIP rule until it has properly taken final action 

on any relevant SIP before it. 

One commenter (EEI) also states that EPA’s assertion that it was compelled to propose a 

FIP at the same time that it disapproved a portion of the Arizona SIP, due to a two-year FIP 

clock that started with EPA’s 2009 Finding of Failure to Submit, is inconsistent with the CSAPR 

decision. The commenter stated that EPA did not provide sufficient notice of the problems with 

the SIP to enable Arizona to remedy them, which is precisely the same problem identified by the 

CSAPR court. The commenter adds that EPA must provide the state a realistic opportunity to 

avoid being pulled into a FIP. Given that EPA has consent decree obligations to finalize BART 

requirements for the EGUs addressed by the proposed SIP by November 15, 2012, and EPA did 

not propose disapproval of the SIP until July 20, 2012, a reasonable opportunity to develop and 

receive approval of a revised SIP was not offered to the state. 

Response: We do not agree that we are required to take final action on Arizona’s 

Regional Haze SIP before promulgating a FIP. Commenters’ arguments to this effect appear to 

conflate the procedural requirements for EPA’s issuance of a FIP with procedural requirements 

for action on a SIP. In fact, these are two actions are governed by different provisions of the 

CAA.

As explained in the previous response, EPA’s 2009 finding that Arizona failed to submit 

a complete Regional Haze SIP triggered a “FIP clock” under CAA section 110(c).255 This FIP 

clock could only have been stopped if Arizona had submitted, and EPA had fully approved a 

 

255 42 U.S.C. § 7410(c). See also Train, 421 U.S. at 64, 79 (explaining that the 1970 CAA Amendments “sharply 

increased federal authority and responsibility in the continuing effort to combat air pollution,” including giving EPA 

authority to devise a FIP if the State’s plan fails to satisfy the standards of section 7410(a)(2)). 
Page 203 of 244

Regional Haze SIP, before January 15, 2011. Neither of these two things occurred. Therefore, 

EPA remains subject to this “FIP duty.” Our action today fulfills part of that duty. 

As several commenters noted, Arizona submitted a Regional Haze SIP on February 28, 

2011, and the SIP was deemed complete by operation of law on August 28, 2011, pursuant to 

CAA section 110(k)(1)(B).256 This, in turn, triggered a deadline of August 28, 2012, for us to 

take final action on the SIP, pursuant to CAA section 110(k)(1)(B).257 We acknowledge that this 

deadline has now passed and we intend to act as quickly as possible to fulfill our duty to act on 

those portions of the SIP not addressed in today’s action. However, the fact that we have not 

acted on the entirety of the SIP submittal does not remove or otherwise alter our legal obligation 

to promulgate a FIP under CAA section 110(c). Our FIP duty does not terminate until we have 

actually approved the submitted SIP. As explained in our NPRM, TSD and elsewhere in this 

document, we cannot approve the State’s BART determinations for NOX at Apache, Cholla and 

Coronado, nor can we approve the compliance-related requirements that were omitted from the 

Arizona Regional Haze SIP. Therefore, we are obligated to promulgate a FIP to address these 

requirements, and we are doing so in today’s action. 

Furthermore, while we agree that the procedural requirements for promulgation of a FIP 

under 110(c) are set forth in CAA section 307(d),258we do not agree that our action violates that 

provision in any way. Consistent with the requirements of that section, our proposal included a 

summary of the factual data on which our proposed FIP was based, as well as the methodology 

used in obtaining the data and in analyzing the data and the major legal interpretations and policy 

 

256 42 U.S.C. § 7410(k)(1)(B). 

257 42 U.S.C. § 7410(k)(2). 

258 See CAA section 307(d)(1)(B), 42 U.S.C. § 7607(d)(1)(B), (“This subsection applies to . . . the promulgation or 

revision of an implementation plan by the Administrator under [CAA § 110](c)”] 
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considerations underlying the proposed FIP.259 In addition, we provided a detailed evaluation of 

Arizona’s BART analyses for the relevant units, which formed the basis for our proposed action 

on those portions of the Arizona Regional Haze SIP.260 This final rulemaking includes similar 

information with respect to the SIP and the FIP, as well as “an explanation of the reasons for any 

major changes in the promulgated rule from the proposed rule” and “a response to each of the 

significant comments, criticisms, and new data submitted in written or oral presentations during 

the comment period.”261 Therefore, our action complies with the applicable procedural 

requirements of the CAA. 

Finally, we do not agree with commenters’ assertions that the D.C. Circuit’s decision in 

EME Homer City Generation precludes us from promulgating a partial FIP concurrently with our 

partial disapproval of Arizona’s Regional Haze SIP. In EME Homer City Generation, the court 

found that EPA had acted improperly in issuing the Transport Rule because we simultaneously 

defined states’ “good neighbor obligations” under CAA section 110(a)(2)(D)(i)(I) and issued 

FIPs to address those obligations.262 The court explained that: 

. . . the triggers for a FIP are EPA’s finding that the SIP fails to contain a 

“required submission” or EPA’s disapproving a SIP because of a “deficiency.” 

But logically, a SIP cannot be deemed to lack a required submission or be deemed 

deficient for failing to implement the good neighbor obligation until after EPA 

has defined the State’s good neighbor obligation. Once it defines the obligation, 

then States may be forced to revise SIPs under Section 110(k)(5) or to submit new 

SIPs under Section 110(a)(1). Only if that revised or new SIP is properly deemed 

to lack a required submission or is properly deemed deficient may EPA resort to a 

FIP for the State’s good neighbor obligation.263

 

259 See CAA section 307(d)(3), 42 U.S.C. § 7607(d)(3). 

260 The SIP portion of our action is subject to the procedural requirements of section 553(b) of Administrative 

Procedure Act (APA), 5 U.S.C. 553(b), rather than the requirements of CAA subsection 307(d), 42 U.S.C. § 

7607(d). 

261 CAA section 307(d)(6)(A) & (B), 42 U.S.C. §7607(d)(6)(A) & (B). 

262 EME Homer City Generation, slip op. at 7. 

263 Id. at 46. 
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In essence, the D.C. Circuit found that EPA’s findings of failure to submit and disapprovals of 

state transport SIPs did not trigger FIP obligations under CAA section 110(c) because these 

actions occurred “before [EPA] told the States what emissions reductions their SIPs were 

supposed to achieve under the good neighbor provision.”264 

In this case, by contrast, EPA defined states’ obligations under the RHR and the BART 

Guidelines well in advance of its findings of failure to submit and subsequent SIP disapprovals. 

EPA promulgated the original RHR on July 1, 1999.265 Following the D.C. Circuit’s decision in 

American Corn Growers, EPA revised the RHR and issued the final BART Guidelines on July 6, 

2005.266 The revised RHR and the Guidelines were upheld by the D.C. Circuit in Utility Air 

Regulatory Group v. EPA, 471 F.3d 1333 (D.C. Cir. 2006).267 As explained in our proposal and 

elsewhere in this document, the BART Guidelines provide detailed instructions to states on how 

to determine which sources are subject to BART and how to analyze the five statutory factors in 

order to set emissions limits representing BART for each subject-to-BART source.268 In 2006, 

responding to specific questions from various States and Regional Planning Organizations 

(RPOs), EPA issued further guidance to help States implement the RHR and BART 

Guidelines.269 

 

264 Id. at 47 (emphasis in original). 

265 64 FR 35714. 

266 70 FR 39104. This finding covered 37 states, the District of Columbia and the Virgin Islands. 

267 In response to another D.C. Circuit decision, Center for Energy and Economic Development v. EPA, 398 F.3d 

653 (D.C. Cir. 2005), EPA revised the RHR’s provisions governing alternatives to source-specific BART 

determinations on October 13, 2006. These revisions did not alter the requirements for source-specific BART 

determinations that apply to Arizona’s BART determinations at issue here. 

268 40 CFR Part 51, Appendix Y. While the Guidelines are only mandatory for fossil fuel-fired electric generating 

plants with a total generating capacity in excess of 750 megawatts, States are encouraged to follow the BART 

Guidelines in making BART determinations for other types of sources. Id. section I.H. The Guidelines also set 

specific presumptive limits for SO2 and NOX for these large power plants, but allow states to apply more or less 

stringent limits based upon source-specific five-factor analyses. 70 FR 39131 -39132. 

269 Memo from Joseph W. Paise Regarding Regional Haze Regulations and Guidelines for BART (July 19, 2006); 

Additional Regional Haze Questions (Guidance) (Sept. 27 2006). In addition, EPA issued final “Guidance for 

Setting Reasonable Progress Goals Under the Regional Haze Program” on June 1, 2007, but this Guidance is not 

directly relevant for individual BART determinations. 
Page 206 of 244

As noted in prior responses, EPA issued a finding of failure to submit for Regional Haze 

SIPs on January 15, 2009, thus triggering a FIP clock under CAA section 110(c).270 By this time, 

states had already had more than three years since issuance of the final BART Guidelines (and 

more than two years since the final revisions to the RHR and the issuance of further guidance on 

the RHR and BART) to develop their Regional Haze SIPs. By the time the FIP clock actually ran 

out in January 2011, EPA had received Regional Haze SIPs from nearly every state. EPA has 

since proposed to approve, in part or in whole, the vast majority of these SIPs.271 We have also 

has taken final action to approve, in part or in whole, many of these SIPs.272 This stands in 

contrast to the situation in EME Homer City Generation, where, the court noted that, “every 

Transport Rule State that submitted a good neighbor SIP for the 2006 24-hour PM2.5 NAAQS 

was disapproved.”273 Thus, it is clear that states had ample opportunity to submit approvable 

Regional Haze SIPs before EPA was obligated to promulgate Regional Haze FIPs under CAA 

section 110(c). 

With respect to Arizona’s Regional Haze SIP in particular, we note that Arizona first 

made public its proposed 308 SIP during a comment period beginning on October 28, 2010.274

At that time, EPA, the National Park Service (NPS) (in consultation with the Fish and Wildlife 

Service) and the U.S. Forest Service all submitted comments expressing concern about the 

 

270 74 FR 2392. 

271 See, e.g., 76 FR 36450 (Nevada); 77 FR 24794 (New York); 76 FR 13944 (California); 77 FR 11798 (Rhode 

Island); 76 FR 27973 (Delaware); 77 FR 12770 (Nebraska); 77 FR 18052 (Colorado); 76 FR 16168 (Oklahoma); 77 

FR 11914 (Vermont); 77 FR 11928 (Wisconsin); 76 FR 52604 (Kansas); 76 FR 64186 (Arkansas); 77 FR 11839 

(Maryland); 76 FR 58570 (North Dakota); 77 FR 3966 (Illinois); 76 FR 76646 (South Dakota). EPA proposed 

limited approval and limited disapproval of the Regional Haze SIPs of states covered by the Clean Air Interstate 

Rule (CAIR), due to the remand of CAIR by the D.C. Circuit. See, e.g. 77 FR 3691 (Jan. 25, 2012) (proposing 

limited approval and limited disapproval of Virginia’s Regional Haze SIP). 

272 See, e.g., 76 FR 34608 (California); 76 FR 42557 (Delaware); 76 FR 80754 (Kansas); 77 FR 19 (New Jersey); 77 

FR 5191 (District of Columbia); 77 FR 14604 (Arkansas); 77 FR 17334 (Nevada); 77 FR 24845 (South Dakota); 77 

FR 40150 (Nebraska); 77 FR 51915 (New York). 

273 Slip op. at 57. 

274 Arizona Regional Haze SIP, Appendix E, Public Process. Approximately 60 days prior to the public comment 

period, ADEQ sent a draft of the SIP to the National Park Service and U.S. Forest Service. 
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proposed SIP’s compliance with the CAA, the RHR and the BART Guidelines.275 Among other 

things, EPA noted that the SIP, “does not provide a sufficient level of information and analysis to 

support its conclusions.”276 NPS provided extensive comments on the proposed SIP, including 

detailed evaluations of ADEQ’s BART analyses for each of the three sources at issue in today’s 

action.277 In each instance, NPS concluded that ADEQ had not conducted a valid BART analysis 

for NOX.

278 The Forest Service concurred with the initial comments provided by NPS on 

Arizona’s BART exclusion process and “strongly disagree[d] with the adequacy of the Arizona 

reasonable progress analysis.”279 Therefore, ADEQ had the benefit not only of the generally 

applicable requirements of the RHR, the BART Guidelines and EPA Guidance, but also specific 

guidance from EPA and the FLMs pointing out shortcomings in its Regional Haze SIP. 

Following receipt of these comments, Arizona had the opportunity to revise its SIP to address the 

deficiencies identified by the commenters, but in most instances it chose not to do so.280 

Finally, while we agree that, in the absence of an expired statutory duty and a courtordered deadline to issue a FIP, it would be preferable for us to give Arizona additional time to 

revise its Regional Haze SIP prior to promulgation of a FIP, we simply do not have this option 

under these circumstances. As explained in our response to the previous comment, we are 

 

275 Id. 

276 Id. Letter from Colleen McKaughan, EPA, to Eric Massey, ADEQ (Dec. 2, 2010). 

277 Id. NPS Initial Comments Arizona Draft Section 308 Regional Haze SIP (Nov. 29, 2010); NPS General BART 

Comments on ADEQ BART Analyses (Nov. 29, 2010); NPS Comments AEPCO – Apache Generating Station 

BART Analysis and Determination (Nov. 29, 2010); NPS Comments APS Cholla Generating Station BART 

Analysis and Determination (Nov. 29, 2010); NPS Comments SRP’s Coronado Generating Station BART Analysis 

and Determination (Nov. 29, 2010); NPS Comments on ADEQ BART Exemptions, (Dec. 1, 2010). 

278 Id. 

279 U.S. Forest Service Specific Comments: Arizona Regional Haze SIP (Nov. 29, 2010). 

280 For example, in response to detailed comments from NPS regarding the efficiency and cost of SCR, ADEQ stated 

that: 

ADEQ has determined that the cost computations presented by the facilities in support of their 

BART applications are reasonable. Many of the computations are based on vendor data and sitespecific conditions. The Department does not agree that the computations over-estimate the costs 

of retrofit technologies and under-estimate the associated emission decreases and visibility 

improvement. 
Page 208 of 244

obligated to issue a FIP to address any gaps left by partial disapprovals of Arizona’s Regional 

Haze SIP. Nonetheless, we encourage ADEQ to submit a revised SIP to replace the FIP and will 

work with ADEQ to develop such a revised plan to meet the requirements of the CAA and the RHR. 

Comment: One commenter (Earthjustice) stated that the CAA’s Regional Haze program 

establishes a national regulatory floor and requires states to develop RH SIPs at least as stringent 

as this floor (citing 40 CFR 51.308). According to the commenter, ADEQ’s SIP is legally and 

technically inadequate because it does not require adequate BART emission limits, does not 

achieve “reasonable progress” are required by the RHR and would fail to achieve natural 

visibility goals by 2064. The commenter believes that the Arizona RH SIP fails to establish a 

program that is at least as stringent as the national floor and that therefore EPA has a legal 

obligation to disapprove the SIP and to issue a FIP in its place under CAA section 110(c)(1).281

Response: We agree that the CAA, the RHR and the BART Guidelines set out specific 

requirements that Regional Haze SIPs must meet in order to be approved by EPA. Our action 

today addresses these requirements as they apply to ADEQ’s BART determinations for Apache, 

Cholla and Coronado, but does not address the requirements as they apply to the remainder of 

Arizona’s Regional Haze SIP (e.g., the reasonable progress goals set by the state). EPA will 

propose action on these aspects of the SIP shortly and take final action after receiving comments. 

As explained in the preceding responses, because of our prior finding of failure to submit, we are 

required to issue a FIP for any portion of the SIP that we cannot approve. Thus, we are 

promulgating a FIP for those aspects of ADEQ’s BART determinations for Apache, Cholla and 

Coronado that we are not approving at this time. 

 

281 The commenter cited Alaska Dep‘t of Envtl. Conservation v. EPA, 540 U.S. 461, 470, 484 (2004); Mont. Sulphur 

& Chem. Co. v. EPA, 666 F.3d 1174, 1181 (9th Cir. 2012) to support the contention that Congress structured the 

CAA to provide expansive EPA oversight to ensure SIPs comply with the CAA. The commenter cited 42 U.S.C. § 

7410(c), (k); EME Homer City Generation, L.P. v. EPA, No. 11-1302, --- F.3d ----, 2012 WL 3570721, at *17 (D.C. 

Cir. Aug. 21, 2012) to support the principle that EPA must issue a FIP when it determines that a SIP does not 

comply with the CAA. 
Page 209 of 244

 G. Other Comments 

 1. Comment on Public Health and Ecosystem Impacts 

Comment: A number of commenters provided comments on the potential health effects of 

our proposal. A number of other commenters stated that the Regional Haze program’s sole focus 

is the improvement of visibility in Class I areas, and is not a health-based or emissions reduction 

program. In relation to the Regional Haze program, any EPA emphasis on health and emissions 

reduction is inappropriate. One commenter (SRP) stated that EPA’s assertion of health benefits is 

unsubstantiated by the proposed rule. A few commenters noted that the air quality in Arizona 

varies from city to city, and stated that EPA should focus on the areas with the poorest air quality 

first, such as Phoenix. 

In contrast, one commenter (Earthjustice) stated that the same pollutants that reduce 

visibility also cause significant public health impacts. The commenter noted that NOX is a 

precursor to ground level ozone, which is associated with respiratory diseases, asthma attacks 

and decreased lung function, and that NOX reacts with other substances to form particulates that 

can cause and worsen respiratory diseases, aggravate heart disease, and lead to premature death. 

The commenter indicated that SO2 increases asthma symptoms, leads to increased hospital visits, 

and can form particulates that aggravate respiratory and heart diseases and cause premature 

death, and that PM can penetrate deep into the lungs and cause health problems such as 

aggravated asthma, chronic bronchitis, and heart attacks. Based on a report prepared by the 

Clean Air Task Force, the commenter asserted that Cholla, Coronado and Apache collectively 

cause approximately 41 deaths, 63 heart attacks and 747 asthma attacks annually.

282 Several 

other commenters provided similar comments concerning health effects. 

 

282 The commenter cited Clean Air Task Force, Death and Disease From Power Plants, 

http://www.catf.us/fossil/problems/power_plants/existing/map.php?state=Arizona 
Page 210 of 244

Response: We acknowledge the commenters' concerns regarding the adverse health 

impacts of haze-causing emissions. We agree that the same PM2.5 emissions that cause visibility 

impairment can cause respiratory problems, decreased lung function, aggravated asthma, 

bronchitis, and premature death. We also agree that the same NOX emissions that cause visibility 

impairment also contribute to the formation of ground-level ozone, which has been linked with 

respiratory problems, aggravated asthma, and even permanent lung damage. Finally, we also 

agree that SO2 emissions that cause visibility impairment also contribute to increased asthma 

symptoms, lead to increased hospital visits, and can form particulates that aggravate respiratory 

and heart diseases and cause premature death. Thus, to the extent that this FIP will lead to 

reductions in these pollutants, there will be co-benefits for public health. However, for purposes 

of this action, we are not authorized to consider these benefits and we have not done so. 

In our NPRM, while discussing Executive Order 13045 (Protection of Children from 

Environmental Health Risks and Safety Risks), we stated that, to the extent the 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. In this action, while discussing Executive Order 13045 

(Protection of Children from Environmental Health Risks and Safety Risks), we conclude that 

this action does not have a disproportionate effect on children, but again note that to the extent 

this final action will limit emissions of NOX, SO2 and PM10, the rule will have a beneficial effect 

on children’s health by reducing air pollution that causes or exacerbates childhood asthma and 

other respiratory issues. However, we do not believe it is necessary or appropriate to quantify the 

extent of this beneficial effect because we are not relying upon health effects in the promulgation 

of this rule. 
Page 211 of 244

Comment: One commenter (Earthjustice) stated that the RHR rule provides important 

environmental benefits to plants and animals, soil health and entire ecosystems. The commenter 

noted that NOX and SO2 are the primary causes of acid rain, which acidifies lakes and streams, 

can damage certain types of trees and soils and accelerates the decay of building materials and 

paints, including irreplaceable buildings and statues that are part of our nation’s cultural heritage. 

The commenter added that nitrogen deposition, caused by wet and dry deposition of nitrates 

derived from NOX emissions, causes well-known adverse impacts on ecological systems. The 

commenter also noted that NOX is a precursor to ozone, which impacts plants and ecosystems by 

interfering with plants’ ability to produce food and increasing their susceptibility to disease and 

insects, and also contributes to wildfires and bark beetle outbreaks in the West by depressing 

plant water levels and growth. 

Response: We appreciate the commenter's concerns regarding the negative ecosystem 

impacts of emissions from the units at issue. We agree that both NOX and SO2 cause acid rain 

and can have negative impacts on ecosystems, damaging plants, trees, and other vegetation 

(including crop yields), which could have a negative effect on species diversity in our 

ecosystems. However, for purposes of this Regional Haze action, we are not authorized to 

consider these ecosystem impacts. Therefore, while we note the potential for co-benefits to 

ecosystem health resulting from our action today, we have not taken these potential benefits into 

account in this action. 

 2. Comments on Economic Impacts 

Comment: Many commenters, including state officials, private citizens and 

representatives of local governments, schools, and business groups, expressed concern over 

potential economic effects resulting from EPA’s proposed BART determinations, asserting that 
Page 212 of 244

EPA’s action would result in rate increases and possibly closures of one or more power plants. 

Some commenters cautioned EPA that rate increases would impact at-risk populations, such as 

seniors on fixed incomes. The commenters emphasized that the three plants have a large 

financial impact on the communities where they are located (i.e., they provide jobs and tax 

revenue) and expressed their concern over the three plants’ economic viability if the plants are 

forced to install SCR to reduce NOX emissions. Several representatives of local school districts 

discussed the harm that large increases in electric power rates would do to their programs in this 

time of declining state support, and one representative of a local, nonprofit hospital similarly 

voiced the difficulty his facility would have in absorbing large rate increases. One commenter 

discussed the multiplier effect by which loss of income from any job losses or the reduction in 

disposable income due to increased power bills would ripple through the local economies and 

affect local businesses and employment. A few commenters discussed the impact on Arizona’s 

water rates, and advised EPA to consider how these rate increases would affect Arizona’s 

economy. A few commenters asserted that the proposed rule is intended to eliminate coal as a 

cheap and reliable energy source. 

By contrast, one commenter (Earthjustice) stated that the RHR provides substantial 

economic benefits, which far outweigh the costs of pollution control technologies such as SCR. 

The commenter noted that EPA has valued the RHR’s health benefits at $8.4 to $9.8 billion 

annually. The commenter further asserted that requiring power plants to invest in pollution 

controls creates short-term construction jobs as well as permanent operations and management 

positions. In addition, the commenter indicated that the national parks and wilderness areas 

protected by the RHR serve as engines for sustainable local capital, with national park visitors 

contributing approximately $30 billion to local economies and supporting 300,000 jobs 
Page 213 of 244

nationwide. Regarding Arizona specifically, the commenter stated that over 4.3 million people 

visited the Grand Canyon in 2010, and this supported over 6,800 jobs and resulted in over 

$428 million in visitor spending, while tourism at Petrified Forest National Park, Saguaro 

National Park and Chiricahua National Monument in 2010 supported over 1,100 jobs and 

resulted in over $74 million in visitor spending. The commenter contended that studies show that 

national park visitors highly value clean air, readily perceive haze and are willing to cut short 

visits to national parks based on their perception of air quality.

283

 

Response: As explained in our prior responses regarding economic issues, the BART 

Guidelines permit consideration of economic impacts only under “unusual circumstances” where 

a potential control option is expected to have a “severe impact on plant operations” or “result in 

significant economic disruption or unemployment.” None of the commenters have provided any 

evidence that our action today would result in the closure of any of the affected units. We discuss 

many of the potential economic impacts raised as concerns here in the context of our analysis of 

affordability of controls to AEPCO, above. Finally, we acknowledge that today’s action may 

have positive economic impacts, as described by Earthjustice. However, we have not taken 

potential economic benefits into account in our action. 

3. Comments from Tribal Representatives and Members 

Comment: One commenter (Navajo Nation) stated that comments on our proposed 

actions were provided pursuant to its government-to-government relationship with EPA. The 

commenter stated that this EPA rulemaking has adverse implications for a pending BART FIP 

for Navajo Generating Station, which is on Navajo Nation land and burns Navajo coal. The 

 

283 The commenter cited and submitted as Exhibit 11 Abt Assocs. Inc., Out of Sight: The Science and Economics of 

Visibility Impairment, at ES-7 (2000), available at http://www.abtassociates.com/reports/ES-clear.pdf. 
Page 214 of 244

commenter also stated that this rule could impact BART decisions for Four Corners Power Plant, 

and San Juan Generating Station. 

The commenter states that EPA has an obligation to consult with Navajo Nation on a 

government-to-government basis for EPA actions and decisions that may affect the Navajo 

Nation’s interests, and reminds EPA that it must defer to tribal government policy decisions, just 

as it would a state, when promulgating a FIP on tribal lands.

The commenter further states that EPA has failed to analyze the cumulative effects of this 

rulemaking and the planned and proposed EPA actions on Navajo Generating Station, Four 

Corners Power Plant, and San Juan Generating Station, including both visibility improvement 

and potential regional economic impacts. The commenter noted that the fossil fuel economy is 

vitally important to the Four Corners region and the Navajo Nation, with many jobs and coal 

royalties at stake from loss of the area’s coal fired power plants and their associated mines. The 

commenter states that EPA must consider these impacts, as well as the impacts of utility rate 

increases, in this BART decision for NOX. 

The commenter observed that it is possible to go forward without imposing a FIP in 

Arizona, as evidenced by the renewed consideration being given to the New Mexico regional 

haze SIP under the current stay on the proposed FIP for that state. The commenter stated that the 

Navajo Nation, where two power plants that are undergoing EPA BART determinations are 

located, shares the concerns of Arizona and New Mexico regarding the economic impacts of 

requiring SCR. The commenter noted that the BART decision is not based only on the most 

effective control measures, but is to be based on an analysis of five factors which include non-air 

quality impacts such as economic impacts. 
Page 215 of 244

The commenter also asserted that real data should underpin EPA’s decisions, rather than 

modeling alone. The commenter also contended that a public health baseline is needed in order 

to chart any public health improvements that result from such emission controls. 

Response: EPA appreciates the comments provided by the Navajo Nation on our 

proposed action pursuant to its government-to-government relationship with EPA. As part of 

separate rulemakings, EPA has engaged in consultation with Navajo Nation regarding the Four 

Corners Power Plant284 and San Juan Generating Station. EPA is currently engaged in active 

consultation with the Navajo Nation and other affected tribes on the Navajo Generating Station. 

Today’s rule approves Arizona’s SIP (in part) and implements a FIP (in part) for Apache 

Units 2 and 3; Cholla Units 2, 3 and 4; and Coronado Units 1 and 2. This action has no 

retroactive effect on final BART determinations for other facilities. We disagree that this action 

has a nexus to the BART determination for Navajo Generating Station, because BART analyses, 

whether performed by the states or EPA, are conducted on a source-by-source basis, applying all 

five statutory factors to a facility on an individual basis. While there are certain commonalities 

among the sources mentioned by the commenter (e.g., all are coal-fired power plants), there are 

also significant differences that necessarily affect the case-by-case BART analysis. For example, 

the unit size, unit age, boiler type, existing controls, type of coal burned and proximity to Class I 

areas vary significantly among these sources. All of these differences have a bearing on at least 

one of the BART factors and thus on the ultimate BART determination. Given these various 

distinguishing factors, we do not agree that this rule will affect our BART determination for 

Navajo Generating Station. 

We also do not agree that we are required to consider the cumulative effects of today’s 

rulemaking together with rulemaking actions on other BART determinations as part of our action 

 

284 See document titled: “Timeline of all tribal consultations on BART.docx” in the docket for this final rulemaking. 
Page 216 of 244

today. As noted above, under the CAA, the RHR and the BART Guidelines, BART 

determinations are made on a source-by-basis, taking into account the five statutory factors. The 

cumulative improvements from the various SIPs, FIPs, and BART determinations are addressed 

in analyses under the RHR requirements for Reasonable Progress, Long Term Strategies and 

future updates to the SIP, which are separate from BART analyses. These cumulative 

improvements will be influenced by changes in hundreds or thousands of emission sources, so 

are more appropriately addressed through use of a grid model, such as CAMx or CMAQ, rather 

than the CALPUFF model recommended in the BART Guidelines, which is geared to a far lower 

number of sources, and lacks the detailed chemistry of the grid models. 

With regard to the economic concerns raised by the commenter, we are required by the 

CAA and the federal regulations implementing the CAA's BART provisions to evaluate (1) cost 

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) remaining useful life of source, and 

(5) degree of improvement in visibility which may reasonably be anticipated to result from the 

use of such technology. As explained in our prior responses regarding economic issues, the 

BART Guidelines permit consideration of economic impacts only under “unusual 

circumstances” where a potential control option is expected to have a “severe impact on plant 

operations” or “result in significant economic disruption or unemployment.” None of the 

commenters have provided any evidence that our action today would result in the closure of any 

of the affected units or result in significant economic disruption. We also note that none of the 

sources affected by today’s rulemaking currently purchase coal from a mine that operates on the 

Navajo Nation. 
Page 217 of 244

We take our duty to estimate the cost of controls very seriously, and make every attempt 

to make a thoughtful and well informed determination. However, we do not consider a potential 

increase in electricity rates to be the most appropriate type of analysis for considering the costs 

of compliance in a BART determination. Projections of electricity rate impacts are inherently 

fraught with uncertainty due to the numerous variables involved and the complexity of the 

regulatory regime governing the power sector. Nevertheless, as discussed elsewhere in this 

document, as part of our consideration of the affordability of controls on AEPCO, a small entity, 

we have analyzed the potential rate increases associated with our proposal for Apache Units 2 

and 3. Given the uncertainty inherent in such an analysis, we have used conservative 

assumptions in an effort to guard against understating the potential rate impacts. 

Regarding the comment that EPA should not rely on modeling alone, it is extremely 

difficult in observational analyses to sufficiently control for all factors, including emissions from 

other sources, to be able to isolate the impacts of closure of a facility. A model such as 

CALPUFF essentially holds constant a number of factors in order to isolate the impacts of a 

single source. As discussed elsewhere in this document, EPA affirms that the regulatory version 

of CALPUFF is the correct model to use for these BART determinations. 

Assessing human exposure and quantifying health benefits are outside the scope of the 

requirements of the Regional Haze Rule. EPA sets National Ambient Air Quality Standards 

(NAAQS) to establish levels of air quality that are protective of public health, including the 

health of sensitive populations, for a number of pollutants including particulate matter. These 

"sensitive" populations include asthmatics, children, and the elderly. At this time the Navajo 

Nation is not identified as out of attainment with any of the NAAQS. However, EPA recognizes 

that there are significant concerns about risk and exposure to air pollutants on the Navajo Nation 
Page 218 of 244

and EPA will continue discussions with the Navajo Nation and will involve other federal 

agencies, as appropriate, to help address these concerns. 

Comment: Various other representatives and members of the Hopi and Navajo Tribes 

provided oral testimony and/or submitted written comments at one or more of the public 

hearings. Most tribal community members supported the proposed FIP and stated their belief that 

it will improve air quality and human health in Arizona. Several commenters recounted their 

personal experiences with the deterioration of visibility in the rural areas in which they live, 

declining water supplies due to water use in mining operations, and illnesses that they believe are 

attributable to air pollution from the power plants and mines in the area (e.g., asthma and 

bronchitis). A number of commenters pointed out that there are numerous old power plants in 

and around the Navajo Nation, which they believe are causing air pollution that contributes to 

haze and an increase in the incidence of lung and heart disease and cancer in humans, as well as 

harming native plants and animals. Some of these commenters advocated for a conversion to 

renewable energy sources, which they believe will provide jobs, improve health, and reduce 

emissions that contribute to climate change. One commenter specifically suggested that EPA 

promote alternatives like natural gas and algae ponds as a source of energy. 

One commenter indicated that reduced haze would improve tourism, resulting in 

increased jobs and tax receipts. Another tribal commenter stated that before acting, EPA should 

evaluate the impact on employment and on the Hopi’s revenue from coal if the FIP causes power 

plants to close. 

One tribal commenter alleged that the National Academy of Sciences did a study a 

number of years ago that concluded that some areas of the country could be designated as 

“national sacrifice areas” that would be used for national priorities, irrespective of resulting 
Page 219 of 244

permanent environmental damages. According to the commenter, many Indian reservations are 

located in such areas, such as all of the Navajo and Hopi reservations. The commenter asserted 

that the study concluded that the well-being of the people in such areas can be forfeited so that 

the rest of the country can enjoy cheap energy. 

Response: EPA acknowledges the comments. Neither Section 169A of the CAA nor the 

BART Guidelines requires that BART analyses include or quantify benefits to health or tourism 

or impact on employment. EPA does not intend for this action to cause any power plants to 

close. Although a quantitative analysis of the health and tourism benefits is beyond the scope of 

what is required under BART EPA agrees with commenters that emission reductions achieved to 

improve visibility will also improve air quality. Improved air quality, in turn, affects public 

health and may enhance tourism in the area. EPA notes that even if we had quantified the 

benefits to health and tourism, such an analysis would not likely have altered the outcome of our 

BART determination.

Renewable energy technology is not a retrofit option for the sources subject to BART and 

is therefore outside the scope of our BART determination. As noted in the BART Guidelines, 

“[w]e do not consider BART as a requirement to redesign the source when considering available 

control alternatives. For example, where the source subject to BART is a coal-fired electric 

generator, we do not require the BART analysis to consider building a natural gas-fired electric 

turbine although the turbine may be inherently less polluting on a per unit basis.”285 Therefore, 

we did not consider such alternatives as part of our BART analyses. Nonetheless, we 

acknowledge that many kinds of renewable energy do not produce haze-causing pollutants, and 

transitioning to those sources of energy could lead to visibility improvements. 

 

285 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.1. 
Page 220 of 244

The CAA applies equally to all parts of the United States. In making a determination in 

this case, we have applied the applicable provisions of the CAA and the RHR. We have also 

considered other applicable requirements, including Executive Order 12898286, which establishes 

federal executive policy on environmental justice. This Executive Order directs federal agencies, 

to the greatest extent practicable and permitted by law, to make environmental justice part of 

their mission by identifying and addressing, as appropriate, disproportionately high and adverse 

human health or environmental effects of their programs, policies, and activities on minority 

populations and low-income populations in the United States. 

EPA has determined that our final rule 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 rule requires emissions reductions of 

NOx from three facilities in Arizona. The partial approval of the SIP approves state law as 

meeting Federal requirements. 

Comment: One commenter suggested that EPA investigate the technology of cooling 

steam exhaust through a magnetic refrigerator to remove NO2 as a liquid, since it would 

condense at the relatively high temperature of 294 K or 70 degrees F (boiling point). 

Response: The BART Guidelines provide that: 

Technologies which have not yet been applied to (or permitted for) full scale 

operations need not be considered as available; we do not expect the source owner 

to purchase or construct a process or control device that has not already been 

demonstrated in practice.287

The Guidelines further provide that: 

 

286 59 FR 7629, February 16, 1994. 

287 BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.1. 
Page 221 of 244

In order to provide certainty in the process, all technologies should be considered 

if available before the close of the State's public comment period. You need not 

consider technologies that become available after this date. 

The commenter has not provided evidence that this technology has been demonstrated in practice 

or that it was available before the close of the State’s public comment period. Therefore, we have 

not considered it as a potential control option. An additional consideration is that typically 90 

percent of the NOX from combustion is emitted in the form of NO, rather than NO2. Since the 

boiling point of NO is 121 K or -242 degrees F, much lower than for NO2, and the stack exit 

temperature is the range of 300-400 K or 120-280 degrees F, a large degree of cooling would be 

necessary to condense the NO, and so the energy costs could be substantial. 

 4. Requests for Extension of Comment Period and Additional Hearings 

Comment: A number of commenters remarked on EPA’s timeline for soliciting public 

comments, and stated that they believe that the time allowed was insufficient. One commenter 

requested more public hearings, and another commenter requested a 90-day extension of the 

deadline for comments (starting from July 18, 2012), so that the public has ample time to review, 

analyze, comment, and react to the rule and in particular EPA’s Technical Support Document. 

The commenter added that an extension would allow the ADEQ the opportunity to further 

collaborate with EPA in revising the state’s SIP submittal (for the purpose of nullifying the 

proposed FIP), and thereby adhering to the intent of the CAA. 

Response: As explained above, our proposed rule, which was signed on July 2, 2012 and 

published in the Federal Register on July 20, 2012,288 provided for a public hearing in Phoenix, 

Arizona, on July 31, 2012, and a public comment deadline of August 31, 2012. In response to 

requests from various parties for a longer comment period and additional hearings, we extended 

 

288 77 FR 42834. 
Page 222 of 244

the public comment period to a total of sixty days from publication in the Federal Register.289

We also scheduled two more public hearings in Southern Arizona (Benson) and in Northern 

Arizona (Holbrook) on August 14 and 15, 2012, respectively. 

Comment: One comment letter signed by 728 residents, business owners, citizens and 

other interested parties urged EPA to extend the comment period on our proposal and provide 

additional hearings near the Cholla Power Plant. 

Response: As noted the preceding response, we extended the comment period on our 

propose rule and we held additional public hearings, including one in Holbrook, Arizona, near 

the Cholla Power Plant. 

V. Summary of Final Action

EPA is taking final action to approve in part and disapprove in part a portion of Arizona’s 

SIP for Regional Haze and to promulgate a FIP for the disapproved elements of the SIP. This 

final action addresses only the State’s BART determinations for the specified units at the three 

power plants. We will propose action on the remainder of Arizona’s Regional Haze SIP in a 

separate notice. EPA takes very seriously a decision to disapprove portions of a state plan. In this 

instance, we find that the State’s NOX BART determinations for the coal-fired units are not 

consistent with the requirements of the Act and the RHR. In addition, the SIP lacks the necessary 

compliance deadlines and requirements for equipment maintenance and operation, including 

monitoring, recordkeeping and reporting requirements for all pollutants at all of the BART units. 

As a result, we find that this final disapproval is the only path that is consistent with the Act at 

this time. 

 

289 See 77 FR 45326 (July 31, 2012). 
Page 223 of 244

EPA estimates this action will improve visibility at 18 Class I areas by reducing NOX

emissions from three power plants by about 22,700 tons per year. The total costs associated with 

these reductions, according to the supplemental cost analysis we performed based on cost 

estimates provided by the facility owners, are summarized in Table 18. 

TABLE 18—SUMMARY OF SUPPLEMENTAL COST ANALYSIS

Capital Cost 

($) 

Annualized 

Capital Cost 

($/yr) 

Annual O&M

($/yr) 

Total Annualized 

Cost 

($/yr) 

Costeffectiveness 

Apache Unit 2 $82,481,439 $7,785,664 $1,760,600 $9,546,264 $3,450

Apache Unit 3 $82,481,439 $7,785,664 $1,760,600 $9,546,264 $2,973

Cholla Unit 2 $87,713,386 $8,279,523 $1,626,683 $9,906,206 $2,979

Cholla Unit 3 $83,461,195 $7,878,146 $1,570,766 $9,448,912 $2,838

Cholla Unit 4 $119,083,832 $11,240,671 $2,350,182 $13,590,853 $3,083

Coronado Unit 1 $80,633,219 $7,611,205 $4,492,736 $12,103,941 $2,135

Coronado Unit 2 $2,500,000 $235,982 -- $235,982 $1,900 

VI. Statutory and Executive Order Reviews 

 A. Executive Order 12866: Regulatory Planning and Review 

This action finalizes approval of a source-specific portion of the Arizona SIP and a 

Regional Haze FIP for units at three facilities in Arizona. This action is not a rule of general 

applicability, and not a “significant regulatory action” under the terms of Executive Order 12866 

(58 FR 51735, October 4, 1993). This type of action is exempt from review under Executive 

Order (EO) 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under 

Executive Order 13563 (76 FR 3821, January 21, 2011). 
Page 224 of 244

B. Paperwork Reduction Act 

This action does not impose an information collection burden under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Burden is defined at 5 CFR 1320.3(b). 

Because this action will finalize approval of a source-specific portion of the Arizona SIP and a 

Regional Haze FIP for units at only three facilities in Arizona, the Paperwork Reduction Act 

does not apply. See 5 CFR 1320.3(c). 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 rule on small 

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

Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction 

that is a government of a city, county, town, school district or special district with a population of 

less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its field. This action finalizes approval 

of a source-specific portion of the Arizona SIP and a Regional Haze FIP for units at three electric 
Page 225 of 244

generating facilities in Arizona. 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. Only one of the three 

facilities affected by this action is a small entity: AEPCO sold under 3 million megawatt hours in 

2011. 

Although a regulatory flexibility analysis as specified by the RFA is not required when a 

rule has impact on only one small entity, EPA estimated the potential impact to AEPCO of our 

proposal to require SCR in AEPCO’s Units 1 and 2. EPA also 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. A 

summary of the comments regarding the impact of this action on AEPCO, and EPA’s response to 

those concerns, is provided in section I.V. of this preamble. After considering the economic 

impacts of this proposed action on small entities, I certify that this 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 because one significantly impacted small entity is not a “substantial” 

number. Finalizing approval of a source-specific portion of the Arizona Regional Haze SIP 

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). 
Page 226 of 244

D. Unfunded Mandates Reform Act (UMRA) 

Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes 

requirements for Federal agencies to assess the effects of their regulatory actions on State, local, 

and Tribal governments and the private sector. Under section 202 of UMRA, EPA generally 

must prepare a written statement, including a cost-benefit analysis, for proposed and final rules 

with “Federal mandates” that may result in expenditures to State, local, and Tribal governments, 

in the aggregate, or to the private sector, of $100 million or more (adjusted for inflation) in any 

one year. Before promulgating an EPA rule for which a written statement is needed, section 205 

of UMRA generally requires EPA to identify and consider a reasonable number of regulatory 

alternatives and to 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 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 rule does not contain a Federal 

mandate that may result in expenditures that exceed the inflation-adjusted UMRA threshold of 
Page 227 of 244

$100 million (in 1996 dollars) by State, local, or Tribal governments or the private sector in any 

1 year. In addition, this 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 

This action does not have federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in Executive Order 13132, because it addresses the State not fully meeting its 

obligation to protect visibility established in the CAA and this final action will reduce the 

emissions of NOX from three facilities in Arizona. Thus, Executive Order 13132 does not apply 

to this action. Although section 6 of Executive Order 13132 does not apply to this action, a 

summary of the concerns raised by State and local officials, and EPA’s response to those 

concerns is provided in section I.V. of this preamble. 

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments 

Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not 

issue a regulation that has tribal 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 tribal governments, or EPA consults with tribal 

officials early in the process of developing the proposed regulation and develops a tribal 

summary impact statement. We believe this rule does not have tribal implications, as specified in 
Page 228 of 244

Executive Order 13175, and will not have substantial direct effects on tribal governments. Thus, 

Executive Order 13175 does not apply to this rule. However, in our proposal we requested 

comment on our proposed rule from tribal officials. The Navajo Nation Environmental 

Protection Agency provided comments on our proposed rule, both orally at a public hearing and 

by letter, which EPA considered in developing this final rule. EPA’s summary of these 

comments and our response to Navajo Nation is provided in section I.V. of this preamble. 

G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety 

Risks 

Executive Order 13045: Protection of Children from Environmental Health Risks and 

Safety Risks (62 FR 19885, April 23, 1997), applies to any rule that: (1) is determined to be 

economically significant as defined under Executive Order 12866; and (2) concerns an 

environmental health or safety risk that we have reason to believe may have a disproportionate 

effect on children. EPA interprets EO 13045 as applying only to those regulatory actions that 

concern health or safety risks, such that the analysis required under section 5-501 of the EO has 

the potential to influence the regulation. This action is not subject to EO 13045 because it 

implements specific standards established by Congress in statutes. Also, because this action only 

applies to three sources and is not a rule of general applicability, it is not economically 

significant as defined under Executive Order 12866, and the rule also does not have a 

disproportionate effect on children. However, to the extent this action will limit emissions of 

NOX, SO2, and PM10, the rule will have a beneficial effect on children’s health by reducing air 

pollution that causes or exacerbates childhood asthma and other respiratory issues. 
Page 229 of 244

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(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law 104-113, 12 (10) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. VCS are technical standards (e.g., materials 

specifications, test methods, sampling procedures and business practices) that are developed or 

adopted by the VCS bodies. The NTTAA directs EPA to provide Congress, through annual 

reports to OMB, with explanations when the Agency decides not to use available and applicable 

VCS. The rulemaking involves technical standards. Therefore, the Agency conducted a search to 

identify potentially applicable voluntary consensus standards. However, we identified no such 

standards, and none were brought to our attention in comments. Therefore, EPA has decided to 

use 40 CFR Part 60 Appendix A Method 5, 40 CFR Part 51 Appendix M Methods 201A/202, 40 

CFR Part 60 Appendix A Method 19, and 40 CFR Part 75. 

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority 

Populations and Low-Income Populations 

Executive Order 12898 (59 FR 7629, February 16, 1994), establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest extent 
Page 230 of 244

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. EPA has determined that this final rule will not have 

disproportionately high and adverse human health or environmental effects on minority or lowincome 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 

rule requires emissions reductions of NOX from three facilities in Arizona. The partial approval 

of the SIP merely approves state law as meeting Federal requirements and imposes no additional 

requirements beyond those imposed by state law. 

 

K. Congressional Review Act 

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take 

effect, the agency promulgating the rule must submit a rule report, which includes a copy of the 

rule, to each House of the Congress and to the Comptroller General of the United States. Section 

804 exempts from section 801 the following types of rules (1) rules of particular applicability; 

(2) rules relating to agency management or personnel; and (3) rules of agency organization, 

procedure, or practice that do not substantially affect the rights or obligations of non-agency 

parties. 5 U.S.C. 804(3). EPA is not required to submit a rule report regarding today’s action 

under section 801 because this is a rule of particular applicability and only applies to three 

facilities. 
Page 231 of 244

Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Arizona; 

Regional Haze State and Federal Implementation Plans 

L. Petitions for Judicial Review 

Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action 

must be filed in the United States Court of Appeals for the appropriate circuit by [insert date 60 

days from publication in Federal Register]. Filing a petition for reconsideration by the 

Administrator of this final rule does not affect the finality of this rule for the purposes of judicial 

review nor does it extend the time within which a petition for judicial review may be filed, and 

shall not postpone the effectiveness of such rule or action. This action may not be challenged 

later in proceedings to enforce its requirements. (See CAA section 307(b)(2).) 

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. 

November 15, 2012 /s/ 

________________ _____________________________ 

Dated: Lisa P. Jackson, 

 Administrator 
Page 232 of 244

Part 52, chapter I, title 40 of the Code of Federal Regulations is amended as follows: 

PART 52--[AMENDED] 

1. The authority citation for Part 52 continues to read as follows: 

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

Subpart D--Arizona 

2. Section 52.120 is amended by adding paragraph (c)(154) to read as follows: 

§ 52.120 Identification of plan. 

* * * * * 

(c) * * * 

(154) The following plan was submitted February 28, 2011, by the Governor's designee. 

(i) [Reserved] 

(ii) Additional materials. 

(A) Arizona Department of Environmental Quality. 

(1) Arizona State Implementation Plan, Regional Haze Under Section 308 of the Federal 

Regional Haze Rule: Appendix D, Arizona BART – Supplemental Information: 

 (i) Table 1.1 – NOX BART, entry for AEPCO [Apache], ST1 [Unit 1] only. 

(ii) Table 1.2 – PM10 BART, entries for AEPCO [Apache], APS Cholla Power Plant and SRP 

Coronado Generating Station. 

(iii) Table 1.3 – SO2 BART, entries for AEPCO, APS Cholla Power Plant and SRP Coronado 

Generating Station. 

* * * * * 

3. Section 52.145 is amended by adding paragraphs (e) and (f) to read as follows: 
Page 233 of 244

§ 52.145 Visibility Protection. 

* * * * * 

(e) Approval. On February 28, 2011, the Arizona Department of Environmental Quality 

submitted the “Arizona State Implementation Plan, Regional Haze Under Section 308 of the 

Federal Regional Haze Rule” (“Arizona Regional Haze SIP”). 

(1) With the exception of the NOX BART determinations for Units ST2 and ST3 at AEPCO 

Apache Generating Station; Units 2, 3, and 4 at APS Cholla Power Plant; and Units 1 and 2 at 

SRP Coronado Generating Station, and the BART compliance provisions for all BART 

emissions limits at the eight units at the three power plants, the BART determinations for 

AEPCO Apache Generating Station, APS Cholla Power Plant, and SRP Coronado Generating 

Station in the Arizona Regional Haze SIP meet the applicable requirements of Clean Air Act 

sections 169A and 169B and the Regional Haze Rule in 40 CFR 51.301 – 51.308. 

(f) Source-specific federal implementation plan for regional haze at Apache Generating Station, 

Cholla Power Plant, and Coronado Generating Station. 

(1) Applicability. This paragraph (f) applies to each owner/operator of the following coal-fired 

electricity generating units (EGUs) in the state of Arizona: Apache Generating Station, Units 2 

and 3; Cholla Power Plant, Units 2, 3, and 4; and Coronado Generating Station, Units 1 and 2. 

This paragraph (f) also applies to each owner/ operator of the following natural gas-fired EGUs 

in the state of Arizona: Apache Generating Station Unit 1. The provisions of this paragraph (f) 

are severable, and if any provision of this paragraph (f), or the application of any provision of 

this paragraph (f) 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 

(f), shall not be affected thereby. 
Page 234 of 244

(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 (f): 

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 unit. 

Coal-fired unit means any of the EGUs identified in paragraph (f)(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 (f). 

Emissions limitation or emissions limit means any of the Federal Emission Limitations 

required by this paragraph (f) or any of the applicable PM10 and SO2 emissions limits for Apache 

Generating Station, Cholla Power Plant, and Coronado Generating Station submitted to EPA as 

part of the Arizona Regional Haze SIP in a letter dated February 28, 2011, and approved into the 

Arizona State Implementation Plan on [INSERT DATE OF PUBLICATION IN THE Federal 

Register]. 

Flue Gas Desulfurization System or FGD means a pollution control device that employs 

flue gas desulfurization technology, including an absorber utilizing lime, fly ash, or limestone 

slurry, for the reduction of sulfur dioxide emissions. 

Group of coal-fired units mean Units 1 and 2 for Coronado Generating Station; Units 2 

and 3 for Apache Generating Station; and Units 2, 3, and 4 for Cholla Power Plant. 

lb means pound(s). 

NOX means nitrogen oxides expressed as nitrogen dioxide (NO2). 
Page 235 of 244

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

supervise(s) one or more of the units identified in paragraph (f)(1) of this section. 

MMBtu means million British thermal unit(s). 

Operating hour means any hour that fossil fuel is fired in the unit. 

PM10 means filterable total particulate matter less than 10 microns and the condensable 

material in the impingers as measured by Methods 201A and 202. 

Regional Administrator means the Regional Administrator of EPA Region IX or his/her 

authorized representative. 

SO2 means sulfur dioxide. 

SO2 removal efficiency means the quantity of SO2 removed as calculated by the 

procedure in paragraph (f)(5)(iii)(B) of this section. 

Unit means any of the EGUs identified in paragraph (f)(1) of this section. 

Valid data means data recorded when the CEMS is not out-of-control as defined by Part 

75. 

(3) Federal Emission Limitations. 

(i) NOX Emission Limitations. The owner/operator of each coal-fired unit subject to this 

paragraph (f) shall not emit or cause to be emitted NOX in excess of the following limitations, in 

pounds per million British thermal units (lb/MMBtu) from any group of coal-fired units. Each 

emission limit shall be based on a rolling 30-boiler-operating-day average, unless otherwise 

indicated in specific paragraphs. 

Group of coal-fired units Federal Emission Limitation 

 

Apache Generating Station Units 2 and 3 0.070 

Cholla Power Plant Units 2, 3, and 4 0.055 

Coronado Generating Station Units 1and 2 0.065 
Page 236 of 244

(ii) SO2 Removal Efficiency Requirement. The owners/operators of Cholla Power Plant Units 2, 

3, and 4 shall achieve and maintain a 30-day rolling average SO2 removal efficiency of 95 

percent at each unit. 

(4) Compliance Dates.

(i) The owners/operators of each unit subject to this paragraph (f) shall comply with the NOX

emissions limitations and other NOX-related requirements of this paragraph (f) no later than 

[INSERT DATE FIVE YEARS AFTER DATE OF PUBLICATION IN THE Federal 

Register]. 

(ii) The owners/operators of each unit subject to this paragraph (f) shall comply with the 

applicable PM10 and SO2 emissions limits submitted to EPA as part of the Arizona Regional 

Haze SIP in a letter dated February 28, 2011, and approved into the Arizona State 

Implementation Plan on [INSERT DATE OF PUBLICATION IN THE Federal Register], as 

well as the related compliance, recordkeeping and reporting of this paragraph (f) no later than the 

following dates: 

Unit Compliance date 

PM10 SO2

Apache 

Generating 

Station, Unit 1

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

Apache 

Generating 

Station, Unit 2

[INSERT DATE FOUR YEARS 

AFTER DATE OF PUBLICATION 

IN THE Federal Register]. 

[INSERT DATE FOUR YEARS 

AFTER DATE OF PUBLICATION 

IN THE Federal Register]. 

Apache 

Generating 

Station, Unit 3

[INSERT DATE FOUR YEARS 

AFTER DATE OF PUBLICATION 

IN THE Federal Register]. 

[INSERT DATE FOUR YEARS 

AFTER DATE OF PUBLICATION 

IN THE Federal Register]. 

Cholla Power 

Plant, Unit 2 

April 1, 2016 April 1, 2016 

Cholla Power [INSERT DATE 180 DAYS AFTER [INSERT DATE 180 DAYS AFTER 
Page 237 of 244

Plant, Unit 3 DATE OF PUBLICATION IN THE 

Federal Register] 

DATE OF PUBLICATION IN THE 

Federal Register] 

Cholla Power 

Plant, Unit 4 

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

Coronado 

Generating 

Station, Unit 1

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

Coronado 

Generating 

Station, Unit 2

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

[INSERT DATE 180 DAYS AFTER 

DATE OF PUBLICATION IN THE 

Federal Register] 

(iii) The owners/operators of Cholla Power Plant Units 2, 3 and 4 shall comply with the SO2

removal efficiency requirement in paragraph (f)(5)(iii)(B) of this section all related compliance, 

recordkeeping and reporting requirements no later than the following dates: 

Cholla Power 

Plant, Unit 2 

April 1, 2016 

Cholla Power 

Plant, Unit 3 

[INSERT DATE ONE YEAR AFTER DATE OF PUBLICATION 

IN THE Federal Register] 

Cholla Power 

Plant, Unit 4 

[INSERT DATE ONE YEAR AFTER DATE OF PUBLICATION 

IN THE Federal Register] 

(5) Compliance determinations for NOX and SO2. 

(i) Continuous emission monitoring system. 

(A) At all times after the compliance date specified in paragraph (f)(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. In addition, the owner/operator of 

Cholla Units 2, 3, and 4 shall calibrate, maintain, and operate a CEMS, in full compliance with 

the requirements found at 40 CFR Part 75, to accurately measure SO2 emissions and diluent at 

the inlet of the sulfur dioxide control device. Apache Unit 1 NOX and diluent CEMs shall be 
Page 238 of 244

operated to meet the requirements of Part 75. All valid CEMS hourly data shall be used to 

determine compliance with the emission limitations for NOX and SO2 in paragraph (f)(3) of this 

section for each unit. When the CEMS is out-of-control as defined by Part 75, that CEMs data 

shall be treated as missing data and not used to calculate the emission average. Each required 

CEMS must obtain valid data for at least 90 percent of the unit operating hours, on an annual 

basis. 

(B) The owner/operator of each unit shall comply with the quality assurance procedures for 

CEMS found in 40 CFR Part 75. In addition to these Part 75 requirements, relative accuracy test 

audits shall be calculated for both the NOX and SO2 pounds per hour measurement and the heat 

input measurement. The CEMs monitoring data shall not be bias adjusted. The inlet SO2 and 

diluent monitors required by this rule shall also meet the Quality Assurance/Quality Control 

(QA/QC) requirements of Part 75. The testing and evaluation of the inlet monitors and the 

calculations of relative accuracy for lb/hr of NOX, SO2 and heat input shall be performed each 

time the Part 75 CEMS undergo relative accuracy testing. In addition, relative accuracy test 

audits shall be performed in the units of lb/MMBtu for the inlet and outlet SO2 monitors at 

Cholla Units 2, 3, and 4. Heat input for Apache Unit 1 shall be measured in accordance with Part 

75 fuel gas measurement procedures found in Part 75 Appendix D. 

(ii) Compliance determinations for NOX. 

(A) The 30-day rolling average NOX emission rate for each group of coal-fired units shall be 

calculated for each calendar day, even if a unit is not in operation on that calendar day, in 

accordance with the following procedure: step one, for each unit, sum the hourly pounds of NOX

emitted during the current boiler-operating day (or most recent boiler-operating day if the unit is 

not in operation), and the preceding twenty-nine (29) boiler-operating days, to calculate the total 
Page 239 of 244

pounds of NOX emitted over the most recent thirty (30) boiler-operating day period for each 

coal-fired unit; step two, for each unit, sum the hourly heat input, in MMBtu, during the current 

boiler-operating day (or most recent boiler-operating day if the unit is not in operation), and the 

preceding twenty-nine (29) boiler-operating days, to calculate the total heat input, in MMBtu, 

over the most recent thirty (30) boiler-operating day period for each coal-fired unit; step 3, sum 

together the total pounds of NOX emitted from the group of coal-fired units over each unit’s most 

recent thirty (30) boiler-operating day period (the most recent 30 boiler-operating day periods for 

different units may be different); step four, sum together the total heat input from the group of 

coal-fired units over each unit’s most recent thirty (30) boiler-operating day period; and step 

five, divide the total pounds of NOX emitted from step three by the total heat input from step four 

for each group of coal-fired units, to calculate the 30-day rolling average NOX emission rate for 

each group of coal-fired units, in pounds of NOX per MMBtu, for each calendar day. Each 30-

day rolling average NOX emission rate shall include all emissions and all heat input that occur 

during all periods within any boiler-operating day, including emissions from startup, shutdown, 

and malfunction. 

(B) The 30-day rolling average NOX emission rate for Apache Unit 1 shall be calculated in 

accordance with the following procedure: step one, sum the total pounds of NOX emitted from 

the unit during the current boiler-operating day and the previous twenty-nine (29) boileroperating days; step two, sum the total heat input to the unit in MMBtu during the current boileroperating day and the previous twenty-nine (29) boiler-operating days; and step three, 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 
Page 240 of 244

NOX emission rate shall include all emissions and all heat input that occur during all periods 

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

(C) 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. 

(iii) Compliance determinations for SO2. 

(A) The 30-day rolling average SO2 emission rate for each coal-fired unit shall be calculated in 

accordance with the following procedure: step one, 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; step two, 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 step three, 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 and all heat input that occur during all periods within 

any boiler-operating day, including emissions from startup, shutdown, and malfunction. 

(B) The 30-day rolling average SO2 removal efficiency for Cholla Units 2, 3, and 4 shall be 

calculated as follows: step one, sum the total pounds of SO2 emitted as measured at the outlet of 

the FGD system for the unit during the current boiler-operating day and the previous twenty-nine 

(29) boiler-operating days as measured at the outlet of the FGD system for that unit; step two, 

sum the total pounds of SO2 delivered to the inlet of the FGD system for the unit during the 

current boiler-operating day and the previous twenty-nine (29) boiler-operating days as measured 

at the inlet to the FGD system for that unit (for each hour, the total pounds of SO2 delivered to 

the inlet of the FGD system for a unit shall be calculated by measuring the ratio of the lb/MMBtu 
Page 241 of 244

SO2 inlet to the lb/MMBtu SO2 outlet and multiplying the outlet pounds of SO2 by that ratio); 

step three, subtract the outlet SO2 emissions calculated in step one from the inlet SO2 emissions 

calculated in step two; step four, divide the remainder calculated in step three by the inlet SO2 

emissions calculated in step two; and step five, multiply the quotient calculated in step four by 

100 to express as a percentage removal efficiency. A new 30-day rolling average SO2 removal 

efficiency shall be calculated for each new boiler-operating day, and shall include all emissions 

that occur during all periods within each boiler-operating day, including emissions from startup, 

shutdown, and malfunction. 

(C) If a valid SO2 pounds per hour at the outlet of the FGD system or heat input is not available 

for any hour for a unit, that heat input and SO2 pounds per hour shall not be used in the 

calculation of the 30-day rolling average. 

(D) If both a valid inlet and outlet SO2 lb/MMBtu and an outlet value of lb/hr of SO2 are not 

available for any hour, that hour shall not be included in the efficiency calculation. 

(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 (f)(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 PM10 using EPA Method 5, in 40 CFR part 60, Appendix A, or 

Method 201A/202 in 40 CFR Part 51, Appendix M. A test protocol shall be submitted to EPA 

and ADEQ a minimum of 30 days prior to the scheduled testing. The protocol shall identify 

which method(s) will be used to demonstrate compliance. 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 
Page 242 of 244

Part 60 Appendix A Method 19. In addition to annual stack tests, the 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 PM10

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: 

(i) All CEMS data, including the date, place, and time of sampling or measurement; parameters 

sampled or measured; and results. 

(ii) Daily 30-day rolling emission rates for NOX and SO2 and SO2 removal efficiency, when 

applicable, for each unit, calculated in accordance with paragraph (f)(5) of this section. 

(iii) 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. 

(iv) Records of the relative accuracy test for hourly NOX and SO2 lb/hr measurement and hourly 

heat input measurement. 

(v) Records of all major maintenance activities conducted on emission units, air pollution control 

equipment, and CEMS. 

(vi) Any other records required by 40 CFR Part 75. 

(8) Reporting. All reports and notifications under this paragraph (f) shall be submitted to the 

Director of Enforcement Division, U.S. EPA Region IX, at 75 Hawthorne Street, San Francisco, 

CA 94105. 

(i) 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. 
Page 243 of 244

(ii) Within 30 days after the applicable compliance date(s) in paragraph (f)(4) of this section and 

within 30 days of every second calendar quarter thereafter (i.e., semi-annually), 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 and, for Cholla Units 2, 3, and 4, the SO2 removal efficiency, 

calculated in accordance with paragraph (f)(5) of this section. Included in this report shall be the 

results of any relative accuracy test audit performed during the two preceding calendar quarters. 

(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. Pollution control equipment shall be 

designed and capable of operating properly to minimize emissions during all expected operating 

conditions. 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: 

(i) R-18-2-101, paragraph 65; 
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(ii) R18-2-310, sections (A), (B), (D) and (E) only; and 

(iii) R18-2-310.01.