Vol. 77 Wednesday, 

No. 234 December 5, 2012 

Part III 

Environmental Protection Agency 

40 CFR Part 52 

Approval, Disapproval and Promulgation of Air Quality Implementation 

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

Final Rule 


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72512 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

1Although states and tribes may designate as 

Class I additional areas which they consider to have 

visibility as an important value, the requirements of 

the visibility program set forth in section 169A of 

the CAA apply only to ‘‘mandatory Class I Federal 

areas.’’ 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R09–OAR–2012–0021, FRL–9754–3] 

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 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 January 4, 2013. 

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. 

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. 

(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. 

(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. 


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2 77 FR 42834. 

3Those provisions also include an affirmative 

defense for excess emissions due to startups and 

shutdowns, which we did not intend to incorporate. 

(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. 

(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. 

(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 

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, 2012.2 In 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 

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. 


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4For 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)). 

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 malfunctionrelated 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. 

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 manmade 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. 

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

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-boileroperating-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 twounit average. The final compliance date 

for this NOX limit remains five years 

from the date of 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-boileroperating-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 threeunit 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 


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6 77 FR 42834. 

7 77 FR 45326 (July 31, 2012). 

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-boileroperating-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 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 twounit 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) 

0.03, 180 days ..... 0.03, Four years 0.15, 180 days ..... 0.15, Four years. 

Apache Unit 3 .... 0.050, Five years 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) 

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 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) 

0.03, 180 days ..... 0.03, 180 days 0.08, 180 days ..... 0.08, 180 days. 

Coronado Unit 2 0.080, June 1, 

2014.

Five years 0.03, 180 days ..... 0.03, 180 days 0.08, 180 days ..... 0.08, 180 days. 

IV. EPA’s Responses to Comments 

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 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 


srobinson on DSK4SPTVN1PROD with 
72516 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

8Exhibit 17 to Earthjustice Comments, WRAP 

BART Clearinghouse (Oct. 24, 2008). 

9 ‘‘Supporting Documentation on Emissions Unit 

Bart Eligibility Analysis’’, section 5.1.2. 

10Arizona Regional Haze SIP at page 155. 

11 Id. 

12 Id. 

13Email from Sue Kidd, APS, to Colleen 

McKaughan, EPA (October 10, 2012, 9:17 a.m.) and 

attachments. 

14See 77 FR 42841. 

15See, 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.’’) 

commercial operation before August 7, 

1962. 

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 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. 

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 case-by-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 

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, 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72517 

16See, 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.’’) 

17See Docket Item No. B–12, ‘‘Summary of WRAP 

RMC BART Modeling for Arizona.’’ 

and at a level that we consider costeffective. 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 

cost-effective. 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: 

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 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.’’ 

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 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 


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72518 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

18BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.4.a. 

19See 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.’’) 

20BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.4. 21BART Guidelines sections IV.D.4.c and IV.E. 

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 cost-effectiveness of a control 

technology for a particular facility is 

outside the range for other similar 

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 ‘applesto-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 

possible 20 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 

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, July 6, 2005) 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 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72519 

22 77 FR 42841. 

23 Id. 

24BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.5. 

25See 70 FR 39126. 

26See, 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). 

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

28 40 CFR Part 51, Appendix Y, section II.A.4. 

29 Id. section IV.D.5. 

protocol, upon which ADEQ relied for 

its BART analyses. On the contrary, we 

found that the modeling procedures 

relied upon by ADEQ 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 the installation of more 

stringent controls (i.e., 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. 

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 

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 


srobinson on DSK4SPTVN1PROD with 
72520 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

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. 

31Mark 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. 

32See, 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. 

34RoMANS—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 mg/m3, respectively, or 0.38 and 

0.78 ppb; and the mean and maximum ammonia are 

about 0.38 and 1.0 mg/m3 or 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 mg/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. 

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. 

approved the use of the same monthlyvarying 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, 

September 18, 2012) 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. 

Response: The IWAQM Guidance 30 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 paper 31 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 visibilityimpairing 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 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 papers 34 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 

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 backcalculated 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72521 

36As 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. 

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)). 

40See 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). 

41 40 CFR Part 51, Appendix Y, Section IV.C. 

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 

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 costeffectiveness 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 more-stringent 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 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 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 coalfired 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 nonmercury 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 costeffective 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 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 fiveVerDate Mar<15>2010 18:49 Dec 04, 2012 Jkt 229001 PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 E:\FR\FM\05DER3.SGM 05DER3

srobinson on DSK4SPTVN1PROD with 
72522 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

42See BART Guidelines, 40 CFR Part 51, 

Appendix Y, section IV.E.4. 

43See Apache Title V Permit Technical Support 

Document (2007), Table 9; Title V Permit (2007), 

Attachment B, section II.E.1.a. 

44See BART Guidelines, 40 CFR Part 51, 

Appendix Y, section IV.E.4. 

45Letter from Michelle Freeark, AEPCO, to Trevor 

Baggiore, ADEQ (July 8, 2009). 

46 Id. 

47 40 CFR Part 51, Appendix Y, section IV.4.a., 

note 15. 

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. 

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) 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. 

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 more-stringent NOX controls by 

including costs not allowed by the 

Manual, and substantially 

underestimated the visibility benefits of 

additional NOX controls. The 

commenter asserted that 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. 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72523 

48 77 FR 9450 (February 16, 2012) (codified at 40 

CFR 60.42Da). 

49 40 CFR Part 51, Appendix Y, Section IV.C. 

50Attachment 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. 

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 fivefactor 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. 

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 costeffective 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 five-factor 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 fivefactor 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 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 costeffective 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 lessstringent 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 


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72524 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

51See ‘‘Additional APS Cholla BART response’’, 

Appendix B. 

52See, e.g., ‘‘APS Cholla Unit 2 BART report’’, 

Table 2–2. 

53See ‘‘Additional APS Cholla BART response’’, 

Appendix B, Section 6.2. 

54BART 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. 

57See ‘‘Additional APS Cholla BART response’’, 

Appendix B, Section 6.2. 

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. 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 removal efficiency of 95 

percent when these units are burning 

this ‘‘worst-case’’ (highest-sulfur) 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. 

• 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 costeffectiveness 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. 

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 


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Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72525 

58Consent Decree in United States v. Salt River 

Project, CV 08–1479–PHX–JAT (entered Dec. 19, 

2008). 

Coronado Units 1 and 2, noting that that 

emissions of PM10 from Coronado Units 

1 and 2 are currently controlled by hotside 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’ 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 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 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 fivefactor 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 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 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 fivefactor 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. 

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 


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72526 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

59Consent 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. 

61See 40 CFR 51.308(d)(2)(i). 

62BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.4.d.1 63CAA 169A(g)(2), 42 U.S.C. 7491(g)(2); see also 

40 CFR 52.308(e)(ii)(A). 64See, e.g., SIP Appendix D at 4; Apache Unit 2 

BART analysis at 2–2; Cholla. 

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. 

68Consent Decree in United States v. Salt River 

Project, CV 08–1479–PHX–JAT (entered December 

19, 2008). 

69BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.4.d.2. 

70See Docket Item B–09, ‘‘Additional APS Cholla 

BART response’’, Appendix B, Section 6.2. 

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 precontrol 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. 

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 

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 federallyenforceable 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

Consistent with this provision, for 

Coronado we used the consent decreemandated 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72527 

71 40 CFR 51.308(d)(2)(i). 

72AZ Regional Haze SIP at page 39. 

73 40 CFR 51.308(d)(3)(v)(G). 

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. 

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. 

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 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 shortterm 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. 

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 


srobinson on DSK4SPTVN1PROD with 
72528 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

74 40 CFR 51.308(e)(1)(ii)(A). 

75BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.D.3. 

76 Id. section V. 

77Citing 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. 

78We 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. 

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 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. 

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 

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 topdown 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 state-wide 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 sector-wide 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 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72529 

79BART 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. 83Or subcategories, which Subpart Da does not 

establish except for ‘‘new’’ and ‘‘modified’’ units. 

84See, 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. 

85See BART Guidelines, 40 CFR Part 51, 

Appendix Y, Table 1. 

86At 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. 

87BART Guidelines, 40 CFR Part 51, Appendix Y, 

section IV.E.5. 

88 70 FR 39132. 

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 postcombustion 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 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 42847). 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, subbituminous, lignite, etc.). Commenters 

also 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 subbituminous 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 fivefactor 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 nonpresumptive 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 postcombustion controls, you should likewise 

presume that these same levels are costeffective. 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

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 costeffective, 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 


srobinson on DSK4SPTVN1PROD with 
72530 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

89 Document ID: EPA–R09–OAR–2012–0021– 

0008, File name: G–15_MODELING_

FILES_EGU_BART_Costs_Apache_

Cholla_Coronado_FINAL2. 90http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Appendix52A.pdf. 91APS comments, page 12. 

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 

health-based regulations and not the 

RHR. 

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., 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 inhouse 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.’’ 

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 sitespecific 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: 

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 


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Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72531 

92As described in Table 2–5 of the CCM, 

Engineering and Home Office Fees represent 10 

percent of purchased equipment costs. 

93CCM (Tables 1.4 and 2.5 show AFUDC value 

as zero). 

94See, 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). 

95EPA Air Pollution Cost Control Manual, Sixth 

Edition page 1–3. 

96Approved Materials Source List, Fly Ash, 

Natural Pozzolan, and Lime, Revised July 10, 2012, 

available at http://www.azdot.gov/Highways/ 

Materials/. 

97See 77 FR 42853–4284, TSD at 38. 

98Citing 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). 

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. 

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: 

* * * 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 

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 


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99See BART Guidelines, 40 CFR Part 51, 

appendix Y, section IV.E.2. 100Central Arizona Water Conservation Dist. v. 

EPA, 990 F.2d 1531, 1541 (9th Cir. 1993). 101See 77 FR 42853–4284, TSD at 38. 

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 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 

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. 

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 visibilityimpairing 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 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 


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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. 

103BART Guidelines section IV.D.4.c. 

104See, 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. 

105BART 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.’’) 

106See, 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.’’) 

107Terhorst, Jonathan and Berkman, Mark, ‘‘Effect 

of Coal-fired Power Generation on Visibility in a 

Nearby National Park’’, Atmospheric Environment 

44, 2524, 2530 (Apr. 2010). 

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 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 costeffectiveness 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 costeffectiveness, 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 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 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 study 107 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 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 


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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. 

109See 40 CFR 51.308(f) (future Regional Haze 

plans must address reasonable progress and longterm strategy, but not BART). 

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. 

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 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. 

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 


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110See 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. 

111As 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. 

112As discussed in further detail in the responses 

on Coronado, this is specifically in regards to 

Coronado Unit 1. 

113The 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. 

114As noted in our NPRM (77 FR 42867). 115See 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.’’ 

116Although 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. 

117BART 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 

* * *). 

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. 

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,110 we 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 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 subbituminous 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 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 status 115 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,117 we 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 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 


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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, unitcycling 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 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 0.26 0.31 0.28 

SNCR+LNB+OFA ............................................................................................ 25 0.19 0.23 0.21 

1This 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. 

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 costeffectiveness 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 costeffective at $/ton values that are 

somewhat higher than those calculated 

by the commenters. As a result, we 

decline to modify our estimates of costeffectiveness 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 sitespecific 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 siteVerDate Mar<15>2010 18:49 Dec 04, 2012 Jkt 229001 PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 E:\FR\FM\05DER3.SGM 05DER3

srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72537 

118 Docket Item No. B–01, Arizona Regional Haze 

SIP, Appendix D, page 49. 

119See 77 FR 42856, Table 16. 

120The analysis was included in Attachment 1 to 

AEPCO’s Comments on the page titled ‘‘SCR Capital 

Cost Comparison.’’ 

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. 

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 action 119

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 

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 costeffective. 

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); 

• 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 


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72538 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

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 sitespecific. 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 cost-effectiveness 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 

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 7.0 ........................

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 89 ........................

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 $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 

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, 


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Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72539 

121CAA section 169A(g)(2), 42 U.S.C. 7491(g)(2); 

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

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 

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. 

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, loadfollowing 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 

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 


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72540 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

122BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.E.3. 123 77 FR 42866–42867; see also 13 CFR 121.201, 

footnote 1. 124Annual Report for year ending December 31, 

2011, from AEPCO to Arizona Corporation 

Commission. 

125See Docket Item H–1 Arizona Electric Power 

Cooperative, Inc. Annual Report Electric for Year 

Ending December 31, 2011 submitted to Arizona 

Corporation Commission Utilities Division, 

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

Annualpercent20Reports/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. 

127Union Electric Co., v. EPA, 427 U.S. 246, 255– 

66 (1976); 42 U.S.C. 7410(a) (2). 

128Arizona 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. 

129Exceptions 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. 

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 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 

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 

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 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 Coops and off-system or non-Member 

sales. Under the alternative scenario 

that the incremental cost for SCR is 

covered exclusively by member 

cooperatives, the incremental revenue 


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130Apache Plant: Report on SCR Incremental Cost 

Assessment. Prepared by Energy Strategies, LLC for 

EC/R, Inc. (November 2012). 

131 Id. 

132Energy 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. 

133Arizona 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). 

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 

$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 

(percent) 

Average $ per 

year per 

customer 

Average $ per 

month per 

customer 

Percent 

Increase 

(percent) 

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 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 fivefactor 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 

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 


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72542 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

134AEPCO Comments page 18. 

135 Id. 

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). 

137See, e.g., Interim Guidance on Considering 

Environmental Justice During the Development of 

an Action page 4, footnote 4. 

‘‘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 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 

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. 

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 Dine ́. 

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 economic impacts 

of EPA actions,137 we 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. 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72543 

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/FinalActionOn

ColoradoRegionalHazePlanSep2012.pdf. 

139A spreadsheet titled ‘‘Supplemental Cost 

Analysis 2012–11–15.xls’’ is in the docket. 

140Citing 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. 

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 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 postcombustion 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 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 higherNOX 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 fivefactor 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.’’ 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 

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 BART for 


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72544 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

141 ‘‘Additional APS Cholla BART response’’, 

Appendix B. 

142BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.D.3. 

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.’’ 

145See 77 FR 42859, Table 18. 

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 sitespecific 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

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 best-performing 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 

efficiency 

(percent) 

Control technology 

(lb/MMBtu) Year 

TX ........ W A Parish ........................................ WAP7 0.038 2007 73 SCR 1

TX ........ W A Parish ........................................ WAP8 0.038 2006 77 SCR 1

VA ........ Chesterfield Power Station ................ 6 0.041 2009 89 SCR+LNB+COFA/SOFA 

NC ....... Marshall ............................................. 3 0.045 2011 85 SCR+LNB+SOFA 

TN ........ Kingston ............................................. 6 0.051 2009 88 SCR+LNB+SOFA 

TN ........ Kingston ............................................. 8 0.052 2009 88 SCR+LNB+SOFA 

TN ........ Kingston ............................................. 9 0.052 2009 89 SCR 

TN ........ Kingston ............................................. 7 0.054 2009 88 SCR+LNB+SOFA 

MN ....... Boswell Energy Center ...................... 3 0.054 2009 86 SCR+LNB+SOFA 

TX ........ Sandow .............................................. 4 0.059 2011 83 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 lowto 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72545 

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 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. 

149The 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. 

efficiencies based upon the difference 

between the highest 24-hour average 

emission rate observed over a 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

(percent) 

Cholla 2 ................................................................................. 0.503 CCOFA 2001–03 0.07 86 

Cholla 3 ................................................................................. 0.410 CCOFA 2001–03 0.07 83 

Cholla 4 ................................................................................. 0.415 CCOFA 2001–03 0.07 83 

1Per Table 2–1 of the original BART analysis for each unit, Docket Items B–06 through B–08. 

2Per Appendix A of the original BART analysis for each unit, Docket Items B–06 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

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 

(percent) 

(lb/MMBtu) 

Cholla 2 .......................................................................................................... 0.326 CCOFA 2001–03 86 0.045 

Cholla 3 .......................................................................................................... 0.304 CCOFA 2001–03 83 0.052 

Cholla 4 .......................................................................................................... 0.296 CCOFA 2001–03 83 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 short-term 

‘‘spike.’’ On an annual average basis, 

such short-term spikes can be averaged 

with 365 other 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 


srobinson on DSK4SPTVN1PROD with 
72546 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

150 ‘‘Cholla CAMD emission data (daily) 2001–03’’ 

151Please consult the regulatory language in our 

final action for the NOX compliance determination 

methodology associated with the bubble limit. 

152Black 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. 

153 ‘‘Cholla CAMD emission data (monthly) 2010– 

12.’’ 

154 Document ID: EPA–R09–OAR–2012–0021– 

0008, File name: G–15_MODELING_FILES_EGU_

BART_Costs_Apache_Cholla_Coronado_FINAL2 

155Specifically, 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. 

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 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 

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 back-up 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 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 Web site 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 

contractors 155 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 cost-effectiveness 

ranging from $7,719/ton to $8,894/ton, 

with incremental costs ranging from 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72547 

156 Docket ID No. EPA–R09–OAR–2012–0021. 

157Regulatory 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). 

158A 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/. 

$8,759/ton to $10,329/ton compared to 

EPA’s estimates of $3,115/ton to $3,473/ 

ton, with 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 costeffective 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 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 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- 


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hour average basis (as provided by APS) 

to a control option value on an annual 

average basis is not an ‘‘apples-toapples’’ comparison, as some portion of 

the emission reduction 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 

(lb/hr) (tpy) (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: 

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 costeffectiveness 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 $/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 


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159CAA section 169A(g)(2), 40 CFR 

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

160 70 FR 39129. 

162BART Guidelines, 40 CFR Part 51, Appendix 

Y, Section IV.d.4.b. 

163 Id. Section IV.D.5. 

164 ‘‘Request for Information Relating to Cholla 

Power Plant’’, letter from Sue Kidd, Director, 

Corporate Environmental Policy and Programs, to 

Francisco Don ̃ ez, EPA, (February 3, 2012). 

165 ‘‘BART Analysis for Cholla Unit 2,’’ Prepared 

for APS by CH2MHill (January 2008). 

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.’’ 

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 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 costeffectiveness,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. 

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 

letter 164 that did not mention the 

merged stack, although it was 

mentioned in APS’s BART analysis 165

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 volumeweighted 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 part 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 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. 


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72550 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

167Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants, Version 2010a, 1020636, 

Technical Update, Electric Power Research 

Institute, April 2010). 168See 40 CFR 52.21(b)(23)(i). 

Comment: One commenter (APS) 

stated that EPA incorrectly applied 

H2SO4 mitigation factors from an 

Electric Power Institute (EPRI) report 167

in reaching its conclusion that H2SO4

production is not a problem with SCR 

at Cholla. The commenter stated that 

this factor is actually 90 percent rather 

than 99 percent in the report, but that 

this factor only applies to subbituminous 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 

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 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-boiler-operatingday average. 

Response: We acknowledge the 

comment. 

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, 


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169CAA section 169A(g)(2), 42 U.S.C. 7491(g)(2); 

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

170 Id. 

171BART Guidelines section IV.D.4.h 

172 Id. section IV.E.2. 173 Id. section IV.E.3. 

174Using 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). 

175See 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. 

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 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 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 costbenefit 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 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 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, 


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72552 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

176 77 FR 42854, July 20, 2012 (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.’’). 

177See 77 FR 42861, July 20, 2012, 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). 

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/FinalActionOn

ColoradoRegionalHazePlanSep2012.pdf. 

179A spreadsheet titled ‘‘Supplemental Cost 

Analysis 2012–11–15.xls’’ is in the docket. 

180See Coronado Title V Permit, Attachment B, 

section II.E.1.a.ii. 

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. 

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 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 fivefactor 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 costeffectiveness 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. 

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 


srobinson on DSK4SPTVN1PROD with 
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181Although 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. 

182See 77 FR 42849–42850, July 20, 2012, 

(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). 

183Consent Decree in United States v. Salt River 

Project, CV 08–1479–PHX–JAT (entered December 

19, 2008). 

184BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.C. 

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 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 costeffective 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 costeffective. 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. 

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 

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, April 6, 2012). 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

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 


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185BART Guidelines, 40 CFR Part 51, Appendix 

Y, section V. 

186 In addition to the final reports, SRP provided 

certain supporting spreadsheets upon request. We 

have placed these spreadsheets in the docket. 

187S&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. 

188Nonetheless, we note that the emission 

modeling results (particularly those produced by 

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 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 lowload 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-byunit basis, and that use of plant-wide 

limits would not affect the expected 

visibility benefits of controls. Therefore, 

they requested that EPA allow for plantwide averaging at Coronado. 

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 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. 

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 


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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. 189BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.D.3. 

190We 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. 192We 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’’. 

193This 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’’. 

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 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 cost 1

($) 

Annualized 

capital cost 2

($/yr) 

Annual O&M 

costs 

($/yr) 

Total annual 

costs 

($/yr) 

Low load temperature control system ............................................................. $2,500,000 $235,982 ........................ $235,982 

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 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 


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72556 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

194 40 CFR 51.301. 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 * * *’’). 

195Citing Docket Item C–16 (SRP Letter to 

DJordan 06–26–2012). 

196As described by the commenter, the ‘‘boilerout’’ 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. 

197See ‘‘Design and Operation of Coal-fired 

TURBO furnaces for NOX control’’, Riley Stoker 

Corporation, November 1978. 

198Acid Rain Program data indicates 22 turbo 

units were in operation in 2011. 

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 rate 1

Removed 

(tpy) 

Annual cost 

($/yr) 

Costeffectiveness 

(lb/hr) (tpy) ($/ton) 

SCR+LNB+OFA (no low load temp ctrl 

sys) ....................................................... 0.080 319 1,242 ........................ ........................ ........................

SCR+LNB+OFA (with low load temp ctrl 

sys) ....................................................... 0.072 287 1,118 124 235,982 1,900 

1Emissions 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 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 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 boilerout 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 venturi-shaped 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


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72557 

199 ‘‘An Overview of Riley Stoker’s Burner 

Development Efforts for NOX Control’’, Riley Stoker 

Corporation, April 7, 1983. 

200 ‘‘Low NOX Combustion System Solutions for 

Wall Fired,T-Fired, and Turbo Fired Boilers.’’ 

Babcock Power, August 28–31, 2006. 

201Supplemental Cost Analysis 2012–11–15.xls. 

202 40 CFR 51.301. 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 * * *’’). 

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 

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 ‘‘boilerout’’ emission rates of the Riley turbo 

design with those achieved by 

tangential and more traditional wallfired 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 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 fivefactor 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 topdown 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 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 ‘‘boilerout’’ 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 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


srobinson on DSK4SPTVN1PROD with 
72558 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

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 costeffectiveness 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 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 costeffective, 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, sitespecific cost analysis. The commenter 

added that ADEQ has discretion to 

conduct and document its cost 

assessment at a level that it deems 

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 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 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72559 

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) 

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) 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 Table 16. As 

noted previously, these emission 

estimates are based on a 2001–2003 

baseline period, during which the 

Coronado units operated only with 

OFA. We have calculated annual 

emission rates for the OFA baseline 

using the annual average emission data 

(lb/MMBtu) reported to CAMD over this 

2001–2003 baseline period. 


srobinson on DSK4SPTVN1PROD with 
72560 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

203 Document ID: EPA–R09–OAR–2012–0021– 

0008, File name: G–15_MODELING_FILES_EGU

_BART_Costs_Apache_Cholla_Coronado_FINAL2. 

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 

(lb/hr) (tpy) (tpy) 

OFA (only) ................................................ 0.407 4,316 0.84 1,756 6,462 ........................

LNB+OFA ................................................. 0.303 4,316 0.84 1,308 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 

1Annual 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) 

Cost-effectiveness 

($/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 costeffectiveness 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 

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 nonair 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 edocket 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 Web site 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 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 postcombustion 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 costeffectiveness’’, 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 SNCRand 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 cost-effectiveness of 

moving from LNB with OFA to SNCR 

with LNB and OFA is therefore 


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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 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-operating-day 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 

five-factor analysis, and that the consent 

decree does not indicate that SCR at 

0.080 lb/MMBtu 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 postcombustion 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 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 costeffectiveness 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 lowemitter 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. 

• 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 


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204See, e.g., 40 CFR 60.13(a) and 40 CFR 

Appendix F. 

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. 

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 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. 

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. 

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 


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205 75 FR 80118, 80121. 

206See 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.’’) 

208See 40 CFR 52.21(b)(23)(i). 

209Although 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 oneyear 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. 

210See Cholla Title V Permit (2012), Table C–3: 

Continuous Emission Monitors. 

211We 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.’’ 

212APS Comments, Table 3–8. No annualized 

cost was provided. 

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 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 

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 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 


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213BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.D.5. 

214 Id. Section V. 

215CAA section 110(a)(1), (k)(3) and (l), 42 U.S.C. 

7410(a)(1), (k)(3) and (l). 

time for installation of the CEMS, the 

compliance deadline for this removal 

efficiency requirement at these units 

will be 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 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 lowload 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 

five-factor 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. 

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, 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 


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216See id. 42 U.S.C. 7410(k)(5), (m). 

217See id. section 7410(c)(1). 

218CAA sections 110(a)(2)(J), 169A and 169B 42 

U.S.C. 7410(a)(2)(J), 7491 and 7492. 

219Under 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 

section 110], or promulgated under [CAA section 

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 EPApromulgated 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). 

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. 

225EPA 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). 

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. 

228CAA section 169A(b)(2)(A)., 42 U.S.C. 

7491(b)(2)(A). 

229 42 U.S.C. 7491(g)(2). 

230 40 CFR 51.308(e)(1)(ii)(A). 

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, 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 

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 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 

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 


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72566 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

231Arizona Regional Haze SIP, Appendix E, 

‘‘Responsiveness Summary’’ at 13. 

232CAA section 169A(b)(2)(A). 

233BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.E.2. 

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 site-specific 

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 

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 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: 

• 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. 

• 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. 

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 


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234 77 FR 42846. 

235 Id. 

236 77 FR 42849, 42851. 

237CAA section 169A(b) and 40 CFR 

51.308(e)(1)(ii)(B). 

238 42 U.S.C. 7410(k)(3). 

239See 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’’). 

240EPA 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 

* * *’’). 

241See 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 BARTContinued 

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 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 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 visibilityimpairing 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. 

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 section 110(k)(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 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-bysource basis and are not dependent 

upon other elements of the plan.241


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eligible source that is subject to BART within the 

State.’’ 

245We 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). 

246Letter from Stephen A. Owens, ADEQ, to 

Wayne Nastri, EPA (Dec. 14, 2008). 

247 40 CFR 51.309(d)(4)(i) and (vii), (g)(2). 

248 74 FR 2392. 

249 Id. at 2393 

250CAA section 307(b). 42 U.S.C. 7607(b). 

251National Parks Conservation Association v. 

Jackson (D.D.C. Case 1:11–cv–01548). 

252National 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). 

253See NPCA v. EPA, (D.D.C. Case 1:11–cv– 

01548). Dkt # 35, at 3, n. 1. 

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 

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 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 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 


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254On 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. 

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)). 

256 42 U.S.C. 7410(k)(1)(B). 

257 42 U.S.C. 7410(k)(2). 

258See 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 section 

110](c)’’] 

259See CAA section 307(d)(3), 42 U.S.C. 

7607(d)(3). 

260The 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). 

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 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-andcomment 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 

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) 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 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),258 we 

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 

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 


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261CAA section 307(d)(6)(A) & (B), 42 U.S.C. 

7607(d)(6)(A) & (B). 

262EME Homer City Generation, slip op. at 7. 

263 Id. at 46. 

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 sourcespecific 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 sourcespecific five-factor analyses. 70 FR 39131–39132. 

269Memo 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. 

270 74 FR 2392. 

271See, 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). 

272See, 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). 273Slip op. at 57. 274Arizona 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. 

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. 

279U.S. Forest Service Specific Comments: 

Arizona Regional Haze SIP (Nov. 29, 2010). 

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

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 DC 

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

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 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 


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280For 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. 

281The 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, 

llF.3dll, 2012 WL 3570721, at *17 (DC 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. 

282The 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. 

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 court-ordered 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 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. 

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. 

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. 

Comment: One commenter 

(Earthjustice) stated that the RHR rule 


srobinson on DSK4SPTVN1PROD with 
72572 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

283The 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. 

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 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 atrisk 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 

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-togovernment 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 

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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72573 

284See document titled: ‘‘Timeline of all tribal 

consultations on BART.docx’’ in the docket for this 

final rulemaking. 

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. 

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 

Plant 284 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 

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. 

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 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 


srobinson on DSK4SPTVN1PROD with 
72574 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

285BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.D.1. 

286 59 FR 7629, February 16, 1994. 

287BART Guidelines, 40 CFR Part 51, Appendix 

Y, section IV.D.1. 

288 77 FR 42834. 

289See 77 FR 45326 (July 31, 2012). 

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 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 hazecausing pollutants, and transitioning to 

those sources of energy could lead to 

visibility improvements. 

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 12898,286 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: 

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 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 


srobinson on DSK4SPTVN1PROD with 
Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 72575 

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 coalfired 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. 

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). 

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 sourcespecific 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-forprofit 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 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 action on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 


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entities. The FIP for the three Arizona 

facilities being issued 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 sourcespecific 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). 

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 costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this 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 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 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. 

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 


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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 

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 this 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 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. 

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 February 4, 2013. 

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. 

Dated: November 15, 2012. 

Lisa P. Jackson, 

Administrator. 

Part 52, chapter I, title 40 of the Code 

of Federal Regulations is amended as 

follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for Part 52 

continues to read as follows: 

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

Subpart 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: 

§ 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 through 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. 

(2) Definitions. Terms not defined 

below shall have the meaning given to 

them in the Clean Air Act or EPA’s 


srobinson on DSK4SPTVN1PROD with 
72578 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

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 December 5, 2012. 

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). 

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. 

SO4 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-operatingday 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 

(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 NOXrelated requirements of this paragraph 

(f) no later than December 5, 2017. 

(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 December 5, 

2012, 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 ...................................................................... June 3, 2013 ......................................... June 3, 2013. 

Apache Generating Station, Unit 2 ...................................................................... December 5, 2016 ................................ December 5, 2016. 

Apache Generating Station, Unit 3 ...................................................................... December 5, 2016 ................................ December 5, 2016. 

Cholla Power Plant, Unit 2 ................................................................................... April 1, 2016 ......................................... April 1, 2016. 

Cholla Power Plant, Unit 3 ................................................................................... June 3, 2013 ......................................... June 3, 2013. 

Cholla Power Plant, Unit 4 ................................................................................... June 3, 2013 ......................................... June 3, 2013. 

Coronado Generating Station, Unit 1 ................................................................... June 3, 2013 ......................................... June 3, 2013. 

Coronado Generating Station, Unit 2 ................................................................... June 3, 2013 ......................................... June 3, 2013. 

(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.

December 5, 2013. 

Cholla Power Plant, 

Unit 4.

December 5, 2013. 

(5) Compliance determinations for 

NOX and SO4—(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 

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 


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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 40 CFR 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) boileroperating days, to calculate the total 

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 boileroperating day (or most recent boileroperating day if the unit is not in 

operation), and the preceding twentynine (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 boileroperating 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) 

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 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) boileroperating days. A new 30-day rolling 

average NOX emission rate shall be 

calculated for each new boiler-operating 

day. Each 30-day rolling average NOX

emission rate shall include all emissions 

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) boileroperating 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) boileroperating 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 boileroperating day and the previous twentynine (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 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 boileroperating 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) 


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72580 Federal Register / Vol. 77, No. 234 / Wednesday, December 5, 2012 / Rules and Regulations 

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 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 (5) 

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. 

(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; 

(ii) R18–2–310, sections (A), (B), (D) 

and (E) only; and 

(iii) R18–2–310.01. 

[FR Doc. 2012–28565 Filed 12–4–12; 8:45 am] 

BILLING CODE 6560–50–P 


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