Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze State and Federal Implementation Plans

Federal RegisterDec 5, 2012

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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 (SO

) and particulate matter less than or equal to 10 micrometers (PM

) at all the units, but disapproves Arizona's BART emissions limits for nitrogen oxides (NO

) at the coal-fired units of the three power plants. We also are promulgating a FIP that contains new emissions limits for NO

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

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.

Although states and tribes may designate as Class I additional areas which they consider to have visibility as an important value, the requirements of the visibility program set forth in section 169A of the CAA apply only to “mandatory Class I Federal areas.”

(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

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,

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

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-NO

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

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

mean or refer to ammonia.

(40) The initials

mean or refer to nitrogen oxides.

(41) The initials

mean or refer to National Park.

(42) The initials

NPRM

mean or refer to Notice of Proposed Rulemaking.

(43) The initials

O&M

mean or refer to operation and maintenance.

(44) The initials

mean or refer to organic carbon.

(45) The initials

OFA

mean or refer to over fire air.

(46) The initials

mean or refer to particulate matter.

(47) The initials

mean or refer to particulate matter with an aerodynamic diameter of less than 10 micrometers (coarse particulate matter).

(48) The initials

2.5

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

mean or refer to Reasonable Progress.

(59) The initials

RPG

r 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

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

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.

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:

77 FR 42834.

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 SO

and PM

at all three sources and units and the emissions limit for NO

at Apache Unit 1.

Proposed Disapproval:

We proposed to disapprove Arizona's BART emissions limits for NO

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 NO

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 PM

10.

In addition, we specifically sought comment on whether we should require lower SO

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.

Those provisions also include an affirmative defense for excess emissions due to startups and shutdowns, which we did not intend to incorporate.

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.

Most notably, and with the exception of Apache Unit 1, the FIP includes NO

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 NO

BART determinations for the coal-fired units are not consistent with the applicable statutory and regulatory requirements. Furthermore, the Arizona Regional Haze SIP does not include the necessary compliance schedules and requirements for equipment maintenance and operation, including monitoring, recordkeeping and reporting requirements for BART. As a result, EPA believes this final disapproval is the only path that is consistent with the Act at this time.

We encourage the State to submit a revised SIP to replace all portions of our FIP, and are ready to work with the State to develop a revised plan. The CAA requires states to prevent any future and remedy any existing man-made impairment of visibility in 156 national parks and wilderness areas designated as Class I areas. Arizona has a wealth of such areas. The three power plants affect visibility at 18 national parks and wilderness areas, including the Grand Canyon, Mesa Verde and the Petrified Forest. The State and EPA must work together to ensure that plans are in place to make progress toward natural visibility conditions at these national treasures.

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 NO

and SO

at Apache Unit 1 as proposed. We are approving the State's emissions limits for PM

and SO

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 NO

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.

For each BART source, the SIP must include a requirement to install and operate control equipment as expeditiously as practicable (40 CFR 51.308(e)(1)(iv)); a requirement to maintain control equipment (40 CFR 51.308(e)(1)(v)); and procedures to ensure control equipment is properly operated and maintained, including requirements for monitoring, recordkeeping and reporting (40 CFR 51.308(e)(1)(v)).

Final Federal Implementation Plan:

We are promulgating a FIP that includes emissions limitations representing BART for NO

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 PM

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 SO

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.

In the regulatory text in our NPRM, we proposed to incorporate by reference into the FIP two provisions of the Arizona Administrative Code, R18-2-310 and R18-2-310.01, which we characterized as establishing an affirmative defense for excess emissions due to malfunctions. However, those provisions also include an affirmative defense for excess emissions due to startups and shutdowns, which we did not intend to incorporate. As explained below, the emission limits that we are promulgating today include an adequate margin of compliance to account for periods of startup and shutdown. Accordingly, as indicated by the title of this provision in our proposed regulatory text (“Affirmative Defense for Malfunctions”), we are only incorporating into the FIP the malfunction-related provisions of these rules and not the startup and shutdown provisions. Our final regulatory text clarifies this distinction and also incorporates the definition of malfunction.

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 NO

is 0.070 pounds per million British thermal units (lb/MMBtu) determined as an average of the two units, based on a rolling 30-boiler-operating-day average. Compared to the proposed emissions limit of 0.050 lb/MMBtu on each unit, this higher limit and the addition of a two-unit average provides an extra margin of compliance to account for periods of startup and shutdown as well as additional operational flexibility for Apache given AEPCO's status as a small entity. When either one of the two units is not operating, its emissions from its own preceding thirty boiler-operating-days will continue to be included in the two-unit average. The final compliance date for this NO

limit remains five years from the date of publication of this final rule. For SO

and PM

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 NO

is 0.055 lb/MMBtu determined as an average of the three units, based on a rolling 30-boiler-operating-day average. Compared to the proposed emissions limit of 0.050 lb/MMBtu on each unit, the higher limit and three-unit average provide an extra margin of compliance to account for periods of startup and shutdown. When any of the three units is not operating, its emissions from its own preceding thirty boiler-operating-days will continue to be included in the three-unit average. As proposed, the final compliance date to install and operate controls is five years from the date of publication of this final rule. For SO

we are adding a removal efficiency requirement of 95 percent for the scrubbers on Cholla Units 2, 3 and 4, in order to ensure that these scrubbers are properly operated and maintained, consistent with 40 CFR 51.308(e)(1)(v). We are retaining the other compliance deadlines as proposed, except for Cholla Unit 2, where we are extending the

compliance deadline to April 1, 2016, for both SO

and PM

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 NO

is 0.065 lb/MMBtu determined as an average of the two units, based on a rolling 30-boiler-operating-day average. Compared to the proposed emissions limits of 0.050 on Unit 1 and 0.080 on Unit 2, this new limit based on a two-unit average provides an extra margin of compliance to account for startup and shutdown. When either one of the two units is not operating, its emissions from its own preceding thirty boiler-operating-days will continue to be included in the two-unit average. The final compliance date for the two units is five years from the date of publication of this final rule.

Table 1—Summary of Changes From Proposal to Final Rule: Emissions Limits (Lb/MMBtu) and Compliance Dates in SIP and FIP

Source

Proposal

Final

Proposal

Final

Proposal

Final

Apache Unit 1

0.056, Five years

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

0.15, 180 days

Add 95 percent efficiency 1 year.

Cholla Unit 4

0.050, Five years

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

0.08, 180 days

0.08, 180 days.

Coronado Unit 2

0.080, June 1, 2014

Five years

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.

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.

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.

77 FR 42834.

77 FR 45326 (July 31, 2012).

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

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.”

The WRAP's “Arizona BART Eligibility TSD” further explains that:

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

[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.

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

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.”

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

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

Arizona Regional Haze SIP at page 155.

Id.

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.

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.

Email from Sue Kidd, APS, to Colleen McKaughan, EPA (October 10, 2012, 9:17 a.m.) and attachments.

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 NO

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 NO

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.

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 NO

BART determinations.

See 77 FR 42841.

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.

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.

See, e.g., BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.5 (“a 0.3 deciview improvement may merit a stronger weighting in one case versus another, so one “bright line” may not be appropriate.”)

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,

and at a level that we consider cost-effective. Although we recognize that NPS's estimates produce even lower values than those from our proposal, we have not updated our own cost estimates to reflect NPS's comments since we already consider SCR to be 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.

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 NO

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.

See, e.g., BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.E.2. (“You should provide a justification for adopting the technology that you select as the `best' level of control, including an explanation of the CAA factors that led you to choose that option over other control levels.”)

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 NO

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 PM

and SO

BART evaluations as were used for the NO

BART evaluation, yet EPA accepted the approach for only PM

and SO

Response:

We disagree that we accepted ADEQ's approach for PM

and SO

Although we did not disapprove ADEQ's PM

and SO

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 PM

and SO

as for NO

and that these analyses exhibit the same deficiencies we have noted elsewhere for the NO

BART determinations. However, we did not disapprove the PM

and SO

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 PM

, 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 PM

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

Assuming that a more stringent control technology could achieve 100 percent PM control and eliminate this entire visibility impact, a more stringent PM

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 PM

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.

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

With regard to SO

, 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 PM

and SO

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

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.”

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.

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

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.

In order for this type of comparison to be meaningful, the cost estimates for these facilities must be performed in a consistent manner. Without an `apples-to-apples' comparison of costs, it is impossible to draw rational conclusions about the reasonableness of the costs of compliance for particular control options. Use of the CCM methodology is intended to allow a fair comparison of pollution control costs between similar applications for regulatory purposes. This is why the BART guidelines specify the use of the CCM where possible

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.

See

Id.

section IV.D.4.f (“A reasonable range [of cost-effectiveness values] would be a range that is consistent with the range of cost-effectiveness values used in other similar permit decisions over a period of time.”)

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

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.

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.

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

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 NO

BART determinations was largely based on its concern with ADEQ's reliance on the Western Regional Air Partnership (WRAP) modeling.

By contrast, another commenter asserted that since the facilities' modeling results indicated that controls would contribute to visibility improvements in multiple Class I areas, ADEQ should consider these benefits rather than looking at the benefits in only a single Class I area. The commenter believes that overlooking significant visibility benefits in this way considerably understates the overall benefit of controls to improved visibility. The commenter contended that the procedure followed by ADEQ is not a sufficient basis for making BART determinations for sources with substantial benefits across many Class I areas.

Response:

EPA's proposed disapproval of ADEQ's NOx BART determinations was not based on any concern with the WRAP modeling

protocol, upon which ADEQ relied for its BART analyses. On the contrary, we found that the modeling procedures relied upon by ADEQ were “in accord with EPA guidance.”

However, we noted that ADEQ's use of the results of modeling in making BART decisions was “problematic in several respects.”

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.

77 FR 42841.

Id.

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.”

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.”

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.

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

See 70 FR 39126.

See, e.g., 76 FR 52388, 52430 (San Juan Generating Station); 77 FR 51620, 51631-51632 (Four Corners Power Plant); and 77 FR 51915, 51922-51923 (Roseton and Danskammer Generating Stations).

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.”

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.”

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. * * *”

This requires consideration of the visibility improvement from BART applied to the facility as a whole.

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

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

Id.

section IV.D.5.

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

approved the use of the same monthly-varying background ammonia concentrations, which were based on actual field measurements, in running the CALPUFF model for two other sites located close to Cholla and that were used by ADEQ in its analysis. These values range from 1 ppb during the summertime to 0.2 ppb during cold winter months. EPA has also stated in response to comments on the Montana regional haze FIP (77 FR 57864, 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

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.

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

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

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.

Since this method accounts only for ammonium, and not remaining free gaseous ammonia, the total ammonia originally available to form visibility-impairing compounds may actually be higher. Because of uncertainty in the “back-calculation” method, and criticism of it, EPA relied on it in the FCPP FIP only as corroboration for the IWAQM default of 1 ppb.

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.

Mark E. Sather

et al.,

“Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern Oklahoma, USA”.

Journal of Environmental Monitoring,

2008, 10, 1319-1325, DOI: 10.1039/b807984f.

See, e.g., Proposed Rule: Source Specific Federal Implementation Plan for Implementing Best Available Retrofit Technology for Four Corners Power Plant: Navajo Nation Technical Support Document, pages 59-61, 65-66, 68-73.

Id.

at page 68.

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. Visibility-impairing ammonium sulfate and ammonium nitrate are formed from ammonia, SO

, and NO

. Therefore the ammonium represents part of the pool of ammonia that could be available to interact with the SO

and NO

from a facility and contribute to visibility impacts, and should be accounted for in estimating ammonia background concentrations. In several of the research papers

cited by commenter APS, the amount of measured ammonium is comparable to and at times much greater than the amount of ammonia.

RoMANS—Rocky Mountain Atmospheric Nitrogen & Sulfur Study,

William C. Malm and Jeffrey L. Collett. National Park Service, CSU-CIRA, Fort Collins, CO. ISSN 0737-5352-84. October 2009.

http://www.nature.nps.gov/air/Studies/romans.cfm

. Table 3.9 on p.3-38 shows ammonium comparable to or about half of ammonia, depending on measurement method. It also shows that the spring time mean and maximum ammonium are about 0.22 and 0.57 µg/m

, respectively, or 0.38 and 0.78 ppb; and the mean and maximum ammonia are about 0.38 and 1.0 µg/m

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 µg/m

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

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.

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,

cited by commenter APS, describes a surprisingly high spatial variability in ammonia concentrations. The two monitors in the Cameron area south of NGS (and east-southeast of the Grand Canyon) showed consistent concentration differences despite being less than five miles from each other; this may be due to relatively localized ammonia sources. These sites also showed consistently lower measurements than the Halls Crossing site, north of NGS (and southwest of Capitol Reef). The range in concentrations was comparable to the range seen between the AECOM values at the low end, and EPA's back-calculated values at the high end. Unfortunately, because of the variability and its unknown causes, the data collected did not lead to a clear picture of appropriate and representative ammonia background concentrations to use with CALPUFF.

“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.

In any case, as mentioned above, some nearby monitored data reported in Sather's paper show considerably higher ammonia than recommended by some commenters, so it is not clear that values lower than 1 ppb should be used. EPA concludes that there is not a compelling case for using ammonia background concentrations other than the 1 ppb found in the only authoritative guidance document available on this topic and supported by the FLMs.

Comment:

Two commenters (APS and AUG) noted that the RHR and BART Guidelines are silent regarding whether visibility improvements should be modeled on a unit-by-unit basis or a plant-wide basis, and there is no legal requirement that units be modeled aggregately. Given that visibility benefits are approximately additive, the commenters contend that it is unreasonable for EPA to conclude that

ADEQ's BART analyses failed to consider any significant visibility effect merely because ADEQ modeled the units separately. In addition, AUG notes that it is necessary to determine the effects of emissions from units individually so that projected visibility impacts can be considered in light of costs and other impacts associated with BART-candidate controls for that particular unit, and modeling units together could obscure these comparisons.

Response:

Considering the visibility benefits of multiple units together does not preclude a state from also considering individual unit benefits, as well as individual unit costs. EPA does not agree that modeling the units together obscures these other comparisons. Rather, the benefit of controls for an entire BART-eligible source is a factor that should be considered along with those other comparisons. In any case, whether considered unit by unit or all units together, visibility improvement has no effect on the assessment of cost-effectiveness as measured by dollars per ton of reductions.

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

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

Comment:

One commenter (NPS) concurred with ADEQ's and EPA's proposals for BART at Apache Unit 1.

Response:

We acknowledge NPS's concurrence.

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

a. ADEQ's BART Analysis and Determination for NO

Comment:

One commenter (Earthjustice) commended EPA's decision to disapprove ADEQ's NO

BART determination for Apache Units 2 and 3. The commenter stated that EPA correctly concluded that ADEQ's BART determination for NO

inflated the costs of more-stringent NO

controls by including costs not allowed by EPA Cost Control Manual, provided little reasoning about the visibility benefits of additional NO

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.

As explained in our proposal, a firm primarily engaged in the generation, transmission, and/or distribution of electric energy for sale is small if, including affiliates, the total electric output for the preceding fiscal year did not exceed 4 million megawatt hours. 77 FR 42867. AEPCO sold under 3 million megawatt hours in 2011 and is therefore a small entity.

b. ADEQ's BART Analysis and Determination for PM

Comment:

One commenter (NPS) agreed with ADEQ and EPA that BART for PM

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

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

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 PM

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 PM

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 PM

. 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 PM

reductions from these units.

Therefore, we proposed to approve ADEQ's determination that BART for PM

at Apache Units 2 and 3 is upgrades to the existing ESPs and a PM

emissions limit of 0.03 lb/MMBtu.

77 FR 42847.

One commenter asserted that this limit is too lenient, since other coal-fired units are achieving lower limits, based on test data submitted by various utilities to EPA as part of an Information Collection Request (ICR) for the Mercury and Air Toxics (MATS) Rule.

EPA disagrees with this comment. The MATS Rule establishes an emission standard of 0.030 lb/MMBtu filterable PM (as a surrogate for toxic non-mercury metals) as representing Maximum Achievable Control Technology (MACT) for coal-fired EGUs.

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.

The BART Guidelines provide that, “unless there are new technologies subsequent to the MACT standards which would lead to cost-effective increases in the level of control, you may rely on the MACT standards for purposes of BART.”

Therefore, we are approving ADEQ's determination that a PM

limit of 0.03 lb/MMBtu represents BART for these units.

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.

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

See Memorandum from Jeffrey Cole (RTI International) to Bill Maxwell (EPA) regarding “National Emission Standards for Hazardous Air Pollutants (NESHAP) Maximum Achievable Control Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating Units for Final Rule” (Dec. 16, 2011).

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

c. ADEQ's BART Analysis and Determination for SO

Comment:

One commenter (Earthjustice) disagreed with EPA's proposal to approve ADEQ's SO

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 five-

factor BART analysis. The commenter argues that an SO

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 SO

removal efficiencies of 98 percent and should have been investigated.

Another commenter (NPS) noted that that AEPCO's BART reports indicate that uncontrolled SO

emissions are 0.69 lb/MMBtu, and that the ADEQ BART proposal would reduce SO

emissions by 78 percent down to 0.15 lb/MMBtu. Based on the SO

control data submitted by the commenter, the commenter asserted that other BART upgrades are achieving higher removal efficiencies and/or lower SO

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 SO

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 SO

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 SO

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 SO

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 SO

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).

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 cost-effective scrubber upgrades designed to improve the system's overall SO

removal efficiency.

In August 2009, AEPCO provided information to ADEQ concerning potential scrubber upgrades at Apache Units 2 and 3.

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.”

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

See Apache Title V Permit Technical Support Document (2007), Table 9; Title V Permit (2007), Attachment B, section II.E.1.a.

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

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

Id.

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].

40 CFR Part 51, Appendix Y, section IV.4.a., note 15.

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 NO

Comment:

One commenter (Earthjustice) commended EPA's decision to disapprove ADEQ's NO

BART determination for Cholla Units 2, 3 and 4. The commenter stated that EPA correctly concluded that ADEQ's BART determination for NO

inflated the costs of more-stringent NO

controls by including costs not allowed by the Manual, and substantially underestimated the visibility benefits of additional NO

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.

Response:

As explained in our proposal and elsewhere in this document, we agree that ADEQ's BART analyses and determinations for NO

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 PM

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 PM

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 PM

10.

According to the commenter, the BART Guidelines' exemption from a full five-factor analysis for the most stringent control technology is not applicable in this case because improvements to the fabric filters are possible and a lower emission rate is thus achievable.

The latter commenter (Earthjustice) stated that had EPA conducted the PM

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 PM

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 (H

). 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.

Also, as noted above, the recent EGU MATS rule sets a PM emissions standard of 0.03 lb/MMBtu, and the BART Guidelines provide that, “unless there are new technologies subsequent to the MACT standards which would lead to cost-effective increases in the level of control, you may rely on the MACT standards for purposes of BART.”

Therefore, we are finalizing our proposed approval of ADEQ's BART determination for PM

at Cholla Units 2, 3 and 4.

77 FR 9450 (February 16, 2012) (codified at 40 CFR 60.42Da).

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

c. ADEQ's BART Analysis and Determination for SO

Comment:

Citing various examples of lower SO

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 SO

control data submitted by the commenter, the commenter asserted that other BART upgrades are achieving higher removal efficiencies and/or lower SO

limits.

Another commenter (Earthjustice) disagreed with EPA's proposal to approve ADEQ's SO

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 SO

BART determinations based on unsupported speculation that the outcome would be the same if EPA performed the BART analysis required by the RHR, although EPA identified nothing in the docket to support its claim that a full BART analysis would have yielded the same result. The commenter states that EPA cannot speculate that it would reach the same conclusion as ADEQ, and it must undertake an independent full five-factor BART analysis.

The commenter further stated that ADEQ's SO

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 SO

emission limits are achievable and cost-effective at Cholla Units 2, 3 and 4. According to the commenter, a report submitted with the comments (the “Stamper report”)

shows that a proper BART determination for Cholla would have found that 98 percent SO

control efficiency achieving a 0.04 lb/MMBtu emission limit is BART for the units, and that even with the less-stringent 95 percent SO

control efficiency that is the basis of ADEQ's BART determinations, ADEQ should have required an SO

emission limit of 0.10 lb/MMBtu because 0.15 lb/MMBtu limit does not reflect 95 percent SO

removal.

Attachment 1 to Earthjustice Comments, Technical Support Document to Comments of Conservation Organizations, Proposed Arizona Regional Haze Partial SIP Approval and Partial FIP SO

and NO

BART Determinations for Cholla Units 2, 3 and 4 (September 17, 2012), prepared by Victoria Stamper.

Another commenter (APS) noted that the SO

content of the coal source for the Cholla plant is up to 3.0 lbs/MMBtu, and the maximum rate of removal that will be continuously achievable after the plant upgrades its scrubbers is 95 percent. Therefore, the commenter asserts that 0.15 lb/MMBtu is the

maximum achievable SO

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 SO

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.

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.

The current coal contract for these units indicates that the typical sulfur content of this coal is equivalent to 2.4 lb/MMBtu SO

and can be as high as 3.0 lb/MMBtu.

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.”

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.

See “Additional APS Cholla BART response”, Appendix B.

See, e.g., “APS Cholla Unit 2 BART report”, Table 2-2.

See “Additional APS Cholla BART response”, Appendix B, Section 6.2.

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

APS's comments on the proposal indicate that the company intends to upgrade the existing SO

controls at Unit 2 to a new wet flue gas desulfurization (FGD) system, identical to those already installed on Units 3 and 4.

APS further explained that:

“Comments of Arizona Public Service Company”, page 27.

The coal source for [Cholla] is El Segundo and Lee Ranch coal with an SO

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 SO

emission limit achievable at Cholla on a continuous basis is, therefore, 0.15 lb/mmBtu.

Id.

page 63.

Given this information, EPA finds that the ADEQ BART limit of 0.15 lb/MMBtu represents BART for SO

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 SO

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 SO

for the El Segundo coal and 1.64 lb/MMBtu of SO

for the Lee Ranch Coal.

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 SO

. 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 SO

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.”

See “Additional APS Cholla BART response”, Appendix B, Section 6.2.

4. ADEQ's BART Analyses and Determinations for Coronado Units 1 and 2

a. ADEQ's BART Analysis and Determination for NO

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 cost-effectiveness for the various candidate controls and the various Class I areas.

• ADEQ does not indicate whether it considered any cost thresholds to be reasonable or expensive in analyzing the costs of compliance for the various control options.

Similarly, another commenter (Earthjustice) supported EPA's disapproval of ADEQ's NO

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 NO

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 NO

BART determinations for Coronado.

Response:

We agree that ADEQ's BART analysis for NO

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 NO

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 NO

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 NO

did not comply with the requirements of the RHR or the BART Guidelines. Therefore, we are finalizing our disapproval of these NO

BART determinations, including the determinations at Coronado Units 1 and 2.

b. ADEQ's BART Analysis and Determination for PM

Comment:

One commenter (NPS) agreed with EPA's proposal to approve ADEQ's PM

BART determination for

Coronado Units 1 and 2, noting that that emissions of PM

from Coronado Units 1 and 2 are currently controlled by hot-side ESPs and that, in terms of the consent decree, SRP is required to optimize its ESPs to achieve a PM

emission rate of 0.030 lb/MMBtu.

Another commenter (SRP) stated that EPA's approval of the Arizona BART determination for PM

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 PM

limit in the recently promulgated MATS Rule will be more stringent than the PM

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 PM

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 PM

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 PM

. According to the commenter, the Sahu report demonstrates that nearly 150 EGUs across the nation with a variety of PM controls achieve emission rates lower than 0.03 lb/MMBtu. The commenter asserted that neither ADEQ nor EPA provided any explanation why Coronado Units 1 and 2 could not similarly meet a lower emission limit.

Response:

EPA acknowledges that ADEQ did not perform a rigorous five-factor BART analysis for PM

at Coronado. However, a full five-factor analysis would be very unlikely to result in a change of control technology for PM

10.

Modeling of visibility impacts from direct PM

emissions has shown very small impairment for EGU PM

emissions in comparison to visibility impairment resulting from SO

and NO

emissions. The existing hotside ESPs at Coronado Units 1 and 2 control PM

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.

The consent decree also requires Coronado to install and conduct performance specification testing of a particulate matter CEMS (PMCEMS).

Consent Decree in

United States

Salt River Project,

CV 08-1479-PHX-JAT (entered Dec. 19, 2008).

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 PM

at these units.

c. ADEQ's BART Analysis and Determination for SO

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 SO

removal efficiency of at least 95 percent or a 30-day rolling average SO

emissions rate of no greater than 0.080 lb/MMBtu. The commenter added that EPA proposed to approve ADEQ's BART SO

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 SO

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 SO

BART determination. The commenter states the approval is contrary to the RHR because ADEQ's BART analyses are not supported by a valid five-factor analysis. The commenter states that EPA cannot speculate that it would reach the same conclusion as ADEQ, and it must undertake an independent full five-factor BART analysis, which the commenter believes would result in a SO

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 SO

removal efficiencies of 98 percent and the use of low-sulfur coals, which can further reduce SO

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 SO

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 SO

or 95 percent reduction of SO

across the FGD, both

over a rolling 30-day basis.

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.

Consent Decree in

United States

Salt River Project,

CV 08-1479-PHX-JAT (entered Dec. 19, 2008).

We also note that the recently promulgated EGU MATS rule, which uses an SO

limit as an acceptable surrogate for limiting the emissions of hazardous acid gases, has set the limit at 0.20 lb/MMBtu of SO

for existing EGUs like Coronado Units 1 and 2.

77 FR 9490 (February 16, 2012), codified in Table 2 to Subpart UUUUU of 40 CFR Part 63.

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

1. Selection of Baseline Period

Comment:

Several commenters expressed disagreement with our general approach to the selection of baseline periods. One commenter (NPS) stated a general preference for the use of a baseline period that represents pre-control emissions, as advised in the BART Guidelines, to estimate baseline emissions for the purpose of calculating the average cost-effectiveness of the complete control system (e.g., combustion controls plus SCR). The commenter believes that this avoids any biasing of the calculations by sources that install combustion controls during the BART evaluation process. NPCA asserted that the “proper” baseline for BART determinations is 2001-2004. ADEQ asserted EPA violated the RHR provision in 51.308(d)(2)(i), which specifies the period for establishing baseline visibility conditions as 2000-2004, by using the period between 2008 and 2011 as a baseline period for EPA's BART analyses.

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,

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:

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

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.

BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d.1

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.”

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.

CAA 169A(g)(2), 42 U.S.C. 7491(g)(2); see also 40 CFR 52.308(e)(ii)(A).

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.

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.

See, e.g., SIP Appendix D at 4; Apache Unit 2 BART analysis at 2-2; Cholla.

However, having proposed to disapprove Arizona's BART determinations for NO

on other grounds, we were obligated to conduct our own five-factor BART analyses for NO

for these sources. At the time we conducted our analysis in 2011 and 2012, several of these units had been retrofitted with additional NO

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.

In addition, during this time period, Cholla completed its transition to a different coal with much higher potential NO

emissions.

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.

77 FR 42859, 42861. Although no new NO

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.

77 FR 42856, 42859, 42861.

77 FR 42861.

With respect to Coronado Unit 2, we also took into account the federally-enforceable emissions limits set by a Consent Decree between the United States and SRP, which was entered in 2008.

Again, this is consistent with the BART Guidelines, which provide that:

Consent Decree in

United States

Salt River Project,

CV 08-1479-PHX-JAT (entered December 19, 2008).

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.

BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d.2.

Consistent with this provision, for Coronado we used the consent decree-mandated NO

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 NO

and SO

controls was required by a consent decree. With respect to Cholla, the installation of newly installed NO

and SO

controls coincided with increases in potential emissions of these pollutants resulting from a change in coal supply.

Therefore, the more recent baseline is likely to be more representative of future operating conditions at these units.

See Docket Item B-09, “Additional APS Cholla BART response”, Appendix B, Section 6.2.

Contrary to the assertions of some commenters, use of updated baselines did not unfairly penalize those sources that reduced their NO

emissions in advance of a final BART determination. Rather, the updated baseline effectively

lowered

the baseline visibility impacts from these sources by reducing the baseline emissions. As a result, the projected benefits of additional controls

were less than if we had used the original baseline. This approach is consistent with the RHR and the BART Guidelines because it accurately reflects controls in place at the time we performed our BART analysis. Nonetheless, in order to address commenters' concerns about the effect of the updated baselines on our proposed determinations, we have also taken into account the original baseline periods considered by ADEQ, as part of the supplemental cost analyses described below.

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.

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

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.

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.

AZ Regional Haze SIP at page 39.

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.”

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.

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

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 short-term emission spikes by using the most recent thirty boiler-operating-day value from the non-operating unit. Otherwise, averaging across units would not be possible during such periods, since the emissions value from the non-operating unit would be zero since it is not operating.

Comment:

One commenter (Earthjustice), based on a report submitted with the comments (the “Sahu report”), stated that SCR can achieve greater NO

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 NO

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 NO

emission limits as low as 0.03 lb/MMBtu. The commenter cited several Prevention of Significant Deterioration (PSD) permit limits based on BACT determinations, including a 0.03 lb/MMbtu limit at Plant Washington, issued by Georgia Environmental Protection Division, and 0.035 lb/MMBtu for Desert Rock, issued by EPA Region 9. Accordingly, the commenter believes that EPA should have analyzed SCR with an emission limit of 0.04 lb/MMBtu because this level is achievable at 90 percent control for each of the units.

Response:

We agree with the information provided by the commenters that SCR technology has the potential to achieve 90 percent and greater rates of removal, as well as achieve emission rates of less than 0.05 lb/MMBtu. However, we disagree with the commenter's assertion that emission limits associated with BART must meet the lowest emission rate achieved with

that technology at any coal-fired power plant. The RHR provides that:

The determination of BART must be based on an analysis of the best system of continuous emission control technology available and associated emission reductions achievable for each BART-eligible source that is subject to BART * * *

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

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”

and that “[t]o complete the BART process, you must establish enforceable emission limits that reflect the BART requirements * * *”.

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.

BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.3.

Id.

section V.

Comment:

Several commenters (APS, AEPCO, SRP, AUG, Pacificorp) note that the proposed NO

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 NO

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 NO

limit below 0.06 lb/MMBtu is not achievable through retrofit of SCR on coal-fired electric generating units.

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.

Citing 76 FR 1109, 1115, January 7, 2011; EPA, Transport Rule Engineering Feasibility Response to Comments, Docket ID No. EPA-HQ-OAR-2009-0491-4529, at 13, July 6, 2011.

Response:

We do not agree that our consideration of a NO

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 top-down BACT determination process and the five-step BART determination process, we note that a BACT determination is based almost exclusively on cost-effectiveness, and does not, for example, take visibility improvement at Class I areas into account.

We note that a Class I area impact analysis must be performed by certain PSD projects as part of the permit application process. However, the visibility results are not used in the BACT determination, which is typically determined prior to performing the visibility modeling, and are not used to determine the appropriate level of control except in those cases where the visibility impact is sufficiently high to warrant mitigation measures that end up involving additional emission reductions.

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 NO

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

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' ”

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,

the recently promulgated NSPS Subpart Da does consider post-combustion controls such as SCR.

BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.1, n. 13.

Id.

section IV.D.1.

40 CFR Part 60, Subpart Da.

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,”

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,

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 NO

emission rates in the range of 0.047 to 0.068 lb/MMBtu, which are emission rates lower than the Subpart Da standards.

Id.

section IV.C.

Or subcategories, which Subpart Da does not establish except for “new” and “modified” units.

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 NO

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 NO

, the Proposed Rule is flawed and must be withdrawn.

The commenters also note that the RHR also established presumptive BART emission limits for NO

emissions from fossil fuel-fired units through notice-and-comment rulemaking. The presumptive NO

emissions limits for coal-fired EGUs vary according to individual source characteristics, including fuel firing configuration (tangential/wall-fired, opposed wall-fired, cyclone) and type of fuel burned (bituminous, sub-bituminous, lignite, etc.). Commenters also 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 NO

limits. Because Apache, Cholla and Coronado all have access to and have historically burned both bituminous and sub-bituminous coal,

there is no single presumptive NO

limit that applies to any of these units.

Therefore, rather than rely upon the numerical values of the presumptive NO

limits listed in the BART Guidelines, we have considered the technological basis for presumptive NO

BART limits, such as the use of combustion control technology, boiler type, and coal type, as part of the five-factor analysis we performed for each facility. For each source, we considered combustion controls as a potential option for BART.

See, e.g., Final Report, Apache Unit 2 BART Analysis, Table 3-1 (December 2007); Cholla Unit 2 BART Report, page ES-2; SRP Comments on Proposed Rule (September 2012), RMB Technical Memorandum, page 3.

See BART Guidelines, 40 CFR Part 51, Appendix Y, Table 1.

At Apache Units 2 and 3, we considered combustion controls (LNB plus OFA) as one of the control scenarios. At Cholla and Coronado, combustion controls were considered as part of the baseline emission rate and were a potential BART option in the event that the five-factor analysis indicated that no additional controls beyond the baseline were justified.

We also disagree with commenters' assertions that our selection of non-presumptive BART technology as BART is flawed or presumptively incorrect. In the BART Guidelines EPA explained that:

For coal-fired EGUs greater than 200 MW located at greater than 750 MW power plants and operating without post-combustion controls (

i.e.

SCR or SNCR), we have provided presumptive NO

limits, differentiated by boiler design and type of coal burned. You may determine that an alternative control level is appropriate based on a careful consideration of the statutory factors. For coal-fired EGUs greater than 200 MW located at power plants 750 MW or less in size and operating without post-combustion controls, you should likewise presume that these same levels are cost-effective. You should require such utility boilers to meet the following NO

emission limits, unless you determine that an alternative control level is justified based on consideration of the statutory factors.

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

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.

70 FR 39132.

Thus, the establishment of presumptive BART limits, and the corresponding technology upon which those limits are based, does not preclude states or EPA from setting limits that differ from those presumptions. The five-factor analysis we performed for these facilities demonstrates that, taking into consideration the expected remaining useful life and the existing controls present at the facilities, SCR is cost-effective, results in the most visibility improvement of all feasible control technologies, and that these factors are not outweighed by SCR's potential energy and non-air quality environmental impacts. As a result, regardless of the appropriateness of SCR

as a control technology for most units on a national scale, our five-factor analyses establish that NO

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.

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.

Document ID: EPA-R09-OAR-2012-0021-0008, File name: G-15_MODELING_FILES_EGU_BART_Costs_Apache_Cholla_Coronado_FINAL2.

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.

These databases include 2004 and 2006 industry cost estimates prepared for the Midwestern Ozone Group (MOG), and a proprietary in-house database maintained by engineering firm Sargent & Lundy (S&L). The MOG information was cross-referenced 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 NO

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.”

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix52A.pdf.

Comment:

Several commenters contended that where specific knowledge is available, the CCM is oriented to allow and provide for the use of such information. The commenters also note that the RHR explicitly provides that the cost analysis should take into account any site-specific information that affect the costs of a particular BART technology option, and the

Corn Growers

court explained that BART determinations must be made on a source-specific basis.

Response:

While we agree that BART determinations must be made on a source-specific basis, we do not agree that site-specific information is required for all aspects of a BART analysis. Nonetheless, in order to address commenters' concerns that our proposal was based on cost information that was insufficiently site-specific and that the costs of the SCR with LNB and OFA control option, in particular, are not representative of actual installation costs at these facilities, we have performed a supplemental cost analysis. The supplemental cost analyses for each facility are described in Section IV.D of this document, and incorporate much of the cost information provided by the facilities in their comments. In performing this supplemental cost analysis, we have adopted a “hybrid” approach that relies on cost estimates provided by the facilities for certain line items, but still retains the use of the CCM methodology as described in the following response.

Comment:

Several commenters stated that EPA's cost estimating techniques are flawed and its reliance on the outdated EPA CCM led to underestimates of costs. Several of these commenters noted that EPA claimed that owner's costs, surcharges and Allowance for Funds Used During Construction (AFUDC) are not allowed by EPA's CCM and refute that these costs are not allowed by the Manual. The commenters state that while the Manual does not have specific line items for owner's costs and surcharges, it discusses some of the items that roll up into these categories. APS, for example, states that:

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.

APS comments, page 12.

APS also notes that there is a line item for AFUDC in the Manual but provides that it is assumed to be zero percent, but that in its experience AFUDC is a real cost and is never zero percent. In

addition, the commenters state neither the CAA nor the BART Guidelines require the Manual to be used to determine the costs of compliance.

Response:

With regard to owner's costs and surcharges, we agree with commenters' assertions that the CCM does discuss some of the items that roll up into these line items as they have described in comments. For the control option of SCR with LNB and OFA, for example, the CCM does provide for “Engineering and Home Office Fees”

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.

As described in Table 2-5 of the CCM, Engineering and Home Office Fees represent 10 percent of purchased equipment costs.

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.

Therefore, in reviewing other BART determinations, EPA has consistently excluded AFUDC.

CCM (Tables 1.4 and 2.5 show AFUDC value as zero).

See, e.g., 77 FR 20894, 20916-17 (Apr. 6, 2012) (explaining in support of the North Dakota Regional Haze FIP, “we maintain that following the overnight method ensures equitable BART determinations * * *.”); 76 FR 52388, 52399-400 (August 22, 2011) (explaining in the New Mexico Regional Haze FIP that the Manual does not allow AFUDC).

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.

EPA Air Pollution Cost Control Manual, Sixth Edition page 1-3.

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.

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.

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.

Approved Materials Source List, Fly Ash, Natural Pozzolan, and Lime, Revised July 10, 2012, available at

http://www.azdot.gov/Highways/Materials/.

See 77 FR 42853-4284, TSD at 38.

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 NO

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.

Citing

Corn Growers,

291 F.3d at 6-7 (finding that EPA's original 1999 regional haze rules had improperly divorced consideration of the BART visibility benefits factor from the other BART factors).

Response:

EPA does not agree with this comment. The RHR and the BART Guidelines allow the reviewing authority (State, Tribe, or EPA) the discretion to determine how to weigh and in what order to evaluate the

statutory factors (cost of compliance, the energy and non-air quality environmental impacts of compliance, any existing pollution control technology in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology), as long as the 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.

In this case, having disapproved the state's BART determinations for NO

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 NO

at any of the sources.

101

See BART Guidelines, 40 CFR Part 51, appendix Y, section IV.E.2.

100

Central Arizona Water Conservation Dist. v. EPA, 990 F.2d 1531, 1541 (9th Cir. 1993).

101

See 77 FR 42853-4284, TSD at 38.

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 NO

modeling by scaling tropospheric column NO

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 NO

closer to background levels.

Response:

While the facilities considered for BART control are not the only NO

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 NO

benefit. However, to assess visibility impacts, the model used must account for the formation of visibility-impairing ammonium nitrate particles. Under the BART Guidelines, CALPUFF is the recommended model that incorporates this nitrate chemistry. Alternative models could potentially be used if they had 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 NO

emissions to evaluate the effects of changing this one pollutant.

Response:

EPA acknowledges the comment. It was our intention to estimate visibility impacts accurately and transparently so that one could more easily compare results to earlier applications of CALPUFF and clearly understand the effect of old versus revised IMROVE equations (methods 6 and 8) as well as alternative natural background conditions. We modeled all pollutants together in order to account for chemical interactions among the various pollutants and also the nonlinear dependence of deciviews upon extinction.

Comment:

One commenter (APS) stated that EPA's proposal noted that it is appropriate to use Method 6a, 6b, 8a or 8b in CALPOST within the CALPUFF model, yet EPA inappropriately rejected

ADEQ's use of Method 6a in its own analysis and instead used Method 8b, which yielded higher predicted visibility improvements in Class I areas.

Response:

EPA did not reject ADEQ's use of visibility method 6a, which remains a viable method for past visibility modeling work under an agreed upon protocol. Method 6a comprises CALPOST Method 6, the old IMPROVE equation for translating pollutant concentration into visibility impacts, and annual average (the “a”) natural background concentrations. However, for new visibility modeling, such as EPA performed for the FIP, method 8b is preferable. Method 8b comprises CALPOST Method 8, the revised IMPROVE 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.

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

Comment:

One commenter (APS) objected to EPA shifting the CAA's mandate to compare costs and benefits under the BART program to an assessment of “cost-effectiveness” ($/ton) without specifying the threshold level of what is cost-effective. APS also noted that in the absence of a specific threshold for cost-effectiveness, the FLMs have referred to a benchmark of $20 million per deciview as the upper limit. The commenter also presented data showing the incremental costs of going from LNB/OFA to SNCR or SCR to be over $20 million per deciview for Cholla.

Response:

The commenter is correct that the BART Guidelines list the $/deciview ratio as an additional cost-effectiveness metric that can be employed along with $/ton for use in a BART evaluation, and we have included this information in our proposal. While the FLMs have indicated that they consider $20 million/dv to be a benchmark for average cost-effectiveness, we note that the BART Guidelines do not require the development of a specific threshold. The BART Guidelines, however, require that cost-effectiveness be calculated in terms of annualized dollars per ton of pollutant removed, or $/ton.

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