[Federal Register Volume 77, Number 140 (Friday, July 20, 2012)]
[Proposed Rules]
[Pages 42833-42871]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-17659]
[[Page 42833]]
Vol. 77
Friday,
No. 140
July 20, 2012
Part II
Environmental Protection Agency
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40 CFR Part 51
Approval, Disapproval and Promulgation of Air Quality Implementation
Plans; Arizona; Regional Haze State and Federal Implementation Plans;
Proposed Rule
Federal Register / Vol. 77 , No. 140 / Friday, July 20, 2012 /
Proposed Rules
[[Page 42834]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 51
[EPA-R09-OAR-2012-0021, FRL-9700-1]
Approval, Disapproval and Promulgation of Air Quality
Implementation Plans; Arizona; Regional Haze State and Federal
Implementation Plans
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing to approve partially and disapprove partially
a revision to Arizona's State Implementation Plan (SIP) to implement
the regional haze program for the first planning period through July
31, 2018. This proposed action addresses only the portion of the SIP
related to Arizona's determination of Best Available Retrofit
Technology (BART) to control emissions from eight units at three
electric generating stations: Apache Generating Station, Cholla Power
Plant and Coronado Generating Station. EPA proposes to approve the
State's determination that these sources are subject to BART, and to
approve the emissions limits for sulfur dioxide (SO2) and
particulate matter (PM10) at all the units. EPA proposes to
disapprove the BART emissions limits for nitrogen oxides
(NOX) at most of the units. EPA also proposes to promulgate
a Federal Implementation Plan (FIP) containing new emissions limits for
NOX as well as BART compliance requirements for the three
facilities. We encourage the State to submit a revised SIP to replace
all portions of our FIP, and we stand ready to work with the State to
develop a revised plan. The Clean Air Act (CAA) requires states to
prevent any future and remedy any existing man-made impairment of
visibility in 156 national parks and wilderness areas designated as
Class I areas. Arizona has a wealth of such areas. The three power
plants affect visibility at 18 national parks and wilderness areas,
including the Grand Canyon, Mesa Verde and the Petrified Forest. The
State and EPA must work together to ensure that plans are in place to
make progress toward natural visibility conditions at these national
treasures.
DATES: Written comments must be received by the designated contact at
the address below on or before August 31, 2012.
ADDRESSES: See the SUPPLEMENTARY INFORMATION section for further
instructions on where and how to learn more about this proposal, attend
a public hearing, or submit comments.
FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9,
Planning Office, Air Division, Air-2, 75 Hawthorne Street, San
Francisco, CA 94105. Thomas Webb can be reached at telephone number
(415) 947-4139 and via electronic mail at webb.thomas@epa.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. General Information
A. Definitions
B. Docket
C. Instructions for Submitting Comments to EPA
D. Submitting Confidential Business Information
E. Tips for Preparing Your Comments
F. Public Hearings
II. Overview of Proposed Actions
III. Regional Haze Background
A. Description of Regional Haze
B. History of Regional Haze Regulations
C. Roles of Agencies in Addressing Regional Haze
IV. Requirements for Regional Haze Implementation Plans
A. Regional Haze Rule
B. The Deciview
C. Best Available Retrofit Technology
D. The Grand Canyon Visibility Transport Commission and Section
309
V. SIP and FIP Background
A. History of State Submittals and EPA Actions
B. EPA's Authority To Promulgate a FIP
VI. EPA's Evaluation of Arizona's BART Analyses and Determinations
A. Arizona's Identification of BART Sources
B. Arizona's BART Control Analysis
1. Cost of Compliance
2. Energy and Non-Air Quality Environmental Impacts
3. Existing Pollution Control Technology
4. Remaining Useful Life of the Source
5. Degree of Visibility Improvement
C. Arizona's BART Determinations
1. Apache Unit 1
a. BART for NOX
b. BART for PM10
c. BART for SO2
2. Apache Units 2 and 3
a. BART for NOX
b. BART for PM10
c. BART for SO2
3. Cholla Units 2, 3 and 4
a. BART for NOX
b. BART for PM10
c. BART for SO2
4. Coronado Units 1 and 2
a. BART for NOX
b. BART for PM10
c. BART for SO2
D. Enforceability of BART Limits
VII. EPA's Proposed FIP Actions
A. EPA's BART Analyses and Determinations
1. Costs of Compliance
2. Energy and Non-Air Environmental Impacts
3. Pollution Control Equipment in Use at the Source
4. Remaining Useful Life of the Source
5. Degree of Improvement in Visibility
a. Modeling Protocol
b. Baseline Emissions
c. Emission Reductions for Alternative Controls
d. Visibility Impacts
B. EPA's FIP BART Determinations
1. Apache Units 2 and 3
a. Costs of Compliance
b. Visibility Improvement
c. EPA's BART Determinations
2. Cholla Units 2, 3 and 4
a. Costs of Compliance
b. Visibility Improvement
c. EPA's BART Determinations
3. Coronado Units 1 and 2
a. Costs of Compliance
b. Visibility Improvement
c. EPA's BART Determinations
C. Enforceability Requirements
VIII. Summary of EPA's Proposed Action
IX. Statutory and Executive Order Reviews
I. General Information
A. Definitions
For the purpose of this document, we are giving meaning to certain
words or initials as follows:
(1) The words or initials Act or CAA mean or refer to the Clean Air
Act, unless the context indicates otherwise.
(2) The initials ADEQ mean or refer to the Arizona Department of
Environmental Quality.
(3) The initials AEPCO mean or refer to Arizona Electric Power
Cooperative.
(4) The initials AFUDC mean or refer to allowance for funds used
during construction.
(5) The initials APS mean or refer Arizona Public Service Company.
(6) The words Arizona and State mean the State of Arizona.
(7) The initials BART mean or refer to Best Available Retrofit
Technology.
(8) The term Class I area refers to a mandatory Class I Federal
area.\1\
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\1\ Although states and tribes may designate as Class I
additional areas which they consider to have visibility as an
important value, the requirements of the visibility program set
forth in section 169A of the CAA apply only to ``mandatory Class I
Federal areas.''
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(9) The initials CBI mean or refer to Confidential Business
Information.
(10) The initials CEMS mean or refer to continuous emission
monitoring system.
(11) The initials COFA mean or refer to close-coupled overfire air.
(12) The initials CY mean or refer to Calendar Year
(13) The initials EGU mean or refer to Electric Generating Unit.
(14) The initials ESPs mean or refer to electrostatic
precipitators.
(15) The words EPA, we, us or our mean or refer to the United
States Environmental Protection Agency.
[[Page 42835]]
(16) The initials FGD mean or refer to flue gas desulfurization.
(17) The initials FGR mean or refer to flue gas recirculation.
(18) The initials FIP mean or refer to Federal Implementation Plan.
(19) The initials FLMs mean or refer to Federal Land Managers.
(20) The initials IMPROVE mean or refer to Interagency Monitoring
of Protected Visual Environments monitoring network.
(21) The initials IPM mean or refer to Integrated Planning Model.
(22) The initials LNB mean or refer to low-NOX burners.
(23) The initials LTS mean or refer to Long-Term Strategy.
(24) The initials MW mean or refer to megawatts.
(25) The initials NEI mean or refer to National Emission Inventory.
(26) The initials NH3 mean or refer to ammonia.
(27) The initials NOX mean or refer to nitrogen oxides.
(28) The initials NP mean or refer to National Park.
(29) The initials OC mean or refer to organic carbon.
(30) The initials OFA mean or refer to over fire air.
(31) The initials PM mean or refer to particulate matter.
(32) The initials PM2.5 mean or refer to fine particulate matter
with an aerodynamic diameter of less than 2.5 micrometers.
(33) The initials PM10 mean or refer to particulate matter with an
aerodynamic diameter of less than 10 micrometers (coarse particulate
matter).
(34) The initials PNG mean or refer to pipeline natural gas.
(35) The initials ppm mean or refer to parts per million.
(36) The initials PSD mean or refer to Prevention of Significant
Deterioration.
(37) The initials RAVI mean or refer to Reasonably Attributable
Visibility Impairment.
(38) The initials RMC mean or refer to Regional Modeling Center.
(39) The initials RP mean or refer to Reasonable Progress.
(40) The initials RPG or RPGs mean or refer to Reasonable Progress
Goal(s).
(41) The initials RPOs mean or refer to regional planning
organizations.
(42) The initials SCR mean or refer to Selective Catalytic
Reduction.
(43) The initials SIP mean or refer to State Implementation Plan.
(44) The initials SNCR mean or refer to Selective Non-catalytic
Reduction.
(45) The initials SO2 mean or refer to sulfur dioxide.
(46) The initials SOFA mean or refer to separated over fire air.
(47) The initials SRP mean or refer to Salt River Project
Agricultural Improvement and Power District.
(48) The initials tpy mean tons per year.
(49) The initials TSD mean or refer to Technical Support Document.
(50) The initials VOC mean or refer to volatile organic compounds.
(51) The initials WA mean or refer to Wilderness Area.
(52) The initials WEP mean or refer to Weighted Emissions
Potential.
(53) The initials WFGD mean or refer to wet flue gas
desulfurization.
(54) The initials WRAP mean or refer to the Western Regional Air
Partnership.
B. Docket
The proposed action relies on documents, information and data that
are listed in the index on http://www.regulations.gov under docket
number EPA-R09-OAR-2012-0021. Although listed in the index, some
information is not publicly available (e.g., Confidential Business
Information (CBI)). Certain other material, such as copyrighted
material, is publicly available only in hard copy form. Publicly
available docket materials are available either electronically at
http://www.regulations.gov or in hard copy at the Planning Office of
the Air Division, AIR-2, EPA Region 9, 75 Hawthorne Street, San
Francisco, CA 94105. EPA requests that you contact the individual
listed in the FOR FURTHER INFORMATION CONTACT section to view the hard
copy of the docket. You may view the hard copy of the docket Monday
through Friday, 9-5:00 PDT, excluding Federal holidays.
C. Instructions for Submitting Comments to EPA
Written comments must be received at the address below on or before
August 31, 2012. Submit your comments, identified by Docket ID No. EPA-
R09-OAR-2011-0021, by one of the following methods:
Federal Rulemaking portal: http://www.regulations.gov.
Follow the on-line instructions for submitting comments.
Email: Arizona_Regional_Haze@epa.gov.
Fax: 415-947-3579 (Attention: Thomas Webb).
Mail, Hand Delivery or Courier: Thomas Webb, EPA Region 9,
Air Division (AIR-2), 75 Hawthorne Street, San Francisco, California
94105. Hand and courier deliveries are only accepted Monday through
Friday, 8:30 a.m.-4:30 p.m., excluding Federal holidays. Special
arrangements should be made for deliveries of boxed information.
EPA's policy is to include all comments received in the public
docket without change. We may make comments available online at http://www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be CBI or other
information for which disclosure is restricted by statute. Do not
submit information that you consider to be CBI or that is otherwise
protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site is an ``anonymous access'' system, which
means EPA will not know your identity or contact information unless you
provide it in the body of your comment. If you send an email comment
directly to EPA, without going through http://www.regulations.gov, we
will include your email address as part of the comment that is placed
in the public docket and made available on the Internet. If you submit
an electronic comment, EPA recommends that you include your name and
other contact information in the body of your comment and with any disk
or CD-ROM you submit. If EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, EPA may not be
able to consider your comment. Electronic files should not include
special characters or any form of encryption, and be free of any
defects or viruses.
D. Submitting Confidential Business Information
Do not submit CBI to EPA through http://www.regulations.gov or
email. Clearly mark the part or all of the information that you claim
as CBI. For CBI information in a disk or CD-ROM that you mail to EPA,
mark the outside of the disk or CD-ROM as CBI and identify
electronically within the disk or CD-ROM the specific information that
is claimed as CBI. In addition to one complete version of the comment
that includes information claimed as CBI, you must submit a copy of the
comment that does not contain the information claimed as CBI for
inclusion in the public docket. We will not disclose information so
marked except in accordance with procedures set forth in 40 CFR part 2.
E. Tips for Preparing Your Comments
When submitting comments, remember to:
Identify the rulemaking by docket number and other
identifying information (e.g., subject heading, Federal Register date
and page number).
Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
[[Page 42836]]
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns, and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the identified
comment period deadline.
F. Public Hearings
EPA will hold a public hearing at the date, time and location
stated below to accept oral and written comments into the record.
Date: July 31, 2012.
Open House: 4:00-5:00 p.m.
Public Hearing: 6:00-8:00 p.m.
Location: Sandra Day O'Connor Federal Courthouse (atrium and juror
room), 401 W. Washington Street, Phoenix, AZ 85003-2118.
To provide opportunities for questions and discussion, EPA will
hold an open house prior to the public hearing. During the open house,
EPA staff will be available informally to answer questions on our
proposed rule. Any comments made to EPA staff during the open house
must still be provided formally in writing or orally during a public
hearing in order to be considered in the record.
The public hearing will provide the public with an opportunity to
present views or information concerning the proposed Regional Haze FIP
for Arizona. EPA may ask clarifying questions during the oral
presentations, but will not respond to the presentations at that time.
Simultaneous translation in Spanish will be available during the public
hearing. We will consider written statements and supporting information
submitted during the comment period with the same weight as any oral
comments and supporting information presented at the public hearing.
Please consult section I.C, I.D. and I.E of this preamble for guidance
on how to submit written comments to EPA. We will include verbatim
transcripts of the hearing in the docket for this action. The EPA
Region 9 Web site for the rulemaking, which includes the proposal and
information about the public hearing, is at http://www.epa.gov/region9/air/actions.
II. Overview of Proposed Actions
EPA proposes to partially approve and partially disapprove a
portion of Arizona's SIP for Regional Haze submitted to EPA Region 9 on
February 28, 2011, to meet the requirements of Section 308 of the
Regional Haze Rule. EPA is proposing to take action only on the BART
requirements for the three electric generating stations and units
listed in Table 1. At this time, EPA is not proposing to take action on
the State's other BART determinations or any other parts of the SIP
regarding the remaining requirements of the Regional Haze Rule. EPA
takes very seriously a decision to disapprove a state plan, as we
believe that it is preferable, and preferred in the provisions of the
Clean Air Act, that these requirements be implemented through state
plans. A state plan need not contain exactly the same provisions that
EPA might require, but EPA must be able to find that the state plan is
consistent with the requirements of the Act. Further, EPA's oversight
role requires that it assure fair implementation of Clean Air Act
requirements by states across the country, even while acknowledging
that individual decisions from source to source or state to state may
not have identical outcomes. In this instance, we believe that
Arizona's SIP generally meets those requirements with respect to its
SO2 and PM10 limits, but as we describe in more
detail below, the SIP does not include several specifically required
elements. The NOX BART determinations for the coal-fired
units are neither consistent with the requirements of the Act nor with
BART decisions that other states have made. As a result, EPA believes
this proposed disapproval is the only path that is consistent with the
Act at this time. Specifically, we propose the following:
Proposed Approval: EPA proposes to approve Arizona's
determination that the following sources and units are subject to BART:
Arizona Electric Power Company's (AEPCO) Apache Generating Station
(Apache) Units 1, 2 and 3; Arizona Public Service's (APS) Cholla Power
Plant (Cholla) Units 2, 3 and 4; and Salt River Project's (SRP)
Coronado Generating Station (Coronado) Units 1 and 2. We are proposing
to approve the State's emissions limits for SO2 and
PM10 at all of these units, but are seeking comment on
whether lower emissions limits may be warranted for any of these units,
and whether an alternative test method should be accepted for
measurement of PM10. Finally, we are proposing to approve
the emissions limits for NOX, SO2 and
PM10 at Apache Unit 1.
Proposed Disapproval: Based on our evaluation described in
this notice, we propose to disapprove the State's BART emissions limits
for NOX at all three sources and units except for Coronado
Unit 2 and Apache Unit 1. We also propose to disapprove the compliance
and equipment maintenance requirements for BART at all three sources,
since these were not included in the revised SIP.\2\
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\2\ For each BART source, the SIP must include a requirement to
install and operate control equipment as expeditiously as
practicable (40 CFR 51.308(e)(1)(iv)); a requirement to maintain
control equipment (40 CFR 51.308(e)(1)(v)); and procedures to ensure
control equipment is properly operated and maintained, including
requirements for monitoring, recordkeeping and reporting (40 CFR
51.308(e)(1)(v)).
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Proposed FIP: We propose to promulgate a Federal
Implementation Plan (FIP) that includes emissions limitations
representing BART for NOX at all units except for Apache
Unit 1. The proposed FIP also includes compliance schedules and
requirements for equipment maintenance, monitoring, testing,
recordkeeping and reporting for all the sources and units. The
regulatory language for the FIP requirements is listed under PART 52 at
the end of this notice.
Table 1--Scope of Proposed Action
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Source name Owner Units Pollutants
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Apache Generating Station.......... AEPCO................. Steam Units 1, 2 and 3 NOX, SO2, PM10
Cholla Power Plant................. APS................... Steam Units 2, 3 and 4 NOX, SO2, PM10
Coronado Generating Station........ SRP................... Units 1 and 2......... NOX, SO2, PM10
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[[Page 42837]]
III. Regional Haze Background
A. Description of Regional Haze
Regional haze is visibility impairment that is produced by a
multitude of sources and activities that are located across a broad
geographic area and emit fine particulates (e.g., sulfates, nitrates,
organic carbon (OC), elemental carbon (EC), and soil dust), and their
precursors (e.g., sulfur dioxide, nitrogen oxides, and in some cases,
ammonia (NH3) and volatile organic compounds (VOC)). Fine
particle precursors react in the atmosphere to form PM2.5,
which impairs visibility by scattering and absorbing light. Visibility
impairment reduces the clarity, color, and visible distance that one
can see. PM2.5 can also cause serious health effects and
mortality in humans and contributes to environmental effects such as
acid deposition and eutrophication.
Data from the existing visibility monitoring network, the
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE)
monitoring network, show that visibility impairment caused by air
pollution occurs virtually all the time at most national parks (NPs)
and wilderness areas (WAs). The average visual range \3\ in many Class
I areas (i.e., NPs and memorial parks, WAs, and international parks
meeting certain size criteria) in the western United States is 100-150
kilometers, or about one-half to two-thirds of the visual range that
would exist without anthropogenic air pollution. In most of the eastern
Class I areas of the United States, the average visual range is less
than 30 kilometers, or about one-fifth of the visual range that would
exist under estimated natural conditions (64 FR 35715, July 1, 1999).
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\3\ Visual range is the greatest distance, in kilometers or
miles, at which a dark object can be viewed against the sky.
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B. History of Regional Haze Regulations
In section 169A of the 1977 Amendments to the CAA, Congress created
a program for protecting visibility in the nation's national parks and
wilderness areas. This section of the CAA establishes as a national
goal the ``prevention of any future, and the remedying of any existing,
impairment of visibility in mandatory Class I Federal areas \4\ which
impairment results from manmade air pollution.'' EPA promulgated
regulations on December 2, 1980, to address visibility impairment in
Class I areas that is ``reasonably attributable'' to a single source or
small group of sources, i.e., ``reasonably attributable visibility
impairment.'' (45 FR 80084, December 2, 1980). These regulations
represented the first phase in addressing visibility impairment. EPA
deferred action on regional haze that emanates from a variety of
sources until monitoring, modeling and scientific knowledge about the
relationships between pollutants and visibility impairment were
improved.
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\4\ Areas designated as mandatory Class I Federal areas consist
of national parks exceeding 6000 acres, wilderness areas and
national memorial parks exceeding 5000 acres, and all international
parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a).
In accordance with section 169A of the CAA, EPA, in consultation
with the Department of Interior, promulgated a list of 156 areas
where visibility is identified as an important value (44 FR 69122,
November 30, 1979). The extent of a mandatory Class I area includes
subsequent changes in boundaries, such as park expansions. 42 U.S.C.
7472(a). Although states and tribes may designate as Class I
additional areas which they consider to have visibility as an
important value, the requirements of the visibility program set
forth in section 169A of the CAA apply only to ``mandatory Class I
Federal areas.'' Each mandatory Class I Federal area is the
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i).
When we use the term ``Class I area'' in this action, we mean a
``mandatory Class I Federal area.''
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As part of the 1990 Amendments to the CAA, Congress added section
169B to focus attention on regional haze issues. EPA promulgated a rule
to address regional haze on July 1, 1999 (64 FR 35714, July 1, 1999)
codified at 40 CFR part 51, subpart P (Regional Haze Rule). The primary
regulatory requirements that address regional haze are found at 40 CFR
51.308 and 51.309 and are summarized below. Under 40 CFR 51.308(b), all
states, the District of Columbia and the Virgin Islands are required to
submit an initial state implementation plan (SIP) addressing regional
haze visibility impairment no later than December 17, 2007.\5\
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\5\ EPA's regional haze regulations require subsequent updates
to the regional haze SIPs. 40 CFR 51.308(g)-(i).
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C. Roles of Agencies in Addressing Regional Haze
Successful implementation of the regional haze program will require
long-term regional coordination among states, tribal governments and
various federal agencies. As noted above, pollution affecting the air
quality in Class I areas can be transported over long distances, even
hundreds of kilometers. Therefore, to effectively address the problem
of visibility impairment in Class I areas, states, or the EPA when
implementing a FIP, need to develop strategies in coordination with one
another, taking into account the effect of emissions from one
jurisdiction on the air quality in another.
Because the pollutants that lead to regional haze can originate
from sources located across broad geographic areas, EPA has encouraged
the states and tribes across the United States to address visibility
impairment from a regional perspective. Five regional planning
organizations (RPOs) were developed to address regional haze and
related issues. The RPOs first evaluated technical information to
better understand how their states and tribes impact Class I areas
across the country, and then pursued the development of regional
strategies to reduce emissions of particulate matter and other
pollutants leading to regional haze.
The Western Regional Air Partnership (WRAP) RPO is a collaborative
effort of state governments, tribal governments, and various federal
agencies established to initiate and coordinate activities associated
with the management of regional haze, visibility and other air quality
issues in the western United States. WRAP member State governments
include: Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana,
New Mexico, North Dakota, Oregon, South Dakota, Utah, Washington, and
Wyoming. Tribal members include Campo Band of Kumeyaay Indians,
Confederated Salish and Kootenai Tribes, Cortina Indian Rancheria, Hopi
Tribe, Hualapai Nation of the Grand Canyon, Native Village of Shungnak,
Nez Perce Tribe, Northern Cheyenne Tribe, Pueblo of Acoma, Pueblo of
San Felipe, and Shoshone-Bannock Tribes of Fort Hall.
IV. Requirements for Regional Haze Implementation Plans
A. Regional Haze Rule
The Regional Haze Rule (RHR) sets out specific requirements for
states' initial regional haze implementation plans.\6\ In particular,
each state's plan must establish a long-term strategy that ensures
reasonable progress toward achieving natural visibility conditions in
each Class I area affected by the emissions from sources within the
state. In addition, for each Class I area within the state's
boundaries, the plan must establish a reasonable progress goal (RPG)
for the first planning period that ends on July 31, 2018. The long-term
strategy must include enforceable emission limits and other measures as
necessary to achieve the RPG. Regional haze plans must also give
specific
[[Page 42838]]
attention to certain stationary sources that were in existence on
August 7, 1977, but were not in operation before August 7, 1962. These
sources, where appropriate, are required to install BART controls to
eliminate or reduce visibility impairment. Although such BART
determinations can be a part of a reasonable progress strategy, BART is
also an independent requirement that can be assessed separately from
the other requirements of the RHR. Because this proposal only pertains
to BART at three specific sources, we do not discuss other requirements
of the RHR below.
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\6\ Pursuant to 40 CFR 51.301, ``implementation plan'' is
defined as ``any State Implementation Plan, Federal Implementation
Plan, or Tribal Implementation Plan.'' Therefore, although the
requirements of the RHR are generally described in relation to SIPs,
they are also relevant where EPA is promulgating a regional haze
plan.
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B. The Deciview
The RHR establishes the deciview (dv) as the principal metric for
measuring visibility. This visibility metric expresses uniform changes
in haziness in terms of common increments across the entire range of
visibility conditions, from pristine to extremely hazy conditions.
Visibility expressed in deciviews is determined by using air quality
measurements to estimate light extinction and then transforming the
value of light extinction to deciviews using a logarithmic function.
The deciview is a more useful measure for tracking progress in
improving visibility than light extinction because each deciview change
is an equal incremental change in visibility as perceived by the human
eye.\7\
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\7\ The preamble to the RHR provides additional details about
the deciview (64 FR 35714, 35725 July 1, 1999).
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C. Best Available Retrofit Technology
Section 169A of the CAA directs states to evaluate the use of
retrofit controls at certain larger, often uncontrolled, older
stationary sources in order to address visibility impacts from these
sources. Specifically, section 169A(b)(2)(A) of the CAA requires states
to revise their SIPs to contain such measures as may be necessary to
make reasonable progress towards the natural visibility goal, including
a requirement that certain categories of existing major stationary
sources \8\ built between 1962 and 1977 procure, install, and operate
the ``Best Available Retrofit Technology'' as determined by the state.
Under the RHR, states are directed to conduct BART determinations for
such ``BART-eligible'' sources that may be anticipated to cause or
contribute to any visibility impairment in a Class I area. Rather than
requiring source-specific BART controls, states also have the
flexibility to adopt an emissions trading program or other alternative
program as long as the alternative provides greater reasonable progress
towards improving visibility than BART.
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\8\ The set of ``major stationary sources'' potentially subject
to BART is listed in CAA section 169A(g)(7).
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EPA published the Guidelines for BART Determinations under the
Regional Haze Rule at Appendix Y to 40 CFR part 51 (hereinafter
referred to as the ``BART Guidelines'') on July 6, 2005. The Guidelines
are to assist states in determining which of their sources should be
subject to the BART requirements and in determining appropriate
emission limits for each such ``subject-to-BART'' source. In making
BART determinations for fossil fuel-fired electric generating plants
with a total generating capacity in excess of 750 megawatts, states
must use the approach set forth in the BART Guidelines. States are
encouraged, but not required, to follow the BART Guidelines in making
BART determinations for other types of sources. States must address all
visibility-impairing pollutants emitted by a source in the BART
determination process. The most significant visibility impairing
pollutants are SO2, NOX and PM. EPA has indicated
that states should use their best judgment in determining whether VOC
or NH3 compounds impair visibility in Class I areas.
Under the BART Guidelines, states may select an exemption threshold
value for their BART modeling, below which a BART-eligible source would
not be expected to cause or contribute to visibility impairment in any
Class I area. The state must document this exemption threshold value in
the SIP and must state the basis for its selection of that value. Any
source with emissions that model above the threshold value would be
subject to a BART determination review. The BART Guidelines acknowledge
varying circumstances affecting different Class I areas. In setting
their exemption threshold values, states should consider the number of
emission sources affecting the Class I areas at issue and the magnitude
of the individual sources' impacts. An exemption threshold set by the
state should not be higher than 0.5 deciview.
In their SIPs, states must identify potential BART sources,
described in the RHR as ``BART-eligible sources,'' and document their
BART control determination analyses. In making BART determinations,
section 169A(g)(2) of the CAA requires that states consider the
following factors: (1) The costs of compliance; (2) the energy and non-
air quality environmental impacts of compliance; (3) any existing
pollution control technology in use at the source; (4) the remaining
useful life of the source; and (5) the degree of improvement in
visibility which may reasonably be anticipated to result from the use
of such technology. States are free to determine the weight and
significance assigned to each factor, but must consider all five
factors and provide a reasoned explanation for adopting the technology
selected as BART, based on the five factors.
A regional haze SIP must include source-specific BART emission
limits and compliance schedules for each source subject to BART, unless
the SIP includes an alternative program that provides greater
reasonable progress towards improving visibility than BART and meets
the other requirements of 40 CFR 51.308(e)(2). Once a state has made
its BART determination, the BART controls must be installed and in
operation as expeditiously as practicable, but no later than five years
after the date EPA approves the regional haze SIP.\9\ The Regional Haze
SIP must also contain a requirement for each BART source to maintain
the relevant control equipment, as well as procedures to ensure control
equipment is properly operated and maintained.\10\ In addition to what
is required by the RHR, general SIP requirements mandate that the SIP
must also include all regulatory requirements related to monitoring,
recordkeeping and reporting for the BART emissions limitations.\11\
---------------------------------------------------------------------------
\9\ CAA section 169(g)(4); 40 CFR 51.308(e)(1)(iv).
\10\ 40 CFR 51.308(e)(1)(v). See also CAA section 302(k)
(defining ``emission limitation'' as ``a requirement established by
the State or the Administrator which limits the quantity, rate, or
concentration of emissions of air pollutants on a continuous basis,
including any requirement relating to the operation or maintenance
of a source to assure continuous emission reduction * * *'')
(emphasis added).
\11\ See CAA section 110(a)(2) (requirements for SIPs).
---------------------------------------------------------------------------
D. The Grand Canyon Visibility Transport Commission and Section 309
In addition to the general requirements of the regional haze
program, the RHR also includes 40 CFR 51.309, which contains the
strategies developed by the Grand Canyon Visibility Transport
Commission (GCVTC), established under Section 169B(f) of CAA, 42 U.S.C.
7492(f). Certain western States and Tribes were eligible to submit
implementation plans under section 309 as an alternative method of
achieving reasonable progress for Class I areas that were covered by
the GCVTC's analysis--i.e., the 16 Class I areas on the Colorado
Plateau. In order for States and Tribes to be able to utilize this
section, however, the rule provided that EPA must receive an ``Annex''
to
[[Page 42839]]
the GCVTC's final recommendations. The purpose of the Annex was to
provide the specific provisions needed to translate the GCVTC's general
recommendations for stationary source SO2 reductions into an
enforceable regulatory program. The rule provided that such an Annex,
meeting certain requirements, be submitted to EPA no later than October
1, 2000, see 40 CFR 51.309(d)(4) and 51.309(f). The Annex was submitted
in 2000, and EPA revised 40 CFR 51.309 in 2003. See 68 FR 33764, June
5, 2003.
V. SIP and FIP Background
A. History of State Submittals and EPA Actions
Since four of its twelve mandatory Class I Federal areas are on the
Colorado Plateau, Arizona had the option of submitting a Regional Haze
SIP under section 309 of the Regional Haze Rule. A SIP that is approved
by EPA as meeting all of the requirements of section 309 is ``deemed to
comply with the requirements for reasonable progress with respect to
the 16 Class I areas [on the Colorado Plateau] for the period from
approval of the plan through 2018.'' 40 CFR 51.309(a). When these
regulations were first promulgated, 309 submissions were due no later
than December 31, 2003. Accordingly, the Arizona Department of
Environmental Quality (ADEQ) submitted to EPA on December 23, 2003, a
309 SIP for Arizona's four Class I Areas on the Colorado Plateau. ADEQ
submitted a revision to its 309 SIP, consisting of rules on emissions
trading and smoke management, and a correction to the state's regional
haze statutes, on December 31, 2004. EPA approved the smoke management
rules submitted as part of the 2004 revisions, see 71 FR 28270 and 72
FR 25973, but did not propose or take final action on any other portion
of the 309 SIP.
In response to an adverse court decision,\12\ EPA revised 40 CFR
51.309 on October 13, 2006, making a number of substantive changes and
requiring states to submit revised 309 SIPs by December 17, 2007. See
71 FR 60612. Subsequently, ADEQ sent a letter to EPA dated December 14,
2008, acknowledging that it had not submitted a SIP revision to address
the requirements of 309(d)(4) related to stationary sources and 309(g),
which governs reasonable progress requirements for Arizona's eight
mandatory Class I areas outside of the Colorado Plateau.\13\
---------------------------------------------------------------------------
\12\ Center for Energy and Economic Development v. EPA, 398 F.3d
653 (D.C. Circuit 2005).
\13\ Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA
(December 14, 2008).
---------------------------------------------------------------------------
EPA made a finding on January 15, 2009, that 37 states, including
Arizona, had failed to make all or part of the required SIP submissions
to address regional haze. See 74 FR 2392. Specifically, EPA found that
Arizona failed to submit the plan elements required by 40 CFR 309(d)(4)
and (g). EPA sent a letter to ADEQ on January 14, 2009, notifying the
state of this failure to submit a complete SIP. ADEQ later decided to
submit a SIP under section 308, instead of section 309.
ADEQ adopted and transmitted its Regional Haze SIP under Section
308 of the Regional Haze Rule (``Arizona Regional Haze SIP'') to EPA
Region 9 in a letter dated February 28, 2011. The plan was determined
complete by operation of law on August 28, 2011.\14\ The SIP was
properly noticed by the State and available for public comment for 30
days prior to a public hearing held in Phoenix, Arizona, on December 2,
2010. Arizona included in its SIP responses to written comments from
EPA Region 9, the National Park Service, the U.S. Forest Service, and
other stakeholders including regulated industries and environmental
organizations. The Arizona Regional Haze SIP is available to review in
the docket for the proposed rule.
---------------------------------------------------------------------------
\14\ See CAA section 110(k)(1)(B).
---------------------------------------------------------------------------
B. EPA's Authority To Promulgate a FIP
Under CAA section 110(c), EPA is required to promulgate a Federal
Implementation Plan within two years of the effective date of a finding
that a state has failed to make a required SIP submission. The FIP
requirement is void if a state submits a regional haze SIP, and EPA
approves that SIP within the two-year period. See 74 FR 2392, January
15, 2009. Specifically, CAA section 110(c) provides:
(1) The Administrator shall promulgate a Federal implementation
plan at any time within 2 years after the Administrator--
(A) finds that a State has failed to make a required submission or
finds that the plan or plan revision submitted by the State does not
satisfy the minimum criteria established under [CAA section
110(k)(1)(A)], or
(B) disapproves a State implementation plan submission in whole or
in part, unless the State corrects the deficiency, and the
Administrator approves the plan or plan revision, before the
Administrator promulgates such Federal implementation plan.
Section 302(y) defines the term ``Federal implementation plan'' in
pertinent part, as:
[A] plan (or portion thereof) promulgated by the Administrator
to fill all or a portion of a gap or otherwise correct all or a
portion of an inadequacy in a State implementation plan, and which
includes enforceable emission limitations or other control measures,
means or techniques (including economic incentives, such as
marketable permits or auctions or emissions allowances).
Thus, because we determined that Arizona failed to timely submit a
Regional Haze SIP, we are required to promulgate a Regional Haze FIP
for Arizona, unless we first approve a SIP that corrects the non-
submittal deficiencies identified in our finding of January 15, 2009.
For the reasons explained below, we are proposing to partially approve
and partially disapprove the Arizona Regional Haze SIP. Therefore, we
are proposing a FIP to address those portions of the SIP that we are
proposing to disapprove. If Arizona submits a SIP revision that
addresses the deficiencies in sufficient time for EPA to review the
submission, then we would prefer to act on that submittal, if such
action is consistent with our obligations under the CAA and applicable
court orders.
VI. EPA's Evaluation of Arizona's BART Analyses and Determinations
A. Arizona's Identification of BART Sources
ADEQ's Analysis: In the first step of the BART process, ADEQ
identified all the BART-eligible sources within the jurisdiction of the
State and local agencies, and applied the three eligibility criteria in
the RHR (40 CFR 51.301) to these facilities. The criteria are: (1) One
or more emission units at the facility are classified in one of the 26
industrial source categories listed in the BART Guidelines; (2) the
emission unit(s) did not operate before August 7, 1962, but was in
existence on August 7, 1977; and (3) the total potential to emit of any
visibility impairing pollutant from the subject emission units is
greater or equal to 250 tons per year. ADEQ determined that Apache,
Cholla and Coronado have emissions units that meet these criteria.
In a second step, ADEQ identified those BART-eligible sources that
may reasonably be anticipated to cause or contribute to visibility
impairment at any Class I area. The BART Guidelines allow states to
consider exempting some BART-eligible sources from BART review in the
event that they may not
[[Page 42840]]
reasonably be anticipated to cause or contribute to any visibility
impairment in a Class I area. For states using modeling to determine
the applicability of BART to single sources, the BART Guidelines note
that the first step is to set a contribution threshold to assess
whether the impact of a single source is sufficient to cause or
contribute to visibility impairment at a Class I area. Further, the
BART Guidelines state that, ``[a] single source that is responsible for
a 1.0 deciview change or more should be considered to `cause'
visibility impairment.'' \15\ The BART Guidelines also state that ``the
appropriate threshold for determining whether a source contributes to
visibility impairment' may reasonably differ across states,'' but,
``[a]s a general matter, any threshold that you use for determining
whether a source `contributes' to visibility impairment should not be
higher than 0.5 deciviews.'' For determining whether a source is
subject to BART, ADEQ used a contribution threshold of 0.50 dv.
---------------------------------------------------------------------------
\15\ 70 FR 39104, 39161, July 6, 2005.
---------------------------------------------------------------------------
The WRAP's Regional Modeling Center (RMC) developed a modeling
protocol, entitled ``CALMET/CALPUFF Protocol for BART Exemption
Screening Analysis for Class I Areas in the Western United States.''
\16\ The protocol specified the use of CALPUFF version 6.112 and CALMET
version 6.211, which were the accepted model versions at the time.\17\
The WRAP RMC used this protocol to perform CALPUFF modeling for each of
the western states. ADEQ then relied on the RMC's modeling to assess
the potential of BART-eligible sources to cause or contribute to Class
I visibility impairment. The visibility impacts of AEPCO Apache
Generating Station, APS Cholla Power Plant, and SRP Coronado Generating
Station are each well above the 0.5 dv ``contribution'' threshold as
well as the 1.0 dv ``causation'' threshold.\18\ As a result, ADEQ
determined that emissions units at the Apache, Cholla, and Coronado
facilities are subject to BART as listed in Table 2.
---------------------------------------------------------------------------
\16\ See Docket Item B-15.
\17\ EPA subsequently required the uses of CALPUFF and CALMET
version 5.8 for new modeling applications. However, EPA is accepting
BART modeling performed according to a previously approved protocol,
as was the case for the WRAP protocol.
\18\ See Docket Item No. B-12. Visibility impacts as listed in
``Summary of WRAP RMC BART Modeling for Arizona'' Draft No. 5, May
7, 2005. Initial draft released on April 4, 2005.
Table 2--Sources Subject to BART
----------------------------------------------------------------------------------------------------------------
WRAP
Facility BART emission Source category Pollutants evaluated modeled
units impact \a\
----------------------------------------------------------------------------------------------------------------
AEPCO Apache Generating Station Units 1, 2, and 3. Fossil-fuel fired steam NOX, SO2, PM10........ 1.95 dv
electric plants of
more than 250 million
British thermal units
per hour heat input.
APS Cholla Power Plant......... Units 2, 3, and 4. ....................... NOX, SO2, PM10........ 2.88 dv
SRP Coronado Generating Station Units 1 and 2..... ....................... NOX, SO2, PM10........ 3.32 dv
----------------------------------------------------------------------------------------------------------------
\a\ Average of the 98th percentile across 2001, 2002 and 2003 for the most affected Class I Area.
EPA's Evaluation: We are proposing to approve ADEQ's determination
that Apache, Cholla, and Coronado are eligible for and subject to a
BART control analysis. Each of the three facilities addressed in this
notice (Apache, Cholla and Coronado) agreed with ADEQ's determination
that they are subject to BART. While we do not agree with all aspects
of the process by which ADEQ identified its eligible-for-BART and
subject-to-BART sources, we do agree with ADEQ that the three
facilities in this notice are eligible for and subject to BART. Since
our action today focuses on only the three facilities, we will address
ADEQ's other subject-to-BART determinations in a separate action at a
later date.
B. Arizona's BART Control Analysis
The third step of the BART evaluation is to perform a five-factor
BART analysis as the basis for making a BART control determination. In
performing this analysis, 40 CFR 51.308(e)(1)(ii)(A) requires that
states consider the following factors on a pollutant-by-pollutant
basis: (1) The costs of compliance of each technically feasible control
technology, (2) the energy and non-air quality environmental impacts of
compliance of the control technologies, (3) any existing pollution
control technology in use at the source, (4) the remaining useful life
of the source, and (5) the degree of improvement in visibility which
may reasonably be anticipated to result from the use of such
technology. These factors are frequently referred to as the ``five-
factor analysis'' for the RHR BART determination.
The BART Guidelines recommend that a BART analysis include the
following five steps. The Guidelines provide detailed instructions on
how to perform each of these steps.\19\
---------------------------------------------------------------------------
\19\ 40 CFR part 51, appendix Y, Sec. IV.D.
Step 1--Identify All Available Retrofit Control Technologies,
Step 2--Eliminate Technically Infeasible Options,
Step 3--Evaluate Control Effectiveness of Remaining Control
Technologies,
Step 4--Evaluate Impacts and Document the Results,\20\ and
---------------------------------------------------------------------------
\20\ Step 4 includes evaluating the cost of compliance, energy
impacts, non-air quality environmental impacts, and remaining useful
life.
---------------------------------------------------------------------------
Step 5--Evaluate Visibility Impacts.
ADEQ's Analysis: ADEQ's BART analyses mostly followed this
approach, with the addition of a step to identify existing control
technologies and a step concluding ``selection of BART.'' \21\ Thus,
ADEQ's analyses included the following seven steps:
---------------------------------------------------------------------------
\21\ Arizona Regional Haze SIP, pp. 138-143.
Step 1: Identify the Existing Control Technologies in Use at
the Source
Step 2: Identify All Available Retrofit Control Options
Step 3: Eliminate All Technically Infeasible Control Options
Step 4: Evaluate Control Effectiveness of Remaining
Technologies
Step 5: Evaluate the Energy and Non-Air Quality Environmental
Impacts and Document Results \22\
---------------------------------------------------------------------------
\22\ We note that, while ADEQ refers to its Step 5 as an
evaluation of energy and non-air quality environmental impacts, this
step also includes consideration of the costs of compliance and the
remaining useful life of the source, consistent with the BART
Guidelines, 40 CFR part 51, appendix Y, Sec. IV.D.4.
---------------------------------------------------------------------------
Step 6: Evaluate Visibility Impacts
Step 7: Select BART
EPA's Evaluation: We find that this overall approach to the five-
factor analysis is generally reasonable and consistent with the RHR and
the BART Guidelines. With respect to the three
[[Page 42841]]
sources covered by this action, we find that ADEQ's implementation of
the first four steps of its approach is generally reasonable and
consistent with the RHR and the BART Guidelines. However, we do not
agree with ADEQ's analysis in steps 5 through 7.\23\ In particular,
under step 5, we find that the costs of control were not calculated in
accordance with the BART Guidelines; under step 6, we find that the
visibility impacts were not appropriately evaluated and considered; and
under step 7, we find that ADEQ did not provide a sufficient
explanation and rationale for its determinations. While we find these
problems in all of ADEQ's BART analyses for the three sources, they do
not appear to have had a substantive impact on ADEQ's selection of
controls for SO2 and PM10. With respect to ADEQ's
NOX BART determinations, however, we find that these
problems resulted in control determinations that are inconsistent with
the RHR and the BART Guidelines. We summarize below how ADEQ applied
the five factors and identify a number of issues common to the three
relevant sources.
---------------------------------------------------------------------------
\23\ We do not believe that ADEQ appropriately used ``the most
stringent emission control level that the technology is capable of
achieving'' for SCR per the BART Guidelines at 40 CFR part 51,
appendix Y, Sec. IV.D.3. This issue is addressed on a source-by-
source basis under the cost and visibility factors of our evaluation
in section VI.C.
---------------------------------------------------------------------------
1. Cost of Compliance
ADEQ included information relating to costs of compliance in its RH
SIP, including information on total annualized costs, cost per ton of
pollutant removed, and incremental cost per ton of pollutant removed
for the various control options considered. Cost calculations were
prepared by consulting firms on behalf of the facilities as part of
their BART analyses that relied on a combination of vendor quotes,
facility data, and internal cost calculation methodology. These BART
analyses were subsequently submitted to ADEQ. Upon review, ADEQ
requested certain clarifying information from the facilities regarding
these cost calculations, including greater detail on the underlying
assumptions and additional supporting documentation. ADEQ received
responses of varying detail to these requests, and included this
information as part of its RH SIP. As described in further detail in
the discussion of each facility, there are certain aspects of these
cost calculations that we find inconsistent with the BART Guidelines
and EPA's Control Cost Manual. We also disagree with the manner in
which ADEQ interpreted the cost-related information included in its RH
SIP.
2. Energy and Non-Air Quality Environmental Impacts
In its BART analyses, ADEQ identified only minor energy and non-air
quality impacts for SO2 or PM10 control
strategies. Regarding NOX emissions, ADEQ's BART analyses
point out that the various control options will incur increased energy
usage by any electric generating unit (EGU) where they are installed.
In particular, Selective Catalytic Reduction (SCR) retrofit will cause
an additional pressure drop in the flue gas system due to the catalyst,
increasing power requirements. Additionally, ADEQ's SIP submission
asserts that ammonia levels in fly ash due to Selective Non-catalytic
Reduction (SNCR) and SCR installations could affect the decision of
facility managers to sell or dispose of fly ash.\24\ Finally, the
Arizona SIP notes that SNCR and SCR may involve potential safety
hazards associated with the transportation and handling of anhydrous
ammonia.\25\ However, ADEQ did not cite any of these potential energy
and non-air impacts as the basis for eliminating any otherwise feasible
control strategies for NOX. EPA concurs that these impacts
do not warrant elimination of any of the control options.
---------------------------------------------------------------------------
\24\ Arizona Regional Haze SIP, Appendix D, p. 63.
\25\ See, e.g. id. p. 53.
---------------------------------------------------------------------------
3. Existing Pollution Control Technology
The presence of existing pollution control technology is reflected
in the BART analysis in two ways: First, in the consideration of
available control technologies (step 1 of ADEQ's analysis), and second,
in the development of baseline emission rates for use in cost
calculations and visibility modeling (steps 5 and 6 of ADEQ's
analysis). As described in greater detail in the discussion for each
facility, AEPCO, APS, and SRP used baseline time periods that varied
from 2001 to 2007. The respective baseline emissions and existing
pollution control technology used in the BART analyses reflect the
levels of control in place at the time. EPA considers ADEQ's approach
to be reasonable and generally consistent with the RHR and the BART
Guidelines.
4. Remaining Useful Life of the Source
The remaining useful life of the source is usually considered as a
quantitative factor in estimating the cost of compliance. With the
exception of Apache Generating Station Unit 1, ADEQ used the default
20-year amortization period in the EPA Cost Control Manual as the
remaining useful life of the facilities in its RH SIP. Without
commitments for an early shut down of an EGU, it is not appropriate to
consider a shorter amortization period in a BART analysis.
5. Degree of Visibility Improvement
ADEQ assessed the degree of improvement in visibility from
candidate BART technologies using models and procedures generally in
accord with EPA guidance. ADEQ relied on visibility analysis performed
by the facilities, which used the WRAP RMC's modeling protocol.
However, ADEQ's use of the modeling results in making BART decisions is
problematic in several respects. First, ADEQ appears to have considered
the visibility benefit of controls at only a single Class I area for
each facility, even though there are nine to seventeen Class I areas
nearby, depending on the facility. Since the facilities' modeling
results indicated that controls would contribute to visibility
improvement in multiple Class I areas, consideration of the benefits in
additional areas is warranted. Although the RHR and the BART Guidelines
do not prescribe a particular approach to calculating or considering
visibility benefits across multiple Class I areas, overlooking
significant visibility benefits at additional areas considerably
understates the overall benefit of controls to improve visibility. A
more complete assessment of the degree of visibility improvement for
candidate BART controls would include consideration of the number of
areas affected and the degree of visibility improvement expected in all
areas. One could conduct this type of analysis by summing the benefits
over the areas, or by some other quantitative or qualitative
procedure.\26\ The procedure followed by ADEQ is not a sufficient basis
for making BART determinations for sources with substantial benefits
across many Class I areas.
---------------------------------------------------------------------------
\26\ Note that the issue here is not whether an individual in a
given time and place would perceive the deciview benefits occurring
at different Class I areas and under possibly different
meteorological conditions. Rather, the issue is accounting in some
way for the full set of expected visibility benefits. A national
program for addressing regional haze must inherently address the
multiple areas that occur in a region.
---------------------------------------------------------------------------
Second, ADEQ appears to have considered benefits from controls on
only one emitting unit at a time. However, because the plumes from
individual units overlap more or less completely by the time they reach
a
[[Page 42842]]
Class I area, the visibility benefits from controls on multiple units
would be approximately additive. This issue of additive unit benefits
could be addressed in some way without modeling all the units together,
but ADEQ does not appear to have done this, and therefore
underestimated the degree of visibility improvement from controls.
Finally, the ammonia background concentration assumed for Cholla
and Coronado may be too low, ranging from 1 ppb to as low as 0.2 ppb.
Nitrogen oxides and SO2 emissions affect visibility after
chemically transforming into particulate ammonium nitrate and ammonium
sulfate, respectively. This process is limited by the amount of ammonia
present, so modeling with a low assumed ammonia background may
underestimate visibility impacts and thus the visibility benefit of
controls. Ambient ammonia measurements for use as input to modeling are
scarce, and measurements that include it in the form of ammonium even
scarcer. In the absence of compelling ammonia background estimates, EPA
guidance recommends the use of a 1 ppb ammonia background for areas in
the west.\27\
---------------------------------------------------------------------------
\27\ Interagency Workgroup on Air Quality Modeling (IWAQM) Phase
2 Summary Report and Recommendations for Modeling Long Range
Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998,
http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
---------------------------------------------------------------------------
C. Arizona's BART Determinations
Our evaluation of ADEQ's BART determinations is organized by
source, unit and pollutant with a focus on the cost and visibility
factors of the BART analysis. A summary of the State's BART
determinations for the three sources is in Table 3. ADEQ's BART
determinations for NOX consist of combustion controls,
either in the form of low-NOX burners (LNB) with flue gas
recirculation (FGR), or LNB with overfire air (OFA) or separated
overfire air (SOFA). For PM10, ADEQ's BART determinations
consist of fuel switching to pipeline natural gas (PNG) for Apache Unit
1, and add-on particulate controls such as electrostatic precipitators
(ESPs) or fabric filters for the remaining units. For SO2,
ADEQ's BART determinations consist of fuel-switching to PNG for Apache
Unit 1, and wet flue gas desulfurization (FGD) systems that are either
already in place or planned for the remaining units.
Table 3--Summary of Arizona's Bart Determinations
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX PM10 SO2
Size -------------------------------------------------------------------------------------------
Unit (MW) Fuel Control Emission Control Emission Control Emission
technology limit * technology limit * technology limit *
--------------------------------------------------------------------------------------------------------------------------------------------------------
Apache 1....................... 75 Natural Gas....... LNB w/FGR, PNG use 0.056 PNG use........... 0.0075 PNG use.......... 0.00064
Apache 2....................... 195 Coal.............. LNB w/OFA......... 0.31 ESP (upgraded).... 0.03 Wet FGD 0.15
(existing).
Apache 3....................... 195 Coal.............. LNB w/OFA......... 0.31 ESP (upgraded).... 0.03 Wet FGD 0.15
(existing).
Cholla 2....................... 305 Coal.............. LNB w/SOFA........ 0.22 Fabric filter..... 0.015 Wet FGD 0.15
(existing).
Cholla 3....................... 305 Coal.............. LNB w/SOFA........ 0.22 Fabric filter 0.015 Wet FGD 0.15
(existing). (existing).
Cholla 4....................... 425 Coal.............. LNB w/SOFA........ 0.22 Fabric filter 0.015 Wet FGD 0.15
(existing). (existing).
Coronado 1..................... 411 Coal.............. LNB w/OFA......... 0.32 Hot-side ESP...... 0.03 Wet FGD (per 0.08
Consent Decree).
Coronado 2..................... 411 Coal.............. LNB w/OFA......... 0.32 Hot-side ESP...... 0.03 Wet FGD (per 0.08
Consent Decree).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Emission limits are in lb/MMBtu.
1. Apache Unit 1
Apache Generating Station (Apache) consists of seven EGUs with a
total plant-wide generating capacity of 560 megawatts. Unit 1 is a
wall-fired boiler with a net unit output of 85 MW that burns pipeline-
quality natural gas as its primary fuel, but also has the capability to
use No. 2 through No. 6 fuel oils. At present, no emissions control
equipment is installed on Unit 1. ADEQ's BART analyses for Apache Unit
1 relied largely on data and analyses provided by AEPCO and its
contractor. These data and analyses are summarized below, along with
ADEQ's determinations for each pollutant and EPA's evaluations of these
analyses and determinations.
a. BART for NOX
ADEQ's Analysis: Unit 1 currently operates with no NOX
controls. In its BART analysis submitted to ADEQ, AEPCO developed
baseline emissions for multiple fuel-use scenarios including natural
gas, and No. 2 and No. 6 fuel oil usage. Baseline natural gas emissions
were based on the highest 75 percent load 24-hour NOX
emission levels reported in EPA's Acid Rain Database for 2006. Since
the only fuel burned in 2006 was natural gas, baseline emissions for
No. 2 or No. 6 fuel oil usage could not be developed based on data from
2006. As a simplifying assumption, baseline No. 2 fuel oil
NOX emissions were assumed to be equal to natural gas usage.
Baseline emissions for No. 6 fuel oil usage were estimated using AP-42
emission factors.\28\ A summary of baseline emissions for various fuels
is provided in Table 4.
---------------------------------------------------------------------------
\28\ See Docket Item B-2. Page 2-1 of AEPCO Apache 1 BART
Analysis.
Table 4--Apache Unit 1: Arizona's Baseline Emission Factors a
------------------------------------------------------------------------
Natural Gas No. 2 Fuel No. 6 fuel
Pollutant (lb/MMBtu) oil oil
------------------------------------------------------------------------
NOX.......................... 0.147 0.147 0.301
PM10......................... 0.0075 0.014 0.0737
SO2.......................... 0.00064 0.051 0.906
------------------------------------------------------------------------
a See Docket Item B-02 (Table 3-1 of AEPCO Apache 1 BART Analysis).
[[Page 42843]]
AEPCO examined multiple control technologies and options for Apache
Unit 1, including combustion controls, post combustion add-on controls,
and fuel-switching. A summary of cost of compliance and degree of
visibility improvement for these options is in Table 5. These cost and
visibility improvement values are based on baseline and control case
emissions corresponding to No. 6 fuel oil usage, which of the three
fuels considered is the fuel type that generates the greatest
NOX emissions.
Table 5--Apache Unit 1: Arizona's Cost and Visibility Analysis for NOX
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost- effectiveness d ($/ton) Visibility Improvement c (dv)
Emission Emissions Annualized -------------------------------------------------------------
Control option b rate (lb/ removed cost ($/ Incremental Total (from Incremental
MMBtu) (tons/yr) year) Average (from previous) base case) (from previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline........................................... 0.301 ........... ........... ........... ................ ........... ................
LNB + FGR.......................................... 0.15 297 551,982 1,859 ................ 0.194 ................
ROFA............................................... 0.16 278 939,093 3,378 -20,374 0.256 0.062
SNCR with LNB + FGR................................ 0.11 376 1,079,389 2,871 1,432 0.24 -0.016
ROFA w/Rotamix..................................... 0.11 376 1,505,825 4,005 a NA 0.24 a NA
SCR with LNB + FGR................................. 0.07 455 5,704,798 12,538 53,152 0.409 0.169
--------------------------------------------------------------------------------------------------------------------------------------------------------
a The previous option, SNCR with LNB + FGR has the same emission rate, making an incremental comparison invalid.
b Per ADEQ's and AEPCO's analyses, control options are ranked here by cost, not by emission rate
c Visibility improvement at Chiricahua Wilderness Area, the Class I area exhibiting the highest impact
d Cost-effectiveness values obtained from Table 10.3, Appendix D (TSD) of Arizona RH SIP. See Docket Item B-01.
In its cost calculations for Apache Unit 1, AEPCO used a capital
recovery factor based on a 7.10 percent interest rate, and a plant
remaining useful life of eight years.\29\ The plant's remaining useful
life was based upon Apache Unit 1 operating until 2021, and an assumed
BART implementation date of 2013.\30\ AEPCO eliminated many control
options, including SCR, based on high cost-effectiveness ($/ton), and
primarily examined the LNB w/FGR and ROFA control options. AEPCO noted
that LNB with FGR resulted in larger incremental visibility improvement
than ROFA, and proposed LNB with FGR, burning either natural gas or
fuel oil, as BART for NOX at Apache Unit 1.
---------------------------------------------------------------------------
\29\ See Docket Item B-02. Appendix A (Economic Analysis) of
AEPCO Apache 1 BART Analysis.
\30\ See Docket Item B-02. Page 2-1 of AEPCO Apache 1 BART
Analysis.
---------------------------------------------------------------------------
In order to evaluate AEPCO's BART analysis, ADEQ requested
supporting information explaining assumptions used in the economic
analysis, baseline emissions, and control technology options. Based on
this additional information, as well as on AEPCO's original analysis,
ADEQ accepted the company's proposed BART recommendation of LNB with
FGR for Unit 1, but added a fuel restriction to allow only the use of
natural gas. This determination corresponds to a BART emission limit
for NOX at Apache Unit 1 of 0.056 lb/MMBtu.\31\
---------------------------------------------------------------------------
\31\ See Docket Item B-01. Emission rate as specified in Table
10.2, Appendix D (Technical Support Document) of Arizona Regional
Haze SIP.
---------------------------------------------------------------------------
EPA's Evaluation: We disagree with multiple aspects of the analysis
for Apache Unit 1. We consider the use of eight years for the plant's
remaining useful life in the control cost calculations as unjustified
in the absence of documentation that the unit will shut down in 2021.
We also note that control cost calculations include costs that are
disallowed by EPA's Control Cost Manual, such as owner's costs and
AFUDC. Both of these elements have the effect of inflating cost
calculations and thus the cost-effectiveness of the various control
options considered. In addition, we do not consider using identical
baseline emissions for No. 2 fuel oil and natural gas appropriate,
although this likely did not affect either AEPCO's or ADEQ's BART
determination, which was informed primarily by emission estimates based
on No. 6 fuel oil, the highest emitting fuel.
By including a natural gas-only fuel restriction, ADEQ's BART
determination of LNB with FGR results in a NOX emissions
limit of 0.056 lb/MMBtu, which is more stringent than any of the
control options that AEPCO and ADEQ considered in conjunction with No.
6 or No. 2 fuel oil. Neither AEPCO's nor ADEQ's analysis, however,
included visibility modeling for control options on a natural gas-only
basis. The absence of such information does not allow us to fully
evaluate if options more stringent than LNB with FGR are appropriate on
a natural gas-only basis. Nevertheless, we are proposing to approve
ADEQ's NOX BART determination of LNB with FGR (natural gas
usage only) with an emission limit of 0.056 lb/MMBtu for Apache Unit 1.
b. BART for PM10
ADEQ's Analysis: Apache Unit 1 currently operates with no
PM10 controls. In its BART analysis submitted to ADEQ, AEPCO
developed baseline emissions for multiple fuel use scenarios including
natural gas, and No. 2 and No. 6 fuel oil usage. Baseline
PM10 emissions for all fuels were calculated based on AP-42
emission factors.\32\ A summary of these emissions is in Table 4.
---------------------------------------------------------------------------
\32\ See Docket Item B-02, Page 2-1 of AEPCO Apache 1 BART
Analysis.
---------------------------------------------------------------------------
AEPCO examined multiple control options for PM10 at
Apache Unit 1, including add-on controls and fuel switching. A summary
of cost of compliance and degree of visibility improvement for these
options is summarized in Table 6. These cost and visibility improvement
values are based on baseline and control case emissions corresponding
to No. 6 fuel oil usage, which of the three fuels considered generates
the greatest PM10 emissions. In its BART analysis, AEPCO
cited high costs of compliance and minimal visibility improvements for
the PM10 control options, and proposed no PM10
controls as BART for PM10, using either natural gas or No. 2
fuel oil. Based on the data and analysis provided by AEPCO, ADEQ
determined that BART for PM10 at Apache Unit 1 is no
additional controls, but also determined that a fuel restriction to
allow only the use of natural gas was appropriate. This corresponds to
a PM10 BART emission
[[Page 42844]]
limit for Apache Unit 1 of 0.0075 lb/MMBtu.\33\
---------------------------------------------------------------------------
\33\ See Docket Item B-01. Emission rate as specified in Table
10.5, Appendix D (Technical Support Document) of Arizona Regional
Haze SIP.
Table 6--Apache Unit 1: Arizona's Cost and Visibility Analysis for PM10
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness \a\ Visibility Improvement
($/ton) \b\ (dv)
Emission Emissions Annualized ---------------------------------------------------
Control option rate (lb/ removed cost ($/ Incremental Total Incremental
MMBtu) (tons/yr) year) Average (from (from base (from
previous) case) previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline..................................................... 0.0737 ........... ........... ........... ........... ........... ...........
Fabric Filter................................................ 0.015 116 3,615,938 31,172 ........... 0.010 ...........
Fuel switch to PNG........................................... 0.0075 ........... 0 ........... ........... ........... ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------
a Cost-effectiveness values as reported in Table 10.6, Appendix D (TSD) of Arizona RH SIP. See Docket Item B-01.
b As summarized in Table 5-12, AEPCO Apache 1 BART Analysis. See Docket Item B-02. Visibility improvement at Chiricahua Wilderness Area, the Class I
area exhibiting the highest impact.
EPA's Evaluation: ADEQ's PM10 analysis includes many of
the same issues we noted in its NOX analysis, including the
use of an eight-year plant remaining useful life, and inclusion of
costs that are disallowed by EPA's Control Cost Manual. Although we do
not agree with elements of ADEQ's PM10 BART analysis for
Apache Unit 1, we find that its conclusion is reasonable, given the
small visibility improvement projected to result from PM10
reductions at this Unit. Thus, we are proposing to approve ADEQ's
PM10 BART determination for Apache Unit 1.
c. BART for SO2
ADEQ's Analysis: Apache Unit 1 currently operates with no
SO2 controls. In its BART analysis submitted to ADEQ, AEPCO
developed baseline emissions for multiple fuel use scenarios including
natural gas, and No. 2 and No. 6 fuel oil. Baseline natural gas
emissions were based upon the highest 75 percent load 24-hour
SO2 emission levels reported in EPA's Acid Rain Database for
2006. Since the only fuel burned in 2006 was natural gas, baseline
emissions for No. 2 or No. 6 fuel oil usage could not be developed
based on data from 2006. Baseline emissions for No. 2 and No. 6 fuel
oil usage were estimated using AP-42 emission factors.\34\ A summary of
these emissions is summarized in Table 4.
---------------------------------------------------------------------------
\34\ See Docket Item B-02. Page 2-2 of AEPCO Apache 1 BART
Analysis.
---------------------------------------------------------------------------
AEPCO also examined multiple control options for SO2 on
Apache 1, including add-on controls and fuel-switching. A summary of
cost of compliance and degree of visibility improvement for these
options is summarized in Table 7. These cost and visibility improvement
values are from baseline and control case emissions corresponding to
No. 6 fuel oil usage, which is the fuel type that generates the
greatest SO2 emissions. In its BART analysis, AEPCO cited
high costs of compliance and minimal visibility improvements for the
SO2 control options, and proposed no additional
SO2 controls, using either natural gas or No. 2 fuel oil, as
BART for SO2. ADEQ determined that BART for SO2
is no additional controls, but added a fuel restriction to allow only
the use of natural gas. This corresponds to an SO2 BART
emission limit for Apache Unit 1 of 0.00064 lb/MMBtu.\35\
---------------------------------------------------------------------------
\35\ See Docket Item B-01. Emission rate as specified in Table
10.7, Appendix D (Technical Support Document) of Arizona Regional
Haze SIP.
Table 7--Apache Unit 1: Arizona's Cost and Visibility Analysis for So2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness a ($/ Visibility Improvement b
ton) (dv)
Emission Emissions Annualized ------------------------------------------------------
Control option rate (lb/ removed cost ($/ Incremental Total Incremental
MMBtu) (tons/yr) year) Average (from (from base (from
previous) case) previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline.................................................. 0.906 ........... ........... ........... ........... ........... ..............
Fuel switch to low-sulfur fuel oil........................ 0.051 ........... ........... ........... ........... ........... ..............
Spray dryer absorber (dry FGD) 1.......................... 0.10 1,587 3,881,706 2,446 ........... 0.765 ..............
Fuel switch to PNG........................................ 0.00064 ........... 0 ........... ........... ........... ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
a Cost-effectiveness values as reported in Table 10.8, Appendix D (TSD) of Arizona RH SIP. See Docket Item B-01.
b As summarized in Table 5-12, AEPCO Apache 1 BART Analysis. See Docket Item B-02. Visibility improvement at Chiricahua Wilderness Area, the Class I
area exhibiting the highest impact.
EPA's Evaluation: The SO2 analysis includes many of the
same issues we noted in the NOX analysis, including the use
of an eight-year plant remaining useful life, and inclusion of costs
that are disallowed by EPA's Control Cost Manual. ADEQ's BART
determination, requiring the use of only natural gas, results in an
SO2 emission limit of 0.00064 lb/MMBtu. This emission rate
is more stringent than any of the control options that ADEQ considered
in conjunction with No. 6 fuel oil. We are proposing to approve ADEQ's
BART determination for SO2 as an emission limit of 0.00064
lb/MMBtu at Apache Unit 1.
2. Apache Units 2 and 3
Apache Units 2 and 3 are both dry-bottom, Riley Stoker turbo-fired
boilers, each with a gross unit output of 204 MW. Both units are BART-
eligible and are coal-fired boilers operating on sub-bituminous coal.
Although there are physical differences between the two units, ADEQ
found that the overall
[[Page 42845]]
differences are minimal and therefore considered both units together in
its BART analysis. As with Apache Unit 1, ADEQ's analysis relied
largely on information provided by AEPCO and its contractor. This
information is summarized below, along with ADEQ's determinations for
each pollutant and EPA's evaluation.
While the following sections describe both ADEQ's and EPA's
evaluations based on the information in the record, we note that we
received additional information from AEPCO on June 29, 2012, related to
the potential adverse impacts of the affordability of NOX
controls. AEPCO states that affordability is affected by its small
size, the low income profiles of AEPCO's service area, and AEPCO's
ability to access financing. While this information came in too late to
be evaluated as part of this proposed rulemaking, EPA has put the
information in the docket and will evaluate it during the public
comment period.\36\
---------------------------------------------------------------------------
\36\ See Docket Item C-16, Letter from Michelle Freeark (AEPCO)
to Deborah Jordan (EPA), AEPCO's Comments on BART for Apache
Generating Station, June 29, 2012.
---------------------------------------------------------------------------
a. BART for NOX
ADEQ's Analysis: AEPCO developed baseline NOX emissions
by examining the average NOX emissions from 2002 to 2007, a
time period in which both units were equipped with OFA as
NOX emission controls.\37\ AEPCO examined several
NOX control technologies, including combustion controls and
add-on post-combustion controls. A summary of Arizona's costs of
compliance and visibility impacts associated with these options is
presented in Table 8. ADEQ relied on this information from the facility
to develop its RH SIP.\38\ Estimates of control technology emission
rates were developed based on a combination of vendor quotes,
contractor information, and internal AEPCO information regarding
environmental upgrades.\39\ Annual emission reductions were calculated
based on the emission rate estimates combined with annual capacity
factors as specified by AEPCO.\40\ Control costs were developed based
on a combination of vendor quotes and contractor information. These
cost calculations provided line item summaries of capital costs and
annual operating costs, but did not include further supporting
information such as detailed equipment lists, vendor quotes, or the
design basis for line item costs.
---------------------------------------------------------------------------
\37\ See Docket Item B-03 and B-04, AEPCO Apache BART Analyses,
page 2-2.
\38\ See Docket Item B-03 and B-04, AEPCO Apache BART Analyses.
This information is also summarized in Docket Item B-01, Arizona
Regional Haze SIP, Appendix D, Tables 10.10 through 10.13.
\39\ As listed in Table 3-2, Docket Items B-03 and B-04, AEPCO
Apache BART Analyses.
\40\ As listed in Table 2-1, Docket Items B-03 and B-04. Annual
capacity factors used for each unit are 92% (Apache 2), and 87%
(Apache 3).
Table 8--Apache Units 2 and 3: Arizona's Cost and Visibility Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness ($/ Visibility improvement
ton) \a\ (deciviews) Cost per
Emission Emissions Annualized -------------------------------------------------- total
Control option rate (lb/ removed cost ($/ Incremental Total Incremental deciview
MMBtu) (tons/yr) year) Average (from (from (from improvement
previous) baseline) previous) ($/dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Apache Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline).................................... 0.47 .......... ............ .......... ........... .......... ........... ............
LNB + OFA......................................... 0.31 1,305 $533,000 $408 ........... 0.267 ........... $1,996,000
ROFA.............................................. 0.26 1,710 1,664,000 973 305 0.359 0.092 4,636,000
SNCR + LNB + OFA.................................. 0.23 1,953 1,738,000 890 1,860 0.416 0.057 4,532,000
ROFA w/Rotamix.................................... 0.18 2,358 2,225,000 944 866 0.491 0.075 4,177,000
SCR + LNB + OFA................................... 0.07 3,250 6,102,000 1,878 4,346 0.676 0.185 9,028,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Apache Unit 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline).................................... 0.43 .......... ............ .......... ........... .......... ........... ............
LNB + OFA......................................... 0.31 926 532,808 575 ........... 0.206 ........... 2,586,000
ROFA.............................................. 0.26 1,312 1,643,241 1,252 322 0.298 0.092 5,484,000
SNCR + LNB + OFA.................................. 0.23 1,543 1,717,633 1,113 1,920 0.356 0.058 5,004,000
ROFA w/Rotamix.................................... 0.18 1,929 2,181,833 1,131 873 0.436 0.080 4,825,000
SCR + LNB + OFA................................... 0.07 2,778 6,062,301 2,182 4,571 0.633 0.197 9,577,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ At the Class I area exhibiting the greatest baseline visibility impact, Chiricahua Wilderness Area.
Regarding visibility impacts, ADEQ relied on visibility modeling
submitted by AEPCO to evaluate the visibility improvement attributable
to each of the NOX control technologies that it considered.
This visibility modeling was performed using three years of
meteorological data (2001 to 2003), and was generally performed in
accordance with the WRAP modeling protocol. The average of the three
98th percentiles from the modeled years 2001 to 2003 was used as the
visibility metric for each emission scenario and Class I area. For
assessing the degree of visibility improvement, ADEQ considered only
the visibility benefits at the area with the highest base case (pre-
control) impact: Chiricahua National Monument and Chiricahua Wilderness
Area (two nearby Class I areas served by one air monitor). For each
control, ADEQ listed visibility improvement in deciviews, and cost in
millions of dollars per deciview improvement.\41\ Results are
comparable for both units, with Unit 2 showing somewhat higher
visibility benefits and somewhat lower cost per improvement than Unit
3. Unit 2 visibility improvements range from 0.27 dv for LNB to 0.68 dv
for SCR, while the costs per deciview range from $2 million for LNB to
over $9 million for SCR. ADEQ concluded that LNBs with the existing OFA
systems represent BART for Units 2 and 3, though no explicit reasoning
is provided for the selection.
---------------------------------------------------------------------------
\41\ Arizona SIP submittal, ``Appendix D: Arizona BART--
Supplemental Information'', p. 65.
---------------------------------------------------------------------------
ADEQ determined that LNB plus OFA constitute BART for
NOX at Apache Units 2 and 3. In making this determination,
ADEQ did not provide adequate information regarding its rationale or
weighing of the five factors. ADEQ stated only that ``(A)fter reviewing
the company's BART analysis, and based upon the information above, ADEQ
has
[[Page 42846]]
determined that, for Units 2 and 3 BART for NOX is new LNBs
and the existing OFA system with a NOX emissions limit of
0.31 lb/MMBtu * * *.'' \42\
---------------------------------------------------------------------------
\42\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D,
Page 65.
---------------------------------------------------------------------------
EPA's Evaluation: We disagree with several aspects of the
NOX BART analysis for Apache Units 2 and 3. The control cost
calculations included line item costs not allowed by the EPA Control
Cost Manual, such as owner's costs, surcharge, and AFUDC. Inclusion of
these line items has the effect of inflating the total cost of
compliance and the cost per ton of pollutant reduced.
Regarding visibility improvement as shown in Table 8, ADEQ chose
LNB as BART, which provides the lowest visibility benefit of any of the
controls modeled. By contrast, SCR would provide an improvement of more
than 0.5 dv at a single Class I Area, and a substantial incremental
benefit relative to the next more stringent control, ROFA-Rotamix.
Multiple Class I areas have comparable benefits. The visibility
benefits are larger than those listed, if both Units 2 and 3 are
considered together. (See Table 17 below for EPA's visibility results.)
The SCR cost per deciview of improvement is lower than those for Cholla
and Coronado, as indicated below in their respective sections.
ADEQ provides little explicit reasoning about the visibility basis
for the BART selection. For example, there is no weighing of visibility
benefits and visibility cost-effectiveness for the various candidate
controls and the various Class I areas. The modeling results show that
controls more stringent than LNB appear to be needed to give
substantial visibility benefits. Visibility impacts at eight nearby
Class I areas were not considered, and the visibility benefits of
simultaneous controls on both units were not considered. For these
reasons, EPA believes that ADEQ gave insufficient consideration to the
visibility benefits of the various NOX control options
available at Apache Units 2 and 3.
In summary, we find that ADEQ has not provided an adequate
justification for adopting LNB with OFA as the ``best'' level of
control.\43\ Although ADEQ has developed information regarding each of
the five factors, there are problems in both its cost and visibility
analyses as described above. Moreover, ADEQ's BART analysis does not
explain how it weighed these factors. For example, ADEQ did not
indicate whether or not it considered any cost thresholds to be
reasonable or expensive in analyzing the costs of compliance for the
various control options. We note that ADEQ has made similar
NOX BART determinations of LNB with OFA at other facilities,
such as Cholla Power Plant. Although ADEQ's BART determinations for
these other facilities implied that cost of compliance was an important
consideration, it does not provide a rationale for this selection of
NOX BART.\44\ Thus, we are proposing to disapprove ADEQ's
BART determination for NOX at Apache Units 2 and 3, since it
does not comply with 40 CFR 51.308(e)(1)(ii)(A).
---------------------------------------------------------------------------
\43\ See BART Guidelines, Sec. IV.E.2.
\44\ We do note, however, that AEPCO does provide some
additional analysis on this position in the Apache BART analyses it
submitted to ADEQ. Aside from stating that it reviewed AEPCO's
analysis, ADEQ did not specifically reference or include any aspects
of AEPCO's analysis in the RH SIP. As a result, we are not assuming
that ADEQ necessarily agrees with AEPCO's rationale, and have
therefore not provided an evaluation of it.
---------------------------------------------------------------------------
b. BART for PM10
ADEQ's Analysis: The existing PM10 controls on Apache
Units 2 and 3 are hot-side Electrostatic Precipitators (ESPs).\45\
AEPCO and ADEQ considered three potential retrofit control options for
PM10:
---------------------------------------------------------------------------
\45\ See Appendix D, pages 65-69 for ADEQ's BART Analysis for
PM10 at Apache Units 2 and 3. See AEPCO Apache Unit 2
BART Analysis.
---------------------------------------------------------------------------
Performance upgrades to existing hot-side ESP,
Replacement of current ESP with a fabric filter, and
Installation of a polishing fabric filter after ESP.
ADEQ found that all of these options are technically feasible and
estimated their associated emission rates as shown in Table 9.
Table 9--Apache Units 2 and 3: Arizona's Controls and Emission Rates for
PM10
------------------------------------------------------------------------
Control technology Expected PM10 emission rate
------------------------------------------------------------------------
ESP Upgrades........................... 0.03 lb/MMBtu.
Full Size Fabric Filter................ 0.015 lb/MMBtu.
Polishing Fabric Filter................ 0.015 lb/MMBtu.
------------------------------------------------------------------------
ADEQ found that a fabric filter, whether in addition to or as
replacement for the ESP, would require additional energy, but did not
identify any non-air environmental impacts from any of the three
options. The cost of compliance and degree of visibility improvement
for each of these options, as analyzed by ADEQ, are summarized in
Tables 10 and 11.
Table 10--Apache Unit 2: Arizona's Control Cost of Visibility Reduction for PM10
----------------------------------------------------------------------------------------------------------------
Total Cost per
Deciview annualized deciview Average cost
Control reduction cost (million reduced ($/ton)
$) (million $/dv)
----------------------------------------------------------------------------------------------------------------
ESP Upgrades.................................... Unknown Unknown Unknown Unknown
Polishing Fabric Filter......................... 0.085 $2.217 $26.09 $9,121
Full Size Fabric Filter......................... 0.085 2.888 33.98 11,880
----------------------------------------------------------------------------------------------------------------
Table 11--Apache Unit 3: Arizona's Control Cost of Visibility Reduction for PM10
----------------------------------------------------------------------------------------------------------------
Total Cost per
Deciview annualized deciview Average cost
Control reduction cost (million reduced ($/ton)
$) (million $/dv)
----------------------------------------------------------------------------------------------------------------
ESP Upgrades.................................... Unknown Unknown Unknown Unknown
Polishing Fabric Filter......................... 0.094 $2.192 $23.32 $9,471
Full Size Fabric Filter......................... 0.094 $2.869 $30.52 12,390
----------------------------------------------------------------------------------------------------------------
[[Page 42847]]
Based on its analysis of the five BART factors, as summarized
above, ADEQ found BART for PM10 is upgrades to the existing
ESP and a PM10 emissions limit of 0.03 lb/MMBtu for Units 2
and 3. In particular, ADEQ referred to installation of a flue gas
conditioning system, improvements to the scrubber bypass damper system,
and implementation of programming optimization measures for ESP
automatic voltage controls as potential upgrades. ADEQ also noted that
``PM10 emissions will be measured by conducting EPA Method
201/202 tests.''
EPA's Evaluation: As noted above, AEPCO's and ADEQ's control cost
calculations include costs that are disallowed by EPA's Control Cost
Manual, such as owner's costs and AFUDC.\46\ In addition, AEPCO's and
ADEQ's analyses do not demonstrate that all potential upgrades to the
existing ESP were fully evaluated. Nonetheless, based on the small
visibility improvement associated with PM10 reductions from
these units (e.g., less than 0.1 dv improvement from the most stringent
technology), we conclude that additional analyses of control options
would not result in a different BART determination. As a result, we
propose to approve ADEQ's PM10 BART determination at Apache
Units 2 and 3.
---------------------------------------------------------------------------
\46\ See AEPCO BART Analysis Technical Memorandum dated July 8,
2009, page 12.
---------------------------------------------------------------------------
Finally, we are seeking comment on whether test methods other than
EPA Method 201 and 202 \47\ (chosen by ADEQ) should be allowed or
required for establishing compliance with the PM10 limits
that we are approving. In particular, as explained below, use of SCR
\48\ at these units is expected to result in increased condensable
particulate matter in the form of sulfuric acid mist
(H2SO4). In effect, the emission limit would be
more stringent than intended by ADEQ and would likely not be achievable
in practice. In order to avoid this result, while still assuring proper
operation of the particulate control devices, we are requesting on
comment on whether to allow compliance with the PM10 limit
to be demonstrated using test methods that do not capture condensable
particulate matter, namely EPA Methods 1 through 4 and Method 5 or
Method 5e.\49\ Method 201 is very rarely used for testing. The typical
method used for filterable PM10 is Method 201A, ``constant
sampling rate procedure,'' which is similar to Method 201, but is much
more practical to perform on a stack.
---------------------------------------------------------------------------
\47\ See 40 CFR part 51 Appendix M.
\48\ EPA is proposing SCR as BART for all of the coal-fired
units. See Section VII.
\49\ See 40 CFR part 60 appendix A.
---------------------------------------------------------------------------
c. BART for SO2
ADEQ's Analysis: Apache Units 2 and 3 currently have wet limestone
scrubbers installed for SO2 removal.\50\ Under the BART
Guidelines, a state is not required to evaluate the replacement of the
current SO2 controls if their removal efficiency is over 50
percent, but should consider cost-effective scrubber upgrades designed
to improve the system's overall SO2 removal efficiency.
Relying upon the BART analysis submitted by AEPCO,\51\ ADEQ found that
the following potential upgrades to the scrubbers are technically
feasible:
---------------------------------------------------------------------------
\50\ See Arizona Regional Haze SIP, Appendix D, pages 69-71 for
ADEQ's BART Analysis for SO2 at Apache Units 2 and 3.
\51\ See AEPCO Apache Unit 2 BART Analysis.
---------------------------------------------------------------------------
Elimination of bypass reheat,
Installation of liquid distribution rings,
Installation of perforated trays,
Use of organic acid additives,
Improved or upgraded scrubber auxiliary system equipment,
and
Redesigned spray header or nozzle.
ADEQ found that any upgrades likely would not increase power
consumption, but would increase scrubber waste disposal and makeup
water requirements, and would reduce the stack gas temperature. These
three factors are the normal outcome of treating more of the exhaust
gas and removing more of the SO2 (increased scrubber waste
disposal) and should not be given much weight in selecting a BART
emission limit. ADEQ also noted that AEPCO had already made the
following upgrades to the scrubbers: Elimination of flue gas bypass;
splitting the limestone feed to the absorber feed tank and tower sump;
upgrade of the mist eliminator system; installation of suction screens
at pump intakes; automation of pump drain valves, and replacement of
scrubber packing with perforated stainless steel trays. In addition,
AEPCO tried using dibasic acid additive, but found that it did not
result in significantly higher SO2 removal. ADEQ did not
evaluate the cost or visibility impacts of any additional upgrades to
the scrubbers, but determined that BART for SO2 emissions
was no new controls and an emission limit of 0.15 lb/MMBtu on a 30-day
rolling average basis.
EPA's Evaluation: We are proposing to approve ADEQ's SO2
BART determination for Apache Units 2 and 3. Although ADEQ has not
demonstrated that it fully considered all cost effective scrubber
upgrades, as recommended by the BART Guidelines, ADEQ conducted a five-
factor BART analysis and its final SO2 BART determination
for Apache Units 2 and 3 is consistent with the presumptive BART limit
of 0.15 lb/MMBtu for utility boilers.\52\ We have no evidence that
additional analysis would have resulted in a lower emission limit.
Therefore, we are proposing to approve the SO2 emission
limit of 0.15 lb/MMBtu (30-day rolling average) for Apache Units 2 and
3.
---------------------------------------------------------------------------
\52\ See BART Guidelines Sec. IV.E.4.
---------------------------------------------------------------------------
However, we note that Apache can receive coal from a number of
different mines that can have differing sulfur content and potential
for SO2 emissions.\53\ Therefore, we are seeking comment on
whether additional cost-effective scrubber upgrades are available that
would warrant a lower emission limit. We are also requesting comment on
whether requiring 90 percent control efficiency in addition to the lb/
MMBtu limit would better assure proper operation of the upgraded
scrubbers when burning some types of low-sulfur western coal. If we
receive information establishing that a lower limit is achievable or
that a control efficiency requirement is needed, then we may disapprove
the SO2 emissions limit set by ADEQ and promulgate a revised
limit for one or both of these units.
---------------------------------------------------------------------------
\53\ See, e.g. Apache Unit 2 BART Analysis, Table 3-1.
---------------------------------------------------------------------------
3. Cholla Units 2, 3 and 4
Cholla Power Plant consists of four primarily coal-fired
electricity generating units with a total plant-wide generating
capacity of 1,150 megawatts. Unit 1 is a 125 MW tangentially-fired,
dry-bottom boiler that is not BART-eligible. Units 2, 3 and 4 have
capacities of 300 MW, 300 MW and 425 MW, respectively, and are
tangentially-fired, dry-bottom boilers that are each BART-eligible.
Based on information provided by APS, the Cholla units operate on a
blend of bituminous and sub-bituminous rank coals from the Lee Ranch
and El Segundo mines.\54\
---------------------------------------------------------------------------
\54\ A copy of the coal contract, including obligation amounts
and coal quality, can be found in Docket Item B-09, ``Additional APS
Cholla BART response'', Appendix B.
---------------------------------------------------------------------------
a. BART for NOX
ADEQ's Analysis: APS submitted a BART analysis to ADEQ in January
2008. At the time of submittal, Cholla Units 2, 3 and 4 were equipped
with close-coupled overfire air (COFA) as NOX controls. APS
developed baseline NOX emissions by examining the highest
24-hour average emissions from
[[Page 42848]]
2001 to 2003.\55\ APS examined several NOX control
technologies, including combustion controls and add-on post combustion
controls. A summary of the costs of compliance and visibility impacts
associated with these options is presented in Table 12.
---------------------------------------------------------------------------
\55\ See Docket Item B-06 through -08, APS Cholla BART Analyses,
page 2-2.
Table 12--Cholla Units 2, 3, and 4: Arizona's Cost and Visibility Summary for NOX
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness ($/ Visibility improvement
ton) \a\ (deciviews) Cost per
Emission Emissions Annualized -------------------------------------------------- total
Control option rate (lb/ removed cost ($/ Incremental Total Incremental deciview
MMBtu) (tons/yr) year) Average (from (from (from improvement
previous) baseline) previous) ($/dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cholla 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
COFA (baseline)................................... 0.50 .......... ............ .......... ........... .......... ........... ............
LNB + SOFA........................................ 0.22 3,314 $635,000 $192 ........... 0.187 ........... $3,400,000
SNCR + LNB + SOFA................................. 0.17 3,900 2,175,000 558 2,628 0.218 0.031 9,980,000
ROFA.............................................. 0.16 4,017 2,297,000 572 1,043 0.232 0.014 9,900,000
ROFA w/Rotamix.................................... 0.12 4,485 3,384,000 755 2,323 0.261 0.029 12,970,000
SCR + LNB + SOFA.................................. 0.07 5,071 9,625,000 1,898 10,650 0.287 0.026 33,540,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cholla 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
COFA (baseline)................................... 0.41 .......... ............ .......... ........... .......... ........... ............
LNB + SOFA........................................ 0.22 2,096 635,000 303 ........... 0.13 ........... 5,040,000
SNCR + LNB + SOFA................................. 0.17 2,648 2,157,000 815 2,757 0.16 0.038 13,150,000
ROFA.............................................. 0.16 2,758 2,243,000 813 782 0.17 0.005 13,270,000
ROFA w/Rotamix.................................... 0.12 3,200 3,308,000 1,034 2,410 0.20 0.029 16,710,000
SCR + LNB + SOFA.................................. 0.07 3,751 9,569,000 2,551 11,363 0.23 0.032 41,610,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cholla 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
COFA (baseline)................................... 0.42 .......... ............ .......... ........... .......... ........... ............
LNB + SOFA........................................ 0.22 3,390 820,000 242 ........... 0.21 ........... 3,960,000
SNCR + LNB + SOFA................................. 0.17 4,259 2,852,000 670 2,338 0.27 0.058 10,760,000
ROFA.............................................. 0.16 4,433 3,179,000 717 1,879 0.28 0.016 11,310,000
ROFA w/Rotamix.................................... 0.12 5,129 4,537,000 885 1,951 0.34 0.055 13,500,000
SCR + LNB + SOFA.................................. 0.07 5,998 13,230,000 2,206 10,003 0.41 0.072 32,430,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ At the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park.
This information is contained in the Cholla BART analyses for each
unit, and was relied upon by ADEQ in developing its RH SIP.\56\
Estimates of control technology emission rates were developed based on
a combination of vendor quotes, contractor information, and internal
APS information regarding environmental upgrades.\57\ Annual emission
reductions were calculated based upon the emission rate estimates
combined with annual capacity factors as reported in CAMD data from
2001 to 2006.\58\ Control costs were also developed based on a
combination of vendor quotes and contractor information. These cost
calculations provided line item summaries of capital costs and annual
operating costs, but did not provide further supporting information
such as detailed equipment lists, vendor quotes, or the design basis
for line item costs.
---------------------------------------------------------------------------
\56\ See Docket Item B-06 through -08, APS Cholla BART Analyses.
This information is also summarized in Docket Item B-01, Arizona
Regional Haze SIP, Appendix D, Tables 11.3 through 11.5.
\57\ As described in Table 3-2, Docket Items B-06 through -08,
APS Cholla BART Analyses.
\58\ As listed in Table 2-1, Docket Items B-06 through -08.
Annual capacity factors used for each unit are 91 percent (Cholla
2), 86 percent (Cholla 3), and 93 percent (Cholla 4).
---------------------------------------------------------------------------
As part of its BART analysis, APS performed visibility modeling in
order to evaluate the visibility improvement attributable to each of
the NOX control technologies that it considered. This
visibility modeling was performed using three years of meteorological
data (2001 to 2003), and was generally performed in accordance with the
WRAP protocol, with a few exceptions. For example, rather than using a
constant monthly ammonia background concentration of 1.0 ppb as
specified in the WRAP protocol, APS used a variable monthly background
ammonia concentration that varied from 0.2 ppb to 1.0 ppb.
For assessing the degree of visibility improvement, ADEQ considered
only the visibility benefits at the area with the highest base case
(pre-control) impact, the Petrified Forest National Park. For each
control, ADEQ listed visibility improvement in deciviews, and
visibility cost-effectiveness, (Arizona SIP submittal, ``Appendix D:
Arizona BART--Supplemental Information'', p.77) as in the comparable
section for Apache. For Unit 2, improvements range from 0.19 dv for LNB
with SOFA to 0.29 dv for SCR. Costs per deciview range from $3.4
million for LNB to $33.5 million for SCR. Benefits for Unit 3 are about
20 percent lower (0.13 to 0.23 deciview), and for Unit 4 are about 20
percent higher (0.21 to 0.41 deciview), with percent differences
increasing with more stringent control. For Unit 3, costs per deciview
range from $5 million for LNB with SOFA to $41.6 million for SCR (about
30 percent higher than for Unit 2). For Unit 4, costs range from $4
million for LNB with SOFA to $32.4 million for SCR (about 20 percent
higher except that SCR has a slightly lower cost per deciview).
ADEQ concluded (ibid., p. 79) that LNBs with new SOFA systems
represent BART for all three units, noting that for all scenarios the
visibility benefits were less than 0.5 dv. ADEQ also stated that SCR,
the most expensive option, provides only about 0.1 dv benefit more than
LNB with SOFA, the least expensive option. This statement appears to
apply only to Units 2 and 3; the comparable benefit for Unit 4 is 0.2
dv.
In evaluating APS' BART analysis, ADEQ requested supporting
information explaining certain assumptions used in the economic
analysis, baseline emissions, and control technology options. Based on
this additional
[[Page 42849]]
information as well as APS' original BART analysis, ADEQ determined
that LNB with SOFA is BART for NOX at Cholla Units 2, 3, and
4. In making this determination, ADEQ relied almost exclusively on the
degree of visibility improvement. ADEQ cited small visibility
improvement on a per-unit basis, stating that ``the change in deciviews
between the least expensive and most expensive NOX control
technologies [..] is only 0.104 deciviews.'' \59\ ADEQ's determination
suggests that total capital costs may have been a consideration,
although it is not clear to what extent this may have informed ADEQ's
decision making, with the RH SIP simply stating, ``[t]he corresponding
capital costs are $5.4 million for LNB/SOFA and $82.8 million for SCR
with LNB/SOFA.'' \60\
---------------------------------------------------------------------------
\59\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D,
Page 79.
\60\ Id.
---------------------------------------------------------------------------
EPA's Evaluation: We disagree with several aspects of the analyses
performed for Cholla Units 2, 3, and 4. Regarding the control cost
calculations, we note that certain line item costs not allowed by the
EPA Control Cost Manual were included, such as owner's costs,
surcharge, and AFUDC. Inclusion of these line items has the effect of
inflating the total cost of compliance and the cost per ton of
pollutant reduced. As a result, we are proposing to find that ADEQ did
not follow the requirements of section 51.308(e)(1)(ii)(A) by not
properly considering the costs of compliance for each control option.
Regarding ADEQ's analysis of visibility impacts, the modeling
procedures relied on by ADEQ for assessing the visibility impacts from
Cholla were generally in accord with EPA guidance, but the use of the
modeling results in evaluating the BART visibility factor was
problematic. As was the case for Apache, ADEQ appears to have
considered benefits from controls on only one emitting unit at a time.
EPA believes that ADEQ's use of this procedure substantially
underestimates the degree of visibility improvement from controls. ADEQ
also overlooked comparable benefits at seven Class I areas besides
Petrified Forest, thereby understating the full visibility benefits of
the candidate controls. Using the default 1 ppb ammonia background
concentration would also have increased estimated impacts and control
benefits. For these reasons, EPA proposes to find that the ADEQ
selection of LNB for Cholla under the degree of visibility improvement
BART factor is not adequately supported, and that more stringent
control may be warranted.
b. BART for PM10
ADEQ's Analysis: As of May 2009, Cholla Units 3 and 4 were both
equipped with fabric filters for PM10 control, while Cholla
Unit 2 was equipped with a mechanical dust collector and a venturi
scrubber.\61\ In its BART analysis, ADEQ noted that the facility had
committed to install a fabric filter at Unit 2 by 2015. Because fabric
filters are the most stringent control available for reducing
PM10 emissions, ADEQ did not conduct a full BART analysis,
but concluded that fabric filters and an emission limit of 0.015 lb/
MMBtu are BART for control of PM10 at Units 2, 3, and 4.
ADEQ also noted that ``PM10 emissions will be measured by
conducting EPA Method 201/202 tests.''
---------------------------------------------------------------------------
\61\ See Arizona Regional Haze SIP, Appendix D, pages 79-81 for
ADEQ's BART Analysis for PM10 at Cholla Units 2, 3, and
4.
---------------------------------------------------------------------------
EPA's Evaluation: Given that ADEQ has chosen the most stringent
control technology available and set an emissions limit consistent with
other units employing this technology, we are proposing to approve this
BART determination of an emission limit of 0.015 lb/MMBtu for
PM10 at Cholla Units 2, 3, and 4.
c. BART for SO2
Cholla Units 2, 3, and 4 are all equipped with wet lime scrubbers
for SO2 control.\62\ Specifically, Unit 2 is equipped with
four venturi flooded disc scrubbers/absorber with lime reagent, capable
of achieving 0.14 lb/MMBtu to 0.25 lb/MMBtu of SO2. Units 3
and 4 were retrofitted in 2009 and 2008, respectively, with scrubbers
capable of achieving 0.15 lb/MMBtu of SO2.
---------------------------------------------------------------------------
\62\ See Arizona Regional Haze SIP, Appendix D, pp. 81-83, for
ADEQ's BART Analysis for SO2 at Cholla Units 2, 3, and 4.
---------------------------------------------------------------------------
ADEQ's Analysis: Based on a limited five-factor analysis, ADEQ
determined BART for SO2 at Cholla Unit 2 is upgrades to the
existing scrubber that would achieve a limit of 0.15 lb/MMBtu. Because
the BART analysis submitted by APS was conducted prior to installation
of the scrubbers on Units 3 and 4, it included an analysis of other
potential control technologies, namely, dry flue gas desulfurization
and dry sodium sorbent injection. However, APS had already installed
the wet lime scrubbers by the time ADEQ conducted its own BART
analysis. Therefore, ADEQ did not consider SO2 controls
other than wet lime scrubbers for Units 3 and 4, but determined BART as
use of these scrubbers with an associated emission limit of 0.15 lb/
MMBtu of SO2.
EPA's Evaluation: We are proposing to approve ADEQ's BART
determination for SO2 at Cholla Units 2, 3, and 4. Although
ADEQ did not fully consider all cost-effective scrubber upgrades as
recommended by the BART Guidelines, we have no basis for concluding
that additional analysis would have resulted in a lower emission limit.
Therefore, we are proposing to approve the SO2 emission
limit of 0.15 lb/MMBtu (30-day rolling average) for Cholla Units 2, 3,
and 4. However, we are seeking comment on whether additional cost-
effective scrubber upgrades are available that would warrant a lower
emission limit. If we receive comments establishing that a lower limit
is achievable, then we may disapprove the SO2 emissions
limit set by ADEQ and promulgate a revised limit for one or more of
these units.
4. Coronado Units 1 and 2
Coronado Generating Station consists of two EGUs with a total
plant-wide generating capacity of over 800 MW. Units 1 and 2 are both
dry-bottom, turbo-fired boilers, each with a gross unit output of 411
MW. Both units are BART-eligible and are coal-fired boilers operating
on primarily Powder River Basin sub-bituminous coal.
SRP entered into a consent decree with EPA in 2008.\63\ This
consent decree resolved alleged violations of the CAA which occurred at
Units 1 and 2 of the Coronado Generating Station, arising from the
construction of modifications without obtaining appropriate permits
under the Prevention of Significant Deterioration provisions of the
CAA, and without installing and applying best available control
technology. The consent decree resolved the claims alleged by EPA in
exchange for SRP's payment of a civil penalty and SRP's commitment to
perform injunctive relief including: (1) Installation of pollution
control technology to control emissions of NOX,
SO2, and PM--including flue gas desulfurization devices to
control SO2 on Units 1 and 2 at the Coronado Station and
installation of SCR to control NOX on one of the units (Unit
2); (2) meet specified emission rates or removal efficiencies for
NOX, SO2, and PM; (3) comply with a plant-wide
emissions cap for NOX; and (4) perform $ 4 million worth of
mitigation projects. The consent decree is not a permit, and compliance
with the consent decree does not guarantee compliance with all
applicable federal, state, or local laws or regulations. The emission
rates and
[[Page 42850]]
removal efficiencies set forth in the consent decree do not relieve SRP
from any obligation to comply with other state and federal requirements
under the CAA, including SRP's obligation to satisfy any State modeling
requirements set forth in the Arizona SIP.
---------------------------------------------------------------------------
\63\ See Docket Item G-01, Consent Decree between United States
and Salt River Project Agricultural Improvement and Power District.
---------------------------------------------------------------------------
a. BART for NOX
ADEQ's Analysis: ADEQ's BART analysis relied in large part on an
analysis submitted by SRP in February 2008. In its analysis, SRP
developed baseline NOX emissions by examining continuous
emission monitoring system (CEMS) data from 2001 to 2003.\64\ SRP
examined several NOX control technologies, including
combustion controls and add-on post combustion controls. A summary of
the costs of compliance and visibility impacts associated with these
options is presented in Table 13. This information was contained in the
SRP Coronado BART analysis, and was relied on by ADEQ in developing its
RH SIP. Estimates of control technology emission rates were developed
based on information provided by equipment vendors.\65\ SRP's analysis
did not provide an estimate of annual emissions.
---------------------------------------------------------------------------
\64\ See Docket Item B-10, SRP Coronado BART Analysis, page 3-1.
\65\ See Docket Item B-10, SRP Coronado BART Analysis, p. 4-5.
Table 13--Coronado Units 1 and 2: Arizona's Cost and Visibility Summary for NOX
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Emission rate (lb/ Cost-effectiveness \b\ Visibility Improvement in
MMBtu) ($/ton) improvement \c\ visibility index \e\
------------------------ Total Total ------------------------ (deciviews) Cost per (deciviews)
emissions annualized ------------------------ total -----------------------
Control option removed cost ($/ Incremental deciview Total
Unit 1 Unit 2 \a\ (tons/ year) Average (from Total Incremental improvement (from Incremental
yr) previous) (from (from \d\ ($/dv) base (from
baseline) previous) case) previous)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)............................................. 0.433 0.466 ......... ........... ......... ........... ......... ........... ........... ......... ...........
Full LNB + OFA............................................. 0.32 0.32 5,838 $1,227,000 $210 ........... 0.12 ........... $10,225,000 0.11 ...........
Full SNCR + LNB + OFA...................................... 0.22 0.22 10,195 4,654,000 456 787 0.16 0.04 29,087,500 0.19 0.080
Partial SCR + LNB + OFA \f\................................ 0.32 0.08 11,003 8,557,000 778 4,830 0.24 0.12 35,654,167 0.22 0.030
Full SCR + LNB + SOFA...................................... 0.08 0.08 16,730 17,090,000 1,022 1,490 0.39 0.27 43,820,513 0.34 0.120
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ SRP did not provide estimates of annual emissions in its BART analysis. These values are summarized from the Arizona RH SIP.
\b\ Cost-effectiveness was not presented in the Arizona RH SIP. These values are calculated from the emission removal and annualized costs that were included in the RH SIP.
\c\ Visibility improvement at the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park, from the SRP Coronado BART Analysis.
\d\ Cost per total deciview improvement was not presented in the Arizona RH SIP. These values are calculated from the annualized costs that were included in the RH SIP, and the visibility
improvement at Petrified Forest National Park, from the SRP Coronado BART Analysis.
\e\ Visibility index used in the Arizona RH SIP is the average of the impacts over the nine closest Class I areas.
\f\ This control option examined LNB+OFA on Unit 1 and SCR on Unit 2.
Control costs for the various options considered were developed by
Sargent and Lundy, the engineering firm retained by SRP for emission
control projects at Coronado. In its BART analysis and subsequent
additional response to ADEQ, SRP provided summaries of total control
costs, such as total annual operating and maintenance costs and total
annualized capital cost, but did not provide cost information at a
level of detail that included line item costs. \66\
---------------------------------------------------------------------------
\66\ See Docket Item B-11, Additional SRP Coronado response.
---------------------------------------------------------------------------
As part of its BART analysis, SRP performed visibility modeling in
order to evaluate the visibility improvement attributable to each of
the NOX control technologies that it considered. This
visibility modeling was performed using three years of meteorological
data (2001 to 2003), and relied partially on the WRAP protocol with
certain revisions based on EPA and Federal Land Manager guidance that
became available in the intervening period. For example, the WRAP
protocol used CALPUFF model version 6, whereas SRP used the current
EPA-approved CALPUFF version 5.8.
For assessing the degree of visibility improvement, ADEQ considered
a visibility index, defined as the average of the visibility benefits
at the closest nine Class I areas. The average included the five areas
with the highest baseline impacts. This metric is unlike that used for
Apache and Cholla, for which the benefits at the single area with
maximum baseline impact were used. Since it is an average, it is
somewhat similar to the sum of benefits over the nine areas, a
cumulative metric used in other analyses, except it is divided by nine
to compute the average. (Typically the sum would be computed over all
17 Class I areas impacted by the Coronado facility.) For each control,
ADEQ listed the average visibility improvement in deciviews, and cost
in millions of dollars per average deciview improvement.\67\
Improvements in the visibility index ranged from 0.11 dv for LNB with
OFA to 0.34 dv for SCR. Costs per deciview for the index ranged from
$11.1 million for LNB to $50.3 million for SCR (not shown in the Table
above).
---------------------------------------------------------------------------
\67\ Arizona RH SIP, Appendix D, p. 112.
---------------------------------------------------------------------------
While an average of the visibility benefits over the nearest areas
is an informative number, it is not directly comparable to the more
typical metrics of the maximum benefit seen at any area, and sum over
the areas. Moreover, neither the ADEQ RH SIP nor the facility's report
(BART Analysis for the Coronado Generating Station Units 1 & 2,
Document No. 05830-012-200, ENSR Corporation, February 2008) include
control benefits for individual Class I areas. Thus, the maximum area
benefit cannot be read from either document. However, the benefits can
be computed from the individual area impacts that are provided in SRP's
report, including for Petrified Forest National Park, which had the
highest baseline impact. Figures that are comparable to those for
Apache and Cholla are included in the Table 13. Coronado's maximum area
visibility benefits range from 0.12 dv for LNB to 0.39 dv for SCR. The
costs per deciview range from $10.2 million for LNB with OFA to $43.8
for SCR.
In evaluating SRP's BART analysis, ADEQ requested additional
supporting information from SRP regarding control cost calculations,
and for further explanation regarding SRP's recommendation for BART for
NOX. In developing its Regional Haze SIP, ADEQ
[[Page 42851]]
determined that LNB with OFA constitutes BART for NOX at
Coronado Units 1 and 2. In making this determination, ADEQ did not
provide adequate information regarding its rationale or weighing of the
five factors, stating only ``[a]fter reviewing the BART analysis
provided by the company, and based upon the information above, ADEQ has
determined that BART for NOX at Coronado Units 1 and 2 is
advanced combustion controls (Low NOX burners with OFA) with
an associated NOX emission rate of 0.32 lb/MMBtu [..]'' \68\
---------------------------------------------------------------------------
\68\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D,
Page 112.
---------------------------------------------------------------------------
EPA's Evaluation: We disagree with several aspects of the BART
analysis for Coronado Units 1 and 2. Regarding the control cost
calculations, we note that SRP did not provide ADEQ with control cost
calculations at a level of detail that allowed for a comprehensive
review. Without such a level of review, we do not believe that ADEQ was
able to evaluate whether SRP's control costs were reasonable. As a
result, we are proposing to find that ADEQ did not follow the
requirements of section 51.308(e)(1)(ii)(A) because ADEQ did not
properly consider the costs of compliance for each control option.
The modeling procedures relied on by ADEQ for assessing the
visibility impacts from Coronado were generally in accord with EPA
guidance. Coronado Units 1 and 2 were modeled together, and the
modeling was done with the current regulatory version 5.8 of the
CALPUFF modeling system.\69\ However, the use of the modeling results
in evaluating the BART visibility factor was problematic. The modeling
results show that, of the controls considered, only SCR would provide
substantial visibility benefits; the other controls options would
provide roughly half the 0.5 dv contribution benchmark. ADEQ did not
consider the typical visibility metrics of benefit at the area with
maximum impact, nor benefits summed over the areas. Using the default 1
ppb ammonia background concentration would also have increased
estimated impacts and control benefits. For these reasons, EPA proposes
to find that the ADEQ selection of LNB with OFA for Coronado under the
degree of visibility improvement BART factor is not adequately
supported, and that more stringent control may be warranted. ADEQ
provided little reasoning about the visibility basis for the Coronado
BART selection. For example, there is no weighing of the visibility
benefits and visibility cost-effectiveness for the various candidate
controls and the various Class I areas.
---------------------------------------------------------------------------
\69\ Arizona Regional Haze SIP, Appendix D, p. 112.
---------------------------------------------------------------------------
In addition to the problems noted above, we find that overall ADEQ
has not documented its evaluation of the results of its five-factor
analysis, as required by 51.308(e)(1)(ii)(A) and the BART Guidelines.
Although ADEQ has developed information regarding each of the five
factors, its selection of BART does not cite or interpret information
from its analyses. ADEQ does not, for example, indicate whether or not
it considered any cost thresholds to be reasonable or expensive in
analyzing the costs of compliance for the various control options. We
note that ADEQ has made similar NOX BART determinations of
LNB with OFA at other facilities, such as Cholla Power Plant. Although
ADEQ's BART determinations for these other facilities implied that cost
of compliance was an important consideration, it does not provide a
rationale for the determination of NOX BART at Coronado.\70\
Therefore, we propose to determine that ADEQ did not follow the
requirements of section 51.308(e)(1)(ii)(A). We propose to disapprove
ADEQ's selection of LNB with OFA as BART for NOX at Coronado
Units 1 and 2.
---------------------------------------------------------------------------
\70\ We do note, however, that SRP does provide some additional
analysis on this position in the BART analysis it submitted to ADEQ
and in the responses it provided to ADEQ's additional questions.
Aside from stating that it reviewed SRP's analysis, ADEQ did not
specifically reference or include any aspects of SRP's analysis in
the RH SIP. As a result, we are not assuming that ADEQ necessarily
agrees with SRP's rationale, and have therefore not provided an
analysis of it.
---------------------------------------------------------------------------
b. BART for PM10
Emissions of PM10 from Coronado Units 1 and 2 are
currently controlled by hot-side ESPs.\71\ Under the terms of the
Consent Decree described above in Section 4, SRP is required to
optimize its ESPs to achieve a PM10 emission rate of 0.030
lb/MMBtu.\72\
---------------------------------------------------------------------------
\71\ See Arizona Regional Haze SIP, Appendix D, p. 112 for
ADEQ's BART Analysis for PM10 at Coronado Units 1 and 2;
and BART Analysis for Coronado Generating Station Units 1 and 2
(February 2008) for SRP's analysis.
\72\ Docket Item G-01, Consent Decree between United States and
Salt River Project Agricultural Improvement and Power District,
Sec. V.
---------------------------------------------------------------------------
ADEQ's Analysis: ADEQ conducted a streamlined PM10 BART
analysis for Coronado Units 1 and 2. In particular, ADEQ found that
``BART for similar emissions units with similar emissions controls was
determined to be 0.03 lb/MMBtu.'' ADEQ concluded that because Coronado
Units 1 and 2 are already meeting a limit of 0.03 lb/MMBtu, ``further
analysis was determined to be unnecessary.''
EPA's Evaluation: ADEQ's analysis does not demonstrate that all
potential upgrades to the existing ESPs were fully evaluated. However,
we have no evidence that additional reductions in PM10
emissions would be achievable or cost-effective, or that such
reductions would yield substantial visibility benefits. Therefore, we
propose to approve ADEQ's PM10 BART determination at
Coronado. However, we are seeking comment on whether additional cost-
effective upgrades to the existing ESPs are available that would
warrant a lower emission limit. If we receive comments establishing
that a lower limit is achievable, then we may disapprove the
PM10 emissions limit set by ADEQ and promulgate a revised
limit for one or both of these units.
Finally, we are seeking comment on whether test methods other than
EPA Method 201 and 202 \73\ (chosen by ADEQ) should be allowed or
required for establishing compliance with the PM10 limits
that we are approving. In particular, as explained below, use of SCR at
these units is expected to result in increased condensable particulate
matter in the form of H2SO4. In effect, the
emission limit would be more stringent than intended by ADEQ and would
likely not be achievable in practice. In order to avoid this result,
while still assuring proper operation of the particulate control
devices, we are requesting on comment on whether to allow compliance
with the PM10 limit to be demonstrated using test methods
that do not capture condensable particulate matter, namely EPA Methods
1 through 4 and Method 5 or Method 5e.\74\ Method 201 is very rarely
used for testing. The typical method used for filterable
PM10 is Method 201A, ``constant sampling rate procedure,''
which is similar to Method 201, but is much more practical to perform
on a stack.
---------------------------------------------------------------------------
\73\ See 40 CFR part 51 appendix M.
\74\ See 40 CFR part 60 appendix A.
---------------------------------------------------------------------------
c. BART for SO2
Emissions of SO2 at Coronado Units 1 and 2 are currently
controlled with the use of low-sulfur coal and partial wet flue
gas.\75\ However, the consent decree between EPA and SRP described
above requires installation of wet flue gas desulfurization (WFGD)
systems at either Unit 1 or Unit 2 by January 2012, and at the
remaining unit by January 1, 2013. Both units must achieve and maintain
a 30-day rolling average SO2 removal efficiency of at least
95.0
[[Page 42852]]
percent or a 30-day rolling average SO2 emissions rate of no
greater than 0.080 lb/MMBtu.
---------------------------------------------------------------------------
\75\ See Arizona Regional Haze SIP, Appendix D, pp. 113-15 for
ADEQ's BART Analysis for PM10 at Coronado Units 1 and 2;
and Docket No. B.10, BART Analysis for Coronado Generating Station
Units 1 and 2 (Feb. 2008) for SRP's analysis.
---------------------------------------------------------------------------
ADEQ's Analysis: Because WFGD is the most effective control
technology available for controlling SO2 emissions, ADEQ did
not evaluate other control options. Table 14 summarizes Arizona's the
costs of compliance and improvement in visibility expected to result
from installation of WFGD at both units. Based on this information,
ADEQ determined SO2 BART for both units is the installation
of WFGDs and an emission rate of 0.08 lbs/MMBtu on 30-day rolling
average basis.
Table 14--Coronado Units 1 and 2: Arizona's Bart Summary for SO2
------------------------------------------------------------------------
Option 1, baseline Option 2, WFGD
------------------------------------------------------------------------
Reduction in Emission (tpy)..... .................. 25,753
Annualized Cost................. .................. $44,353,330
Visibility Index (dv)........... 2.66 1.28
Improvement in Visibility Index .................. 1.38
(dv)...........................
Incremental Cost-effectiveness .................. $32,140,094
($ per dv).....................
------------------------------------------------------------------------
EPA's Evaluation: We are proposing to approve ADEQ's SO2
BART determination for Coronado Units 1 and 2. Although we do not
necessarily agree with the underlying cost and visibility analyses
performed by SRP, we have no evidence that additional analysis would
have resulted in a lower emission limit. Therefore, we propose to
approve ADEQ's SO2 emission limit of 0.08 lb/MMBtu (30-day
rolling average) for Coronado Units 1 and 2. However, we are seeking
comment on whether a lower emission limit may be achievable when the
units are burning a lower-sulfur coal. If we receive comments
establishing that a lower limit is achievable, then we may disapprove
the SO2 emissions limit set by ADEQ and promulgate a revised
limit for one or both of these units.
D. Enforceability of BART Limits
Regional Haze SIPs must include requirements to ensure that BART
emission limits are enforceable. In particular, the RHR requires
inclusion of (1) A schedule for compliance with BART for each source
subject to BART; (2) a requirement for each BART source to maintain the
relevant control equipment; and (3) procedures to ensure control
equipment is properly operated and maintained.\76\ General SIP
requirements also mandate that the SIP include all regulatory
requirements related to monitoring, recordkeeping and reporting for the
BART emissions limitations.\77\ ADEQ did not include any of these
elements in its Regional Haze SIP.\78\ Therefore, we are proposing to
disapprove this aspect of the Regional Haze SIP for these three sources
and to promulgate a FIP to ensure the emission limits are enforceable.
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\76\ 40 CFR 51.308(e)(1).
\77\ See, e.g. CAA section 110(a)(2) (F) and 40 CFR 51.212(c).
\78\ As described above, ADEQ did specify a test method for
PM10 for each of the relevant sources (Method 201/202).
However, we are proposing to also allow the use of test methods that
do not capture condensable particulate matter, namely EPA Methods 1
through 4 and Method 5 or Method 5e.
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VII. EPA's Proposed FIP Actions
A. EPA's BART Analyses and Determinations
EPA conducted a new five-factor BART analysis of the three
facilities in order to evaluate Arizona's RH SIP, and to document the
technical basis for proposing BART determinations in our FIP. Because
EPA generally concurs with ADEQ's BART analyses in Steps 1 and 2
(Identify All Available Retrofit Control Technologies and Eliminate
Technically Infeasible Options), we focused our technical analysis on
Steps 3, 4 and 5 (Evaluate Control Effectiveness of Remaining Control
Technologies, Evaluate Impacts and Document Results, and Evaluate
Visibility Impacts). We relied on contractor assistance from the
University of North Carolina Institute for the Environment to evaluate
control effectiveness, perform cost calculations, and conduct new
visibility modeling for each of the units at the three facilities,
except Apache Generating Station Unit 1 for which this level of
analysis was unnecessary. Our approach to each of these factors is
explained below, followed by our BART determinations for the three
sources in the next section. Copies of the contractor's reports and the
details of our BART analyses are in our Technical Support Document
(TSD) available in the docket.
1. Costs of Compliance
Cost Estimates and Calculations: In estimating the costs of
compliance, we have relied on facility data from a number of sources
including ADEQ, the Energy Information Administration (EIA), and EPA's
Control Cost Manual. As discussed previously, ADEQ, in developing its
RH SIP, requested certain clarifying information from the facilities
regarding their control cost calculations, including greater detail
regarding the underlying assumptions. ADEQ received responses of
varying detail to these requests. Although in some cases the facilities
provided summaries of certain broad line item costs, in no case does
the supporting information that is available provide detail at a level
that allows for critical review. In the case of SRP Coronado Generating
Station, ADEQ received only a broad summary of control costs without
itemized breakdowns of specific costs.
As a result, we have used EPA's Integrated Planning Model (IPM) to
calculate the capital costs and annual operating costs associated with
the various NOX control options. EPA's Clean Air Markets
Division (CAMD) uses IPM to evaluate the cost and emissions impacts of
proposed policies to limit emissions of SO2, NOX,
carbon dioxide (CO2), and mercury (Hg) from the electric
power sector. Developed by ICF Consulting, Inc. and used to support
public and private sector clients, IPM is a multi-regional, dynamic,
deterministic linear programming model of the U.S. electric power
sector. EPA has used IPM in rulemakings such as the Mercury and Air
Toxics Standard and the Cross-State Air Pollution Rule. For the
purposes of this BART determination, we specifically used only the
NOX emission control technology cost methodologies contained
in EPA's IPM Base Case v4.10 (August 2010).\79\ For Base Case v4.10,
EPA's Clean Air Markets Division contracted with engineering firm
Sargent and Lundy to perform a complete bottom-up engineering
reassessment of the cost and performance assumptions for SO2
and nitrogen oxides NOX emission controls. Summaries of our
control cost estimates for the various control technology options
considered for each unit are included below. Detailed cost
[[Page 42853]]
calculations, including our contractor's report and cost calculation
spreadsheets, are in the Technical Support Document.
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\79\ http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation.
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We used publicly available information to estimate that AEPCO is a
small utility. EPA requested information from AEPCO on the economics of
operating Apache Generating Station and what impact the installation of
SCR may have on the economics of operating Apache Generating Station.
Specifically, EPA is seeking information on the ability of AEPCO to
recover the cost of pollution control technology through rate increases
and the impact those rate increases may have on AEPCO's customers. If
we receive comments sufficiently documenting that installation of SCR
may have a severe impact on the economics of operating Apache
Generating Station, we may incorporate such considerations in our
selection of BART. Our impact analysis and request for comment is
discussed in more detail below, under EPA's BART Determinations for
Apache Units 2 and 3.
Control Effectiveness: The evaluation of control effectiveness is
an important part of a five-factor analysis because it influences both
cost-effectiveness and visibility benefits. The BART Guidelines note
that for each technically feasible control option:
``It is important * * * that in analyzing the technology you
take into account the most stringent emission control level that the
technology is capable of achieving. You should consider recent
regulatory decisions and performance data (e.g., manufacturer's
data, engineering estimates and the experience of other sources)
when identifying an emissions performance level or levels to
evaluate.'' \80\
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\80\ 40 CFR part 51, appendix Y Sec. IV.D.3.
In general, our estimates of LNB and SNCR control effectiveness differ
slightly from the control effectiveness levels considered by ADEQ. In
the case of LNB, for example, this is the result of the fact that
actual emissions data for LNB performance were available for certain
units at the time of our analysis. ADEQ's analysis was performed at an
earlier date when these emissions data were not available. More
detailed information regarding these differences is in our discussion
of individual facilities in the following sections of this notice, as
well as in our TSD.
In particular, we find that ADEQ did not adequately support its
estimate of SCR control effectiveness. SCR, as an add-on control
technology, can be installed by itself as a standalone option or in
conjunction with burner upgrades. In cases where units can be upgraded
with combustion control technology such as low-NOx burners, SCR is
commonly installed as an add-on post-combustion control. When
evaluating control options with a range of emission performance levels,
the BART Guidelines indicate that ``in analyzing the technology you
take into account the most stringent emission control level that the
technology is capable of achieving.'' \81\ Existing vendor literature
and technical studies indicate that SCR systems are capable of
achieving a 0.05 lb/MMBtu emission rate (approximately 80-90% control
efficiency) and that this emission rate can be achieved on a retrofit
basis, particularly when combined with combustion control technology
such as LNB.\82\
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\81\ 70 FR 39166.
\82\ See Docket Items G-04, ``Emissions Control: Cost-Effective
Layered Technology for Ultra-Low NOX Control'' (2007),
Docket Item G-05 ``What's New in SCRs'' (2006), and Docket Item G-06
``Nitrogen Oxides Emission Control Options for Coal-Fired Electric
Utility Boilers'' (2005).
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For control options involving the installation SCR in conjunction
with LNB, ADEQ considered the achievable emission rate to be between
0.07 lb/MMbtu (for Apache and Cholla) and 0.08 lb/MMbtu (for Coronado).
These emission rates are within a range of SCR performance that has
been considered by other western states in preparing RH SIPs, and may
possibly be an appropriate estimation of the site-specific level of SCR
performance for coal-fired units at Apache, Cholla, and Coronado. We
note that the BART Guidelines indicate that, ``In assessing the
capability of the control alternative, latitude exists to consider
special circumstances pertinent to the specific source under review [*
* *]. However, you should explain the basis for choosing the alternate
level (or range) of control in the BART analysis.'' \83\ Although the
alternate levels of emission control considered by ADEQ for SCR in
conjunction with LNB were stated in each respective facility's BART
analysis, these emission rates were not further supported by any
calculations, engineering analysis, or documentation. We do not believe
that AEPCO, APS, and SRP have provided adequate supporting analysis to
justify these emission rates. We are seeking comment on whether it is
appropriate to consider an emission rate less stringent than 0.05 lb/
MMBtu when evaluating the installation SCR in conjunction with LNB at
Apache, Cholla, and Coronado.
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\83\ 40 CFR part 51, appendix Y Sec. IV.D.3.
---------------------------------------------------------------------------
In the absence of source-specific considerations warranting a less
stringent control level, we presume that an emissions limit of 0.05 lb/
MMBtu is achievable by these units through the use of SCR in addition
to advanced combustion controls. We have recently received information
from AEPCO and SRP regarding potential NOX controls at their
facilities. This information arrived too late to be fully evaluated for
this proposed rulemaking, and EPA will need additional documentation
from the utilities to support the information that they have provided
to date. We have put the utility information in the docket for public
review, and we will evaluate the information, and any additional
information that the utilities may want to provide prior to making our
final BART determinations.\84\ If we receive additional comments that
sufficiently document source-specific considerations justifying the use
of an emission rate less stringent than 0.05 lb/MMBtu, we may
incorporate such considerations in our selection of BART.
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\84\ Docket Items C-15 ``Letter from Kelly Barr (SRP) to Deborah
Jordan (EPA)'' and C-16 ``Letter from Michelle Freeark (AEPCO) to
Deborah Jordan (EPA).''
---------------------------------------------------------------------------
2. Energy and Non-Air Environmental Impacts
Energy Impacts: With respect to the potential energy impacts of the
BART control options, we note that SCR incurs a draft loss that will
increase parasitic loads, and that other emissions controls may also
have modest energy impacts. The costs for direct energy impacts, i.e.,
power consumption from the control equipment and additional draft
system fans from each control technology, are included in the cost
analyses and are not considered further in this section. Indirect
energy impacts, such as the energy to produce raw materials, are not
considered, consistent with the BART guidelines.
Ammonia Adsorption: Ammonia adsorption (resulting from ammonia
injection from SCR or selective non-catalytic reduction--SNCR) to fly
ash is generally not desirable due to odor but does not impact the
integrity of the use of fly ash in concrete. However, other
NOX control technologies, including LNB, also have
undesirable impacts on fly ash. LNBs increase the amount of unburned
carbon in the fly ash, also known as Loss of Ignition (LOI), which does
affect the integrity of the concrete. Commercial scale technologies
exist to remove ammonia and LOI from fly ash. Moreover, the impact of
SCR on fly ash is smaller than the impact of LNB on fly ash, and in
both cases, the adverse effects can be mitigated.\85\ We conclude
[[Page 42854]]
that the ability of the relevant facilities to sell fly ash is unlikely
to be affected by the installation of SCR and SNCR technologies.
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\85\ ``Impact of Ammonia in Fly Ash on its Beneficial Use,''
Memorandum from Nancy Jones and Stephen Edgerton, EC/R Incorporated,
to Anita Lee, U.S. EPA/Region 9, August 31, 2010. Also see the TSD
for further discussion.
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Safety: SCR and SNCR may involve potential safety hazards
associated with the transportation and handling of anhydrous ammonia.
Since each of the relevant facilities is served by a nearby railroad
line, EPA concludes that the use of ammonia does not pose any
additional safety concern as long as established safety procedures are
followed.
Thus, EPA proposes to find that potential energy and non-air
quality impacts do not warrant elimination of any of the otherwise
feasible control options for NOX at any of the sources.
3. Pollution Control Equipment in Use at the Source
The presence of existing pollution control technology at each
source is reflected in our BART analysis in two ways: First, in the
consideration of available control technologies, and second, in the
development of baseline emission rates for use in cost calculations and
visibility modeling. As noted above, we largely agree with ADEQ's
consideration of available control technologies. However, because
several of the affected units have had new controls installed in the
last several years, we have adjusted the baseline emissions periods to
reflect current control technology at the sources, as described further
below in our proposed BART determinations.
4. Remaining Useful Life of the Source
We are considering each source's ``remaining useful life'' as one
element of the overall cost analysis as allowed by the BART Guidelines.
Since we are not aware of any federally- or State-enforceable shut-down
date for any of the affected sources, we have used the default 20-year
amortization period in the EPA Cost Control Manual as the remaining
useful life of the facilities considered in this proposed action.
5. Degree of Improvement in Visibility
EPA estimated the degree of visibility improvement expected from a
BART control based on the difference between baseline visibility
impacts prior to controls and visibility impacts with controls in
operation. EPA used the CALPUFF model version 5.8 \86\ to determine the
baseline and post-control visibility impacts for all three facilities.
EPA followed the modeling approach recommended in the BART Guidelines.
We developed a modeling protocol, used maximum daily emissions as a
baseline, applied estimated percent reductions for alternative control
technologies, and used the CALPUFF model to estimate visibility impacts
at Class I areas within 300 kilometers.
---------------------------------------------------------------------------
\86\ EPA relied on version 5.8 of CALPUFF because it is the EPA-
approved version promulgated in the Guideline on Air Quality Models
(40 CFR part 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15,
2003. It was also the approved version when EPA promulgated the BART
Guidelines (70 FR 39122, July 6, 2005). EPA updated the specific
version to be used for regulatory purposes on June 29, 2007,
including minor revisions as of that date; the approved CALPUFF
modeling system includes CALPUFF version 5.8, level 070623, and
CALMET version 5.8 level 070623. At this time, any other version of
the CALPUFF modeling system would be considered an ``alternative
model'', subject to the provisions of Guideline on Air Quality
Models section 3.2.2(b), requiring a full theoretical and
performance evaluation.
---------------------------------------------------------------------------
a. Modeling Protocol
A modeling protocol was developed by our contractor \87\ at the
University of North Carolina that is based largely on the WRAP
protocol,\88\ although there are a few differences between our protocol
and that of the WRAP. Both protocols used meteorological inputs for
2001, 2002, and 2003 based on the Mesoscale Model version 5 (MM5). EPA
meteorological inputs differed from the WRAP's in that the WRAP
incorporated upper air data, as recommended by the Federal Land
Managers, and also values for some parameters that enabled smoother and
more realistic wind fields. These CALMET inputs were developed by the
ENSR corporation for modeling of emissions at the Navajo Generating
Station.\89\ Another key difference was EPA's use of the current
regulatory version of the CALPUFF modeling system, version 5.8.
Facility stack parameters, such as stack height and exit temperature,
were generally the same as those provided by WRAP member states to the
WRAP, except that in some cases updated parameters were provided by the
facilities at EPA's request.
---------------------------------------------------------------------------
\87\ Technical Analysis for Arizona Regional Haze FIPs: Modeling
Protocol for Subject-to-BART and BART Control Options Analyses, EP-
D-07-102 WA5-12 Task 5, Institute for the Environment, University of
North Carolina at Chapel Hill, March 14, 2012
\88\ CALMET/CALPUFF Protocol for BART Exemption Screening
Analysis for Class I Areas in the Western United States, Western
Regional Air Partnership (WRAP); Gail Tonnesen, Zion Wang; Ralph
Morris, Abby Hoats and Yiqin Jia, August 15, 2006. Available on UCR
Regional Modeling Center web site, BART CALPUFF Modeling, http://pah.cert.ucr.edu/aqm/308/bart.shtml.
\89\ Revised BART Analysis for the Navajo Generating Station
Units 1-3, ENSR Corporation, Document No. 05830-012-300, January
2009, Salt River Project--Navajo Generating Station, Tempe, AZ.
---------------------------------------------------------------------------
We performed separate CALPUFF modeling runs using baseline
emissions, and using the emissions remaining after each candidate
control technology was applied to the baseline. For baseline PM
emissions, EPA used the WRAP's estimates. However, following procedures
developed by the National Park Service,\90\ EPA divided those emissions
into separate chemical species, and into separate coarse and fine
particle fractions, to reflect better their varying visibility impacts.
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\90\ ``Particulate Matter Speciation'', National Park Service,
2006. http://www.nature.nps.gov/air/Permits/ect/index.cfm.
---------------------------------------------------------------------------
Although costs and emission reductions for each candidate BART
control technology must necessarily be calculated separately for each
emitting unit of a facility, emissions from all the units will be
emitted into the air simultaneously. EPA modeled all units (stacks) and
pollutants simultaneously. That is, even though only NOX
BART alternatives were evaluated, SO2 and PM10
emissions were also included in the modeling. Modeling all emissions
from all the units accounts for the chemical interaction between
multiple plumes, and between the plumes and the background
concentrations. This also accounts for the facts that deciview benefits
from individual units are not additive, and that each EPA BART proposal
is for the facility as a whole.
b. Baseline Emissions
Baseline NOX and SO2 emissions for the
facilities were generally based on the maximum daily emissions from
recent data in EPA's CAMD database, with data examined for 2008 to
2011. The CAMD data derive from Continuous Emissions Monitoring in
place at the facilities, and give the actual emissions that occurred.
However, in cases where EPA is proposing to approve the BART emissions
limits submitted by ADEQ, EPA used emission rates based on those
limits, in lb/MMBtu, in combination with the maximum daily heat rate in
MMBtu/hour from the CAMD data. The baseline emissions used by EPA
reflect current fuels and control technologies in place at the
facilities, as well as regulatory requirements the facilities will be
required to meet independent of EPA's BART determination. This results
in a more realistic estimate of current visibility impacts, and of the
improvements that one would expect to result from implementation of
EPA's proposed BART controls.
[[Page 42855]]
c. Emission Reductions for Alternative Controls
For the CALPUFF modeling to assess visibility after application of
a control technology, the percent control expected from the technology
was applied to the baseline maximum daily emissions just described, as
recommended in the BART Guidelines. As discussed elsewhere, LNB and
SNCR each were assumed to reduce NOX by 30 percent, and SCR
was assumed to reduce NOX by 90 percent. However, for SCR,
we used a lower bound of 0.05 lb/MMBtu NOX, an emission rate
that we have confidence is achievable, as discussed above under
``Control Effectiveness''. The percent reduction actually applied to
the maximum daily emissions was whatever was required to reduce the
CAMD annual average emission factor down to this 0.05 lb/MMBtu
NOX. For the various emitting units at the facilities, this
ranged from 80 to 89 percent, instead of a full 90 percent reduction.
Finally, in modeling the visibility impact of SCR, EPA accounted for
the increased sulfuric acid emissions that occur when the SCR catalyst
oxidizes SO2 present in the flue gas, using an estimation
procedure developed by the Electric Power Research Institute\91\.
(Estimating Total Sulfuric Acid Emissions from Stationary Power Plants,
Version 2010a, 1020636, Technical Update, Electric Power Research
Institute, April 2010) This side effect of SCR's NOX
reduction increases sulfate emissions and decreases the visibility
benefits of SCR by around 5 percent.
---------------------------------------------------------------------------
\91\ Estimating Total Sulfuric Acid Emissions from Stationary
Power Plants, Version 2010a, 1020636, Technical Update, Electric
Power Research Institute, April 2010.
---------------------------------------------------------------------------
d. Visibility Impacts
CALPUFF Modeling: EPA followed the BART Guidelines in assessing
visibility impacts. For each Class I area within 300 km of a facility,
the CALPUFF model is used to simulate the baseline visibility impact of
each facility and the impacts resulting after alternative controls are
applied. However, certain aspects of assessing visibility with CALPUFF
are not fully addressed in the Guidelines. These aspects include which
``98th percentile'' from the model to use, the visibility calculation
method (old vs. revised IMPROVE equation), and natural background
concentrations (annual average versus best 20 percent of days).
As recommended in the BART Guidelines, the 98th percentile daily
impact in deciviews is used as the basic metric of visibility impact.
(For a given Class I area, and for each modeled day, the model finds
the maximum impact. From among the 365 maximum daily values, the 98th
percentile is chosen, that is, the 8th highest.) Since multiple years
of meteorology are modeled, there are at least three ways to use the
model results: The maximum from among the 98th percentiles for the
individual years 2001, 2002, and 2003 (``maximum''); the average of
these three (``average''), or a single 98th percentile computed from
all three years of data together (``merged'', the 22nd high among 1095
daily values). The average and merged values are both unbiased
estimates of the true 98th percentile; for this proposal EPA has used
the merged value. The more conservative maximum value would be
appropriate for a screening purpose, such as for determining whether a
source is subject to BART.
Visibility Calculation Method: The visibility calculation method
relied on by EPA differed from that used by ADEQ. Visibility impacts
may be simulated with CALPUFF using either the old or the revised
IMPROVE equation for translating pollutant concentrations into
deciviews; these are respectively CALPUFF visibility methods 6 and 8
(implemented in the CALPOST post-processor). Many BART assessments were
performed before method 8 was incorporated into CALPUFF, so method 6
was generally for past assessments. However, in this proposal EPA is
primarily relying on method 8. Method 8 is currently preferred by the
Federal Land Managers; since the revised IMPROVE equation performs
better at estimating visibility.\92\ For the facilities examined in
this proposal, baseline impacts using method 6 would average about 10
percent higher than those using method 8 (with a range of 3 percent
lower to 22 percent higher depending on facility and Class I area; the
effect for areas showing the largest benefit from control was similar
to the average).
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\92\ Pitchford, Marc, 2006, ``New IMPROVE algorithm for
estimating light extinction approved for use'', The IMPROVE
Newsletter, Volume 14, Number 4, Air Resource Specialists, Inc.; Web
page: http://vista.cira.colostate.edu/improve/Publications/news_letters.htm.
---------------------------------------------------------------------------
Another CALPUFF choice is whether to calculate visibility impacts
relative to annual average natural conditions, or relative to the best
20 percent of natural background days; these may be referred to as
``a'' and ``b''. For both ``a'' and ``b'', background concentrations
for each Class I area are available in a Federal Land Managers'
document.\93\ EPA Guidance allows for the use of either ``a'' or
``b.''94 95 Since the annual average has worse visibility
and higher deciviews than the best days do, a given facility impact
will be smaller relative to the average than it is relative to the best
days. That is, a facility's impact will stand out less under poorer
visibility conditions. Thus, modeled facility impacts and control
benefits appear smaller when ``a'' is used than when ``b'' is used. In
this proposal, EPA is relying on ``b'', best 20 percent, consistent
with initial EPA recommendations for BART assessments. For the
facilities examined in this proposal, baseline impacts would average
about 20 percent lower using background ``a'' than those using
background ``b'' (with a range of 18 percent to 28 percent lower
depending on facility and Class I area; the effect for areas showing
the largest benefit from control was similar to the average).
---------------------------------------------------------------------------
\93\ Federal Land Managers' Air Quality Related Values Work
Group (FLAG) Phase I Report--Revised (2010), U.S. Forest Service,
National Park Service, U.S. Fish and Wildlife Service, October 2010.
Available on Web page http://www.nature.nps.gov/air/Permits/flag/.
\94\ BART Guidelines, 70 FR 39125, July 6, 2005. ``Finally,
these final BART guidelines use the natural visibility baseline for
the 20 percent best visibility days for comparison to the `cause or
contribute' applicability thresholds.''
\95\ ``Regional Haze Regulations and Guidelines for Best
Available Retrofit Technology (BART) Determinations'', memorandum
from Joseph W. Paisie, EPA OAQPS, July 19, 2006, p.2.
---------------------------------------------------------------------------
Considering visibility method and choice of background together,
the BART visibility assessments relied on by ADEQ used method ``6a'',
the old IMPROVE equation, and impacts relative to annual average
natural conditions. This is a valid approach, and is consistent with
EPA guidance.\96\ However, for this proposal, EPA considered all four
combinations of IMPROVE equation version and natural background: 6a,
6b, 8a, and 8b. EPA primarily relied on method ``8b'', that is, the
revised IMPROVE equation, and impacts relative to the best 20 percent
of natural background days. This is most consistent with our current
understanding of how best to assess source specific visibility impacts.
Combining the differences in visibility method and chosen background,
for the facilities examined in this proposal, baseline impacts would
average about 15 percent lower using method ``6a'' than those using
method ``8b'' (with a range of 3 percent to 37 percent lower depending
on facility and Class I area; the effect for areas showing the largest
benefit from control was similar to the average). Results for all the
various
[[Page 42856]]
visibility methods are available in the TSD.
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\96\ Additional Regional Haze Questions'', September 27, 2006
Revision, EPA OAQPS.
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B. EPA's FIP BART Determinations
1. Apache Units 2 and 3
a. Costs of Compliance
Our general approach to calculating the costs of compliance is
described in VII.A.1., while issues unique to Apache Units 2 and 3 are
described herein. In particular, we highlight below certain aspects of
our analysis of this factor that differ from ADEQ's and AEPCO's
analysis.
i. Selection of Baseline Period
AEPCO's BART analysis used a 2002 to 2007 time period in order to
establish its baseline NOX emissions. In our analysis, we
decided to make use of the most recent Acid Rain Program emission data
reported to CAMD, which, at the time that we began our analysis in
2011, was the three-year period from 2008 to 2010. Based on CAMD
documentation, no new control technology beyond the existing OFA system
has been installed on either Apache Unit 2 or 3. We consider the use of
this more recent baseline period to be a realistic depiction of
anticipated future emissions.\97\
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\97\ BART Guidelines, 40 CFR part 51, appendix P, Section
IV.D.4.d.
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ii. SCR Control Efficiency
In determining the control efficiency of SCR, we have relied upon
an SCR level of performance of 0.05 lb/MMBtu, which is more stringent
than the level of performance used by ADEQ in its SIP. In the Apache
BART analyses submitted to ADEQ, AEPCO indicated an SCR level of
performance of 0.07 lb/MMBtu, but did not provide site-specific
information describing how this emission rate was developed or
discussing why a more stringent 0.05 lb/MMBtu level of performance
could not be attained. Our control cost calculations for the SCR and
LNB with OFA control options are based upon the control efficiency of
SCR (combined with LNB) summarized in Table 15.
Table 15--Apache 2 and 3: EPA's SCR (Combined With LNB) Control Efficiency
----------------------------------------------------------------------------------------------------------------
Baseline SCR control
Unit emission rate SCR emission efficiency
\1\ (lb/MMBtu) rate (percentage)
----------------------------------------------------------------------------------------------------------------
Apache 2.................................................. 0.371 0.05 87
Apache 3.................................................. 0.438 0.05 89
----------------------------------------------------------------------------------------------------------------
\1\ This baseline emission rate represents operation of OFA only.
iii. Capacity Factor
As noted previously, AEPCO calculated annual emission estimates for
its control scenarios, in tons per year, using annual capacity factors
developed internally over an unspecified time frame.\98\ The annual
capacity factors AEPCO used for each unit were 92 percent (Apache 2),
and 87 percent (Apache 3). We have also calculated annual emission
estimates for our control scenarios using capacity factors, but have
used information developed from CAMD information, and over a more
recent 2008 to 2011 time frame. The annual capacity factors we have
used for each unit are 62 percent (Apache 2), and 71 percent (Apache
3). We recognize that these capacity factors are lower than those used
by AEPCO, and that by using these lower capacity factors, our estimates
of total annual emissions (and correspondingly, the annual emission
reductions) for each control scenario are lower than AEPCO's
estimates.\99\ Since cost-effectiveness ($/ton) is calculated by
dividing annual control costs ($/year) by annual emission reductions
(tons/year), the use of emission reductions based on lower capacity
factors will increase the cost per ton of pollutant reduced.
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\98\ As listed in Table 2-1 in Docket Items B-03 and B-04,
Apache BART Analyses.
\99\ We note that there are multiple reasons why our annual
emission estimates (and estimates of emission removal) are lower
than AEPCO's and ADEQ's estimates. We are not implying that the use
of capacity factor is the sole, or even dominant, reason for this
difference, simply that the use of lower capacity factors will
result in lower annual emission estimates.
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We have elected to use the capacity factors specified above, as
based on a 2008 to 2011 time frame, in order to remain consistent with
the time frame used to develop baseline annual emissions for Apache and
the other power plants that are the subject of today's proposed action.
iv. Summary of Control Cost Estimates
A summary of our control cost estimates for the various control
technology options considered for Apache Units 2 and 3 is in Table 16.
Detailed cost calculations, including our contractor's report and cost
calculation spreadsheets, are available in our Technical Support
Document.
Table 16--Apache Units 2 and 3: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission rate Cost-effectiveness ($/ton)
Emission -------------------------- Emissions ----------------------------
Control option factor (lb/ removed Annual cost Incremental
MMBtu) (lb/hr) (tpy) (tpy) ($/yr) Ave (from
previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Apache 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)........................................... 0.371 859 2,333 ........... ........... ........... ..............
LNB+OFA.................................................. 0.26 601 1,633 700 1,142,120 1,632 ..............
SNCR+LNB+OFA............................................. 0.18 421 1,143 1,190 2,652,841 2,230 3,084
SCR+LNB+OFA.............................................. 0.05 116 314 2,019 5,869,299 2,908 3,881
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 42857]]
Apache 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)........................................... 0.438 974 3,028 ........... ........... ........... ..............
LNB+OFA.................................................. 0.31 682 2,120 908 1,153,378 1,270 ..............
SNCR+LNB+OFA............................................. 0.22 477 1,484 1,544 2,968,611 1,922 2,854
SCR+LNB+OFA.............................................. 0.05 111 346 2,683 6,103,078 2,275 2,754
--------------------------------------------------------------------------------------------------------------------------------------------------------
As seen in Table 16, our calculations indicate that the SCR-based
control options have average cost-effectiveness values of $2,275/ton to
$2,908/ton, which falls in a range that we consider cost-effective. In
addition, our calculations indicate that the SCR-based control options
have an incremental cost-effectiveness of $2,754/ton to $3,881/ton,
which is also in a range that we would consider cost-effective. As a
result, our analysis of this factor indicates that the costs of
compliance (average or incremental) are not sufficiently large to
warrant eliminating any of the control options from consideration.
b. Visibility Improvement
The overall visibility modeling approach was described above;
aspects of the modeling specific to Apache are described here. EPA is
proposing a NOX BART determination only for Apache units 2
and 3, but Unit 1 was also included in the modeling runs for greater
realism in assessing the full facility's visibility impacts.\100\ For
Unit 1's NOX emissions, ADEQ's emission factor of 0.56 lb/
MMBtu was combined with the maximum MMBtu/hr heat rate from EPA's CAMD
database for 2008 to 2010. The baseline emissions used for these units
were the maximum daily emissions in lb/hr from 2008 to 2010; the maxima
occurred in early 2008. The base case reflects only OFA as the control
in place.
---------------------------------------------------------------------------
\100\ Apache Unit 4, which consists of four simple-cycle gas
turbines, was not included in the modeling because its
NOX emissions are less than 1 percent of the emissions of
units 2 and 3, and are therefore expected to have a de minimis
effect on modeled visibility impacts.
---------------------------------------------------------------------------
EPA evaluated LNB, SNCR (including LNB), and SCR (including LNB)
applied to both Units 2 and 3; as mentioned above the SCR simulation
accounted for the increase in sulfuric acid emissions due to catalyst
oxidation of SO2. SCR was assumed to give a control
effectiveness of 87 percent and 89 percent for Units 2 and 3,
respectively (less than 90 percent due to the 0.05 lb/MMBtu
NOX lower limit assumed for SCR). The nine Class I areas
within 300 km of Apache were modeled; they are in the states of Arizona
and New Mexico. The 98th percentile of delta deciviews over all three
years of data was computed for each area and emission scenario.
Table 17 shows the impact for the base case, and the improvement
from that baseline impact when controls are applied, all in deciviews,
for each area. The Class I area types are National Monument (NM),
Wilderness Area (WA), and National Park (NP). Also shown are the
cumulative deciviews, the simple sum of impacts or improvements over
all the Class I areas, and the number of areas with a baseline impact
or improvement of at least 0.5 dv. Finally, the table includes two
``dollars per deciview'' measures of cost-effectiveness, both of which
take the annual cost of the control in millions of dollars per year,
and divide by an improvement in deciviews. For the first metric, ``$/
max dv'', cost is divided by the deciview improvement at the Class I
area with the greatest improvement. The second metric, ``$/cumulative
dv'', divides cost by the cumulative deciview improvement. In assessing
the degree of visibility improvement from controls, EPA relied heavily
on the maximum dv improvement and the number of areas showing
improvement, with cumulative improvement providing a supplemental
measure that combines information on the number of areas and on
individual area improvement. The dollars per deciview metrics provided
information supplemental to the dollars per ton that was considered in
the cost factor.
In its comments on Arizona's proposed Regional Haze SIP, the
National Park Service noted that:
Compared to the typical control cost analysis in which estimates
fall into the range of $2,000-$10,000 per ton of pollutant removed,
spending millions of dollars per deciview (dv) to improve visibility
may appear extraordinarily expensive. However, our compilation of
BART analyses across the U.S. reveals that the average cost per dv
proposed by either a state or a BART source is $14-$18 million.\101\
\101\ Arizona Regional Haze SIP, Appendix E, Public Process, NPS
General BART Comments on ADEQ BART Analyses (November 29, 2010), p.
4.
---------------------------------------------------------------------------
While we do not necessarily consider $14 to $18 million/dv as being a
reasonable range in all cases, we note that for all of the
NOX control options, including SCR, both the $/max dv and
the $/cumulative dv are well below this range.
The area with the greatest dv improvement was the Chiricahua
Wilderness Area; the improvement from LNB was 0.5 dv, from SNCR was 1
dv, and from SCR was 1.6 dv. Any of these improvements would contribute
to improved visibility, with SCR being the superior option for
visibility. The corresponding cumulative improvements are 2.1, 3.8, and
6.5. Both SNCR and SCR give improvements exceeding 0.5 dv at four
areas, but for SCR the improvements at those areas also exceed a full 1
dv. The improvements from SCR are substantially greater than for the
other candidate controls. The modeled degree of visibility improvement
supports SCR as BART for Apache.
[[Page 42858]]
Table 17--Apache Units 2 and 3: EPA'S Visibility Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
Baseline Improvement Improvement Improvement
Class I Area impact (dv) from LNB (dv) from SNCR (dv) from SCR (dv)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM................................... 3.41 0.44 0.82 1.51
Chiricahua WA................................... 3.46 0.53 1.00 1.59
Galiuro WA...................................... 2.22 0.39 0.65 1.10
Gila WA......................................... 0.63 0.14 0.22 0.37
Mazatzal WA..................................... 0.28 0.05 0.09 0.14
Mount Baldy WA.................................. 0.28 0.07 0.11 0.18
Saguaro NP...................................... 2.49 0.38 0.66 1.16
Sierra Ancha WA................................. 0.29 0.06 0.10 0.14
Superstition WA................................. 0.61 0.10 0.19 0.31
Cumulative dv................................... 13.67 2.14 3.83 6.51
areas >=0.5........................... 6 1 4 4
$/max dv, millions.............................. .............. $4.8 $6.0 $8.7
$/cumulative dv, millions....................... .............. $1.2 $1.6 $2.1
----------------------------------------------------------------------------------------------------------------
c. EPA's BART Determination
In considering the results of the five-factor analysis, we note
that the remaining useful life of the source, as indicated previously
by the plant economic life of Apache Units 2 and 3, is incorporated
into control cost calculations as a 20-year amortization period. In
addition, the presence of existing pollution control technology is
reflected in the cost and visibility factors as a result of selection
of the baseline period for cost calculations and visibility modeling.
For Apache Units 2 and 3, a baseline period (2008 to 2010) was selected
that reflects the currently existing pollution control technology
(OFA). In examining energy and non-air quality impacts, we note certain
potential impacts resulting from the use of ammonia injection
associated with the SNCR and SCR control options, but do not consider
these impacts sufficient enough to warrant eliminating any of the
available control technologies.
Our consideration of degree of visibility improvement focuses
primarily on the improvement from base case impacts associated with
each control option. While each of the available NOX control
options achieves some degree of visibility improvement, we consider the
improvement associated with the most stringent option, SCR with LNB and
OFA, to be substantial. Our consideration of cost of compliance focuses
primarily on the cost-effectiveness of each control option, as measured
in cost per ton and incremental cost per ton of each control option.
Despite the fact that the most stringent option, SCR with LNB and OFA,
is the most expensive of the available control options, we consider it
cost-effective on an average basis as well as on an incremental basis
when compared to the next most stringent option, SNCR with LNB and OFA.
As a result, we consider the most stringent available control
option, SCR with LNB and OFA, to be both cost-effective and to result
in substantial visibility improvement, and that the energy and non-air
quality impacts are not sufficient to warrant eliminating it from
consideration. Therefore, the results of our five-factor analysis
indicate that NOX BART for Apache Units 2 and 3 is SCR with
LNB and OFA.
However, we note that the BART guidelines state that:
Even if the control technology is cost-effective, there may be
cases where the installation of controls would affect the viability
of continued plant operations. [[hellip]]You may take into
consideration the conditions of the plant and the economic effects
of requiring the use of a control technology. Where these effects
are judged to have a severe impact on plant operations you may
consider them in the selection process, but you may wish to provide
an economic analysis that demonstrates, in sufficient detail for
public review, the specific economic effects, parameters, and
reasoning.'' \102\
---------------------------------------------------------------------------
\102\ 70 FR 39171.
As explained in Section IX.C below, because AEPCO is a ``small
entity'', as defined under the Regulatory Flexibility Act, we have
conducted an initial assessment of the potential adverse impacts on
AEPCO of requiring SCR with LNB and OFA. Using publicly available
information, EPA estimates that the annualized cost of requiring SCR in
Units 1 and 2 would likely be in the range of 3 percent of AEPCO's
assets and between 6 and 7 percent of AEPCO's annual sales. The
projected costs of SCR with LNB and OFA are approximately $12 million
per year. This exceeds AEPCO's net margins of $9.5 million in 2010 and
$1.9 million in 2011.\103\
---------------------------------------------------------------------------
\103\ See Docket Item H-1Arizona Electric Power Cooperative,
Inc. Annual Report Electric for Year Ending December 31, 2011
submitted to Arizona Corporation Commission Utilities Division,
available at http://www.azcc.gov/Divisions/Utilities/Annual%20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_Inc.pdf.
---------------------------------------------------------------------------
In addition to conducting this initial economic impact assessment,
we requested information from AEPCO on the economics of operating
Apache Generating Station and what impact the installation of SCR may
have on the economics of operating Apache Generating Station. We have
just received a description of plant conditions and potential economic
effects and are placing this information in the docket for this
action.\104\ We will consider this information and any additional
information received during the comment period as part of our final
action. If our analysis of this information indicates that installation
of SCR will have a severe impact on the economics of operating Apache
Generating Station, we will incorporate such considerations in our
selection of BART.
---------------------------------------------------------------------------
\104\ Docket Item C-16, Letter from Michelle Freeark (AEPCO) to
Deborah Jordan (EPA), AEPCO's Comments on BART for Apache Generating
Station, June 29, 2012.
---------------------------------------------------------------------------
Nonetheless, based on the available control technologies and the
five factors discussed above, EPA is proposing to require Apache
Generating Station to meet an emission limit for NOX on
Units 2 and 3 of 0.050 lb/MMBtu. Each of these emission limits is based
on a rolling 30-boiler-operating-day average.
2. Cholla Units 2, 3 and 4
a. Costs of Compliance
Our general approach to calculating the costs of compliance is
described in section VII.A.1 above. Issues unique to Cholla Units 2, 3
and 4 are explained
[[Page 42859]]
herein. There are several aspects of our analysis of this factor that
differ from ADEQ's and APS' analysis and we discuss the most important
of these below.
i. Selection of Baseline Period
APS' BART analysis used a 2001-03 time period in order to establish
its baseline NOX emissions. As noted previously, the
NOX control technology present on Cholla Units 2 through 4
during that time period was close-coupled over fire air (COFA). APS has
since installed low-NOX burners with separated over fire air
(SOFA) on Cholla Units 2 through 4. In order to properly consider the
second BART factor (pollution control equipment in use at the source)
and to ensure that actual conditions at the plant were reflected in our
baseline NOX emissions, we decided to make use of the most
recent Acid Rain Program emission data reported to CAMD, which, at the
time that we began our analysis in 2011, was the three-year period from
2008 to 2010. Based on CAMD documentation, the low-NOX
burners were installed on the Cholla units at different times during
2008 and 2009, making it necessary for us to clearly distinguish
between the pre-LNB and post-LNB periods of emission data for each
unit.
The use of a 2008 to 2010 baseline was, however, complicated by the
fact that the Cholla plant operates under a new coal contract for Lee
Ranch/El Segundo coal, which is a higher NOX-emitting coal
than what was previously used.\105\ This coal contract indicates that
steadily increasing minimum quantities of coal shall be delivered,
starting with 325,000 tons in 2006 and up to 3,700,000 tons in 2010.
This gradual transition to the newer, higher-NOX emitting
coal source made it difficult to determine the extent to which a
particular year's emissions were representative of anticipated annual
emissions. In the absence of more detailed fuel usage records on a per-
unit basis, it was not possible for us to identify which units may have
operated using the newer coal during the 2006 to 2010 transition period
to the newer coal type. We note, however, that the coal contract
specifically states that, for 2010 to 2024, no later than July 1 of
each year, the buyer shall indicate the annual tonnage for the
following calendar year, and that in no case shall the annual tonnage
be less than 3,700,000 tons. As a result, 2011 represents the first
complete calendar year at which we can be certain that the Cholla plant
operated at the new coal contract's ``full'' minimum purchase quantity
of 3,700,000 tons per year.
---------------------------------------------------------------------------
\105\ A copy of the coal contract, including obligation amounts
and coal quality, can be found in Docket Item B-09, ``Additional APS
Cholla BART response'', Appendix B.
---------------------------------------------------------------------------
Since 2011 Acid Rain Program emission data became available during
the intervening time between the start of our analysis and our proposed
action today, we have selected 2011 as the time period for establishing
baseline annual NOX emissions. Although this represents only
a single year of data, we believe the use of this more recent baseline
period represents the most realistic depiction of anticipated annual
emissions, as it is the only time period that ensures each of the
Cholla units is operating using the new coal and LNB with SOFA.
ii. SCR Control Efficiency
In determining the control efficiency of SCR, we have relied upon
an SCR level of performance of 0.05 lb/MMBtu, which is more stringent
than the level of performance used by ADEQ in its SIP. In the Cholla
BART analysis submitted to ADEQ, APS indicated an SCR level of
performance of 0.07 lb/MMBtu, but did not provide site-specific
information describing how this emission rate was developed or
discussing why a more stringent 0.05 lb/MMBtu level of performance
could not be attained. Our control cost calculations for the SCR and
LNB with OFA control options are based upon the SCR control
efficiencies summarized below. These control efficiencies reflect the
emission reductions associated with controlling from an annual average
baseline emission rate that represents LNB with OFA (as described
previously) down to an SCR emission rate of 0.05 lb/MMBtu.
Table 18--Cholla Units 2, 3 and 4: EPA's Scr Control Efficiency
----------------------------------------------------------------------------------------------------------------
Baseline SCR control
Unit emission rate 1 SCR emission efficiency
(lb/MMBtu) rate (percentage)
----------------------------------------------------------------------------------------------------------------
Cholla 2.................................................. 0.295 0.05 83
Cholla 3.................................................. 0.254 0.05 80
Cholla 4.................................................. 0.260 0.05 81
----------------------------------------------------------------------------------------------------------------
1 As noted previously, this baseline emission rate reflects the installation of LNB+OFA
iii. Capacity Factor
As noted previously, APS calculated annual emission estimates for
its control scenarios, in tons per year, using annual capacity factors
based on Acid Rain Program data from CAMD over a 2001 to 2006 time
frame.\106\ The annual capacity factors APS used for each unit were 91
percent (Cholla 2), 86 percent (Cholla 3), and 93 percent (Cholla 4).
We have also calculated annual emission estimates for our control
scenarios using capacity factors developed from CAMD information, but
have instead used a more recent 2008 to 2011 time frame. The annual
capacity factors we have used for each unit are 74 percent (Cholla 2),
75 percent (Cholla 3), and 71 percent (Cholla 4). We recognize that
these capacity factors are lower than those used by APS, and that by
using these lower capacity factors, our estimates of total annual
emissions (and correspondingly, the annual emission reductions) for
each control scenario are lower than APS' estimates.\107\ Since cost-
effectiveness ($/ton) is calculated by dividing annual control costs
($/year) by annual emission reductions (tons/year), the use of emission
reductions based on lower capacity factors will increase the cost per
ton of pollutant reduced.
---------------------------------------------------------------------------
\106\ As listed in Table 2-1 in Docket Items B-06 through B-08,
Cholla BART Analyses.
\107\ We note that there are multiple reasons why our annual
emission estimates (and estimates of emission removal) are lower
than APS' and ADEQ's estimates. We are not implying that the use of
capacity factor is the sole, or even dominant, reason for this
difference, simply that the use of lower capacity factors will
result in lower annual emission estimates.
---------------------------------------------------------------------------
We have elected to use the capacity factors specified above, as
based on a 2008 to 2011 time frame, in order to remain consistent with
the time frame used to develop baseline annual emissions for Cholla and
the other
[[Page 42860]]
power plants that are the subject of today's proposed action.\108\
---------------------------------------------------------------------------
\108\ We recognize that there are more aggressive approaches we
could adopt that could justify the use of higher capacity factors,
which would thereby lower the cost per ton of pollutant reduced. For
example, instead of using historical data to develop a capacity
factor value for each unit, we could use a single capacity factor
value for each unit, one that represented a reasonable depiction of
anticipated annual baseload operations. Alternately, we could also
use the capacity factor estimates from APS' Cholla BART analyses, as
based on a 2001-06 time frame, or develop new capacity factors based
on a longer 2001 to 2011 time frame.
---------------------------------------------------------------------------
iv. Summary of Control Costs
A summary of our control cost estimates for the various control
technology options considered for is included below. Detailed cost
calculations, including our contractor's report and cost calculation
spreadsheets, can be found in our TSD.
Table 19--Cholla Units 2, 3 And 4: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission rate Cost-effectiveness ($/ton)
Emission -------------------------- Emissions ----------------------------
Control option factor (lb/ removed Annual cost Incremental
MMBtu) (lb/hr) (tpy) (tpy) ($/yr) Ave (from
previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cholla 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA...................................................... NA; LNB+OFA is the currently installed technology
----------------------------------------------------------------------------------------------
LNB+OFA (baseline)....................................... 0.295 892 2,890 ........... ........... ........... ..............
SNCR+LNB+OFA............................................. 0.21 624 2,023 867 2,482,318 2,863 ..............
SCR+LNB+OFA.............................................. 0.05 151 490 2,400 7,475,028 3,114 3,257
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cholla 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA...................................................... NA; LNB+OFA is the currently installed technology
----------------------------------------------------------------------------------------------
LNB+OFA (baseline)....................................... 0.254 885 2,908 ........... ........... ........... ..............
SNCR+LNB+OFA............................................. 0.18 620 2,036 872 2,533,432 2,904 ..............
SCR+LNB+OFA.............................................. 0.05 174 572 2,337 8,113,131 3,472 3,811
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cholla 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA...................................................... NA; LNB+OFA is the currently installed technology
----------------------------------------------------------------------------------------------
LNB+OFA (baseline)....................................... 0.260 1144 3,609 ........... ........... ........... ..............
SNCR+LNB+OFA............................................. 0.18 801 2,526 1,083 3,185,822 2,943 ..............
SCR+LNB+OFA.............................................. 0.05 220 694 2,915 9,894,796 3,395 3,661
--------------------------------------------------------------------------------------------------------------------------------------------------------
As indicated in Table 19, our calculations indicate that the SCR-
based control options have average cost-effectiveness values of $3,114/
ton to $3,472/ton, which falls in a range that we would consider cost-
effective. In addition, our calculations indicate that the SCR-based
control options have an incremental cost-effectiveness of $3,257/ton to
$3,811/ton, which is also in a range that we would consider cost-
effective. As a result, our analysis of this factor indicates that the
costs of compliance (average or incremental) are not sufficiently large
to warrant eliminating any of the control options from consideration.
b. Visibility Improvement
The overall visibility modeling approach was described above;
aspects of the modeling specific to Cholla are described here. EPA made
a NOX BART determination for Cholla Units 2, 3 and 4, but
Unit 1 (which is not BART-eligible) was also included in the modeling
runs for greater realism in assessing the full facility's visibility
impacts. For Unit 1's NOX emissions, the maximum daily
emissions from EPA's CAMD database for 2008 to 2010 were used; the
maximum occurred in early 2008. LNB was installed on Units 2 and 4
early in 2008, and on Unit 3 in mid-2009; for a realistic base case,
the baseline emissions used for these units were the maximum daily
emissions in lb/hr from 2008-2010 occurring after the respective LNB
installation dates. The maximum for unit 2 occurred in mid-2009, and
the maxima for Units 2 and 3 occurred in late 2010. The base case
reflects LNB as the control in place.
EPA evaluated SNCR (including LNB) and SCR (including LNB) applied
to Units 2, 3 and 4. SCR was assumed to give a control effectiveness of
83 percent, 80 percent, and 81 percent for units 2, 3 and 4,
respectively (less than 90 percent due to the 0.05 lb/MMBtu
NOX lower limit assumed for SCR). For Cholla, the increase
in sulfuric acid due to SCR was not simulated, because the baghouse
(fabric filter) installed for particulate matter control would reduce
this increased sulfate by 99 percent, resulting in a negligible effect
on the visibility estimate. The 13 Class I areas within 300 km of
Cholla were modeled; they are in the states of Arizona, Colorado, New
Mexico, and Utah. The 98th percentile delta deciview using all three
years of data together was computed for each area and emission
scenario.
Table 20 shows baseline visibility impacts and the visibility
improvement when controls are applied; the various table entries are
described above in the discussion of the comparable table for Apache.
The area with the greatest dv improvement was the Petrified Forest
National Park; the improvement from SNCR was just under 0.5 dv and from
SCR was 1.3 dv. Either of these improvements would contribute to
improved visibility, with SCR being the superior option for visibility.
The corresponding cumulative improvements are 2.7 and 7.2. Only SCR
gives improvements exceeding 0.5 dv, and it does so at eight areas, two
of which have improvements above a full 1 dv. The modeled degree of
visibility
[[Page 42861]]
improvements supports SCR as BART for Cholla.
Table 20--Cholla Units 2, 3 and 4: EPA's Visibility Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
Baseline impact Improvement from Improvement from
Class I area (dv) SNCR (dv) SCR (dv)
----------------------------------------------------------------------------------------------------------------
Capitol Reef NP......................................... 1.46 0.27 0.76
Galiuro WA.............................................. 0.45 0.05 0.14
Gila WA................................................. 0.70 0.09 0.22
Grand Canyon NP......................................... 2.22 0.37 1.06
Mazatzal WA............................................. 1.19 0.16 0.43
Mesa Verde NP........................................... 1.34 0.26 0.70
Mount Baldy WA.......................................... 1.21 0.27 0.52
Petrified Forest NP..................................... 4.53 0.47 1.34
Pine Mountain WA........................................ 0.85 0.12 0.31
Saguaro NP.............................................. 0.30 0.02 0.05
Sierra Ancha WA......................................... 1.36 0.20 0.51
Superstition WA......................................... 1.27 0.17 0.51
Sycamore Canyon WA...................................... 1.42 0.27 0.68
Cumulative dv........................................... 18.30 2.71 7.21
areas >=0.5................................... 11 0 8
$/max dv, millions...................................... ................ $17.8 $20.8
$/cumulative dv, millions............................... ................ $3.1 $3.8
----------------------------------------------------------------------------------------------------------------
c. EPA's BART Determination
As noted above, the remaining useful life of the source is
incorporated into control cost calculations as a 20-year amortization
period. In addition, the presence of existing pollution control
technology is reflected in the cost and visibility factors as a result
of selection of the baseline period for cost calculations and
visibility modeling. For Cholla Units 2, 3, and 4, a baseline period
(2011) was selected that reflects the currently existing pollution
control technology (LNB with OFA). In examining energy and non-air
quality impacts, we note certain potential impacts resulting from the
use of ammonia injection associated with the SNCR and SCR control
options, but do not consider these impacts sufficient enough to warrant
eliminating any of the available control technologies.
Our consideration of degree of visibility improvement focuses
primarily on the improvement from base case impacts associated with
each control option. While each of the available NOX control
options achieves some degree of visibility improvement, we consider the
improvement associated with the most stringent option, SCR with LNB and
OFA, to be substantial.
Our consideration of cost of compliance focuses primarily on the
cost-effectiveness of each control option, as measured in cost per ton
and incremental cost per ton of each control option. Despite the fact
that the most stringent option, SCR with LNB and OFA, is the most
expensive of the available control options, we consider it cost-
effective on average basis as well as on an incremental basis when
compared to the next most stringent option, SNCR with LNB and OFA.
As a result, we consider the most stringent available control
option, SCR with LNB and OFA, to be both cost-effective and to result
in substantial visibility improvement, and that the energy and non-air
quality impacts are not sufficient to warrant eliminating it from
consideration. Therefore, we propose to determine that NOX
BART for Cholla Units 2, 3, and 4 is SCR with LNB and OFA, with an
associated emission limit for NOX on each of Units 2, 3, and
4 of 0.050 pounds per million British thermal units (lb/MMBtu), based
on a rolling 30-boiler-operating-day average.
3. Coronado Units 1 and 2
a. Costs of Compliance
Our general approach to calculating the costs of compliance is
described in section VII.A.2 above, while considerations unique to
Coronado Units 1 and 2 are explained herein. There are several aspects
of our analysis of this factor that differ from ADEQ's and SRP's
analysis and we describe the most important elements below.
i. Selection of Baseline Period and Baseline Control Technology
SRP's BART analysis used a 2001-03 time period in order to
establish its baseline NOX emissions. Since that time
period, SRP has since installed LNB with OFA on Coronado Units 1 and 2.
In order to ensure that actual conditions at the plant are reflected in
our baseline NOX emissions, we decided to make use of the
most recent Acid Rain Program emission data reported to CAMD, which, at
the time that we began our analysis in 2011, was the three-year period
from CY2008-10. Based on CAMD documentation, the low-NOX
burners were installed on Coronado Unit 1 on May 16, 2009, making it
necessary for us to clearly distinguish between the pre-LNB and post-
LNB periods of emission data for Coronado Unit 1. In our analysis, we
have decided to make use of CAMD emission data corresponding to the
post-LNB period extending from May 16, 2009 to December 31, 2010. We
believe the use of this more recent baseline period represents the most
realistic depiction of anticipated annual emissions, as it reflects
operation of Coronado Unit 1 with LNB and OFA.
For Coronado Unit 2, we note that a consent decree between SRP and
EPA requires the installation of SCR and compliance with an emission
limit of 0.080 lb/MMBtu (30-day rolling average) by June 1, 2014.\109\
Although we realize this SCR system has not yet been installed on
Coronado Unit 2, this limit is federally enforceable and represents a
realistic depiction of anticipated future emissions.\110\ As a result,
we consider 0.080 lb/MMBtu to be the baseline emission rate in our BART
analysis and are examining only one control scenario
[[Page 42862]]
in our analysis for Unit 2, SCR at a more stringent emission rate of
0.050 lb/MMBtu.\111\
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\109\ See Docket Item G-01, ``Consent Decree Between U.S. and
SRP (final as entered).'' See also ADEQ Title V Permit Renewal
Number 52639, SRP--Coronado Generating Station, section II.E.1.a.iii
(December 06, 2011).
\110\ See 40 CFR part 51, appendix Y, Section IV.D.4.d.
\111\ A discussion of our rationale for considering SCR at an
emission rate of 0.05 lb/MMBtu can be found in Section VII.A.2
(Control Effectiveness) of this notice.
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ii. SCR Control Efficiency
In determining the control efficiency of SCR in our BART analysis,
we have relied upon an SCR level of performance of 0.05 lb/MMBtu, which
is more stringent than the level of performance used by ADEQ in its
SIP, or by SRP in its Coronado BART analysis. In the Coronado BART
analysis submitted to ADEQ, SRP indicated an SCR level of performance
of 0.08 lb/MMBtu, and noted that ``If inlet NOX
concentrations are less than 250 ppmvd, SCR can achieve NOX
control efficiencies ranging only from 70 to 80 percent.'' \112\ SRP
suggests that the 75 percent reduction (and associated 0.08 lb/MMBtu
emission rate) it estimates for SCR is the result of low inlet
NOX concentration, but does not provide specific information
regarding inlet NOX concentration at Coronado, or how a 75
percent reduction was determined. Our control cost calculations for the
SCR control option at Coronado Unit 1 are based upon the SCR control
efficiency summarized below. This control efficiency reflects the
emission reductions associated with controlling from an annual average
baseline emission rate that represents LNB+OFA (as described
previously) down to an SCR emission rate of 0.05 lb/MMBtu.
---------------------------------------------------------------------------
\112\ See Docket Item B-10, SRP Coronado BART Analysis, page 4-5
Table 21--Coronado Unit 1: EPA's SCR Control Efficiency
----------------------------------------------------------------------------------------------------------------
Baseline SCR control
Unit No. emission rate (lb/ SCR emission rate efficiency
MMBtu) (percentage)
----------------------------------------------------------------------------------------------------------------
Coronado 1............................................. 0.303 0.05 83.5
----------------------------------------------------------------------------------------------------------------
iii. Capacity Factor
SRP did not calculate annual emission estimates for its control
scenarios, in tons per year, in its BART analysis submitted to ADEQ. In
developing its RH SIP, ADEQ estimated annual emission reductions based
upon 8,760 hours/year of operation (i.e., 100 percent capacity factor).
We have calculated annual emission estimates for our control scenarios
using capacity factors developed over a CY2008-11 time frame. The
annual capacity factors we have used for each unit are 81 percent
(Coronado 1), and 89 percent (Coronado 2). We recognize that these
capacity factors are lower than those used by ADEQ, and that by using
these lower capacity factors, our estimates of total annual emissions
(and correspondingly, the annual emission reductions) for each control
scenario are lower than ADEQ's estimates.\113\ Since cost-effectiveness
($/ton) is calculated by dividing annual control costs ($/year) by
annual emission reductions (tons/year), the use of emission reductions
based on lower capacity factors will increase the cost per ton of
pollutant reduced.
---------------------------------------------------------------------------
\113\ We note that there are multiple reasons why our annual
emission estimates (and estimates of emission removal) are lower
than AEPCO's and ADEQ's estimates. We are not implying that the use
of capacity factor is the sole, or even dominant, reason for this
difference, simply that the use of lower capacity factors will
result in lower annual emission estimates.
---------------------------------------------------------------------------
We have elected to use the capacity factors specified above, as
based on a 2008 to 2011 time frame, in order to remain consistent with
the time frame used to develop baseline annual emissions for Coronado
and the other power plants that are the subject of today's proposed
action.\114\
---------------------------------------------------------------------------
\114\ We recognize that there are more aggressive approaches we
could adopt that could justify the use of higher capacity factors,
which would thereby lower the cost per ton of pollutant reduced. For
example, instead of using historical data to develop a capacity
factor value for each unit, we could use a single capacity factor
value for each unit, one that represented a reasonable depiction of
anticipated annual baseload operations. Alternately, we could also
use a 100% capacity factor, or develop new capacity factors based on
a longer 2001 to 2011 time frame.
---------------------------------------------------------------------------
iv. Summary and Conclusions Regarding Costs of Control
A summary of our control cost estimates for the various control
technology options considered for Coronado Units 1 and 2 is in Table
22. Detailed cost calculations, including our contractor's report and
cost calculation spreadsheets, are in our TSD.
Table 22--Coronado Units 1 and 2: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission rate Cost-effectiveness ($/ton)
Emission -------------------------- Emissions Annual cost ------------------------------
Control option factor (lb/ removed ($/yr) Incremental
MMBtu) (lb/hr) (tpy) (tpy) Average (from previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coronado 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.................................................... NA; LNB+OFA is the currently installed technology
------------------------------------------------------------------------------------------------
LNB+OFA (baseline)..................................... 0.303 1,308 4,639 ........... ........... ........... ................
SNCR+LNB+OFA........................................... 0.21 915 3,248 1,392 3,825,556 2,749 ................
SCR+LNB+OFA............................................ 0.05 216 766 3,874 9,315,313 2,405 2,212
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coronado 2
____________________________________________________________________________
SCR@0.08 lb/MMBtu...................................... 0.08 319 1,242 ........... \1\ ........... ................
(baseline)............................................. 8,721,636
SCR@0.05 lb/MMBtu...................................... 0.05 199 776 466 8,993,116 ........... 583
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Annual cost for the baseline scenario is provided here only to allow calculation of the incremental cost associated with a control option of
SCR@0.05 lb/MMBtu.
[[Page 42863]]
For Coronado 1, our calculations indicate that the SCR-based
control option has an average cost-effectiveness value of $2,405/ton
and an incremental cost-effectiveness of $2,212/ton, both of which we
consider cost-effective. As described further below, our analysis for
Coronado 2 relied upon SCR at an emission rate of 0.08 lb/MMBtu as a
baseline scenario. As a result, the only control option we examined for
Coronado 2 was an SCR-based option at a more stringent level of
performance, 0.05 lb/MMBtu. Our initial analysis indicates that the
incremental cost-effectiveness of such an option is $583/ton, making it
a control option that we would consider cost-effective. However, we
received information from SRP indicating that design and construction
of the SCR system for this unit are well under way. In its letter, SRP
states that ``if SRP were required to abandon the current design, incur
procurement losses, possibly remove foundations, and undertake new
design and procurement, such steps would vastly increase the cost of
the SCR retrofit.'' Since these types of additional costs were not
factored into our original analysis, the average and incremental cost-
effectiveness of requiring Coronado Unit 2 to meet an emissions limit
of 0.050 lb/MMBtu may in fact be greater than indicated by our
analysis. However, we intend to request further documentation in order
to determine the extent of these costs and how they would affect our
cost-effectiveness calculations. We will include all non-CBI material
received in the docket for this action and will consider it as part of
our final action. We are specifically interested in information from
SRP concerning the number of layers of catalyst for the SCR at Unit 2,
how they plan to manage replacement of the catalyst, and whether the
catalyst could be installed and managed to allow Unit 2 to meet a lower
emission limit than 0.08 lb/MMBtu.
Thus, our initial analysis of this factor indicates that the costs
of compliance (average or incremental) are not sufficiently large to
warrant eliminating any of the control options from consideration.
However, we note that, based on preliminary information received from
SRP, the average and incremental costs of achieving an emission rate of
0.050 lb/MMBtu at Unit 2 may be much greater than our initial analysis
suggests.
b. Visibility Improvement
The overall modeling approach was described above; aspects of the
modeling specific to Coronado are described here. LNB was installed on
Unit 1 in mid-2009, and on Unit 2 in mid-2011. For Unit 1's
NOX emissions, the maximum daily emissions in EPA's CAMD
database for 2008 to 2010 was used; the maximum post-LNB installation
emissions occurred in late 2010. For unit 2 emissions, the consent
decree-mandated NOX emission limit of 0.08 lb/MMBtu was
combined with the maximum heat rate from 2008-2010 CAMD data, which
occurred in late 2008. Since this limit has a 30-day averaging time,
daily emissions may be larger than the emissions EPA modeled; the
emission and visibility benefit would also be larger. Thus, visibility
benefits from control applied to the base case may actually be larger
than presented here. The base case reflects LNB as the control in place
on Unit 1, and SCR at 0.08 lb/MMBtu NOX on Unit 2.
EPA evaluated SNCR applied to Unit 1, and SCR at 0.05 lb/MMBtu
applied to both Units 1 and 2. SCR was assumed to give a control
effectiveness of 83.5 percent for unit 1 (less than 90 percent due to
the 0.05 lb/MMBtu NOX lower limit assumed for SCR). SCR at
0.05 lb/MMBtu NOX was assumed to give a control
effectiveness of 37.5 percent over the base case 0.08 lb/MMBtu. As
mentioned above, the SCR simulation accounted for the increase in
sulfuric acid emissions due to catalyst oxidation of SO2.
However, the simulation with SNCR applied to unit 1 did not account for
this effect. If this additional Unit 2 sulfate were accounted for, it
could make some background ammonia unavailable to form visibility-
affecting particulate from Unit 1's NOX emissions, thus
reducing the visibility impact and also the visibility benefit from
SNCR. We expect this to have very little effect on the estimated SNCR
visibility benefit, since it was computed relative to an alternative
base case that likewise did not include the catalyst oxidation effect,
but the visibility benefits from SNCR may thus be slightly less than
reported here, weakening the case for SNCR.
Sixteen Class I areas within 300 km of Coronado were modeled; they
are in the states of Arizona, Colorado, and New Mexico. A 17th area,
the Bosque del Apache Wilderness Area in New Mexico, was inadvertently
omitted. Since it is in the same general direction from Coronado as the
Gila Wilderness Area, but farther way, visibility impacts and control
benefits at Bosque del Apache are likely to be lower than for Gila, so
the maximum dv benefit would not be affected by this omission. However,
the cumulative impacts and benefits would be higher than reported here
since Bosque del Apache is omitted from the sum. The 98th percentile
delta deciviews over all three years of data were computed for each
area and emission scenario.
Table 23 shows baseline visibility impacts and the visibility
improvement when controls are applied; the various table entries are
described above in the discussion of the comparable table for Apache.
The area with the greatest dv improvement was the Gila Wilderness Area;
there is an improvement of 0.3 dv from SNCR, 0.6 dv from SCR on unit 1,
and 0.7 dv from SCR at 0.05 lb/MMBtu on both units. These improvements
are smaller than for the other facilities because the benefit from SCR
at 0.08 lb/MMBtu on unit 2 is subsumed in the baseline. Any of these
improvements would contribute to improved visibility, though SNCR on
unit 2 only marginally so. SCR is the superior option for visibility,
with the more stringent SCR at 0.05 lb/MMBtu on unit 2 giving a
slightly greater benefit than when that limit is applied only to unit
1. The cumulative improvements corresponding to the three control
scenarios are 1.3 dv, 2.8 dv, and 3.1 dv. Only the SCR scenarios give
improvements exceeding 0.5 dv. The modeled degree of visibility
improvements supports either SCR scenario as BART for Coronado.
Table 23--Coronado Units 1 and 2: EPA's Visibility Improvements From NOX Controls
----------------------------------------------------------------------------------------------------------------
Improvement Improvement Improvement
Class I area Baseline from SNCR on from SCR .05 from SCR, 0.05
impact (dv) unit 1 (dv) on unit 1 (dv) lb/MMBtu (dv)
----------------------------------------------------------------------------------------------------------------
Bandelier NM.................................... 0.37 0.07 0.19 0.20
Chiricahua NM................................... 0.20 0.03 0.07 0.08
Chiricahua WA................................... 0.21 0.04 0.08 0.09
Galiuro WA...................................... 0.20 0.03 0.08 0.09
Gila WA......................................... 1.23 0.33 0.60 0.66
[[Page 42864]]
Grand Canyon NP................................. 0.24 0.03 0.10 0.11
Mazatzal WA..................................... 0.20 0.03 0.06 0.07
Mesa Verde NP................................... 0.40 0.10 0.19 0.20
Mount Baldy WA.................................. 0.87 0.16 0.42 0.44
Petrified Forest NP............................. 1.22 0.22 0.47 0.56
Pine Mountain WA................................ 0.14 0.02 0.04 0.05
Saguaro NP...................................... 0.12 0.01 0.03 0.04
San Pedro Parks WA.............................. 0.54 0.11 0.28 0.30
Sierra Ancha WA................................. 0.24 0.04 0.06 0.07
Superstition WA................................. 0.21 0.02 0.06 0.06
Sycamore Canyon WA.............................. 0.16 0.02 0.06 0.06
Cumulative dv................................... 6.54 1.25 2.78 3.07
areas >=0.5........................... 4 0 1 2
$/max dv, millions.............................. .............. $11.9 $16.2 $15.0
$/cumulative dv, millions....................... .............. $3.1 $3.5 $3.2
----------------------------------------------------------------------------------------------------------------
Note: Costs of implementing SCR at 0.08 lb/MMBtu on unit 2 are not included.
c. EPA's BART Determinations
As noted above, we have considered the remaining useful life of the
source by incorporating a 20-year amortization period into our control
cost calculations. The presence of existing pollution control
technology is reflected in the cost and visibility factors as a result
of selection of the baseline period for cost calculations and
visibility modeling. For Coronado Unit 1, a baseline period (May 2009
to December 2010) was selected that reflects the currently existing
pollution control technology (LNB with OFA). For Coronado Unit 2, a
baseline of 0.080 lb/MMBtu was selected to reflect the requirements of
the consent decree decribed above. In addition, as noted above, we have
received information from SRP indicating that the design and
construction of SCR at Unit 2 have aleady progressed significantly. To
the extent that we receive additional documentation establishing the
status of this effort, we will take this information into consideration
under the factors of ``costs of compliance'' and ``existing controls.''
In examining energy and non-air quality impacts, we note certain
potential impacts resulting from the use of ammonia injection
associated with the SNCR and SCR control options, but do not consider
these impacts sufficient enough to warrant eliminating any of the
available control technologies.
Our consideration of degree of visibility improvement focuses
primarily on the improvement from base case impacts associated with
each control option. While each of the available NOX control
options achieves some degree of visibility improvement, we consider the
improvement associated with the most stringent option, SCR with LNB and
OFA, to be substantial. Our consideration of cost of compliance focuses
primarily on the cost-effectiveness of each control option, as measured
in cost per ton and incremental cost per ton of each control option.
Despite the fact that the most stringent option, SCR with LNB and OFA,
is the most expensive of the available control options, we consider it
cost-effective on average basis as well as on an incremental basis when
compared to the next most stringent option, SNCR with LNB and OFA.
As a result, we consider the most stringent available control
option, SCR with LNB and OFA, to be cost-effective and to result in
substantial visibility improvement, and that the energy and non-air
quality impacts are not sufficient to warrant eliminating it from
consideration. Therefore, we propose to determine that NOX
BART for Coronado Units 1 and 2 is SCR with LNB and OFA. At Unit1 we
propose an emission limit for NOX of 0.050 lb/MMBtu, based
on a rolling 30-boiler-operating-day average.
At Unit 2, we propose an emission limit of 0.080 lb/MMBtu, which is
consistent with the emission limit in the consent decree. We
acknowledge that the emission limit of 0.080 lb/MMBtu established in
the consent decree was not the result of a BART five-factor analysis,
nor does the consent decree indicate that SCR at 0.080 lb/MMBtu
represents BART. Nonetheless, given the compliance schedule established
in the consent decree and the preliminary information received from SRP
regarding the status of design and construction of the SCR system, it
appears that achieving a 0.050 lb/MMBtu emission rate may not be
technically feasible. Even if it is feasible, achievement of this
emission rate may not be cost-effective. Therefore, we are proposing an
emission limit of 0.080 lb/MMBtu as BART for NOX at Unit 2.
However, if we do not receive sufficient documentation establishing
that achievement of a more stringent limit is infeasible or not cost-
effective, then we may determine that a more stringent limit for this
unit is required in our final action.
For Coronado Unit 2, we are proposing a compliance date of June 1,
2014 for the NOX limit, consistent with the consent decree
described above.
Finally, at Coronado Unit 1, we are proposing to require compliance
with the NOX limit within five years of final promulgation
of this FIP consistent with the compliance times for the NOX
limits at the other units. However, we are seeking comment on whether a
shorter compliance schedule may be practicable for this unit.
C. Enforceability Requirements
In order to meet the requirements of the RHR and the CAA and to
ensure that the BART limits are practically enforeceable, we propose to
include the following elements in the FIP:
1. Requirements for use of continuous emission monitoring systems
(CEMS) (and associated quality assurance procedures) to determine
compliance with NOX and SO2 limits.
2. Use of 30-day rolling averaging period and definition of boiler
operating day, consistent with the BART Guidelines.
3. Requirements for annual performance stack tests and
implementation of Compliance Assurance Monitoring (CAM) plan to
establish compliance with PM emission limits.
[[Page 42865]]
4. Recordkeeping and reporting requirements.
5. Requirement to maintain and operate the unit including
associated air pollution control equipment in a manner consistent with
good air pollution control practices for minimizing emissions.
The foregoing requirements would apply to all units.
In addition, we are proposing specific compliance deadlines for
each of ADEQ's BART emissions limits that we are proposing to approve.
In most instances, the control technologies required to meet these
limits have already been installed. See Table 3. Therefore, we are
proposing to require compliance with the applicable emissions limits
for PM and SO2 within 180 days of final promulgation of this
FIP, except that at Cholla Unit 2, we propose to require compliance
with the PM limit by January 1, 2015, consistent with ADEQ's BART
determination.
Regarding NOX, we propose to allow up to five years from
final promulgation of this FIP for each unit subject to an emission
limit consistent with SCR, with the exception of Coronado Unit 2. This
proposal is based on the results of two analyses of SCR installation
times, as summarized in EPA Region 6's Complete Response to Comments
for NM Regional Haze/Visibility Transport FIP.\115\ An analysis
performed by EPA Region 6, based on a review of a number of sources,
found that the design and installation of SCR took between 18 and 69
months. A separate analysis performed for the Utility Air Regulatory
Group (UARG) found that it took 28 to 62 months to design and install
the 14 SCRs in its sample.\116\ In the case of the BART FIP for San
Juan Generating Station, EPA Region 6 initially proposed to allow a
three-year compliance time frame for design and installation of SCR,
but ultimately allowed for a five-year compliance schedule.\117\ We
also note that SCR installations often trigger Prevention of
Significant of Deterioration permitting requirements because they
constitute physical changes to an existing emission unit that may
result in increased emissions of sulfuric acid mist. Therefore, we are
proposing a five-year compliance time frame, which would provide
adequate time for SCR design and installation based on the high-end of
the range of dates in the analyses cited above. However, we are seeking
comment on whether these compliance dates are reasonable and consistent
with the requirement of the CAA and the RHR that BART be installed ``as
expeditiously as practicable.'' We are specifically seeking comment on
whether the outage schedule for any of these units may warrant a
shorter compliance schedule (up to five years). If we receive
information during the comment period that establishes that a shorter
compliance timeframe is appropriate for one or more of these units, we
may finalize a different compliance date.
---------------------------------------------------------------------------
\115\ Available on regulations.gov, docket no. EPA-R06-OAR-2010-
0846, pp. 70-72. See also 76 FR at 52408-09.
\116\ J. Edward Cichanowicz, Implementation Schedule for
Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization
(FGD) Process Equipment (Oct. 10, 2010).
\117\ 76 FR at 52408-09.
---------------------------------------------------------------------------
VIII. Summary of EPA's Proposed Action
Based on the available control technologies and the five factors
discussed in more detail below, EPA is proposing to require these
facilities to meet NOX, PM10 and SO2
emission limits as listed in Table 24. With the exception of Apache
Unit 1, the NOX emission limits in Table 24 are proposed as
part of EPA's FIP, based on the five factor analyses summarized in
Section VII. The PM10 and SO2 emission limits in
Table 24 are taken from ADEQ's BART determinations for these
facilities, proposed for EPA approval in this action. EPA is seeking
comment on alternative PM10 and SO2 emissions
limits for Apache Generating Station Units 2 and 3; Cholla Power Plant
Units 2, 3 and 4; and Coronado Units 1 and 2 as described in Section
VI.B. We are also seeking comment on whether a test method other than
EPA Method 201/202 should be allowed or required for establishing
compliance with the PM10 limits that we are proposing to
approve. Finally, we are proposing compliance dates and specific
requirements for monitoring, recordkeeping, reporting and equipment
operation and maintenance for all of the units covered by this action.
Our proposed compliance dates are summarized in Table 25. We are
seeking comment on whether these compliance dates are reasonable and
consistent with the requirement of the CAA and the RHR that BART be
installed ``as expeditiously as practicable.'' We are also taking
comment on whether it would be technically feasible and cost-effective
for Coronado Unit 2 to meet an emissions limit of 0.050 lb/MMBtu for
NOX.
EPA takes very seriously a decision to disapprove a state plan. In
this instance, we believe that Arizona's SIP meets the CAA requirements
with respect to its SO2 and PM10 limits, but the
NOX BART determinations for the coal-fired units are neither
consistent with the requirements of the Act nor with BART decisions
that other states have made. As a result, EPA considers that this
proposed disapproval is the only path that is consistent with the Act
at this time.
Table 24--Summary of BART Emission Limits
----------------------------------------------------------------------------------------------------------------
Emission limitation (lb/MMBtu) (rolling 30-boiler-
operating-day average)
Unit -----------------------------------------------------
NOX PM10 SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1.......................... 0.056 0.0075 0.00064
Apache Generating Station Unit 2.......................... 0.050 0.03 0.15
Apache Generating Station Unit 3.......................... 0.050 0.03 0.15
Cholla Power Plant Unit 2................................. 0.050 0.015 0.15
Cholla Power Plant Unit 3................................. 0.050 0.015 0.15
Cholla Power Plant Unit 4................................. 0.050 0.015 0.15
Coronado Generating Station Unit 1........................ 0.050 0.03 0.08
Coronado Generating Station Unit 2........................ 0.080 0.03 0.08
----------------------------------------------------------------------------------------------------------------
[[Page 42866]]
Table 25--Summary of BART Compliance Dates
----------------------------------------------------------------------------------------------------------------
Compliance date
Unit ------------------------------------------------------------------------------
NOX PM10 SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1. Five years............... 180 days................ 180 days.
Apache Generating Station Unit 2. Five years............... 180 days................ 180 days.
Apache Generating Station Unit 3. Five years............... 180 days................ 180 days.
Cholla Power Plant Unit 2........ Five years............... January 1, 2015......... 180 days.
Cholla Power Plant Unit 3........ Five years............... 180 days................ 180 days.
Cholla Power Plant Unit 4........ Five years............... 180 days................ 180 days.
Coronado Generating Station Unit Five years............... 180 days................ 180 days.
1.
Coronado Generating Station Unit June 1, 2014............. 180 days................ 180 days.
2.
----------------------------------------------------------------------------------------------------------------
Table 26--Summary of Arizona's Proposed BART Emission Limits
----------------------------------------------------------------------------------------------------------------
Emission limitation (lb/MMBtu) (rolling 30-boiler-
operating-day average)
Unit -----------------------------------------------------
NOX PM10 SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1.......................... 0.056 0.0075 0.00064
Apache Generating Station Unit 2.......................... n/a 0.03 0.15
Apache Generating Station Unit 3.......................... n/a 0.03 0.15
Cholla Power Plant Unit 2................................. n/a 0.015 0.15
Cholla Power Plant Unit 3................................. n/a 0.015 0.15
Cholla Power Plant Unit 4................................. n/a 0.015 0.15
Coronado Generating Station Unit 1........................ n/a 0.03 0.08
Coronado Generating Station Unit 2........................ n/a 0.03 0.08
----------------------------------------------------------------------------------------------------------------
Table 27--Summary of EPA's Proposed FIP BART Emission Limits
----------------------------------------------------------------------------------------------------------------
Emission limitation (lb/MMBtu) (rolling 30-boiler-
operating-day average)
Unit -----------------------------------------------------
NOX PM10 SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1.......................... n/a n/a n/a
Apache Generating Station Unit 2.......................... 0.050 n/a n/a
Apache Generating Station Unit 3.......................... 0.050 n/a n/a
Cholla Power Plant Unit 2................................. 0.050 n/a n/a
Cholla Power Plant Unit 3................................. 0.050 n/a n/a
Cholla Power Plant Unit 4................................. 0.050 n/a n/a
Coronado Generating Station Unit 1........................ 0.050 n/a n/a
Coronado Generating Station Unit 2........................ 0.080 n/a n/a
----------------------------------------------------------------------------------------------------------------
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
This proposed action is not a ``significant regulatory action''
under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993)
and is therefore not subject to review under Executive Orders 12866 and
13563 (76 FR 3821, January 21, 2011). As discussed in detail in section
C below, the proposed FIP applies to only three facilities. It is
therefore not a rule of general applicability.
B. Paperwork Reduction Act
This proposed action does not impose an information collection
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C.
3501 et seq. Under the Paperwork Reduction Act, a ``collection of
information'' is defined as a requirement for ``answers to * * *
identical reporting or recordkeeping requirements imposed on ten or
more persons * * *.'' 44 U.S.C. 3502(3)(A). Because the proposed FIP
applies to just three facilities, the Paperwork Reduction Act does not
apply. See 5 CFR 1320(c). Burden means the total time, effort, or
financial resources expended by persons to generate, maintain, retain,
or disclose or provide information to or for a Federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information. An agency may not conduct or sponsor, and a person is not
required to respond to a collection of information unless it displays a
currently valid Office of Management and Budget (OMB) control number.
The OMB control numbers for our regulations in 40 CFR are listed in 40
CFR part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
[[Page 42867]]
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impacts of today's proposed rule on small entities,
small entity is defined as: (1) A small business as defined by the
Small Business Administration's (SBA) regulations at 13 CFR 121.201;
(2) a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any not-for
profit enterprise which is independently owned and operated and is not
dominant in its field. Firms primarily engaged in the generation,
transmission, and/or distribution of electric energy for sale are small
if, including affiliates, the total electric output for the preceding
fiscal year did not exceed 4 million megawatt hours. AEPCO sold under 3
million megawatt hours in 2011. APS and SRP are not small entities.
After considering the economic impacts of this proposed action on small
entities, I certify that this proposed action will not have a
significant economic impact on a substantial number of small entities.
The FIP for the three Arizona facilities being proposed today does not
impose new requirements on a substantial number of small entities. The
proposed partial approval of the SIP, if finalized, merely approves
state law as meeting Federal requirements and imposes no additional
requirements beyond those imposed by state law. See Mid-Tex Electric
Cooperative, Inc. v. FERC, 773 F.2d 327 (DC Cir. 1985). Although a
regulatory flexibility analysis as specified by the RFA is not required
when a rule has some impact on one small entity, EPA policy is to
assess the direct adverse impact of every rule on small entities and
minimize any adverse impact to the extent feasible, regardless of the
magnitude of the impact or number of small entities affected.\118\
Using easily available public information,\119\ EPA estimates that the
annualized cost of requiring SCR in Units 1 and 2 would likely be in
the range of 3 percent of AEPCO's assets and between 6 and 7 percent of
AEPCO's annual sales. EPA requested information from AEPCO on the
economics of operating Apache Generating Station and what impact the
installation of SCR may have on the economics of operating Apache
Generating Station.
---------------------------------------------------------------------------
\118\ See Docket Item A-22 Final Guidance for EPA Rulewriters:
Regulatory Flexibility Act as Amended by the Small Business and
Regulatory Enforcement Fairness Act, November 2006 at 3.
\119\ See Docket Item H-1 Arizona Electric Power Cooperative,
Inc. Annual Report Electric for Year Ending December 31, 2011
submitted to Arizona Corporation Commission Utilities Division,
available at http://www.azcc.gov/Divisions/Utilities/Annual%20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_Inc.pdf.
---------------------------------------------------------------------------
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and Tribal
governments and the private sector. Under section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and Tribal governments, in
the aggregate, or to the private sector, of $100 million or more
(adjusted for inflation) in any 1 year. Before promulgating an EPA rule
for which a written statement is needed, section 205 of UMRA generally
requires EPA to identify and consider a reasonable number of regulatory
alternatives and adopt the least costly, most cost-effective, or least
burdensome alternative that achieves the objectives of the rule. The
provisions of section 205 of UMRA do not apply when they are
inconsistent with applicable law. Moreover, section 205 of UMRA allows
EPA to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator
publishes with the final rule an explanation why that alternative was
not adopted. Before EPA establishes any regulatory requirements that
may significantly or uniquely affect small governments, including
Tribal governments, it must have developed under section 203 of UMRA a
small government agency plan. The plan must provide for notifying
potentially affected small governments, enabling officials of affected
small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
Under Title II of UMRA, EPA has determined that this proposed rule
does not contain a Federal mandate that may result in expenditures that
exceed the inflation-adjusted UMRA threshold of $100 million by State,
local, or Tribal governments or the private sector in any 1 year. In
addition, this proposed rule does not contain a significant Federal
intergovernmental mandate as described by section 203 of UMRA nor does
it contain any regulatory requirements that might significantly or
uniquely affect small governments.
E. Executive Order 13132: Federalism
Federalism (64 FR 43255, August 10, 1999) revokes and replaces
Executive Orders 12612 (Federalism) and 12875 (Enhancing the
Intergovernmental Partnership). Executive Order 13132 requires EPA to
develop an accountable process to ensure ``meaningful and timely input
by State and local officials in the development of regulatory policies
that have federalism implications.'' ``Policies that have federalism
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government.'' Under Executive Order 13132, EPA may not issue a
regulation that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides the funds necessary to pay the direct
compliance costs incurred by State and local governments, or EPA
consults with State and local officials early in the process of
developing the proposed regulation. EPA also may not issue a regulation
that has federalism implications and that preempts State law unless the
Agency consults with State and local officials early in the process of
developing the proposed regulation.
This rule will not have substantial direct effects on the States,
on the relationship between the national government and the States, or
on the distribution of power and responsibilities among the various
levels of government, as specified in Executive Order 13132, because it
addresses the State not fully meeting its obligation to prohibit
emissions from interfering with other states measures to protect
visibility established in the CAA. Thus, Executive Order 13132 does not
apply to this action. In the spirit of Executive Order 13132, and
consistent with EPA policy to promote communications between EPA and
State and local governments, EPA specifically solicits comment on this
proposed rule from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled Consultation and Coordination With
Indian Tribal Governments (65 FR 67249, November 9, 2000), requires EPA
[[Page 42868]]
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' This proposed rule does not have
tribal implications, as specified in Executive Order 13175. It will not
have substantial direct effects on tribal governments. Thus, Executive
Order 13175 does not apply to this rule. EPA specifically solicits
additional comment on this proposed rule from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks (62 FR 19885,April 23, 1997), applies to
any rule that: (1) Is determined to be economically significant as
defined under Executive Order 12866; and (2) concerns an environmental
health or safety risk that we have reason to believe may have a
disproportionate effect on children. EPA interprets EO 13045 as
applying only to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the EO
has the potential to influence the regulation. This action is not
subject to EO 13045 because it implements specific standards
established by Congress in statutes. However, to the extent this
proposed rule will limit emissions of NOX, SO2,
and PM10, the rule will have a beneficial effect on
children's health by reducing air pollution.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not subject to Executive Order 13211 (66 FR 28355
(May 22, 2001)), because it is not a significant regulatory action
under Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12 of the National Technology Transfer and Advancement Act
(NTTAA) of 1995 requires Federal agencies to evaluate existing
technical standards when developing a new regulation. To comply with
NTTAA, EPA must consider and use ``voluntary consensus standards''
(VCS) if available and applicable when developing programs and policies
unless doing so would be inconsistent with applicable law or otherwise
impractical. The EPA believes that VCS are inapplicable to this action.
Today's action does not require the public to perform activities
conducive to the use of VCS.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994), establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
We have determined that this proposed rule, if finalized, will not
have disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population. This proposed federal rule limits emissions of
NOX, from three facilities in Arizona. The partial approval
of the SIP for SO2, and PM10, if finalized,
merely approves state law as meeting Federal requirements and imposes
no additional requirements beyond those imposed by state law.
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Nitrogen dioxide, Particulate
matter, Reporting and recordkeeping requirements, Sulfur dioxide,
Visibility, Volatile organic compounds.
Dated: July 2, 2012.
Jared Blumenfeld,
Regional Administrator, Region 9.
Part 52, chapter I, title 40 of the Code of Federal Regulations is
proposed to be amended as follows:
PART 52--[AMENDED]
1. The authority citation for Part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart D--Arizona
2. Add paragraph (e) to Sec. 52.145, to read as follows:
Sec. 52.145 Visibility Protection.
* * * * *
(e) Federal implementation plan for regional haze.
(1) Applicability. This paragraph (e) applies to each owner/
operator of the following coal-fired electricity generating units
(EGUs) in the state of Arizona: Apache Generating Station, Units 2 and
3; Cholla Power Plant, Units 2, 3, and 4; and Coronado Generating
Station, Units 1 and 2. This paragraph (e) also applies to each owner/
operator of the following natural gas-fired EGU in the state of
Arizona: Apache Generating Station Unit 1. The provisions of this
paragraph (e) are severable, and if any provision of this paragraph
(e), or the application of any provision of this paragraph (e) to any
owner/operator or circumstance, is held invalid, the application of
such provision to other owner/operators and other circumstances, and
the remainder of this paragraph (e), shall not be affected thereby.
(2) Definitions. Terms not defined below shall have the meaning
given to them in the Clean Air Act or EPA's regulations implementing
the Clean Air Act. For purposes of this paragraph (e):
ADEQ means the Arizona Department of Environmental Quality.
Boiler operating day means a 24-hour period between 12 midnight and
the following midnight during which any fuel is combusted at any time
in the steam-generating unit. It is not necessary for fuel to be
combusted the entire 24-hour period.
Coal-fired unit means any of the EGUs identified in paragraph
(e)(1) of this section, except for Apache Generating Station, Unit 1.
Continuous emission monitoring system or CEMS means the equipment
required by 40 CFR part 75 and this paragraph (e).
Emissions limitation or emissions limit means the Federal emissions
limitation required by this paragraph (e) and the applicable
PM10 and SO2 emissions limits for Apache
Generating Station, Cholla Power Plant, and Coronada Generating Station
submitted to EPA as part of the Arizona Regional Haze State
Implementation Plan in a letter dated February 28, 2011 and approved
into the Arizona state implementation plan on [INSERT DATE OF
PUBLICATION OF FINAL ACTION IN THE Federal Register].
lb means pound(s).
NOX means nitrogen oxides expressed as nitrogen dioxide
(NO2).
Owner(s)/operator(s) means any person(s) who own(s) or who
operate(s), control(s), or supervise(s) one more of
[[Page 42869]]
the units identified in paragraph (e)(1) of this section.
MMBtu means million British thermal unit(s).
Operating hour means any hour that fossil fuel is fired in the
unit.
Pipeline natural gas means a naturally occurring fluid mixture of
hydrocarbons (e.g., methane, ethane, or propane) produced in geological
formations beneath the Earth's surface that maintains a gaseous state
at standard atmospheric temperature and pressure under ordinary
conditions, and which is provided by a supplier through a pipeline.
Pipeline natural gas contains 0.5 grains or less of total sulfur per
100 standard cubic feet. Additionally, pipeline natural gas must either
be composed of at least 70 percent methane by volume or have a gross
calorific value between 950 and 1100 Btu per standard cubic foot.
PM10 means filterable total particulate matter less than 10 microns
and the condensable material in the impingers as measured by Methods
201A and 202.
Regional Administrator means the Regional Administrator of EPA
Region IX or his/her authorized representative.
SO2 means sulfur dioxide.
Unit means any of the EGUs identified in paragraph (e)(1) of this
section.
(3) Emission Limitations. The owner/operator of each unit subject
to this paragraph (e) shall not emit or cause to be emitted
NOX in excess of the following limitations, in pounds per
million British thermal units (lb/MMBtu). Each emission limit shall be
based on a rolling 30-boiler-operating-day average, unless otherwise
indicated in specific paragraphs. Apache Generating Station Unit 1
shall operate only on pipeline natural gas.
------------------------------------------------------------------------
Federal
Unit emission
limit NOX
------------------------------------------------------------------------
Apache Generating Station Unit 1......................... 0.056
Apache Generating Station Unit 2......................... 0.050
Apache Generating Station Unit 3......................... 0.050
Cholla Power Plant Unit 2................................ 0.050
Cholla Power Plant Unit 3................................ 0.050
Cholla Power Plant Unit 4................................ 0.050
Coronado Generating Station Unit 1....................... 0.050
Coronado Generating Station Unit 2....................... 0.08
------------------------------------------------------------------------
(4) Compliance Dates.
i. The owners/operators of each unit subject to paragraph (e) shall
comply with the emissions limitations and other requirements of this
paragraph (e) as expeditiously as practicable, but in no event later
than the following dates:
----------------------------------------------------------------------------------------------------------------
Compliance date
Unit --------------------------------------------------------------------------
NOX PM10 SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station, Unit 1.... [INSERT DATE FIVE YEARS [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF AFTER DATE OF
PUBLICATION OF FINAL PUBLICATION OF FINAL PUBLICATION OF FINAL
ACTION IN THE Federal ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]. Register]
Apache Generating Station, Unit 2.... [INSERT DATE FIVE YEARS [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF AFTER DATE OF
PUBLICATION OF FINAL PUBLICATION OF FINAL PUBLICATION OF FINAL
ACTION IN THE Federal ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]. Register]
Apache Generating Station, Unit 3.... [INSERT DATE FIVE YEARS [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF AFTER DATE OF
PUBLICATION OF FINAL PUBLICATION OF FINAL PUBLICATION OF FINAL
ACTION IN THE Federal ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]. Register]
Cholla Power Plant, Unit 2........... [INSERT DATE FIVE YEARS January 1, 2015........ [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF
PUBLICATION OF FINAL PUBLICATION OF FINAL
ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]
Cholla Power Plant, Unit 3........... [INSERT DATE FIVE YEARS [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF AFTER DATE OF
PUBLICATION IN THE PUBLICATION OF FINAL PUBLICATION OF FINAL
Federal Register]. ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]
Cholla Power Plant, Unit 4........... [INSERT DATE FIVE YEARS [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF AFTER DATE OF
PUBLICATION IN THE PUBLICATION IN THE PUBLICATION IN THE
Federal Register]. Federal Register]. Federal Register]
Coronado Generating Station, Unit 1.. [INSERT DATE FIVE YEARS [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF AFTER DATE OF
PUBLICATION OF FINAL PUBLICATION OF FINAL PUBLICATION OF FINAL
ACTION IN THE Federal ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]. Register]
Coronado Generating Station, Unit 2.. June 1, 2014........... [INSERT DATE 180 DAYS [INSERT DATE 180 DAYS
AFTER DATE OF AFTER DATE OF
PUBLICATION OF FINAL PUBLICATION OF FINAL
ACTION IN THE Federal ACTION IN THE Federal
Register]. Register]
----------------------------------------------------------------------------------------------------------------
[[Page 42870]]
(5) Compliance determinations for NOX and SO2.
i. Continuous emission monitoring system.
A. At all times after the compliance date specified in paragraph
(e)(4) of this section, the owner/operator of each coal-fired unit
shall maintain, calibrate, and operate a CEMS, in full compliance with
the requirements found at 40 CFR part 75, to accurately measure
SO2, NOX, diluent, and stack gas volumetric flow
rate from each unit. Apache Unit 1 NOX and diluent CEMs
shall be operated to meet the requirements of Part 75. Valid data means
data recorded when the CEMS is not out-of-control as defined by Part
75. All valid CEMS hourly data shall be used to determine compliance
with the emission limitations for NOX and SO2 in
paragraph (e)(3) of this section for each unit. When the CEMS is out-
of-control as defined by Part 75, that CEMs data shall be treated as
missing data and not used to calculate the emission average.
B. The owner/operator of each unit shall comply with the quality
assurance procedures for CEMS found in 40 CFR part 75. In addition to
these Part 75 requirements, relative accuracy test audits shall be
performed for both the NOX pounds per hour measurement and
the heat input measurement. These shall have relative accuracies of
less than 20%. This testing shall be evaluated each time the CEMS
undergo relative accuracy testing. Heat input for Apache Unit 1 shall
be measured in accordance with Part 75 fuel gas measurement procedures
found in Part 75 Appendix D.
ii. Compliance determinations for NOX.
A. The 30-day rolling average NOX emission rate for each
unit shall be calculated in accordance with the following procedure:
First, sum the total pounds of NOX emitted from the unit
during the current boiler operating day and the previous twenty-nine
(29) boiler-operating days; second, sum the total heat input to the
unit in MMBtu during the current boiler operating day and the previous
twenty-nine (29) boiler-operating days; and third, divide the total
number of pounds of NOX emitted during the thirty (30)
boiler-operating days by the total heat input during the thirty (30)
boiler-operating days. A new 30-day rolling average NOX
emission rate shall be calculated for each new boiler operating day.
Each 30-day rolling average NOX emission rate shall include
all emissions that occur during all periods within any boiler operating
day, including emissions from startup, shutdown, and malfunction.
B. If a valid NOX pounds per hour or heat input is not
available for any hour for a unit, that heat input and NOX
pounds per hour shall not be used in the calculation of the 30-day
rolling average. Each unit must obtain valid hourly data for at least
90% of the operating hours for each calendar quarter.
iii. Compliance determinations for SO2.
A. The 30-day rolling average SO2 emission rate for each
coal-fired unit shall be calculated in accordance with the following
procedure: First, sum the total pounds of SO2 emitted from
the unit during the current boiler operating day and the previous
twenty-nine (29) boiler-operating days; second, sum the total heat
input to the unit in MMBtu during the current boiler-operating day and
the previous twenty-nine (29) boiler-operating day; and third, divide
the total number of pounds of SO2 emitted during the thirty
(30) boiler-operating days by the total heat input during the thirty
(30) boiler-operating days. A new 30-day rolling average SO2
emission rate shall be calculated for each new boiler operating day.
Each 30-day rolling average SO2 emission rate shall include
all emissions that occur during all periods within any boiler-operating
day, including emissions from startup, shutdown, and malfunction.
B. If a valid SO2 pounds per hour or heat input is not
available for any hour for a unit, that heat input and SO2
pounds per hour shall not be used in the calculation of the 30-day
rolling average. Each unit must obtain valid hourly data for at least
90% of the operating hours for each calendar quarter.
(6) Compliance Determinations for Particulate Matter. Compliance
with the particulate matter emission limitation for each coal-fired
unit shall be determined from annual performance stack tests. Within
sixty (60) days of the compliance deadline specified in paragraph
(e)(4) of this section, and on at least an annual basis thereafter, the
owner/operator of each unit shall conduct a stack test on each unit to
measure PM-10 using 40 CFR part 51, appendix M, Method 201A/202. A test
protocol shall be submitted to EPA a minimum of 30 days prior to the
scheduled testing. Each test shall consist of three runs, with each run
at least 120 minutes in duration and each run collecting a minimum
sample of 60 dry standard cubic feet. Results shall be reported in lb/
MMBtu using the calculation in 40 CFR part 60 appendix A Method 19. In
addition to annual stack tests, owner/operator shall monitor
particulate emissions for compliance with the emission limitations in
accordance with the applicable Compliance Assurance Monitoring (CAM)
plan developed and approved in accordance with 40 CFR part 64. The
averaging time for any other demonstration of the PM-10 compliance or
exceedance shall be based on a 6-hour average.
(7) Recordkeeping. The owner or operator of each unit shall
maintain the following records for at least five years:
a. All CEMS data, including the date, place, and time of sampling
or measurement; parameters sampled or measured; and results.
b. Daily 30-day rolling emission rates for NOX and
SO2 for each unit, calculated in accordance with paragraph
(e)(5) of this section.
c. Records of quality assurance and quality control activities for
emissions measuring systems including, but not limited to, any records
required by 40 CFR part 75.
d. Records of the relative accuracy test for NOX and
SO2 lb/hr measurement and hourly heat input.
e. Records of all major maintenance activities conducted on
emission units, air pollution control equipment, and CEMS.
f. Any other records required by 40 CFR part 75.
(8) Reporting. All reports and notifications under this paragraph
(e) shall be submitted to the Director of Enforcement Division, U.S.
EPA Region IX, at 75 Hawthorne Street, San Francisco, CA 94105.
a. The owner/operator shall notify EPA within two weeks after
completion of installation of combustion controls or Selective
Catalytic Reactors on any of the units subject to this section.
b. Within 30 days after the applicable compliance date(s) in
paragraph (e)(4) of this section and within 30 days of the end of each
calendar quarter thereafter, the owner/operator of each unit shall
submit a report that lists the daily 30-day rolling emission rates for
NOX and SO2 for each unit, calculated in
accordance with paragraph (e)(5) of this section. Included in this
report shall be the results of any relative accuracy test audit
performed during the calendar quarter.
(9) Enforcement. Notwithstanding any other provision in this
implementation plan, any credible evidence or information relevant as
to whether the unit would have been in compliance with applicable
requirements if the appropriate performance or compliance test had been
performed, can be used to establish whether or not the owner or
operator has violated or is in violation
[[Page 42871]]
of any standard or applicable emission limit in the plan.
(10) Equipment Operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
(11) Affirmative Defense for Malfunctions. The following
regulations are incorporated by reference and made part of this federal
implementation plan: Rules R18-2-310 and R18-2-310.01, approved into
the Arizona SIP at 40 CFR 52.120(c)(97)(i)(A).
[FR Doc. 2012-17659 Filed 7-19-12; 8:45 am]
BILLING CODE 6560-50-P