[Federal Register Volume 77, Number 58 (Monday, March 26, 2012)]
[Proposed Rules]
[Pages 18052-18098]
[FR Doc No: 2012-6908]

Vol. 77

Monday,

No. 58

March 26, 2012

Part IV

Environmental Protection Agency

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40 CFR Part 52

Approval and Promulgation of Implementation Plans; State of Colorado;
Regional Haze State Implementation Plan; Proposed Rule

Federal Register / Vol. 77 , No. 58 / Monday, March 26, 2012 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R08-OAR-2011-0770, FRL-9650-7]

Approval and Promulgation of Implementation Plans; State of
Colorado; Regional Haze State Implementation Plan

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to approve a State implementation plan (SIP)
revision submitted by the State of Colorado on May 25, 2011 that
addresses regional haze (RH). EPA is proposing to determine that the
plan submitted by Colorado satisfies the requirements of the Clean Air
Act (CAA or ``the Act'') and our rules that require states to prevent
any future and remedy any existing man-made impairment of visibility in
mandatory Class I areas caused by emissions of air pollutants from
numerous sources located over a wide geographic area (also referred to
as the ``regional haze program''). States are required to assure
reasonable progress toward the national goal of achieving natural
visibility conditions in Class I areas. EPA is taking this action
pursuant to section 110 of the CAA.

DATES: Written comments must be received at the address below on or
before May 25, 2012.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R08-
OAR-2011-0770, by one of the following methods:
     http://www.regulations.gov. Follow the on-line
instructions for submitting comments.
     Email<EMAIL_ADDRESS>     Fax:<PHONE_NUMBER> (please alert the individual listed in
the FOR FURTHER INFORMATION CONTACT if you are faxing comments).
     Mail: Carl Daly, Director, Air Program, Environmental
Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street,
Denver, Colorado 80202-1129.
     Hand Delivery: Carl Daly, Director, Air Program,
Environmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595
Wynkoop, Denver, Colorado 80202-1129. Such deliveries are only accepted
Monday through Friday, 8 a.m. to 4:30 p.m., excluding Federal holidays.
Special arrangements should be made for deliveries of boxed
information.
    Instructions: Direct your comments to Docket ID No. EPA-R08-OAR-
2011-0770. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or 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, your email address will be
automatically captured and included 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 avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses. For additional instructions on submitting
comments, go to Section I, ``General Information'' of the SUPPLEMENTARY
INFORMATION section of this document.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly-available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air Program,
Environmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595
Wynkoop, Denver, Colorado 80202-1129. EPA requests that if at all
possible, 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, 8 a.m. to 4
p.m., excluding Federal holidays.

FOR FURTHER INFORMATION CONTACT: Laurel Dygowski, Air Program, U.S.
Environmental Protection Agency, Region 8, Mailcode 8P-AR, 1595
Wynkoop, Denver, Colorado 80202-1129,<PHONE_NUMBER>,
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

I. General Information
II. What action is EPA proposing to take?
III. Background
    A. Regional Haze
    B. Requirements of the CAA and EPA's Regional Haze Rule (RHR)
    C. Roles of Agencies in Addressing Regional Haze
IV. Requirements for the RH SIPs
    A. The CAA and the Regional Haze Rule
    B. Determination of Baseline, Natural, and Current Visibility
Conditions
    C. Determination of Reasonable Progress Goals
    D. Best Available Retrofit Technology (BART)
    E. Long-Term Strategy (LTS)
    F. Coordinating Regional Haze and Reasonably Attributable
Visibility Impairment (RAVI)
    G. Monitoring Strategy and Other Implementation Plan
Requirements
    H. Consultation With States and Federal Land Managers (FLMs)
V. EPA's Evaluation of Colorado's Regional Haze SIP
    A. Affected Class I Areas
    B. Baseline Visibility, Natural Visibility, and Uniform Rate of
Progress
    C. BART Determinations
    1. BART Eligible Sources
    2. Sources Subject to BART
    a. Modeling Methodology
    b. Contribution Threshold
    c. Sources Identified by Colorado as BART- Eligible and Subject
to BART
    3. BART Determinations and Federally Enforceable Limits
    a. Visibility Improvement Modeling
    b. Summary of BART Determinations and Federally Enforceable
Limits
    i. Cemex Lyons Dryer and Kiln
    ii. CENC Boilers 4 and 5
    iii. PSCO Comanche Station Units 1 and 2
    iv. Tri-State Craig Units 1 and 2
    v. PSCO Hayden Station Units 1 and 2
    vi. CSU Martin Drake Units 5, 6, and 7
    vii. PSCO BART Alternative
    D. Reasonable Progress Requirements
    1. Visibility Impairing Pollutants and Sources
    a. Source Regions of Pollutants
    b. Source Categories
    c. Stationary Sources
    2. Four Factor Analyses
    a. Visibility Improvement Modeling
    b. Summary of RP Determinations and Limits
    i. Platte River Power Authority (PRPA)--Rawhide Unit 101
    ii. CENC Boiler 3
    iii. CSU Nixon Unit 1
    iv. Black Hills Energy Clark Power Plant, Units 1 and 2
    v. Holcim Florence Cement Plant

    vi. Tri-State Generation Nucla Facility
    vii. Tri-State Craig Unit 3
    viii. PSCO Cameo Station
    ix. Area Oil and Gas Sources
    x. Combustion Turbines
    3. Reasonable Progress Goals
    E. Long Term Strategy
    1. Emission Inventories
    2. Consultation and Emissions Reductions for Other States' Class
I Areas
    3. Mandatory Long-Term Strategy Requirements
    a. Reductions Due to Ongoing Air Pollution Programs
    b. Measures to Mitigate the Impacts of Construction Activities
    c. Smoke Management
    d. Emission Limitations and Schedules for Compliance
    e. Sources Retirement and Replacement Schedules
    f. Enforceability of Colorado's Measures
    g. Anticipated Net Effect on Visibility Due to Projected Changes
    F. Coordination of RAVI and RH Rule Requirements
    G. Monitoring Strategy and Other Implementation Plan
Requirements
    H. Consultation with FLMs
    I. Periodic SIP Revisions and 5-year Progress Reports
VI. EPA's Proposed Action
VII. Statutory and Executive Order Reviews

Definitions

    For the purpose of this document, we are giving meaning to
certain words or initials as follows:
    i. The words or initials Act or CAA mean or refer to the Clean
Air Act, unless the context indicates otherwise.
    ii. The initials BACT mean or refer to Best Available Control
Technology.
    iii. The initials BART mean or refer to Best Available Retrofit
Technology.
    iv. The initials CAMx mean or refer to Comprehensive Air Quality
Model.
    v. The initials CMAQ mean or refer to Community Multi-Scale Air
Quality modeling system.
    vi. The initials CEMS mean or refer to continuous emission
monitoring systems.
    vii. The words Colorado and State mean the State of Colorado.
    viii. The initials EC mean or refer to elemental carbon.
    ix. The initials EGUs mean or refer to Electric Generating
Units.
    x. The words EPA, we, us or our mean or refer to the United
States Environmental Protection Agency.
    xi. The initials FETS mean or refer to the Fire Emission
Tracking System.
    xii. The initials FGD mean or refer to flue gas desulfurization.
    xiii. The initials FGR mean or refer to external flue gas
recirculation.
    xiv. The initials FLMs mean or refer to Federal Land Managers.
    xv. The initials FS mean or refer to the U.S. Forest Service.
    xvi. The initials IMPROVE mean or refer to Interagency
Monitoring of Protected Visual Environments monitoring network.
    xvii. The initials IWAQM mean or refer to Interagency Workgroup
on Air Quality Modeling.
    xviii. The initials LB mean or refer to lean burn.
    xix. The initials LNB mean or refer to low NOX
burner.
    xx. The initials LTS mean or refer to Long-Term Strategy.
    xxi. The initials MACT mean or refer to Maximum Achievable
Control Technology.
    xxii. The initials NH3 mean or refer to ammonia.
    xxiii. The initials NOX mean or refer to nitrogen
oxides.
    xxiv. The initials NPS mean or refer to National Park Service.
    xxv. The initials OC mean or refer to organic carbon.
    xxvi. The initials OFA mean or refer to overfire air.
    xxvii. The initials PM2.5 mean or refer to
particulate matter with an aerodynamic diameter of less than 2.5
micrometers.
    xxviii. The initials PM10 mean or refer to
particulate matter with an aerodynamic diameter of less than 10
micrometers.
    xxix. The initials PSAT mean or refer to Particle Source
Apportionment Technology
    xxx. The initials PSD mean or refer to Prevention of
Signification Deterioration.
    xxxi. The initials RAVI mean or refer to Reasonably Attributable
Visibility Impairment.
    xxxii. The initials RB mean or refer to rich burn.
    xxxiii. The initials RH mean or refer to regional haze.
    xxxiv. The initials RH SIP mean or refer to Colorado's RH State
Implementation Plan.
    xxxv. The initials RHR mean or refer to the Regional Haze Rule.
    xxxvi. The initials RMC mean or refer to the Regional Modeling
Center at the University of California Riverside.
    xxxvii. The initials ROFA mean or refer to rotating overfire
air.
    xxxviii. The initials RP mean or refer to Reasonable Progress.
    xxxix. The initials RPGs mean or refer to Reasonable Progress
Goals.
    xl. The initials RPOs mean or refer to regional planning
organizations.
    xli. The initials RRI mean or refer to rich reagent injection.
    xlii. The initials SCR mean or refer to selective catalytic
reduction.
    xliii. The initials SIP mean or refer to State Implementation
Plan.
    xliv. The initials SNCR mean or refer to selective non-catalytic
reduction.
    xlv. The initials SO2 mean or refer to sulfur
dioxide.
    xlvi. The initials SOFA mean or refer to separated overfire air.
    xlvii. The initials TSD mean or refer to Technical Support
Document.
    xlviii. The initials URP mean or refer to Uniform Rate of
Progress.
    xlix. The initials VOC mean or refer to volatile organic
compounds.
    l. The initials WEP mean or refer to Weighted Emissions
Potential.
    li. The initials WRAP mean or refer to the Western Regional Air
Partnership.

I. General Information

A. What should I consider as I prepare my comments for EPA?

    1. Submitting CBI. 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 to be 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 then 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, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2.
    2. Tips for Preparing Your Comments. When submitting comments,
remember to:
    a. Identify the rulemaking by docket number and other identifying
information (subject heading, Federal Register date and page number).
    b. Follow directions--The agency may ask you to respond to specific
questions or organize comments by referencing a Code of Federal
Regulations (CFR) part or section number.
    c. Explain why you agree or disagree; suggest alternatives and
substitute language for your requested changes.
    d. Describe any assumptions and provide any technical information
and/or data that you used.
    e. If you estimate potential costs or burdens, explain how you
arrived at your estimate in sufficient detail to allow for it to be
reproduced.
    f. Provide specific examples to illustrate your concerns, and
suggest alternatives.
    g. Explain your views as clearly as possible, avoiding the use of
profanity or personal threats.
    h. Make sure to submit your comments by the comment period deadline
identified.

II. What action is EPA proposing to take?

    EPA is proposing to approve a SIP revision submitted by the State
of Colorado on May 25, 2011 that addresses RH. In so doing, EPA is
proposing to determine that the plan submitted by Colorado satisfies
the requirements of 40 CFR 51.308.

III. Background

A. Regional Haze

    RH is visibility impairment that is produced by a multitude of
sources and

activities which are located across a broad geographic area and emit
fine particles (PM2.5) (e.g., sulfates, nitrates, organic
carbon (OC), elemental carbon (EC), and soil dust), and their
precursors (e.g., sulfur dioxide (SO2), nitrogen oxides
(NOX), 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 park and
wilderness areas. The average visual range \1\ in many Class I areas
(i.e., national parks and memorial parks, wilderness areas, 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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    \1\ 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. Requirements of the CAA and EPA's Regional Haze Rule (RHR)

    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 \2\ which
impairment results from manmade air pollution.'' On December 2, 1980,
EPA promulgated regulations 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. These regulations represented the first
phase in addressing visibility impairment. EPA deferred action on RH
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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    \2\ 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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    Congress added section 169B to the CAA in 1990 to address RH
issues. EPA promulgated a rule to address RH on July 1, 1999. 64 FR
35714 (July 1, 1999), codified at 40 CFR part 51, subpart P. The RHR
revised the existing visibility regulations to integrate into the
regulation provisions addressing RH impairment and established a
comprehensive visibility protection program for Class I areas. The
requirements for RH, found at 40 CFR 51.308 and 51.309, are included in
EPA's visibility protection regulations at 40 CFR 51.300-309. Some of
the main elements of the RH requirements are summarized in section III
of this preamble. The requirement to submit a RH SIP applies to all 50
states, the District of Columbia and the Virgin Islands. 40 CFR
51.308(b) requires states to submit the first implementation plan
addressing RH visibility impairment no later than December 17, 2007.\3\
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    \3\ EPA's regional haze regulations require subsequent updates
to the regional haze SIPs. 40 CFR 51.308(g)-(i).
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    Few states submitted a RH SIP prior to the December 17, 2007
deadline, and on January 15, 2009, EPA found that 37 states (including
Colorado), the District of Columbia, and the Virgin Islands, had failed
to submit SIPs addressing the RH requirements. 74 FR 2392. Once EPA has
found that a state has failed to make a required submission, EPA is
required to promulgate a FIP within two years unless the state submits
a SIP and the Agency approves it within the two-year period. CAA Sec.
110(c)(1).

C. Roles of Agencies in Addressing Regional Haze

    Successful implementation of the RH 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 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 RH 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 RH 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 (PM) and other pollutants leading to RH.
    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 RH, visibility and other air quality issues in
the western United States. WRAP member State governments include:
Alaska, Arizona, California, Colorado, 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 SIPs

    The following is a summary of the requirements of the RHR. See 40
CFR 51.308 for further detail regarding the requirements of the rule.

A. The CAA and the Regional Haze Rule

    RH SIPs must assure reasonable progress (RP) towards the national
goal of achieving natural visibility conditions in Class I areas.
Section 169A of the CAA and EPA's implementing regulations require
states to establish long-term strategies for making RP toward meeting
this goal. Implementation plans must also give

specific attention to certain stationary sources that were in existence
on August 7, 1977, but were not in operation before August 7, 1962, and
require these sources, where appropriate, to install BART controls for
the purpose of eliminating or reducing visibility impairment. The
specific RH SIP requirements are discussed in further detail below.

B. Determination of Baseline, Natural, and Current Visibility
Conditions

    The RHR establishes the deciview (dv) as the principal metric or
unit for expressing visibility. See 70 FR 39104, 39118. This visibility
metric expresses uniform changes in the degree of haze in terms of
common increments across the entire range of visibility conditions,
from pristine to extremely hazy conditions. Visibility expressed in dvs
is determined by using air quality measurements to estimate light
extinction and then transforming the value of light extinction using a
logarithm function. The dv is a more useful measure for tracking
progress in improving visibility than light extinction itself because
each dv change is an equal incremental change in visibility perceived
by the human eye. Most people can detect a change in visibility at one
dv.\4\
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    \4\ The preamble to the RHR provides additional details about
the dv. 64 FR 35714, 35725 (July 1, 1999).
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    The dv is used in expressing Reasonable Progress Goals (RPGs)
(which are interim visibility goals towards meeting the national
visibility goal), defining baseline, current, and natural conditions,
and tracking changes in visibility. The RH SIPs must contain measures
that ensure ``reasonable progress'' toward the national goal of
preventing and remedying visibility impairment in Class I areas caused
by anthropogenic air pollution by reducing anthropogenic emissions that
cause RH. The national goal is a return to natural conditions, i.e.,
anthropogenic sources of air pollution would no longer impair
visibility in Class I areas.
    To track changes in visibility over time at each of the 156 Class I
areas covered by the visibility program (40 CFR 81.401-437), and as
part of the process for determining RP, states must calculate the
degree of existing visibility impairment at each Class I area at the
time of each RH SIP submittal and periodically review progress every
five years midway through each 10-year implementation period. To do
this, the RHR requires states to determine the degree of impairment (in
dvs) for the average of the 20 percent least impaired (``best'') and 20
percent most impaired (``worst'') visibility days over a specified time
period at each of their Class I areas. In addition, states must also
develop an estimate of natural visibility conditions for the purpose of
comparing progress toward the national goal. Natural visibility is
determined by estimating the natural concentrations of pollutants that
cause visibility impairment and then calculating total light extinction
based on those estimates. We have provided guidance to states regarding
how to calculate baseline, natural and current visibility
conditions.\5\
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    \5\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available
at http://www.epa.gov/ttncaaa1/t1/memoranda/Regional Haze _
envcurhr_gd.pdf, (hereinafter referred to as ``our 2003 Natural
Visibility Guidance''); and Guidance for Tracking Progress Under the
Regional Haze Rule, (September 2003, EPA-454/B-03-004, available at
http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf,
(hereinafter referred to as our ``2003 Tracking Progress
Guidance'').
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    For the first RH SIPs that were due by December 17, 2007,
``baseline visibility conditions'' were the starting points for
assessing ``current'' visibility impairment. Baseline visibility
conditions represent the degree of visibility impairment for the 20
percent least impaired days and 20 percent most impaired days for each
calendar year from 2000 to 2004. Using monitoring data for 2000 through
2004, states are required to calculate the average degree of visibility
impairment for each Class I area, based on the average of annual values
over the five-year period. The comparison of initial baseline
visibility conditions to natural visibility conditions indicates the
amount of improvement necessary to attain natural visibility, while the
future comparison of baseline conditions to the then current conditions
will indicate the amount of progress made. In general, the 2000-2004
baseline period is considered the time from which improvement in
visibility is measured.

C. Determination of Reasonable Progress Goals

    The vehicle for ensuring continuing progress towards achieving the
natural visibility goal is the submission of a series of RH SIPs from
the states that establish two RPGs (i.e., two distinct goals, one for
the ``best'' and one for the ``worst'' days) for every Class I area for
each (approximately) 10-year implementation period. See 40 CFR
51.308(d), (f). The RHR does not mandate specific milestones or rates
of progress, but instead calls for states to establish goals that
provide for ``reasonable progress'' toward achieving natural visibility
conditions. In setting RPGs, states must provide for an improvement in
visibility for the most impaired days over the (approximately) 10-year
period of the SIP, and ensure no degradation in visibility for the
least impaired days over the same period. Id.
    In establishing RPGs, states are required to consider the following
factors established in section 169A of the CAA and in our RHR at 40 CFR
51.308(d)(1)(i)(A): (1) The costs of compliance; (2) the time necessary
for compliance; (3) the energy and non-air quality environmental
impacts of compliance; and (4) the remaining useful life of any
potentially affected sources. States must demonstrate in their SIPs how
these factors are considered when selecting the RPGs for the best and
worst days for each applicable Class I area. In setting the RPGs,
states must also consider the rate of progress needed to reach natural
visibility conditions by 2064 (referred to as the ``uniform rate of
progress'' (URP) or the ``glidepath'') and the emission reduction
measures needed to achieve that rate of progress over the 10-year
period of the SIP. Uniform progress towards achievement of natural
conditions by the year 2064 represents a rate of progress, which states
are to use for analytical comparison to the amount of progress they
expect to achieve. In setting RPGs, each state with one or more Class I
areas (``Class I state'') must also consult with potentially
``contributing states,'' i.e., other nearby states with emission
sources that may be affecting visibility impairment at the state's
Class I areas. 40 CFR 51.308(d)(1)(iv). In determining whether a
state's goals for visibility improvement provide for RP toward natural
visibility conditions, EPA is required to evaluate the demonstrations
developed by the state pursuant to paragraphs 40 CFR 51.308(d)(1)(i)
and (d)(1)(ii). 40 CFR 51.308(d)(1)(iii).

D. Best Available Retrofit Technology (BART)

    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 RP towards the natural visibility goal, including a requirement
that certain categories of existing major stationary

sources \6\ 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 RP towards
improving visibility than BART.
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    \6\ The set of ``major stationary sources'' potentially subject
to BART is listed in CAA section 169A(g)(7).
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    On July 6, 2005, 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'') to assist
states in determining which of their sources should be subject to the
BART requirements and in determining appropriate emission limits for
each applicable source. 70 FR 39104. In making a BART determination for
a fossil fuel-fired electric generating plant with a total generating
capacity in excess of 750 megawatts (MW), a state must use the approach
set forth in the BART Guidelines. A state is encouraged, but not
required, to follow the BART Guidelines in making BART determinations
for other types of sources. Regardless of source size or type, a state
must meet the requirements of the CAA and our regulations for selection
of BART, and the state's BART analysis and determination must be
reasonable in light of the overarching purpose of the RH program.
    The process of establishing BART emission limitations can be
logically broken down into three steps: first, states identify those
sources which meet the definition of ``BART-eligible source'' set forth
in 40 CFR 51.301; \7\ second, states determine which of such sources
``emits any air pollutant which may reasonably be anticipated to cause
or contribute to any impairment of visibility in any such area'' (a
source which fits this description is ``subject to BART''); and third,
for each source subject to BART, states then identify the best
available type and level of control for reducing emissions.
---------------------------------------------------------------------------

    \7\ BART-eligible sources are those sources that have the
potential to emit 250 tons or more of a visibility-impairing air
pollutant, were not in operation prior to August 7, 1962, but were
in existence on August 7, 1977, and whose operations fall within one
or more of 26 specifically listed source categories. 40 CFR 51.301.
---------------------------------------------------------------------------

    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 stated 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. States should
consider the number of emission sources affecting the Class I areas at
issue and the magnitude of the individual sources' impacts. Any
exemption threshold set by the state should not be higher than 0.5 dv.
40 CFR part 51, appendix Y, section III.A.1.
    In their SIPs, states must identify the sources that are subject to
BART and document their BART control determination analyses for such
sources. In making their BART determinations, section 169A(g)(2) of the
CAA requires that states consider the following factors when evaluating
potential control technologies: (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.
    A RH SIP must include source-specific BART emission limits and
compliance schedules for each source subject to BART. 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 of EPA approval of the RH SIP. CAA section 169(g)(4) and
40 CFR 51.308(e)(1)(iv). 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 controls on the source. See CAA section 110(a).
As noted above, the RHR allows states to implement an alternative
program in lieu of BART so long as the alternative program can be
demonstrated to achieve greater RP toward the national visibility goal
than would BART.

E. Long-Term Strategy (LTS)

    Consistent with the requirement in section 169A(b) of the CAA that
states include in their RH SIP a 10 to 15 year strategy for making RP,
section 51.308(d)(3) of the RHR requires that states include a LTS in
their RH SIPs. The LTS is the compilation of all control measures a
state will use during the implementation period of the specific SIP
submittal to meet applicable RPGs. The LTS must include ``enforceable
emissions limitations, compliance schedules, and other measures as
necessary to achieve the reasonable progress goals'' for all Class I
areas within, or affected by emissions from, the state. 40 CFR
51.308(d)(3).
    When a state's emissions are reasonably anticipated to cause or
contribute to visibility impairment in a Class I area located in
another state, the RHR requires the impacted state to coordinate with
the contributing states in order to develop coordinated emissions
management strategies. 40 CFR 51.308(d)(3)(i). In such cases, the
contributing state must demonstrate that it has included, in its SIP,
all measures necessary to obtain its share of the emission reductions
needed to meet the RPGs for the Class I area. Id. at (d)(3)(ii). The
RPOs have provided forums for significant interstate consultation, but
additional consultations between states may be required to sufficiently
address interstate visibility issues. This is especially true where two
states belong to different RPOs.
    States should consider all types of anthropogenic sources of
visibility impairment in developing their LTS, including stationary,
minor, mobile, and area sources. At a minimum, states must describe how
each of the following seven factors listed below are taken into account
in developing their LTS: (1) Emission reductions due to ongoing air
pollution control programs, including measures to address RAVI; (2)
measures to mitigate the impacts of construction activities; (3)
emissions limitations and schedules for compliance to achieve the RPG;
(4) source retirement and replacement schedules; (5) smoke management
techniques for agricultural and forestry management purposes including
plans as currently exist within the state for these purposes; (6)
enforceability of emissions limitations and control measures; and (7)
the anticipated net effect on visibility due to projected changes in
point, area, and mobile source emissions over the period

addressed by the LTS. 40 CFR 51.308(d)(3)(v).

F. Coordinating Regional Haze and Reasonably Attributable Visibility
Impairment (RAVI)

    As part of the RHR, EPA revised 40 CFR 51.306(c) regarding the LTS
for RAVI to require that the RAVI plan must provide for a periodic
review and SIP revision not less frequently than every three years
until the date of submission of the state's first plan addressing RH
visibility impairment, which was due December 17, 2007, in accordance
with 40 CFR 51.308(b) and (c). On or before this date, the state must
revise its plan to provide for review and revision of a coordinated LTS
for addressing RAVI and RH, and the state must submit the first such
coordinated LTS with its first RH SIP. Future coordinated LTS's, and
periodic progress reports evaluating progress towards RPGs, must be
submitted consistent with the schedule for SIP submission and periodic
progress reports set forth in 40 CFR 51.308(f) and 51.308(g),
respectively. The periodic review of a state's LTS must report on both
RH and RAVI impairment and must be submitted to EPA as a SIP revision.

G. Monitoring Strategy and Other Implementation Plan Requirements

    Section 51.308(d)(4) of the RHR includes the requirement for a
monitoring strategy for measuring, characterizing, and reporting of RH
visibility impairment that is representative of all mandatory Class I
Federal areas within the state. The strategy must be coordinated with
the monitoring strategy required in section 51.305 for RAVI. Compliance
with this requirement may be met through ``participation'' in the
IMPROVE network, i.e., review and use of monitoring data from the
network. The monitoring strategy is due with the first RH SIP, and it
must be reviewed every five years. The monitoring strategy must also
provide for additional monitoring sites if the IMPROVE network is not
sufficient to determine whether RPGs will be met.
    The SIP must also provide for the following:
     Procedures for using monitoring data and other information
in a state with mandatory Class I areas to determine the contribution
of emissions from within the state to RH visibility impairment at Class
I areas both within and outside the state;
     Procedures for using monitoring data and other information
in a state with no mandatory Class I areas to determine the
contribution of emissions from within the state to RH visibility
impairment at Class I areas in other states;
     Reporting of all visibility monitoring data to the
Administrator at least annually for each Class I area in the state, and
where possible, in electronic format;
     Developing a statewide inventory of emissions of
pollutants that are reasonably anticipated to cause or contribute to
visibility impairment in any Class I area. The inventory must include
emissions for a baseline year, emissions for the most recent year for
which data are available, and estimates of future projected emissions.
A state must also make a commitment to update the inventory
periodically; and
     Other elements, including reporting, recordkeeping, and
other measures necessary to assess and report on visibility.
    The RHR requires control strategies to cover an initial
implementation period extending to the year 2018, with a comprehensive
reassessment and revision of those strategies, as appropriate, every 10
years thereafter. Periodic SIP revisions must meet the core
requirements of section 51.308(d) with the exception of BART. The
requirement to evaluate sources for BART applies only to the first RH
SIP. Facilities subject to BART must continue to comply with the BART
provisions of section 51.308(e), as noted above. Periodic SIP revisions
will assure that the statutory requirement of RP will continue to be
met.

H. Consultation With States and Federal Land Managers (FLMs)

    The RHR requires that states consult with FLMs before adopting and
submitting their SIPs. 40 CFR 51.308(i). States must provide FLMs an
opportunity for consultation, in person and at least 60 days prior to
holding any public hearing on the SIP. This consultation must include
the opportunity for the FLMs to discuss their assessment of impairment
of visibility in any Class I area and to offer recommendations on the
development of the RPGs and on the development and implementation of
strategies to address visibility impairment. Further, a state must
include in its SIP a description of how it addressed any comments
provided by the FLMs. Finally, a SIP must provide procedures for
continuing consultation between the state and FLMs regarding the
state's visibility protection program, including development and review
of SIP revisions, five-year progress reports, and the implementation of
other programs having the potential to contribute to impairment of
visibility in Class I areas.

V. EPA's Evaluation of Colorado's Regional Haze SIP

    The State of Colorado submitted a revision to its SIP to address
the requirements for RH on May 25, 2011. The following is a discussion
of our evaluation of the revision.

A. Affected Class I Areas

    Pursuant to 40 CFR 51.308(d), the State identified 12 mandatory
Class I areas in Colorado: Black Canyon of the Gunnison National Park,
Eagles Nest Wilderness Area, Flat Tops Wilderness Area, Great Sand
Dunes National Park, La Garita Wilderness Area, Maroon Bells-Snowmass
Wilderness Area, Mesa Verde National Park, Mount Zirkel Wilderness
Area, Rawah Wilderness Area, Rocky Mountain National Park, Weminuche
Wilderness Area, and West Elk Wilderness Area. The State developed and
submitted as part of its RH SIP technical support documents (TSDs) for
each of the Class I areas. The Class I area TSDs include a detailed
description of each area, along with photographs, summaries of
monitoring data, an overview of current visibility conditions, and
sources of pollution.
    The State also identified in the TSD areas outside of the State
that modeling shows may be impacted from emissions from Colorado.\8\
These areas include: Upper Buffalo Wilderness in Arkansas; Petrified
Forest National Park, Grand Canyon National Park, and Sycamore Canyon
Wilderness in Arizona; Hercules-Glade Wilderness in Missouri; San Pedro
Parks Wilderness, Bandelier National Monument, and Wheeler Peak in New
Mexico; Wichita Mountains National Wildlife Refuge in Oklahoma; Wind
Cave National Park and Badlands National Park in South Dakota;
Canyonlands National Park and Capitol Reef National Park in Utah; and
Bridger Wilderness in Wyoming.
---------------------------------------------------------------------------

    \8\ See Colorado TSD document titled Colorado Visibility Impacts
on nearby Class I Areas.
---------------------------------------------------------------------------

B. Baseline Visibility, Natural Visibility, and Uniform Rate of
Progress

    As required by 40 CFR 51.308(d)(2), Colorado determined baseline
visibility, natural visibility, and the URP for each Class I area in
the State. Natural background visibility, as defined in our 2003
Natural Visibility Guidance, is estimated by calculating the expected
light extinction using default estimates of natural concentrations of
fine particle components adjusted by site-specific estimates of
humidity. This calculation uses the IMPROVE equation, which is a

formula for estimating light extinction from the estimated natural
concentrations of fine particle components (or from components measured
by the IMPROVE monitors). As documented in our 2003 Natural Visibility
Guidance, EPA allows states to use ``refined'' or alternative
approaches to this guidance to estimate the values that characterize
the natural visibility conditions of Class I areas.
    One alternative approach is to develop and justify the use of
alternative estimates of natural concentrations of fine particle
components. Another alternative is to use the ``new IMPROVE equation''
that was adopted for use by the IMPROVE Steering Committee in December
2005.\9\ The purpose of this refinement to the ``old IMPROVE equation''
is to provide more accurate estimates of the various factors that
affect the calculation of light extinction.
---------------------------------------------------------------------------

    \9\ The IMPROVE program is a cooperative measurement effort
governed by a steering committee composed of representatives from
Federal agencies (including representatives from EPA and the FLMs)
and regional planning organizations. The IMPROVE monitoring program
was established in 1985 to aid the creation of Federal and State
implementation plans for the protection of visibility in Class I
areas. One of the objectives of IMPROVE is to identify chemical
species and emission sources responsible for existing anthropogenic
visibility impairment. The IMPROVE program has also been a key
participant in visibility-related research, including the
advancement of monitoring instrumentation, analysis techniques,
visibility modeling, policy formulation and source attribution field
studies.
---------------------------------------------------------------------------

    Colorado used the new IMPROVE equation to calculate natural
conditions and baseline visibility. The natural condition for each
Class I area represents the visibility goal expressed in dvs for the
20% worst days and the 20% best days that would exist if there were
only naturally occurring visibility impairment. In accordance with 40
CFR 51.308(d)(2)(iii), the State calculated natural visibility
conditions based on available monitoring information and appropriate
data analysis techniques and in accordance with our 2003 Natural
Visibility Guidance. The State also calculated the number of dvs by
which baseline conditions exceed natural conditions at each of its
Class I areas to meet the requirements of 40 CFR 51.308(d)(2)(iv)(A).
    Colorado has established baseline visibility for the best and worst
visibility days for each Class I area based on data from the IMPROVE
monitoring sites. Each IMPROVE monitor collects particulate
concentration data which are converted into reconstructed light
extinction through a complex calculation using the IMPROVE equation
(see Class I area TSDs for more information on reconstructed light
extinction and the IMPROVE equation). Per 40 CFR 51.308(d)(2)(i), the
State calculated baseline visibility using a five-year average (2000 to
2004) of IMROVE data for both the 20% best and 20% worst days. The
State's baseline calculations were made in accordance with our 2003
Tracking Progress Guidance.
    Pursuant to 40 CFR 51.308(d)(1)(i)(B), the State calculated the URP
for each of its Class I areas. For the 20% worst days, the URP is the
calculation of the dv reduction needed to achieve natural conditions by
2064. For the 20% worst days, the State calculated the URP in dvs per
year using the following formula: URP = [Baseline Condition - Natural
Condition]/60 years. In order to determine the uniform progress needed
by 2018 to be on the path to achieving natural visibility conditions by
2064, the State multiplied the URP by the 14 years in the first
planning period (2004-2018).
    Table 1 shows the baseline visibility, natural conditions, and URP
for each of the Class I areas.

                        Table 1--Baseline Visibility, Natural Conditions, and Uniform Rate of Progress for Colorado Class I Areas
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                20% Worst Days                            20% Best
                                                                            ----------------------------------------------------------------     days
                                                                                Reduction                     Delta     ------------
                     Colorado class I areas                        Monitor    2000-2004     2018    needed to       2064     Baseline--2064
                                                                     name      Baseline     URP     reach 2018    Natural        Natural      2000-2004
                                                                                (dv)       (dv)   URP  (delta   conditions    Conditions      Baseline
                                                                                dv)          (dv)          (dv)           (dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Great Sand Dunes National Park and Preserve.....................      GRSA1        12.78    11.35         1.43         6.66           6.12          4.50
Mesa Verde National Park........................................      MEVE1        13.03    11.58         1.45         6.81           6.22          4.32
Mount Zirkel and Rawah Wilderness Area..........................      MOZI1        10.52     9.48         1.04         6.08           4.44          1.61
Rocky Mountain National Park....................................      RMHQ1        13.83    12.27         1.56         7.15           6.68          2.29
Weminuche Wilderness, Black Canyon of Gunnison, and La Garita         WEMI1        10.33     9.37         0.96         6.21           4.12          3.11
 Wilderness.....................................................
Eagles Nest Wilderness, Flat Tops Wilderness, Maroon Bells-           WHRI1         9.61     8.78         0.83         6.06           3.55          0.70
 Snowmass Wilderness, and West Elk Wilderness...................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We have reviewed Colorado's calculations of baseline visibility,
natural conditions, and URP. We find they have been calculated
correctly and are proposing to approve them.

C. BART Determinations

    BART is an element of Colorado's LTS for the first implementation
period. As discussed in more detail in section IV.D of this notice, the
BART evaluation process consists of three components: (1) An
identification of all the BART-eligible sources; (2) an assessment of
whether those BART-eligible sources are in fact subject to BART; and
(3) a determination of any BART controls. Colorado addressed these
steps as follows:
1. BART Eligible Sources
    The first step of a BART evaluation is to identify all the BART-
eligible sources within the State's boundaries. Colorado identified the
BART-eligible sources in Colorado by utilizing the approach set out in
the BART Guidelines (70 FR 39158). This approach provides three
criteria for identifying BART-eligible sources: (1) One or more
emission units at the facility fit within one of the 26 categories
listed in the BART Guidelines; (2) the emission unit or units began
operation on or after August 6, 1962, and were in existence on August
6, 1977; and (3) combined potential emissions of any visibility-
impairing pollutant from the units that meet the criteria in (1) and
(2) are 250

tons or more per year. Colorado reviewed source permits and emission
data from 2001-2003 to identify facilities in the BART source
categories with potential emissions of 250 tons per year or more for
any visibility-impairing pollutant from any unit or units that were in
existence on August 7, 1977 and began operation on or after August 7,
1962. The BART Guidelines direct States to address SO2,
NOX, and direct PM (including both coarse particulate matter
(PM10) and fine particulate matter (PM2.5))
emissions as visibility-impairing pollutants and to exercise their
``best judgment to determine whether VOC or NH3 emissions
from a source are likely to have an impact on visibility in an area.''
(70 FR 39162).
    The State analyzed the emissions from VOC and NH3 from
sources in the State. VOC is a precursor to OC. The State eliminated
VOC from further consideration in the RH SIP as it determined statewide
point source emissions of VOC constitute a negligible portion of the
emission inventory for OC (3 tons per year (tpy)). Colorado also
determined that statewide point sources of NH3 emissions are
small. The State's emission inventory for 2001-2003 shows that point
sources emitted 453 tpy of NH3, while total State
NH3 emissions are 67,686 tpy. Thus, the State has eliminated
NH3 from further consideration.\10\ We have reviewed this
information and propose to accept this determination.
---------------------------------------------------------------------------

    \10\ More details on the State's emission inventory can be found
in Colorado Emission Inventories Plan 2002d and PRP 2018b in the
Supporting and Related Materials section of the docket.
---------------------------------------------------------------------------

    Table 2 lists the 12 sources that Colorado determined were BART-
eligible.
2. Sources Subject to BART
    The second step of the BART evaluation is to identify those BART-
eligible sources that may reasonably be anticipated to cause or
contribute to any visibility impairment at any Class I area, i.e.,
those sources that are subject to BART. The BART Guidelines allow
states to consider exempting some BART-eligible sources from further
BART review because they may not reasonably be anticipated to cause or
contribute to any visibility impairment in a Class I area. Consistent
with the BART Guidelines, Colorado performed dispersion modeling on the
BART-eligible sources to assess the extent of their contribution to
visibility impairment at surrounding Class I areas.
a. Modeling Methodology
    The BART Guidelines provide that states may use the CALPUFF \11\
modeling system or another appropriate model to predict the visibility
impacts from a single source on a Class I area and to, therefore,
determine whether an individual source is anticipated to cause or
contribute to impairment of visibility in Class I areas, i.e., ``is
subject to BART.'' The Guidelines state that CALPUFF is the best
regulatory modeling application currently available for predicting a
single source's contribution to visibility impairment (70 FR 39162).
---------------------------------------------------------------------------

    \11\ Note that our reference to CALPUFF encompasses the entire
CALPUFF modeling system, which includes the CALMET, CALPUFF, and
CALPOST models and other pre and post processors. The different
versions of CALPUFF have corresponding versions of CALMET, CALPOST,
etc. which may not be compatible with previous versions (e.g., the
output from a newer version of CALMET may not be compatible with an
older version of CALPUFF). The different versions of the CALPUFF
modeling system are available from the model developer at http://www.src.com/verio/download/download.htm.
---------------------------------------------------------------------------

    The BART Guidelines also recommend that states develop a modeling
protocol for making individual source attributions, and suggest that
states may want to consult with EPA and their RPO to address any issues
prior to modeling. Colorado used the CALPUFF model for Colorado BART
sources in accordance with a protocol it developed titled CALMET/
CALPUFF BART Protocol for Class I Federal Area Individual Source
Attribution Visibility Impairment Modeling Analysis, October 24, 2005,
which was approved by EPA and is included in the Supporting and Related
Materials section of the docket. The Colorado protocol follows
recommendations for long-range transport described in appendix W to 40
CFR part 51, Guideline on Air Quality Models, and in EPA's Interagency
Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and
Recommendations for Modeling Long Range Transport Impacts as
recommended by the BART Guidelines. (40 CFR part 51, appendix Y,
section III.A.3).
    To determine if each BART-eligible source has a significant impact
on visibility, Colorado used the CALPUFF model to estimate daily
visibility impacts above estimated natural conditions at each Class I
area within 300 km of any BART-eligible facility, based on maximum
actual 24-hour emissions over a three year period (2000-2002).
b. Contribution Threshold
    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. 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.'' (70 FR 39104, 39161).
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.'' Id.
Further, in setting a contribution threshold, states should ``consider
the number of emissions sources affecting the Class I areas at issue
and the magnitude of the individual sources' impacts.'' The Guidelines
affirm that states are free to use a lower threshold if they conclude
that the location of a large number of BART-eligible sources in
proximity to a Class I area justifies this approach.
    Colorado used a contribution threshold of 0.5 dvs for determining
which sources are subject to BART. The State's decision was based on
the following factors: 0.5 dvs equates to the 5% extinction threshold
for new sources under the Prevention of Significant Deterioration (PSD)
New Source Review rules, and 0.5 dvs represents the limit of
perceptible change. Although we do not agree with Colorado that these
factors are always the appropriate ones to consider in determining
which BART-eligible sources should be subject to BART in Colorado, we
propose to approve the State's threshold of 0.5 dvs based on our own
evaluation, discussed below. As shown in Table 2 below, Colorado
exempted three of the 12 BART-eligible sources in the State from
further review under the BART requirements. These three sources are
Lamar Light and Power, Suncor Denver Refinery, and Ray D. Nixon Unit 1.
According to Colorado's modeling, each of these sources had a
visibility impact less than 0.5 dvs. As shown in Table 2, the
visibility impact attributable to each of these sources is 0.06, 0.48,
and 0.24 dvs, respectively. Given the relatively limited combined
impact on visibility from these three sources, we propose to agree with
Colorado that 0.5 dvs is a reasonable threshold for determining

whether its BART-eligible sources are subject to BART.
    Because our recommended modeling approach already incorporates
choices that tend to lower peak daily visibility impact values,\12\ our
BART Guidelines state that a state should compare the 98th percentile
(as opposed to the 90th or lower percentile) of CALPUFF modeling
results against the ``contribution'' threshold established by the state
for purposes of determining BART applicability. Colorado used a 98th
percentile comparison that we find appropriate. Further explanation on
use of the 98th versus 90th percentile value is provided at 70 FR
39121.
---------------------------------------------------------------------------

    \12\ See our BART Guidelines, Section III.A.3.
---------------------------------------------------------------------------

c. Sources Identified by Colorado as BART-Eligible and Subject to BART
    Table 2 shows the sources that the State identified as BART-
eligible and the results of the State's CALPUFF modeling. Colorado
determined that the BART-eligible facilities with modeled impacts at
all Class I areas less than 0.5 dvs were not subject to BART and those
with impacts greater than 0.5 dvs were subject to BART (see Chapter 6.3
of the SIP).

                  Table 2--Colorado BART-Eligible Sources and Subject-to-BART Modeling Results
----------------------------------------------------------------------------------------------------------------
                                                                               State modeling
                                                                                results--98th
            Unit name                      Owner              Source type        percentile     Subject to BART?
                                                                                delta-Dv
----------------------------------------------------------------------------------------------------------------
Cemex--Lyons Cement Kiln and       Cemex...............  Portland Cement.....            1.53  Yes.
 Dryer.
CENC (Trigen-Colorado) Units 4 &   Colorado Energy       EGU.................            1.26  Yes.
 5.                                 Nations Company
                                    (CENC).
Cherokee Station--Unit 4.........  Public Service        EGU.................            1.46  Yes.
                                    Company of Colorado
                                    (PSCO).
Comanche Station--Units 1 & 2....  PSCO................  EGU.................            0.7   Yes.
Craig Station--Units 1 & 2.......  Tri-State Generation  EGU.................            2.69  Yes.
                                    and Transmission,
                                    Inc. (Tri-State).
Hayden Station--Units 1 & 2......  PSCO................  EGU.................            2.54  Yes.
Lamar Light and Power--Unit 6....  City of Lamar.......  EGU.................            0.06  No.
Martin Drake Power Plant--Units    Colorado Springs      EGU.................            1.04  Yes.
 5, 6, & 7.                         Utilities (CSU).
Pawnee Station--Unit 1...........  PSCO................  EGU.................            1.19  Yes.
Ray D. Nixon Power Plant--Unit 1.  CSU.................  EGU.................       \13\ 0.48  No.
Suncor Denver Refinery...........  Suncor..............  Refinery............            0.24  No.
Valmont Station--Unit 5..........  PSCO................  EGU.................            1.59  Yes.
----------------------------------------------------------------------------------------------------------------
\13\ The State of Colorado originally modeled an impact of 0.57 dvs for Ray D. Nixon Power Plant. The source
  submitted refined modeling that showed an impact of 0.48 dvs. Both the State and EPA agree with the refined
  modeling submitted by the source.

3. BART Determinations and Federally Enforceable Limits
    The third step of a BART evaluation is to perform the BART
analysis. The BART Guidelines (70 FR 39164) describe the BART analysis
as consisting of the following five steps:
     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; and
     Step 5: Evaluate Visibility Impacts.
    In determining BART, the State must consider the five statutory
factors in section 169A of the CAA: (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. See also 40 CFR 51.308(e)(1)(ii)(A). The five-
factor analysis occurs during steps 4 and 5 of the BART analysis.
    Colorado performed BART determinations for all of the sources
subject to BART for NOX, SO2, and PM. We find
that Colorado adequately considered all five steps above in its BART
determinations.

State NOX Control Criteria

    For NOX, the State developed criteria to assist in the
selection of post-combustion controls for BART. For the highest-
performing NOX post-combustion control options (i.e.,
selective catalytic reduction (SCR) systems for electric generating
units) that do not exceed a cost of $5,000 per ton and which provide a
modeled visibility benefit of 0.50 dv or greater at the primary Class I
Area affected, the State views that level of control as generally
reasonable for BART. For lesser-performing NOX post-
combustion control options (e.g., selective non-catalytic reduction
(SNCR) technologies for electric generating units) that do not exceed a
cost of $5,000 per ton which provide a modeled visibility benefit of
0.20 dv or greater at the primary Class I Area affected, the State
views that level of control as generally reasonable for BART.
    EPA does not necessarily agree that the State's criteria for
selecting NOX controls would always be appropriate. First,
the criteria appear to discriminate against SCR as a potential control
option. Under the criteria, if the cost of SCR is under $5,000/ton and
the modeled visibility benefit is 0.20 delta-dv or greater but less
than 0.50 delta-dv, the State would reject SCR. Using the State's
criteria, the State would find SNCR reasonable with the same $/ton and
delta-dv values. We are not aware of a valid basis for applying
different criteria to the two control options. In addition, we are
aware of no basis for establishing benchmarks for post-combustion
controls but not for other types of NOX controls. The
criteria may also preclude a reasonable weighing of the five factors
where the delta dv benefit is over 0.5 but the cost is higher than
$5,000/ton.
    While we do not necessarily agree that the criteria used by the
State would always be appropriate to select NOX controls, we
agree with the State's determinations for NOX BART controls
on the BART sources as discussed below.

SO2 Controls--Wet and Dry Scrubbing

    Scrubbing is one of the most common ways to control emissions of
SO2 from stationary sources. Scrubbing can consist of either
wet flue gas desulfurization (FGD) or dry FGD. The State eliminated wet
FGD from consideration as a BART control because of negative non-air
quality environmental impacts. The main non-air quality environmental
impact that the State identified for wet FGDs is very heavy water
usage. Wet FGDs consume approximately 23% more water than dry FGDs
depending on boiler size.\14\ In Colorado, water law is based upon the
doctrine of prior appropriation or ``first in time-first in right,''
and the priority date is established by the date the water was first
put to a beneficial use. The State reasoned that, depending upon
whether and when a power plant first secured a water appropriation and
whether such appropriation is adequate to supply the demand, there may
be insufficient water appropriations available in some areas of the
State, particularly in the Front Range area, to accommodate the added
demands of wet FGD controls. The State also found that the water
demands of wet FGDs would compete for what is already a scarce resource
needed for Colorado's domestic, agricultural, and industrial demands.
---------------------------------------------------------------------------

    \14\ ``Revised BART Analysis for Unit 1 & 2 Gerald Gentleman
Station Sutherland, Nebraska: Nebraska Public Power District.''
Prepared by: HDF 701 Xenia Avenue South, Suite 600 Minneapolis, MN
55416 With control technology costs provided by: Sargent & Lundy.
---------------------------------------------------------------------------

    Generally, wet FGD controls can achieve a slightly higher level of
SO2 control than dry FGDs on a percent capture basis.
Considering this, the State determined that the non-air quality
environmental impacts outweigh any incremental improvement in
SO2 emission reductions that would result from the use of
wet FGDs rather than dry FGDs (see Chapter <IP_ADDRESS> of the SIP). EPA is
proposing that the State provided adequate justification to eliminate
the consideration of wet FGDs as SO2 BART controls.
a. Visibility Improvement Modeling
    The BART Guidelines provide that states may use the CALPUFF
modeling system or another appropriate model to determine the
visibility improvement expected at a Class I area from potential BART
control technologies applied to the source. Colorado performed CALPUFF
modeling to determine the degree of visibility improvement expected at
a Class I area based on the controls evaluated for BART for the
subject-to-BART sources, with the exception of Cemex. For Cemex, the
State relied on modeling submitted by the source based on a modeling
protocol approved by the State.
    The BART Guidelines also recommend that states develop a modeling
protocol for modeling visibility improvement, and suggest that states
may want to consult with EPA and their RPO to address any issues prior
to modeling. Colorado used the CALPUFF model for Colorado BART sources
in accordance with a protocol it developed titled Supplemental BART
Analysis CALPUFF Protocol for Class I Federal Area Visibility
Improvement Modeling Analysis, revised August 19, 2010, which was
approved by EPA and is included in the Supporting and Related Materials
section of the docket. The Colorado protocol follows recommendations
for long-range transport described in appendix W to 40 CFR part 51,
Guideline on Air Quality Models, and in EPA's Interagency Workgroup on
Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations
for Modeling Long Range Transport Impacts, as recommended by the BART
Guidelines. (40 CFR part 51, appendix Y, section III.D.5).
b. Summary of BART Determinations and Federally Enforceable Limits
    In lieu of individual BART determinations, the State submitted a
BART alternative as allowed for by 40 CFR 51.308(e)(2) for three of the
subject-to-BART sources: Cherokee Station Unit 4, Pawnee Station Unit
1, and Valmont Station Unit 5. We provide a summary of the BART
alternative in section IV.C.3.b.vii of this notice. We are proposing to
approve the BART alternative. For the rest of the subject-to-BART
sources, the State provided analyses that took into consideration the
five factors as required by section 169A(g)(2) of the CAA. The State's
five factor analyses, as well as additional technical information and
materials, are included in Appendix C of the SIP. Chapter 6 of the SIP
provides a summary of the five factor analyses. EPA is proposing to
approve the BART determinations submitted by the State for Cemex Lyons
Kiln and Dryer, CENC Unit 4 and Unit 5, Comanche Unit 1 and Unit 2,
Craig Unit 2, Hayden Unit 1 and Unit 2, and Martin Drake Unit 5, Unit
6, and Unit 7. A summary of the BART determination for each source is
provided below.
i. Cemex Lyons Dryer and Kiln

Background

    The Cemex facility manufactures Portland cement and is located in
Lyons, Colorado, approximately 20 miles from Rocky Mountain National
Park. There are two BART-eligible units at the facility: The dryer and
the kiln. The Lyons plant was originally constructed with a long dry
kiln. In 1980, the kiln was cut to one-half its original length, and a
flash vessel was added with a single-stage preheater. The permitted
kiln feed rate is 120 tons per hour of raw material (kiln feed), and on
average yields approximately 62 tons of clinker per hour. The kiln is
the main source of SO2 and NOX emissions. The raw
material dryer emits minor amounts of SO2 and
NOX. The State's BART determination can be found in Chapter
<IP_ADDRESS> and Appendix C of the SIP.

Baseline Emissions

    The State has emissions data for the dryer from 1999, 2003, 2008,
and 2009. The 1999 emissions are based on emission factors, whereas the
2003, 2008 and 2009 emissions are based on a stack test. The State has
determined that the 2008 emissions best represent baseline emissions
for the dryer since the State considers stack test data more reliable
than emission factors. Furthermore, the 2008 clinker production is
representative of typical operations because it falls within the normal
range of the historical average. The 2008 baseline emissions for the
dryer are: 10.41 tpy for NOX; 0.89 tpy for SO2;
and 5.12 tpy for PM.
    The State has determined that the 2002 emissions best represent
baseline emissions for the kiln because they correspond to the high
range for SO2 emissions (which can vary significantly due to
pyrites in the limestone) and the normal historical range for
NOX emissions and clinker production. The 2002 baseline
emissions for the kiln are: 1,747 tpy for NOX; 95 tpy for
SO2; and 8.5 tpy for PM.

SO2 and NOX BART Determination for the Dryer

    CALPUFF modeling provided by the source, using a maximum
SO2 emission rate of 123.4 lbs/hour for both the dryer and
kiln combined, shows a 98th percentile visibility impact of 0.78 delta
dv at the most impacted Class I area, Rocky Mountain National Park. The
State determined the modeling was performed correctly and EPA agrees
with the State's assessment. The modeled 98th percentile visibility
impact from the kiln is 0.76 dv. Thus, the visibility impact of the
dryer alone

is the resultant difference of 0.02 dv. Because of the extremely low
visibility impact and emissions from the dryer, the State has
determined that no meaningful visibility improvements would result from
any conceivable controls on the dryer. The State has determined that
SO2 and NOX BART for the Cemex dryer are the
following existing emission limits: 36.7 tpy for SO2 and
13.9 tpy for NOX on a 12-month rolling average.
    EPA is proposing to approve the State's SO2 and
NOX BART determinations for the Cemex Lyons dryer. EPA
agrees with the State that no significant visibility improvements would
result from the application of controls on the dryer.

SO2 BART Determination for the Kiln

    The kiln has no current SO2 controls, but approximately
80% of the SO2 emissions are captured as part of the
inherent control of the kiln process. The State determined that lime
addition to kiln feed, fuel substitution (coal with tire-derived fuel),
dry sorbent injection (DSI), and wet lime scrubbing (WLS) were
technically feasible for reducing SO2 emissions from the
Cemex kiln. The State determined raw materials substitution was
technically infeasible.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, and there are no remaining-useful-life issues for
this source. A summary of the State's SO2 BART analysis and
the visibility impacts derived from modeling conducted by the source is
provided in Table 3 below.

                                                 Table 3--Summary of Cemex-Lyons Kiln SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                              Annual                                                        improvement
                                                                            controlled       Emission                          Cost        (delta dv for
                   Control technology                         Control       hourly SO2       reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)  emissions (lbs/      (tpy)           cost           ($/ton)          98th
                                                                                hr)                                                         percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lime Addition to Kiln Feed..............................              25              19            23.8      $3,640,178        $153,271           0.033
Fuel Substitution.......................................              40            15.2              38         172,179           4,531           0.034
DSI.....................................................              50            12.7            47.5  ..............  ..............           0.036
WLS.....................................................              90             2.5            85.5       2,529,018          29,579           0.040
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based upon its consideration and weighing of the five factors, the
State has determined that no additional SO2 emissions
control on the kiln is reasonable for BART. The State determined that
the added expense of any of the potential SO2 controls was
not reasonable for the small visibility improvement of 0.04 dvs or
less. Despite not having cost information on DSI, the State determined
that the minimal visibility improvement of 0.036 dv does not justify
further consideration of this control technology. The State has
determined that emissions from the 2002 baseline period represent BART
for SO2 emissions for the kiln. The State determined that
the SO2 BART emission limits for the kiln are 25.3 lbs/hour
and 95.0 tpy of SO2 (12-month rolling average).
    We are proposing to approve the State's SO2 BART
determination for the Cemex Lyons kiln. The State's weighing of the
factors was reasonable and resulted in a reasonable determination for
SO2 BART.

NOX BART Determination for the Kiln

    The kiln is currently uncontrolled for NOX emissions.
The State determined that water injection, firing coal supplemented
with tire-derived fuel (TDF), indirect firing with low NOX
burners (LNBs), SNCR, and the combination of SNCR and LNBs were
technically feasible and appropriate for reducing NOX
emissions from the Cemex kiln. The State determined that SCR is not
commercially available for Portland cement kilns. EPA does not agree
with the State's assertion that SCR is not commercially available for
Portland cement kilns.
    Although we disagree with the State's conclusion on the commercial
availability of SCR for cement kilns, we accept the State's decision,
for purposes of RH, not to analyze this control technology further. We
note that EPA has acknowledged, in the context of establishing the New
Source Performance Standards (NSPS) for Portland Cement Plants,
substantial uncertainty regarding the cost effectiveness associated
with the use of SCR at such plants. See 75 FR 54995. We expect the
State to reevaluate this technology in subsequent RP planning periods.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, and there are no remaining-useful-life issues for
this facility. A summary of the State's NOX BART analysis
and the visibility impacts derived from modeling conducted by the
source is provided in Table 4 below.

                                                 Table 4--Summary of Cemex-Lyons Kiln NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                              Annual                                                        improvement
                                                              Control       controlled       Emission                          Cost        (delta dv for
                   Control technology                       efficiency      hourly NOX       reduction      Annualized     effectiveness    the maximum
                                                                (%)       emissions (lbs/      (tpy)           cost           ($/ton)          98th
                                                                                hr)                                                         percentile
                                                                                Impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Water Injection.........................................               7           431.8           122.3         $43,598            $356            0.22
Firing TDF..............................................              10           417.8           174.7         172,179             986            0.23
Indirect Firing with LNBs...............................              20           371.4           349.4         710,179           2,034            0.28
SNCR....................................................              45           255.3           786.2       1,636,636           2,082            0.39
SNCR....................................................            48.5           239.4           846.1       1,636,636           1,934            0.41
SNCR with LNBs..........................................              55           208.9           960.9       1,686,395           1,755            0.44
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As the table shows, SNCR with LNB could potentially achieve the
greatest emission reductions for the control technologies evaluated.
The Cemex-Lyons facility is a unique kiln system most accurately
described as a modified long dry kiln. The characteristics of a
modified long dry kiln system are not similar to either a long wet kiln
or a multi-stage preheater/precalciner kiln. The temperature profile in
a long dry kiln system (>1500[deg]F) is significantly higher at the
exit than a more typical preheater/precalciner kiln (650 [deg]F). This
limits the location and residence time available for an effective
NOX control system. Because of this unique design, the State
determined that SNCR and the combination of SNCR with LNBs have an
uncertain level of control. Because the design of the Cemex kiln is
unlike that for other kilns where SNCR has been successfully applied,
it is uncertain whether SNCR can achieve emission reductions of 48.5%.
The incremental reduction in visibility associated with SNCR in
combination with LNBs would be 0.05 dv over just SNCR alone. Based on
the uncertainty concerning the control efficiency of SNCR alone and
SNCR with LNBs, and based on the small incremental visibility
improvement that would result from SNCR in combination with LNBs over
just SNCR, the State determined that BART for NOX equates to
an emission limit consistent with SNCR at 45% control. The State
determined that the NOX BART emission limits for the Cemex
kiln are 255.3 pounds per hour (30-day rolling average) and 901.0 tons
per year (12-month rolling average). The State assumes the emission
limits can be met with the installation and operation of SNCR.
    We agree with the State's conclusion, and we are proposing to
approve the State's NOX BART determination for the Cemex-
Lyons kiln.

PM BART Determination

    PM emissions from the kiln and dryer are currently controlled by
fabric filter baghouses and wet dust suppression techniques. Current PM
emission limits are in compliance with the National Emission Standards
for Hazardous Air Pollutants (NESHAP) for Source Categories; Portland
Cement Manufacturing Industry, 40 CFR part 63, subpart LLL. The
existing NESHAP regulatory emission limits for the kiln are 0.275 lb/
ton of dry feed and 20% opacity. For the dryer, the emission limit is
22.8 tpy and 10% opacity. For sources already regulated by a NESHAP
standard, EPA stated the following in the BART guidelines: ``We believe
that, in many cases, it will be unlikely that States will identify
emission controls more stringent than the MACT standards without
identifying control options that would cost many thousands of dollars
per ton. Unless there are new technologies subsequent to the MACT
standards which would lead to cost effective increases in the level of
control, you may rely on the MACT standards for purposes of BART.'' (70
FR 39163) (MACT means Maximum Achievable Control Technology).
    The State determined that no new PM control methodologies could be
identified that would improve upon the PM controls required in the
NESHAP. The State determined that the current emission limit and
control technology represent the most stringent level of control and
are BART for PM for the Cemex-Lyons kiln and dryer. Per the BART
Guidelines, if the BART source has the most stringent control
technology and limit in place, a full five-factor analysis is not
required (70 FR 39165). The State determined that PM BART emission
limits for the kiln are 0.275 lb/ton of dry feed and 20% opacity and
the emission limits for the dryer are 22.8 tpy (12-month rolling
average) and 10% opacity. The State assumes the limits can be achieved
with the operation of the current fabric filter baghouses.
    We are proposing to approve the State's PM BART determinations for
the Cemex-Lyons kiln and dryer. We agree with the State that the
existing controls and emission limits represent the most stringent
level of PM control for this type of facility.
ii. CENC Boilers 4 and 5

Background

    This CENC facility is located adjacent, and supplies steam and
electrical power, to the Coors Brewery in Golden, Colorado. The
facility consists of five boilers and the associated equipment for coal
and ash handling. Boilers 4 and 5 are the only units that are subject
to BART. Boiler 4 mainly fires coal, but can also fire natural gas.
Fuel oil may be used as a backup fuel, but has not been used in recent
years. Boiler 5 fires coal, but uses oil as a backup fuel. Either
boiler may also fire ethanol or sludge from the Coors Brewery. Boiler 4
is rated at 360 MMBtu/hr and Boiler 5 at 650 MMBtu/hr. Both boilers are
pulverized-coal dry-bottom tangentially-fired boilers. The BART
determination for CENC Boilers 4 and 5 can be found in Chapter <IP_ADDRESS>
and Appendix C of the SIP.

SO2 BART Determination

    Boilers 4 and 5 are currently uncontrolled for SO2. The
State determined that DSI and SO2 emission management were
technically feasible for reducing SO2 emissions from Boilers
4 and 5. The State determined that dry FGD controls were not
technically feasible due to space constraints at the facility.
Emissions management for SO2 encompasses a variety of
options to reduce SO2 emissions, including dispatching
natural gas-fired capacity, reducing total system load, and/or reducing
coal firing rate to maintain a new peak SO2 limit. The State
also evaluated tightening the emission limits for Boiler 4 and 5 based
on current operations.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
the source. A summary of the State's SO2 BART analysis and
the visibility impacts is provided in Tables 5 and 6 below. The State
did not model the visibility improvement of SO2 emissions
management because the emission reduction from the control technology
is negligible. The emission rate for each control option in the tables
is reflective of the 30-day rolling average contained in the State's
BART analysis. Baseline SO2 emissions are 781 tpy for Boiler
4 and 1,406 tpy for Boiler 5 based on the average of 2006-2008 actual
emissions.

                                                   Table 5--Summary of CENC Boiler 4 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                                improvement
                                                              Control                        Emission                          Cost        (delta dv for
                   Control technology                       efficiency     Emission rate     reduction      Annualized     effectiveness    the maximum
                                                                (%)         (lb/MMBtu)         (tpy)           cost           ($/ton)          98th
                                                                                percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 Emissions Management................................            0.13             .74               1         $44,299         $43,600              NA

DSI.....................................................              60             .30             468       1,766,000           3,774            0.08
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                   Table 6--Summary of CENC Boiler 5 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                                improvement
                                                              Control                        Emission                          Cost        (delta dv for
                   Control technology                       efficiency     Emission rate     reduction      Annualized     effectiveness    the maximum
                                                                (%)         (lb/MMBtu)         (tpy)           cost           ($/ton)          98th
                                                                                percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 Emissions Management................................           0.063             .82             0.8         $65,882         $78,095              NA
DSI.....................................................              60             .33             844       2,094,000           2,482            0.13
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on its consideration of the five factors, the State
determined that SO2 emissions management and DSI are not
reasonable for BART. The State further evaluated emissions limit
tightening based on current operations, which is a no-cost control
option. The State determined that it would be appropriate to evaluate a
lower emission limit based on percent sulfur and heat content. Based on
the boiler sulfur to SO2 conversions, the State has
determined that the SO2 BART emission limit for CENC Boiler
4 is 1.0 lb/MMBtu (30-day rolling average) and for Boiler 5 is 1.0 lb/
MMBtu (30-day rolling average). The details of the State's calculation
can be found in the State's BART analysis.
    We agree with the State's conclusions, and we are proposing to
approve its SO2 BART determinations for CENC Boiler 4 and
Boiler 5.

NOX BART Determination

    Boilers 4 and 5 are currently uncontrolled for NOX. The
State determined that LNBs, LNBs plus separated overfire air (SOFA),
SNCR, SNCR plus LNB plus SOFA, and SCR were technically feasible for
reducing NOX emissions at CENC Boilers 4 and 5. The State
determined rich reagent injection (RRI), ECO System, and coal reburn
with SNCR were technically infeasible.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. A summary of the State's NOX BART analysis and
the visibility impacts is provided in Tables 7 and 8 below. The
emission rate for each control option in the tables is reflective of
the 30-day rolling average contained in the State's BART analysis.
Baseline NOX emissions are 600 tpy for Boiler 4 and 691 tpy
for Boiler 5, based on the average of 2006-2008 actual emissions.

                                                   Table 7--Summary of CENC Boiler 4 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                                            (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                         Control         (30-day        reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)      rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNBs....................................................          \15\ 7             .52            59.9        $193,433          $3,227            0.05
SNCR....................................................              30             .40           179.8         694,046           3,860            0.07
LNBs + SOFA.............................................            18.5             .37           209.8         678,305           3,234            0.08
LNB + SOFA + SNCR.......................................              51             .22             368       1,372,351           3,729            0.12
SCR.....................................................            79.6             .08           515.4       4,201,038           8,150            0.18
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                   Table 8--Summary of CENC Boiler 5 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNBs....................................................               7             .37            48.4        $249,858          $5,166            0.17
SNCR....................................................              30             .32           127.3         815,829           6,383            0.21
LNBs + SOFA.............................................            18.5             .28           207.3         923,996           4,458            0.21
LNBs + SOFA + SNCR......................................              51             .19           353.7       1,739,825           4,918            0.26
SCR.....................................................            79.6             .08           550.0       6,469,610          11,764            0.31
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on its consideration of the five factors, the State
determined BART is LNBs + SOFA for Boiler 4 and LNBs + SOFA + SNCR for
Boiler 5. Although SCR achieves better emissions reductions, the State
determined that SCR is not reasonable based on the high cost
effectiveness values and the low visibility improvement afforded by
this control. The State has determined that the NOX BART
emission limit for CENC Boiler 4 is 0.37 lb/MMBtu (30-day rolling
average) and for Boiler 5 is 0.19 lb/MMBtu (30-day rolling average).
The State assumes the BART emission limits can be achieved by the
installation and operation of LNBs with SOFA on Boiler 4 and LNBs +
SOFA + SNCR on Boiler 5.
---------------------------------------------------------------------------

    \15\ EPA's AP-42 emission factor tables estimate that LNBs can
control 35-55%, and LNB with OFA can control 40-60%, of
NOX emissions. However, due to the size and configuration
(e.g. furnace dimensions) of the CENC boilers, the State has
determined that the estimated control efficiency for LNBs and LNBs
with OFA used in the analysis are reasonable.
---------------------------------------------------------------------------

    Per the BART Guidelines, states may consider allowing sources to
average emissions across any set of BART eligible emissions units
within a fenceline, so long as the emission reductions from each
pollutant being controlled for BART would be equal to those reductions
that would be obtained by simply controlling each of the BART-eligible
sources (70 FR 39172). Pursuant to this, the State also established a
combined NOX BART limit for CENC Boiler 4 and Boiler 5 of
0.26 lb/MMBtu on a 30-day rolling average.
    We agree with the State's conclusions, and we are proposing to
approve the State's NOX BART determinations for CENC Boiler
4 and Boiler 5.

PM BART Determination

    CENC Boilers 4 and 5 are each equipped with fabric filter baghouses
to control PM emissions with a current emission limit of 0.07 lb/MMBtu.
Fabric filter baghouses are the most stringent control technology for
controlling PM emissions, and stack tests show that the fabric filter
baghouses are achieving a 98% reduction in PM. The State determined
that PM BART for Boiler 4 and Boiler 5 is an emission limit of 0.07 lb/
MMBtu. The State assumes the BART emission limit can be met with the
operation of the current fabric filter baghouses.
    While we do not agree with all of the State's assumptions and
conclusions in arriving at a PM BART limit of 0.07 lb/MMBtu, we are
proposing to approve the State's PM BART determinations for CENC Boiler
4 and Boiler 5. Based on our review/analysis, CENC is capable of
achieving a lower emission limit than 0.07 lb/MMBtu with existing
equipment. However, we anticipate that the visibility improvement that
would result from lowering the limit from 0.07 lb/MMBtu to 0.03 lb/
MMBtu would be insignificant. Under these circumstances, we propose to
find that the State's BART determination was reasonable.
iii. PSCO Comanche Station Units 1 and 2

Background

    Comanche Station is located in Pueblo, Colorado. It consists of
three coal-fired EGUs, Units 1, 2, and 3. Unit 1 is rated at 325
megawatts (MW) and Unit 2 is rated at 335 MW. Unit 1 and Unit 2 are the
only subject-to-BART units at Comanche Station. The boilers burn sub-
bituminous coal as fuel and use natural gas for startup, shutdown, and
flame stabilization. Both units are dry-bottom pulverized coal-fired
boilers. Unit 1 is tangentially fired and Unit 2 is wall-fired.
    In August of 2004, PSCO proposed to construct and operate Unit 3 at
Comanche Station. As part of the project, PSCO proposed to install
NOX and SO2 control devices on Unit 1 and Unit 2
and take new emission limits on those units. In November 2008, PSCO
installed LNBs with OFA and a lime spray dryer (LSD) on Unit 1, and in
November 2007, PSCO installed LNBs with OFA and a LSD on Unit 2.
Operation of the LSDs did not commence until June 3, 2009 for Unit 1
and January 10, 2009 for Unit 2. The State's BART determination for
Comanche Station Units 1 and 2 can be found in Chapter <IP_ADDRESS> and
Appendix C of the SIP.

SO2 BART Determination

    The State determined that the LSD on Unit 1 is achieving 76.1%
control and the LSD on Unit 2 is achieving 81.9% control. Baseline
SO2 emissions are 1,557 tpy for Unit 1 and 1,244 tpy for
Unit 2 based on 2009 actual emissions. The current emission limit for
Units 1 and 2 is 0.12 lb/MMBtu each on a 30-day rolling average and a
combined annual average of 0.10 lb/MMBtu. Per the BART Guidelines, for
EGUs with preexisting post-combustion SO2 controls achieving
removal efficiencies of at least 50 percent, states should consider
cost effective scrubber upgrades designed to improve the system's
overall SO2 removal efficiency (70 FR 39171). 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%. The State's BART analysis evaluated numerous LSD upgrades
including: (1) Use of performance additives; (2) use of more reactive
sorbent; (3) increasing the pulverization level of sorbent; (4)
engineering redesign of atomizer or slurry injection system; and (5)
additional equipment and maintenance. The State analyzed the potential
upgrades and determined all upgrades were either technically infeasible
or would not achieve a decrease in current SO2 emissions.
    The State also assessed emissions limit tightening based on current
operations. The State reviewed available SO2 emissions data
from EPA's Clean Air Markets Division (CAMD) for 2009 and for part of
2010 (January-October 2010). Since the LSDs only recently commenced
full operation, there was limited data available for the State to
determine post-control achievable emissions. In its submittal to the
State, PSCO provided additional information pertaining to emissions
limit tightening. PSCO stated that during low-load operations the inlet
temperature at the baghouse approaches the minimum acceptable level,
lowering the overall SO2 control efficiency during low-load
operations. PSCO indicated that, due to the increased use of wind
resources, the boilers will be required to cycle more frequently to
accommodate intermittent wind resources, and, therefore, the units will
run at low loads more frequently. As a result, the SO2
reduction levels will be lower during those times.
    Based on this information, the State determined that the limited
emissions data from 2009 and 2010 may not accurately represent future
plant emissions. In addition, since the LSDs only came on line
recently, the State recognized that PSCO has limited operating
experience with these units. Although PSCO has other units that are
equipped with LSDs, Comanche Station Units 1 and 2 are the first such
units in PSCO's system that are firing Powder River Basin coal. After
startup of the LSDs in 2009, both units have had a number of days
indicating zero emissions, presumably due to a unit shutdown. In many
cases, emissions data shows that for one or more days following these
events, the daily SO2 emission rate is frequently well above
0.12 lb/MMBtu. In looking at the data, the State also found that both
units have historically lower inlet temperatures to the scrubbers in
the winter months, resulting in increased SO2 emissions.
    Based on the information discussed above, the State concluded that
a tighter 30-day rolling average and annual average SO2
emission limit is not feasible at this time for either unit.

Based on its analysis, the State determined that the SO2
BART emission limit for Comanche Station Unit 1 is 0.12 lb/MMBtu (30-
day rolling average) and for Unit 2 is 0.12 lb/MMBtu (30-day rolling
average). The State also established a SO2 BART emission
limit of 0.10 lb/MMBtu, combined annual average for both units.
    We agree with the State's conclusions and are proposing to approve
its SO2 BART determinations for Comanche Station Unit 1 and
Unit 2.

NOX BART Determination

    Comanche Station Units 1 and 2 currently have a NOX
permit limit of 0.20 lb/MMBtu on a 30-day rolling average for each unit
and a combined annual average limit of 0.15 lb/MMBtu. The State
determined that SCR and SNCR were technically feasible at Unit 1 and
SCR was technically feasible for Unit 2. PSCO conducted testing in the
fall of 2008 on Unit 2 using a temporary SNCR system. PSCO performed
the testing following the installation of LNBs and OFA to determine if
additional reductions could be achieved. PSCO primarily conducted
testing at full load over a seven-day period using a single-level urea
based SNCR system. The SNCR system is sensitive to temperature and
average exhaust temperature in the injection area for Unit 2 was nearly
2,200 [deg]F, which exceeds the optimal temperature for the technology.
During the test periods, NOX reductions were less than 10%,
and in some cases during testing, an actual increase in NOX
emissions was observed by PSCO. Based on the results of PSCO's test of
SNCR on Unit 2, the State did not evaluate SNCR further as a control
option for Unit 2. The State also determined that ECO system and RRI
were technically infeasible for both units. The State did not evaluate
rotating opposed fire air (ROFA) and reburning because they do not
achieve better emission reductions than the current controls.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. Baseline NOX emissions from the 2009 calendar
year are 1,511 tpy for Unit 1 and 2,349 tpy for Unit 2. A summary of
the State's NOX BART analysis and the visibility impacts is
provided in Tables 9 and 10 below. The emission rate for each control
option in the tables is reflective of the 30-day rolling average
contained in the State's BART analysis.

                                              Table 9--Summary of Comanche Station Unit 1 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR....................................................            29.5            0.10             446      $1,624,100          $3,644            0.11
SCR.....................................................              51            0.07             770      12,265,014          15,290            0.14
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                             Table 10--Summary of Comanche Station Unit 2 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR.....................................................              63            0.07            1480     $14,650,885          $9,900            0.17
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on its consideration of the five factors, the State has
determined that the NOX BART emission limit for Comanche
Station Unit 1 is 0.20 lb/MMBtu (30-day rolling average) and for Unit 2
is 0.20 lb/MMBtu (30-day rolling average). The State also established a
NOX BART emission limit of 0.15 lb/MMBtu, combined annual
average for both units.
    The State assumes that the BART emission limits can be achieved
through the operation of existing LNBs. Although the other alternatives
achieve better emissions reductions, the State determined that the
added expense of achieving lower limits through different controls was
not reasonable based on the high cost effectiveness coupled with the
low visibility improvement (under 0.2 dv) afforded.
    We agree with the State's conclusions, and we are proposing to
approve the State's NOX BART determinations for Comanche
Station Unit 1 and Unit 2.

PM BART Determination

    Comanche Station Units 1 and 2 are each equipped with fabric filter
baghouses to control PM emissions with an emission limit of 0.03 lb/
MMBtu. Stack tests show that the fabric filter baghouses are achieving
a 99% reduction in PM. Fabric filter baghouses are the most stringent
control technology for controlling PM emissions. The State also
evaluated what would constitute the most stringent level of control for
PM by looking at recent Best Available Control Technology (BACT)
determinations. Based on this evaluation, the State determined that an
emission limit of 0.03 lb/MMBtu represents the most stringent level of
control for this type of source. Consistent with the BART Guidelines,
the State did not provide a full five-factor analysis because the State
determined BART to be the most stringent control technology and limit.
The State determined that the PM BART limit for Comanche Station Units
1 and 2 is 0.03 lb/MMBtu (30-day rolling average). The State assumes
the BART limit can be met with the operation of the existing fabric
filter baghouses.
    We agree with the State's conclusions, and we are proposing to
approve its PM BART determinations for Comanche Station Unit 1 and Unit
2.
iv. Tri-State Craig Units 1 and 2

Background

    The Tri-State Generation & Transmission Association, Inc. (Tri-
State) Craig Station is located in Moffat County approximately 2.5
miles southwest of the town of Craig,

Colorado. This facility is a coal-fired power plant with a total net
electric generating capacity of 1264 MW, consisting of three units.
Only Units 1 and 2 are BART-eligible. Units 1 and 2 are dry-bottom
pulverized coal-fired boilers and are each rated at a net capacity of
428 MW. The State's BART determination for Craig Units 1 and 2 can be
found in Chapter <IP_ADDRESS> and Appendix C of the SIP.

SO2 BART Determination

    Craig Unit 1 and Unit 2 are currently controlled with wet FGD. The
units have a current SO2 emission limit of 0.16 lb/MMBtu on
a 30-day rolling average and a requirement to achieve a 90% reduction
of SO2 (90-day rolling average). Per the BART Guidelines,
for EGUs with preexisting post-combustion SO2 controls
achieving removal efficiencies of at least 50 percent, states should
consider cost effective scrubber upgrades designed to improve the
system's overall SO2 removal efficiency (70 FR 39171). 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%.
    The State evaluated the following wet FGD upgrades: (1) Elimination
of bypass reheat; (2) installation of liquid distribution rings; (3)
installation of perforated trays; (4) use of organic acid additives;
(5) improve or upgrade scrubber auxiliary equipment; and (6) redesign
spray header or nozzle configuration. Tri-State performed numerous
upgrades at Units 1 and 2 during 2003-2004. The State determined that
Tri-State had installed all of the above upgrades with the exception of
liquid distribution rings and use of organic additives. The State
determined that the installation of perforated trays achieved the same
objective as these upgrades.
    The State evaluated emission limit tightening based on current
operations. The State analyzed the baseline period (2006-2008) emission
data from EPA's CAMD to determine the maximum and average 30-day
rolling emission rates. The emissions data shows that the maximum 30-
day rolling average was 0.08 lb/MMBtu for Unit 1 and 0.09 lb/MMBtu for
Unit 2. The average 30-day rolling emission rate was 0.05 lb/MMBtu for
Unit 1 and 0.08 for Unit 2. The daily maximum over the three-year
period was 0.17 lb/MMBtu for Unit 1 and 0.16 lb/MMBtu for Unit 2. Table
11 shows the visibility improvement modeled by the State for possible
lower SO2 emission limits.

                          Table 11--Craig Unit 1 and Unit 2 SO2 Visibility Improvement
----------------------------------------------------------------------------------------------------------------
                                                                               Craig unit 1--    Craig unit 2--
                                                                                visibility        visibility
                                                              Emission rate      improvement       improvement
                        SO2 Control                         (lb/MMBtu)  (30-    (delta dv for     (delta dv for
                                                               day rolling    the maximum 98th  the maximum 98th
                                                                average)         percentile        percentile
                                                                                impact)           impact)
----------------------------------------------------------------------------------------------------------------
Wet FGD...................................................              0.11              0.03              0.03
Wet FGD...................................................              0.07              0.05              0.05
----------------------------------------------------------------------------------------------------------------

    The State determined that an emission limit of 0.11 lb/MMBtu would
be achievable without additional capital investment. The State
determined that an emission limit lower than 0.11 lb/MMBtu would likely
require additional capital expenditure and determined it was not
reasonable for the incremental visibility improvement of 0.02. The
State has determined that the SO2 BART emission limit for
Craig Unit 1 is 0.11 lb/MMBtu (30-day rolling average) and for Unit 2
is 0.11 lb/MMBtu (30-day rolling average). The State assumes that the
BART emission limits can be achieved through the operation of the
existing wet FGD.
    We agree with the State's conclusions, and we are proposing to
approve its SO2 BART determinations for Craig Unit 1 and
Unit 2.

NOX BART Determination

    Craig Units 1 and 2 are currently controlled with ultra low
NOX burners (ULNBs) plus OFA, achieving emission reductions
of about 54 percent each. The State determined that combustion control
refinements, neural network systems, SNCR, and SCR were technically
feasible. \16\ The State determined that ECO, RRI, ROFA, and coal
reburn plus SNCR were not technically feasible. The State did not
identify any energy or non-air quality environmental impacts that would
preclude the selection of any of the controls evaluated, nor are there
any remaining-useful-life issues for this source. Baseline
NOX emissions are 5,190 tpy for Unit 1 and 5,372 tpy for
Unit 2 based on the average of 2006-2008 actual emissions. A summary of
the State's NOX BART analysis and the visibility impacts is
provided in Tables 12 and 13 below. The emission rate for each control
option in the tables is reflective of the 30-day rolling average
contained in the State's BART analysis. Due to the very small percent
control achieved with combustion control refinements and neural network
systems, the State did not perform visibility modeling for these two
control options. Thus, Tables 12 and 13 do not show a value for
visibility improvement for these options.
---------------------------------------------------------------------------

    \16\ Although not reflected in the SIP, the State's five-factor
analysis in Appendix C of the SIP contains information on combustion
control refinements and neural network systems.

                                                   Table 12--Summary of Craig Unit 1 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Combustion Control Refinements..........................               2            0.31             104        $122,000          $1,175  ..............
Neural Network System...................................               5            0.30             260         280,000           1,079  ..............
SNCR....................................................              15            0.27             779       3,797,000           4,877            0.31
SCR.....................................................            74.9            0.08           3,893      25,036,709           6,432            1.01
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                   Table 13--Summary of Craig Unit 2 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum