[Federal Register Volume 77, Number 58 (Monday, March 26, 2012)]
[Proposed Rules]
[Pages 18052-18098]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-6908]



[[Page 18051]]

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

[[Page 18052]]


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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:
    <bullet> http://www.regulations.gov. Follow the on-line 
instructions for submitting comments.
    <bullet> Email: <a href="/cdn-cgi/l/email-protection#bfdbc6d8d0c8ccd4d691d3decacddad3ffdacfde91d8d0c9"><span class="__cf_email__" data-cfemail="80e4f9e7eff7f3ebe9aeece1f5f2e5ecc0e5f0e1aee7eff6">[email protected]</span></a>.
    <bullet> Fax: (303) 312-6064 (please alert the individual listed in 
the FOR FURTHER INFORMATION CONTACT if you are faxing comments).
    <bullet> Mail: Carl Daly, Director, Air Program, Environmental 
Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, 
Denver, Colorado 80202-1129.
    <bullet> 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, (303) 312-6144, 
<a href="/cdn-cgi/l/email-protection#3b5f425c544c48505215575a4e495e577b5e4b5a155c544d"><span class="__cf_email__" data-cfemail="dcb8a5bbb3abafb7b5f2b0bda9aeb9b09cb9acbdf2bbb3aa">[email protected]</span></a>.

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

[[Page 18053]]

    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 NO<INF>X</INF> 
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 NH<INF>3</INF> mean or refer to ammonia.
    xxiii. The initials NO<INF>X</INF> 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 PM<INF>2.5</INF> mean or refer to 
particulate matter with an aerodynamic diameter of less than 2.5 
micrometers.
    xxviii. The initials PM<INF>10</INF> 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 SO<INF>2</INF> 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

[[Page 18054]]

activities which are located across a broad geographic area and emit 
fine particles (PM<INF>2.5</INF>) (e.g., sulfates, nitrates, organic 
carbon (OC), elemental carbon (EC), and soil dust), and their 
precursors (e.g., sulfur dioxide (SO<INF>2</INF>), nitrogen oxides 
(NO<INF>X</INF>), and in some cases, ammonia (NH<INF>3</INF>) and 
volatile organic compounds (VOC)). Fine particle precursors react in 
the atmosphere to form PM<INF>2.5</INF>, which impairs visibility by 
scattering and absorbing light. Visibility impairment reduces the 
clarity, color, and visible distance that one can see. PM<INF>2.5</INF> 
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

[[Page 18055]]

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

[[Page 18056]]

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.
---------------------------------------------------------------------------

    \6\ The set of ``major stationary sources'' potentially subject 
to BART is listed in CAA section 169A(g)(7).
---------------------------------------------------------------------------

    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 SO<INF>2</INF>, NO<INF>X</INF>, and 
PM. EPA has stated that states should use their best judgment in 
determining whether VOC or NH<INF>3</INF> 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

[[Page 18057]]

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:
    <bullet> 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;
    <bullet> 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;
    <bullet> 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;
    <bullet> 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
    <bullet> 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

[[Page 18058]]

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

[[Page 18059]]

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 SO<INF>2</INF>, 
NO<INF>X</INF>, and direct PM (including both coarse particulate matter 
(PM<INF>10</INF>) and fine particulate matter (PM<INF>2.5</INF>)) 
emissions as visibility-impairing pollutants and to exercise their 
``best judgment to determine whether VOC or NH<INF>3</INF> 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 NH<INF>3</INF> 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 NH<INF>3</INF> emissions are 
small. The State's emission inventory for 2001-2003 shows that point 
sources emitted 453 tpy of NH<INF>3,</INF> while total State 
NH<INF>3</INF> emissions are 67,686 tpy. Thus, the State has eliminated 
NH<INF>3</INF> 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

[[Page 18060]]

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:
    <bullet> Step 1: Identify All Available Retrofit Control 
Technologies;
    <bullet> Step 2: Eliminate Technically Infeasible Options;
    <bullet> Step 3: Evaluate Control Effectiveness of Remaining 
Control Technologies;
    <bullet> Step 4: Evaluate Impacts and Document the Results; and
    <bullet> 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 NO<INF>X</INF>, SO<INF>2</INF>, and PM. We find 
that Colorado adequately considered all five steps above in its BART 
determinations.

State NOX Control Criteria

    For NO<INF>X</INF>, the State developed criteria to assist in the 
selection of post-combustion controls for BART. For the highest-
performing NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> controls, we 
agree with the State's determinations for NO<INF>X</INF> BART controls 
on the BART sources as discussed below.

[[Page 18061]]

SO2 Controls--Wet and Dry Scrubbing

    Scrubbing is one of the most common ways to control emissions of 
SO<INF>2</INF> 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 
SO<INF>2</INF> 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 
SO<INF>2</INF> emission reductions that would result from the use of 
wet FGDs rather than dry FGDs (see Chapter 6.4.1.3 of the SIP). EPA is 
proposing that the State provided adequate justification to eliminate 
the consideration of wet FGDs as SO<INF>2</INF> 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 SO<INF>2</INF> and NO<INF>X</INF> emissions. The raw 
material dryer emits minor amounts of SO<INF>2</INF> and 
NO<INF>X</INF>. The State's BART determination can be found in Chapter 
6.4.3.1 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 NO<INF>X</INF>; 0.89 tpy for SO<INF>2</INF>; 
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 SO<INF>2</INF> emissions (which can vary significantly due to 
pyrites in the limestone) and the normal historical range for 
NO<INF>X</INF> emissions and clinker production. The 2002 baseline 
emissions for the kiln are: 1,747 tpy for NO<INF>X</INF>; 95 tpy for 
SO<INF>2</INF>; and 8.5 tpy for PM.

SO2 and NOX BART Determination for the Dryer

    CALPUFF modeling provided by the source, using a maximum 
SO<INF>2</INF> 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

[[Page 18062]]

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 
SO<INF>2</INF> and NO<INF>X</INF> BART for the Cemex dryer are the 
following existing emission limits: 36.7 tpy for SO<INF>2</INF> and 
13.9 tpy for NO<INF>X</INF> on a 12-month rolling average.
    EPA is proposing to approve the State's SO<INF>2</INF> and 
NO<INF>X</INF> 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 SO<INF>2</INF> controls, but approximately 
80% of the SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> emissions 
control on the kiln is reasonable for BART. The State determined that 
the added expense of any of the potential SO<INF>2</INF> 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 SO<INF>2</INF> emissions for the kiln. The State determined that 
the SO<INF>2</INF> BART emission limits for the kiln are 25.3 lbs/hour 
and 95.0 tpy of SO<INF>2</INF> (12-month rolling average).
    We are proposing to approve the State's SO<INF>2</INF> BART 
determination for the Cemex Lyons kiln. The State's weighing of the 
factors was reasonable and resulted in a reasonable determination for 
SO<INF>2</INF> BART.

NOX BART Determination for the Kiln

    The kiln is currently uncontrolled for NO<INF>X</INF> emissions. 
The State determined that water injection, firing coal supplemented 
with tire-derived fuel (TDF), indirect firing with low NO<INF>X</INF> 
burners (LNBs), SNCR, and the combination of SNCR and LNBs were 
technically feasible and appropriate for reducing NO<INF>X</INF> 
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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 18063]]

    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 
NO<INF>X</INF> 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 NO<INF>X</INF> equates to 
an emission limit consistent with SNCR at 45% control. The State 
determined that the NO<INF>X</INF> 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 NO<INF>X</INF> 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 6.4.3.2 
and Appendix C of the SIP.

SO2 BART Determination

    Boilers 4 and 5 are currently uncontrolled for SO<INF>2</INF>. The 
State determined that DSI and SO<INF>2</INF> emission management were 
technically feasible for reducing SO<INF>2</INF> 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 SO<INF>2</INF> encompasses a variety of 
options to reduce SO<INF>2</INF> emissions, including dispatching 
natural gas-fired capacity, reducing total system load, and/or reducing 
coal firing rate to maintain a new peak SO<INF>2</INF> 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 SO<INF>2</INF> BART analysis and 
the visibility impacts is provided in Tables 5 and 6 below. The State 
did not model the visibility improvement of SO<INF>2</INF> 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 SO<INF>2</INF> 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

[[Page 18064]]

 
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 SO<INF>2</INF> 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 SO<INF>2</INF> conversions, the State has 
determined that the SO<INF>2</INF> 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 SO<INF>2</INF> BART determinations for CENC Boiler 4 and 
Boiler 5.

NOX BART Determination

    Boilers 4 and 5 are currently uncontrolled for NO<INF>X</INF>. The 
State determined that LNBs, LNBs plus separated overfire air (SOFA), 
SNCR, SNCR plus LNB plus SOFA, and SCR were technically feasible for 
reducing NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 18065]]

    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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> and SO<INF>2</INF> 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 6.4.3.3 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 
SO<INF>2</INF> 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 SO<INF>2</INF> controls achieving 
removal efficiencies of at least 50 percent, states should consider 
cost effective scrubber upgrades designed to improve the system's 
overall SO<INF>2</INF> removal efficiency (70 FR 39171). Under the BART 
Guidelines, a state is not required to evaluate the replacement of the 
current SO<INF>2</INF> 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 SO<INF>2</INF> emissions.
    The State also assessed emissions limit tightening based on current 
operations. The State reviewed available SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 
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 SO<INF>2</INF> 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 SO<INF>2</INF> emissions.
    Based on the information discussed above, the State concluded that 
a tighter 30-day rolling average and annual average SO<INF>2</INF> 
emission limit is not feasible at this time for either unit.

[[Page 18066]]

Based on its analysis, the State determined that the SO<INF>2</INF> 
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 SO<INF>2</INF> 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 SO<INF>2</INF> BART determinations for Comanche Station Unit 1 and 
Unit 2.

NOX BART Determination

    Comanche Station Units 1 and 2 currently have a NO<INF>X</INF> 
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, NO<INF>X</INF> reductions were less than 10%, 
and in some cases during testing, an actual increase in NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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,

[[Page 18067]]

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 6.4.3.4 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 SO<INF>2</INF> emission limit of 0.16 lb/MMBtu on 
a 30-day rolling average and a requirement to achieve a 90% reduction 
of SO<INF>2</INF> (90-day rolling average). Per the BART Guidelines, 
for EGUs with preexisting post-combustion SO<INF>2</INF> controls 
achieving removal efficiencies of at least 50 percent, states should 
consider cost effective scrubber upgrades designed to improve the 
system's overall SO<INF>2</INF> removal efficiency (70 FR 39171). Under 
the BART Guidelines, a state is not required to evaluate the 
replacement of the current SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> BART determinations for Craig Unit 1 and 
Unit 2.

NOX BART Determination

    Craig Units 1 and 2 are currently controlled with ultra low 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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.

[[Page 18068]]



                                                   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
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                                                                              impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Combustion Control Refinements..........................               2            0.31             104        $122,000          $1,136  ..............
Neural Network System...................................               5            0.30             260         280,000           1,043  ..............
SNCR....................................................              15            0.27             779       3,797,000           4,712            0.31
SCR.....................................................              74            0.07           3,893      25,036,709           6,299            1.01
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State determined that SNCR was reasonable for BART for both 
Unit 1 and Unit 2 based on the cost effectiveness and visibility 
improvement associated with this level of control. The State determined 
SCR was not reasonable because of the high cost effectiveness value. 
Based upon its consideration of the five factors, the State determined 
that the NO<INF>X</INF> BART emission limit for Craig Unit 1 is 0.27 
lb/MMBtu (30-day rolling average) and for Unit 2 is 0.27 lb/MMBtu (30-
day rolling average). The State assumed that the BART emission limits 
can be achieved through the operation of SNCR. We agree with the 
State's BART determination that an emission limit of 0.27 lb/MMBtu is 
NO<INF>X</INF> BART for Craig Unit 1 and Unit 2. The State arrived at 
this limit based on a reasonable consideration of the five factors.
    Although the State determined that 0.27 lb/MMBtu was NO<INF>X</INF> 
BART for Craig Unit 1 and Unit 2, the State adopted a more stringent 
emission limit for Craig Unit 2 in its SIP and a slightly less 
stringent limit for Unit 1. Tri-State and the State agreed to a 
NO<INF>X</INF> emissions control plan for Craig Unit 1 and Unit 2 that 
is more stringent overall. It consists of emission limits associated 
with the operation of SNCR for Unit 1 and the operation of SCR for Unit 
2. These NO<INF>X</INF> emission limits are 0.28 lb/MMBtu (30-day 
rolling average) for Craig Unit 1 and 0.08 lb/MMBtu (30-day rolling 
average) for Craig Unit 2. The State adopted these emission limits in 
its SIP, and these are the emission limits Tri-State must meet for 
purposes of the RH program. We are proposing to approve the State's 
NO<INF>X</INF> emission limits for Craig Unit 1 and for Craig Unit 2 as 
satisfying the requirements of 40 CFR 51.308(e).

PM BART Determination

    Craig 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 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 emission 
limit is 0.03 lb/MMBtu (30-day rolling average) at Craig Unit 1 and 
Craig Unit 2. The State assumes the BART emission limits can be met 
through the operation of the current fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM BART determinations for Craig Unit 1 and Unit 2.
v. PSCO Hayden Station Units 1 and 2

Background

    The Hayden facility is located four miles east of Hayden, Colorado 
in Routt County. This facility consists of two steam driven turbine/
generator units, Units 1 and 2, and the associated equipment needed for 
generating electricity. Unit 1 is a pulverized-coal front-fired dry-
bottom boiler, firing coal, with natural gas and No. 2 fuel oil used 
for startup, shutdown, and/or flame stabilization. Unit 2 is a 
pulverized-coal tangentially-fired dry-bottom boiler, firing coal, with 
No. 2 fuel oil used for startup, shutdown, and/or flame stabilization. 
Units 1 and 2 are the only subject-to-BART units at the facility. The 
State's BART determination for Hayden Units 1 and 2 can be found in 
Chapter 6.4.3.5 and Appendix C of the SIP.

SO2 BART Determination

    PSCO Hayden Units 1 and 2 are currently controlled with LSDs. Both 
units have a current SO<INF>2</INF> emission limit of 0.16 lb/MMBtu 
(30-day rolling average) and a requirement to achieve an 82% reduction 
of SO<INF>2</INF> (30-day rolling average). As mentioned earlier, if a 
BART source has current SO<INF>2</INF> controls achieving at least 50% 
control, then the state needs to evaluate upgrades to the existing 
control technology but does not need to consider the replacement of 
that technology. 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

[[Page 18069]]

level of sorbent; (4) engineering redesign of atomizer or slurry 
injection system (including an additional scrubber vessel); and (5) 
additional equipment and maintenance. The State determined that the 
application of the first three upgrades in the list above would not 
result in lower SO<INF>2</INF> emissions. The State determined that 
engineering redesign using an additional scrubber vessel and additional 
equipment and maintenance were technically feasible and would 
potentially achieve SO<INF>2</INF> emissions reductions.
    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 SO<INF>2</INF> emissions are 1,172 tpy for Unit 1 
and 1,469 tpy for Unit 2 based on the average of 2006-2008 actual 
emissions. A summary of the State's SO<INF>2</INF> BART analysis and 
the visibility impacts is provided in Tables 14 and 15 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 14--Summary of Hayden Unit 1 SO2 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Additional Equipment and Maintenance....................             5.2            0.13              61        $141,150          $2,317             .10
Additional Scrubber Vessel..............................            41.7            0.08             488       4,142,538           8,490            0.14
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                                  Table 15--Summary of Hayden Unit 2 SO2 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Additional Equipment and Maintenance....................             2.7            0.13              39        $141,150          $3,626            0.21
Additional Scrubber Vessel..............................            40.1            0.08             589       4,808,896           8,164            0.26
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State determined that the cost of an additional scrubber vessel 
was not reasonable for BART controls. The State determined that 
additional equipment and maintenance was reasonable for SO<INF>2</INF> 
BART controls and that a more stringent 30-day rolling SO<INF>2</INF> 
limit represents an appropriate level of emissions control for BART for 
Hayden Units 1 and 2. Based on its consideration of the five factors, 
the State has determined that the SO<INF>2</INF> BART emission limit 
for Hayden Unit 1 is 0.13 lb/MMBtu (30-day rolling average) and for 
Unit 2 is 0.13 lb/MMBtu (30-day rolling average). The State assumes the 
BART emission limit can be met with the operation of the existing LSD.
    We agree with the State's conclusions, and we are proposing to 
approve its SO<INF>2</INF> BART determinations for Hayden Unit 1 and 
Unit 2.

NOX BART Determination

    Hayden Units 1 and 2 are currently controlled with LNBs plus OFA, 
achieving emission reductions of 54 percent and 33 percent, 
respectively. The State determined that upgrades to the existing LNBs, 
SNCR, and SCR were technically feasible. 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 NO<INF>X</INF> emissions are 3,750 tpy for Unit 1 and 
3,743 tpy for Unit 2 based on the average of 2006-2008 actual 
emissions. A summary of the State's NO<INF>X</INF> BART analysis and 
the visibility impacts is provided in Tables 16 and 17 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 16--Summary of Hayden 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNBs....................................................              37            0.30           1,391        $572,010            $411            0.69
SNCR....................................................              37            0.30           1,391       1,353,500             973            0.69
SCR.....................................................              83            0.08           3,120      10,560,612           3,385            1.12
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 18070]]


                                                  Table 17--Summary of Hayden 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNBs....................................................              35            0.24           1,303        $992,729            $762            0.40
SNCR....................................................              43            0.21           1,610       1,893,258           1,176            0.48
SCR.....................................................              81            0.07           3,032      12,321,491           4,064            0.85
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on its consideration of the five factors, the State has 
determined that the NO<INF>X</INF> BART emission limit for Hayden Unit 
1 is 0.08 lb/MMBtu (30-day rolling average) and for Unit 2 is 0.07 lb/
MMBtu (30-day rolling average). The State assumes the BART emission 
limit can met through the installation and operation of SCR.
    We agree with the State's conclusions, and we are proposing to 
approve its NO<INF>X</INF> BART determinations for Hayden Unit 1 and 
Unit 2.

PM BART Determination

    Hayden 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 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 has determined that the PM BART 
emission limit is 0.03 lb/MMBtu (30-day rolling average) for Hayden 
Unit 1 and Unit 2. The State assumes the BART emission limit can be met 
through the operation of the current fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM BART determinations for Hayden Unit 1 and Unit 2.
vi. CSU Martin Drake Units 5, 6, and 7

Background

    The CSU's Martin Drake facility is located in Colorado Springs, 
Colorado. This facility consists of three steam driven turbine/
generator units, Units 5, 6, and 7, and the associated equipment needed 
for generating electricity. Units 5, 6, and 7 are the only BART-
eligible units at the facility. These units fire coal as the primary 
fuel and use natural gas for backup and startup. All three boilers are 
pulverized-coal, dry-bottom, front-fired boilers. The State's BART 
determination for CSU Martin Drake can be found in Chapter 6.4.3.6 and 
Appendix C of the SIP.

SO2 BART Determination

    Martin Drake Units 5, 6, and 7 are currently uncontrolled for 
SO<INF>2</INF>. The State determined that DSI was technically feasible 
for all three units and that dry FGD was technically feasible for Units 
6 and 7. The State determined dry FGD was not technically feasible for 
Unit 5 because of space constraints surrounding this unit. The State 
also examined emission limit tightening based on current operations for 
Unit 5.
    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 SO<INF>2</INF> emissions are 1,269 tpy for Unit 
5, 2,785 tpy for Unit 6, and 4,429 tpy for Unit 7 based on an average 
of 2006-2008 actual emissions. A summary of the State's SO<INF>2</INF> 
BART analysis and the visibility impacts is provided in Tables 18, 19, 
and 20 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 18--Summary of Martin Drake Unit 5 SO2 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI.....................................................              60            0.26             762      $1,340,663          $1,760            0.12
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                               Table 19--Summary of Martin Drake Unit 6 SO2 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI.....................................................              60            0.34           1,671      $2,234,438          $1,741            0.18
Dry FGD.................................................              82            0.15           3,632       6,186,854           2,709            0.24
Dry FGD.................................................              85            0.13           2,368       6,647,835           2,808            0.25

[[Page 18071]]

 
Dry FGD.................................................              90            0.09           2,507       7,452,788           4,064            0.26
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                               Table 20--Summary of Martin Drake Unit 7 SO2 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI.....................................................              60            0.35           2,657      $3,732,826          $1,405            0.29
Dry FGD.................................................              82            0.16           3,632       8,216,863           2,263            0.39
Dry FGD.................................................              85            0.13           3,764       8,829,321           2,345            0.40
Dry FGD.................................................              90            0.09           3,986       9,898,382           2,483            0.41
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State also examined emission limits tightening based on current 
operations for Unit 5. (The State did not evaluate emissions limit 
tightening on Units 6 and 7 because the State determined BART to be the 
most stringent control technology). In order to evaluate emissions 
limit tightening, the State analyzed actual emission data for Unit 5 
from the baseline period of 2006-2008. The State found that the maximum 
30-day rolling emission rate for Unit 5 was 0.83 lb/MMBtu. The State 
applied a 5 percent buffer to the maximum 30-day rolling emission rate 
because the Drake facility has limited coal storage capacity and blends 
four different types of coals. These factors can lead to a greater 
fluctuation in emissions. Assuming no new control technology for Unit 5 
and a 5 percent buffer, the State determined that an appropriate 
SO<INF>2</INF> emission limit would be 0.9 lb/MMBtu on a 30-day rolling 
average, which is less control than would be achieved with DSI.
    Based upon its consideration of the five factors, the State 
determined that the following are the SO<INF>2</INF> BART limits for 
Drake Units 5, 6, and 7: 0.26 lb/MMBtu (30-day rolling average) for 
Unit 5; 0.13 lb/MMBtu (30-day rolling average) for Unit 6; and 0.13 lb/
MMBtu (30-day rolling average) for Unit 7. The State assumes the BART 
emission limits can be met with the installation and operation of DSI 
on Unit 5 and the installation and operation of dry FGD on Unit 6 and 
Unit 7. The State determined that a lower emissions limit (0.09 lb/
MMBtu) for Units 6 and 7 was not reasonable because the increased 
control costs to achieve such an emissions limit would not provide 
significant improvements in visibility (0.01 delta dv for each unit 
respectively).
    We agree with the State's conclusions, and we are proposing to 
approve its SO<INF>2</INF> BART determinations for Martin Drake Unit 5, 
Unit 6, and Unit 7.

NOX BART Determination

    Martin Drake Units 5, 6, and 7 are currently controlled with LNBs 
achieving 54.7%, 52.8%, and 57.7% control, respectively. The State's 
BART analysis shows that OFA, ULNBs, ULNBs plus OFA, SNCR, SNCR plus 
ULNBs, and SCR are technically feasible for reducing NO<INF>X</INF> 
emissions at Drake Units 5, 6 and 7. The State determined that RRI, 
ECO, and coal reburn plus 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. Baseline NO<INF>X</INF> emissions are 768 tpy for Unit 5, 
1,413 tpy for Unit 6, and 2,081 tpy for Unit 7 based on an average of 
2006-2008 actual emissions. A summary of the State's NO<INF>X</INF> 
BART analysis and the visibility impacts is provided in Tables 21, 22, 
and 23 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 21--Summary of Martin Drake Unit 5 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                            Visibility
                                                                                                                                            improvement
                                                                           Emission rate     Emission                          Cost        (delta dv for
                   Control technology                         Control     (lb/MMBtu) (30-    reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)    day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                                                                              impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.....................................................              20            0.35             154        $141,844            $923            0.07
ULNBs...................................................              26            0.32             200         147,000             736            0.08
ULNBs + OFA.............................................              28            0.31             215         288,844           1,342            0.08
SNCR....................................................              30            0.30             231       1,011,324           4,387            0.08
ULNB/SCR layered approach...............................            81.5            0.08             626       4,467,000           7,133            0.12
SCR.....................................................            81.5            0.08             626       4,580,349           7,314            0.12
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 18072]]


                                               Table 22--Summary of Martin Drake Unit 6 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                            Visibility
                                                                                                                                            improvement
                                                                           Emission rate     Emission                          Cost        (Delta dv for
                   Control technology                         Control     (lb/MMBtu) (30-    reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)    day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                                                                              impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.....................................................              20            0.38             283        $104,951            $371            0.18
SNCR....................................................              30            0.33             424       1,208,302           2,851            0.19
ULNBs...................................................              32            0.32             452         232,800             515            0.20
ULNBs + OFA.............................................              36            0.31             509         337,751             664            0.19
ULNB/SCR layered approach...............................              83            0.08           1,175       6,182,800           5,260            0.27
SCR.....................................................              83            0.08           1,175       6,340,797           5,395            0.27
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                               Table 23--Summary of Martin Drake Unit 7 NOX Bart Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                            Visibility
                                                                                                                                            improvement
                                                                           Emission rate     Emission                          Cost        (Delta dv for
                   Control technology                         Control     (lb/MMBtu) (30-    reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)    day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                                                                              impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.....................................................              20            0.36             416         $75,217            $181            0.22
SNCR....................................................              28            0.33             583         386,000             662            0.24
ULNBs...................................................              30            0.32             624       2,018,575           3,233            0.26
ULNBs + OFA.............................................              36            0.29             749         461,217             616            0.24
ULNB/SCR layered approach...............................              80            0.08           1,709       8,196,000           4,797            0.37
SCR.....................................................              80            0.08           1,709       8,510,067           4,981            0.37
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State determined that ULNBs plus OFA constitute BART based on 
the low dollars-per-ton control costs and the visibility improvement 
afforded by this control technology. The State did not choose SNCR as 
that technology provides a similar level of NO<INF>X</INF> reduction 
and visibility improvement as ULNBs plus OFA, but at a higher cost per 
ton of pollutant removed. The State determined SCR was not cost 
effective for any of the units when compared with the visibility 
improvement.
    Based upon its consideration of the five factors, the State 
determined that the following are the NO<INF>X</INF> BART limits for 
Drake Units 5, 6, and 7: 0.31 lb/MMBtu (30-day rolling average) for 
Unit 5 and Unit 6; and 0.29 lb/MMBtu (30-day rolling average) for Unit 
7. The State assumes that the BART emission limits can be achieved 
through the installation and operation of ULNBs plus OFA.
    We agree with the State's conclusions, and we are proposing to 
approve the State's NO<INF>X</INF> BART determinations for Martin Drake 
Units 5, 6, and 7.

PM BART Determination

    Martin Drake Units 5, 6, and 7 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 95% 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 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 has determined that 0.03 lb/MMBtu (30-day rolling 
average) is the PM BART limit for Martin Drake Units 5, 6, and 7. The 
State assumes the limits can be met with the operation of the current 
fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM BART determinations for Martin Drake Units 5, 6, and 7.

Summary of Colorado's BART Determinations

    Table 24 provides a summary of the State's BART determinations that 
we are proposing to approve.

                                    Table 24--Summary of the State's BART Determinations EPA Is Proposing To Approve
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                    Assumed particulate
           Emission unit               Assumed NOX control     NOX emission limit     Assumed SO2 control     SO2 emission limit    control and emission
                                              type                                            type                                         limit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cemex-Lyons Kiln...................  SNCR..................  255.3 lbs/hr (30-day    None.................  25.3 lbs/hr (12-month  Fabric Filter
                                                              rolling average)                               rolling average)       Baghouse * 0.275 lb/
                                                              901.0 tpy (12-month                            95.0 tpy (12-month     ton of dry feed 20%
                                                              rolling average).                              rolling average).      opacity.
Cemex-Lyons Dryer..................  None..................  13.9 tpy..............  None.................  36.7 tpy.............  Fabric Filter
                                                                                                                                    Baghouse * 22.8 tons/
                                                                                                                                    yr 10% opacity.

[[Page 18073]]

 
CENC Unit 4........................  LNBs with OFA.........  0.37 lb/MMBtu (30-day   None.................  1.0 lb/MMBtu (30-day   Fabric Filter
                                                              rolling average) Or                            rolling average).      Baghouse * 0.07 lb/
                                                              0.26 lb/MMBtu                                                         MMBtu.
                                                              Combined Average for
                                                              Units 4 & 5 (30-day
                                                              rolling average).
CENC Unit 5........................  LNBS with SOFA and      0.19 lb/MMBtu (30-day   None.................  1.0 lb/MMBtu (30-day   Fabric Filter
                                      SNCR.                   rolling average) Or                            rolling average).      Baghouse * 0.07 lb/
                                                              0.26 lb/MMBtu                                                         MMBtu.
                                                              Combined Average for
                                                              Units 4 & 5 (30-day
                                                              rolling average).
Comanche Unit 1....................  LNBs *................  0.20 lb/MMBtu (30-day   Lime Spray Dryer *...  0.12 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average) 0.15                          rolling average)       Baghouse * 0.03 lb/
                                                              lb/MMBtu (combined                             0.10 lb/MMBtu          MMBtu.
                                                              annual average for                             (combined annual
                                                              units 1 & 2).                                  average for units 1
                                                                                                             & 2).
Comanche Unit 2....................  LNBs*.................  0.20 lb/MMBtu (30-day   Lime spray Dryer *...  0.12 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average) 0.15                          rolling average)       Baghouse * 0.03 lb/
                                                              lb/MMBtu (combined                             0.10 lb/MMBtu          MMBtu.
                                                              annual average for                             (combined annual
                                                              units 1 & 2).                                  average for units 1
                                                                                                             & 2).
Craig Unit 1.......................  SNCR..................  0.28 lb/MMBtu (30-day   Wet Limestone          0.11 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       scrubber *.            rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
Craig Unit 2.......................  SCR...................  0.08 lb/MMBtu (30-day   Wet Limestone          0.11 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       scrubber *.            rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
Hayden Unit 1......................  SCR...................  0.08 lb/MMBtu (30-day   Lime Spray Dryer *...  0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
Hayden Unit 2......................  SCR...................  0.07 lb/MMBtu (30-day   Lime Spray Dryer *...  0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
Martin Drake Unit 5................  ULNBs with OFA........  0.31 lb/MMBtu (30-day   Dry Sorbent Injection  0.26 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
Martin Drake Unit 6................  ULNBs with OFA........  0.31 lb/MMBtu (30-day   Lime Spray Dryer or    0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       Equivalent Control     rolling average).      Baghouse * 0.03 lb/
                                                                                      Technology.                                   MMBtu.
Martin Drake Unit 7................  ULNBs with OFA........  0.29 lb/MMBtu (30-day   Lime Spray Dryer or    0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       Equivalent Control     rolling average).      Baghouse * 0.03 lb/
                                                                                      Technology.                                   MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Indicates controls that are already installed.

vii. PSCO BART Alternative
    Colorado has adopted the PSCO BART Alternative Program (BART 
alternative) to meet the requirements for BART for PSCO Cherokee Unit 
4, Valmont Unit 5, and Pawnee Station Unit 1 and RP for PSCO Arapahoe 
Units 3 and 4 and Cherokee Units 1, 2, and 3. Under 40 CFR 
51.308(e)(2), states may choose to meet the BART requirements with a 
BART alternative. Section 51.308(e)(2) specifies the requirements that 
a state must meet to show that the alternative measure or alternative 
program achieves greater RP than would be achieved through the 
installation and operation of BART. Section 51.308(e)(3) contains 
additional requirements that states must address pertaining to their 
alternative program. Table 25 provides a summary of the units covered 
under the BART alternative, as well as the required control or shutdown 
date for the facility.

                                                Table 25--Sources Covered Under the PSCO BART Alternative
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                       Particulate type
              Unit                 BART  eligible?     NOX control type   NOX emission uimit   SO2 control type   SO2 emission limit       and limit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cherokee Unit 1.................  No...............  Shutdown by 7/1/     0.................  Shutdown by 7/1/    0.................  Shutdown by 7/1/
                                                      2012.                                    2012.                                   2012.
Cherokee Unit 2.................  No...............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2011.                                    2011.                                   2011.
Cherokee Unit 3.................  No...............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2016.                                    2016.                                   2016.

[[Page 18074]]

 
Cherokee Unit 4.................  Yes..............  Natural Gas          0.12 lb/MMBtu (30-  Natural Gas         7.81 tpy (12 month  Fabric Filter
                                                      Operation by 12/31/  day rolling         Operation by 12/    rolling average).   Baghouse * 0.03
                                                      2017.                average) by 12/31/  31/2017.                                lb/MMBtu.
                                                                           2017.
Valmont Unit 5..................  Yes..............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2017.                                    2017.                                   2017.
Pawnee Unit 1...................  Yes..............  SCR **.............  0.07 lb/MMBtu (30-  Lime Spray Dryer    0.12 lb/MMBtu (30-  Fabric Filter
                                                                           day rolling         **.                 day rolling         Baghouse * 0.03
                                                                           average) by 12/31/                      average) by 12/31/  lb/MMBtu.
                                                                           2014.                                   2014.
Arapahoe Unit 3.................  No...............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2013.                                    2013.                                   2013.
Arapahoe Unit 4.................  No...............  Natural Gas          600 tpy (12 month   Natural Gas         1.28 tpy (12 month  Fabric Filter
                                                      Operation by 12/31/  rolling average)    operation by 12/    rolling average)    Baghouse * 0.03
                                                      2014.                by 12/31/2014.      31/2014.            by 12/31/2014.      lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Controls are already installed.
** The State assumes this is the control technology the source will use to meet the limit.

    A summary of Colorado's BART alternative and the requirements under 
40 CFR 51.308(e)(2) and (e)(3) are discussed below. The State's 
analysis of the PSCO BART alternative can be found in Chapter 6.4.3.7 
of the SIP.
i. A List of All BART-Eligible Sources
    Pursuant to 40 CFR 51.308(e)(2)(i)(A), the State included a list of 
all BART-eligible sources in the State in Chapter 6, Table 6-3 of the 
SIP. A list of BART-eligible sources can also be found in Table 2 of 
this notice.
ii. A List of All Sources Covered by the Alternative
    Pursuant to 40 CFR 51.308(e)(2)(i)(B), the State included in the 
SIP a list of the BART-eligible sources that are included in the BART 
alternative, as well as the RP sources covered under the program.
iii. Best System of Continuous Emission Control Technology
    As required by 40 CFR 51.308(e)(2)(i)(C), the State determined the 
best system of continuous emission control for sources that are subject 
to BART and that are covered by the BART alternative program. Because 
the State's BART alternative program was designed to meet requirements 
other than BART,\17\ our regulation allowed the State to use 
simplifying assumptions to determine the best system of continuous 
emission control for the BART sources in the State's BART alternative 
program. 40 CFR 51.308(e)(2)(i)(C); 71 FR 60619. We have indicated that 
our BART presumptive limits for SO<INF>2</INF> and NO<INF>X</INF>, set 
forth in our BART Guidelines (70 FR 39171-39172), represent appropriate 
simplifying assumptions for determining the best system of continuous 
emission control for EGUs. The presumptive limit for SO<INF>2</INF> is 
0.15 lb/MMBtu. The presumptive limits for NO<INF>X</INF> vary depending 
on boiler and coal type. The State used the presumptive limits in the 
BART Guidelines for calculating the best system of continuous emission 
control for the BART sources in the State's BART alternative program. 
The State also used the presumptive limits as a benchmark for control 
levels that might have been anticipated from the non-BART sources that 
are included in the BART alternative, if the State had not adopted the 
BART alternative.
---------------------------------------------------------------------------

    \17\ Specifically, the program was designed to help the State 
achieve its overarching reasonable progress goals and to meet the 
requirements of Colorado House Bill 10-1365 and Sec.  40-3.2-202, 
C.R.S.--Colorado's Clean Air-Clean Jobs Act.
---------------------------------------------------------------------------

iv. Projected Emissions Reductions
    Pursuant to 40 CFR 51.308(e)(2)(i)(D), the State provided a 
calculation of the emission reductions expected from the BART 
alternative compared to emissions reductions that would be achieved by 
the application of the presumptive limits to sources covered under the 
alternative. Tables 26 and 27 show the relative emissions.

           Table 26--SO2 Reductions Under the BART Alternative
------------------------------------------------------------------------
                                                    SO2
                                                 emissions       SO2
                                   SO2 average      with      emissions
               Unit                 emissions   presumptive   under BART
                                    2006-2008      limits    alternative
                                      (tpy)      (0.15 lb/     in 2018
                                                   MMBtu)       (tpy)
------------------------------------------------------------------------
Arapahoe Unit 3..................       924.97       328.51         0.00
Arapahoe Unit 4..................     1,764.70       640.93         1.28
Cherokee Unit 1..................     2,220.80       623.35         0.00
Cherokee Unit 2..................     1,888.37       418.95         0.00
Cherokee Unit 3..................       743.00       611.99         0.00
Cherokee Unit 4..................     2,135.43     1,953.57         7.81
Valmont Unit 5...................       758.47     1,029.19         0.00
Pawnee Unit 1....................    13,472.07     3,007.03     2,405.63
                                  --------------------------------------
    Total........................       23,908        8,614        2,415
------------------------------------------------------------------------


[[Page 18075]]


                               Table 27--NOX Reductions Under the BART Alternative
----------------------------------------------------------------------------------------------------------------
                                                    NOX average         NOX        NOX emissions   NOX emissions
                                                  emissions 2006-   presumptive        with         under BART
                      Unit                          2008 (tpy)      limit (lb/      presumptive   alternative in
                                                                      MMBtu)       limits (tpy)     2018 (tpy)
----------------------------------------------------------------------------------------------------------------
Arapahoe Unit 3.................................        1,770.47            0.23          503.71            0.00
Arapahoe Unit 4.................................        1,147.67            0.23          982.77          900.00
Cherokee Unit 1.................................        1,556.23            0.39        1,620.71            0.00
Cherokee Unit 2.................................        2,895.20            0.39        1,089.27            0.00
Cherokee Unit 3.................................        1,865.50            0.39        1,591.18            0.00
Cherokee Unit 4.................................        4,274.00            0.28        3,646.67        2,062.86
Valmont Unit 5..................................        2,313.73            0.28        1,921.15            0.00
Pawnee Unit 1...................................        4,537.73            0.23        4,610.78        1,403.28
                                                 ---------------------------------------------------------------
    Total.......................................          20,361  ..............          15,996           4,366
----------------------------------------------------------------------------------------------------------------

v. Evidence That the Alternative Program Achieves Greater RP Than BART
    Tables 26 and 27 demonstrate that the State's BART Alternative 
achieves greater RP than would be achieved through the installation of 
BART. By applying presumptive limits to the sources, the resulting 
emissions would be 8,614 tpy for SO<INF>2</INF> and 15,996 tpy for 
NO<INF>X</INF>. Under the BART alternative, the emissions from the 
sources in 2018 will be 2,415 tpy for SO<INF>2</INF> and 4,366 tpy for 
NO<INF>X</INF>. Thus, EPA concludes that the BART alternative achieves 
greater RP than would be achieved through the installation of BART and 
meets the requirements of 40 CFR 51.308(e)(2)(i)(E).
vi. All Emission Reductions Take Place During First Planning Period
    Pursuant to 40 CFR 51.308(e)(2)(ii), Table 25 shows that all 
controls under the BART alternative will occur by December 17, 2017, 
within the first planning period, which ends in December 2018.
vii. Reductions Are Surplus
    As required by 40 CFR 51.308(e)(2)(iv), the State has concluded 
that emission controls associated with the BART alternative have not 
been used for other SIP purposes and are only a requirement under the 
RH SIP. The State has thus determined they are surplus. EPA agrees with 
the State's assessment.
viii. Distribution of Emissions
    The State has determined that the distribution of emissions under 
the BART alternative is not substantially different than under source-
by-source BART or RP. The BART alternative includes only sources that 
are BART or RP sources and does not include any sources that would not 
have been included in the RH SIP. All of the units in the BART 
alternative are located within or adjacent to the 8-hour ozone non-
attainment area in the Front Range of Colorado. Pursuant to 40 CFR 
51.308(e)(3), since the State has determined that the geographic 
distribution of emissions is not substantially different under the 
alternative program, the State is not required to perform visibility 
modeling. We agree that the BART alternative will not result in a 
significant shift in the distribution of emissions.
    EPA is proposing to approve the State's BART alternative as it 
meets the requirements for alternative programs under 40 CFR 
51.308(e)(2) and (e)(3).

D. Reasonable Progress Requirements

    In order to establish RPGs for its Class I areas, and to determine 
the controls needed for the long-term strategy, Colorado followed the 
process established in the RHR. First, Colorado identified the 
anticipated visibility improvement in 2018 in all its Class I areas 
using the WRAP Community Multi-Scale Air Quality (CMAQ) modeling 
results. This modeling identified the extent of visibility improvement 
from the baseline by pollutant for each Class I area. The modeling 
relied on projected source emission inventories, which included 
enforceable Federal and State regulations already in place and 
anticipated BART controls.
    Colorado then identified sources and source categories (other than 
BART sources) in Colorado that are major contributors to visibility 
impairment and considered whether these sources should be controlled 
based on a consideration of the factors identified in the CAA and EPA's 
regulations. See CAA 169A(g)(1) and 40 CFR 51.308(d)(1)(i)(A).
    The SIP includes Colorado's analysis and conclusion that reasonable 
progress will be made by 2018, including an analysis of pollutant 
trends, emission reductions, and improvements expected. The RP 
discussion and analyses are included in Chapter 8 and Appendix D of the 
SIP. We are proposing to approve Colorado's submitted RP goals as 
described more fully below.
1. Visibility Impairing Pollutants and Sources
a. Source Regions of Pollutants
    In order to determine the significant sources contributing to haze 
in Colorado's Class I areas, Colorado relied upon two source 
apportionment analysis techniques developed by the WRAP. The first 
technique was regional modeling using the Comprehensive Air Quality 
Model (CAMx) and the PM Source Apportionment Technology (PSAT) tool, 
used for the attribution of sulfate and nitrate sources only. The 
second technique was the Weighted Emissions Potential (WEP) tool, used 
for attribution of sources of OC, EC, PM<INF>2.5</INF>, and 
PM<INF>10</INF>. The WEP tool is based on emissions and residence time, 
not modeling.
    PSAT uses the CAMx air quality model to show nitrate-sulfate-
ammonia chemistry and apply this chemistry to a system of tracers or 
``tags'' to track the chemical transformations, transport, and removal 
of NO<INF>X</INF> and SO<INF>2</INF>. These two pollutants are 
important because they tend to originate from anthropogenic sources. 
Therefore, the results from this analysis can be useful in determining 
contributing sources that may be controllable, both in-state and in 
neighboring states.
    WEP is a screening tool that helps to identify source regions that 
have the potential to contribute to haze formation at specific Class I 
areas. Unlike PSAT, this method does not account for chemistry or 
deposition. The WEP combines emissions inventories, wind patterns, and 
residence times of air

[[Page 18076]]

masses over each area where emissions occur, to estimate the percent 
contribution of different pollutants. Like PSAT, the WEP tool compares 
baseline values (2000-2004) to 2018 values, to show the improvement 
expected by 2018, for sulfate, nitrate, OC, EC, PM<INF>2.5</INF>, and 
PM<INF>10</INF>. More information on the WRAP modeling methodologies is 
available in the document Technical Support Document for Technical 
Products Prepared by the Western Regional Air Partnership (WRAP) in 
Support of Western Regional Haze Plans in the Supporting and Related 
Materials section of the docket. Table 28 shows Colorado's contribution 
to extinction at its own Class I areas. Sulfate and nitrate 
contribution is based on PSAT results and OC, EC, PM<INF>2.5,</INF> 
PM<INF>10</INF>, and sea salt contributions are based on WEP.

                 Table 28--Colorado Sources Extinction Contribution 2000-2004 for 20% Worst Days
----------------------------------------------------------------------------------------------------------------
                                                                                                    CO sources
                                                                     2000-2004        Species      contribution
             Class I area                   Pollutant species     extinction (Mm-  contribution     to species
                                                                        1)           to  total      extinction
                                                                                  extinction (%)      (%) \1\
----------------------------------------------------------------------------------------------------------------
GRSA1 (Great Sand Dunes National park   Sulfate.................            5.97            21.1            13.0
 and Preserve).                         Nitrate.................            1.96             6.9            14.7
                                        OC......................            8.47            30.0            34.8
                                        EC......................            1.74             6.2            39.1
                                        PM2.5...................            2.81            10.0            34.9
                                        PM10....................            7.24            25.6            37.7
                                        Sea Salt................            0.05             0.2               *
MEVE1 (Mesa Verde National Park)......  Sulfate.................            6.46            19.9             2.0
                                        Nitrate.................            2.30             7.1            10.4
                                        OC......................           12.28            37.8            35.4
                                        EC......................            2.37             7.3            35.4
                                        PM2.5...................            2.51             7.7            19.0
                                        PM10....................            6.52            20.1            15.3
                                        Sea Salt................            0.04             0.1               *
MOZI1 (Mount Zirkel and Rawah           Sulfate.................            5.25         22.69.3            26.9
 Wilderness Area).                      Nitrate.................            2.16                            39.7
                                        OC......................            9.94            42.7            90.7
                                        EC......................            1.76             7.6            87.9
                                        PM2.5...................            0.98             4.2            51.8
                                        PM10....................            3.15            13.5            48.5
                                        Sea Salt................            0.02             0.1               *
RMHQ1 (Rocky Mountain National Park)..  Sulfate.................            7.91            24.3            31.3
                                        Nitrate.................            5.26            16.2            37.8
                                        OC......................           10.51            32.3            77.4
                                        EC......................            2.56             7.9            77.1
                                        PM2.5...................            1.37             4.2            49.9
                                        PM10....................            4.90            15.1            52.2
                                        Sea Salt................            0.01             0.0               *
WEMI1 (Weminuche Wilderness, Black      Sulfate.................            4.99            23.9             5.0
 Canyon of the Gunnison, and La Garita  Nitrate.................            1.21             5.8             5.0
 Wilderness).
                                        OC......................            8.29            39.7            47.7
                                        EC......................            2.01             9.6            45.1
                                        PM2.5...................            1.26             6.0            20.7
                                        PM10....................            2.99            14.3            18.4
                                        Sea Salt................            0.13             0.6  ..............
WHRI1 (Eagles Nest Wilderness, Flat     Sulfate.................            4.79            24.3             6.5
 Tops Wilderness, Maroon Bells--        Nitrate.................            1.31             6.6            20.0
 Snowmass Wilderness, and West Elk      OC......................            7.83            39.7            60.6
 Wilderness).
                                        EC......................            1.76             8.9            61.1
                                        PM2.5...................            1.18             6.0            39.7
                                        PM10....................            2.82            14.3            35.8
                                        Sea Salt................            0.02             0.1               *
----------------------------------------------------------------------------------------------------------------
* Not modeled by the WRAP.

    Table 29 shows influences from sources both inside and outside of 
Colorado per the PSAT modeling for 2018. As indicated, boundary 
conditions or outside domain are the highest contributor to sulfate at 
all Colorado Class I areas. The boundary conditions represent the 
background concentrations of pollutants that enter the edge of the 
modeling domain. Depending on meteorology and the type of pollutant 
(particularly sulfate), these emissions can be transported great 
distances that can include regions such as Canada, Mexico, and the 
Pacific Ocean.
    Colorado appears to be a major contributor of particulate sulfate 
at those Class I areas near significant sources of SO<INF>2</INF>, 
specifically Rocky Mountain National Park, Mount Zirkel, and Rawah 
Wilderness. For nitrate, Colorado appears to be a major contributor at 
most of its Class I areas except for the Weminuche Wilderness, La 
Garita Wilderness, and Black Canyon of Gunnison National Park. Boundary 
conditions are also a major contributor of nitrate at all Colorado 
Class I areas.
---------------------------------------------------------------------------

    \18\ OD denotes Outside Domain; MEX denotes the country of 
Mexico; CEN denotes the Central Regional Air Partnership; PO denotes 
Pacific Offshore.

[[Page 18077]]



                          Table 29--PSAT Source Region Apportionment for 20% Worst Days
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
Class I Area:                                           2018 Sulfate PSAT
                                           2018 Nitrate PSAT
----------------------------------------------------------------------------------------------------------------
    GRSA1 (Great Sand Dunes    Region \18\.....  OD       CO      NM      MEX     OD      NM      CO      CEN
     National Park and
     Preserve).
                               % Contribution..  38.2     9.7     8.1     7.9     28.9    27.2    12.3    8.8
    MEVE1 (Mesa Verde          Region..........  OD       NM      MEX     AZ      NM      CO      OD      AZ
     National Park).
                               % Contribution..  35.4     17.2    11.3    10.2    60.2    12.3    9.7     9.7
    MOZI1 (Mount Zirkel and    Region..........  OD       CO      WY      UT      CO      OD      UT      WY
     Rawah Wilderness Area).
                               % Contribution..  29.3     20.9    9.2     7.6     41.6    17.8    14.1    10.3
    RMHQ1 (Rocky Mountain      Region..........  OD       CO      WY      CEN     CO      OD      WY      UT
     National Park).
                               % Contribution..  29.1     23.5    7.7     7.2     33.7    15.8    11.0    5.9
    WEMI1 (Weminuche           Region..........  OD       NM      MEX     PO      NM      OD      CA      AZ
     Wilderness, Black Canyon
     of the Gunnison, and La
     Garita Wilderness).
                               % Contribution..  34.9     13.2    10.7    9.1     43.7    19.7    14.1    9.9
    WHRI1 (Eagles Nest         Region..........  OD       MEX     AZ      NM      OD      UT      CO      NM
     Wilderness, Flat Tops
     Wilderness, Maroon
     Bells--Snowmass
     Wilderness, and West Elk
     Wilderness).
                               % Contribution..  40.1     10.8    6.8     6.1     55.0    20.0    15.0    10.0
----------------------------------------------------------------------------------------------------------------

b. Source Categories
    The State conducted a detailed evaluation of six visibility 
impairing pollutants: nitrates, sulfates, OC, EC, fine soil and coarse 
mass (CM) (fine soil and CM are collectively known as PM) contributing 
to visibility impairment at Colorado's Class I areas.\19\ The State 
relied on WRAP emission inventory information and modeling to determine 
what pollutants and sources were contributing to visibility impairment 
at its Class I areas. Once the State determined what sources were 
contributing to visibility impairment and by what amount, it determined 
whether the source/source category was significant and if it was 
reasonable to control.
---------------------------------------------------------------------------

    \19\ See Significant Source Categories Contributing to Regional 
Haze at Colorado Class I Areas, October 2, 2007, located in the 
Supplemental and Related Materials section of the docket.
---------------------------------------------------------------------------

    Based on its analysis, the State determined that the sources of OC, 
EC, and area source PM are not well documented because of emission 
inventory limitations associated with natural sources (predominantly 
wildfires), uncertainty of windblown emissions, and poor model 
performance for these constituents. The State determined it would defer 
on addressing these pollutants until science and emission inventories 
are improved for consideration in future RH SIPs. The State determined 
that RP controls would be evaluated for SO<INF>2</INF>, NO<INF>X</INF>, 
and stationary source PM.
    The State's analysis evaluated the projected sources of 
SO<INF>2</INF> and NO<INF>X</INF> in 2018. The State's analysis shows 
that 78% of 2018 total statewide SO<INF>2</INF> emissions are from 
point sources, mainly coal-fired boilers. Area source SO<INF>2</INF> 
emissions (14% of total SO<INF>2</INF> emissions) are mainly comprised 
of thousands of small commercial boilers and internal combustion 
engines spread throughout the State that burn distillate fuel. The 
State determined there is no practical way to control thousands of 
small boilers and engines. The State determined SO<INF>2</INF> 
emissions from natural fires constitute 6% of total SO<INF>2</INF> 
emissions and are considered uncontrollable. Both off-road and on-road 
mobile sources each constitute 1% of SO<INF>2</INF> emissions and are 
subject to federal ultra-low sulfur diesel fuel requirements that limit 
sulfur content to 15 ppm. Ultra-low sulfur diesel fuel was in 
widespread use after June 2010 for off-road mobile sources and after 
June 2006 for on-road mobile sources. The State has determined that 
point sources are the dominant source of emissions and, for this 
planning period, the only practical category to evaluate under RP for 
SO<INF>2</INF>.
    Colorado's analysis shows that point sources comprise 36% of total 
NO<INF>X</INF> emissions; these emissions are primarily from coal-fired 
external combustion boilers and natural gas-fired internal combustion 
engines (in oil and gas compression service). On-road and off-road 
mobile sources comprise 16% and 14% of Statewide NO<INF>X</INF> 
emissions, respectively. Because mobile exhaust emissions are primarily 
addressed, and will continue to be addressed, through federal programs, 
the State did not evaluate mobile sources for RP control in this 
planning period. Emissions of NO<INF>X</INF> from biogenic activity and 
natural fire are considered uncontrollable and vary from year-to-year. 
Non-oil and gas area sources comprise about 6% of NO<INF>X</INF> 
emissions and involve thousands of combustion sources that the State 
determined are not reasonable to control in this planning period. Area 
oil and gas emissions contribute 12% of total NO<INF>X</INF> emissions.
    The State has determined that large point sources are the dominant 
source of NO<INF>X</INF> emissions and are practical to evaluate under 
RP in this planning period. The State determined that smaller point 
sources (combustion turbines) and area oil and gas emissions, 
specifically heater-treaters and reciprocating internal combustion 
engines (RICE), significantly contribute to visibility impairment in 
Colorado's Class I areas and are also practical to evaluate for RP 
controls in this planning period.
c. Stationary Sources
    The State used a RP screening methodology called ``Q/d'' to 
determine which stationary (point) sources would be candidates for 
controls under RP. The methodology Q/d is a calculated ratio that 
evaluates stationary source emissions (mathematical sum of actual 
SO<INF>2</INF>, NO<INF>X</INF> and PM emissions in tons per year, 
denoted as ``Q'') divided by the distance (in kilometers, denoted as 
``d'') of the point source from the nearest Class I area. The State 
evaluated the visibility impact sensitivity of different Q/d thresholds 
and determined that a Q/d ratio equal to or greater than 20 
approximated a delta dv impact ranging from 0.06 dv to 0.56 dv. The 
resultant average of the range is about 0.3 dv, which is a more 
conservative RP threshold than the 0.5 dv that was used in determining 
which sources would be subject-to-BART under the federal BART 
regulations. Since the threshold is more conservative than the subject-
to-BART threshold, the State determined that a Q/d value of 20 is 
reasonable for determining which RP sources the State should consider 
for RP controls.

[[Page 18078]]

    The evaluation of potential RP sources involved all Colorado 
stationary sources with actual SO<INF>2</INF>, NO<INF>X</INF>, or 
PM<INF>10</INF> emissions over 100 tpy in 2007. The State identified 
113 sources as exceeding the 100 tpy threshold for any of the three 
pollutants and further analyzed these sources using the Q/d analysis. 
The State determined that there were seven sources that had a Q/d equal 
to or greater than the threshold of 20 that were not already being 
controlled under BART.\20\ The State deemed these seven sources to be 
subject to RP and the State completed a RP analysis for each of the 
sources.
---------------------------------------------------------------------------

    \20\ The State has concluded that it need not reanalyze a source 
for RP controls for which it has already made a BART determination. 
This conclusion is consistent with our RP guidance.
---------------------------------------------------------------------------

    Table 30 shows the subject-to-RP sources identified by the State.

               Table 30--RP Sources Evaluated for Controls
------------------------------------------------------------------------
                                   Q  (tpy
                                   based on
             Source                  2007      Nearest Class I     Q/d
                                    actual           area         value
                                  emissions)
------------------------------------------------------------------------
Platte River Power Authority--         2,796  Rocky Mountain        49.9
 Rawhide Station.                              National Park.
CENC--Unit 3...................        4,453  Rocky Mountain        81.7
                                               National Park.
CSU-Nixon Power Plant--Nixon           6,668  Great Sand Dunes      63.9
 Unit 1.                                       National Park.
Black Hills Energy Clark Power         2,393  Great Sand Dunes      40.8
 Plant Units 1 and 2.                          National Park.
Holcim--Kiln and Dryer.........        3,250  Great Sand Dunes      49.2
                                               National Park.
Tri-State--Nucla...............        3,327  Black Canyon          47.1
                                               National Park.
Tri-State--Craig Unit 3........       20,628  Flat Tops            432.4
                                               Wilderness Area.
PSCO--Cameo Station............        3,750  Black Canyon          53.2
                                               National Park.
------------------------------------------------------------------------

    We agree with the State's analysis on appropriate source categories 
and stationary sources to be evaluated under RP.
2. Four Factor Analyses
    In determining the measures necessary to make RP, states must take 
into account the following four factors and demonstrate how they were 
taken into consideration in selecting RP goals for a Class I area:
    <bullet> Costs of Compliance;
    <bullet> Time Necessary for Compliance;
    <bullet> Energy and Non-air Quality Environmental Impacts of 
Compliance; and
    <bullet> Remaining Useful Life of any Potentially Affected Sources. 
CAA Sec.  169A(g)(1) and 40 CFR 308(d)(1)(i)(A).
    The State performed a four factor analysis for each of the RP 
sources pursuant to 40 CFR 51.308(d)(1)(i)(A).

State NOX Control Criteria

    For potential NO<INF>X</INF> controls in the RP context, the State 
adopted the same screening criteria as used to evaluate potential 
NO<INF>X</INF> BART controls. For further detail, see section V.C.3 
above. We have some of the same concerns regarding the use of these 
criteria for RP as we expressed concerning their use in BART 
determinations. Nonetheless, as discussed below, we agree with the 
State's determinations concerning NO<INF>X</INF> controls on the RP 
sources.

SO2 Controls--Wet and Dry Scrubbing

    As it did in the BART context, the State eliminated wet FGD from 
consideration as a potential RP control for the same reasons--because 
of negative non-air quality environmental impact on water usage. EPA is 
proposing that the State has provided adequate justification to 
eliminate wet FGD as a potential SO<INF>2</INF> RP control.
a. Visibility Improvement Modeling
    Colorado concluded that it is also appropriate to consider a fifth 
factor for evaluating potential RP control options--the degree of 
visibility improvement that may reasonably be anticipated from the use 
of the RP controls. Our RP guidance contemplates that states may be 
able to consider other relevant factors for RP sources (see EPA's 
Guidance for Setting Reasonable Progress Goals under the Regional Haze 
Program, (``Reasonable Progress Guidance''), pp. 2-3, July 1, 2007), 
and we find it appropriate to consider visibility improvement when 
evaluating potential RP controls.
    For the RP modeling, the State followed the BART Guidelines. 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 the potential BART control technology 
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 RP for the subject-to-RP sources.
    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 RP 
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 Supplemental 
Information 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 RP Determinations and Limits
    For the subject-to-RP sources, the State provided analyses that 
took into consideration the four factors as required by section 
169A(g)(1) of the CAA. The State also included visibility improvement 
as a fifth factor in its RP analyses for most sources. The State 
elected to consider EPA's BART Guidelines as relevant to its RP 
evaluations, in addition to EPA's Reasonable Progress Guidance. A 
summary of the RP analysis for each source is included in Chapter 8 of 
the SIP. The State's complete RP analyses, as well as additional 
technical information and materials, are included in Appendix D of the 
SIP. EPA is

[[Page 18079]]

proposing to approve the RP determinations submitted by the State for: 
Platte River Power Authority (PRPA), Rawhide Unit 101; CENC Unit 3; CSU 
Nixon Power Plant, Nixon Unit 1; Black Hills Energy Clark Power Plant, 
Units 1 and 2; Holcim Florence Cement Plant; Tri-State Generation, 
Nucla; Tri-State Generation, Craig Unit 3; and PSCO Cameo Station. A 
summary of the RP determination for each source is provided below.
i. Platte River Power Authority--Rawhide Unit 101

Background

    The PRPA Rawhide Energy Station is located in Larimer County 
approximately 10 miles north of the town of Wellington, Colorado. 
Rawhide Unit 101 is a coal-fired steam-driven EGU with a rated electric 
generating capacity of 305 MW (gross). The Rawhide Station also has 
five natural-gas-fired combustion turbines. The primary use of these 
units is to meet PRPA's energy reliability and peak load requirements. 
The turbines operate on limited, intermittent, and unpredictable 
schedules as peak loading units. Additionally, the facility includes a 
number of fugitive dust sources. The State did not do a RP analysis for 
the turbines or fugitive dust sources since these units fall below the 
de minimis threshold established by the State.\21\ Unit 101 is the only 
subject-to-RP unit at the facility. The State's RP determination can be 
found in Chapter 8.5.2.1 and Appendix D of the SIP.
---------------------------------------------------------------------------

    \21\ For the purposes of evaluating RP, the State has elected to 
set de minimis thresholds for any emission unit at a subject-to-RP 
source with actual baseline emissions of SO<INF>2</INF>, 
NO<INF>X</INF>, or PM<INF>10</INF> less than the federal Prevention 
of Significant Deterioration (PSD) significance levels. These de 
minimis levels are as follows: NOx--40 tons per year; 
SO<INF>2</INF>--40 tons per year; PM<INF>10</INF>--15 tons per year. 
Any unit emitting below these levels is not subject to an RP 
analysis. The BART Guidelines allow for states to set de minimis 
levels (see 70 FR 39161), and we think it was reasonable for the 
State to set de minimis levels for RP sources.
---------------------------------------------------------------------------

SO2 RP Determination

    Rawhide Unit 101 is currently controlled with a dry FGD achieving 
over 72 percent SO<INF>2</INF> reduction with a current permit limit of 
0.09 lb/MMBtu (annual average). Per the BART Guidelines, for EGUs with 
preexisting post-combustion SO<INF>2</INF> controls achieving removal 
efficiencies greater than 50 percent, states should consider cost 
effective scrubber upgrades designed to improve the system's overall 
SO<INF>2</INF> removal efficiency (70 FR 39171). Under the BART 
Guidelines, a state is not required to evaluate the replacement of the 
current SO<INF>2</INF> controls if the removal efficiency is over 50% 
(70 FR 39171). We conclude that it is reasonable to follow this 
approach for evaluating potential RP controls in this initial planning 
period. Colorado should consider replacement of existing scrubbers in 
future planning periods. The State's RP analysis evaluated numerous dry 
FGD upgrades including: (1) Use of performance additives; (2) use of 
more reactive sorbent; (3) increase the pulverization level of sorbent; 
and (4) engineering redesign of atomizer or slurry injection system. 
The State analyzed each possible upgrade and determined that all were 
technically infeasible for Rawhide Unit 101. The State determined that 
fuel switching from coal to natural gas was a technically feasible 
option for Rawhide Unit 101.
    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 SO<INF>2</INF> emissions are 913 tpy based on an average 
of 2006-2008 actual emissions. A summary of the State's SO<INF>2</INF> 
RP analysis and the visibility impacts for fuel switching is provided 
in Table 31 below.

                              Table 31--Summary of Rawhide Unit 101 SO2 RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                                                                    Visibility
                                   Emission rate                                                    improvement
                                    (lb/MMBtu)       Emission                          Cost        (delta dv for
       Control technology             (30-day        Reduction      Annualized     effectiveness    the maximum
                                      rolling          (tpy)           costs          ($/ton)          98th
                                     average)                                                       percentile
                                                                                                      impact)
----------------------------------------------------------------------------------------------------------------
Fuel Switching..................            0.00             906    $237,424,331        $262,169            0.87
----------------------------------------------------------------------------------------------------------------

    The State determined it would take PRPA approximately 2-3 years to 
switch from coal to natural gas. The State determined fuel switching 
was not reasonable based on the high cost effectiveness value.
    The State also assessed emissions limit tightening based on current 
operations. Rawhide Unit 101's average 30-day rolling emission rate 
during the baseline period (2006-2008) was 0.09 lb/MMBtu. The maximum 
30-day rolling emission rate during this period was 0.11 lb/MMBtu. The 
State evaluated both these levels as potential emissions limits. The 
State also evaluated an emission limit of 0.07 lb/MMBtu. Emissions 
limit tightening to emissions levels currently achieved is a no-cost 
control option. The State modeled visibility improvement for 
SO<INF>2</INF> emission limits lower than 0.11 lb/MMBtu. The modeling 
showed that, compared to an emission limit of 0.11 lb/MMBtu, an 
emission limit of 0.09 lb/MMBtu would result in 0.01 dvs of visibility 
improvement, and an emission limit of 0.07 lb/MMBtu would result in 
0.03 dvs of visibility improvement.
    The State has determined that the SO<INF>2</INF> RP emission limit 
for Rawhide Unit 101 is 0.11 lb/MMBtu (30-day rolling average), 
reflecting the actual performance of the current controls. It 
represents a more stringent limit than the current limit of 0.13 lb/
MMBtu (30-day rolling average). The State assumes the RP limit can be 
achieved by the operation of the current LSD. The State determined a 
lower SO<INF>2</INF> limit was not reasonable as it would not result in 
significant visibility improvement (less than 0.02 dv) and would likely 
result in frequent non-compliance events.
    We agree with the State's conclusions, and we are proposing to 
approve its SO<INF>2</INF> RP determination for PRPA Rawhide Unit 101.

NOX RP Determination

    Rawhide Unit 101 is currently controlled with LNB+ close coupled 
over fire air + SOFA achieving a 49.6% control. The State determined 
that enhanced combustion controls (ECC), SNCR, fuel switching from coal 
to natural gas, and SCR were technically feasible NO<INF>X</INF> 
controls for Rawhide Unit 101. The State determined that RRI, ECO, and 
coal reburn + SNCR were not technically feasible.
    The State did not identify any energy or non-air quality 
environmental

[[Page 18080]]

impacts that would preclude the selection of any of the controls 
evaluated, nor are there any remaining-useful-life issues for this 
source. Baseline NO<INF>X</INF> emissions are 1,866 tpy based on an 
average of 2006-2008 actual emissions. A summary of the State's 
NO<INF>X</INF> BART analysis and the visibility impacts is provided in 
Table 32 below. The emission rate for each control option in the table 
is reflective of the 30-day rolling average contained in the State's RP 
analysis.

                                                  Table 32--Summary of Rawhide Unit 101 NOX RP 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ECC.....................................................              24           0.145             448        $288,450            $644            0.45
SNCR....................................................              27           0.140             504       1,596,000           3,168            0.46
Fuel Switching..........................................              29           0.135             545     237,424,331         435,681            0.47
SCR.....................................................            63.5             .07           1,185      12,103,000          10,214            0.59
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State estimates that the time necessary for compliance after 
SIP approval would be approximately 2-3 years for SNCR and 3-4 years 
for SCR. ECC could be functional within 6 months of SIP approval.
    The State eliminated switching to natural gas and SCR from 
consideration due to the high cost effectiveness values and associated 
degree of visibility improvement. The State determined that ECC was 
reasonable for RP control. The State made this determination based on 
the cost effectiveness and visibility improvement associated with ECC. 
SNCR would achieve similar emissions reductions to ECC and would afford 
a minimal additional visibility benefit (0.01 delta dv), but it would 
do so at a significantly higher dollar-per-ton control cost compared to 
the selected ECC. Thus, the State determined that SNCR was not 
reasonable. Based upon its consideration of the five factors that it 
used for RP, the State determined that the NO<INF>X</INF> RP emission 
limit for Rawhide Unit 101 is 0.145 lb/MMBtu (30-day rolling average). 
The State assumes that the RP emission limit can be achieved through 
the operation of ECC.
    We agree with the State's conclusions, and we are proposing to 
approve its NO<INF>X</INF> RP determination for PRPA Rawhide Unit 101.

PM RP Determination

    Rawhide Unit 101 is 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 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. The State did not 
provide a full four-factor analysis plus visibility improvement 
modeling because the State determined RP to be the most stringent 
control technology and limit.
    The State has determined that the PM RP emission limit for Rawhide 
Unit 101 is 0.03 lb/MMBtu (30-day rolling average). The State assumes 
that the emission limit can be achieved through the operation of the 
existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for PRPA Rawhide Unit 101.
ii. CENC Boiler 3

Background

    The CENC facility includes five coal-fired boilers (Boilers 1-5) 
that supply steam and electrical power to Coors Brewery. Of these five 
Boilers, Boilers 4 and 5 are subject to BART and Boiler 3 is subject to 
RP. Boiler 3 is a 225 MMBtu/hr boiler. The State did not evaluate 
Boiler 1, Boiler 2, or fugitive dust sources at the facility for RP 
controls since emissions from these units were below the State's de 
minimis levels. The State's RP determination for CENC Boiler 3 can be 
found in Chapter 8.5.2.2 and Appendix D of the SIP.

SO2 RP Determination

    CENC Boiler 3 is currently uncontrolled for SO<INF>2</INF>. The 
State determined that DSI and fuel switching to natural gas were 
technically feasible for reducing SO<INF>2</INF> emissions from Boiler 
3. The State determined that dry FGD is not technically feasible for 
Boiler 3 due to space constraints onsite. Boiler 3's load range varies 
from low loads (ready to respond in the event of a malfunction in 
Boiler 4 or Boiler 5), medium loads (increased customer steam loads) to 
high loads (during Boiler 4 or Boiler 5 overhauls). The load range 
varies within the month and has patterns throughout the year. Because 
of the varying loads, the State has reasoned that a longer-than-three-
year average of emissions is needed to determine baseline emissions. 
The State determined that a baseline average from 2000-2008 represents 
a reasonable depiction of actual emissions from this unit.
    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. The baseline SO<INF>2</INF> emissions are 257 tpy. A 
summary of the State's SO<INF>2</INF> RP analysis is provided in Table 
33 below. The emission rate for each control option in the table is 
reflective of the 30-day rolling average contained in the State's RP 
analysis.

[[Page 18081]]



                               Table 33--Summary of CENC Boiler 3 SO2 RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                   Emission rate
                                      Control       (lb/MMBtu)       Emission                          Cost
       Control technology           efficiency        (30-day        reduction      Annualized     effectiveness
                                        (%)           rolling          (tpy)           costs          ($/ton)
                                                     average)
----------------------------------------------------------------------------------------------------------------
DSI.............................              60            0.11             147      $1,340,661          $9,114
Fuel Switching..................             100            0.00             245       1,428,911           5,828
----------------------------------------------------------------------------------------------------------------

    The State determined it would take CENC five years after SIP 
approval to install any controls.
    The State used modeling results from CENC Boiler 4 to determine the 
projected visibility improvement for Boiler 3 because the units are 
similar and located at the same facility. CALPUFF modeling indicates a 
0.08 dv improvement for DSI applied to Boiler 4. DSI controls for 
Boiler 4 would reduce SO<INF>2</INF> emissions by approximately 268 
tons per year. DSI controls for Boiler 3 would reduce SO<INF>2</INF> 
emissions by about 147 tons per year. Fuel switching to natural gas 
would reduce SO<INF>2</INF> emissions by an estimated 245 tons 
annually. The State inferred that either control applied to Boiler 3 
would yield visibility improvements of less than 0.10 dv.
    The State determined that fuel switching and DSI were not 
reasonable to select as RP controls due to the high cost effectiveness 
values and low visibility improvement associated with these controls. 
Based on a fuel analysis, the State determined that the maximum 
SO<INF>2</INF> emissions rate from 2000-2010 is 0.99 lb/MMBtu. In 
establishing an RP emission limit, the State determined a 20% 
contingency factor is warranted for CENC Boiler 3 due to the different 
load factors discussed above. Based upon its consideration of the five 
factors that it used for RP, the State has determined that the 
SO<INF>2</INF> RP emission limit for CENC Boiler 3 is 1.2 lbs/MMBtu 
(annual average).
    We agree with the State's conclusions, and we are proposing to 
approve its SO<INF>2</INF> RP determination for CENC Boiler 3.

NOX RP Determination

    The State determined that flue gas recirculation (FGR), SNCR, ROFA, 
fuel switching to natural gas, and three options for SCR (regenerative 
SCR (RSCR), high temperature SCR (HTSCR), and low temperature SCR 
(LTSCR)) were technically feasible for reducing NO<INF>X</INF> 
emissions at CENC Boiler 3. The State determined that LoTOx\TM\, ECO, 
RRI, and coal reburn plus SNCR were not technically feasible. The State 
determined that because CENC Boiler 3 is a coal stoker boiler, LNBs are 
also 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. A summary of the State's NO<INF>X</INF> RP analysis is 
provided in Table 34 below. Baseline NO<INF>X</INF> emissions are 205 
tpy. The emission rate for each control option in the table is 
reflective of the 30-day rolling average contained in the State's RP 
analysis.

                               Table 34--Summary of CENC Boiler 3 NOX RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                   Emission rate
                                      Control       (lb/MMBtu)       Emission                          Cost
       Control technology           efficiency        (30-day        reduction      Annualized     effectiveness
                                        (%)           rolling          (tpy)           costs          ($/ton)
                                                     average)
----------------------------------------------------------------------------------------------------------------
FGR.............................              20            0.17              34      $1,042,941         $30,292
SNCR............................              30            0.15              51         513,197          10,146
Fuel Switching..................              35            0.14              84       1,428,911          16,950
ROFA w/Rotamix..................              57            0.09              77         978,065           9,496
RSCR............................              75            0.05              96         978,065          10,160
HTSCR...........................              86            0.03             126       1,965,929          15,651
LTSCR...........................              86            0.03             145       2,772,286          19,187
----------------------------------------------------------------------------------------------------------------

    The State estimates that the source would need at least five years 
after SIP approval to install the control equipment.
    The State used modeling results from CENC Boiler 4 to determine the 
projected visibility improvement for Boiler 3 since the units are 
similar and located at the same facility. CALPUFF modeling indicates a 
0.12 dv improvement for LNB + SOFA + SNCR applied to Boiler 4. LNB + 
SOFA + SNCR controls for Boiler 4 would reduce NO<INF>X</INF> emissions 
by approximately 368 tons per year. The highest performing SCR controls 
for Boiler 3 would reduce NO<INF>X</INF> emissions by about 145 tons 
per year. Based on this information, the State has inferred that any 
control applied to Boiler 3 would yield visibility improvements of less 
than 0.12 dv. The State determined that none of the evaluated controls 
were reasonable because of the high cost effectiveness values and low 
visibility improvement for each of the controls.
    Based on a review of historical load characteristics of this 
boiler, the State determined that RP for Boiler 3 is an annual 
NO<INF>X</INF> limit based on 50% annual capacity utilization using the 
maximum capacity year in the last decade. Included in this annual 
capacity utilization, there is a 20% contingency factor for reasons 
explained above. The State determined that the NO<INF>X</INF> RP 
emission limit for Boiler 3 is 246 tons/year (12-month rolling total).
    We agree with the State's conclusions, and we are proposing to 
approve its NO<INF>X</INF> RP determination for CENC Boiler 3.

PM RP Determination

    CENC Boiler 3 is equipped with a fabric filter baghouse 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 RP for Boiler 3 is an emission limit of 0.07 lb/MMBtu.

[[Page 18082]]

The State assumes the RP 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 RP limit of 0.07 lb/MMBtu, we are 
proposing to approve the State's PM RP determination for CENC Boiler 3. 
Based on our review/analysis, it appears 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 to a value below 0.07 lb/MMBtu would be 
insignificant. Under these circumstances, we are proposing to find that 
the State's RP determination was reasonable.
    We find that an emission limit of 0.07 lb/MMBtu is reasonable, as a 
lower emission limit would not result in significant visibility 
improvement. Thus, we are proposing to approve the State's PM RP 
determination for CENC Boiler 3.
iii. CSU--Nixon Unit 1

Background

    The Nixon facility is located in Fountain, Colorado. This facility 
consists of one coal fired boiler (Unit 1), an auxiliary boiler, the 
associated equipment needed for generating electricity, and two 
natural-gas-fired simple cycle combustion turbines driving electricity 
generators. The facility also includes the various processes necessary 
to handle the coal, flyash and bottom ash. The State determined that 
Unit 1 and the two combustion turbines were subject to RP. The State 
determined the rest of the units at this facility had emissions below 
the de minimis thresholds set by the State. The boiler is a 227 MW unit 
with a pulverized-coal, dry-bottom, front-fired boiler that fires low 
sulfur western coal as the primary fuel. It can currently use No. 2 
distillate oil or natural gas for an ignition fuel. The State's RP 
determination can be found in Chapter 8.5.2.3 and Appendix D of the 
SIP. The analysis for the combustion turbines can be found in section 
V.D.2.b.x of this notice.

SO2 RP Determination

    Nixon Unit 1 is currently uncontrolled for SO<INF>2</INF>. The 
State determined that DSI and dry FGD were technically feasible for 
reducing SO<INF>2</INF> emissions from Nixon Unit 1. 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 SO<INF>2</INF> RP analysis is provided in Table 35 below. 
Baseline SO<INF>2</INF> emissions are 4,121 tpy based on the average of 
2006-2008 actual emissions. The emission rate for each control option 
in the table is reflective of the 30-day rolling average contained in 
the State's RP analysis.

                                                    Table 35--Summary of Nixon Unit 1 SO2 RP 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI--Trona..............................................              60            0.19           2,473      $9,438,692          $1,997            0.44
Dry FGD.................................................              78            0.11           3,215      12,036,604           3,744            0.46
Dry FGD.................................................              85            0.08           3,392      13,399,590           3,950            0.50
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State estimates it would take 3-5 years after SIP approval for 
the source to install controls on Nixon Unit 1.
    The State determined that dry FGD was reasonable for RP control for 
Nixon Unit 1. Based upon its consideration of the five factors that it 
used for RP, the State determined that the SO<INF>2</INF> RP emission 
limit for CSU Nixon Unit 1 is 0.11 lb/MMBtu (30-day rolling average). 
The State assumes that the emission limit can be achieved with dry FGD. 
The State determined that a lower emissions limit (85% control 
efficiency) for Unit 1 was not reasonable as increased control costs to 
achieve such an emissions rate would not provide appreciable 
incremental improvements in visibility (0.04 delta dv).
    We agree with the State's conclusions, and we are proposing to 
approve its SO<INF>2</INF> RP determination for CSU Nixon Unit 1.

NOX RP determination

    Nixon Unit 1 is currently controlled for NO<INF>X</INF> emissions 
with LNBs. The State determined ULNB, OFA, SNCR, SNCR plus ULNB, and 
SCR were technically feasible for reducing NO<INF>X</INF> emissions at 
Nixon Unit 1. The State determined ECO, RRI, 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. A summary of the State's NO<INF>X</INF> RP analysis is 
provided in Table 36 below. Baseline NO<INF>X</INF> emissions are 2,356 
tpy based on the average of 2006-2008 actual emissions. The emission 
rate for each control option in the table is reflective of the 30-day 
rolling average contained in the State's RP analysis.

                                                    Table 36--Summary of Nixon Unit 1 NOX RP 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ULNBs...................................................              20            0.24             471        $567,000          $1,203            0.15
OFA.....................................................              25            0.22             589         403,000             684            0.15
ULNBs + OFA.............................................              30            0.21             707         907,000           1,372            0.16
SNCR....................................................              30            0.21             707       3,266,877           4,564            0.16

[[Page 18083]]

 
ULNBs + SCR.............................................              73            0.08           1,720      11,007,000           6,398            0.24
SCR.....................................................              73            0.08           1,720      11,010,000           6,400            0.24
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State estimates it would take CSU 2-3 years to install SNCR and 
3-4 years to install SCR after SIP approval.
    The State determined NO<INF>X</INF> RP is ULNBs plus OFA. The State 
eliminated SNCR, ULNBs plus SCR, and SCR from consideration due to the 
high cost effectiveness values and low visibility improvement for these 
controls. Based upon its consideration of the five factors that it used 
for RP, the State determined that the NO<INF>X</INF> RP emission limit 
for Nixon Unit 1 is 0.21 lb/MMBtu (30-day rolling average). The State 
assumes that the emission limit can be achieved with ultra-low 
NO<INF>X</INF> burners with overfire air control. The State did not 
choose SNCR as it would achieve the same emissions reductions at a 
greater expense.
    We agree with the State's conclusions, and we are proposing to 
approve the State's NO<INF>X</INF> RP determination for CSU Nixon Unit 
1.

PM RP Determination

    Nixon Unit 1 is 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 greater than a 95% 
reduction in PM. The State determined that 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 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. The State did not provide a full four-factor analysis plus 
visibility improvement modeling because the State determined RP to be 
the most stringent control technology and limit.
    The State has determined that the PM RP emission limit for CSU 
Nixon Unit 1 is 0.03 lb/MMBtu (30-day rolling average). The State 
assumes that the emission limit can be achieved through the operation 
of the existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for CSU Nixon Unit 1.
iv. Black Hills Energy Clark Power Plant, Units 1 and 2
    Black Hills/Colorado Electric Utility Company informed the State 
that the Clark Units 1 and 2 will be shut down by December 31, 2013. 
The shutdown will result in SO<INF>2</INF>, NO<INF>X</INF> and PM 
reductions of approximately 1,457 tpy, 861 tpy, and 72 tpy, 
respectively. The State determined that the shutdown of Clark Power 
Plant Units 1 and 2 by December 31, 2013 is RP for this source. The 
State did not provide a RP analysis for this facility since the 
shutdown of the facility represents the most stringent control. The 
State's discussion for the source can be found in Chapter 8.5.2.4 of 
the SIP. The shutdown of Black Hills Energy Clark Power Plant Unit 1 
and Unit 2 is required by the RH SIP (see section 8.5.2 of the SIP and 
Regulation No. 3, Part F, Section VI.B).
v. Holcim Florence Cement Plant

Background

    The Holcim Florence Cement Plant is a Portland cement plant located 
in Florence, Colorado. In May 2002, a newly constructed cement kiln 
commenced operation at the plant. This more energy-efficient 5-stage 
preheater/precalciner kiln replaced three older wet process kilns. The 
Florence Plant includes a quarry where major raw materials used to 
produce Portland cement, such as limestone, translime and sandstone, 
are mined, crushed and then conveyed to the plant site. Emissions from 
the kiln system, raw mill, coal mill, alkali bypass and clinker cooler 
are all routed through a common main stack for discharge to the 
atmosphere. The kiln system is rated at 950 MMBtu per hour of fuel 
input with a nominal clinker production rate of 5,950 tons per day. It 
is permitted to burn the following fuel types: Coal, tire derived fuel, 
petroleum coke, natural gas, dried cellulose, and oil, including non-
hazardous used oil. The State determined that the kiln system, quarry, 
and finish mill were subject to RP and that all other units at this 
facility fall below the State's de minimis threshold. The quarry and 
finish mill only have PM emissions. The State RP determination for the 
Holcim Florence Cement Plant can be found in Chapter 8.5.2.5 and 
Appendix D of the SIP.

SO2 RP Determination

    The kiln system is currently controlled with a wet FGD with a 
current SO<INF>2</INF> permit limit of 1006.5 tpy. The wet FGD, in 
conjunction with good combustion practices and the inherent recycling 
and scrubbing of acid gases in the manufacturing process, achieves a 
98.3% reduction in SO<INF>2</INF> emissions as measured by the total 
sulfur input into the system versus the amount of sulfur emitted to 
atmosphere. The State estimates that the wet FGD itself achieves an 
overall SO<INF>2</INF> removal efficiency of greater than 90%.
    On August 9, 2010, EPA finalized changes to the NSPS for Portland 
Cement Plants. The NSPS requires new, modified, or reconstructed cement 
kilns to meet an emission standard of 0.4 pound of SO<INF>2</INF> per 
ton of clinker on a 30-day rolling average or a 90% reduction as 
measured at the inlet and outlet of the control device. While the new 
NSPS does not apply to the Holcim Portland Plant because it is an 
existing facility, the State determined that 90 percent control 
represents the most stringent level of control and wet FGD the most 
stringent control technology for Portland cement plants. Therefore, the 
State did not complete a full RP analysis.
    The State did evaluate emissions limit tightening based on current 
operations. As a part of its submittals to the State, Holcim analyzed 
continuous hourly emission data for SO<INF>2</INF>. The State used the 
hourly emission data from 2004 to 2008 to calculate the daily emission 
rates. The State calculated a 30-day rolling average emission rate by 
dividing the total emissions from the previous 30 operating days by the 
total clinker production from the previous 30 operating days. The State 
established two RP limits for the Holcim Florence Cement Plant. The 
State used the 99th percentile of the 30-day rolling average data to 
establish a short-term SO<INF>2</INF> RP emission limit of 1.30 pounds 
per ton of clinker (30-day rolling average). The State calculated the 
long-term annual

[[Page 18084]]

limit by multiplying the long-term baseline SO<INF>2</INF> value of 
0.77 lb/ton clinker (the mean of 0.51 pound per ton plus one standard 
deviation of 0.26 pound per ton) by the annual clinker limit of 
1,873,898 tpy, and then dividing by 2,000 pounds per ton. The State 
determined that the SO<INF>2</INF> RP long-term limit is 721.4 tpy (12-
month rolling total). The State assumes that the 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 SO<INF>2</INF> RP determination for the Holcim Florence 
Cement Kiln.

NOX RP Determination

    NO<INF>X</INF> emissions from the kiln are currently controlled by 
a number of technologies, including LNBs. The State determined water 
injection (the injection of water into the main flame of the kiln to 
act as a heat sink and reduce the flame temperature) and SNCR were 
technically feasible. The State determined 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 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, nor are there any remaining-useful-life issues for 
this source. A summary of the State's NO<INF>X</INF> RP analysis is 
provided in Table 37 below. Baseline NO<INF>X</INF> emissions are 1,931 
tpy based on the average of 2007-2009 actual emissions. The emission 
rate in the table is reflective of the 30-day rolling average contained 
in the State's RP analysis. The State estimates that water injection 
would result in a 7 percent or less emission reduction and SCNR could 
achieve about 45 percent control.\22\ Since the State's initial 
analysis indicated that SNCR would be reasonable for RP control, the 
State did not analyze water injection further.
---------------------------------------------------------------------------

    \22\ An SNCR control efficiency of 50% is feasible for the 
Portland Plant kiln. However, to achieve the necessary system 
configuration and temperature profile, SNCR will be applied at the 
top of the preheater tower and thus the alkali bypass exhaust stream 
cannot be treated. To achieve the proper cement product 
specifications, the Portland Plant alkali bypass varies from 0-30% 
of main kiln gas flow. Adjusting by 10%, for the alkali bypass to 
account for the exhaust gas that is not treated (i.e., bypassed) by 
the SNCR system, the State determined the overall SNCR control 
efficiency for the main stack will be 45%.

                                            Table 37--Summary of Holcim Florence Cement Kiln NOX RP Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                            Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/ton of       Emission                          Cost        (delta dv for
                   Control technology                       efficiency     clinker) (30-     reduction      Annualized     effectiveness    the maximum
                                                                (%)         day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                                                                              impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR....................................................              45            2.73          1098.9      $2,520,000          $2,293            0.29
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State has determined that Holcim will need five years from SIP 
approval to install SNCR controls.
    The State determined that NO<INF>X</INF> RP control is SNCR. The 
State has determined that the NO<INF>X</INF> RP emission limits for the 
Holcim Florence Cement Kiln are 2.73 pounds per ton of clinker (30-day 
rolling average) and 2086.8 tpy (12-month rolling average). The State 
assumes that the emission limits can be achieved through the operation 
of the existing LNBs and the installation and operation of SNCR.
    The State calculated the 30-day rolling average short-term limit by 
adjusting upward by 10% (to account for the use of tire-derived fuel) 
the short-term baseline emission rate of 4.47 pounds of NO<INF>X</INF> 
per ton clinker, and by then accounting for SNCR at 45% control 
efficiency [4.47/0.9*(1-0.45) = 2.73]. The State calculated the long-
term annual limit by adjusting the annual baseline emission rate of 
3.64 lbs/ton clinker (the mean of 3.43 pounds per ton plus one standard 
deviation of 0.21 pound per ton) in a similar fashion [3.64/0.9*(1-
0.45) = 2.23 lb/ton]. The State took the calculated value of 2.23 
pounds per ton, multiplied it by the annual clinker limit of 1,873,898 
tpy, and then divided by 2,000 pounds per ton to arrive at the 2,086.8 
tpy NO<INF>X</INF> limit.
    We agree with the State's conclusions, and we are proposing to 
approve its NO<INF>X</INF> RP determination for the Holcim Florence 
Cement Kiln.

PM RP Determination for the Kiln

    The kiln system is currently controlled with fabric filter 
baghouses with an emission limit of 246.3 tpy. The units are exceeding 
a PM control efficiency of 95%. The State has determined that the 
existing fabric filter baghouses installed on the kiln system represent 
the most stringent control technology.
    The 246.3 tpy limit equates to an annual average of 0.26 pound of 
PM per ton of clinker. The State evaluated the impact on visibility of 
a lower emission rate. The State modeled possible visibility 
improvements associated with two emission rates: an emission rate of 
0.08 pound of PM per ton of clinker (19.83 lbs/hour) and a rate of 0.04 
pound of PM per ton of clinker (9.92 lbs/hour). This analysis assumed 
the emissions were all attributable to the kiln (i.e., no contribution 
from the clinker cooler) to assess the impact of a possible reduction 
of the kiln emission limit. The 98th percentile impact for all 
pollutants is 0.435 dv. The modeling showed no change to this value 
when the State modeled the lower emission limits. The State's modeling 
demonstrates that PM is an insignificant contributor to visibility 
impairment.
    Given the very limited impact of PM emissions from the kiln system 
on visibility impairment, the State determined that no additional PM 
emissions control is warranted. The State has determined that the PM RP 
emission limit for the Holcim Florence Cement Kiln is 246.3 tpy of PM 
(12-month rolling total) from the kiln system main stack (including 
emissions from the clinker cooler). The State assumes that the emission 
limit can be achieved through the operation of the existing fabric 
filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for the Holcim Florence Cement Kiln.

[[Page 18085]]

PM RP Determination for the Quarry \23\
---------------------------------------------------------------------------

    \23\ The summary of the RP analysis was not included in the SIP. 
Please see the State's full RP analysis for information on the 
quarry and finish mill.
---------------------------------------------------------------------------

    The quarry has a current PM emission limit of 47.9 tpy. The State 
has determined that the existing fugitive dust control plan and 
associated control measures represent the most stringent controls for 
the quarry emission sources. The control measures include: watering and 
the use of chemical stabilizers, compaction and re-vegetation of 
stockpiles, vehicle speed limitations, reclamation and sequential 
extraction of materials, paving, graveling and cleaning of haul roads, 
sequential blasting, wet drilling, and the suspension of activities 
during high wind events. The State also determined that additional 
controls would result in no additional visibility benefit based on the 
low permitted emissions.
    The State has determined that the PM RP emission limit for the 
Holcim Florence Cement Quarry is 47.9 tpy fugitive PM (12-month rolling 
total).
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for the Holcim Florence Cement Quarry.

PM RP Determination for the Finish Mill

    The finish mill is currently controlled with fabric filter 
baghouses with an emission limit of 34.3 tpy of PM (12-month rolling 
total). The units are exceeding a PM control efficiency of 95%. The 
State determined that the current control technology and limit 
represent the most stringent level of control for the finish mill. 
Accordingly, the State did not provide a four-factor analysis plus 
visibility improvement modeling for the finish mill.
    The State has determined that the PM RP emission limit for the 
Holcim Florence Cement Finish Mill is 34.3 tpy (12-month rolling 
total). The State assumes that the emission limit can be achieved 
through the operation of the existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for the Holcim Florence Cement Finish 
Mill.
vi. Tri-State Generation Nucla Facility

Background

    The Tri-State Nucla facility is located in Montrose County 
approximately 3 miles southeast of the town of Nucla, Colorado. The 
Nucla facility consists of one coal-fired steam-driven electric 
generating unit, Unit 4, with a rated electric generating capacity of 
110 MW (gross). The Nucla facility is an atmospheric circulating 
fluidized bed (CFB) unit. Additionally, the facility includes a number 
of fugitive dust sources. Unit 4 is the only unit subject to RP as the 
fugitive dust sources fall below the de minimis levels set by the 
State. The State's RP determination for the Nucla facility can be found 
in Chapter 8.5.2.6 and Appendix D of the SIP.

SO2 RP Determination

    Unit 4 is currently controlled for SO<INF>2</INF> emissions by 
limestone injection achieving a 70% reduction in emissions. Unit 4 has 
a current permit limit of 0.4 lbs/MMBtu (30-day rolling average). The 
State determined that limestone injection improvements (LII), dry FGD, 
DSI, and LII with a dry FGD were technically feasible. Study-level 
information for hydrated ash reinjection (HAR) systems at Nucla or any 
other EGU in the western United States were not available for use in 
evaluating costs. Based on the lack of cost information, the State does 
not consider this option to be commercially available and did not 
consider HAR in this analysis. The State did not evaluate DSI, as this 
technology would achieve less than a 50% reduction in emissions, which 
is less than the current SO<INF>2</INF> 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. A summary of the State's SO<INF>2</INF> RP analysis is 
provided in Table 38 below. Baseline SO<INF>2</INF> emissions are 1,335 
tpy based on the average of 2006-2008 actual emissions. The emission 
rate for each control option in the table is reflective of the 30-day 
rolling average contained in the State's RP analysis. Costs for 
SO<INF>2</INF> control options (and NO<INF>X</INF>) were evaluated 
based on analyses for similar systems proposed at other western CFB 
boiler units, specifically Spiritwood in North Dakota \24\ and Bonanza 
in Utah.\25\ The State did not model visibility improvement due to time 
constraints.
---------------------------------------------------------------------------

    \24\ Barr, July 2007. ``Application for a Permit to Construct a 
Combined Heat and Power (CHP) Plant.'' Prepared for Great River 
Energy--Spiritwood Station, Spiritwood, ND.
    \25\ EPA, August 30, 2007. ``Deseret Power Electric Cooperative, 
Bonanza Power Plant, Waste Coal Fired Unit: Prevention of 
Significant Deterioration Permit to Construct--Final Statement of 
Basis for Permit No. PSD-00-0002.01.00. ''

                                Table 38--Summary of Nucla Unit 4 SO2 RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                   Emission rate
                                      Control     (lb/mmbtu) (30-    Emission       Annualized         Cost
       Control technology           efficiency      day rolling      reduction         costs       effectiveness
                                        (%)          average)          (tpy)                          ($/ton)
----------------------------------------------------------------------------------------------------------------
LII.............................            39.4            0.19             526        $914,290           4,161
Dry FGD.........................            87.0            0.04           1,162       7,604,627           6,547
LII + dry FGD...................            93.9            0.02           1,254       9,793,222           7,808
----------------------------------------------------------------------------------------------------------------

    The State's analysis assumes that the LII will not require any 
construction or capital improvements and compliance time will be 
minimal. The State anticipates that the time necessary for installing 
dry FGD or dry FGD plus LII would be 3-5 years after SIP approval.
    The State eliminated dry FGD and dry FGD plus limestone injection 
improvements from consideration due to the high cost effectiveness 
values. The State originally asserted in the Nucla RP analysis that 
limestone injection improvements are technically feasible. However, 
Tri-State provided additional information on November 29, 2011 in the 
Colorado Air Quality Control Commission hearing that introduced 
significant uncertainty regarding the technical feasibility of LII for 
Unit 4 at Nucla Station. The State determined upon further evaluation 
that LII beyond current operations were not feasible in all operating 
conditions.
    Based upon its consideration of the four factors, the State has 
determined that the SO<INF>2</INF> RP emission limit for Nucla Unit 4 
is 0.5 lb/MMBtu (30-day rolling average). The State assumes that the 
emission limit can be achieved through the operation of the current 
limestone injection system.

[[Page 18086]]

    We agree with the State's conclusions, and we are proposing to 
approve the State's SO<INF>2</INF> RP determination for Nucla Unit 4.

NOX RP Determination

    In 2006, Tri-State installed a small-scale SNCR system on Unit 4 
that injects anhydrous ammonia to achieve NO<INF>X</INF> reductions. 
Tri-State does not operate the SNCR system frequently. It is used on 
occasions when NO<INF>X</INF> emissions approach 0.4 lb/MMBtu. 
Operation above this level at high unit capacity factors results in 
levels that approach the annual NO<INF>X</INF> limit of 1,987.9 tpy 
(12-month rolling average).
    The State determined full-scale SNCR and SCR were technically 
feasible for reducing NO<INF>X</INF> emissions at Nucla Unit 4. Though 
the SIP states SCR is not technically feasible on a CFB coal-fired 
boiler, the State's RP analysis contains a discussion on SCR being 
technically feasible, and we agree with the State's assessment in the 
RP analysis. With respect to SNCR, the State has asserted that there is 
substantial uncertainty surrounding the potential control efficiency 
achievable by a full-scale SNCR system at a CFB boiler burning western 
coal. The State's estimates for control efficiency vary between 10-40% 
for NO<INF>X</INF> reduction potential.
    The State determined that the costs for SCR would likely be 
excessive, and the State did not further evaluate this control option. 
The State estimated that the incremental cost of using SCR versus SNCR 
on a CFB Boiler as $25,315 per ton per the Spiritwood BACT analysis and 
$40,297 per ton per the Bonanza BACT analysis. The State expects a SCR 
system at the Nucla Station to have even higher costs due to the 
retrofit factor and small size of Unit 4.
    The State did not identify any energy or non-air quality 
environmental impacts that would preclude the selection of the 
remaining control evaluated, nor are there any remaining-useful-life 
issues for this source. A summary of the State's NO<INF>X</INF> RP 
analysis is provided in Table 39 below. Baseline NO<INF>X</INF> 
emissions are 1,760 tpy based on the average of 2006-2008 actual 
emissions. The emission rate for each control option in the table is 
reflective of the 30-day rolling average contained in the State's RP 
analysis. The State did not model visibility improvement due to time 
constraints. The State evaluated SNCR at two different control 
efficiencies due to the uncertainty of SNCR control on this type of 
boiler.

                                Table 39--Summary of Nucla Unit 4 NOX RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                   Emission rate
                                      Control     (lb/mmbtu) (30-    Emission                          Cost
       Control technology           efficiency      day rolling      reduction      Annualized     effectiveness
                                        (%)          average)          (tpy)           costs          ($/ton)
 
----------------------------------------------------------------------------------------------------------------
SNCR............................            10.3            0.40             173      $2,238,592          12,974
SNCR............................            43.6            0.25             730       2,238,592           3,065
----------------------------------------------------------------------------------------------------------------

    The State anticipates that the time necessary to install and 
operate SNCR would be approximately 3-5 years after SIP approval.
    Based on its consideration of the four factors, the State has 
determined that NO<INF>X</INF> RP for Nucla Unit 4 is the following 
NO<INF>X</INF> emission limit: 0.5 lb/MMBtu (30-day rolling average). 
Due to the uncertainty of the control efficiency of SNCR control, the 
State determined that it was not reasonable for NO<INF>X</INF> RP 
control at this time.
    We agree with the State's conclusions, and we are proposing to 
approve its NO<INF>X</INF> RP determination for Tri-State Nucla Unit 4.

PM RP Determination

    Nucla Unit 4 is 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 99.9% reduction in PM. 
The State determined that 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 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. The State did not provide a full four-factor analysis because 
the State determined RP to be the most stringent control technology and 
limit.
    The State has determined that the PM RP emission limit for Tri-
State Nucla Unit 4 is 0.03 lb/MMBtu (30-day rolling average). The State 
assumes that the emission limit can be achieved through the operation 
of the existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for Tri-State Nucla Unit 4.
vii. Tri-State Craig Unit 3

Background

    The Tri-State Craig Station is located in Moffat County about 2.5 
miles southwest of the town of Craig, Colorado. This facility is a 
three unit coal-fired power plant with a total net electric generating 
capacity of 1264 MW. Craig Units 1 and 2 are subject to BART. The State 
determined Craig Unit 3 was subject to RP. Craig Unit 3 is a dry-bottom 
pulverized coal-fired boiler. The Craig facility also includes two 
cooling towers, coal handling systems, ash handling systems, limestone 
handling system, and the staging/landfill area. In addition to Craig 
Unit 3, the State determined that the ash handling system and the 
limestone hauling system were subject to RP (they only emit PM 
emissions, not SO<INF>2</INF> or NO<INF>X</INF>). The State determined 
the other systems were not subject to RP as their emissions were below 
the de minimis threshold set by the State. The State's RP determination 
can be found in Chapter 8.5.2.7 and Appendix D of the SIP.

SO2 RP Determination

    Craig Unit 3 is currently controlled with a dry FGD currently 
achieving over 80 percent SO<INF>2</INF> reduction. The current 
emission limits are .20 lb/MMBtu (calendar day average), 80% reduction 
(30-day rolling average). As mentioned earlier, if a BART source has 
current SO<INF>2</INF> controls achieving at least a 50% reduction in 
emissions, the state needs to evaluate upgrades to the existing control 
technology but does not need to consider the replacement of that 
technology (70 FR 39171). We conclude that it is reasonable to follow 
this approach for evaluating potential RP controls in this initial 
planning period. Colorado should consider replacement of existing 
scrubbers in future planning periods. The State considered the 
following dry FGD upgrades: (1) Use of performance additives; (2) use 
of more reactive sorbent or increasing the pulverization level of 
sorbent; (3)

[[Page 18087]]

engineering redesign of atomizer or slurry injection system. Based on 
the design of Unit 3, the State could not identify any performance 
additives that could be used and determined that Tri-State cannot use a 
more reactive sorbent or increase the pulverization level of sorbent. 
The source recently redesigned the slurry injection system, and the 
State could not identify any other feasible upgrades. Based on its 
analysis, the State determined that no upgrades are technically 
feasible. We agree with the State's assessment of possible upgrades. 
The State determined that fuel switching and DSI were technically 
feasible, but did not further analyze these controls as they would 
achieve less emission reductions than the current controls.
    The State analyzed emission limit tightening based on current 
operations. Tri-State made upgrades to the dry FGD between 2007 and 
2009. The maximum 30-day rolling emission rate post-upgrade (June 2009-
June 2010) was 0.14 lbs/MMBtu and the average 30-day rolling average 
was 0.11 lbs/MMBtu. The State modeled the visibility improvement that 
would result from a 0.15 lbs/MMBtu emission limit and 0.07 lbs/MMBtu 
emission limit. The visibility improvement was 0.26 dv and 0.38 dv, 
respectively.
    Based on its analysis, the State determined that a more stringent 
30-day rolling SO<INF>2</INF> limit of 0.15 lbs/MMBtu represents an 
appropriate and reasonable level of emissions control for this dry FGD 
control technology. Upon review of 2009 emissions data from EPA's CAMD 
Web site, the State has determined that this emissions rate is 
achievable without additional capital investment. The State has 
determined that the SO<INF>2</INF> RP emission limit for Craig Unit 3 
is 0.15 lb/MMBtu (30-day rolling average). The State assumes the 
emission limit is achievable with the current dry FGD controls.
    The State has determined that a SO<INF>2</INF> limit lower than 
0.15 lbs/MMBtu would not result in significant visibility improvement 
(0.12 dv), would likely result in frequent non-compliance events, and, 
would, thus, not be reasonable.
    We agree with the State's conclusions, and we are proposing to 
approve its SO<INF>2</INF> RP determination for Tri-State Craig Unit 3.

NOX RP Determination

    Craig Unit 3 is currently controlled with LNBs and OFA that were 
installed in 2009. The State determined that combustion control 
refinements, neural network system (NNS) combustion controls, SNCR, and 
SCR were technically feasible. The State determined that ROFA, ECO, 
RRI, 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. A summary of the State's NO<INF>X</INF> RP analysis is 
provided in Table 40 below. Baseline NO<INF>X</INF> emissions are 6,402 
tpy based on the average of 2006-2008 actual emissions. The emission 
rate for each control option in the table is reflective of the 30-day 
rolling average contained in the State's RP analysis. The State did not 
model combustion control refinements or NNS because of the extremely 
low control efficiency for these two control options.

                                               Table 40--Summary of Tri-State Craig Unit 3 NOX RP Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                            Visibility
                                                                           Emission rate                                                    improvement
                                                              Control     (lb/mmbtu) (30-    Emission                          Cost        (delta dv for
                   Control technology                       efficiency      day rolling      reduction      Annualized     effectiveness    the maximum
                                                                (%)          average)          (tpy)           costs          ($/ton)          98th
                                                                                                                                            percentile
                                                                                                                                              impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Combustion Control Refinements..........................               2            0.32             114        $122,000          $1,071  ..............
NNS.....................................................               5            0.31             285         280,000             984  ..............
SNCR....................................................              15            0.28             858       4,173,000           4,887            0.32
SCR.....................................................              75            0.08           4,281     239,762,387           6,952            0.79
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State eliminated SCR from consideration due to the high cost 
effectiveness value and the visibility improvement associated with this 
control. The State determined SNCR was reasonable for RP control. Based 
upon its consideration of the five factors that it used for RP, the 
State has determined that the NO<INF>X</INF> RP emission limit for 
Craig Unit 3 is 0.28 lb/MMBtu (30-day rolling average). The State 
assumes that the RP emission limit can be achieved through the 
operation of SNCR.
    We agree with the State's conclusions, and we are proposing to 
approve its NO<INF>X</INF> RP determination for Tri-State Craig Unit 3.

PM RP Determination

    Craig Unit 3 is equipped with fabric filter baghouses to control PM 
emissions with an emission limit of 0.013 lb/MMBtu for PM filterable 
and 0.012 lb/MMBtu for PM<INF>10</INF>. Stack tests show that the 
fabric filter baghouses are achieving over a 95% reduction in PM. The 
State determined that 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 BACT determinations. Based on this evaluation, 
the State determined that the current emission limits represents the 
most stringent level of control for this type of source. The State did 
not provide a full four-factor analysis plus visibility improvement 
modeling because the State determined RP to be the most stringent 
control technology and limit.
    The State has determined that the PM RP emission limits for Tri-
State Craig Unit 3 are 0.013 lb/MMBtu for filterable PM (30-day rolling 
average) and 0.012 lb/MMBtu for PM<INF>10</INF> (30-day rolling 
average). The State assumes that the emission limits can be achieved 
through the operation of the existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to 
approve its PM RP determination for Tri-State Craig Unit 3.
viii. PSCO Cameo Station
    PSCO informed the State that the Cameo Station east of Grand 
Junction, Colorado would be shut down by December 31, 2011, resulting 
in SO<INF>2</INF>, NO<INF>X</INF>, and PM reductions of approximately 
2,618, 1,140, and 225 tons per year, respectively. The State did not 
perform a RP analysis for this source since a shutdown is the most 
stringent control. The State determined that the shutdown of Cameo 
Station by

[[Page 18088]]

December 31, 2011 is RP for this source. We agree with the State's 
conclusions, and we are proposing to approve its RP determination for 
PSCO Cameo Station. The State's discussion of RP for Cameo Station can 
be found in Chapter 8.5.2.8 of the SIP. The shutdown of PSCO Cameo 
Station is required by the RH SIP (see Chapter 8.5.2 of the SIP and 
Regulation No. 3, Part F, Section VI.B).\26\
---------------------------------------------------------------------------

    \26\ PSCO Cameo Station was shut down in December 2010.
---------------------------------------------------------------------------

Summary of State's RP Determinations

                                        Table 41--Summary of the State's RP Determinations for Stationary Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                    Assumed  particulate
           Emission unit              Assumed NOX  control     NOX  Emission limit    Assumed SO2  control    SO2 Emission limit   control and  emission
                                              type                                            type                                         limit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rawhide............................  Enhanced Combustion     0.145 lb/MMBtu (30-day  Lime Spray Dryer*....  0.11 lb/MMBtu (30-day  Fabric Filter
Unit 101...........................   Control *.              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
CENC...............................  No Control............  246 tons per year (12-  No Control...........  1.2 lbs/MMBtu........  Fabric Filter
Unit 3.............................                           month rolling total).                                                 Baghouse * 0.07 lb/
                                                                                                                                    MMBtu.
Nixon..............................  ULNBS with OFA........  0.21 lb/MMBtu (30-day   Lime Spray Dryer.....  0.11 lb/MMBtu (30-day  Fabric Filter
Unit 1.............................                           rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                                                                    MMBtu.
Clark..............................  Shutdown by 12/31/2013  0.....................  Shutdown by 12/31/     0....................  Shutdown by 12/31/
Units 1 &2.........................                                                   2013.                                         2013.
Holcim--Florence...................  SNCR..................  2.73 lbs/ton clinker    Wet Lime Scrubber *..  1.30 lbs/ton clinker.  Fabric Filter
Kiln...............................                           (30-day rolling                               (30-day rolling         Baghouse *
                                                              average).                                      average).             246.3 tons/year.
                                                             2,086.8 tons/year.....                         721.4 tons/year......
Nucla..............................  No Control............  0.5 lb/MMBtu..........  Limestone Injection *  0.4 lb/MMBtu.........  Fabric Filter
                                                             (30-day rolling                                (30-day rolling         Baghouse *
                                                              average).                                      average).             0.03 lb/MMBtu.
Craig..............................  SNCR..................  0.28 lb/MMBtu.........  Lime Spray Dryer *...  0.15 lb/MMBtu........  Fabric Filter
Unit 3.............................                          (30-day rolling                                (30-day rolling         Baghouse *
                                                              average).                                      average).             0.013 lb/MMBtu
                                                                                                                                    filterable PM
                                                                                                                                   0.012 lb/MMBtu
                                                                                                                                   PM10.
Cameo..............................  Shutdown by 12/31/2011  0.....................  Shutdown by 12/31/     0....................  Shutdown by 12/31/
                                                                                      2011.                                         2011.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Controls already operating.

ix. Area Oil and Gas Sources
    Because the area source oil and gas category is made up of numerous 
smaller sources, the State determined it is only practical to evaluate 
the category for RP control as a whole. When reviewing oil and gas area 
sources, the State identified heater-treaters and RICE as the largest 
NO<INF>X</INF> emission sources.
a. Oil and Gas Heater-Treaters
    A heater-treater is a device used to remove contaminants from the 
natural gas or oil at or near the wellhead before the gas is sent down 
the production line to a natural gas processing plant or the oil is 
collected in storage tanks. The latest 2018 emissions inventory for the 
State assumes approximately 23,000 tons of NO<INF>X</INF> per year from 
26,000 natural gas and oil heater-treaters. This equates to 
approximately 0.88 tpy of NO<INF>X</INF> per gas/oil well heater-
treater.
    The State's research shows that emission controls and control 
applications for this source category are not well developed and have 
focused primarily on methane reductions. Though the State identified 
some technically feasible control options, the State determined that 
the costs of compliance and the control effectiveness could not be 
confidently determined. Because of the uncertainty of controls, the 
State has determined that additional controls under RP are not 
reasonable in this initial planning period.
b. RICE

Background

    Power generated by large RICE is generally used to compress natural 
gas or to generate electricity in remote locations. The designation 
large RICE refers to engines have a rating of at least 100 horsepower 
(hp) for the purpose of this RP analysis. Large RICE produce power by 
combustion of fuel and are operated at various air-to-fuel ratios. RICE 
are operated with either fuel-rich ratios, which are called rich-burn 
(RB) engines, or air-rich ratios, which are called lean-burn (LB) 
engines. The State's 2018 emission inventory shows that large RICE 
represent 16% of the Statewide point source NO<INF>X</INF> emission 
inventory, with 2018 emissions expected to be 16,199 tpy.
    The State determined the following were technically feasible for 
controlling NO<INF>X</INF> emissions from RICE: (1) Air/fuel ratio 
adjustment for LB engines; (2) ignition/spark timing retard for LB 
engines; (3) 3-way non-selective catalytic reduction (NSCR) for RB 
engines; (4) SNCR for RB and LB engines; (5) SCR for LB engines; and 6) 
replace RICE with electric motors for LB and RB engines.
    A summary of the State's RP analysis for RICE engines is provided 
in Table 42 below. Because control effectiveness and cost effectiveness 
is dependent on a number of engine-specific factors, the State has 
provided a range for these factors. Due to a lack of available 
information, the State did not provide the cost effectiveness for SNCR.

[[Page 18089]]



                Table 42--Summary of RICE Controls for RP
------------------------------------------------------------------------
                                    Control
      Control technology         effectiveness   Cost effectiveness  ($/
                                      (%)                  ton)
------------------------------------------------------------------------
Lean Burn (Air/Fuel Ratio                  5-30  $320-8,300.
 Adjustment).
Lean Burn (Ignition/Spark                    20  $310-2,000.
 Timing Retard).
Rich Burn NSCR w/an air to                80-90  $571.
 fuel ratio (ATF) controller.
Rich/Lean Burn SNCR...........            50-95  .......................
Lean Burn SCR.................            80-90  $430-4,900.
Replace RICE with electric               60-100  4,700 or more.
 motors.
------------------------------------------------------------------------

    For RICE NO<INF>X</INF> control under the RHR, the State determined 
that the installation of NSCR plus ATF controllers on all RB RICE 
greater than 500 hp throughout the State satisfies RP requirements. 
Additional NO<INF>X</INF> control for lean burn RICE throughout the 
State is not reasonable for this planning period. For existing RICE 
less than 500 hp, the State determined that no additional control is 
necessary for RP in this planning period. Colorado's emission inventory 
indicates that in the 2007-2008 timeframe, there were 538 engines with 
less than 500 hp in the State, and these engines emitted 5,464 tpy of 
NO<INF>X</INF>. At an average of about 10 tons of NO<INF>X</INF> 
emissions per year, the State determined controlling engines of this 
size is not reasonable.
    In addition, for new and modified RICE of 100 hp or greater, the 
State is relying on emissions controls that are required by EPA's NSPS 
subpart JJJJ, 40 CFR part 60, and EPA's NESHAP subpart ZZZZ, 40 CFR 
part 63. The State determined that these federal control requirements 
satisfy RP for these sources in this planning period.
    Colorado adopted regulations to control NO<INF>X</INF> emissions 
from RICE in 2004. For the Denver metro area/North Front Range ozone 
control area, the State revised Regulation No. 7 to require the 
installation of controls on new and existing rich burn RICE larger than 
500 hp by May 1, 2005. EPA approved the revisions to Regulation No. 7 
as part of the Colorado SIP on August 19, 2005 (70 FR 48652).
    In December 2008, Colorado adopted section XVII.E.3.a into 
Regulation No. 7. Section XVII.E.3.a applies to all existing RB RICE 
over 500 hp throughout the State. The revisions to Regulation No. 7 
required that by July 1, 2010 all existing RB RICE over 500 hp in 
Colorado had to install NSCR with an ATF controller. Sources subject to 
emission controls under a MACT, BACT, or NSPS are not subject to the 
requirements of section XVII.E.3.a. In addition, sources that fall 
below State permitting thresholds are not subject to the requirements 
of section XVII.E.3.a. An exemption from control for RB RICE can be 
obtained upon demonstration that the cost of emission control would 
exceed $5,000 per ton. The State has included Regulation No. 7, section 
XVII.E.3.a, as part of the RH SIP to become federally enforceable upon 
EPA approval.
    We are proposing to approve the State's RP determination for RICE 
engines. We are also proposing to approve Regulation No. 7, section 
XVII.E.3.a, as part of the SIP.
x. Combustion Turbines
    Combustion turbines fueled by natural gas are either co-located 
with coal-fired electric generating units or are stand-alone 
facilities. These units are primarily used to supplement power supply 
during peak demand periods when electricity use is highest. Typical 
emissions for this source type may be significant for NO<INF>X</INF>, 
but usually have very low SO<INF>2</INF> and PM<INF>10</INF> emissions.
    The State evaluated combustion turbines that are co-located at 
subject-to-BART or subject-to-RP sources. The State determined there 
are five BART and RP facilities with combustion turbines: PSCO Valmont 
Generating Station, PSCO Arapahoe Generating Station, CSU--Nixon Power 
Plant, PRPA Rawhide Energy Station, and PSCO Pawnee Generating Station. 
Of these, only two turbines located at the Nixon Front Range Power 
Plant (Turbine <greek-i>1 and Turbine <greek-i>2) emit levels of 
pollutants above the State de minimis levels for NO<INF>X</INF>. 
Baseline NO<INF>X</INF> emissions based on the average of 2006-2008 
actual emissions are 159.6 tpy for Turbine <greek-i>1 and 148 tpy for 
Turbine <greek-i>2.
    The combustion turbines at the Nixon Front Range Power Plant were 
installed with advanced dry-low-NO<INF>X</INF> combustion systems, 
which are achieving a control efficiency of 89.4% on Turbine <greek-i>1 
and 90.1% on Turbine <greek-i>2. The State determined that the 
following were technically feasible controls for NO<INF>X</INF>: 1) dry 
controls using advanced combustor design to suppress NO<INF>X</INF> 
formation and/or promote CO burnout (already installed); and (2) post-
combustion controls (SNCR, SCR). Although post-combustions controls are 
technically feasible, the State's search of the EPA's RACT/BACT/LAER 
Clearinghouse database revealed SCR is the predominant post-combustion 
control technology for combustion turbines and did not find any 
examples of SNCR post-combustion technology applied to combustion 
turbines. The State could not find any instances of commercial scale 
SNCR applied at combustion turbines, so the State eliminated SNCR.
    The State analyzed SCR for RP control. The State determined that 
applying SCR at a 90% control efficiency to both turbines would result 
in about 275 tons of NO<INF>X</INF> reduced annually with a capital 
expenditure of at least $15 million. The State estimated that SCR for 
these turbines would range from approximately $57,000-$62,000 per ton 
of NO<INF>X</INF> reduced annually. Based on the cost effectiveness 
value, the State determined that SCR was not reasonable for RP control. 
Combustion turbines are subject to 40 CFR part 60, subpart GG--
Standards of Performance for Stationary Gas Turbines, which limits 
nitrogen oxides to 117.8 percent by volume at 15 percent oxygen on a 
dry basis (60.332(a)(1)), supported by monitoring and testing. The 
State determined that the limits of 40 CFR part 60, subpart GG are 
NO<INF>X</INF> RP for combustion turbines.
    We agree with the State's analysis and are proposing to approve its 
RP determination for combustion turbines and for the CSU--Nixon Power 
Plant Turbine <greek-i>1 and Turbine <greek-i>2.
3. Reasonable Progress Goals
    40 CFR 51.308(d)(1) requires states to ``establish goals (in dvs) 
that provide for RP towards achieving natural visibility conditions'' 
for each Class I area of the State. These RP goals are interim goals 
that must provide for incremental visibility improvement for the most 
impaired visibility days, and ensure no degradation for the least 
impaired visibility days. The RP goals for the first planning period 
are goals for the year 2018. The State's discussion of RP and RPGs can 
be found in Chapter 8 and section 9.5 of the SIP.

[[Page 18090]]

    Colorado is relying on the WRAP's CMAQ regional modeling performed 
in 2009 to establish its RP goals for 2018. As part of the 2009 CMAQ 
modeling, WRAP included all western states' reasonably foreseeable 
control measures in the projections of 2018 visibility levels.
    The Regional Modeling Center at the University of California 
Riverside, under the oversight of the WRAP Modeling Forum, performed 
modeling used for the RH long-term strategy for the WRAP member states, 
including Colorado. The modeling analysis is a complex technical 
evaluation that began with selection of the modeling system. The 
Regional Modeling Center primarily used the CMAQ photochemical grid 
model to estimate 2018 visibility conditions in Colorado and all 
western Class I areas, based on application of the RH strategies in the 
various state plans, including assumed controls on BART sources.
    The Regional Modeling Center developed air quality modeling inputs, 
including annual meteorology and emissions inventories for: (1) A 2002 
actual emissions base case; (2) a planning case to represent the 2000-
2004 RH baseline period using averages for key emissions categories; 
and (3) a 2018 base case of projected emissions determined using 
factors known at the end of 2005. Each of these inventories underwent a 
number of revisions throughout the development process to arrive at the 
final versions used in CMAQ modeling. The WRAP states' modeling was 
developed in accordance with our guidance.\27\ A more detailed 
description of the CMAQ modeling performed for the WRAP can be found in 
the Colorado Class I area TSDs.
---------------------------------------------------------------------------

    \27\ Guidance on the Use of Models and Other Analyses for 
Demonstrating Attainment of Air Quality Goals for Ozone, 
PM<INF>2.5</INF>, and Regional Haze, (EPA-454/B-07-002), April 2007, 
located at http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf. Emissions Inventory Guidance for Implementation of 
Ozone and Particulate Matter National Ambient Air Quality Standards 
(NAAQS) and Regional Haze Regulations, August 2005, updated November 
2005 (``our Modeling Guidance''), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001.
---------------------------------------------------------------------------

    The photochemical modeling of RH for the WRAP states for 2002 and 
2018 was conducted on the 36-km resolution national regional planning 
organization domain that covered the continental United States, 
portions of Canada and Mexico, and portions of the Atlantic and Pacific 
Oceans along the east and west coasts. The Regional Modeling Center 
examined the model performance of the regional modeling for the areas 
of interest before determining whether the CMAQ model results were 
suitable for use in the RH assessment of the long-term strategy and for 
use in the modeling assessment. The 2002 modeling efforts were used to 
evaluate air quality/visibility modeling for a historical episode, in 
this case, for calendar year 2002, to demonstrate the suitability of 
the modeling systems for subsequent planning, sensitivity, and 
emissions control strategy modeling. Model performance evaluation 
compares output from model simulations with ambient air quality data 
for the same time period to determine whether model performance is 
sufficiently accurate to justify using the model to simulate future 
conditions.
    Once the Regional Modeling Center determined that model performance 
was acceptable, it used the model to determine the 2018 RP goals using 
the current and future year air quality modeling predictions, and 
compared the RP goals to the uniform rate of progress.
    The State determined that the WRAP 2018 projections represent 
significant visibility improvement and RP toward natural visibility 
based upon the State's consideration of the factors required for BART 
and RP. The State is adopting the WRAPs 2018 projections as its RPG for 
each Class I area in Colorado. Table 43 shows the URP and the 2018 RPG 
adopted by the State for such areas.

                                                      Table 43--Colorado's URP and RP Goal for 2018
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                          20% Worst days                              20% Best days
                                                                   -------------------------------------------------------------------------------------
                                                                                               Reduction
                      Colorado class I areas                         2000-2004                 needed to    2018 CMAQ Modeling   2000-2004    2018 CMAQ
                                                                      Baseline     2018 URP    reach URP   projection--state's    Baseline     Modeling
                                                                        (dv)         (dv)         goal           RP goal            (dv)      projection
                                                                                               (delta dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Great Sand Dunes National Park and Preserve.......................        12.78        11.35         1.43            12.20              4.5         4.16
Mesa Verde National Park..........................................        13.03        11.58         1.45             12.5             4.32         4.10
Mount Zirkel & Rawah Wilderness Area..............................        10.52         9.48         1.04             9.91             1.61         1.29
Rocky Mountain National Park......................................        13.83        12.27         1.56            12.83             2.29         2.06
Weminuche Wilderness, Black Canyon of Gunnison, and La Garita             10.33         9.37         0.96             9.83             3.11         2.93
 Wilderness.......................................................
Eagles Nest Wilderness, Flat Tops Wilderness, Maroon Bells-                9.61         8.78         0.83             8.98             0.70         0.53
 Snowmass Wilderness, and West Elk Wilderness.....................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Table 43 shows that the State's RH SIP will provide for improvement 
in visibility for the most-impaired days over the period ending in 2018 
and will allow for no degradation in visibility for the least-impaired 
days.
    Table 43 also shows that Colorado is not meeting the URP to meet 
natural visibility conditions by 2064 because the projected 2018 RPG is 
greater than the 2018 URP. The State finds that the RPGs established in 
this SIP are reasonable for this planning period and that achieving the 
URP in this planning period is not reasonable. Pursuant to 40 CFR 
51.308(d)(1)(ii), the State has determined and presented detailed 
analyses to show why certain controls for specified RP sources are 
reasonable, and why additional controls during this planning period are 
not reasonable based upon its consideration of the required factors for 
RP (40 CFR 51.308(d)(1)(i)(A)). The State has determined and presented 
detailed analyses to show why certain controls for specified BART 
sources are reasonable based upon its consideration of the five-factors 
(40 CFR 51.308(e)(1)(A)). In addition, sources outside of the modeling 
domain are the single largest contributor to sulfate or nitrate at many 
Class I areas (see Table 29 in section V.D.1 of this notice). These 
sources are not under the control of Colorado or the surrounding 
States, and

[[Page 18091]]

will not be significantly controlled by 2018. As discussed below, the 
State consulted with other states on RP.
    Since the State is not meeting the URP, the State is required by 40 
CFR 51.308(d)(1)(ii) to assess the number of years it would take to 
reach natural conditions if visibility improvement continues at the 
current rate of progress. The State has calculated the year and the 
length of time to reach natural visibility as follows: Great Sand 
Dunes: 2152 (148 years); Mesa Verde: 2168 (164 years); Zirkel and 
Rawah: 2106 (102 years); Rocky Mountain: 2098 (94 years); Black Canyon, 
Weminuche, and La Garita: 2119 (115 years); and Eagles Nest, Flat Tops, 
Maroon Bells and West Elk: 2083 (79 years).
    We note that the WRAP 2018 reasonable progress projections did not 
reflect the additional RH controls that Colorado adopted in 2010. These 
controls included additional BART requirements, the PSCO BART 
alternative, and RP limits as described above. These additional 
controls will produce about 44,500 tpy of NO<INF>X</INF> and 
SO<INF>2</INF> reductions that were not included in the WRAP CMAQ 
modeling. Thus, it is likely that the State is closer to the URP than 
is indicated by the WRAP modeling.
    EPA has evaluated Colorado's demonstrations concerning the RPGs and 
finds that they provide for reasonable progress towards natural 
visibility conditions for the first planning period. Based on the RP 
factors, Colorado has demonstrated that it is not reasonable to attain 
the URPs for Colorado's Class I areas in the first planning period, and 
that Colorado's RPGs (as augmented by the additional measures that 
Colorado adopted in 2010) are reasonable. Colorado has adopted BART, 
BART alternative, and RP controls that will achieve substantial 
reductions of NO<INF>X</INF> and SO<INF>2</INF> emissions by 2018. We 
find that Colorado, considering the statutory BART and RP factors, has 
reasonably evaluated and rejected more stringent controls in this first 
planning period. We also find that Colorado has focused on an 
appropriate set of sources and source categories in considering 
potential reasonable progress controls in this first planning period. 
Finally, we agree that sources outside of the modeling domain are the 
single largest contributor to sulfate or nitrate at many Class I areas, 
that these sources are not under the control of Colorado or the 
surrounding states, and that they will not be significantly controlled 
by 2018. This is another major reason that it is not reasonable for the 
Class I areas in Colorado to attain the URPs in 2018. For these 
reasons, EPA is proposing that the State's RPGs are reasonable.

E. Long Term Strategy

1. Emission Inventories
    40 CFR 51.308(d)(3)(iii) requires that Colorado document the 
technical basis, including modeling, monitoring, and emissions 
information, on which it relied to determine its apportionment of 
emission reduction obligations necessary for achieving RP in each 
mandatory Class I Federal area it affects. Colorado must identify the 
baseline emissions inventory on which its strategies are based. 40 CFR 
51.308(d)(3)(iv) requires that Colorado identify all anthropogenic 
(human-caused) sources of visibility impairment it considered in 
developing its long-term strategy. This includes major and minor 
stationary sources, mobile sources, and area sources.
    In order to meet these requirements, Colorado relied on the 
emission inventory developed by the WRAP. The pollutants inventoried by 
the WRAP that Colorado used for this SIP include SO<INF>2</INF>, 
NO<INF>X</INF>, VOC, OC, EC, PM<INF>2.5</INF>, PM<INF>10</INF>, and 
ammonia. WRAP developed an inventory for the baseline year 2002 and 
provided projections of future emissions in 2018 based on expected 
controls, growth, or other factors. The emission inventories developed 
by the WRAP were calculated using best available data and approved EPA 
methods.\28\
---------------------------------------------------------------------------

    \28\ The methods WRAP used to develop these emission inventories 
are described in more detail in Technical Support Document for 
Technical Products Prepared by the Western Regional Air Partnership 
(WRAP) in Support of Western Regional Haze Plans; February 28, 2011. 
This document is included in the Supporting and Related Materials 
section of the docket.
---------------------------------------------------------------------------

    There are a number of emission inventory source categories 
identified in the Colorado SIP: point, area, on-road mobile, off-road 
mobile, anthropogenic fire, natural fire, road dust, fugitive dust, 
area source oil and gas, and biogenic emissions. The State provided the 
2002 baseline, the 2018 projected emissions, and the net change of 
emissions between 2002 and 2018 for SO<INF>2</INF>, NO<INF>X</INF>, 
VOC, OC, EC, PM<INF>2.5</INF>, PM<INF>10</INF>, and ammonia for each of 
the above source categories. Following is a summary of the emission 
inventory for each pollutant by source.

SO2

    Sulfur dioxide emissions come primarily from coal combustion at 
EGUs but smaller amounts come from natural gas combustion, mobile 
sources and wood combustion.

                                 Table 44--Colorado SO2 Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................          97,984          44,062             -55
Area............................................................           6,533           7,644              17
On-Road Mobile..................................................           4,389             677             -85
Off-Road Mobile.................................................           3,015             754             -75
WRAP Area O & G.................................................             118              11             -91
Road Dust.......................................................               4               6              34
Fugitive Dust...................................................               6               5             -13
Anthropogenic Fire..............................................             108              91             -15
Natural Fire....................................................           3,335           3,335               0
Biogenic........................................................  ..............  ..............  ..............
                                                                 -----------------------------------------------
    Total.......................................................         115,492          56,585             -51
----------------------------------------------------------------------------------------------------------------

    Overall, SO<INF>2</INF> emission source categories are expected to 
decline statewide by 51% by 2018. Area sources is the only source 
category expected to increase by 2018 (we are discounting the 2 tpy 
increase in road-dust). Increases in area source emissions are linked 
to population growth.

[[Page 18092]]

NOX

    NO<INF>X</INF> emissions in Colorado come mostly from point sources 
and from on-road and off-road mobile sources.

                                 Table 45--Colorado NOX Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................         118,667         101,818             -14
Area............................................................          11,729          16,360              39
On-Road Mobile..................................................         141,883          45,249             -68
Off-Road Mobile.................................................          62,448          37,916             -39
WRAP Area O & G.................................................          23,518          33,517              43
Road Dust.......................................................               1               1               0
Fugitive Dust...................................................              16              14             -13
Anthropogenic Fire..............................................             520             408             -21
Natural Fire....................................................           9,377           9,377               0
Biogenic........................................................          37,349          37,349               0
                                                                 -----------------------------------------------
    Total.......................................................         405,507         282,010             -30
----------------------------------------------------------------------------------------------------------------

    Overall, NO<INF>X</INF> emissions in Colorado are expected to 
decline by 30% by 2018. Area source and oil and gas emissions are the 
only source categories expected to increase. Area source emissions 
increases are related to population growth, and increases in oil and 
gas emissions are attributable to increased oil and gas development.

VOCs

    VOCs come from such sources as automobiles, industrial and 
commercial facilities, solvent use, and refueling automobiles. 
Substantial natural emissions of VOCs come from vegetation.

                                 Table 46--Colorado VOC Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................          91,750          77,312             -16
Area............................................................          99,191         136,032              37
On-Road Mobile..................................................         100,860          41,489             -59
Off-Road Mobile.................................................          38,401          24,684             -36
WRAP Area O & G.................................................          27,259          43,639              60
Road Dust.......................................................  ..............  ..............  ..............
Fugitive Dust...................................................  ..............  ..............  ..............
Anthropogenic Fire..............................................             915             666             -27
Natural Fire....................................................          20,404          20,404               0
Biogenic........................................................         804,777         804,777               0
                                                                 -----------------------------------------------
Total...........................................................       1,183,557       1,149,002              -3
----------------------------------------------------------------------------------------------------------------

    Overall, VOC emissions are projected to decrease by 3% statewide, 
with a 37% increase in area source emissions and a 60% increase in oil 
and gas emissions. Area source emission increases are a result of 
increased population growth, and increases in oil and gas emissions are 
attributable to increased oil and gas development.

OC

    OC are emitted directly from the combustion of organic material. A 
wide variety of sources contribute emissions to this pollutant, 
including diesel emissions and combustion byproducts from wood and 
agricultural burning.

                                 Table 47--Colorado OC Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................              17               3             -83
Area............................................................           8,432           8,738               4
On-Road Mobile..................................................           1,280           1,288               1
Off-Road Mobile.................................................           1,286             843             -34
WRAP Area O & G.................................................  ..............  ..............  ..............
Road Dust.......................................................             102             135              33
Fugitive Dust...................................................             777             677             -13
Anthropogenic Fire..............................................             850             621             -27
Natural Fire....................................................          30,581          30,581               0

[[Page 18093]]

 
Biogenic........................................................  ..............  ..............  ..............
                                                                 -----------------------------------------------
    Total.......................................................          43,325          42,886              -1
----------------------------------------------------------------------------------------------------------------

    Overall, OC emissions decrease by 1% in 2018. The main source 
category expected to increase by 2018 is road dust. The increase in 
road dust is associated with increases in population and more vehicle 
miles traveled.

EC

    Elemental carbon, also known as soot, is a byproduct of incomplete 
combustion. Emissions and reductions in this category are dominated by 
mobile sources. Expected new federal emission standards for mobile 
sources, especially for diesel engines, along with fleet replacement, 
are the reasons for the reductions.

                                 Table 48--Colorado EC Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................  ..............  ..............  ..............
Area............................................................           1,264           1,325               5
On-Road Mobile..................................................           1,448             408             -72
Off-Road Mobile.................................................           3,175           1,344             -58
WRAP Area O & G.................................................  ..............  ..............  ..............
Road Dust.......................................................               9              11              33
Fugitive Dust...................................................              53              46             -13
Anthropogenic Fire..............................................              92              74             -20
Natural Fire....................................................           6,337           6,337               0
Biogenic........................................................  ..............  ..............  ..............
                                                                 -----------------------------------------------
    Total.......................................................          12,377           9,545             -23
----------------------------------------------------------------------------------------------------------------

    Overall, this category is expected to decline by 23%, with on-road 
and off-road mobile sources expected to decline by 72% and 58%, 
respectively. The main source category expected to increase by 2018 is 
road dust. The increase in road dust is associated with increases in 
population and more vehicle miles traveled.

PM2.5

    Fine soil emissions are largely related to agricultural and mining 
activities, windblown dust from construction areas and emissions from 
unpaved and paved roads.

                                Table 49--Colorado PM2.5 Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................               6              85           1,404
Area............................................................           4,170           4,311               3
On-Road Mobile..................................................  ..............  ..............  ..............
Off-Road Mobile.................................................  ..............  ..............  ..............
WRAP Area O & G.................................................  ..............  ..............  ..............
Road Dust.......................................................           1,082           1,435              33
Fugitive Dust...................................................          13,401          11,679             -13
Windblown Dust..................................................          15,105          15,105               0
Anthropogenic Fire..............................................             253             169             -33
Natural Fire....................................................           1,948           1,948               0
Biogenic........................................................  ..............  ..............  ..............
                                                                 -----------------------------------------------
    Total.......................................................          35,964          34,732              -3
----------------------------------------------------------------------------------------------------------------

    Overall, PM<INF>2.5</INF> emissions are expected to decrease 3%. 
Increases in road dust emissions are tied to population growth and 
vehicle miles traveled.

PM10

    PM<INF>10</INF> is closely related to the same sources as fine soil 
emissions, but other activities like rock crushing and processing, 
material transfer, open pit mining, and unpaved road emissions can be 
prominent sources.

[[Page 18094]]



                                Table 50--Colorado PM10 Emissions--2002 and 2018
----------------------------------------------------------------------------------------------------------------
                         Source category                           Baseline 2002    Future 2018   Percent change
----------------------------------------------------------------------------------------------------------------
Point...........................................................          21,096          26,828              27
Area............................................................           1,363           1,388               2
On-Road Mobile..................................................             794             917              15
Off-Road Mobile.................................................  ..............  ..............  ..............
WRAP Area O & G.................................................  ..............  ..............  ..............
Road Dust.......................................................           8,930          11,826              32
Fugitive Dust...................................................          67,642          67,910               0
Windblown Dust..................................................         135,945         135,945               0
Anthropogenic Fire..............................................              51              32             -37
Natural Fire....................................................           5,973           5,973               0
Biogenic........................................................  ..............  ..............  ..............
                                                                 -----------------------------------------------
    Total.......................................................         241,794         250,818               4
----------------------------------------------------------------------------------------------------------------

    Overall, PM<INF>10</INF> emissions are expected to increase by 4% 
in 2018. Increases in coarse mass are seen in the fugitive dust 
category. The increase in PM<INF>10</INF> from road dust is associated 
with population growth and increased vehicle miles traveled. Point 
source emissions are addressed by the State for BART and RP sources.
2. Consultation and Emissions Reductions for Other States' Class I 
Areas
    40 CFR 51.308(d)(3)(i) requires that Colorado consult with another 
state if its emissions are reasonably anticipated to contribute to 
visibility impairment at that state's Class I area(s), and that 
Colorado consult with other states if those other states' emissions are 
reasonably anticipated to contribute to visibility impairment at its 
Class I areas. Colorado consulted with other states during ongoing 
participation in the WRAP while developing its SIP. Through the WRAP 
consultation process, Colorado has reviewed and analyzed contributions 
from other states that reasonably may cause or contribute to visibility 
impairment in Colorado's Class I areas and Colorado's impact on other 
states' Class I areas. The State held specific discussions with states 
that have a primary impact on Colorado Class I areas. These include 
California, Utah, Nebraska, Wyoming, New Mexico, and Arizona.
    40 CFR 51.308(d)(3)(ii) requires that if Colorado emissions cause 
or contribute to impairment in another state's Class I area, Colorado 
must demonstrate that it has included in its RH SIP all measures 
necessary to obtain its share of the emission reductions needed to meet 
the progress goal for that Class I area. Section 51.308(d)(3)(ii) also 
requires that, since Colorado participated in a regional planning 
process, it must ensure it has included all measures needed to achieve 
its apportionment of emission reduction obligations agreed upon through 
that process. As we state in the RHR, Colorado's commitments to 
participate in WRAP bind it to secure emission reductions agreed to as 
a result of that process.
    Colorado analyzed the WRAP PSAT modeling and determined that 
emissions from the State do not significantly impact other states' 
Class I areas. Colorado's largest visibility impacts are at Canyonlands 
National Park in Utah and Bandelier National Monument in New Mexico. 
Colorado's total nitrate and sulfate contributions represent 1.0% and 
0.5%, respectively, of total haze at these Class I areas. The State 
determined this is not a meaningful level of contribution. Colorado 
accepted and incorporated the WRAP-developed visibility modeling into 
its RH SIP, and the State's RH SIP includes the controls assumed in the 
modeling. Colorado satisfied the RHR's requirements for consultation 
and included controls in the SIP sufficient to address the relevant 
requirements of the RHR related to impacts on Class I areas in other 
states.
    We are proposing to find that the State has met the requirements 
for consultation under 40 CFR 51.308(d)(3)(ii) and 40 CFR 
51.308(d)(3)(iii).
3. Mandatory Long-Term Strategy Requirements
    40 CFR 51.308(d)(3)(v) requires that Colorado, at a minimum, 
consider certain factors in developing its long-term strategy (the 
long-term strategy factors). These are: (a) Emission reductions due to 
ongoing air pollution control programs, including measures to address 
reasonably attributable visibility impairment (RAVI); (b) measures to 
mitigate the impacts of construction activities; (c) emissions 
limitations and schedules for compliance to achieve the RPGs; (d) 
source retirement and replacement schedules; (e) smoke management 
techniques for agricultural and forestry management purposes including 
plans that currently exist within the state for these purposes; (f) 
enforceability of emissions limitations and control measures; and (g) 
the anticipated net effect on visibility due to projected changes in 
point, area, and mobile source emissions over the period addressed by 
the long-term strategy.
a. Reductions Due to Ongoing Air Pollution Programs
    In addition to its BART and RP determinations, the State's long-
term strategy contains other reductions due to ongoing air pollution 
programs. The State's long-term strategy contains both state only and 
federally enforceable programs. Some examples of these programs that 
are federally enforceable and the emission reductions they achieve 
include: (1) Oil and gas condensate tank control regulations for the 
Front Range region that have achieved approximately 52,000 tpy of VOC 
emission reductions by 2007 with additional projected reductions of 
18,000 tpy by 2010 (Regulation No. 7); (2) existing industrial engine 
control regulations for the Front Range region that have achieved 
NO<INF>X</INF> and VOC emissions reductions of approximately 8,900 tpy 
(Regulation No. 7); (3) PM<INF>10</INF> emission reduction programs in 
PM<INF>10</INF> maintenance areas throughout the State; and 4) fugitive 
dust control programs for construction, mining, vehicular traffic, and 
industrial sources state-wide (Regulation No. 1). The State has also 
adopted some of the federal NSPS and the New Source Review and PSD 
permit requirements for stationary sources. Additional information on 
ongoing air pollution programs is included in Chapter 9 of the State 
SIP.

[[Page 18095]]

b. Measures to Mitigate the Impacts of Construction Activities
    Regulation No.1 Particles, Smokes, Carbon Monoxide, and Sulfur 
Oxides and Regulation No. 3 Air Pollution Emission Notices--Permits 
have requirements that pertain to controlling emissions from 
construction activity. EPA has approved both regulations into the 
Colorado SIP. Regulation No. 3 requires air pollution sources to file 
Air Pollutant Emission Notices with the State. It also requires that 
new or modified sources of air pollution, with certain exemptions, 
obtain preconstruction permits. Regulation No. 1 sets forth emission 
limitations, equipment requirements and work practices (abatement and 
control measures) intended to control the emissions of particles, smoke 
and sulfur oxides from new and existing stationary sources, including 
construction activities.
c. Smoke Management
    Colorado addresses the requirements for smoke management in 
Regulation No. 9 Open Burning, Prescribed Fire, and Permitting. The 
intent of Regulation No. 9 is to prevent unacceptable smoke impacts, 
pertaining to both health and visibility. The rule applies to all open 
burning activity within Colorado, with the exception of agriculture 
open burning.\29\ Section III.A of the regulation requires anyone 
seeking to conduct open burning to obtain a permit from the State 
before conducting a burn. Regulation No. 9 also contains a number of 
factors the State must consider in determining whether and, if so, 
under what conditions, a permit may be granted. Some of the factors the 
State must consider include: the potential contribution of such burning 
to air pollution in the area; the meteorological conditions on the day 
or days of the proposed burning; the location of the proposed burn and 
smoke-sensitive areas and Class I areas that might be impacted by the 
smoke and emissions from the burn; whether the applicant will conduct 
the burn in accordance with a smoke management plan or narrative that 
requires that best smoke management methods will be used to minimize or 
eliminate smoke impacts at smoke-sensitive receptors (including Class I 
areas); and that the burn will be scheduled outside times of 
significant visitor use in smoke-sensitive receptor areas that may be 
impacted by smoke and emissions from the fire.
---------------------------------------------------------------------------

    \29\ The State has determined that agricultural burning is not a 
significant source of emissions related to regional haze impairment. 
For example, the State estimates that in 2004 only 503 tpy of 
PM<INF>10</INF> were generated from agricultural burning in the 
entire State of Colorado. See Colorado TSD document ``Agricultural 
Burning in Colorado, 2003 and 2004 Inventories.''
---------------------------------------------------------------------------

    The regulation requires all prescribed fire permitees to submit an 
application to the State. The State only grants a permit if the State's 
assessment demonstrates that under the prescribed meteorological 
conditions for the burn there will be no unacceptable air pollution, 
including visibility impacts. The regulation provides for the State to 
impose permit conditions necessary to ensure that the burn will be 
conducted to minimize the impacts of the fire on visibility and on 
public health and welfare. Permitted sources are also required to 
report actual activity to the State. Depending on the size and type of 
fire, reporting may be a daily requirement. At a minimum, permitted 
sources must report yearly to the State with information indicating 
whether or not there was any activity in the area covered by the permit 
and, if so, how many acres were burned.
    Colorado inputs fire data into the WRAP Fire Emissions Tracking 
System (FETS). The FETS gives the State more precise information for 
future inventories and studies. The State commits in this SIP to 
continue administration of Regulation 9 as part of this LTS, and to 
input data into the FETS as long as it is operational.
d. Emission Limitations and Schedules for Compliance
    The State has included the emission limitations and compliance 
schedules for those sources specifically identified for control in this 
RH SIP in Chapters 6 and 8, Regulation No. 3, Part F and Regulation 
No.7, Section XVII.E.3.a. For the BART sources, Regulation No. 3, 
section VI.A contains the emission limitations for each of the sources 
and provides that sources must comply as expeditiously as possible, but 
no later than five years from EPA approval of the SIP. For RP sources, 
Regulation No. 3, section VI.B, contains the emission limitations for 
each of the sources and provides that sources must comply no later than 
December 31, 2017. For the PSCO BART alternative, Regulation No. 3, 
section VI.C, contains the emission limitations and the compliance 
deadlines for sources covered by the PSCO BART alternative. Regulation 
No. 7, Section XVII.E.3.a contains the compliance schedule for RB RICE 
over 500 hp.
    We are proposing to approve the emission limits and compliance 
schedules contained in Regulation No. 3, sections VI.A, VI.B, and VI.C.
e. Sources Retirement and Replacement Schedules
    The State has included specific information on source retirement 
for those sources specifically identified for shutdown in its RH SIP. 
The State has identified the sources in the PSCO BART alternative that 
will shut down. Specifically, under the PSCO BART alternative, the 
following units will be retired: Arapahoe Unit 3 by December 31, 2013; 
Cherokee Unit 1 by July 1, 2012, Cherokee Unit 2 by December 31, 2011, 
Cherokee Unit 3 by December 31, 2016, and Valmont by December 31, 2017. 
The shutdown of the sources under the BART alternative is required by 
the RH SIP (see Chapter 6.4.3.7 of the SIP and Regulation No. 3, Part 
F, SectionVI.C). Under RP, PSCO Cameo Station and Black Hills Clark 
Facility Units 1 and 2 will be, or have already, shut down. The 
shutdown of these RP sources is required by the RH SIP (see Chapter 
8.5.2 of the SIP and Regulation No. 3, Part F, Section VI.B). The State 
is assuming that all other stationary sources evaluated in the SIP will 
remain in operation through the end of this planning period.
    The State is also assuming mobile source fleet turnover. For mobile 
sources, the turnover of the fleet from older, higher-emitting vehicles 
to newer, lower-emitting vehicles is captured in the emission inventory 
presented in section V.E.1 of this notice. The State developed the 
fleet turnover rate utilizing EPA-approved methodologies.
f. Enforceability of Colorado's Measures
    Section 51.308(d)(3)(v)(f) of the RHR requires States to ensure 
that emission limitations and control measures used to meet RPGs are 
enforceable. In addition to what is required by the RHR, general SIP 
requirements mandate that the SIP must also include adequate 
monitoring, recordkeeping, and reporting requirements for the RH 
emission limits and requirements. (see CAA section 110(a)). As noted 
above, Chapters 6 and 8 of the SIP and Regulation No. 3, Part F, 
Sections VI.A, VI.B, and VI.C, specify BART, RP, and BART alternative 
emission limits and compliance schedules. The State is submitting 
Regulation No. 3, Part F, Section VI, as part of the RH SIP.
    Regulation No. 3, Part F, Section VII, specifies monitoring, 
recordkeeping, and reporting requirements for BART, RP, and BART 
alternative units. The State is submitting Regulation No. 3, Part F, 
Section VII, as part of its RH SIP. Colorado worked closely with EPA in 
developing these requirements. For SO<INF>2</INF> and NO<INF>X</INF> 
limits, Colorado has required

[[Page 18096]]

sources to use continuous emission monitoring systems (CEMS) that must 
be operated and maintained in accordance with relevant EPA regulations, 
in particular, 40 CFR part 75 or 40 CFR part 60. For PM limits, 
Regulation No. 3 requires that sources perform testing in accordance 
with EPA approved test methods and that sources have a compliance 
assurance monitoring plan developed and approved in accordance with 40 
CFR part 64. Regulation No. 3, Part F, Section VII, requires that 
sources keep relevant records for five years, and that sources report 
excess emissions on a semi-annual basis.
g. Anticipated Net Effect on Visibility Due to Projected Changes
    The anticipated net effect on visibility due to projected changes 
in point, area, and mobile source emissions during this planning period 
is addressed in section V.D.3 of this notice.
    Based on our analysis, we have determined the State is meeting the 
long-term strategy requirements under 40 CFR 51.308(d)(3)(v). EPA is 
proposing to approve the State's long-term strategy found in Chapter 9 
of the SIP. In addition, EPA is proposing to approve Regulation No. 3, 
Part F, Section VI and Section VII.

F. Coordination of RAVI and Regional Haze Rule Requirements

    Our visibility regulations direct states to coordinate their RAVI 
long-term strategy and monitoring provisions with those for RH, as 
explained in section IV.F above. Under our RAVI regulations, the RAVI 
portion of a state SIP must address any integral vistas identified by 
the FLMs pursuant to 40 CFR 51.304 (see 40 CFR 51.302). An integral 
vista is defined in 40 CFR 51.301 as a view perceived from within the 
mandatory Class I Federal area of a specific landmark or panorama 
located outside the boundary of the mandatory Class I Federal area. 
Visibility in any mandatory Class I Federal area includes any integral 
vista associated with that area. The long-term strategy must have the 
capability of addressing current and future existing impairment 
situations as they face the state.
    Regulation No. 3, Part D, Section XIV provides FLMs the opportunity 
to certify whether an existing stationary source(s) is reasonably 
attributable to existing visibility impairment and potentially subject 
to BART and provides the State's review schedule for the RAVI long-term 
strategy. The EPA previously approved the State's 2004 RAVI long-term 
strategy as meeting the requirements of 40 CFR 51.306 (see 71 FR 
64465). In order to coordinate the RH long-term strategy and the RAVI 
long-term strategy, the State submitted revisions to Regulation No. 3, 
Part D, Section XIV. The State amended Regulation No. 3, Part D, 
Section XIV.F as part of this SIP action to change the current three-
year RAVI long-term strategy review cycle to a five-year cycle (as 
required by the RH Rule) to coordinate the RAVI and RH elements 
together as intended by the RH rule.
    We propose to find that the RH SIP appropriately supplements and 
augments Colorado's RAVI provisions by updating the monitoring and 
long-term strategy provisions to address RH. We discuss the relevant 
monitoring provisions further below. We are also proposing to approve 
the revision to Regulation No. 3, Part D, Section XIV.F, to change the 
review period from three years to five years to coordinate with the 
five-year periodic review required by the RH Rule.

G. Monitoring Strategy and Other Implementation Plan Requirements

    40 CFR 51.308(d)(4) requires that the SIP contain a monitoring 
strategy for measuring, characterizing, and reporting RH visibility 
impairment that is representative of all mandatory Class I Federal 
areas within the state. This monitoring strategy must be coordinated 
with the monitoring strategy required in 40 CFR 51.305 for RAVI. As 40 
CFR 51.308(d)(4) notes, compliance with this requirement may be met 
through participation in the IMPROVE network. 40 CFR 51.308(d)(4)(i) 
further requires the establishment of any additional monitoring sites 
or equipment needed to assess whether RPGs to address RH for all 
mandatory Class I Federal areas within the state are being achieved.
    Consistent with EPA's monitoring regulations for RAVI and RH, 
Colorado indicates in Chapter 3 of the RH SIP that it will rely on the 
IMPROVE network for compliance purposes, in addition to any additional 
visibility impairment monitoring that may be needed in the future. The 
IMPROVE monitors at the Colorado Class I Areas are described in section 
IV.B of this notice.
    Section 51.308(d)(4)(ii) requires that Colorado establish 
procedures by which monitoring data and other information are used in 
determining the contribution of emissions from within Colorado to RH 
visibility impairment at mandatory Class I Federal areas both within 
and outside the state. The IMPROVE monitoring program is national in 
scope, and other states have similar monitoring and data reporting 
procedures, ensuring a consistent and robust monitoring data collection 
system. As 40 CFR 51.308(d)(4) indicates, Colorado's participation in 
the IMPROVE program constitutes compliance with this requirement.
    Section 51.308(d)(4)(iv) requires that the SIP provide for the 
reporting of all visibility monitoring data to the Administrator at 
least annually for each mandatory Class I Federal area in the state. To 
the extent possible, Colorado should report visibility monitoring data 
electronically. Section 51.308(d)(4)(vi) also requires that the SIP 
provide for other elements, including reporting, recordkeeping, and 
other measures, necessary to assess and report on visibility. We 
propose that Colorado's participation in the IMPROVE network ensures 
that the monitoring data is reported at least annually and is easily 
accessible; therefore, such participation complies with this 
requirement. IMPROVE data are centrally compiled and made available to 
EPA, states and the public via various electronic formats and Web sites 
including IMPROVE (http://vista.cira.colostate.edu/improve/ improve/) and VIEWS 
(http://vista.cira.colostate.edu/views/).
    Section 51.308(d)(4)(v) requires that Colorado maintain a statewide 
inventory of emissions of pollutants that are reasonably anticipated to 
cause or contribute to visibility impairment in any mandatory Class I 
Federal 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. The state must also include a 
commitment to update the inventory periodically. The State's emission 
inventory is discussed in section V.E.1 above. Chapter 3 of the SIP 
states that Colorado will update its portion of the regional inventory 
on the tri-annual cycle as dictated by the Air Emissions Reporting Rule 
in order to track emission change commitments and trends as well as for 
input to regional modeling exercises.
    Section 51.308(d)(4)(vi) requires that states provide for any 
additional reporting, recordkeeping, and measures necessary to evaluate 
and report on visibility. The State has committed to provide any 
additional reporting, recordkeeping and measures necessary to evaluate 
and report on visibility but has concluded that it cannot identify a 
need for any specific commitment at this time. We agree with the 
State's conclusion that no specific additional measures are necessary 
at this time.
    We propose to find that Colorado has satisfied the requirements in 
40 CFR 51.308(d)(4).

[[Page 18097]]

H. Consultation With FLMs

    Class I areas in Colorado are managed by either the U.S. Forest 
Service (FS) or the U.S. National Park Service (NPS). Although the FLMs 
are very active in participating in the regional planning 
organizations, the RHR grants the FLMs a special role in the review of 
the RH SIPs, summarized in section IV.H, above. The FLMs and the state 
environmental agencies are our partners in the RH process. Under 40 CFR 
51.308(i)(2), Colorado was obligated to provide the FS and the NPS with 
an opportunity for consultation, in person and at least 60 days prior 
to holding a public hearing on the RH SIP. In development of its 2010 
RH SIP submittal, Colorado met with the FS and NPS for consultation on 
June 2, 2010, August 12, 2010, and October 5, 2010.
    Section CFR 51.308(i)(3) requires that Colorado provide in its RH 
SIP a description of how it addressed any comments provided by the 
FLMs. The FLMs formally commented on the 2010 proposed SIP in November 
and December of 2010. The NPS and FS provided support for the modeling 
approach used by the State in the BART determinations and complimented 
the State on thorough BART and RP analyses and area source evaluations. 
The FLMs also presented recommendations that the State reevaluate costs 
and emission limits for some of the BART and RP sources. Chapter 2.1 of 
the State's SIP provides more detailed information on the State's 
response to FLM comments.
    Lastly, 40 CFR 51.308(i)(4) specifies the RH SIP must provide 
procedures for continuing consultation between the state and FLMs on 
the implementation of the visibility protection program required by 40 
CFR 51.308. This includes development and review of implementation plan 
revisions and five-year progress reports and the implementation of 
other programs having the potential to contribute to impairment of 
visibility in mandatory Class I Federal areas. In Chapter 10 of the 
SIP, the State has included a commitment that it will provide the FLMs 
an opportunity to review and comment on SIP revisions, the five-year 
progress reports, and other developing programs that may contribute to 
Class I visibility impairment. Colorado will afford the FLMs with an 
opportunity for consultation in person and at least 60 days prior to 
holding any public hearing on a SIP revision. The FLM consultation must 
include the opportunity to discuss the FLMs' assessment of visibility 
impairment in each federal Class I area and to provide recommendations 
on the development and implementation of the visibility control 
strategies.

I. Periodic SIP Revisions and 5-Year Progress Reports

    In accordance with the requirements listed in 40 CFR 51.308(g), 
Colorado commits in Chapter 10 of its SIP to submit a report on RP to 
EPA every five years following the initial submittal of the SIP. That 
report will be in the form of an implementation plan revision. The 
State's report will evaluate the progress made towards the RPGs for 
each mandatory Class I area located within Colorado and in each 
mandatory Class I area located outside Colorado, which have been 
identified as being affected by emissions from Colorado. The State will 
also evaluate the monitoring strategy adequacy in assessing RPGs.
    Based on the findings of the five-year progress report, 40 CFR 
51.308(h) requires a state to make a determination of adequacy of the 
current implementation plan. The State must take one or more of the 
actions listed in 40 CFR 51. 308(h)(1) through (4) that are applicable 
at the same time as the state submits a five-year progress report. 
Colorado commits in Chapter 10 of the SIP to determine the adequacy of 
the current SIP at the same time a five-year progress report is due.
    Section CFR 51.308(f) requires a state to revise and submit its RH 
SIP to EPA by July 31, 2018, and every ten years thereafter. The State 
commits in Chapter 10 of the SIP to provide this revision and to 
evaluate and reassess elements required under 40 CFR 51.308(d), taking 
into account improvements in monitoring data collection and analysis, 
and control technologies.

VI. EPA's Proposed Action

    EPA is proposing to approve a SIP revision submitted by the State 
of Colorado on May 25, 2011 that addresses RH. EPA is proposing to 
determine that the plan submitted by Colorado satisfies requirements of 
the CAA and our rules under 40 CFR 51.308 that require states to 
prevent any future and remedy any existing man-made impairment of 
visibility in mandatory Class I areas. We are proposing to approve the 
State's RH SIP, including revisions submitted as part of the RH SIP to:
    <bullet> Regulation No. 3, Part F, Section VI and Section VII.
    <bullet> Regulation No. 3, Part D, Section XIV.F.
    <bullet> Regulation No. 7, Section XVII.E.3.a.

VII. Statutory and Executive Order Reviews

    Under the CAA, the Administrator is required to approve a SIP 
submission that complies with the provisions of the Act and applicable 
Federal regulations (42 USC 7410(k), 40 CFR 52.02(a)). Thus, in 
reviewing SIP submissions, EPA's role is to approve state choices, 
provided that they meet the criteria of the CAA. Accordingly, this 
proposed action merely approves state law as meeting Federal 
requirements; this proposed action does not impose additional 
requirements beyond those imposed by state law. For that reason, this 
proposed action:
    <bullet> Is not a ``significant regulatory action'' subject to 
review by the Office of Management and Budget under Executive Order 
12866 (58 FR 51735, October 4, 1993);
    <bullet> Does not impose an information collection burden under the 
provisions of the Paperwork Reduction Act (44 USC 3501 et seq.);
    <bullet> Is certified as not having a significant economic impact 
on a substantial number of small entities under the Regulatory 
Flexibility Act (5 USC 601 et seq.);
    <bullet> Does not contain any unfunded mandate or significantly or 
uniquely affect small governments, as described in the Unfunded 
Mandates Reform Act of 1995 (Pub. L. 104-4);
    <bullet> Does not have Federalism implications as specified in 
Executive Order 13132 (64 FR 43255, August 10, 1999);
    <bullet> Is not an economically significant regulatory action based 
on health or safety risks subject to Executive Order 13045 (62 FR 
19885, April 23, 1997);
    <bullet> Is not a significant regulatory action subject to 
Executive Order 13211 (66 FR 28355, May 22, 2001);
    <bullet> Is not subject to requirements of Section 12(d) of the 
National Technology Transfer and Advancement Act of 1995 (15 USC 272 
note) because application of those requirements would be inconsistent 
with the CAA; and,
    <bullet> Does not provide EPA with the discretionary authority to 
address, as appropriate, disproportionate human health or environmental 
effects, using practicable and legally permissible methods, under 
Executive Order 12898 (59 FR 7629, February 16, 1994).
    In addition, this rule does not have Tribal implications as 
specified by Executive Order 13175 (65 FR 67249, November 9, 2000), 
because the SIP is not approved to apply in Indian country located in 
the State, and EPA notes that it will not impose substantial direct 
costs on Tribal governments or preempt Tribal law.

[[Page 18098]]

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Intergovernmental 
relations, Nitrogen dioxide, Particulate matter, Reporting and 
recordkeeping requirements, Sulfur oxides, Volatile organic compounds.

    Dated: March 8, 2012.
James B. Martin,
Regional Administrator, Region 8.
[FR Doc. 2012-6908 Filed 3-23-12; 8:45 am]
BILLING CODE 6560-50-P


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