18052 Federal Register / Vol. 77, No. 58 / Monday, March 26, 2012 / Proposed Rules 

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. 

SUMMARY: EPA is proposing to approve 

a State implementation plan (SIP) 

revision submitted by the State of 

Colorado on May 25, 2011 that 

addresses regional haze (RH). EPA is 

proposing to determine that the plan 

submitted by Colorado satisfies the 

requirements of the Clean Air Act (CAA 

or ‘‘the Act’’) and our rules that require 

states to prevent any future and remedy 

any existing man-made impairment of 

visibility in mandatory Class I areas 

caused by emissions of air pollutants 

from numerous sources located over a 

wide geographic area (also referred to as 

the ‘‘regional haze program’’). States are 

required to assure reasonable progress 

toward the national goal of achieving 

natural visibility conditions in Class I 

areas. EPA is taking this action pursuant 

to section 110 of the CAA. 

DATES: Written comments must be 

received at the address below on or 

before May 25, 2012. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–R08– 

OAR–2011–0770, by one of the 

following methods: 

• http://www.regulations.gov. Follow 

the on-line instructions for submitting 

comments. 

• Email: dygowski.laurel@epa.gov. 

• Fax: (303) 312–6064 (please alert 

the individual listed in the FOR FURTHER

INFORMATION CONTACT if you are faxing 

comments). 

• Mail: Carl Daly, Director, Air 

Program, Environmental Protection 

Agency (EPA), Region 8, Mailcode 8P– 

AR, 1595 Wynkoop Street, Denver, 

Colorado 80202–1129. 

• Hand Delivery: Carl Daly, Director, 

Air Program, Environmental Protection 

Agency (EPA), Region 8, Mailcode 8P– 

AR, 1595 Wynkoop, Denver, Colorado 

80202–1129. Such deliveries are only 

accepted Monday through Friday, 8 a.m. 

to 4:30 p.m., excluding Federal 

holidays. Special arrangements should 

be made for deliveries of boxed 

information. 

Instructions: Direct your comments to 

Docket ID No. EPA–R08–OAR–2011– 

0770. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an email comment directly 

to EPA, without going through http:// 

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional instructions on 

submitting comments, go to Section I, 

‘‘General Information’’ of the 

SUPPLEMENTARY INFORMATION section of 

this document. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly-available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air Program, Environmental 

Protection Agency (EPA), Region 8, 

Mailcode 8P–AR, 1595 Wynkoop, 

Denver, Colorado 80202–1129. EPA 

requests that if at all possible, you 

contact the individual listed in the FOR

FURTHER INFORMATION CONTACT section to 

view the hard copy of the docket. You 

may view the hard copy of the docket 

Monday through Friday, 8 a.m. to 4 

p.m., excluding Federal holidays. 

FOR FURTHER INFORMATION CONTACT: 

Laurel Dygowski, Air Program, U.S. 

Environmental Protection Agency, 

Region 8, Mailcode 8P–AR, 1595 

Wynkoop, Denver, Colorado 80202– 

1129, (303) 312–6144, 

dygowski.laurel@epa.gov. 

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 BARTEligible 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 

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vi. Tri-State Generation Nucla Facility 

vii. Tri-State Craig Unit 3 

viii. PSCO Cameo Station 

ix. Area Oil and Gas Sources 

x. Combustion Turbines 

3. Reasonable Progress Goals 

E. Long Term Strategy 

1. Emission Inventories 

2. Consultation and Emissions Reductions 

for Other States’ Class I Areas 

3. Mandatory Long-Term Strategy 

Requirements 

a. Reductions Due to Ongoing Air Pollution 

Programs 

b. Measures to Mitigate the Impacts of 

Construction Activities 

c. Smoke Management 

d. Emission Limitations and Schedules for 

Compliance 

e. Sources Retirement and Replacement 

Schedules 

f. Enforceability of Colorado’s Measures 

g. Anticipated Net Effect on Visibility Due 

to Projected Changes 

F. Coordination of RAVI and RH Rule 

Requirements 

G. Monitoring Strategy and Other 

Implementation Plan Requirements 

H. Consultation with FLMs 

I. Periodic SIP Revisions and 5-year 

Progress Reports 

VI. EPA’s Proposed Action 

VII. Statutory and Executive Order Reviews 

Definitions 

For the purpose of this document, we are 

giving meaning to certain words or initials as 

follows: 

i. The words or initials Act or CAA mean 

or refer to the Clean Air Act, unless the 

context indicates otherwise. 

ii. The initials BACT mean or refer to Best 

Available Control Technology. 

iii. The initials BART mean or refer to Best 

Available Retrofit Technology. 

iv. The initials CAMx mean or refer to 

Comprehensive Air Quality Model. 

v. The initials CMAQ mean or refer to 

Community Multi-Scale Air Quality 

modeling system. 

vi. The initials CEMS mean or refer to 

continuous emission monitoring systems. 

vii. The words Colorado and State mean 

the State of Colorado. 

viii. The initials EC mean or refer to 

elemental carbon. 

ix. The initials EGUs mean or refer to 

Electric Generating Units. 

x. The words EPA, we, us or our mean or 

refer to the United States Environmental 

Protection Agency. 

xi. The initials FETS mean or refer to the 

Fire Emission Tracking System. 

xii. The initials FGD mean or refer to flue 

gas desulfurization. 

xiii. The initials FGR mean or refer to 

external flue gas recirculation. 

xiv. The initials FLMs mean or refer to 

Federal Land Managers. 

xv. The initials FS mean or refer to the U.S. 

Forest Service. 

xvi. The initials IMPROVE mean or refer to 

Interagency Monitoring of Protected Visual 

Environments monitoring network. 

xvii. The initials IWAQM mean or refer to 

Interagency Workgroup on Air Quality 

Modeling. 

xviii. The initials LB mean or refer to lean 

burn. 

xix. The initials LNB mean or refer to low 

NOX burner. 

xx. The initials LTS mean or refer to LongTerm Strategy. 

xxi. The initials MACT mean or refer to 

Maximum Achievable Control Technology. 

xxii. The initials NH3 mean or refer to 

ammonia. 

xxiii. The initials NOX mean or refer to 

nitrogen oxides. 

xxiv. The initials NPS mean or refer to 

National Park Service. 

xxv. The initials OC mean or refer to 

organic carbon. 

xxvi. The initials OFA mean or refer to 

overfire air. 

xxvii. The initials PM2.5 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers. 

xxviii. The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers. 

xxix. The initials PSAT mean or refer to 

Particle Source Apportionment Technology 

xxx. The initials PSD mean or refer to 

Prevention of Signification Deterioration. 

xxxi. The initials RAVI mean or refer to 

Reasonably Attributable Visibility 

Impairment. 

xxxii. The initials RB mean or refer to rich 

burn. 

xxxiii. The initials RH mean or refer to 

regional haze. 

xxxiv. The initials RH SIP mean or refer to 

Colorado’s RH State Implementation Plan. 

xxxv. The initials RHR mean or refer to the 

Regional Haze Rule. 

xxxvi. The initials RMC mean or refer to 

the Regional Modeling Center at the 

University of California Riverside. 

xxxvii. The initials ROFA mean or refer to 

rotating overfire air. 

xxxviii. The initials RP mean or refer to 

Reasonable Progress. 

xxxix. The initials RPGs mean or refer to 

Reasonable Progress Goals. 

xl. The initials RPOs mean or refer to 

regional planning organizations. 

xli. The initials RRI mean or refer to rich 

reagent injection. 

xlii. The initials SCR mean or refer to 

selective catalytic reduction. 

xliii. The initials SIP mean or refer to State 

Implementation Plan. 

xliv. The initials SNCR mean or refer to 

selective non-catalytic reduction. 

xlv. The initials SO2 mean or refer to sulfur 

dioxide. 

xlvi. The initials SOFA mean or refer to 

separated overfire air. 

xlvii. The initials TSD mean or refer to 

Technical Support Document. 

xlviii. The initials URP mean or refer to 

Uniform Rate of Progress. 

xlix. The initials VOC mean or refer to 

volatile organic compounds. 

l. The initials WEP mean or refer to 

Weighted Emissions Potential. 

li. The initials WRAP mean or refer to the 

Western Regional Air Partnership. 

I. General Information 

A. What should I consider as I prepare 

my comments for EPA? 

1. Submitting CBI. Do not submit CBI 

to EPA through http://www.regulations.

gov or email. Clearly mark the part or all 

of the information that you claim to be 

CBI. For CBI information in a disk or CD 

ROM that you mail to EPA, mark the 

outside of the disk or CD ROM as CBI 

and then identify electronically within 

the disk or CD ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. 

Information so marked will not be 

disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

2. Tips for Preparing Your Comments. 

When submitting comments, remember 

to: 

a. Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

b. Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

c. Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

d. Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

e. If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

f. Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

g. Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

h. Make sure to submit your 

comments by the comment period 

deadline identified. 

II. What action is EPA proposing to 

take? 

EPA is proposing to approve a SIP 

revision submitted by the State of 

Colorado on May 25, 2011 that 

addresses RH. In so doing, EPA is 

proposing to determine that the plan 

submitted by Colorado satisfies the 

requirements of 40 CFR 51.308. 

III. Background 

A. Regional Haze 

RH is visibility impairment that is 

produced by a multitude of sources and 

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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. 

2Areas 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.’’ 

3EPA’s regional haze regulations require 

subsequent updates to the regional haze SIPs. 40 

CFR 51.308(g)–(i). 

activities which are located across a 

broad geographic area and emit fine 

particles (PM2.5) (e.g., sulfates, nitrates, 

organic carbon (OC), elemental carbon 

(EC), and soil dust), and their precursors 

(e.g., sulfur dioxide (SO2), nitrogen 

oxides (NOX), and in some cases, 

ammonia (NH3) and volatile organic 

compounds (VOC)). Fine particle 

precursors react in the atmosphere to 

form PM2.5, which impairs visibility by 

scattering and absorbing light. Visibility 

impairment reduces the clarity, color, 

and visible distance that one can see. 

PM2.5 can also cause serious health 

effects and mortality in humans and 

contributes to environmental effects 

such as acid deposition and 

eutrophication. 

Data from the existing visibility 

monitoring network, the ‘‘Interagency 

Monitoring of Protected Visual 

Environments’’ (IMPROVE) monitoring 

network, show that visibility 

impairment caused by air pollution 

occurs virtually all the time at most 

national park and wilderness areas. The 

average visual range 1 in many Class I 

areas (i.e., national parks and memorial 

parks, wilderness areas, and 

international parks meeting certain size 

criteria) in the western United States is 

100–150 kilometers, or about one-half to 

two-thirds of the visual range that 

would exist without anthropogenic air 

pollution. In most of the eastern Class 

I areas of the United States, the average 

visual range is less than 30 kilometers, 

or about one-fifth of the visual range 

that would exist under estimated 

natural conditions. 64 FR 35715 (July 1, 

1999). 

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. 

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

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 § 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 ShoshoneBannock 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 

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4The preamble to the RHR provides additional 

details about the dv. 64 FR 35714, 35725 (July 1, 

1999). 

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’’). 

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

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

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 

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6The set of ‘‘major stationary sources’’ potentially 

subject to BART is listed in CAA section 169A(g)(7). 

7BART-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. 

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 ‘‘BARTeligible’’ 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. 

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. 

States must address all visibilityimpairing pollutants emitted by a source 

in the BART determination process. The 

most significant visibility impairing 

pollutants are SO2, NOX, and PM. EPA 

has stated that states should use their 

best judgment in determining whether 

VOC or NH3 compounds impair 

visibility in Class I areas. 

Under the BART Guidelines, states 

may select an exemption threshold 

value for their BART modeling, below 

which a BART-eligible source would 

not be expected to cause or contribute 

to visibility impairment in any Class I 

area. The state must document this 

exemption threshold value in the SIP 

and must state the basis for its selection 

of that value. Any source with 

emissions that model above the 

threshold value would be subject to a 

BART determination review. The BART 

Guidelines acknowledge varying 

circumstances affecting different Class I 

areas. States should consider the 

number of emission sources affecting 

the Class I areas at issue and the 

magnitude of the individual sources’ 

impacts. Any exemption threshold set 

by the state should not be higher than 

0.5 dv. 40 CFR part 51, appendix Y, 

section III.A.1. 

In their SIPs, states must identify the 

sources that are subject to BART and 

document their BART control 

determination analyses for such sources. 

In making their BART determinations, 

section 169A(g)(2) of the CAA requires 

that states consider the following factors 

when evaluating potential control 

technologies: (1) The costs of 

compliance; (2) the energy and non-air 

quality environmental impacts of 

compliance; (3) any existing pollution 

control technology in use at the source; 

(4) the remaining useful life of the 

source; and (5) the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. 

A RH SIP must include sourcespecific 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 

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8See Colorado TSD document titled Colorado 

Visibility Impacts on nearby Class I Areas. 

addressed by the LTS. 40 CFR 

51.308(d)(3)(v). 

F. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment (RAVI) 

As part of the RHR, EPA revised 40 

CFR 51.306(c) regarding the LTS for 

RAVI to require that the RAVI plan must 

provide for a periodic review and SIP 

revision not less frequently than every 

three years until the date of submission 

of the state’s first plan addressing RH 

visibility impairment, which was due 

December 17, 2007, in accordance with 

40 CFR 51.308(b) and (c). On or before 

this date, the state must revise its plan 

to provide for review and revision of a 

coordinated LTS for addressing RAVI 

and RH, and the state must submit the 

first such coordinated LTS with its first 

RH SIP. Future coordinated LTS’s, and 

periodic progress reports evaluating 

progress towards RPGs, must be 

submitted consistent with the schedule 

for SIP submission and periodic 

progress reports set forth in 40 CFR 

51.308(f) and 51.308(g), respectively. 

The periodic review of a state’s LTS 

must report on both RH and RAVI 

impairment and must be submitted to 

EPA as a SIP revision. 

G. Monitoring Strategy and Other 

Implementation Plan Requirements 

Section 51.308(d)(4) of the RHR 

includes the requirement for a 

monitoring strategy for measuring, 

characterizing, and reporting of RH 

visibility impairment that is 

representative of all mandatory Class I 

Federal areas within the state. The 

strategy must be coordinated with the 

monitoring strategy required in section 

51.305 for RAVI. Compliance with this 

requirement may be met through 

‘‘participation’’ in the IMPROVE 

network, i.e., review and use of 

monitoring data from the network. The 

monitoring strategy is due with the first 

RH SIP, and it must be reviewed every 

five years. The monitoring strategy must 

also provide for additional monitoring 

sites if the IMPROVE network is not 

sufficient to determine whether RPGs 

will be met. 

The SIP must also provide for the 

following: 

• Procedures for using monitoring 

data and other information in a state 

with mandatory Class I areas to 

determine the contribution of emissions 

from within the state to RH visibility 

impairment at Class I areas both within 

and outside the state; 

• Procedures for using monitoring 

data and other information in a state 

with no mandatory Class I areas to 

determine the contribution of emissions 

from within the state to RH visibility 

impairment at Class I areas in other 

states; 

• Reporting of all visibility 

monitoring data to the Administrator at 

least annually for each Class I area in 

the state, and where possible, in 

electronic format; 

• Developing a statewide inventory of 

emissions of pollutants that are 

reasonably anticipated to cause or 

contribute to visibility impairment in 

any Class I area. The inventory must 

include emissions for a baseline year, 

emissions for the most recent year for 

which data are available, and estimates 

of future projected emissions. A state 

must also make a commitment to update 

the inventory periodically; and 

• Other elements, including 

reporting, recordkeeping, and other 

measures necessary to assess and report 

on visibility. 

The RHR requires control strategies to 

cover an initial implementation period 

extending to the year 2018, with a 

comprehensive reassessment and 

revision of those strategies, as 

appropriate, every 10 years thereafter. 

Periodic SIP revisions must meet the 

core requirements of section 51.308(d) 

with the exception of BART. The 

requirement to evaluate sources for 

BART applies only to the first RH SIP. 

Facilities subject to BART must 

continue to comply with the BART 

provisions of section 51.308(e), as noted 

above. Periodic SIP revisions will assure 

that the statutory requirement of RP will 

continue to be met. 

H. Consultation With States and Federal 

Land Managers (FLMs) 

The RHR requires that states consult 

with FLMs before adopting and 

submitting their SIPs. 40 CFR 51.308(i). 

States must provide FLMs an 

opportunity for consultation, in person 

and at least 60 days prior to holding any 

public hearing on the SIP. This 

consultation must include the 

opportunity for the FLMs to discuss 

their assessment of impairment of 

visibility in any Class I area and to offer 

recommendations on the development 

of the RPGs and on the development 

and implementation of strategies to 

address visibility impairment. Further, a 

state must include in its SIP a 

description of how it addressed any 

comments provided by the FLMs. 

Finally, a SIP must provide procedures 

for continuing consultation between the 

state and FLMs regarding the state’s 

visibility protection program, including 

development and review of SIP 

revisions, five-year progress reports, and 

the implementation of other programs 

having the potential to contribute to 

impairment of visibility in Class I areas. 

V. EPA’s Evaluation of Colorado’s 

Regional Haze SIP 

The State of Colorado submitted a 

revision to its SIP to address the 

requirements for RH on May 25, 2011. 

The following is a discussion of our 

evaluation of the revision. 

A. Affected Class I Areas 

Pursuant to 40 CFR 51.308(d), the 

State identified 12 mandatory Class I 

areas in Colorado: Black Canyon of the 

Gunnison National Park, Eagles Nest 

Wilderness Area, Flat Tops Wilderness 

Area, Great Sand Dunes National Park, 

La Garita Wilderness Area, Maroon 

Bells-Snowmass Wilderness Area, Mesa 

Verde National Park, Mount Zirkel 

Wilderness Area, Rawah Wilderness 

Area, Rocky Mountain National Park, 

Weminuche Wilderness Area, and West 

Elk Wilderness Area. The State 

developed and submitted as part of its 

RH SIP technical support documents 

(TSDs) for each of the Class I areas. The 

Class I area TSDs include a detailed 

description of each area, along with 

photographs, summaries of monitoring 

data, an overview of current visibility 

conditions, and sources of pollution. 

The State also identified in the TSD 

areas outside of the State that modeling 

shows may be impacted from emissions 

from Colorado.8 These areas include: 

Upper Buffalo Wilderness in Arkansas; 

Petrified Forest National Park, Grand 

Canyon National Park, and Sycamore 

Canyon Wilderness in Arizona; 

Hercules-Glade Wilderness in Missouri; 

San Pedro Parks Wilderness, Bandelier 

National Monument, and Wheeler Peak 

in New Mexico; Wichita Mountains 

National Wildlife Refuge in Oklahoma; 

Wind Cave National Park and Badlands 

National Park in South Dakota; 

Canyonlands National Park and Capitol 

Reef National Park in Utah; and Bridger 

Wilderness in Wyoming. 

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 

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9The 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. 

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. 

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

Colorado class I areas Monitor 

name 

20% Worst Days 20% Best 

days 

2000–2004 

Baseline 

(dv) 

2018 

URP 

(dv) 

Reduction 

needed to 

reach 2018 

URP 

(delta dv) 

2064 

Natural 

conditions 

(dv) 

Delta 

Baseline— 

2064 Natural Conditions 

(dv) 

2000–2004 

Baseline 

(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 Wilderness ........................ WEMI1 10.33 9.37 0.96 6.21 4.12 3.11 

Eagles Nest Wilderness, Flat Tops Wilderness, 

Maroon Bells-Snowmass Wilderness, and 

West Elk Wilderness ........................................ WHRI1 9.61 8.78 0.83 6.06 3.55 0.70 

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 BARTeligible 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 visibilityimpairing pollutant from the units that 

meet the criteria in (1) and (2) are 250 

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10More 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. 

11Note 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. 

tons or more per year. Colorado 

reviewed source permits and emission 

data from 2001–2003 to identify 

facilities in the BART source categories 

with potential emissions of 250 tons per 

year or more for any visibility-impairing 

pollutant from any unit or units that 

were in existence on August 7, 1977 and 

began operation on or after August 7, 

1962. The BART Guidelines direct 

States to address SO2, NOX, and direct 

PM (including both coarse particulate 

matter (PM10) and fine particulate 

matter (PM2.5)) emissions as visibilityimpairing pollutants and to exercise 

their ‘‘best judgment to determine 

whether VOC or NH3 emissions from a 

source are likely to have an impact on 

visibility in an area.’’ (70 FR 39162). 

The State analyzed the emissions 

from VOC and NH3 from sources in the 

State. VOC is a precursor to OC. The 

State eliminated VOC from further 

consideration in the RH SIP as it 

determined statewide point source 

emissions of VOC constitute a negligible 

portion of the emission inventory for OC 

(3 tons per year (tpy)). Colorado also 

determined that statewide point sources 

of NH3 emissions are small. The State’s 

emission inventory for 2001–2003 

shows that point sources emitted 453 

tpy of NH3, while total State NH3

emissions are 67,686 tpy. Thus, the 

State has eliminated NH3 from further 

consideration.10 We have reviewed this 

information and propose to accept this 

determination. 

Table 2 lists the 12 sources that 

Colorado determined were BARTeligible. 

2. Sources Subject to BART 

The second step of the BART 

evaluation is to identify those BARTeligible 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 BARTeligible 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). 

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 BARTeligible 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 

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

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. 

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

Unit name Owner Source type 

State modeling 

results—98th 

percentile 

delta-Dv 

Subject to 

BART? 

Cemex—Lyons Cement Kiln and Dryer ......... Cemex ............................................................ Portland Cement .. 1 .53 Yes. 

CENC (Trigen-Colorado) Units 4 & 5 ............ Colorado Energy Nations Company (CENC) EGU ..................... 1 .26 Yes. 

Cherokee Station—Unit 4 .............................. Public Service Company of Colorado 

(PSCO).

EGU ..................... 1 .46 Yes. 

Comanche Station—Units 1 & 2 .................... PSCO ............................................................. EGU ..................... 0 .7 Yes. 

Craig Station—Units 1 & 2 ............................. Tri-State Generation and Transmission, Inc. 

(Tri-State).

EGU ..................... 2 .69 Yes. 

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 5, 6, & 7 ... Colorado Springs Utilities (CSU) ................... EGU ..................... 1 .04 Yes. 

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. 

13The State of Colorado originally modeled an impact of 0.57 dvs for Ray D. Nixon Power Plant. The source submitted refined modeling that 

showed an impact of 0.48 dvs. Both the State and EPA agree with the refined modeling submitted by the source. 

3. BART Determinations and Federally 

Enforceable Limits 

The third step of a BART evaluation 

is to perform the BART analysis. The 

BART Guidelines (70 FR 39164) 

describe the BART analysis as 

consisting of the following five steps: 

• Step 1: Identify All Available 

Retrofit Control Technologies; 

• Step 2: Eliminate Technically 

Infeasible Options; 

• Step 3: Evaluate Control 

Effectiveness of Remaining Control 

Technologies; 

• Step 4: Evaluate Impacts and 

Document the Results; and 

• Step 5: Evaluate Visibility Impacts. 

In determining BART, the State must 

consider the five statutory factors in 

section 169A of the CAA: (1) The costs 

of compliance; (2) the energy and nonair quality environmental impacts of 

compliance; (3) any existing pollution 

control technology in use at the source; 

(4) the remaining useful life of the 

source; and (5) the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. See also 40 

CFR 51.308(e)(1)(ii)(A). The five-factor 

analysis occurs during steps 4 and 5 of 

the BART analysis. 

Colorado performed BART 

determinations for all of the sources 

subject to BART for NOX, SO2, and PM. 

We find that Colorado adequately 

considered all five steps above in its 

BART determinations. 

State NOX Control Criteria 

For NOX, the State developed criteria 

to assist in the selection of postcombustion controls for BART. For the 

highest-performing NOX postcombustion control options (i.e., 

selective catalytic reduction (SCR) 

systems for electric generating units) 

that do not exceed a cost of $5,000 per 

ton and which provide a modeled 

visibility benefit of 0.50 dv or greater at 

the primary Class I Area affected, the 

State views that level of control as 

generally reasonable for BART. For 

lesser-performing NOX post-combustion 

control options (e.g., selective noncatalytic reduction (SNCR) technologies 

for electric generating units) that do not 

exceed a cost of $5,000 per ton which 

provide a modeled visibility benefit of 

0.20 dv or greater at the primary Class 

I Area affected, the State views that 

level of control as generally reasonable 

for BART. 

EPA does not necessarily agree that 

the State’s criteria for selecting NOX

controls would always be appropriate. 

First, the criteria appear to discriminate 

against SCR as a potential control 

option. Under the criteria, if the cost of 

SCR is under $5,000/ton and the 

modeled visibility benefit is 0.20 deltadv 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 postcombustion controls but not for other 

types of NOX controls. The criteria may 

also preclude a reasonable weighing of 

the five factors where the delta dv 

benefit is over 0.5 but the cost is higher 

than $5,000/ton. 

While we do not necessarily agree 

that the criteria used by the State would 

always be appropriate to select NOX

controls, we agree with the State’s 

determinations for NOX BART controls 

on the BART sources as discussed 

below. 

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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. 

SO2 Controls—Wet and Dry Scrubbing 

Scrubbing is one of the most common 

ways to control emissions of SO2 from 

stationary sources. Scrubbing can 

consist of either wet flue gas 

desulfurization (FGD) or dry FGD. The 

State eliminated wet FGD from 

consideration as a BART control 

because of negative non-air quality 

environmental impacts. The main nonair 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. 

Generally, wet FGD controls can 

achieve a slightly higher level of SO2

control than dry FGDs on a percent 

capture basis. Considering this, the State 

determined that the non-air quality 

environmental impacts outweigh any 

incremental improvement in SO2

emission reductions that would result 

from the use of wet FGDs rather than 

dry FGDs (see Chapter 6.4.1.3 of the 

SIP). EPA is proposing that the State 

provided adequate justification to 

eliminate the consideration of wet FGDs 

as SO2 BART controls. 

a. Visibility Improvement Modeling 

The BART Guidelines provide that 

states may use the CALPUFF modeling 

system or another appropriate model to 

determine the visibility improvement 

expected at a Class I area from potential 

BART control technologies applied to 

the source. Colorado performed 

CALPUFF modeling to determine the 

degree of visibility improvement 

expected at a Class I area based on the 

controls evaluated for BART for the 

subject-to-BART sources, with the 

exception of Cemex. For Cemex, the 

State relied on modeling submitted by 

the source based on a modeling protocol 

approved by the State. 

The BART Guidelines also 

recommend that states develop a 

modeling protocol for modeling 

visibility improvement, and suggest that 

states may want to consult with EPA 

and their RPO to address any issues 

prior to modeling. Colorado used the 

CALPUFF model for Colorado BART 

sources in accordance with a protocol it 

developed titled Supplemental BART 

Analysis CALPUFF Protocol for Class I 

Federal Area Visibility Improvement 

Modeling Analysis, revised August 19, 

2010, which was approved by EPA and 

is included in the Supporting and 

Related Materials section of the docket. 

The Colorado protocol follows 

recommendations for long-range 

transport described in appendix W to 40 

CFR part 51, Guideline on Air Quality 

Models, and in EPA’s Interagency 

Workgroup on Air Quality Modeling 

(IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long 

Range Transport Impacts, as 

recommended by the BART Guidelines. 

(40 CFR part 51, appendix Y, section 

III.D.5). 

b. Summary of BART Determinations 

and Federally Enforceable Limits 

In lieu of individual BART 

determinations, the State submitted a 

BART alternative as allowed for by 40 

CFR 51.308(e)(2) for three of the subjectto-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 subjectto-BART sources, the State provided 

analyses that took into consideration the 

five factors as required by section 

169A(g)(2) of the CAA. The State’s five 

factor analyses, as well as additional 

technical information and materials, are 

included in Appendix C of the SIP. 

Chapter 6 of the SIP provides a 

summary of the five factor analyses. 

EPA is proposing to approve the BART 

determinations submitted by the State 

for Cemex Lyons Kiln and Dryer, CENC 

Unit 4 and Unit 5, Comanche Unit 1 and 

Unit 2, Craig Unit 2, Hayden Unit 1 and 

Unit 2, and Martin Drake Unit 5, Unit 

6, and Unit 7. A summary of the BART 

determination for each source is 

provided below. 

i. Cemex Lyons Dryer and Kiln 

Background 

The Cemex facility manufactures 

Portland cement and is located in 

Lyons, Colorado, approximately 20 

miles from Rocky Mountain National 

Park. There are two BART-eligible units 

at the facility: The dryer and the kiln. 

The Lyons plant was originally 

constructed with a long dry kiln. In 

1980, the kiln was cut to one-half its 

original length, and a flash vessel was 

added with a single-stage preheater. The 

permitted kiln feed rate is 120 tons per 

hour of raw material (kiln feed), and on 

average yields approximately 62 tons of 

clinker per hour. The kiln is the main 

source of SO2 and NOX emissions. The 

raw material dryer emits minor amounts 

of SO2 and NOX. The State’s BART 

determination can be found in Chapter 

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 NOX; 0.89 tpy 

for SO2; and 5.12 tpy for PM. 

The State has determined that the 

2002 emissions best represent baseline 

emissions for the kiln because they 

correspond to the high range for SO2

emissions (which can vary significantly 

due to pyrites in the limestone) and the 

normal historical range for NOX

emissions and clinker production. The 

2002 baseline emissions for the kiln are: 

1,747 tpy for NOX; 95 tpy for SO2; and 

8.5 tpy for PM. 

SO2 and NOX BART Determination for 

the Dryer 

CALPUFF modeling provided by the 

source, using a maximum SO2 emission 

rate of 123.4 lbs/hour for both the dryer 

and kiln combined, shows a 98th 

percentile visibility impact of 0.78 delta 

dv at the most impacted Class I area, 

Rocky Mountain National Park. The 

State determined the modeling was 

performed correctly and EPA agrees 

with the State’s assessment. The 

modeled 98th percentile visibility 

impact from the kiln is 0.76 dv. Thus, 

the visibility impact of the dryer alone 

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is the resultant difference of 0.02 dv. 

Because of the extremely low visibility 

impact and emissions from the dryer, 

the State has determined that no 

meaningful visibility improvements 

would result from any conceivable 

controls on the dryer. The State has 

determined that SO2 and NOX BART for 

the Cemex dryer are the following 

existing emission limits: 36.7 tpy for 

SO2 and 13.9 tpy for NOX on a 12-month 

rolling average. 

EPA is proposing to approve the 

State’s SO2 and NOX BART 

determinations for the Cemex Lyons 

dryer. EPA agrees with the State that no 

significant visibility improvements 

would result from the application of 

controls on the dryer. 

SO2 BART Determination for the Kiln 

The kiln has no current SO2 controls, 

but approximately 80% of the SO2

emissions are captured as part of the 

inherent control of the kiln process. The 

State determined that lime addition to 

kiln feed, fuel substitution (coal with 

tire-derived fuel), dry sorbent injection 

(DSI), and wet lime scrubbing (WLS) 

were technically feasible for reducing 

SO2 emissions from the Cemex kiln. The 

State determined raw materials 

substitution was technically infeasible. 

The State did not identify any energy 

or non-air quality environmental 

impacts that would preclude the 

selection of any of the controls 

evaluated, and there are no remaininguseful-life issues for this source. A 

summary of the State’s SO2 BART 

analysis and the visibility impacts 

derived from modeling conducted by 

the source is provided in Table 3 below. 

TABLE 3—SUMMARY OF CEMEX-LYONS KILN SO2 BART ANALYSIS

Control technology Control 

efficiency (%) 

Annual controlled hourly 

SO2 emissions 

(lbs/hr) 

Emission 

reduction 

(tpy) 

Annualized 

cost 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

Lime Addition to Kiln Feed ...................... 25 19 23.8 $3,640,178 $153,271 0.033 

Fuel Substitution ...................................... 40 15.2 38 172,179 4,531 0.034 

DSI ........................................................... 50 12.7 47.5 ........................ ........................ 0.036 

WLS ......................................................... 90 2.5 85.5 2,529,018 29,579 0.040 

Based upon its consideration and 

weighing of the five factors, the State 

has determined that no additional SO2

emissions control on the kiln is 

reasonable for BART. The State 

determined that the added expense of 

any of the potential SO2 controls was 

not reasonable for the small visibility 

improvement of 0.04 dvs or less. Despite 

not having cost information on DSI, the 

State determined that the minimal 

visibility improvement of 0.036 dv does 

not justify further consideration of this 

control technology. The State has 

determined that emissions from the 

2002 baseline period represent BART 

for SO2 emissions for the kiln. The State 

determined that the SO2 BART emission 

limits for the kiln are 25.3 lbs/hour and 

95.0 tpy of SO2 (12-month rolling 

average). 

We are proposing to approve the 

State’s SO2 BART determination for the 

Cemex Lyons kiln. The State’s weighing 

of the factors was reasonable and 

resulted in a reasonable determination 

for SO2 BART. 

NOX BART Determination for the Kiln 

The kiln is currently uncontrolled for 

NOX emissions. The State determined 

that water injection, firing coal 

supplemented with tire-derived fuel 

(TDF), indirect firing with low NOX

burners (LNBs), SNCR, and the 

combination of SNCR and LNBs were 

technically feasible and appropriate for 

reducing NOX emissions from the 

Cemex kiln. The State determined that 

SCR is not commercially available for 

Portland cement kilns. EPA does not 

agree with the State’s assertion that SCR 

is not commercially available for 

Portland cement kilns. 

Although we disagree with the State’s 

conclusion on the commercial 

availability of SCR for cement kilns, we 

accept the State’s decision, for purposes 

of RH, not to analyze this control 

technology further. We note that EPA 

has acknowledged, in the context of 

establishing the New Source 

Performance Standards (NSPS) for 

Portland Cement Plants, substantial 

uncertainty regarding the cost 

effectiveness associated with the use of 

SCR at such plants. See 75 FR 54995. 

We expect the State to reevaluate this 

technology in subsequent RP planning 

periods. 

The State did not identify any energy 

or non-air quality environmental 

impacts that would preclude the 

selection of any of the controls 

evaluated, and there are no remaininguseful-life issues for this facility. A 

summary of the State’s NOX BART 

analysis and the visibility impacts 

derived from modeling conducted by 

the source is provided in Table 4 below. 

TABLE 4—SUMMARY OF CEMEX-LYONS KILN NOX BART ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Annual 

controlled 

hourly NOX

emissions (lbs/ 

hr) 

Emission 

reduction 

(tpy) 

Annualized 

cost 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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 

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As the table shows, SNCR with LNB 

could potentially achieve the greatest 

emission reductions for the control 

technologies evaluated. The CemexLyons 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°F) is significantly 

higher at the exit than a more typical 

preheater/precalciner kiln (650 °F). This 

limits the location and residence time 

available for an effective NOX control 

system. Because of this unique design, 

the State determined that SNCR and the 

combination of SNCR with LNBs have 

an uncertain level of control. Because 

the design of the Cemex kiln is unlike 

that for other kilns where SNCR has 

been successfully applied, it is 

uncertain whether SNCR can achieve 

emission reductions of 48.5%. The 

incremental reduction in visibility 

associated with SNCR in combination 

with LNBs would be 0.05 dv over just 

SNCR alone. Based on the uncertainty 

concerning the control efficiency of 

SNCR alone and SNCR with LNBs, and 

based on the small incremental 

visibility improvement that would 

result from SNCR in combination with 

LNBs over just SNCR, the State 

determined that BART for NOX equates 

to an emission limit consistent with 

SNCR at 45% control. The State 

determined that the NOX BART 

emission limits for the Cemex kiln are 

255.3 pounds per hour (30-day rolling 

average) and 901.0 tons per year (12- 

month rolling average). The State 

assumes the emission limits can be met 

with the installation and operation of 

SNCR. 

We agree with the State’s conclusion, 

and we are proposing to approve the 

State’s NOX BART determination for the 

Cemex-Lyons kiln. 

PM BART Determination 

PM emissions from the kiln and dryer 

are currently controlled by fabric filter 

baghouses and wet dust suppression 

techniques. Current PM emission limits 

are in compliance with the National 

Emission Standards for Hazardous Air 

Pollutants (NESHAP) for Source 

Categories; Portland Cement 

Manufacturing Industry, 40 CFR part 63, 

subpart LLL. The existing NESHAP 

regulatory emission limits for the kiln 

are 0.275 lb/ton of dry feed and 20% 

opacity. For the dryer, the emission 

limit is 22.8 tpy and 10% opacity. For 

sources already regulated by a NESHAP 

standard, EPA stated the following in 

the BART guidelines: ‘‘We believe that, 

in many cases, it will be unlikely that 

States will identify emission controls 

more stringent than the MACT 

standards without identifying control 

options that would cost many thousands 

of dollars per ton. Unless there are new 

technologies subsequent to the MACT 

standards which would lead to cost 

effective increases in the level of 

control, you may rely on the MACT 

standards for purposes of BART.’’ (70 

FR 39163) (MACT means Maximum 

Achievable Control Technology). 

The State determined that no new PM 

control methodologies could be 

identified that would improve upon the 

PM controls required in the NESHAP. 

The State determined that the current 

emission limit and control technology 

represent the most stringent level of 

control and are BART for PM for the 

Cemex-Lyons kiln and dryer. Per the 

BART Guidelines, if the BART source 

has the most stringent control 

technology and limit in place, a full 

five-factor analysis is not required (70 

FR 39165). The State determined that 

PM BART emission limits for the kiln 

are 0.275 lb/ton of dry feed and 20% 

opacity and the emission limits for the 

dryer are 22.8 tpy (12-month rolling 

average) and 10% opacity. The State 

assumes the limits can be achieved with 

the operation of the current fabric filter 

baghouses. 

We are proposing to approve the 

State’s PM BART determinations for the 

Cemex-Lyons kiln and dryer. We agree 

with the State that the existing controls 

and emission limits represent the most 

stringent level of PM control for this 

type of facility. 

ii. CENC Boilers 4 and 5 

Background 

This CENC facility is located adjacent, 

and supplies steam and electrical 

power, to the Coors Brewery in Golden, 

Colorado. The facility consists of five 

boilers and the associated equipment for 

coal and ash handling. Boilers 4 and 5 

are the only units that are subject to 

BART. Boiler 4 mainly fires coal, but 

can also fire natural gas. Fuel oil may be 

used as a backup fuel, but has not been 

used in recent years. Boiler 5 fires coal, 

but uses oil as a backup fuel. Either 

boiler may also fire ethanol or sludge 

from the Coors Brewery. Boiler 4 is 

rated at 360 MMBtu/hr and Boiler 5 at 

650 MMBtu/hr. Both boilers are 

pulverized-coal dry-bottom tangentiallyfired 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 SO2. The State 

determined that DSI and SO2 emission 

management were technically feasible 

for reducing SO2 emissions from Boilers 

4 and 5. The State determined that dry 

FGD controls were not technically 

feasible due to space constraints at the 

facility. Emissions management for SO2

encompasses a variety of options to 

reduce SO2 emissions, including 

dispatching natural gas-fired capacity, 

reducing total system load, and/or 

reducing coal firing rate to maintain a 

new peak SO2 limit. The State also 

evaluated tightening the emission limits 

for Boiler 4 and 5 based on current 

operations. 

The State did not identify any energy 

or non-air quality environmental 

impacts that would preclude the 

selection of any of the controls 

evaluated, nor are there any remaininguseful-life issues for the source. A 

summary of the State’s SO2 BART 

analysis and the visibility impacts is 

provided in Tables 5 and 6 below. The 

State did not model the visibility 

improvement of SO2 emissions 

management because the emission 

reduction from the control technology is 

negligible. The emission rate for each 

control option in the tables is reflective 

of the 30-day rolling average contained 

in the State’s BART analysis. Baseline 

SO2 emissions are 781 tpy for Boiler 4 

and 1,406 tpy for Boiler 5 based on the 

average of 2006–2008 actual emissions. 

TABLE 5—SUMMARY OF CENC BOILER 4 SO2 BART ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emission 

reduction 

(tpy) 

Annualized 

cost 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

SO2 Emissions Management ................... 0.13 .74 1 $44,299 $43,600 NA 

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TABLE 5—SUMMARY OF CENC BOILER 4 SO2 BART ANALYSIS—Continued 

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emission 

reduction 

(tpy) 

Annualized 

cost 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

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

TABLE 6—SUMMARY OF CENC BOILER 5 SO2 BART ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emission 

reduction (tpy) 

Annualized 

cost 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

SO2 Emissions Management ................... 0.063 .82 0.8 $65,882 $78,095 NA 

DSI ........................................................... 60 .33 844 2,094,000 2,482 0.13 

Based on its consideration of the five 

factors, the State determined that SO2

emissions management and DSI are not 

reasonable for BART. The State further 

evaluated emissions limit tightening 

based on current operations, which is a 

no-cost control option. The State 

determined that it would be appropriate 

to evaluate a lower emission limit based 

on percent sulfur and heat content. 

Based on the boiler sulfur to SO2

conversions, the State has determined 

that the SO2 BART emission limit for 

CENC Boiler 4 is 1.0 lb/MMBtu (30-day 

rolling average) and for Boiler 5 is 1.0 

lb/MMBtu (30-day rolling average). The 

details of the State’s calculation can be 

found in the State’s BART analysis. 

We agree with the State’s conclusions, 

and we are proposing to approve its SO2

BART determinations for CENC Boiler 4 

and Boiler 5. 

NOX BART Determination 

Boilers 4 and 5 are currently 

uncontrolled for NOX. The State 

determined that LNBs, LNBs plus 

separated overfire air (SOFA), SNCR, 

SNCR plus LNB plus SOFA, and SCR 

were technically feasible for reducing 

NOX emissions at CENC Boilers 4 and 

5. The State determined rich reagent 

injection (RRI), ECO System, and coal 

reburn with SNCR were technically 

infeasible. 

The State did not identify any energy 

or non-air quality environmental 

impacts that would preclude the 

selection of any of the controls 

evaluated, nor are there any remaininguseful-life issues for this source. A 

summary of the State’s NOX BART 

analysis and the visibility impacts is 

provided in Tables 7 and 8 below. The 

emission rate for each control option in 

the tables is reflective of the 30-day 

rolling average contained in the State’s 

BART analysis. Baseline NOX emissions 

are 600 tpy for Boiler 4 and 691 tpy for 

Boiler 5, based on the average of 2006– 

2008 actual emissions. 

TABLE 7—SUMMARY OF CENC BOILER 4 NOX BART ANALYSIS

Control technology Control 

efficiency (%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 

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15EPA’s AP–42 emission factor tables estimate 

that LNBs can control 35–55%, and LNB with OFA 

can control 40–60%, of NOX emissions. However, 

due to the size and configuration (e.g. furnace 

dimensions) of the CENC boilers, the State has 

determined that the estimated control efficiency for 

LNBs and LNBs with OFA used in the analysis are 

reasonable. 

Based on its consideration of the five 

factors, the State determined BART is 

LNBs + SOFA for Boiler 4 and LNBs + 

SOFA + SNCR for Boiler 5. Although 

SCR achieves better emissions 

reductions, the State determined that 

SCR is not reasonable based on the high 

cost effectiveness values and the low 

visibility improvement afforded by this 

control. The State has determined that 

the NOX BART emission limit for CENC 

Boiler 4 is 0.37 lb/MMBtu (30-day 

rolling average) and for Boiler 5 is 0.19 

lb/MMBtu (30-day rolling average). The 

State assumes the BART emission limits 

can be achieved by the installation and 

operation of LNBs with SOFA on Boiler 

4 and LNBs + SOFA + SNCR on Boiler 

5. 

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 BARTeligible sources (70 FR 39172). Pursuant 

to this, the State also established a 

combined NOX BART limit for CENC 

Boiler 4 and Boiler 5 of 0.26 lb/MMBtu 

on a 30-day rolling average. 

We agree with the State’s conclusions, 

and we are proposing to approve the 

State’s NOX BART determinations for 

CENC Boiler 4 and Boiler 5. 

PM BART Determination 

CENC Boilers 4 and 5 are each 

equipped with fabric filter baghouses to 

control PM emissions with a current 

emission limit of 0.07 lb/MMBtu. Fabric 

filter baghouses are the most stringent 

control technology for controlling PM 

emissions, and stack tests show that the 

fabric filter baghouses are achieving a 

98% reduction in PM. The State 

determined that PM BART for Boiler 4 

and Boiler 5 is an emission limit of 0.07 

lb/MMBtu. The State assumes the BART 

emission limit can be met with the 

operation of the current fabric filter 

baghouses. 

While we do not agree with all of the 

State’s assumptions and conclusions in 

arriving at a PM BART limit of 0.07 lb/ 

MMBtu, we are proposing to approve 

the State’s PM BART determinations for 

CENC Boiler 4 and Boiler 5. Based on 

our review/analysis, CENC is capable of 

achieving a lower emission limit than 

0.07 lb/MMBtu with existing 

equipment. However, we anticipate that 

the visibility improvement that would 

result from lowering the limit from 0.07 

lb/MMBtu to 0.03 lb/MMBtu would be 

insignificant. Under these 

circumstances, we propose to find that 

the State’s BART determination was 

reasonable. 

iii. PSCO Comanche Station Units 1 and 

2 

Background 

Comanche Station is located in 

Pueblo, Colorado. It consists of three 

coal-fired EGUs, Units 1, 2, and 3. Unit 

1 is rated at 325 megawatts (MW) and 

Unit 2 is rated at 335 MW. Unit 1 and 

Unit 2 are the only subject-to-BART 

units at Comanche Station. The boilers 

burn sub-bituminous coal as fuel and 

use natural gas for startup, shutdown, 

and flame stabilization. Both units are 

dry-bottom pulverized coal-fired boilers. 

Unit 1 is tangentially fired and Unit 2 

is wall-fired. 

In August of 2004, PSCO proposed to 

construct and operate Unit 3 at 

Comanche Station. As part of the 

project, PSCO proposed to install NOX

and SO2 control devices on Unit 1 and 

Unit 2 and take new emission limits on 

those units. In November 2008, PSCO 

installed LNBs with OFA and a lime 

spray dryer (LSD) on Unit 1, and in 

November 2007, PSCO installed LNBs 

with OFA and a LSD on Unit 2. 

Operation of the LSDs did not 

commence until June 3, 2009 for Unit 1 

and January 10, 2009 for Unit 2. The 

State’s BART determination for 

Comanche Station Units 1 and 2 can be 

found in Chapter 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 SO2 emissions are 

1,557 tpy for Unit 1 and 1,244 tpy for 

Unit 2 based on 2009 actual emissions. 

The current emission limit for Units 1 

and 2 is 0.12 lb/MMBtu each on a 30- 

day rolling average and a combined 

annual average of 0.10 lb/MMBtu. Per 

the BART Guidelines, for EGUs with 

preexisting post-combustion SO2

controls achieving removal efficiencies 

of at least 50 percent, states should 

consider cost effective scrubber 

upgrades designed to improve the 

system’s overall SO2 removal efficiency 

(70 FR 39171). Under the BART 

Guidelines, a state is not required to 

evaluate the replacement of the current 

SO2 controls if their removal efficiency 

is over 50%. The State’s BART analysis 

evaluated numerous LSD upgrades 

including: (1) Use of performance 

additives; (2) use of more reactive 

sorbent; (3) increasing the pulverization 

level of sorbent; (4) engineering redesign 

of atomizer or slurry injection system; 

and (5) additional equipment and 

maintenance. The State analyzed the 

potential upgrades and determined all 

upgrades were either technically 

infeasible or would not achieve a 

decrease in current SO2 emissions. 

The State also assessed emissions 

limit tightening based on current 

operations. The State reviewed available 

SO2 emissions data from EPA’s Clean 

Air Markets Division (CAMD) for 2009 

and for part of 2010 (January–October 

2010). Since the LSDs only recently 

commenced full operation, there was 

limited data available for the State to 

determine post-control achievable 

emissions. In its submittal to the State, 

PSCO provided additional information 

pertaining to emissions limit tightening. 

PSCO stated that during low-load 

operations the inlet temperature at the 

baghouse approaches the minimum 

acceptable level, lowering the overall 

SO2 control efficiency during low-load 

operations. PSCO indicated that, due to 

the increased use of wind resources, the 

boilers will be required to cycle more 

frequently to accommodate intermittent 

wind resources, and, therefore, the units 

will run at low loads more frequently. 

As a result, the SO2 reduction levels 

will be lower during those times. 

Based on this information, the State 

determined that the limited emissions 

data from 2009 and 2010 may not 

accurately represent future plant 

emissions. In addition, since the LSDs 

only came on line recently, the State 

recognized that PSCO has limited 

operating experience with these units. 

Although PSCO has other units that are 

equipped with LSDs, Comanche Station 

Units 1 and 2 are the first such units in 

PSCO’s system that are firing Powder 

River Basin coal. After startup of the 

LSDs in 2009, both units have had a 

number of days indicating zero 

emissions, presumably due to a unit 

shutdown. In many cases, emissions 

data shows that for one or more days 

following these events, the daily SO2

emission rate is frequently well above 

0.12 lb/MMBtu. In looking at the data, 

the State also found that both units have 

historically lower inlet temperatures to 

the scrubbers in the winter months, 

resulting in increased SO2 emissions. 

Based on the information discussed 

above, the State concluded that a tighter 

30-day rolling average and annual 

average SO2 emission limit is not 

feasible at this time for either unit. 

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Based on its analysis, the State 

determined that the SO2 BART emission 

limit for Comanche Station Unit 1 is 

0.12 lb/MMBtu (30-day rolling average) 

and for Unit 2 is 0.12 lb/MMBtu (30-day 

rolling average). The State also 

established a SO2 BART emission limit 

of 0.10 lb/MMBtu, combined annual 

average for both units. 

We agree with the State’s conclusions 

and are proposing to approve its SO2

BART determinations for Comanche 

Station Unit 1 and Unit 2. 

NOX BART Determination 

Comanche Station Units 1 and 2 

currently have a NOX permit limit of 

0.20 lb/MMBtu on a 30-day rolling 

average for each unit and a combined 

annual average limit of 0.15 lb/MMBtu. 

The State determined that SCR and 

SNCR were technically feasible at Unit 

1 and SCR was technically feasible for 

Unit 2. PSCO conducted testing in the 

fall of 2008 on Unit 2 using a temporary 

SNCR system. PSCO performed the 

testing following the installation of 

LNBs and OFA to determine if 

additional reductions could be 

achieved. PSCO primarily conducted 

testing at full load over a seven-day 

period using a single-level urea based 

SNCR system. The SNCR system is 

sensitive to temperature and average 

exhaust temperature in the injection 

area for Unit 2 was nearly 2,200 °F, 

which exceeds the optimal temperature 

for the technology. During the test 

periods, NOX reductions were less than 

10%, and in some cases during testing, 

an actual increase in NOX emissions 

was observed by PSCO. Based on the 

results of PSCO’s test of SNCR on Unit 

2, the State did not evaluate SNCR 

further as a control option for Unit 2. 

The State also determined that ECO 

system and RRI were technically 

infeasible for both units. The State did 

not evaluate rotating opposed fire air 

(ROFA) and reburning because they do 

not achieve better emission reductions 

than the current controls. 

The State did not identify any energy 

or non-air quality environmental 

impacts that would preclude the 

selection of any of the controls 

evaluated, nor are there any remaininguseful-life issues for this source. 

Baseline NOX emissions from the 2009 

calendar year are 1,511 tpy for Unit 1 

and 2,349 tpy for Unit 2. A summary of 

the State’s NOX BART analysis and the 

visibility impacts is provided in Tables 

9 and 10 below. The emission rate for 

each control option in the tables is 

reflective of the 30-day rolling average 

contained in the State’s BART analysis. 

TABLE 9—SUMMARY OF COMANCHE STATION UNIT 1 NOX BART ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

SCR .......................................................... 63 0.07 1480 $14,650,885 $9,900 0.17 

Based on its consideration of the five 

factors, the State has determined that 

the NOX BART emission limit for 

Comanche Station Unit 1 is 0.20 lb/ 

MMBtu (30-day rolling average) and for 

Unit 2 is 0.20 lb/MMBtu (30-day rolling 

average). The State also established a 

NOX BART emission limit of 0.15 lb/ 

MMBtu, combined annual average for 

both units. 

The State assumes that the BART 

emission limits can be achieved through 

the operation of existing LNBs. 

Although the other alternatives achieve 

better emissions reductions, the State 

determined that the added expense of 

achieving lower limits through different 

controls was not reasonable based on 

the high cost effectiveness coupled with 

the low visibility improvement (under 

0.2 dv) afforded. 

We agree with the State’s conclusions, 

and we are proposing to approve the 

State’s NOX BART determinations for 

Comanche Station Unit 1 and Unit 2. 

PM BART Determination 

Comanche Station Units 1 and 2 are 

each equipped with fabric filter 

baghouses to control PM emissions with 

an emission limit of 0.03 lb/MMBtu. 

Stack tests show that the fabric filter 

baghouses are achieving a 99% 

reduction in PM. Fabric filter baghouses 

are the most stringent control 

technology for controlling PM 

emissions. The State also evaluated 

what would constitute the most 

stringent level of control for PM by 

looking at recent Best Available Control 

Technology (BACT) determinations. 

Based on this evaluation, the State 

determined that an emission limit of 

0.03 lb/MMBtu represents the most 

stringent level of control for this type of 

source. Consistent with the BART 

Guidelines, the State did not provide a 

full five-factor analysis because the 

State determined BART to be the most 

stringent control technology and limit. 

The State determined that the PM BART 

limit for Comanche Station Units 1 and 

2 is 0.03 lb/MMBtu (30-day rolling 

average). The State assumes the BART 

limit can be met with the operation of 

the existing fabric filter baghouses. 

We agree with the State’s conclusions, 

and we are proposing to approve its PM 

BART determinations for Comanche 

Station Unit 1 and Unit 2. 

iv. Tri-State Craig Units 1 and 2 

Background 

The Tri-State Generation & 

Transmission Association, Inc. (TriState) Craig Station is located in Moffat 

County approximately 2.5 miles 

southwest of the town of Craig, 

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16Although 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. 

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 SO2 emission limit of 

0.16 lb/MMBtu on a 30-day rolling 

average and a requirement to achieve a 

90% reduction of SO2 (90-day rolling 

average). Per the BART Guidelines, for 

EGUs with preexisting post-combustion 

SO2 controls achieving removal 

efficiencies of at least 50 percent, states 

should consider cost effective scrubber 

upgrades designed to improve the 

system’s overall SO2 removal efficiency 

(70 FR 39171). Under the BART 

Guidelines, a state is not required to 

evaluate the replacement of the current 

SO2 controls if their removal efficiency 

is over 50%. 

The State evaluated the following wet 

FGD upgrades: (1) Elimination of bypass 

reheat; (2) installation of liquid 

distribution rings; (3) installation of 

perforated trays; (4) use of organic acid 

additives; (5) improve or upgrade 

scrubber auxiliary equipment; and (6) 

redesign spray header or nozzle 

configuration. Tri-State performed 

numerous upgrades at Units 1 and 2 

during 2003–2004. The State 

determined that Tri-State had installed 

all of the above upgrades with the 

exception of liquid distribution rings 

and use of organic additives. The State 

determined that the installation of 

perforated trays achieved the same 

objective as these upgrades. 

The State evaluated emission limit 

tightening based on current operations. 

The State analyzed the baseline period 

(2006–2008) emission data from EPA’s 

CAMD to determine the maximum and 

average 30-day rolling emission rates. 

The emissions data shows that the 

maximum 30-day rolling average was 

0.08 lb/MMBtu for Unit 1 and 0.09 lb/ 

MMBtu for Unit 2. The average 30-day 

rolling emission rate was 0.05 lb/ 

MMBtu for Unit 1 and 0.08 for Unit 2. 

The daily maximum over the three-year 

period was 0.17 lb/MMBtu for Unit 1 

and 0.16 lb/MMBtu for Unit 2. Table 11 

shows the visibility improvement 

modeled by the State for possible lower 

SO2 emission limits. 

TABLE 11—CRAIG UNIT 1 AND UNIT 2 SO2 VISIBILITY IMPROVEMENT

SO2 Control 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Craig unit 1— 

visibility 

improvement 

(delta dv for the 

maximum 98th 

percentile impact) 

Craig unit 2— 

visibility 

improvement 

(delta dv for the 

maximum 98th 

percentile impact) 

Wet FGD .......................................................................................................................... 0.11 0.03 0.03 

Wet FGD .......................................................................................................................... 0.07 0.05 0.05 

The State determined that an 

emission limit of 0.11 lb/MMBtu would 

be achievable without additional capital 

investment. The State determined that 

an emission limit lower than 0.11 lb/ 

MMBtu would likely require additional 

capital expenditure and determined it 

was not reasonable for the incremental 

visibility improvement of 0.02. The 

State has determined that the SO2 BART 

emission limit for Craig Unit 1 is 0.11 

lb/MMBtu (30-day rolling average) and 

for Unit 2 is 0.11 lb/MMBtu (30-day 

rolling average). The State assumes that 

the BART emission limits can be 

achieved through the operation of the 

existing wet FGD. 

We agree with the State’s conclusions, 

and we are proposing to approve its SO2

BART determinations for Craig Unit 1 

and Unit 2. 

NOX BART Determination 

Craig Units 1 and 2 are currently 

controlled with ultra low NOX burners 

(ULNBs) plus OFA, achieving emission 

reductions of about 54 percent each. 

The State determined that combustion 

control refinements, neural network 

systems, SNCR, and SCR were 

technically feasible. 16 The State 

determined that ECO, RRI, ROFA, and 

coal reburn plus SNCR were not 

technically feasible. The State did not 

identify any energy or non-air quality 

environmental impacts that would 

preclude the selection of any of the 

controls evaluated, nor are there any 

remaining-useful-life issues for this 

source. Baseline NOX emissions are 

5,190 tpy for Unit 1 and 5,372 tpy for 

Unit 2 based on the average of 2006– 

2008 actual emissions. A summary of 

the State’s NOX BART analysis and the 

visibility impacts is provided in Tables 

12 and 13 below. The emission rate for 

each control option in the tables is 

reflective of the 30-day rolling average 

contained in the State’s BART analysis. 

Due to the very small percent control 

achieved with combustion control 

refinements and neural network 

systems, the State did not perform 

visibility modeling for these two control 

options. Thus, Tables 12 and 13 do not 

show a value for visibility improvement 

for these options. 

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TABLE 12—SUMMARY OF CRAIG UNIT 1 NOX BART ANALYSIS

Control technology 

Control efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 NOX 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 NOX

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 NOX 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 NOX 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 NOX 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 NOX 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 SO2 emission limit 

of 0.16 lb/MMBtu (30-day rolling 

average) and a requirement to achieve 

an 82% reduction of SO2 (30-day rolling 

average). As mentioned earlier, if a 

BART source has current SO2 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 

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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 SO2 emissions. The State 

determined that engineering redesign 

using an additional scrubber vessel and 

additional equipment and maintenance 

were technically feasible and would 

potentially achieve SO2 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 remaininguseful-life issues for this source. 

Baseline SO2 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 SO2

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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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

Control technology 

Control efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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 

SO2 BART controls and that a more 

stringent 30-day rolling SO2 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 SO2 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 SO2

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 NOX 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 NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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 

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TABLE 17—SUMMARY OF HAYDEN UNIT 2 NOX BART ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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 NOX 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 

NOX 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 fivefactor 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, frontfired 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 SO2. 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 remaininguseful-life issues for this source. 

Baseline SO2 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 SO2 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

Effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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 

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TABLE 19—SUMMARY OF MARTIN DRAKE UNIT 6 SO2 BART ANALYSIS—Continued 

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility improvement 

(delta dv for 

the maximum 

98th 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 SO2 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 SO2 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 SO2

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 NOX 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 remaininguseful-life issues for this source. 

Baseline NOX 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 NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 

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TABLE 22—SUMMARY OF MARTIN DRAKE UNIT 6 NOX BART ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission 

rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(Delta dv for 

the maximum 

98th 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

Control 

technology 

Control 

efficiency 

(%) 

Emission 

rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(Delta dv for 

the maximum 

98th 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 NOX

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 NOX 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 NOX 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

Emission unit Assumed NOX control type NOX emission limit Assumed SO2 control type SO2 emission limit 

Assumed particulate 

control and emission 

limit 

Cemex-Lyons Kiln .... SNCR ...................... 255.3 lbs/hr (30-day rolling average) 901.0 tpy 

(12-month rolling average).

None ....................... 25.3 lbs/hr (12-month 

rolling average) 95.0 

tpy (12-month rolling 

average).

Fabric Filter 

Baghouse * 0.275 

lb/ton of dry feed 

20% opacity. 

Cemex-Lyons Dryer None ....................... 13.9 tpy ......................... None ....................... 36.7 tpy ......................... Fabric Filter 

Baghouse * 22.8 

tons/yr 10% opacity. 

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TABLE 24—SUMMARY OF THE STATE’S BART DETERMINATIONS EPA IS PROPOSING TO APPROVE—Continued 

Emission unit Assumed NOX control type NOX emission limit Assumed SO2 control type SO2 emission limit 

Assumed particulate 

control and emission 

limit 

CENC Unit 4 ............ LNBs with OFA ....... 0.37 lb/MMBtu (30-day 

rolling average) Or 

0.26 lb/MMBtu Combined Average for 

Units 4 & 5 (30-day 

rolling average).

None ....................... 1.0 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.07 

lb/MMBtu. 

CENC Unit 5 ............ LNBS with SOFA 

and SNCR.

0.19 lb/MMBtu (30-day 

rolling average) Or 

0.26 lb/MMBtu Combined Average for 

Units 4 & 5 (30-day 

rolling average).

None ....................... 1.0 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.07 

lb/MMBtu. 

Comanche Unit 1 ..... LNBs * ..................... 0.20 lb/MMBtu (30-day 

rolling average) 0.15 

lb/MMBtu (combined 

annual average for 

units 1 & 2).

Lime Spray Dryer * 0.12 lb/MMBtu (30-day 

rolling average) 0.10 

lb/MMBtu (combined 

annual average for 

units 1 & 2).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Comanche Unit 2 ..... LNBs* ...................... 0.20 lb/MMBtu (30-day 

rolling average) 0.15 

lb/MMBtu (combined 

annual average for 

units 1 & 2).

Lime spray Dryer * .. 0.12 lb/MMBtu (30-day 

rolling average) 0.10 

lb/MMBtu (combined 

annual average for 

units 1 & 2).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Craig Unit 1 .............. SNCR ...................... 0.28 lb/MMBtu (30-day 

rolling average).

Wet Limestone 

scrubber *.

0.11 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Craig Unit 2 .............. SCR ........................ 0.08 lb/MMBtu (30-day 

rolling average).

Wet Limestone 

scrubber *.

0.11 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Hayden Unit 1 .......... SCR ........................ 0.08 lb/MMBtu (30-day 

rolling average).

Lime Spray Dryer * 0.13 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Hayden Unit 2 .......... SCR ........................ 0.07 lb/MMBtu (30-day 

rolling average).

Lime Spray Dryer * 0.13 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Martin Drake Unit 5 .. ULNBs with OFA .... 0.31 lb/MMBtu (30-day 

rolling average).

Dry Sorbent Injection.0.26 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Martin Drake Unit 6 .. ULNBs with OFA .... 0.31 lb/MMBtu (30-day 

rolling average).

Lime Spray Dryer or 

Equivalent Control 

Technology.

0.13 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Martin Drake Unit 7 .. ULNBs with OFA .... 0.29 lb/MMBtu (30-day 

rolling average).

Lime Spray Dryer or 

Equivalent Control 

Technology.

0.13 lb/MMBtu (30-day 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/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

Unit BART 

eligible? NOX control type NOX emission uimit SO2 control type SO2 emission limit Particulate type 

and limit 

Cherokee Unit 1 ..... No ............ Shutdown by 7/1/ 

2012.

0 ............................ Shutdown by 7/1/ 

2012.

0 ............................ Shutdown by 7/1/ 

2012. 

Cherokee Unit 2 ..... No ............ Shutdown by 12/ 

31/2011.

0 ............................ Shutdown by 12/ 

31/2011.

0 ............................ Shutdown by 12/ 

31/2011. 

Cherokee Unit 3 ..... No ............ Shutdown by 12/ 

31/2016.

0 ............................ Shutdown by 12/ 

31/2016.

0 ............................ Shutdown by 12/ 

31/2016. 

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17Specifically, 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 § 40–3.2–202, 

C.R.S.—Colorado’s Clean Air-Clean Jobs Act. 

TABLE 25—SOURCES COVERED UNDER THE PSCO BART ALTERNATIVE—Continued 

Unit BART 

eligible? NOX control type NOX emission uimit SO2 control type SO2 emission limit Particulate type and limit 

Cherokee Unit 4 ..... Yes .......... Natural Gas Operation by 12/31/ 

2017.

0.12 lb/MMBtu (30- 

day rolling average) by 12/31/ 

2017.

Natural Gas Operation by 12/31/ 

2017.

7.81 tpy (12 month 

rolling average).

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Valmont Unit 5 ........ Yes .......... Shutdown by 12/ 

31/2017.

0 ............................ Shutdown by 12/ 

31/2017.

0 ............................ Shutdown by 12/ 

31/2017. 

Pawnee Unit 1 ........ Yes .......... SCR ** ................... 0.07 lb/MMBtu (30- 

day rolling average) by 12/31/ 

2014.

Lime Spray Dryer ** 0.12 lb/MMBtu (30- 

day rolling average) by 12/31/ 

2014.

Fabric Filter 

Baghouse * 0.03 

lb/MMBtu. 

Arapahoe Unit 3 ..... No ............ Shutdown by 12/ 

31/2013.

0 ............................ Shutdown by 12/ 

31/2013.

0 ............................ Shutdown by 12/ 

31/2013. 

Arapahoe Unit 4 ..... No ............ Natural Gas Operation by 12/31/ 

2014.

600 tpy (12 month 

rolling average) 

by 12/31/2014.

Natural Gas operation by 12/31/ 

2014.

1.28 tpy (12 month 

rolling average) 

by 12/31/2014.

Fabric Filter 

Baghouse * 0.03 

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 BARTeligible sources in the State in Chapter 

6, Table 6–3 of the SIP. A list of BARTeligible 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 SO2 and NOX, 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 SO2 is 0.15 

lb/MMBtu. The presumptive limits for 

NOX 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. 

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

Unit 

SO2 average emissions 2006– 

2008 

(tpy) 

SO2 emissions with 

presumptive 

limits 

(0.15 lb/ 

MMBtu) 

SO2 emissions under 

BART alternative in 

2018 

(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 

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TABLE 27—NOX REDUCTIONS UNDER THE BART ALTERNATIVE

Unit 

NOX average 

emissions 

2006–2008 

(tpy) 

NOX presumptive limit 

(lb/MMBtu) 

NOX emissions with presumptive limits 

(tpy) 

NOX emissions under 

BART alternative in 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 SO2 and 15,996 tpy for 

NOX. Under the BART alternative, the 

emissions from the sources in 2018 will 

be 2,415 tpy for SO2 and 4,366 tpy for 

NOX. 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, PM2.5, 

and PM10. 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 NOX and SO2. 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 

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18076 Federal Register / Vol. 77, No. 58 / Monday, March 26, 2012 / Proposed Rules 

18OD denotes Outside Domain; MEX denotes the 

country of Mexico; CEN denotes the Central 

Regional Air Partnership; PO denotes Pacific 

Offshore. 

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, PM2.5, 

and PM10. 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, PM2.5, PM10, and sea salt 

contributions are based on WEP. 

TABLE 28—COLORADO SOURCES EXTINCTION CONTRIBUTION 2000–2004 FOR 20% WORST DAYS

Class I area Pollutant species 

2000–2004 

extinction 

(Mm¥1) 

Species 

contribution to 

total 

extinction 

(%) 

CO sources 

contribution to 

species extinction 

(%) 1

GRSA1 (Great Sand Dunes National park and 

Preserve).

Sulfate ......................................................

Nitrate ......................................................

5.97 

1.96 

21.1 

6.9 

13.0 

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 Wilderness 

Area).

Sulfate ......................................................

Nitrate ......................................................

5.25 

2.16 

22.69.3 26.9 

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 Canyon 

of the Gunnison, and La Garita Wilderness).

Sulfate ......................................................

Nitrate ......................................................

4.99 

1.21 

23.9 

5.8 

5.0 

5.0 

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 Tops Wilderness, Maroon Bells—Snowmass Wilderness, and West Elk Wilderness).Sulfate ......................................................

Nitrate ......................................................

OC ............................................................

4.79 

1.31 

7.83 

24.3 

6.6 

39.7 

6.5 

20.0 

60.6 

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 SO2, 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 Iareas. 

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19See 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. 

TABLE 29—PSAT SOURCE REGION APPORTIONMENT FOR 20% WORST DAYS

Class I Area: 2018 Sulfate PSAT 2018 Nitrate PSAT 

GRSA1 (Great Sand Dunes National Park and 

Preserve).

Region 18 ......................... OD CO NM MEX OD NM CO CEN 

% Contribution ................. 38.2 9.7 8.1 7.9 28.9 27.2 12.3 8.8 

MEVE1 (Mesa Verde National Park) .................. Region ............................. OD NM MEX AZ NM CO OD AZ 

% Contribution ................. 35.4 17.2 11.3 10.2 60.2 12.3 9.7 9.7 

MOZI1 (Mount Zirkel and Rawah Wilderness 

Area).

Region ............................. OD CO WY UT CO OD UT WY 

% Contribution ................. 29.3 20.9 9.2 7.6 41.6 17.8 14.1 10.3 

RMHQ1 (Rocky Mountain National Park) .......... Region ............................. OD CO WY CEN CO OD WY UT 

% Contribution ................. 29.1 23.5 7.7 7.2 33.7 15.8 11.0 5.9 

WEMI1 (Weminuche Wilderness, Black Canyon 

of the Gunnison, and La Garita Wilderness).

Region ............................. OD NM MEX PO NM OD CA AZ 

% Contribution ................. 34.9 13.2 10.7 9.1 43.7 19.7 14.1 9.9 

WHRI1 (Eagles Nest Wilderness, Flat Tops Wilderness, Maroon Bells—Snowmass Wilderness, and West Elk Wilderness).Region ............................. OD MEX AZ NM OD UT CO NM 

% 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. 

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 SO2, 

NOX, and stationary source PM. 

The State’s analysis evaluated the 

projected sources of SO2 and NOX in 

2018. The State’s analysis shows that 

78% of 2018 total statewide SO2

emissions are from point sources, 

mainly coal-fired boilers. Area source 

SO2 emissions (14% of total SO2

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 SO2 emissions from natural 

fires constitute 6% of total SO2

emissions and are considered 

uncontrollable. Both off-road and onroad mobile sources each constitute 1% 

of SO2 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 SO2. 

Colorado’s analysis shows that point 

sources comprise 36% of total NOX

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 offroad mobile sources comprise 16% and 

14% of Statewide NOX 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 

NOX 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 NOX

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 NOX

emissions. 

The State has determined that large 

point sources are the dominant source 

of NOX 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 

SO2, NOX 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-toBART 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. 

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20The 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. 

The evaluation of potential RP 

sources involved all Colorado stationary 

sources with actual SO2, NOX, or PM10

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. 

Table 30 shows the subject-to-RP 

sources identified by the State. 

TABLE 30—RP SOURCES EVALUATED FOR CONTROLS

Source 

Q 

(tpy based 

on 2007 

actual 

emissions) 

Nearest Class I area Q/d 

value 

Platte River Power Authority—Rawhide Station ..................................... 2,796 Rocky Mountain National Park .......................... 49.9 

CENC—Unit 3 .......................................................................................... 4,453 Rocky Mountain National Park .......................... 81.7 

CSU-Nixon Power Plant—Nixon Unit 1 ................................................... 6,668 Great Sand Dunes National Park ..................... 63.9 

Black Hills Energy Clark Power Plant Units 1 and 2 .............................. 2,393 Great Sand Dunes National Park ..................... 40.8 

Holcim—Kiln and Dryer ........................................................................... 3,250 Great Sand Dunes National Park ..................... 49.2 

Tri-State—Nucla ...................................................................................... 3,327 Black Canyon National Park ............................. 47.1 

Tri-State—Craig Unit 3 ............................................................................ 20,628 Flat Tops Wilderness Area ................................ 432.4 

PSCO—Cameo Station ........................................................................... 3,750 Black Canyon National Park ............................. 53.2 

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: 

• Costs of Compliance; 

• Time Necessary for Compliance; 

• Energy and Non-air Quality 

Environmental Impacts of Compliance; 

and 

• Remaining Useful Life of any 

Potentially Affected Sources. CAA 

§ 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 NOX controls in the RP 

context, the State adopted the same 

screening criteria as used to evaluate 

potential NOX 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 NOX

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 SO2 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 

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Federal Register / Vol. 77, No. 58 / Monday, March 26, 2012 / Proposed Rules 18079 

21For 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 SO2, NOX, or PM10 less than 

the federal Prevention of Significant Deterioration 

(PSD) significance levels. These de minimis levels 

are as follows: NOx—40 tons per year; SO2—40 tons 

per year; PM10—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. 

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; TriState 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 naturalgas-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. 

SO2 RP Determination 

Rawhide Unit 101 is currently 

controlled with a dry FGD achieving 

over 72 percent SO2 reduction with a 

current permit limit of 0.09 lb/MMBtu 

(annual average). Per the BART 

Guidelines, for EGUs with preexisting 

post-combustion SO2 controls achieving 

removal efficiencies greater than 50 

percent, states should consider cost 

effective scrubber upgrades designed to 

improve the system’s overall SO2

removal efficiency (70 FR 39171). Under 

the BART Guidelines, a state is not 

required to evaluate the replacement of 

the current SO2 controls if 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 remaininguseful-life issues for this source. 

Baseline SO2 emissions are 913 tpy 

based on an average of 2006–2008 actual 

emissions. A summary of the State’s SO2

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

Control technology 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

Reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 SO2 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 SO2

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 SO2 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 SO2

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 NOX 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 

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impacts that would preclude the 

selection of any of the controls 

evaluated, nor are there any remaininguseful-life issues for this source. 

Baseline NOX emissions are 1,866 tpy 

based on an average of 2006–2008 actual 

emissions. A summary of the State’s 

NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 NOX 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 

NOX 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 coalfired 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 SO2. The State 

determined that DSI and fuel switching 

to natural gas were technically feasible 

for reducing SO2 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 longerthan-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 remaininguseful-life issues for this source. The 

baseline SO2 emissions are 257 tpy. A 

summary of the State’s SO2 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. 

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TABLE 33—SUMMARY OF CENC BOILER 3 SO2 RP ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

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 SO2 emissions by approximately 

268 tons per year. DSI controls for 

Boiler 3 would reduce SO2 emissions by 

about 147 tons per year. Fuel switching 

to natural gas would reduce SO2

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 

SO2 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 SO2 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 SO2

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 

NOX emissions at CENC Boiler 3. The 

State determined that LoTOxTM, 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 remaininguseful-life issues for this source. A 

summary of the State’s NOX RP analysis 

is provided in Table 34 below. Baseline 

NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

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 NOX emissions by approximately 

368 tons per year. The highest 

performing SCR controls for Boiler 3 

would reduce NOX 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 NOX 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 NOX 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 

NOX 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. 

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18082 Federal Register / Vol. 77, No. 58 / Monday, March 26, 2012 / Proposed Rules 

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 SO2. The State 

determined that DSI and dry FGD were 

technically feasible for reducing SO2

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 SO2 RP 

analysis is provided in Table 35 below. 

Baseline SO2 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 SO2 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 SO2

RP determination for CSU Nixon Unit 1. 

NOX RP determination 

Nixon Unit 1 is currently controlled 

for NOX emissions with LNBs. The State 

determined ULNB, OFA, SNCR, SNCR 

plus ULNB, and SCR were technically 

feasible for reducing NOX 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 remaininguseful-life issues for this source. A 

summary of the State’s NOX RP analysis 

is provided in Table 36 below. Baseline 

NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 

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TABLE 36—SUMMARY OF NIXON UNIT 1 NOX RP ANALYSIS—Continued 

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th percentile 

impact) 

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 NOX 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 NOX 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 NOX 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 NOX 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 SO2, NOX 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 SO2 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 SO2 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 SO2 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 SO2 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 SO2. 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 SO2 RP 

emission limit of 1.30 pounds per ton of 

clinker (30-day rolling average). The 

State calculated the long-term annual 

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18084 Federal Register / Vol. 77, No. 58 / Monday, March 26, 2012 / Proposed Rules 

22An 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%. 

limit by multiplying the long-term 

baseline SO2 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 SO2 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 SO2

RP determination for the Holcim 

Florence Cement Kiln. 

NOX RP Determination 

NOX 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 remaininguseful-life issues for this source. A 

summary of the State’s NOX RP analysis 

is provided in Table 37 below. Baseline 

NOX 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. 

TABLE 37—SUMMARY OF HOLCIM FLORENCE CEMENT KILN NOX RP ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/ton of clinker) (30-day 

rolling average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

98th 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 NOX RP 

control is SNCR. The State has 

determined that the NOX 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 NOX 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 NOX

limit. 

We agree with the State’s conclusions, 

and we are proposing to approve its 

NOX 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. 

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23The 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. 

24Barr, July 2007. ‘‘Application for a Permit to 

Construct a Combined Heat and Power (CHP) 

Plant.’’ Prepared for Great River Energy— 

Spiritwood Station, Spiritwood, ND. 

25EPA, 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. ’’ 

PM RP Determination for the Quarry 23

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 SO2

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 SO2 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 remaininguseful-life issues for this source. A 

summary of the State’s SO2 RP analysis 

is provided in Table 38 below. Baseline 

SO2 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 SO2

control options (and NOX) 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. 

TABLE 38—SUMMARY OF NUCLA UNIT 4 SO2 RP ANALYSIS

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/mmbtu) 

(30-day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/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 SO2 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. 

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We agree with the State’s conclusions, 

and we are proposing to approve the 

State’s SO2 RP determination for Nucla 

Unit 4. 

NOX RP Determination 

In 2006, Tri-State installed a smallscale SNCR system on Unit 4 that injects 

anhydrous ammonia to achieve NOX

reductions. Tri-State does not operate 

the SNCR system frequently. It is used 

on occasions when NOX emissions 

approach 0.4 lb/MMBtu. Operation 

above this level at high unit capacity 

factors results in levels that approach 

the annual NOX limit of 1,987.9 tpy (12- 

month rolling average). 

The State determined full-scale SNCR 

and SCR were technically feasible for 

reducing NOX 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 NOX 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 remaininguseful-life issues for this source. A 

summary of the State’s NOX RP analysis 

is provided in Table 39 below. Baseline 

NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/mmbtu) 

(30–day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost 

effectiveness 

($/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 

NOX RP for Nucla Unit 4 is the 

following NOX 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 NOX RP 

control at this time. 

We agree with the State’s conclusions, 

and we are proposing to approve its 

NOX 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 SO2 or 

NOX). 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 SO2 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 

SO2 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) 

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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 TriState 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 postupgrade (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 SO2 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 SO2 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 SO2

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 SO2

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 remaininguseful-life issues for this source. A 

summary of the State’s NOX RP analysis 

is provided in Table 40 below. Baseline 

NOX 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

Control technology 

Control 

efficiency 

(%) 

Emission rate 

(lb/mmbtu) 

(30–day rolling 

average) 

Emission 

reduction 

(tpy) 

Annualized 

costs 

Cost effectiveness 

($/ton) 

Visibility 

improvement 

(delta dv for 

the maximum 

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 NOX 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 

NOX 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 PM10. 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 fourfactor 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 PM10 (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 SO2, 

NOX, 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 

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18088 Federal Register / Vol. 77, No. 58 / Monday, March 26, 2012 / Proposed Rules 

26PSCO Cameo Station was shut down in 

December 2010. 

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

Summary of State’s RP Determinations 

TABLE 41—SUMMARY OF THE STATE’S RP DETERMINATIONS FOR STATIONARY SOURCES

Emission unit Assumed NOX

control type 

NOX

Emission limit 

Assumed SO2

control type SO2 Emission limit 

Assumed 

particulate 

control and 

emission limit 

Rawhide .....................

Unit 101 ......................

Enhanced Combustion Control *.0.145 lb/MMBtu (30- 

day rolling average).

Lime Spray Dryer* .... 0.11 lb/MMBtu (30- 

day rolling average).

Fabric Filter 

Baghouse * 0.03 lb/ 

MMBtu. 

CENC .........................

Unit 3 ..........................

No Control ................. 246 tons per year 

(12-month rolling 

total).

No Control ................. 1.2 lbs/MMBtu ........... Fabric Filter 

Baghouse * 0.07 lb/ 

MMBtu. 

Nixon ..........................

Unit 1 ..........................

ULNBS with OFA ...... 0.21 lb/MMBtu (30- 

day rolling average).

Lime Spray Dryer ...... 0.11 lb/MMBtu (30- 

day rolling average).

Fabric Filter 

Baghouse * 0.03 lb/ 

MMBtu. 

Clark ...........................

Units 1 &2 ..................

Shutdown by 12/31/ 

2013.

0 ................................ Shutdown by 12/31/ 

2013.

0 ................................ Shutdown by 12/31/ 

2013. 

Holcim—Florence .......

Kiln .............................

SNCR ........................ 2.73 lbs/ton clinker 

(30-day rolling average).

2,086.8 tons/year ......

Wet Lime Scrubber * 1.30 lbs/ton clinker ....

(30-day rolling average).

721.4 tons/year .........

Fabric Filter 

Baghouse * 

246.3 tons/year. 

Nucla .......................... No Control ................. 0.5 lb/MMBtu .............

(30-day rolling average).

Limestone Injection * 0.4 lb/MMBtu .............

(30-day rolling average).

Fabric Filter 

Baghouse * 

0.03 lb/MMBtu. 

Craig ...........................

Unit 3 ..........................

SNCR ........................ 0.28 lb/MMBtu ...........

(30-day rolling average).

Lime Spray Dryer * .... 0.15 lb/MMBtu ...........

(30-day rolling average).

Fabric Filter 

Baghouse * 

0.013 lb/MMBtu filterable PM 

0.012 lb/MMBtu 

PM10. 

Cameo ........................ Shutdown by 12/31/ 

2011.

0 ................................ Shutdown by 12/31/ 

2011.

0 ................................ Shutdown by 12/31/ 

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 NOX 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 NOX per year from 26,000 

natural gas and oil heater-treaters. This 

equates to approximately 0.88 tpy of 

NOX 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 NOX emission 

inventory, with 2018 emissions 

expected to be 16,199 tpy. 

The State determined the following 

were technically feasible for controlling 

NOX 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. 

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TABLE 42—SUMMARY OF RICE CONTROLS FOR RP 

Control technology 

Control 

effectiveness 

(%) 

Cost effectiveness 

($/ton) 

Lean Burn (Air/Fuel Ratio Adjustment) ........................................................................................................... 5–30 $320–8,300. 

Lean Burn (Ignition/Spark Timing Retard) ...................................................................................................... 20 $310–2,000. 

Rich Burn NSCR w/an air to fuel ratio (ATF) controller ................................................................................. 80–90 $571. 

Rich/Lean Burn SNCR .................................................................................................................................... 50–95 

Lean Burn SCR ............................................................................................................................................... 80–90 $430–4,900. 

Replace RICE with electric motors ................................................................................................................. 60–100 4,700 or more. 

For RICE NOX 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 NOX 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 NOX. At an average of about 10 

tons of NOX 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 NOX 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 NOX, but usually have 

very low SO2 and PM10 emissions. 

The State evaluated combustion 

turbines that are co-located at subject-toBART 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 #1 and Turbine #2) emit levels 

of pollutants above the State de minimis 

levels for NOX. Baseline NOX emissions 

based on the average of 2006–2008 

actual emissions are 159.6 tpy for 

Turbine #1 and 148 tpy for Turbine #2. 

The combustion turbines at the Nixon 

Front Range Power Plant were installed 

with advanced dry-low-NOX

combustion systems, which are 

achieving a control efficiency of 89.4% 

on Turbine #1 and 90.1% on Turbine 

#2. The State determined that the 

following were technically feasible 

controls for NOX: 1) dry controls using 

advanced combustor design to suppress 

NOX formation and/or promote CO 

burnout (already installed); and (2) postcombustion 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 NOX 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 NOX 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 NOX 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 #1 and Turbine #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. 

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27 Guidance on the Use of Models and Other 

Analyses for Demonstrating Attainment of Air 

Quality Goals for Ozone, PM2.5, 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. 

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. 

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 longterm 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 

Colorado class I areas 

20% Worst days 20% Best days 

2000–2004 

Baseline 

(dv) 

2018 URP 

(dv) 

Reduction 

needed to 

reach URP 

goal 

(delta dv) 

2018 CMAQ 

Modeling 

projection— 

state’s RP 

goal 

2000–2004 

Baseline 

(dv) 

2018 CMAQ 

Modeling 

projection 

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 Wilderness ............................................ 10.33 9.37 0.96 9.83 3.11 2.93 

Eagles Nest Wilderness, Flat Tops Wilderness, Maroon 

Bells-Snowmass Wilderness, and West Elk Wilderness .............................................................................. 9.61 8.78 0.83 8.98 0.70 0.53 

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 

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28The 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. 

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 NOX and 

SO2 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 NOX and SO2 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 (humancaused) sources of visibility impairment 

it considered in developing its longterm 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 

SO2, NOX, VOC, OC, EC, PM2.5, PM10, 

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

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 

SO2, NOX, VOC, OC, EC, PM2.5, PM10, 

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, SO2 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. 

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NOX

NOX emissions in Colorado come 

mostly from point sources and from onroad 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, NOX 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 

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TABLE 47—COLORADO OC EMISSIONS—2002 AND 2018—Continued 

Source category Baseline 2002 Future 2018 Percent 

change 

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 offroad 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, PM2.5 emissions are expected 

to decrease 3%. Increases in road dust 

emissions are tied to population growth 

and vehicle miles traveled. 

PM10

PM10 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. 

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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, PM10 emissions are expected 

to increase by 4% in 2018. Increases in 

coarse mass are seen in the fugitive dust 

category. The increase in PM10 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 longterm 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 NOX and VOC 

emissions reductions of approximately 

8,900 tpy (Regulation No. 7); (3) PM10

emission reduction programs in PM10

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. 

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29The 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 

PM10 were generated from agricultural burning in 

the entire State of Colorado. See Colorado TSD 

document ‘‘Agricultural Burning in Colorado, 2003 

and 2004 Inventories.’’ 

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. 

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 SO2

and NOX limits, Colorado has required 

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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 longterm 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 longterm 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 longterm 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/) 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). 

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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 fiveyear 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: 

• Regulation No. 3, Part F, Section VI 

and Section VII. 

• Regulation No. 3, Part D, Section 

XIV.F. 

• 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: 

• 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); 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

USC 3501 et seq.); 

• 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.); 

• 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); 

• Does not have Federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• 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, 

• 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. 

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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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