23988 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R08–OAR–2011–0851; FRL–9655–7] 

Approval and Promulgation of 

Implementation Plans; State of 

Montana; State Implementation Plan 

and Regional Haze Federal 

Implementation Plan 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing a Federal 

Implementation Plan (FIP) to address 

regional haze in the State of Montana. 

EPA developed this proposal in 

response to the State’s decision in 2006 

to not submit a regional haze State 

Implementation Plan (SIP) revision. 

EPA is proposing to determine that the 

FIP satisfies requirements of the Clean 

Air Act (CAA or ‘‘the Act’’) that require 

states, or EPA in promulgating a FIP, to 

assure reasonable progress towards the 

national goal of preventing any future 

and remedying any existing man-made 

impairment of visibility in mandatory 

Class I areas. In addition, EPA is also 

proposing to approve a revision to the 

Montana SIP submitted by the State of 

Montana through the Montana 

Department of Environmental Quality 

on February 17, 2012. The State’s 

submittal contains revisions to the 

Montana Visibility Plan that includes 

amendments to the ‘‘Smoke 

Management’’ section, which adds a 

reference to Best Available Control 

Technology (BACT) as the visibility 

control measure for open burning as 

currently administered through the 

State’s air quality permit program. This 

change was made to meet the 

requirements of the Regional Haze Rule. 

EPA will act on the remaining revisions 

in the State’s submittal in a future 

action. 

DATES: Written comments must be 

received at the address below on or 

before June 19, 2012. 

Public Hearings. We will be holding 

two public hearings for this proposal. 

One hearing is scheduled to be held in 

Helena, Montana on Tuesday, May 1, 

2012 from 2 p.m. until 5:30 p.m. and 

from 6:30 p.m. until 9 p.m. at the Lewis 

& Clark Library, 120 S. Last Chance 

Gulch, Helena, Montana 59601, (406) 

447–1690. The other hearing is 

scheduled to be held in Billings, 

Montana on Wednesday, May 2, 2012 

from 1 p.m. until 5 p.m. and from 6 p.m. 

until 8 p.m. at the Montana State 

University—Downtown Campus, 

Meeting Room—Broadway III A, 2804 

3rd Avenue North, Billings, Montana 

59101, (406) 896–5860. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–R08– 

OAR–2011–0851, by one of the 

following methods: 

• http://www.regulations.gov. Follow 

the on-line instructions for submitting 

comments. 

• Email: r8airrulemakings@epa.gov. 

• Fax: (303) 312–6064 (please alert 

the individual listed in 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– 

0851. 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: 

Vanessa Hinkle, Air Program, U.S. 

Environmental Protection Agency, 

Region 8, Mailcode 8P–AR, 1595 

Wynkoop, Denver, Colorado 80202– 

1129, (303) 312–6561, 

hinkle.vanessa@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 

C. Roles of Agencies in Addressing 

Regional Haze 

IV. Requirements for a Regional Haze FIP 

A. The CAA and the Regional Haze Rule 

B. EPA’s Authority to Promulgate a FIP 

C. Determination of Baseline, Natural, and 

Current Visibility Conditions 

D. Determination of Reasonable Progress 

Goals (RPGs) 

E. Best Available Retrofit Technology 

(BART) 

F. Long-Term Strategy (LTS) 

G. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment (RAVI) 

H. Monitoring Strategy and Other 

Implementation Plan Requirements 

I. Consultation with States and Federal 

Land Managers (FLMs) 

V. EPA’s Analysis of Montana’s Regional 

Haze 

A. Affected Class I Areas 

B. Baseline Visibility, Natural Visibility, 

and Uniform Rate of Progress 

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1. Estimating Natural Visibility Conditions 

2. Estimating Baseline Conditions 

3. Summary of Baseline and Natural 

Conditions 

4. Uniform Rate of Progress 

5. Contribution Assessment According to 

Improve Monitoring Data 

C. BART Determinations 

1. BART-Eligible Sources 

2. Sources Subject to BART 

a. Modeling Methodology 

b. Contribution Threshold 

c. Sources Identified by EPA as BARTEligible and Subject to BART 

3. BART Determinations and Federally 

Enforceable Limits 

a. Visibility Improvement Modeling 

b. BART Five-Factor Determinations and 

Federally Enforceable Limits 

i. Ash Grove Cement 

ii. Holcim 

iii. Columbia Falls Aluminum Company 

(CFAC) 

iv. Colstrip 

(a) Colstrip Unit 1 

(b) Colstrip Unit 2 

v. Corette 

D. Long-Term Strategy/Strategies 

1. Emissions Inventories 

2. Sources of Visibility Impairment in 

Montana Class I Areas 

3. Other States’ Class I Areas Affected by 

Montana Emissions 

4. Visibility Projection Modeling 

5. Consultation and Emissions Reductions 

for Other States’ Class I Areas 

6. EPA’s Reasonable Progress Goals for 

Montana 

a. EPA’s Use of WRAP Visibility Modeling 

b. EPA’s Reasonable Progress ‘‘FourFactor’’ Analysis 

c. Four Factor Analyses for Point Sources 

i. Colstrip Energy Limited Partnership 

ii. Colstrip Unit 3 

iii. Colstrip Unit 4 

iv. Devon Energy Production 

v. Montana-Dakota Utilities Lewis & Clark 

Station 

vi. Montana Sulphur and Chemical 

vii. Plum Creek Manufacturing 

viii. Roseburg Forest Products 

ix. Smurfit Stone Container 

x. Yellowstone Energy Limited Partnership 

d. Establishment of the Reasonable 

Progress Goal 

e. Reasonable Progress Consultation 

f. Mandatory Long-Term Strategy 

Requirements 

i. Reductions Due to Ongoing Air Pollution 

Programs 

ii. Measures to Mitigate the Impacts of 

Construction Activities 

iii. Emission Limitations and Schedules for 

Compliance 

iv. Sources Retirement and Replacement 

Schedules 

v. Agricultural and Forestry Smoke 

Management Techniques 

vi. Enforceability of Montana’s Measures 

vii. Anticipated Net Effect on Visibility 

Due to Projected Changes 

E. Coordination of RAVI and Regional Haze 

Requirements 

F. Monitoring Strategy and Other 

Implementation Plan Requirements 

G. Coordination with FLMs 

H. Periodic FIP Revisions and Five-Year 

Progress Reports 

VI. 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 A/F mean or refer to air-tofuel. 

iii. The initials ARM mean or refer to 

Administrative Rule of Montana. 

iv. The initials ARP mean or refer to the 

acid rain program. 

v. The initials ASOFA mean or refer to 

advanced separated overfire air. 

vi. The initials BACT mean or refer to Best 

Available Control Technology. 

vii. The initials BART mean or refer to Best 

Available Retrofit Technology. 

viii. The initials CAMD mean or refer to 

EPA Clean Air Markets Division. 

ix. The initials CAMx mean or refer to 

Comprehensive Air Quality Model. 

x. The initials CCM mean or refer to EPA 

Control Cost Manual. 

xi. The initials CCOFA mean or refer to 

close-coupled overfire air system. 

xii. The initials CDS mean or refer to 

circulating dry scrubber. 

xiii. The initials CELP mean or refer to 

Colstrip Energy Limited Partnership. 

xiv. The initials CEMS mean or refer to 

continuous exhaust monitoring systems. 

xv. The initials CEPCI mean or refer to 

Chemical Engineering Plant Cost Index. 

xvi. The initials CFAC mean or refer to 

Columbia Falls Aluminum Company. 

xvii. The initials CFB mean or refer to 

circulating fluidized bed. 

xviii. The initials CKD mean or refer to 

cement kiln dust. 

xix. The initials CMAQ mean or refer to 

Community Multi-Scale Air Quality 

modeling system. 

xx. The initials CO mean or refer to carbon 

monoxide. 

xxi. The initials CPI mean or refer to 

Consumer Price Index. 

xxii. The initials CRF mean or refer to 

Capital Recovery Factor. 

xxiii. The initials DAA mean or refer to Dry 

Absorbent Addition. 

xxiv. The initials DPCS mean or refer to 

digital process control system. 

xxv. The initials D–R mean or refer to 

Dresser-Rand. 

xxvi. The initials DSI mean or refer to dry 

sorbent injection. 

xxvii. The initials EC mean or refer to 

elemental carbon. 

xxviii. The initials EGU mean or refer to 

Electric Generating Units. 

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

or refer to the United States Environmental 

Protection Agency. 

xxx. The initials ESP mean or refer to 

electrostatic precipitator. 

xxxi. The initials FCCU mean or refer to 

fluid catalytic cracking unit. 

xxxii. The initials FGD mean or refer to 

flue gas desulfurization. 

xxxiii. The initials FGR mean or refer to 

flue gas recirculation. 

xxxiv. The initials FIP mean or refer to 

Federal Implementation Plan. 

xxxv. The initials FLMs mean or refer to 

Federal Land Managers. 

xxxvi. The initials HAR mean or refer to 

hydrated ash reinjection. 

xxxvii. The initials HDSCR mean or refer 

to high-dust selective catalytic reduction. 

xxxviii. The initials HC mean or refer to 

hydrocarbons. 

xxxix. The initials IMPROVE mean or refer 

to Interagency Monitoring of Protected Visual 

Environments monitoring network. 

xl. The initials IPM mean or refer to 

Integrated Planning Model. 

xli. The initials LDSCR mean or refer to 

low-dust selective catalytic reduction. 

xlii. The initials LEA mean or refer to low 

excess air. 

xliii. The initials LNBs mean or refer to low 

NOX burners. 

xliv. The initials LSD mean or refer to lime 

spray drying. 

xlv. The initials LSFO mean or refer to 

limestone forced oxidation. 

xlvi. The initials LTS mean or refer to 

Long-Term Strategy. 

xlvii. The initials MDEQ mean or refer to 

Montana’s Department of Environmental 

Quality. 

xlviii. The initials MDF mean or refer to 

medium density fiberboard. 

xlix. The initials MISO mean or refer to 

Midwest Independent Transmission System 

Operator. 

l. The initials MDU mean or refer to 

Montana-Dakota Utilities Company. 

li. The initials MKF mean or refer to midkiln firing of solid fuel. 

lii. The words Montana and State mean the 

State of Montana. 

liii. The initials MSCC mean or refer to 

Montana Sulphur and Chemical Company. 

liv. The initials NEI mean or refer to 

National Emission Inventory. 

lv. The initials NESHAP mean or refer to 

National Emission Standards for Hazardous 

Air Pollutants. 

lvi. The initials NH3 mean or refer to 

ammonia. 

lvii. The initials NOX mean or refer to 

nitrogen oxides. 

lviii. The initials NP mean or refer to 

National Park. 

lix. The initials NSCR mean or refer to nonselective catalytic reduction. 

lx. The initials NSPS mean or refer to New 

Source Performance Standards. 

lxi. The initials NWR mean or refer to 

National Wildlife Reserve. 

lxii. The initials OC mean or refer to 

organic carbon. 

lxiii. The initials OFA mean or refer to 

overfire air. 

lxiv. The initials PC mean or refer to 

pulverized coal. 

lxv. The initials PH/PC mean or refer to 

preheater/precalciner. 

lxvi. The initials PM mean or refer to 

particulate matter. 

lxvii. The initials PM2.5 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers (fine 

particulate matter). 

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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. 

lxviii. The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers (coarse 

particulate matter). 

lxix. The initials PMCD mean or refer to 

particulate matter control device. 

lxx. The initials ppm mean or refer to parts 

per million. 

lxxi. The initials PRB mean or refer to 

Powder River Basin. 

lxxii. The initials PSAT mean or refer to 

Particulate Matter Source Apportionment 

Technology. 

lxxiii. The initials PSD mean or refer to 

Prevention of Significant Deterioration. 

lxxiv. The initials RAVI mean or refer to 

Reasonably Attributable Visibility 

Impairment. 

lxxv. The initials RICE mean or refer to 

Reciprocating Internal Combustion Engines. 

lxxvi. The initials RMC mean or refer to 

Regional Modeling Center. 

lxxvii. The initials ROFA mean or refer to 

rotating opposed fire air. 

lxxviii. The initials RP mean or refer to 

Reasonable Progress. 

lxxix. The initials RPG or RPGs mean or 

refer to Reasonable Progress Goal(s). 

lxxx. The initials RPOs mean or refer to 

regional planning organizations. 

lxxxi. The initials RRI mean or refer to rich 

reagent injection. 

lxxxii. The initials RSCR mean or refer to 

regenerative selective catalytic reduction. 

lxxxiii. The initials SCOT mean or refer to 

Shell Claus Off-Gas Treatment. 

lxxxiv. The initials SCR mean or refer to 

selective catalytic reduction. 

lxxxv. The initials SDA mean or refer to 

spray dryer absorbers. 

lxxxvi. The initials SIP mean or refer to 

State Implementation Plan. 

lxxxvii. The initials SMOKE mean or refer 

to Sparse Matrix Operator Kernel Emissions. 

lxxxviii. The initials SNCR mean or refer 

to selective non-catalytic reduction. 

lxxxix. The initials SO2 mean or refer to 

sulfur dioxide. 

xc. The initials SOFA mean or refer to 

separated overfire air. 

xci. The initials SRU mean or refer to 

sulfur recovery unit. 

xcii. The initials TESCR mean or refer to 

tail-end selective catalytic reduction. 

xciii. The initials TCEQ mean or refer to 

Texas Commission on Environmental 

Quality. 

xciv. The initials tpy mean tons per year. 

xcv. The initials TSD mean or refer to 

Technical Support Document. 

xcvi. The initials URP mean or refer to 

Uniform Rate of Progress. 

xcvii. The initials VOC mean or refer to 

volatile organic compounds. 

xcviii. The initials WA mean or refer to 

Wilderness Area. 

xcic. The initials WEP mean or refer to 

Weighted Emissions Potential. 

c. The initials WRAP mean or refer to the 

Western Regional Air Partnership. 

ci. The initials YELP mean or refer to 

Yellowstone Energy Limited Partnership. 

I. General Information 

The public hearings will provide 

interested parties the opportunity to 

present information and opinions to 

EPA concerning our proposal. Interested 

parties may also submit written 

comments, as discussed in the proposal. 

Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearing. We will 

not respond to comments during the 

public hearing. When we publish our 

final action, we will provide written 

responses to all oral and written 

comments received on our proposal. 

At the public hearing, the hearing 

officer may limit the time available for 

each commenter to address the proposal 

to 5 minutes or less if the hearing officer 

determines it to be appropriate. We will 

not be providing equipment for 

commenters to show overhead slides or 

make computerized slide presentations. 

Any person may provide written or oral 

comments and data pertaining to our 

proposal at the public hearing. Verbatim 

transcripts, in English, of the hearing 

and written statements will be included 

in the rulemaking docket. 

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 a FIP for the State 

of Montana (State) to address regional 

haze. In so doing, EPA is proposing to 

determine that the federal plan along 

with the change to Montana’s visibility 

plan, submitted on February 17, 2012, 

that requires BACT as the visibility 

control measure for open burning satisfy 

the requirements of 40 CFR 51.308. 

III. Background 

A. Regional Haze 

Regional haze is visibility impairment 

that is produced by a multitude of 

sources and activities which are located 

across a broad geographic area and emit 

fine particulates (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 (NP) and wilderness areas 

(WA). The average visual range 1 in 

many Class I areas (i.e., NPs and 

memorial parks, WA, and international 

parks meeting certain size criteria) in 

the western United States is 100–150 

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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.’’ 

3Albuquerque/Bernalillo County in New Mexico 

must also submit a regional haze SIP to completely 

satisfy the requirements of section 110(a)(2)(D) of 

the CAA for the entire State of New Mexico under 

the New Mexico Air Quality Control Act (section 

74–2–4). 

4EPA’s regional haze regulations require 

subsequent updates to the regional haze SIPs. 40 

CFR 51.308(g)–(i). 

kilometers, or about one-half to twothirds 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 

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 (December 2, 

1980). These regulations represented the 

first phase in addressing visibility 

impairment. EPA deferred action on 

regional haze that emanates from a 

variety of sources until monitoring, 

modeling and scientific knowledge 

about the relationships between 

pollutants and visibility impairment 

were improved. 

Congress added section 169B to the 

CAA in 1990 to address regional haze 

issues. EPA promulgated a rule to 

address regional haze on July 1, 1999. 

64 FR 35714 (July 1, 1999), codified at 

40 CFR part 51, subpart P. The Regional 

Haze Rule revised the existing visibility 

regulations to integrate into the 

regulation provisions addressing 

regional haze impairment and 

established a comprehensive visibility 

protection program for Class I areas. The 

requirements for regional haze, 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 regional 

haze requirements are summarized in 

this section of this preamble. The 

requirement to submit a regional haze 

SIP applies to all 50 states, the District 

of Columbia and the Virgin Islands.3 40 

CFR 51.308(b) requires states to submit 

the first implementation plan 

addressing regional haze visibility 

impairment no later than December 17, 

2007.4

Few states submitted a Regional Haze 

SIP prior to the December 17, 2007 

deadline, and on January 15, 2009, EPA 

found that 37 states, including Montana 

and the District of Columbia, and the 

Virgin Islands, had failed to submit SIPs 

addressing the regional haze 

requirements. 74 FR 2392 (January 15, 

2009). 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 

regional haze program will require longterm regional coordination among 

states, tribal governments and various 

federal agencies. As noted above, 

pollution affecting the air quality in 

Class I areas can be transported over 

long distances, even hundreds of 

kilometers. Therefore, to effectively 

address the problem of visibility 

impairment in Class I areas, states, or 

the EPA when implementing a FIP, need 

to develop strategies in coordination 

with one another, taking into account 

the effect of emissions from one 

jurisdiction on the air quality in 

another. 

Because the pollutants that lead to 

regional haze can originate from sources 

located across broad geographic areas, 

EPA has encouraged the states and 

tribes across the United States to 

address visibility impairment from a 

regional perspective. Five regional 

planning organizations (RPOs) were 

developed to address regional haze and 

related issues. The RPOs first evaluated 

technical information to better 

understand how their states and tribes 

impact Class I areas across the country, 

and then pursued the development of 

regional strategies to reduce emissions 

of particulate matter (PM) and other 

pollutants leading to regional haze. 

The Western Regional Air Partnership 

(WRAP) RPO is a collaborative effort of 

state governments, tribal governments, 

and various federal agencies established 

to initiate and coordinate activities 

associated with the management of 

regional haze, visibility and other air 

quality issues in the western United 

States. WRAP member State 

governments include: Alaska, Arizona, 

California, Colorado, Idaho, Montana, 

New Mexico, North Dakota, Oregon, 

South Dakota, Utah, Washington, and 

Wyoming. Tribal members include 

Campo Band of Kumeyaay Indians, 

Confederated Salish and Kootenai 

Tribes, Cortina Indian Rancheria, Hopi 

Tribe, Hualapai Nation of the Grand 

Canyon, Native Village of Shungnak, 

Nez Perce Tribe, Northern Cheyenne 

Tribe, Pueblo of Acoma, Pueblo of San 

Felipe, and Shoshone-Bannock Tribes of 

Fort Hall. 

IV. Requirements for a Regional Haze 

FIP 

The following is a summary of the 

requirements of the Regional Haze Rule. 

See 40 CFR 51.308 for further detail 

regarding the requirements of the rule. 

A. The CAA and the Regional Haze Rule 

Regional haze FIPs must assure 

Reasonable Progress 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, 

or EPA when implementing a FIP, to 

establish long-term strategies for making 

Reasonable Progress toward meeting 

this goal. The FIP must also give 

specific attention to certain stationary 

sources that were in existence on 

August 7, 1977, but were not in 

operation before August 7, 1962, and 

require these sources, where 

appropriate, to install BART controls for 

the purpose of eliminating or reducing 

visibility impairment. The specific 

regional haze FIP requirements are 

discussed in further detail below. 

B. EPA’s Authority To Promulgate a FIP 

On June 19, 2006, Montana submitted 

a letter to us signifying that the State 

would be discontinuing its efforts to 

revise the visibility control plan that 

would have incorporated provisions of 

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5Letter from Richard H. Opper, Director Montana 

Department of Environmental Quality (further 

referred to as MDEQ) to Laurel Dygowski, EPA 

Region Air Program, June 19, 2006. 

6The preamble to the Regional Haze Rule 

provides additional details about the deciview. 64 

FR 35714, 35725 (July 1, 1999). 

7 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/

RegionalHaze_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’’). 

the Regional Haze Rule.5 The State 

acknowledged with this letter that EPA 

would make a finding of failure to 

submit and thus promulgate additional 

federal rules to address the 

requirements of the Regional Haze Rule, 

including BART. In response to the 

State’s decision EPA made a finding of 

SIP inadequacy on January 15, 2009 (74 

FR 2392), determining that Montana 

failed to submit a SIP that addressed 

any of the required regional haze SIP 

elements of 40 CFR 51.308. 

Under section 110(c) of the Act, 

whenever we find that a State has failed 

to make a required submission we are 

required to promulgate a FIP. 

Specifically, section 110(c) provides: 

‘‘(1) The Administrator shall 

promulgate a Federal implementation 

plan at any time within 2 years after the 

Administrator— 

(A) finds that a State has failed to 

make a required submission or finds 

that the plan or plan revision submitted 

by the State does not satisfy the 

minimum criteria established under 

[section 110(k)(1)(A)], or 

(B) disapproves a State 

implementation plan submission in 

whole or in part, unless the State 

corrects the deficiency, and the 

Administrator approves the plan or plan 

revision, before the Administrator 

promulgates such Federal 

implementation plan.’’ 

Section 302(y) defines the term 

‘‘Federal implementation plan’’ in 

pertinent part, as: 

‘‘[A] plan (or portion thereof) 

promulgated by the Administrator to fill 

all or a portion of a gap or otherwise 

correct all or a portion of an inadequacy 

in a State implementation plan, and 

which includes enforceable emission 

limitations or other control measures, 

means or techniques (including 

economic incentives, such as 

marketable permits or auctions or 

emissions allowances) * * *.’’ 

Thus, because the State withdrew 

their efforts to revise the visibility 

control plan that would have 

incorporated provisions of the Regional 

Haze Rule and we determined the State 

failed to submit the SIP, we are required 

to promulgate a FIP. 

C. Determination of Baseline, Natural, 

and Current Visibility Conditions 

The Regional Haze Rule establishes 

the deciview as the principal metric or 

unit for expressing visibility. See 70 FR 

39104, 39118 (July 6, 2005). 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 deciviews is 

determined by using air quality 

measurements to estimate light 

extinction and then transforming the 

value of light extinction using a 

logarithm function. The deciview is a 

more useful measure for tracking 

progress in improving visibility than 

light extinction itself because each 

deciview change is an equal incremental 

change in visibility perceived by the 

human eye. Most people can detect a 

change in visibility at one deciview.6

The deciview is used in expressing 

Reasonable Progress Goals (which are 

interim visibility goals towards meeting 

the national visibility goal), defining 

baseline, current, and natural 

conditions, and tracking changes in 

visibility. The regional haze FIPs 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 regional haze. 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 Reasonable 

Progress, states, or EPA when 

implementing a FIP, must calculate the 

degree of existing visibility impairment 

at each Class I area at the time of each 

regional haze SIP submittal and 

periodically review progress every five 

years midway through each 10-year 

implementation period. To do this, the 

Regional Haze Rule requires states, or 

EPA when implementing a FIP, to 

determine the degree of impairment (in 

deciviews) for the average of the 20% 

least impaired (‘‘best’’) and 20% most 

impaired (‘‘worst’’) visibility days over 

a specified time period at each of their 

Class I areas. In addition, states, or EPA 

if implementing a FIP, 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 

regarding how to calculate baseline, 

natural and current visibility 

conditions.7

For the first regional haze SIPs that 

were due by December 17, 2007, 

‘‘baseline visibility conditions’’ were the 

starting points for assessing ‘‘current’’ 

visibility impairment. If a state does not 

submit this SIP, EPA will implement a 

FIP to cover this requirement. Baseline 

visibility conditions represent the 

degree of visibility impairment for the 

20% least impaired days and 20% most 

impaired days for each calendar year 

from 2000 to 2004. Using monitoring 

data for 2000 through 2004, states, or 

EPA if implementing a FIP, 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 to 2004 baseline period is 

considered the time from which 

improvement in visibility is measured. 

D. Determination of Reasonable 

Progress Goals (RPGs) 

The vehicle for ensuring continuing 

progress toward achieving the natural 

visibility goal is the submission of a 

series of regional haze 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). However, if a state does 

not submit a SIP for any of these 

requirements, then EPA shall 

implement a FIP. The Regional Haze 

Rule does not mandate specific 

milestones or rates of progress, but 

instead requires EPA to establish goals 

that provide for ‘‘reasonable progress’’ 

towards achieving natural (i.e., 

‘‘background’’) visibility conditions. In 

setting RPGs, EPA must provide for an 

improvement in visibility for the most 

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8The set of ‘‘major stationary sources’’ potentially 

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

9BART-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. 

impaired days over the (approximately) 

10-year period of the FIP, and ensure no 

degradation in visibility for the least 

impaired days over the same period. Id. 

In establishing RPGs, states, or EPA if 

implementing a FIP, are required to 

consider the following factors 

established in section 169A of the CAA 

and in our Regional Haze Rule 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. EPA must demonstrate in our 

FIP, 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, EPA must 

also consider the rate of progress needed 

to reach natural visibility conditions by 

2064 (referred to as the ‘‘uniform rate of 

progress’’ or the ‘‘glidepath’’) and the 

emission reduction measures needed to 

achieve that rate of progress over the 10- 

year period of the FIP. Uniform progress 

towards achievement of natural 

conditions by the year 2064 represents 

a rate of progress which EPA is to use 

for analytical comparison to the amount 

of progress we expect to achieve. In 

setting RPGs, EPA must also consult 

with potentially ‘‘contributing states,’’ 

i.e., other nearby states with emission 

sources that may be affecting visibility 

impairment at Montana’s Class I areas. 

40 CFR 51.308(d)(1)(iv). In determining 

whether EPA’s goals for visibility 

improvement provide for Reasonable 

Progress toward natural visibility 

conditions, EPA is required to evaluate 

the demonstrations developed through 

our FIP, pursuant to paragraphs 40 CFR 

51.308(d)(1)(i) and (d)(1)(ii). 40 CFR 

51.308(d)(1)(iii). 

E. Best Available Retrofit Technology 

(BART) 

Section 169A of the CAA directs 

states, or EPA if implementing a FIP, 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 EPA to implement a 

FIP to contain such measures as may be 

necessary to make Reasonable Progress 

towards the natural visibility goal, 

including a requirement that certain 

categories of existing major stationary 

sources 8 built between 1962 and 1977 

procure, install, and operate the ‘‘Best 

Available Retrofit Technology’’ as 

determined by EPA. Under the Regional 

Haze Rule, EPA is 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, EPA also has the 

flexibility to adopt an emissions trading 

program or other alternative program as 

long as the alternative provides greater 

Reasonable Progress towards improving 

visibility than BART. 

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, or EPA if 

implementing a FIP, 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 

(July 6, 2005). In making a BART 

determination for a fossil fuel-fired 

electric generating plant with a total 

generating capacity in excess of 750 

megawatts (MW), EPA must use the 

approach set forth in the BART 

Guidelines. EPA 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, EPA must meet the 

requirements of the CAA and our 

regulations for selection of BART, and 

EPA’s BART analysis and determination 

must be reasonable in light of the 

overarching purpose of the regional 

haze program. 

The process of establishing BART 

emission limitations can be logically 

broken down into three steps: first, EPA 

identifies those sources which meet the 

definition of ‘‘BART-eligible source’’ set 

forth in 40 CFR 51.301; 9 second, EPA 

determines 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, EPA then identifies the 

best available type and level of control 

for reducing emissions. 

States, or EPA if implementing a FIP, 

must address all visibility-impairing 

pollutants emitted by a source in the 

BART determination process. The most 

significant visibility impairing 

pollutants are SO2, NOX, and PM. EPA 

has stated that we should use our best 

judgment in determining whether VOC 

or NH3 compounds impair visibility in 

Class I areas. 

Under the BART Guidelines, states, or 

EPA if implementing a FIP, may select 

an exemption threshold value for their 

BART modeling, below which a BARTeligible source would not be expected to 

cause or contribute to visibility 

impairment in any Class I area. EPA 

must document this exemption 

threshold value in the FIP, and must 

state the basis for our 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. EPA 

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 EPA should 

not be higher than 0.5 deciviews. 40 

CFR part 51, appendix Y, section III.A.1. 

A regional haze FIP, must include 

source-specific BART emission limits 

and compliance schedules for each 

source subject to BART. Once EPA 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 the final FIP. CAA 

section 169(g)(4) and 40 CFR 

51.308(e)(1)(iv). In addition to what is 

required by the Regional Haze Rule, 

general SIP, or FIP, requirements 

mandate that the SIP, or FIP, 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 Regional Haze Rule 

allows EPA to implement an alternative 

program in lieu of BART so long as the 

alternative program can be 

demonstrated to achieve greater 

Reasonable Progress toward the national 

visibility goal than would BART. 

F. Long-Term Strategy (LTS) 

Consistent with the requirement in 

section 169A(b) of the CAA that states, 

or EPA if implementing a FIP, include 

in the regional haze SIP, or FIP, a 10 to 

15 year strategy for making Reasonable 

Progress, section 51.308(d)(3) of the 

Regional Haze Rule requires that states, 

or EPA if implementing a FIP, include 

a LTS in the regional haze SIP, or FIP. 

The LTS is the compilation of all 

control measures that will be used 

during the implementation period of the 

FIP to meet applicable RPGs. The LTS 

must include ‘‘enforceable emissions 

limitations, compliance schedules, and 

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other measures as necessary to achieve 

the reasonable progress goals’’ for all 

Class I areas within, or affected by 

emissions from, the state of Montana. 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 

Regional Haze Rule requires the 

impacted state, or EPA if implementing 

a FIP, to coordinate with the 

contributing states in order to develop 

coordinated emissions management 

strategies. 40 CFR 51.308(d)(3)(i). In 

such cases, EPA must demonstrate that 

it has included in its FIP, 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, 

or EPA if implementing a FIP, may be 

required to sufficiently address 

interstate visibility issues. This is 

especially true where two states belong 

to different RPOs. 

States, or EPA if implementing a FIP, 

should consider all types of 

anthropogenic sources of visibility 

impairment in developing their LTS, 

including stationary, minor, mobile, and 

area sources. At a minimum, EPA must 

describe how each of the following 

seven factors listed below are taken into 

account in developing our LTS: (1) 

Emission reductions due to ongoing air 

pollution control programs, including 

measures to address Reasonably 

Attributable Visibility Impairment; (2) 

measures to mitigate the impacts of 

construction activities; (3) emissions 

limitations and schedules for 

compliance to achieve the RPG; (4) 

source retirement and replacement 

schedules; (5) smoke management 

techniques for agricultural and forestry 

management purposes including plans 

as currently exist within the state for 

these purposes; (6) enforceability of 

emissions limitations and control 

measures; and (7) the anticipated net 

effect on visibility due to projected 

changes in point, area, and mobile 

source emissions over the period 

addressed by the LTS. 40 CFR 

51.308(d)(3)(v). 

G. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment (RAVI) 

As part of the Regional Haze Rule, 

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 regional haze 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 regional 

haze, and the state must submit the first 

such coordinated LTS with its first 

regional haze SIP. If the state does not 

revise its plan in the appropriate 

amount of time, EPA shall implement a 

FIP to address this requirement. 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 regional haze and RAVI 

impairment and must be submitted to 

EPA as a SIP revision. However, if the 

state does not provide future 

coordinated LTS and periodic progress 

reports towards RPGs then EPA will 

cover this by implementing a FIP. 

H. Monitoring Strategy and Other 

Implementation Plan Requirements 

Section 51.308(d)(4) of the Regional 

Haze Rule includes the requirement for 

a monitoring strategy for measuring, 

characterizing, and reporting of regional 

haze 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 

regional haze SIP, and it must be 

reviewed every five (5) 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. 

Under section 51.308(d)(4), 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 regional haze 

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 regional haze 

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 Regional Haze Rule 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 Regional 

Haze SIP. Facilities subject to BART 

must continue to comply with the BART 

provisions of section 51.308(e). Periodic 

SIP revisions will assure that the 

statutory requirement of reasonable 

progress will continue to be met. 

I. Consultation with States and Federal 

Land Managers (FLMs) 

The Regional Haze Rule requires that 

states, or EPA if implementing a FIP, 

consult with FLMs before adopting and 

submitting their SIPs, or FIPs. 40 CFR 

51.308(i). EPA must provide FLMs an 

opportunity for consultation, in person 

and at least 60 days prior to holding any 

public hearing on the FIP. 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, 

EPA must include in its FIP, a 

description of how it addressed any 

comments provided by the FLMs. 

Finally, a FIP must provide procedures 

for continuing consultation between 

EPA and FLMs regarding EPA’s FIP, 

visibility protection program, including 

development and review of FIP 

revisions, five-year progress reports, and 

the implementation of other programs 

having the potential to contribute to 

impairment of visibility in Class I areas. 

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10 Information presented here was taken from the 

WRAP TSS (http://vista.cira.colostate.edu/tss/). 

Some of this information was printed and is 

available in the docket in the document titled 

Selected Information from the WRAP TSS (‘‘WRAP 

TSS Information’’). 

11The 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 RPOs. 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 

instrument in visibility-related research, including 

the advancement of monitoring instrumentation, 

analysis techniques, visibility modeling, policy 

formulation and source attribution field studies. 

http://vista.cira.colostate.edu/improve/

Publications/GrayLit/gray_literature.htm. 

V. EPA’s Analysis of Montana’s 

Regional Haze 

A. Affected Class I Areas 

In accordance with 40 CFR 51.308(d), 

we have identified 12 Class I areas 

within Montana: Anaconda-Pintler WA, 

Bob Marshall WA, Cabinet Mountains 

WA, Gates of the Mountains WA, 

Glacier NP, Medicine Lake WA, Mission 

Mountain WA, Red Rock Lakes WA, 

Scapegoat WA, Selway-Bitterroot WA, 

U.L. Bend WA and Yellowstone NP. 

EPA is responsible for developing RPGs 

for these 12 Class I areas. EPA has also 

determined that Montana emissions 

have or may reasonably be expected to 

have impacts at Class I areas in other 

states including: Badlands WA, Bridger 

WA, Craters of the Moon WA, 

Fitzpatrick WA, Grand Teton NP, Hells 

Canyon WA, Lostwood National 

Wildlife Reserve (NWR), North 

Absaroka NP, Teton WA, Theodore 

Roosevelt NP, Washakie WA and Wind 

Cave NP. This determination was based 

on Particulate Matter Source 

Apportionment Technology (PSAT) and 

Weighted Emissions Potential (WEP) 

analysis and is further described in 

Table 150. 

EPA worked with the appropriate 

state air quality agency in each of these 

states through our involvement with the 

WRAP. The WRAP is a collaborative 

effort of tribal governments, state 

governments and various federal 

agencies to implement the Grand 

Canyon Visibility Transport 

Commission’s recommendations and to 

develop the technical and policy tools 

needed by western states and tribes to 

comply with the U.S. EPA’s regional 

haze regulations. Assessment of 

Montana’s contribution to haze in these 

Class I areas is based on technical 

analyses developed by WRAP as 

discussed in this notice. 

B. Baseline Visibility, Natural Visibility, 

and Uniform Rate of Progress 

As required by section 51.308(d)(2)(i) 

of the Regional Haze Rule and in 

accordance with our 2003 Natural 

Visibility Guidance, EPA calculated 

baseline/current and natural visibility 

conditions for the Montana Class I areas, 

Anaconda-Pintler WA, Bob Marshall 

WA, Cabinet Mountains WA, Gates of 

the Mountains WA, Glacier NP, 

Medicine Lake WA, Mission Mountain 

WA, Red Rock Lakes WA, Scapegoat 

WA, Selway-Bitterroot WA, U.L. Bend 

WA and Yellowstone NP on the most 

impaired and least impaired days, as 

summarized below (and further 

described in the docket).10 The natural 

visibility conditions, baseline visibility 

conditions, and visibility impact 

reductions needed to achieve the 

Uniform Rate of Progress (URP) in 2018 

for all Montana Class I areas are 

presented in Table 1 and further 

explained in this section. 

TABLE 1—VISIBILITY IMPACT REDUCTIONS NEEDED BASED ON BEST AND WORST DAYS BASELINES, NATURAL

CONDITIONS, AND UNIFORM RATE OF PROGRESS GOALS FOR MONTANA CLASS I AREAS

Montana class I area 

20% Worst days 20% Best days 

2000–2004 

Baseline 

(deciview) 

2018 

URP Goal 

(deciview) 

2018 

Reduction 

needed 

(delta 

deciview) 

2064 

Natural 

conditions 

(deciview) 

2000–2004 

Baseline 

(deciview) 

2064 

Natural 

conditions 

(deciview) 

Anaconda-Pintler WA ................................................... 13.41 12.02 1.39 7.43 2.58 1.12 

Bob Marshall WA ......................................................... 14.48 12.91 1.57 7.73 3.85 1.48 

Cabinet Mountains WA ................................................ 14.09 12.56 1.53 7.52 3.62 1.48 

Gates of the Mountains WA ........................................ 11.29 10.15 1.14 6.38 1.71 0.32 

Glacier NP .................................................................... 22.26 19.21 3.05 9.18 7.22 2.42 

Medicine Lake WA ....................................................... 17.72 15.42 2.30 7.89 7.26 2.96 

Mission Mountain WA .................................................. 14.48 12.91 1.57 7.73 3.85 1.48 

Red Rock Lakes WA ................................................... 11.76 10.52 1.24 6.44 2.58 0.43 

Scapegoat WA ............................................................. 14.48 12.91 1.57 7.73 3.85 1.48 

Selway-Bitterroot WA ................................................... 13.41 12.02 1.39 7.43 2.58 1.12 

U.L. Bend WA .............................................................. 15.14 13.51 1.63 8.16 4.75 2.45 

Yellowstone NP ............................................................ 11.76 10.52 1.24 6.44 2.58 0.43 

1. Estimating Natural Visibility 

Conditions 

Natural background visibility, as 

defined in our 2003 Natural Visibility 

Guidance, is estimated by calculating 

the expected light extinction using 

default estimates of natural 

concentrations of fine particle 

components adjusted by site-specific 

estimates of humidity. This calculation 

uses the IMPROVE equation, which is a 

formula for estimating light extinction 

from the estimated natural 

concentrations of fine particle 

components (or from components 

measured by the IMPROVE monitors). 

As documented in our 2003 Natural 

Visibility Guidance, EPA allows the use 

of ‘‘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 

and the Natural Conditions II algorithm 

that was finalized in May 2007.11 The 

purpose of this refinement to the ‘‘old 

IMPROVE equation’’ is to provide more 

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12The science behind the revised IMPROVE 

equation is summarized in our technical support 

document (TSD), in the TSD for Technical Products 

Prepared by the WRAP in Support of Western 

Regional Haze Plans (‘‘WRAP TSD’’), February 28, 

2011, and in numerous published papers. See for 

example: Hand, J.L., and Malm, W.C., 2006, Review 

of the IMPROVE Equation for Estimating Ambient 

Light Extinction Coefficients—Final Report. March 

2006. Prepared for IMPROVE, Colorado State 

University, Cooperative Institute for Research in the 

Atmosphere, Fort Collins, Colorado, available at 

http://vista.cira.colostate.edu/improve/

publications/GrayLit/016_IMPROVEeqReview/

IMPROVEeqReview.htm and Pitchford, March 2006, 

Natural Haze Levels II: Application of the New 

IMPROVE Algorithm to Natural Species 

Concentrations Estimates. Final Report of the 

Natural Haze Levels II Committee to the RPO 

Monitoring/Data Analysis Workgroup. September 

2006, available at http://vista.cira.colostate.edu/

improve/Publications/GrayLit/029_NaturalCondII/

naturalhazelevelsIIreport.ppt. 

13The amount of light lost as it travels over one 

million meters. The haze index, in units of 

deciviews, is calculated directly from the total light 

extinction, bext expressed in inverse megameters 

(Mm¥1), as follows: HI = 10 ln(bext/10). 

accurate estimates of the various factors 

that affect the calculation of light 

extinction. 

For all 12 Class I Areas in Montana, 

EPA opted to use WRAP calculations in 

which the default estimates for the 

natural conditions (see Table 2) were 

combined with the ‘‘new IMPROVE 

equation’’ and the Natural Conditions II 

algorithm (see Table 3). This is an 

acceptable approach under our 2003 

Natural Visibility Guidance. Table 2 

shows the default natural visibility 

values for the 20% worst days and 20% 

best days. 

TABLE 2—DEFAULT NATURAL VISIBILITY VALUES FOR THE 20% BEST

DAYS AND 20% WORST DAYS

Class I area 

20% 

Worst 

days 

20% Best 

days 

Anaconda-Pintler WA 7.28 2.16 

Bob Marshall WA ...... 7.36 2.24 

Cabinet Mountains 

WA ........................ 7.43 2.31 

Gates of the Mountains WA ................ 7.22 2.10 

Glacier NP ................ 7.56 2.44 

Medicine Lake WA ... 7.30 2.18 

Mission Mountain WA 7.39 2.27 

Red Rock Lakes WA 7.14 2.02 

Scapegoat WA .......... 7.29 2.17 

Selway-Bitterroot WA 7.32 2.20 

U.L. Bend WA ........... 7.18 2.06 

Yellowstone NP ........ 7.12 2.00 

EPA also referred to WRAP 

calculations using the new IMPROVE 

equation. Table 3 shows the natural 

visibility values for each Class I Area for 

the 20% worst days and 20% best days 

using the new IMPROVE Equation and 

Natural Conditions II algorithm. 

TABLE 3—VISIBILITY VALUES FOR THE

20% BEST DAYS AND 20% WORST

DAYS USING THE NEW IMPROVE 

EQUATION

Class I area 

20% 

Worst 

days 

20% Best 

days 

Anaconda-Pintler WA 7.43 1.12 

Bob Marshall WA ...... 7.73 1.48 

Cabinet Mountains 

WA ........................ 7.52 1.48 

Gates of the Mountains WA ................ 6.38 0.32 

Glacier NP ................ 9.18 2.42 

Medicine Lake WA ... 7.89 2.96 

Mission Mountain WA 7.73 1.48 

Red Rock Lakes WA 6.44 0.43 

Scapegoat WA .......... 7.73 1.48 

Selway-Bitterroot WA 7.43 1.12 

U.L. Bend WA ........... 8.16 2.45 

Yellowstone NP ........ 6.44 0.43 

The new IMPROVE equation takes 

into account the most recent review of 

the science 12 and accounts for the effect 

of particle size distribution on light 

extinction efficiency of sulfate, nitrate, 

and OC. It also adjusts the mass 

multiplier for OC (particulate organic 

matter) by increasing it from 1.4 to 1.8. 

New terms are added to the equation to 

account for light extinction by sea salt 

and light absorption by gaseous nitrogen 

dioxide. Site-specific values are used for 

Rayleigh scattering (scattering of light 

due to atmospheric gases) to account for 

the site-specific effects of elevation and 

temperature. Separate relative humidity 

enhancement factors are used for small 

and large size distributions of 

ammonium sulfate and ammonium 

nitrate and for sea salt. The terms for the 

remaining contributors, EC (lightabsorbing carbon), fine soil, and coarse 

mass terms, do not change between the 

original and new IMPROVE equations. 

2. Estimating Baseline Conditions 

As required by section 51.308(d)(2)(i) 

of the Regional Haze Rule and in 

accordance with our 2003 Natural 

Visibility Guidance, EPA calculated 

baseline visibility conditions for 

Anaconda-Pintler WA, Bob Marshall 

WA, Cabinet Mountains WA, Gates of 

the Mountains WA, Glacier NP, 

Medicine Lake WA, Mission Mountain 

WA, Red Rock Lakes WA, Scapegoat 

WA, Selway-Bitterroot WA, U.L. Bend 

WA and Yellowstone NP. The baseline 

condition calculation begins with the 

calculation of light extinction, using the 

IMPROVE equation. The IMPROVE 

equation sums the light extinction 13

resulting from individual pollutants, 

such as sulfates and nitrates. As with 

the natural visibility conditions 

calculation, EPA chose to use the new 

IMPROVE equation. 

The period for establishing baseline 

visibility conditions is 2000 through 

2004, and baseline conditions must be 

calculated using available monitoring 

data. 40 CFR 51.308(d)(2). This FIP 

proposes to use visibility monitoring 

data collected by IMPROVE monitors 

located in all Montana Class I areas for 

the years 2000 through 2004 and the 

resulting baseline conditions represent 

an average for 2000 through 2004. Table 

4 shows the baseline conditions for each 

Class I area. 

TABLE 4—BASELINE CONDITIONS ON

20% WORST DAYS AND 20% BEST

DAYS

Class I area 

20% 

Worst 

days 

20% Best 

days 

Anaconda-Pintler WA 13.41 2.58 

Bob Marshall WA ...... 14.48 3.85 

Cabinet Mountains 

WA ........................ 14.09 3.62 

Gates of the Mountains WA ................ 11.29 1.71 

Glacier NP ................ 22.26 7.22 

Medicine Lake WA ... 17.72 7.26 

Mission Mountain WA 14.48 3.85 

Red Rock Lakes WA 11.76 2.58 

Scapegoat WA .......... 14.48 3.85 

Selway-Bitterroot WA 13.41 2.58 

U.L. Bend WA ........... 15.14 4.75 

Yellowstone NP ........ 11.76 2.58 

3. Summary of Baseline and Natural 

Conditions 

To address the requirements of 40 

CFR 51.308(d)(2)(iv)(A), EPA also 

calculated the number of deciviews by 

which baseline conditions exceed 

natural visibility conditions at each 

Class I area. Table 5 shows the number 

of deciviews by which baseline 

conditions exceed natural visibility 

conditions at each Class I area. 

TABLE 5—NUMBER OF DECIVIEWS BY

WHICH BASELINE CONDITIONS EXCEED NATURAL VISIBILITY CONDITIONS

Class I area 

20% 

Worst 

days 

20% Best 

days 

Anaconda-Pintler WA 5.98 1.46 

Bob Marshall WA ...... 6.75 2.37 

Cabinet Mountains 

WA ........................ 6.57 2.14 

Gates of the Mountains WA ................ 4.91 1.39 

Glacier NP ................ 13.08 4.8 

Medicine Lake WA ... 9.83 4.3 

Mission Mountain WA 6.75 2.37 

Red Rock Lakes WA 5.32 2.15 

Scapegoat WA .......... 6.75 2.37 

Selway-Bitterroot WA 5.98 1.46 

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14Additional data and information can be found 

at: http://views.cira.colostate.edu/web/DataFiles/

SummaryDataFiles.aspx. 

TABLE 5—NUMBER OF DECIVIEWS BY

WHICH BASELINE CONDITIONS EXCEED NATURAL VISIBILITY CONDITIONS—Continued 

Class I area 

20% 

Worst 

days 

20% Best 

days 

U.L. Bend WA ........... 6.98 2.3 

Yellowstone NP ........ 5.32 2.15 

4. Uniform Rate of Progress 

In setting the RPGs, EPA reviewed 

and relied on the WRAP analysis to 

analyze and determine the URP needed 

to reach natural visibility conditions by 

the year 2064. In so doing, the analysis 

compared the baseline visibility 

conditions in each Class I area to the 

natural visibility conditions in each 

Class I area (as described above) and 

determined the URP needed in order to 

attain natural visibility conditions by 

2064 in all Class I areas. The analysis 

constructed the URP consistent with the 

requirements of the Regional Haze Rule 

and consistent with our 2003 Tracking 

Progress Guidance by plotting a straight 

graphical line from the baseline level of 

visibility impairment for 2000 through 

2004 to the level of visibility conditions 

representing no anthropogenic 

impairment in 2064 for each Class I 

area. The URPs are summarized in Table 

6. It is clear from Table 6 that there is 

a large range of baseline and natural 

visibility conditions across the 12 Class 

I areas in Montana. The degree of 

improvement to meet the URP at these 

sites varies from, 1.24 deciviews at 

Yellowstone NP to 3.05 deciviews at 

Glacier NP. 

TABLE 6—SUMMARY OF UNIFORM RATE OF PROGRESS FOR 20% WORST DAYS

Class I area 

Baseline 

conditions 

(deciview) 

Natural 

visibility 

(deciview) 

Total improvement by 2064 

(deciview) 

URP 

(deciview/ 

year) 

2018 URP 

target 

(deciview) 

Improvement 

by 2018 

(deciview) 

Anaconda-Pintler WA ............................................. 13.41 7.43 5.98 0.10 12.02 1.39 

Bob Marshall WA ................................................... 14.48 7.73 6.75 0.11 12.91 1.57 

Cabinet Mountains WA .......................................... 14.09 7.52 6.57 0.11 12.56 1.53 

Gates of the Mountains WA .................................. 11.29 6.38 4.91 0.08 10.15 1.14 

Glacier NP .............................................................. 22.26 9.18 13.08 0.22 19.21 3.05 

Medicine Lake WA ................................................. 17.72 7.89 9.83 0.16 15.42 2.3 

Mission Mountain WA ............................................ 14.48 7.73 6.75 0.11 12.91 1.57 

Red Rock Lakes WA ............................................. 11.76 6.44 5.32 0.09 10.52 1.24 

Scapegoat WA ....................................................... 14.48 7.73 6.75 0.11 12.91 1.57 

Selway-Bitterroot WA ............................................. 13.41 7.43 5.98 0.10 12.02 1.39 

U.L. Bend WA ........................................................ 15.14 8.16 6.98 0.12 13.51 1.63 

Yellowstone NP ...................................................... 11.76 6.44 5.32 0.09 10.52 1.24 

5. Contribution Assessment According 

to IMPROVE Monitoring Data 

The visibility and pollutant 

contributions on the 20% worst 

visibility days for the baseline period 

(2000–2004) show considerable 

variation across the 12 Class I areas in 

Montana. Table 7 shows average data 

from the IMPROVE monitors for 2000 to 

2004.14 The table shows light extinction 

from specific pollutants as well as total 

extinction, as determined by the 

monitoring data. As stated above, this 

data provides further detail regarding 

the considerable variation across the 12 

Class I areas in Montana. 

TABLE 7—SPECIES-SPECIFIC LIGHT EXTINCTION DETERMINED FROM MONITORING DATA

Class I area Deciview Sulfate Nitrate Organic 

carbon 

Elemental 

carbon Soil Sea salt Coarse matter 

Total 

extinction 

Anaconda-Pintler WA ................... 13.41 4.83 1.46 20.01 2.52 0.94 0.26 2.49 42.52 

Bob Marshall WA ......................... 14.48 5.12 1.43 22.29 2.80 1.29 0.03 3.60 46.58 

Cabinet Mountains WA ................ 14.09 6.48 2.02 16.95 2.79 1.03 0.10 2.81 42.18 

Gates of the Mountains WA ........ 11.29 5.41 1.88 11.26 1.82 0.75 0.06 1.68 31.85 

Glacier NP .................................... 22.26 11.37 9.36 87.68 11.20 1.40 0.28 5.22 137.50 

Medicine Lake WA ....................... 17.72 16.96 16.27 9.48 2.34 0.75 0.03 4.46 61.30 

Mission Mountains WA ................ 14.48 5.12 1.43 22.29 2.80 1.29 0.03 3.60 46.58 

Red Rock Lakes WA ................... 11.76 4.26 1.77 13.48 2.48 0.95 0.02 2.58 34.55 

Scapegoat WA ............................. 14.48 5.12 1.43 22.29 2.80 1.29 0.03 3.60 46.58 

Selway-Bitterroot WA ................... 13.41 4.83 1.46 20.01 2.52 0.94 0.26 2.49 42.52 

U.L. Bend WA .............................. 15.14 9.78 8.01 12.76 2.08 0.77 0.01 4.01 48.43 

Yellowstone NP ............................ 11.76 4.26 1.77 13.48 2.48 0.95 0.02 2.58 34.55 

The poorest visibility on the 20% 

worst days was at Glacier NP at 22.26 

deciviews, while the best visibility was 

at Gates of the Mountains WA at 11.26 

deciviews. Fire appears to be a major 

factor contributing to the spatial 

differences. The five-year average 

contributions in Table 7 indicate that 

Glacier NP has significantly higher 

contributions from organic carbon mass 

than Gates of the Mountains WA. The 

daily monitoring data for Glacier NP 

shows an episode of exceptionally high 

organic carbon mass during August 

2003 that indicates a fire event. This 

single episode influenced the five-year 

average values for Glacier NP. 

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15This list can be found in the docket with the 

title, Montana BART-Eligible Facility List. 16Correspondence between ASARCO LLC and 

EPA can be found in the docket in the file titled 

ASARCO Correspondence. 17The flow charts that Montana used to identify 

BART-eligible sources are included in the docket in 

a file titled Montana BART Flow Charts. 

18Examples of the letters sent to the Montana 

facilities are included in the docket in a file titled 

Montana Letters. 

19The WRAP’s work is documented in the 

document titled, ‘‘Identification of BART-Eligible 

Sources in the WRAP Region’’ dated April 4, 2005. 

The ‘‘Master List of Montana Sources Reviewed’’ in 

this report is a second document from the one that 

is referred to in a previous footnote titled, 

‘‘Montana BART-Eligible Facility List’’. 

20WRAP TSS Information. 

C. BART Determinations 

BART is an element of EPA’s LTS for 

the first implementation period. As 

discussed in more detail in section IV.E 

of this preamble, 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. 

EPA 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. While 

Montana did not submit a SIP, the State 

did provide some useful information; 

and as discussed below, we are 

proposing it as our conclusion. 

EPA used some information and 

analyses developed by Montana as 

described below. 

Montana identified the following 10 

sources to be BART-eligible: ASARCO 

LLC East Helena Plant; Ash Grove 

Cement Company; Cenex Harvest States 

Cooperative; Laurel Refinery; PPL 

Montana, LLC; Colstrip Steam Electric 

Station Units 1 and 2; Columbia Falls 

Aluminum Company, LLC; ExxonMobil 

Refining & Supply Company Billings 

Refinery; Holcim (US), Inc,; Montana 

Sulfur & Chemical Company; and 

Smurfit-Stone Container Enterprises Inc, 

Missoula Mill.15 Montana originally 

identified ASARCO LLC East Helena 

Plant as BART-eligible; however, the 

emission units at the facility have since 

been demolished. Thus, we are 

proposing that the ASARCO LLC East 

Helena Plant is not BART-eligible.16

The State identified the BART-eligible 

sources in Montana by utilizing the 

approach set out in the BART 

Guidelines (70 FR 39158 (July 6, 

2005)); 17 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(s) 

began operation on or after August 6, 

1962, and was in existence on August 6, 

1977; and (3) potential emissions of any 

visibility-impairing pollutant from 

subject units are 250 tons or more per 

year. Montana initially screened its 

records to identify facilities that could 

potentially meet the three criteria in the 

BART Guidelines (70 FR 39158 (July 6, 

2005)). Montana contacted the sources 

identified through its screening efforts, 

through a series of letters, to obtain or 

confirm this information.18

The WRAP also reviewed facility 

information to identify BART-eligible 

sources. The WRAP used the 

Preliminary 2002 National Emission 

Inventory (NEI) to identify all facilities 

whose actual emissions exceed 100 tons 

per year (tpy) or more of any visibilityimpairing pollutant. The WRAP added 

sources to this preliminary list if they 

were identified by the states or tribes; 

found in various CAA Title V, U.S. 

Department of Energy, and EPA 

databases; or found in EPA background 

documents such as those prepared for 

New Source Performance Standards 

(NSPS), maximum achievable control 

technology standards, and AP–42 

emission factors. The WRAP then 

considered category, date of 

construction, and PTE information to 

determine eligibility. The results from 

this analysis identified facilities as 

BART-eligible, potentially BARTeligible, not known, or not BARTeligible.19

We have reviewed the ‘‘Master List of 

Montana Sources Reviewed’’ in the 

report titled ‘‘Identification of BART 

Eligible Sources in the WRAP Region’’ 

dated April 4, 2005. We propose to 

determine that the following nine 

facilities identified as BART-eligible by 

the State and the WRAP are BARTeligible: Ash Grove Cement Company; 

Cenex Harvest States Cooperative, 

Laurel Refinery; PPL Montana, LLC, 

Colstrip Steam Electric Station Units 1 

and 2; Columbia Falls Aluminum 

Company, LLC; ExxonMobil Refining & 

Supply Company Billings Refinery; 

Holcim (US); Inc, Montana Sulfur & 

Chemical Company; and Smurfit-Stone 

Container Enterprises Inc, Missoula 

Mill. We propose to determine that the 

other facilities identified in the WRAP’s 

April 4, 2005 list as ‘‘potentially BARTeligible’’, ‘‘not known’’, or ‘‘not BARTeligible’’ are not BART-eligible. 

The BART Guidelines require that we 

address SO2, NOX, and direct PM 

(including both coarse particulate 

matter (PM10) and PM2.5) emissions as 

visibility-impairing pollutants and to 

exercise our ‘‘best judgment to 

determine whether VOC or ammonia 

emissions from a source are likely to 

have an impact on visibility in an area.’’ 

See 70 FR 39160, July 6, 2005. VOCs 

and NH3 from point sources are not 

significant visibility-impairing 

pollutants at Montana’s Class I areas. 

Point sources contribute less than 1% to 

Montana’s inventory for both NH3 and 

VOC emissions.20 As a result, we have 

determined that the emissions from 

these point sources do not merit BART 

review. 

We are proposing that the nine 

Montana facilities listed in Table 8 are 

the BART-eligible sources in the State. 

TABLE 8—LIST OF BART-ELIGIBLE SOURCES IN MONTANA

BART-eligible source Location BART Source category (SC) Nearest class I area 

1. Ash Grove Cement Company ... Montana City, western Montana .. Portland cement plants ................. Gates of the Mountains WA 30 

km. 

2. Cenex Harvest States Cooperatives Laurel Refinery.Laurel, central Montana ................ Petroleum refineries ..................... North Absaroka WA 113 km. 

3. PPL Montana, LLC Colstrip 

Steam Electric Station (Unit 1 

and Unit 2).

Colstrip, southeastern Montana ... Fossil-fuel fired steam electric 

plants of more than 250 million 

BTUs per hour heat input.

U.L. Bend WA 200 km. 

4. Columbia Falls Aluminum Company, LLC.Columbia Falls, northwestern 

Montana.

Primary aluminum ore reduction 

plants.

Glacier NP 10 km. 

5. ExxonMobil Refinery & Supply 

Company, Billings Refinery.

Billings, central Montana .............. Petroleum refineries ..................... North Absaroka WA 143 km. 

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21Note 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/

calpuff/calpuff1.htm. 

22This approval is described on p. 57 of the 

WRAP TSD. The WRAP protocol, CALMET/ 

CALPUFF Protocol for BART Exemption Screening 

Analysis for Class I Areas in the Western United 

States, August 15, 2006 can be found in the docket. 

TABLE 8—LIST OF BART-ELIGIBLE SOURCES IN MONTANA—Continued 

BART-eligible source Location BART Source category (SC) Nearest class I area 

6. Holcim (US), Inc. ....................... Three Forks, western Montana .... Portland cement plants ................. Yellowstone NP 100 km. 

7. PPL Montana, LLC—JE Corette 

Steam Electric Station.

Billings, central Montana .............. Fossil-fuel fired steam electric 

plants of more than 250 million 

BTUs per hour heat input.

North Absaroka WA 137 km. 

8. Montana Sulfur & Chemical 

Company.

Billings, central Montana .............. Chemical process plants .............. North Absaroka WA 143 km. 

9. Smurfit-Stone Container Enterprises Inc., Missoula Mill.Missoula, northwestern Montana Kraft pulp mills and fossil fuel boilers of more than 250 million 

BTUs per hour heat input.

Selway-Bitterroot WA 32 km. 

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 us 

to consider exempting some BARTeligible 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, the WRAP performed 

dispersion modeling to assess the extent 

of each BART-eligible source’s 

contribution to visibility impairment at 

surrounding Class I areas and we 

propose to use that modeling. 

a. Modeling Methodology 

The BART Guidelines provide that we 

may use the CALPUFF 21 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 we 

find CALPUFF is the best regulatory 

modeling application currently 

available for predicting a single source’s 

contribution to visibility impairment (70 

FR 39162 (July 6, 2005)). 

The BART Guidelines also 

recommend that a modeling protocol be 

developed for making individual source 

attributions. To determine whether each 

BART-eligible source has a significant 

impact on visibility, we propose to use 

the WRAP’s modeling that used the 

CALPUFF model to estimate daily 

visibility impacts above estimated 

natural conditions at each Class I area 

within 300 kilometers (km) of any 

BART-eligible facility, based on 

maximum actual 24-hour emissions 

over a 3-year period (2000–2002). The 

modeling followed the WRAP protocol, 

CALMET/CALPUFF Protocol for BART 

Exemption Screening Analysis for Class 

I Areas in the Western United States, 

August 15, 2006, which was approved 

by EPA.22

b. Contribution Threshold 

For the 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 39161, 

July 5, 2005. 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 or EPA 

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 and EPA 

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. 

EPA proposes to use a contribution 

threshold of 0.5 deciviews for 

determining which sources are subject 

to BART. EPA’s proposal considered the 

numerous sources affecting the Class I 

areas and the magnitude of the 

individual sources impacts. 70 FR 

39121, July 6, 2005. As shown in Table 

9, EPA proposes to exempt four of the 

nine BART-eligible sources in the State 

from further review under the BART 

requirements. The visibility impacts 

attributable to each of these three 

sources fell well below 0.5 deciviews. 

Our proposed contribution threshold 

captures those sources responsible for 

most of the total visibility impacts, 

while still excluding other sources with 

very small impacts. Id. 

c. Sources Identified by EPA as BART– 

Eligible and Subject to BART 

The results of the CALPUFF modeling 

are summarized in Table 9. Those 

facilities listed with demonstrated 

impacts at all Class I areas less than 0.5 

deciviews are proposed by EPA to not 

be subject to BART; those with impacts 

greater than 0.5 deciviews are proposed 

by EPA to be subject to BART. 

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24000 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

TABLE 9—INDIVIDUAL BART-ELIGIBLE SOURCE VISIBILITY IMPACTS ON MONTANA CLASS I AREAS

Source and unit Class I area 

Maximum 24- 

hour 98th percentile visibility 

impact 

(deciview) 

Subject to BART or exempt 

1. Ash Grove Cement Company ..................... Gates of the Mountains WA ............................ 2.52 Subject to BART. 

Scapegoat WA ................................................ 0.42 

Anaconda-Pintler WA ...................................... 0.09 

Bob Marshall WA ............................................ 0.39 

Mission Mountains WA ................................... 0.06 

Selway-Bitterroot WA ...................................... 0.01 

Yellowstone NP ............................................... 0.01 

Red Rock Lakes WA ....................................... 0.00 

Theodore Roosevelt NP .................................. 0.10 

North Absaroka WA ........................................ 0.00 

Washakie WA .................................................. 0.00 

Teton WA ........................................................ 0.00 

2. Cenex Harvest States Cooperatives, Laurel 

Refinery.

North Absaroka WA ........................................ 0.04 Exempt. 

Yellowstone NP ............................................... 0.02 

Washakie WA .................................................. 0.03 

Teton WA ........................................................ 0.01 

U.L. Bend WA ................................................. 0.00 

Red Rocks Lake WA ....................................... 0.00 

Gates of the Mountains WA ............................ 0.00 

3. PPL Montana, LLC Colstrip Steam Electric 

Station Units 1 and 1.

U.L. Bend WA ................................................. 2.52 Subject to BART. 

North Absaroka WA ........................................ 1.35 

Theodore Roosevelt NP .................................. 2.28 

Washakie WA .................................................. 0.69 

Yellowstone NP ............................................... 0.86 

4. Columbia Falls Aluminum Company, LLC .. Glacier NP ....................................................... 4.54 Subject to BART.

Bob Marshall WA ............................................ 0.11 

Mission Mountains WA ................................... 0.08 

Cabinet Mountains WA ................................... 0.12 

Scapegoat WA ................................................ 0.05 

Selway-Bitterroot WA ...................................... 0.03 

Gates of the Mountains WA ............................ 0.03 

Anaconda-Pintler WA ...................................... 0.02 

5. ExxonMobil Refinery & Supply Company, 

Billings Refinery.23

North Absaroka WA ........................................ 0.27 Exempt. 

Yellowstone NP ............................................... 0.17 

Washakie WA .................................................. 0.22 

U.L. Bend WA ................................................. 0.23 

Teton WA ........................................................ 0.10 

Gates of the Mountains WA ............................ 0.22 

Red Rock Lakes WA ....................................... 0.09 

6. Holcim (US), Inc. ......................................... Yellowstone NP ............................................... 0.52 Subject to BART. 

Gates of the Mountains WA ............................ 1.02 

Anaconda-Pintler WA ...................................... 0.23 

Red Rock Lakes WA ....................................... 0.20 

Scapegoat WA ................................................ 0.28 

North Absaroka WA ........................................ 0.43 

Bob Marshall WA ............................................ 0.28 

Washakie WA .................................................. 0.11 

Theodore Roosevelt NP .................................. 0.08 

Selway-Bitterroot WA ...................................... 0.15 

Mission Mountains WA ................................... 0.12 

Glacier NP ....................................................... 0.11 

7. PPL Montana, LLC-JE Corette Steam Electric Station.North Absaroka WA ........................................ 0.74 Subject to BART. 

Yellowstone NP ............................................... 0.45 

Washakie WA .................................................. 0.53 

U.L. Bend WA ................................................. 0.91 

Teton WA ........................................................ 0.22 

Gates of the Mountains WA ............................ 0.52 

Red Rock Lakes WA ....................................... 0.21 

8. Montana Sulfur & Chemical Company ........ North Absaroka WA ........................................ 0.22 Exempt. 

Yellowstone NP ............................................... 0.17 

Washakie WA .................................................. 0.16 

U.L. Bend WA ................................................. 0.30 

Teton WA ........................................................ 0.08 

Gates of the Mountains WA ............................ 0.19 

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24BART Guidelines, 70 FR 39120 (July 6, 2005). 

25EPA’s Model Distribution Web page available 

at: http://www.epa.gov/ttn/scram/dispersion_

prefrec.htm#calpuff. 

TABLE 9—INDIVIDUAL BART-ELIGIBLE SOURCE VISIBILITY IMPACTS ON MONTANA CLASS I AREAS—Continued 

Source and unit Class I area 

Maximum 24- 

hour 98th percentile visibility 

impact 

(deciview) 

Subject to BART or exempt 

Red Rock Lakes WA ....................................... 0.09 

9. Smurfit-Stone Container Enterprises Inc., 

Missoula Mill.

Selway-Bitterroot WA ...................................... 0.23 Exempt. 

Mission Mountains WA ................................... 0.36 

Bob Marshall WA ............................................ 0.23 

Scapegoat ....................................................... 0.21 

Anaconda-Pintler WA ...................................... 0.07 

Cabinet Mountains WA ................................... 0.14 

Glacier NP ....................................................... 0.19 

Gates of the Mountains WA ............................ 0.11 

Hells Canyon WA ............................................ 0.01 

Eagles Cap Wilderness ................................... 0.00 

23Exxon Mobil submitted revised modeling dated November 29, 2007 (‘‘Exxon Correspondence’’), which is the basis for our analysis and is 

available in the docket. 

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 (July 6, 

2005)) 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, or 

EPA if implementing a FIP, 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 actual 

visibility impact analysis occurs during 

steps 4 and 5 of the process. 

a. Visibility Improvement Modeling 

The fifth factor to consider under 

EPA’s BART Guidelines is the degree of 

visibility improvement from the BART 

control options. See 59 FR 39170 

(August 1, 1994). The BART Guidelines 

recommend using the CALPUFF air 

quality dispersion modeling system to 

estimate the visibility improvements of 

alternative control technologies at each 

Class I area, typically those within a 300 

km radius of the source, and to compare 

these to each other and to the impact of 

the baseline (i.e., current) source 

configuration. The CALPUFF modeling 

system is comprised of the CALMET 

data which is used to pre-process 

meteorological data; the CALPUFF 

model which is used to simulate the 

conversion of pollutant emissions to 

PM2.5 and the transport and fate of 

PM2.5; and the CALPOST processor 

which is used to calculate visibility 

impairments at receptors sites. 

The BART Guidelines recommend 

comparing visibility improvements 

between control options using the 98th 

percentile of 24-hour delta deciviews, 

which is equivalent to the facility’s 8th 

highest visibility impact day. The 98th 

percentile is recommended rather than 

the maximum value to allow for 

uncertainty in the modeled impacts and 

to avoid undue influence from unusual 

meteorological conditions. The ‘‘delta’’ 

refers to the difference between total 

deciview impact from the facility plus 

natural background, and deciviews of 

natural background alone, so ‘‘delta 

deciviews’’ is the estimate of the 

facility’s impact relative to natural 

visibility conditions. Visibility is 

traditionally described in terms of 

visual range in kilometers or miles. 

However, the visual range scale does not 

correspond to how people perceive 

visibility because how a given increase 

in visual range is perceived depends on 

the starting visibility against which it is 

compared. Thus, an increase in visual 

range may be perceived to be a big 

improvement when starting visibility is 

poor, but a relatively small 

improvement when starting visibility is 

good. 

The ‘‘deciview’’ scale is designed to 

address this problem. It is linear with 

respect to perceived visibility changes 

over its entire range, and is analogous to 

the decibel scale for sound. This means 

that a given change in deciviews will be 

perceived as the same amount of 

visibility change regardless of the 

starting visibility. Lower deciview 

values represent better visibility and 

greater visual range, while increasing 

deciview values represent increasingly 

poor visibility. In the BART Guidelines, 

EPA determined that ‘‘a 1.0 deciview 

change or more from an individual 

source would cause visibility 

impairment, and a change of 0.5 

deciviews would contribute to 

impairment. Generally, 0.5 deciviews is 

equivalent to a 5% change in perceived 

visibility and is the amount of change 

that will evoke a just noticeable change 

in most landscapes.’’ 24 Converting a 5% 

change in light extinction to a change in 

deciviews yields a change of 

approximately 0.5 deciviews. 

Under the BART Guidelines, the 

improved visibility in deciviews from 

installing controls is determined by 

using the CALPUFF air quality model. 

CALPUFF, generally, simulates the 

transport and dispersion of emissions, 

and the conversion of SO2 to particulate 

sulfate and NOX to particulate nitrate, at 

a rate dependent on meteorological 

conditions and background ozone 

concentration. These concentrations are 

then converted to delta deciviews by the 

CALPOST post-processor. The 

CALPUFF modeling system is available 

and documented at EPA’s Model 

Distribution Web page.25

The ‘‘delta deciviews’’ for control 

options estimated by the modeling 

represents a BART source’s impact on 

visibility at the Class I areas under 

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24002 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

26CALPUFF model simulations had previously 

been performed for some MT BART sources for 

certain emissions scenarios using meteorological 

data sets for the period 2001–2003 that were 

developed by the WRAP. ‘‘CALMET/CALPUFF 

Protocol for BART Exemption Screening Analysis 

for Class I Areas in the Western United States’’, 

available at http://pah.cert.ucr.edu/aqm/308/bart/

WRAP_RMC_BART_Protocol_Aug15_2006.pdf. 

The WRAP data sets were developed in 2006 

using the CALPUFF model versions and EPA 

guidance available at that time. 

27 ‘‘Modeling Protocol: Montana Regional Haze 

Federal Implementation Plan (FIP) Support’’, 

University of North Carolina, Contract EP–D–07– 

102, November 14, 2011. 

28Modeling Report: Montana Regional Haze 

Federal Implementation Plan (FIP) Support, March 

16, 2012. 

29The following information has been submitted 

by Ash Grove: BART Five Factor Analysis Ash 

Grove Cement Montana City, Montana, Prepared by 

Trinity Consultants (‘‘Ash Grove BART Analysis’’) 

(June 2007); Letter to Callie Videtich RE: Ash Grove 

Cement Montana City Plant, Response to Comments 

on Best Available Retrofit Technology (‘‘Ash Grove 

Response to Comments’’), (February 28, 2008) (note 

that no redacted information that was claimed to be 

CBI by Ash Grove was used from this submittal); 

Letter to Callie Videtich RE: Ash Grove CementMontana City Plant, Response to Comments on Best 

Available Retrofit Technology (‘‘Ash Grove 

Additional Response to Comments’’) (May 5, 2008); 

Email to Laurel Dygowski from Bob Vantuyl RE: 

Ash Grove Cement Montana City BART: Cost 

Analysis for Ash Grove SNCR (‘‘Ash Grove SNCR 

Cost’’) (December 17, 2008); Email to Laurel 

Dygowski from Bob Vantuyl RE: Ash Grove Cement 

Montana City Low NOX Burner Cost Effectiveness 

(‘‘Ash Grove LNB Cost’’) (January 23, 2009); Letter 

to Vanessa Hinkle from Thomas R. Wood RE: 

Substantiation for Confidential Business 

Information Claim for Information Submitted for 

Best Available Retrofit Technology Analysis (‘‘Ash 

Grove Additional Information July 2011’’) (July 18, 

2011); Letter to Vanessa Hinkle from Thomas R. 

Wood RE: Response to Request for Additional 

Information for Montana City BART Determination 

(‘‘Ash Grove Additional Information October 2011’’) 

(October 5, 2011); Email to Vanessa Hinkle from 

Thomas R. Wood RE: Ash Grove City Cement 

Company, Montana City Plant (‘‘Ash Grove 

Additional Information November 2011’’) 

(November 7, 2011); Email to Vanessa Hinkle from 

Curtis Lesslie RE: DAA Cost Analysis (‘‘Ash Grove 

DAA Cost Analysis’’) (December 20, 2011); Email to 

Vanessa Hinkle from Curtis Lesslie RE: Ash Grove 

Montana City BART Analysis Update (‘‘Ash Grove 

Update January 2012’’) (January 19, 2012); Letter to 

Vanessa Hinkle from Thomas R. Wood RE: Ash 

Grove Cement Company Response to Supplemental 

Information Request (‘‘Ash Grove Update March 

2012’’) (March 9, 2012). 30Ash Grove BART Analysis, p. 5–6. 

different control scenarios. Each 

modeled day and location in the Class 

I area will have an associated delta 

deciviews for each control option. For 

each day, the model finds the maximum 

visibility impact of all locations (i.e., 

receptors) in the Class I area. From 

among these daily values, the BART 

Guidelines recommend use of the 98th 

percentile, for comparing the base case 

and the effects of various controls. 

As part of the FIP development 

efforts, EPA determined that CALPUFF 

modeling was needed to evaluate 

emissions scenarios that would be 

consistent with the application of 

controls for Montana sources that were 

subject to BART.26 EPA contracted with 

the University of North Carolina and its 

subcontractor, Alpine Geophysics, to 

perform CALPUFF model simulations 

for BART sources in Montana. The 

University of North Carolina developed 

a modeling protocol that EPA approved. 

The protocol outlines the data sets, 

models and procedures that were used 

in the new CALPUFF modeling for 

BART sources.27 The evaluated Class I 

areas that were included in the 

modeling domain for each BART source 

are listed in Table 2 of the modeling 

protocol. The final report from this 

modeling effort is available in the 

docket.28

The BART determination guidelines 

recommend that visibility impacts 

should be estimated in deciviews 

relative to natural background 

conditions. CALPOST uses background 

concentrations of various pollutants to 

calculate the natural background 

visibility impact. EPA used background 

concentrations from Table 2–1 of 

‘‘Guidance for Estimating Natural 

Visibility Conditions Under the 

Regional Haze Rule.’’ Although the 

concentration for each pollutant is a 

single value for the year, this method 

allows for monthly variation in its 

visibility impact, which changes with 

relative humidity. 

b. BART Five-Factor Determinations 

and Federally Enforceable Limits 

i. Ash Grove Cement 

Background 

The Ash Grove Cement (Ash Grove) 

cement plant near Montana City was 

determined to be subject to the BART 

requirements as explained in section 

V.C. As explained in section V.C., the 

document titled ‘‘Identification of BART 

Eligible Sources in the WRAP Region’’ 

dated April 4, 2005 provides more 

details on the specific emission units at 

each facility. Our analysis focuses on 

the long wet kiln as the primary source 

of SO2 and NOX emissions. 

We requested a five factor BART 

analysis for Ash Grove Cement and the 

company submitted that analysis along 

with updated information.29 Ash 

Grove’s five factor BART analysis is 

contained in the docket for this action 

and we have taken it into consideration 

in our proposed action. 

NOX

Step 1: Identify All Available 

Technologies 

We identified that the following NOX

control technologies are available for the 

kiln at Ash Grove: low NOX burners 

(LNB), mid-kiln firing of solid fuel 

(MKF), cement kiln dust (CKD) 

insufflation, flue gas recirculation 

(FGR), selective noncatalytic reduction 

(SNCR), and selective catalytic 

reduction (SCR). 

LNBs use stepwise or staged 

combustion and localized exhaust gas 

recirculation (i.e., at the flame). Staging 

of combustion air as achieved by such 

burners is an available control 

technology for NOX reduction in cement 

kilns. In the first stage, fuel combustion 

is carried out in a high temperature fuelrich environment and the combustion is 

completed in the fuel-lean low 

temperature second stage. By 

controlling the available oxygen and 

temperature, LNBs attempt to reduce 

NOX formation in the flame zone. LNBs 

have been used by the cement industry 

for nearly 30 years and are designed to 

reduce flame turbulence, delay fuel/air 

mixing, and establish fuel-rich zones for 

initial combustion. LNBs can be used in 

combination with SNCR to achieve even 

greater emissions reduction. 

MKF is a form of secondary 

combustion where a portion of the fuel 

is fired in a location other than the 

burning zone. Ash Grove currently uses 

a mixture of coal and petroleum coke as 

the primary fuels for the kiln. A 

common fuel used for mid kiln firing is 

scrap tires. By adding fuel mid-kiln, 

MKF changes both the flame 

temperature and the flame length. This 

reduces thermal NOX formation by 

burning part of the fuel at a lower 

temperature by creating reducing 

conditions at the mid-kiln fuel injection 

point which may destroy some of the 

NOX formed upstream in the kiln 

burning zone. 

CKD insufflation is a residual 

byproduct that can be produced by any 

of the four basic types of cement kiln 

systems. As a means of recycling usable 

CKD to the cement pyroprocess, CKD 

can be injected or insufflated into the 

burning zone of the rotary kiln in or 

near the main flame. The presence of 

these cold solids within or in close 

proximity to the flame cools the flame 

and/or the burning zone thereby 

reducing the formation of thermal NOX. 

FGR involves the use of oxygendeficient flue gas from some point in the 

process as a substitute for primary air in 

the main burner pipe in the rotary 

kiln.30 FGR lowers the peak flame 

temperature and develops localized 

reducing conditions in the burning zone 

by reducing the oxygen content of the 

primary combustion air. The intended 

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31Ash Grove BART Analysis, p. 5–8. 

32Ash Grove BART Analysis, p. 5–6. 

33EPA provided an example of LNB on a long wet 

kiln with a control effectiveness of 14% in NOX

Control Technologies for the Cement Industry, Final 

Report, September 2000, p. 61. 

34See the document received from TCEQ 

available in the docket: Ash Grove Texas, L.P.— 

Midlothian Plant 2008 Actual Emission Rate 

Calculations—Kilns, Ash Grove Texas, L.P.— 

Midlothian Plant 2008 Actual Emission Rate 

calculations—Input Data. 

35See the documents received from TCEQ 

available in the docket: Ash Grove Texas, L.P.— 

Midlothian Plant 2006 Actual Emission Rate 

Calculations—Kilns; Ash Grove Texas, L.P.— 

Midlothian Plant 2006 Actual Emission Rate 

Calculations—Input Data; Ash Grove Texas, L.P.— 

Midlothian Plant 2008 Actual Emission Rate 

Calculations—Kilns, Ash Grove Texas, L.P.— 

Midlothian Plant 2008 Actual Emission Rate 

calculations—Input Data. 

effect is to decrease both thermal and 

fuel NOX formation in the rotary kiln. 

In SNCR systems, a reagent such as 

NH3 or urea is injected into the flue gas 

at a suitable temperature zone, typically 

in the range of 1,800 to 2,000 °F and at 

an appropriate ratio of reagent to NOX. 

SNCR system performance depends on 

temperature, residence time, turbulence, 

oxygen content, and other factors 

specific to the given gas stream. SNCR 

can be used in combination with LNBs 

to achieve even greater emissions 

control. 

SCR uses either NH3 or urea in the 

presence of a metal based catalyst to 

selectively reduce NOX emissions. SCR 

is used in the electric utility industry to 

reduce NOX emissions from boilers and 

has been used on three cement kilns in 

Europe. SCR is capable of reducing NOX

emissions by about 80%. 

Step 2: Eliminate Technically Infeasible 

Options 

Ash Grove estimated that 

approximately 1.3 million tires would 

be required to use MKF at the Montana 

City kiln.31 There is not a consistent 

supply of scrap tires of this volume that 

would be available for the Montana city 

kiln; therefore, MKF was not considered 

further. 

CKD insufflation can be used at some 

cement kilns, but can be problematic for 

others. The cement making process 

requires a very hot flame to heat the 

clinkering raw material to about 2,700 

°F in as short a time as possible.32

Because of the increased requirements 

for thermal energy in the burning zone 

when insufflation is employed, and the 

expected increase in fuel required, it is 

not an attractive technology for wet kiln 

systems; therefore, CKD insufflation was 

not considered further. 

FGR is used in the electric utility 

industry, but is not transferrable to 

cement kilns. For cement kilns, a hot 

flame is required to complete the 

chemical reactions that form the clinker 

minerals from the raw materials. The 

long/lazy flame that would be produced 

by FGR would result in the production 

of unacceptable quality clinker . 

Clinkering reactions must take place in 

an oxidizing atmosphere in the burning 

zone to generate clinker that can be used 

to produce acceptable cement. FGR 

would tend to produce localized or 

general reducing conditions that also 

could detrimentally affect clinker 

quality. Adding FGR to a burner that is 

already designed for optimum flame 

shaping and control would distort the 

thermal profile of the kiln, such that 

product quality would be unacceptably 

compromised. For these reasons, FGR 

was not considered further. 

SCR has been used on three kilns in 

Europe; two are preheater kilns, and one 

kiln is a Polysius Lepol technology kiln, 

which is a traveling grate preheater kiln. 

73 FR 34079 (June 16, 2008). Although 

we find that SCR is technically feasible 

for cement kilns, we have not analyzed 

it further because of the uncertainty 

regarding control effectiveness and 

costs. We note that EPA has 

acknowledged, in the context of 

establishing the NSPS for Portland 

Cement Plants, substantial uncertainty 

regarding the control effectiveness and 

costs associated with the use of SCR at 

such plants. See 75 FR 54995 

(September 9, 2010). SCR for cement 

kilns will be re-evaluated in subsequent 

reasonable progress (RP) planning 

periods. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

For LNB on Ash Grove’s kiln it is 

appropriate to assume a control 

effectiveness of 15%.33 For SNCR, in 

evaluating the technology, a control 

effectiveness of 50% is appropriate, and 

for LNB+SNCR a control effectiveness of 

58% is appropriate. 

The following discussion is an 

explanation of why we consider 50% 

control effectiveness an appropriate 

estimate for SNCR at long wet kilns, 

such as Ash Grove’s Montana City kiln. 

Ash Grove has used SNCR at similar wet 

kilns in Midlothian, TX. Emissions data 

submitted by Ash Grove to the Texas 

Commission on Environmental Quality 

(TCEQ) show that Ash Grove was able 

to achieve emission rates in the range of 

1.6 to 2.9 lb/ton of clinker from June 

through August 2008 when using 

SNCR.34 The emissions reports 

submitted to the TCEQ indicate that Ash 

Grove had been using SNCR in 2007 on 

one of their kilns at Midlothian; 

however, since the report doesn’t 

specify the exact timeframe we do not 

know whether the 2007 data can be 

compared to the June through August 

2008 data. Because the emission report 

data submitted to the TCEQ for SNCR 

use in 2007 is from an unknown time, 

we used 2006 emission data from the 

same three months as the 2008 data— 

June through August to assess the 

performance of the SNCR.35 Table 10 

summarizes emission from the 

Midlothian kilns using the 2006 and 

2008 data. 

TABLE 10—NOX EMISSIONS FOR 2006 AND 2008 FOR ASH GROVE CEMENT

June through August 2006 emission rate (lb/ton clinker) June through August 2008 emission rate (lb/ton clinker) Percentage 

reduction 

June July August Average June July August Average (%) 

Kiln 1 ........ 5.2 5.0 4.5 4.9 1.7 1.6 2.2 1.8 62.5 

Kiln 2 ........ 5.0 4.1 3.9 4.4 2.7 2.6 2.8 2.7 37.7 

Kiln 3 ........ 5.0 4.4 4.2 4.5 2.9 2.6 2.5 2.7 40.5 

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36EPA has stated previously that, ‘‘[o]n average, 

SNCR achieves approximately a 35 percent 

reduction in NOX at a ratio of NH3-to-NOX of about 

0.5 and a reduction of 63 percent at an NH3-to-NOX

ratio of 1.0’’ in the Federal Register notice 

proposing New Source Performance Standards for 

Portland cement plants. 73 FR 34078 (June 16, 

2008). 

37The Cadence brochures available at: http:// 

cadencerecycling.com/sncr.html and http://

www.cadencerecycling.com/Resources/6–Page

Complete.pdf state that control efficiencies of up to 

50% can be achieved on long wet kilns. See also 

Enhancing SNCR Performance by Induced Mixing, 

Eric Hansen and Fred Lockwood, December 2006 

available at http://www.cadencerecycling.com/

Resources/ICR–Formatted2006.pdf. 

38EPA has stated that, ‘‘there are numerous 

examples of SNCR systems achieving emission 

reductions greater than 50 percent and as high as 

80 percent or more’’ in the Federal Register notice 

proposing New Source Performance Standards for 

Portland cement plants. 73 FR 34079 (June 16, 

2008). 

39EPA’s Control Cost Manual (further referred to 

as CCM) Sixth Edition, January 2002, EPA 452/B– 

02–001 p. 1–10. The CCM can be found at: http:// 

www.epa.gov/ttncatc1/dir1/c_allchs.pdf. 

40Ash Grove Update March 2012 (Ash Grove’s 

email indicates a mean of 14.4 lbs./ton clinker and 

a 99th percentile of 18.6 lb NOX/ton clinker. This 

is significantly greater than the 2006 emissions 

shown in Table 10 for the Midlothian kilns.) 

41Capital Recovery was determined by 

multiplying the Total Capital Investment by the 

CRF of 0.0944 which is based on a 7% interest rate 

and 20 year equipment life. The justification for 

using the CRF of 0.0944 can be found in Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

When the control effectiveness on all 

three kilns are averaged together, a 

47.5% reduction was achieved. This is 

within the range of control effectiveness 

values that have been demonstrated at 

other kilns.36 37 38

The concentration of baseline NOX

emissions is one parameter affecting the 

effectiveness of SNCR. The percentage 

of control effectiveness is greater when 

initial NOX concentrations are greater. 

The reaction kinetics decrease as the 

concentration of reactants decreases. 

This is due to thermodynamic 

considerations that limit the reduction 

process at low NOX concentrations.39

The baseline NOX emissions of the Ash 

Grove Montana City kiln are 

significantly higher than those at 

Midlothian,40 indicating that SNCR on 

the Montana City kiln would be 

expected to achieve even greater control 

effectiveness when compared to SNCR 

on the Midlothian kilns. 

A summary of the emissions 

projections for the NOX control options 

is provided in Table 11. 

TABLE 11—SUMMARY OF NOX BART ANALYSIS CONTROL TECHNOLOGIES FOR ASH GROVE

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

LNB+SNCR ...................................................................................................................... 58 1088 803 

SNCR ............................................................................................................................... 50 946 946 

LNB .................................................................................................................................. 15 284 1,607 

No Controls (Baseline) .................................................................................................... 0 0 1 1,891 

1Ash Grove LNB Cost. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

LNB 

We relied on cost estimates supplied 

by Ash Grove for capital costs and 

annual costs associated with LNB. We 

present the costs for LNB in Table 12 

and 13. For our analysis, we used a 

capital recovery factor (CRF) consistent 

with 20 years for the useful life of the 

kiln. EPA has determined that the 

default 20-year amortization period is 

most appropriate to use as the 

remaining useful life of the facility. 

Without commitments for an early shut 

down, EPA cannot consider a shorter 

amortization period in our analysis. In 

order to calculate the annualized capital 

cost, we multiplied the capital cost by 

the CRF.41 We summarize the cost 

information for LNB in Tables 12, 13, 

and 14. 

TABLE 12—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR LNB ON ASH GROVE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 266,309 

Capital Recovery ................................................................................................................................................................................. 2 25,140 

1Ash Grove LNB Cost. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944 which is based on a 7% interest rate and 

20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 13—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR LNB ON ASH GROVE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1,2 65,642 

Direct Annual Operating Cost .............................................................................................................................................................. 2 92,988 

Total Annual Cost ............................................................................................................................................................................ 158,630 

1 Includes capital recovery. 

2Ash Grove LNB Cost. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24005 

42CRF is 0.0944 and is based on a 7% interest 

rate and 20 year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 43CRF is 0.0944 and is based on a 7% interest 

rate and 20 year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/

circulars_a004_a-4/. 

TABLE 14—SUMMARY OF NOX BART COSTS FOR LNB ON ASH GROVE

Control option 

Total capital 

investment 

($) 

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

LNB .................................................................................................. 266,309 158,630 284 559 

SNCR 

We relied on cost estimates supplied 

by Ash Grove for capital costs and 

annual costs, with the exception of the 

CRF. We present the costs for SNCR in 

Table 15. For our analysis, we used a 

CRF consistent with 20 years for the 

useful life of the kiln. EPA has 

determined that the default 20-year 

amortization period is most appropriate 

to use as the remaining useful life of the 

facility. Without commitments for an 

early shut down, EPA cannot consider 

a shorter amortization period in our 

analysis.42 In order to calculate the 

annualized capital cost, we multiplied 

the capital cost by the CRF.43 We 

summarize the cost information from 

our SNCR analysis in Tables 15, 16, and 

17. 

TABLE 15—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SNCR ON ASH GROVE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 925,324 

Capital Recovery ................................................................................................................................................................................. 1,2 87,351 

1Ash Grove SNCR Cost. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944 which is based on a 7% interest rate and 

20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 16—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR SNCR ON ASH GROVE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1,2 184,063 

Direct Annual Operating Cost .............................................................................................................................................................. 2 1,896,199 

Total Annual Cost ............................................................................................................................................................................ 2,080,262 

1 Includes capital recovery 

2Ash Grove SNCR Cost. 

TABLE 17—SUMMARY OF NOX BART COSTS FOR SNCR ON ASH GROVE

Total capital investment 

($) 

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

925,324 ............................................................................................................................ 2,080,262 946 2,199 

LNB + SNCR 

We calculated the cost effectiveness of 

LNB + SNCR by dividing the sum of the 

annual cost of the two technologies 

described above by the emissions 

reduction that would be achieved. We 

summarize the cost information from 

our LNB + SNCR analysis in Tables 18 

and 19. 

TABLE 18—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR LNB + SNCR ON ASH GROVE

Description Cost ($) 

Total Annual Cost LNB ........................................................................................................................................................................ 158,630 

Total Annual Cost SNCR ..................................................................................................................................................................... 2,080,262 

Total Annual Cost LNB + SNCR ..................................................................................................................................................... 2,238,892 

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24006 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

44Ash Grove BART Analysis, pp. 5–13, 14. 

TABLE 19—SUMMARY OF NOX BART COSTS FOR LNB + SNCR ON ASH GROVE

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

2,238,892 ......................................................................................................................................................... 1,088 2,058 

Factor 2: Energy and Non Air Quality 

Impacts 

LNBs are not expected to have energy 

impacts. SNCR systems require 

electricity to operate the blowers and 

pumps. The generation of the electricity 

will most likely involve fuel 

combustion, which will cause 

emissions. While the required electricity 

will result in emissions, these emissions 

should be small compared to the 

reduction in NOX that would be gained 

by operating an SNCR system.44 LNBs 

are not expected to have any non-air 

quality environmental impacts. 

Transporting the chemical reagents for 

SNCR would use natural resources for 

fuel and would have associated air 

quality impacts. The chemical reagents 

would be stored on site and could result 

in spills to the environment while being 

transferred between storage vessels or if 

containers were to fail during storage or 

movement. The environmental impacts 

associated with proper transportation, 

storage, and/or disposal should not be 

significant. Therefore, the non-air 

quality environmental impacts did not 

warrant eliminating LNB or SNCR. 

Factor 3: Any Existing Pollution Control 

Technology in Use at the Source 

Ash Grove currently uses good 

combustion practices and burner pipe 

maintenance/position for NOX control. 

Factor 4: Remaining Useful Life 

EPA has determined that the 

remaining useful life of the kiln is at 

least 20 years. EPA has determined that 

the default 20-year amortization period 

is most appropriate to use as the 

remaining useful life of the facility. 

Without commitments for an early shut 

down, EPA cannot consider a shorter 

amortization period in our analysis. 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Ash 

Grove as described in section V.C.3.a. 

Table 20 presents the visibility impacts 

of the 98th percentile of daily maxima 

for each Class I area from 2006 through 

2008. 

TABLE 20—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON ASH GROVE

Class I area Baseline impact 

(delta deciview) 

Improvement 

from LNB 

(delta deciview) 

Improvement 

from SNCR 

(delta deciview) 

Improvement 

from LNB + 

SNCR 

(delta deciview) 

Anaconda Pintler WA ...................................................................... 0.426 0.050 0.116 0.166 

Bob Marshall WA ............................................................................. 0.604 0.074 0.173 0.247 

Gates of the Mountains WA ............................................................ 4.446 0.359 0.856 1.248 

Glacier NP ....................................................................................... 0.193 0.021 0.050 0.069 

Mission Mountains WA .................................................................... 0.242 0.024 0.043 0.072 

North Absaroka WA ......................................................................... 0.215 0.028 0.065 0.092 

Red Rock Lakes WA ....................................................................... 0.130 0.016 0.038 0.054 

Scapegoat WA ................................................................................. 1.022 0.131 0.308 0.441 

Selway-Bitterroot WA ....................................................................... 0.412 0.047 0.110 0.158 

Teton WA ......................................................................................... 0.163 0.021 0.048 0.065 

Washakie WA .................................................................................. 0.174 0.020 0.046 0.068 

Yellowstone NP ............................................................................... 0.190 0.028 0.064 0.091 

Table 21 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class area from 2006 through 

2008. 

TABLE 21—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON ASH GROVE

[Three year total] 

Class I area Baseline 

(days) Using LNB Using SNCR Using LNB + SNCR 

Anaconda Pintler WA ...................................................................... 6 6 6 5 

Bob Marshall WA ............................................................................. 21 18 13 9 

Gates of the Mountains WA ............................................................ 361 349 327 296 

Glacier NP ....................................................................................... 2 1 0 0 

Mission Mountains WA .................................................................... 8 8 6 5 

North Absaroka WA ......................................................................... 2 2 0 0 

Red Rock Lakes WA ....................................................................... 0 0 0 0 

Scapegoat WA ................................................................................. 37 35 25 18 

Selway-Bitterroot WA ....................................................................... 7 7 5 4 

Teton WA ......................................................................................... 0 0 0 0 

Washakie WA .................................................................................. 2 0 0 0 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24007 

45Ash Grove Update, March 2012 (Ash Grove 

lists the mean 30-day rolling average NOX emission 

rate for May 26, 2006 through September 8, 2008, 

at 14.4 lb/ton clinker. The 99th percentile 30-day 

rolling average was 18.63 lb/ton clinker. Applying 

58% reduction to the 99th percentile figure yields 

7.82 lb/ton clinker.) 

46As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

TABLE 21—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON ASH GROVE—Continued 

[Three year total] 

Class I area Baseline 

(days) Using LNB Using SNCR Using LNB + SNCR 

Yellowstone NP ............................................................................... 3 1 1 1 

Modeling was performed at 35% 

control effectiveness rather than 50% 

control effectiveness for SNCR and at 

50% control effectiveness rather than 

58% control effectiveness for LNB + 

SNCR. Therefore, visibility 

improvement from SNCR and LNB + 

SNCR would be greater than what is 

shown. 

Step 5: Select BART 

We propose to find that BART for 

NOX is an emission limit of 8.0 lb/ton 

of clinker (30-day rolling average) based 

on the use of LNB + SNCR at Ash Grove. 

Of the five BART factors, cost and 

visibility improvement were the critical 

ones in our analysis of controls for this 

source. 

In our BART analysis for NOX at Ash 

Grove, we considered LNB, SNCR, and 

LNB + SNCR. The comparison between 

our LNB, SNCR, and LNB + SNCR 

analysis is provided in Table 22. 

TABLE 22—SUMMARY OF NOX BART ANALYSIS COMPARISON OF CONTROL OPTIONS FOR ASH GROVE

Control option Total capital 

investment 

Total annual 

cost 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts 1,2

Visibility improvement 

(delta 

deciviews) 

Fewer days > 

0.5 deciview 

LNB + SNCR ........................................... 1,191,632 2,238,893 2,058 1,117 1.248 65 

SNCR ....................................................... 925,324 2,080,262 2,199 2,903 0.856 34 

LNB .......................................................... 266,309 158,630 559 3 0.359 12 

1The visibility benefit shown is for Gates of the Mountains WA. 

2The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I area that showed the greatest improvement, Gates of the Mountains, WA. Similarly, the 

number of days above 0.5 deciviews is the total for the modeled 3-year meteorological period at Gates of the Mountains WA. 3 Incremental cost is not applicable to the option that has the lowest effectiveness. 

We have concluded that LNB, SNCR, 

and LNB + SNCR are all cost effective 

control technologies and that all would 

provide substantial visibility benefits. 

LNB has a cost effectiveness value of 

$559 per ton of NOX emissions reduced. 

SNCR is more expensive than LNB, with 

a cost effectiveness value of $2,199 per 

ton of NOX emissions reduced. While 

LNB + SNCR are more expensive than 

LNB or SNCR alone, it has a cost 

effectiveness value of $2,058 per ton of 

NOX emissions reduced. This is well 

within the range of values we have 

considered reasonable for BART and 

that states have considered reasonable 

for BART. We have weighed costs 

against the anticipated visibility impacts 

for Ash Grove. Any of the control 

options would have a positive impact 

on visibility. As compared to LNB 

alone, LNB + SNCR would provide an 

additional visibility benefit of 0.889 

deciviews and 53 fewer days above 0.5 

deciviews at Gates of the Mountains 

WA. As compared to SNCR alone, LNB 

+ SNCR would provide an additional 

visibility benefit of 0.392 deciviews and 

31 fewer days above 0.5 deciviews at 

Gates of the Mountains WA. We 

consider these impacts to be substantial, 

especially in light of the fact that this 

Class I area is not projected to meet the 

URP. Given the incremental visibility 

improvement associated with LNB + 

SNCR, the relatively low incremental 

cost effectiveness between the options, 

and the reasonable average cost 

effectiveness values for LNB + SNCR, 

we propose that the NOX BART 

emission limit for the kiln at Ash Grove 

should be based on what can be 

achieved with LNB + SNCR. 

As EPA has stated previously, 

adopting an output-based standard 

avoids rewarding a source for becoming 

less efficient, i.e., requiring more feed to 

produce a unit of product. An outputbased standard promotes the most 

efficient production process. 73 FR 

34076, June 16, 2008. Thus, for 

example, the NSPS for NOX and 

National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for 

PM are normalized by ton of clinker 

produced. We have recognized 

previously that facilities are allowed to 

measure feed inputs and to use a sitespecific feed/clinker ratio to calculate 

clinker production. 75 FR 54990 

(September 9, 2010). For these reasons, 

we are proposing to establish an 

emission limit on a lb/ton of clinker 

basis. 

In proposing a BART emission limit 

of 8.00 lb/ton clinker, we considered the 

emission rate currently being achieved 

by Ash Grove.45 This limit also allows 

for a sufficient margin of compliance for 

a 30-day rolling average limit that 

would apply at all times, including 

startup, shutdown, and malfunction.46

We also are proposing monitoring, 

recordkeeping, and reporting 

requirements in regulatory text at the 

end of this proposal. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ We 

propose a compliance deadline of five 

(5) years from the date our final FIP 

becomes effective because of the 

equipment installation and potential 

kiln combustion modifications that will 

be required. 

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24008 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

47Ash Grove Additional Response to Comments. 

48Ash Grove BART Analysis, p. 4–2. 

49Ash Grove Response to Comments, 

Attachment A. 

50Ash Grove January 2012 Update. 

51Formation and Techniques for Control of Sulfur 

Oxide and Other Sulfur Compounds in Portland 

Cement Kiln Systems by F.M. Miller, G.L. Young 

and M. von Seebach (‘‘Formation and Techniques 

of Sulfur Oxide and Other Sulfur Compounds’’, 

(PCA R&D Serial No. 2460), p. 43. 

52Ash Grove BART Analysis, p. 4–11. 

53Formation and Techniques of Sulfur Oxide and 

Other Sulfur Compounds, p. 46. 

54Assessment of Control Technology Options for 

BART–Eligible Sources, March 2005. 

SO2

Step 1: Identify All Available 

Technologies 

We identified that the following SO2

control technologies are available: dry 

absorbent addition (DAA), fuel 

substitution, raw material substitution, 

lime spray drying (LSD), semi-wet 

scrubbing, and wet scrubbing. 

In the DAA process, a dry alkaline 

material such as lime, calcium hydrate, 

limestone, or soda ash would be added 

to the process gas stream upstream of 

the particulate matter control device 

(PMCD) to react with the SO2. Ash 

Grove estimated that they would add a 

2:1 molar ratio of lime to SO2. Solid 

particles of CaSO4 would be produced, 

which would be removed from the gas 

stream along with excess reagent by a 

PMCD in the process flow. The SO2

removal efficiency would vary 

depending on the point of introduction 

into the process according to the 

temperature, degree of mixing, and 

retention time. 

Fuel substitution is a control 

alternative. Ash Grove currently uses a 

mixture of coal and petroleum coke as 

the primary fuels for the kiln. In 2008, 

Ash Grove used 50% petroleum coke, 

41% coal and 1% natural gas. The 

sulfur content of the petroleum coke 

was 5.2%47 and the sulfur content of 

the coal was approximately 0.8%.48 If 

sulfur in fuel input to the kiln were 

reduced by burning a different blend of 

coal and coke with lower sulfur 

contents, a reduction in SO2 emissions 

would be expected. We considered two 

different options for fuel switching. 

Option 1 would use 62% coal with 

0.8% sulfur and 38% coke with 5.2% 

sulfur. Option 2 would use 100% coal 

that has a lower sulfur content (0.7%), 

and a higher Btu value.49

Raw material substitution would 

entail using a different source of 

limestone that contains a lower pyritic 

sulfur content. 

LSD involves injecting an aqueous 

lime suspension in fine droplets into the 

flue gas. The lime reacts with SO2 in the 

flue gas to create fine particles of CaSO3

or CaSO4. The moisture evaporates from 

the particles, and the particles are 

collected in the PMCD. 

Semi-wet scrubbers are sometimes 

referred to as spray dryer absorbers 

(SDAs). This technology uses lime or 

limestone to react with SO2. This 

technology has been used for SO2

control on preheater/calciner kilns, but 

it can be successfully used on long kilns 

by adding spray nozzles that are made 

of special materials to prevent nozzle 

clogging. A semi-wet scrubber can 

achieve a SO2 removal efficiency of 30% 

to 60%. Clogging may not be an issue 

with semi-wet scrubbers that use lime 

due to the small size of the lime 

particles (3–10 microns) which allows 

the particles to dissolve in water 

droplets quickly and react with the 

gaseous SO2. 

Wet scrubbing involves passing flue 

gas downstream from the main PMCD 

through a sprayed aqueous suspension 

of lime or limestone that is contained in 

a scrubbing device. The SO2 reacts with 

the scrubbing reagent to form lime 

sludge that is collected. The sludge 

usually is dewatered and disposed of at 

an offsite landfill. 

Step 2: Eliminate Technically Infeasible 

Options 

With regard to raw material 

substitution, using raw materials with a 

lower pyritic sulfur content could 

reduce SO2 emissions. Because cement 

plants are built at or near a source of 

limestone so that shipping costs are 

minimized, it would be infeasible, 

however, to obtain raw material with a 

lower pyritic sulfur content from some 

other source. 

The design of a wet kiln, unlike a 

preheater/precalciner (PH/PC) kiln, is 

not amenable to the addition of a LSD. 

By its design, a PH/PC provides a 

natural location for a spray dryer type 

control system to be used between the 

top of the preheater tower and the 

PMCD. A wet kiln does not have that 

attribute. The back end of Ash Grove’s 

wet kiln has a relatively short retention 

time prior to the PMCD and this would 

not allow for a spray dryer. For this 

reason, this alternative was not 

considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

EPA estimates that the appropriate 

control effectiveness of DAA at Ash 

Grove is 30%.50 A literature search 

indicates that hydrated lime 

appropriately injected can easily 

produce a 30% SO2 control efficiency 

with a 2.5 to 1 CaO to SO2 ratio.51

For fuel switching, we used a SO2

control effectiveness of 17% for the 

purposes of considering fuel switching 

to 38% coke and 62% coal and SO2

control effectiveness of 60% for the 

purposes of considering fuel switching 

to 100% low-sulfur coal.52

The efficiency of semi-wet scrubbing 

is estimated to be 90%. A 90% SO2

control effectiveness is the minimum of 

the range for a semi-wet scrubber with 

lime absorbent medium.53 EPA has 

stated that a well designed and operated 

wet scrubber can consistently achieve at 

least 90% control (75 FR 54995, Sept. 9, 

2010) and that 95% control efficiency is 

possible on cement kilns and consistent 

with other information on the 

performance of scrubbers for SO2

removal (73 FR 34080, June 16, 2008).54

We used 90% control effectiveness for 

our analysis, which is at the lower end 

of the range that is possible. 

TABLE 23—SUMMARY OF SO2 BART ANALYSIS CONTROL TECHNOLOGIES FOR ASH GROVE

Control Option 

Control 

effectiveness 

(%) 

Annual 

emissions 

reduction 

(tpy) 

Remaining 

annual 

emissions 

(tpy) 

Fuel Switching Option 1 (38% coke/62% coal) ............................................................... 1 17 200 978 

DAA .................................................................................................................................. 30 353 825 

Fuel Switching Option 2 (lower sulfur coal) .................................................................... 1 60 707 471 

Semi-wet scrubbing ......................................................................................................... 90 1060 118 

Wet scrubbing .................................................................................................................. 90 1060 118 

No Controls (Baseline) .................................................................................................... 0 0 2 1,178 

1Ash Grove Response to Comments, Attachment A. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24009 

55Ash Grove Update January 2012. 

56CRF is 0.0944 and is based on a 7% interest 

rate and 20 year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

57 Id. 

58 2008 NEI. 

59Ash Grove Response to Comments, 

Attachment A. 

2 2008 NEI. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

DAA 

We relied on Ash Grove’s costs 55 for 

DAA with the following exceptions. We 

present the costs for DAA in Table 24. 

In our estimate, we used a CRF 

consistent with 20 years of useful life of 

the kiln and equipment.56 EPA has 

determined that the default 20-year 

amortization period is most appropriate 

to use as the remaining useful life of the 

facility. Without commitments for an 

early shut down, EPA cannot consider 

a shorter amortization period in our 

analysis. In order to calculate the 

annualized capital cost, we multiplied 

the capital cost by the CRF.57 We used 

1,178 tpy of SO2 as was reported to the 

NEI for 2008.58 We summarize the cost 

information for DAA in Tables 24, 25, 

and 26. 

TABLE 24—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR DAA ON ASH GROVE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 330,620 

Capital Recovery ................................................................................................................................................................................. 2 31,211 

1Ash Grove Update January 2012. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944, which is based on a 7% interest rate and 

20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 25—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR DAA ON ASH GROVE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1 205,243 

Total Annual Operating Cost ............................................................................................................................................................... 2 257,839 

Total Annual Cost ................................................................................................................................................................................ 463,082 

1 Includes capital recovery. 

2Ash Grove Update January 2012. 

TABLE 26—SUMMARY OF SO2 BART COSTS FOR DAA ON ASH GROVE

Total capital investment 

($) 

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

330,620 ............................................................................................................................ 463,082 323 1,434 

We relied on Ash Grove’s costs 59 for 

fuel switching with the following 

exception. We used 1,178 tpy of SO2 as 

was reported to the NEI for 2008. There 

is no capital cost for fuel switching 

because there is no equipment to buy or 

install. However, annual cost will 

increase due to increased fuel cost. We 

summarize the cost information for fuel 

switching in Tables 27 and 28. 

TABLE 27—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR FUEL SWITCHING FOR ASH GROVE

Description Cost ($) 

Total Annual Cost Option 1 (38% coke/62% coal) ............................................................................................................................. 1 487,877 

Total Annual Cost Option 2 (lower sulfur coal) ................................................................................................................................... 1 2,908,170 

1Ash Grove Response to Comments. 

TABLE 28—SUMMARY OF SO2 BART COSTS FOR FUEL SWITCHING ON ASH GROVE

Control option Total annual cost 

($) 

Emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

Fuel Switching Option 1 .................................................................................................. 487,877 200 2,439 

Fuel Switching Option 2 .................................................................................................. 2,908,170 707 4,113 

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24010 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

60Ash Grove Additional Information October 

2011. 

61CRF is 0.0944 and is based on a 7% interest 

rate and 20 year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

62 Id. 

63 Id. 

64 Id. 

Semi-Wet Scrubbing 

We relied on Ash Grove’s costs 60 for 

fuel switching with the following 

exceptions. We present the costs for 

semi-wet scrubbing in Table 29. In our 

estimate, we used a CRF consistent with 

20 years for the useful life of the kiln 61

EPA has determined that the default 20- 

year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

In order to calculate the annualized 

capital cost, we multiplied the capital 

cost by the CRF.62 We used 1,178 tpy of 

SO2 as was reported to the NEI for 2008. 

We summarize the cost information for 

semi-wet scrubbing in Tables 29, 30, 

and 31. 

TABLE 29—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR SEMI-WET SCRUBBING ON ASH GROVE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 11,644,912 

Capital Recovery ................................................................................................................................................................................. 1,2 1,099,280 

1Ash Grove Additional Information October 2011. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944 which is based on a 7% interest rate and 

20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 30—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR SEMI-WET SCRUBBING ON ASH GROVE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1,2 1,689,936 

Total Annual Operating Cost ............................................................................................................................................................... 1 250,068 

Total Annual Cost ................................................................................................................................................................................ 1,940,004 

1Ash Grove Additional Information October 2011. 

2 Includes capital recovery. 

TABLE 31—SUMMARY OF SO2 BART COSTS FOR SEMI-WET SCRUBBING ON ASH GROVE

Total capital investment 

($) 

Total annual cost 

($) 

Emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

11,644,912 ....................................................................................................................... 1,940,004 1,060 1,830 

Wet Scrubbing 

We relied on costs provided by Ash 

Grove for wet scrubbing, which we note 

appear to be more expensive than other 

cost estimates for wet scrubbing on 

cement kilns. We present the costs for 

wet scrubbing in Table 32. In our 

estimate, we used a CRF consistent with 

20 years for the remaining useful life of 

the kiln 63 EPA has determined that the 

default 20-year amortization period is 

most appropriate to use as the 

remaining useful life of the facility. 

Without commitments for an early shut 

down, EPA cannot consider a shorter 

amortization period in our analysis. 

In order to calculate the annualized 

capital cost, we multiplied the capital 

cost by the CRF.64 We used 1,178 tpy of 

SO2 as was reported to the NEI for 2008. 

We summarize the cost information for 

wet scrubbing in Tables 32, 33, and 34. 

TABLE 32—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR WET SCRUBBER ON ASH GROVE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 30,022,424 

Capital Recovery ................................................................................................................................................................................. 1,2 2,834,117 

1Ash Grove Additional Information October 2011. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944 which is based on a 7% interest rate and 

20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 33—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR WET SCRUBBER ON ASH GROVE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1,2 4,335,284 

Total Annual Operating Cost ............................................................................................................................................................... 2 759,278 

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65Ash Grove Additional Information October 

2011, p. 14. 

66Ash Grove Additional Information October 

2011, p. 10. 

67Ash Grove Additional Information October 

2011, p. 14. 

68Ash Grove Additional Information October 

2011, p. 10. 

69Ash Grove Additional Information October 

2011, Attachments 1 and 2. 

70Ash Grove Response to Comments. 

71Ash Grove BART Analysis, p. 4–2. 

TABLE 33—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR WET SCRUBBER ON ASH GROVE—Continued 

Description Cost ($) 

Total Annual Cost ............................................................................................................................................................................ 5,094,562 

1 Includes capital recovery. 

2Ash Grove Additional Information October 2011. 

TABLE 34—SUMMARY OF SO2 BART COSTS FOR WET SCRUBBER ON ASH GROVE

Total capital investment 

($) 

Total annual cost 

($) 

Emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

30,022,424 ....................................................................................................................... 5,094,562 1,060 4,806 

Factor 2: Energy and Non Air Quality 

Impacts 

We did not identify any energy or 

non-air quality environmental impacts 

associated with fuel switching at Ash 

Grove. Wet scrubbing and semi-wet 

scrubbing use additional water. Wet 

scrubbing would consume 

approximately 38 gallons per minute of 

water, resulting in approximately 19 

million gallons per year. Semi-wet 

scrubbing would use 3.5 gallons per 

minute, for an annual usage of 1.75 

million gallons per year.65 DAA would 

not require additional water. This arid 

location receives 11.9 inches of rainfall 

annually.66 Montana decreased the 

water rights held by Ash Grove’s 

Montana City plant to match historical 

use, which resulted in withdrawal of 

previous water rights.67 As a result even 

if Ash Grove were able to obtain water 

rights, there is no guarantee that Ash 

Grove would be able to rely on that 

water right, as in a dryer than normal 

year a more senior water rights holder 

could require that Ash Grove cease its 

water use.68 The cost analysis for wet 

scrubbing and semi-wet scrubbing 

included the costs of obtaining water.69

Wet scrubbing, semi-wet scrubbing, 

and DAA would also generate a waste 

stream that would need to be 

transported and disposed. Transporting 

the waste would use natural resources 

for fuel and would have associated air 

quality impacts. The disposal of the 

solid waste itself would be to a landfill 

and could possibly result in 

groundwater or surface water 

contamination if a landfill’s engineering 

controls were to fail. The environmental 

impacts associated with proper 

transportation and/or disposal should 

not be significant. 

Wet scrubbing, semi-wet scrubbing 

and DAA require additional electricity 

to service pretreatment and injection 

equipment, pumps, compressors, and 

control systems. The additional energy 

requirements that would be involved in 

installation and operation of the 

evaluated controls are not significant 

enough to warrant eliminating any of 

the options evaluated. Note that cost of 

the additional energy requirements has 

been included in our calculations. 

Factor 3: Any Existing Pollution Control 

Technology in Use at the Source 

The kiln currently uses low sulfur 

coal as a component of fuel mix and 

inherent scrubbing for SO2 control. The 

kiln inherently acts as an SO2 scrubber, 

since some of the sulfur that is oxidized 

to SO2 is absorbed by the alkali 

compounds in the raw material fed to 

the kiln.70 Ash Grove currently uses a 

mixture of petroleum coke with a sulfur 

content of 5.2% and coal with a sulfur 

content of 0.8%.71

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Ash 

Grove as described in section V.C.3.a. 

Table 35 presents the visibility impacts 

of the 98th percentile of daily maxima 

for each Class I area from 2006 through 

2008. 

TABLE 35—DELTA DECIVIEW IMPROVEMENT FOR SO2 CONTROLS ON ASH GROVE

Class I area 

Baseline impact (delta 

deciview) 

Improvement 

from fuel 

switching— 

Option 1 

(delta 

deciview) 

Improvement 

from DAA 

(delta 

deciview) 

Improvement 

from fuel 

wwitching— 

Option 2 

(delta 

deciview) 

Improvement 

from semi-wet 

scrubbing 

(delta 

deciview) 

Improvement 

from wet 

scrubbing 

(delta 

deciview) 

Anaconda Pintler WA ............................... 0.426 0.015 0.020 0.050 0.074 0.074 

Bob Marshall WA ..................................... 0.604 0.016 0.023 0.056 0.083 0.083 

Gates of the Mountains WA .................... 4.446 0.033 0.049 0.119 0.180 0.180 

Glacier NP ................................................ 0.193 0.009 0.013 0.035 0.048 0.048 

Mission Mountains WA ............................ 0.242 0.012 0.018 0.039 0.059 0.059 

North Absaroka WA ................................. 0.215 0.009 0.012 0.018 0.030 0.030 

Red Rock Lakes WA ............................... 0.130 0.007 0.010 0.015 0.022 0.022 

Scapegoat WA ......................................... 1.022 0.017 0.025 0.060 0.090 0.090 

Selway-Bitterroot WA ............................... 0.412 0.014 0.020 0.049 0.074 0.074 

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TABLE 35—DELTA DECIVIEW IMPROVEMENT FOR SO2 CONTROLS ON ASH GROVE—Continued 

Class I area 

Baseline impact (delta 

deciview) 

Improvement 

from fuel 

switching— 

Option 1 

(delta 

deciview) 

Improvement 

from DAA 

(delta 

deciview) 

Improvement 

from fuel 

wwitching— 

Option 2 

(delta 

deciview) 

Improvement 

from semi-wet 

scrubbing 

(delta 

deciview) 

Improvement 

from wet 

scrubbing 

(delta 

deciview) 

Teton WA ................................................. 0.163 0.008 0.012 0.030 0.044 0.044 

Washakie WA .......................................... 0.174 0.006 0.009 0.021 0.033 0.033 

Yellowstone NP ........................................ 0.190 0.012 0.018 0.042 0.062 0.062 

Table 36 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class area from 2006 through 

2008. 

TABLE 36—DAYS GREATER THAN 0.5 DECIVIEW FOR SO2 CONTROLS ON ASH GROVE

[Three year total] 

Class I area Baseline days 

Using fuel 

switching 

Option 1 

Using fuel 

switching 

Option 2 

Using DSI Using SDA Using wet 

scrubber 

Anaconda Pintler WA ............................... 6 6 6 6 6 6 

Bob Marshall WA ..................................... 21 21 19 21 18 18 

Gates of the Mountains WA .................... 361 359 352 356 349 348 

Glacier NP ................................................ 2 1 1 1 1 1 

Mission Mountains WA ............................ 8 8 8 8 7 7 

North Absaroka WA ................................. 2 2 2 2 2 2 

Red Rock Lakes WA ............................... 0 0 0 0 0 0 

Scapegoat WA ......................................... 37 37 34 36 33 33 

Selway-Bitterroot WA ............................... 7 7 7 7 6 6 

Teton WA ................................................. 0 0 0 0 0 0 

Washakie WA .......................................... 2 2 0 1 0 0 

Yellowstone NP ........................................ 3 2 2 2 2 2 

Modeling was performed at a 25% 

control effectiveness rather than at a 

30% control effectiveness for DAA, and 

at a control effectiveness of 60% rather 

than 50% for fuel switching—option 2; 

however, this should not change the 

outcome of the analysis because of the 

relatively small visibility improvement 

for each of the SO2 controls considered. 

Step 5: Select BART 

We propose to find that BART for SO2

is no additional controls at Ash Grove. 

We are accordingly proposing a BART 

emission limit of 11.5 lb/ton clinker (30- 

day rolling average). Of the five BART 

factors, visibility was the critical one in 

our analysis of controls for this source. 

The low visibility improvement 

predicted from the use of SO2 controls 

did not justify proposing additional 

controls on this source. 

In our BART analysis for SO2 at Ash 

Grove, we considered DAA, fuel 

switching, semi-wet scrubbing and wet 

scrubbing. The comparison between our 

DAA, fuel switching, semi-wet 

scrubbing and wet scrubbing analysis is 

provided in Table 37. 

TABLE 37—SUMMARY OF EPA SO2 BART ANALYSIS COMPARISON OF DAA, FUEL SWITCHING, SEMI-WET SCRUBBING

AND WET SCRUBBING FOR ASH GROVE

Control option Total capital 

investment 

Total annual 

cost 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost effectiveness 

($/ton) 

Visibility impacts 1,2

Visibility improvement 

(delta 

deciviews) 

Fewer 

days > 0.5 

deciview 

Wet Scrubbing ......................................... 30,022,424 5,094,562 4,806 3 0.180 12 

Semi-wet scrubbing ................................. 11,644,912 1,940,004 1,830 2,095 0.180 12 

Fuel Switching—Option 2 ........................ 4 2,908,170 4,113 4,773 0.119 9 

DAA .......................................................... 330,620 463,082 1,434 5 0.049 5 

Fuel Switching—Option 1 ........................ 4 487,877 2,439 6 0.033 ........................

1The visibility benefit shown is for Gates of the Mountains WA. 

2The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I area that showed the greatest improvement, Gates of the Mountains, WA. Similarly, the 

number of days above 0.5 deciviews is the total for the modeled 3-year meteorological period at Gates of the Mountains WA. 3 Incremental Cost Effectiveness cannot be calculated because both technologies reduce the same amount of emissions. 

4 Capital cost is not required for fuel switching. 

5 Incremental cost would result in a negative number and therefore was not calculated. 

6 Incremental cost is not applicable to the option that has the lowest effectiveness. 

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72As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

73Response to EPA request for supplemental 

information on emissions from the Montana City 

plant, March 9, 2012. Ash Grove lists the mean 30- 

day rolling average SO2 emission rate for May 26, 

2006 through September 8, 2008, at 7.2 lb/ton 

clinker. The 99th percentile 30-day rolling average 

was 11.02 lb/ton clinker. 

74EPA Air Pollution Control Online Course, 

description at: http://www.epa.gov/apti/course422/ 

ce6a1.html. 

75BART analysis by Holcim for Trident Cement 

Plant, Three Forks, MT (‘‘Holcim Initial Response’’) 

(Jul 6, 2007); Responses to EPA comments on BART 

analysis for Trident Cement Plant (‘‘Holcim 2008 

Responses’’) (Jan. 25, 2008); BART analysis by 

Holcim for low NOX burners for Trident Cement 

Plant (‘‘Holcim Additional Response, June 2009’’) 

(Jun 9, 2009); Response to EPA letter regarding 

Confidential Business Information (CBI) claims on 

BART analysis for Trident Cement Plant (‘‘Holcim 

Continued 

We have concluded that DAA, fuel 

switching, semi-wet scrubbing, and wet 

scrubbing are all cost effective control 

technologies, but that they would not 

provide substantial visibility benefits. 

Given that the visibility improvement 

associated with SO2 controls are 

relatively small, we propose that the 

SO2 BART emission limit for the kiln at 

Ash Grove should be based on current 

emissions, while allowing for a 

sufficient margin of compliance for a 30- 

day rolling average limit that would 

apply at all times, including startup, 

shutdown, and malfunction.72 As EPA 

has stated previously, adopting an 

output-based standard avoids rewarding 

a source for becoming less efficient, i.e., 

requiring more feed to produce a unit of 

product. An output-based standard 

promotes the most efficient production 

process. 73 FR 34076, June 16, 2008. 

The NSPS for NOX and NESHAP for PM 

are normalized by ton of clinker 

produced. We have recognized 

previously that facilities are allowed to 

measure feed inputs and to use sitespecific feed/clinker ratio to calculate 

clinker production. 75 FR 54990, Sept. 

9, 2010. 

Accordingly, we are proposing 11.5 

lb/ton clinker as a BART emission limit 

for SO2 at Ash Grove Cement. In 

proposing this limit, we considered the 

emission rate currently being achieved 

by Ash Grove Cement in lb/ton 

clinker.73 We are also proposing 

monitoring, recordkeeping, and 

reporting requirements as described in 

our proposed regulatory text for 40 CFR 

52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Because 

we are not requiring additional controls 

to be installed, we propose that Ash 

Grove must comply with this emission 

limit within 180 days from the date our 

final FIP becomes effective. This will 

allow time for monitoring systems to be 

certified if necessary. 

PM 

Ash Grove currently has an 

electrostatic precipitator (ESP) for 

particulate control from the kiln. An 

ESP is a particle control device that uses 

electrical forces to move the particles 

out of the flowing gas stream and onto 

collector plates. The ESP places 

electrical charges on the particles, 

causing them to be attracted to 

oppositely charged metal plates located 

in the precipitator. The particles are 

removed from the plates by ‘‘rapping’’ 

and collected in a hopper located below 

the unit. The removal efficiencies for 

ESPs are highly variable; however, for 

very small particles alone, the removal 

efficiency is about 99%.74

Ash Grove Cement must meet a PM10

emission rate based on the process 

weight of the kiln. Pursuant to the 

regulatory requirement in Montana’s 

EPA approved SIP (Administrative Rule 

of Montana (ARM) 17.8.310), permit 

condition A.8 in Ash Grove’s Final Title 

V Operating Permit #OP2005–06 

contains the following requirements: if 

the process weight rate of the kiln is less 

than or equal to 30 tons per hour, then 

the emission limit shall be calculated 

using E = 4.10p0.67 where E = rate of 

emission in pounds per hour and p = 

process weight rate in tons per hour; 

however, if the process weight rate of 

the kiln is greater than 30 tons per hour, 

then the emission limit shall be 

calculated using E = 55.0p0.11¥40, 

where E = rate of emission in pounds 

per hour and P = process weight rate in 

tons per hour. 

Based on our modeling described in 

section V.C.3.a, PM contribution to the 

baseline visibility impairment is low. 

Table 38 shows the maximum baseline 

visibility impact from PM and 

percentage contribution to that impact 

from coarse PM and fine PM. 

TABLE 38—ASH GROVE VISIBILITY IMPACT CONTRIBUTION FROM PM 

Maximum baseline visibility impact 

(deciview) 

% Contribution 

coarse PM 

% Contribution 

fine PM 

4.446 ................................................................................................................................................................ 0.84 4.77 

The PM contribution to the baseline 

visibility impact for Ash Grove is very 

small; therefore, any visibility 

improvement that could be achieved 

with improvements to the existing PM 

controls would be negligible. 

Taking into consideration the above 

factors we propose a BART emission 

limit based on use of the current control 

technology at Ash Grove and the 

emission limits described above for PM/ 

PM10 as BART. We find that the BART 

emission limit can be achieved through 

the operation of the existing ESP. Thus, 

as described in our BART Guidelines, a 

full five-factor analysis for PM/PM10 is 

not needed for Ash Grove. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

ii. Holcim 

Background 

The Holcim (US) Inc. Trident cement 

plant near Three Forks, MT was 

determined to be subject to the BART 

requirements as explained in section 

V.C. As explained in section V.C., the 

document titled ‘‘Identification of 

BART-Eligible Sources in the WRAP 

Region’’ dated April 4, 2005 provides 

more details on the specific emission 

units at each facility. Our analysis 

focuses on the kiln as the primary 

source of SO2 and NOX emissions. We 

requested a five factor BART analysis 

for Holcim’s Trident cement plant. The 

company submitted that analysis on 

July 6, 2007, with updated information 

on January 25, 2008, June 9, 2009, 

August 12, 2009, June 16, 2011, and 

March 2, 2012.75 Holcim’s five factor 

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Additional Response, August 2009’’) (Aug. 12, 

2009); Response to EPA request for NOX and SO2

emissions data for 2008–2010 (‘‘Holcim 2011 

Response’’) (Jun. 16, 2011); Response to EPA 

request for emissions and clinker production for 

Holcim pursuant to CAA section 114(a) (‘‘Holcim 

2012 Response’’) (Mar. 2, 2012). 

76EPA provided an example of LNB on a long wet 

kiln with a control effectiveness of 14% in NOx 

Control Technologies for the Cement Industry, Final 

Report, September 2000, p. 61. 

77Holcim Initial Response, p. 4–16. 

78We analyzed only for commercial SNCR at 

Holcim. In its January 25, 2008 submittal to EPA, 

Holcim discussed (at pages 11–12) an alternative 

form of SNCR, which Holcim refers to as ‘‘dust 

scoops’’ SNCR. This version of SNCR would use a 

solid pelletized form of urea, which could be 

mechanically introduced into the existing ‘‘dust 

scoops’’ mechanism. In its August 12, 2009 

submittal to EPA, Holcim presented cost 

spreadsheets which estimated substantially less 

cost for ‘‘dust scoops’’ SNCR than for commercial 

SNCR ($716,800 capital cost versus $1,312,800 

capital cost). However, Holcim’s 2008 submittal 

indicated that neither type of SNCR was being 

considered by Holcim on anything more than a trial 

basis. Therefore, EPA has chosen to use the 

commercial SNCR cost estimate in its analysis, 

rather than the ‘‘dust scoops’’ SNCR cost estimate. 

79CCM, p. 1–10. 

80Holcim 2012 Response. 

81Holcim Additional Response, June 2009. 

82Holcim applied a 1.5 multiplier to the direct 

installation costs, for ‘‘retrofit installation.’’ We did 

not. 

83CRF is 0.0944 and is based on a 7% interest 

rate and 20-year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

BART analysis is contained in the 

docket for this action and we have taken 

it into consideration in our proposed 

action. 

NOX

Step 1: Identify All Available 

Technologies 

We identified the following 

previously described NOX control 

technologies are available: LNB, MKF, 

FGR, SNCR, and SCR. 

Step 2: Eliminate Technically Infeasible 

Options 

We did not consider FGR and SCR 

further for Holcim since Holcim and 

Ash Grove are similar with regard to the 

relevant factors. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

For LNB on Holcim’s kiln, it is 

appropriate to assume a control 

effectiveness of 15%.76 For MKF, a 

control effectiveness of 30% is 

appropriate.77 For SNCR, in evaluating 

the technology, a control effectiveness 

of 50% is appropriate, and for 

LNB+SNCR a control effectiveness of 

58% is appropriate.78

As described above in the Ash Grove 

analysis, we consider 50% control 

effectiveness appropriate for SNCR at 

long wet kilns, such as Holcim’s kiln. 

Concentration of baseline NOX

emissions is one parameter affecting 

control effectiveness. The percentage of 

control effectiveness is greater when 

initial NOX concentrations are greater. 

The reaction kinetics decrease as the 

concentration of reactants decreases. 

This is due to thermodynamic 

considerations that limit the reduction 

process at low NOX concentrations.79

The baseline NOX emissions of the 

Holcim Trident kiln, in pounds per ton 

of clinker produced (lb/ton clinker) are 

significantly higher than those at Ash 

Grove’s Midlothian kilns in Texas 

(described above in the Ash Grove 

analysis), indicating that SNCR on the 

Holcim kiln would be expected to 

achieve even greater control 

effectiveness when compared to SNCR 

on the Midlothian kilns. Information 

provided to EPA by Holcim on NOX

emissions at the Trident cement plant 

from 2008 through 2010 indicate that 

the mean 30-day rolling average 

emission rate was 9.7 lb/ton clinker,80

much higher than Midlothian’s preSNCR emission rate shown in the Ash 

Grove analysis above, which is between 

4.5 and 4.9 lb/ton clinker. 

A summary of the emissions 

projections for the NOX control options 

is provided in Table 39. 

TABLE 39—SUMMARY OF NOX BART ANALYSIS CONTROL TECHNOLOGIES FOR HOLCIM

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

LNB + SNCR ................................................................................................................... 58 645 467 

SNCR ............................................................................................................................... 50 556 556 

MKF ................................................................................................................................. 30 334 778 

LNB .................................................................................................................................. 15 167 945 

No Controls (Baseline) .................................................................................................... 0 0 1 1,112 

1 Holcim 2012 Response. (Holcim lists NOX emissions at 998 tons for 2009, 1,175 tons for 2010, and 1164 tons for 2011. The average is 

1,112 tons). 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

LNB 

We relied on cost estimates supplied 

by Holcim for capital costs and annual 

costs,81 but with two exceptions. We 

used a capital cost estimate of 

$4,385,307.82 Also in our analysis, we 

used a CRF consistent with 20 years for 

the useful life of the kiln. EPA has 

determined that the default 20-year 

amortization period is most appropriate 

to use as the remaining useful life of the 

facility. Without commitments for an 

early shut down, EPA cannot consider 

a shorter amortization period in our 

analysis. In order to calculate the 

annualized capital cost, we multiplied 

the capital cost by the CRF.83

We calculated the average cost 

effectiveness from the total annual cost 

and a 15% reduction from the baseline 

actual emissions of 1,112 tpy. We 

summarize the cost information for LNB 

in Tables 40, 41, and 42. 

TABLE 40—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR LNB ON HOLCIM

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 4,385,307 

Capital Recovery ................................................................................................................................................................................. 2 413,972 

1 Holcim Additional Response, June 2009 (revised by EPA to eliminate 1.5 multiplier for ‘‘retrofit installation’’). 

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84Holcim Additional Response, June 2009. 85Holcim Initial Response. 86NOX Control Technologies for the Cement 

Industry: Final Report, September 19, 2000, EPA– 

457/R–00–002, Table 6–10. 

87Holcim Initial Response, p. 4–23. 

88 Id., p. 4–25. 

89Holcim Additional Response, August 2009, 

Appendix C. 

90CRF is 0.0944 and is based on a 7% interest 

rate and 20-year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944 which is based on a 7% interest rate and 

20-year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 41—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR LNB ON HOLCIM

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1 413,972 

Direct Annual Operating Cost .............................................................................................................................................................. 2 300,658 

Total Annual Cost ............................................................................................................................................................................ 714,629 

1 Includes capital recovery. 

2 Holcim Additional Response, June 2009. 

The capital cost estimate of 

$4,385,307 includes the cost of 

converting from a direct to an indirect 

firing system to accommodate LNB, 

including installation of a baghouse, 

additional explosion prevention, 

pulverized coal storage, and dosing 

equipment.84

By comparison, our LNB cost analysis 

for Ash Grove Cement contains a capital 

cost estimate of $266,309 and annual 

cost estimate of $158,630. These figures 

are much lower than the estimate for 

Holcim because Ash Grove did not 

factor in the cost of any kiln 

modifications to convert from direct to 

indirect firing. 

TABLE 42—SUMMARY OF NOX BART COSTS FOR LNB ON HOLCIM

Total installed capital cost 

($) 

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

4,385,307 ......................................................................................................................... 714,629 167 4,279 

MKF 

We relied on cost estimates supplied 

by Holcim for annual costs.85 No 

separate calculation of capital cost was 

presented by Holcim. Total annual cost 

of MKF was provided from an EPA 

publication,86 for MKF conversion for a 

50 tons-per-hour long wet kiln, scaled 

up by Holcim from 1997 dollars to 2006 

dollars, using a 1.25607 Consumer Price 

Index (CPI) multiplier.87 We calculated 

the cost effectiveness, from the total 

annual cost and a 30% reduction from 

the baseline actual emissions of 1,112 

tpy. We present the costs for MKF in 

Table 43. 

TABLE 43—SUMMARY OF NOX BART COSTS FOR MKF ON HOLCIM

Total capital investment 

($) 

Total 

annual 

cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

Not calculated separately, but included in total annual cost ........................................... 473,738 334 1,418 

As explained in Holcim’s BART 

analysis, the use of tire-derived fuel for 

MKF cannot be ensured within the fiveyear timeline required in the BART 

program. Holcim is not permitted by the 

State of Montana to use tires as a fuel 

source in its kiln until the State issues 

a final air quality permit allowing such 

use and any legal appeals are 

concluded.88 Therefore, MKF is not 

considered further. 

SNCR 

We relied on cost estimates supplied 

by Holcim for capital costs and annual 

costs, with the exception of the CRF 

used.89 For our analysis, we used a CRF 

consistent with 20 years for the useful 

life of the kiln. EPA has determined that 

the default 20-year amortization period 

is most appropriate to use as the 

remaining useful life of the facility. 

Without commitments for an early shut 

down, EPA cannot consider a shorter 

amortization period in our analysis. In 

order to calculate the annualized capital 

cost, we multiplied the capital cost by 

the CRF.90 We calculated the average 

cost effectiveness from the total annual 

cost and a 50% reduction from the 

baseline actual emissions of 1,112 tpy, 

yielding a 588 tpy reduction. We 

summarize the cost information from 

our SNCR analysis in Tables 44, 45, and 

46. 

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24016 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

91Holcim Initial Response, p. 4–23. 92Holcim Initial Response, p. 5–13, 14. 

TABLE 44—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SNCR ON HOLCIM

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 11,312,800 

Capital Recovery ................................................................................................................................................................................. 2 123,928 

1 Holcim Additional Response, August, 2009. 

2 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF of 0.0944, which is based on a 7% interest rate and 

20-year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 45—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR SNCR ON HOLCIM

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1123,928 

Direct Annual Operating Cost .............................................................................................................................................................. 2 147,288 

Total Annual Cost ............................................................................................................................................................................ 271,216 

1 Includes capital recovery. 

2 Holcim Additional Response, August, 2009. 

TABLE 46—SUMMARY OF NOX BART COSTS FOR SNCR ON HOLCIM

Total capital investment 

($) 

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

1,312,800 ......................................................................................................................... 271,216 556 488 

LNB + SNCR 

We calculated the cost effectiveness of 

LNB + SNCR by dividing the sum of the 

annual cost of the two technologies 

described above by the 58% emissions 

reduction that would be achieved. We 

summarize the cost information from 

our LNB + SNCR analysis in Tables 47 

and 48. 

TABLE 47—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR LNB + SNCR ON HOLCIM

Description Cost ($) 

Total Annual Cost LNB ........................................................................................................................................................................ 714,629 

Total Annual Cost SNCR ..................................................................................................................................................................... 271,216 

Total Annual Cost LNB + SNCR ..................................................................................................................................................... 985,845 

TABLE 48—SUMMARY OF NOX BART COSTS FOR LNB + SNCR ON HOLCIM

Total annual cost 

($) 

Annual 

emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

985,845 .................................................................................................................................................................... 645 1,528 

Factor 2: Energy and Non-Air Quality 

Impacts 

LNBs are not expected to have any 

significant negative energy impacts 91

and are not expected to have any nonair quality environmental impacts. 

SNCR systems require electricity to 

operate the blowers and pumps. The 

generation of the electricity will most 

likely involve fuel combustion, which 

will cause emissions. While the 

required electricity will result in 

emissions, these emissions should be 

small compared to the reduction in NOX

that would be gained by operating an 

SNCR system.92 Transporting the 

chemical reagents for SNCR would use 

natural resources for fuel and would 

have associated air quality impacts. The 

chemical reagents would be stored on 

site and could result in spills to the 

environment while being transferred 

between storage vessels or if containers 

were to fail during storage or movement. 

The environmental impacts associated 

with proper transportation, storage, and/ 

or disposal should not be significant. 

Therefore, the non-air quality 

environmental impacts did not warrant 

eliminating LNB or SNCR. 

Factor 3: Any Existing Pollution Control 

Technology in Use at the Source 

Holcim currently uses proper kiln 

design and operation for NOX control. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

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commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Factor 5: Evaluate Visibility Impacts 

We performed modeling as described 

previously. 

We conducted modeling for Holcim as 

described in section V.C.3.a. Table 49 

presents the Visibility Impacts of the 

98th percentile of daily maxima for each 

Class I area from 2006 through 2008. 

Table 50 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class area from 2006 through 

2008. 

TABLE 49—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON HOLCIM

Class I area 

Baseline 

impact 

(delta 

deciview) 

Improvement 

from LNB 

(delta 

deciview) 

Improvement 

from SNCR 

(delta 

deciview) 

Improvement 

from LNB + 

SNCR 

(delta 

deciview) 

Gates of the Mountains WA ............................................................ 0.980 0.125 0.295 0.424 

Yellowstone NP ............................................................................... 0.411 0.051 0.120 0.171 

TABLE 50—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON HOLCIM

[Three-year total] 

Class I area Baseline days Using LNB Using SNCR Using 

LNB + SNCR 

Gates of the Mountains WA ............................................................ 46 39 26 19 

Yellowstone NP ............................................................................... 13 7 4 3 

Modeling was performed at 35% 

control effectiveness rather than 50% 

control effectiveness for SNCR and at 

50% control effectiveness rather than 

58% control effectiveness for LNB + 

SNCR. Therefore, visibility 

improvement from SNCR and LNB + 

SNCR would be greater than what is 

shown. 

Step 5: Select BART 

We propose to find that BART for 

NOX is LNB + SNCR with an emission 

limit of 5.5 lb/ton of clinker (30-day 

rolling average). Of the five BART 

factors, cost and visibility improvement 

were the critical ones in our analysis of 

controls for this source. 

In our BART analysis for NOX at 

Holcim, we considered LNB, SNCR, and 

LNB + SNCR. The comparison between 

our LNB, SNCR, and LNB + SNCR 

analysis is provided in Table 51. 

TABLE 51—SUMMARY OF NOX BART ANALYSIS COMPARISON OF CONTROL OPTIONS FOR HOLCIM

Control option Total capital 

investment 

Total annual 

cost 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts 1,2

Visibility 

improvement 

(delta 

deciviews) 

Fewer 

days > 0.5 

deciview 

LNB + SNCR ........................................... 6,271,009 985,845 1,528 8,029 0.424 27 

SNCR ....................................................... 1,312,800 271,216 488 3¥1,140 0.295 20 

LNB .......................................................... 4,958,209 714,629 4,279 4 0.125 7 

1The visibility benefit shown is for Gates of the Mountains WA. 

2The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I area that showed the greatest improvement, Gates of the Mountains, WA. Similarly, the 

number of days above 0.5 deciviews is the total for the modeled 3-year meteorological period at Gates of the Mountains WA. 3The incremental cost effectiveness from LNB to SNCR is a negative number because the numerator in dollars is negative (i.e., the total annual cost of SNCR is less than LNB) but the denominator in tons is positive (i.e., SNCR achieves more tons of emission reduction than LNB). 4 Incremental cost and impact is not applicable to the option that has the lowest emission control effectiveness. 

We have concluded that LNB + SNCR 

is a cost effective control technology 

and would provide substantial visibility 

benefits. LNB + SNCR has a cost 

effectiveness value of $1,528 per ton of 

NOX emissions reduced. This is well 

within the range of values we have 

considered reasonable for BART and 

that states have considered reasonable 

for BART. 

We have weighed costs against the 

anticipated visibility impacts for 

Holcim. Any of the control options 

would have a positive impact on 

visibility. As compared to LNB alone, 

LNB + SNCR would provide an 

additional visibility benefit of .299 

deciviews and 20 fewer days above 0.5 

deciviews at Gates of the Mountains 

WA. As compared to SNCR alone, LNB 

+ SNCR would provide an additional 

visibility benefit of 0.129 deciviews and 

seven fewer days above 0.5 deciviews at 

Gates of the Mountains WA. Overall 

improvement from LNB + SNCR is 0.424 

deciviews. We consider this impact to 

be beneficial, especially in light of the 

fact that this Class I area is not projected 

to meet the URP. Given the visibility 

improvement associated with LNB + 

SNCR and the reasonable average cost 

effectiveness for LNB + SNCR, we 

propose that the NOX BART emission 

limit for the kiln at Holcim should be 

based on what can be achieved with 

LNB + SNCR. 

As EPA has explained in earlier in 

this notice, adopting an output-based 

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24018 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

93Holcim 2012 Response. (Holcim lists the mean 

30-day rolling average NOX emission rate for 2008– 

2011 at 9.7 lb/ton clinker. The 99th percentile 30- 

day rolling average was 12.6 lb/ton clinker. 

Applying 58% reduction to the 99th percentile 

figure yields 5.29 lb/ton clinker.) 

94As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

95Formation and Techniques of Sulfur Oxide and 

Other Sulfur Compounds, p. 46. 

96Holcim 2008 Responses, p. 6. 

97Formation and Techniques of Sulfur Oxide and 

Other Sulfur Compounds, pp. 31, 44 and 48. 

98Holcim Initial Response, p. 4–11. 

99Holcim 2012 Response (Holcim listed the SO2

emissions at 53.5 tons in 2009, 64.1 tons in 2010, 

and 33.1 tons in 2011. The average was 50.2 tons). 

100Holcim 2008 Responses, p. 6. 

standard avoids rewarding a source for 

becoming less efficient. 

In proposing a BART emission limit 

of 5.5 lb/ton clinker, we considered the 

emission rate currently being achieved 

by Holcim in lb/ton clinker, then 

applied an emission reduction of 58%.93

This limit allows for a sufficient margin 

of compliance for a 30-day rolling 

average limit that would apply at all 

times, including startup, shutdown, and 

malfunction.94 We also are proposing 

monitoring, recordkeeping, and 

reporting requirements in regulatory 

text at the end of this proposal. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ We 

propose a compliance deadline of five 

(5) years from the date our final FIP 

becomes effective because of the 

equipment installation and potential 

kiln combustion modifications that will 

be required. 

SO2

Step 1: Identify All Available 

Technologies 

We identified that the following SO2

control technologies are available: wet 

scrubbing, semi-wet scrubbing which 

for this source is the same as a SDA, fuel 

switching (lower sulfur fuel), and hot 

meal injection. 

Wet scrubbing involves passing flue 

gas downstream from the main PMCD 

through a sprayed aqueous suspension 

of lime or limestone that is contained in 

a scrubbing device. The SO2 reacts with 

the scrubbing reagent to form calcium 

sulfate (CaSO4) sludge that is collected. 

The sludge usually is dewatered and 

disposed of at an offsite landfill. 

SDAs use lime or limestone to react 

with SO2. This technology involves 

injecting an aqueous lime or limestone 

suspension in fine droplets into the flue 

gas. The lime reacts with SO2 in the flue 

gas to create fine particles of calcium 

sulfite (CaSO3) or CaSO4. The moisture 

evaporates from the particles, and the 

particles are collected in the PMCD. 

Limestone absorbent scrubbers have 

been used for SO2 control on preheater/ 

calciner kilns, but they can be 

successfully used on long kilns by 

adding spray nozzles that are made of 

special materials to prevent nozzle 

clogging. A SDA can achieve a SO2

removal efficiency of 30% to 60%. 

Clogging may not be an issue with SDAs 

that use lime due to the small size of the 

lime particles (3–10 microns) which 

allows the particles to dissolve in water 

droplets quickly and react with the 

gaseous SO2. One manufacturer of these 

scrubber systems indicates an SO2

removal efficiency of greater than 90% 

for SDAs.95

Fuel switching is a control alternative. 

Holcim currently uses a mixture of 

about 60% low-sulfur coal and 40% 

petroleum coke as the primary fuels for 

the kiln. The sulfur content of the 

petroleum coke is approximately 5.3% 

and the sulfur content of the coal is 

approximately 0.8%.96 If sulfur in fuel 

input to the kiln were reduced by 

burning a different blend of coal and 

coke with lower sulfur contents, a 

reduction in SO2 emissions would be 

expected. We considered two different 

options for fuel switching. Option 1 

would use 75% coal with 0.8% sulfur 

and 25% coke with 5.3% sulfur. Option 

2 would use 100% coal, which has a 

lower sulfur content (0.8%) than coke. 

Hot meal injection is the hot-meal 

bypass in a PH/PC kiln system, where 

calcined hot meal produced in the kiln 

is, in part, discharged in front of the kiln 

entrance after the precalcining process, 

so that the hot meal can scrub some of 

the SO2 generated from the kiln feed. 

Achievable SO2 reduction has been 

estimated at between 0% and 30%.97

Step 2: Eliminate Technically Infeasible 

Options 

As explained above, hot meal is 

produced in a calcined/preheated kiln. 

Holcim does not have a PH/PC kiln 

design from which hot meal can be 

obtained. Therefore, hot meal injection 

was not considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

EPA has stated that a well designed 

and operated wet scrubber can 

consistently achieve at least 90% 

control (75 FR 54995 (September 9, 

2010)) and that 95% control efficiency 

is possible (73 FR 34080 (June 16, 

2008)). Holcim’s analysis used 95% 

control, which is the upper end of the 

range that is possible.98 We used 95% 

control effectiveness for our analysis of 

wet scrubbing. 

As cited above, according to one SDA 

manufacturer, 90% SO2 control 

effectiveness is the minimum of the 

range for a SDA with lime absorbent 

medium. Given the extremely low SO2

emissions from Holcim’s kiln (about 50 

tpy),99 we consider 90% control to be 

optimistic here; nevertheless, relying on 

information from Holcim’s July 6, 2007 

submittal, we used 90% control 

effectiveness for our analysis. 

For fuel substitution to 100% coal 

with 0.8% sulfur content, we relied on 

Holcim’s estimate of 62% control 

effectiveness. For fuel substitution to 

75% coal with 0.8% sulfur content and 

25% petroleum coke with 5.3% sulfur 

content, we relied on Holcim’s estimate 

of 32% control effectiveness.100 We also 

evaluated the visibility impact from fuel 

switching to lower sulfur coal for which 

we used a control effectiveness of 60%. 

TABLE 52—SUMMARY OF SO2 BART ANALYSIS CONTROL TECHNOLOGIES FOR HOLCIM

Control option Control effectiveness (%) 

Annual emissions reduction 

(tpy) 

Remaining annual emissions 

(tpy) 

Wet scrubbing .................................................................................................................. 95 47.7 2.5 

SDA .................................................................................................................................. 90 45.2 5.0 

Fuel Switching Option 2 (100% lower sulfur coal) .......................................................... 62 19.1 31.1 

Fuel Switching Option 1 (25% coke/75% coal) ............................................................... 32 34.1 16.1 

No Controls (Baseline) .................................................................................................... 0 0 50.2 

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101Holcim Additional Response, August 2009, 

Appendix B. 

102CRF is 0.0944 and is based on a 7% interest 

rate and 20 year equipment life. Office of 

Management and Budget, Circular A–4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/

circulars_a004_a-4/. 

103 Id. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Wet Scrubbing 

We present the costs for wet 

scrubbing in Table 53. We relied on cost 

estimates from Holcim,101 with the 

exception of the CRF. We used a CRF 

consistent with 20 years for the 

remaining useful life of the kiln. EPA 

has determined that the default 20-year 

amortization period is most appropriate 

to use as the remaining useful life of the 

facility. Without commitments for an 

early shut down, EPA cannot consider 

a shorter amortization period in our 

analysis. In order to calculate the 

annualized capital cost, we multiplied 

the capital cost by the CRF.102 Since 

Holcim presented the capital costs and 

annual costs in 2002 dollars, then scaled 

up the total annual cost to 2007 dollars 

using a 1.1582 CPI multiplier, we 

present the costs in the same manner 

here. We calculated the average cost 

effectiveness from the total annual cost 

and a 95% reduction in the baseline 

actual emissions of 50.2 tpy. We 

summarize the cost information for wet 

scrubbing in Tables 53, 54, and 55. 

TABLE 53—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR WET SCRUBBER ON HOLCIM

Description Cost ($) 

Total Capital Investment (2002 dollars) .............................................................................................................................................. 1 8,098,489 

Capital Recovery (2002 dollars) .......................................................................................................................................................... 2 764,497 

1 Holcim Additional Response, August 2009, Appendix B. 

2 Capital Recovery was determined by multiplying the CRF of 0.0944 which is based on a 7% interest rate and 20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory Analysis, http://

www.whitehouse.gov/omb/circulars_a004_a-4/. 

TABLE 54—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR WET SCRUBBER ON HOLCIM

Description Cost ($) 

Total Indirect Annual Cost (2002 dollars) ............................................................................................................................................ 1 764,297 

Total Annual Operating Cost (2002 dollars) ........................................................................................................................................ 2 3,453,408 

Total Annual Cost (2002 dollars) ......................................................................................................................................................... 4,217,905 

Total Annual Cost (2007 dollars) ......................................................................................................................................................... 4,885,177 

1 Includes capital recovery. 

2 Holcim Additional Response August 2009, Appendix B. 

TABLE 55—SUMMARY OF SO2 BART COSTS FOR WET SCRUBBER ON HOLCIM

Total capital investment ($) Total annual cost ($) 

Emissions 

reductions 

(tpy) 

Average 

cost 

effectiveness 

($/ton) 

8,098,489 (2002 dollars) .................................................. 4,885,177 (2007 dollars) .................................................. 47.7 102,414 

SDA 

We present the costs for SDA in Table 

56. We relied on cost estimates from 

Holcim,2 with the exception that we 

used a CRF consistent with 20 years for 

the useful life of the kiln. EPA has 

determined that the default 20-year 

amortization period is most appropriate 

to use as the remaining useful life of the 

facility. Without commitments for an 

early shut down, EPA cannot consider 

a shorter amortization period in our 

analysis. In order to calculate the 

annualized capital cost, we multiplied 

the capital cost by the CRF.103 We 

calculated the average cost effectiveness 

from the total annual cost and a 90% 

reduction in the baseline actual 

emissions of 50.2 tpy. We summarize 

the cost information for SDA in Tables 

56, 57, and 58. 

TABLE 56—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR SDA ON HOLCIM

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 1 22,597,000 

Capital Recovery ................................................................................................................................................................................. 2 2,133,156 

1 Holcim Initial Response, Appendix C. 

2 Capital Recovery was determined by multiplying the CRF of 0.0944 which is based on a 7% interest rate and 20 year equipment life. The justification for using the CRF of 0.0944 can be found in Office of Management and Budget, Circular A–4, Regulatory Analysis, http:// 

www.whitehouse.gov/omb/circulars_a004_a-4/. 

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24020 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

104Holcim 2008 Responses, p. 6. 

TABLE 57—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR SDA ON HOLCIM

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 1 2,133,156 

Total Annual Operating Cost ............................................................................................................................................................... 2 1,186,133 

Total Annual Cost ................................................................................................................................................................................ 3,319,289 

1 Includes capital recovery. 

2 Holcim Initial Response, Appendix C. 

TABLE 58—SUMMARY OF SO2 BART COSTS FOR SDA ON HOLCIM

Total capital investment ($) Total annual 

cost ($) 

Emissions 

reductions 

(tpy) 

Average 

cost 

effectiveness 

($/ton) 

22,597,000 ............................................................................................................................................... 3,319,289 45.2 73.435 

Fuel Switching 

We relied on Holcim’s costs for fuel 

switching.104 We calculated the average 

cost effectiveness from the total annual 

cost and a 32% reduction in the 

baseline actual emissions of 50.2 tpy for 

option 1, or a 62% reduction for option 

2. There is no capital cost for fuel 

switching because there is no 

equipment to buy or install. However, 

annual cost will increase due to 

increased fuel cost. We summarize the 

cost information for fuel switching in 

Tables 59 and 60. 

TABLE 59—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR FUEL SWITCHING FOR HOLCIM

Description Cost ($) 

Total Annual Cost Option 1 (25% coke/75% coal) ............................................................................................................................. 1 240,515 

Total Annual Cost Option 2 (100% lower sulfur coal) ......................................................................................................................... 1 659,651 

1 Holcim 2008 Response. 

TABLE 60—SUMMARY OF SO2 BART COSTS FOR FUEL SWITCHING ON HOLCIM

Control option Total annual 

cost ($) 

Emissions 

reductions 

(tpy) 

Average 

cost 

effectiveness 

($/ton) 

Fuel Switching Option 1 .......................................................................................................................... 240,515 1 19.1 12,592 

Fuel Switching Option 2 .......................................................................................................................... 659,651 2 34.1 19,344 

1 Reflects 32% reduction from 50.2 tpy baseline emissions. 

2 Reflects 62% reduction from 50.2 tpy baseline emissions. 

Factor 2: Energy and Non Air Quality 

Impacts 

Fuel Switching Does Not Have Energy 

or Non Air Quality Environmental 

Impacts 

Wet scrubbing and SDA use 

additional water and would generate a 

waste stream that would need to be 

transported and be disposed. 

Transporting the waste would use 

natural resources for fuel and would 

have associated air quality impacts. The 

disposal of the solid waste itself would 

be to a landfill and could possibly result 

in groundwater or surface water 

contamination if a landfill’s engineering 

controls were to fail. The environmental 

impacts associated with proper 

transportation and/or disposal should 

not be significant. 

Wet scrubbing and SDAs require 

additional electricity to service 

pretreatment and injection equipment, 

pumps, compressors, and control 

systems. The additional energy 

requirements that would be involved in 

installation and operation of the 

evaluated controls are not significant 

enough to warrant eliminating any of 

the options evaluated. The cost of the 

additional energy requirements has been 

included in our calculations. 

Factor 3: Any Existing Pollution Control 

Technology in Use at the Source 

The kiln currently uses low sulfur 

coal as a component of fuel mix and 

inherent scrubbing for SO2 control. The 

kiln inherently acts as an SO2 scrubber, 

since some of the sulfur that is oxidized 

to SO2 is absorbed by the alkali 

compounds in the raw material fed to 

the kiln. Holcim currently uses a 

mixture of petroleum coke with a sulfur 

content of 5.3% and coal with a sulfur 

content of 0.8%. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24021 

105As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

106Holcim 2012 Response (Holcim lists the mean 

30-day rolling average SO2 emission rate for 2008– 

2011 at 0.37 lb/ton clinker. The 99th percentile 30- 

day rolling average was 1.20 lb/ton clinker). 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Holcim as 

described in section V.C.3.a. Table 61 

presents the visibility impacts of the 

98th percentile of daily maxima for each 

Class I area from 2006 through 2008. 

Table 62 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class I area from 2006 through 

2008. 

TABLE 61—DELTA DECIVIEW IMPROVEMENT FOR SO2 CONTROLS ON HOLCIM

Class I area 

Baseline impact (delta 

deciview) 

Improvement 

from fuel 

switching option 1 (delta 

deciview) 

Improvement 

from fuel 

switching option 2 (delta 

deciview) 

Improvement 

from SDA 

(delta 

deciview) 

Improvement 

from wet 

scrubber (delta 

deciview) 

Gates of the Mountains WA ................................................ 0.980 0.015 0.024 0.044 0.046 

Yellowstone NP .................................................................... 0.411 0.011 0.007 0.020 0.021 

TABLE 62—DAYS GREATER THAN 0.5 DECIVIEW FOR SO2 CONTROLS ON HOLCIM

[Three-year total] 

Class I area Baseline 

(days) 

Using fuel 

switching 

option 1 

Using fuel 

switching 

option 2 

Using SDA Using wet 

scrubbing 

Gates of the Mountains WA .................................................................... 46 45 44 43 43 

Yellowstone NP ....................................................................................... 13 12 12 12 12 

Modeling for fuel switching option #2 

was performed assuming a 50% 

reduction rather than a 62% reduction. 

Step 5: Select BART 

We propose to find that BART for SO2

is no additional controls at Holcim with 

an emission limit of 1.3 lb/ton clinker. 

Of the five BART factors, visibility was 

the critical one in our analysis of 

controls for this source. The low 

visibility improvement did not justify 

requiring additional SO2 controls on 

this source. 

In our BART analysis for SO2 at 

Holcim, we considered wet scrubbing, 

SDA and fuel switching. The 

comparison between our wet scrubbing, 

SDA and fuel switching analysis is 

provided in Table 63. 

TABLE 63—SUMMARY OF EPA SO2 BART ANALYSIS COMPARISON OF WET SCRUBBING, SDA AND FUEL SWITCHING FOR

HOLCIM

Control option Total capital 

investment 

Total annual 

cost 

Average 

cost 

effectiveness 

($/ton) 

Incremental 

cost effectiveness 

($/ton) 

Visibility impacts 1,2

Visibility improvement 

(delta 

deciviews) 

Fewer days 

> 0.5 

deciview 

Wet Scrubbing ............................................................. 8,098,489 4,217,905 102,414 408,462 0.046 3 

SDA .............................................................................. 22,597,000 3,319,289 73,435 239,607 0.044 3 

Fuel Switching—Option 2 ............................................ 3 659,651 19,344 27,942 0.024 2 

Fuel Switching—Option 1 ............................................ 3 240,515 12,592 4 0.015 1 

1The visibility benefit shown is for Gates of the Mountains WA. 

2The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I area that showed the greatest improvement, Gates of the Mountains WA. Similarly, the 

number of days above 0.5 deciviews is the total for the modeled 3-year meteorological period at Gates of the Mountains WA. 3 Capital cost is not required for fuel switching. 

4 Incremental cost is not applicable to the option that has the lowest effectiveness. 

We have concluded that wet 

scrubbing, SDA and fuel switching are 

not cost effective control technologies 

and would not provide substantial 

visibility benefits. Given the minimal 

visibility improvements associated with 

SO2 controls, we propose that the SO2

BART emission limit for the kiln at 

Holcim should be based on current 

emissions, while allowing for a 

sufficient margin of compliance for a 30- 

day rolling average limit that would 

apply at all times, including startup, 

shutdown, and malfunction.105

As EPA has explained earlier in this 

notice, adopting an output-based 

standard avoids rewarding a source for 

becoming less efficient. Accordingly, we 

are proposing 1.3 lb/ton clinker as a 

BART emission limit for SO2 at Holcim. 

In proposing this limit, we considered 

the emission rate currently being 

achieved by Holcim in lb/ton clinker.106

We are also proposing monitoring, 

recordkeeping, and reporting 

requirements in regulatory text at the 

end of this proposal. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

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24022 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

107Air Quality Technical Analysis Report, 

Review of Submittals Supporting the Holcim (US) 

Inc. Tires Combustion Proposal, Prepared for 

MDEQ, Prepared by Lorenzen Engineering, Inc., p. 

13. 

108The following information has been submitted 

by CFAC: Best Available Retrofit Technology 

(BART) Analysis, Nov. 5, 2007; Letter to Callie 

Videtich from Harold W. Robbins, RE: CFAC BART 

Analysis—Response to EPA Comments, June 19, 

2008. 

109See Montana Air Quality Operating Permit 

(MAQOP) #OP2655–02 (Title V). 

110See Section V of MDEQ’s CFAC Compliance 

Monitoring Report, p. 10. 

111See Compliance Monitoring Report Section 

VII, p. 11. 

implementation plan revision.’’ Because 

we are not requiring additional controls 

to be installed, we propose that Holcim 

must comply with this emission limit 

within 180 days from the date our final 

FIP becomes effective. This will allow 

time for monitoring systems to be 

certified, if necessary. 

PM 

Holcim currently has an ESP that uses 

two fields in series for particulate 

control from the kiln. A description of 

an ESP can be found under the PM 

section of the BART analysis for Ash 

Grove. The efficiency of the ESP is 

greater than 99.9%.107

Based on our modeling described in 

section V.C.3.a, PM contribution to the 

baseline visibility impairment is low. 

Table 64 shows the maximum baseline 

visibility impact and percentage 

contribution to that impact from coarse 

PM and fine PM. 

TABLE 64—HOLCIM VISIBILITY IMPACT CONTRIBUTION FROM PM 

Maximum baseline visibility impact (deciview) % Contribution 

coarse PM 

% Contribution 

fine PM 

0.980 ................................................................................................................................................................ 5.79 12.61 

The PM contribution to the baseline 

visibility impact for Holcim is very 

small; therefore, any visibility 

improvement that could be achieved 

with improvements to the existing PM 

controls would be negligible. 

Holcim must meet the filterable PM 

emission standard of 0.77 lb/ton of 

clinker in accordance with their Final 

Title V Operating Permit #OP0982–02. 

This Title V requirement appears in 

Permit Condition G.3.; and was 

included in the permit pursuant to the 

regulatory requirements in Montana’s 

EPA approved SIP (ARM 17.8.749). 

Taking into consideration the above 

factors we propose basing the BART 

emission limit on what Holcim is 

currently meeting. The unit is exceeding 

a PM control efficiency of 99.9%, and 

therefore we are proposing that the 

current control technology and the 

emission limit of 0.77 lb/ton clinker for 

PM/PM10 as BART. We find that the 

BART emission limit can be achieved 

through the operation of the existing 

ESP. Thus, as described in our BART 

Guidelines, a full five-factor analysis for 

PM/PM10 is not needed for Holcim. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

iii. Columbia Falls Aluminum Company 

(CFAC) 

As described in section V.C., CFAC 

was determined to be subject to BART. 

As explained in that section, the 

document titled ‘‘Identification of BART 

Eligible Sources in the WRAP Region’’ 

dated April 4, 2005 provides more 

details on the specific emission units at 

each facility. We requested a five factor 

BART analysis for CFAC and the 

company submitted that analysis along 

with updated information.108 CFAC’s 

five factor BART analysis is contained 

in the docket for this action. 

CFAC holds a permit to operate five 

Vertical Stud Soderberg potlines at the 

Columbia Falls plant.109 Each potline 

has 120 individual cells that produce 

aluminum by the Hall-Heroult process. 

Subsequent to CFAC submitting its 

BART analysis, the CFAC plant closed 

at the end of October 2009.110 In a 

February 19, 2010 report on the CFAC 

facility, Montana’s Department of 

Environmental Quality (MDEQ) noted 

witnessing the plant’s closure during a 

January 14, 2010 inspection.111 The 

State’s report also noted that CFAC’s 

environmental manager was uncertain 

as to whether and when the plant would 

resume aluminum production. CFAC’s 

environmental manager stated that the 

only operating emission units were 

some natural gas heaters used in 

conjunction with water treatment at the 

facility. 

CFAC is currently not operating and 

it is unknown whether and when the 

Company will resume operations. As 

explained in the regulatory text for this 

proposal, if CFAC resumes operations, 

we will complete a BART determination 

after notification and revise the FIP as 

necessary in accordance with regional 

haze requirements, including the BART 

provisions in 40 CFR 51.308(e). CFAC 

will be required to install any controls 

that are required as soon as practicable, 

but in no case later than five years 

following date of the final action of this 

FIP. 

iv. Colstrip 

As described in section V.C., Colstrip 

Units 1 and 2 were determined to be 

subject to BART. As explained in 

section V.C., the document titled 

‘‘Identification of BART Eligible Sources 

in the WRAP Region’’ dated April 4, 

2005 provides more details on the 

specific emission units at each facility. 

PPL Montana’s (PPL) Colstrip Power 

Plant (Colstrip), located in Colstrip, 

Montana, consists of a total of four 

electric utility steam generating units. 

Of the four units, only Units 1 and 2 are 

subject to BART. We previously 

provided in Section V.C. our reasoning 

for proposing that these two units are 

BART-eligible and why they are subject 

to BART. Units 1 and 2 boilers have a 

nominal gross capacity of 333 MW each. 

The boilers began commercial operation 

in 1975 (Unit 1) and 1976 (Unit 2) and 

are tangentially fired pulverized coal 

boilers that burn Powder River Basin 

(PRB) sub-bituminous coal as their 

exclusive fuel. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24023 

112Also, the BART Guidelines establish 

presumptive NOX limits for coal-fired Electric 

Generating Units (EGUs) located at greater than 750 

MW power plants that are operating without postcombustion controls. For the tangential-fired boilers 

burning sub-bituminous coal at Colstrip, that limit 

is 0.15 lb/MMBtu. 70 FR 39172 (July 6, 2005), Table 

1. The guidelines provide that the five factor 

analysis may result in a limit that is different than 

the presumptive limit. 

113Baseline emissions were determined by 

averaging the annual emissions from 2008 through 

2010 as reported to the CAMD database available 

at http://camddataandmaps.epa.gov/gdm/index.

cfm?fuseaction=emissions. 

114 Institute of Clean Air Companies (ICAC) White 

Paper, Selective Catalytic Reduction Controls of 

NOX Emissions from Fossil Fuel-Fired Electric 

Power Plants, May 2009, pp. 7–8. 

115Control Technologies to Reduce Conventional 

and Hazardous Air Pollutants from Coal-Fired 

Power Plants Northeast States for Coordinated Air 

Use Management (NESCAUM), March 31, 2011, p. 

16. 

116 ICAC White Paper, Selective Non-Catalytic 

Reduction for Controlling NOX Emissions, February 

2008, pp. 6–7. 

117Low NOX Firing Systems and PRB Fuel; 

Achieving as Low as 0.12 LB NOX/MMBtu, 

Jennings, P., ICAC Forum, Feb. 2002. 

118 June 2008 PPL Addendum, p. 5–1. 

119White Paper, SNCR for Controlling NOX

Emissions, Institute of Clean of Clean Air 

Companies, pp. 4 and 9, February 2008. 

Our analysis follows EPA’s BART 

Guidelines. For Colstrip Units 1 and 2, 

the BART Guidelines are mandatory 

because the combined capacity for all 

four units at Colstrip is greater than 750 

MW.112

We requested a five factor BART 

analysis for Colstrip Units 1 and 2 from 

PPL and the Company submitted that 

analysis in August 2007 along with 

updated information in June 2008 and 

September 2011. PPL’s five factor BART 

analysis information is contained in the 

docket for this action and we have taken 

it into consideration in our proposed 

action. 

(a) Colstrip Unit 1 

NOX

The Colstrip Unit 1 boiler is of 

tangential-fired design with low-NOX

burners and close-coupled overfire air 

(CCOFA). Originally, the unit operated 

with a NOX emission limit of 0.7 lb/ 

MMBtu. In 1997, EPA approved an early 

election plan under the acid rain 

program (ARP) that included a 0.45 lb/ 

MMBtu annual NOX limit. The early 

reduction limit expired in 2007 and the 

new annual limit of 0.40 lb/MMBtu 

under the ARP became effective in 2008. 

Normally, the unit operates with an 

actual annual average NOX emission 

rate in the range of 0.30 to 0.35 lb/ 

MMBtu, accomplished with low NOX

burners and CCOFA.113

Step 1: Identify All Available 

Technologies 

We identified that the following NOX

control technologies are available: 

separated overfire air (SOFA), advanced 

separated overfire air (ASOFA), rotating 

opposed fire air (ROFA), rich reagent 

injection (RRI), SNCR, and SCR. 

SOFA technology is similar to CCOFA 

but the air injection point for SOFA is 

separated some distance above the main 

burners and can result in improved NOX

removal efficiencies. SOFA in 

combination with LNB technology 

provides additional NOX control by 

injecting air into the lower temperature 

combustion zone where NOX is less 

likely to form. This allows complete 

combustion of the fuel while reducing 

both thermal and chemical NOX

formation. 

ASOFA technology is similar to 

SOFA, but the amount of air staged is 

in the range of 20 to 30%, and, in some 

cases, can result in even further 

improved NOX removal efficiencies 

compared to SOFA. 

ROFA is a low NOX system that is 

somewhat similar to the SOFA. ROFA 

uses more ports and a significantly 

bigger fan to accomplish similar results 

of getting air into the upper portion of 

the boiler. ROFA uses a rotating 

opposed fire air process, while the 

SOFA system uses both horizontal (yaw) 

and vertical nozzle tip controls. 

RRI is similar to SNCR and achieves 

similar results. 

In SNCR systems, a reagent such as 

NH3 or urea is injected into the flue gas 

at a suitable temperature zone, typically 

in the range of 1,600 to 2,000 °F and at 

an appropriate ratio of reagent to NOX. 

SCR uses either NH3 or urea in the 

presence of a metal based catalyst to 

selectively reduce NOX emissions. 

Step 2: Eliminate Technically Infeasible 

Options 

Based on our review, all the 

technologies identified in Step 1 appear 

to be technically feasible for Colstrip 

Unit 1. In particular, both SCR and 

SNCR have been widely employed to 

control NOX emissions from coal-fired 

power plants.114,115,116

However, in the BART Guidelines, 

EPA states that it may be appropriate to 

eliminate from further consideration 

technologies that provide similar 

control levels at higher cost. The 

guidelines say that, ‘‘a possible outcome 

of the BART procedures discussed in 

these guidelines is the evaluation of 

multiple control technology alternatives 

which result in essentially equivalent 

emissions. It is not our intent to 

encourage evaluation of unnecessarily 

large numbers of control alternatives for 

every emissions unit. For example, if 

two or more control techniques result in 

control levels that are essentially 

identical, considering the uncertainties 

of emissions factors and other 

parameters pertinent to estimating 

performance, you may evaluate only the 

less costly of these options.’’ 70 FR 

39165 (July 6, 2005). As explained 

below, we have eliminated ASOFA, 

ROFA, and RRI from further 

consideration for this reason. SOFA is 

the least costly of these options. 

Since ASOFA would likely not 

achieve greater emissions reductions 

compared to SOFA it is not considered 

further. 

Since ROFA would achieve very 

similar emissions reductions compared 

to the SOFA system, ROFA is not 

considered further. 

Since RRI would not achieve greater 

emissions reductions compared to 

SNCR, RRI is not considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

At tangentially fired boilers firing PRB 

coal, SOFA in combination with CCOFA 

and LNB, can typically achieve 

emission rates below 0.15 lb/MMBtu on 

an annual basis.117 However, due to 

certain issues unique to Colstrip Unit 1, 

a rate of 0.20 lb/MMBtu is more 

realistic. Specifically, these issues 

include: (1) that the furnace is sized 

smaller than others and therefore runs 

hotter than similar units, and (2) that 

the PRB coal used, classified as a 

borderline sub-bituminous B coal, is 

less reactive (produces more NOX) than 

typical PRB coals.118 The 0.20 lb/ 

MMBtu rate represents a 34.9% 

reduction from the current baseline 

(2008 through 2010) rate of 0.308 lb/ 

MMbtu. 

The post-combustion control 

technologies, SNCR and SCR, have been 

evaluated in combination with 

combustion controls. That is, the inlet 

concentration to the post-combustion 

controls is assumed to be 0.20 lb/ 

MMBtu. This allows the equipment and 

operating and maintenance costs of the 

post-combustion controls to be 

minimized based on the lower inlet 

NOX concentration. Typically, SNCR 

reduces NOX an additional 20 to 30% 

above LNB/combustion controls without 

excessive NH3 slip.119 Assuming that a 

minimum 25% additional emission 

reduction is achievable with SNCR, 

SOFA combined with SNCR can achieve 

an overall control efficiency of 51.1%. 

SCR can achieve performance emission 

rates as low as 0.04 to 0.07 lb/MMBtu 

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24024 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

120 Information available at: http://www.netl.doe.

gov/technologies/coalpower/ewr/pubs/NOx%20

control%20Lani%20AWMA%200905.pdf. 

121EPA’s CCM Sixth Edition, January 2002, EPA 

452/B–02–001. 

122 Documentation for EPA Base Case v.4.10 

Using the Integrated Planning Model, August 2010, 

EPA #430R10010. 

123Section 1, Chapter 2, p. 2–21. 

124Office of Management and Budget, Circular A– 

4, Regulatory Analysis, http://www.whitehouse.gov/ 

omb/circulars_a004_a-4/. 

125Chemical Engineering Magazine, p. 56, August 

2011. (http://www.che.com). 

126Addendum to PPL Montana’s Colstrip BART 

Report Prepared for PPL Montana, LLC; Prepared by 

TRC, (‘‘Colstrip Addendum’’), June 2008, Table 5.1– 

1. 

127 IPM, Chapter 5, Appendix 5–2B. 

on an annual basis.120 Assuming that an 

annual emission rate of 0.05 lb/MMBtu 

is achievable with SCR, SOFA 

combined with SCR can achieve an 

overall control efficiency of 83.8%. A 

summary of emissions projections for 

the control options is provided in Table 

65. 

TABLE 65—SUMMARY OF NOX BART ANALYSIS CONTROL TECHNOLOGIES FOR COLSTRIP UNIT 1 

Control option 

Control 

effectiveness 

(%) 

Annual 

emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

SOFA+SCR ...................................................................................... 83.5 0.050 425 678 

SOFA+SNCR ................................................................................... 51.1 0.150 2,097 2,006 

SOFA ............................................................................................... 34.9 0.200 1,432 2,671 

No Controls (Baseline) 1 .................................................................. ............................ 0.308 ............................ 4,103 

1Baseline emissions were determined by averaging the annual emissions from 2008 to 2010 as reported to the CAMD database available at 

http://camddataandmaps.epa.gov/gdm/. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

We relied on a number of resources to 

assess the cost of compliance for the 

control technologies under 

consideration. In accordance with the 

BART Guidelines (70 FR 39166 (July 6, 

2005)), and in order to maintain and 

improve consistency, in all cases we 

sought to align our cost methodologies 

with the EPA’s Control Cost Manual 

(CCM).121 However, to ensure that our 

methods also reflect the most recent cost 

levels seen in the marketplace, we also 

relied on control costs developed for the 

Integrated Planning Model (IPM) 

version 4.10.122 These IPM control costs 

are based on databases of actual control 

project costs and account for project 

specifics such as coal type, boiler type, 

and reduction efficiency. The IPM 

control costs reflect the recent increase 

in costs in the five years proceeding 

2009 that is largely attributed to 

international competition. Finally, our 

costs were also informed by cost 

analyses submitted by the sources, 

including in some cases vendor data. 

Annualization of capital investments 

was achieved using the CRF as 

described in the CCM.123 The CRF was 

computed using an economic lifetime of 

20 years and an annual interest rate of 

7%.124 Unless otherwise noted, all costs 

presented in this proposal for the PPL 

BART units have been adjusted to 2010 

dollars using the Chemical Engineering 

Plant Cost Index (CEPCI).125 EPA’s 

detailed control costs for Colstrip can be 

found in the docket. 

SOFA 

We relied on estimates submitted by 

PPL in 2008 for capital costs and direct 

annual costs for SOFA.126 The Capital 

Cost is listed in Table 66. We then used 

the CEPCI to adjust capital costs to 2010 

dollars. Annual costs were determined 

by summing the indirect annual cost 

and the direct annual cost (see Table 

67). 

TABLE 66—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Capital Investment SOFA ........................................................................................................................................................... 4,507,528 

TABLE 67—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR SOFA ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 425,511 

Total Direct Annual Cost ..................................................................................................................................................................... 664,884 

Total Annual Cost ............................................................................................................................................................................ 1,090,395 

TABLE 68—SUMMARY OF NOX BART COSTS FOR SOFA ON COLSTRIP UNIT 1 

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions reductions 

(tpy) 

Average cost effectiveness 

($/ton) 

4.508 1.090 1,432 761 

SOFA+SNCR We relied on control 

costs developed for the IPM for direct 

capital costs for SNCR.127 We then used 

methods provided by the CCM for the 

remainder of the SOFA+SNCR analysis. 

Specifically, we used the methods in the 

CCM to calculate total capital 

investment, annual costs associated 

with operation and maintenance, to 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24025 

128Cost and Quality of Fuels for Electric Utility 

Plants 1999 Tables, Energy Information 

Administration, DOE/EIA–0191(99), June 2000, 

Table 24. 

129 IPM, Chapter 5, p. 5–9. 

130 ICAC, p. 8. 

131NOX Control Update to PPL Montana’s 

Colstrip Generating Station BART Report Prepared 

for PPL Montana, LLC, by TRC, September 2011, p. 

4–1. 

132 IPM, Chapter 5, Appendix 5–2A. 

133Email communication with Fuel Tech, Inc., 

March 2, 2012. 

134Cichanowicz 2010, p. 6–7. 

annualize the total capital investment 

using the CRF, and to sum the total 

annual costs. 

We used a retrofit factor of ‘‘1’’ 

reflecting an SNCR retrofit of typical 

difficulty in the IPM control costs. As 

Colstrip Unit 1 burns sub-bituminous 

PRB coal having a low sulfur content of 

0.91 lb/MMBtu (equating to a SO2 rate 

of 1.8 lb/MMBtu),128 it was not 

necessary to make allowances in the 

cost calculations to account for 

equipment modifications or additional 

maintenance associated with fouling 

due to the formation of ammonium 

bisulfate. These are only concerns when 

the SO2 rate is above 3 lb/MMBtu.129

Moreover, ammonium bisulfate 

formation can be minimized by 

preventing excessive NH3 slip. 

Optimization of the SNCR system can 

commonly limit NH3 slip to levels less 

than the 5 parts per million (ppm) 

upstream of the pre-air heater.130 EPA’s 

detailed cost calculations for 

SOFA+SNCR can be found in the 

docket. 

We used a urea reagent cost estimate 

of $450 per ton taken from PPL’s 

September 2011 submittal.131 To 

estimate the average cost effectiveness 

(dollars per ton of emissions reductions) 

we divided the total annual cost by the 

estimated NOX emissions reductions. 

We summarize the costs from our 

SOFA+SNCR cost analysis in Tables 69, 

70, and 71. 

TABLE 69—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA+SNCR ON COLSTRIP UNIT 1 

Description Cost ($) 

Capital Investment SOFA .................................................................................................................................................................... 4,507,528 

Capital Investment SNCR .................................................................................................................................................................... 8,873,145 

Total Capital Investment SOFA+SNCR ....................................................................................................................................... 13,380,673 

TABLE 70—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SNCR ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Annual Cost SOFA ..................................................................................................................................................................... 1,090,395 

Total Annual Cost SNCR ..................................................................................................................................................................... 2,188,569 

Total Annual Cost SOFA+SNCR ................................................................................................................................................. 3,278,964 

TABLE 71—SUMMARY OF NOX BART COSTS FOR SOFA+SNCR ON COLSTRIP UNIT 1 

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions reductions 

(tpy) 

Average cost effectiveness 

($/ton) 

13.381 3.279 2,097 1,564 

SOFA+SCR 

We relied on control costs developed 

for the IPM for direct capital costs for 

SCR.132 We then used methods in the 

CCM for the remainder of the 

SOFA+SCR analysis. Specifically, we 

used the methods in the CCM to 

calculate total capital investment, 

annual costs associated with operation 

and maintenance, to annualize the total 

capital investment using the CRF, and to 

sum the total annual costs. 

We used a retrofit factor of ‘‘1’’ in the 

IPM control costs, which reflects an SCR 

retrofit of typical difficulty. We used an 

aqueous ammonia (29%) cost of $240 

per ton,133 and a catalyst cost of $6,000 

per cubic meter.134 To estimate the 

average cost effectiveness (dollars per 

ton of emissions reductions) we divided 

the total annual cost by the estimated 

NOX emissions reductions. We 

summarize the costs from our 

SOFA+SCR cost analysis in Tables 72, 

73, and 74. 

TABLE 72—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA+SCR ON COLSTRIP UNIT 1 

Description Cost ($) 

Capital Investment SOFA .................................................................................................................................................................... 4,507,528 

Capital Investment SCR ...................................................................................................................................................................... 78,264,060 

Total Capital Investment SOFA+SCR .......................................................................................................................................... 82,771,589 

TABLE 73—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SCR ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Annual Cost SOFA ..................................................................................................................................................................... 1,090,395 

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24026 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

135CCM, Section 4.2, Chapter 1, p. 1–21. 136 Id., Section 4.2, Chapter 2, p. 2–28. 

TABLE 73—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SCR ON COLSTRIP UNIT 1— 

Continued 

Description Cost ($) 

Total Annual Cost SCR ....................................................................................................................................................................... 9,852,395 

Total Annual Cost SOFA+SCR .................................................................................................................................................... 10,942,766 

TABLE 74—SUMMARY OF NOX BART COSTS FOR SOFA+SCR ON COLSTRIP UNIT 1 

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

82.772 10.942 3,425 3,195 

Factor 2: Energy Impacts 

SNCR reduces the thermal efficiency 

of a boiler as the reduction reaction uses 

thermal energy from the boiler.135

Therefore, additional coal must be 

burned to make up for the decreases in 

power generation. Using CCM 

calculations we determined the 

additional coal needed for Unit 1 

equates to 77,600 MMBtu/yr. For an 

SCR, the new ductwork and the 

reactor’s catalyst layers decrease the flue 

gas pressure. As a result, additional fan 

power is necessary to maintain the flue 

gas flow rate through the ductwork. SCR 

systems require additional electric 

power to meet fan requirements 

equivalent to approximately 0.3% of the 

plant’s electric output.136 Both SCR and 

SNCR require some minimal additional 

electricity to service pretreatment and 

injection equipment, pumps, 

compressors, and control systems. The 

additional energy requirements that 

would be involved in installation and 

operation of the evaluated controls are 

not significant enough to warrant 

eliminating any of the options 

evaluated. Note that cost of the 

additional energy requirements has been 

included in our calculations. 

Factor 3: Non-Air Quality 

Environmental Impacts 

SNCR and SCR will increase the 

quantity of ash that will need to be 

disposed. Transporting this waste 

stream for disposal would use natural 

resources for fuel and would have 

associated air quality impacts. The 

disposal of the solid waste itself would 

be to a landfill and could possibly result 

in groundwater or surface water 

contamination if a landfill’s engineering 

controls were to fail. Transporting the 

chemical reagents and catalysts would 

use natural resources for fuel and would 

have associated air quality impacts. The 

chemical reagents would be stored on 

site and could result in spills to the 

environment while being transferred 

between storage vessels or if containers 

were to fail during storage or movement. 

The environmental impacts associated 

with proper transportation, storage, and/ 

or disposal should not be significant. 

Therefore, the non-air quality 

environmental impacts do not warrant 

eliminating either SNCR or SCR. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Thus, this factor does not impact our 

BART determination because the 

annualized cost was calculated over a 

20 year period in accordance with the 

BART Guidelines. 

Factor 5: Evaluate visibility impacts 

We conducted modeling for Colstrip 

Unit 1 as described in section V.C.3.a. 

Table 75 presents the visibility impacts 

of the 98th percentile of daily maxima 

for each Class I area from 2006 through 

2008. Table 76 presents the number of 

days with impacts greater than 0.5 

deciviews for each Class I area from 

2006 through 2008. 

TABLE 75—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON COLSTRIP UNIT 1 

Class I area 

Baseline 

impact 

(delta 

deciview) 

Improvement 

from 

SOFA+SCR 

(delta 

deciview) 

Improvement 

from 

SOFA+SNCR 

(delta 

deciview) 

Improvement 

from 

SOFA 

(delta 

deciview) 

North Absaroka WA ......................................................................................... 0.414 0.181 0.089 0.047 

Theodore Roosevelt NP .................................................................................. 0.922 0.404 0.264 0.182 

UL Bend WA .................................................................................................... 0.895 0.378 0.249 0.164 

Washakie WA .................................................................................................. 0.410 0.121 0.077 0.052 

Yellowstone NP ............................................................................................... 0.275 0.081 0.059 0.034 

TABLE 76—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON COLSTRIP UNIT 1 

[Three year total] 

Class I area Baseline 

(days) 

Using 

SOFA+SCR 

Using 

SOFA+SNCR 

Using 

SOFA 

North Absaroka WA ......................................................................................... 7 5 5 7 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24027 

137As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

138BART Assessment Colstrip Generating Station, 

prepared for PPL Montana, LLC, by TRC (‘‘Colstrip 

Initial Response’’), August 2007, p. ES–3. 

TABLE 76—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON COLSTRIP UNIT 1—Continued 

[Three year total] 

Class I area Baseline 

(days) 

Using 

SOFA+SCR 

Using 

SOFA+SNCR 

Using 

SOFA 

Theodore Roosevelt NP .................................................................................. 52 17 27 33 

UL Bend WA .................................................................................................... 68 29 47 52 

Washakie WA .................................................................................................. 12 5 9 10 

Yellowstone NP ............................................................................................... 4 2 2 2 

Step 5: Select BART 

We propose to find that BART for 

NOX is SOFA+SNCR at Colstrip Unit 1 

with an emission limit of 0.15 lb/ 

MMBtu (30-day rolling average). Of the 

five BART factors, cost and visibility 

improvement were the critical ones in 

our analysis of controls for this source. 

In our BART analysis for NOX at 

Colstrip Unit 1, we considered SOFA, 

SOFA+SNCR, and SOFA+SCR. The 

comparison between our SOFA, 

SOFA+SNCR, and SOFA+SCR analysis 

is provided in Table 77. 

TABLE 77—SUMMARY OF NOX BART ANALYSIS COMPARISON OF CONTROL OPTIONS FOR COLSTRIP UNIT 1 

Control option 

Total capital 

investment 

(MM$) 

Total annual 

cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental cost 

effectiveness 

($/ton) 

Visibility impacts 1

Visibility 

improvement 

(delta deciviews) 

Fewer days 

>0.5 

deciview 

SOFA+SCR ............ 82.772 10.942 3,195 5,770 0.404 TRNP ...........

0.378 UL Bend .......

35 TRNP. 

39 UL Bend. 

SOFA+SNCR ......... 13.380 3.279 1,564 3,291 0.264 TRNP ...........

0.249 UL Bend .......

25 TRNP. 

21 UL Bend. 

SOFA ...................... 4.508 1.090 761 2 0.182 TRNP ...........

0.164 UL Bend .......

19 TRNP. 

16 UL Bend. 

TRNP—Theodore Roosevelt National Park. 

UL Bend—UL Bend Wilderness Area. 

1The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I areas in the table. 2 Incremental cost is not applicable to the option that has the lowest effectiveness. 

We have concluded that SOFA, 

SOFA+SNCR, and SOFA+SCR are all 

cost effective control technologies. 

SOFA has a cost effectiveness value of 

$761 per ton of NOX emissions reduced. 

SOFA+SNCR is more expensive than 

SOFA, with a cost effectiveness value of 

$1,564 per ton of NOX emissions 

reduced. SOFA+SCR is more expensive 

than SOFA or SOFA+SNCR, having a 

cost effectiveness value of $3,195 per 

ton of NOX emissions reduced. This is 

well within the range of values we have 

considered reasonable for BART and 

that states have considered reasonable 

for BART. 

We have weighed costs against the 

anticipated visibility impacts for 

Colstrip Unit 1. Any of the control 

options would have a positive impact 

on visibility; however, the cost of 

SOFA+SCR ($3,195/ton) is not justified 

by the visibility improvement of 0.404 

deciviews at TRNP and 0.378 deciviews 

at UL Bend. The lower cost of 

SOFA+SNCR ($1,564/ton) is justified 

when the visibility improvement is 

considered. SOFA+SNCR would have a 

visibility improvement of 0.264 

deciviews at Theodore Roosevelt NP 

and 0.249 deciviews at UL Bend WA 

and it would result in 25 fewer days 

above 0.5 deciviews at Theodore 

Roosevelt-NP and 21 fewer days above 

0.5 deciviews at UL Bend WA. In 

addition, application of SOFA+SNCR at 

both Colstrip Units 1 and 2 would have 

a combined modeled visibility 

improvement of 0.501 deciviews at 

Theodore Roosevelt NP and 0.451 

deciviews at UL Bend WA. We consider 

these improvements to be substantial, 

especially in light of the fact that 

Theodore Roosevelt NP and UL Bend 

WA are not projected to meet the URP. 

We propose that the NOX BART 

emission limit for Colstrip Unit 1 

should be based on what can be 

achieved with SOFA+SNCR. 

The proposed BART emission limit of 

0.15 lb/MMBtu allows for a sufficient 

margin of compliance for a 30-day 

rolling average limit that would apply at 

all times, including startup, shutdown, 

and malfunction.137 We are also 

proposing monitoring, recordkeeping, 

and reporting requirements as described 

in our proposed regulatory text for 40 

CFR 52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ We 

propose a compliance deadline of five 

(5) years from the date our final FIP 

becomes effective because of the 

equipment installation and potential 

combustion modifications that will be 

required. 

SO2

Colstrip Unit 1 is already controlled 

by wet venturi scrubbers for 

simultaneous particulate and SO2

control. The venturi scrubbers utilize 

the alkalinity of the fly ash to achieve 

an estimated SO2 removal efficiency of 

75%.138 Based on emissions data from 

the EPA Clean Air Markets Division 

(CAMD), for the baseline period 2008 

through 2010, the average SO2 emission 

rate was 0.418 lb/MMBtu and the 

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24028 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

139Clean Air Markets—Data and Maps: http://

camddataandmaps.epa.gov/gdm/. 

140EPA Air Pollution Control Technology Fact 

Sheet: Venturi Scrubber, EPA–452/F–03–017. 

141Colstrip Addendum, p. 4–1. 

142Clean Air Markets—Data and Maps: http://

camddataandmaps.epa.gov/gdm/. 

143Colstrip Initial Response, Table A4–6(c). 

144Colstrip Addendum, Table 4.1–4. 

average SO2 emissions were 5,548 

tpy.139

Step 1: Identify All Available 

Technologies 

The Colstrip Unit 1 venturi scrubber 

currently achieves greater than 50% 

removal of SO2. For units with 

preexisting post-combustion SO2

controls achieving removal efficiencies 

of at least 50%, the BART Guidelines 

state that upgrades to the system 

designed to improve the system’s 

overall removal efficiency should be 

considered. 70 FR 39171 (July 6, 2005). 

For wet scrubbers, the BART Guidelines 

recommend that the following upgrades 

be considered: (a) Elimination of bypass 

reheat; (b) installation of liquid 

distribution rings; (c) installation of 

perforated trays; (d) use of organic acid 

additives; (e) improve or upgrade 

scrubber auxiliary equipment; and (f) 

redesign spray header or nozzle 

configuration. 

In addition to the upgrades 

recommended by the BART Guidelines, 

two other upgrades are available: lime 

injection and lime injection with an 

additional scrubber vessel. Some of the 

upgrades recommended by the BART 

Guidelines are inherent in lime 

injection; consequently, they are 

available technologies only within that 

context. Specifically, these include 

options (b), (e), and (f) as listed above. 

A venturi scrubber works by 

increasing the contact between the 

pollutant-bearing gas stream and the 

scrubbing liquid. This is achieved in the 

throat of the venturi scrubber where the 

gas stream is accelerated, thereby 

atomizing the scrubber liquid and 

promoting greater gas-liquid contact.140

Absorption of SO2 is further enhanced 

by use of alkaline reagents. Currently, 

the venturi scrubbers for Colstrip Unit 1 

rely on the alkalinity of the coal ash to 

reduce SO2. Adding lime to the water 

stream for these scrubbers will increase 

SO2 removal. However, as the amount of 

lime is increased, scaling of piping and 

equipment is also expected to increase 

and this scaling will have to be 

removed. The scrubber vessel would not 

be operational during the descaling 

process, resulting in downtime. Greater 

removal efficiencies could be achieved 

if an additional scrubber vessel is added 

to the system to reduce downtime for 

descaling. Therefore, addition of a spare 

scrubber vessel is an upgrade that can 

improve the overall SO2 removal 

efficiency of the scrubber system by 

increasing the system’s reliability and 

decreasing its downtime. The additional 

scrubber vessel is an example of 

equipment redundancy that will 

enhance the overall system 

performance. 

Step 2: Eliminate Technically Infeasible 

Options 

Elimination of bypass reheat is not 

feasible option because Colstrip Unit 1 

is designed so that there is no bypass of 

flue gas. Installation of perforated trays 

is not a feasible option because the 

existing scrubber design already 

includes this technology in the form of 

wash trays. Finally, the use of organic 

acid additives is not a feasible option 

because the reactivity of the lime would 

neutralize the acids, making the 

additives ineffective. 

Lime injection or lime injection with 

an additional scrubber vessel are 

technically feasible control options 

because lime injection is currently used 

to control SO2 emissions at Colstrip 

Units 3 and 4. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

An annual emission rate of 0.015 lb/ 

MMBtu can be achieved with lime 

injection without an additional scrubber 

vessel. PPL stated that this is the lowest 

emission rate that could be achieved 

without adding an additional scrubber 

vessel.141 An annual emission rate of 

0.08 to 0.09 lb/MMBtu can be achieved 

with lime injection with an additional 

scrubber vessel. This is the emission 

rate that is being achieved at Colstrip 

Units 3 and 4 according to emissions 

data from CAMD.142 The control 

effectiveness of each of the control 

options was calculated using the 

controlled emission rates that were 

provided by PPL. 

A summary of control efficiencies, 

emission rates, and resulting emissions 

and emission reductions, is provided in 

Table 78. EPA’s detailed emissions 

calculations can be found in the docket. 

TABLE 78—SUMMARY OF BART ANALYSIS CONTROL TECHNOLOGIES FOR SO2 FOR COLSTRIP UNIT 1 

Control option 

Control 

effectiveness 

(%) 1

Annual 

emission rate 

(lb/MMBtu) 2

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

Lime Injection with Additional Scrubber Vessel .............................. 80.9 0.080 4,486 1,062 

Lime Injection ................................................................................... 64.1 0.150 3,557 1,991 

Existing Controls (Baseline) 3 .......................................................... ............................ 0.418 ............................ 5,548 

1 Control efficiency is provided relative to the emission rate with current controls. 

2Emission rates are provided on an annual basis. 

3Baseline emissions for 2008 through 2010 from Clean Air Markets—Data and Maps: http://camddataandmaps.epa.gov/gdm/. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

We relied on capital costs and direct 

annual costs provided by PPL when 

determining the cost of compliance for 

both lime injection and lime injection 

with an additional scrubber 

vessel.143,144 All costs presented here 

for the Colstrip Unit 1 SO2 control 

options are in year 2007 dollars. EPA’s 

cost calculations can be found in the 

docket. 

Lime Injection 

We summarize our cost analysis for 

lime injection in Tables 79, 80, and 81. 

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145Colstrip Initial Response, p. 4–16. 

TABLE 79—SUMMARY OF SO2 CAPITAL COST ANALYSIS FOR LIME INJECTION ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 3,000,000 

TABLE 80—SUMMARY OF SO2 BART ANNUAL COST ANALYSIS FOR LIME INJECTION ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Direct Annual Cost ..................................................................................................................................................................... 1,600,000 

Indirect Annual Cost ............................................................................................................................................................................ 283,200 

Total Annual Cost ......................................................................................................................................................................... 1,883,200 

TABLE 81—SUMMARY OF SO2 BART COSTS FOR LIME INJECTION ON COLSTRIP UNIT 1 

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions reductions 

(tpy) 

Average cost effectiveness 

($/ton) 

3.000 1.883 3,557 $529 

Lime Injection With an Additional 

Scrubber Vessel 

We summarize our cost analysis for 

lime injection with an additional 

scrubber vessel cost analysis in Tables 

82, 83, and 84. 

TABLE 82—SUMMARY OF SO2 CAPITAL COST ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER VESSEL ON

COLSTRIP UNIT 1 

Description Cost ($) 

Total Capital Investment, Lime Injection ............................................................................................................................................. 3,000,000 

Capital Investment, Scrubber Vessel .................................................................................................................................................. 25,000,000 

Total Capital Investment ............................................................................................................................................................... 28,000,000 

TABLE 83—SUMMARY OF SO2 BART ANNUAL COST ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER

VESSEL ON COLSTRIP UNIT 1 

Description Cost ($) 

Total Direct Annual Cost ..................................................................................................................................................................... 1,450,000 

Indirect Annual Cost ............................................................................................................................................................................ 2,643,200 

Total Annual Cost ......................................................................................................................................................................... 4,093,200 

TABLE 84—SUMMARY OF SO2 BART COSTS ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER VESSEL ON

COLSTRIP UNIT 1 

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions reductions 

(tpy) 

Average cost effectiveness 

($/ton) 

$28.000 $4.100 4,486 912 

Factor 2: Energy Impacts 

According to PPL, the pressure drop 

of the venturi scrubbers is maintained in 

the range of 17 to 20 inches of water 

column. The injection of lime will be 

accompanied by little to no increase in 

pressure drop, but it will require a small 

increase in pump power consumption. 

This is included in the cost analysis in 

the additional operations and 

maintenance expenses of $125,000 per 

year.145 The additional energy 

requirements are not significant enough 

to warrant eliminating either lime 

injection or lime injection with an 

additional scrubber vessel. 

Factor 3: Non-Air Quality 

Environmental Impacts 

Adding lime to the scrubbers will 

require more frequent descaling 

operations that would increase the 

quantity of solid waste from descaling 

operations. Transporting this waste 

stream for disposal would use natural 

resources for fuel and would have 

associated air quality impacts. The 

disposal of the solid waste itself would 

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24030 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

be to a landfill and could possibly result 

in groundwater or surface water 

contamination if a landfill’s engineering 

controls were to fail. EPA’s analysis 

indicates that the environmental 

impacts associated with the proper 

transport and land disposal of the solid 

waste should not be significant. 

Therefore, the non-air quality 

environmental impacts do not warrant 

eliminating either lime injection 

addition or lime injection addition with 

an additional scrubber vessel. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Because the remaining useful life of the 

source is equal to that assumed for 

amortization of control option capital 

investments, this factor does not impact 

our BART determination. 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Colstrip 

Unit 1 as described in section V.C.3.a. 

Table 85 presents the visibility impacts 

of the 98th percentile of daily maxima 

for each Class I area from 2006 through 

2008. Table 86 presents the number of 

days with impacts greater than 0.5 

deciviews for each Class area from 2006 

through 2008. 

TABLE 85—DELTA DECIVIEW IMPROVEMENT FOR SO2 CONTROLS ON COLSTRIP UNIT 1 

Class I area Baseline impact 

(delta deciview) 

Improvement 

from lime 

injection + additional scrubber 

vessel 

(delta deciview) 

Improvement 

from lime 

injection 

(delta deciview) 

North Absaroka WA ......................................................................................................... 0.414 0.164 0.146 

Theodore Roosevelt NP .................................................................................................. 0.922 0.350 0.284 

UL Bend WA .................................................................................................................... 0.895 0.261 0.234 

Washakie WA .................................................................................................................. 0.410 0.154 0.145 

Yellowstone NP ............................................................................................................... 0.275 0.115 0.090 

TABLE 86—DAYS GREATER THAN 0.5 DECIVIEW FOR SO2 CONTROLS ON COLSTRIP UNIT 1 

[Three-year total] 

Class I area Baseline 

(days) 

Using lime injection + additional 

scrubber vessel 

Using lime 

injection 

North Absaroka WA ......................................................................................................... 7 7 7

Theodore Roosevelt NP .................................................................................................. 52 29 33

UL Bend WA .................................................................................................................... 68 31 41 

Washakie WA .................................................................................................................. 12 6 7 

Yellowstone NP ............................................................................................................... 4 2 2 

Step 5: Select BART 

We propose to find that BART for SO2

is lime injection with an additional 

scrubber vessel at Colstrip Unit 1 with 

an emission limit of 0.08 lb/MMBtu (30- 

day rolling average). Of the five BART 

factors, cost and visibility improvement 

were the critical ones in our analysis of 

controls for this source. 

In our BART analysis for SO2 at 

Colstrip Unit 1, we considered lime 

injection and lime injection with an 

additional scrubber vessel. The 

comparison between our lime injection 

and lime injection with an additional 

scrubber vessel analysis is provided in 

Table 87. 

TABLE 87—SUMMARY OF EPA SO2 BART ANALYSIS COMPARISON OF LIME INJECTION AND LIME INJECTION WITH AN

ADDITIONAL SCRUBBER VESSEL FOR COLSTRIP UNIT 1 

Control option 

Total capital 

investment 

(MM$) 

Total annual 

cost (MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost effectiveness ($/ton) 

Visibility impacts 1

Visibility improvement (delta 

deciviews) 

Fewer days 

>0.5 deciview 

Lime Injection with Additional Scrubber Vessel.28.000 4.100 912 1,957 0.350 TRNP ......

0.261 UL Bend

23 TRNP. 

37 UL Bend. 

Lime Injection ..................................... 3.000 1.883 529 2 0.283 TRNP ......

0.234 UL Bend

19 TRNP. 

27 UL Bend. 

TRNP—Theodore Roosevelt National Park. 

UL Bend—UL Bend Wilderness Area. 

1The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I areas in the table. 2 Incremental cost is not applicable to the option that has the lowest effectiveness. 

We have concluded that lime 

injection and lime injection with an 

additional scrubber vessel are both cost 

effective control technologies. Lime 

injection has a cost effectiveness value 

of $539 per ton of SO2 emissions 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24031 

146As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

147EPA Air Pollution Control Online Course, 

description at: http://www.epa.gov/apti/course422/ 

ce6a3.html. 

148Colstrip Addendum, p. 6–1 

149Colstrip Initial Response, p. 4–8. 

150Baseline emissions were determined by 

averaging the annual emissions from 2008 to 2010 

as reported to the CAMD database available at 

http://camddataandmaps.epa.gov/gdm/ 

index.cfm?fuseaction=emissions. 

reduced. Lime injection with an 

additional scrubber vessel is more 

expensive than lime injection, with a 

cost effectiveness value of $912 per ton 

of SO2 emissions reduced. Both of these 

costs are well within the range of values 

we have considered reasonable for 

BART and that states have considered 

reasonable for BART. 

We have weighed costs against the 

anticipated visibility impacts for 

Colstrip Unit 1. Either of the control 

options would have a positive impact 

on visibility. We have concluded that 

the cost of lime injection with an 

additional scrubber vessel ($912/ton) is 

justified by the visibility improvement 

of 0.350 deciviews at Theodore 

Roosevelt NP and 0.261 deciviews at UL 

Bend WA and it would result in 23 

fewer days above 0.5 deciviews at 

Theodore Roosevelt NP and 37 fewer 

days above 0.5 deciviews at UL Bend 

WA. In addition, the application of lime 

injection with an additional scrubber 

vessel on both Colstrip Units 1 and 2 

would result in a combined modeled 

visibility improvement of 0.592 

deciviews at Theodore Roosevelt NP 

and 0.384 deciviews at UL Bend WA. 

We consider these improvements to be 

substantial, especially in light of the fact 

that Theodore Roosevelt NP and UL 

Bend WA are not projected to meet the 

URP. We propose that the SO2 BART 

emission limit for Colstrip Unit 1 

should be based on what can be 

achieved with lime injection with an 

additional scrubber vessel. 

The proposed BART emission limit of 

0.08 lb/MMBtu allows for a sufficient 

margin of compliance for a 30-day 

rolling average limit that would apply at 

all times, including startup, shutdown, 

and malfunction.146 We are also 

proposing monitoring, recordkeeping, 

and reporting requirements as described 

in our proposed regulatory text for 40 

CFR 52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ We 

propose a compliance deadline of five 

(5) years from the date our final FIP 

becomes effective because of the 

equipment installation that will be 

required. 

PM 

Colstrip Unit 1 currently has wet 

venturi scrubbers designed to control 

PM emissions. Venturi scrubbers use a 

liquid stream to remove solid particles. 

In the venturi scrubber, gas laden with 

PM passes through a short tube with 

flared ends and a constricted middle. 

This constriction causes the gas stream 

to speed up when the pressure is 

increased. A water spray is directed into 

the gas stream either prior to or at the 

constriction in the tube. The difference 

in velocity and pressure resulting from 

the constriction causes the particles and 

water to mix and combine. The reduced 

velocity at the expanded section of the 

throat allows the droplets of water 

containing the particles to drop out of 

the gas stream. Venturi scrubbers are 

effective in removing small particles, 

with removal efficiencies of up to 

99%.147 The venturi scrubbers at Unit 1 

are designed to have at least 98% 

control efficiency and have shown 

control efficiencies approximating 

99.5%.148 The present filterable 

particulate emission rate is 0.047 lb/ 

MMBtu.149

Based on our modeling described in 

V.C.3.a., PM contribution to the baseline 

visibility impairment is low. Table 88 

shows the maximum baseline visibility 

impact and percentage contribution to 

that impact from coarse PM and fine 

PM. 

TABLE 88—COLSTRIP UNIT 1 VISIBILITY IMPACT CONTRIBUTION FROM PM 

Maximum baseline visibility impact (deciview) % Contribution coarse PM % Contribution fine PM 

0.922 0.73 3.01 

The PM contribution to the baseline 

visibility impact for Colstrip Unit 1 is 

very small; therefore, any visibility 

improvement that could be achieved 

with improvements to the existing PM 

controls would be negligible. 

Colstrip Unit 1 must meet the 

filterable PM emission standard of 0.1 

lb/MMBtu in accordance with their 

Final Title V Operating Permit 

#OP0513–06. This requirement appears 

in Permit Condition B.2.; and was 

included in the permit pursuant to ARM 

17.8.340 and 40 CFR part 60, subpart D. 

Taking into consideration the above 

factors we propose basing the BART 

emission limit on what Colstrip Unit 1 

is currently meeting. The units are 

exceeding a PM control efficiency of 

99%, and therefore we are proposing 

that the current control technology and 

the emission limit of 0.1lb/MMBtu for 

PM/PM10 as BART. We find that the 

BART emission limit can be achieved 

through the operation of the existing 

venturi scrubbers. Thus, as described in 

our BART Guidelines, a full five-factor 

analysis for PM/PM10 is not needed for 

Colstrip Unit 1. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

(b) Colstrip Unit 2 

NOX

The Colstrip Unit 2 boiler is of 

tangential-fired design with LNB and 

OFA. Originally, the unit operated with 

a NOX emission limit of 0.7 lb/MMBtu. 

In 1997, EPA approved an early election 

plan under the ARP that included a 0.45 

lb/MMBtu annual NOX limit. The early 

reduction limit expired in 2007 and the 

new annual limit under the ARP (0.40 

lb/MMBtu) became effective in 2008. 

Normally, the unit operates with an 

actual annual average NOX emission 

rate in the range of 0.30 to 0.35 lb/ 

MMBtu, accomplished with the low 

NOX burners and CCOFA.150

Step 1: Identify All Available 

Technologies 

We identified that the same NOX

control technologies for Colstrip Unit 2 

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151 Low NOX Firing Systems and PRB Fuel; 

Achieving as Low as 0.12 LB NOX/MMBtu, Jennings, 

P., ICAC Forum, Feb. 2002. 

152Colstrip Addendum, p. 5–1. 

153White Paper, SNCR for Controlling NOX

Emissions, Institute of Clean Air Companies, pp. 4 

and 9, February 2008. 

154http://www.netl.doe.gov/technologies/

coalpower/ewr/pubs/NOx%20control%20Lani%20

AWMA%200905.pdf. 

155Colstrip Addendum, Table 5.1–1. 

as for Colstrip Unit 1; see Step 1 above 

under Colstrip Unit 1 for a list of 

proposed controls. 

Step 2: Eliminate Technically Infeasible 

Options 

Our analysis for Colstrip Unit 1 

explains our reasoning for eliminating 

some of the technologies that were 

identified in Step 1. We have retained 

SOFA, SOFA+SNCR, and SOFA+SCR 

for evaluation. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

At tangentially fired boilers firing PRB 

coal, SOFA in combination with CCOFA 

and LNB, can typically achieve 

emission rates below 0.15 lb/MMBtu on 

an annual basis.151 However, due to 

certain issues unique to Colstrip Unit 2, 

a rate of 0.20 lb/MMBtu is more 

realistic. Specifically, these issues 

include: (1) That the furnace was sized 

too small and therefore runs hotter than 

similar units, and (2) that the PRB coal, 

classified as a borderline subbituminous B coal, is less reactive 

(produces more NOX) than typical PRB 

coals.152 The 0.20 lb/MMBtu rate 

represents a 35.3% reduction from the 

current baseline (2008 through 2010) 

rate of 0.309 lb/MMbtu. 

The post-combustion control 

technologies, SNCR and SCR, have been 

evaluated in combination with 

combustion controls. That is, the inlet 

concentration to the post-combustion 

controls is assumed to be 0.20 lb/ 

MMBtu. This allows the equipment and 

operating and maintenance costs of the 

post-combustion controls to be 

minimized based on the lower inlet 

NOX concentration. Typically, SNCR 

reduces NOX an additional 20 to 30% 

above LNB/combustion controls without 

excessive NH3 slip.153 Assuming that a 

minimum 25% additional emission 

reduction is achievable with SNCR, 

SOFA combined with SNCR can achieve 

an overall control efficiency of 51.4%. 

SCR can achieve performance emission 

rates as low as 0.04–0.07 lb/MMBtu on 

an annual basis.154 Assuming that an 

annual emission rate of 0.05 lb/MMBtu 

is achievable with SCR, SOFA 

combined with SCR can achieve an 

overall control efficiency of 83.8%. A 

summary of emissions projections for 

the control options is provided in Table 

89. 

TABLE 89—SUMMARY OF NOX BART ANALYSIS CONTROL TECHNOLOGIES FOR COLSTRIP UNIT 2 

Control option Control 

effectiveness (%) 

Annual emission 

rate (lb/MMBtu) 

Emissions 

reduction (tpy) 

Remaining 

emissions (tpy) 

SOFA+SCR .................................................................................... 83 .8 0.050 3,376 652 

SOFA+SNCR ................................................................................. 51 .4 0.150 2,072 1,956 

SOFA ............................................................................................. 35 .3 0.200 1,420 2,608 

No Controls (Baseline) 1 ................................................................ 0 0.309 ............................ 4,028 

1Baseline emissions were determined by averaging the annual emissions from 2008 to 2010 as reported to the CAMD database available at 

http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions. A summary of this information can be found in our docket. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Refer to the Colstrip Unit 1 section 

above for general information on how 

we evaluated the cost of compliance for 

NOX controls. 

SOFA 

We relied on estimates submitted by 

PPL in 2008 for capital costs and direct 

annual costs for SOFA.155 We then used 

the CEPCI to adjust capital costs to 2010 

dollars (see Table 90). Annual costs 

were determined by summing the 

indirect annual cost and the direct 

annual cost (see Table 91). 

TABLE 90—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Capital Investment SOFA ........................................................................................................................................................... 4,507,528 

TABLE 91—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR SOFA ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 425,511 

Total Direct Annual Cost ..................................................................................................................................................................... 664,884 

Total Annual Cost ......................................................................................................................................................................... 1,090,395 

TABLE 92—SUMMARY OF NOX BART COSTS FOR SOFA ON COLSTRIP UNIT 2 

Total capital investment (MM$) Total annual cost (MM$) Emissions 

reductions (tpy) 

Average cost 

effectiveness ($/ton) 

4.508 1.090 1,420 768 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24033 

156 IPM, Chapter 5, Appendix 5–2B. 

157Cost and Quality of Fuels for Electric Utility 

Plants 1999 Tables, Energy Information 

Administration, DOE/EIA–0191(99), June 2000, 

Table 24. 

158NOX Control Update to PPL Montana’s 

Colstrip Generating Station BART Report Prepared 

for PPL Montana, LLC, by TRC, September 2011, 

p. 4–1. 

159 IPM, Chapter 5, Appendix 5–2A. 

160Email communication with Fuel Tech, Inc., 

March 2, 2012. 

161Cichanowicz 2010, p. 6–7. 

SOFA+SNCR 

We relied on control costs developed 

for the IPM for direct capital costs for 

SNCR.156 We then used methods 

provided by the CCM for the remainder 

of the SOFA+SNCR analysis. 

Specifically, we used the methods in the 

CCM to calculate total capital 

investment, annual costs associated 

with operation and maintenance, to 

annualize the total capital investment 

using the CRF, and to sum the total 

annual costs. 

We used a retrofit factor of ‘‘1’’ 

reflecting an SNCR retrofit of typical 

difficulty in the IPM control costs. 

Colstrip Unit 2 burns sub-bituminous 

PRB coal having a low sulfur content of 

0.91 lb/MMBtu (equating to a SO2 rate 

of 1.8 lb/MMBtu).157 As explained in 

our analysis for Colstrip Unit 1, it was 

not necessary to make allowances in the 

cost calculations to account for 

equipment modifications or additional 

maintenance associated with fouling 

due to the formation of ammonium 

bisulfate. EPA’s detailed cost 

calculations for SOFA+SNCR can be 

found in the docket. 

We used a urea reagent cost estimate 

of $450 per ton taken from PPL’s 

September 2011 submittal.158 To 

estimate the average cost effectiveness 

(dollars per ton of emissions reductions) 

we divided the total annual cost by the 

estimated NOX emissions reductions. 

We summarize the costs from our 

SOFA+SNCR cost analysis in Tables 93, 

94, and 95. 

TABLE 93—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA+SNCR ON COLSTRIP UNIT 2 

Description Cost ($) 

Capital Investment SOFA .................................................................................................................................................................... 4,507,528 

Capital Investment SNCR .................................................................................................................................................................... 8,873,145 

Total Capital Investment SOFA+SNCR ....................................................................................................................................... 13,380,673 

TABLE 94—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SNCR ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Annual Cost SOFA ..................................................................................................................................................................... 1,090,395 

Total Annual Cost SNCR ..................................................................................................................................................................... 2,165,732 

Total Annual Cost SOFA+SNCR ................................................................................................................................................. 3,256,127 

TABLE 95—SUMMARY OF NOX BART COSTS FOR SOFA+SNCR ON COLSTRIP UNIT 2 

Total capital investment (MM$) Total annual cost (MM$) Emissions 

reductions (tpy) 

Average cost 

effectiveness ($/ton) 

13.381 3.256 2,072 1,571 

SOFA+SCR 

We relied on control costs developed 

for the IPM for direct capital costs for 

SCR.159 We then used methods in the 

CCM for the remainder of the 

SOFA+SCR analysis. Specifically, we 

used the methods in the CCM to 

calculate total capital investment, 

annual costs associated with operation 

and maintenance, to annualize the total 

capital investment using the CRF, and to 

sum the total annual costs. 

We used a retrofit factor of ‘‘1’’ in the 

IPM control costs, which reflects an SCR 

retrofit of typical difficulty. We used an 

aqueous ammonia (29%) cost of $240 

per ton,160 and a catalyst cost of $6,000 

per cubic meter.161 To estimate the 

average cost effectiveness (dollars per 

ton of emissions reductions) we divided 

the total annual cost by the estimated 

NOX emissions reductions. We 

summarize the costs from our 

SOFA+SCR cost analysis in Tables 96, 

97, and 98. 

TABLE 96—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA+SCR ON COLSTRIP UNIT 2 

Description Cost ($) 

Capital Investment SOFA .................................................................................................................................................................... 4,507,528 

Capital Investment SCR ...................................................................................................................................................................... 78,263,720 

Total capital Investment SOFA + SCR ........................................................................................................................................ 82,771,248 

TABLE 97—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SCR ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Annual Cost SOFA ..................................................................................................................................................................... 1,090,395 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24034 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

162CCM, Section 4.2, Chapter 1, p. 1–21. 163CCM, Section 4.2, Chapter 2, p. 2–28. 

TABLE 97—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SCR ON COLSTRIP UNIT 2— 

Continued 

Description Cost ($) 

Total Annual Cost SCR ....................................................................................................................................................................... 9,830,104 

Total Annual Cost SOFA+SCR .................................................................................................................................................... 10,920,499 

TABLE 98—SUMMARY OF NOX BART COSTS FOR SOFA+SCR ON COLSTRIP UNIT 2 

Total capital investment (MM$) Total annual cost (MM$) Emissions 

reductions (tons/yr) 

Average cost 

effectiveness ($/ton) 

82.771 10.920 3,376 3,235 

Factor 2: Energy Impacts 

An SNCR process reduces the thermal 

efficiency of a boiler as the reduction 

reaction uses thermal energy from the 

boiler.162 Therefore, additional coal 

must be burned to make up for the 

decreases in power generation. Using 

CCM calculations we determined the 

additional coal needed for Unit 2 

equates to 75,800 MMBtu/yr. For an 

SCR, the new ductwork and the 

reactor’s catalyst layers decrease the flue 

gas pressure. As a result, additional fan 

power is necessary to maintain the flue 

gas flow rate through the ductwork. SCR 

systems require additional electric 

power to meet fan requirements 

equivalent to approximately 0.3% of the 

plant’s electric output.163 Both SCR and 

SNCR require some minimal additional 

electricity to service pretreatment and 

injection equipment, pumps, 

compressors, and control systems. The 

additional energy requirements that 

would be involved in installation and 

operation of the evaluated controls are 

not significant enough to warrant 

eliminating any of the options 

evaluated. Note that cost of the 

additional energy requirements has been 

included in our calculations. 

Factor 3: Non-Air Quality 

Environmental Impacts 

The non-air quality environmental 

impacts for Colstrip Unit 2 are the same 

as for Colstrip Unit 1, see previous 

discussion for Colstrip Unit 1. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Thus, this factor does not impact our 

BART determination because the 

annualized cost was calculated over a 

20 year period in accordance with the 

BART Guidelines. 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Colstrip 

Unit 2 as described in section V.C.3.a. 

Table 99 presents the visibility impacts 

of the 98th percentile of daily maxima 

for each Class I area from 2006 through 

2008. Table 100 presents the number of 

days with impacts greater than 0.5 

deciviews for each Class area from 2006 

through 2008. 

TABLE 99—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON COLSTRIP UNIT 2 

Class I area Baseline impact 

(delta deciview) 

Improvement 

from SOFA+SCR 

(delta deciview) 

Improvement 

from 

SOFA+SNCR 

(delta deciview) 

Improvement 

from SOFA 

(delta deciview) 

North Absaroka WA ......................................................................... 0.402 0.185 0.083 0.055 

Theodore Roosevelt NP .................................................................. 0.895 0.423 0.269 0.190 

UL Bend WA .................................................................................... 0.889 0.406 0.269 0.185 

Washakie WA .................................................................................. 0.392 0.143 0.089 0.063 

Yellowstone NP ............................................................................... 0.289 0.091 0.071 0.063 

TABLE 100—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON COLSTRIP UNIT 2 

[Three year total] 

Class I Area Baseline (days) Using 

SOFA+SCR 

Using 

SOFA+SNCR Using SOFA 

North Absaroka WA ......................................................................... 8 5 5 7 

Theodore Roosevelt NP .................................................................. 54 14 25 35 

UL Bend WA .................................................................................... 66 17 41 46 

Washakie WA .................................................................................. 12 5 8 11 

Yellowstone NP ............................................................................... 4 2 2 2 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24035 

164As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

165Colstrip Initial Response, p. ES–3. 

166Clean Air Markets—Data and Maps: http:// 

camddataandmaps.epa.gov/gdm. 

Step 5: Select BART 

We propose to find that BART for 

NOX is SOFA+SNCR at Colstrip Unit 2 

with an emission limit of 0.15 lb/ 

MMBtu (30-day rolling average). Of the 

five BART factors, cost and visibility 

improvement were the critical ones in 

our analysis of controls for this source. 

In our BART analysis for NOX at 

Colstrip Unit 2, we considered SOFA, 

SOFA+SNCR, and SOFA+SCR. The 

comparison between our SOFA, 

SOFA+SNCR, and SOFA+SCR analysis 

is provided in Table 101. 

TABLE 101—SUMMARY OF NOX BART ANALYSIS COMPARISON OF CONTROL OPTIONS FOR COLSTRIP UNIT 2 

Control option 

Total capital 

investment 

(MM$) 

Total annual cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental cost 

effectiveness 

($/ton) 

Visibility Impacts 1

Visibility 

Improvement 

(delta deciviews) 

Fewer days > 

0.5 deciview 

SOFA+SCR ........................ 82.771 10.920 3,235 5,877 0.423 TRNP ......

0.406 UL Bend

40 TRNP 

49 UL Bend 

SOFA+SNCR ..................... 13.380 3.256 1,571 3,322 0.269 TRNP ......

0.269 UL Bend

29 TRNP 

25 UL Bend 

SOFA ................................. 4.508 1.090 768 2 0.190 TRNP ......

0.185 UL Bend

19 TRNP 

20 UL Bend 

TRNP—Theodore Roosevelt National Park. 

UL Bend—UL Bend Wilderness Area. 

1The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I areas in the table. 2 Incremental cost is not applicable to the option that has the lowest effectiveness. 

We have concluded that SOFA, 

SOFA+SNCR, and SOFA+SCR are all 

cost effective control technologies. 

SOFA has a cost effectiveness value of 

$768 per ton of NOX emissions reduced. 

SOFA+SNCR is more expensive than 

SOFA, with a cost effectiveness value of 

$1,571 per ton of NOX emissions 

reduced. SOFA+SCR is more expensive 

than SOFA or SOFA+SNCR, having a 

cost effectiveness value of $3,235 per 

ton of NOX emissions reduced. This is 

well within the range of values we have 

considered reasonable for BART and 

that states have considered reasonable 

for BART. 

We have weighed costs against the 

anticipated visibility impacts for 

Colstrip Unit 2. Any of the control 

options would have a positive impact 

on visibility; however, the cost of 

SOFA+SCR ($3,322) is not justified by 

the visibility improvement of 0.423 

deciviews at TRNP and 0.404 deciviews 

at UL Bend. The lower cost of 

SOFA+SNCR ($1,571/ton) is justified 

when the visibility improvement is 

considered. SOFA+SNCR would have a 

visibility improvement of 0.269 

deciviews at Theodore Roosevelt NP 

and 0.269 deciviews at UL Bend WA 

and it would result in 29 fewer days 

above 0.5 deciviews at Theodore 

Roosevelt NP and 25 fewer days above 

0.5 deciviews at UL Bend WA. In 

addition, application of SOFA+SNCR at 

both Colstrip Units 1 and 2 would have 

a combined modeled visibility 

improvement of 0.501 deciviews at 

Theodore Roosevelt NP and 0.451 

deciviews at UL Bend WA. We consider 

these improvements to be substantial, 

especially in light of the fact that 

Theodore Roosevelt NP and UL Bend 

WA are not projected to meet the URP. 

We propose that the NOX BART 

emission limit for Colstrip Unit 2 

should be based on what can be 

achieved with SOFA + SNCR. 

The proposed BART emission limit of 

0.15 lb/MMBtu allows for a sufficient 

margin of compliance for a 30-day 

rolling average limit that would apply at 

all times, including startup, shutdown, 

and malfunction.164 We are also 

proposing monitoring, recordkeeping, 

and reporting requirements as described 

in our proposed regulatory text for 40 

CFR 52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ We 

propose a compliance deadline of five 

(5) years from the date our final FIP 

becomes effective because of the 

equipment installation and potential 

combustion modifications that will be 

required. 

SO2

Colstrip Unit 2 is already controlled 

by wet venturi scrubbers, which are 

identical to Colstrip Unit 1 scrubbers, 

for simultaneous particulate and SO2

control. The venturi scrubbers utilize 

the alkalinity of the fly ash to achieve 

an estimated SO2 removal efficiency of 

75%.165 Based on emissions data from 

CAMD, for the baseline period 2008 

through 2010, the average SO2 emission 

rate was 0.418 lb/MMBtu and the 

average SO2 emissions were 5,548 

tpy.166

Step 1: Identify All Available 

Technologies 

The Colstrip Unit 2 venturi scrubber 

currently achieves greater than 50% 

removal of SO2. The available 

technologies for Colstrip Unit 2 are the 

same as those for Colstrip Unit 1; see 

Step 1 analysis for Colstrip Unit 1. 

Step 2: Eliminate Technically Infeasible 

Options 

Elimination of bypass reheat is not a 

feasible option because Colstrip Unit 2 

is designed so that there is no bypass of 

flue gas. Installation of perforated trays 

is not a feasible option because the 

existing scrubber design already 

includes this technology in the form of 

wash trays. Finally, the use of organic 

acid additives is not a feasible option 

because the reactivity of the lime would 

neutralize the acids, making the 

additives ineffective. 

Lime injection or lime injection with 

an additional scrubber vessel are 

technically feasible control options 

because lime injection is currently used 

to control SO2 emissions at Colstrip 

Units 3 and 4. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24036 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

167Colstrip Addendum, p. 4–1. 168Clean Air Markets—Data and Maps: http:// 

camddataandmaps.epa.gov/gdm/. 

169Colstrip Initial Response, Table A4–6(c). 

170Colstrip Addendum, Table 4.1–4. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

An annual emission rate of 0.015 lb/ 

MMBtu can be achieved with lime 

injection without an additional scrubber 

vessel. PPL stated that this is the lowest 

emission rate that could be achieved 

without adding an additional scrubber 

vessel.167 An annual emission rate of 

0.08–0.09 lb/MMBtu can be achieved 

with lime injection with an additional 

scrubber vessel. This is the emission 

rate that is being achieved at Colstrip 

Units 3 and 4 according to emissions 

data from CAMD.168 The control 

effectiveness of each of the control 

options was calculated using the 

controlled emission rates that were 

provided by PPL. 

A summary of control efficiencies, 

emission rates, and resulting emissions 

and emission reductions, is provided in 

Table 102. EPA’s detailed emissions 

calculations for Colstrip 2 can be found 

in the docket. 

TABLE 102—SUMMARY OF BART ANALYSIS CONTROL TECHNOLOGIES FOR SO2 FOR COLSTRIP UNIT 2 

Control option Control effectiveness (%) 1

Annual emission 

rate (lb/MMBtu) 2

Emissions 

reduction (tpy) 

Remaining 

emissions (tpy) 

Lime Injection with Additional Scrubber Vessel .............................. 79.7 0.080 4,129 1,049 

Lime Injection ................................................................................... 62.0 0.150 3,212 1,966 

Existing Controls (Baseline) 3 .......................................................... ............................ 0.395 ............................ 5,178 

1 Control efficiency is provided relative to the emission rate with current controls. 

2Emission rates are provided on an annual basis. 

3Baseline emissions for 2008 through 2010 from Clean Air Markets—Data and Maps: http://camddataandmaps.epa.gov/gdm/. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

We relied on capital costs and direct 

annual costs provided by PPL when 

determining the cost of compliance for 

both lime injection and lime injection 

with an additional scrubber vessel.169 170

All costs presented here for the Colstrip 

Unit 2 SO2 control options are in year 

2007 dollars. EPA’s cost calculations for 

Colstrip 2 can be found in the docket. 

Lime Injection 

We summarize our cost analysis for 

lime injection in Tables 103, 104, and 

105. 

TABLE 103—SUMMARY OF SO2 CAPITAL COST ANALYSIS FOR LIME INJECTION ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 3,000,000 

TABLE 104—SUMMARY OF SO2 BART ANNUAL COST ANALYSIS FOR LIME INJECTION ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Direct Annual Cost ..................................................................................................................................................................... 1,600,000 

Indirect Annual Cost ............................................................................................................................................................................ 283,200 

Total Annual Cost ............................................................................................................................................................................ 1,883,200 

TABLE 105—SUMMARY OF SO2 BART COSTS FOR LIME INJECTION ON COLSTRIP UNIT 2 

Total Capital Investment (MM$) Total Annual Cost (MM$) Emissions 

reductions (tpy) 

Average cost 

effectiveness 

($/ton) 

3.000 1.883 3,212 586 

Lime Injection With an Additional 

Scrubber Vessel 

We summarize our cost analysis for 

lime injection with an additional 

scrubber vessel cost analysis in Tables 

106, 107, and 108. 

TABLE 106—SUMMARY OF SO2 CAPITAL COST ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER VESSEL

ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Capital Investment, Lime Injection ............................................................................................................................................. 3,000,000 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24037 

171Colstrip Initial Response, p. 4–16. 

TABLE 106—SUMMARY OF SO2 CAPITAL COST ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER VESSEL

ON COLSTRIP UNIT 2—Continued 

Description Cost ($) 

Capital Investment, Scrubber Vessel .................................................................................................................................................. 25,000,000 

Total Capital Investment .................................................................................................................................................................. 28,000,000 

TABLE 107—SUMMARY OF SO2 BART ANNUAL COST ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER

VESSEL ON COLSTRIP UNIT 2 

Description Cost ($) 

Total Direct Annual Cost ..................................................................................................................................................................... 1,450,000 

Indirect Annual Cost ............................................................................................................................................................................ 2,643,200 

Total Annual Cost ............................................................................................................................................................................ 4,093,200 

TABLE 108—SUMMARY OF SO2 BART COSTS ANALYSIS FOR LIME INJECTION WITH AN ADDITIONAL SCRUBBER VESSEL

ON COLSTRIP UNIT 2 

Total installed capital cost (MM$) Total annual cost (MM$) Emissions 

reductions (tpy) 

Average cost 

effectiveness ($/ton) 

$28.000 $4.093 4,129 991 

Factor 2: Energy Impacts 

According to PPL, the pressure drop 

of the venturi scrubbers is maintained in 

the range of 17 to 20 inches of water 

column. The injection of lime will be 

accompanied by little to no increase in 

pressure drop, but it will require a small 

increase in pump power consumption. 

This is included in the cost analysis in 

the additional operations and 

maintenance expenses of $125,000 per 

year.171 The additional energy 

requirements are not significant enough 

to warrant eliminating either lime 

injection or lime injection with an 

additional scrubber vessel. 

Factor 3: Non-Air Quality 

Environmental Impacts 

Adding lime to the scrubbers will 

require more frequent descaling 

operations that would increase the 

quantity of solid waste from descaling 

operations. Transporting this waste 

stream for disposal would use natural 

resources for fuel and would have 

associated air quality impacts. The 

disposal of the solid waste itself would 

be to a landfill and could possibly result 

in groundwater or surface water 

contamination if a landfill’s engineering 

controls were to fail. EPA’s analysis 

indicates that the environmental 

impacts associated with the proper 

transport and land disposal of the solid 

waste should not be significant. 

Therefore, the non-air quality 

environmental impacts do not warrant 

eliminating either lime injection 

addition or lime injection addition with 

an additional scrubber vessel. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Because the remaining useful life of the 

source is equal to that assumed for 

amortization of control option capital 

investments, this factor does not impact 

our BART determination. 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Colstrip 

Unit 2 as described in section V.C.3.a. 

Table 109 presents the visibility impacts 

of the 98th percentile of daily maxima 

for each Class I area from 2006 through 

2008. Table 110 presents the number of 

days with impacts greater than 0.5 

deciviews for each Class I area from 

2006 through 2008. 

TABLE 109—DELTA DECIVIEW IMPROVEMENT FOR SO2 CONTROLS ON COLSTRIP 2 

Class I area Baseline impact 

(delta deciview) 

Improvement 

from lime injection + additional 

scrubber vessel 

(delta deciview) 

Improvement 

from lime 

injection (delta 

deciview) 

North Absaroka WA ......................................................................................................... 0.402 0.140 0.111 

Theodore Roosevelt NP .................................................................................................. 0.895 0.280 0.225 

UL Bend WA .................................................................................................................... 0.889 0.179 0.143 

Washakie WA .................................................................................................................. 0.392 0.141 0.119 

Yellowstone NP ............................................................................................................... 0.289 0.090 0.067 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24038 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

172As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 173Colstrip Addendum, p. 6–1. 

TABLE 110—DAYS GREATER THAN 0.5 DECIVIEW FOR SO2 CONTROLS ON COLSTRIP 2 

[Three year total] 

Class I area Baseline 

(days) 

Using lime 

injection + additional scrubber 

vessel 

Using lime 

injection 

North Absaroka WA ......................................................................................................... 7 7 7

Theodore Roosevelt NP .................................................................................................. 52 33 37

UL Bend WA .................................................................................................................... 68 39 44 

Washakie WA .................................................................................................................. 12 7 8 

Yellowstone NP ............................................................................................................... 4 2 3 

Step 5: Select BART 

We propose to find that BART for SO2

is lime injection with an additional 

scrubber vessel at Colstrip Unit 2 with 

an emission limit of 0.08 lb/MMBtu (30- 

day rolling average). Of the five BART 

factors, cost and visibility improvement 

were the critical ones in our analysis of 

controls for this source. 

In our BART analysis for SO2 at 

Colstrip Unit 2, we considered lime 

injection and lime injection with an 

additional scrubber vessel. The 

comparison between our lime injection 

and lime injection with an additional 

scrubber vessel analysis is provided in 

Table 111. 

TABLE 111—SUMMARY OF EPA SO2 BART ANALYSIS COMPARISON OF LIME INJECTION AND LIME INJECTION WITH AN

ADDITIONAL SCRUBBER VESSEL FOR COLSTRIP UNIT 2 

Control option 

Total capital 

investment 

(MM$) 

Total annual 

cost (MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost effectiveness ($/ton) 

Visibility impacts 1

Visibility improvement (delta 

deciviews) 

Fewer days > 

0.5 deciview 

Lime Injection with Additional Scrubber Vessel.28.000 4.093 991 2,410 0.280 TRNP ......

0.179 UL Bend

7 TRNP 

8 UL Bend 

Lime Injection ..................................... 3.000 1.883 586 2 0.225 TRNP ......

0.143 UL Bend

6 TRNP 

7 UL Bend 

TRNP—Theodore Roosevelt National Park. 

UL Bend—UL Bend Wilderness Area. 

1The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) at the Class I areas in the table. 2 Incremental cost is not applicable to the option that has the lowest effectiveness. 

We have concluded that lime 

injection and lime injection with an 

additional scrubber vessel are both cost 

effective control technologies. Lime 

injection has a cost effectiveness value 

of $586 per ton of SO2 emissions 

reduced. Lime injection with an 

additional scrubber vessel is more 

expensive than lime injection, with a 

cost effectiveness value of $919 per ton 

of SO2 emissions reduced. Both of these 

costs are well within the range of values 

we have considered reasonable for 

BART and that states have considered 

reasonable for BART. 

We have weighed costs against the 

anticipated visibility impacts at Colstrip 

Unit 2. Either of the control options 

would have a positive impact on 

visibility. We have concluded that the 

cost of lime injection with an additional 

scrubber vessel ($991/ton) is justified by 

the visibility improvement of 0.280 

deciviews at Theodore Roosevelt NP 

and 0.179 deciviews at UL Bend WA 

and it would result in seven fewer days 

above 0.5 deciviews at Theodore 

Roosevelt NP and eight fewer days 

above 0.5 deciviews at UL Bend WA. In 

addition, the application of lime 

injection with an additional scrubber 

vessel on both Colstrip Units 1 and 2 

would result in a combined modeled 

visibility improvement of 0.592 

deciviews at Theodore Roosevelt NP 

and 0.384 deciviews at UL Bend WA. 

We consider these improvements to be 

substantial, especially in light of the fact 

that Theodore Roosevelt NP and UL 

Bend WA are not projected to meet the 

URP. We propose that the SO2 BART 

emission limit for Colstrip Unit 2 

should be based on what can be 

achieved with lime injection with an 

additional scrubber vessel. 

The proposed BART emission limit of 

0.08 lb/MMBtu allows for a sufficient 

margin of compliance for a 30-day 

rolling average limit that would apply at 

all times, including startup, shutdown, 

and malfunction.172 We are also 

proposing monitoring, recordkeeping, 

and reporting requirements as described 

in our proposed regulatory text for 40 

CFR 52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ We 

propose a compliance deadline of five 

(5) years from the date our final FIP 

becomes effective because of the 

equipment installation that will be 

required. 

PM 

Colstrip Unit 2 currently has venturi 

scrubbers designed to control PM 

emissions. A description of a venturi 

scrubber can be found under the PM 

section of the BART analysis for 

Colstrip Unit 1. The venturi scrubbers at 

Colstrip unit 2 are designed to have at 

least 98% control efficiency and have 

shown control efficiencies 

approximating 99.5%. The present 

emission rate is 0.0525 lb/MMBtu.173

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24039 

174 70 FR 39108 (July 6, 2005). 

175 Institute of Clean Air Companies (ICAC) White 

Paper, SCR Controls of NOX Emissions from Fossil 

Fuel-Fired Electric Power Plants, May 2009, pp. 7– 

8. 

176Control Technologies to Reduce Conventional 

and Hazardous Air Pollutants from Coal-Fired 

Power Plants, Northeast States for Coordinated Air 

Use Management (NESCAUM), March 31, 2011, p. 

16. 

177 ICAC White Paper, SNCR for Controlling NOX

Emissions, February 2008, pp. 6–7. 

178Low NOX Firing Systems and PRB Fuel; 

Achieving as Low as 0.12 LB NOX/MMBtu, 

Jennings, P., ICAC Forum, Feb. 2002. 

179White Paper, SNCR for Controlling NOX

Emissions, Institute of Clean Air Companies, pp. 4 

and 9, February 2008. 

180Srivastava, R., Hall, R., Khan, S., Lani, B., and 

Culligan, K., ‘‘Nitrogen oxides emission control 

options for coal-fired utility boilers,’’ Journal of Air 

and Waste Management Association 55(9):1367–88 

(2005). Available at: http://www.netl.doe.gov/ 

technologies/coalpower/ewr/pubs/ 

NOx%20control%20Lani%20AWMA%200905.pdf. 

Based on our modeling described in 

section V.C.3.a. PM contribution to the 

baseline visibility impairment is low. 

Table 112 shows the maximum baseline 

visibility impact and percentage 

contribution to that impact from coarse 

PM and fine PM. 

TABLE 112—COLSTRIP UNIT 2 VISIBILITY IMPACT CONTRIBUTION FROM PM 

Maximum baseline visibility impact (deciview) % Contribution coarse PM % Contribution fine PM 

0.895 0.95 3.88 

The PM contribution to the baseline 

visibility impact for Colstrip Unit 2 is 

very small; therefore, any visibility 

improvement that could be achieved 

with improvements to the existing PM 

controls would be negligible. We are 

proposing that the existing PM control 

device represents BART. 

Colstrip Unit 2 must meet the 

filterable PM emission standard of 

0.1lb/MMBtu in accordance with its 

Final Title V Operating Permit 

#OP0513–06. This requirement appears 

in Permit Condition B.2.; and was 

included in the permit pursuant to ARM 

17.8.340 and 40 CFR part 60, subpart D. 

Taking into consideration the above 

factors we propose basing the BART 

emission limit on what Colstrip Unit 2 

is currently meeting. The units are 

exceeding a PM control efficiency of 

99%, and therefore we are proposing 

that the current control technology and 

the emission limit of 0.1lb/MMBtu for 

PM/PM10 as BART. We find that the 

BART emission limit can be achieved 

through the operation of the existing 

venturi scrubbers. Thus, as described in 

our BART Guidelines, a full five-factor 

analysis for PM/PM10 is not needed for 

Colstrip Unit 2. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

v. Corette 

Background 

PPL Montana’s Corette Power Plant 

(Corette), located in Billings, Montana, 

consists of one electric utility steam 

generating unit. We previously provided 

in Section V.C. our reasoning for 

proposing that this unit is BART-eligible 

and why it is subject to BART. As 

explained in section V.C., the document 

titled ‘‘Identification of BART Eligible 

Sources in the WRAP Region’’ dated 

April 4, 2005 provides more details on 

the specific emission units at each 

facility. Corette’s boiler has a nominal 

gross capacity of 162 MW. The boiler 

began commercial operation in 1968 

and is a tangentially fired pulverized 

coal boiler that burns PRB subbituminous coal as their exclusive fuel. 

Although the gross capacity of Corette 

is below the 750 MW cutoff for which 

use of the BART Guidelines is 

mandatory, we have nonetheless 

followed the guidelines as they 

‘‘provide useful advice in implementing 

the BART provisions of the regional 

haze rule.’’ 174

We requested a five factor BART 

analysis for Corette from PPL and the 

Company submitted that analysis in 

August 2007 along with updated 

information in June 2008 and September 

2011. PPL’s five factor BART analysis 

information is contained in the docket 

for this action and we have taken it into 

consideration in our proposed action. 

NOX

The Corette boiler is a tangential-fired 

unit with existing low-NOX burners and 

CCOFA. The unit is subject to an annual 

NOX emission limit of 0.4 lb/MMBtu. 

Step 1: Identify All Available 

Technologies 

We identified the following NOX

control technologies are available: 

SOFA, SNCR, and SCR. Descriptions for 

each of these NOX control technologies 

can be found in the Colstrip 1 

evaluation above. 

Step 2: Eliminate Technically Infeasible 

Options 

Based on our review all the 

technologies identified in Step 1 appear 

to be technically feasible for Corette. In 

particular, both SCR and SNCR have 

been widely employed to control NOX

emissions from coal-fired power 

plants.175 176 177

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

At tangentially fired boilers firing subbituminous coal, SOFA in combination 

with CCOFA and LNB, can typically 

achieve emission rates below 0.15 lb/ 

MMBtu on an annual basis.178 However, 

due to certain issues unique to Corette, 

a rate of 0.20 lb/MMBtu is more 

realistic. Specifically, these issues 

include: (1) That the furnace is 

undersized, has a high heat rate, and 

therefore runs hotter than newer units 

designed for low NOX emissions; and (2) 

the nature of the particular PRB coal 

burned. The 0.20 lb/MMBtu rate 

represents a 26.8% reduction from the 

current baseline (2008 through 2010) 

rate of 0.274 lb/MMbtu. 

The post-combustion control 

technologies, SNCR and SCR, have been 

evaluated in combination with 

combustion controls. That is, the inlet 

concentration to the post-combustion 

controls is assumed to be 0.20 lb/ 

MMBtu. This allows the equipment and 

operating and maintenance costs of the 

post-combustion controls to be 

minimized based on the lower inlet 

NOX concentration. Typically, SNCR 

reduces NOX an additional 20 to 30% 

above LNB/combustion controls without 

excessive NH3 slip.179 Assuming that a 

minimum 25% additional emission 

reduction is achievable with SNCR, 

SOFA combined with SNCR can achieve 

an overall control efficiency of 44.9%. 

SCR can achieve performance emission 

rates as low as 0.04–0.07 lb/MMBtu on 

an annual basis.180 Assuming that an 

annual emission rate of 0.05 lb/MMBtu 

is achievable with SOFA+SCR, this 

equates to an overall control efficiency 

of 81.2%. A summary of control 

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24040 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

181Addendum to PPL Montana’s J.E. Corette 

Generating Station BART Report Prepared for PPL 

Montana, LLC; Prepared by TRC (‘‘Corette 

Addendum’’), June 2008, Table 5.1–3. 

182 IPM, Chapter 5, Appendix 5–2B. 

183Cost and Quality of Fuels for Electric Utility 

Plants 1999 Tables, Energy Information 

Administration, DOE/EIA–0191(99), June 2000, 

Table 24. 

184NOX Control Update to PPL Montana’s J.E. 

Corette Generating Station BART Report, September 

2011, Prepared for PPL Montana, LLC by TRC, p. 

8. 

efficiencies, emission rates, and 

resulting emission reductions for the 

control options under consideration are 

provided in Table 113. EPA’s detailed 

emissions calculations for Corette can 

be found in the docket. 

TABLE 113—SUMMARY OF NOX BART ANALYSIS CONTROL TECHNOLOGIES FOR CORETTE

Control option 

Control 

effectiveness 

(%) 

Annual emission 

rate 

(lb/MMBtu) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

SOFA+SCR ...................................................................................... 81.2 0.050 1,320 305 

SOFA+SNCR ................................................................................... 44.9 0.150 730 895 

SOFA ............................................................................................... 26.9 0.200 435 1,190 

No Controls (Baseline) 1 .................................................................. ............................ 0.274 ............................ 1,625 

1Baseline emissions were determined by averaging the annual emissions from 2008 to 2010 as reported to the CAMD database available at 

http://camddataandmaps.epa.gov/gdm/. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Refer to the Colstrip Unit 1 section 

above for general information on how 

we evaluated the cost of compliance for 

NOX controls. EPA’s cost calculations 

for NOX controls at Corette can be found 

in the docket. 

SOFA 

We relied on estimates submitted by 

PPL in 2008 for capital costs and direct 

annual costs for SOFA.181 We then used 

the CEPCI to adjust capital costs to 2010 

dollars (see Table 114). Annual costs 

were determined by summing the 

indirect annual cost and the direct 

annual cost (see Table 115). 

TABLE 114—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA ON CORETTE

Description Cost ($) 

Total Capital Investment SOFA ........................................................................................................................................................... 3,350,365 

TABLE 115—SUMMARY OF NOX BART ANNUAL COST ANALYSIS FOR SOFA ON CORETTE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 330,375 

Total Direct Annual Cost ..................................................................................................................................................................... 315,754 

Total Annual Cost ............................................................................................................................................................................ 646,129 

TABLE 116—SUMMARY OF NOX BART COSTS FOR SOFA ON CORETTE

Total installed capital cost 

(MM$) 

Total annual cost 

(MM$) 

Emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

3.351 0.646 435 1,487 

SOFA+SNCR 

We relied on control costs developed 

for the IPM for direct capital costs for 

SNCR.182 We then used methods 

provided by the CCM for the remainder 

of the SOFA+SNCR analysis. 

Specifically, we used the methods in the 

CCM to calculate total capital 

investment, annual costs associated 

with operation and maintenance, to 

annualize the total capital investment 

using the CRF, and to sum the total 

annual costs. 

We used a retrofit factor of ‘‘1’’ 

reflecting an SNCR retrofit of typical 

difficulty in the IPM control costs. 

Corette burns sub-bituminous PRB coal 

having a low sulfur content of 0.24 lb/ 

MMBtu.183 As explained in our analysis 

for Colstrip Unit 1, it was not necessary 

to make allowances in the cost 

calculations to account for equipment 

modifications or additional 

maintenance associated with fouling 

due to the formation of ammonium 

bisulfate. EPA’s detailed cost 

calculations for SOFA+SNCR can be 

found in the docket. 

We used a urea reagent cost estimate 

of $450 per ton taken from PPL’s 

September 2011 submittal.184 To 

estimate the average cost effectiveness 

(dollars per ton of emissions reductions) 

we divided the total annual cost by the 

estimated NOX emissions reductions. 

We summarize the costs from our 

SPFA+SNCR cost analysis in Tables 

117, 118, and 119. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24041 

185 IPM, Chapter 5, Appendix 5–2A. 186Email communication with Fuel Tech, Inc., 

March 2, 2012. 

187Cichanowicz 2010, p. 6–7. 

188CCM, Section 4.2, Chapter 1, p. 1–21. 

TABLE 117—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA+SNCR ON CORETTE

Description Cost ($) 

Capital Investment SOFA .................................................................................................................................................................... 3,350,365 

Capital Investment SNCR .................................................................................................................................................................... 6,464,691 

Total Capital Investment SOFA + SNCR ........................................................................................................................................ 9,815,056 

TABLE 118—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SNCR ON CORETTE

Description Cost ($) 

Total Annual Cost SOFA ..................................................................................................................................................................... 646,129 

Total Annual Cost SNCR ..................................................................................................................................................................... 1,248,062 

Total Annual Cost SOFA+SNCR ..................................................................................................................................................... 1,894,191 

TABLE 119—SUMMARY OF NOX BART COSTS FOR SOFA+SNCR ON CORETTE

Total installed capital cost (MM$) Total annual cost (MM$) Emissions 

reductions (tpy) 

Average cost 

effectiveness ($/ton) 

9.815 1.894 730 2,596 

SOFA+SCR 

We relied on control costs developed 

for the IPM for direct capital costs for 

SCR.185 We then used methods in the 

CCM for the remainder of the 

SOFA+SCR analysis. Specifically, we 

used the methods in the CCM to 

calculate total capital investment, 

annual costs associated with operation 

and maintenance, to annualize the total 

capital investment using the CRF, and to 

sum the total annual costs. 

We used a retrofit factor of ‘‘1’’ in the 

IPM control costs, which reflects an SCR 

retrofit of typical difficulty. We used an 

aqueous ammonia (29%) cost of $240 

per ton,186 and a catalyst cost of $6,000 

per cubic meter.187 To estimate the 

average cost effectiveness (dollars per 

ton of emissions reductions) we divided 

the total annual cost by the estimated 

NOX emissions reductions. We 

summarize the costs from our 

SOFA+SCR cost analysis in Tables 120, 

121, and 122. 

TABLE 120—SUMMARY OF NOX BART CAPITAL COST ANALYSIS FOR SOFA+SCR ON CORETTE

Description Cost ($) 

Capital Investment SOFA .................................................................................................................................................................... 3.350,365 

Capital Investment SCR ...................................................................................................................................................................... 42,958,390 

Total Capital Investment SOFA+SCR ............................................................................................................................................. 46,308,755 

TABLE 121—SUMMARY OF NOX BART TOTAL ANNUAL COST ANALYSIS FOR SOFA+SCR ON CORETTE

Description Cost ($) 

Total Annual Cost SOFA ..................................................................................................................................................................... 646,129 

Total Annual Cost SCR ....................................................................................................................................................................... 5,281,486 

Total Annual Cost SOFA+SCR ........................................................................................................................................................ 5,927,615 

TABLE 122—SUMMARY OF NOX BART COSTS FOR SOFA+SCR ON CORETTE

Total capital investment (MM$) Total annual cost (MM$) Emissions 

reductions (tpy) 

Average cost 

effectiveness ($/ton) 

46.309 5.927 1,320 4,491 

Factor 2: Energy Impacts 

SNCR reduces the thermal efficiency 

of a boiler as the reduction reaction uses 

thermal energy from the boiler.188

Therefore, additional coal must be 

burned to make up for the decrease in 

power generation. Using CCM 

calculations we determined the 

additional coal needed for Corette 

equates to 34,319 MMBtu/yr. For SCR, 

the new ductwork and the reactor’s 

catalyst layers decrease the flue gas 

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24042 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

189 Id., Section 4.2, Chapter 2, p. 2–28. 

pressure. As a result, additional fan 

power is necessary to maintain the flue 

gas flow rate through the ductwork. SCR 

systems require additional electric 

power to meet fan requirements 

equivalent to approximately 0.3% of the 

plant’s electric output.189 Both SCR and 

SNCR require some minimal additional 

electricity to service pretreatment and 

injection equipment, pumps, 

compressors, and control systems. The 

additional energy requirements that 

would be involved with operation of the 

evaluated controls are not significant 

enough to warrant eliminating any of 

the options evaluated. Note that the cost 

of the additional energy requirements 

has been included in our calculations. 

Factor 3: Non-Air Quality 

Environmental Impacts 

The non-air quality environmental 

impacts for Corette are the same as for 

Colstrip Unit 1, see previous discussion 

for Colstrip Unit 1. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Thus, this factor does not impact our 

BART determination because the 

annualized cost was calculated over a 

20 year period in accordance with the 

BART Guidelines. 

Factor 5: Evaluate Visibility Impacts 

We conducted modeling for Corette as 

described in section V.C.3.a. Table 123 

presents the visibility impacts of the 

98th percentile of daily maxima for each 

Class I area from 2006 through 2008. 

Table 124 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class area from 2006 through 

2008. 

TABLE 123—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON CORETTE

Class I area Baseline impact 

(delta deciview) 

SOFA+SCR 

(delta deciview) 

SOFA+SNCR 

(delta deciview) 

SOFA (delta 

deciview) 

Gates of the Mountains WA ............................................................ 0.295 0.093 0.049 0.028 

North Absaroka WA ......................................................................... 0.497 0.184 0.103 0.062 

Red Rock Lakes WA ....................................................................... 0.090 0.029 0.016 0.010 

Teton WA ......................................................................................... 0.298 0.118 0.062 0.042 

UL Bend WA .................................................................................... 0.462 0.158 0.091 0.057 

Washakie WA .................................................................................. 0.667 0.264 0.146 0.087 

Yellowstone NP ............................................................................... 0.325 0.093 0.053 0.033 

TABLE 124—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON CORETTE

[Three Year Total] 

Class I area Baseline (days) Using 

SOFA+SCR 

Using 

SOFA+SNCR Using SOFA 

Gates of the Mountains WA ............................................................ 4 2 3 3 

North Absaroka WA ......................................................................... 11 7 9 10 

Red Rock Lakes WA ....................................................................... 0 0 0 0 

Teton WA ......................................................................................... 7 2 6 7 

UL Bend WA .................................................................................... 14 2 5 8 

Washakie WA .................................................................................. 20 7 13 13 

Yellowstone NP ............................................................................... 7 2 3 4 

Step 5. Select BART 

We propose to find that BART for 

NOX is the existing tangential firing 

design of the boilers and existing lowNOX burners with close coupled over 

fire air at Corette with an emission limit 

of 0.40 lb/MMBtu (annual average). Of 

the five BART factors, cost and visibility 

improvement were the critical ones in 

our analysis of controls for this source. 

In our BART analysis for NOX at 

Corette, we considered SOFA, 

SOFA+SNCR, and SOFA+SCR. The 

comparison between our SOFA, 

SOFA+SNCR, and SOFA+SCR analysis 

is provided in Table 125. 

TABLE 125—SUMMARY OF NOX BART ANALYSIS COMPARISON OF CONTROL OPTIONS FOR CORETTE

Control option 

Total capital 

investment 

(MM$) 

Total annual 

cost (MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost effectiveness ($/ton) 

Visibility impacts 1

Visibility improvement 

(delta 

deciviews) 

Fewer days > 

0.5 deciview 

SOFA+SCR .............................................. 46.309 5.927 4,491 6,836 0.264 13 

SOFA+SNCR ........................................... 9.815 1.894 2,596 4,231 0.146 9 

SOFA ....................................................... 3.350 0.646 1,487 2 0.087 7 

1The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) is for Washakie WA, the Class I area with the greatest change, except that the fewer days >0.5 deciview 

for SOFA+SNCR is for UL Bend WA. 2 Incremental cost is not applicable to the option that has the lowest effectiveness. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24043 

190As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

191BART Assessment J.E. Corette Generating 

Station, prepared for PPL Montana, LLC, by TRC, 

(‘‘Corette Initial Response’’), August 2007, p. 4–9. 

192MDEQ, Final Operating Permit #OP2953–05, 

for PPL Montana, LLC, JE Corette Steam Electric 

Station, 9.25/09. 

193Control Technologies to Reduce Conventional 

and Hazardous Air Pollutants from Coal-Fired 

Power Plants, NESCAUM, March 31, 2011, p. 13. 

194 Id., p. 11. 

195 Id., p. 10. 

196 Id., p. 10. 

197 Id., p. 13. 

198 ICAC, Acid Gas/SO2 Control Technologies, 

http://www.icac.com/i4a/pages/ 

index.cfm?pageid=3401. 

199 Documentation for IPM v. 4.1, Table 5–2. 

We have concluded that SOFA, 

SOFA+SNCR, and SOFA+SCR are all 

cost effective control technologies. 

SOFA has a cost effectiveness value of 

$1,487 per ton of NOX emissions 

reduced. SOFA+SNCR is more 

expensive than SOFA, with a cost 

effectiveness value of $2,596 per ton of 

NOX emissions reduced. SOFA+SCR is 

more expensive than SOFA or 

SOFA+SNCR, having a cost 

effectiveness value of $4,491 per ton of 

NOX emissions reduced. This is well 

within the range of values we have 

considered reasonable for BART and 

that states have considered reasonable 

for BART. 

We have weighed costs against the 

anticipated visibility impacts for 

Corette. Any of the control options 

would have a positive impact on 

visibility; however, the cost of controls 

is not justified by the visibility 

improvement. 

In proposing a BART emission limit 

of 0.40 lb/MMBtu, we evaluated the 

existing emissions from the facility and 

determined this rate to allow for a 

sufficient margin of compliance for a 30- 

day rolling average limit that that would 

apply at all times, including startup, 

shutdown, and malfunction.190 We are 

also proposing monitoring, 

recordkeeping, and reporting 

requirements as described in our 

proposed regulatory text for 40 CFR 

52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

SO2

The Corette boiler currently burns 

very low-sulfur PRB sub-bituminous 

coal with a sulfur content of 0.3% by 

weight.191 The boiler is subject to a fuel 

sulfur limit of 1 lb/MMBtu (as fired) on 

a continuous basis and an annual 

emission limit of 9,990,00 lbs/calendar 

year.192

Step 1: Identify All Available 

Technologies 

We identified that three flue gas 

desulfurization (FGD or ‘‘scrubbing’’) 

technologies as available control 

technologies for consideration at 

Corette. Two of these options, dry 

sorbent injection (DSI) and semi-dry 

scrubbing (sometimes referred to as 

LSD), are dry scrubbing technologies. 

The third option is a wet scrubbing 

technology known as limestone forced 

oxidation (LSFO). We did not consider 

fuel-switching options as Corette 

already burns very low-sulfur coal. 

DSI is the injection of dry sorbent 

reagents that react with SO2 and other 

acid gases, with a downstream PM 

control device (ESP or baghouse) to 

capture the reaction products. Unlike 

wet or semi-dry scrubbing, a reaction 

chamber is not necessary and reagents 

are introduced directly into the existing 

ductwork. Trona, a naturally occurring 

mixture of sodium carbonate and 

sodium bicarbonate mined in some 

western states, is commonly used as a 

reagent in DSI systems.193 DSI is 

typically more attractive for smaller 

boilers. 

In a LSD system, the polluted gas 

stream is brought into contact with the 

alkaline sorbent in a semi-dry state 

through use of a spray dryer absorber. 

The term ‘‘dry’’ refers to the fact that, 

although water is added to the flue gas, 

the amount of water added is only just 

enough to maintain the gas above the 

saturation (dew point) temperature. In 

most cases, the reaction products and 

any unreacted lime from the LSD 

process are captured in a downstream 

fabric filter (baghouse), which helps 

provide additional capture of SO2.194

In LSFO, the polluted gas stream is 

brought into contact with a liquid 

alkaline sorbent (typically limestone) by 

forcing it through a pool of the liquid 

slurry or by spraying it with the liquid. 

In the absorber, the gas is cooled to 

below the saturation temperature, 

resulting in a wet gas stream and high 

rates of capture. Because a wet FGD 

system operates at low temperatures, it 

is usually the last pollution control 

device before the stack. The wet FGD 

absorber is typically located 

downstream of the PM control device 

(most often an ESP) and immediately 

upstream of the stack.195

There are several variations of the 

scrubbing systems described above. 

However, as discussed in the NOX

control evaluation, the BART 

Guidelines do not require that all 

variations be evaluated. The particular 

variations that we have identified 

here—DSI with trona, LSD, and LSFO— 

represent designs that have been 

successfully applied in a cost-effective 

manner at numerous utility boilers. 

Step 2: Eliminate Technically Infeasible 

Options 

Based on our review, all the 

technologies identified in Step 1 appear 

to be technically feasible for Corette. 

Using these technologies, over 480 

power plant boilers, representing nearly 

two-thirds of the electric generating 

capacity in the United States, are 

scrubbed or are projected to be scrubbed 

in the near future.196

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

The control effectiveness of DSI, 

when located upstream of an ESP (as 

would be the case at Corette), is in the 

range of 30 to 60%.197 For the purposes 

of our BART analysis for Corette, we 

assumed a SO2 removal target for DSI of 

50%, which is at the upper end of this 

range. Higher control efficiencies can be 

achieved with DSI in conjunction with 

a baghouse. However, as described 

under the PM control evaluation, 

replacement of the existing ESP with a 

new baghouse is not warranted under 

BART. 

The control effectiveness of LSD or 

LSFO is dependent on the sulfur 

content of the coal burned, with greater 

removal efficiencies being achieved 

with higher sulfur coals. LSD, which is 

more commonly applied to lower sulfur 

coals, can achieve control efficiencies of 

70 to 95%, while LSFO can routinely 

achieve control efficiencies of 95% 

when applied to higher sulfur coals.198

Because the control efficiency varies 

significantly with the inlet sulfur 

concentration, we evaluated the control 

effectiveness of LSD and LSFO based on 

the performance rate that can be 

achieved. Specifically, we aligned the 

performance rate with the ‘‘floor’’ 

assumed for retrofits in the IPM control 

cost methodology.199 On an annual 

basis, these rates are 0.065 lb/MMBtu 

and 0.060 lb/MMBtu for LSD and LSFO, 

respectively. 

A summary of control efficiencies, 

emission rates, and resulting emission 

reductions for the control options under 

consideration are provided in Table 126. 

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24044 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

200CCM, Section 1, Chapter 2, p. 2–21. 201Office of Management and Budget, Circular A– 

4, Regulatory Analysis, http://www.whitehouse.gov/ 

omb/circulars_a004_a-4/. 

202Chemical Engineering Magazine, p. 56, August 

2011. (http://www.che.com). 

TABLE 126—SUMMARY OF SO2 BART ANALYSIS CONTROL TECHNOLOGIES FOR CORETTE

Control option Control effectiveness (%) 

Annual emission 

rate (lb/MMBtu) 

Emissions reduction (tpy) Remaining emissions (tpy) 

LSFO ................................................................................................ 87.0 0.060 2,369 354 

LSD .................................................................................................. 85.9 0.065 2,339 384 

DSI ................................................................................................... 50.0 0.232 1,362 1,361 

No Controls (Baseline) 1 .................................................................. NA 0.461 ............................ 2,723 

1Baseline emissions were determined by averaging the annual emissions from 2008 to 2010 as reported to the CAMD database available at 

http://camddataandmaps.epa.gov/gdm/. A summary of this information can be found in our docket. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of compliance 

In accordance with the BART 

Guidelines (70 FR 39166 (July 6, 2005)), 

and in order to maintain and improve 

consistency, we sought to align our cost 

analysis for SO2 controls with the CCM. 

In a manner similar to our evaluation of 

costs for NOX controls as described 

above, we relied on the cost methods 

developed for IPM version 4.10. 

However, unlike our evaluation of costs 

for NOX controls, we relied on the IPM 

cost methods for both the capital costs 

and operating and maintenance costs 

(i.e., direct annual costs). The IPM cost 

methods for both capital and operation 

and maintenance costs for SO2 controls 

are more appropriate to utility boilers 

than the methods for industrial 

processes found in the CCM. Our costs 

were also informed by cost analyses 

submitted by PPL. EPA’s detailed cost 

calculations for each of the SO2 control 

options can be found in the docket. 

Annualization of capital investments 

was achieved using the CRF as 

described in the CCM.200 Unless noted 

otherwise, the CRF was computed using 

an economic lifetime of 20 years and an 

annual interest rate of 7%.201 All costs 

presented in this proposal are adjusted 

to 2010 dollars using the CEPCI.202

EPA’s detailed cost calculations can be 

found in the docket. 

DSI 

The specific methods that we relied 

upon for evaluating costs for DSI are 

found in Appendix 5–4 to the IPM v.4.1 

documentation. Our costs are based on 

utilization of the existing ESP to handle 

the increased particulate loading 

associated with injection of dry sorbent. 

This is consistent with the SO2 control 

efficiency of 50% that we assumed for 

DSI in conjunction with ESP. We used 

a retrofit factor of ‘‘1’’ reflecting a DSI 

retrofit of typical difficulty in the IPM 

control costs. We used a reagent cost of 

$145/ton of trona, consistent with the 

assumption in the IPM cost methods. 

We summarize the costs from our DSI 

cost analysis in Tables 127, 128, and 

129. 

TABLE 127—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR DSI ON CORETTE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 10,311,531 

TABLE 128—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR DSI ON CORETTE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 973,409 

Total Direct Annual Cost ..................................................................................................................................................................... 4,390,487 

Total Annual Cost ............................................................................................................................................................................ 5,363,896 

TABLE 129—SUMMARY OF SO2 BART COSTS FOR DSI ON CORETTE

Total capital investment (MM$) Total annual cost 

(MM$) 

Emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

10.311 .............................................................................................................................. 5.364 1,361 3,940 

Semi-dry Scrubbing with LSD 

The specific methods that we relied 

upon for evaluating costs for LSD can be 

found in Appendix 5–1B to the IPM 

v.4.1 documentation. We used a retrofit 

factor of ‘‘1’’ reflecting a LSD retrofit of 

typical difficulty in the IPM control 

costs. We summarize the costs from our 

LSD cost analysis in Tables 130, 131, 

and 132. 

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TABLE 130—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR LSD ON CORETTE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 93,175,857 

TABLE 131—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR LSD ON CORETTE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 8,795,801 

Total Direct Annual Cost ..................................................................................................................................................................... 3,932,763 

Total Annual Cost ......................................................................................................................................................................... 12,728,564 

TABLE 132—SUMMARY OF SO2 BART COSTS FOR LSD ON CORETTE

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions 

reductions 

(tons/yr) 

Average cost 

effectiveness 

($/ton) 

93.175 .............................................................................................................................. 12.728 2,339 5,442 

Wet Scrubbing With LSFO 

The specific methods that we relied 

upon for evaluating costs for LSFO can 

be found in Appendix 5–1A to the IPM 

v.4.1 documentation. We used a retrofit 

factor of ‘‘1’’ reflecting a LSFO retrofit 

of typical difficulty in the IPM control 

costs. We summarize the costs from our 

LSFO cost analysis in Tables 133, 134, 

and 135. 

TABLE 133—SUMMARY OF SO2 BART CAPITAL COST ANALYSIS FOR LSFO ON CORETTE

Description Cost ($) 

Total Capital Investment ...................................................................................................................................................................... 98,352,945 

TABLE 134—SUMMARY OF EPA SO2 BART ANNUAL COST ANALYSIS FOR LSFO ON CORETTE

Description Cost ($) 

Total Indirect Annual Cost ................................................................................................................................................................... 9,284,518 

Total Direct Annual Cost ..................................................................................................................................................................... 5,792,020 

Total Annual Cost ......................................................................................................................................................................... 15,076,538 

TABLE 135—SUMMARY OF SO2 BART COSTS FOR LSFO ON CORETTE

Total capital investment 

(MM$) 

Total annual cost 

(MM$) 

Emissions 

reductions 

(tpy) 

Average cost 

effectiveness 

($/ton) 

98.352 .............................................................................................................................. 15.076 2,369 6,365 

Factor 2: Energy Impacts 

Auxiliary power requirements were 

calculated consistent with the methods 

found in the IPM cost model for variable 

operating and maintenance costs. DSI 

requires additional power of 0.19% of 

the plant’s electrical output for air 

blowers for the injection system, drying 

equipment for the transport air, and inline trona milling equipment. LSD and 

LSFO require additional power of 

1.64% and 1.42% of the plant’s 

electrical output, respectively, to meet 

power requirements primarily 

associated with increased fan power to 

overcome the pressure drop of the FGD 

system. The average annual gross output 

of the Corette facility between 2008 and 

2010 was 1,084,455 MW-hours (MWh). 

The additional annual power needs 

associated with DSI, LSD, and LSFO 

equate to 2,060 MWh, 17,785 MWh, and 

15,399 MWh, respectively. We find that 

the additional energy requirements are 

not significant enough to warrant 

elimination of any of the SO2 control 

options under consideration. 

Factor 3: Non-air Quality Environmental 

Impacts 

Non-air quality environmental 

impacts for the SO2 control options 

under consideration for Corette include 

increased waste disposal, and with the 

exception of DSI, water usage. 

Waste disposal rates were calculated 

consistent with the methods found in 

the IPM cost model for variable 

operation and maintenance costs; PPL 

currently sells the fly ash generated at 

Corette. However, with the addition of 

a sodium sorbent used in DSI, any fly 

ash produced must be landfilled. 

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Therefore, the total waste disposal rate 

includes waste associated with both fly 

ash and sorbent. The hourly waste 

generation rate for DSI is 9.51 tons/hr. 

For both LSD and LSFO, the waste 

generation rate is directly proportional 

to the reagent usage and is estimated 

based on 10% moisture in the byproduct. The hourly waste generation 

rates for LSD and LSFO are 1.41 tons/ 

hr and 1.42 tons/hr, respectively. The 

average annual hours of operation at the 

Corette facility between 2008 and 2010 

were 7,513 hours. The annual waste 

generation rates associated with DSI, 

LSD, and LSFO equate to 71,448 tons/ 

yr, 10,593 tons/yr, and 10,668 tons/yr, 

respectively. 

Makeup water rates were calculated 

consistent with the methods found in 

the IPM cost model for variable 

operation and maintenance costs. The 

makeup water rates for LSD and LSFO 

are a function of gross unit size (actual 

gas flow rate) and sulfur feed rate. The 

hourly makeup water rates for LSD and 

LSFO are 11,290 gallons/hr and 15,380 

gallons/hr, respectively. These rates 

equate to an increase of annual 

consumption of 85,024,990 gallons/yr 

and 115,813,373 gallons/yr, 

respectively. 

With the exception of water use 

explained above, we find that the nonair quality environmental impacts are 

not significant enough to warrant 

elimination of any of the SO2 control 

options under consideration. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Thus, this factor does not impact our 

BART determination because the 

annualized cost was calculated over a 

20 year period in accordance with the 

BART Guidelines. 

Factor 5: Evaluate Visibility Impacts. 

We conducted modeling for Corette as 

described in section V.C.3.a. Table 136 

presents the visibility impacts of the 

98th percentile of daily maxima for each 

Class I area from 2006 through 2008. 

Table 137 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class area from 2006 through 

2008. 

TABLE 136—DELTA DECIVIEW IMPROVEMENT FOR SO2 CONTROLS ON CORETTE

Class I area Baseline impact 

(Delta deciview) 

LSFO 

(Delta deciview) 

LSD 

(Delta deciview) 

DSI 

(Delta deciview) 

Gates of the Mountains WA ............................................................ 0.295 0.147 0.145 0.090 

North Absaroka WA ......................................................................... 0.497 0.148 0.147 0.093 

Red Rock Lakes WA ....................................................................... 0.090 0.044 0.043 0.025 

Teton WA ......................................................................................... 0.298 0.114 0.112 0.065 

UL Bend WA .................................................................................... 0.462 0.168 0.168 0.101 

Washakie WA .................................................................................. 0.667 0.256 0.253 0.176 

Yellowstone NP ............................................................................... 0.325 0.135 0.134 0.097 

TABLE 137—DAYS GREATER THAN 0.5 DECIVIEW FOR SO2 CONTROLS ON CORETTE (THREE YEAR TOTAL) 

Class I area Baseline 

(days) Using LSFO Using LSD Using DSI 

Gates of the Mountains WA ............................................................ 4 2 2 3 

North Absaroka WA ......................................................................... 11 8 8 9 

Red Rock Lakes WA ....................................................................... 0 0 0 0 

Teton WA ......................................................................................... 7 4 4 5 

UL Bend WA .................................................................................... 14 4 4 6 

Washakie WA .................................................................................. 20 8 8 12 

Yellowstone NP ............................................................................... 7 3 3 4 

Step 5: Select BART. 

We propose to find that BART for SO2

is the existing operation at Corette with 

an emission limit of 0.70 lb/MMBtu 

(annual average). Of the five BART 

factors, cost and visibility improvement 

were the critical ones in our analysis of 

controls for this source. 

In our BART analysis for SO2 at 

Corette, we considered DSI, LSD, and 

LSFO. The comparison between our 

DSI, LSD, and LSFO analysis is 

provided in Table 138. 

TABLE 138—SUMMARY OF EPA SO2 BART ANALYSIS COMPARISON OF DSI, LSD, AND LSFO FOR CORETTE

Control option 

Total capital 

investment 

(MM$) 

Total annual 

cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost effectiveness 

($/ton) 

Visibility Impacts 1

Visibility improvement 

(delta 

deciviews) 

Fewer days > 

0.5 

deciview 

LSFO ........................................................ 98.352 15.076 6,365 78,266 0.256 12 

LSD .......................................................... 93.175 12.728 5,442 7,530 0.253 12 

DSI ........................................................... 10.312 5.364 3,940 2 0.176 8 

1The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological period (2006 through 2008) is for Washakie WA, the Class I area with the greatest change. 2 Incremental cost is not applicable to the option that has the lowest effectiveness. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24047 

203As discussed in the BART Guidelines, section 

V (70 FR 39172, July 6, 2005), and Section 302(k) 

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

204EPA Air Pollution Control Online Course, 

description at http://www.epa.gov/apti/course422/ 

ce6a1.html. 

205Corette Addendum, p. 6–1. 

206 Id. 

We have concluded that DSI is a cost 

effective control technology. DSI has a 

cost effectiveness value of $3,940 per 

ton of NOX emissions reduced. This is 

within the range of values we have 

considered reasonable for BART and 

that states have considered reasonable 

for BART. We have concluded that LSD 

and LSFO are not cost effective. LSD has 

a cost effectiveness of $5,442 per ton of 

SO2 emissions reduced and LSFO has a 

cost effectiveness of $6,365 per ton of 

SO2 emissions reduced. 

We have weighed costs against the 

anticipated visibility impacts at Corette. 

Any of the control options would have 

a positive impact on visibility; however, 

the cost of controls is not justified by 

the visibility improvement. 

In proposing a BART emission limit 

of 0.70 lb/MMBtu, we evaluated the 

existing emissions from the facility and 

determined this rate to allow for a 

sufficient margin of compliance for an 

annual average limit that would apply at 

all times, including startup, shutdown, 

and malfunction.203 We are also 

proposing monitoring, recordkeeping, 

and reporting requirements as described 

in our proposed regulatory text for 40 

CFR 52.1395. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

PM 

Corette currently has an ESP for 

particulate control. ESP is a particle 

control device that uses electrical forces 

to move the particles out of the flowing 

gas stream and onto collector plates. 

The ESP places electrical charges on the 

particles, causing them to be attracted to 

oppositely charged metal plates located 

in the precipitator. The particles are 

removed from the plates by ‘‘rapping’’ 

and collected in a hopper located below 

the unit. The removal efficiencies for 

ESPs are highly variable; however, for 

very small particles alone, the removal 

efficiency is about 99%.204 The ESP at 

Corette is designed to achieve a 96% 

control efficiency, but is currently 

operating at 98.5%.205 The present 

emission annual average filterable 

particulate emission rate is 0.082 lb/ 

MMBtu.206

Based on our modeling described in 

section V.C.3.a., PM contribution to the 

baseline visibility impairment is low. 

Table 139 shows the maximum baseline 

visibility impact and percentage 

contribution to that impact from coarse 

PM and fine PM. 

TABLE 139—CORETTE VISIBILITY IMPACT CONTRIBUTION FROM PM 

Maximum baseline visibility impact 

(deciview) 

% Contribution 

coarse PM 

% Contribution 

fine PM 

0.497 ........................................................................................................................................................................ 1.97 2.42 

The PM contribution to the baseline 

visibility impact for Corette is very 

small; therefore, any visibility 

improvement that could be achieved 

with improvements to the existing PM 

controls would be negligible. 

Corette must meet the filterable PM 

emission standard of 0.26 lb/MMBtu in 

accordance with its Final Title V 

Operating Permit #OP2953–05. This 

Title V requirement appears in Permit 

Condition H.4.; and was included in the 

permit pursuant to the regulatory 

requirements in Montana’s EPA 

approved SIP (ARM 17.8.749). 

Taking into consideration the above 

factors we propose basing the BART 

emission limit on what Corette is 

currently meeting. The units are 

exceeding a PM control efficiency of 

99%, and therefore we are proposing 

that the current control technology and 

the emission limit of 0.10 lb/MMBtu for 

PM/PM10 as BART. We find that the 

BART emission limit can be achieved 

through the operation of the existing 

ESP. Thus, as described in our BART 

Guidelines, a full five-factor analysis for 

PM/PM10 is not needed for Corette. 

As we have noted previously, under 

section 51.308(e)(1)(iv), ‘‘each source 

subject to BART [is] required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ Since 

we propose a BART emission limit that 

represents current operations and no 

installation is necessary, we propose a 

compliance deadline of 30 days from 

the date our final FIP becomes effective. 

D. Long-Term Strategy/Strategies 

1. Emissions Inventories 

40 CFR 51.308(d)(3)(iii) requires that 

EPA 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 Reasonable 

Progress in each mandatory Class I 

Federal area Montana affects. EPA must 

identify the baseline emissions 

inventory on which its strategies for 

Montana are based. 40 CFR 

51.308(d)(3)(iv) requires that EPA 

identify all anthropogenic (humancaused) sources of visibility impairment 

it considered in developing Montana’s 

LTS. This includes major and minor 

stationary sources, mobile sources, and 

area sources. In its efforts to meet these 

requirements, EPA relied on technical 

analyses developed by WRAP and 

approved by all state participants, as 

described below. 

Emissions within Montana are both 

naturally occurring and man-made. Two 

primary sources of naturally occurring 

emissions include wildfires and 

windblown dust. In Montana, the 

primary sources of anthropogenic 

emissions include electric utility steam 

generating units, energy production and 

processing sources, agricultural 

production and processing sources, 

prescribed burning, and fugitive dust 

sources. The Montana inventory 

includes emissions of SO2, NOX, PM2.5, 

PM10, OC, EC, VOCs, and NH3. 

An emissions inventory for each 

pollutant was developed by WRAP for 

Montana for the baseline year 2002 and 

for 2018, which is the first RP 

milestone. The 2018 emissions 

inventory was developed by projecting 

2002 emissions and applying reductions 

expected from federal and state 

regulations. The emission inventories 

developed by WRAP were calculated 

using approved EPA methods. 

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24048 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

207The WRAP 2002 Plan02d and WRAP 2018 

PRP18b inventories cited in Tables 73–78 can be 

found at http://vista.cira.colostate.edu/tss/Results/ 

HazePlanning.aspx. 

There are ten different emission 

inventory source categories identified: 

Point, area, area oil and gas, on-road, 

off-road, all fire, biogenic, road dust, 

fugitive dust, and windblown dust. 

Tables 140 through 145 show the 2002 

baseline emissions, the 2018 projected 

emissions, and net changes of emissions 

for SO2, NOX, OC, EC, PM2.5, and PM10

by source category in Montana. The 

methods that WRAP used to develop 

these emission inventories are described 

in more detail in the WRAP documents 

included in the docket.207

SO2 emissions in Montana, shown in 

Table 140, come mostly from point 

sources with smaller amounts coming 

from fire, area, mobile and the oil and 

gas industry. WRAP assumed more than 

6,000 tpy of SO2 would be reduced at 

Colstrip due to controls required by the 

Regional Haze program. Overall, a 12% 

statewide reduction in SO2 emissions is 

expected by 2018. 

TABLE 140—MONTANA SO2 EMISSION INVENTORY—2002 AND 2018 

Montana statewide SO2 emissions 

[tons/year] 

Source category Baseline 

2002 

Future 

2018 Net change Percent change 

Point ................................................................................................. 36,888 36,749 ¥138 ¥0.4 

All Fire .............................................................................................. 5,134 4,912 ¥222 ¥4.3 

Biogenic ........................................................................................... 0 0 0 0 

Area ................................................................................................. 3,236 3,580 344 11 

Area Oil and Gas ............................................................................. 225 6 ¥219 ¥97 

On-Road Mobile ............................................................................... 1,863 234 ¥1629 ¥87 

Off-Road Mobile ............................................................................... 4,552 282 ¥4270 ¥94 

Road Dust ........................................................................................ 11 13 2 20 

Fugitive Dust .................................................................................... 13 17 4 32.8 

Wind Blown Dust ............................................................................. 0 0 0 0 

Total .......................................................................................... 51,923 45,794 ¥6,128 ¥12 

NOX emissions in Montana, shown in 

Table 141, are expected to decline 26% 

by 2018. Off-road and on-road vehicle 

NOX emissions are estimated to decline 

by more than 50,000 tpy from the base 

case emissions total of approximately 

104,000 tpy. WRAP assumed more than 

23,000 tpy of NOX would be reduced at 

Colstrip by 2018 due to an enforcement 

action and additional controls required 

as a result of the regional haze 

requirements. NOX emissions from oil 

and gas sources are projected to increase 

by 84% (6000 tons). Overall, a 26% 

statewide reduction in NOX emissions is 

expected by 2018. 

TABLE 141—MONTANA NOX EMISSION INVENTORY—2002 AND 2018 

Montana statewide NOX emissions 

[tons/year] 

Source Category Baseline 

2002 

Future 

2018 Net change Percent change 

Point ................................................................................................. 53,416 33,508 ¥19,909 ¥37 

All Fire .............................................................................................. 15,283 14,632 ¥652 ¥4 

Biogenic ........................................................................................... 58,354 58,354 0 0 

Area ................................................................................................. 4,292 5,535 1,244 29 

Area Oil and Gas ............................................................................. 7,557 13,880 6,323 84 

On-Road Mobile ............................................................................... 53,597 22,036 ¥31,560 ¥59 

Off-Road Mobile ............................................................................... 50,604 32,054 ¥18,550 ¥37 

Road Dust ........................................................................................ 25 29 4 17 

Fugitive Dust .................................................................................... 14 15 1 11 

Wind Blown Dust ............................................................................. 0 0 0 0 

Total .......................................................................................... 243,142 180,043 ¥63,099 ¥26 

Most of the PM OC emissions in 

Montana are from fires as shown in 

Table 142. In 2002, natural (nonanthropogenic) wildfire accounted for 

38,324 tons of OC emissions while 

anthropogenic fire accounted for 3,745 

tons of OC emission. Anthropogenic fire 

(human-caused), includes such 

activities as forestry prescribed burning, 

agricultural field burning, and outdoor 

residential burning. Overall, OC 

emissions are estimated to decline by 

3% by 2018. 

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TABLE 142—MONTANA PARTICULATE MATTER ORGANIC CARBON EMISSION INVENTORY—2002 AND 2018 

Montana statewide organic carbon emissions 

[tons/year] 

Source category Baseline 

2002 

Future 

2018 Net change Percent Change 

Point ................................................................................................. 101 267 167 165 

All Fire .............................................................................................. 42,069 40,162 ¥1,907 ¥5 

Biogenic ........................................................................................... 0 0 0 0 

Area 1 ............................................................................................... 2788 2974 187 7 

On-Road Mobile ............................................................................... 455 469 14 3 

Off-Road Mobile ............................................................................... 718 382 ¥336 ¥47 

Road Dust ........................................................................................ 1,271 1,487 216 17 

Fugitive Dust .................................................................................... 687 760 73 11 

Wind Blown Dust ............................................................................. 0 0 0 0 

Total .......................................................................................... 48,089 46,502 ¥1,587 ¥3 

1Area Source Oil and Gas emissions are included in Area Source total for OC, EC, and PM. 

The primary source of EC is fire as 

shown in Table 143. In 2002, natural 

(non-anthropogenic) wildfire accounted 

for 7,743 tons of EC emissions while 

anthropogenic fire accounted for 759 

tons of OC emissions. Other emissions 

of note are off-road mobile and on-road 

mobile sources, particularly those 

associated with diesel engines. EC 

emissions are estimated to decrease by 

17% by 2018 due mostly to new federal 

mobile source regulations. 

TABLE 143—MONTANA ELEMENTAL CARBON EMISSION INVENTORY—2002 AND 2018 

Montana statewide elemental carbon emissions 

[tons/year] 

Source category Baseline 

2002 

Future 

2018 Net change Percent change 

Point ................................................................................................. 17 25 8 49 

All Fire .............................................................................................. 8,502 8,116 ¥386 ¥5 

Biogenic ........................................................................................... 0 0 0 0 

Area 1 ............................................................................................... 413 447 34 8 

On-Road Mobile ............................................................................... 519 159 ¥361 ¥69 

Off-Road Mobile ............................................................................... 2,288 1,001 ¥1287 ¥56 

Road Dust ........................................................................................ 87 102 15 17 

Fugitive Dust .................................................................................... 47 52 5 11 

Wind Blown Dust ............................................................................. 0 0 0 0 

Total .......................................................................................... 11,873 9,901 ¥1,971 ¥17 

1Area Source Oil and Gas emissions are included in Area Source total for OC, EC, and PM. 

As detailed in Tables 144 and 145, the 

primary sources of PM (both PM10 and 

PM2.5) are road, fugitive, and 

windblown dust (agriculture, mining, 

construction, and unpaved and paved 

roads). Overall, PM shows an increase of 

8–9% by 2018. 

TABLE 144—MONTANA FINE PARTICULATE MATTER EMISSION INVENTORY—2002 AND 2018 

Montana statewide PM2.5 emissions 

[tons/year] 

Source category Baseline 

2002 

Future 

2018 Net change Percent change 

Point ................................................................................................. 182 294 112 62 

All Fire .............................................................................................. 3,190 3,047 ¥142 ¥5 

Biogenic ........................................................................................... 0 0 0 0 

Area 1 ............................................................................................... 2,472 2,754 281 11 

On-Road Mobile ............................................................................... 0 0 0 0 

Off-Road Mobile ............................................................................... 0 0 0 0 

Road Dust ........................................................................................ 21,671 25,294 3,623 17 

Fugitive Dust .................................................................................... 13,276 15,209 1,933 15 

Wind Blown Dust ............................................................................. 36,448 36,448 0 0 

Total .......................................................................................... 77,239 83,047 5,807 8 

1Area Source Oil and Gas emissions are included in Area Source total for OC, EC, and PM. 

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208WRAP TSD. 

TABLE 145—MONTANA COARSE PARTICULATE MATTER EMISSION INVENTORY—2002 AND 2018 

Montana statewide coarse particulate matter emissions 

[tons/year] 

Source category Baseline 

2002 

Future 

2018 Net change Percent change 

Point ................................................................................................. 7,818 11,384 3,566 46 

All Fire .............................................................................................. 9,210 8,808 ¥401 ¥4 

Biogenic ........................................................................................... 0 0 0 0 

Area 1 ............................................................................................... 706 790 84 12 

On-Road Mobile ............................................................................... 270 329 59 22 

Off-Road Mobile ............................................................................... 0 0 0 0 

Road Dust ........................................................................................ 206,863 241,329 34,467 17 

Fugitive Dust .................................................................................... 68,373 85,309 16,936 25 

Wind Blown Dust ............................................................................. 328,036 328,036 0 0 

Total .......................................................................................... 621,276 675,985 54,709 9 

1Area Source Oil and Gas emissions are included in Area Source total for OC, EC, and PM. 

See the WRAP documents included in 

the docket for details on how the 2018 

emissions inventory was constructed. 

WRAP used this inventory and other 

states’ 2018 emission inventories to 

construct visibility projection modeling 

for 2018. 

The reduction in point and area 

emissions shown in Tables 140 through 

145 is explained in the WRAP’s 2018 

point and area source projection on 

Reasonable Progress inventory (version 

2018 PRP 18b, http://www.wrapair.org/ 

forums/ssjf/pivot.html). The factors 

contributing to the reductions included 

emission reductions due to known 

controls in place on the emission 

sources, consent decrees, SIP control 

measures, and other relevant regulations 

that have gone into effect since 2002, or 

will go into effect before the end of 

2018. This includes estimates made in 

2007 for controls for BART sources. 

These controls do not include impacts 

from any future control scenarios that 

had not been defined by 2007. The 

reduction in emissions due to the 

retirement of older equipment was 

estimated using annual retirement rates 

and based on expected equipment 

lifetimes. Unit lifetimes were examined 

for natural gas-fired electrical generating 

units (EGU) but no retirements were 

assumed for coal-fired EGU. The permit 

limits for a source having a limit were 

considered in the cases where the 

projected emissions may have 

inadvertently exceeded an enforceable 

emission limit i.e., emissions were 

adjusted downward to the permit limit. 

2. Sources of Visibility Impairment in 

Montana Class I Areas 

In order to determine the significant 

sources contributing to haze in 

Montana’s Class I areas, EPA relied 

upon two source apportionment 

analysis techniques developed by 

WRAP. The first technique was regional 

modeling using the Comprehensive Air 

Quality Model (CAMx) and the PSAT 

tool, used for the attribution of sulfate 

and nitrate sources only. The second 

technique was the 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 

masses over each area where emissions 

occur, to estimate the percent 

contribution of different pollutants. Like 

PSAT, the WEP tool compares baseline 

values (2000 through 2004) to 2018 

values, to show the improvement 

expected by 2018, for sulfate, nitrate, 

OC, EC, PM2.5, and PM10. More 

information on WRAP modeling 

methodologies is available in the 

docket.208 Note that the PSAT analyses 

used the earlier 2002 Plan 02c and 2018 

Base 18b inventories, rather than the 

2002 Plan 02d and 2018 PRP 18b 

inventories that are listed in the tables 

here. The 2018 Base 18b inventory does 

not assume BART controls. 

The contributions of sulfate and 

nitrate are based on PSAT while the 

contributions of OC, EC, PM2.5, PM10, 

and Sea Salt are based on WEP. The 

PSAT and WEP results presented in 

Tables 146, 147, and 148 were derived 

from WRAP analysis. Table 147 shows 

the contribution of different pollutant 

species from Montana sources. 

TABLE 146—MT SOURCES EXTINCTION CONTRIBUTION 2000–2004 FOR 20% WORST DAYS

Class I area Pollutant species Extinction 

(Mm¥1) 

Species contribution to 

total extinction 

(%) 

MT sources 

contribution to 

species 

extinction 

(%)1

Sulfate ............................................................ 4.83 11 4 

Nitrate ............................................................. 1.46 3 18 

OC .................................................................. 20.01 47 5 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24051 

TABLE 146—MT SOURCES EXTINCTION CONTRIBUTION 2000–2004 FOR 20% WORST DAYS—Continued 

Class I area Pollutant species Extinction 

(Mm¥1) 

Species contribution to 

total extinction 

(%) 

MT sources 

contribution to 

species 

extinction 

(%)1

Anaconda-Pintler WA ...................................... EC .................................................................. 2.52 6 6 

PM2.5 .............................................................. 0.94 2 21 

PM10 ............................................................... 2.49 6 21 

Sea Salt .......................................................... 0.26 1 2

Sulfate ............................................................ 5.12 11 6 

Nitrate ............................................................. 1.43 3 31 

Bob Marshall WA ............................................ OC .................................................................. 22.29 48 33 

EC .................................................................. 2.8 6 36 

PM2.5 .............................................................. 1.29 3 49 

PM10 ............................................................... 3.6 8 60 

Sea Salt .......................................................... 0.03 0 2

Cabinet ............................................................ Sulfate ............................................................ 6.48 15 3 

Mountains WA.

Nitrate ............................................................. 2.02 5 14 

OC .................................................................. 16.95 40 25 

EC .................................................................. 2.79 7 25 

PM2.5 .............................................................. 1.03 2 13 

PM10 ............................................................... 2.81 7 16 

Sea Salt .......................................................... 0.1 0 2

Sulfate ............................................................ 5.41 17 8 

Nitrate ............................................................. 1.88 6 30 

Gates of the Mountains WA ........................... OC .................................................................. 11.26 35 35 

EC .................................................................. 1.82 6 38 

PM2.5 .............................................................. 0.75 2 73 

PM10 ............................................................... 1.68 5 82 

Sea Salt .......................................................... 0.06 0 2

Sulfate ............................................................ 11.37 8 10 

Nitrate ............................................................. 9.36 7 23 

Glacier National Park ...................................... OC .................................................................. 87.68 64 44 

EC .................................................................. 11.2 8 45 

PM2.5 .............................................................. 1.4 1 36 

PM10 ............................................................... 5.22 4 42 

Sea Salt .......................................................... 0.28 0 2

Sulfate ............................................................ 16.96 28 3 

Nitrate ............................................................. 16.27 27 16 

OC .................................................................. 9.48 15 40 

Medicine Lake WA.

EC .................................................................. 2.34 4 40 

PM2.5 .............................................................. 0.75 1 45 

PM10 ............................................................... 4.46 7 51 

Sea Salt .......................................................... 0.03 0 2

Sulfate ............................................................ 5.12 11 6 

Nitrate ............................................................. 1.43 3 31 

Mission Mountain WA ..................................... OC .................................................................. 22.29 48 33 

EC .................................................................. 2.8 6 36 

PM2.5 .............................................................. 1.29 3 49 

PM10 ............................................................... 3.6 8 60 

Sea Salt .......................................................... 0.03 0 2

Sulfate ............................................................ 4.26 12 1 

Nitrate ............................................................. 1.77 5 1 

Red Rock Lakes WA ...................................... OC .................................................................. 13.48 39 2 

EC .................................................................. 2.48 7 3 

PM2.5 .............................................................. 0.95 3 18 

PM10 ............................................................... 2.58 7 26 

Sea Salt .......................................................... 0.02 0 2

Sulfate ............................................................ 5.12 11 6 

Nitrate ............................................................. 1.43 3 31 

OC .................................................................. 22.29 48 33 

Scapegoat WA ................................................ EC .................................................................. 2.8 6 36 

PM2.5 .............................................................. 1.29 3 49 

PM10 ............................................................... 3.6 8 60 

Sea Salt .......................................................... 0.03 0 2

Sulfate ............................................................ 4.83 11 4 

Nitrate ............................................................. 1.46 3 1 

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24052 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

TABLE 146—MT SOURCES EXTINCTION CONTRIBUTION 2000–2004 FOR 20% WORST DAYS—Continued 

Class I area Pollutant species Extinction 

(Mm¥1) 

Species contribution to 

total extinction 

(%) 

MT sources 

contribution to 

species 

extinction 

(%)1

Selway-Bitterroot WA ...................................... OC .................................................................. 20.01 47 5 

EC .................................................................. 2.52 6 6 

PM2.5 .............................................................. 0.94 2 21 

PM10 ............................................................... 2.49 6 21 

Sea Salt .......................................................... 0.26 1 2

Sulfate ............................................................ 9.78 20 5 

Nitrate ............................................................. 8.01 17 18 

OC .................................................................. 12.76 26 52 

U.L. Bend WA ................................................. EC .................................................................. 2.08 4 51 

PM2.5 .............................................................. 0.77 2 75 

PM10 ............................................................... 4.01 8 81 

Sea Salt .......................................................... 0.01 0 2

Sulfate ............................................................ 4.26 12 1 

Nitrate ............................................................. 1.77 5 1 

OC .................................................................. 13.48 39 2 

Yellowstone NP ............................................... EC .................................................................. 2.48 7 3 

PM2.5 .............................................................. 0.95 3 18 

PM10 ............................................................... 2.58 7 26 

Sea Salt .......................................................... 0.02 0 2

1 Contribution of sulfate and nitrate based on PSAT; OC, EC, PM2.5, PM10, and Sea Salt contribution based on WEP. 2 MT sources contribution to sea salt was not included in the WRAP results. 

Tables 147 and 148 show influences 

from sources both inside and outside of 

Montana. 

TABLE 147—SOURCE REGION APPORTIONMENT FOR SO4 FOR 20% WORST DAYS

[Percentage] 

Montana Canada Idaho Washington Oregon Outside 

domain 

Anaconda-Pintler WA ............................... 4 14 13 10 7 45 

Bob Marshall WA ..................................... 6 14 5 6 4 47 

Cabinet Mountains WA ............................ 3 17 7 14 5 48 

Gates of the Mountains WA .................... 8 1 4 6 3 48 

Glacier NP ................................................ 10 24 2 6 5 51 

Medicine Lake WA ................................... 3 50 0 2 1 23 

Mission Mountain WA .............................. 6 14 5 6 4 47 

Red Rock Lakes WA ............................... 1 5 8 4 4 46 

Scapegoat WA ......................................... 6 14 5 6 4 47 

Selway-Bitterroot WA ............................... 4 14 13 10 7 45 

U.L. Bend WA .......................................... 5 34 1 2 1 37 

Yellowstone NP ........................................ 1 5 8 4 4 46 

TABLE 148—SOURCE REGION APPORTIONMENT FOR NO3 FOR 20% WORST DAYS

[Percentage] 

Montana Canada Idaho Washington Oregon Outside 

domain 

Anaconda-Pintler WA ............................... 18 9 13 15 5 23 

Bob Marshall WA ..................................... 31 11 7 9 3 25 

Cabinet Mountains WA ............................ 14 9 14 32 7 14 

Gates of the Mountains WA .................... 29 13 6 9 2 26 

Glacier NP ................................................ 23 22 9 13 6 23 

Medicine Lake WA ................................... 16 47 1 6 3 18 

Mission Mountain WA .............................. 31 11 7 9 3 25 

Red Rock Lakes WA ............................... 2 1 24 8 6 27 

Scapegoat WA ......................................... 31 11 7 9 3 25 

Selway-Bitterroot WA ............................... 18 9 13 15 5 23 

U.L. Bend WA .......................................... 18 38 2 5 3 21 

Yellowstone NP ........................................ 2 1 24 8 6 27 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24053 

209WRAP TSD. 

3. Other States’ Class I Areas Affected 

by Montana Emissions 

Table 149 shows the impact Montana 

sources have on Class I areas in adjacent 

states.209

TABLE 149—MT SOURCES EXTINCTION CONTRIBUTION 2000–2004, 20% WORST DAYS

Class I area Pollutant species Extinction 

(Mm ¥1) 

Species contribution to 

particle extinction (%) 

MT sources 

contribution to 

species 

extinction 

(%) 1

Badlands WA ................................................. Sulfate ........................................................... 18 .85 41 2 

Nitrate ............................................................ 5 .85 13 7 

OC ................................................................. 11 .78 26 18 

EC ................................................................. 2 .59 6 12 

PM2.5 .............................................................. 0 .98 2 4 

PM10 .............................................................. 5 .94 13 5 

Sea Salt ......................................................... 0 .19 0 ........................

Bridger WA ..................................................... Sulfate ........................................................... 4 .99 22 2 

Nitrate ............................................................ 1 .43 6 3 

OC ................................................................. 10 .55 47 2 

EC ................................................................. 1 .99 9 2 

PM2.5 .............................................................. 1 .1 5 8 

PM10 .............................................................. 2 .51 11 13 

Sea Salt ......................................................... 0 .04 0 ........................

Craters of the Moon WA ................................ Sulfate ........................................................... 5 .69 18 1 

Nitrate ............................................................ 11 .35 35 3 

OC ................................................................. 9 .06 28 1 

EC ................................................................. 1 .92 6 1 

PM2.5 .............................................................. 1 .04 3 4 

PM10 .............................................................. 2 .95 9 5 

Sea Salt ......................................................... 0 .03 0 ........................

Fitzpatrick WA ................................................ Sulfate ........................................................... 4 .99 22 2 

Nitrate ............................................................ 1 .43 6 3 

OC ................................................................. 10 .55 47 2 

EC ................................................................. 1 .99 9 2 

PM2.5 .............................................................. 1 .1 5 8 

PM10 .............................................................. 2 .51 11 13 

Sea Salt ......................................................... 0 .04 0 ........................

Grand Teton NP ............................................. Sulfate ........................................................... 4 .26 17 0 

Nitrate ............................................................ 1 .77 7 0 

OC ................................................................. 13 .48 53 2 

EC ................................................................. 2 .48 10 3 

PM2.5 .............................................................. 0 .95 4 18 

PM10 .............................................................. 2 .58 10 26 

Sea Salt ......................................................... 0 .02 0 ........................

Hells Canyon WA ........................................... Sulfate ........................................................... 8 .37 14 1 

Nitrate ............................................................ 28 .47 49 1 

OC ................................................................. 15 .6 27 1 

EC ................................................................. 3 .06 5 1 

PM2.5 .............................................................. 0 .66 1 2 

PM10 .............................................................. 1 .93 3 3 

Sea Salt ......................................................... 0 .05 0 ........................

Lostwood NWR .............................................. Sulfate ........................................................... 21 .4 34 2 

Nitrate ............................................................ 22 .94 36 9 

OC ................................................................. 11 .05 18 17 

EC ................................................................. 2 .84 5 12 

PM2.5 .............................................................. 0 .62 1 7 

PM10 .............................................................. 3 .93 6 11 

Sea Salt ......................................................... 0 .26 0 ........................

North Absaroka NP ........................................ Sulfate ........................................................... 4 .87 21 7 

Nitrate ............................................................ 1 .61 7 16 

OC ................................................................. 11 .64 49 15 

EC ................................................................. 1 .86 8 15 

PM2.5 .............................................................. 0 .85 4 45 

PM10 .............................................................. 2 .91 12 56 

Sea Salt ......................................................... 0 .01 0 ........................

Teton WA ....................................................... Sulfate ........................................................... 4 .26 17 0 

Nitrate ............................................................ 1 .77 7 0 

OC ................................................................. 13 .48 53 2 

EC ................................................................. 2 .48 10 3 

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24054 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

210 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. 

211WRAP TSD and ‘‘Air Quality Modeling,’’ 

available at: http://vista.cira.colostate.edu/docs/ 

WRAP/Modeling/AirQualityModeling.doc. 

TABLE 149—MT SOURCES EXTINCTION CONTRIBUTION 2000–2004, 20% WORST DAYS—Continued 

Class I area Pollutant species Extinction 

(Mm ¥1) 

Species contribution to 

particle extinction (%) 

MT sources 

contribution to 

species 

extinction 

(%) 1

PM2.5 .............................................................. 0 .95 4 18 

PM10 .............................................................. 2 .58 10 26 

Sea Salt ......................................................... 0 .02 0 ........................

Theodore Roosevelt NP ................................ Sulfate ........................................................... 17 .53 35 3 

Nitrate ............................................................ 13 .74 27 15 

OC ................................................................. 10 .82 21 49 

EC ................................................................. 2 .75 5 33 

PM2.5 .............................................................. 0 .9 2 22 

PM10 .............................................................. 4 .82 10 25 

Sea Salt ......................................................... 0 .07 0 ........................

Washakie WA ................................................ Sulfate ........................................................... 4 .87 21 7 

Nitrate ............................................................ 1 .61 7 16 

OC ................................................................. 11 .64 49 15 

EC ................................................................. 1 .86 8 15 

PM2.5 .............................................................. 0 .85 4 45 

PM10 .............................................................. 2 .91 12 56 

Sea Salt ......................................................... 0 .01 0 ........................

Wind Cave NP ............................................... Sulfate ........................................................... 13.2 32 2 

Nitrate ............................................................ 6 .98 17 0 

OC ................................................................. 13 .22 32 21 

EC ................................................................. 2 .92 7 15 

PM2.5 .............................................................. 0 .85 2 11 

PM10 .............................................................. 3 .52 9 13 

Sea Salt ......................................................... 0 .03 0 ........................

1 Contribution of sulfate and nitrate based on PSAT; OC, EC, PM2.5, PM10, and Sea Salt contribution based on WEP. 

4. Visibility Projection Modeling 

The Regional Modeling Center (RMC) 

at the University of California Riverside, 

under the oversight of the WRAP 

Modeling Forum, performed modeling 

for the regional haze LTS for the WRAP 

member states, including Montana. The 

modeling analysis is a complex 

technical evaluation that began with 

selection of the modeling system. RMC 

primarily used the Community MultiScale Air Quality (CMAQ) 

photochemical grid model to estimate 

2018 visibility conditions in Montana 

and all western Class I areas, based on 

application of the regional haze 

strategies in the various state plans, 

including some assumed controls on 

BART sources. 

The RMC 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 regional haze 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 2007. All 

emission inventories were spatially and 

temporally allocated using the Sparse 

Matrix Operator Kernel Emissions 

(SMOKE) modeling system. 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.210 A more detailed 

description of the CMAQ modeling 

performed for the WRAP can be found 

in the docket.211

The photochemical modeling of 

regional haze 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 RMC 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 

regional haze assessment of the LTS 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 RMC determined that model 

performance was acceptable, it used the 

model to determine the 2018 RPGs 

using the current and future year air 

quality modeling predictions, and 

compared the RPGs to the URP. 

5. Consultation and Emissions 

Reduction for Other States’ Class I Areas 

40 CFR 51.308(d)(3)(i) requires that 

EPA consult with another state if 

Montana’s emissions are reasonably 

anticipated to contribute to visibility 

impairment at that state’s Class I area(s), 

and that EPA consult with other states 

if those other states’ emissions are 

reasonably anticipated to contribute to 

visibility impairment at Montana’s Class 

I areas. EPA worked with other states 

and tribes through the WRAP process. 

EPA also accepts and incorporates the 

WRAP-developed visibility modeling 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24055 

212See ‘‘Air Quality Modeling,’’ available at: 

http://vista.cira.colostate.edu/docs/WRAP/ 

Modeling/AirQualityModeling.doc. 

213WRAP TSD; WRAP PRP 18b Emissions 

Inventory—Revised Point and Area Sources 

Projections, Final dated October 16, 2009; 

Development of 2000–04 Baseline period and 2018 

Projection Year Emission Inventories, Final, dated 

May 2007; Final Report, WRAP Mobile Source 

Emission Inventories Updated, dated May 2006; 

Emissions Overview, for which WRAP did not 

include a date; 2002 Planning Simulation Version 

D Specification Sheet for which WRAP did not 

include a date; 2018 Preliminary Reasonable 

Progress Simulation Version B Specification Sheet 

for which WRAP did not include a date. The actual 

inventories can be found in the docket in the 

spreadsheets with the following titles: 02d Point 

Source Inventory; 02d Area Source Inventory; 

PRP18b Point Source Inventory; PRP 18b Area 

Source Inventory. 

214A more detailed description of the CMAQ 

modeling performed by WRAP can be found in 

WRAP’s TSD dated February 29, 2011, and also in 

the document in the docket titled Air Quality 

Modeling for which the WRAP did not include a 

date. 

into the Regional Haze FIP for 

Montana.212

This proposal contains the necessary 

measures to meet Montana’s share of the 

reasonable progress goals for the other 

state’s Class I areas. 

Table 149 above shows Montana’s 

contribution to Class I areas in 

neighboring states. None of the 

neighboring states with Class I areas 

have indicated to EPA that specific 

reductions are necessary for this FIP. 

Therefore, EPA proposes that this FIP 

meets Montana’s share of the reasonable 

progress goals for the other state’s Class 

I areas. 

6. EPA’s Reasonable Progress Goals for 

Montana 

In order to establish RPGs for the 

Class I areas in Montana and to 

determine the controls needed for the 

LTS, we followed the process 

established in the Regional Haze Rule. 

First, we identified the anticipated 

visibility improvement in 2018 in all 

Montana Class I areas accounting for all 

existing enforceable federal and state 

regulations already in place and 

anticipated BART controls. The WRAP 

CMAQ modeling results were used to 

identify the extent of visibility 

improvement from the baseline by 

pollutant for each Class I area. 

a. EPA’s Use of WRAP Visibility 

Modeling 

We are relying on modeling 

performed by WRAP. The primary tool 

WRAP relied upon for modeling 

regional haze improvements by 2018, 

and for estimating Montana’s RPGs, was 

the CMAQ model. The CMAQ model 

was used to estimate 2018 visibility 

conditions in Montana and all western 

Class I areas, based on application of 

anticipated regional haze strategies in 

the various states’ regional haze plans, 

including assumed controls on BART 

sources. 

The RMC at the University of 

California Riverside conducted the 

CMAQ modeling under the oversight of 

the WRAP Modeling Forum. The RMC 

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 regional haze 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 2007. A 

more detailed description of the 

inventories can be found in the 

following documents that are included 

in the docket.213 All emission 

inventories were spatially and 

temporally allocated using the SMOKE 

modeling system. Each of these 

inventories underwent a number of 

revisions throughout the development 

process to arrive at the final versions 

used in CMAQ modeling.214

b. EPA’s Reasonable Progress ‘‘FourFactor’’ Analysis 

In determining the measures 

necessary to make reasonable progress 

and in selecting RPGs for mandatory 

Class I areas within Montana, we must 

take into account the following four 

factors and demonstrate how they were 

taken into consideration: 

• 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 

51.308(d)(1)(i)(A). 

As the purpose of the reasonable 

progress analysis is to evaluate the 

potential of controlling certain sources 

or source categories for addressing 

visibility from manmade sources, our 

four-factor analysis addresses only 

anthropogenic sources, on the 

assumption that the focus should be on 

sources that can be ‘‘controlled.’’ 

As explained previously, WRAP 

developed emission inventories for 11 

source categories and we are proposing 

to use this analysis to identify sources 

that should be evaluated for further 

control. Specifically, we identified those 

source categories that, based on the 

inventories, contribute the most to 

emissions of visibility impairing 

pollutants and for which there are not 

adequate controls. The visibility 

impairing pollutants we considered are 

primary organic aerosol, EC, PM2.5, 

PM10, SO2, and NOX. 

Tables 150 through 154 provide the 

statewide 2002 baseline primary organic 

aerosol, EC, PM2.5 and PM10 emissions 

and percentage contribution from the 

eleven source categories evaluated by 

WRAP. 

TABLE 150—MONTANA PRIMARY ORGANIC AEROSOL EMISSION INVENTORY—2002 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Point ......................................................................................................................................................................... 101 <1 

Anthropogenic Fire .................................................................................................................................................. 3,745 8 

Natural Fire .............................................................................................................................................................. 38,324 80 

Biogenic ................................................................................................................................................................... 0 0 

Area ......................................................................................................................................................................... 2,788 6 

Area Oil and Gas ..................................................................................................................................................... 0 0 

On-Road Mobile ....................................................................................................................................................... 455 1 

Off-Road Mobile ....................................................................................................................................................... 718 2 

Road Dust ................................................................................................................................................................ 1,271 3 

Fugitive Dust ............................................................................................................................................................ 687 1 

Wind Blown Dust ..................................................................................................................................................... 0 0 

Total .................................................................................................................................................................. 48,089 ........................

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24056 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

TABLE 151—MONTANA ELEMENTAL CARBON EMISSION INVENTORY—2002 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Point ......................................................................................................................................................................... 17 <1 

Anthropogenic Fire .................................................................................................................................................. 759 6 

Natural Fire .............................................................................................................................................................. 7,743 65 

Biogenic ................................................................................................................................................................... 0 0 

Area ......................................................................................................................................................................... 413 3 

Area Oil and Gas ..................................................................................................................................................... 0 0 

On-Road Mobile ....................................................................................................................................................... 519 4 

Off-Road Mobile ....................................................................................................................................................... 2,288 19 

Road Dust ................................................................................................................................................................ 89 <1 

Fugitive Dust ............................................................................................................................................................ 47 <1 

Wind Blown Dust ..................................................................................................................................................... 0 0 

Total .................................................................................................................................................................. 11,873 ........................

TABLE 152—MONTANA FINE PARTICULATE MATTER EMISSION INVENTORY—2002 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Point ......................................................................................................................................................................... 182 <1 

Anthropogenic Fire .................................................................................................................................................. 279 <1 

Natural Fire .............................................................................................................................................................. 2,911 4 

Biogenic ................................................................................................................................................................... 0 0 

Area ......................................................................................................................................................................... 2,472 3 

Area Oil and Gas ..................................................................................................................................................... 0 0 

On-Road Mobile ....................................................................................................................................................... 0 0 

Off-Road Mobile ....................................................................................................................................................... 0 0 

Road Dust ................................................................................................................................................................ 21,671 28 

Fugitive Dust ............................................................................................................................................................ 13,276 17 

Wind Blown Dust ..................................................................................................................................................... 36,448 47 

Total .................................................................................................................................................................. 77,239 ........................

TABLE 153—MONTANA COARSE PARTICULATE MATTER EMISSION INVENTORY—2002 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Point ......................................................................................................................................................................... 7,818 1 

Anthropogenic Fire .................................................................................................................................................. 713 <1 

Natural Fire .............................................................................................................................................................. 8,496 1 

Biogenic ................................................................................................................................................................... 0 0 

Area ......................................................................................................................................................................... 706 <1 

Area Oil and Gas ..................................................................................................................................................... 0 0 

On-Road Mobile ....................................................................................................................................................... 270 <1 

Off-Road Mobile ....................................................................................................................................................... 0 0 

Road Dust ................................................................................................................................................................ 206,863 33 

Fugitive Dust ............................................................................................................................................................ 68,373 11 

Wind Blown Dust ..................................................................................................................................................... 328,036 53 

Total .................................................................................................................................................................. 621,276 ........................

As indicated, point sources contribute 

less than 1% to primary organic aerosol 

emissions, less than 1% to EC 

emissions, less than 1% to fine 

particulate, and 1% to coarse particulate 

emissions. Also, BART modeling that 

we conducted tends to indicate that PM 

emissions from point sources have the 

potential to contribute only a minimal 

amount to the visibility impairment in 

the Montana Class I areas. Since the 

contribution from point sources to 

primary organic aerosols, EC, PM2.5 and 

PM10 is very small, and modeling tends 

to show that PM emissions from point 

sources do not have a very large impact, 

we are proposing that additional 

controls on point sources for primary 

organic aerosols, EC, PM2.5 and PM10 are 

not necessary for this planning period. 

We next consider other sources of these 

pollutants. 

Anthropogenic fire contributes 8% to 

primary organic aerosol emissions, 6% 

to EC emissions, less than 1% to PM2.5

emissions and less than 1% to PM10

emissions. Anthropogenic fire emissions 

are controlled through Montana’s 

visibility SIP, which we propose for 

approval as addressing one of the 

required LTS factors, Agricultural and 

Forestry Smoke Management 

Techniques, in section V.D.6.f.v . 

Natural fire contributes 80% to primary 

organic aerosol emissions, 65% to EC 

emissions, 4% to PM2.5 emissions, and 

1% to PM10 emissions. Natural fires are 

considered uncontrollable. In summary, 

we are proposing that additional 

controls for primary organic aerosols, 

EC, PM2.5 and PM10 from anthropogenic 

fire are not necessary for this planning 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24057 

period. We also are proposing that 

natural fires do not need to be addressed 

because they are not man-made. 

Area sources contribute only 6% to 

primary organic aerosol emissions, 3% 

to EC emissions, 3% to PM2.5 emissions, 

and less than 1% to PM10 emissions. We 

are proposing that because area sources 

have such a small contribution to the 

emissions inventory, additional controls 

for primary organic aerosols, EC, PM2.5

and PM10 from area sources are not 

necessary for this planning period. 

On-road mobile sources contribute 

only 1% to primary organic aerosol 

emissions, 4% to EC emissions, and less 

than 1% to PM10 emissions. Off-road 

mobile sources contribute 2% to 

primary organic aerosol emissions and 

19% to EC emissions. Both on-road and 

off-road mobile sources will benefit 

from fleet turnover to cleaner vehicles 

resulting from more stringent federal 

emission standards. Since emissions are 

expected to decrease as newer vehicles 

replace older ones, we are proposing 

that additional controls for primary 

organic aerosols, EC, PM2.5 and PM10

from on-road and off-road vehicles are 

not necessary during this planning 

period. 

Emissions from road dust contribute 

3% to primary organic aerosol 

emissions, less than 1% to EC 

emissions, 28% to PM2.5 emissions and 

33% to PM10 emissions. Wind-blown 

dust contributes 47% to fine particulate 

emissions and 53% to PM10 emissions. 

Road dust and wind-blown dust are 

regulated by the State’s ARM 17.8.308, 

Particulate Matter, Airborne. This 

regulation, which is approved into 

Montana’s SIP, establishes an opacity 

limit of 20% and also requires 

reasonable precautions to be taken to 

control emissions of airborne PM from 

the production, handling, 

transportation, or storage of any 

material. It also requires reasonable 

precautions to be taken to control 

emissions of airborne PM from streets, 

roads, and parking lots. In addition, in 

any nonattainment area, this regulation 

requires Reasonable Available Control 

Technology for existing sources, BACT 

for new sources with a potential to emit 

less than 100 tpy, and Lowest 

Achievable Emission Rates for new 

sources that have the potential to emit 

more than 100 tpy. Finally, this 

regulation requires operators of a 

construction site to take reasonable 

precautions to control emissions of 

airborne PM at construction and 

demolition sites and it establishes a 

20% opacity limit for emissions of 

airborne pollutants at these sites. The 

measures to mitigate the impact of 

construction activities are included as 

one of the required LTS factors in 

section V.D.6.f.ii. We are proposing that 

the existing rules at ARM 17.8.308 are 

sufficient to control emissions of OC, 

EC, PM2.5 and PM10 and that additional 

controls for primary organic aerosols, 

EC, PM2.5 and PM10 from road dust, 

fugitive dust, and windblown dust are 

not necessary for this planning period. 

Table 154 provides the Statewide 

baseline SO2 emissions and percentage 

contribution to the total SO2 emissions 

in Montana. 

TABLE 154—MONTANA SO2 EMISSION INVENTORY—2002 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Point ......................................................................................................................................................................... 36,887 71 

Anthropogenic Fire .................................................................................................................................................. 500 1 

Natural Fire .............................................................................................................................................................. 4,634 9 

Biogenic ................................................................................................................................................................... 0 0 

Area ......................................................................................................................................................................... 3,236 6 

Area Oil and Gas ..................................................................................................................................................... 225 <1 

On-Road Mobile ....................................................................................................................................................... 1,836 4 

Off-Road Mobile ....................................................................................................................................................... 4,552 9 

Road Dust ................................................................................................................................................................ 11 <1 

Fugitive Dust ............................................................................................................................................................ 13 <1 

Wind Blown Dust ..................................................................................................................................................... 0 0 

Total .................................................................................................................................................................. 51,923 ........................

As indicated, 71% of total Statewide 

SO2 emissions are from point sources, 

6% are from area sources and less than 

1% are from area oil and gas sources. 

Emissions from anthropogenic fire 

contribute 1% and emissions from 

natural fire contribute 9% to Statewide 

SO2 emissions. Anthropogenic fire 

emissions are controlled through 

Montana’s Visibility SIP, which is 

further described as one of the required 

LTS factors, Agricultural and Forestry 

Smoke Management Techniques, in 

V.D.6.f.v. SO2 emissions from natural 

fires (9%) are considered 

uncontrollable. On-road mobile sources 

contribute 4% and off-road sources 

contribute 9% to Statewide SO2

emissions. Both off-road and on-road 

mobile sources are subject to federal 

ultra-low sulfur diesel fuel requirements 

that limit sulfur content to 15 ppm 

(0.0015%), which was in widespread 

use after June 2010 for off-road mobile 

and June 2006 for on-road mobile. Road 

dust, fugitive dust and windblown dust 

comprise less than 1% of Statewide 

emissions. We are proposing that point 

sources are the dominant source of 

emissions and, for this planning period, 

the only category necessary to evaluate 

further under reasonable progress for 

SO2. 

Table 155 provides the Statewide 

baseline NOX emissions and percentage 

contribution to the total NOX emissions 

in Montana. 

TABLE 155—MONTANA NOX EMISSION INVENTORY—2002 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Point ......................................................................................................................................................................... 53,416 22 

Anthropogenic Fire .................................................................................................................................................. 1,513 <1 

Natural Fire .............................................................................................................................................................. 13,770 6 

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24058 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

215The relevant language in our BART Guidelines 

reads, ‘‘Based on our analyses, we believe that a 

State that has established 0.5 deciviews as a 

contribution threshold could reasonably exempt 

from the BART review process sources that emit 

less than 500 tpy of NOX or SO2 (or combined NOX

and SO2), as long as these sources are located more 

than 50 kilometers from any Class I area; and 

sources that emit less than 1000 tpy of NOX or SO2

(or combined NOX and SO2) that are located more 

than 100 kilometers from any Class I area.’’ (See 40 

CFR part 51, appendix Y, section III, How to 

Identify Sources ‘‘Subject to BART.’’) The values 

described equate to a Q/D of 10. 

TABLE 155—MONTANA NOX EMISSION INVENTORY—2002—Continued 

Source category Baseline 2002 

(tpy) 

Percentage of 

total 

Biogenic ................................................................................................................................................................... 58,353 24 

Area ......................................................................................................................................................................... 4,292 2 

Area Oil and Gas ..................................................................................................................................................... 7,557 3 

On-Road Mobile ....................................................................................................................................................... 53,597 22 

Off-Road Mobile ....................................................................................................................................................... 50,604 21 

Road Dust ................................................................................................................................................................ 25 <1 

Fugitive Dust ............................................................................................................................................................ 14 <1 

Wind Blown Dust ..................................................................................................................................................... 0 0 

Total .................................................................................................................................................................. 24,314 ........................

As indicated, 22% of total Statewide 

NOX emissions are from point sources. 

Emissions from anthropogenic fire 

contribute less than 1% and emissions 

from natural fire contribute 6% to 

Statewide NOX emissions. Agricultural 

and Forestry smoke management 

techniques are discussed in section 

V.D.6.f.v as one of the mandatory LTS 

factors required to be considered. 

Emissions from natural fires are 

considered uncontrollable. Emissions 

from biogenic sources contribute 24% 

and also are considered uncontrollable. 

Emissions from area sources contribute 

only 2% and emissions from area oil 

and gas sources contribute only 3% of 

statewide emissions. Emissions from onroad mobile sources contribute 22% and 

emissions from off-road mobile sources 

contribute 21% to Statewide NOX

emissions. Both on-road and off-road 

mobile sources will benefit from fleet 

turnover to cleaner vehicles resulting 

from more stringent federal emission 

standards. We are proposing that point 

sources are the dominant source of 

emissions not already being addressed 

and, for this planning period, the only 

category necessary to evaluate further 

under reasonable progress for NOX. 

To identify the point sources in 

Montana that potentially affect visibility 

in Class I areas, we started with the list 

of sources included in the 2002 NEI, 

except that for Colstrip Units 3 and 4 we 

used data from 2010. For Colstrip, we 

included only the emissions for Units 3 

and 4 because Units 1 and 2 are subject 

to BART. Also, a consent decree signed 

in 2007 required upgraded combustion 

controls on Units 3 and 4. The year 2010 

was the first full year that the upgraded 

combustions controls were operational 

for both units. 

We divided the actual emissions (Q) 

in tpy from each source in the inventory 

by their distance (D) in kilometers to the 

nearest Class I Federal area. We are 

proposing to use a Q/D value of 10 as 

our threshold for further evaluation for 

RP controls. We chose this value based 

on the FLMs’ Air Quality Related Values 

Work Group guidance amendments for 

initial screening criteria, as well as 

statements in EPA’s BART 

Guidelines.215 A comprehensive list of 

the sources we reviewed is included in 

the docket as a spreadsheet titled, 

‘‘Montana Q Over D Analysis.’’ The 

sources with Q/D results greater than 10 

are listed below in Table 156. 

TABLE 156—MONTANA Q/D ANALYSIS SOURCES WITH RESULTS GREATER THAN 10 

Source 

SO2 + NOX

emissions 

(tons) 

Distance to 

nearest class I 

area 

(km) 

Q/D 

(tons/km) 

PPL Montana, LLC Colstrip Steam Electric Station (Units 3 and 4) .......................................... 15,754 193 82 

Plum Creek Manufacturing .......................................................................................................... 1,067 13 82 

Ash Grove Cement Company ..................................................................................................... 2,060 31 66 

Columbia Falls Aluminum Company, LLC .................................................................................. 591 10 59

ExxonMobil Refinery & Supply Company, Billings Refinery ....................................................... 6,313 161 39 

PPL Montana, LLC—JE Corette Steam Electric Station ............................................................ 4,838 136 36 

Smurfit Stone Container Enterprises Inc., Missoula Mill ............................................................. 1,315 41 32

Montana-Dakota Utilities Company Lewis and Clark Station ..................................................... 1,576 54 29 

Cenex Harvest States Cooperatives Laurel Refinery ................................................................. 3,038 161 19 

Holcim (US), Inc. ......................................................................................................................... 1,783 97 18 

Montana Sulphur and Chemical .................................................................................................. 2,408 161 15 

Yellowstone Energy Limited Partnership ..................................................................................... 1,928 141 14 

Roseburg Forest Products ........................................................................................................... 518 44 12 

Devon Energy Production Company, LP, Blaine County #1 Compressor Station ..................... 1,155 107 11 

Colstrip Energy Limited Partnership ............................................................................................ 1,242 117 11 

Montana Refining ......................................................................................................................... 774 77 10 

Conoco Phillips ............................................................................................................................ 1,323 136 10 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24059 

216Response to Request for Information for the 

Colstrip Energy Limited Partnership Facility 

Pursuant to Section 114(a) of the Clean Air Act (42 

U.S.C. Section 7414(A) (‘‘CELP Initial Response’’), 

Rosebud Energy Corp. (Mar. 11, 2009); Response to 

Additional Reasonable Progress Information for the 

Colstrip Energy Limited Partnership Facility 

Pursuant to Section 114(a) of the Clean Air Act (42 

U.S.C. Section 7414(A)) (‘‘CELP Additional 

Response’’), Rosebud Energy Corp., Prepared by 

Bison Engineering Inc (Feb. 24, 2011). 217CELP Additional Response, p. 2–1. 218CELP Additional Response, p. 2–2. 

For the reasons described below, we 

eliminated from further consideration 

several sources that met the Q/D 

criteria. 

We are eliminating the four refineries 

from further consideration as a result of 

consent decrees entered into by the 

owners. Under these consent decrees, 

emissions have been reduced 

sufficiently after the 2002 baseline so 

that the Q/D for each facility is below 

10. Specifically, ExxonMobil’s 

emissions in 2008 of NOX and SO2 were 

1,019 tpy, resulting in a Q/D of 6. 

Cenex’s emissions in 2008 of NOX and 

SO2 were 727 tpy, resulting in a Q/D of 

5. Conoco’s emissions in 2008 of NOX

and SO2 were 1,087 tpy, resulting in a 

Q/D of 8. Montana Refining’s emissions 

in 2008 of NOX and SO2 were 122 tpy, 

resulting in a Q/D of 2. The consent 

decrees are available in the docket. 

We eliminated from further 

discussion the following sources 

because they were evaluated under 

BART: Colstrip Units 1 and 2, Ash 

Grove Cement, CFAC, PPL Montana JE 

Corette, and Holcim US Incorporated, 

Trident Plant. As the BART analysis is 

based, in part, on an assessment of 

many of the same factors that are 

addressed under RP or RPGs, we 

propose that the BART control 

requirements for these facilities also 

satisfy the requirements for reasonable 

progress for the facilities for this 

planning period. 

We undertook a more detailed 

analysis of the remaining sources that 

exceeded a Q/D of 10. These sources are 

shown below in Table 157. 

TABLE 157—SOURCES FOR REASONABLE PROGRESS FOUR-FACTOR ANALYSES

Source 

SO2 + NOX

Emissions 

(tons) 

Distance to 

nearest class I 

area 

(km) 

Q/D 

(tons/km) 

PPL Montana, LLC Colstrip Steam Electric Station (Units 3 and 4) .......................................... 15,754 193 82 

Plum Creek Manufacturing .......................................................................................................... 1,067 13 82 

Smurfit Stone Container Enterprises Inc., Missoula Mill ............................................................. 1,315 41 32

Montana Dakota Utilities Company Lewis and Clark Station ..................................................... 1,576 54 29 

Montana Sulphur and Chemical .................................................................................................. 2,408 161 15 

Yellowstone Energy Limited Partnership ..................................................................................... 1,928 141 14 

Roseburg Forest Products ........................................................................................................... 518 44 12 

Devon Energy Production Company, LP Blaine County #1 Compressor Station ...................... 1,155 107 11 

Colstrip Energy Limited Partnership ............................................................................................ 1,242 117 11 

c. Four Factor Analyses for Point 

Sources 

The BART Guidelines recommend 

that states utilize a five-step process for 

determining BART for sources that meet 

specific criteria. In proposing a FIP we 

are considering this recommendation 

applicable to us as it would be 

applicable to a state. Although this fivestep process is not required for making 

RP determinations, we have elected to 

largely follow it in our RP analysis 

because there is some overlap in the 

statutory BART and RP factors and 

because it provides a reasonable 

structure for evaluating potential control 

options. 

We requested a four factor analysis 

from each RP source and our analysis 

has taken that information into 

consideration. 

i. Colstrip Energy Limited Partnership 

Colstrip Energy Limited Partnership 

(CELP) submitted analysis and 

supporting information on March 11, 

2009 and February 24, 2011.216

CELP in partnership with Rosebud 

Energy Corporation, owns the Rosebud 

Power Plant, operated by Rosebud 

Operating Services. The plant is rated at 

43 MWs gross output (38 MWs net). The 

primary source of emissions consists of 

a single circulating fluidized bed (CFB) 

boiler, fired on waste coal. The boiler 

and emission controls were installed in 

1989–90. 

PM emissions are controlled by a 

fabric filter baghouse that is designed to 

achieve greater than 99% control of 

particulates.217 As discussed previously 

in Section V.D.6.b., the contribution 

from point sources to primary organic 

aerosols, EC, PM2.5 and PM10 at Montana 

Class I areas is very small, and modeling 

tends to confirm that PM emissions 

from point sources do not have a very 

large impact. Therefore, we are 

proposing that additional controls for 

PM are not necessary for this planning 

period. 

SO2

The current SO2 control consists of 

limestone injection with waste coal 

prior to its combustion in the boiler. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies are available: limestone 

injection process upgrade, SDA, DSI, a 

circulating dry scrubber (CDS), hydrated 

ash reinjection (HAR), a wet lime 

scrubber, a wet limestone scrubber, and/ 

or a dual alkali scrubber. 

CELP currently controls SO2

emissions using limestone injection. 

Crushed limestone is injected with the 

waste coal prior to its combustion in the 

boiler, becoming the solid medium in 

which coal combustion takes place. 

When limestone is heated to 1550°F, it 

releases CO2 and forms lime, which 

subsequently reacts with acid gases 

released from the burning coal, to form 

calcium sulfates and calcium sulfites. 

The calcium compounds are removed as 

PM by the baghouse. Depending on the 

fuel fired in the boiler and the total heat 

input, this process currently removes 

70% to 90% of SO2 emissions, on 

average about 80%. Increasing the 

limestone injection rate beyond current 

levels could theoretically result in a 

modest increase in SO2 control.218

SDAs use lime slurry and water 

injected into a tower to remove SO2

from the combustion gases. The towers 

must be designed to provide adequate 

contact and residence time between the 

exhaust gas and the slurry in order to 

produce a relatively dry by-product. The 

process equipment associated with an 

SDA typically includes an alkaline 

storage tank, mixing and feed tanks, 

atomizer, spray chamber, particulate 

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24060 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

219US EPA Region 8, Final Statement of Basis, 

PSD Permit to Construct, Deseret Power Elec. Coop., 

Bonanza Power Plant (‘‘Deseret Bonanza SOB’’), p. 

92 (Aug. 30, 2007), available at http://www.epa.gov/ 

region8/air/pdf/FinalStatementOfBasis.pdf. 

220 Id. 

221 Id., p. 93. 

222 Id., p. 94 (for proposed CFB boiler, indicating 

that a wet FGD scrubber plus limestone injection 

can achieve 99.1% control efficiency). 

223CELP Additional Response, p. 2–2. 

224 Deseret Bonanza SOB, p. 92 (indicating that 

CDS systems have thus far not been used on CFB 

boilers). 

225 Id., p. 93. 

control device, and recycle system. The 

recycle system collects solid reaction 

product and recycles it back to the spray 

dryer feed system to reduce alkaline 

sorbent use. SDAs are the commonly 

used dry scrubbing method in large 

industrial and utility boiler 

applications. SDAs have demonstrated 

the ability to achieve 90% to 94% SO2

reduction. SDA plus limestone injection 

can achieve between 98% and 99% SO2

reduction.219

DSI was previously described in our 

evaluation for Corette. SO2 control 

efficiencies for DSI systems by 

themselves (not downstream of 

limestone injection systems) are 

approximately 50%, but if the sorbent is 

hydrated lime, then 80% or greater 

removal can be achieved. These systems 

are commonly called lime spray dryers. 

A CDS uses a fluidized bed of dry 

hydrated lime reagent to remove SO2. 

Flue gas passes through a venturi at the 

base of a vertical reactor tower and is 

humidified by a water mist. The 

humidified flue gas then enters a 

fluidized bed of powdered hydrated 

lime where SO2 is removed. The dry byproduct produced by this system is 

routed with the flue gas to the 

particulate removal system. A CDS can 

achieve removal efficiency similar to 

that achieved by SDA on CFB boilers.220

The HAR process is a modified dry 

FGD process developed to increase the 

use of unreacted lime in the CFB ash 

and any free lime left from the furnace 

burning process. HAR will further 

reduce the SO2 concentration in the flue 

gas. The actual design of an HAR system 

is vendor-specific, but in general, a 

portion of the collected ash and lime is 

hydrated and re-introduced into a 

reaction vessel located ahead of the 

fabric filter inlet. In conventional boiler 

applications, additional lime may be 

added to the ash to increase the 

mixture’s alkalinity. For CFB 

applications, sufficient residual lime is 

available in the ash and additional lime 

is not required. HAR downstream of a 

CFB boiler that utilizes limestone 

injection can reduce the remaining SO2

by about 80%.221

The wet lime scrubbing process uses 

alkaline slurry made by adding CaO to 

water. The alkaline slurry is sprayed 

into the exhaust stream and reacts with 

the SO2 in the flue gas. Insoluble 

calcium sulfite (CaSO3) and calcium 

sulfate (CaSO4) salts are formed in the 

chemical reaction that occurs in the 

scrubber. The salts are removed as a 

solid waste by-product. 

Wet lime and wet limestone scrubbers 

involve spraying alkaline slurry into the 

exhaust gas to react with SO2 in the flue 

gas. The reaction in the scrubber forms 

insoluble salts that are removed as a 

solid waste by-product. Wet lime and 

limestone scrubbers are very similar, but 

the type of additive used differs (lime or 

limestone). Using limestone (CaCO3) 

instead of lime requires different feed 

preparation equipment and a higher 

liquid-to-gas ratio. The higher liquid-togas ratio typically requires a larger 

absorbing unit. The limestone slurry 

process also requires a ball mill to crush 

the limestone feed. Wet lime and 

limestone scrubbers have been 

demonstrated to achieve greater than 

99% control efficiency.222

Dual-alkali scrubbers use a sodiumbased alkali solution to remove SO2

from the combustion exhaust gas. The 

process uses both sodium-based and 

calcium-based compounds. The sodiumbased reagents absorb SO2 from the 

exhaust gas, and the calcium-based 

solution (lime or limestone) regenerates 

the spent liquor. Calcium sulfites and 

sulfates are precipitated and discarded 

as sludge, and the regenerated sodium 

solution is returned to the absorber 

loop. The dual-alkali process requires 

lower liquid-to-gas ratios than scrubbing 

with lime or limestone. The reduced 

liquid-to-gas ratios generally mean 

smaller reaction units; however, 

additional regeneration and sludge 

processing equipment is necessary. 

A sodium-based scrubbing solution, 

typically consisting of a mixture of 

sodium hydroxide, sodium carbonates, 

and sodium sulfite, is an efficient SO2

control reagent. However, the process 

generates a sludge that can create 

material handling and disposal issues. 

The control efficiency is similar to the 

wet lime/limestone scrubbers at 

approximately 95% or greater. 

Step 2: Eliminate Technically Infeasible 

Options 

The current limestone injection 

system is operating at or near its 

maximum capacity. The boiler feed 

rates are approximately 770 tons/day of 

waste coal and 91 tons/day of limestone. 

Increasing limestone injection beyond 

the current levels would result in 

plugging of the injection lines, and 

increased bed ash production, which 

can reduce combustion efficiency, and 

increased particulate loading to the 

baghouses. Therefore, increasing 

limestone injection beyond its current 

level would require major upgrades to 

the limestone feeding system and the 

baghouses.223 Only modest increases in 

SO2 removal efficiency, if any, are 

expected with this scenario, compared 

to add-on SO2 control systems discussed 

below. Therefore, a limestone injection 

process upgrade is eliminated from 

further consideration. 

CDS systems result in high particulate 

loading to the unit’s particulate control 

device. Because of the high particulate 

loading, the pressure drop across a 

fabric filter would be unacceptable; 

therefore, ESPs are generally used for 

particulate control. CELP has a high 

efficiency fabric filter (baghouse) in 

place. Based on limited technical data 

from non-comparable applications and 

engineering judgment, we are 

determining that CDS is not technically 

feasible for this baghouse-equipped 

facility.224 Therefore, CDS is eliminated 

from further consideration. 

A DSI system is not practical for use 

in a CFB boiler such as CELP, where 

limestone injection is already being 

used upstream in the boiler for SO2

control. With limestone injection, the 

CFB boiler flue gas already contains 

excess unreacted lime. Fly ash 

containing this unreacted lime is 

reinjected back into the CFB boiler 

combustion bed, as part of the boiler 

operating design. A DSI system would 

simply add additional unreacted lime to 

the flue gas and would achieve little, if 

any, additional SO2 control.225 If used 

instead of limestone injection (the only 

practical way it might be used), DSI 

would achieve less control efficiency 

(50%) than the limestone injection 

system already being used (70% to 

90%). Therefore, DSI is eliminated from 

further consideration. 

Regarding wet scrubbing, there is 

limited area to install additional SO2

controls that would require high 

quantities of water and dewatering 

ponds. The wet FGD scrubber systems 

with the higher water requirements (wet 

lime scrubber, wet limestone scrubber, 

dual alkali wet scrubber) would require 

an on-site dewatering pond or an 

additional landfill to dispose of 

scrubber sludge. Due to the limited 

available space, its proximity to the East 

Armels Creek to the east of the plant, an 

unnamed creek to the south of the plant, 

and limited water availability for these 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24061 

226CELP Additional Response, p. 2–5. 

227CELP Additional Response, Appendix A, pp. 

17–24. 

228Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

229CELP Additional Response, p. 3–1. 

230 Id., p. 4–1. 

231 Id. 

controls,226 we consider these 

technologies technically infeasible and 

do not evaluate them further. 

The remaining technically feasible 

SO2 control options for CELP are SDA 

and HAR. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline SO2 emissions from CELP are 

1141 tpy. A summary of emissions 

projections for the various control 

options is provided in Table 158. Since 

limestone injection is already in use at 

the CELP facility, the control 

efficiencies and emissions reductions 

shown below are those that might be 

achieved beyond the control already 

being achieved by the existing limestone 

injection system. 

TABLE 158—SUMMARY OF CELP SO2 REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

tpy 

Remaining 

emissions 

tpy 

SDA .................................................................................................................................. 80 913 228 

HAR ................................................................................................................................. 50 571 570 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Table 159 provides a summary of 

estimated annual costs for the various 

control options. 

TABLE 159—SUMMARY OF CELP SO2 REASONABLE PROGRESS COST ANALYSIS

Control option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

SDA with baghouse replacement .................................................................................................................... 4,419,472 4,840 

SDA without baghouse replacement ............................................................................................................... 3,138,450 3,437 

HAR with baghouse replacement .................................................................................................................... 3,384,565 5,927 

HAR without baghouse replacement ............................................................................................................... 2,103,543 3,684 

We are relying on the control costs 

provided by CELP,227 with two 

exceptions. First, we calculated the 

annual cost of capital using a 7% annual 

interest rate and a 20-year equipment 

life (which yields a capital CRF of 

0.0944), as specified in the Office of 

Management and Budget’s Circular A–4, 

Regulatory Analysis.228 Second, we 

calculated the cost of SDA and HAR in 

two ways: (1) With baghouse 

replacement, and (2) without baghouse 

replacement. 

Factor 2: Time Necessary for 

Compliance 

We have relied on CELP’s estimates 

that the time necessary to complete the 

modifications to the boiler to 

accommodate SDA or HAR, without 

baghouse replacement, would be 

approximately four to six months and 

that a boiler outage of approximate two 

to three months would be necessary to 

perform the installation of either 

system. As noted previously, CELP 

states that complete replacement or 

major modifications to the existing 

baghouse would be necessary; however, 

the company does not explain why the 

existing baghouse would need to be 

replaced or modified to accommodate 

SDA or HAR.229

Factor 3: Energy and Non-air Quality 

Environmental Impacts of Compliance 

Wet FGD systems are estimated to 

consume 1% to 2.5% of the total electric 

generation of the plant and can consume 

approximately 40% more than dry FGD 

systems (SDA). Electricity requirements 

for a HAR system are less than FGD 

systems. DSI systems are estimated to 

consume 0.1% to 0.5% of the total plant 

generation.230 For reasons explained 

above, wet FGD systems and DSI 

systems have already been eliminated as 

technically infeasible. 

SO2 controls would result in 

increased ash production at the CELP 

facility. Boiler ash is currently either 

sent to a landfill or sold for beneficial 

use, such as oil well reclamation. 

Changes in ash properties due to 

increased calcium sulfates and calcium 

sulfites could result in the ash being no 

longer suitable to be sold for beneficial 

uses. If the ash properties were to 

change such that the ash could no 

longer be sold for beneficial use, the loss 

of this market would cost approximately 

$1,020,000 per year at the current ash 

value and production rates 

(approximately 100,000 tons of ash per 

year). The loss of this market could also 

result in the company having to dispose 

of the ash at its current landfill, which 

is adjacent to the plant. The cost to 

dispose of the ash would be 

approximately $62,000 per year. The 

total cost from the loss of the beneficial 

use market and the increase in ash 

disposal costs would be a total of 

$1,082,000 per year.231 This potential 

cost has not been included in the cost 

described above, as it is only 

speculative, being based on an 

undetermined potential future change in 

ash properties. 

As described above, wet FGD scrubber 

systems with the higher water 

requirements (wet lime scrubber, wet 

limestone scrubber, dual alkali wet 

scrubber) would require an on-site 

dewatering pond or an additional 

landfill to dispose of scrubber sludge. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24062 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

232 Deseret Bonanza SOB, p. 46. 

233US EPA, Office of Air Quality Planning and 

Standards, Technical Bulletin: Nitrogen Oxides 

(NOX), Why and How They Are Controlled, EPA– 

456/F–99–006R, p. 19 (Nov. 1999), available at 

http://www.epa.gov/ttn/catc/dir1/fnoxdoc.pdf. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: the cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

source. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. 

Given the cost of $3,437 per ton of SO2

(at a minimum) for the most costeffective option (SDA), the relatively 

small size of CELP, and the small 

baseline Q/D of 11, we find it reasonable 

to not impose any of the SO2 control 

options. We therefore propose to not 

require additional SO2 controls for this 

planning period. 

NOX

Currently, there are no NOX controls 

at the CELP facility. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available: SCR, 

SNCR, low excess air (LEA), FGR, OFA, 

LNB, non-thermal plasma reactor, and 

carbon injection into the combustion 

chamber. 

SCR uses either NH3 or urea in the 

presence of a metal-based catalyst to 

selectively reduce NOX emissions. 

Technical factors that impact the 

effectiveness of SCR include the catalyst 

reactor design, operating temperature, 

type of fuel fired, sulfur content of the 

fuel, design of the NH3 injection system, 

and the potential for catalyst poisoning. 

SCR has been demonstrated to 

achieve high levels of NOX reduction in 

the range of 80% to 90% control, for a 

wide range of industrial combustion 

sources, including PC and stoker coalfired boilers and natural gas-fired 

boilers and turbines. Typically, 

installation of the SCR is upstream of 

the particulate control device (e.g., 

baghouse). However, calcium oxide 

(from a dry scrubber) in the exhaust 

stream can cause the SCR catalyst to 

plug and foul, which would lead to an 

ineffective catalyst. 

SCRs are classified as low dust SCR 

(LDSCR) or high dust SCR (HDSCR). 

LDSCR is usually applied to natural gas 

combustion units or after a particulate 

control device. HDSCR units can be 

installed on solid fuel combustion units 

before the particulate control device, but 

they have their limitations. Installation 

of SCR in a low dust flue gas stream is 

often not practical, especially on an 

existing boiler. The reason is that the 

low dust portion of a flue gas stream is 

located after a baghouse or precipitator. 

The temperature of the flue gas stream 

is too low in these areas for proper 

operation of SCR. The temperature 

range for proper operation of SCR is 

between 480 °F and 800 °F. Many of the 

CFBs in the United States have 

baghouses for particulate control. The 

normal maximum allowable 

temperature for a baghouse is 400 °F. 

Therefore, on some installations, 

regenerative SCR (RSCR) is installed. 

RSCRs are expensive to install and 

expensive to operate, because an RSCR 

requires the use of burners to heat up 

the flue gas stream in order for the NOX

capture to occur. This is often an 

efficiency decrease for the boiler, 

significant increase in operating cost, 

and often not a practical solution. For 

this reason, RSCR was not evaluated as 

a control option for CELP. Instead, 

HDSCR was evaluated. 

In SNCR systems, a reagent such as 

NH3 or urea is injected into the flue gas 

at a suitable temperature zone, typically 

in the range of 1,600 to 2,000 °F and at 

an appropriate ratio of reagent to NOX. 

LEA operation involves lowering the 

amount of combustion air to the 

minimum level compatible with 

efficient and complete combustion. 

Limiting the amount of air fed to the 

furnace reduces the availability of 

oxygen for the formation of fuel NOX

and lowers the peak flame temperature, 

which inhibits thermal NOX formation. 

Emissions reductions achieved by LEA 

are limited by the need to have 

sufficient oxygen present for flame 

stability and to ensure complete 

combustion. As excess air levels 

decrease, emissions of carbon monoxide 

(CO), hydrocarbons (HC) and unburned 

carbon increase, resulting in lower 

boiler efficiency. Other impediments to 

LEA operation are the possibility of 

increased corrosion and slagging in the 

upper boiler because of the reducing 

atmosphere created at low oxygen 

levels. 

FGR is a flame-quenching technique 

that involves recirculating a portion of 

the flue gas from the economizers or the 

air heater outlet and returning it to the 

furnace through the burner or windbox. 

The primary effect of FGR is to reduce 

the peak flame temperature through 

absorption of the combustion heat by 

relatively cooler flue gas. FGR also 

serves to reduce the oxygen 

concentration in the combustion zone. 

OFA allows staged combustion by 

supplying less than the stoichiometric 

amount of air theoretically required for 

complete combustion through the 

burners. The remaining necessary 

combustion air is injected into the 

furnace through overfire air ports. 

Having an oxygen-deficient primary 

combustion zone in the furnace lowers 

the formation of fuel NOX. In this 

atmosphere, most of the fuel nitrogen 

compounds are driven into the gas 

phase. Having combustion occur over a 

larger portion of the furnace lowers peak 

flame temperatures. Use of a cooler, less 

intense flame limits thermal NOX

formation. 

Poorly controlled OFA may result in 

increased CO and hydrocarbon 

emissions, as well as unburned carbon 

in the fly ash. These products of 

incomplete combustion result from a 

decrease in boiler efficiency. OFA may 

also lead to reducing conditions in the 

lower furnace that in turn may lead to 

corrosion of the boiler. 

LNBs use stepwise or staged 

combustion and localized exhaust gas 

recirculation (i.e., at the flame). 

The non-thermal plasma technique 

involves using methane and hexane as 

reducing agents. Non-thermal plasma is 

shown to remove NOX in a laboratory 

setting with a reactor duct only two feet 

long. The reducing agents were ionized 

by a transient high voltage that created 

a non-thermal plasma. The ionized 

reducing agents reacted with NOX

achieving a 94% destruction efficiency, 

and there are indications that an even 

higher destruction efficiency can be 

achieved. A successful commercial 

vendor uses NH3 as a reducing agent to 

react with NOX in an electron beam 

generated plasma.232 Such a short 

reactor can meet available space 

requirements for virtually any plant. 

The non-thermal plasma reactor can 

also be used without a reducing agent to 

generate ozone and use that ozone to 

raise the valence of nitrogen for 

subsequent absorption as nitric acid. 

This control technology may have 

practical potential for application to 

coal-fired CFB boilers as a technology 

transfer option. 

A version of sorbent injection uses 

carbon injected into the air flow to 

finish the capture of NOX. The carbon 

is captured in either the baghouse or the 

ESP, just like other sorbents.233

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24063 

234CELP Additional Response, pp. 2–7, 2–8. 235CELP Additional Response, p. 2–8. 236 Deseret Bonanza SOB, pp. 46, 48. 237CELP Additional Response. 

238Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

239CELP Additional Response, p. 3–1. 

Step 2: Eliminate Technically Infeasible 

Options 

LEA, FGR, and OFA are typically 

used on Pulverized Coal (PC) units and 

cannot be used on CFB boilers due to air 

needed to fluidize the bed.234 While 

LEA may have substantial effect on NOX

emissions at PC boilers, it has much less 

effect on NOX emissions at combustion 

sources such as CFBs that operate at low 

combustion temperatures. FGR reduces 

NOX formation by reducing peak flame 

temperature and is ineffective on 

combustion sources such as CFBs that 

already operate at low combustion 

temperatures. For these reasons, LEA, 

FGR and OFA are eliminated from 

further consideration. 

LNBs are typically used on PC units 

and cannot be used on CFB boilers 

because the combustion occurs within 

the fluidized bed.235 CFB boilers do not 

use burners during normal operation. 

Therefore, LNBs are eliminated from 

further consideration. 

While a non-thermal plasma reactor 

may have practical potential for 

application to coal-fired CFB boilers as 

a technology transfer option at Step 1 of 

the analysis, it is not known to be 

commercially available for CFB 

boilers.236 Therefore, a non-thermal 

plasma reactor is eliminated from 

further consideration. 

Although carbon injection is an 

emerging technology used to reduce 

mercury emissions, it has not been used 

anywhere to control NOX. Therefore, it 

is eliminated from further 

consideration. 

The remaining technically feasible 

NOX control options for CELP are 

HDSCR and SNCR. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions from CELP 

are 768 tpy. A summary of emissions 

projections for the various control 

options is provided in Table 160. 

TABLE 160—SUMMARY OF CELP NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

reduction 

(tpy) 

HDSCR ............................................................................................................................ 80 614 154 

SNCR ............................................................................................................................... 50 384 384 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Table 161 provides a summary of 

estimated annual costs for the various 

control options. 

TABLE 161—SUMMARY OF CELP NOX REASONABLE PROGRESS COST ANALYSIS

Control option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

HDSCR ............................................................................................................................................................ 2,102,189 3,423 

SNCR ............................................................................................................................................................... 584,717 1,523 

We are relying on all the NOX control 

costs provided by CELP,237 with one 

exception. We calculated the annual 

cost of capital using a 7% annual 

interest rate and 20-year equipment life 

(which yields a capital CRF of 0.0944), 

as specified in the Office of 

Management and Budget’s Circular A–4, 

Regulatory Analysis.238

Factor 2: Time Necessary for 

Compliance 

We are relaying on CELP’s estimates 

that SCR would take approximately 26 

months to install and that SNCR would 

take 16 to 24 weeks to install.239

Factor 3: Energy and Non-air Quality 

Environmental Impacts of Compliance 

The energy impacts from SNCR are 

expected to be minimal. SNCR is not 

expected to cause a loss of power output 

from the facility. SCR, however, could 

cause significant backpressure on the 

boiler, leading to lost boiler efficiency 

and, thus, a loss of power production. 

If LDSCR was to be installed instead of 

HDSCR, CELP would be subject to the 

additional cost of reheating the exhaust 

gas. 

Regarding other non-air quality 

environmental impacts of compliance, 

SCRs can contribute to airheater fouling 

from the formation of ammonium 

sulfate. Airheater fouling could reduce 

unit efficiency, increase flue gas 

velocities in the airheater, cause 

corrosion, and erosion. Catalyst 

replacement can lengthen boiler 

outages, especially in retrofit 

installations, where space and access is 

limited. This is a retrofit installation in 

a high dust environment, thus fouling is 

likely, which could lead to unplanned 

outages or less time between planned 

outages. On some installations, catalyst 

life is short and SCRs have fouled in 

high dust environments. For both SCR 

and SNCR, the storage of on-site NH3

could pose a risk from potential releases 

to the environment. An additional 

concern is the loss of NH3, or ‘‘slip’’ into 

the emissions stream from the facility. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24064 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

240Letter from James Parker to Vanessa Hinkle 

regarding Request for Additional Reasonable Progress Information—Colstrip Steam Electric Station Units 3 & 4 (‘‘Colstrip 3 & 4 Additional 

Response’’), Attachment 2, p. 2 (Jan. 31, 2011). 

This ‘‘slip’’ contributes another 

pollutant to the environment, which has 

been implicated as a precursor to PM2.5

formation. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: the cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline 

Q/D of the facility, and the potential 

reduction in Q/D from the controls. 

Based on costs of compliance, the 

relatively small size of CELP, and the 

relatively small baseline Q/D, we 

propose to eliminate the more expensive 

control option (SCR). The more costeffective control option (SNCR) would 

result in a fairly small total reduction in 

emissions (384 tpy). This would 

constitute an approximately 20% 

reduction in overall emissions of SO2 + 

NOX for the facility and a reduction of 

the facility’s Q/D from 11 to 9. Based on 

the cost of compliance, the relatively 

small size of CELP, and the reduction in 

Q/D for SNCR, we find it reasonable to 

not require SNCR. We therefore propose 

to not require additional NOX controls 

for this planning period. 

ii. Colstrip Unit 3 

PPL Montana’s Colstrip Power Plant 

(Colstrip), located in Colstrip, Montana, 

consists of a total of four electric utility 

steam generating unit; however, only 

Units 3 and 4 are being analyzed for 

control options to meet RP requirements 

under the Regional Haze Rule. All 

information found within this section is 

located in the docket. Unit 3, a 

tangentially fired CE boiler which burns 

low sulfur, sub-bituminous northern 

PRB coal, is rated at 805 MW gross 

output. The boiler started operation in 

1984. 

PM emissions are controlled by using 

a wet particulate scrubber that is 

designed to achieve approximately 

99.8% particulate control efficiency.240

As discussed previously in Section 

V.D.6.b., the contribution from point 

sources to primary organic aerosols, EC, 

PM2.5 at Montana Class I areas is very 

small, and modeling tends to confirm 

that PM emissions from point sources 

do not have a very large impact. 

Therefore, we are proposing that 

additional controls for PM are not 

necessary for this planning period. 

Colstrip Unit 3 burns low-sulfur 

(0.7%) coal and has a wet particulate 

scrubber that achieves 95% SO2 control. 

Emissions for the last five years have 

averaged 0.08 lb/MMBtu. The scrubber 

has no provisions for bypass and the 

system includes a spare vessel for the 

unit which is available for use while 

servicing the other vessels. Other 

upgrades to the scrubber are infeasible 

for the same reasons as described in the 

BART determinations for Colstrip Units 

1 and 2. For these reasons, additional 

controls for SO2 will not be considered 

or required in this planning period. We 

now consider controls for NOX. 

Currently, Colstrip Unit 3 has 

installed LNB with SOFA and a Digital 

Process Control System (DPCS). These 

controls reduce NOX emissions by 81%. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available for Colstrip 

Unit 3: SCR and SNCR. These 

technologies have been described in the 

BART determinations for Colstrip Unit 

1. 

Step 2: Eliminate Technically Infeasible 

Options 

We are not eliminating either SCR or 

SNCR as technically infeasible. Thus, 

the technically feasible NOX control 

options for Colstrip Unit 3 are SCR and 

SNCR. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions from Colstrip 

Unit 3 are 5,428 tpy. A summary of 

emissions projections for the various 

control options is provided in Table 

162. 

TABLE 162—SUMMARY OF COLSTRIP UNIT 3 NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

reduction 

(tpy) 

SCR ................................................................................................................................. 70.2 3,810 1,618 

SNCR ............................................................................................................................... 25.0 1,356 4,072 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Refer to the Colstrip Unit 1 section 

above for general information on how 

we evaluated the cost of compliance for 

NOX controls. EPA’s control costs can 

be found in the docket. 

Table 163 provides a summary of 

estimated annual costs for the various 

control options. 

TABLE 163—SUMMARY OF COLSTRIP UNIT 3 NOX REASONABLE PROGRESS COST ANALYSIS

Control option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

SCR ................................................................................................................................................................. 17,425,444 4,574 

SNCR ............................................................................................................................................................... 3,755,238 2,769 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24065 

241 IPM, Chapter 5, Appendix 5–2A and 5–2B. 

242U.S. DOE, Energy Information Administration, 

Cost and Quality of Fuels for Electric Utility Plants 

1999 Tables, DOE/EIA–0191(99), Table 24 (June 

2000). 

243 IPM, Chapter 5, p. 5–9. 

244 ICAC, p. 8. 

245NOX Control Update to PPL Montana’s 

Colstrip Generating Station BART Report, 

September 2011, p. 8. 

246Email communication with Fuel Tech, Inc. 

(Mar. 2, 2012). 

247Cichanowicz 2010, p. 6–7. 

248CCM, Section 4.2, Chapter 1, p. 1–21. 

249CCM, Section 4.2, Chapter 2, p. 2–28. 

We relied on control costs developed 

for the IPM for direct capital costs for 

SCR and SNCR.241 We then used 

methods provided by the CCM for the 

remainder of SCR and SNCR 

calculations. Specifically, we used the 

methods in the CCM to calculate total 

capital investment, annual costs 

associated with operation and 

maintenance, to annualize the total 

capital investment using the CRF, and to 

sum the total annual costs. We used a 

retrofit factor of ‘‘1,’’ reflecting an SCR 

and SNCR retrofit of typical difficulty in 

the IPM control costs. 

As Colstrip Unit 3 burns subbituminous PRB coal having a low 

sulfur content of 0.91 lb/MMBtu 

(equating to a SO2 rate of 1.8 lb/ 

MMBtu),242 it was not necessary to 

make allowances in the control costs to 

account for equipment modifications or 

additional maintenance associated with 

fouling due to the formation of 

ammonium bisulfate. These are only 

concerns when the rate of SO2 is above 

3 lb/MMBtu.243 Moreover, ammonium 

bisulfate formation can be minimized by 

preventing excessive NH3 slip. 

Optimization of the SNCR system can 

commonly limit NH3 slip to levels less 

than the 5 ppm upstream of the pre-air 

heater.244 EPA’s detailed cost 

calculations for SNCR can be found in 

the docket. 

For SNCR we used a urea reagent cost 

estimate of $450 per ton, taken from 

PPL’s September 2011 submittal for 

Colstrip Units 1 and 2.245 For SCR, we 

used an aqueous ammonia (29%) cost of 

$240 per ton,246 and a catalyst cost of 

$6,000 per cubic meter.247 To estimate 

the average cost effectiveness (dollars 

per ton of emissions reductions), we 

divided the total annual cost by the 

estimated NOX emissions reductions. 

Factor 2: Time Necessary for 

Compliance 

We estimate that SCR and SNCR can 

be installed within this planning period. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

An SNCR process reduces the thermal 

efficiency of a boiler as the reduction 

reaction uses thermal energy from the 

boiler.248 Therefore, additional coal 

must be burned to make up for the 

decreases in power generation. Using 

CCM calculations, we determined the 

additional coal needed for Unit 3 

equates to 176,800 MMBtu/yr. For an 

SCR, the new ductwork and the 

reactor’s catalyst layers decrease the flue 

gas pressure. As a result, additional fan 

power is necessary to maintain the flue 

gas flow rate through the ductwork. SCR 

systems require additional electric 

power to meet fan requirements 

equivalent to approximately 0.3% of the 

plant’s electric output.249 Both SCR and 

SNCR require some minimal additional 

electricity to service pretreatment and 

injection equipment, pumps, 

compressors, and control systems. Note 

that cost of the additional energy 

requirements has been included in our 

calculations. 

Non-air quality environmental 

impacts of SNCR and SCR were 

described in our BART analysis for 

Colstrip Unit 1. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Optional Factor: Modeled Visibility 

Impacts 

We conducted modeling for Colstrip 

Unit 3 as described in section V.C.3.a. 

Table 164 presents the visibility impacts 

and benefits of SCR and SNCR at the 

98th percentile of daily maxima for each 

Class I area from 2006 through 2008. 

Table 165 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class I area from 2006 through 

2008. 

TABLE 164—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON COLSTRIP UNIT 3 

Class I area Baseline impact 

(delta deciview) 

Improvement 

from SCR 

(delta deciview) 

Improvement 

from SNCR 

(delta deciview) 

North Absaroka WA ............................................................................................. 0.200 0.109 0.036

Theodore Roosevelt NP ...................................................................................... 0.498 0.273 0.099 

UL Bend WA ........................................................................................................ 0.471 0.261 0.084 

Washakie WA ...................................................................................................... 0.223 0.105 0.044 

Yellowstone NP ................................................................................................... 0.151 0.063 0.032 

TABLE 165—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON COLSTRIP UNIT 3 

[Three Year Total] 

Class I area Baseline 

(days) Using SCR Using SNCR 

North Absaroka WA ..................................................................................................................... 2 0 2 

Theodore Roosevelt NP .............................................................................................................. 14 2 8 

UL Bend WA ................................................................................................................................ 15 0 10 

Washakie WA .............................................................................................................................. 2 0 2 

Yellowstone NP ........................................................................................................................... 1 0 1 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24066 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

250Colstrip 3 & 4 Additional Response, 

Attachment 2, p. 2. 

251 Id. 

252 IPM, Chapter 5, Appendix 5–2A and 5–2B. 

253U.S. DOE, Energy Information Administration, 

Cost and Quality of Fuels for Electric Utility Plants 

1999 Tables, DOE/EIA–0191(99), Table 24 (June 

2000). 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We have also considered an 

additional factor: The modeled visibility 

benefits of controls. We evaluated this 

factor for Colstrip Units 3 and 4, due to 

the size of Colstrip Units 3 and 4 in 

comparison with the other RP sources. 

For the more cost-effective option 

(SNCR), the modeled visibility benefits 

are relatively modest. For the more 

expensive option (SCR), the modeled 

visibility benefits, although more 

substantial, are not sufficient for us to 

consider it reasonable to impose this 

option in this planning period. 

Therefore, we are proposing that no 

additional NOX controls will be 

required for this planning period on 

Colstrip Unit 3. 

iii. Colstrip Unit 4 

All information found within this 

section is located in the docket. Unit 4, 

a tangentially fired CE boiler which 

burns low sulfur, sub-bituminous 

northern PRB coal, is rated at 805 MW 

gross output. The boiler started 

operation in 1984. 

PM emissions are controlled by using 

a wet particulate scrubber that is 

designed to achieve approximately 

99.8% particulate control efficiency.250

As discussed previously in Section 

V.D.6.b., the contribution from point 

sources to primary organic aerosols, EC, 

PM2.5 at Montana Class I areas is very 

small, and modeling tends to confirm 

that PM emissions from point sources 

do not have a very large impact. 

Therefore, we are proposing that 

additional controls for PM are not 

necessary for this planning period. 

Colstrip Unit 4 burns low-sulfur 

(0.7%) coal and has a wet particulate 

scrubber that achieves 95% SO2 control. 

Emissions for the last five years have 

averaged 0.08 lb/MMBtu. The scrubber 

has no provisions for bypass and the 

system includes a spare vessel for the 

unit which is available for use while 

servicing the other vessels.251 Other 

upgrades to the scrubber are infeasible 

for the same reasons as described in the 

BART determinations for Colstrip Units 

1 and 2. For these reasons, additional 

controls for SO2 will not be considered 

or required in this planning period. 

Currently, Colstrip Unit 4 has 

installed LNB with SOFA and a DPCS. 

These controls reduce NOX emissions 

by 81%. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available for Colstrip 

Unit 4: SCR and SNCR. These 

technologies have been described in the 

BART determinations for Colstrip Unit 

1. 

Step 2: Eliminate Technically Infeasible 

Options 

We are not eliminating any options as 

technically infeasible. Thus, the 

technically feasible NOX control options 

for Colstrip Unit 4 are SCR and SNCR. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions from Colstrip 

Unit 4 are 5,347 tpy. A summary of 

emissions projections for the various 

control options is provided in Table 

166. 

TABLE 166—SUMMARY OF COLSTRIP UNIT 4 NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

SCR ................................................................................................................................. 70.7 3,780 1,567 

SNCR ............................................................................................................................... 25.0 1,336 4,011 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Refer to the Colstrip Unit 1 section 

above for general information on how 

we evaluated the cost of compliance for 

NOX controls. EPA’s cost calculations 

can be found in the docket. 

Table 167 provides a summary of 

estimated annual costs for the various 

control options. 

TABLE 167—SUMMARY OF COLSTRIP UNIT 4 NOX REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

SCR ................................................................................................................................................................. 17,441,422 4,607 

SNCR ............................................................................................................................................................... 3,682,750 2,757 

We relied on control costs developed 

for the IPM for direct capital costs for 

SCR and SNCR.252 We then used 

methods provided by the CCM for the 

remainder of the SCR and SNCR. 

Specifically, we used the methods in the 

CCM to calculate total capital 

investment, annual costs associated 

with operation and maintenance, to 

annualize the total capital investment 

using the CRF, and to sum the total 

annual costs. We used a retrofit factor of 

‘‘1,’’ reflecting an SCR and SNCR retrofit 

of typical difficulty in the IPM control 

costs. 

As Colstrip Unit 4 burns subbituminous PRB coal having a low 

sulfur content of 0.91 lb/MMBtu 

(equating to a SO2 rate of 1.8 lb/ 

MMBtu),253 it was not necessary to 

make allowances in the cost 

calculations to account for equipment 

modifications or additional 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24067 

254 IPM, Chapter 5, p. 5–9. 

255 ICAC, p. 8. 

256NOX Control Update to PPL Montana’s 

Colstrip Generating Station BART Report, 

September 2011, p. 8. 

257Email communication with Fuel Tech, Inc., 

March 2, 2012. 

258Cichanowicz 2010, p. 6–7. 

259CCM, Section 4.2, Chapter 1, p. 1–21. 

260CCM, Section 4.2, Chapter 2, p. 2–28. 

maintenance associated with fouling 

due to the formation of ammonium 

bisulfate. These are only concerns when 

the rate of SO2 is above 3 lb/MMBtu.254

Moreover, ammonium bisulfate 

formation can be minimized by 

preventing excessive NH3 slip. 

Optimization of the SNCR system can 

commonly limit NH3 slip to levels less 

than the 5 ppm upstream of the pre-air 

heater.255 EPA’s detailed cost 

calculations for SNCR can be in the 

docket. 

For SNCR we used a urea reagent cost 

estimate of $450 per ton taken from 

PPL’s September 2011 submittal for 

Colstrip Units 1 and 2.256 For SCR, we 

used an aqueous ammonia (29%) cost of 

$240 per ton,257 and a catalyst cost of 

$6,000 per cubic meter.258

Factor 2: Time Necessary for 

Compliance 

We estimate that SCR and SNCR can 

be installed within this planning period. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

An SNCR process reduces the thermal 

efficiency of a boiler as the reduction 

reaction uses thermal energy from the 

boiler.259 Therefore, additional coal 

must be burned to make up for the 

decreases in power generation. Using 

CCM calculations we determined the 

additional coal needed for Unit 4 

equates to 172,200 MMBtu/yr. For an 

SCR, the new ductwork and the 

reactor’s catalyst layers decrease the flue 

gas pressure. As a result, additional fan 

power is necessary to maintain the flue 

gas flow rate through the ductwork. SCR 

systems require additional electric 

power to meet fan requirements 

equivalent to approximately 0.3% of the 

plant’s electric output.260 Both SCR and 

SNCR require some minimal additional 

electricity to service pretreatment and 

injection equipment, pumps, 

compressors, and control systems. Note 

that cost of the additional energy 

requirements has been included in our 

calculations. 

Non-air quality environmental 

impacts of SNCR and SCR were 

described in our BART analysis for 

Colstrip Unit 1. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Optional Factor: Modeled Visibility 

Impacts 

We conducted modeling for Colstrip 

Unit 4 as described in section V.C.3.a. 

Table 168 presents the visibility impacts 

and benefits of SCR and SNCR at the 

98th percentile of daily maxima for each 

Class I area from 2006 through 2008. 

Table 169 presents the number of days 

with impacts greater than 0.5 deciviews 

for each Class I area from 2006 through 

2008. 

TABLE 168—DELTA DECIVIEW IMPROVEMENT FOR NOX CONTROLS ON COLSTRIP UNIT 4 

Class I area 

Baseline 

impact 

(delta 

deciview) 

Improvement 

from SCR 

(delta 

deciview) 

Improvement 

from SNCR 

(delta 

deciview) 

North Absaroka WA ..................................................................................................................... 0.168 0.077 0.030 

Theodore Roosevelt NP .............................................................................................................. 0.485 0.260 0.091 

UL Bend WA ................................................................................................................................ 0.468 0.249 0.081 

Washakie WA .............................................................................................................................. 0.223 0.101 0.043 

Yellowstone NP ........................................................................................................................... 0.148 0.057 0.026 

TABLE 169—DAYS GREATER THAN 0.5 DECIVIEW FOR NOX CONTROLS ON COLSTRIP UNIT 4 

[Three Year Total] 

Class I area Baseline 

(days) Using SCR Using SNCR 

North Absaroka WA ..................................................................................................................... 2 0 1 

Theodore Roosevelt NP .............................................................................................................. 14 2 8 

UL Bend WA ................................................................................................................................ 14 0 11 

Washakie WA .............................................................................................................................. 2 0 1 

Yellowstone NP ........................................................................................................................... 1 0 1 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We have also considered an 

additional factor: The modeled visibility 

benefits of controls. We evaluated this 

factor for Colstrip Units 3 and 4, due to 

the size of Colstrip Units 3 and 4 in 

comparison with the other RP sources. 

For the more cost-effective option 

(SNCR), the modeled visibility benefits 

are relatively modest. For the more 

expensive option (SCR), the modeled 

visibility benefits, although more 

substantial, are not sufficient for us to 

consider it reasonable to impose this 

option in this planning period. 

Therefore, we are proposing that no 

additional NOX controls will be 

required for this planning period on 

Colstrip Unit 4. 

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24068 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

261Letter to Laurel Dygowski from Tracy Carter, 

no subject (June 18, 2009); Memo to Laurel 

Dygowski from Brad Nelson, RE: Four-Factor 

Analysis of Control Options for Devon EnergyBlaine County #1 Compressor Station—Chinook, 

Montana (July 17, 2009); Letter to Vanessa Hinkle 

from Tracy Carter, no subject, (Feb. 25, 2011); 

APMM Unit Recommendations/Considerations for 

AQP Unit Reasonable Progress Determination for 

Devon Energy Blaine County #1 Compressor 

Station, Prepared by Claudia Smith (Dec. 5, 2011); 

Email to Vanessa Hinkle from Alden West RE: 

Regional Haze RP Analysis (Oct. 26, 2011). 

262CAM Technical Guidance Document, 

Appendix B–16, Non-Selective Catalytic Reduction 

(Apr. 2002), available at: www.epa.gov/ttnchie1/ 

mkb/documents/B_16a.pdf. 

iv. Devon Energy Blaine County #1 

Compressor Station 

Devon Energy Blaine County #1 

Compressor Station (Devon) operates 

two 5,500-hp Ingersoll Rand 616 natural 

gas compressor engines at its Blaine 

County #1 Compressor Station. The 

engines began operation in 1972 and 

combust natural gas. Emissions exit 

through a 45-foot stack. Additional 

information to support this four factor 

analysis can be found in the docket.261

PM and SO2 emissions are relatively 

small (0.32 tpy of PM and 0.02 tpy of 

SO2 per engine). Thus, SO2 and PM 

emissions from these two engines are 

not significant contributors to regional 

haze and our determination only 

considers NOX. Additional controls for 

SO2 and PM will not be considered or 

required in this planning period. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available for the 

compressor station: A continuous 

exhaust monitoring system (CEMS) with 

upgraded ignition system and air-fuel 

ratio control, a Dresser-Rand (D–R) 

mixing kit, a D–R mixing kit with screwin prechambers, SCR, and non-selective 

catalytic reduction (NSCR). Both 

engines are already equipped with 

electronic air/fuel controllers, as well as 

electronic fuel valves and ignition. 

Emissions are adjusted through manual 

setpoint control of the air-to-fuel (A/F) 

ratio. 

The CEMS involves continuous 

monitoring of the exhaust stack gases 

and making the necessary automatic 

adjustments to the ignition timing and 

air-fuel ratio to ensure optimization of 

the combustion cycle within the power 

cylinders. Load changes on the engine 

are compensated for in real time as 

opposed to the manual adjustments that 

currently take place. It is estimated that 

this system could achieve a 12% 

reduction in NOX from the baseline 

case. This technology has been used in 

the past on similar engines. 

A D–R mixing kit system, supplied by 

the engine manufacturer, improves the 

fuel delivery system to enhance fuel/air 

mixing, which improves exhaust NOX

levels and combustion stability. DresserRand estimates that this system could 

achieve a 14% reduction in NOX from 

the baseline case. 

The D–R mixing kit with screw-in 

prechambers adds a new turbocharger 

and cooling system to the hardware of 

the mixing kit. This system further leans 

out the combustion of the existing 

engine to improve NOX emissions 

performance. Dresser-Rand estimates 

that this system could achieve a 78% 

reduction in NOX from the baseline 

case. 

SCR has been described in general 

terms in the above BART 

determinations. SCR is considered 

feasible for this source. However, 

typical compressor engines operate at 

variable loads, thereby creating 

technical difficulties for SCR operation 

leading to periods of NH3 slip or periods 

of insufficient NH3 injection. It is 

estimated that this system could achieve 

a 75% reduction in NOX from the 

baseline case. This technology is 

available from Catalytic Combustion, 

Inc and has been used in the past on 

similar engines. 

NSCR is an add-on NOX control 

technology for exhaust streams with low 

O2 content. NSCR uses a catalyst 

reaction to simultaneously reduce NOX, 

CO, and HC to water, carbon dioxide, 

and nitrogen. The catalyst is usually a 

noble metal. 

One type of NSCR system injects a 

reducing agent into the exhaust gas 

stream prior to the catalyst reactor to 

reduce the NOX. Another type of NSCR 

system has an afterburner and two 

catalytic reactors (one reduction catalyst 

and one oxidation catalyst). In this 

system, natural gas is injected into the 

afterburner to combust unburned HC (at 

a minimum temperature of 1700 °F). 

The gas stream is cooled prior to 

entering the first catalytic reactor where 

CO and NOX are reduced. A second heat 

exchanger cools the gas stream (to 

reduce any NOX reformation) before the 

second catalytic reactor where 

remaining CO is converted to carbon 

dioxide. 

The control efficiency achieved by 

NSCR for NOX ranges from 80 to 90%. 

The NOX reduction efficiency is 

controlled by similar factors as for SCR, 

including the catalyst material and 

condition, the space velocity, and the 

catalyst bed operating temperature. 

Other factors include the A/F ratio, the 

exhaust gas temperature, and the 

presence of masking or poisoning 

agents. The operating temperature for an 

NSCR system ranges from 

approximately 700 °F to 1500 °F, 

depending on the catalyst.262

Step 2: Eliminate Technically Infeasible 

Options 

We are not eliminating any of the 

control options as being technically 

infeasible. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions are 372 tpy 

for each engine. A summary of 

emissions projections for the various 

control options is provided in Table 

170. 

TABLE 170—SUMMARY OF DEVON NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

Unit 1 Unit 2 

NSCR ............................................................... 90 335 37 335 37 

Mixing kit plus screw-in prechambers ............. 78 290 82 290 82 

SCR .................................................................. 75 279 93 279 93 

Mixing kit .......................................................... 14 52 320 52 320 

CEMS with upgraded ignition system and airfuel ratio control ............................................ 12 45 327 45 327 

CAM Technical Guidance Document, Appendix B–16, Non-Selective Catalytic Reduction (Apr. 2002), available at: www.epa.gov/ttnchie1/mkb/ 

documents/B_16a.pdf. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24069 

263US EPA, Office of Air Quality Planning and 

Standards, Regulatory Impact Analysis of the 

Proposed Reciprocating Internal Combustion 

Engines NESHAP, Final Report (Nov. 2002), 

available at http://www.epa.gov/ttn/atw/rice/ 

riceria.pdf. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

We are adopting cost figures provided 

by Devon, except for the costs of NSCR. 

For NSCR, we estimated the annual cost 

to be $105,000 based on information 

used to support the 2002 NESHAP for 

Reciprocating Internal Combustion 

Engines (RICE).263

Table 171 provides a summary of 

estimated annual costs for the various 

control options. 

TABLE 171—SUMMARY OF DEVON NOX REASONABLE PROGRESS COST ANALYSIS

Control option 

Total annual cost 

($) 

(same for both 

units) 

Cost 

effectiveness 

($/ton) 

Cost 

effectiveness 

($/ton) 

Unit 1 Unit 2 

NSCR ............................................................................................................................... 105,000 282 282 

Mixing kit plus screw-in prechambers ............................................................................. 261,000 897 897 

SCR ................................................................................................................................. 308,822 1,108 1,108 

Mixing kit .......................................................................................................................... 110,500 2,079 2,079 

CEMS with Upgraded ignition system and air-fuel ratio control ..................................... 29,100 652 652 

Factor 2: Time Necessary for 

Compliance 

Installation of a CEMS would take 

approximately nine weeks, installation 

of the mixing kit would take between 17 

to 22 weeks, installation of a mixing kit 

plus screw-in prechambers would take 

20 to 26 weeks, installation of SCR 

would take approximately 25 weeks, 

and installation of NSCR could take up 

to one year. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts 

A CEMS with an upgraded ignition 

system and air-fuel ratio control would 

actually improve fuel consumption. 

Installation of SCR would cause 

backpressure on the engine exhausts 

which would lead to a reduction of 

available power and an increase in 

engine fuel use. NSCR can potentially 

require up to a 5% increase in fuel 

consumption and up to a 2% reduction 

in power output. 

A CEMS with an integrated ignition 

system and air-fuel ratio control, D–R 

mixing kit, or D–R mixing kit with 

screw-in prechambers would not have 

direct environmental impacts. Some 

manufacturers accept the return of spent 

catalyst that would be used by NSCR 

and SCR. If the catalyst could not be 

returned to the manufacturer, it would 

need to be disposed. In addition, SCR 

uses NH3, which would have the 

possibility of being released if not 

properly managed. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline 

Q/D of the facility, and the potential 

reduction in Q/D from the controls. 

Based primarily on the low cost of $282 

per ton of NOX removed, we propose to 

find NSCR is a reasonable control to 

address reasonable progress for the 

initial planning period, with an 

emission limit of 21.8 lb/hr (30-day 

rolling average). 

We have eliminated lower performing 

options—upgraded ignition system and 

air-fuel ratio control, D–R mixing kit, 

SCR, and D–R mixing kit with screw-in 

prechambers because their cost 

effectiveness values are higher and/or 

the emission reductions are lower than 

NSCR. We are proposing an emission 

limit of 21.8 lbs/hr (30-day rolling 

average) based on a predicted control 

efficiency of 90%. The emission limit 

would apply on a continuous basis, 

including during startup, shutdown, 

and malfunction. We propose to require 

that Devon start meeting our proposed 

emission limit at Blaine County #1 

Compressor Station as expeditiously as 

practicable, but no later than July 31, 

2018. This is consistent with the 

requirement that the FIP cover an initial 

planning period that ends July 31, 2018. 

We propose this compliance deadline 

because of the equipment installation 

that is required. 

In order to ensure the effectiveness of 

the NSCR, we are proposing to require 

the following work practices and 

operational requirements. We are 

proposing that Devon install a 

temperature-sensing device (i.e., 

thermocouple or resistance temperature 

detectors) before the catalyst in order to 

monitor the inlet temperatures of the 

catalyst for each engine and that Devon 

maintain the engine at a minimum of at 

least 750 °F and no more than 1250 °F 

in accordance with manufacturer’s 

specifications. Also, we are proposing 

that Devon install gauges before and 

after the catalyst for each engine in 

order to monitor pressure drop across 

the catalyst, and that Devon maintain 

the pressure drop within ±2′′ water at 

100% load plus or minus 10% from the 

pressure drop across the catalyst 

measured during the initial performance 

test. We are proposing to require Devon 

to follow the manufacturer’s 

recommended maintenance schedule 

and procedures for each engine and its 

respective catalyst. We are proposing 

that Devon only fire each engine with 

natural gas that is of pipeline-quality in 

all respects except that the CO2

concentration in the gas shall not be 

required to be within pipeline-quality. 

We are proposing the following 

monitoring, recordkeeping, and 

reporting requirements for Devon: 

• Devon shall measure NOX

emissions from each engine at least 

semi-annually or once every six month 

period to demonstrate compliance with 

the emission limits. To meet this 

requirement, we are proposing that 

Devon measure NOX emissions from the 

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24070 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

264Response to Reasonable Progress Request for 

Information, Montana-Dakota Utilities Co. (‘‘L&C 

Initial Response’’) (Mar. 17, 2009); Emissions 

Control Analysis for Lewis & Clark Station Unit 1, 

Prepared for Montana-Dakota Utilities Co. by Barr 

Consultants (‘‘L&C Emissions Control Analysis’’) 

(Feb. 2011, rev’d June 2011); Revised Emissions 

Control Analysis for Lewis & Clark Station, in 

Response to EPA Request of November 5, 2010, 

Montana-Dakota Utilities Co. (‘‘L&C Revised 

Emissions Control Analysis’’) (June 14, 2011); 

Response to EPA Questions of January 19, 2012, 

Regarding Fuel Switch to Natural Gas, Basis for SCR 

Cost Calculation, and SDA Efficiency, MontanaDakota Utilities Co. (‘‘L&C Feb. 10, 2012 Response’’) 

(Feb. 10, 2012); Response to EPA Questions of 

February 15, 2012, Regarding Cost of Fuel Switch 

to Natural Gas, Montana-Dakota Utilities Co. (‘‘L&C 

Feb. 27, 2012 Response’’) (Feb. 27, 2012). 

265L&C Initial Response, pp. 3–5; L&C Emissions 

Control Analysis, p. 4. 266L&C Emissions Control Analysis, pp. 13–17. 

engines using a portable analyzer and a 

monitoring protocol approved by EPA. 

• Devon shall submit the analyzer 

specifications and monitoring protocol 

to EPA for approval within 45 calendar 

days prior to installation of the NSCR 

unit. 

• Monitoring for NOX emissions shall 

commence during the first complete 

calendar quarter following Devon’s 

submittal of the initial performance test 

results for NOX to EPA. 

• Devon shall measure the engine 

exhaust temperature at the inlet to the 

oxidation catalyst at least once per week 

and shall measure the pressure drop 

across the oxidation catalyst monthly. 

• Each temperature-sensing device 

shall be accurate to within plus or 

minus 0.75% of span and that the 

pressure sensing devices be accurate to 

within plus or minus 0.1 inches of 

water. 

• Devon shall keep records of all 

temperature and pressure 

measurements; vendor specifications for 

the thermocouples and pressure gauges; 

vendor specifications for the NSCR 

catalyst and the A/F ratio controller on 

each engine. 

• Devon shall keep records sufficient 

to demonstrate that the fuel for the 

engines is pipeline-quality natural gas 

in all respects, with the exception of the 

CO2 concentration in the natural gas. 

• Devon shall keep records of all 

required testing and monitoring that 

include: the date, place, and time of 

sampling or measurements; the date(s) 

analyses were performed; the company 

or entity that performed the analyses; 

the analytical techniques or methods 

used; the results of such analyses or 

measurements; and the operating 

conditions as existing at the time of 

sampling or measurement. 

• Devon shall maintain records of all 

required monitoring data and support 

information (e.g. all calibration and 

maintenance records, all original stripchart recordings for continuous 

monitoring instrumentation, and copies 

of all reports required) for a period of at 

least five years from the date of the 

monitoring sample, measurement, or 

report and that these records be made 

available upon request by EPA. 

Devon shall submit a written report of 

the results of the required performance 

tests to EPA within 90 calendar days of 

the date of testing completion. 

v. Montana-Dakota Utilities Lewis & 

Clark Station 

Montana-Dakota Utilities Company 

(MDU) submitted analyses and 

supporting information on March 17, 

2009, February 2011 (Revised June 

2011), June 14, 2011, February 10, 2012, 

and February 27, 2012.264

MDU owns and operates an electric 

utility power plant in Sidney, Montana, 

known as the L&C Station. The plant is 

rated at 52 MWs gross output (48 MWs 

net output) and consists of a single dry 

bottom, tangentially fired boiler, fueled 

with lignite coal. The boiler was 

installed in 1958. 

PM emissions are controlled by a 

multi-cyclone dust collector, installed 

in 1957, with design control of 75–80%, 

as well as a flooded disc wet scrubber 

installed in 1975, designed for 98% PM 

control, with a nominal SO2 control 

efficiency of approximately 15%, but 

which has achieved up to 60% control 

during certain operating conditions, 

mainly by the presence of calcium in 

the coal, but also by MDU’s addition of 

lime to the existing scrubber system 

when the coal has lower calcium and 

higher sulfur content. Current NOX

controls consist of LNBs and a CCOFA 

system, installed in 1996. Estimated 

level of control is 33%.265

As discussed previously in Section 

V.D.6.b., the contribution from point 

sources to primary organic aerosols, EC, 

PM2.5 at Montana Class I areas is very 

small, and modeling tends to confirm 

that PM emissions from point sources 

do not have a very large impact. 

Therefore, we are proposing that 

additional controls for PM are not 

necessary for this planning period. 

SO2

Current SO2 controls consist of a wet 

scrubbing system (flooded disc wet 

scrubber, with lime addition as needed, 

depending on coal quality) with an 

estimated control efficiency of up to 

60%. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available for 

emissions reductions beyond those 

achieved by the current control 

configuration: Wet lime scrubbing/ 

optimization of existing wet PM 

scrubber, lime SDA and baghouse, DSI 

and baghouse, and fuel switching to 

either PRB coal or to natural gas. 

Wet lime scrubbing involves 

scrubbing the exhaust gas stream with 

slurry comprised of lime (CaO) in 

suspension. The process takes place in 

a wet scrubbing tower located 

downstream of a PM control device to 

prevent the plugging of spray nozzles 

and other problems caused by the 

presence of particulates in the scrubber. 

The SO2 in the gas stream reacts with 

the lime to form CaSO3•2H2O and 

CaSO4. This control option is 

functionally equivalent to ‘‘in terms of 

concept and control efficiency. Forced 

oxidation is used in wet scrubbing 

systems to convert calcium sulfite to 

calcium sulfate (gypsum). Air is blown 

through spent lime reagent to 

accomplish this reaction. This often 

takes place in the bottom of the wet 

scrubber. Calcium sulfite is a watery 

compound and cannot be de-watered. It 

is typically disposed in ash ponds. 

Calcium sulfate is a solid. Wet scrubber 

blowdown containing calcium sulfate 

can be run through a filter press for 

calcium sulfate recovery. After 

filtration, calcium sulfate can be 

disposed of as a solid waste or it can be 

sold as a raw material for drywall 

production. The use of forced oxidation 

has an impact on the method of 

scrubber waste disposal, but does not 

appreciably impact SO2 removal. 

This wet scrubbing option at L&C 

Station would involve modification to 

the existing PM wet scrubber to increase 

SO2 removal efficiency. The 

modification would primarily involve 

upgrade and optimization of the lime 

injection system. Expected total SO2

emissions reduction would be 

approximately 70% on an annual basis, 

versus the estimated 60% control 

currently being achieved (about a 10% 

improvement). The scrubber lime 

injection system would be upgraded to 

achieve this additional removal.266

Lime SDA is a dry scrubbing system 

that sprays a fine mist of lime slurry 

into an absorption tower where the SO2

is absorbed by the droplets. Once 

absorbed, the SO2 reacts with lime to 

form CaSO3•2H2O and CaSO4 within the 

droplets. The SDA temperature must be 

hot enough to ensure that the heat from 

the exhaust gas causes the water to 

evaporate before the droplets reach the 

bottom of the tower. This leads to the 

formation of a dry powder, which is 

carried out with the gas and collected 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24071 

267L&C Feb. 10, 2012 Response, p. 3. 

268L&C Emissions Control Analysis, p. 15. 

269 Id. 

270 Id., pp. 13, 15. 

271 Id., pp. 8–10. 

272 Id. 

273L&C Initial Response, p. 7. 

274L&C Feb. 10, 2012 Response, p. 2. 

275L&C Emissions Control Analysis, p. 8–10. 

with a fabric filter baghouse. Spray 

dryer absorption control efficiency is 

typically in the 70% to 90% range, but 

can be as high as 95%.267 We used 95% 

control for this analysis. To 

accommodate the SDA control option, 

the existing particulate scrubber at L&C 

Station would need to be abandoned in 

place and replaced with a baghouse.268

This is necessary to ensure the required 

system residence time for a dry control 

option; otherwise, the achievable 

control efficiency would be significantly 

decreased.269

DSI involves the injection of a lime or 

limestone powder into the exhaust gas 

duct work. The stream is then passed 

through a baghouse or ESP to remove 

the sorbent and entrained SO2. The 

process was developed as a lower cost 

FGD option because the mixing occurs 

directly in the exhaust gas stream 

instead of in a separate tower. 

Depending on the residence time 

allowed in the system and gas duct 

temperature, sorbent injection control 

efficiency is typically between 50% and 

70%. Based on the particulate loading of 

the existing control system, DSI is 

expected to achieve removal efficiencies 

of less than the design range in 

combination with existing controls. We 

used 70% control for this analysis. To 

accommodate the DSI control option, 

the existing particulate scrubber at L&C 

Station would need to be abandoned in 

place and replaced with a new 

baghouse. Again, this is necessary to 

ensure the required system residence 

time for a dry control option; otherwise, 

the achievable control efficiency would 

be significantly decreased.270

Fuel switching is a control technology 

option. Blending of subbituminous PRB 

coal is already employed at L&C Station, 

in instances where relatively poor 

quality lignite coal is provided to the 

plant. MDU’s boiler is currently 

permitted to blend PRB coal with the 

primary lignite fuel.271 Therefore, we 

consider a fuel switch to PRB coal as 

primary fuel to be an available SO2

control option, although, since there is 

no appreciable difference in the sulfur 

content (weight percent) of PRB coal 

versus lignite coal, this option might 

yield only marginal SO2 reductions.272

Also, since MDU has provided data 

indicating natural gas is used to some 

extent (about 0.37% of total heat input 

to the boiler in 2002, by our 

calculations, based on information 

supplied by MDU),273 we consider a 

fuel switch to natural gas as primary 

fuel to be another available control 

option for SO2. Since pipeline-quality 

natural gas has negligible sulfur content, 

we would expect a greater than 99% 

reduction in SO2. To supply sufficient 

natural gas to serve as primary fuel for 

the boiler, a new 22-mile pipeline from 

the nearest connection point to L&C 

Station would have to be constructed.274

Step 2: Eliminate Technically Infeasible 

Options 

Although switching to coals with 

lower sulfur content and higher Btu 

content represents a viable precombustion method of reducing SO2

emissions, there are limitations to 

achievable blending. Switching to any 

fuel with an appreciably different 

composition and energy content would 

require boiler surface and other design 

changes. Previous test burns of PRB coal 

at the boiler confirm that the high flue 

gas temperatures, resulting from the use 

of PRB coal, cause significant fouling to 

boiler walls and other boiler surfaces. 

Due to the physical properties of PRB 

coal, coal mills and coal piping to the 

boiler would also need to be replaced, 

along with the addition of a railcar 

unloading system. A re-design of the 

existing boiler does not constitute a 

feasible retrofit control option. Further, 

there is no appreciable difference in the 

sulfur content (weight percent) of the 

subbituminous coal supplement, and 

reduced calcium/magnesium 

concentrations present in the 

subbituminous coal would also result in 

less inherent SO2 control. Finally, the 

on-site coal inventory is fairly limited 

(generally 2–3 days’ supply of lignite), 

due primarily to lack of property to 

safely store additional inventory.275

Therefore, a switch to PRB coal as 

primary fuel is not considered further in 

this evaluation. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

A summary of emissions projections 

for the various control options is 

provided in Table 172. For all options, 

we relied on the estimated control 

efficiencies, estimated emissions 

reductions, and emissions baseline 

provided by MDU. The emissions 

baseline of 1,002.1 tpy used in our 

analysis reflects an estimated 60% level 

of control already being achieved by the 

existing scrubber system. The control 

efficiencies listed in the table below are 

the degree of control that is expected to 

be achieved on baseline SO2 emissions 

(1,002 tpy). 

TABLE 172—SUMMARY OF MDU LEWIS AND CLARK SO2 REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

Fuel switch to natural gas ............................................................................................... 99+ 1,002 Negligible 

SDA with baghouse ......................................................................................................... 85 850.3 151.8 

DSI with baghouse .......................................................................................................... 10 100.2 901.9 

Existing scrubber mod. .................................................................................................... 10 100.2 901.9 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Table 173 provides a summary of 

estimated annual costs for the various 

control options. 

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276L&C Feb. 10, 2012 Response, p. 2. 

277Report from Bradley Nelson, EC/R Inc. to 

Laurel Dygowski of EPA, Four-factor Analysis of 

Control Options for MDU L&C Station, p. 5 (July 3, 

2009). 

278L&C Emissions Control Analysis, p. 17. 279L&C Emissions Control Analysis, p. 16. 

280L&C Feb. 27, 2012 Response. MDU cited 

typical heat content of 6,435 Btu/lb for lignite coal, 

based on 2009–2011 average from FERC Form 1/EIA 

923 reports. 281The AP–42 emission factor for natural gas is 

170 lb/MMSCF. MDU’s February 27, 2012 letter to 

EPA states that annual natural gas consumption, if 

natural gas is used as primary fuel, would be 3,283 

MMSCF. This yields 279 tpy of NOX emissions. 

Baseline NOX emissions used by MDU in its June 

2011 analysis, with lignite coal as primary fuel, are 

802 tpy. Switching to natural gas would therefore 

represent a potential 65% reduction in NOX

emissions. 

TABLE 173—SUMMARY OF MDU LEWIS & CLARK REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

Fuel switch to natural gas ............................................................................................................................... 21,919,094 21,875 

SDA with baghouse ......................................................................................................................................... 10,055,056 11,825 

DSI with baghouse .......................................................................................................................................... 2,840,734 28,350 

Existing scrubber mod. .................................................................................................................................... 138,637 1,383 

We have relied on costs provide by 

MDU for these control options. The high 

annual cost of a fuel switch is due partly 

to the need to construct a new 22-mile 

natural gas pipeline, and partly to the 

large difference in cost of natural gas 

versus lignite coal. Natural gas would 

cost about five times as much as lignite 

coal to fuel the boiler. 

Factor 2: Time Necessary for 

Compliance 

For the option involving a fuel switch 

to natural gas as primary fuel, we 

estimate several years would be needed 

to secure the necessary rights-of-way 

and install a new 22-mile pipeline that 

MDU has stated would be needed to 

provide a sufficient supply of natural 

gas.276 For the SDA-with-baghouse and 

DSI-with-baghouse control options, we 

relied on an estimate from the Institute 

of Clean Air Companies (ICAC) that 

approximately 30 months is required to 

design, build and install SO2 scrubbing 

technology.277 For the option involving 

modification to the existing scrubbing 

system, we relied on MDU’s estimate of 

6 to 12 months to conduct an 

optimization study to evaluate scrubber 

capabilities and identify operational 

constraints.278

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

A fuel switch to natural gas as 

primary fuel could significantly increase 

the demand for natural gas in the region 

and could increase natural gas prices for 

other consumers of natural gas in the 

region, as well as create impacts 

associated with more production of 

natural gas in the region. For the SDAwith-baghouse control option, as well as 

for the DSI-with-baghouse control 

option, energy impacts would include a 

blower requiring increased energy use 

and an associated indirect CO2

emissions increase. For the option of 

modifying the existing wet scrubber 

system, no appreciable energy impacts 

are expected. There is, however, a 

potential for additional water 

consumption and wastewater 

generation.279

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. The costs per ton of pollutant 

reduced are excessive for the three most 

expensive options. We are also taking 

into account the size of the facility, the 

baseline Q/D of the facility, and the 

potential reduction in Q/D from the 

controls. Based on costs of compliance, 

the small size of MDU L&C, and the 

relatively small baseline Q/D, we 

propose to eliminate the more expensive 

control options (fuel switch to natural 

gas, SDA with baghouse, and DSI with 

baghouse). The most cost-effective 

control option (scrubber modifications) 

would reduce SO2 emissions by 100 tpy, 

which equates to a 5.5% reduction in 

overall emissions of SO2 + NOX for this 

facility, or a reduction of Q/D from 29 

to 27. Based on the costs of compliance, 

the relatively small size of MDU L&C, 

the baseline Q/D, and the modest 

reduction in Q/D, we find it reasonable 

to eliminate this option. We therefore 

propose to not require additional SO2

controls for this planning period. 

NOX

Current NOX controls consist of LNBs 

and a CCOFA system, with estimated 

control efficiency of 33%. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available for 

emissions reductions beyond those 

achieved by the current control 

configuration: Fuel switching to PRB 

coal or to natural gas, SCR + SOFA/ 

LNB, SNCR, SOFA/LNB, and SNCR 

with SOFA/LNB. 

We consider fuel switching to PRB 

coal or to natural gas, as primary fuel for 

the boiler, as an available control for 

NOX, for the same reasons as described 

in our SO2 analysis. With regard to a 

potential switch to PRB coal, higher 

heat content of coal can yield lower 

NOX emissions in lb/MMBtu. The 

lignite coal used at L&C Station has an 

average heating value of 6,435 Btu/lb.280

PRB coal typically ranges from 8,000 to 

8,500 Btu/lb and therefore could be 

expected to have lower NOX emissions 

than lignite coal, per ton of coal fired. 

Similarly, natural gas could be expected 

to produce lower NOX emissions than 

lignite coal. We used a 65% reduction 

in our analysis.281

SCR was generally described in our 

BART analysis for CELP. SCR has been 

demonstrated to achieve high levels of 

NOX reduction in the range of 80% to 

90% (or higher) control, for a wide 

range of industrial combustion sources, 

including PC, cyclone, and stoker coalfired boilers and natural gas-fired 

boilers and turbines. For our SCR 

analysis, we included SOFA and LNB 

upstream of the SCR controls, on the 

basis that these controls are much less 

expensive than SCR and would enable 

the SCR system to use less reagent. Our 

calculations reveal that a control system 

consisting of SCR + SOFA/LNB would 

be more cost-effective than SCR alone 

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282MDU NOX control cost analysis by US EPA 

Region 8 for SCR, SOFA/LNB, and SCR + SOFA/ 

LNB, Summary Spreadsheet (Mar. 7, 2012). 

and would also achieve a higher level of 

control than SCR alone. We have used 

87.5% control as our estimate for the 

combined SCR + SOFA/LNB system.282

A description of SNCR was provided 

in our BART analysis for CELP. We used 

38% control effectiveness for SNCR 

alone, and 50% control effectiveness for 

the control option of SNCR with SOFA/ 

LNB. 

L&C Station is a member of Midwest 

Independent Transmission System 

Operator (MISO) and, as such, is 

operated as called upon based on energy 

demand and price. Generally, 

combustion systems on boilers are not 

optimized for low load operation, 

including associated NOX emissions. 

This is important because the efficiency 

of many air emission controls cannot be 

guaranteed at low load operating 

conditions. This is especially true for 

SNCR. Therefore, to reflect actual 

emission reductions on cost per ton 

basis, an SNCR scenario at low load 

operation is also presented in our 

analysis, using 23 MW capacity as the 

low load operational case. Based on a 

preliminary SNCR engineering 

assessment that includes the 

temperature, residence time, and the 

current level of NOX control, an 

emissions reduction of approximately 

15% to 30% would be expected at low 

load conditions. We used 16% for our 

analysis. 

SOFA was described in our BART 

analysis for Colstrip Unit 1. LNB was 

described in our analysis for CELP. 

SOFA technology is compatible with the 

existing LNB. 

LNBs typically achieve NOX emission 

reductions of 25% to 50% as compared 

to uncontrolled emissions. LNBs are 

currently used at L&C Station. Based on 

the currently achieved emission rates, a 

combined reduction in the range of 30% 

to 40% is expected at L&C Station with 

the addition of SOFA and new LNB. We 

used 38% for our analysis. 

Step 2: Eliminate Technically Infeasible 

Options 

We consider fuel switching to PRB 

coal to be technically infeasible, for 

reasons already described in Step 2 of 

our SO2 analysis. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

A summary of emissions projections 

for the various control options is 

provided in Table 174. We relied on 

information from MDU for estimated 

control efficiencies, expected emission 

reductions, and baseline emissions, 

with the exception of HDSCR + SOFA/ 

LNB, for which we performed our own 

analysis. The control efficiencies listed 

in the table below, other than for the 

SNCR low-load scenario, are the degree 

of reduction that is expected to be 

achieved on actual controlled baseline 

NOX emissions of 802 tpy. Similarly, the 

emission reductions in tpy in the table 

are reductions from the baseline 

emissions. For the SNCR low-load 

scenario, the baseline emissions, control 

efficiency and emissions reduction are 

those that correspond to low load 

operation (23 MW). 

TABLE 174—SUMMARY OF MDU LEWIS & CLARK NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

HDSCR + SOFA/LNB ...................................................................................................... 87.5 693 109 

Fuel switch to natural gas ............................................................................................... 65 523 279 

SNCR with SOFA/LNB .................................................................................................... 50 401 401 

SOFA/LNB ....................................................................................................................... 38 301 501 

SNCR ............................................................................................................................... 38 301 501 

SNCR (low load) 1 ............................................................................................................ 16 57.6 298 

1Baseline emissions for the low load scenario are 356 tpy. 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Table 175 provides a summary of 

estimated annual costs for the various 

control options. We relied on MDU’s 

cost figures, with the exception of 

HDSCR + SOFA/LNB, for which we 

performed our own cost calculations, 

using a combination of EPA’s OAQPS 

CCM and control costs from EPA’s IPM. 

TABLE 175—SUMMARY OF MDU LEWIS & CLARK NOX REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

HDSCR + SOFA/LNB ...................................................................................................................................... 3,361,965 4,853 

Fuel switch to natural gas ............................................................................................................................... 21,919,094 41,934 

SNCR with SOFA/LNB .................................................................................................................................... 1,093,962 2,729 

SOFA/LNB ....................................................................................................................................................... 364,546 1,213 

SNCR ............................................................................................................................................................... 761,654 2,533 

SNCR (low load) .............................................................................................................................................. 565,673 9,817 

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283L&C Emissions Control Analysis, p. 26. 

284L&C Feb. 10, 2012 Response, p. 2. 

285Reasonable Progress (RP) Four-Factor Analysis 

of Control Options for Montana Sulphur & 

Chemical Company in Billings Montana; Response 

to Request for Information, Reasonable Progress for 

Montana Sulphur & Chemical Co, pursuant to 

Section 114(A) of the Federal Clean Air (Feb. 6, 

2012). 

Factor 2: Time Necessary for 

Compliance 

For combustion modifications such as 

SOFA and/or LNB, furnace penetration 

would be required and, as such, will 

need to align with a major outage. The 

next planned outage is spring of 

2018.283 Therefore, it might not be 

possible to ensure that SOFA or LNB 

could be installed within the first 

planning period for regional haze 

requirements under the CAA. If HDSCR 

+ SOFA/LNB is the chosen control 

option, the construction schedule could 

extend into many months. If SNCR is 

the chosen control option, installation 

would likely be much quicker. For the 

option involving a fuel switch to natural 

gas as primary fuel, several years might 

be needed to secure the necessary 

rights-of-way and install a new 22-mile 

pipeline that MDU has stated would be 

needed to provide a sufficient supply of 

natural gas.284

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

A fuel switch to natural gas as 

primary fuel could significantly increase 

the demand for natural gas in the region 

and could increase natural gas prices for 

other consumers of natural gas in the 

region, as well as create impacts 

associated with more production of 

natural gas in the region. Other control 

options, however, would have minimal 

energy impacts. 

Depending on HDSCR installation in 

relation to existing controls, NH3 slip 

can generally cause additional NH3 to be 

emitted to air or water. As NH3 is both 

a visibility impairing air pollutant and 

a wastewater regulated pollutant, air 

emissions and water discharges can be 

impacted. This is also a potential SNCR 

impact. Also, spent catalyst from SCR 

produces an increase in solid waste. 

Finally, for combustion modifications 

(SOFA and/or LNB), there is a potential 

for increased CO emissions from the 

boiler. During normal operation at L&C 

Station, CO levels are currently on the 

order of 20 ppm. Generally, CO 

performance guarantees are in the 100 

ppm to 200 ppm range for LNBs. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: the cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. 

Based on costs of compliance, the small 

size of the facility, and the relatively 

small baseline Q/D, we propose to 

eliminate the more expensive control 

options (fuel switching to natural gas 

and HDSCR + SOFA/LNB). For similar 

reasons, taking into account costs in the 

low load scenario, we propose to 

eliminate SNCR and SNCR + SOFA/ 

LNB. Finally, for the most cost effective 

option (SOFA/LNB), emissions 

reductions would be fairly small (300 

tpy), which would result in 

approximately 16.6% reduction in 

overall emissions of SO2 + NOX for this 

facility, or a reduction of Q/D from 29 

to 24. Based on the costs of compliance, 

the relatively small size of MDU L&C, 

and the modest reduction in Q/D, we 

find it reasonable to eliminate this 

option. We therefore propose to not 

require NOX controls for this planning 

period. 

vi. Montana Sulphur and Chemical 

Montana Sulphur and Chemical 

Company (MSCC) is a sulfur recovery 

source located in Billings, Montana. 

Additional information to support this 

four factor analysis can be found in the 

docket.285

MSCC converts the raw sulfur 

compound from fuel gases, acid gases 

and other materials to create marketable 

products, including: low sulfur fuel gas, 

elemental sulfur, dry fertilizers, 

hydrogen gas, hydrogen sulfide, and 

carbon and sodium sulfates. MSCC 

receives sulfur-containing fuel gases 

from the ExxonMobil refinery, 

desulfurizes these gases in its amine 

unit, and returns low-sulfur fuels back 

to the refinery. This process reduces 

sulfur oxide emissions that might 

otherwise be emitted to the atmosphere 

at the oil refinery site. 

At MSCC, acid gases are processed in 

a multistage Claus process and tail gas 

incinerator. In 1998, MSCC installed a 

SuperClaus Process, which further 

desulfurizes Claus tail gases by selective 

partial oxidation and controls emissions 

of SO2. In 2008, a second SuperClaus 

unit was installed in parallel to the first 

unit, so that sulfur and fuel gas 

processing can continue during periods 

of repair and maintenance. 

The sulfur recovery process and its 

related stack is the preponderant source 

of SO2 emissions from the facility and 

is the only emissions unit included in 

our analysis. 

PM emissions from the sulfur 

recovery process are estimated to be 

only 1 tpy. As discussed previously in 

Section V.D.6.b., the contribution from 

point sources to primary organic 

aerosols, EC, PM2.5 and PM10 at Montana 

Class I areas is very small, and modeling 

tends to confirm that PM emissions 

from point sources do not have a very 

large impact. Therefore, we are 

proposing that additional controls for 

PM are not necessary for this planning 

period. 

NOX emissions also are relatively 

small, at 3 tpy. Thus, NOX emissions 

from the unit are not significant 

contributors to regional haze. 

Additional controls for NOX will not be 

considered or required in this planning 

period. We are therefore considering 

controls only for SO2 for this planning 

period. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available: extending 

the Claus reaction into a lower 

temperature liquid phase (the Sulfured®

process) and tail gas scrubbing 

(Wellman-Lord, SCOT, and traditional 

FGD processes). 

In the Sulfured® process, the Claus 

reaction is extended at low temperatures 

(260 to 300°F) to recover SO2 and H2S 

in the tail gas. Tail gas passes through 

one of three reactors on line at a given 

time. Two reactors are on either heating 

or cooling cycles while the third is on 

the gas stream. Gas flow is switched 

from the reactors and is determined by 

the sulfur-holding capacity of each 

catalyst bed in the reactors. Sulfur is 

vaporized by using inert gas from a 

blower, resulting in the regeneration of 

the catalyst bed. The inert gas is then 

cooled in a condenser, where the liquid 

sulfur is removed. The hot regenerated 

catalyst bed must be cooled before going 

back on the gas stream. 

The Wellman-Lord is an oxidation tail 

gas scrubber that uses sodium sulfite 

(Na2SO3) and sodium bisulfate 

(NaHSO3) to react with SO2 gas from the 

Claus incinerator to form bisulfate. The 

incinerator gases must be cooled and 

quenched before scrubbing, subjected to 

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misting after scrubbing, and reheated 

afterwards. The bisulfate solution is 

regenerated to sodium sulfite in a steamenergized evaporator. The concentrated 

wet SO2 gas stream from the evaporator 

is partially condensed and some of the 

liquid water is used to dissolve sulfite 

crystals. The remaining enriched SO2

gas stream is recycled back to the Claus 

plant and used to recover additional 

sulfur by reaction with the incoming 

hydrogen sulfide. 

The Shell Claus Off-Gas Treatment 

(SCOT) process is another example of 

reduction tail gas scrubbing. In the 

SCOT process, and numerous variants, 

tail gas from the sulfur recovery unit 

(SRU) is re-heated and mixed with a 

hydrogen-rich reducing gas stream. 

Heated tail gas is treated using a 

catalytic reactor where the free sulfur, 

SO2, and reduced sulfur compounds are 

substantially reconverted to H2S. The 

H2S-rich gas stream is then routed to a 

cooling/quench system where the gases 

are cooled. Excess condensed water 

from the quench system is routed to a 

separate sour water system for treatment 

and disposal. The cooled quench system 

gas effluent is then fed to an absorber 

section where the acidic gas comes in 

contact with a selective amine solution 

and is absorbed into solution; the amine 

must selectively reject carbon dioxide 

gas to avoid problems in the following 

steps, and must not be exposed to 

unreduced gases or oxygen (e.g., 

unconverted SO2 or sulfur) that may 

arise during malfunctions. The rich 

solution is separately regenerated using 

steam, cooled and returned to the 

scrubber/absorber. The H2S-rich gas 

released at the regenerator is 

reprocessed by the SRU. 

Other traditional FGD technologies 

include: Wet lime scrubbers, wet 

limestone scrubbers, dual alkali wet 

scrubbers, spray dry absorbers, DSI, and 

CDS. All of these technologies were 

described in previous sections (see the 

BART analysis for Corette and the four 

factor analyses for CELP, YELP, and 

MDU, L&C Station). 

Step 2: Eliminate Technically Infeasible 

Options 

The Wellman-Lord scrubber is 

infeasible for MSCC. This system can 

require significant space, especially in 

retrofit applications. There is limited 

space at MSCC. Also, the purge system 

required by this process would generate 

excess acid water that would require 

onsite management and onsite or offsite 

disposal. For these reasons, the 

Wellman Lord system was not 

considered further. 

SDA and DSI are not technically 

feasible because the flue gas SO2

concentrations at MSCC are too high. 

These technologies cannot be used 

when concentrations are greater than 

2000 ppm. The average concentration of 

SO2 in the flue gas at MSCC ranges from 

2,100 to 6,000 ppm. For this reason, 

SDA and DSI were not considered 

further. 

MSCC has very limited space to 

install wet systems or to manage the 

waste streams generated by wet systems 

(wet lime scrubbers, wet limestone 

scrubbers, and dual alkali wet 

scrubbers). These systems can require 

significant space, especially in retrofit 

applications. There is limited space at 

MSCC. Also, these processes would 

generate excess water that would 

require onsite management and onsite 

or offsite disposal. Wet systems would 

require an onsite dewatering pond and 

landfill to process and dispose of 

scrubber sludge. For these reasons, the 

wet systems were not considered 

further. 

CDS cannot be used at MSCC because 

it would result in high particulate 

loading. It would be necessary to control 

those particulates. Because of the high 

particulate loading, the pressure drop 

across a fabric filter would be 

unacceptable; therefore, ESPs are 

generally used for particulate control for 

power plants. Either type of particulate 

control device would require substantial 

space, which is not available at MSCC. 

Based on limited technical data from 

non-comparable applications and our 

engineering judgment, we have 

determined that CDS is not technically 

feasible for this facility. For this reason, 

CDS was not considered further. 

Both the SCOT and Sulfured®

processes are feasible; however, in the 

BART Guidelines, EPA states that it may 

be appropriate to eliminate from further 

consideration technologies that provide 

similar control levels at higher cost. See 

70 FR 39165 (July 6, 2005). We think it 

appropriate to do the same for RP 

determinations. In this case, Sulfured®

systems reportedly can achieve 98% to 

99.5% sulfur recovery efficiency while 

SCOT can reportedly achieve sulfur 

recovery as high as 99.8% to 99.9%. The 

cost is higher for the Sulfured® system 

when compared to the SCOT process. 

Because the SCOT process is more 

effective and costs less than the 

Sulfured® system, the Sulfured® system 

was not considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Baseline SO2 emissions from MSCC 

are 1,452 tpy. A summary of emissions 

projections for the SCOT process, the 

only remaining control technology, is 

provided in Table 176. 

TABLE 176—SUMMARY OF MSCC SO2 REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY CONTROL

EFFECTIVENESS

Control option 

Control 

effectiveness 1 (%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

SCOT ............................................................................................................................... 99.9 871 581 

1Overall control efficiency is shown. Incremental control efficiency, over the current SuperclausTM Process is 60%. 

Factor 1: Costs of Compliance 

Table 177 provides a summary of 

estimated annual costs and cost 

effectiveness for the SCOT process. 

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24076 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

286Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

287Letter from Thomas Ray to Vanessa Hinkle 

(Feb. 28, 2011); Reasonable Progress (RP) FourFactor Analysis of Control Options for Plum Creek 

Manufacturing/Columbia Falls Operations. 

TABLE 177—SUMMARY OF MSCC SO2 REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

SCOT ............................................................................................................................................................... 7,705,000 5,441 

We are adopting cost figures provided 

by MSCC, except that we annualized the 

capital cost using a 7% interest rate and 

20-year equipment life (which yields a 

CRF of 0.0944), as specified in the 

Office of Management and Budget’s 

Circular A–4, Regulatory Analysis.286

The capital cost is annualized by 

multiplying the total capital investment 

by the CRF (0.0944). We also used a 

control efficiency of 99.9% for the 

SCOT process. 

Factor 2: Time Necessary for 

Compliance 

The SCOT process could be installed 

in 18 to 36 months. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

The SCOT process requires 

substantial additional energy for 

operation. The tail gas from the Claus 

unit would need to be heated prior to 

entering a reducing reactor and/or 

heating recycled gas for regeneration 

requirements. Low-temperature based 

systems such as the SCOT system would 

also require additional fuel for reheat of 

the final tail gas for incineration prior to 

discharge. SCOT systems also require 

substantial electricity to operate 

numerous pumps, coolers and a 

condenser. Additional power is required 

to provide relatively large amounts of 

cooling water. Additional fuel and 

power energy (and equipment) is 

required for processing of the new sour 

water waste that is continuously 

produced in the quench process 

necessary for scrubbing. Additional 

details of the energy requirements for 

the SCOT process are described in the 

docket. 

The quench system in the SCOT 

system produces a sour water effluent 

that requires treatment prior to disposal. 

This effluent contains hydrogen sulfide, 

and may contain other troublesome 

species as well, particularly during 

upset conditions. An engineered facility 

needs to be installed at MSCC to manage 

this waste stream. 

Factor 4: Remaining useful life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. 

Based on costs of compliance for the 

only control option (SCOT), the 

relatively small size of the facility, and 

the relatively small baseline Q/D, we 

propose to eliminate this option. 

Therefore, we are proposing that no 

additional controls for SO2 will be 

required for this planning period. 

vii. Plum Creek Manufacturing 

Plum Creek Manufacturing’s 

Columbia Falls Operation, in Columbia 

Falls, Montana consists of a sawmill, a 

planner, and plywood and medium 

density fiberboard (MDF) processes. 

Additional information to support this 

four-factor analysis can be found in the 

docket.287 This RP analysis focuses on 

four emitting units at the Columbia Falls 

Operation: the Riley Union hog fuel 

boiler (Riley Union boiler), two Line 1 

MDF dryer sander dust burners (Line 1 

sander dust burners), and the Line 2 

MDF dryer sander dust burner (Line 2 

sander dust burner). The Riley Union 

boiler is used as a load-following steam 

generator for the dry kilns, plywood 

press, log vats, and MDF platen press. 

Downstream from the spreader-stoker 

grate, there are sander dust burners that 

are capable of supplementing 10% of 

the heat rate capacity of the boiler. 

These burners are normally fired with 

sander dust, but have the ability to fire 

natural gas during sander dust shortages 

and startup. 

The Line 1 MDF dryers include two 

direct-contact dryers, a core fiber dryer, 

and a face fiber dryer. One Cone sander 

dust burner supplies heat to each dryer. 

The Line 1 fireboxes are one-quarter the 

size of the Line 2 firebox. 

The Line 2 MDF dryers are directcontact dryers. The flue gas from the 

combustion chamber provides heat for 

the first- and second-stage dryer lines. 

The design of the Line 2 burner employs 

staged combustion, with a rich zone 

followed by a lean zone reducing peak 

flame temperature, thereby reducing 

thermal NOX emissions. 

The Riley Union boiler exhausts to a 

dry ESP that was installed in 1993. The 

Line 1 dryer exhausts combine with the 

Line 1 press vents and metering bin 

baghouse exhausts before being 

controlled by a wet ESP that was 

installed in 1995. They emit to the 

atmosphere through two 80-foot stacks. 

The Line 2 dryer exhausts to a Venturi 

scrubber (installed in 2001) before 

emitting to the atmosphere through 

three 40-foot stacks. As discussed 

previously in Section V.D.6.b., the 

contribution from point sources to 

primary organic aerosols, EC, PM2.5 and 

PM10 at Montana Class I areas is very 

small, and modeling tends to confirm 

that PM emissions from point sources 

do not have a very large impact. 

Therefore, we are proposing that 

additional controls for PM are not 

necessary for this planning period. 

SO2 emissions are relatively small (18 

tpy for all units combined). Thus, SO2

emissions from these units are not 

significant contributors to regional haze, 

and additional controls for SO2 will not 

be considered or required in this 

planning period. We are therefore only 

considering controls for NOX for this 

planning period. 

Riley Union Boiler 

Step 1: Identify All Available 

Technologies 

The Riley Union Boiler does not 

currently have post-combustion or low 

NOX combustion technology. We 

identified that the following 

technologies to be available: SCR, RSCR, 

SNCR, SNCR/SCR hybrid, staged 

combustion, fuel staging, LNB, OFA, 

LEA, and FGR. 

SCR, SNCR, LNB, OFA, LEA and FGR 

were described in our analysis for CELP. 

RSCR uses a regenerative thermal 

oxidizer (or waste heat transfer system) 

to bring cool exhaust gas back up to the 

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temperature required for the SCR 

catalyst to be effective at reducing NOX

to nitrogen and water. RSCR is a good 

option for an exhaust gas that has 

constituents requiring removal prior to 

introduction into the catalyst (to prevent 

fouling or plugging), such as high PM 

concentrations. 

The SNCR/SCR hybrid approach 

involves injecting the reagent (NH3 or 

urea) into the combustion chamber, 

which is a higher temperature zone than 

traditional SCR injection. This provides 

an initial reaction that is similar to 

SNCR. A catalyst is placed in the 

downstream flue gas to further reduce 

NOX and any reagent that remains. 

Staged combustion can be achieved 

through a wide variety of methods and 

techniques, but in general creates a fuelrich zone followed by a fuel lean zone. 

This reduces the peak flame 

temperature and the generation of 

thermal NOX. 

Fuel staging is a technique that uses 

10% to 20% of the total fuel input 

downstream from the primary 

combustion zone. The fuel in the 

downstream secondary zone acts as a 

reducing agent to reduce NO emissions 

to N2. Natural gas or distillate oil 

usually are used in the secondary 

combustion zone. 

Step 2: Eliminate Technically Infeasible 

Options 

SCR catalysts may be fouled or 

plugged by exhaust gas that contains 

high concentrations of PM, as is the case 

with the combustion of wood, biomass, 

or hog fuel. To prevent the premature 

failure of the catalyst, the PM must be 

removed from the exhaust stream prior 

to SCR. At this facility, the exhaust from 

the boiler’s ESP will not meet the 

minimum temperature required for SCR 

(without reheat). Since the PM loading 

is too high for high dust SCR prior to 

PM controls; and the gas is too cool after 

the PM control equipment for a low dust 

SCR (downstream of the ESP). For these 

reasons, SCR was not considered 

further. 

Since the PM concentrations in the 

exhaust of the Riley Union boiler would 

require the PM controls to precede the 

catalyst section of the hybrid system, 

reheat would be required. RSCR is 

considered to be feasible without 

firebox/SNCR injection, therefore 

SNCR/SCR Hybrid systems were not 

considered further. 

Further staged combustion is not 

possible for the Riley Union boiler. The 

boiler is a stoker boiler with sander dust 

burners downstream from the stoker. In 

order to create a further staged 

combustion process (and lower flame 

temperature), the energy density must 

be reduced in the combustion fuel. This 

means that more volume would be 

required to accommodate the current 

heat rate. In addition to the space 

constraint, as with OFA, it is unlikely 

that the current design could further 

stratify the rich and lean combustion 

zones (either through decreased underfire air, or increased OFA), due to the 

minimum air flow needed to cool the 

stoker grate and maintain an even heat 

release rate. For these reasons, staged 

combustion was not considered further. 

The Riley Union boiler already 

employs fuel staging by having a stoker 

grate for a majority of the heat input 

followed by sander dust burners 

downstream of the grate. Further fuel 

staging is infeasible for the boiler. For 

this reason, fuel staging was not 

considered further. 

LNBs are not feasible for spreaderstoker boilers, as they do not use 

burners for a majority (90% in this case) 

of the heat input. Sander dust burners 

are located downstream from the stoker 

grate; however, their small size may 

restrict the ability to create conditions 

necessary for a LNB. For LNB 

technology to be effective, the rich zone 

must precede the lean zone. In this case, 

the secondary combustion zone burners 

would not have sufficient space to 

accommodate a larger flame front 

characterized by LNB technology. In 

addition, lowering the flame 

temperature at that location may 

negatively affect the function of the 

secondary combustion zone, which 

could result in increased emissions of 

some pollutants. For these reasons, LNB 

technology was not considered further. 

In order to implement OFA on the 

boiler, further modifications would be 

required to add OFA ports. The OFA 

ports would need to be installed at the 

same location as the current sander dust 

burners. In addition, installation of OFA 

ports will increase the size/volume of 

the flame front, in turn, increasing flame 

impingement on the boiler walls, which 

may lead to tube failure. Flame 

impingement may also increase 

quenching of the flame thereby 

increasing emissions associated with 

incomplete combustion. The reducing 

atmosphere of the rich primary zone 

also may result in accelerated corrosion 

of the furnace, and grate corrosion and 

overheating may occur in stokers as 

primary air flow is diverted to OFA 

ports. Some level of staged combustion 

is already achieved through fuel staging 

(by use of the downstream sander dust 

burners). Further staging of the 

combustion process through OFA (or 

other techniques) is technically 

infeasible without increasing the boiler 

volume or decreasing the heat input 

rate. For these reasons, OFA was not 

considered further. 

LEA is not compatible with the design 

of the boiler. The boiler is a stoker boiler 

that operates on the principle of creating 

an even release of heat across the entire 

grate. In order to achieve optimal 

conditions, sufficient air flow is 

required from beneath the grate. In 

addition sufficient air flow is needed to 

keep the grate and parts exposed to 

combustion material below their 

maximum operating temperatures. For 

these reasons, LEA is not considered 

further. 

Similarly, FGR creates a LEA 

condition, but may not affect the under 

fire air needed to properly operate the 

stoker grate system. In order to prevent 

high loss on ignition and increased 

emissions associated with incomplete 

combustion (and the LEA condition) the 

volume of the boiler’s combustion 

chamber would likely need to be 

increased to maintain the current steam 

rate and overall heat release rate, and 

thus is not compatible with the design 

of the boiler. FGR is a technique with 

multiple mechanisms for reducing NOX, 

including reducing the available 

oxygen, since some exhaust gas replaces 

oxygen rich ambient air. For this reason, 

FGR is not considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Baseline NOX emissions from the 

boiler are 587 tpy. A summary of 

emissions projections for RSCR and 

SNCR, the only remaining control 

technologies, are provided in Table 178. 

Further information can be found in the 

docket. 

TABLE 178—SUMMARY OF BOILER NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

SNCR ............................................................................................................................... 35 205 382 

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288Plum Creek Revised Response, Table C–4 

(Mar. 13, 2012). 

289Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

TABLE 178—SUMMARY OF BOILER NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY—Continued 

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

RSCR ............................................................................................................................... 75 440 147 

Factor 1: Costs of Compliance 

Table 179 provides a summary of 

estimated annual costs and cost 

effectiveness for SNCR and RSCR. 

TABLE 179—SUMMARY OF BOILER NOX REASONABLE PROGRESS COST ANALYSIS

Control 

option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

SNCR ............................................................................................................................................................... $294,377 $1,436 1 RSCR ............................................................................................................................................................. 748,097 1,700 

1Further information on our cost calculation can be found in the docket in the document titled Reasonable Progress (RP) Four-Factor Analysis 

of Control Options for Roseburg Forest Products Co./Missoula Particleboard (a similar type source to Plum Creek’s boiler). 

For SNCR, we are adopting cost 

figures provided by Plum Creek,288

except that we annualized the capital 

cost by multiplying the capital cost by 

a CRF that corresponds to a 7% interest 

rate and 20-year equipment life (which 

yields a CRF of 0.0944), as specified in 

the Office of Management and Budget’s 

Circular A–4, Regulatory Analysis.289

For RSCR, we are adopting the total 

annual cost for RSCR for the SolaGen 

sander dust burner at Roseburg Forest 

Products. This is likely an 

underestimation of the cost for the 

boiler dryers at Plum Creek, because the 

boiler at Plum Creek is larger than the 

SolaGen sander dust burner at Roseburg. 

Factor 2: Time Necessary for 

Compliance 

RSCR systems can be operational 

within eight months to one year. 

Because RSCR includes much of the 

equipment needed for SNCR, with 

additional equipment (the catalyst for 

instance), we have assumed that SNCR 

could be installed within a similar 

timeframe to that quoted for RSCR. 

Therefore, SNCR also can be installed 

and operational within eight months to 

one year. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

RSCR requires the reheat of the flue 

gas, either through a heat exchanger that 

uses plant waste heat, and/or through 

direct reheat of the flue gas by 

additional combustion or electrically 

powered heating elements. Although 

specific estimates of resources needed to 

operate RSCR on the Columbia Falls 

boiler were not available, we have 

examined estimates presented for a 

similar source (Roseburg Forest 

Products) to illustrate the approximate 

quantity of resources needed to run a 

RSCR system. Table 180 provides 

estimates of these additional resources 

that are necessary for RSCR. 

TABLE 180—ADDITIONAL AMMONIA, NATURAL GAS, ELECTRICITY, AND STEAM REQUIRED FOR RSCR 

Ammonia (NH3) Natural gas Electricity Steam 

RSCR usage per system .. 300,000 to 400,000 gal/ 

year.

2 million scf/year to 9.7 

million scf/year.

930,000–5.4 million kWh/ 

year.

42.5–125 lb/hr or 186–548 

tpy. 

Additionally, the RSCR catalyst may 

have the potential to emit NH3 (as NH3

slip) and generate nitrous oxide if not 

operated optimally. Catalysts must be 

disposed of, presenting a cost; however, 

many catalyst manufacturers provide a 

system to regenerate or recycle the 

catalyst reducing the impacts associated 

with spent catalysts. In addition to these 

considerations, there are issues 

associated with the production, 

transport, storage, and use of NH3. 

However, regular handling of NH3 has 

reduced the risks associated with its 

transport, storage, and use. 

As with RSCR, there are issues 

associated with NH3, electricity, and 

compressed air for SNCR. Although 

specific estimates of resources needed to 

operate SNCR on the Columbia Falls 

boiler were not available, we have 

examined estimates presented for a 

similar source (Roseburg Forest 

Products) to illustrate the approximate 

quantity of resources needed to run a 

SNCR system. Table 181 provides 

estimates for additional reagent, 

electricity and steam use. 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24079 

TABLE 181—ADDITIONAL REAGENT, ELECTRICITY AND STEAM REQUIRED FOR SNCR 

Reagent (Urea) Electricity Steam 

Boiler SNCR System ..................... 165 tpy or 69,740 gallons Urea 

solution/year.

204,108 kWh/year ........................ 51.4 lb/hr or 225 tpy. 

As with RSCR, some level of NH3 slip 

will be present, which is dependent on 

the amount of reagent injected and the 

level of control that is desired. Higher 

levels of control are associated with 

greater NH3 slip. Whether urea or NH3

is used, there are impacts associated 

with the production, transport, storage, 

and use of these chemicals. If urea is 

used, there will be GHG emissions 

associated with its hydrolysis prior to 

its use as a NOX reagent. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. We 

propose to eliminate the most expensive 

option (RSCR), based on costs of 

compliance and the relatively small size 

of this facility. The less expensive 

option (SNCR) would reduce emissions 

by 205 tpy, which equates to 

approximately an 18.5% reduction in 

overall emissions of SO2 + NOX from the 

facility, or a reduction of Q/D from 82 

to 67. Based on the relatively small size 

of this facility, the baseline Q/D, and the 

reduction in Q/D, we propose to find it 

reasonable to eliminate this option. 

Therefore, we are proposing to not 

require any NOX controls for this 

planning period. 

Line 1 Sander Dust Burners 

Step 1: Identify All Available 

Technologies 

The Line 1 sander dust burners do not 

currently have post-combustion or low 

NOX combustion technology. We 

identified the following technologies to 

be available: SCR, RSCR, SNCR, SNCR/ 

SCR hybrid, staged combustion, fuel 

staging, LNB, OFA, LEA, and FGR. SCR, 

SNCR, LNB, OFA, LEA and FGR were 

described in our analysis for CELP. 

RSCR, SNCR/SCR hybrid, staged 

combustion, and fuel staging were 

described in our analysis for Plum 

Creek’s Riley Union boiler. 

Step 2: Eliminate Technically Infeasible 

Options 

For the Line 1 sander dust burners, 

PM loadings are too high for a hot/high 

dust SCR, and temperatures are too cool 

following the PMCD unless reheat is 

used. In addition to these issues, the 

dryer burners are direct contact dryers. 

Therefore, any NH3 in the gas stream 

from a hot/high dust SCR would have 

the potential to stain or darken the 

wood product. For these reasons, SCR 

was not considered further. 

The exhaust from the Line 1 sander 

dust burners acts as a direct contact heat 

source for the drying processes at the 

facility. The use of SNCR would require 

injection of the reagent prior to the 

dryers introducing NH3 to the product 

lines. Contact with NH3 may result in 

reduced product quality. NH3 darkens 

wood, which would not be acceptable 

for Plum Creek’s light colored stains. 

Additionally, NH3 may affect the curing 

of any formaldehyde-based resins used 

in the wood products. High levels of 

NH3 reduce the cellulosic structure of 

the wood, allowing it to be permanently 

shaped; however compressive strength 

is reduced, which is an important factor 

for product quality. Space constraints 

also are a consideration because there is 

not sufficient residence time at the 

required temperatures in the exhaust 

stream prior to the location where the 

exhaust comes into contact with the 

wood products; therefore, there is a 

likelihood that the conversion of the 

NH3 reagent may not be sufficiently 

completed before the exhaust enters the 

dryers, making product quality a 

concern (as stated above). For these 

reasons, SNCR was not considered 

further. 

Because the PM concentrations in the 

exhaust of the sander dust burners 

would require the PM controls to 

precede the catalyst section of the 

hybrid system, reheat would be 

required. RSCR is considered to be 

feasible without firebox/SNCR injection, 

therefore SNCR/SCR hybrid systems 

were not considered further. 

Fuel staging is not feasible for the 

Line 1 sander dust burners. The Line 1 

sander dust burners have a combustion 

chamber that is too small to 

accommodate fuel staging; therefore, 

fuel staging was not considered further. 

Staged combustion is not compatible 

with the Line 1 sander dust burners. 

The Line 1 sander dust burners have a 

combustion chamber that is one-quarter 

the volume of the Line 2 sander dust 

burner. Staged combustion techniques 

increase the volume (or size) of the 

flame front for a given heat input rate; 

therefore it would be necessary to 

reduce the overall heat input of the 

burners to achieve lower flame 

temperatures and thereby realize the 

NOX reduction achievable with staged 

combustion techniques. A reduction in 

the heat rate to the Line 1 sander dust 

burners would result in insufficient heat 

being sent into the drying process. 

As stated above in the Step 2 

discussion of staged combustion, there 

is insufficient combustion chamber 

volume to implement LNB design for 

the Line 1 sander dust burners; 

therefore, LNB are considered to be 

technically infeasible for the Line 1 

sander dust burners without increasing 

combustion chamber volume or 

decreasing the heat input rate (which 

would affect Plum Creek’s ability to 

successfully operate the wood product 

dryers). For this reason, LNB was not 

considered further. 

As also discussed above, there is 

insufficient combustion chamber 

volume to implement OFA on the Line 

1 burners without decreasing the heat 

input rate. The reduced heat input rate 

would prevent the dryers from operating 

as designed. For this reason, OFA was 

not considered further. 

LEA is considered to be technically 

infeasible for the Line 1 sander dust 

burners because sander dust suspension 

burners require high levels of air in 

order to fluidize the solid fuel. Poor 

operation of the burners would result 

with LEA since high excess air 

conditions are necessary to sustain 

stable combustion. The Line 1 dryers are 

all suspension burners, and therefore 

LEA is considered technically infeasible 

for these sources. 

Because FGR depends on the same 

conditions as LEA and LEA is 

considered technically infeasible for the 

Line 1 sander dust burners, FGR is also 

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24080 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

considered infeasible for the Line 1 

sander dust burners. Additionally, FGR 

may require additional combustion 

chamber volume to accommodate the 

same heat input while maintaining a 

reduced flame temperature. For these 

reasons, FGR was not considered 

further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Baseline NOX emissions from the Line 

1 sander dust burners are 319 tpy. A 

summary of emissions projections for 

RSCR, the only remaining control 

technology, is provided in Table 182. 

Further information can be found in the 

docket. 

TABLE 182—SUMMARY OF LINE 1 NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions (tpy) 

RSCR ............................................................................................................................... 75 240 79 

Factor 1: Costs of Compliance 

Table 183 provides a summary of 

estimated annual costs and cost 

effectiveness for RSCR. 

TABLE 183—SUMMARY OF LINE 1 NOX REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

1 RSCR ............................................................................................................................................................. 748,097 3,117 

1Further information on our cost calculation can be found in the docket in the document titled Reasonable Progress (RP) Four-Factor Analysis 

of Control Options for Roseburg Forest Products Co./Missoula Particleboard (a similar type source to Plum Creek). 

For RSCR, we are adopting the total 

annual cost for RSCR for the SolaGen 

sander dust burner at Roseburg Forest 

Products. This is likely an 

underestimation of the cost for the Line 

1 sander dust burners at Plum Creek, 

because the Line 1 sander dust burners 

are smaller than the SolaGen sander 

dust burner at Roseburg. 

Factor 2: Time Necessary for 

Compliance 

RSCR systems for the Line 1 sander 

dust burners could be operational 

within eight months to one year. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

The energy and non-air quality 

environmental impacts from RSCR were 

discussed in the analysis for the boiler. 

Specific reagent, electricity and steam 

requirements were not calculated for the 

Line 1 sander dust burners but are 

expected to be less than what would be 

needed for the boiler. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. The 

emissions reductions from the only 

feasible option (RSCR) would be fairly 

small (240 tpy), which would result in 

approximately 21.7% reduction in 

overall emissions of SO2 + NOX for this 

facility, or a reduction of Q/D from 82 

to 64. Based on the costs of compliance, 

the relatively small size of the facility, 

and the reduction in Q/D, we think it 

reasonable to not impose RSCR for this 

facility. Therefore, we are proposing to 

not require any NOX controls on this 

unit for this planning period. 

Line 2 Sander Dust Burner 

Step 1: Identify All Available 

Technologies 

The line 2 sander dust burner uses 

staged combustion to control NOX. We 

identified the following technologies to 

be available: SCR, RSCR, SNCR, SNCR/ 

SCR hybrid, staged combustion, fuel 

staging, LNB, OFA, LEA, and FGR. SCR, 

SNCR, LNB, OFA, LEA and FGR were 

described in our analysis for CELP. 

RSCR, SNCR/SCR hybrid, staged 

combustion, and fuel staging were 

described in our analysis for Plum 

Creek’s boiler. 

Step 2: Eliminate Technically Infeasible 

Options 

All of the sander dust burners have 

the same issues associated with the 

implementation of SCR as the boiler. 

PM loadings are too high for a hot/high 

dust SCR, and temperatures are too cool 

following PM control unless reheat is 

used. In addition to these issues, the 

dryer burners are all direct contact 

dryers. Therefore, any NH3 in the gas 

stream from a hot/high dust SCR would 

have the potential to stain or darken the 

wood product. For these reasons, SCR 

was not considered further. 

The exhaust from the Line 2 sander 

dust burner acts as a direct contact heat 

source for the drying processes at the 

facility. Using SNCR on the Line 2 

sander dust burner would cause the 

same product quality issues that were 

explained in the analysis for the Line 1 

sander dust burners. Space constraints 

are also an issue as explained for the 

Line 1 sander dust burners. For these 

reasons, SNCR was not considered 

further. 

As explained in the analysis for the 

Line 1 sander dust burners, the PM 

concentrations in the exhaust of the 

sander dust burners would require the 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24081 

PM controls to precede the catalyst 

section of the hybrid system, and so 

reheat would be required. RSCR is 

considered to be feasible without 

firebox/SNCR injection; therefore 

SNCR/SCR Hybrid systems were not 

considered further. 

Fuel staging is not feasible for the 

Line 2 sander dust burner. The Line 2 

sander dust burner uses staged 

combustion. Further modification of the 

combustion chamber would be required 

to use fuel staging; however, space 

constraints would make the expansion 

infeasible. Also, additional NOX

reductions would not likely be realized 

because the staged combustion design 

has already reduced thermal NOX to the 

extent possible. For these reasons, fuel 

staging is not considered further. 

The Line 2 sander dust burner already 

uses staged combustion, therefore 

further staging would not be technically 

feasible without complete replacement. 

LNB (or staged combustion) is a 

technique that was designed into the 

Line 2 sander dust burner; therefore, 

further staging, or LNB configuration 

was not considered further. 

The Line 2 sander dust burner uses 

staged combustion. Further 

modification of the combustion chamber 

would be required to use fuel staging; 

however, space constraints would make 

the expansion infeasible. Also, further 

NOX reductions would not likely be 

realized because the staged combustion 

design has already reduced thermal 

NOX to the extent possible. For these 

reasons, fuel staging is not considered 

further. 

The Line 2 sander dust burner already 

employs staged combustion; therefore, 

further staging through the use of OFA 

is technically infeasible. For this reason, 

OFA was not considered further. 

LEA is considered to be technically 

infeasible for the Line 2 sander dust 

burner because sander dust suspension 

burners require high levels of air in 

order to fluidize the solid fuel. Poor 

operation of the burners would result 

with LEA since high excess air 

conditions are found under the 

conditions necessary to sustain stable 

combustion. The Line 2 dryers are all 

suspension burners, and therefore LEA 

is considered technically infeasible for 

these sources. For these reasons, LEA 

was not considered further. 

FGR is not technically feasible for the 

Line 2 sander dust burner for the same 

reasons as were described under the 

analysis for the Line 1 sander dust 

burners. Because FGR causes a LEA 

condition and LEA is considered 

technically infeasible for the Line 2 

sander dust burner, FGR has also been 

considered to be infeasible for the Line 

2 sander dust burner. Also, FGR may 

require additional combustion chamber 

volume to accommodate the same heat 

input while maintaining a reduced 

flame temperature. For these reasons, 

FGR was not considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Baseline NOX emissions from the Line 

2 sander dust burner are 200 tpy. A 

summary of emissions projections for 

RSCR, the only remaining control 

technology, is provided in Table 184. 

TABLE 184—SUMMARY OF LINE 2 NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

RSCR ............................................................................................................................... 75 150 50 

Factor 1: Costs of Compliance 

Table 185 provides a summary of 

estimated annual costs and cost 

effectiveness for RSCR. 

TABLE 185—SUMMARY OF LINE 2 NOX REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

1 RSCR ............................................................................................................................................................. 748,000 4,987 

1Further information on our cost calculation can be found in the docket in the document titled Reasonable Progress (RP) Four-Factor Analysis 

of Control Options for Roseburg Forest Products Co./Missoula Particleboard (a similar type source to Plum Creek’s boiler). 

For RSCR, we are adopting the total 

annual cost for RSCR for the SolaGen 

sander dust burner at Roseburg Forest 

Products. This is likely an 

underestimation of the cost for the Line 

2 sander dust burner because the line 2 

sander dust burner at Plum Creek is 

larger than the SolaGen sander dust 

burner at Roseburg. 

Factor 2: Time Necessary for 

Compliance 

RSCR systems for the Line 2 sander 

dust burner could be operational within 

eight months to one year. 

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

The energy and non-air quality 

environmental impacts from RSCR were 

discussed in the analysis for the boiler. 

Specific reagent, electricity and steam 

requirements were not calculated for the 

Line 2 sander dust burner, but are 

expected to be less than what would be 

needed for the boiler. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

24082 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

290Reasonable Progress Analysis, Roseburg Forest 

Products, Missoula Particleboard, Submitted for 

Roseburg Forest Products by Golder Associates, Inc. 

(Feb. 2, 2011); Reasonable Progress (RP) Four-Factor 

Analysis of Control Options for Roseburg Forest 

Products Co., Missoula Particleboard. 

D of the facility, and the potential 

reduction in Q/D from the controls. 

Based on the costs of compliance and 

the relatively small size of this facility, 

we find it reasonable to eliminate the 

only control option (RSCR). Therefore, 

we are proposing that no additional 

controls will be required for this 

planning period. 

viii. Roseburg Forest Products 

Roseburg Forest Products Company 

owns and operates a particleboard 

manufacturing facility in Missoula, 

Montana. Additional information to 

support this four factor analysis can be 

found in the docket.290 The facility has 

two production lines, one with a multiplaten batch press (Line 1) and one with 

a continuous press (Line 2). A pre-dryer 

is used to reduce the moisture of green 

wood materials received at the facility. 

Heat for the pre-dryer is provided by 

exhaust from a 45 MMBtu/hr SolaGen 

sander dust burner. There are four final 

dryers associated with Line 1 and two 

final dryers associated with Line 2 that 

produce dried wood furnish for face and 

core material in the particleboard. Heat 

input for all six of the final dryers is 

provided by the combined exhaust of a 

50 MMBtu/hr ROEMMC sander dust 

burner and 55 MMBtu/hr sander dustfired Babcock & Wilcox boiler, which 

also provides steam for facility 

processes. 

The Babcock & Wilcox boiler is the 

oldest of the three sander dust-fired 

sources at the facility. It is a stoker-type 

boiler that was installed in 1969. Unlike 

the other sander dust burners at the 

facility, the boiler serves the function of 

producing steam for facility processes in 

addition to providing heat input to the 

final dryers. The ROEMMC burner was 

installed in 1979, although it is a 1978 

model burner. The sole purpose of this 

burner is to provide heat input for the 

final dryers. The SolaGen sander dust 

burner was installed in 2006, although 

it is a 2005 model. The sole purpose of 

this burner is to provide heat input to 

the pre-dryer. 

PM emissions from the Babcock & 

Wilcox boiler, ROEMMC burner, and 

Line 1 and 2 final dryers are controlled 

by multi-clones at the dryer outlets. PM 

emissions from the SolaGen burner and 

pre-dryer are controlled by a cyclone, a 

wet ESP, and a regenerative thermal 

oxidizer. As discussed previously in 

Section V.D.6.b., the contribution from 

point sources to primary organic 

aerosols, EC, PM2.5 and PM10 at Montana 

Class I areas is very small, and modeling 

tends to confirm that PM emissions 

from point sources do not have a very 

large impact. Therefore, we are 

proposing that additional controls for 

PM are not necessary for this planning 

period. 

SO2 emissions are relatively small (6 

tpy of SO2 for all units combined). Thus, 

SO2 emissions from these units are not 

significant contributors to regional haze 

and our analysis only considers NOX. 

Additional controls for SO2 will not be 

considered or required in this planning 

period. We are therefore considering 

controls only for NOX for this planning 

period. 

Babcock & Wilcox Boiler 

Step 1: Identify All Available 

Technologies 

The Babcock & Wilcox boiler does not 

currently have post-combustion controls 

or low NOX combustion technology. We 

identified that the following 

technologies to be available: SCR, RSCR, 

SNCR, SNCR/SCR hybrid, staged 

combustion, fuel staging, LNB, OFA, 

LEA, and FGR. SCR, SNCR, LNB, OFA, 

LEA and FGR were described in our 

analysis for CELP. RSCR, SNCR/SCR 

hybrid, staged combustion, and fuel 

staging were described in our analysis 

for the boiler at Plum Creek 

Manufacturing. 

Step 2: Eliminate Technically Infeasible 

Options 

SCR catalysts may be fouled or 

plugged by exhaust gas that contains 

high concentrations of PM, as is the case 

with the combustion of wood, biomass, 

or hog fuel. To prevent the premature 

failure of the catalyst, the PM must be 

removed from the exhaust stream prior 

to the SCR. In this case, the exhaust 

from the PM control equipment will not 

meet the minimum temperature 

required for SCR to be effective. In 

addition to these issues, there is 

insufficient space prior to the dryers to 

add both PM controls and SCR. Even if 

there were space to add both systems, 

the exhaust from PM controls and SCR 

would be at a lower temperature, 

resulting in insufficient heat being sent 

to the dryers. For these reasons, SCR 

was not considered further. 

The exhaust from all of the units act 

as direct contact heat sources for the 

drying processes at the facility. The use 

of SNCR would require injection of the 

reagent prior to the dryers, which would 

introduce NH3 to the product lines. 

Roseburg has stated that contact with 

NH3 may reduce product quality. For 

this reason, SNCR was not considered 

further. 

A SNCR/SCR hybrid system also uses 

a catalyst and thus would experience 

similar technical difficulties related to 

catalyst plugging and/or fouling, as 

described for SCR. If PM controls were 

retrofitted prior to the dryers to allow 

the SCR to be operated without reheat, 

the exhaust from the PM controls would 

be significantly reduced, resulting in 

insufficient heat being sent to the 

dryers. Space constraints and product 

quality concerns are also issues. For 

these reasons, a SNCR/SCR hybrid 

system was not considered further. 

Two stable zones of combustion are 

required for fuel staging. If there is 

insufficient space, the secondary fuel 

and combustion zone will impinge on 

the primary zone having the effect of 

raising the peak flame temperature and, 

in turn, increasing NOX emissions. 

There is not sufficient room within the 

boiler to achieve fuel staging while 

maintaining the necessary heat input to 

the dryers. The creation of a larger 

combustion zone within the boiler also 

has the possibility of causing greater 

flame impingement on the boiler wall 

and tubes, which may compromise their 

integrity and cause premature failure. 

For these reasons, fuel staging was not 

considered further. 

Staged combustion is considered 

feasible for the boiler in the form of a 

new SolaGen-type LNB; however, staged 

combustion in the form of OFA is 

considered technically infeasible for the 

boiler. Suspension burners such as the 

boiler need high air flow through the 

fuel-feed auger and burner to suspend 

and fluidize the solid fuel. Splitting the 

combustion air to OFA ports would 

result in poor and perhaps unstable 

combustion at the burner tip. For this 

reason, OFA was not considered further. 

As with OFA, suspension-type 

burners, such as the boiler, require high 

levels of air in order to fluidize the solid 

fuel. The burners would operate poorly 

with LEA. For this reason, LEA was not 

considered further. 

FGR is a technique with multiple 

mechanisms for reducing NOX, 

including reducing the available 

oxygen, since some exhaust gas replaces 

oxygen rich ambient air. As with LEA, 

some combustion air must be reduced to 

accommodate the recirculating flue gas, 

which may cause the suspension burner 

to operate improperly. FGR may be 

applied in some situations, but in order 

to maintain the necessary heat input in 

this situation, additional combustion 

chamber volume would be required to 

accommodate the volume of the flue gas 

introduced into the combustion 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24083 

291Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

chamber. For these reasons, FGR was 

not considered further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

A summary of emissions projections 

for LNB and RSCR, the only remaining 

control technologies, are provided in 

Table 186. At this facility, RSCR would 

be placed downstream of the wood 

particle dryers and as a result would 

control emissions from both the boiler 

and the ROEMMC sander dust burner. 

Baseline NOX emissions from the boiler 

are 134 tpy. Baseline NOX emissions 

from the Line 1 dryers would be from 

the boiler and ROEMMC sander dust 

burner combined and are 202 tpy. 

Baseline NOX emissions from the Line 

2 dryers would be from the boiler and 

ROEMMC sander dust burner combined 

and are 92 tpy. 

TABLE 186—SUMMARY OF ROSEBURG NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

LNB ................................................................................................................................ 22 .2 30 104 

RSCR Line 1 .................................................................................................................. 75 1151 151 

RSCR Line 2 .................................................................................................................. 75 169 123 

1 RSCR on the dryers would control emissions from the boiler and the ROEMMC. 

LNBs are a form of staged combustion 

and may be able to achieve 50–70% 

reductions in NOX emissions when 

firing coal, depending on the design or 

generation of the burner. However, NOX

reductions are highly dependent on the 

specifics of the burner design, fuel fired, 

and the operational setting. Roseburg 

presented a control efficiency for LNB 

applicable to the boiler of 

approximately 20%, which was based 

on information from the LNB vendor. 

This is not unreasonable considering 

that biomass produces primarily fuel 

NOX rather than thermal NOX, and LNB 

primarily reduce the generation of 

thermal NOX. 

Factor 1: Costs of Compliance 

Table 187 provides a summary of 

estimated annual costs and cost 

effectiveness for LNB and RSCR. 

TABLE 187—SUMMARY OF ROSEBURG NOX REASONABLE PROGRESS COST ANALYSIS

Control option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

LNB .................................................................................................................................................................. 70,624 2,354 

RSCR Line 1 .................................................................................................................................................... 2,261,273 14,975 

RSCR Line 2 .................................................................................................................................................... 1,234,469 17,891 

For LNB, we are adopting cost figures 

provided by Roseburg, except that we 

annualized the capital cost by 

multiplying the capital cost by a CRF 

that corresponds to a 7% interest rate 

and 20-year equipment life (which 

yields a CRF of 0.0944), as specified in 

the Office of Management and Budget’s 

Circular A–4, Regulatory Analysis.291

Factor 2: Time Necessary for 

Compliance 

EPA found cases in which boilers 

have been retrofitted with LNB in less 

than six months. However, this does not 

take into account variables that affect 

the ability of a company to have 

equipment off-line, such as seasonal 

variations in business that may require 

Roseburg to postpone retrofit until such 

time as is appropriate. In this case, we 

would expect that the LNB can be 

installed within a maximum of 12 

months. 

RSCR systems can be operational 

within eight months to one year. 

Factor 3: Energy and Non-air Quality 

Environmental Impacts of Compliance 

LNB would reduce the heat rate that 

could be sent to the units without 

increasing the volume of the 

combustion chamber. That would have 

the effect of reducing the mass flow rate 

and heat flux through the dryers. In 

order to make up for the lost heat it may 

be possible to add an additional heat 

source; however, that would use 

additional fuel, increasing natural 

resource use. It may be possible to 

reduce the amount of ambient air mixed 

into the exhaust prior to the dryers, but 

this is unlikely because there must be 

sufficient air flow, in addition to heat, 

to reduce the moisture content of the 

product. 

RSCR requires the reheat of the flue 

gas, either through a heat exchanger that 

utilizes plant waste heat, and/or through 

direct reheat of the flue gas by 

additional combustion or electrically 

powered heating elements. The flue gas 

at the boiler exhaust is approximately 

572 °F, and the temperature of the 

exhaust of the ROEMMC varies between 

700 °F and 1050 °F. These two gas 

streams then mix with additional 

ambient air and pass through the Line 

1 and Line 2 dryers, further reducing the 

exhaust gas temperature to 130 °F to 

155 °F. In order to reheat the gas stream 

and operate the RSCR system it is 

anticipated that the following resources 

described in Table 188 would be 

required or consumed. 

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24084 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

TABLE 188—ADDITIONAL AMMONIA, NATURAL GAS, ELECTRICITY AND COMPRESSED AIR FOR RSCR 

Ammonia (NH3) Natural gas Electricity Compressed air 

Line 1 RSCR ..................... 433,000 gal/year ............... 9.7 million scf/year ............ 3.6 million kWh/year ......... 7.2 million scf/year 

Line 2 RSCR ..................... 433,000 gal/year ............... 4.7 million scf/year ............ 1.7 million kWh/year ......... 3.8 million scf/year 

Additionally, the RSCR catalyst may 

have the potential to emit NH3 (as NH3

slip) and generate nitrous oxide if not 

operated optimally. Catalysts must be 

disposed of, presenting a cost; however, 

many catalyst manufacturers provide a 

system to regenerate or recycle the 

catalyst reducing the impacts associated 

with spent catalysts. In addition to these 

considerations, there are issues 

associated with the production, 

transport, storage, and use of NH3. 

However, regular handling of NH3 has 

reduced the risks associated with its 

transport, storage, and use. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. We 

propose to eliminate the most expensive 

options (RSCR on line 1 and line 2), 

based on costs of compliance and the 

relatively small size of this facility. The 

most cost-effective option (LNB) would 

reduce emissions by only 34 tpy, which 

equates to approximately a 9.2% 

reduction in overall emissions of SO2 + 

NOX from the facility, or a reduction of 

Q/D from 12 to 11. Based on this 

benefit, the baseline Q/D, and the 

reduction in Q/D, we find it reasonable 

to eliminate this option. Therefore, we 

are proposing to not require any NOX

controls on this unit for this planning 

period. 

ROEMMC Sander Dust Burner 

Step 1: Identify All Available 

Technologies 

The ROEMMC sander dust burner 

does not currently have post 

combustion controls or low NOX

combustion technology. We identified 

that the following technologies to be 

available: SCR, RSCR, SNCR, SNCR/SCR 

hybrid, staged combustion, fuel staging, 

LNB, OFA, LEA, and FGR. SCR, SNCR, 

and LNB, OFA, LEA and FGR were 

described in our analysis for CELP. 

RSCR, SNCR/SCR hybrid, staged 

combustion, and fuel staging were 

described in our analysis for the boiler 

at Plum Creek Manufacturing. 

Step 2: Eliminate Technically Infeasible 

Options 

SCR was not considered further for 

the ROEMMC sander dust burner for the 

same reasons provided for the boiler: 

Insufficient space for both PM controls 

(necessary to avoid fouling and 

plugging) and the SCR catalyst, and 

insufficient heat from the exhaust to 

operate the dryers. 

RSCRs would be placed downstream 

of the wood particle dryers. The RSCRs 

would control emissions from the 

ROEMMC sander dust burner in 

addition to the Babcock & Wilcox boiler. 

This technology was described in the 

analysis for the boiler; for the same 

reasons it was considered feasible there, 

it is considered feasible here. 

SNCR was not considered further for 

the ROEMMC sander dust burner for the 

same reason provided for the boiler: 

reduced product quality due to contact 

with NH3. A SNCR/SCR hybrid system 

was also not considered further for the 

ROEMMC sander dust burner for the 

same reasons provided for the boiler: 

lower temperature exhaust from PM 

controls and the SCR/SNCR hybrid 

system would provide insufficient heat 

for the dryers. 

Staged combustion techniques 

increase the volume of the flame front 

for a given heat input rate. The 

ROEMMC sander dust burner is small, 

making it necessary to reduce the 

overall heat input to levels below what 

is needed to operate the dryers to 

achieve staged combustion. For this 

reason, staged combustion was not 

considered further. 

Fuel staging was not considered 

further for the same reasons provided 

for the boiler: Insufficient space to 

achieve fuel staging while maintaining 

the necessary heat input the dryers. 

LNB designs increase the length of the 

flame front. In order for the ROEMMC 

sander dust burner to operate as 

designed (with a rich and lean zone), 

the heat input to the burner would need 

to be decreased so that a smaller, yet 

longer flame could be created within the 

same physical space available with the 

current combustion chamber. The 

reduced firing rate would have the effect 

of reducing the necessary heat input 

below acceptable levels for operating 

the dryers. For these reasons, LNB was 

not considered further. 

The ROEMMC sander dust burner 

does not have sufficient space to install 

OFA ports. In addition to space 

constraints, suspension burners such as 

the ROEMMC need high air flow 

through the fuel feed auger and burner 

to suspend and fluidize the solid fuel. 

Splitting the combustion air to OFA 

ports would result in poor and perhaps 

unstable combustion at the burner tip. 

For these reasons, OFA was not 

considered further. 

LEA was not considered further for 

the ROEMMC sander dust burner for the 

same reasons provided for the boiler. 

Suspension-type burners, such as the 

ROEMMC sander dust burner, require 

high levels of air in order to fluidize the 

solid fuel. The burners would operate 

poorly with LEA. 

FGR was not considered further for 

the ROEMMC sander dust burner for the 

same reasons provided for the boiler. 

FGR reduces the available oxygen, since 

some exhaust gas replaces oxygen rich 

ambient air. Additionally, FGR may 

require increased combustion chamber 

volume to accommodate the same heat 

input while maintaining a reduced 

flame temperature. For these reasons, 

FGR was not considered further. 

All technologies identified in Step 1 

were eliminated in Step 2; therefore, our 

analysis for the ROEMMC sander dust 

burner is complete. We have determined 

that no additional controls should be 

imposed on this unit in this planning 

period. 

SolaGen Sander Dust Burner 

Step 1: Identify All Available 

Technologies 

The SolaGen sander dust burner 

currently uses LNB and FGR to control 

NOX. We identified that the following 

technologies to be available: SCR, RSCR, 

SNCR, SNCR/SCR hybrid, staged 

combustion, fuel staging, OFA, and 

LEA. SCR, SNCR, LNB, OFA, LEA and 

FGR were described in our analysis for 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24085 

292Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

CELP. RSCR, SNCR/SCR hybrid, staged 

combustion, and fuel staging were 

described in our analysis for the boiler 

at Plum Creek Manufacturing. 

Step 2: Eliminate Technically Infeasible 

Options 

SCR was not considered further for 

the SolaGen sander dust burner for the 

same reasons provided for the boiler. 

There is insufficient space prior to the 

pre-dryer to add both PM controls and 

SCR, and the exhaust from PM controls 

and SCR would be at a lower 

temperature resulting in insufficient 

heat being sent to the pre-dryer. 

SNCR was not considered further for 

the SolaGen sander dust burner for the 

same reason provided for the boiler: 

reduced product quality from contact 

with NH3. A SNCR/SCR hybrid system 

was not considered further for the 

SolaGen sander dust burner for the same 

reasons provided for the boiler: lower 

temperature exhaust from PM controls 

and the SCR/SNCR hybrid system 

would provide insufficient heat for the 

pre-dryer. 

The SolaGen sander dust burner is a 

LNB, which is a form of staged 

combustion; further staging would not 

be technically feasible for the SolaGen. 

For this reason, staged combustion was 

not considered further. 

Fuel staging was not considered 

further for the same reasons provided 

for the boiler. There is not sufficient 

room to achieve fuel staging while 

maintaining the necessary heat input for 

the pre-dryer. 

The SolaGen sander dust burner 

already utilizes a LNB design, making 

further excess air infeasible to support 

stable combustion. For this reason, OFA 

was not considered further. 

LEA was not considered further for 

the SolaGen sander dust burner for the 

same reasons provided for the boiler. 

Suspension-type burners, such as the 

SolaGen sander dust burner, require 

high levels of air in order to fluidize the 

solid fuel. The burners would operate 

poorly with LEA. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions from the 

SolaGen sander dust burner are 58 tpy. 

A summary of emissions projections for 

RSCR, the only remaining control 

technology, is provided in Table 189. 

TABLE 189—SUMMARY OF ROSEBURG NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGY

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

RSCR ............................................................................................................................... 75 43 15 

Factor 1: Costs of Compliance 

Table 190 provides a summary of 

estimated annual costs for RSCR. 

TABLE 190—SUMMARY OF ROSEBURG RSCR REASONABLE PROGRESS COST ANALYSIS

Control option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

RSCR ............................................................................................................................................................... 748,097 17,398 

We are adopting cost figures provided 

by Roseburg, except that we annualized 

the capital cost by multiplying the 

capital cost by a CRF that corresponds 

to a 7% interest rate and 20-year 

equipment life (which yields a CRF of 

0.0944), as specified in the Office of 

Management and Budget’s Circular A–4, 

Regulatory Analysis.292

Factor 2: Time Necessary for 

Compliance 

RSCR systems can be operational 

within eight months to one year. 

Factor 3: Energy and Non-air Quality 

Environmental Impacts of Compliance 

RSCR requires the reheat of the flue 

gas, either through a heat exchanger that 

utilizes plant waste heat, and/or through 

direct reheat of the flue gas by 

additional combustion or electrically 

powered heating elements. In order to 

reheat the gas stream and operate the 

RSCR system, the following resources 

described in Table 191 would be 

consumed. 

TABLE 191—ADDITIONAL AMMONIA, NATURAL GAS, ELECTRICITY AND COMPRESSED AIR REQUIRED FOR RSCR 

Ammonia (NH3) Natural gas Electricity Compressed air 

304,000 gal/year ............................ 2 million scf/year ........................... 700,000 kWh/year ........................ 1.3 million scf/year 

Environmental impacts were 

described in the analysis for the boiler. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: the cost of compliance; the 

time necessary for compliance; the 

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24086 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

293See http://www.greeninvgroup.com/news/ 

news-release-missoula-announcement.html. 

294M2Green Redevelopment LLC Quarterly 

Excess Emissions Report—Third Quarter 2011 

(11/1/2011). 

295All information found within this section can 

be found in the corresponding report in the docket. 

296Response to Additional Reasonable Progress 

Information for the Yellowstone Energy Limited 

Partnership Facility Pursuant to Section 114(a) of 

the CAA (42 U.S.C. Section 7414(A)) Prepared for 

Billings Generation, Inc. (‘‘YELP Additional 

Response’’), p. 2–1 February 24, 2011. 

297 Deseret Bonanza SOB, p. 92. 

298 Id. 

299 Id., p. 93. 

300 Deseret Bonanza SOB, p. 94. 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. We 

find it reasonable to eliminate the only 

feasible option, RSCR, on the basis of 

the costs of compliance and the 

relatively small size of this facility. 

Therefore, we are proposing that no 

additional NOX controls will be 

required for this planning period. 

ix. Smurfit Stone Container 

Smurfit Stone Container Enterprises 

Inc., Missoula Mill (purchased and 

renamed M2Green Redevelopment LLC 

Missoula Site on 5/3/11) 293 was 

determined to be below the threshold of 

sources subject to BART, but above the 

threshold for sources subject to further 

evaluation for RP controls. According to 

an emissions report from M2Green 

Redevelopment LLC, the mill was 

permanently shut down on January 12, 

2010 and is no longer operating.294

While the current owners have 

permanently shut down the mill at 

M2Green Redevelopment LLC, Missoula 

Site, and it is uncertain whether the mill 

will resume operations, should the mill 

resume operations we will revise the 

FIP as necessary in accordance with 

regional haze requirements, including 

the ‘‘reasonable progress’’ provisions in 

40 CFR 51.308(d)(1). 

x. Yellowstone Energy Limited 

Partnership 

Yellowstone Energy Limited 

Partnership (YELP), in partnership with 

Billings Generation Incorporated, owns 

an electric power plant in Billings, 

Montana.295 The plant is rated at 65 

MW gross output and includes two 

identical CFB boilers that are fired on 

petroleum coke and cooker gas; exhaust 

exits through a common stack. The 

boilers and emission controls were 

installed in 1995. 

PM emissions are controlled by two 

fabric filter baghouses at the common 

stack that is designed to achieve greater 

than 99% control of particulates.296 As 

discussed previously in Section 

V.D.6.b., the contribution from point 

sources to primary organic aerosols, EC, 

PM2.5 at Montana Class I areas is very 

small, and modeling tends to confirm 

that PM emissions from point sources 

do not have a very large impact. 

Therefore, we are proposing that 

additional controls for PM are not 

necessary for this planning period. 

SO2

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available: limestone 

injection process upgrade, a SDA, DSI, 

a CDS, HAR, a wet lime scrubber, a wet 

limestone scrubber, and/or a dual alkali 

scrubber. 

YELP currently controls SO2

emissions using limestone injection. 

Crushed limestone is injected with the 

petroleum coke prior to its combustion 

in the two CFB boilers. When limestone 

is heated to 1550 °F, it releases CO2 and 

forms lime (CaO), which subsequently 

reacts with the SO2 in the combustion 

gas to form calcium sulfates and 

calcium sulfites. The calcium 

compounds are removed as PM by the 

baghouse. Depending on the fuel fired 

in the boilers and the total heat input, 

YELP must achieve, under a Montana 

operating permit, 70% to 90% reduction 

of SO2 emissions. YELP states that, 

during 2008 through 2009, SO2

reduction averaged 95%. Increasing the 

limestone injection rate beyond current 

levels could theoretically result in a 

modest increase in SO2 control. 

SDAs were described in our analysis 

for CELP. SDAs have demonstrated the 

ability to achieve 90% to 94% SO2

reduction. SDA plus limestone injection 

can achieve between 98% and 99% SO2

reduction.297 Due to the high degree of 

SO2 control efficiency already achieved 

by limestone injection at this facility 

(95%), we have used 80% control 

efficiency for SDA in this analysis, 

downstream of limestone injection. 

DSI was described in our BART 

analysis for Corette. SO2 control 

efficiencies for DSI systems by 

themselves (not downstream of 

limestone injection systems) are 

approximately 50%, but if the sorbent is 

hydrated lime, then 80% or greater 

removal can be achieved. These systems 

are commonly called lime spray dryers. 

A description of a CDS was provided 

in our analysis for CELP. A CDS can 

achieve removal efficiency similar to 

that achieved by SDA on CFB boilers.298

The HAR process was described in 

our analysis for CELP. HAR downstream 

of a CFB boiler that utilizes limestone 

injection can reduce the remaining SO2

by about 80%.299

A general description of wet lime 

scrubbing was provided in our BART 

analysis for Ash Grove. 

Wet lime and wet limestone scrubbers 

involve spraying alkaline slurry into the 

exhaust gas to react with SO2 in the flue 

gas. Insoluble salts are formed in the 

chemical reaction that occurs in the 

scrubber and the salts are removed as a 

solid waste by-product. Wet lime and 

limestone scrubbers are very similar, but 

the type of additive used differs (lime or 

limestone). The use of limestone 

(CaCO3) instead of lime requires 

different feed preparation equipment 

and a higher liquid-to-gas ratio. The 

higher liquid-to-gas ratio typically 

requires a larger absorbing unit. The 

limestone slurry process also requires a 

ball mill to crush the limestone feed. 

Wet lime and limestone scrubbers have 

been demonstrated to achieve greater 

than 99% control efficiency.300

Dual-alkali scrubbers use a sodiumbased alkali solution to remove SO2

from the combustion exhaust gas. The 

process uses both sodium-based and 

calcium-based compounds. The sodiumbased reagents absorb SO2 from the 

exhaust gas, and the calcium-based 

solution (lime or limestone) regenerates 

the spent liquor. Calcium sulfites and 

sulfates are precipitated and discarded 

as sludge, and the regenerated sodium 

solution is returned to the absorber 

loop. The dual-alkali process requires 

lower liquid-to-gas ratios than scrubbing 

with lime or limestone. The reduced 

liquid-to-gas ratios generally mean 

smaller reaction units; however, 

additional regeneration and sludge 

processing equipment is necessary. A 

sodium-based scrubbing solution, 

typically consisting of a mixture of 

sodium hydroxide, sodium carbonates, 

and sodium sulfite, is an efficient SO2

control reagent. However, the process 

generates a sludge that can create 

material handling and disposal issues. 

The control efficiency is similar to the 

wet lime/limestone scrubbers at 

approximately 95% or greater. 

Step 2: Eliminate Technically Infeasible 

Options 

The current limestone injection 

system is operating at or near its 

maximum capacity. The boiler feed 

rates are approximately 740 tons/day of 

petroleum coke and 415 tons/day of 

limestone. Increasing limestone 

injection beyond the current levels 

would result in plugging of the injection 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24087 

301 YELP Additional Response, p. 2–2. 

302 Deseret Bonanza SOB, p. 92. 

303 Id., p. 93. 

304 YELP Additional Response, p. 2–5. 

305 Id., p. 7–3. 

306Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

lines, and increased bed ash production, 

which can reduce combustion 

efficiency, and increased particulate 

loading to the baghouses. Therefore, 

increasing limestone injection beyond 

its current level would require major 

upgrades to the limestone feeding 

system and the baghouses.301 Only 

modest increases in SO2 removal 

efficiency, if any, would be expected 

with this scenario, compared to add-on 

SO2 control systems discussed below. 

Therefore, a limestone injection process 

upgrade is eliminated from further 

consideration. 

CDS systems result in high particulate 

loading to the unit’s particulate control 

device. Because of the high particulate 

loading, the pressure drop across a 

fabric filter would be unacceptable; 

therefore, ESPs are generally used for 

particulate control. YELP has two high 

efficiency fabric filters (baghouses) in 

place. Based on limited technical data 

from non-comparable applications and 

engineering judgment, we are 

determining that CDS is not technically 

feasible for this facility.302 Therefore, 

CDS is eliminated from further 

consideration. 

A DSI system is not practical for use 

in a CFB boiler such as YELP, where 

limestone injection is already being 

used upstream in the boiler for SO2

control. With limestone injection, the 

CFB boiler flue gas already contains 

excess unreacted lime. Fly ash 

containing this unreacted lime is 

reinjected back into the CFB boiler 

combustion bed, as part of the boiler 

operating design. A DSI system would 

simply add additional unreacted lime to 

the flue gas and would achieve little, if 

any, additional SO2 control.303 If used 

instead of limestone injection (the only 

practical way it might be used), DSI 

would achieve less control efficiency 

(50%) than the limestone injection 

system already being used (70 to 90%). 

Therefore, DSI is eliminated from 

further consideration. 

Regarding wet scrubbing, there is 

limited area to install additional SO2

controls that would require high 

quantities of water and dewatering 

ponds. The wet FGD scrubber systems 

with the higher water requirements (wet 

lime scrubber, wet limestone scrubber, 

and dual alkali wet scrubber) would 

require an on-site dewatering pond or 

an additional landfill to dispose of 

scrubber sludge. Due to the limited 

available space, its proximity to the 

Yellowstone River and limited water 

availability for these controls,304 we 

consider these technologies technically 

infeasible and do not evaluate them 

further. 

The remaining technically feasible 

SO2 control options for YELP are SDA 

and HAR. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions from YELP 

are 1,826 tpy. A summary of emissions 

projections for the various control 

options is provided in Table 192. Since 

limestone injection is already in use at 

the YELP facility, the control 

efficiencies and emissions reductions 

shown below are those that might be 

achieved beyond the control already 

being achieved by the existing limestone 

injection system. 

TABLE 192—SUMMARY OF YELP SO2 REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

SDA .................................................................................................................................. 80 1,461 365 

HAR ................................................................................................................................. 50 913 913 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of compliance 

Table 193 provides a summary of 

estimated annual costs for the various 

control options. All costs shown are for 

the two boilers combined. 

TABLE 193—SUMMARY OF YELP SO2 REASONABLE PROGRESS COST ANALYSIS AS RECALCULATED BY EPA 

Control option 

Total annual 

cost 

($) 

Cost 

effectiveness 

($/ton) 

SDA with baghouse replacement .................................................................................................................... 6,237,065 4,211 

SDA without baghouse replacement ............................................................................................................... 4,709,504 3,182 

HAR with baghouse replacement .................................................................................................................... 4,660,376 5,104 

HAR without baghouse replacement ............................................................................................................... 3,132,815 3,431 

We have relied on the control costs 

provided by YELP,305 with two 

exceptions. First, we calculated the 

annual cost of capital using 7% annual 

interest rate and a 20-year equipment 

life (which yields a CRF of 0.0944), as 

specified in the Office of Management 

and Budget’s Circular A–4 Regulatory 

Analysis.306 Second, we calculated the 

cost of SDA and HAR in two ways: (1) 

With baghouse replacement, and (2) 

without baghouse replacement, see 

Table 193 above. 

Factor 2: Time Necessary for 

Compliance 

We have relied on YELP’s estimates 

that the time necessary to complete the 

modifications to the two boilers to 

accommodate SDA or HAR, without 

replacing the baghouses, would be 

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24088 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

307 YELP Additional Response, p. 3–1. 

308 Id., p. 4–2. 

309 Id. 

310 Id. 

311 Id. 

312 Deseret Bonanza SOB, pp. 46, 48. 

approximately one year and that a boiler 

outage of approximate two to three 

months per boiler would be necessary to 

perform the installation of either 

system. The installation of the controls 

would need to be staggered to allow one 

boiler to remain in operation while the 

retrofits are applied to the other boiler. 

YELP states that complete replacement 

or major modifications to the existing 

baghouses would be necessary, 

however, the company does not explain 

why the existing baghouses would need 

to be replaced or modified to 

accommodate SDA or HAR.307

Factor 3: Energy and Non-air Quality 

Environmental Impacts of Compliance 

Wet FGD systems are estimated to 

consume 1% to 2.5% of the total electric 

generation of the plant and can consume 

approximately 40% more than dry FGD 

systems (SDA). Electricity requirements 

for a HAR system are less than FGD 

systems. DSI systems are estimated to 

consume 0.1% to 0.5% of the total plant 

generation.308 For reasons explained 

above, wet FGD systems and DSI 

systems have already been eliminated as 

technically infeasible. 

SO2 controls would result in 

increased ash production at the YELP 

facility. Boiler ash is currently either 

sent to a landfill or sold for beneficial 

use, such as oil well reclamation. 

Changes in ash properties due to 

increased calcium sulfates and calcium 

sulfites could result in the ash being no 

longer suitable to be sold for beneficial 

uses. If the ash properties were to 

change such that the ash could no 

longer be sold for beneficial use, the loss 

of this market would cost approximately 

$2,300,000 per year at the current ash 

value and production rates 

(approximately 170,000 tons of ash per 

year). The loss of this market could also 

result in the company having to dispose 

of the ash at its current landfill, which 

is approximately 80 miles from the 

plant. The cost to dispose of the ash 

would be approximately $96,000 per 

year. The total cost from the loss of the 

beneficial use market and the increase 

in ash disposal costs would be a total of 

$2,400,000 per year.309 This potential 

cost has not been included in the cost 

described above, as it is only 

speculative, being based on an 

undetermined potential future change in 

ash properties. 

As described above, wet FGD scrubber 

systems with the higher water 

requirements (Wet Lime Scrubber, Wet 

Limestone Scrubber, and Dual Alkali 

Wet Scrubber) would require 

construction of an on-site dewatering 

pond or an additional landfill to dispose 

of scrubber sludge. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: the cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

sources. We are also taking into account 

the size of the facility, the baseline Q/ 

D of the facility, and the potential 

reduction in Q/D from the controls. 

Given the cost of $3,182 per ton of SO2

(at a minimum) for the most costeffective option (SDA), the relatively 

small size of YELP, and the small 

baseline Q/D of 14, we find it reasonable 

to not impose any of the SO2 control 

options. Therefore, we are proposing 

that no additional controls will be 

required for this planning period. 

NOX

Currently, there are no NOX controls 

at the YELP facility. 

Step 1: Identify All Available 

Technologies 

We identified that the following 

technologies to be available: SCR, 

SNCR, LEA, FGR, OFA, LNB, nonthermal plasma reactor, and carbon 

injection into the combustion chamber. 

SCR, SNCR, LNB, LEA, OFA, FGR, 

non-thermal plasma reactor, and carbon 

injection into the combustion chamber 

were described in our analysis for CELP. 

The temperature range for proper 

operation of an SCR is between 480 °F 

and 800 °F. Many of the CFBs in the 

United States have baghouses for 

particulate control. The normal 

maximum allowable temperature for a 

baghouse is 400 °F. 

Therefore, on some installations, 

RSCR is installed. RSCRs are expensive 

to install and expensive to operate, 

because an RSCR requires the use of 

burners to heat up the flue gas stream 

in order for the NOX capture to occur. 

This is often an efficiency decrease for 

the boiler, significant increase in 

operating cost, and often not a practical 

solution. For this reason, RSCR was not 

evaluated as a control option for YELP. 

Instead, high dust SCR was evaluated. 

Step 2: Eliminate Technically Infeasible 

Options 

LEA, FGR, and OFA are typically 

used on Pulverized Coal (PC) units and 

cannot be used on CFB boilers due to air 

needed to fluidize the bed.310 While 

LEA may have substantial effect on NOX

emissions at PC boilers, it has much less 

effect on NOX emissions at combustion 

sources such as CFBs that operate at low 

combustion temperatures. FGR reduces 

NOX formation by reducing peak flame 

temperature and is ineffective on 

combustion sources such as CFBs that 

already operate at low combustion 

temperatures. For these reasons, LEA, 

FGR and OFA are eliminated from 

further consideration. 

LNBs are typically used on PC units 

and cannot be used on CFB boilers 

because the combustion occurs within 

the fluidized bed.311 CFB boilers do not 

use burners during normal operation. 

Therefore, LNBs are eliminated from 

further consideration. 

While a non-thermal plasma reactor 

may have practical potential for 

application to coal-fired CFB boilers as 

a technology transfer option at Step 1 of 

the analysis, it is not known to be 

commercially available for CFB 

boilers.312 Therefore, a non-thermal 

plasma reactor is eliminated from 

further consideration. 

Although carbon injection is an 

emerging technology used to reduce 

mercury emissions, it has not been used 

anywhere to control NOX. Therefore, it 

is eliminated from further 

consideration. 

The remaining technically feasible 

NOX control options for YELP are 

HDSCR and SNCR. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technology 

Baseline NOX emissions from YELP 

are 396 tpy. A summary of emissions 

projections for the various control 

options is provided in Table 194. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

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313 YELP Additional Response, Appendix A. 314Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4/. 

315 YELP Additional Response, p. 3–1. 

TABLE 194—SUMMARY OF YELP NOX REASONABLE PROGRESS ANALYSIS CONTROL TECHNOLOGIES

Control option 

Control 

effectiveness 

(%) 

Emissions 

reduction 

(tpy) 

Remaining 

emissions 

(tpy) 

HDSCR ............................................................................................................................ 80 317 79 

SNCR ............................................................................................................................... 50 198 198 

Step 4: Evaluate Impacts and Document 

Results 

Factor 1: Costs of Compliance 

Table 195 provides a summary of 

estimated annual costs for the various 

control options. 

TABLE 195—SUMMARY OF YELP NOX REASONABLE PROGRESS COST ANALYSIS

Control option Total annual cost 

($) 

Cost 

effectiveness 

($/ton) 

HDSCR ............................................................................................................................................................ 3,883,020 12,249 

SNCR ............................................................................................................................................................... 529,810 2,689 

We have relied on the NOX control 

costs provided by YELP,313 with one 

exception. We calculated the annual 

cost of capital using a 7% annual 

interest rate and 20-year equipment life 

(which yields a CRF of 0.0944), as 

specified in the Office of Management 

and Budget’s Circular A–4, Regulatory 

Analysis.314

Factor 2: Time Necessary for 

Compliance 

We have relied on YELP’s estimates 

that HDSCR would take approximately 

26 months to install and that SNCR 

would take 24 to 30 weeks to install.315

Factor 3: Energy and Non-Air Quality 

Environmental Impacts of Compliance 

The energy impacts from SNCR are 

expected to be minimal. SNCR is not 

expected to cause a loss of power output 

from the facility. SCR, however, could 

cause significant backpressure on the 

boiler, leading to lost boiler efficiency 

and, thus, a loss of power production. 

If LDSCR was to be installed instead of 

HDSCR, YELP would be subject to the 

additional cost of reheating the exhaust 

gas. 

Regarding other non-air quality 

environmental impacts of compliance, 

SCRs can contribute to airheater fouling 

from the formation of ammonium 

sulfate. Airheater fouling could reduce 

unit efficiency, increase flue gas 

velocities in the airheater, cause 

corrosion, and erosion. Catalyst 

replacement can lengthen boiler 

outages, especially in retrofit 

installations, where space and access is 

limited. This is a retrofit installation in 

a high dust environment, thus fouling is 

likely, which could lead to unplanned 

outages or less time between planned 

outages. On some installations, catalyst 

life is short and SCRs have fouled in 

high dust environments. For both SCR 

and SNCR, the storage of on-site NH3

could pose a risk from potential releases 

to the environment. An additional 

concern is the loss of NH3, or ‘‘slip’’ into 

the emissions stream from the facility. 

This ‘‘slip’’ contributes another 

pollutant to the environment, which has 

been implicated as a precursor to PM2.5

formation. 

Factor 4: Remaining Useful Life 

EPA has determined that the default 

20-year amortization period is most 

appropriate to use as the remaining 

useful life of the facility. Without 

commitments for an early shut down, 

EPA cannot consider a shorter 

amortization period in our analysis. 

Step 5: Select Reasonable Progress 

Controls 

We have considered the following 

four factors: The cost of compliance; the 

time necessary for compliance; the 

energy and non-air quality 

environmental impacts of compliance; 

and the remaining useful life of the 

source. For the more expensive option 

(SCR), we have concluded that the costs 

per ton of pollutant reduced are 

excessive for this facility. The less 

expensive option (SNCR) would reduce 

emissions by 198 tpy, which equates to 

approximately an 8.9% reduction in 

overall emissions of SO2 + NOX from 

this facility, or a reduction of Q/D from 

14 to 13. Given the small size of the 

facility, the baseline Q/D, and the 

potential reduction in Q/D, we find it 

reasonable to eliminate this option. 

Therefore, we are proposing to not 

require any NOX controls on this unit 

for this planning period. 

d. Establishment of the Reasonable 

Progress Goal 

40 CFR 51.308(d)(1) of the Regional 

Haze Rule requires states to ‘‘establish 

goals (in deciviews) that provide for 

Reasonable Progress towards achieving 

natural visibility conditions’’ for each 

Class I area of the state. These RPGs 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 RPGs for 

the first planning period are goals for 

the year 2018. 

Based on (1) the results of the WRAP 

CMAQ modeling, and (2) the results of 

the four-factor analysis of Montana 

point sources, we established RPGs for 

the most impaired days for all of 

Montana’s Class I areas, as identified in 

Table 196 below. Also shown in Table 

197 is a comparison of the RPGs to the 

URP for Montana Class I areas. The 

RPGs for the 20% worst days fall short 

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24090 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

of the URP by the amounts shown in the 

table. 

TABLE 196—COMPARISON OF REASONABLE PROGRESS GOALS TO UNIFORM RATE OF PROGRESS ON MOST IMPAIRED

DAYS FOR MONTANA CLASS I AREAS

Montana class I area 

Visibility conditions on 20% worst days 

(deciview) 

Percentage of 

URP achieved 

(%) 

Average for 

20% worst 

days (baseline 

2000–2004) 

2018 URP 

goal 

RPG (WRAP 

projection) 

Anaconda-Pintler WA ...................................................................................... 13.41 12.02 12.94 34 

Bob Marshall WA ............................................................................................. 14.48 12.91 13.83 41 

Cabinet Mountains WA .................................................................................... 14.09 12.56 13.31 51 

Gates of the Mountains WA ............................................................................ 11.29 10.15 10.82 41 

Glacier NP ....................................................................................................... 22.26 19.21 21.48 26 

Medicine Lake WA ........................................................................................... 17.72 15.42 17.36 16

Mission Mountain WA ...................................................................................... 14.48 12.91 13.83 41 

Red Rock Lakes WA ....................................................................................... 11.76 10.52 11.23 43 

Scapegoat WA ................................................................................................. 14.48 12.91 13.83 41 

Selway-Bitterroot WA ....................................................................................... 13.41 12.02 12.94 34

U.L. Bend WA .................................................................................................. 15.14 13.51 14.85 18 

Yellowstone NP ............................................................................................... 11.76 10.52 11.23 43 

Our RPGs for each Class I area for 

2018 for the 20% worst days represents 

the improvement shown in Table 197. 

Our RPGs establish a slower rate of 

progress than the URP. The number of 

years necessary to attain natural 

conditions was calculated by dividing 

the amount of improvement needed by 

the rate of progress established by the 

RPGs. Table 197 shows the number of 

years it would take to attain natural 

conditions if visibility improvement 

continues at the rate of progress 

established by the RPGs. 

TABLE 197—NUMBER OF YEARS TO REACH NATURAL CONDITIONS FOR MONTANA CLASS I AREAS

Montana class I area 

2064 natural 

conditions 

(deciview) 

Average for 

20% worst 

days (Baseline 

2000–2004) 

Improvement 

needed 

(deciview) 

RPG Rate of 

improvement 

(deciview/year) 

Number of years 

to reach natural 

conditions 

Anaconda-Pintler WA ..................................................... 7.43 13.41 5.98 0.03 204 

Bob Marshall WA ........................................................... 7.73 14.48 6.75 0.04 166 

Cabinet Mountains WA .................................................. 7.52 14.09 6.57 0.05 135 

Gates of the Mountains WA .......................................... 6.38 11.29 4.91 0.03 167 

Glacier NP ...................................................................... 9.18 22.26 13.08 0.05 268 

Medicine Lake WA ......................................................... 7.89 17.72 9.83 0.02 437 

Mission Mountain WA .................................................... 7.73 14.48 6.75 0.04 166 

Red Rock Lakes WA ..................................................... 6.44 11.76 5.32 0.03 161 

Scapegoat WA ............................................................... 7.73 14.48 6.75 0.04 166 

Selway-Bitterroot WA ..................................................... 7.43 13.41 5.98 0.03 204 

U.L. Bend WA ................................................................ 8.16 15.14 6.98 0.02 385 

Yellowstone NP .............................................................. 6.44 11.76 5.32 0.03 161 

Table 198 provides a comparison of 

our RPGs for Montana to baseline 

conditions on the least impaired days. 

This comparison demonstrates that our 

RPGs will result in no degradation in 

visibility conditions in the first 

planning period. 

TABLE 198—COMPARISON OF REASONABLE PROGRESS GOALS TO BASELINE CONDITIONS ON LEAST IMPAIRED DAYS FOR

MONTANA CLASS I AREAS

Montana class I area 

Visibility conditions on 20% best 

days 

(deciview) Achieved ‘‘No 

degradation’’ 

Average for 20% (Y/N) 

best days (Baseline 2000–2004) 

RPG (WRAP 

projection) 

Anaconda-Pintler WA ...................................................................................................... 2.58 2.48 Y 

Bob Marshall WA ............................................................................................................. 3.85 3.60 Y 

Cabinet Mountains WA .................................................................................................... 3.62 3.27 Y 

Gates of the Mountains WA ............................................................................................ 1.71 1.54 Y 

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TABLE 198—COMPARISON OF REASONABLE PROGRESS GOALS TO BASELINE CONDITIONS ON LEAST IMPAIRED DAYS FOR

MONTANA CLASS I AREAS—Continued 

Montana class I area 

Visibility conditions on 20% best 

days 

(deciview) Achieved ‘‘No 

degradation’’ 

Average for 20% (Y/N) 

best days (Baseline 2000–2004) 

RPG (WRAP 

projection) 

Glacier NP ....................................................................................................................... 7.22 6.92 Y 

Medicine Lake WA ........................................................................................................... 7.26 7.11 Y 

Mission Mountain WA ...................................................................................................... 3.85 3.60 Y 

Red Rock Lakes WA ....................................................................................................... 2.58 2.36 Y 

Scapegoat WA ................................................................................................................. 3.85 3.60 Y 

Selway-Bitterroot WA ....................................................................................................... 2.58 2.48 Y 

U.L. Bend WA .................................................................................................................. 4.75 4.57 Y 

Yellowstone NP ............................................................................................................... 2.58 2.36 Y 

The Regional Haze Rule states that if 

we establish a RPG that provides for a 

slower rate of improvement in visibility 

than the rate that would be needed to 

attain natural conditions by 2064, we 

must demonstrate that the rate of 

progress for the implementation plan to 

attain natural conditions by 2064 is not 

reasonable; and that the progress goal 

we adopt is reasonable. 40 CFR 

51.308(d)(1)(B)(ii). 

We are proposing that the RPGs we 

established for the Montana Class I areas 

are reasonable, and that it is not 

reasonable to achieve the glide path in 

2018, for the following reasons: 

1. Findings from our four-factor 

analyses resulted in limited 

opportunities for reasonable controls for 

point sources. 

2. As described previously in section 

V.D.2., significant visibility impairment 

is caused by non-anthropogenic sources 

in and outside Montana. 

We could not re-run the WRAP 

modeling, but anticipate that the 

additional controls would result in an 

increase in visibility improvement 

during the 20% worst days and the 20% 

best days. As noted in our analyses, 

many of our proposed controls would 

result in significant incremental 

visibility benefits when modeled against 

natural background. We anticipate that 

this would translate into some 

measurable improvement if modeled on 

the 20% worst days as well. We are 

confident that this improvement would 

not be sufficient to achieve the URP at 

Montana Class I areas. 

For purposes of this action, we are 

proposing RPGs that are consistent with 

the additional controls we are 

proposing. While we would prefer to 

quantify the RPGs, we note that the 

RPGs themselves are not enforceable 

values. The more critical elements of 

our FIP are the enforceable emissions 

limits we are proposing. 

e. Reasonable Progress Consultation 

In accordance with 40 CFR 

51.308(d)(3)(i) and (ii), each state that 

causes or contributes to impairment in 

a Class I area in another state or states 

is required to consult with other states 

and demonstrate that it has included in 

its SIP all measures necessary to obtain 

its share of the emission reductions 

needed to meet the progress goals for 

the Class I area. If the state has 

participated in a regional planning 

process, the state must ensure it has 

included all measures needed to achieve 

its apportionment of emission reduction 

obligations agreed upon through that 

process. 

In this case, where EPA is 

promulgating a FIP, we take on the 

responsibilities of the state. We propose 

that we have met the requirement for 

consultation with other states through 

our participation in the WRAP process. 

Through this processes, we worked with 

neighboring states, and relied on the 

technical tools, policy documents, and 

other products that all western states 

used to develop their regional haze 

plans. The WRAP Implementation Work 

Group was one of the primary 

collaboration mechanisms. Discussions 

with neighboring states included the 

review of major contributing sources of 

air pollution, as documented in 

numerous WRAP reports and projects. 

The focus of this review process was 

interstate transport of emissions, major 

sources believed to be contributing, and 

whether any mitigation measures were 

needed. All the states relied upon 

similar emission inventories, results 

from source apportionment studies and 

BART modeling, review of IMPROVE 

monitoring data, existing state smoke 

management programs, and other 

information in assessing the extent to 

which each state contributes to visibility 

impairment other states’ Class I areas. 

The Regional Haze Rule at 40 CFR 

51.308(d)(3)(ii) requires a state to 

demonstrate that its regional haze plan 

includes all measures necessary to 

obtain its fair share of emission 

reductions needed to meet RPGs. Based 

on the consultation described above, we 

identified no major contributions that 

supported developing new interstate 

strategies, mitigation measures, or 

emission reduction obligations. Both 

EPA and neighboring states agreed that 

the implementation of BART and other 

existing measures in state regional haze 

plans were sufficient for the states to 

meet the RPGs for their Class I areas, 

and that future consultation would 

address any new strategies or measures 

needed. 

f. Mandatory Long-Term Strategy 

Requirements 

40 CFR 51.308(d)(3)(v) requires that 

we, at a minimum, consider certain 

factors in developing our LTS (the LTS 

factors). These are: (a) Emission 

reductions due to ongoing air pollution 

control programs, including measures to 

address RAVI; (b) measures to mitigate 

the impacts of construction activities; 

(c) emissions limitations and schedules 

for compliance to achieve the RPG; (d) 

source retirement and replacement 

schedules; (e) smoke management 

techniques for agricultural and forestry 

management purposes including plans 

as 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 LTS. 

i. Reductions Due to Ongoing Air 

Pollution Programs 

In addition to our BART 

determinations, our LTS incorporates 

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24092 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

316WRAP TSD. and Final Report, WRAP Mobile 

Source Emission Inventories Updated, dated May 

2006. 

317Email from Debbie Skibicki to Vanessa Hinkle 

dated January 4, 2012 regarding Roundup Power. 

emission reductions due to a number of 

ongoing air pollution control programs. 

a. Prevention of Significant 

Deterioration/New Source Review Rules 

The two primary regulatory tools for 

addressing visibility impairment from 

industrial sources are BART and the 

PSD New Source Review rules. The PSD 

rules protect visibility in Class I areas 

from new industrial sources and major 

changes to existing sources. Title 17, 

Chapter 8 of the ARM contain 

requirements for visibility impact 

assessment and mitigation associated 

with emissions from new and modified 

major stationary sources. A primary 

responsibility of Montana under these 

rules is visibility protection. ARM 

17.8.1106 requires an owner or operator 

of a major source or major modification 

to demonstrate that the emissions will 

not cause or contribute to adverse 

impact on a Class I area or the 

Department shall not issue a permit. 

ARM 17.8.1107 describes the modeling 

methods. 

b. Montana’s Phase I Visibility 

Protection Program 

Montana’s Visibility SIP was 

approved as meeting the requirements 

of 40 CFR 51.305 (Monitoring for RAVI) 

and 40 CFR 51.307 (New Source 

Review) on June 6, 1986 (51 FR 20646). 

On February 17, 2012, Montana 

submitted a revised Visibility SIP, 

which as explained in the submittal, 

includes administrative updates to rule 

citations, board affiliation, and 

grammar/punctuation edits to these 

sections. 

EPA will act on the revisions to the 

sections addressing monitoring for 

RAVI, new source review, and other 

sections in a future action. 

c. On-going Implementation of State and 

Federal Mobile Source Regulations 

Mobile source NOX and SO2

emissions are expected to decrease in 

Montana from 2002 to 2018.316 This 

reduction will result from numerous 

‘‘on the books’’ federal mobile source 

regulations described below. This trend 

is expected to provide significant 

visibility benefits. Beginning in 2006, 

EPA mandated new standards for onroad (highway) diesel fuel, known as 

ultra-low sulfur diesel. This regulation 

dropped the sulfur content of diesel fuel 

from 500 ppm to 15 ppm. Ultra-low 

sulfur diesel fuel enables the use of 

cleaner technology diesel engines and 

vehicles with advanced emissions 

control devices, resulting in 

significantly lower emissions. 

Diesel fuel intended for locomotive, 

marine, and non-road (farming and 

construction) engines and equipment 

was required to meet a low sulfur diesel 

fuel maximum specification of 500 ppm 

sulfur in 2007 (down from 5000 ppm). 

By 2010, the ultra-low sulfur diesel fuel 

standard of 15 ppm sulfur applied to all 

non-road diesel fuel. Locomotive and 

marine diesel fuel will be required to 

meet the ultra-low sulfur diesel 

standard beginning in 2012, resulting in 

further reductions of diesel emissions. 

ii. Measures to Mitigate the Impacts of 

Construction Activities 

In developing our LTS, we have 

considered the impact of construction 

activities. Based on our general 

knowledge of construction activity in 

the State, and without conducting 

extensive research on the contribution 

of emissions from construction activities 

to visibility impairment in Montana 

Class I areas, we propose to find that 

current State regulations adequately 

address construction activities because 

the regulations already require controls 

for these sources. Current rules 

addressing impacts from construction 

activities in Montana include ARM 

17.8.308, which regulates fugitive dust 

emissions. The rule requires that ‘‘no 

person shall operate a construction site 

or demolition project unless reasonable 

precautions are taken to control 

emissions of airborne particulate 

matter.’’ The SIP rule also requires that 

‘‘[s]uch emissions of airborne 

particulate matter from any stationary 

source shall not exhibit an opacity of 

20% or greater averaged over six 

consecutive minutes.’’ Additionally, 

emissions from vehicles at construction 

site are expected to decrease due to ongoing implementation of federal mobile 

source regulations. ARM 18.8.743 

requires permits for asphalt concrete 

plants, mineral crushers, and mineral 

screens that have a potential to emit that 

is greater than 15 tpy. 

iii. Emission Limitations and Schedules 

for Compliance 

For those sources subject to BART: 

Ash Grove Cement Company; PPL 

Montana, LLC Colstrip Steam Electric 

Station (Unit 1 and Unit 2); Holcim 

(US), Inc.; and PPL Montana, LLC JE 

Corette Steam Electric Station, we have 

included proposed emission limits and 

schedules of compliance in regulatory 

text at the end of this proposal. 

As described earlier in Section 

V.C.3.b.iii, we are proposing that we 

make a BART determination in the 

future for CFAC if the sources at that 

facility begin operating. Additionally, 

we also are proposing that those sources 

at CFAC will be required to implement 

that determination within five years of 

our final FIP for this action. 

For the source that is subject to 

additional controls for RP requirements, 

Devon, we have included proposed 

emission limits and schedules of 

compliance in regulatory text at the end 

of this proposal. 

We are proposing to determine 

whether additional controls will be 

required for Green Investment Group, 

Inc. (previously owned by Smurfit Stone 

Container Enterprises Inc.) if the sources 

at that facility begin operating. We also 

are proposing that those sources will be 

required to implement any additional 

controls that are required by those 

determinations within this planning 

period. The proposed schedules for 

implementation of additional controls 

for this source is identified within the 

four factor analyses for this source. 

iv. Sources Retirement and Replacement 

Schedules 

Even though the sources at CFAC and 

Green Investment Group Inc. are not 

currently operating, we are not relying 

on those source retirements or 

replacements in the LTS. Replacement 

of existing facilities will be managed 

according to Montana’s existing PSD 

program. The 2018 modeling that WRAP 

conducted included one new power 

plant in Montana that is unlikely to be 

built.317 Construction of new power 

plants or replacement of existing plants 

prior to 2018 is unlikely. 

v. Agricultural and Forestry Smoke 

Management Techniques 

We are proposing to use the WRAP’s 

estimates of fire emissions in our 

analysis for Montana. Table 199, below, 

shows WRAP’s estimate of emissions 

from fire in Montana for the 2000–2004 

baseline period. 

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318WRAP TSD; Development of 2000–04 Baseline 

Period and 2018 Projection Year Emission 

Inventories, FINAL dated May 2007; Emissions 

Overview, for which WRAP did not include a date; 

2002 Planning Simulation Version D Specification 

Sheet for which WRAP did not include a date; 1996 

Fire Emission Inventory dated December 2002. The 

actual inventories can be found in the docket in the 

spreadsheets with the following title: 02d Area 

Source Inventory. 

319There are several key elements of Montana’s 

existing smoke management program, which 

include: (1) Smoke is monitored in Montana 

(http://www.satguard.com/usfs4/realtime/MT.asp); 

(2) the open burning SIP regulations require best 

available control technology (BACT) as the 

visibility mitigation measure for open burning 

administered through MDEQ’s open burning permit 

program; and (3) the State participates in Montana 

State Airshed Group, which implements an 

enhanced smoke management plan (information on 

the Montana State Airshed Group can be found at 

http://www.smokemu.org/about.cfm). 

320State of Montana Air Quality Control 

Implementation Plan, Volume I, Chapter 9, p. 9.6(8) 

(Dec. 2, 2011). 

TABLE 199—ANNUAL AVERAGE EMISSIONS FROM FIRE (2000–2004) (TONS/YEAR) 

Source PM2.5 PM10 NOX SO2 OC EC 

Natural .............................................................................. 2,911 8,496 13,770 4,634 38,324 7,743 

Anthropogenic .................................................................. 279 713 1,513 500 3,745 759 

Total .......................................................................... 3,190 9,209 15,283 5,134 42,069 8,502 

A more detailed description of the 

inventories can be found in the 

docket.318 40 CFR 308(d)(3)(v)(E) of the 

Regional Haze Rule requires the LTS to 

address smoke management techniques 

for agricultural and forestry burning. 

These two sources generally have a very 

small contribution to visibility 

impairment in Montana Class I areas. 

Much of these fire emissions are from 

wildfires, which fluctuate significantly 

from year to year. The following 

paragraph summarizes source 

apportionment analyses conducted by 

the WRAP. 

As described previously in Sections 

V.D.6.b., most of the emissions from fire 

are from wildfires which fluctuate 

significantly from year to year. 

Anthropogenic fire contributes 8% to 

primary organic aerosol emissions, 6% 

to EC emissions, less than 1% to PM2.5

emissions, less than 1% to PM10

emissions, 1% to SO2 emissions, and 

less than 1% to NOX emissions. Natural 

fire contributes 80% to primary organic 

aerosol emissions, 65% to EC emissions, 

4% to PM2.5 emissions, 1% to PM10

emissions, 9% to SO2 emissions, and 

6% to NOX emissions. As described 

previously in Section V.D.2., OC 

contributes 15% to 64%, EC contributes 

4% to 8%, fine particulate contributes 

1% to 7%, coarse particulate contributes 

4% to 8%, SO2 contributes 8% to 28%, 

and NOX contributes 3% to 27% of the 

total light extinction to Montana Class I 

areas. 

40 CFR 308(d)(3)(v)(E) of the Regional 

Haze Rule requires states to consider 

smoke management techniques for 

agricultural and forestry burning in their 

LTS. We are proposing to approve 

amendments to Montana’s existing 

smoking management program that will 

ensure that the State’s program meets 

the Regional Haze Rule requirement. 

Montana’s existing smoke 

management program regulates major 

and minor sources of open burning; and 

the State operates a year round open 

burning program as well as issues air 

quality open burning permits for 

specific types of open burning.319 On 

February 17, 2012, Montana submitted a 

revised Montana Visibility Plan (Plan) 

that contained revisions to the smoke 

management program. As described in 

Montana’s ‘‘Explanation of Proposed 

Action’’ the revised Plan ‘‘includes a 

reference to BACT as the current 

visibility mitigation measure for open 

burning administered through the 

Department’s open burning permit 

program’’. The revised Plan requires 

Montana to consider the visibility 

impact of smoke on the mandatory 

federal class I areas when developing, 

issuing or conditioning permits and 

when making dispersion forecast 

recommendations through the 

implementation of Title 17, Chapter 8, 

Subchapter 6, Open Burning. These 

revisions appear in the paragraph of the 

Plan titled ‘‘Smoke Management’’.320

We are proposing that to approve the 

revisions to this paragraph titled 

‘‘Smoke Management’’ as meeting the 

requirement in 40 CFR 308(d)(3)(v)(E) 

because the Plan controls emissions 

from these sources by requiring BACT 

and takes into consideration the 

visibility impacts on the mandatory 

class I areas. We will take action in a 

future notice on the additional revisions 

in the Montana Visibility Plan, which as 

explained in the State’s February 17, 

2012 submittal include administrative 

updates to rule citations, board 

affiliation, and grammar/punctuation 

edits. 

vi. Enforceability of Montana’s 

Measures 

40 CFR 51.308(d)(3)(v)(F) of the 

Regional Haze Rule requires us to 

ensure that emission limitations and 

control measures used to meet RPGs are 

enforceable. In addition to what is 

required by the Regional Haze Rule, 

general FIP requirements mandate that 

the FIP must also include adequate 

monitoring, recordkeeping, and 

reporting requirements for the regional 

haze emission limits and requirements. 

See CAA section 110(a). As noted, we 

are proposing specific BART and other 

emission limits and compliance 

schedules. For SO2 and NOX limits, we 

are proposing to require the use of 

CEMS that must be operated and 

maintained in accordance with relevant 

EPA regulations, in particular, 40 CFR 

part 75. For PM limits, we are requiring 

regular testing. We are proposing to 

require that relevant records be kept for 

five years, and that sources report 

excess emissions on a quarterly basis. 

In addition to these requirements, 

various requirements that are relevant to 

regional haze are codified in Montana’s 

regulations, including Montana’s PSD 

and other provisions mentioned above. 

vii. 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.4 above. 

E. Coordination of RAVI and Regional 

Haze Requirements 

Our visibility regulations direct states 

to coordinate their RAVI LTS and 

monitoring provisions with those for 

regional haze, as explained in section 

IV.G, 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 

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321 Visibility Monitoring Guidance, EPA–454/R– 

99–003, June 1999, http://www.epa.gov/ttn/amtic/ 

files/ambient/visible/r-99-003.pdf. 

322 Guidance for Tracking Progress Under the 

Regional Haze Rule, EPA–454/B–03–004, 

September 2003, available at http://www.epa.gov/ 

ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf. Figure 

1–2 shows the monitoring network on a map, while 

Table A–2 lists Class I areas and corresponding 

monitors. 

323Spatial and Seasonal Patterns and Temporal 

Variability of Haze and its Constituents in the 

United States, Report V, ISSN 0737–5352–87, June 

2011. 

area. The FLMs did not identify any 

integral vistas in Montana. In addition, 

there have been no certifications of 

RAVI in the Montana Class I areas, nor 

are any Montana sources affected by the 

RAVI provisions. We commit to 

coordinate the Montana regional haze 

LTS with our RAVI FIP LTS. We 

propose to find that the Regional Haze 

FIP appropriately supplements and 

augments the EPA FIP for RAVI 

visibility provisions by updating the 

monitoring and LTS provisions to 

address regional haze. We discuss the 

relevant monitoring provisions further 

below. 

F. Monitoring Strategy and Other 

Implementation Plan Requirements 

40 CFR 51.308(d)(4) requires that the 

FIP contain a monitoring strategy for 

measuring, characterizing, and reporting 

regional haze 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 regional 

haze for all mandatory Class I Federal 

areas within the state are being 

achieved. Consistent with EPA’s 

monitoring regulations for RAVI and 

regional haze, EPA will rely on the 

IMPROVE network for compliance 

purposes, in addition to any RAVI 

monitoring that may be needed in the 

future. Further information on 

monitoring methods and monitor 

locations can be found in the 

docket.321 322 The most recent report also 

can be found in the docket.323

Therefore, we propose to find that we 

have satisfied the requirements of 40 

CFR 51.308(d)(4) enumerated in this 

paragraph. 

40 CFR 51.308(d)(4)(ii) requires that 

EPA establish procedures by which 

monitoring data and other information 

are used in determining the contribution 

of emissions from within Montana to 

regional haze 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, participation in the IMPROVE 

program constitutes compliance with 

this requirement. 

40 CFR 51.308(d)(4)(iv) requires that 

the FIP 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, EPA 

should report visibility monitoring data 

electronically. 40 CFR 51.308(d)(4)(vi) 

also requires that the FIP provide for 

other elements, including reporting, 

recordkeeping, and other measures, 

necessary to assess and report on 

visibility. We propose that EPA’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. 

40 CFR 51.308(d)(4)(v) requires that 

EPA 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. EPA must also include a 

commitment to update the inventory 

periodically. Please refer to section 

V.D.1, above, where we discuss EPA’s 

emission inventory for Montana. EPA 

proposes that we will update statewide 

emissions inventories periodically and 

review periodic emissions information 

from other states and future emissions 

projections. Additionally, during the 

next planning period EPA intends to 

review and consider emissions from oil 

and gas activities, as well as from other 

sources. Therefore, we propose that this 

satisfies the requirement. 

G. Coordination With FLMs 

The Forest Service manages 

Anaconda-Pintler WA, Bob Marshall 

WA, Cabinet Mountains WA, Gates of 

the Mountains WA, Mission Mountains 

WA, Scapegoat WA, and SelwayBitterroot WA. The Fish and Wildlife 

Service manages the Medicine Lake 

WA, Red Rocks Lake WA, and U.L. 

Bend WA. The National Park Service 

manages Glacier NP and Yellowstone 

NP. Although the FLMs are very active 

in participating in the RPOs, the 

Regional Haze Rule grants the FLMs a 

special role in the review of regional 

haze FIPs, summarized in section IV.H, 

above. 

Initially, MDEQ met the requirement 

of 40 CFR 51.308(i)(1) by sending letters 

to the FLMs dated November 5, 1999. 

The letters included the title of the 

official to which the FLM of any 

mandatory Class I Federal area could 

submit any recommendations on the 

implementation of the regional haze 

rule including the identification of 

impairment of visibility in any 

mandatory Class I Federal area(s) and 

the identification of elements for 

inclusion in the visibility monitoring 

strategy required by 40 CFR 51.305 and 

the regional haze rule. 

Under 40 CFR 51.308(i)(2), we were 

obligated to provide the Forest Service, 

the Fish and Wildlife Service, and the 

National Park Service with an 

opportunity for consultation, in person 

and at least 60 days prior to holding a 

public hearing on the Regional Haze 

FIP. We sent a draft of our Regional 

Haze FIP to the Forest Service, the Fish 

and Wildlife Service, and the National 

Park Service on February 16, 2012 and 

March 5, 2012. We notified the FLMs of 

our public hearings (as initially 

scheduled) on March 14, 2012. 40 CFR 

51.308(i)(3) requires that we provide in 

our Regional Haze FIP a description of 

how we addressed any comments 

provided by the FLMs. We revised our 

proposed Regional Haze FIP to 

incorporate comments received by the 

FLMs. 

Lastly, 40 CFR 51.308(i)(4) specifies 

the regional haze FIP must provide 

procedures for continuing consultation 

with the FLMs on the implementation of 

the visibility protection program 

required by 40 CFR 51.308, including 

development and review of 

implementation plan revisions and 

5-year progress reports, and on the 

implementation of other programs 

having the potential to contribute to 

impairment of visibility in mandatory 

Class I Federal areas. We commit to 

continue to coordinate and consult with 

the FLMs as required by 40 CFR 

51.308(i)(4). We intend to consult the 

FLMs in the development and review of 

implementation plan revisions; review 

of progress reports; and development 

and implementation of other programs 

that may contribute to impairment of 

visibility at Montana and other Class I 

areas. 

We are proposing that we have 

complied with the requirements of 

40 CFR 51.308(i). 

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H. Periodic FIP Revisions and Five-Year 

Progress Reports 

Consistent with 40 CFR 51.308(g), we 

are committing to prepare a progress 

report in the form of a FIP revision, 

every five years following the final FIP. 

The FIP revision will evaluate progress 

towards the RPG for each mandatory 

Class I Federal area located within 

Montana and in each mandatory Class I 

Federal area located outside Montana 

that may be affected by emissions from 

within Montana. The FIP revision will 

include all the activities in 40 CFR 

51.308(g). 

VI. Proposed Action 

A. Montana Visibility SIP 

B. We are proposing to approve the 

changes to one of the sections of 

Montana’s Visibility SIP that were 

submitted on February 17, 2012 that 

includes amendments to the ‘‘Smoke 

Management’’ section, which adds a 

reference to BACT as the visibility 

control measure for open burning as 

currently administered through the 

State’s air quality permit program. 

Montana Regional Haze FIP 

We are proposing the promulgation of 

a FIP to address Regional Haze for 

Montana that we have identified in this 

proposal. The proposed FIP includes the 

following elements: 

• For Ash Grove Cement: 

Æ A NOX BART determination and 

emission limit of 8 lb/ton clinker that 

applies on a 30-day rolling average, and 

a requirement that the owners/operators 

comply with this NOX BART limit 

within five (5) years of the effective date 

of our final rule. 

Æ A SO2 BART determination and 

emission limit of 11.5 lb/ton clinker that 

applies on a 30-day rolling average, and 

a requirement that the owners/operators 

comply with this SO2 BART limit 

within 180 days of the effective date of 

our final rule. 

Æ The following PM BART 

determination and emission limit: if the 

process weight rate of the kiln is less 

than or equal to 30 tons per hour, then 

the emission limit shall be calculated 

using E=4.10p0.67 where E = rate of 

emission in pounds per hour and p = 

process weight rate in tons per hour; 

however, if the process weight rate of 

the kiln is greater than 30 tons per hour, 

then the emission limit shall be 

calculated using E = 55.0p0.11¥40, 

where E = rate of emission in pounds 

per hour and P = process weight rate in 

tons per hour. This limit applies on a 

30-day rolling average, and a 

requirement that the owners/operators 

comply with this PM BART limit within 

30 days of the effective date of our final 

rule. 

• For Colstrip Units 1 and 2: 

Æ NOX BART determinations and 

emission limits of 0.15 lb/MMBtu that 

apply singly to each of these units on a 

30-day rolling average, and a 

requirement that the owners/operators 

comply with these NOX BART limits 

within five (5) years of the effective date 

of our final rule. 

Æ SO2 BART determinations and 

emission limits of 0.08 lb/MMBtu that 

apply singly to each of these units on a 

30-day rolling average, and a 

requirement that the owners/operators 

comply with these SO2 BART limits 

within five (5) years of the effective date 

of our final rule. 

Æ PM BART determinations and 

emission limits of 0.10 lb/MMBtu that 

apply singly to each of these units on a 

30-day rolling average, and a 

requirement that the owners/operators 

comply with these PM BART limits 

within 30 days of the effective date of 

our final rule. 

• For Holcim: 

Æ A NOX BART determination and 

emission limit of 5.5 lbs/ton clinker 

produced that applies on a 30-day 

rolling average, and a requirement that 

the owners/operators comply with this 

NOX BART limit within five (5) years of 

the effective date of our final rule. 

Æ A SO2 BART determination and 

emission limit of 1.3 lbs/ton clinker 

produced that applies on a 30-day 

rolling average, and a requirement that 

the owners/operators comply with this 

SO2 BART limit within 180 days of the 

effective date of our final rule. 

Æ A PM BART determination and 

emission limit of 0.77 lb/ton clinker 

produced that applies on a 30-day 

rolling average, and a requirement that 

the owners/operators comply with this 

PM BART limit within 30 days of the 

effective date of our final rule. 

• For Corette: 

Æ A NOX BART determination and 

emission limit of .40 lb/MMBtu that 

applies on a 30-day rolling average, and 

a requirement that the owners/operators 

comply with this NOX BART limit 

within 30 days of the effective date of 

our final rule. 

Æ A SO2 BART determination and 

emission limit of 0.70 lb/MMBtu that 

applies on a 30-day rolling average, and 

a requirement that the owners/operators 

comply with this SO2 BART limit 

within 30 days of the effective date of 

our final rule. 

Æ A PM BART determination and 

emission limit of 0.10 lb/MMBtu that 

applies on a 30-day rolling average, and 

a requirement that the owners/operators 

comply with this PM BART limit within 

30 days of the effective date of our final 

rule. 

• For Devon Energy Blaine County #1 

Compressor Station, a NOX emission 

limit of 21.8 lb/hr that applies on a 30- 

day rolling average, and a requirement, 

as described in our proposed regulatory 

text for 40 CFR § 52.1395, that the 

owners/operators comply with this limit 

as expeditiously as practicable, but no 

later than July 31, 2018. 

• For CFAC, CFAC must notify EPA 

60 days in advance of resuming 

operation. Once CFAC notifies EPA that 

it intends to resume operation, EPA will 

initiate and complete a BART 

determination after notification and 

revise the FIP as necessary in 

accordance with regional haze 

requirements, including the BART 

provisions in 40 CFR 51.308(e). CFAC 

will be required to install any controls 

that are required as soon as practicable, 

but in no case later than five years 

following the effective date of this 

action. 

• For the M2Green Redevelopment 

LLC, Missoula Site, M2Green 

Redevelopment LLC must notify EPA 60 

days in advance of resuming operation. 

Once M2 Green Redevelopment LLC 

notifies EPA that it intends to resume 

operation, EPA will initiate and 

complete a four factor analysis after 

notification and revise the FIP as 

necessary in accordance with regional 

haze requirements including the 

‘‘reasonable progress’’ provisions in 40 

CFR 51.308(d)(1). M2 Green 

Redevelopment LLC will be required to 

install any controls that are required as 

soon as practicable, but in no case later 

than July 31, 2018. 

• Monitoring, recordkeeping, and 

reporting requirements for the above six 

units to ensure compliance with these 

emission limitations. 

• RPGs consistent with the proposed 

FIP limits. 

• LTS elements that reflect the other 

aspects of the proposed FIP. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 12866 

(58 FR 51735, October 4, 1993) and is 

therefore not subject to review under 

Executive Orders 12866 and 13563 

(76 FR 3821, January 21, 2011). As 

discussed in detail in section C below, 

the proposed FIP applies to only six 

sources. It is therefore not a rule of 

general applicability. 

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24096 Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *.’’ 44 U.S.C. 3502(3)(A). 

Because the proposed FIP applies to just 

six facilities, the Paperwork Reduction 

Act does not apply. See 5 CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a federal 

agency. This includes the time needed 

to review instructions; develop, acquire, 

install, and utilize technology and 

systems for the purposes of collecting, 

validating, and verifying information, 

processing and maintaining 

information, and disclosing and 

providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid 

Office of Management and Budget 

(OMB) control number. The OMB 

control numbers for our regulations in 

40 CFR are listed in 40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. EPA’s 

proposal consists of the proposed partial 

approval of Montana’s Regional Haze 

SIP submission and the proposed 

Regional Haze FIP by EPA that adds 

additional controls to certain sources. 

The Regional Haze FIP that EPA is 

proposing for purposes of the regional 

haze program consists of imposing 

federal controls to meet the BART 

requirement for PM, NOX and SO2

emissions on specific units at five 

sources in Montana, and imposing 

controls to meet the RP requirement for 

NOX emissions at one additional source 

in Montana. The net result of the FIP 

action is that EPA is proposing direct 

emission controls on selected units at 

six sources. The sources in question are 

two large electric generating plants, two 

cement plants, and one gas compressor 

station, and none of these sources are 

not owned by small entities, and 

therefore are not small entities. The 

proposed partial approval of the SIP, if 

finalized, merely approves state law as 

meeting federal requirements and 

imposes no additional requirements 

beyond those imposed by state law. See 

Mid-Tex Electric Cooperative, Inc. v. 

FERC, 773 F.2d 327 (D.C. Cir. 1985) 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 

inflation) in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

one year. In addition, this proposed rule 

does not contain a significant federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

affect small governments. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 

1999) revokes and replaces Executive 

Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental 

Partnership). Executive Order 13132 

requires EPA to develop an accountable 

process to ensure ‘‘meaningful and 

timely input by State and local officials 

in the development of regulatory 

policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ Under 

Executive Order 13132, EPA may not 

issue a regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by State and local 

governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

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regulation. EPA also may not issue a 

regulation that has federalism 

implications and that preempts State 

law unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

This rule will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

merely addresses the State not fully 

meeting its obligation to prohibit 

emissions from interfering with other 

states measures to protect visibility 

established in the CAA. Thus, Executive 

Order 13132 does not apply to this 

action. In the spirit of Executive Order 

13132, and consistent with EPA policy 

to promote communications between 

EPA and State and local governments, 

EPA specifically solicits comment on 

this proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

Consultation and Coordination with 

Indian Tribal Governments (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. It will not 

have substantial direct effects on tribal 

governments. Thus, Executive Order 

13175 does not apply to this rule. 

However, EPA did send letters, dated 

October 7, 2011, to each of the Montana 

Tribes explaining our regional haze FIP 

action and offering consultation. We did 

not receive any written or verbal 

requests from the Montana Tribes for 

more information or consultation. As a 

follow-up to our letter, we invited all of 

the Tribes to a January 5, 2012 

conference call. The call was attended 

by tribal Air Program Managers and one 

Environmental Director from tribes from 

four reservations. We will be offering to 

meet with the Montana Tribes prior to 

the start of the public hearings being 

held in Helena and Billings, Montana. 

EPA specifically solicits additional 

comment on this proposed rule from 

tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. EPA 

interprets EO 13045 as applying only to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this proposed rule will limit 

emissions of NOX, SO2, and PM, the rule 

will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. 

The EPA believes that VCS are 

inapplicable to this action. Today’s 

action does not require the public to 

perform activities conducive to the use 

of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this 

proposed rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

This proposed rule limits emissions of 

NOX SO2 and PM from six sources in 

Montana. 

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 20, 2012. 

James B. Martin, 

Regional Administrator, Region 8. 

40 CFR part 52 is proposed to be 

amended as follows: 

PART 52—[AMENDED] 

1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart BB—Montana 

2. Section 52.1370 is amended by 

revising paragraph (c)(27)(i)(H) to read 

as follows: 

§ 52.1370 Identification of plan. 

* * * * * 

(c) * * * 

(27) * * * 

(i) * * * 

(H) Appendix G–2, Montana Smoke 

Management Plan, effective April 15, 

1988, is superseded by § 52.1365. 

* * * * * 

3. Add § 52.1395 to read as follows: 

§ 52.1395 Smoke management plan. 

The Department considers smoke 

management techniques for agriculture 

and forestry management burning 

purposes as set forth in 40 CFR 

51.308(d)(3)(v)(E). The Department 

considers the visibility impact of smoke 

when developing, issuing, or 

conditioning permits and when making 

dispersion forecast recommendations 

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through the implementation of Title 17, 

Chapter 8, subchapter 6, ARM, Open 

Burning. 

4. Add section 52.1396 to read as 

follows: 

§ 52.1396 Federal implementation plan for 

regional haze. 

(a) Applicability. This section applies 

to each owner and operator of the 

following coal fired electric generating 

units (EGUs) in the State of Montana: 

PPL Montana, LLC, Colstrip Power 

Plant, Units 1, 2; and PPL Montana, 

LLC, JE Corette Steam Electric Station. 

This section also applies to each owner 

and operator of cement kilns at the 

following cement production plants: 

Ash Grove Cement, Montana City Plant; 

and Holcim (US) Inc. Cement, Trident 

Plant. This section also applies to each 

owner or operator of Blaine County #1 

Compressor Station. This section also 

applies to each owner and operator of 

CFAC and M2 Green Redevelopment 

LLC, Missoula site. 

(b) Definitions. Terms not defined 

below shall have the meaning given 

them in the Clean Air Act or EPA’s 

regulations implementing the Clean Air 

Act. For purposes of this section: 

Boiler operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

EGU. It is not necessary for fuel to be 

combusted for the entire 24-hour period. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of SO2 or 

NOX emissions, other pollutant 

emissions, diluent, or stack gas 

volumetric flow rate. 

Kiln operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which the 

kiln operates. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises an EGU identified in 

paragraph (a) of this section. 

PM means filterable total particulate 

matter. 

SO2 means sulfur dioxide. 

Unit means any of the EGUs or 

cement kilns identified in paragraph (a) 

of this section. 

(c) Emissions limitations. (1) The 

owners/operators of EGUs subject to this 

section shall not emit or cause to be 

emitted PM, SO2 or NOX in excess of the 

following limitations, in pounds per 

million British thermal units (lb/ 

MMBtu), averaged over a rolling 30-day 

period: 

Source name PM Emission limit 

(lb/MMBtu) 

SO2 Emission limit 

(lb/MMBtu) 

NOX Emission limit 

(lb/MMBtu) 

Colstrip Unit 1 .......................................................................................... 0.10 0.08 0.15 

Colstrip Unit 2 .......................................................................................... 0.10 0.08 0.15 

JE Corette Unit 1 ..................................................................................... 0.10 0.70 0.40 

(2) The owners/operators of cement 

kilns subject to this section shall not 

emit or cause to be emitted PM, SO2 or 

NOX in excess of the following 

limitations, in pounds per ton of clinker 

produced, averaged over a rolling 30- 

day period: 

Source name PM Emission limit (lb/ton clinker) SO2 Emission limit 

(lb/ton clinker) 

NOX Emission limit 

(lb/ton clinker) 

Ash Grove Cement ................................... If the process weight rate of the kiln is less than or 

equal to 30 tons per hour, then the emission limit 

shall be calculated using E = 4.10p 0.67 where E 

= rate of emission in pounds per hour and p = 

process weight rate in tons per hour; however, if 

the process weight rate of the kiln is greater than 

30 tons per hour, then the emission limit shall be 

calculated using E = 55.0p 0.11-40, where E = 

rate of emission in pounds per hour and P = 

process weight rate in tons per hour..

11.5 8.0 

Holcim (US) Inc. ........................................ 0.77 lb/ton ................................................................ 1.3 5.5 

(3) The owners/operators of LP, 

Blaine County #1 Compressor Station 

shall not emit or cause to be emitted 

NOX in excess of 21.8 lbs/hr (30-day 

rolling average). 

(4) These emission limitations shall 

apply at all times, including startups, 

shutdowns, emergencies, and 

malfunctions. 

(d) Compliance date. The owners and 

operators of Blaine County #1 

Compressor Station shall comply with 

the emissions limitation and other 

requirements of this section 

expeditiously as practicable, but no later 

than July 31, 2018. The owners and 

operators of the BART sources subject to 

this section shall comply with the 

emissions limitations and other 

requirements of this section within five 

years of the effective date of this rule 

unless otherwise indicated in specific 

paragraphs. 

(e) Compliance determinations for 

SO2 and NOX. (1) CEMS for EGUs. At all 

times after the compliance date 

specified in paragraph (d) of this 

section, the owner/operator of each unit 

shall maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR part 75, 

to accurately measure SO2, NOX, 

diluent, and stack gas volumetric flow 

rate from each unit. The CEMS shall be 

used to determine compliance with the 

emission limitations in paragraph (c) of 

this section for each unit. 

(2) Method for EGUs. (i) For any hour 

in which fuel is combusted in a unit, the 

owner/operator of each unit shall 

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calculate the hourly average SO2 and 

NOX concentration in lb/MMBtu at the 

CEMS in accordance with the 

requirements of 40 CFR part 75. At the 

end of each boiler operating day, the 

owner/operator shall calculate and 

record a new 30-day rolling average 

emission rate in lb/MMBtu from the 

arithmetic average of all valid hourly 

emission rates from the CEMS for the 

current boiler operating day and the 

previous 29 successive boiler operating 

days. 

(ii) An hourly average SO2 or NOX

emission rate in lb/MMBtu is valid only 

if the minimum number of data points, 

as specified in 40 CFR part 75, is 

acquired by both the pollutant 

concentration monitor (SO2 or NOX) and 

the diluent monitor (O2 or CO2). 

(iii) Data reported to meet the 

requirements of this section shall not 

include data substituted using the 

missing data substitution procedures of 

subpart D of 40 CFR part 75, nor shall 

the data have been bias adjusted 

according to the procedures of 40 CFR 

part 75. 

(3) CEMS for cement kilns. At all 

times after the compliance date 

specified in paragraph (d) of this 

section, the owner/operator of each unit 

shall maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.63(f), 

to accurately measure concentration by 

volume of SO2 and NOX emissions into 

the atmosphere from each unit. The 

CEMS shall be used to determine 

compliance with the emission 

limitations in paragraph (c) of this 

section for each unit, in combination 

with data on actual clinker production. 

(4) Method for cement kilns. (i) The 

owner/operator of each unit shall record 

the daily clinker production rates. 

(ii) The owner/operator of each unit 

shall calculate and record the 30- 

operating day rolling emission rates of 

SO2 and NOX, in lb/ton of clinker 

produced, as the total of all hourly 

emissions data for the cement kiln in 

the preceding 30 days, divided by the 

total tons of clinker produced in that 

kiln during the same 30-day operating 

period, using the following equation: 

E = (CsQs)/(PK) 

Where: 

E = emission rate of SO2 or NOX, lb/ton of 

clinker produced 

Cs = concentration of SO2 or NOX, in grains 

per standard cubic foot (gr/scf); 

Qs = volumetric flow rate of effluent gas, 

where Cs and Qs are on the same basis 

(either wet or dry), scf/hr; 

P = total kiln clinker production rate, tons/ 

hr, and 

K = conversion factor, 7000 gr/lb. 

Hourly clinker production shall be 

determined in accordance with the 

requirements found at 40 CFR 60.63(b). 

(iii) At the end of each kiln operating 

day, the owner/operator of each unit 

shall calculate and record a new 30-day 

rolling average emission rate in lb/ton 

clinker from the arithmetic average of 

all valid hourly emission rates for the 

current kiln operating day and the 

previous 29 successive kiln operating 

days. 

(5) The owner/operator of Blaine 

County #1 Compressor Station shall 

install a temperature-sensing device (i.e. 

thermocouple or resistance temperature 

detectors) before the catalyst in order to 

monitor the inlet temperatures of the 

catalyst for each engine. The owner/ 

operator shall maintain the engine at a 

minimum of at least 750°F and no more 

than 1250°F in accordance with 

manufacturer’s specifications. Also, the 

owner/operator shall install gauges 

before and after the catalyst for each 

engine in order to monitor pressure 

drop across the catalyst, and that the 

owner/operator maintain the pressure 

drop within ± 2’’ water at 100% load 

plus or minus 10% from the pressure 

drop across the catalyst measured 

during the initial performance test. The 

owner/operator shall follow the 

manufacturer’s recommended 

maintenance schedule and procedures 

for each engine and its respective 

catalyst. The owner/operator shall only 

fire each engine with natural gas that is 

of pipeline-quality in all respects except 

that the CO2 concentration in the gas 

shall not be required to be within 

pipeline-quality. 

(f) Compliance determinations for 

particulate matter. (1) EGU particulate 

matter BART limits. Compliance with 

the particulate matter BART emission 

limits for each EGU BART unit shall be 

determined from annual performance 

stack tests. Within 60 days of the 

compliance deadline specified in 

paragraph (d) of this section, and on at 

least an annual basis thereafter, the 

owner/operator of each unit shall 

conduct a stack test on each unit to 

measure particulate emissions using 

EPA Method 5, 5B, 5D, or 17, as 

appropriate, in 40 CFR part 60, 

Appendix A. A test shall consist of three 

runs, with each run at least 120 minutes 

in duration and each run collecting a 

minimum sample of 60 dry standard 

cubic feet. Results shall be reported in 

lb/MMBtu. In addition to annual stack 

tests, owner/operator shall monitor 

particulate emissions for compliance 

with the BART emission limits in 

accordance with the applicable 

Compliance Assurance Monitoring 

(CAM) plan developed and approved in 

accordance with 40 CFR part 64. 

(2) Cement kiln particulate matter 

BART limits. Compliance with the 

particulate matter BART emission limits 

for each cement kiln shall be 

determined from annual performance 

stack tests. Within 60 days of the 

compliance deadline specified in 

paragragh (d) of this section, and on at 

least an annual basis thereafter, the 

owner/operator of each unit shall 

conduct a stack test on each unit to 

measure particulate matter emissions 

using EPA Method 5, 5B, 5D, or 17, as 

appropriate, in 40 CFR part 60, 

Appendix A. A test shall consist of three 

runs, with each run at least 120 minutes 

in duration and each run collecting a 

minimum sample of 60 dry standard 

cubic feet. The emission rate (E) of 

particulate matter, in lb/ton clinker, 

shall be computed for each run using 

the equation in paragraph (e)(4)(ii) of 

this section above. Clinker production 

shall be determined in accordance with 

the requirements found at 40 CFR 

60.63(b). Results of each test shall be 

reported as the average of three valid 

test runs. In addition to annual stack 

tests, owner/operator shall monitor 

particulate emissions for compliance 

with the BART emission limits in 

accordance with the applicable 

Compliance Assurance Monitoring 

(CAM) plan developed and approved in 

accordance with 40 CFR part 64. 

(g) Recordkeeping for EGUs. Owner/ 

operator shall maintain the following 

records for at least five years: 

(1) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(2) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 

40 CFR Part 75 . 

(3) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(4) Any other records required by 

40 CFR part 75. 

(h) Recordkeeping for cement kilns. 

Owner/operator shall maintain the 

following records for at least five years: 

(1) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(2) All particulate matter stack test 

results. 

(3) All records of clinker production. 

(4) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 

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40 CFR part 60, appendix F, Procedure 

1. 

(5) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, CEMS 

and clinker production measurement 

devices. 

(6) Any other records required by 

40 CFR part 75, 40 CFR part 60, Subpart 

F, or 40 CFR part 60, Appendix F, 

Procedure 1. 

(i) Reporting. All reports under this 

section, with the exception of 40 CFR 

53.1395(n) and (o), shall be submitted to 

the Director, Office of Enforcement, 

Compliance and Environmental Justice, 

U.S. Environmental Protection Agency, 

Region 8, Mail Code 8ENF–AT, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129. 

(1) Owner/operator of each unit shall 

submit quarterly excess emissions 

reports for SO2 and NOX BART limits no 

later than the 30th day following the 

end of each calendar quarter. Excess 

emissions means emissions that exceed 

the emissions limits specified in 

paragraph (c) of this section. The reports 

shall include the magnitude, date(s), 

and duration of each period of excess 

emissions, specific identification of 

each period of excess emissions that 

occurs during startups, shutdowns, and 

malfunctions of the unit, the nature and 

cause of any malfunction (if known), 

and the corrective action taken or 

preventative measures adopted. 

(2) Owner/operator of each unit shall 

submit quarterly CEMS performance 

reports, to include dates and duration of 

each period during which the CEMS 

was inoperative (except for zero and 

span adjustments and calibration 

checks), reason(s) why the CEMS was 

inoperative and steps taken to prevent 

recurrence, and any CEMS repairs or 

adjustments. 

(i) For EGUs: Owner/operator of each 

unit shall also submit results of any 

CEMS performance tests required by 

40 CFR part 75 (Relative Accuracy Test 

Audits, Relative Accuracy Audits, and 

Cylinder Gas Audits). 

(ii) For cement kilns: Owner/operator 

of each unit shall also submit results of 

any CEMS performance tests required 

by 40 CFR part 60, appendix F, 

Procedure 1 (Relative Accuracy Test 

Audits, Relative Accuracy Audits, and 

Cylinder Gas Audits). 

(3) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, such information 

shall be stated in the quarterly reports 

required by sections (h)(1) and (2) of 

this section. 

(4) Owner/operator of each unit shall 

submit results of any particulate matter 

stack tests conducted for demonstrating 

compliance with the particulate matter 

BART limits in paragragh (c) of this 

section. 

(j) Monitoring, recordkeeping, and 

reporting requirements for Blaine 

County #1 Compressor Station: 

(1) The owner/operator shall measure 

NOX emissions from each engine at least 

semi-annually or once every six month 

period to demonstrate compliance with 

the emission limits. To meet this 

requirement, the owner/operator shall 

measure NOX emissions from the 

engines using a portable analyzer and a 

monitoring protocol approved by EPA. 

(2) The owner/operator shall submit 

the analyzer specifications and 

monitoring protocol to EPA for approval 

within 45 calendar days prior to 

installation of the NSCR unit. 

(3) Monitoring for NOX emissions 

shall commence during the first 

complete calendar quarter following the 

owner/operator’s submittal of the initial 

performance test results for NOX to EPA. 

(4) The owner/operator shall measure 

the engine exhaust temperature at the 

inlet to the oxidation catalyst at least 

once per week and shall measure the 

pressure drop across the oxidation 

catalyst monthly. 

(5) Each temperature-sensing device 

shall be accurate to within plus or 

minus 0.75% of span and that the 

pressure sensing devices be accurate to 

within plus or minus 0.1 inches of 

water. 

(6) The owner/operator shall keep 

records of all temperature and pressure 

measurements; vendor specifications for 

the thermocouples and pressure gauges; 

vendor specifications for the NSCR 

catalyst and the air-to-fuel ratio 

controller on each engine. 

(7) The owner/operator shall keep 

records sufficient to demonstrate that 

the fuel for the engines is pipelinequality natural gas in all respects, with 

the exception of the CO2 concentration 

in the natural gas. 

(8) The owner/operator shall keep 

records of all required testing and 

monitoring that include: The date, 

place, and time of sampling or 

measurements; the date(s) analyses were 

performed; the company or entity that 

performed the analyses; the analytical 

techniques or methods used; the results 

of such analyses or measurements; and 

the operating conditions as existing at 

the time of sampling or measurement. 

(9) The owner/operator shall maintain 

records of all required monitoring data 

and support information (e.g. all 

calibration and maintenance records, all 

original strip-chart recordings for 

continuous monitoring instrumentation, 

and copies of all reports required) for a 

period of at least five years from the 

date of the monitoring sample, 

measurement, or report and that these 

records be made available upon request 

by EPA. 

(10) The owner/operator shall submit 

a written report of the results of the 

required performance tests to EPA 

within 90 calendar days of the date of 

testing completion. 

(k) Notifications. (1) Owner/operator 

shall submit notification of 

commencement of construction of any 

equipment which is being constructed 

to comply with the SO2 or NOX

emission limits in paragraph (c) of this 

section. 

(2) Owner/operator shall submit semiannual progress reports on construction 

of any such equipment. 

(3) Owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(l) Equipment operation. At all times, 

owner/operator shall maintain each 

unit, including associated air pollution 

control equipment, in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. 

(m) Credible evidence. Nothing in this 

section shall preclude the use, including 

the exclusive use, of any credible 

evidence or information, relevant to 

whether a source would have been in 

compliance with requirements of this 

section if the appropriate performance 

or compliance test procedures or 

method had been performed. 

(n) CFAC notification. CFAC must 

notify EPA 60 days in advance of 

resuming operation. CFAC shall submit 

such notice to the Director, Air Program, 

U.S. Environmental Protection Agency, 

Region 8, Mail Code 8P–AR, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129. Once CFAC notifies EPA 

that it intends to resume operation, EPA 

will initiate and complete a BART 

determination after notification and 

revise the FIP as necessary in 

accordance with regional haze 

requirements, including the BART 

provisions in 40 CFR 51.308(e). CFAC 

will be required to install any controls 

that are required as soon as practicable, 

but in no case later than five years 

following the effective date of this rule. 

(o) M2Green Redevelopment LLC 

notification. M2Green Redevelopment 

LLC must notify EPA 60 days in 

advance of resuming operation. 

M2Green Redevelopment LLC shall 

submit such notice to the Director, Air 

Program, U.S. Environmental Protection 

Agency, Region 8, Mail Code 8P–AR, 

1595 Wynkoop Street, Denver, Colorado 

80202–1129. Once M2 Green 

Redevelopment LLC notifies EPA that it 

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Federal Register / Vol. 77, No. 77 / Friday, April 20, 2012 / Proposed Rules 24101 

intends to resume operation, EPA will 

initiate and complete a four factor 

analysis after notification and revise the 

FIP as necessary in accordance with 

regional haze requirements including 

the ‘‘reasonable progress’’ provisions in 

40 CFR 51.308(d)(1). M2 Green 

Redevelopment LLC will be required to 

install any controls that are required as 

soon as practicable, but in no case later 

than July 31, 2018. 

[FR Doc. 2012–8367 Filed 4–13–12; 8:30 am] 

BILLING CODE 6560–50–P 

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