[Federal Register Volume 77, Number 77 (Friday, April 20, 2012)]
[Proposed Rules]
[Pages 23988-24101]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-8367]



[[Page 23987]]

Vol. 77

Friday,

No. 77

April 20, 2012

Part III





Environmental Protection Agency





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40 CFR Part 52





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

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

[[Page 23988]]


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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.

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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:
    <bullet> http://www.regulations.gov. Follow the on-line 
instructions for submitting comments.
    <bullet> Email: <a href="/cdn-cgi/l/email-protection#b5c78dd4dcc7c7c0d9d0d8d4dedcdbd2c6f5d0c5d49bd2dac3"><span class="__cf_email__" data-cfemail="c2b0faa3abb0b0b7aea7afa3a9abaca5b182a7b2a3eca5adb4">[email protected]</span></a>.
    <bullet> Fax: (303) 312-6064 (please alert the individual listed in 
FOR FURTHER INFORMATION CONTACT if you are faxing comments).
    <bullet> Mail: Carl Daly, Director, Air Program, Environmental 
Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, 
Denver, Colorado 80202-1129.
    <bullet> Hand Delivery: Carl Daly, Director, Air Program, 
Environmental Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 
Wynkoop, Denver, Colorado 80202-1129. Such deliveries are only accepted 
Monday through Friday, 8 a.m. to 4:30 p.m., excluding federal holidays. 
Special arrangements should be made for deliveries of boxed 
information.
    Instructions: Direct your comments to Docket ID No. EPA-R08-OAR-
2011-0851. 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, 
<a href="/cdn-cgi/l/email-protection#83ebeaede8efe6adf5e2ede6f0f0e2c3e6f3e2ade4ecf5"><span class="__cf_email__" data-cfemail="8de5e4e3e6e1e8a3fbece3e8fefeeccde8fdeca3eae2fb">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. General Information
II. What Action is EPA Proposing to Take?
III. Background
    A. Regional Haze
    B. Requirements of the CAA and EPA's Regional Haze Rule
    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

[[Page 23989]]

    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 BART-Eligible 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 ``Four-Factor'' 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-to-fuel.
    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 NO<INF>X</INF> 
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 mid-kiln 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 NH<INF>3</INF> mean or refer to ammonia.
    lvii. The initials NO<INF>X</INF> mean or refer to nitrogen 
oxides.
    lviii. The initials NP mean or refer to National Park.
    lix. The initials NSCR mean or refer to non-selective 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 PM<INF>2.5</INF> mean or refer to 
particulate matter with an aerodynamic diameter of less than 2.5 
micrometers (fine particulate matter).

[[Page 23990]]

    lxviii. The initials PM<INF>10</INF> 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 SO<INF>2</INF> 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 (PM<INF>2.5</INF>) (e.g., 
sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and 
soil dust), and their precursors (e.g., sulfur dioxide 
(SO<INF>2</INF>), nitrogen oxides (NO<INF>X</INF>), and in some cases, 
ammonia (NH<INF>3</INF>) and volatile organic compounds (VOC)). Fine 
particle precursors react in the atmosphere to form PM<INF>2.5</INF>, 
which impairs visibility by scattering and absorbing light. Visibility 
impairment reduces the clarity, color, and visible distance that one 
can see. PM<INF>2.5</INF> can also cause serious health effects and 
mortality in humans and contributes to environmental effects such as 
acid deposition and eutrophication.
    Data from the existing visibility monitoring network, the 
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE) 
monitoring network, show that visibility impairment caused by air 
pollution occurs virtually all the time at most national park (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

[[Page 23991]]

kilometers, or about one-half to two-thirds of the visual range that 
would exist without anthropogenic air pollution. In most of the eastern 
Class I areas of the United States, the average visual range is less 
than 30 kilometers, or about one-fifth of the visual range that would 
exist under estimated natural conditions. 64 FR 35715 (July 1, 1999).
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    \1\ Visual range is the greatest distance, in kilometers or 
miles, at which a dark object can be viewed against the sky.
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B. Requirements of the CAA and EPA's Regional Haze Rule

    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.
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    \2\ Areas designated as mandatory Class I Federal areas consist 
of national parks exceeding 6000 acres, wilderness areas and 
national memorial parks exceeding 5000 acres, and all international 
parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a). 
In accordance with section 169A of the CAA, EPA, in consultation 
with the Department of Interior, promulgated a list of 156 areas 
where visibility is identified as an important value. 44 FR 69122 
(November 30, 1979). The extent of a mandatory Class I area includes 
subsequent changes in boundaries, such as park expansions. 42 U.S.C. 
7472(a). Although states and tribes may designate as Class I 
additional areas which they consider to have visibility as an 
important value, the requirements of the visibility program set 
forth in section 169A of the CAA apply only to ``mandatory Class I 
Federal areas.'' Each mandatory Class I Federal area is the 
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i). 
When we use the term ``Class I area'' in this action, we mean a 
``mandatory Class I Federal area.''
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    Congress added section 169B to the CAA in 1990 to address 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\
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    \3\ Albuquerque/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).
    \4\ EPA's regional haze regulations require subsequent updates 
to the regional haze SIPs. 40 CFR 51.308(g)-(i).
---------------------------------------------------------------------------

    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 Sec.  110(c)(1).

C. Roles of Agencies in Addressing Regional Haze

    Successful implementation of the regional haze program will require 
long-term regional coordination among states, tribal governments and 
various federal agencies. As noted above, pollution affecting the air 
quality in Class I areas can be transported over long distances, even 
hundreds of kilometers. Therefore, to effectively address the problem 
of visibility impairment in Class I areas, states, or the EPA when 
implementing a FIP, need to develop strategies in coordination with one 
another, taking into account the effect of emissions from one 
jurisdiction on the air quality in another.
    Because the pollutants that lead to regional haze can originate 
from sources located across broad geographic areas, EPA has encouraged 
the states and tribes across the United States to address visibility 
impairment from a regional perspective. Five regional planning 
organizations (RPOs) were developed to address regional haze and 
related issues. The RPOs first evaluated technical information to 
better understand how their states and tribes impact Class I areas 
across the country, and then pursued the development of regional 
strategies to reduce emissions of particulate matter (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

[[Page 23992]]

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

    \5\ Letter 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \6\ The preamble to the Regional Haze Rule provides additional 
details about the deciview. 64 FR 35714, 35725 (July 1, 1999).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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

[[Page 23993]]

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 ``BART-eligible'' sources that may be 
anticipated to cause or contribute to any visibility impairment in a 
Class I area. Rather than requiring source-specific BART controls, 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.
---------------------------------------------------------------------------

    \8\ The set of ``major stationary sources'' potentially subject 
to BART is listed in CAA section 169A(g)(7).
---------------------------------------------------------------------------

    On July 6, 2005, EPA published the Guidelines for BART 
Determinations Under the Regional Haze Rule at appendix Y to 40 CFR 
part 51 (hereinafter referred to as the ``BART Guidelines'') to assist 
states, 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.
---------------------------------------------------------------------------

    \9\ BART-eligible sources are those sources that have the 
potential to emit 250 tons or more of a visibility-impairing air 
pollutant, were not in operation prior to August 7, 1962, but were 
in existence on August 7, 1977, and whose operations fall within one 
or more of 26 specifically listed source categories. 40 CFR 51.301.
---------------------------------------------------------------------------

    States, 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 
SO<INF>2</INF>, NO<INF>X</INF>, and PM. EPA has stated that we should 
use our best judgment in determining whether VOC or NH<INF>3</INF> 
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 BART-eligible 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

[[Page 23994]]

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:
    <bullet> Procedures for using monitoring data and other information 
in a state with mandatory Class I areas to determine the contribution 
of emissions from within the state to regional haze visibility 
impairment at Class I areas both within and outside the state;
    <bullet> Procedures for using monitoring data and other information 
in a state with no mandatory Class I areas to determine the 
contribution of emissions from within the state to regional haze 
visibility impairment at Class I areas in other states;
    <bullet> Reporting of all visibility monitoring data to the 
Administrator at least annually for each Class I area in the state, and 
where possible, in electronic format;
    <bullet> Developing a statewide inventory of emissions of 
pollutants that are reasonably anticipated to cause or contribute to 
visibility impairment in any Class I area. The inventory must include 
emissions for a baseline year, emissions for the most recent year for 
which data are available, and estimates of future projected emissions. 
A state must also make a commitment to update the inventory 
periodically; and
    <bullet> Other elements, including reporting, recordkeeping, and 
other measures necessary to assess and report on visibility.
    The 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.

[[Page 23995]]

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

    \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'').

  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
----------------------------------------------------------------------------------------------------------------
                                                     20% Worst days                          20% Best days
                                 -------------------------------------------------------------------------------
                                                                2018
      Montana class I area         2000-2004     2018 URP    Reduction   2064 Natural   2000-2004   2064 Natural
                                    Baseline       Goal        needed     conditions     Baseline    conditions
                                   (deciview)   (deciview)     (delta     (deciview)    (deciview)   (deciview)
                                                             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

[[Page 23996]]

accurate estimates of the various factors that affect the calculation 
of light extinction.
---------------------------------------------------------------------------

    \11\ The IMPROVE program is a cooperative measurement effort 
governed by a steering committee composed of representatives from 
Federal agencies (including representatives from EPA and the FLMs) 
and 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.
---------------------------------------------------------------------------

    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
------------------------------------------------------------------------
                                                    20% Worst   20% Best
                   Class I area                        days       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
------------------------------------------------------------------------
                                                    20% Worst   20% Best
                   Class I area                        days       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 (light-
absorbing carbon), fine soil, and coarse mass terms, do not change 
between the original and new IMPROVE equations.
---------------------------------------------------------------------------

    \12\ The 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.
---------------------------------------------------------------------------

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

    \13\ The 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, b<INF>ext</INF> expressed 
in inverse megameters (Mm<SUP>-1</SUP>), as follows: HI = 10 
ln(b<INF>ext</INF>/10).
---------------------------------------------------------------------------

    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
------------------------------------------------------------------------
                                                    20% Worst   20% Best
                   Class I area                        days       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
------------------------------------------------------------------------
                                                    20% Worst   20% Best
                   Class I area                        days       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

[[Page 23997]]

 
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                     Total
                                                                       Baseline      Natural    improvement by      URP        2018 URP   Improvement by
                            Class I area                              conditions    visibility       2064        (deciview/     target         2018
                                                                      (deciview)    (deciview)    (deciview)       year)      (deciview)    (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.
---------------------------------------------------------------------------

    \14\ Additional data and information can be found at: http://views.cira.colostate.edu/web/DataFiles/SummaryDataFiles.aspx.

                                       Table 7--Species-Specific Light Extinction Determined From Monitoring Data
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Organic   Elemental                          Coarse      Total
                    Class I area                       Deciview   Sulfate    Nitrate     carbon     carbon      Soil     Sea salt    matter   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.

[[Page 23998]]

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 BART-eligible sources; (2) an assessment of 
whether those BART-eligible sources are in fact subject to BART; and 
(3) a determination of any BART controls. 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\
---------------------------------------------------------------------------

    \15\ This list can be found in the docket with the title, 
Montana BART-Eligible Facility List.
    \16\ Correspondence between ASARCO LLC and EPA can be found in 
the docket in the file titled ASARCO Correspondence.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \17\ The flow charts that Montana used to identify BART-eligible 
sources are included in the docket in a file titled Montana BART 
Flow Charts.
    \18\ Examples of the letters sent to the Montana facilities are 
included in the docket in a file titled Montana Letters.
---------------------------------------------------------------------------

    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 visibility-impairing 
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 
BART-eligible, not known, or not BART-eligible.\19\
---------------------------------------------------------------------------

    \19\ The 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''.
---------------------------------------------------------------------------

    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 BART-eligible: 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 
BART-eligible'', ``not known'', or ``not BART-eligible'' are not BART-
eligible.
    The BART Guidelines require that we address SO<INF>2</INF>, 
NO<INF>X</INF>, and direct PM (including both coarse particulate matter 
(PM<INF>10</INF>) and PM<INF>2.5</INF>) 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 NH<INF>3</INF> 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 NH<INF>3</INF> 
and VOC emissions.\20\ As a result, we have determined that the 
emissions from these point sources do not merit BART review.
---------------------------------------------------------------------------

    \20\ WRAP TSS Information.
---------------------------------------------------------------------------

    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 Source category
         BART-eligible source                  Location                   (SC)             Nearest class I area
----------------------------------------------------------------------------------------------------------------
1. Ash Grove Cement Company..........  Montana City, western    Portland cement plants.  Gates of the Mountains
                                        Montana.                                          WA 30 km.
2. Cenex Harvest States Cooperatives   Laurel, central Montana  Petroleum refineries...  North Absaroka WA 113
 Laurel Refinery.                                                                         km.
3. PPL Montana, LLC Colstrip Steam     Colstrip, southeastern   Fossil-fuel fired steam  U.L. Bend WA 200 km.
 Electric Station (Unit 1 and Unit 2).  Montana.                 electric plants of
                                                                 more than 250 million
                                                                 BTUs per hour heat
                                                                 input.
4. Columbia Falls Aluminum Company,    Columbia Falls,          Primary aluminum ore     Glacier NP 10 km.
 LLC.                                   northwestern Montana.    reduction plants.
5. ExxonMobil Refinery & Supply        Billings, central        Petroleum refineries...  North Absaroka WA 143
 Company, Billings Refinery.            Montana.                                          km.

[[Page 23999]]

 
6. Holcim (US), Inc..................  Three Forks, western     Portland cement plants.  Yellowstone NP 100 km.
                                        Montana.
7. PPL Montana, LLC--JE Corette Steam  Billings, central        Fossil-fuel fired steam  North Absaroka WA 137
 Electric Station.                      Montana.                 electric plants of       km.
                                                                 more than 250 million
                                                                 BTUs per hour heat
                                                                 input.
8. Montana Sulfur & Chemical Company.  Billings, central        Chemical process plants  North Absaroka WA 143
                                        Montana.                                          km.
9. Smurfit-Stone Container             Missoula, northwestern   Kraft pulp mills and     Selway-Bitterroot WA 32
 Enterprises Inc., Missoula Mill.       Montana.                 fossil fuel boilers of   km.
                                                                 more than 250 million
                                                                 BTUs per hour heat
                                                                 input.
----------------------------------------------------------------------------------------------------------------

2. Sources Subject to BART
    The second step of the BART evaluation is to identify those BART-
eligible sources that may reasonably be anticipated to cause or 
contribute to any visibility impairment at any Class I area, i.e., 
those sources that are subject to BART. The BART Guidelines allow us to 
consider exempting some BART-eligible sources from further BART review 
because they may not reasonably be anticipated to cause or contribute 
to any visibility impairment in a Class I area. Consistent with the 
BART Guidelines, 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)).
---------------------------------------------------------------------------

    \21\ Note that our reference to CALPUFF encompasses the entire 
CALPUFF modeling system, which includes the CALMET, CALPUFF, and 
CALPOST models and other pre and post processors. The different 
versions of CALPUFF have corresponding versions of CALMET, CALPOST, 
etc. which may not be compatible with previous versions (e.g., the 
output from a newer version of CALMET may not be compatible with an 
older version of CALPUFF). The different versions of the CALPUFF 
modeling system are available from the model developer at http://www.src.com/calpuff/calpuff1.htm.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \22\ This 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.
---------------------------------------------------------------------------

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.

[[Page 24000]]



              Table 9--Individual BART-Eligible Source Visibility Impacts on Montana Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                         Maximum 24-hour
                                                         98th percentile
         Source and unit               Class I area        visibility            Subject to BART or exempt
                                                             impact
                                                           (deciview)
----------------------------------------------------------------------------------------------------------------
1. Ash Grove Cement Company......  Gates of the                     2.52  Subject to BART.
                                    Mountains WA.
                                   Scapegoat WA.......              0.42
                                   Anaconda-Pintler WA              0.09
                                   Bob Marshall WA....              0.39
                                   Mission Mountains                0.06
                                    WA.
                                   Selway-Bitterroot                0.01
                                    WA.
                                   Yellowstone NP.....              0.01
                                   Red Rock Lakes WA..              0.00
                                   Theodore Roosevelt               0.10
                                    NP.
                                   North Absaroka WA..              0.00
                                   Washakie WA........              0.00
                                   Teton WA...........              0.00
2. Cenex Harvest States            North Absaroka WA..              0.04  Exempt.
 Cooperatives, Laurel Refinery.
                                   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                     0.00
                                    Mountains WA.
3. PPL Montana, LLC Colstrip       U.L. Bend WA.......              2.52  Subject to BART.
 Steam Electric Station Units 1
 and 1.
                                   North Absaroka WA..              1.35
                                   Theodore Roosevelt               2.28
                                    NP.
                                   Washakie WA........              0.69
                                   Yellowstone NP.....              0.86
4. Columbia Falls Aluminum         Glacier NP.........              4.54  Subject to BART.
 Company, LLC.
                                   Bob Marshall WA....              0.11
                                   Mission Mountains                0.08
                                    WA.
                                   Cabinet Mountains                0.12
                                    WA.
                                   Scapegoat WA.......              0.05
                                   Selway-Bitterroot                0.03
                                    WA.
                                   Gates of the                     0.03
                                    Mountains WA.
                                   Anaconda-Pintler WA              0.02
5. ExxonMobil Refinery & Supply    North Absaroka WA..              0.27  Exempt.
 Company, Billings Refinery.\23\
                                   Yellowstone NP.....              0.17
                                   Washakie WA........              0.22
                                   U.L. Bend WA.......              0.23
                                   Teton WA...........              0.10
                                   Gates of the                     0.22
                                    Mountains WA.
                                   Red Rock Lakes WA..              0.09
6. Holcim (US), Inc..............  Yellowstone NP.....              0.52  Subject to BART.
                                   Gates of the                     1.02
                                    Mountains WA.
                                   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               0.08
                                    NP.
                                   Selway-Bitterroot                0.15
                                    WA.
                                   Mission Mountains                0.12
                                    WA.
                                   Glacier NP.........              0.11
7. PPL Montana, LLC-JE Corette     North Absaroka WA..              0.74  Subject to BART.
 Steam Electric Station.
                                   Yellowstone NP.....              0.45
                                   Washakie WA........              0.53
                                   U.L. Bend WA.......              0.91
                                   Teton WA...........              0.22
                                   Gates of the                     0.52
                                    Mountains WA.
                                   Red Rock Lakes WA..              0.21
8. Montana Sulfur & Chemical       North Absaroka WA..              0.22  Exempt.
 Company.
                                   Yellowstone NP.....              0.17
                                   Washakie WA........              0.16
                                   U.L. Bend WA.......              0.30
                                   Teton WA...........              0.08
                                   Gates of the                     0.19
                                    Mountains WA.

[[Page 24001]]

 
                                   Red Rock Lakes WA..              0.09
9. Smurfit-Stone Container         Selway-Bitterroot                0.23  Exempt.
 Enterprises Inc., Missoula Mill.   WA.
                                   Mission Mountains                0.36
                                    WA.
                                   Bob Marshall WA....              0.23
                                   Scapegoat..........              0.21
                                   Anaconda-Pintler WA              0.07
                                   Cabinet Mountains                0.14
                                    WA.
                                   Glacier NP.........              0.19
                                   Gates of the                     0.11
                                    Mountains WA.
                                   Hells Canyon WA....              0.01
                                   Eagles Cap                       0.00
                                    Wilderness.
----------------------------------------------------------------------------------------------------------------
\23\ Exxon 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:
    <bullet> Step 1: Identify All Available Retrofit Control 
Technologies;
    <bullet> Step 2: Eliminate Technically Infeasible Options;
    <bullet> Step 3: Evaluate Control Effectiveness of Remaining 
Control Technologies;
    <bullet> Step 4: Evaluate Impacts and Document the Results; and
    <bullet> Step 5: Evaluate Visibility Impacts.
    In determining BART, the state, 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 non-air quality environmental 
impacts of compliance; (3) any existing pollution control technology in 
use at the source; (4) the remaining useful life of the source; and (5) 
the degree of improvement in visibility which may reasonably be 
anticipated to result from the use of such technology. See also 40 CFR 
51.308(e)(1)(ii)(A). The 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 PM<INF>2.5</INF> and the transport and fate of 
PM<INF>2.5</INF>; 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.
---------------------------------------------------------------------------

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

    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 SO<INF>2</INF> to particulate sulfate 
and NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \25\ EPA's Model Distribution Web page available at: http://www.epa.gov/ttn/scram/dispersion_prefrec.htm#calpuff.
---------------------------------------------------------------------------

    The ``delta deciviews'' for control options estimated by the 
modeling represents a BART source's impact on visibility at the Class I 
areas under

[[Page 24002]]

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\
---------------------------------------------------------------------------

    \26\ CALPUFF 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.
    \28\ Modeling Report: Montana Regional Haze Federal 
Implementation Plan (FIP) Support, March 16, 2012.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> and NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \29\ The 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 
Cement-Montana 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 
NO<INF>X</INF> 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).
---------------------------------------------------------------------------

NO<INF>X</INF>
Step 1: Identify All Available Technologies
    We identified that the following NO<INF>X</INF> control 
technologies are available for the kiln at Ash Grove: low 
NO<INF>X</INF> 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 
NO<INF>X</INF> reduction in cement kilns. In the first stage, fuel 
combustion is carried out in a high temperature fuel-rich 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF>.
    FGR involves the use of oxygen-deficient 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

[[Page 24003]]

effect is to decrease both thermal and fuel NO<INF>X</INF> formation in 
the rotary kiln.
---------------------------------------------------------------------------

    \30\ Ash Grove BART Analysis, p. 5-6.
---------------------------------------------------------------------------

    In SNCR systems, a reagent such as NH<INF>3</INF> or urea is 
injected into the flue gas at a suitable temperature zone, typically in 
the range of 1,800 to 2,000 [deg]F and at an appropriate ratio of 
reagent to NO<INF>X</INF>. 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 NH<INF>3</INF> or urea in the presence of a metal 
based catalyst to selectively reduce NO<INF>X</INF> emissions. SCR is 
used in the electric utility industry to reduce NO<INF>X</INF> 
emissions from boilers and has been used on three cement kilns in 
Europe. SCR is capable of reducing NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \31\ Ash Grove BART Analysis, p. 5-8.
---------------------------------------------------------------------------

    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 [deg]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.
---------------------------------------------------------------------------

    \32\ Ash Grove BART Analysis, p. 5-6.
---------------------------------------------------------------------------

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

    \33\ EPA provided an example of LNB on a long wet kiln with a 
control effectiveness of 14% in NO<INF>X</INF> Control Technologies 
for the Cement Industry, Final Report, September 2000, p. 61.
---------------------------------------------------------------------------

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

    \34\ See 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.
    \35\ See 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.

                                             Table 10--NOX Emissions for 2006 and 2008 for Ash Grove Cement
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                       June through August 2006 emission rate (lb/ton      June through August 2008 emission rate (lb/ton
                                                          clinker)                                            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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 24004]]

    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.<SUP>36 37 38</SUP>
---------------------------------------------------------------------------

    \36\ EPA has stated previously that, ``[o]n average, SNCR 
achieves approximately a 35 percent reduction in NO<INF>X</INF> at a 
ratio of NH<INF>3</INF>-to-NO<INF>X</INF> of about 0.5 and a 
reduction of 63 percent at an NH<INF>3</INF>-to-NO<INF>X</INF> ratio 
of 1.0'' in the Federal Register notice proposing New Source 
Performance Standards for Portland cement plants. 73 FR 34078 (June 
16, 2008).
    \37\ The Cadence brochures available at: http://cadencerecycling.com/sncr.html and http://www.cadencerecycling.com/Resources/6-PageComplete.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.
    \38\ EPA 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).
---------------------------------------------------------------------------

    The concentration of baseline NO<INF>X</INF> emissions is one 
parameter affecting the effectiveness of SNCR. The percentage of 
control effectiveness is greater when initial NO<INF>X</INF> 
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 NO<INF>X</INF> 
concentrations.\39\ The baseline NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \39\ EPA'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.
    \40\ Ash 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 
NO<INF>X</INF>/ton clinker. This is significantly greater than the 
2006 emissions shown in Table 10 for the Midlothian kilns.)
---------------------------------------------------------------------------

    A summary of the emissions projections for the NO<INF>X</INF> 
control options is provided in Table 11.

                    Table 11--Summary of NOX BART Analysis Control Technologies for Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
LNB+SNCR..................................................                58              1088               803
SNCR......................................................                50               946               946
LNB.......................................................                15               284             1,607
No Controls (Baseline)....................................                 0                 0         \1\ 1,891
----------------------------------------------------------------------------------------------------------------
\1\ Ash 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.
---------------------------------------------------------------------------

    \41\ 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 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
------------------------------------------------------------------------
\1\ Ash 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/ 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.
\2\ Ash Grove LNB Cost.


[[Page 24005]]


                            Table 14--Summary of NOX BART Costs for LNB on Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
           Control option               Total capital    Total annual cost  Annual  emissions  effectiveness ($/
                                        investment ($)          ($)          reductions (tpy)         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.
---------------------------------------------------------------------------

    \42\ CRF 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/.
    \43\ CRF 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 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
------------------------------------------------------------------------
\1\ Ash 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/ 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
\2\ Ash Grove SNCR Cost.


                            Table 17--Summary of NOX BART Costs for SNCR on Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
              Total capital investment ($)               Total annual cost  Annual  emissions  effectiveness ($/
                                                                ($)          reductions (tpy)         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
------------------------------------------------------------------------


[[Page 24006]]


     Table 19--Summary of NOX BART Costs for LNB + SNCR on Ash Grove
------------------------------------------------------------------------
                                                          Average cost
       Total annual cost ($)        Annual  emissions  effectiveness ($/
                                     reductions (tpy)         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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \44\ Ash Grove BART Analysis, pp. 5-13, 14.
---------------------------------------------------------------------------

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 NO<INF>X</INF> 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
----------------------------------------------------------------------------------------------------------------
                                                            Improvement from  Improvement from  Improvement from
              Class I area                 Baseline impact     LNB  (delta      SNCR  (delta       LNB + SNCR
                                          (delta deciview)      deciview)         deciview)     (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]
----------------------------------------------------------------------------------------------------------------
                                                                                                  Using  LNB +
              Class I area                Baseline  (days)      Using LNB        Using SNCR           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

[[Page 24007]]

 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts \1,2\
                                                                                                            Incremental  -------------------------------
                                                           Total capital   Total annual    Average cost        cost         Visibility
                     Control option                         investment         cost        effectiveness   effectiveness    improvement    Fewer days >
                                                                                              ($/ton)         ($/ton)         (delta       0.5 deciview
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility benefit shown is for Gates of the Mountains WA.
\2\ The 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 NO<INF>X</INF> emissions reduced. SNCR is more expensive than LNB, 
with a cost effectiveness value of $2,199 per ton of NO<INF>X</INF> 
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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 output-based standard 
promotes the most efficient production process. 73 FR 34076, June 16, 
2008. Thus, for example, the NSPS for NO<INF>X</INF> 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 site-
specific 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.
---------------------------------------------------------------------------

    \45\ Ash Grove Update, March 2012 (Ash Grove lists the mean 30-
day rolling average NO<INF>X</INF> 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.)
    \46\ As 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.
---------------------------------------------------------------------------

    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.

[[Page 24008]]

SO<INF>2</INF>
Step 1: Identify All Available Technologies
    We identified that the following SO<INF>2</INF> 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 SO<INF>2</INF>. Ash Grove estimated that they would add 
a 2:1 molar ratio of lime to SO<INF>2.</INF> Solid particles of 
CaSO<INF>4</INF> would be produced, which would be removed from the gas 
stream along with excess reagent by a PMCD in the process flow. The 
SO<INF>2</INF> 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 SO<INF>2</INF> 
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\
---------------------------------------------------------------------------

    \47\ Ash Grove Additional Response to Comments.
    \48\ Ash Grove BART Analysis, p. 4-2.
    \49\ Ash Grove Response to Comments, Attachment A.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> in the flue gas 
to create fine particles of CaSO<INF>3</INF> or CaSO<INF>4</INF>. 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 
SO<INF>2</INF>. This technology has been used for SO<INF>2</INF> 
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 
SO<INF>2</INF> 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 
SO<INF>2</INF>.
    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 SO<INF>2</INF> 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 SO<INF>2</INF> 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% SO<INF>2</INF> control 
efficiency with a 2.5 to 1 CaO to SO<INF>2</INF> ratio.\51\
---------------------------------------------------------------------------

    \50\ Ash Grove January 2012 Update.
    \51\ Formation 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.
---------------------------------------------------------------------------

    For fuel switching, we used a SO<INF>2</INF> control effectiveness 
of 17% for the purposes of considering fuel switching to 38% coke and 
62% coal and SO<INF>2</INF> control effectiveness of 60% for the 
purposes of considering fuel switching to 100% low-sulfur coal.\52\
---------------------------------------------------------------------------

    \52\ Ash Grove BART Analysis, p. 4-11.
---------------------------------------------------------------------------

    The efficiency of semi-wet scrubbing is estimated to be 90%. A 90% 
SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \53\ Formation and Techniques of Sulfur Oxide and Other Sulfur 
Compounds, p. 46.
    \54\ Assessment of Control Technology Options for BART-Eligible 
Sources, March 2005.

                    Table 23--Summary of SO2 BART Analysis Control Technologies for Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                 Control           Annual           Remaining
                      Control Option                          effectiveness       emissions          annual
                                                                   (%)        reduction  (tpy)  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
----------------------------------------------------------------------------------------------------------------
\1\ Ash Grove Response to Comments, Attachment A.

[[Page 24009]]

 
\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 SO<INF>2</INF> as was reported to 
the NEI for 2008.\58\ We summarize the cost information for DAA in 
Tables 24, 25, and 26.
---------------------------------------------------------------------------

    \55\ Ash Grove Update January 2012.
    \56\ CRF 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.

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
------------------------------------------------------------------------
\1\ Ash 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/ 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.
\2\ Ash Grove Update January 2012.


                            Table 26--Summary of SO2 BART Costs for DAA on Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                            Annual  emissions     Average cost
             Total capital investment  ($)               Total annual cost      reductions     effectiveness  ($/
                                                                 ($)              (tpy)               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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \59\ Ash Grove Response to Comments, Attachment A.

     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
------------------------------------------------------------------------
\1\ Ash Grove Response to Comments.


                       Table 28--Summary of SO2 BART Costs for Fuel Switching on Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                                  Emissions       Average cost
                      Control option                          Total annual       reductions       effectiveness
                                                                cost  ($)           (tpy)            ($/ton)
----------------------------------------------------------------------------------------------------------------
Fuel Switching Option 1...................................           487,877               200             2,439
Fuel Switching Option 2...................................         2,908,170               707             4,113
----------------------------------------------------------------------------------------------------------------


[[Page 24010]]

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

    \60\ Ash Grove Additional Information October 2011.
    \61\ CRF 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/.
---------------------------------------------------------------------------

    In order to calculate the annualized capital cost, we multiplied 
the capital cost by the CRF.\62\ We used 1,178 tpy of SO<INF>2</INF> as 
was reported to the NEI for 2008. We summarize the cost information for 
semi-wet scrubbing in Tables 29, 30, and 31.
---------------------------------------------------------------------------

    \62\ Id.

    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
------------------------------------------------------------------------
\1\ Ash 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/ 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
------------------------------------------------------------------------
\1\ Ash Grove Additional Information October 2011.
\2\ Includes capital recovery.


                     Table 31--Summary of SO2 BART Costs for Semi-Wet Scrubbing on Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
             Total capital investment  ($)               Total annual cost      Emissions      effectiveness  ($/
                                                                 ($)        reductions  (tpy)         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.
---------------------------------------------------------------------------

    \63\ Id.
---------------------------------------------------------------------------

    In order to calculate the annualized capital cost, we multiplied 
the capital cost by the CRF.\64\ We used 1,178 tpy of SO<INF>2</INF> as 
was reported to the NEI for 2008. We summarize the cost information for 
wet scrubbing in Tables 32, 33, and 34.
---------------------------------------------------------------------------

    \64\ Id.

 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
------------------------------------------------------------------------
\1\ Ash 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/ 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
                                                         ---------------

[[Page 24011]]

 
  Total Annual Cost.....................................       5,094,562
------------------------------------------------------------------------
\1\ Includes capital recovery.
\2\ Ash Grove Additional Information October 2011.


                        Table 34--Summary of SO2 BART Costs for Wet Scrubber on Ash Grove
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
             Total capital investment  ($)               Total annual cost      Emissions      effectiveness  ($/
                                                                 ($)        reductions  (tpy)         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\
---------------------------------------------------------------------------

    \65\ Ash Grove Additional Information October 2011, p. 14.
    \66\ Ash Grove Additional Information October 2011, p. 10.
    \67\ Ash Grove Additional Information October 2011, p. 14.
    \68\ Ash Grove Additional Information October 2011, p. 10.
    \69\ Ash Grove Additional Information October 2011, Attachments 
1 and 2.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> control. The kiln inherently 
acts as an SO<INF>2</INF> scrubber, since some of the sulfur that is 
oxidized to SO<INF>2</INF> 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\
---------------------------------------------------------------------------

    \70\ Ash Grove Response to Comments.
    \71\ Ash Grove BART Analysis, p. 4-2.
---------------------------------------------------------------------------

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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                            Improvement
                                                                        Improvement from    Improvement      from fuel      Improvement     Improvement
                                                          Baseline      fuel switching--     from DAA       wwitching--    from semi-wet     from wet
                     Class I area                       impact (delta   Option 1  (delta      (delta         Option 2        scrubbing       scrubbing
                                                          deciview)        deciview)         deciview)        (delta          (delta          (delta
                                                                                                             deciview)       deciview)       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

[[Page 24012]]

 
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]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            Using fuel      Using fuel
                      Class I area                         Baseline days     switching       switching       Using DSI       Using SDA       Using wet
                                                                             Option 1        Option 2                                        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 SO<INF>2</INF> controls 
considered.
Step 5: Select BART
    We propose to find that BART for SO<INF>2</INF> 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 SO<INF>2</INF> controls did not justify proposing additional 
controls on this source.
    In our BART analysis for SO<INF>2</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts \1,2\
                                                                                                            Incremental  -------------------------------
                                                           Total capital   Total annual    Average cost        cost         Visibility
                     Control option                         investment         cost        effectiveness   effectiveness    improvement    Fewer  days >
                                                                                              ($/ton)         ($/ton)         (delta       0.5  deciview
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility benefit shown is for Gates of the Mountains WA.
\2\ The 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.


[[Page 24013]]

    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 SO<INF>2</INF> controls are 
relatively small, we propose that the SO<INF>2</INF> 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 NO<INF>X</INF> 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 site-specific feed/clinker ratio to calculate clinker production. 
75 FR 54990, Sept. 9, 2010.
---------------------------------------------------------------------------

    \72\ As 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.
---------------------------------------------------------------------------

    Accordingly, we are proposing 11.5 lb/ton clinker as a BART 
emission limit for SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \73\ Response 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \74\ EPA Air Pollution Control Online Course, description at: 
http://www.epa.gov/apti/course422/ce6a1.html.
---------------------------------------------------------------------------

    Ash Grove Cement must meet a PM<INF>10</INF> 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 <greek-i>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 = 4.10p\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.
    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    % Contribution     % Contribution
             (deciview)                 coarse PM           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/PM<INF>10</INF> 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/PM<INF>10</INF> 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 SO<INF>2</INF> and NO<INF>X</INF> 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

[[Page 24014]]

BART analysis is contained in the docket for this action and we have 
taken it into consideration in our proposed action.
---------------------------------------------------------------------------

    \75\ BART 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 
NO<INF>X</INF> 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 Additional Response, 
August 2009'') (Aug. 12, 2009); Response to EPA request for 
NO<INF>X</INF> and SO<INF>2</INF> 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).
---------------------------------------------------------------------------

NO<INF>X</INF>
Step 1: Identify All Available Technologies
    We identified the following previously described NO<INF>X</INF> 
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\
---------------------------------------------------------------------------

    \76\ EPA 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.
    \77\ Holcim Initial Response, p. 4-16.
    \78\ We 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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions is one parameter 
affecting control effectiveness. The percentage of control 
effectiveness is greater when initial NO<INF>X</INF> 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 NO<INF>X</INF> concentrations.\79\ 
The baseline NO<INF>X</INF> 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 NO<INF>X</INF> 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 
pre-SNCR emission rate shown in the Ash Grove analysis above, which is 
between 4.5 and 4.9 lb/ton clinker.
---------------------------------------------------------------------------

    \79\ CCM, p. 1-10.
    \80\ Holcim 2012 Response.
---------------------------------------------------------------------------

    A summary of the emissions projections for the NO<INF>X</INF> 
control options is provided in Table 39.

                     Table 39--Summary of NOX BART Analysis Control Technologies for Holcim
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)        reduction  (tpy)  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\
---------------------------------------------------------------------------

    \81\ Holcim Additional Response, June 2009.
    \82\ Holcim applied a 1.5 multiplier to the direct installation 
costs, for ``retrofit installation.'' We did not.
    \83\ CRF 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/.
---------------------------------------------------------------------------

    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'').

[[Page 24015]]

 
\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/ 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\
---------------------------------------------------------------------------

    \84\ Holcim Additional Response, June 2009.
---------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                            Annual  emissions     Average cost
           Total installed capital cost  ($)             Total annual cost      reductions     effectiveness  ($/
                                                                 ($)              (tpy)               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.
---------------------------------------------------------------------------

    \85\ Holcim Initial Response.
    \86\ NO<INF>X</INF> Control Technologies for the Cement 
Industry: Final Report, September 19, 2000, EPA-457/R-00-002, Table 
6-10.
    \87\ Holcim Initial Response, p. 4-23.

                              Table 43--Summary of NOX BART Costs for MKF on Holcim
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
              Total capital investment ($)               Total annual cost   Annual emissions  effectiveness ($/
                                                                ($)          reductions (tpy)         ton)
----------------------------------------------------------------------------------------------------------------
Not calculated separately, but included in total annual           473,738                334              1,418
 cost..................................................
----------------------------------------------------------------------------------------------------------------

    As explained in Holcim's BART analysis, the use of tire-derived 
fuel for MKF cannot be ensured within the five-year 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.
---------------------------------------------------------------------------

    \88\ Id., p. 4-25.
---------------------------------------------------------------------------

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

    \89\ Holcim Additional Response, August 2009, Appendix C.
    \90\ CRF 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/.

[[Page 24016]]



 Table 44--Summary of NOX BART Capital Cost Analysis for SNCR on Holcim
------------------------------------------------------------------------
                       Description                           Cost ($)
------------------------------------------------------------------------
Total Capital Investment................................    \1\1,312,800
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/ 4/.


  Table 45--Summary of NOX BART Annual Cost Analysis for SNCR on Holcim
------------------------------------------------------------------------
                       Description                           Cost ($)
------------------------------------------------------------------------
Total Indirect Annual Cost..............................      \1\123,928
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
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
              Total capital investment ($)               Total annual cost   Annual emissions  effectiveness ($/
                                                                ($)          reductions (tpy)         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
----------------------------------------------------------------------------------------------------------------
                                                                                     Annual
                                                                                   emissions       Average cost
                             Total annual cost ($)                                 reductions     effectiveness
                                                                                     (tpy)           ($/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 non-air 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

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

Factor 3: Any Existing Pollution Control Technology in Use at the 
Source
    Holcim currently uses proper kiln design and operation for 
NO<INF>X</INF> 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

[[Page 24017]]

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
----------------------------------------------------------------------------------------------------------------
                                                            Improvement from  Improvement from  Improvement from
              Class I area                 Baseline impact     LNB (delta        SNCR (delta       LNB + SNCR
                                          (delta deciview)      deciview)         deciview)     (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 NO<INF>X</INF> 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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts \1,2\
                                                                                                            Incremental  -------------------------------
                                                           Total capital   Total annual    Average cost        cost         Visibility
                     Control option                         investment         cost        effectiveness   effectiveness    improvement    Fewer days >
                                                                                              ($/ton)         ($/ton)         (delta       0.5 deciview
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility benefit shown is for Gates of the Mountains WA.
\2\ The 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\ The 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> 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

[[Page 24018]]

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

    \93\ Holcim 2012 Response. (Holcim lists the mean 30-day rolling 
average NO<INF>X</INF> 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.)
    \94\ As 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.
---------------------------------------------------------------------------

    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.
SO<INF>2</INF>
Step 1: Identify All Available Technologies
    We identified that the following SO<INF>2</INF> 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 SO<INF>2</INF> reacts with the 
scrubbing reagent to form calcium sulfate (CaSO<INF>4</INF>) sludge 
that is collected. The sludge usually is dewatered and disposed of at 
an offsite landfill.
    SDAs use lime or limestone to react with SO<INF>2</INF>. This 
technology involves injecting an aqueous lime or limestone suspension 
in fine droplets into the flue gas. The lime reacts with SO<INF>2</INF> 
in the flue gas to create fine particles of calcium sulfite 
(CaSO<INF>3</INF>) or CaSO<INF>4</INF>. The moisture evaporates from 
the particles, and the particles are collected in the PMCD. Limestone 
absorbent scrubbers have been used for SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>. One manufacturer of these 
scrubber systems indicates an SO<INF>2</INF> removal efficiency of 
greater than 90% for SDAs.\95\
---------------------------------------------------------------------------

    \95\ Formation and Techniques of Sulfur Oxide and Other Sulfur 
Compounds, p. 46.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \96\ Holcim 2008 Responses, p. 6.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> generated from the kiln 
feed. Achievable SO<INF>2</INF> reduction has been estimated at between 
0% and 30%.\97\
---------------------------------------------------------------------------

    \97\ Formation and Techniques of Sulfur Oxide and Other Sulfur 
Compounds, pp. 31, 44 and 48.
---------------------------------------------------------------------------

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

    \98\ Holcim Initial Response, p. 4-11.
---------------------------------------------------------------------------

    As cited above, according to one SDA manufacturer, 90% 
SO<INF>2</INF> control effectiveness is the minimum of the range for a 
SDA with lime absorbent medium. Given the extremely low SO<INF>2</INF> 
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.
---------------------------------------------------------------------------

    \99\ Holcim 2012 Response (Holcim listed the SO<INF>2</INF> 
emissions at 53.5 tons in 2009, 64.1 tons in 2010, and 33.1 tons in 
2011. The average was 50.2 tons).
---------------------------------------------------------------------------

    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%.
---------------------------------------------------------------------------

    \100\ Holcim 2008 Responses, p. 6.

                     Table 52--Summary of SO2 BART Analysis Control Technologies for Holcim
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness   Annual emissions  Remaining annual
                                                                   (%)         reduction (tpy)   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
----------------------------------------------------------------------------------------------------------------


[[Page 24019]]

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

    \101\ Holcim Additional Response, August 2009, Appendix B.
    \102\ CRF 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 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
----------------------------------------------------------------------------------------------------------------
                                                                                       Emissions    Average cost
          Total capital investment ($)                   Total annual cost ($)         reductions  effectiveness
                                                                                         (tpy)         ($/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,<SUP>2</SUP> 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.
---------------------------------------------------------------------------

    \103\ Id.

  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/.


[[Page 24020]]


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      Emissions    Average cost
  Total capital investment ($)   annual cost   reductions  effectiveness
                                     ($)         (tpy)         ($/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.
---------------------------------------------------------------------------

    \104\ Holcim 2008 Responses, p. 6.

     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
------------------------------------------------------------------------
                                    Total      Emissions    Average cost
         Control option          annual cost   reductions  effectiveness
                                     ($)         (tpy)         ($/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 SO<INF>2</INF> control. The kiln inherently 
acts as an SO<INF>2</INF> scrubber, since some of the sulfur that is 
oxidized to SO<INF>2</INF> 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.

[[Page 24021]]

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
----------------------------------------------------------------------------------------------------------------
                                                    Improvement     Improvement
                                                     from fuel       from fuel      Improvement     Improvement
                                     Baseline        switching       switching       from SDA        from wet
          Class I area             impact (delta     option 1        option 2         (delta         scrubber
                                     deciview)        (delta          (delta         deciview)        (delta
                                                     deciview)       deciview)                       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]
----------------------------------------------------------------------------------------------------------------
                                                               Using fuel   Using fuel
                  Class I area                     Baseline    switching    switching    Using SDA    Using wet
                                                    (days)      option 1     option 2                 scrubbing
----------------------------------------------------------------------------------------------------------------
Gates of the Mountains WA......................           46           45           44           43           43
Yellowstone NP.................................           13           12           12           12           12
----------------------------------------------------------------------------------------------------------------

    Modeling for fuel switching option <greek-i>2 was performed 
assuming a 50% reduction rather than a 62% reduction.
Step 5: Select BART
    We propose to find that BART for SO<INF>2</INF> 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 SO<INF>2</INF> controls on this source.
    In our BART analysis for SO<INF>2</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                Visibility impacts \1,2\
                                                                                                                  Incremental  -------------------------
                                                                      Total capital     Total      Average cost       cost       Visibility
                           Control option                              investment    annual cost  effectiveness  effectiveness  improvement   Fewer days
                                                                                                      ($/ton)        ($/ton)       (delta       > 0.5
                                                                                                                                 deciviews)    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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility benefit shown is for Gates of the Mountains WA.
\2\ The 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 SO<INF>2</INF> controls, we propose that 
the SO<INF>2</INF> 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\
---------------------------------------------------------------------------

    \105\ As 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.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \106\ Holcim 2012 Response (Holcim lists the mean 30-day rolling 
average SO<INF>2</INF> emission rate for 2008-2011 at 0.37 lb/ton 
clinker. The 99th percentile 30-day rolling average was 1.20 lb/ton 
clinker).
---------------------------------------------------------------------------

    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

[[Page 24022]]

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\
---------------------------------------------------------------------------

    \107\ Air 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.
---------------------------------------------------------------------------

    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    % Contribution    % Contribution
             (deciview)                   coarse PM          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 
<greek-i>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/PM<INF>10</INF> 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/PM<INF>10</INF> 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.
---------------------------------------------------------------------------

    \108\ The 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.
---------------------------------------------------------------------------

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

    \109\ See Montana Air Quality Operating Permit (MAQOP) 
<greek-i>OP2655-02 (Title V).
    \110\ See Section V of MDEQ's CFAC Compliance Monitoring Report, 
p. 10.
    \111\ See Compliance Monitoring Report Section VII, p. 11.
---------------------------------------------------------------------------

    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.

[[Page 24023]]

    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\
---------------------------------------------------------------------------

    \112\ Also, the BART Guidelines establish presumptive 
NO<INF>X</INF> limits for coal-fired Electric Generating Units 
(EGUs) located at greater than 750 MW power plants that are 
operating without post-combustion 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.
---------------------------------------------------------------------------

    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
NO<INF>X</INF>
    The Colstrip Unit 1 boiler is of tangential-fired design with low-
NO<INF>X</INF> burners and close-coupled overfire air (CCOFA). 
Originally, the unit operated with a NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> emission rate in the range of 0.30 to 0.35 lb/MMBtu, 
accomplished with low NO<INF>X</INF> burners and CCOFA.\113\
---------------------------------------------------------------------------

    \113\ Baseline 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.
---------------------------------------------------------------------------

Step 1: Identify All Available Technologies
    We identified that the following NO<INF>X</INF> 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 NO<INF>X</INF> removal efficiencies. SOFA in combination 
with LNB technology provides additional NO<INF>X</INF> control by 
injecting air into the lower temperature combustion zone where 
NO<INF>X</INF> is less likely to form. This allows complete combustion 
of the fuel while reducing both thermal and chemical NO<INF>X</INF> 
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 NO<INF>X</INF> removal efficiencies compared to SOFA.
    ROFA is a low NO<INF>X</INF> 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 NH<INF>3</INF> or urea is 
injected into the flue gas at a suitable temperature zone, typically in 
the range of 1,600 to 2,000[emsp14] [deg]F and at an appropriate ratio 
of reagent to NO<INF>X</INF>.
    SCR uses either NH<INF>3</INF> or urea in the presence of a metal 
based catalyst to selectively reduce NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions from coal-fired power plants.\114,115,116\
---------------------------------------------------------------------------

    \114\ Institute of Clean Air Companies (ICAC) White Paper, 
Selective Catalytic Reduction Controls of NO<INF>X</INF> Emissions 
from Fossil Fuel-Fired Electric Power Plants, May 2009, pp. 7-8.
    \115\ Control 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 NO<INF>X</INF> Emissions, February 2008, pp. 6-7.
---------------------------------------------------------------------------

    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 NO<INF>X</INF>) 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.
---------------------------------------------------------------------------

    \117\ Low NO<INF>X</INF> Firing Systems and PRB Fuel; Achieving 
as Low as 0.12 LB NO<INF>X</INF>/MMBtu, Jennings, P., ICAC Forum, 
Feb. 2002.
    \118\ June 2008 PPL Addendum, p. 5-1.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> concentration. Typically, SNCR reduces NO<INF>X</INF> an 
additional 20 to 30% above LNB/combustion controls without excessive 
NH<INF>3</INF> 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

[[Page 24024]]

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

    \119\ White Paper, SNCR for Controlling NO<INF>X</INF> 
Emissions, Institute of Clean of Clean Air Companies, pp. 4 and 9, 
February 2008.
    \120\ Information available at: http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/NOx%20control%20Lani%20AWMA%200905.pdf.

                 Table 65--Summary of NOX BART Analysis Control Technologies for Colstrip Unit 1
----------------------------------------------------------------------------------------------------------------
                                               Control
             Control option                 effectiveness   Annual  emission      Emissions         Remaining
                                                 (%)        rate  (lb/MMBtu)  reduction  (tpy)  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
----------------------------------------------------------------------------------------------------------------
\1\ Baseline 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.
---------------------------------------------------------------------------

    \121\ EPA'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 <greek-i>430R10010.
---------------------------------------------------------------------------

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

    \123\ Section 1, Chapter 2, p. 2-21.
    \124\ Office of Management and Budget, Circular A-4, Regulatory 
Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.
    \125\ Chemical Engineering Magazine, p. 56, August 2011. (http://www.che.com).
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    \126\ Addendum to PPL Montana's Colstrip BART Report Prepared 
for PPL Montana, LLC; Prepared by TRC, (``Colstrip Addendum''), June 
2008, Table 5.1-1.

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                                   Emissions reductions     Average cost effectiveness
           (MM$)               Total annual cost  (MM$)              (tpy)                      ($/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

[[Page 24025]]

annualize the total capital investment using the CRF, and to sum the 
total annual costs.
---------------------------------------------------------------------------

    \127\ IPM, Chapter 5, Appendix 5-2B.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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 SO<INF>2</INF> rate is above 3 lb/MMBtu.\129\ 
Moreover, ammonium bisulfate formation can be minimized by preventing 
excessive NH<INF>3</INF> slip. Optimization of the SNCR system can 
commonly limit NH<INF>3</INF> 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.
---------------------------------------------------------------------------

    \128\ Cost 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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions reductions. 
We summarize the costs from our SOFA+SNCR cost analysis in Tables 69, 
70, and 71.
---------------------------------------------------------------------------

    \131\ NO<INF>X</INF> Control Update to PPL Montana's Colstrip 
Generating Station BART Report Prepared for PPL Montana, LLC, by 
TRC, September 2011, p. 4-1.

  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                                   Emissions reductions     Average cost effectiveness
           (MM$)               Total annual cost  (MM$)              (tpy)                      ($/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.
---------------------------------------------------------------------------

    \132\ IPM, Chapter 5, Appendix 5-2A.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions reductions. We summarize 
the costs from our SOFA+SCR cost analysis in Tables 72, 73, and 74.
---------------------------------------------------------------------------

    \133\ Email communication with Fuel Tech, Inc., March 2, 2012.
    \134\ Cichanowicz 2010, p. 6-7.

   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

[[Page 24026]]

 
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                                   Emissions reductions            Average cost
           (MM$)               Total annual cost  (MM$)              (tpy)              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.
---------------------------------------------------------------------------

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

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
----------------------------------------------------------------------------------------------------------------
                                                                    Improvement     Improvement     Improvement
                                                     Baseline      from SOFA+SCR  from SOFA+SNCR     from SOFA
                  Class I area                     impact (delta      (delta          (delta          (delta
                                                     deciview)       deciview)       deciview)       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]
----------------------------------------------------------------------------------------------------------------
                                                     Baseline                          Using
                  Class I area                        (days)      Using SOFA+SCR     SOFA+SNCR      Using SOFA
----------------------------------------------------------------------------------------------------------------
North Absaroka WA...............................               7               5               5               7

[[Page 24027]]

 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                       Visibility impacts \1\
                                                                          Average cost    Incremental cost ---------------------------------------------
          Control option              Total capital     Total annual    effectiveness ($/ effectiveness ($/       Visibility
                                    investment (MM$)     cost (MM$)           ton)              ton)          improvement (delta      Fewer days >0.5
                                                                                                                  deciviews)              deciview
--------------------------------------------------------------------------------------------------------------------------------------------------------
SOFA+SCR..........................            82.772            10.942             3,195             5,770  0.404 TRNP...........  35 TRNP.
                                                                                                            0.378 UL Bend........  39 UL Bend.
SOFA+SNCR.........................            13.380             3.279             1,564             3,291  0.264 TRNP...........  25 TRNP.
                                                                                                            0.249 UL Bend........  21 UL Bend.
SOFA..............................             4.508             1.090               761               \2\  0.182 TRNP...........  19 TRNP.
                                                                                                            0.164 UL Bend........  16 UL Bend.
--------------------------------------------------------------------------------------------------------------------------------------------------------
TRNP--Theodore Roosevelt National Park.
UL Bend--UL Bend Wilderness Area.
\1\ The 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 NO<INF>X</INF> emissions reduced. SOFA+SNCR is more 
expensive than SOFA, with a cost effectiveness value of $1,564 per ton 
of NO<INF>X</INF> emissions reduced. SOFA+SCR is more expensive than 
SOFA or SOFA+SNCR, having a cost effectiveness value of $3,195 per ton 
of NO<INF>X</INF> 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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \137\ As 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.
---------------------------------------------------------------------------

    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.
SO<INF>2</INF>
    Colstrip Unit 1 is already controlled by wet venturi scrubbers for 
simultaneous particulate and SO<INF>2</INF> control. The venturi 
scrubbers utilize the alkalinity of the fly ash to achieve an estimated 
SO<INF>2</INF> 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 SO<INF>2</INF> emission rate was 0.418 
lb/MMBtu and the

[[Page 24028]]

average SO<INF>2</INF> emissions were 5,548 tpy.\139\
---------------------------------------------------------------------------

    \138\ BART Assessment Colstrip Generating Station, prepared for 
PPL Montana, LLC, by TRC (``Colstrip Initial Response''), August 
2007, p. ES-3.
    \139\ Clean Air Markets--Data and Maps: http://camddataandmaps.epa.gov/gdm/.
---------------------------------------------------------------------------

Step 1: Identify All Available Technologies
    The Colstrip Unit 1 venturi scrubber currently achieves greater 
than 50% removal of SO<INF>2</INF>. For units with preexisting post-
combustion SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>. Adding lime to the water stream for these 
scrubbers will increase SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \140\ EPA Air Pollution Control Technology Fact Sheet: Venturi 
Scrubber, EPA-452/F-03-017.
---------------------------------------------------------------------------

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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \141\ Colstrip Addendum, p. 4-1.
    \142\ Clean Air Markets--Data and Maps: http://camddataandmaps.epa.gov/gdm/.
---------------------------------------------------------------------------

    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      Annual  emission
             Control option                 effectiveness    rate (lb/MMBtu)      Emissions         Remaining
                                               (%) \1\             \2\         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
Lime Injection with Additional Scrubber               80.9             0.080             4,486             1,062
 Vessel.................................
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.
\2\ Emission rates are provided on an annual basis.
\3\ Baseline 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 SO<INF>2</INF> control options 
are in year 2007 dollars. EPA's cost calculations can be found in the 
docket.
---------------------------------------------------------------------------

    \143\ Colstrip Initial Response, Table A4-6(c).
    \144\ Colstrip Addendum, Table 4.1-4.
---------------------------------------------------------------------------

Lime Injection
    We summarize our cost analysis for lime injection in Tables 79, 80, 
and 81.

[[Page 24029]]



  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                                                            Average cost effectiveness
           (MM$)               Total annual cost (MM$)    Emissions reductions (tpy)            ($/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                                                            Average cost effectiveness
           (MM$)               Total annual cost (MM$)    Emissions reductions (tpy)            ($/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.
---------------------------------------------------------------------------

    \145\ Colstrip Initial Response, p. 4-16.
---------------------------------------------------------------------------

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

[[Page 24030]]

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
----------------------------------------------------------------------------------------------------------------
                                                                              Improvement from
                                                                               lime  injection  Improvement from
                       Class I area                          Baseline impact    + additional     lime  injection
                                                            (delta deciview)   scrubber vessel  (delta deciview)
                                                                              (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]
----------------------------------------------------------------------------------------------------------------
                                                                                 Using lime
                                                                                 injection +       Using lime
                       Class I area                          Baseline (days)     additional         injection
                                                                               scrubber vessel
----------------------------------------------------------------------------------------------------------------
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 SO<INF>2</INF> 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 SO<INF>2</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                      Incremental                  Visibility impacts \1\
                                     Total capital   Total annual    Average cost        cost      -----------------------------------------------------
          Control option              investment      cost (MM$)     effectiveness   effectiveness    Visibility improvement
                                         (MM$)                          ($/ton)         ($/ton)         (delta deciviews)      Fewer days  >0.5 deciview
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lime Injection with Additional              28.000           4.100             912           1,957  0.350 TRNP...............  23 TRNP.
 Scrubber Vessel.                                                                                   0.261 UL Bend............  37 UL Bend.
Lime Injection....................           3.000           1.883             529             \2\  0.283 TRNP...............  19 TRNP.
                                                                                                    0.234 UL Bend............  27 UL Bend.
--------------------------------------------------------------------------------------------------------------------------------------------------------
TRNP--Theodore Roosevelt National Park.
UL Bend--UL Bend Wilderness Area.
\1\ The 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 SO<INF>2</INF> emissions

[[Page 24031]]

reduced. Lime injection with an additional scrubber vessel is more 
expensive than lime injection, with a cost effectiveness value of $912 
per ton of SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \146\ As 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \147\ EPA Air Pollution Control Online Course, description at: 
http://www.epa.gov/apti/course422/ce6a3.html.
    \148\ Colstrip Addendum, p. 6-1
    \149\ Colstrip Initial Response, p. 4-8.
---------------------------------------------------------------------------

    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      % Contribution coarse   % Contribution fine PM
       (deciview)                   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 
<greek-i>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/PM<INF>10</INF> 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/PM<INF>10</INF> 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
NO<INF>X</INF>
    The Colstrip Unit 2 boiler is of tangential-fired design with LNB 
and OFA. Originally, the unit operated with a NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> emission 
rate in the range of 0.30 to 0.35 lb/MMBtu, accomplished with the low 
NO<INF>X</INF> burners and CCOFA.\150\
---------------------------------------------------------------------------

    \150\ Baseline 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.
---------------------------------------------------------------------------

Step 1: Identify All Available Technologies
    We identified that the same NO<INF>X</INF> control technologies for 
Colstrip Unit 2

[[Page 24032]]

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 sub-bituminous B coal, is less 
reactive (produces more NO<INF>X</INF>) 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.
---------------------------------------------------------------------------

    \151\ Low NO<INF>X</INF> Firing Systems and PRB Fuel; Achieving 
as Low as 0.12 LB NO<INF>X</INF>/MMBtu, Jennings, P., ICAC Forum, 
Feb. 2002.
    \152\ Colstrip Addendum, p. 5-1.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> concentration. Typically, SNCR reduces NO<INF>X</INF> an 
additional 20 to 30% above LNB/combustion controls without excessive 
NH<INF>3</INF> 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.
---------------------------------------------------------------------------

    \153\ White Paper, SNCR for Controlling NO<INF>X</INF> 
Emissions, Institute of Clean Air Companies, pp. 4 and 9, February 
2008.
    \154\ http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/NOx%20control%20Lani%20AWMA%200905.pdf.

                 Table 89--Summary of NOX BART Analysis Control Technologies for Colstrip Unit 2
----------------------------------------------------------------------------------------------------------------
                                              Control        Annual emission      Emissions         Remaining
             Control option              effectiveness (%)   rate (lb/MMBtu)   reduction (tpy)   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
----------------------------------------------------------------------------------------------------------------
\1\ Baseline 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 NO<INF>X</INF> 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).
---------------------------------------------------------------------------

    \155\ Colstrip Addendum, Table 5.1-1.

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                                   Emissions  reductions           Average cost
           (MM$)               Total annual cost (MM$)               (tpy)               effectiveness ($/ton)
----------------------------------------------------------------------------------------------------------------
                4.508                        1.090                        1,420                         768
----------------------------------------------------------------------------------------------------------------


[[Page 24033]]

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

    \156\ IPM, Chapter 5, Appendix 5-2B.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \157\ Cost and Quality of Fuels for Electric Utility Plants 1999 
Tables, Energy Information Administration, DOE/EIA-0191(99), June 
2000, Table 24.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions reductions. 
We summarize the costs from our SOFA+SNCR cost analysis in Tables 93, 
94, and 95.
---------------------------------------------------------------------------

    \158\ NO<INF>X</INF> Control Update to PPL Montana's Colstrip 
Generating Station BART Report Prepared for PPL Montana, LLC, by 
TRC, September 2011, p. 4-1.

  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                                   Emissions  reductions           Average cost
           (MM$)               Total annual cost (MM$)               (tpy)               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.
---------------------------------------------------------------------------

    \159\ IPM, Chapter 5, Appendix 5-2A.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions reductions. We summarize 
the costs from our SOFA+SCR cost analysis in Tables 96, 97, and 98.
---------------------------------------------------------------------------

    \160\ Email communication with Fuel Tech, Inc., March 2, 2012.
    \161\ Cichanowicz 2010, p. 6-7.

   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

[[Page 24034]]

 
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                                   Emissions  reductions           Average cost
           (MM$)               Total annual cost (MM$)             (tons/yr)             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.
---------------------------------------------------------------------------

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

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
----------------------------------------------------------------------------------------------------------------
                                                            Improvement from  Improvement from  Improvement from
              Class I area                 Baseline impact   SOFA+SCR (delta  SOFA+SNCR (delta     SOFA (delta
                                          (delta deciview)      deciview)         deciview)         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
----------------------------------------------------------------------------------------------------------------


[[Page 24035]]

Step 5: Select BART
    We propose to find that BART for NO<INF>X</INF> 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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Visibility Impacts \1\
                                   Total capital     Total annual      Average cost    Incremental cost ------------------------------------------------
         Control option          investment (MM$)     cost (MM$)       effectiveness     effectiveness   Visibility  Improvement     Fewer days > 0.5
                                                                          ($/ton)           ($/ton)          (delta deciviews)           deciview
--------------------------------------------------------------------------------------------------------------------------------------------------------
SOFA+SCR.......................            82.771            10.920             3,235             5,877  0.423 TRNP.............  40 TRNP
                                                                                                         0.406 UL Bend..........  49 UL Bend
SOFA+SNCR......................            13.380             3.256             1,571             3,322  0.269 TRNP.............  29 TRNP
                                                                                                         0.269 UL Bend..........  25 UL Bend
SOFA...........................             4.508             1.090               768               \2\  0.190 TRNP.............  19 TRNP
                                                                                                         0.185 UL Bend..........  20 UL Bend
--------------------------------------------------------------------------------------------------------------------------------------------------------
TRNP--Theodore Roosevelt National Park.
UL Bend--UL Bend Wilderness Area.
\1\ The 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 NO<INF>X</INF> emissions reduced. SOFA+SNCR is more 
expensive than SOFA, with a cost effectiveness value of $1,571 per ton 
of NO<INF>X</INF> emissions reduced. SOFA+SCR is more expensive than 
SOFA or SOFA+SNCR, having a cost effectiveness value of $3,235 per ton 
of NO<INF>X</INF> 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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \164\ As 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.
---------------------------------------------------------------------------

    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.
SO<INF>2</INF>
    Colstrip Unit 2 is already controlled by wet venturi scrubbers, 
which are identical to Colstrip Unit 1 scrubbers, for simultaneous 
particulate and SO<INF>2</INF> control. The venturi scrubbers utilize 
the alkalinity of the fly ash to achieve an estimated SO<INF>2</INF> 
removal efficiency of 75%.\165\ Based on emissions data from CAMD, for 
the baseline period 2008 through 2010, the average SO<INF>2</INF> 
emission rate was 0.418 lb/MMBtu and the average SO<INF>2</INF> 
emissions were 5,548 tpy.\166\
---------------------------------------------------------------------------

    \165\ Colstrip Initial Response, p. ES-3.
    \166\ Clean Air Markets--Data and Maps: http://camddataandmaps.epa.gov/gdm.
---------------------------------------------------------------------------

Step 1: Identify All Available Technologies
    The Colstrip Unit 2 venturi scrubber currently achieves greater 
than 50% removal of SO<INF>2</INF>. 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 SO<INF>2</INF> emissions at Colstrip Units 3 
and 4.

[[Page 24036]]

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

    \167\ Colstrip Addendum, p. 4-1.
    \168\ Clean Air Markets--Data and Maps: http://camddataandmaps.epa.gov/gdm/.
---------------------------------------------------------------------------

    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       Annual emission
             Control option                 effectiveness    rate (lb/MMBtu)      Emissions         Remaining
                                               (%) \1\             \2\         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
Lime Injection with Additional Scrubber               79.7             0.080             4,129             1,049
 Vessel.................................
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.
\2\ Emission rates are provided on an annual basis.
\3\ Baseline 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.<SUP>169 170</SUP> 
All costs presented here for the Colstrip Unit 2 SO<INF>2</INF> control 
options are in year 2007 dollars. EPA's cost calculations for Colstrip 
2 can be found in the docket.
---------------------------------------------------------------------------

    \169\ Colstrip Initial Response, Table A4-6(c).
    \170\ Colstrip Addendum, Table 4.1-4.
---------------------------------------------------------------------------

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                                   Emissions  reductions           Average cost
           (MM$)               Total Annual Cost (MM$)               (tpy)              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

[[Page 24037]]

 
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                                    Emissions  reductions           Average cost
         cost (MM$)            Total annual cost (MM$)               (tpy)               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.
---------------------------------------------------------------------------

    \171\ Colstrip Initial Response, p. 4-16.
---------------------------------------------------------------------------

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
----------------------------------------------------------------------------------------------------------------
                                                                              Improvement from
                                                                              lime injection +  Improvement from
                       Class I area                          Baseline impact     additional      lime  injection
                                                            (delta deciview)   scrubber vessel  (delta deciview)
                                                                              (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
----------------------------------------------------------------------------------------------------------------


[[Page 24038]]


                    Table 110--Days Greater Than 0.5 Deciview for SO2 Controls on Colstrip 2
                                               [Three year total]
----------------------------------------------------------------------------------------------------------------
                                                                                 Using lime
                                                                                 injection +       Using lime
                       Class I area                          Baseline (days)     additional         injection
                                                                               scrubber vessel
----------------------------------------------------------------------------------------------------------------
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 SO<INF>2</INF> 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 SO<INF>2</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                      Incremental                  Visibility impacts \1\
                                     Total capital   Total annual    Average cost        cost      -----------------------------------------------------
          Control option              investment      cost (MM$)     effectiveness   effectiveness    Visibility improvement
                                         (MM$)                          ($/ton)         ($/ton)         (delta deciviews)      Fewer days > 0.5 deciview
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lime Injection with Additional              28.000           4.093             991           2,410  0.280 TRNP...............  7 TRNP
 Scrubber Vessel.                                                                                   0.179 UL Bend............  8 UL Bend
Lime Injection....................           3.000           1.883             586             \2\  0.225 TRNP...............  6 TRNP
                                                                                                    0.143 UL Bend............  7 UL Bend
--------------------------------------------------------------------------------------------------------------------------------------------------------
TRNP--Theodore Roosevelt National Park.
UL Bend--UL Bend Wilderness Area.
\1\ The 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \172\ As 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \173\ Colstrip Addendum, p. 6-1.

---------------------------------------------------------------------------

[[Page 24039]]

    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      % Contribution coarse   % Contribution fine PM
       (deciview)                   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 
<greek-i>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/PM<INF>10</INF> 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/PM<INF>10</INF> 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 sub-bituminous 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\
---------------------------------------------------------------------------

    \174\ 70 FR 39108 (July 6, 2005).
---------------------------------------------------------------------------

    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.
NO<INF>X</INF>
    The Corette boiler is a tangential-fired unit with existing low-
NO<INF>X</INF> burners and CCOFA. The unit is subject to an annual 
NO<INF>X</INF> emission limit of 0.4 lb/MMBtu.
Step 1: Identify All Available Technologies
    We identified the following NO<INF>X</INF> control technologies are 
available: SOFA, SNCR, and SCR. Descriptions for each of these 
NO<INF>X</INF> 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 NO<INF>X</INF> emissions 
from coal-fired power plants.<SUP>175 176 177</SUP>
---------------------------------------------------------------------------

    \175\ Institute of Clean Air Companies (ICAC) White Paper, SCR 
Controls of NO<INF>X</INF> Emissions from Fossil Fuel-Fired Electric 
Power Plants, May 2009, pp. 7-8.
    \176\ Control 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 NO<INF>X</INF> 
Emissions, February 2008, pp. 6-7.
---------------------------------------------------------------------------

Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    At tangentially fired boilers firing sub-bituminous 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \178\ Low NO<INF>X</INF> Firing Systems and PRB Fuel; Achieving 
as Low as 0.12 LB NO<INF>X</INF>/MMBtu, Jennings, P., ICAC Forum, 
Feb. 2002.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> concentration. Typically, SNCR reduces NO<INF>X</INF> an 
additional 20 to 30% above LNB/combustion controls without excessive 
NH<INF>3</INF> 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

[[Page 24040]]

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

    \179\ White Paper, SNCR for Controlling NO<INF>X</INF> 
Emissions, Institute of Clean Air Companies, pp. 4 and 9, February 
2008.
    \180\ Srivastava, 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.

                    Table 113--Summary of NOX BART Analysis Control Technologies for Corette
----------------------------------------------------------------------------------------------------------------
                                               Control
             Control option                 effectiveness    Annual emission      Emissions         Remaining
                                                 (%)        rate  (lb/MMBtu)  reduction  (tpy)  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
----------------------------------------------------------------------------------------------------------------
\1\ Baseline 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 NO<INF>X</INF> controls. 
EPA's cost calculations for NO<INF>X</INF> 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).
---------------------------------------------------------------------------

    \181\ Addendum 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.

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                                    Emissions  reductions           Average cost
        cost  (MM$)            Total annual cost  (MM$)              (tpy)              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.
---------------------------------------------------------------------------

    \182\ IPM, Chapter 5, Appendix 5-2B.
---------------------------------------------------------------------------

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

    \183\ Cost and Quality of Fuels for Electric Utility Plants 1999 
Tables, Energy Information Administration, DOE/EIA-0191(99), June 
2000, Table 24.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions reductions. 
We summarize the costs from our SPFA+SNCR cost analysis in Tables 117, 
118, and 119.
---------------------------------------------------------------------------

    \184\ NO<INF>X</INF> Control Update to PPL Montana's J.E. 
Corette Generating Station BART Report, September 2011, Prepared for 
PPL Montana, LLC by TRC, p. 8.

[[Page 24041]]



  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                                    Emissions  reductions           Average cost
         cost (MM$)            Total annual cost (MM$)               (tpy)               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.
---------------------------------------------------------------------------

    \185\ IPM, Chapter 5, Appendix 5-2A.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emissions reductions. We summarize 
the costs from our SOFA+SCR cost analysis in Tables 120, 121, and 122.
---------------------------------------------------------------------------

    \186\ Email communication with Fuel Tech, Inc., March 2, 2012.
    \187\ Cichanowicz 2010, p. 6-7.

  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                                   Emissions  reductions           Average cost
           (MM$)               Total annual cost (MM$)               (tpy)               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

[[Page 24042]]

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

    \188\ CCM, Section 4.2, Chapter 1, p. 1-21.
    \189\ Id., Section 4.2, Chapter 2, p. 2-28.
---------------------------------------------------------------------------

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
----------------------------------------------------------------------------------------------------------------
                                           Baseline impact   SOFA+SCR (delta  SOFA+SNCR (delta     SOFA (delta
              Class I area                (delta deciview)      deciview)         deciview)         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 NO<INF>X</INF> is the existing 
tangential firing design of the boilers and existing low-NO<INF>X</INF> 
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 NO<INF>X</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts \1\
                                                                                                            Incremental  -------------------------------
                                                           Total capital   Total annual    Average cost        cost         Visibility
                     Control option                         investment      cost (MM$)     effectiveness   effectiveness    improvement    Fewer days >
                                                               (MM$)                          ($/ton)         ($/ton)         (delta       0.5 deciview
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The 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.


[[Page 24043]]

    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 NO<INF>X</INF> emissions reduced. SOFA+SNCR is more 
expensive than SOFA, with a cost effectiveness value of $2,596 per ton 
of NO<INF>X</INF> emissions reduced. SOFA+SCR is more expensive than 
SOFA or SOFA+SNCR, having a cost effectiveness value of $4,491 per ton 
of NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \190\ As 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.
---------------------------------------------------------------------------

    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.
SO<INF>2</INF>
    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\
---------------------------------------------------------------------------

    \191\ BART Assessment J.E. Corette Generating Station, prepared 
for PPL Montana, LLC, by TRC, (``Corette Initial Response''), August 
2007, p. 4-9.
    \192\ MDEQ, Final Operating Permit <greek-i>OP2953-05, for PPL 
Montana, LLC, JE Corette Steam Electric Station, 9.25/09.
---------------------------------------------------------------------------

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 
SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \193\ Control Technologies to Reduce Conventional and Hazardous 
Air Pollutants from Coal-Fired Power Plants, NESCAUM, March 31, 
2011, p. 13.
---------------------------------------------------------------------------

    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 
SO<INF>2</INF>.\194\
---------------------------------------------------------------------------

    \194\ Id., p. 11.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \195\ Id., p. 10.
---------------------------------------------------------------------------

    There are several variations of the scrubbing systems described 
above. However, as discussed in the NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \196\ Id., p. 10.
---------------------------------------------------------------------------

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 
SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \197\ Id., p. 13.
---------------------------------------------------------------------------

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

    \198\ ICAC, Acid Gas/SO<INF>2</INF> Control Technologies, http://www.icac.com/i4a/pages/index.cfm?pageid=3401.
    \199\ Documentation for IPM v. 4.1, Table 5-2.
---------------------------------------------------------------------------

    A summary of control efficiencies, emission rates, and resulting 
emission reductions for the control options under consideration are 
provided in Table 126.

[[Page 24044]]



                    Table 126--Summary of SO2 BART Analysis Control Technologies for Corette
----------------------------------------------------------------------------------------------------------------
                                               Control
             Control option                 effectiveness    Annual emission      Emissions         Remaining
                                                 (%)         rate (lb/MMBtu)   reduction (tpy)   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
----------------------------------------------------------------------------------------------------------------
\1\ Baseline 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 SO<INF>2</INF> controls with the CCM. In a 
manner similar to our evaluation of costs for NO<INF>X</INF> controls 
as described above, we relied on the cost methods developed for IPM 
version 4.10. However, unlike our evaluation of costs for 
NO<INF>X</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \200\ CCM, Section 1, Chapter 2, p. 2-21.
    \201\ Office of Management and Budget, Circular A-4, Regulatory 
Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.
    \202\ Chemical Engineering Magazine, p. 56, August 2011. (http://www.che.com).
---------------------------------------------------------------------------

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 SO<INF>2</INF> 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
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
             Total capital investment (MM$)              Total annual cost      Emissions      effectiveness  ($/
                                                               (MM$)        reductions  (tpy)         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.

[[Page 24045]]



 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
----------------------------------------------------------------------------------------------------------------
                                                                                Emissions         Average cost
            Total capital investment  (MM$)              Total annual cost  reductions  (tons/ effectiveness  ($/
                                                                (MM$)              yr)                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
----------------------------------------------------------------------------------------------------------------
                                                                                                  Average cost
            Total capital investment  (MM$)              Total annual cost      Emissions      effectiveness  ($/
                                                                (MM$)       reductions  (tpy)         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 in-line 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 SO<INF>2</INF> control options under 
consideration.
Factor 3: Non-air Quality Environmental Impacts
    Non-air quality environmental impacts for the SO<INF>2</INF> 
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.

[[Page 24046]]

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 by-product. 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 
non-air quality environmental impacts are not significant enough to 
warrant elimination of any of the SO<INF>2</INF> 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
----------------------------------------------------------------------------------------------------------------
                                           Baseline impact    LSFO  (Delta       LSD  (Delta       DSI  (Delta
              Class I area                (Delta deciview)      deciview)         deciview)         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 SO<INF>2</INF> 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 SO<INF>2</INF> 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility Impacts \1\
                                                                                                            Incremental  -------------------------------
                                                           Total capital   Total annual    Average cost        cost         Visibility
                     Control option                         investment      cost  (MM$)    effectiveness   effectiveness    improvement    Fewer days >
                                                               (MM$)                          ($/ton)         ($/ton)         (delta       0.5  deciview
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The 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.


[[Page 24047]]

    We have concluded that DSI is a cost effective control technology. 
DSI has a cost effectiveness value of $3,940 per ton of NO<INF>X</INF> 
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 
SO<INF>2</INF> emissions reduced and LSFO has a cost effectiveness of 
$6,365 per ton of SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \203\ As 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \204\ EPA Air Pollution Control Online Course, description at 
http://www.epa.gov/apti/course422/ce6a1.html.
    \205\ Corette Addendum, p. 6-1.
    \206\ Id.
---------------------------------------------------------------------------

    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     % Contribution  % Contribution
               (deciview)                    coarse PM        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 
<greek-i>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/PM<INF>10</INF> 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/PM<INF>10</INF> 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 (human-caused) 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 SO<INF>2</INF>, NO<INF>X</INF>, 
PM<INF>2.5</INF>, PM<INF>10</INF>, OC, EC, VOCs, and NH<INF>3</INF>.
    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.

[[Page 24048]]

    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 SO<INF>2</INF>, 
NO<INF>X</INF>, OC, EC, PM<INF>2.5</INF>, and PM<INF>10</INF> 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\
---------------------------------------------------------------------------

    \207\ The 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.
---------------------------------------------------------------------------

    SO<INF>2</INF> 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 SO<INF>2</INF> would be reduced at Colstrip due to controls required 
by the Regional Haze program. Overall, a 12% statewide reduction in 
SO<INF>2</INF> 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
----------------------------------------------------------------------------------------------------------------

    NO<INF>X</INF> emissions in Montana, shown in Table 141, are 
expected to decline 26% by 2018. Off-road and on-road vehicle 
NO<INF>X</INF> 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 NO<INF>X</INF> would be reduced at 
Colstrip by 2018 due to an enforcement action and additional controls 
required as a result of the regional haze requirements. NO<INF>X</INF> 
emissions from oil and gas sources are projected to increase by 84% 
(6000 tons). Overall, a 26% statewide reduction in NO<INF>X</INF> 
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 (non-anthropogenic) 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.

[[Page 24049]]



             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
----------------------------------------------------------------------------------------------------------------
\1\ Area 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
----------------------------------------------------------------------------------------------------------------
\1\ Area 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 
PM<INF>10</INF> and PM<INF>2.5</INF>) 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
----------------------------------------------------------------------------------------------------------------
\1\ Area Source Oil and Gas emissions are included in Area Source total for OC, EC, and PM.


[[Page 24050]]


                 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
----------------------------------------------------------------------------------------------------------------
\1\ Area 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, PM<INF>2.5</INF>, and PM<INF>10</INF>. The WEP tool is based on 
emissions and residence time, not modeling.
    PSAT uses the CAMx air quality model to show nitrate-sulfate-
ammonia chemistry and apply this chemistry to a system of tracers or 
``tags'' to track the chemical transformations, transport, and removal 
of NO<INF>X</INF> and SO<INF>2</INF>. These two pollutants are 
important because they tend to originate from anthropogenic sources. 
Therefore, the results from this analysis can be useful in determining 
contributing sources that may be controllable, both in-state and in 
neighboring states.
    WEP is a screening tool that helps to identify source regions that 
have the potential to contribute to haze formation at specific Class I 
areas. Unlike PSAT, this method does not account for chemistry or 
deposition. The WEP combines emissions inventories, wind patterns, and 
residence times of air 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, PM<INF>2.5</INF>, and PM<INF>10</INF>. 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.
---------------------------------------------------------------------------

    \208\ WRAP TSD.
---------------------------------------------------------------------------

    The contributions of sulfate and nitrate are based on PSAT while 
the contributions of OC, EC, PM<INF>2.5</INF>, PM<INF>10</INF>, 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
----------------------------------------------------------------------------------------------------------------
                                                                                      Species       MT sources
                                                                                   contribution    contribution
             Class I area                   Pollutant species     Extinction (Mm-    to total       to species
                                                                       \1\)         extinction      extinction
                                                                                        (%)           (%)\1\
----------------------------------------------------------------------------------------------------------------
                                        Sulfate.................            4.83              11               4
                                        Nitrate.................            1.46               3              18
                                        OC......................           20.01              47               5

[[Page 24051]]

 
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

[[Page 24052]]

 
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]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                              Outside
                                                              Montana         Canada           Idaho        Washington        Oregon          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]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                              Outside
                                                              Montana         Canada           Idaho        Washington        Oregon          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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 24053]]

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\
---------------------------------------------------------------------------

    \209\ WRAP TSD.

                     Table 149--MT Sources Extinction Contribution 2000-2004, 20% Worst Days
----------------------------------------------------------------------------------------------------------------
                                                                                                    MT sources
                                                                                      Species      contribution
             Class I area                   Pollutant species       Extinction     contribution     to species
                                                                      (Mm -1)       to particle     extinction
                                                                                  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

[[Page 24054]]

 
                                        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 Multi-Scale 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\
---------------------------------------------------------------------------

    \210\ Guidance on the Use of Models and Other Analyses for 
Demonstrating Attainment of Air Quality Goals for Ozone, 
PM<INF>2.5</INF>, and Regional Haze, (EPA-454/B-07-002), April 2007, 
located at http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf; Emissions Inventory Guidance for Implementation of 
Ozone and Particulate Matter National Ambient Air Quality Standards 
(NAAQS) and Regional Haze Regulations, August 2005, updated November 
2005 (``Our Modeling Guidance''), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001.
    \211\ WRAP TSD and ``Air Quality Modeling,'' available at: 
http://vista.cira.colostate.edu/docs/WRAP/Modeling/AirQualityModeling.doc.
---------------------------------------------------------------------------

    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

[[Page 24055]]

into the Regional Haze FIP for Montana.\212\
---------------------------------------------------------------------------

    \212\ See ``Air Quality Modeling,'' available at: http://vista.cira.colostate.edu/docs/WRAP/Modeling/AirQualityModeling.doc.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \213\ WRAP 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.
    \214\ A 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.
---------------------------------------------------------------------------

b. EPA's Reasonable Progress ``Four-Factor'' 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:
    <bullet> Costs of Compliance;
    <bullet> Time Necessary for Compliance;
    <bullet> Energy and Non-air Quality Environmental Impacts of 
Compliance; and
    <bullet> Remaining Useful Life of any Potentially Affected Sources.

CAA Sec.  169A(g)(1) and 40 CFR 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, 
PM<INF>2.5</INF>, PM<INF>10</INF>, SO<INF>2</INF>, and NO<INF>X</INF>.
    Tables 150 through 154 provide the statewide 2002 baseline primary 
organic aerosol, EC, PM<INF>2.5</INF> and PM<INF>10</INF> emissions and 
percentage contribution from the eleven source categories evaluated by 
WRAP.

   Table 150--Montana Primary Organic Aerosol Emission Inventory--2002
------------------------------------------------------------------------
                                           Baseline 2002   Percentage of
             Source category                   (tpy)           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  ..............
------------------------------------------------------------------------


[[Page 24056]]


      Table 151--Montana Elemental Carbon Emission Inventory--2002
------------------------------------------------------------------------
                                           Baseline 2002   Percentage of
             Source category                   (tpy)           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
------------------------------------------------------------------------
                                           Baseline 2002   Percentage of
             Source category                   (tpy)           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
------------------------------------------------------------------------
                                           Baseline 2002   Percentage of
             Source category                   (tpy)           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, 
PM<INF>2.5</INF> and PM<INF>10</INF> 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, PM<INF>2.5</INF> and PM<INF>10</INF> 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 PM<INF>2.5</INF> 
emissions and less than 1% to PM<INF>10</INF> 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 PM<INF>2.5</INF> emissions, and 
1% to PM<INF>10</INF> emissions. Natural fires are considered 
uncontrollable. In summary, we are proposing that additional controls 
for primary organic aerosols, EC, PM<INF>2.5</INF> and PM<INF>10</INF> 
from anthropogenic fire are not necessary for this planning

[[Page 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 PM<INF>2.5</INF> emissions, and 
less than 1% to PM<INF>10</INF> emissions. We are proposing that 
because area sources have such a small contribution to the emissions 
inventory, additional controls for primary organic aerosols, EC, 
PM<INF>2.5</INF> and PM<INF>10</INF> 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 
PM<INF>10</INF> 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, PM<INF>2.5</INF> and PM<INF>10</INF> 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 PM<INF>2.5</INF> 
emissions and 33% to PM<INF>10</INF> emissions. Wind-blown dust 
contributes 47% to fine particulate emissions and 53% to 
PM<INF>10</INF> 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, PM<INF>2.5</INF> and PM<INF>10</INF> and that 
additional controls for primary organic aerosols, EC, PM<INF>2.5</INF> 
and PM<INF>10</INF> from road dust, fugitive dust, and windblown dust 
are not necessary for this planning period.
    Table 154 provides the Statewide baseline SO<INF>2</INF> emissions 
and percentage contribution to the total SO<INF>2</INF> emissions in 
Montana.

             Table 154--Montana SO2 Emission Inventory--2002
------------------------------------------------------------------------
                                           Baseline 2002   Percentage of
             Source category                   (tpy)           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 SO<INF>2</INF> 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 
SO<INF>2</INF> 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. SO<INF>2</INF> emissions from natural fires 
(9%) are considered uncontrollable. On-road mobile sources contribute 
4% and off-road sources contribute 9% to Statewide SO<INF>2</INF> 
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 SO<INF>2</INF>.
    Table 155 provides the Statewide baseline NO<INF>X</INF> emissions 
and percentage contribution to the total NO<INF>X</INF> emissions in 
Montana.

             Table 155--Montana NOX Emission Inventory--2002
------------------------------------------------------------------------
                                           Baseline 2002   Percentage of
             Source category                   (tpy)           total
------------------------------------------------------------------------
Point...................................          53,416              22
Anthropogenic Fire......................           1,513              <1
Natural Fire............................          13,770               6

[[Page 24058]]

 
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 NO<INF>X</INF> emissions are 
from point sources. Emissions from anthropogenic fire contribute less 
than 1% and emissions from natural fire contribute 6% to Statewide 
NO<INF>X</INF> 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 on-road 
mobile sources contribute 22% and emissions from off-road mobile 
sources contribute 21% to Statewide NO<INF>X</INF> 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 NO<INF>X</INF>.
    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.
---------------------------------------------------------------------------

    \215\ The 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 NO<INF>X</INF> or SO<INF>2</INF> (or combined 
NO<INF>X</INF> and SO<INF>2</INF>), 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 NO<INF>X</INF> or SO<INF>2</INF> (or 
combined NO<INF>X</INF> and SO<INF>2</INF>) 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 156--Montana Q/D Analysis Sources With Results Greater Than 10
----------------------------------------------------------------------------------------------------------------
                                                                     SO2 + NOX      Distance to
                             Source                                  emissions     nearest class  Q/D  (tons/km)
                                                                      (tons)       I area  (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 <greek-i>1              1,155             107              11
 Compressor Station.............................................
Colstrip Energy Limited Partnership.............................           1,242             117              11
Montana Refining................................................             774              77              10
Conoco Phillips.................................................           1,323             136              10
----------------------------------------------------------------------------------------------------------------


[[Page 24059]]

    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 NO<INF>X</INF> and 
SO<INF>2</INF> were 1,019 tpy, resulting in a Q/D of 6. Cenex's 
emissions in 2008 of NO<INF>X</INF> and SO<INF>2</INF> were 727 tpy, 
resulting in a Q/D of 5. Conoco's emissions in 2008 of NO<INF>X</INF> 
and SO<INF>2</INF> were 1,087 tpy, resulting in a Q/D of 8. Montana 
Refining's emissions in 2008 of NO<INF>X</INF> and SO<INF>2</INF> 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
----------------------------------------------------------------------------------------------------------------
                                                                     SO2 + NOX      Distance to
                             Source                                  Emissions     nearest class  Q/D  (tons/km)
                                                                      (tons)       I area  (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 <greek-i>1               1,155             107              11
 Compressor Station.............................................
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 five-step 
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\
---------------------------------------------------------------------------

    \216\ Response 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).
---------------------------------------------------------------------------

    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, PM<INF>2.5</INF> and 
PM<INF>10</INF> 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.
---------------------------------------------------------------------------

    \217\ CELP Additional Response, p. 2-1.
---------------------------------------------------------------------------

SO<INF>2</INF>
    The current SO<INF>2</INF> 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 SO<INF>2</INF> 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[deg]F, it 
releases CO<INF>2</INF> 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 SO<INF>2</INF> 
emissions, on average about 80%. Increasing the limestone injection 
rate beyond current levels could theoretically result in a modest 
increase in SO<INF>2</INF> control.\218\
---------------------------------------------------------------------------

    \218\ CELP Additional Response, p. 2-2.
---------------------------------------------------------------------------

    SDAs use lime slurry and water injected into a tower to remove 
SO<INF>2</INF> 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

[[Page 24060]]

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% SO<INF>2</INF> 
reduction. SDA plus limestone injection can achieve between 98% and 99% 
SO<INF>2</INF> reduction.\219\
---------------------------------------------------------------------------

    \219\ US 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.
---------------------------------------------------------------------------

    DSI was previously described in our evaluation for Corette. 
SO<INF>2</INF> 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 
SO<INF>2</INF>. 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 SO<INF>2</INF> is removed. The dry by-product 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\
---------------------------------------------------------------------------

    \220\ Id.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 
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 
SO<INF>2</INF> by about 80%.\221\
---------------------------------------------------------------------------

    \221\ Id., p. 93.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> in the flue gas. Insoluble calcium 
sulfite (CaSO<INF>3</INF>) and calcium sulfate (CaSO<INF>4</INF>) 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 SO<INF>2</INF> 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 (CaCO<INF>3</INF>) 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.\222\
---------------------------------------------------------------------------

    \222\ Id., p. 94 (for proposed CFB boiler, indicating that a wet 
FGD scrubber plus limestone injection can achieve 99.1% control 
efficiency).
---------------------------------------------------------------------------

    Dual-alkali scrubbers use a sodium-based alkali solution to remove 
SO<INF>2</INF> from the combustion exhaust gas. The process uses both 
sodium-based and calcium-based compounds. The sodium-based reagents 
absorb SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> removal 
efficiency, if any, are expected with this scenario, compared to add-on 
SO<INF>2</INF> control systems discussed below. Therefore, a limestone 
injection process upgrade is eliminated from further consideration.
---------------------------------------------------------------------------

    \223\ CELP Additional Response, p. 2-2.
---------------------------------------------------------------------------

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

    \224\ Deseret Bonanza SOB, p. 92 (indicating that CDS systems 
have thus far not been used on CFB boilers).
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \225\ Id., p. 93.
---------------------------------------------------------------------------

    Regarding wet scrubbing, there is limited area to install 
additional SO<INF>2</INF> 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

[[Page 24061]]

controls,\226\ we consider these technologies technically infeasible 
and do not evaluate them further.
---------------------------------------------------------------------------

    \226\ CELP Additional Response, p. 2-5.
---------------------------------------------------------------------------

    The remaining technically feasible SO<INF>2</INF> control options 
for CELP are SDA and HAR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline SO<INF>2</INF> 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
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)          reduction tpy     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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            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.
---------------------------------------------------------------------------

    \227\ CELP Additional Response, Appendix A, pp. 17-24.
    \228\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \229\ CELP Additional Response, p. 3-1.
---------------------------------------------------------------------------

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

    \230\ Id., p. 4-1.
---------------------------------------------------------------------------

    SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \231\ Id.
---------------------------------------------------------------------------

    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.

[[Page 24062]]

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 
SO<INF>2</INF> (at a minimum) for the most cost-effective 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 SO<INF>2</INF> control 
options. We therefore propose to not require additional SO<INF>2</INF> 
controls for this planning period.
NO<INF>X</INF>
    Currently, there are no NO<INF>X</INF> 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 NH<INF>3</INF> or urea in the presence of a metal-
based catalyst to selectively reduce NO<INF>X</INF> 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 NH<INF>3</INF> injection 
system, and the potential for catalyst poisoning.
    SCR has been demonstrated to achieve high levels of NO<INF>X</INF> 
reduction in the range of 80% to 90% control, for a wide range of 
industrial combustion sources, including PC and stoker coal-fired 
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 [deg]F and 
800 [deg]F. Many of the CFBs in the United States have baghouses for 
particulate control. The normal maximum allowable temperature for a 
baghouse is 400 [deg]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 NO<INF>X</INF> 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 NH<INF>3</INF> or urea is 
injected into the flue gas at a suitable temperature zone, typically in 
the range of 1,600 to 2,000[emsp14][deg]F and at an appropriate ratio 
of reagent to NO<INF>X</INF>.
    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 NO<INF>X</INF> and lowers the peak 
flame temperature, which inhibits thermal NO<INF>X</INF> 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 NO<INF>X</INF>. 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> achieving a 94% destruction efficiency, and there 
are indications that an even higher destruction efficiency can be 
achieved. A successful commercial vendor uses NH<INF>3</INF> as a 
reducing agent to react with NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \232\ Deseret Bonanza SOB, p. 46.
---------------------------------------------------------------------------

    A version of sorbent injection uses carbon injected into the air 
flow to finish the capture of NO<INF>X</INF>. The carbon is captured in 
either the baghouse or the ESP, just like other sorbents.\233\
---------------------------------------------------------------------------

    \233\ US EPA, Office of Air Quality Planning and Standards, 
Technical Bulletin: Nitrogen Oxides (NO<INF>X</INF>), 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.

---------------------------------------------------------------------------

[[Page 24063]]

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 NO<INF>X</INF> 
emissions at PC boilers, it has much less effect on NO<INF>X</INF> 
emissions at combustion sources such as CFBs that operate at low 
combustion temperatures. FGR reduces NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \234\ CELP Additional Response, pp. 2-7, 2-8.
---------------------------------------------------------------------------

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

    \235\ CELP Additional Response, p. 2-8.
---------------------------------------------------------------------------

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

    \236\ Deseret Bonanza SOB, pp. 46, 48.
---------------------------------------------------------------------------

    Although carbon injection is an emerging technology used to reduce 
mercury emissions, it has not been used anywhere to control 
NO<INF>X</INF>. Therefore, it is eliminated from further consideration.
    The remaining technically feasible NO<INF>X</INF> control options 
for CELP are HDSCR and SNCR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NO<INF>X</INF> 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                            Remaining
                      Control option                          effectiveness       Emissions         emissions
                                                                   (%)         reduction (tpy)   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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
HDSCR...............................         2,102,189             3,423
SNCR................................           584,717             1,523
------------------------------------------------------------------------

    We are relying on all the NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \237\ CELP Additional Response.
    \238\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \239\ CELP Additional Response, p. 3-1.
---------------------------------------------------------------------------

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 NH<INF>3</INF> could pose a risk from potential 
releases to the environment. An additional concern is the loss of 
NH<INF>3</INF>, or ``slip'' into the emissions stream from the 
facility.

[[Page 24064]]

This ``slip'' contributes another pollutant to the environment, which 
has been implicated as a precursor to PM<INF>2.5</INF> 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 cost-
effective 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 SO<INF>2</INF> + 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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, 
PM<INF>2.5</INF> 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.
---------------------------------------------------------------------------

    \240\ Letter 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).
---------------------------------------------------------------------------

    Colstrip Unit 3 burns low-sulfur (0.7%) coal and has a wet 
particulate scrubber that achieves 95% SO<INF>2</INF> 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 SO<INF>2</INF> will 
not be considered or required in this planning period. We now consider 
controls for NO<INF>X</INF>.
    Currently, Colstrip Unit 3 has installed LNB with SOFA and a 
Digital Process Control System (DPCS). These controls reduce 
NO<INF>X</INF> 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 NO<INF>X</INF> control 
options for Colstrip Unit 3 are SCR and SNCR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NO<INF>X</INF> 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                            Remaining
                      Control option                          effectiveness       Emissions         emissions
                                                                   (%)         reduction (tpy)   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 NO<INF>X</INF> 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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
SCR.................................        17,425,444             4,574
SNCR................................         3,755,238             2,769
------------------------------------------------------------------------


[[Page 24065]]

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

    \241\ IPM, Chapter 5, Appendix 5-2A and 5-2B.
---------------------------------------------------------------------------

    As Colstrip Unit 3 burns sub-bituminous PRB coal having a low 
sulfur content of 0.91 lb/MMBtu (equating to a SO<INF>2</INF> 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 SO<INF>2</INF> is 
above 3 lb/MMBtu.\243\ Moreover, ammonium bisulfate formation can be 
minimized by preventing excessive NH<INF>3</INF> slip. Optimization of 
the SNCR system can commonly limit NH<INF>3</INF> 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.
---------------------------------------------------------------------------

    \242\ U.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.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> emissions reductions.
---------------------------------------------------------------------------

    \245\ NO<INF>X</INF> Control Update to PPL Montana's Colstrip 
Generating Station BART Report, September 2011, p. 8.
    \246\ Email communication with Fuel Tech, Inc. (Mar. 2, 2012).
    \247\ Cichanowicz 2010, p. 6-7.
---------------------------------------------------------------------------

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

    \248\ CCM, Section 4.2, Chapter 1, p. 1-21.
    \249\ CCM, Section 4.2, Chapter 2, p. 2-28.
---------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                           Improvement from    Improvement from
                    Class I area                        Baseline impact       SCR (delta          SNCR (delta
                                                       (delta deciview)        deciview)           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]
----------------------------------------------------------------------------------------------------------------
                                                                     Baseline
                          Class I area                                (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
----------------------------------------------------------------------------------------------------------------


[[Page 24066]]

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 NO<INF>X</INF> 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, 
PM<INF>2.5</INF> 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.
---------------------------------------------------------------------------

    \250\ Colstrip 3 & 4 Additional Response, Attachment 2, p. 2.
---------------------------------------------------------------------------

    Colstrip Unit 4 burns low-sulfur (0.7%) coal and has a wet 
particulate scrubber that achieves 95% SO<INF>2</INF> 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 
SO<INF>2</INF> will not be considered or required in this planning 
period.
---------------------------------------------------------------------------

    \251\ Id.
---------------------------------------------------------------------------

    Currently, Colstrip Unit 4 has installed LNB with SOFA and a DPCS. 
These controls reduce NO<INF>X</INF> 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 NO<INF>X</INF> control options for Colstrip 
Unit 4 are SCR and SNCR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NO<INF>X</INF> 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
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)        reduction  (tpy)  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 NO<INF>X</INF> 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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual      effectiveness
                                          cost  ($)          ($/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.
---------------------------------------------------------------------------

    \252\ IPM, Chapter 5, Appendix 5-2A and 5-2B.
---------------------------------------------------------------------------

    As Colstrip Unit 4 burns sub-bituminous PRB coal having a low 
sulfur content of 0.91 lb/MMBtu (equating to a SO<INF>2</INF> 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

[[Page 24067]]

maintenance associated with fouling due to the formation of ammonium 
bisulfate. These are only concerns when the rate of SO<INF>2</INF> is 
above 3 lb/MMBtu.\254\ Moreover, ammonium bisulfate formation can be 
minimized by preventing excessive NH<INF>3</INF> slip. Optimization of 
the SNCR system can commonly limit NH<INF>3</INF> 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.
---------------------------------------------------------------------------

    \253\ U.S. DOE, Energy Information Administration, Cost and 
Quality of Fuels for Electric Utility Plants 1999 Tables, DOE/EIA-
0191(99), Table 24 (June 2000).
    \254\ IPM, Chapter 5, p. 5-9.
    \255\ ICAC, p. 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \256\ NO<INF>X</INF> Control Update to PPL Montana's Colstrip 
Generating Station BART Report, September 2011, p. 8.
    \257\ Email communication with Fuel Tech, Inc., March 2, 2012.
    \258\ Cichanowicz 2010, p. 6-7.
---------------------------------------------------------------------------

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

    \259\ CCM, Section 4.2, Chapter 1, p. 1-21.
    \260\ CCM, Section 4.2, Chapter 2, p. 2-28.
---------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                                    Improvement     Improvement
                                                                     Baseline        from SCR        from SNCR
                          Class I area                            impact  (delta      (delta          (delta
                                                                     deciview)       deciview)       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]
----------------------------------------------------------------------------------------------------------------
                                                                     Baseline
                          Class I area                                (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 NO<INF>X</INF> controls will be 
required for this planning period on Colstrip Unit 4.

[[Page 24068]]

iv. Devon Energy Blaine County <greek-i>1 Compressor Station
    Devon Energy Blaine County <greek-i>1 Compressor Station (Devon) 
operates two 5,500-hp Ingersoll Rand 616 natural gas compressor engines 
at its Blaine County <greek-i>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\
---------------------------------------------------------------------------

    \261\ Letter 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 Energy-Blaine County 
<greek-i>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 
<greek-i>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).
---------------------------------------------------------------------------

    PM and SO<INF>2</INF> emissions are relatively small (0.32 tpy of 
PM and 0.02 tpy of SO<INF>2</INF> per engine). Thus, SO<INF>2</INF> and 
PM emissions from these two engines are not significant contributors to 
regional haze and our determination only considers NO<INF>X</INF>. 
Additional controls for SO<INF>2</INF> 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 screw-in 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 NO<INF>X</INF> 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 NO<INF>X</INF> levels and combustion stability. 
Dresser-Rand estimates that this system could achieve a 14% reduction 
in NO<INF>X</INF> 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 NO<INF>X</INF> emissions performance. Dresser-Rand estimates 
that this system could achieve a 78% reduction in NO<INF>X</INF> 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 
NH<INF>3</INF> slip or periods of insufficient NH<INF>3</INF> 
injection. It is estimated that this system could achieve a 75% 
reduction in NO<INF>X</INF> 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 NO<INF>X</INF> control technology for exhaust 
streams with low O<INF>2</INF> content. NSCR uses a catalyst reaction 
to simultaneously reduce NO<INF>X</INF>, 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 NO<INF>X</INF>. 
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 [deg]F). The gas stream 
is cooled prior to entering the first catalytic reactor where CO and 
NO<INF>X</INF> are reduced. A second heat exchanger cools the gas 
stream (to reduce any NO<INF>X</INF> reformation) before the second 
catalytic reactor where remaining CO is converted to carbon dioxide.
    The control efficiency achieved by NSCR for NO<INF>X</INF> ranges 
from 80 to 90%. The NO<INF>X</INF> 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 
[deg]F to 1500 [deg]F, depending on the catalyst.\262\
---------------------------------------------------------------------------

    \262\ CAM Technical Guidance Document, Appendix B-16, Non-
Selective Catalytic Reduction (Apr. 2002), available at: 
www.epa.gov/ttnchie1/mkb/documents/B_16a.pdf.
---------------------------------------------------------------------------

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 NO<INF>X</INF> 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
                        Control option                            effectiveness       Emissions         Remaining         Emissions         Remaining
                                                                       (%)        reduction  (tpy)  emissions  (tpy)  reduction  (tpy)  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 air-fuel 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.


[[Page 24069]]

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\
---------------------------------------------------------------------------

    \263\ US 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.
---------------------------------------------------------------------------

    Table 171 provides a summary of estimated annual costs for the 
various control options.




                        Table 171--Summary of Devon NOX Reasonable Progress Cost Analysis
----------------------------------------------------------------------------------------------------------------
                                                                                    Cost              Cost
                                                              Total annual      effectiveness     effectiveness
                      Control option                         cost  ($) (same       ($/ton)           ($/ton)
                                                             for both units) -----------------------------------
                                                                                   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                 29,100               652               652
 control..................................................
----------------------------------------------------------------------------------------------------------------

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 NH<INF>3</INF>, 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 NO<INF>X</INF> 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 <greek-i>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 
[deg]F and no more than 1250 [deg]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 <plus-minus>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 CO<INF>2</INF> 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:
    <bullet> Devon shall measure NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions from the

[[Page 24070]]

engines using a portable analyzer and a monitoring protocol approved by 
EPA.
    <bullet> Devon shall submit the analyzer specifications and 
monitoring protocol to EPA for approval within 45 calendar days prior 
to installation of the NSCR unit.
    <bullet> Monitoring for NO<INF>X</INF> emissions shall commence 
during the first complete calendar quarter following Devon's submittal 
of the initial performance test results for NO<INF>X</INF> to EPA.
    <bullet> 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.
    <bullet> 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.
    <bullet> 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.
    <bullet> 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 CO<INF>2</INF> concentration in the 
natural gas.
    <bullet> 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.
    <bullet> Devon 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.
    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\
---------------------------------------------------------------------------

    \264\ Response 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, Montana-
Dakota 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).
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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 NO<INF>X</INF> 
controls consist of LNBs and a CCOFA system, installed in 1996. 
Estimated level of control is 33%.\265\
---------------------------------------------------------------------------

    \265\ L&C Initial Response, pp. 3-5; L&C Emissions Control 
Analysis, p. 4.
---------------------------------------------------------------------------

    As discussed previously in Section V.D.6.b., the contribution from 
point sources to primary organic aerosols, EC, PM<INF>2.5</INF> 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.
SO<INF>2</INF>
    Current SO<INF>2</INF> 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 SO<INF>2</INF> in the gas 
stream reacts with the lime to form 
CaSO<INF>3</INF><bullet>2H<INF>2</INF>O and CaSO<INF>4</INF>. 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 SO<INF>2</INF> removal.
    This wet scrubbing option at L&C Station would involve modification 
to the existing PM wet scrubber to increase SO<INF>2</INF> removal 
efficiency. The modification would primarily involve upgrade and 
optimization of the lime injection system. Expected total 
SO<INF>2</INF> 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\
---------------------------------------------------------------------------

    \266\ L&C Emissions Control Analysis, pp. 13-17.
---------------------------------------------------------------------------

    Lime SDA is a dry scrubbing system that sprays a fine mist of lime 
slurry into an absorption tower where the SO<INF>2</INF> is absorbed by 
the droplets. Once absorbed, the SO<INF>2</INF> reacts with lime to 
form CaSO<INF>3</INF><bullet>2H<INF>2</INF>O and CaSO<INF>4</INF> 
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

[[Page 24071]]

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\
---------------------------------------------------------------------------

    \267\ L&C Feb. 10, 2012 Response, p. 3.
    \268\ L&C Emissions Control Analysis, p. 15.
    \269\ Id.
---------------------------------------------------------------------------

    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 SO<INF>2</INF>. 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\
---------------------------------------------------------------------------

    \270\ Id., pp. 13, 15.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>. Since pipeline-quality natural gas 
has negligible sulfur content, we would expect a greater than 99% 
reduction in SO<INF>2</INF>. 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\
---------------------------------------------------------------------------

    \271\ Id., pp. 8-10.
    \272\ Id.
    \273\ L&C Initial Response, p. 7.
    \274\ L&C Feb. 10, 2012 Response, p. 2.
---------------------------------------------------------------------------

Step 2: Eliminate Technically Infeasible Options
    Although switching to coals with lower sulfur content and higher 
Btu content represents a viable pre-combustion method of reducing 
SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \275\ L&C Emissions Control Analysis, p. 8-10.
---------------------------------------------------------------------------

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 SO<INF>2</INF> emissions (1,002 tpy).

         Table 172--Summary of MDU Lewis and Clark SO2 Reasonable Progress Analysis Control Technologies
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   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.

[[Page 24072]]



    Table 173--Summary of MDU Lewis & Clark Reasonable Progress Cost
                                Analysis
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            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 
SO<INF>2</INF> 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\
---------------------------------------------------------------------------

    \276\ L&C Feb. 10, 2012 Response, p. 2.
    \277\ Report 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).
    \278\ L&C Emissions Control Analysis, p. 17.
---------------------------------------------------------------------------

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 SDA-with-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 
CO<INF>2</INF> 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\
---------------------------------------------------------------------------

    \279\ L&C Emissions Control Analysis, p. 16.
---------------------------------------------------------------------------

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 SO<INF>2</INF> emissions by 100 tpy, which 
equates to a 5.5% reduction in overall emissions of SO<INF>2</INF> + 
NO<INF>X</INF> 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 SO<INF>2</INF> controls for this planning period.
NO<INF>X</INF>
    Current NO<INF>X</INF> 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 
NO<INF>X</INF>, for the same reasons as described in our SO<INF>2</INF> 
analysis. With regard to a potential switch to PRB coal, higher heat 
content of coal can yield lower NO<INF>X</INF> 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 NO<INF>X</INF> emissions 
than lignite coal, per ton of coal fired. Similarly, natural gas could 
be expected to produce lower NO<INF>X</INF> emissions than lignite 
coal. We used a 65% reduction in our analysis.\281\
---------------------------------------------------------------------------

    \280\ L&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.
    \281\ The 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 NO<INF>X</INF> emissions. Baseline 
NO<INF>X</INF> 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 
NO<INF>X</INF> emissions.
---------------------------------------------------------------------------

    SCR was generally described in our BART analysis for CELP. SCR has 
been demonstrated to achieve high levels of NO<INF>X</INF> reduction in 
the range of 80% to 90% (or higher) control, for a wide range of 
industrial combustion sources, including PC, cyclone, and stoker coal-
fired 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

[[Page 24073]]

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\
---------------------------------------------------------------------------

    \282\ MDU NO<INF>X</INF> control cost analysis by US EPA Region 
8 for SCR, SOFA/LNB, and SCR + SOFA/LNB, Summary Spreadsheet (Mar. 
7, 2012).
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
SO<INF>2</INF> 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 NO<INF>X</INF> 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
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   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
----------------------------------------------------------------------------------------------------------------
\1\ Baseline 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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual      effectiveness
                                          cost  ($)          ($/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
------------------------------------------------------------------------


[[Page 24074]]

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\
---------------------------------------------------------------------------

    \283\ L&C Emissions Control Analysis, p. 26.
    \284\ L&C Feb. 10, 2012 Response, p. 2.
---------------------------------------------------------------------------

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, 
NH<INF>3</INF> slip can generally cause additional NH<INF>3</INF> to be 
emitted to air or water. As NH<INF>3</INF> 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 
SO<INF>2</INF> + NO<INF>X</INF> 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 
NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \285\ Reasonable 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).
---------------------------------------------------------------------------

    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 SO<INF>2.</INF> 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 SO<INF>2</INF> 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, 
PM<INF>2.5</INF> and PM<INF>10</INF> 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.
    NO<INF>X</INF> emissions also are relatively small, at 3 tpy. Thus, 
NO<INF>X</INF> emissions from the unit are not significant contributors 
to regional haze. Additional controls for NO<INF>X</INF> will not be 
considered or required in this planning period. We are therefore 
considering controls only for SO<INF>2</INF> 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[supreg] process) and tail gas scrubbing (Wellman-Lord, SCOT, 
and traditional FGD processes).
    In the Sulfured[supreg] process, the Claus reaction is extended at 
low temperatures (260 to 300[deg]F) to recover SO<INF>2</INF> and 
H<INF>2</INF>S 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 (Na<INF>2</INF>SO<INF>3</INF>) and sodium bisulfate 
(NaHSO<INF>3</INF>) to react with SO<INF>2</INF> gas from the Claus 
incinerator to form bisulfate. The incinerator gases must be cooled and 
quenched before scrubbing, subjected to

[[Page 24075]]

misting after scrubbing, and reheated afterwards. The bisulfate 
solution is regenerated to sodium sulfite in a steam-energized 
evaporator. The concentrated wet SO<INF>2</INF> gas stream from the 
evaporator is partially condensed and some of the liquid water is used 
to dissolve sulfite crystals. The remaining enriched SO<INF>2</INF> 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, 
SO<INF>2</INF>, and reduced sulfur compounds are substantially 
reconverted to H<INF>2</INF>S. The H<INF>2</INF>S-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 SO<INF>2</INF> or sulfur) that may 
arise during malfunctions. The rich solution is separately regenerated 
using steam, cooled and returned to the scrubber/absorber. The 
H<INF>2</INF>S-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 
SO<INF>2</INF> concentrations at MSCC are too high. These technologies 
cannot be used when concentrations are greater than 2000 ppm. The 
average concentration of SO<INF>2</INF> 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[supreg] 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[supreg] 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[supreg] 
system when compared to the SCOT process. Because the SCOT process is 
more effective and costs less than the Sulfured[supreg] system, the 
Sulfured[supreg] system was not considered further.
Step 3: Evaluate Control Effectiveness of Remaining Control 
Technologies
    Baseline SO<INF>2</INF> 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
                     Control option                        effectiveness        Emissions          Remaining
                                                              \1\ (%)        reduction  (tpy)   emissions  (tpy)
----------------------------------------------------------------------------------------------------------------
SCOT...................................................              99.9                871                581
----------------------------------------------------------------------------------------------------------------
\1\ Overall 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.

[[Page 24076]]



    Table 177--Summary of MSCC SO2 Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual 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.
---------------------------------------------------------------------------

    \286\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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 
SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \287\ Letter from Thomas Ray to Vanessa Hinkle (Feb. 28, 2011); 
Reasonable Progress (RP) Four-Factor Analysis of Control Options for 
Plum Creek Manufacturing/Columbia Falls Operations.
---------------------------------------------------------------------------

    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 direct-contact 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 NO<INF>X</INF> 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, PM<INF>2.5</INF> 
and PM<INF>10</INF> 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.
    SO<INF>2</INF> emissions are relatively small (18 tpy for all units 
combined). Thus, SO<INF>2</INF> emissions from these units are not 
significant contributors to regional haze, and additional controls for 
SO<INF>2</INF> will not be considered or required in this planning 
period. We are therefore only considering controls for NO<INF>X</INF> 
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 NO<INF>X</INF> 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

[[Page 24077]]

temperature required for the SCR catalyst to be effective at reducing 
NO<INF>X</INF> 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 
(NH<INF>3</INF> 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 NO<INF>X</INF> and any reagent 
that remains.
    Staged combustion can be achieved through a wide variety of methods 
and techniques, but in general creates a fuel-rich zone followed by a 
fuel lean zone. This reduces the peak flame temperature and the 
generation of thermal NO<INF>X</INF>.
    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 N<INF>2</INF>. 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 under-fire 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 spreader-stoker 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 NO<INF>X</INF>, 
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 NO<INF>X</INF> 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
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
SNCR......................................................                35               205               382

[[Page 24078]]

 
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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
SNCR................................          $294,377            $1,436
\1\ RSCR............................           748,097             1,700
------------------------------------------------------------------------
\1\ Further 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.
---------------------------------------------------------------------------

    \288\ Plum Creek Revised Response, Table C-4 (Mar. 13, 2012).
    \289\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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  2 million scf/year  930,000-5.4         42.5-125 lb/hr or
                                   gal/year.           to 9.7 million      million kWh/year.   186-548 tpy.
                                                       scf/year.
----------------------------------------------------------------------------------------------------------------

    Additionally, the RSCR catalyst may have the potential to emit 
NH<INF>3</INF> (as NH<INF>3</INF> 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 
NH<INF>3</INF>. However, regular handling of NH<INF>3</INF> has reduced 
the risks associated with its transport, storage, and use.
    As with RSCR, there are issues associated with NH<INF>3</INF>, 
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.

[[Page 24079]]



                     Table 181--Additional Reagent, Electricity and Steam Required for SNCR
----------------------------------------------------------------------------------------------------------------
                                            Reagent (Urea)            Electricity                 Steam
----------------------------------------------------------------------------------------------------------------
Boiler SNCR System...................  165 tpy or 69,740        204,108 kWh/year.......  51.4 lb/hr or 225 tpy.
                                        gallons Urea solution/
                                        year.
----------------------------------------------------------------------------------------------------------------

    As with RSCR, some level of NH<INF>3</INF> 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 NH<INF>3</INF> slip. Whether urea or NH<INF>3</INF> 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 
NO<INF>X</INF> 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 SO<INF>2</INF> + NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NH<INF>3</INF> 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 NH<INF>3</INF> to the product lines. Contact with 
NH<INF>3</INF> may result in reduced product quality. NH<INF>3</INF> 
darkens wood, which would not be acceptable for Plum Creek's light 
colored stains. Additionally, NH<INF>3</INF> may affect the curing of 
any formaldehyde-based resins used in the wood products. High levels of 
NH<INF>3</INF> 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 
NH<INF>3</INF> 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 NO<INF>X</INF> 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

[[Page 24080]]

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 NO<INF>X</INF> 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           Emissions          Remaining
                     Control option                      effectiveness (%)   reduction (tpy)    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
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual cost  effectiveness ($/
                                           ($)                ton)
------------------------------------------------------------------------
\1\ RSCR..........................           748,097              3,117
------------------------------------------------------------------------
\1\ Further 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 
SO<INF>2</INF> + NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF>. 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 NH<INF>3</INF> 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

[[Page 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 NO<INF>X</INF> reductions would not likely be realized 
because the staged combustion design has already reduced thermal 
NO<INF>X</INF> 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 NO<INF>X</INF> reductions would not likely be 
realized because the staged combustion design has already reduced 
thermal NO<INF>X</INF> 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 NO<INF>X</INF> 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           Emissions          Remaining
                     Control option                      effectiveness (%)   reduction (tpy)    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
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual cost  effectiveness ($/
                                           ($)                ton)
------------------------------------------------------------------------
\1\ RSCR..........................           748,000              4,987
------------------------------------------------------------------------
\1\ Further 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/

[[Page 24082]]

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 multi-platen 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 dust-fired Babcock & Wilcox boiler, which also 
provides steam for facility processes.
---------------------------------------------------------------------------

    \290\ Reasonable 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.
---------------------------------------------------------------------------

    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, PM<INF>2.5</INF> 
and PM<INF>10</INF> 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.
    SO<INF>2</INF> emissions are relatively small (6 tpy of 
SO<INF>2</INF> for all units combined). Thus, SO<INF>2</INF> emissions 
from these units are not significant contributors to regional haze and 
our analysis only considers NO<INF>X</INF>. Additional controls for 
SO<INF>2</INF> will not be considered or required in this planning 
period. We are therefore considering controls only for NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NH<INF>3</INF> to the product lines. Roseburg has stated that 
contact with NH<INF>3</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF>, 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

[[Page 24083]]

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 NO<INF>X</INF> emissions from the 
boiler are 134 tpy. Baseline NO<INF>X</INF> emissions from the Line 1 
dryers would be from the boiler and ROEMMC sander dust burner combined 
and are 202 tpy. Baseline NO<INF>X</INF> 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           Emissions         Remaining
                      Control option                       effectiveness (%)   reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
LNB......................................................               22.2                30               104
RSCR Line 1..............................................               75              \1\151             \1\51
RSCR Line 2..............................................               75               \1\69             \1\23
----------------------------------------------------------------------------------------------------------------
\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 NO<INF>X</INF> emissions when firing coal, depending 
on the design or generation of the burner. However, NO<INF>X</INF> 
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 NO<INF>X</INF> rather 
than thermal NO<INF>X</INF>, and LNB primarily reduce the generation of 
thermal NO<INF>X</INF>.
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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            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\
---------------------------------------------------------------------------

    \291\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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 [deg]F, and the temperature of the exhaust of the ROEMMC varies 
between 700 [deg]F and 1050 [deg]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 [deg]F to 155 
[deg]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.

[[Page 24084]]



               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/    3.6 million kWh/    7.2 million scf/
                                                       year.               year.               year
Line 2 RSCR.....................  433,000 gal/year..  4.7 million scf/    1.7 million kWh/    3.8 million scf/
                                                       year.               year.               year
----------------------------------------------------------------------------------------------------------------

    Additionally, the RSCR catalyst may have the potential to emit 
NH<INF>3</INF> (as NH<INF>3</INF> 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 
NH<INF>3</INF>. However, regular handling of NH<INF>3</INF> 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 SO<INF>2</INF> + 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NH<INF>3</INF>. 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 NO<INF>X</INF>. 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

[[Page 24085]]

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 NH<INF>3</INF>. 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 NO<INF>X</INF> 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           Emissions          Remaining
                     Control option                      effectiveness (%)   reduction (tpy)    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
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual 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\
---------------------------------------------------------------------------

    \292\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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

[[Page 24086]]

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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \293\ See http://www.greeninvgroup.com/news/news-release-missoula-announcement.html.
    \294\ M2Green Redevelopment LLC Quarterly Excess Emissions 
Report--Third Quarter 2011 (11/1/2011).
---------------------------------------------------------------------------

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

    \295\ All information found within this section can be found in 
the corresponding report in the docket.
---------------------------------------------------------------------------

    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, 
PM<INF>2.5</INF> 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.
---------------------------------------------------------------------------

    \296\ Response 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.
---------------------------------------------------------------------------

SO<INF>2</INF>
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 SO<INF>2</INF> 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[emsp14][deg]F, it releases CO<INF>2</INF> and forms lime (CaO), 
which subsequently reacts with the SO<INF>2</INF> 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 SO<INF>2</INF> emissions. 
YELP states that, during 2008 through 2009, SO<INF>2</INF> reduction 
averaged 95%. Increasing the limestone injection rate beyond current 
levels could theoretically result in a modest increase in 
SO<INF>2</INF> control.
    SDAs were described in our analysis for CELP. SDAs have 
demonstrated the ability to achieve 90% to 94% SO<INF>2</INF> 
reduction. SDA plus limestone injection can achieve between 98% and 99% 
SO<INF>2</INF> reduction.\297\ Due to the high degree of SO<INF>2</INF> 
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.
---------------------------------------------------------------------------

    \297\ Deseret Bonanza SOB, p. 92.
---------------------------------------------------------------------------

    DSI was described in our BART analysis for Corette. SO<INF>2</INF> 
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\
---------------------------------------------------------------------------

    \298\ Id.
---------------------------------------------------------------------------

    The HAR process was described in our analysis for CELP. HAR 
downstream of a CFB boiler that utilizes limestone injection can reduce 
the remaining SO<INF>2</INF> by about 80%.\299\
---------------------------------------------------------------------------

    \299\ Id., p. 93.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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 
(CaCO<INF>3</INF>) 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\
---------------------------------------------------------------------------

    \300\ Deseret Bonanza SOB, p. 94.
---------------------------------------------------------------------------

    Dual-alkali scrubbers use a sodium-based alkali solution to remove 
SO<INF>2</INF> from the combustion exhaust gas. The process uses both 
sodium-based and calcium-based compounds. The sodium-based reagents 
absorb SO<INF>2</INF> 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 SO<INF>2</INF> 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

[[Page 24087]]

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 SO<INF>2</INF> removal 
efficiency, if any, would be expected with this scenario, compared to 
add-on SO<INF>2</INF> control systems discussed below. Therefore, a 
limestone injection process upgrade is eliminated from further 
consideration.
---------------------------------------------------------------------------

    \301\ YELP Additional Response, p. 2-2.
---------------------------------------------------------------------------

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

    \302\ Deseret Bonanza SOB, p. 92.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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 SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \303\ Id., p. 93.
---------------------------------------------------------------------------

    Regarding wet scrubbing, there is limited area to install 
additional SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \304\ YELP Additional Response, p. 2-5.
---------------------------------------------------------------------------

    The remaining technically feasible SO<INF>2</INF> control options 
for YELP are SDA and HAR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NO<INF>X</INF> 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
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            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.
---------------------------------------------------------------------------

    \305\ Id., p. 7-3.
    \306\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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

[[Page 24088]]

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\
---------------------------------------------------------------------------

    \307\ YELP Additional Response, p. 3-1.
---------------------------------------------------------------------------

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

    \308\ Id., p. 4-2.
---------------------------------------------------------------------------

    SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \309\ Id.
---------------------------------------------------------------------------

    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 
SO<INF>2</INF> (at a minimum) for the most cost-effective 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 SO<INF>2</INF> control 
options. Therefore, we are proposing that no additional controls will 
be required for this planning period.
NO<INF>X</INF>
    Currently, there are no NO<INF>X</INF> 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, non-thermal 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 
[deg]F and 800 [deg]F. Many of the CFBs in the United States have 
baghouses for particulate control. The normal maximum allowable 
temperature for a baghouse is 400 [deg]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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions at PC boilers, it has much less effect on NO<INF>X</INF> 
emissions at combustion sources such as CFBs that operate at low 
combustion temperatures. FGR reduces NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \310\ Id.
---------------------------------------------------------------------------

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

    \311\ Id.
---------------------------------------------------------------------------

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

    \312\ Deseret Bonanza SOB, pp. 46, 48.
---------------------------------------------------------------------------

    Although carbon injection is an emerging technology used to reduce 
mercury emissions, it has not been used anywhere to control 
NO<INF>X</INF>. Therefore, it is eliminated from further consideration.
    The remaining technically feasible NO<INF>X</INF> control options 
for YELP are HDSCR and SNCR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NO<INF>X</INF> emissions from YELP are 396 tpy. A summary 
of emissions projections for the various control options is provided in 
Table 194.

[[Page 24089]]



                Table 194--Summary of YELP NOX Reasonable Progress Analysis Control Technologies
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   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
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
HDSCR...............................         3,883,020            12,249
SNCR................................           529,810             2,689
------------------------------------------------------------------------

    We have relied on the NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \313\ YELP Additional Response, Appendix A.
    \314\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \315\ YELP Additional Response, p. 3-1.
---------------------------------------------------------------------------

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 NH<INF>3</INF> could pose a risk from potential 
releases to the environment. An additional concern is the loss of 
NH<INF>3</INF>, 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 
PM<INF>2.5</INF> 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 SO<INF>2</INF> + NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 24090]]

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
----------------------------------------------------------------------------------------------------------------
                                                      Visibility conditions on 20% worst days
                                                                    (deciview)
                                                 ------------------------------------------------  Percentage of
              Montana class I area                  Average for                                    URP achieved
                                                  20% worst days                     RPG (WRAP          (%)
                                                  (baseline 2000-  2018 URP goal    projection)
                                                       2004)
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
                                                 Average for                     RPG Rate of
                                2064 natural   20% worst days    Improvement     improvement    Number of years
     Montana class I area        conditions    (Baseline 2000-     needed        (deciview/     to reach natural
                                 (deciview)         2004)        (deciview)         year)          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
----------------------------------------------------------------------------------------------------------------
                                                            Visibility conditions on 20% best
                                                                    days  (deciview)
                                                          ------------------------------------   Achieved ``No
                   Montana class I area                     Average for 20%                    degradation''  (Y/
                                                               best days         RPG (WRAP             N)
                                                            (Baseline 2000-     projection)
                                                                 2004)
----------------------------------------------------------------------------------------------------------------
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

[[Page 24091]]

 
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

[[Page 24092]]

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 NO<INF>X</INF> and SO<INF>2</INF> 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 on-road (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.
---------------------------------------------------------------------------

    \316\ WRAP TSD. and Final Report, WRAP Mobile Source Emission 
Inventories Updated, dated May 2006.
---------------------------------------------------------------------------

    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 on-going 
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.
---------------------------------------------------------------------------

    \317\ Email from Debbie Skibicki to Vanessa Hinkle dated January 
4, 2012 regarding Roundup Power.
---------------------------------------------------------------------------

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.

[[Page 24093]]



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

    \318\ WRAP 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.
---------------------------------------------------------------------------

    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 PM<INF>2.5</INF> 
emissions, less than 1% to PM<INF>10</INF> emissions, 1% to 
SO<INF>2</INF> emissions, and less than 1% to NO<INF>X</INF> emissions. 
Natural fire contributes 80% to primary organic aerosol emissions, 65% 
to EC emissions, 4% to PM<INF>2.5</INF> emissions, 1% to 
PM<INF>10</INF> emissions, 9% to SO<INF>2</INF> emissions, and 6% to 
NO<INF>X</INF> 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%, 
SO<INF>2</INF> contributes 8% to 28%, and NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \319\ There 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).
    \320\ State of Montana Air Quality Control Implementation Plan, 
Volume I, Chapter 9, p. 9.6(8) (Dec. 2, 2011).
---------------------------------------------------------------------------

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 SO<INF>2</INF> and NO<INF>X</INF> 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

[[Page 24094]]

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.<SUP>321 322</SUP> 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.
---------------------------------------------------------------------------

    \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.
    \323\ Spatial and Seasonal Patterns and Temporal Variability of 
Haze and its Constituents in the United States, Report V, ISSN 0737-
5352-87, June 2011.
---------------------------------------------------------------------------

    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 Selway-Bitterroot 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).

[[Page 24095]]

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:
    <bullet> For Ash Grove Cement:
    [cir] A NO<INF>X</INF> 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 NO<INF>X</INF> 
BART limit within five (5) years of the effective date of our final 
rule.
    [cir] A SO<INF>2</INF> 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 SO<INF>2</INF> 
BART limit within 180 days of the effective date of our final rule.
    [cir] 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=4.10p\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. 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.
    <bullet> For Colstrip Units 1 and 2:
    [cir] NO<INF>X</INF> 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 NO<INF>X</INF> BART limits within five (5) years of the 
effective date of our final rule.
    [cir] SO<INF>2</INF> 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 SO<INF>2</INF> BART limits within five (5) years of the 
effective date of our final rule.
    [cir] 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.
    <bullet> For Holcim:
    [cir] A NO<INF>X</INF> 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 NO<INF>X</INF> 
BART limit within five (5) years of the effective date of our final 
rule.
    [cir] A SO<INF>2</INF> 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 SO<INF>2</INF> 
BART limit within 180 days of the effective date of our final rule.
    [cir] 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.
    <bullet> For Corette:
    [cir] A NO<INF>X</INF> 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 NO<INF>X</INF> BART limit 
within 30 days of the effective date of our final rule.
    [cir] A SO<INF>2</INF> 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 SO<INF>2</INF> 
BART limit within 30 days of the effective date of our final rule.
    [cir] 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.
    <bullet> For Devon Energy Blaine County <greek-i>1 Compressor 
Station, a NO<INF>X</INF> 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 Sec.  52.1395, that the owners/
operators comply with this limit as expeditiously as practicable, but 
no later than July 31, 2018.
    <bullet> 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.
    <bullet> 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.
    <bullet> Monitoring, recordkeeping, and reporting requirements for 
the above six units to ensure compliance with these emission 
limitations.
    <bullet> RPGs consistent with the proposed FIP limits.
    <bullet> 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.

[[Page 24096]]

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-for-profit 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, NO<INF>X</INF> and SO<INF>2</INF> emissions on specific units at 
five sources in Montana, and imposing controls to meet the RP 
requirement for NO<INF>X</INF> 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 cost-
effective, or least burdensome alternative that achieves the objectives 
of the rule. The provisions of section 205 of UMRA do not apply when 
they are inconsistent with applicable law. Moreover, section 205 of 
UMRA allows EPA to adopt an alternative other than the least costly, 
most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including Tribal governments, it must have developed under 
section 203 of UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    Under Title II of UMRA, EPA has determined that this proposed rule 
does not contain a federal mandate that may result in expenditures that 
exceed the inflation-adjusted UMRA threshold of $100 million by State, 
local, or Tribal governments or the private sector in any 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

[[Page 24097]]

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 NO<INF>X,</INF> SO<INF>2,</INF> 
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 
NO<INF>X</INF> SO<INF>2</INF> 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:


Sec.  52.1370  Identification of plan.

* * * * *
    (c) * * *
    (27) * * *
    (i) * * *
    (H) Appendix G-2, Montana Smoke Management Plan, effective April 
15, 1988, is superseded by Sec.  52.1365.
* * * * *
    3. Add Sec.  52.1395 to read as follows:


Sec.  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

[[Page 24098]]

through the implementation of Title 17, Chapter 8, subchapter 6, ARM, 
Open Burning.
    4. Add section 52.1396 to read as follows:


Sec.  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 <greek-i>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 SO<INF>2</INF> or NO<INF>X</INF> 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.
    NO<INF>X</INF> 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.
    SO<INF>2</INF> 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, 
SO<INF>2</INF> or NO<INF>X</INF> in excess of the following 
limitations, in pounds per million British thermal units (lb/MMBtu), 
averaged over a rolling 30-day period:

 
----------------------------------------------------------------------------------------------------------------
                                                  PM Emission limit    SO2 Emission limit    NOX Emission limit
                  Source name                        (lb/MMBtu)            (lb/MMBtu)            (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, SO<INF>2</INF> or 
NO<INF>X</INF> in excess of the following limitations, in pounds per 
ton of clinker produced, averaged over a rolling 30-day period:

 
----------------------------------------------------------------------------------------------------------------
                                         PM Emission limit (lb/ton     SO2 Emission limit    NOX Emission limit
             Source name                          clinker)              (lb/ton clinker)      (lb/ton clinker)
----------------------------------------------------------------------------------------------------------------
Ash Grove Cement.....................  If the process weight rate of                  11.5                   8.0
                                        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..
Holcim (US) Inc......................  0.77 lb/ton..................                   1.3                   5.5
----------------------------------------------------------------------------------------------------------------

     (3) The owners/operators of LP, Blaine County <greek-i>1 
Compressor Station shall not emit or cause to be emitted NO<INF>X</INF> 
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 
<greek-i>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 SO<INF>2</INF>, 
NO<INF>X</INF>, 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

[[Page 24099]]

calculate the hourly average SO<INF>2</INF> and NO<INF>X</INF> 
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 SO<INF>2</INF> or NO<INF>X</INF> 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 (SO<INF>2</INF> or NO<INF>X</INF>) and the 
diluent monitor (O<INF>2</INF> or CO<INF>2</INF>).
    (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 SO<INF>2</INF> and NO<INF>X</INF> 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 SO<INF>2</INF> and 
NO<INF>X</INF>, 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 = (C<INF>s</INF>Q<INF>s</INF>)/(PK)

Where:

E = emission rate of SO<INF>2</INF> or NO<INF>X</INF>, lb/ton of 
clinker produced
C<INF>s</INF> = concentration of SO<INF>2</INF> or NO<INF>X</INF>, 
in grains per standard cubic foot (gr/scf);
Q<INF>s</INF> = volumetric flow rate of effluent gas, where 
C<INF>s</INF> and Q<INF>s</INF> 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 <greek-i>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[deg]F and no more than 1250[deg]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 <plus-minus> 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 CO<INF>2</INF> 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

[[Page 24100]]

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 SO<INF>2</INF> and NO<INF>X</INF> 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 <greek-i>1 Compressor Station:
    (1) The owner/operator shall measure NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emissions shall commence during 
the first complete calendar quarter following the owner/operator's 
submittal of the initial performance test results for NO<INF>X</INF> 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 pipeline-quality natural gas in all 
respects, with the exception of the CO<INF>2</INF> 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 SO<INF>2</INF> or NO<INF>X</INF> 
emission limits in paragraph (c) of this section.
    (2) Owner/operator shall submit semi-annual 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

[[Page 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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