Document ID: EPA-R08-OAR-2010-0406-0001
Agency: epa
Document Type: Proposed Rule
Title: Approval and Promulgation of Implementation Plans: North Dakota; Regional Haze State Implementation Plan, etc.
Posted Date: 2011-09-21T04:00Z

[Federal Register Volume 76, Number 183 (Wednesday, September 21, 2011)]
[Proposed Rules]
[Pages 58570-58648]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-23372]

[[Page 58569]]

Vol. 76

Wednesday,

No. 183

September 21, 2011

Part II

Environmental Protection Agency

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40 CFR Part 52

 Approval and Promulgation of Implementation Plans; North Dakota; 
Regional Haze State Implementation Plan; Federal Implementation Plan 
for Interstate Transport of Pollution Affecting Visibility and Regional 
Haze; Proposed Rule

  Federal Register / Vol. 76, No. 183 / Wednesday, September 21, 2011 / 
Proposed Rules  

[[Page 58570]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R08-OAR-2010-0406; FRL-9461-7]

Approval and Promulgation of Implementation Plans; North Dakota; 
Regional Haze State Implementation Plan; Federal Implementation Plan 
for Interstate Transport of Pollution Affecting Visibility and Regional 
Haze

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to partially approve and partially disapprove 
a revision to the North Dakota State Implementation Plan (SIP) 
addressing regional haze submitted by the Governor of North Dakota on 
March 3, 2010, along with SIP Supplement No. 1 submitted on July 27, 
2010, and part of SIP Amendment No. 1 submitted on July 28, 2011. These 
SIP revisions were submitted to address the requirements of the Clean 
Air Act (CAA or Act) and our rules that require states to prevent any 
future and remedy any existing man-made impairment of visibility in 
mandatory Class I areas caused by emissions of air pollutants from 
numerous sources located over a wide geographic area (also referred to 
as the ``regional haze program''). EPA is proposing a Federal 
Implementation Plan (FIP) to address the deficiencies identified in our 
proposed partial disapproval of North Dakota's regional haze SIP. In 
lieu of this proposed FIP, or a portion thereof, we are proposing 
approval of a SIP revision if the State submits such a revision in a 
timely way, and the revision matches the terms of our proposed FIP.
    In addition, EPA is proposing to disapprove a revision to the North 
Dakota SIP addressing the interstate transport of pollutants that the 
Governor submitted on April 6, 2009. We are proposing to disapprove it 
because it does not meet the Act's requirements concerning non-
interference with programs to protect visibility in other states. To 
address this deficiency, we are proposing a FIP.

DATES: Comments: Comments must be received on or before November 21, 
2011. Public Hearing. A public hearing for this proposal is scheduled 
to be held on Thursday, October 13, 2011, at the Bismarck Veterans 
Memorial Public Library, Meeting Room A, 515 North 5th Street, 
Bismarck, North Dakota 58501, (701) 355-1480. The public hearing will 
be held from 3 p.m. until 5 p.m., and again from 6 p.m. until 8 p.m.
    The public hearing 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.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R08-
OAR-2010-0406, by one of the following methods:
     http://www.regulations.gov. Follow the on-line 
instructions for submitting comments.
     E-mail: r8airndhaze@epa.gov.
     Fax: (303) 312-6064 (please alert the individual listed in 
the FOR FURTHER INFORMATION CONTACT section if you are faxing 
comments).
     Mail: Director, Air Program, Environmental Protection 
Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, Denver, 
Colorado 80202-1129.
     Hand Delivery: Director, Air Program, Environmental 
Protection Agency (EPA), Region 8, Mailcode 8P-AR, 1595 Wynkoop Street, 
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-
2010-0406. 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 e-mail. 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 e-mail comment directly to EPA, without 
going through http://www.regulations.gov, your e-mail 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 information about EPA's public 
docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.
    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, 1595 Wynkoop Street, 
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: Gail Fallon, EPA Region 8, at (303) 
312-6281, or Fallon.Gail@epa.gov.

SUPPLEMENTARY INFORMATION: 

Definitions

    For the purpose of this document, we are giving meaning to certain 
words or initials as follows:

[[Page 58571]]

    (i) The words or initials Act or CAA mean or refer to the Clean Air 
Act, unless the context indicates otherwise.
    (ii) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.
    (iii) The initials SIP mean or refer to State Implementation Plan.
    (iv) The initials FIP mean or refer to Federal Implementation Plan.
    (v) The initials NAAQS mean or refer to National Ambient Air 
Quality Standards.
    (vi) The words North Dakota and State mean the State of North 
Dakota.
    (vii) The initials BART mean or refer to Best Available Retrofit 
Technology.
    (viii) The initials RP mean or refer to Reasonable Progress.
    (ix) The initials NOX mean or refer to nitrogen oxides.
    (x) The initials SO2 mean or refer to sulfur dioxide.
    (xi) The initials NH3 mean or refer to ammonia.
    (xii) The initials PM2.5 mean or refer to particulate matter with 
an aerodynamic diameter of less than 2.5 micrometers.
    (xiii) The initials PM10 mean or refer to particulate matter with 
an aerodynamic diameter of less than 10 micrometers.
    (xiv) The initials OC mean or refer to organic carbon.
    (xv) The initials EC mean or refer to elemental carbon.
    (xvi) The initials VOC mean or refer to volatile organic compounds.
    (xvii) The initials EGUs mean or refer to Electric Generating 
Units.
    (xviii) The initials RPGs mean or refer to Reasonable Progress 
Goals.
    (xix) The initials LTS mean or refer to Long-Term Strategy.
    (xx) The initials RAVI mean or refer to Reasonably Attributable 
Visibility Impairment.
    (xxi) The initials FLMs mean or refer to Federal Land Managers.
    (xxii) The initials URP mean or refer to Uniform Rate of Progress.
    (xxiii) The initials MRYS mean or refer to Milton R. Young Station.
    (xxiv) The initials LOS mean or refer to Leland Olds Station.
    (xxv) The initials IMPROVE mean or refer to Interagency Monitoring 
of Protected Visual Environments monitoring network.
    (xxvi) The initials RPOs mean or refer to regional planning 
organizations.
    (xxvii) The initials WRAP mean or refer to the Western Regional Air 
Program.
    (xxviii) The initials PSD mean or refer to Prevention of 
Signification Deterioration.
    (xxix) The initials Theodore Roosevelt or TRNP mean or refer to 
Theodore Roosevelt National Park.
    (xxx) The initials Lostwood or LWA mean or refer to Lostwood 
National Wildlife Refuge Wilderness Area.
    (xxxi) The initials TSD mean or refer to Technical Support 
Document.
    (xxxii) The initials IWAQM mean or refer to Interagency Workgroup 
on Air Quality Modeling.
    (xxxiii) The initials FGD mean or refer to flue gas 
desulfurization.
    (xxxiv) The initials SOFA mean or refer to separated overfire air.
    (xxxv) The initials LNB mean or refer to low NOX 
burners.
    (xxxvi) The initials PRB mean or refer to Powder River Basin.
    (xxxvii) The initials SCR mean or refer to selective catalytic 
reduction.
    (xxxviii) The initials LTO mean or refer to low temperature 
oxidation.
    (xxxix) The initials NSCR mean or refer to non-selective catalytic 
reduction.
    (xl) The initials ECO mean or refer to electro-catalytic oxidation.
    (xli) The initials SNCR mean or refer to selective non-catalytic 
reduction.
    (xlii) The initials RRI mean or refer to rich reagent injection.
    (xliii) The initials FGR mean or refer to external flue gas 
recirculation.
    (xliv) The initials OFA mean or refer to overfire air.
    (xlv) The initials HE-SNCR mean or refer to hydrocarbon enhanced 
SNCR.
    (xlvi) The initials CGR mean or refer to conventional gas reburn.
    (xlvii) The initials FLGR mean or refer to fuel-lean gas reburn.
    (xlviii) The initials ROFA mean or refer to rotating overfire air.
    (xlix) The initials LDSCR mean or refer to low-dust SCR.
    (l) The initials TESCR mean or refer to tail-end SCR.
    (li) The initials ASOFA mean or refer to advanced separated 
overfire air.
    (lii) The initials OEC mean or refer to oxygen enhanced combustion.
    (liii) The initials FGD mean or refer to flue gas desulfurization 
system.
    (liv) The initials CoHPAC mean or refer to compact hybrid 
particulate collector.
    (lv) The initials CAM mean or refer to compliance assurance 
monitoring.
    (lvi) The initials CEMS mean or refer to continuous emission 
monitoring systems.
    (lvii) The initials CMAQ mean or refer to Community Multi-Scale Air 
Quality modeling system.
    (lviii) The initials SMOKE mean or refer to Sparse Matrix Operator 
Kernel Emissions modeling system.
    (lix) The initials CAMx mean or refer to Comprehensive Air Quality 
Model.
    (lx) The initials EIA mean or refer to Energy Information Agency.
    (lxi) The initials GRE mean or refer to Great River Energy.
    (lxii) The initials RMC mean or refer to the Regional Modeling 
Center at the University of California Riverside.
    (lxiii) The initials WEP mean or refer to Weighted Emissions 
Potential.

Table of Contents

I. Overview of Proposed Actions
    A. Regional Haze
    B. Interstate Transport of Pollutants that Impact Visibility
II. SIP and FIP Background
III. What is the background for our proposed actions?
    A. Regional Haze
    B. Roles of Agencies in Addressing Regional Haze
    C. The 1997 NAAQS for Ozone and PM2.5 and CAA 
110(a)(2)(D)(i)
IV. What are the requirements for Regional Haze SIPs?
    A. The CAA and the Regional Haze Rule
    B. Determination of Baseline, Natural, and Current Visibility 
Conditions
    C. Determination of Reasonable Progress Goals
    D. Best Available Retrofit Technology (BART)
    E. Long-Term Strategy (LTS)
    F. Coordinating Regional Haze and Reasonably Attributable 
Visibility Impairment (RAVI)
    G. Monitoring Strategy and Other SIP Requirements
    H. Consultation With States and Federal Land Managers (FLMs)
V. Our Analysis of North Dakota's Regional Haze SIP
    A. Affected Class I Areas
    B. Determination of Baseline, Natural, and Current Visibility 
Conditions
    1. Estimating Natural Visibility Conditions
    2. Estimating Baseline Visibility Conditions
    3. Natural Visibility Impairment
    4. Uniform Rate of Progress (URP)
    C. Evaluation of North Dakota's BART Determinations other than 
for NOX for Milton R. Young Station Units 1 and 2, Leland 
Olds Station Unit 2, and Coal Creek Station Units 1 and 2
    1. Identification of BART-Eligible Sources
    2. Identification of Sources Subject to BART
    a. Modeling Methodology
    b. Contribution Threshold
    c. Sources Identified by North Dakota as Subject to BART
    3. BART Determinations and Federally Enforceable Limits
    a. Great River Energy, Coal Creek Station
    b. Great River Energy, Stanton Station
    c. Minnkota Power Cooperative, Milton R. Young Station (MRYS)
    d. Basin Electric Power Cooperative, Leland Olds Station (LOS)
    e. North Dakota BART Results and Summary
    D. Evaluation of North Dakota's NOX BART 
Determinations for Milton R. Young Station Units 1 and 2, Leland 
Olds

[[Page 58572]]

Station Unit 2, and Coal Creek Station Units 1 and 2
    1. Milton R. Young Station Units 1 and 2 and Leland Olds Station 
Unit 2
    a. Milton R. Young Station Unit 1--State Analysis
    b. Milton R. Young Station Unit 2--State Analysis
    c. Leland Olds Station Unit 2--State Analysis
    d. EPA's Evaluation of the State's Cost Analyses for 
NOX BART for Milton R. Young Station Unit 1 and 2 and 
Leland Olds Station Unit 2
    e. EPA's Evaluation of the State's Visibility Analyses for 
NOX BART for Milton R. Young Station Unit 1 and 2 and 
Leland Olds Station Unit 2
    2. Coal Creek Station Units 1 and 2
    a. Coal Creek Station Units 1 and 2--State Analysis
    b. EPA's Evaluation of the State's NOX BART Review 
for Coal Creek Units 1 and 2
    E. Federal Implementation Plan to Address NOX BART 
for Milton R. Young Station Units 1 and 2, and Leland Olds Station 
Unit 2
    1. Introduction
    2. BART analysis for Milton R. Young Station 1
    3. BART analysis for Milton R. Young Station 2
    4. BART analysis for Leland Olds Station 2
    F. Federal Implementation Plan to Address NOX BART 
for Coal Creek Station Units 1 and 2
    1. Introduction
    2. BART analysis for Coal Creek Units 1 and 2
    G. Evaluation of North Dakota's Reasonable Progress Goal
    1. North Dakota's Visibility Modeling
    2. North Dakota's Reasonable Progress ``Four-Factor'' Analysis
    3. North Dakota's Conclusions from the Four-Factor Analysis
    4. Establishment of the Reasonable Progress Goal
    5. Reasonable Progress Consultation
    6. Our Conclusion on North Dakota's Reasonable Progress Goal and 
Need for Additional Controls
    H. Our Conclusion on North Dakota's Reasonable Progress Goal and 
Need for Additional Controls
    I. Federal Implementation Plan to Address Nitrogen Oxides 
(NOX) Reasonable Progress Measures for Antelope Valley 
Station Units 1 and 2 and Reasonable Progress Goals
    1. Introduction
    2. Reasonable Progress Analysis for Antelope Valley Station 
Units 1 and 2
    J. Long-Term Strategy
    1. Emissions Inventories
    2. Sources of Visibility Impairment in North Dakota Class I 
Areas
    3. Visibility Projection Modeling
    4. Consultation and Emissions Reductions for Other States' Class 
I Areas
    5. Mandatory Long-Term Strategy Factors
    a. Reductions Due to Ongoing Air Pollution Programs
    b. Measures to Mitigate the Impacts of Construction Activities
    c. Emission Limitation and Schedules of Compliance
    d. Source Retirement and Replacement Schedules
    e. Agricultural and Forestry Smoke Management Techniques
    f. Enforceability of North Dakota's Measures
    g. Anticipated Net Effect on Visibility Due to Projected Changes
    h. Periodic SIP Revisions and 5-Year Progress Reports
    K. Coordination of Reasonably Attributable Visibility Impairment 
and Regional Haze Requirements
    L. Monitoring Strategy and Other SIP Requirements
    M. Federal Land Manager Coordination
    N. Periodic SIP Revisions and Five-year Progress Reports
VI. Our Analysis of North Dakota's Interstate Visibility Transport 
SIP Provisions
VII. FIP for Interstate Visibility Transport
VIII. Proposed Actions
    A. Regional Haze
    B. Interstate Transport and Visibility
IX. Statutory and Executive Order Reviews

List of Tables

Table 1. Visibility Impact Reductions Needed Based on Best and Worst 
Days Baselines, Natural Conditions, and Uniform Rate of Progress 
Goals for North Dakota Class I Areas
Table 2. Summary of Uniform Rate of Progress
Table 3. List of BART--Eligible Sources in North Dakota
Table 4. Individual BART--Eligible Source Visibility Impacts on 
North Dakota Class I Areas
Table 5. Summary of Coal Creek SO2 BART Analysis for Unit 
1 and Unit 2 Boilers
Table 6. Summary of Coal Creek Filterable PM BART Analysis for Unit 
1 and Unit 2 Boilers
Table 7. Summary of Stanton SO2 BART Analysis for Unit 1 
Boiler with Lignite Coal
Table 8. Summary of Stanton SO2 BART Analysis for Unit 1 
Boiler with Powder River Basin Coal
Table 9. Summary of Stanton NOX BART Analysis for Unit 1 
Boiler with Lignite Coal
Table 10. Summary of Stanton NOX BART Analysis for Unit 1 
Boiler with Powder River Basin Coal
Table 11. Summary of Stanton PM BART Analysis for Unit 1 Boiler with 
Lignite Coal
Table 12. Summary of Milton R. Young Station SO2 BART 
Analysis for Unit 1 Boiler
Table 13. Summary of Milton R. Young Station PM BART Analysis for 
Unit 1 Boiler
Table 14. Summary of Milton R. Young Station SO2 BART 
Analysis for Unit 2 Boiler
Table 15. Summary of Milton R. Young Station PM BART Analysis for 
Unit 2 Boiler
Table 16. Summary of Leland Olds Station SO2 BART 
Analysis for Unit 1 Boiler
Table 17. Summary of Leland Olds Station NOX BART 
Analysis for Unit 1 Boiler
Table 18. Summary of Leland Olds Station PM BART Analysis for Unit 1 
Boiler
Table 19. Summary of Leland Olds Station SO2 BART 
Analysis for Unit 2 Boiler
Table 20. Summary of Leland Olds Station PM BART Analysis for Unit 2 
Boiler
Table 21. North Dakota BART Determinations for SO2 
Emissions that EPA is Proposing to Approve
Table 22. North Dakota BART Determinations for NOX 
Emissions that EPA is Proposing to Approve
Table 23. Summary of Milton R. Young Station NOX BART 
Analysis for Unit 1 Boiler
Table 24. Summary of Milton R. Young Station NOX BART 
Analysis for Unit 2 Boiler
Table 25. Summary of Leland Olds Station NOX BART 
Analysis for Unit 2 Boiler
Table 26. North Dakota BART Determinations for NOX 
Emissions for Milton R. Young Station Units 1 and 2 and Leland Olds 
Station Unit 2
Table 27. Contrast of TESCR Cost Effectiveness
Table 28. Comparison of EPA Control Cost Manual and Burns & 
McDonnell Indirect Capital Costs
Table 29. Comparison of EPA Control Cost Manual & B&McD ``Other'' 
Capital Costs
Table 30. Comparison of Sargent & Lundy and Dr. Fox's Tail-End SCR 
Variable Operation and Maintenance Costs for Leland Olds Station 
Unit 2 (2009 Dollars)
Table 31. Summary of Coal Creek NOX BART Analysis for 
Unit 1 and Unit 2 Boilers
Table 32. Summary of EPA NOX BART Analysis Control 
Technologies for Milton R. Young Station Unit 1 Boiler
Table 33. Summary of EPA NOX BART Capital Cost Analysis 
for SNCR on Milton R. Young Station Unit 1 Boiler
Table 34. Summary of EPA NOX BART Annual Analysis for 
SNCR on Milton R. Young Station Unit 1 Boiler
Table 35. Summary of EPA NOX BART Costs for SNCR on 
Milton R. Young Station Unit 1 Boiler
Table 36. Summary of EPA NOX BART Capital Cost Analysis 
for TESCR on Milton R. Young Station Unit 1 Boiler
Table 37. Summary of EPA NOX BART Annual Costs for TESCR 
Scenario 3 \1\ on Milton R. Young Station Unit 1 Boiler
Table 38. Summary of EPA NOX BART Costs for Various TESCR 
Scenarios on Milton R. Young Station Unit 1 Boiler
Table 39. Summary of EPA NOX BART Analysis Comparison of 
TESCR and SNCR Options for Milton R. Young Station Unit 1 Boiler
Table 40. Summary of EPA NOX BART Analysis Control 
Technologies for Milton R. Young Station Unit 2 Boiler
Table 41. Summary of EPA NOX BART Capital Cost Analysis 
for SNCR on Milton R. Young Station Unit 2 Boiler
Table 42. Summary of EPA NOX BART Annual Analysis for 
SNCR on Milton R. Young Station Unit 2 Boiler
Table 43. Summary of EPA NOX BART Costs for SNCR on 
Milton R. Young Station Unit 2 Boiler
Table 44. Summary of EPA NOX BART Capital Cost Analysis 
for TESCR

[[Page 58573]]

Scenario 3 \1\ on Milton R. Young Station Unit 2 Boiler
Table 45. Summary of EPA NOX BART Annual Costs for TESCR 
Scenario 3 \1\ on Unit 2 Boiler
Table 46. Summary of EPA NOX BART Costs for Various TESCR 
+ ASOFA Scenarios on Milton R. Young Station Unit 2 Boiler
Table 47. Summary of EPA NOX BART Analysis Comparison of 
TESCR and SNCR Options for Milton R. Young Station Unit 2 Boiler
Table 48. Summary of EPA NOX BART Analysis Control 
Technologies for Leland Olds Station Unit 2 Boiler
Table 49. Summary of EPA NOX BART Capital Cost Analysis 
for SNCR on Leland Olds Station Unit 2 Boiler
Table 50. Summary of EPA NOX BART Annual Costs for SNCR 
on Leland Olds Station Unit 2 Boiler
Table 51. Summary of EPA NOX BART Costs for SNCR on 
Leland Olds Station Unit 2 Boiler
Table 52. Summary of EPA NOX BART Capital Cost Analysis 
for TESCR Scenario 3 on Leland Olds Station Unit 2 Boiler
Table 53. Summary of Some EPA NOX BART Annual Costs for 
TESCR Scenario 3 \1\ on Leland Olds Station Unit 2 Boiler
Table 54. Summary of EPA NOX BART Costs for Various TESCR 
+ ASOFA Scenarios on Leland Olds Station Unit 2 Boiler
Table 55. Summary of EPA NOX BART Analysis Comparison of 
TESCR and SNCR Options for Leland Olds Station Unit 2 Boiler
Table 56. Summary of EPA Coal Creek BART Analysis Control 
Technologies for Units 1 and 2 Boilers
Table 57. Summary of EPA NOX BART Capital Cost Analysis 
for SNCR on Coal Creek Station Units 1 and 2 Boilers
Table 58. Summary of EPA Annual Cost Analysis for SNCR + ASOFA on 
Coal Creek Station Units 1 and 2 Boilers
Table 59. Summary of EPA Costs for SNCR on Coal Creek Station Units 
1 and 2 Boilers
Table 60. Summary of EPA Capital Cost Analysis for LDSCR on Coal 
Creek Station Units 1 and 2 Boilers
Table 61. Summary of EPA Annual Cost Analysis for LDSCR on Coal 
Creek Station Units 1 and 2 Boilers
Table 62. Summary of EPA Costs for LDSCR on Coal Creek Station Units 
1 and 2 Boilers
Table 63. Summary of EPA NOX BART Analysis for Coal Creek 
Station Units 1 and 2 Boilers
Table 64. North Dakota Q/D Analysis Sources with Results Greater 
than 10
Table 65. North Dakota Sources for Reasonable Progress Four-Factor 
Analyses
Table 66. Current Control for Reasonable Progress Sources
Table 67. Control Option Costs for Reasonable Progress Sources
Table 68. ND's Modeled Visibility Improvement for Reasonable 
Progress Sources
Table 69. Comparison of Reasonable Progress Goals to Uniform Rate of 
Progress on Most Impaired Days for North Dakota Class I Areas
Table 70. Comparison of Reasonable Progress Goals to Baseline 
Conditions on Least Impaired Days for North Dakota Class I Areas
Table 71. Summary of Antelope Valley Station NOX 
Reasonable Progress Analysis Control Technologies for Units 1 and 2 
Boilers
Table 72. Summary of Antelope Valley Station NOX 
Reasonable Progress Cost Analysis for Units 1 and 2 Boilers
Table 73. North Dakota SO2 Emission Inventory--2002 and 
2018
Table 74. North Dakota NOX Emission Inventory--2002 and 
2018
Table 75. North Dakota Organic Carbon Emission Inventory--2002 and 
2018
Table 76. North Dakota Elemental Carbon Emission Inventory--2002 and 
2018
Table 77. North Dakota PM2.5 Emission Inventory--2002 and 
2018
Table 78. North Dakota Coarse Particulate Matter Emission 
Inventory--2002 and 2018
Table 79. ND Sources Extinction Contribution 2000-2004 for 20% Worst 
Days
Table 80. Source Region Apportionment for 20% Worst Days 
(Percentage)
Table 81. Annual Average Emissions from Fire (2000-2004) (Tons/Year)

I. Overview of Proposed Actions

A. Regional Haze

    We propose to partially approve and partially disapprove North 
Dakota's regional haze State Implementation Plan (Regional Haze SIP) 
revision that was submitted on March 3, 2010, SIP Supplement No. 1 that 
was submitted on July 27, 2010, and part of SIP Amendment No. 1 that 
was submitted on July 28, 2011. Specifically, we propose to disapprove 
the following:
     North Dakota's NOX BART determinations and 
emissions limits for Units 1 and 2 of Minnkota Power Cooperative's 
Milton R. Young Station, Unit 2 of Basin Electric Power Cooperative's 
Leland Olds Station, and Units 1 and 2 of Great River Energy's Coal 
Creek Station.
     North Dakota's determination under the reasonable progress 
requirements found at 40 CFR 51.308(d)(1) that no additional 
NOX emissions controls are warranted at Units 1 and 2 of 
Basin Electric Power Cooperative's Antelope Valley Station.
     North Dakota's Reasonable Progress Goals (RPGs).
     Portions of North Dakota's long-term strategy that rely on 
or reflect other aspects of the Regional Haze SIP we are proposing to 
disapprove.
    We are proposing to approve the remaining aspects of North Dakota's 
Regional Haze SIP revision that was submitted on March 3, 2010 and SIP 
Supplement No. 1 that was submitted on July 27, 2010. We are proposing 
to approve the following parts of SIP Amendment No. 1 that the State 
submitted on July 28, 2011: (1) Amendments to Section 10.6.1.2 
pertaining to Coyote Station, and (2) amendments to Appendix A.4, the 
Permit to Construct of Coyote Station. We are not proposing action on 
the remainder of the July 28, 2011 submittal at this time.
    We are proposing the promulgation of a FIP to address the 
deficiencies in the North Dakota Regional Haze SIP that we have 
identified in this proposal.
    The proposed FIP includes the following elements:
     NOX BART determinations and emission limits for 
Milton R. Young Station Units 1 and 2 and Leland Olds Station Unit 2 of 
0.07 lb/MMBtu (pounds per one million British Thermal Units) that apply 
singly to each of these units on a 30-day rolling average, and a 
requirement that the owners/operators comply with these NOX 
BART limits within five (5) years of the effective date of our final 
rule.
     NOX BART determination and emission limit for 
Coal Creek Station Units 1 and 2 of 0.12 lb/MMBtu that applies singly 
to each of these units on a 30-day rolling average, but inviting 
comment on whether 0.14 lb/MMBtu should be the limit instead, and a 
requirement that the owners/operators comply with these NOX 
BART limits within five (5) years of the effective date of our final 
rule.
     A reasonable progress determination and NOX 
emission limit for Antelope Valley Station Units 1 and 2 of 0.17 lb/
MMBtu that applies singly to each of these units on a 30-day rolling 
average, and a requirement that the owner/operator meet the limit as 
expeditiously as practicable, but no later than July 31, 2018.
     Monitoring, record-keeping, and reporting requirements for 
the above seven units to ensure compliance with these emission 
limitations.
     Reasonable progress goals consistent with the SIP limits 
proposed for approval and the proposed FIP limits.
     Long-term strategy elements that reflect the other aspects 
of the proposed FIP.
    In lieu of this proposed FIP, or portion thereof, we are proposing 
approval of a SIP revision if the State submits such a revision in a 
timely way, and the revision matches the terms of our proposed FIP, or 
relevant portion thereof.

[[Page 58574]]

B. Interstate Transport of Pollutants That Impact Visibility

    We are proposing to disapprove a portion of the SIP revision North 
Dakota submitted on April 6, 2009, for the purpose of addressing the 
``good neighbor'' provisions of CAA section 110(a)(2)(D)(i) for the 
1997 8-hour ozone NAAQS and the PM2.5 NAAQS. Section 
110(a)(2)(D)(i)(II) of the Act requires that states have a SIP, or 
submit a SIP revision, containing provisions ``prohibiting any source 
or other type of emission activity within the state from emitting any 
air pollutant in amounts which will * * * interfere with measures 
required to be included in the applicable implementation plan for any 
other State under part C [of the CAA] * * * to protect visibility.'' 
Because of the potential significant impacts on visibility from the 
interstate transport of pollutants, we interpret the ``good neighbor'' 
provisions of section 110(a)(2)(D)(i) as requiring states to include in 
their SIPs either measures to prohibit emissions that would interfere 
with the reasonable progress goals required to be set to protect Class 
I areas in other states, or a demonstration that emissions from North 
Dakota sources and activities will not have the prohibited impacts 
under the existing SIP.
    The State's April 6, 2009 SIP submission suggested that North 
Dakota intended to address the requirements of section 
110(a)(2)(D)(i)(II) by a timely submission of its Regional Haze SIP by 
December of 2007, but the State did not make that submission until 
March 3, 2010. Moreover, while North Dakota ultimately submitted a 
Regional Haze SIP revision that addresses visibility and reasonable 
progress goals directly, North Dakota did not explicitly specify that 
it was submitting the Regional Haze SIP revision to satisfy the 
visibility prong of 110(a)(2)(D)(i)(II). Most importantly, however, EPA 
must review the April 6, 2009 submission in light of the current facts 
and circumstances, and the Regional Haze SIP revision that the State 
ultimately submitted does not fully meet the substantive requirements 
of the regional haze program. The State made no other SIP submission in 
which it indicated that it intended to meet the visibility prong of 
section 110(a)(2)(D)(i)(II) in any other way. Accordingly, we are 
proposing to disapprove North Dakota's April 6, 2009 SIP submittal for 
the visibility prong of section 110(a)(2)(D)(i)(II), because that 
submittal neither contains adequate measures to eliminate emissions 
that would interfere with the required visibility programs in other 
states, nor a demonstration that the existing North Dakota SIP already 
includes measures sufficient to eliminate such prohibited impacts.
    We are proposing the promulgation of a FIP to address the 
deficiency in North Dakota's April 6, 2009 SIP submission that we have 
identified in this proposal, in order to meet the interstate transport 
requirements of section 110(a)(2)(D)(i)(II) for visibility. 
Specifically, the proposed FIP consists of a finding that the 
combination of our proposed partial approval of North Dakota's Regional 
Haze SIP and our proposed partial FIP for regional haze for North 
Dakota will satisfy the interstate transport requirements of section 
110(a)(2)(D)(i)(II) with respect to visibility. The emissions 
reductions resulting from the combination SIP/FIP and other provisions 
contained in the SIP will ensure non-interference with the required 
visibility programs of other states, as well as simultaneously meet the 
substantive requirements of the regional haze program. Simultaneous 
action on both the section 110(a)(2)(D)(i)(II) and regional haze 
program requirements will also be the most efficient approach to ensure 
that sources in North Dakota are controlled adequately to meet both 
requirements, and to avoid the possibility that sources might be 
required to implement two successive levels of controls in order to 
meet both requirements.

II. SIP and FIP Background

    The CAA requires each state to develop plans to meet various air 
quality requirements, including protection of visibility. CAA sections 
110(a), 169A, and 169B. The plans developed by a state are referred to 
as SIPs. A state must submit its SIPs and SIP revisions to us for 
approval. Once approved, a SIP is enforceable by EPA and citizens under 
the CAA, also known as being federally enforceable. If a state fails to 
make a required SIP submittal or if we find that a state's required 
submittal is incomplete or unapprovable, then we must promulgate a FIP 
to fill this regulatory gap. CAA section 110(c)(1). As discussed 
elsewhere in this notice, we are proposing to disapprove aspects of 
North Dakota's Regional Haze SIP. We are also proposing to disapprove, 
as not meeting the requirements of section 110(a)(2)(D)(i)(II) of the 
CAA regarding visibility, North Dakota's interstate transport SIP. We 
are proposing FIPs to address the deficiencies in North Dakota's 
regional haze and interstate transport SIPs.

III. What is the background for our proposed actions?

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 PM2.5 (e.g., sulfates, nitrates, 
organic carbon (OC), elemental carbon (EC), and soil dust) and its 
precursors (e.g., sulfur dioxide (SO2), NOX, and 
in some cases, ammonia (NH3) and volatile organic compounds 
(VOCs)). These precursors react in the atmosphere to form 
PM2.5. PM2.5 impairs visibility by scattering and 
absorbing light. Visibility impairment reduces the clarity, color, and 
visible distance that one can see. PM2.5 also can cause 
serious health effects and mortality in humans and contributes to 
environmental effects such as acid deposition and eutrophication.
    Data from the existing visibility monitoring network, the 
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE) 
monitoring network, show that visibility impairment caused by air 
pollution occurs virtually all the time at most national park and 
wilderness areas. The average visual range \1\ in many Class I areas 
(i.e., national parks and memorial parks, wilderness areas, and 
international parks meeting certain size criteria) in the western 
United States is 100-150 kilometers, or about one-half to two-thirds of 
the visual range that would exist without anthropogenic air pollution. 
64 FR 35714, 35715 (July 1, 1999). 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. Id.
---------------------------------------------------------------------------

    \1\ Visual range is the greatest distance, in kilometers or 
miles, at which a dark object can be viewed against the sky.
---------------------------------------------------------------------------

    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

[[Page 58575]]

results from manmade air pollution.'' CAA Sec.  169A(a)(1). The terms 
``impairment of visibility'' and ``visibility impairment'' are defined 
in the Act to include a reduction in visual range and atmospheric 
discoloration. Id. section 169A(g)(6). In 1980, we 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'' 
(RAVI). 45 FR 80084 (December 2, 1980). These regulations represented 
the first phase in addressing visibility impairment. We 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 had improved.
---------------------------------------------------------------------------

    \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. See CAA section 
162(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. See 
44 FR 69122, November 30, 1979. The extent of a mandatory Class I 
area includes subsequent changes in boundaries, such as park 
expansions. CAA section 162(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'' (FLM). See 
CAA section 302(i). When we use the term ``Class I area'' in this 
action, we mean a ``mandatory Class I Federal area.''
---------------------------------------------------------------------------

    Congress added section 169B to the CAA in 1990 to address regional 
haze issues, and we promulgated regulations addressing regional haze in 
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 them provisions addressing regional haze impairment 
and establish 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 our visibility protection regulations at 40 CFR 
51.300-309. Some of the main regional haze requirements are summarized 
in section IV of this action. The requirement to submit a Regional Haze 
SIP applies to all 50 states, the District of Columbia and the Virgin 
Islands. States were required to submit a SIP addressing regional haze 
visibility impairment no later than December 17, 2007.\3\ 40 CFR 
51.308(b).
---------------------------------------------------------------------------

    \3\ 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 North Dakota, and the District of Columbia and the Virgin 
Islands, had failed to submit SIPs addressing the regional haze 
requirements. 74 FR 2392. Once EPA has found that a State has failed to 
make a required submission, EPA is required to promulgate a FIP within 
two years unless the State submits a SIP and the Agency approves it 
within the two year period. CAA Sec.  110(c)(1).

B. 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. Pollution affecting the air quality in Class 
I areas can be transported over long distances, even hundreds of 
kilometers. Therefore, to address effectively the problem of visibility 
impairment in Class I areas, states need to develop strategies in 
coordination with one another, taking into account the effect of 
emissions from one jurisdiction on the air quality in another.
    Because the pollutants that lead to regional haze can originate 
from sources located across broad geographic areas, we have encouraged 
the states and tribes across the United States to address visibility 
impairment from a regional perspective. Five regional planning 
organizations (RPOs) were formed to address regional haze and related 
issues. The regional planning organizations 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 Program (WRAP) is a collaborative effort 
of state governments, tribal governments, and various federal agencies 
established to conduct data analyses, conduct pollutant transport 
modeling, and coordinate planning activities among the western states. 
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.

C. The 1997 NAAQS for Ozone and PM2.5 and CAA 
110(a)(2)(D)(i)

    On July 18, 1997, we promulgated the 1997 8-hour ozone NAAQS and 
the 1997 PM2.5 NAAQS. 62 FR 38652. Section 110(a)(1) of the 
CAA requires states to submit SIPs to address a new or revised NAAQS 
within 3 years after promulgation of such standards, or within such 
shorter period as we may prescribe. Section 110(a)(2) of the CAA lists 
the elements that such new SIPs must address, as applicable, including 
section 110(a)(2)(D)(i), which pertains to the interstate transport of 
certain emissions.
    On April 25, 2005, we published a ``Finding of Failure to Submit 
SIPs for Interstate Transport for the 8-hour Ozone and PM2.5 
NAAQS.'' 70 FR 21147. This action included a finding that North Dakota 
and other states had failed to submit SIPs to address interstate 
transport of air pollution affecting required visibility programs in 
other states, among other things, and started a 2-year clock for the 
promulgation of a FIP by us, unless a state made a submission to meet 
the requirements of section 110(a)(2)(D)(i), and we approved the 
submission, prior to that time. Id.
    On August 15, 2006, we issued our ``Guidance for State 
Implementation Plan (SIP) Submissions to Meet Current Outstanding 
Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour Ozone and 
PM2.5 National Ambient Air Quality Standards'' (2006 
Guidance). We developed the 2006 Guidance to make recommendations to 
states for making submissions to meet the requirements of section 
110(a)(2)(D)(i) for the 1997 8-hour ozone NAAQS and the 1997 
PM2.5 NAAQS.
    As identified in the 2006 Guidance, the ``good neighbor'' 
provisions in section 110(a)(2)(D)(i) of the CAA require each state to 
have a SIP that prohibits emissions that adversely affect another state 
in the ways contemplated in the statute. Section 110(a)(2)(D)(i) 
contains four distinct requirements or ``prongs'' related to the 
impacts of interstate transport. The SIP must prevent sources in the 
state from emitting pollutants in amounts which will: (1) Contribute 
significantly to nonattainment of the NAAQS in other states; (2) 
interfere with maintenance of the NAAQS in other states; (3) interfere 
with provisions to prevent significant deterioration of air quality in 
other states; or (4) interfere with efforts to protect visibility in 
other states.
    Acknowledging that the Regional Haze SIPs were still under 
development and were not due until December 17, 2007, the 2006 Guidance 
recommended that states could make a simple SIP submission confirming 
that it was not possible at that point in time to assess whether there 
was any interference with

[[Page 58576]]

measures in the applicable SIP for another state designed to ``protect 
visibility'' for the 1997 8-hour ozone NAAQS and the 1997 
PM2.5 NAAQS. See 74 FR 2392 (January 15, 2009). We note that 
our 2006 Guidance was based on the premise that as of the time of its 
issuance in August 2006, it was reasonable for EPA to recommend that 
states could merely indicate that the imminent Regional Haze SIP would 
be the appropriate means to establish that its SIP contained adequate 
provisions to prevent interference with the visibility programs 
required in other states. As discussed in more detail below, at this 
point in time, EPA must review the submissions in light of the actual 
facts and in light of the statutory requirements of section 
110(a)(2)(D)(i)(II).
    On June 2, 2009, WildEarth Guardians sued EPA for our failure to 
take action to promulgate FIPs, or to act on submitted SIPs in lieu 
thereof, to satisfy the requirements of section 110(a)(2)(D)(i) for the 
1997 8-hour ozone NAAQS and 1997 PM2.5 NAAQS. Seven western 
states were named in the lawsuit: Colorado, North Dakota, New Mexico, 
Oklahoma, California, Idaho, and Oregon. A consent decree was filed on 
November 10, 2009. The consent decree included various dates by which 
EPA was required to take action on each of the four prongs of section 
110(a)(2)(D)(i) for each of the seven states for both of the applicable 
NAAQS. It required that EPA sign a notice by May 10, 2011, approving a 
SIP or FIP or combination SIP/FIP for North Dakota meeting the 
requirements of section 110(a)(2)(D) regarding interference with 
measures in other states related to protection of visibility. Pursuant 
to a subsequent modification to the consent decree and a subsequent 
stipulation, this date for final action was extended to February 9, 
2012. The modification and subsequent stipulation also required that 
EPA sign a notice of proposed rulemaking by September 1, 2011.
    On April 6, 2009, we received a SIP revision from North Dakota to 
address the interstate transport provisions of CAA 110(a)(2)(D)(i) for 
the 1997 8-hour ozone NAAQS and the 1997 PM2.5 NAAQS. In 
prior actions we approved this North Dakota SIP submittal for the three 
other prongs of section 110(a)(2)(D)(i). (75 FR 31290, June 3, 2010 and 
75 FR 71023, November 22, 2010). However, as noted above, we are 
proposing to disapprove the submittal for purposes of the visibility 
prong and are proposing a FIP to address this requirement. Acting on 
both the section 110(a)(2)(D)(i)(II) requirement and the Regional Haze 
SIP requirement simultaneously will ensure the most efficient use of 
resources by the affected sources and EPA.

IV. What are the requirements for Regional Haze SIPs?

    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 SIPs must assure reasonable progress towards the 
national goal of achieving natural visibility conditions in Class I 
areas. Section 169A of the CAA and our implementing regulations require 
states to establish long-term strategies for making reasonable progress 
toward meeting this goal. Implementation plans must also give specific 
attention to certain stationary sources that were in existence on 
August 7, 1977, but were not in operation before August 7, 1962, and 
require these sources, where appropriate, to install BART controls for 
the purpose of eliminating or reducing visibility impairment. The 
specific Regional Haze SIP requirements are discussed in further detail 
below.

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

    The Regional Haze Rule establishes the deciview (dv) as the 
principal metric for measuring visibility. See 70 FR 39104, 39118. This 
visibility metric expresses uniform changes in the degree of haze in 
terms of common increments across the entire range of visibility 
conditions, from pristine to extremely hazy conditions. Visibility is 
sometimes expressed in terms of the visual range, which is the greatest 
distance, in kilometers or miles, at which a dark object can just be 
distinguished against the sky. The deciview is a useful measure for 
tracking progress in improving visibility, because each deciview change 
is an equal incremental change in visibility perceived by the human 
eye. Most people can detect a change in visibility of one deciview.\4\
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    \4\ 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 SIPs must contain measures 
that ensure ``reasonable progress'' toward the national goal of 
preventing and remedying visibility impairment in Class I areas caused 
by manmade air pollution by reducing anthropogenic emissions that cause 
regional haze. The national goal is a return to natural conditions, 
i.e., manmade 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 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 to determine the degree of impairment (in deciviews) for the 
average of the 20 percent least impaired (``best'') and the average of 
the 20 percent most impaired (``worst'') visibility days over a 
specified time period at each of their Class I areas. In addition, 
states must also develop an estimate of natural visibility conditions 
for the purpose of comparing progress toward the national goal. Natural 
visibility is determined by estimating the natural concentrations of 
pollutants that cause visibility impairment and then calculating total 
light extinction based on those estimates. We have provided guidance to 
states regarding how to calculate baseline, natural and current 
visibility conditions.\5\
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    \5\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available 
at http://www.epa.gov/ttncaaa1/t1/memoranda/Regional Haze _
envcurhr_gd.pdf, (hereinafter referred to as ``our 2003 Natural 
Visibility Guidance''); and Guidance for Tracking Progress Under the 
Regional Haze Rule, (September 2003, EPA-454/B-03-004, available at 
http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf, 
(hereinafter referred to as our ``2003 Tracking Progress 
Guidance'').
---------------------------------------------------------------------------

    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. Baseline visibility 
conditions represent the degree of visibility impairment for the 20 
percent least impaired days and 20 percent most impaired days for each 
calendar year from 2000 to 2004. Using monitoring data for 2000 through 
2004, states are required to calculate the average degree of visibility 
impairment for each Class I area, based on the average of annual values 
over the five-year period. The comparison of initial baseline 
visibility conditions to natural visibility conditions indicates the 
amount of improvement necessary to attain natural

[[Page 58577]]

visibility, while the future comparison of baseline conditions to the 
then current conditions will indicate the amount of progress made. In 
general, the 2000--2004 baseline period is considered the time from 
which improvement in visibility is measured.

C. Determination of Reasonable Progress Goals

    The vehicle for ensuring continuing progress towards achieving the 
natural visibility goal is the submission of a series of Regional Haze 
SIPs from the states that establish two reasonable progress goals 
(i.e., two distinct goals, one for the ``best'' and one for the 
``worst'' days) for every Class I area for each (approximately) 10-year 
implementation period. See 40 CFR 51.308(d), (f). The Regional Haze 
Rule does not mandate specific milestones or rates of progress, but 
instead calls for states to establish goals that provide for 
``reasonable progress'' toward achieving natural (i.e., ``background'') 
visibility conditions. In setting reasonable progress goals, states 
must provide for an improvement in visibility for the most impaired 
days over the (approximately) 10-year period of the SIP, and ensure no 
degradation in visibility for the least impaired days over the same 
period. Id.
    In establishing reasonable progress goals, states 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. States 
must demonstrate in their SIPs how these factors are considered when 
selecting the reasonable progress goals for the best and worst days for 
each applicable Class I area. In setting the reasonable progress goals, 
states must also consider the rate of progress needed to reach natural 
visibility conditions by 2064 (referred to hereafter as the ``Uniform 
Rate of Progress'') and the emission reduction measures needed to 
achieve that rate of progress over the 10-year period of the SIP. 
Uniform progress towards achievement of natural conditions by the year 
2064 represents a rate of progress, which states are to use for 
analytical comparison to the amount of progress they expect to achieve. 
If a state establishes a reasonable progress goal that provides for a 
slower rate of improvement in visibility than the rate that would be 
needed to attain natural conditions by 2064, the state must 
demonstrate, based on the reasonable progress factors, that the rate of 
progress for the implementation plan to attain natural conditions by 
2064 is not reasonable, and that the progress goal adopted by the state 
is reasonable. In setting reasonable progress goals, each state with 
one or more Class I areas (``Class I State'') must also consult with 
potentially ``contributing states,'' i.e., other nearby states with 
emission sources that may be affecting visibility impairment at the 
State's Class I areas. 40 CFR 51.308(d)(1)(iv). In determining whether 
a state's goals for visibility improvement provide for reasonable 
progress toward natural visibility conditions, EPA is required to 
evaluate the demonstrations developed by the state pursuant to 
paragraphs 40 CFR 51.308(d)(1)(i) and (d)(1)(ii). 40 CFR 
51.308(d)(1)(iii).

D. Best Available Retrofit Technology (BART)

    Section 169A of the CAA directs states to evaluate the use of 
retrofit controls at certain larger, often uncontrolled, older 
stationary sources with the potential to emit 250 tons or more per year 
of any pollutant in order to address visibility impacts from these 
sources. Specifically, section 169A(b)(2)(A) of the Act requires states 
to revise their SIPs 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 \6\ built between 1962 and 1977 procure, install, and operate 
BART, as determined by the state or by EPA in the case of a plan 
promulgated under section 110(c) of the CAA. Under the Regional Haze 
Rule, states are directed to conduct BART determinations for such 
``BART-eligible'' sources that may be anticipated to cause or 
contribute to any visibility impairment in a Class I area. Rather than 
requiring source-specific BART controls, states also have the 
flexibility to adopt an emissions trading program or other alternative 
program as long as the alternative provides greater reasonable progress 
towards improving visibility than BART.
---------------------------------------------------------------------------

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

    On July 6, 2005, we published the Guidelines for BART 
Determinations Under the Regional Haze Rule at Appendix Y to 40 CFR 
part 51 (``BART Guidelines'') to assist states in determining which of 
their sources should be subject to the BART requirements and in 
determining appropriate emission limits for each applicable source. 70 
FR 39104. In making a BART determination for a fossil fuel-fired 
electric generating plant with a total generating capacity in excess of 
750 megawatts (MW), a state must use the approach set forth in the BART 
Guidelines. A state is encouraged, but not required, to follow the BART 
Guidelines in making BART determinations for other types of sources. 
Regardless of source size or type, a state must meet the requirements 
of the CAA and our regulations for selection of BART, and the state's 
BART analysis and determination must be reasonable in light of the 
overarching purpose of the regional haze program.
    The process of establishing BART emission limitations can be 
logically broken down into three steps: first, states identify those 
sources which meet the definition of ``BART-eligible source'' set forth 
in 40 CFR 51.301; \7\ second, states determine which of such sources 
``emits any air pollutant which may reasonably be anticipated to cause 
or contribute to any impairment of visibility in any such area'' (a 
source which fits this description is ``subject to BART,''); and third, 
for each source subject to BART, states then identify the best 
available type and level of control for reducing emissions.
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    \7\ BART-eligible sources are those sources that have the 
potential to emit 250 tons or more of a visibility-impairing air 
pollutant, were not in operation prior to August 7, 1962, but were 
in existence on August 7, 1977, and whose operations fall within one 
or more of 26 specifically listed source categories. 40 CFR 51.301.
---------------------------------------------------------------------------

    States must address all visibility-impairing pollutants emitted by 
a source in the BART determination process. The most significant 
visibility-impairing pollutants are SO2, NOX, and 
PM. We have stated that states should use their best judgment in 
determining whether VOC or NH3 compounds impair visibility 
in Class I areas.
    Under the BART Guidelines, states may select an exemption threshold 
value for their BART modeling, below which a BART-eligible source would 
not be expected to cause or contribute to visibility impairment in any 
Class I area. The state must document this exemption threshold value in 
the SIP and must state the basis for its selection of that value. Any 
source with emissions that model above the threshold value would be 
subject to a BART determination review. The BART Guidelines acknowledge 
varying circumstances affecting different Class I areas. States should 
consider the number of emission sources affecting the Class I areas at 
issue and the magnitude of the individual sources'

[[Page 58578]]

impacts. Any exemption threshold set by the state should not be higher 
than 0.5 deciviews. 40 CFR part 51, appendix Y, section III.A.1.
    In their SIPs, states must identify ``BART-eligible sources'' and 
``subject-to-BART sources'' and document their BART control 
determination analyses. The term ``BART-eligible source'' used in the 
BART Guidelines means the collection of individual emission units at a 
facility that together comprises the BART-eligible source. In making 
BART determinations, section 169A(g)(2) of the CAA requires that states 
consider the following factors: (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).
    A Regional Haze SIP must include source-specific BART emission 
limits and compliance schedules for each source subject to BART. Once a 
state has made its BART determination, the BART controls must be 
installed and in operation as expeditiously as practicable, but no 
later than five years after the date of our approval of the Regional 
Haze SIP. 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 
requirements mandate that the SIP must also include all regulatory 
requirements related to monitoring, recordkeeping, and reporting for 
the BART controls on the source. See CAA section 110(a). As noted 
above, the Regional Haze Rule allows states 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.

E. Long-Term Strategy (LTS)

    Consistent with the requirement in section 169A(b) of the CAA that 
states include in their Regional Haze SIP a 10- to 15-year strategy for 
making reasonable progress, section 51.308(d)(3) of the Regional Haze 
Rule requires that states include a long-term strategy in their 
Regional Haze SIPs. The long-term strategy is the compilation of all 
control measures a state will use during the implementation period of 
the specific SIP submittal to meet applicable reasonable progress 
goals. The long-term strategy must include ``enforceable emissions 
limitations, compliance schedules, and other measures as necessary to 
achieve the reasonable progress goals'' for all Class I areas within, 
or affected by emissions from, the state. 40 CFR 51.308(d)(3).
    When a state's emissions are reasonably anticipated to cause or 
contribute to visibility impairment in a Class I area(s) located in 
another state or states, the Regional Haze Rule requires the state to 
consult with the other state(s) in order to develop coordinated 
emissions management strategies. 40 CFR 51.308(d)(3)(i). Also, a state 
with a Class I area impacted by emissions from another state must 
consult with such contributing state, (id.) and must also demonstrate 
that it has included in its SIP all measures necessary to obtain its 
share of the emission reductions needed to meet the reasonable progress 
goals for the Class I area. Id. at (d)(3)(ii). The regional planning 
organizations have provided forums for significant interstate 
consultation, but additional consultations between states may be 
required to sufficiently address interstate visibility issues. This is 
especially true where two states belong to different regional planning 
organizations.
    States should consider all types of anthropogenic sources of 
visibility impairment in developing their long-term strategy, including 
stationary, minor, mobile, and area sources. At a minimum, states must 
describe how each of the following seven factors listed below are taken 
into account in developing their long-term strategy: (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 
reasonable progress goals; (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 long-term strategy. 40 CFR 
51.308(d)(3)(v).

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

    As part of the Regional Haze Rule, we revised 40 CFR 51.306(c) 
regarding the long-term strategy for reasonably attributable visibility 
impairment to require that the reasonably attributable visibility 
impairment 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 long-term strategy for 
addressing reasonably attributable visibility impairment and regional 
haze, and the state must submit the first such coordinated long-term 
strategy with its first Regional Haze SIP. Future coordinated long-term 
strategy and periodic progress reports evaluating progress towards 
reasonable progress goals, 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 long-term strategy must report on both regional haze and 
reasonably attributable visibility impairment and must be submitted to 
us as a SIP revision.

G. Monitoring Strategy and Other SIP 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 reasonably attributable visibility impairment. 
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 reasonable 
progress goals will be met.
    Under section 51.308(d)(4), the SIP must also provide for the 
following:
     Procedures for using monitoring data and other information 
in a state with mandatory Class I areas to determine the contribution 
of emissions from within the state to regional haze visibility 
impairment at Class I areas both within and outside the state;
     Procedures for using monitoring data and other information 
in a state with no mandatory Class I areas to determine the 
contribution of emissions from within the state to regional haze

[[Page 58579]]

visibility impairment at Class I areas in other states;
     Reporting of all visibility monitoring data to the 
Administrator at least annually for each Class I area in the state, and 
where possible, in electronic format;
     Developing a statewide inventory of emissions of 
pollutants that are reasonably anticipated to cause or contribute to 
visibility impairment in any Class I area. The inventory must include 
emissions for a baseline year, emissions for the most recent year for 
which data are available, and estimates of future projected emissions. 
A state must also make a commitment to update the inventory 
periodically; and
     Other elements, including reporting, recordkeeping, and 
other measures necessary to assess and report on visibility.
    The Regional Haze Rule requires control strategies to cover an 
initial implementation period extending to the year 2018, with a 
comprehensive reassessment and revision of those strategies, as 
appropriate, every 10 years thereafter. Periodic SIP revisions must 
meet the core requirements of section 51.308(d), with the exception of 
BART. The requirement to evaluate sources for BART applies only to the 
first Regional Haze SIP. Facilities subject to BART must continue to 
comply with the BART provisions of section 51.308(e). Periodic SIP 
revisions will assure that the statutory requirement of reasonable 
progress will continue to be met.

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

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

V. Our Analysis of North Dakota's Regional Haze SIP

    On March 3, 2010, the State of North Dakota submitted a Regional 
Haze SIP revision for approval into the North Dakota SIP. North Dakota 
provided two other submittals--SIP Supplement No. 1 on July 27, 2010 
(provisions pertaining to Heskett Station) and SIP Amendment No. 1 on 
July 28, 2011 (provisions pertaining to Coyote Station and materials 
relating to the Prevention of Signification Deterioration (PSD) BACT 
determination for Milton R. Young Station).
    As part of Amendment No. 1, the State submitted the entire 
administrative record for its BACT determination for Milton R. Young 
Station. The administrative record consists of at least 259 documents 
comprising over 850 megabytes of information. Given our September 1, 
2011 deadline to sign this notice of proposed rulemaking under the 
consent decree discussed in section III.C, we lack sufficient time to 
act on or consider this aspect of Amendment No. 1. Under CAA section 
110(k)(2), EPA is not required to act on a SIP submittal until 12 
months after it is determined to be or deemed complete. We have 
considered some of the documents related to the State's BACT 
determination for Milton R. Young Station and have included those 
documents in the docket for this proposed action.
    We are proposing action on the aspects of Amendment No. 1 that 
pertain to Coyote Station because such provisions were amenable to our 
evaluation in the available time.
    The following is a discussion of our evaluation of the relevant 
submittals.

A. Affected Class I Areas

    In accordance with 40 CFR 51.308(d), North Dakota identified two 
Class I areas within its borders: Theodore Roosevelt National Park 
(Theodore Roosevelt or TRNP) and Lostwood National Wildlife Refuge 
Wilderness Area (Lostwood or LWA). North Dakota is responsible for 
developing reasonable progress goals for these two Class I areas. North 
Dakota has also determined that North Dakota emissions have or may 
reasonably be expected to have impacts at Class I areas in other states 
including: Boundary Waters Canoe Area Wilderness Area and Voyageurs 
National Park in Minnesota, Isle Royale National Park and Seney 
National Wildlife Refuge Wilderness Area in Michigan, Medicine Lake 
National Wildlife Refuge Wilderness Area and U.L. Bend National 
Wildlife Refuge Wilderness Area in Montana, and Badlands National Park 
and Wind Cave National Park in South Dakota. North Dakota consulted 
with the appropriate state air quality agency in each of these states 
through their involvement with the WRAP. Assessment of North Dakota's 
contribution to haze in these Class I areas is based on technical 
analyses developed by WRAP.

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

    As required by section 51.308(d)(2)(i) of the Regional Haze Rule 
and in accordance with our 2003 Natural Visibility Guidance, North 
Dakota calculated baseline/current and natural visibility conditions 
for its Class I areas, Theodore Roosevelt and Lostwood, on the most 
impaired and least impaired days, as summarized below (and further 
described in the Technical Support Document (TSD)). The natural 
visibility conditions, baseline visibility conditions, and visibility 
impact reductions needed to achieve the uniform rate of progress in 
2018 for both North Dakota Class I areas are presented in Table 1 and 
further explained in this section. More detail is available in Sections 
5 and 8 of the North Dakota SIP.

[[Page 58580]]

  Table 1--Visibility Impact Reductions Needed Based on Best and Worst Days Baselines, Natural Conditions, and
                          Uniform Rate of Progress Goals for North Dakota Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                  20% Worst days                             20% Best days
                             -----------------------------------------------------------------------------------
                                                              2018
  North Dakota class I area     2000-2004     2018 URP      Reduction   2064 Natural    2000-2004   2064 Natural
                                Baseline      Goal (dv)      needed      conditions     Baseline     conditions
                                  (dv)                     (delta dv)       (dv)          (dv)          (dv)
----------------------------------------------------------------------------------------------------------------
Theodore Roosevelt National          17.80         15.47          2.33           7.8          7.76          3.04
 Park.......................
Lostwood National Wildlife           19.57         16.89          2.68           8.0          8.19          2.92
 Refuge Wilderness Area.....
----------------------------------------------------------------------------------------------------------------

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 states to use ``refined'' or alternative approaches to this 
guidance to estimate the values that characterize the natural 
visibility conditions of Class I areas. One alternative approach is to 
develop and justify the use of alternative estimates of natural 
concentrations of fine particle components. Another alternative is to 
use the ``new IMPROVE equation'' that was adopted for use by the 
IMPROVE Steering Committee in December 2005.\8\ The purpose of this 
refinement to the ``old IMPROVE equation'' is to provide more accurate 
estimates of the various factors that affect the calculation of light 
extinction.
---------------------------------------------------------------------------

    \8\ The IMPROVE program is a cooperative measurement effort 
governed by a steering committee composed of representatives from 
Federal agencies (including representatives from EPA and the FLMs) 
and regional planning organizations. The IMPROVE monitoring program 
was established in 1985 to aid the creation of Federal and State 
implementation plans for the protection of visibility in Class I 
areas. One of the objectives of IMPROVE is to identify chemical 
species and emission sources responsible for existing anthropogenic 
visibility impairment. The IMPROVE program has also been a key 
participant in visibility-related research, including the 
advancement of monitoring instrumentation, analysis techniques, 
visibility modeling, policy formulation and source attribution field 
studies.
---------------------------------------------------------------------------

    For Theodore Roosevelt and Lostwood, North Dakota opted to use WRAP 
calculations in which the default estimates for the natural conditions 
were combined with the ``new IMPROVE equation.'' This is an acceptable 
approach under our 2003 Natural Visibility Guidance. For Theodore 
Roosevelt, the default natural visibility value for the 20 percent 
worst days is 7.31 deciviews and for the 20 percent best days is 2.19 
deciviews. For Lostwood, the default natural visibility value for the 
20 percent worst days is 7.33 deciviews and for the 20 percent best 
days is 2.21 deciviews. For Theodore Roosevelt, North Dakota also 
referred to WRAP calculations using the new IMPROVE equation, finding 
the ``refined'' natural visibility value for the 20 percent worst days 
to be 7.8 deciviews and for the 20 percent best days to be 3.0 
deciviews. For Lostwood, the ``refined'' natural visibility result for 
the 20 percent worst days is 8.0 deciviews and for the 20 percent best 
days is 2.9 deciviews. We have reviewed North Dakota's estimate of the 
natural visibility conditions and propose to find it acceptable using 
the new IMPROVE equation.
    The new IMPROVE equation takes into account the most recent review 
of the science \9\ and accounts for the effect of particle size 
distribution on light extinction efficiency of sulfate, nitrate, and 
organic carbon. It also adjusts the mass multiplier for organic carbon 
(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, elemental carbon (light-absorbing carbon), fine 
soil, and coarse mass terms, do not change between the original and new 
IMPROVE equations.
---------------------------------------------------------------------------

    \9\ The science behind the revised IMPROVE equation is 
summarized in our Technical Support Document, in the Technical 
Support Document for Technical Products Prepared by the Western 
Regional Air Partnership (WRAP) in Support of Western Regional Haze 
Plans, Februrary 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 Interagency Monitoring of Protected 
Visual Environments (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, Marc., 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 Visibility Conditions
    As required by section 51.308(d)(2)(i) of the Regional Haze Rule 
and in accordance with our 2003 Natural Visibility Guidance, North 
Dakota calculated baseline visibility conditions for Theodore Roosevelt 
and Lostwood. The baseline condition calculation begins with the 
calculation of light extinction, using the IMPROVE equation. The 
IMPROVE equation sums the light extinction \10\ resulting from 
individual pollutants, such as sulfates and nitrates. As with the 
natural visibility conditions calculation, North Dakota chose to use 
the new IMPROVE equation.
---------------------------------------------------------------------------

    \10\ The amount of light lost as it travels over one million 
meters. The haze index, in units of deciviews (dv), is calculated 
directly from the total light extinction, bext expressed 
in inverse megameters (Mm-1), as follows: HI = 10 
ln(bext/10).
---------------------------------------------------------------------------

    The period for establishing baseline visibility conditions is 2000-
2004, and baseline conditions must be calculated using available 
monitoring data. 40 CFR 51.308(d)(2). The North Dakota Regional Haze 
SIP employed visibility monitoring data collected by IMPROVE monitors 
located in both North Dakota Class I areas for the years 2000 through 
2004 and the resulting baseline conditions represent an average for 
2000-2004. North Dakota calculated the baseline conditions at Theodore 
Roosevelt as 17.8 deciviews on the 20

[[Page 58581]]

percent worst days, and 7.8 deciviews on the 20 percent best days. 
North Dakota calculated the baseline conditions at Lostwood as 19.6 
deciviews on the 20 percent worst days, and 8.2 deciviews on the 20 
percent best days. We have reviewed North Dakota's estimations of 
baseline visibility conditions at Theodore Roosevelt National Park and 
Lostwood and propose to find them acceptable.
3. Natural Visibility Impairment
    To address the requirements of 40 CFR 51.308(d)(2)(iv)(A), North 
Dakota also calculated the number of deciviews by which baseline 
conditions exceed natural visibility conditions at Theodore Roosevelt 
and Lostwood: for the 20 percent worst days, 10.0 deciviews (17.8-7.8) 
and 11.6 deciviews (19.6-8.0), respectively; for the 20 percent best 
days, 4.8 deciviews (7.8-3.0) and 5.3 deciviews (8.2-2.9), 
respectively. We have reviewed North Dakota's estimate of the natural 
visibility impairment and propose to find it acceptable.
4. Uniform Rate of Progress (URP)
    In setting the reasonable progress goals, North Dakota analyzed and 
determined the uniform rate of progress needed to reach natural 
visibility conditions by the year 2064. In so doing, North Dakota 
compared the baseline visibility conditions in Theodore Roosevelt and 
Lostwood to the natural visibility conditions in Theodore Roosevelt and 
Lostwood (as described above) and determined the uniform rate of 
progress needed in order to attain natural visibility conditions by 
2064 in both Class I areas. North Dakota constructed the uniform rate 
of progress 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 2000-2004 to the level of visibility conditions 
representing no anthropogenic impairment in 2064 for Theodore Roosevelt 
and Lostwood. The uniform rate of progress are summarized in Table 2 
and further described below.
    Using a baseline visibility value at Theodore Roosevelt of 17.8 
deciviews and a ``refined'' natural visibility value of 7.8 deciviews 
for the 20 percent worst days, North Dakota calculated the uniform rate 
of progress to be approximately 0.17 deciviews per year (dv/year or dv/
yr). This results in a total reduction of 10.0 deciviews to reach the 
natural visibility condition of 7.8 deciviews in 2064. The uniform rate 
of progress results in a visibility improvement of 2.3 deciviews needed 
for the period covered by this SIP revision submittal (up to and 
including 2018).
    Using a baseline visibility value at Lostwood of 19.6 deciviews and 
a ``refined'' natural visibility value of 8.0 deciviews for the 20 
percent worst days, North Dakota calculated the uniform rate of 
progress to be approximately 0.19 deciviews per year. This results in a 
total reduction of 11.6 deciviews to reach the natural visibility 
condition of 8.0 deciviews in 2064. The uniform rate of progress 
results in a visibility improvement of 2.7 deciviews needed for the 
period covered by this SIP revision submittal (up to and including 
2018).

              Table 2--Summary of Uniform Rate of Progress
------------------------------------------------------------------------
          Class I area                   TRNP                 LWA
------------------------------------------------------------------------
Baseline Conditions.............  17.8 dv...........  19.6 dv.
Natural Visibility..............  7.8 dv............  8.0 dv.
                                 ---------------------------------------
Total Improvement by 2064.......  10.0 dv...........  11.6 dv.
------------------------------------------------------------------------
Improvement for this SIP by 2018  2.3 dv............  2.7 dv.
URP.............................  0.17 dv/year......  0.19 dv/year.
------------------------------------------------------------------------

    We propose to find that North Dakota has appropriately calculated 
the uniform rate of progress.

C. Evaluation of North Dakota's BART Determinations Other Than for 
NOX for Milton R. Young Station Units 1 and 2, Leland Olds 
Station Unit 2, and Coal Creek Station Units 1 and 2

    BART is an element of North Dakota's long-term strategy for the 
first implementation period. As discussed in more detail in section 
IV.D 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. North 
Dakota addressed these steps as follows:
1. Identification of BART-Eligible Sources
    The first step of a BART evaluation is to identify all the BART-
eligible sources within the state's boundaries. North Dakota identified 
the BART-eligible sources in North Dakota by utilizing the approach set 
out in the BART Guidelines (70 FR 39158); this approach provides three 
criteria for identifying BART-eligible sources: (1) One or more 
emission units at the facility fit within one of the 26 categories 
listed in the BART Guidelines; (2) the emission unit(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. North Dakota initially 
screened its emissions inventory and permitting database to identify 
major facilities with emission units in one or more of the 26 BART 
categories. Following this, North Dakota used its databases and records 
to identify facilities in these source categories with potential 
emissions of 250 tons per year or more for any visibility-impairing 
pollutant from any unit that was in existence on August 7, 1977 and 
began operation on or after August 7, 1962. North Dakota contacted the 
sources, when necessary, to obtain or confirm this information.
    The BART Guidelines direct states to address SO2, 
NOX, and direct PM (including both coarse particulate matter 
(PM10) and PM2.5) emissions as visibility-
impairing pollutants and to exercise their ``best judgment to determine 
whether VOC or NH3 emissions from a source are likely to 
have an impact on visibility in an area.'' See 70 FR 39162. WRAP 
modeling demonstrated that VOCs from anthropogenic sources are not 
significant visibility-impairing pollutants at Theodore Roosevelt and 
Lostwood. NH3 emissions in North Dakota are primarily due to 
area sources, such as livestock and fertilizer

[[Page 58582]]

application. Because these are not point sources, they are not subject 
to BART. For the BART-eligible sources in North Dakota, North Dakota 
determined that NH3 and VOC emissions are negligible. The 
emissions inventory prepared for the WRAP modeling demonstrates that 
NH3 from point sources are not significant visibility-
impairing pollutants in North Dakota. We have reviewed this information 
and propose to accept this determination.
    North Dakota identified BART-eligible sources in North Dakota as 
shown in Table 3. This information is presented in Section 7 of North 
Dakota's SIP.

                             Table 3--List of BART-Eligible Sources in North Dakota
----------------------------------------------------------------------------------------------------------------
                                                                  BART Source category
         BART-eligible source                  Location                   (SC)             Nearest class I area
----------------------------------------------------------------------------------------------------------------
1. American Crystal Sugar Company      Drayton, northeastern..  SC 22--fossil fuel       LWA 400 km.
 (Main Boiler and Lime Kiln).          North Dakota...........   boilers >250 MMBtu/hr
                                                                 heat input and SC 12--
                                                                 lime plants.
2. Basin Electric Power Cooperative,   Stanton, central.......  SC 1--fossil fuel steam  TRNP 150 km.
 Leland Olds Station (Unit 1 and Unit  North Dakota...........   electric plants >250
 2).                                                             MMBtu/hr heat input.
3. Great River Energy, Coal Creek      Falkirk, central.......  SC 1--fossil fuel steam  TRNP 160 km.
 Station (Unit 1 and Unit 2).          North Dakota...........   electric plants >250
                                                                 MMBtu/hr heat input.
4. Great River Energy, Stanton         Stanton, central.......  SC 1--fossil fuel steam  TRNP 150 km.
 Station (Unit 1).                     North Dakota...........   electric plants >250
                                                                 MMBtu/hr heat input.
5. Minnkota Power Cooperative, Milton  Center, central........  SC 1--fossil fuel steam  TRNP 150 km.
 R. Young Station (Unit 1 and Unit 2). North Dakota...........   electric plants >250
                                                                 MMBtu/hr heat input.
6. Montana Dakota Utilities Resources  Mandan, central........  SC 1--fossil fuel steam  TRNP 180 km.
 Group, Inc. R.M. Heskett Station      North Dakota...........   electric plants >250
 (Unit 2).                                                       MMBtu/hr heat input.
7. Tesoro Petroleum Corporation,       Mandan, central........  SC 11--petroleum         TRNP 180 km.
 Mandan Refinerry Carbon Monoxide      North Dakota...........   refineries.
 Furnace.
----------------------------------------------------------------------------------------------------------------

2. Identification of Sources Subject to BART

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

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

    The BART Guidelines also recommend that states develop a modeling 
protocol for making individual source attributions, and suggest that 
states may want to consult with us and their RPO to address any issues 
prior to modeling. North Dakota used the CALPUFF model for North Dakota 
BART sources in accordance with a protocol it developed entitled 
``Protocol for BART-Related Visibility Impairment Modeling Analyses in 
North Dakota, November 2005,'' which was approved by EPA and the 
Federal Land Managers and is included in Appendix A.1 of the SIP. The 
North Dakota protocol follows recommendations for long range transport 
described in appendix W to 40 CFR part 51, ``Guideline on Air Quality 
Models,'' and in EPA's ``Interagency Workgroup on Air Quality Modeling 
(IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long 
Range Transport Impacts,'' as recommended by the BART Guidelines. 40 
CFR part 51, appendix Y, section III.A.3.
    To determine if each BART-eligible source has a significant impact 
on visibility, North Dakota used the CALPUFF model to estimate daily 
visibility impacts above estimated natural conditions at each Class I 
area within 300 km of any BART-eligible facility, based on maximum 
actual 24-hour emissions over a three year period (2000-2002).
    North Dakota opted to conduct supplemental modeling for some 
sources using its own unique modeling approach. Further discussion on 
this is provided in section V.D and in the Technical Support Document.
b. Contribution Threshold
    For states using modeling to determine the applicability of BART to 
single sources, the BART Guidelines note that the first step is to set 
a contribution threshold to assess whether the impact of a single 
source is sufficient to cause or contribute to visibility impairment at 
a Class I area. The BART Guidelines state that, ``[a] single source 
that is responsible for a 1.0 deciview change or more should be 
considered to `cause' visibility impairment.'' 70 FR 39104, 39161. The 
BART Guidelines also state that ``the appropriate threshold for 
determining whether a source contributes to visibility impairment may 
reasonably differ across states,'' but, ``[a]s a general matter, any 
threshold that you use for determining whether a source `contributes' 
to visibility impairment should not be higher than 0.5 deciviews.'' Id. 
Further, in setting a contribution threshold, states should ``consider 
the number of emissions sources affecting the Class I areas at issue 
and the magnitude of the individual sources' impacts.'' The Guidelines 
affirm that states are free to

[[Page 58583]]

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.
    North Dakota used a contribution threshold of 0.5 deciviews for 
determining which sources are subject to BART. The State's decision was 
based on the following factors: (1) 0.5 Deciviews equates to the 5% 
extinction threshold for new sources under the Prevention of 
Signification Deterioration New Source Review rules, (2) 0.5 deciviews 
represents the limit of perceptible change, (3) most of North Dakota's 
major point sources are over 100 miles away from Class I areas and are 
located downwind in the prevailing wind direction, and (4) BART 
screening modeling indicates the visibility impact of these point 
sources is either much greater than both 1.0 deciviews and 0.5 
deciviews or less than 0.5 deciviews. Although we do not agree that all 
of the factors considered by North Dakota's Department of Health are 
relevant in determining whether a source can be considered to cause or 
contribute to visibility impairment, we propose to approve the State's 
threshold of 0.5 deciviews. As shown in Table 4, North Dakota exempted 
four of the seven BART-eligible sources in the state from further 
review under the BART requirements. The visibility impacts attributable 
to each of these four sources fell well below 0.5 deciviews. Given the 
relatively limited impact on visibility from these four sources, we 
propose to agree with North Dakota's Department of Health that 0.5 
deciviews is a reasonable threshold for North Dakota in determining 
whether its BART-eligible sources are subject to BART.
    Because our recommended modeling approach already incorporates 
choices that tend to lower peak daily visibility impact values,\12\ our 
BART Guidelines state that a state should compare the 98th percentile 
(as opposed to the 90th or lower percentile) of CALPUFF modeling 
results against the ``contribution'' threshold established by the state 
for purposes of determining BART applicability. While North Dakota used 
a 98th percentile comparison, North Dakota also included a 90th 
percentile comparison in its SIP. The use of the 90th percentile 
excludes roughly the worst 36 days of data in a year compared to 7 days 
for the 98th percentile. We find that the 98th percentile value is 
appropriate. Further explanation on use of the 98th versus 90th 
percentile value is provided at 70 FR 39121, July 6, 2005.
---------------------------------------------------------------------------

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

c. Sources Identified by North Dakota as Subject to BART
    The results of the CALPUFF modeling are summarized in Table 4. 
Those facilities listed with demonstrated impacts at all Class I areas 
less than 0.5 deciviews were determined by North Dakota to not be 
subject to BART; those with impacts greater than 0.5 deciviews were 
determined to be subject to BART.
---------------------------------------------------------------------------

    \13\ The State's single-source modeling for Heskett Station Unit 
2 predicted the highest maximum 24-hour 98th percentile visibility 
impact value to be 0.82 dv at Theodore Rooseveltand 0.58 dv at 
Lostwood. Since these values were close to the BART exemption 
threshold, MDU hired a consultant to perform a refined CALPUFF 
modeling analysis. We and the FLMs expressed concerns about the 
refined modeling. MDU agreed to remodel using an EPA approved 
protocol. The results of the final analysis predicted the highest 
maximum 24-hour 98th percentile visibility impact value to be 0.28 
dv at TRNP and 0.23 dv at LWA in 2001. The refined modeling used a 1 
kilometer grid size instead of 3 kilometer, speciated particulate 
matter emissions into several components with varying light 
scattering potential, and used annual average background visibility 
instead of the annual 20% best day's background visibility. We agree 
with the revised modeling results and with the State's analysis that 
Heskett Station Unit 2 is below the BART threshold and not subject 
to BART. Information on the refined modeling and the State's updated 
analysis was submitted with SIP Supplement No. 1 on July 27, 2010.

            Table 4--Individual BART-Eligible Source Visibility Impacts on North Dakota Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                              Maximum 24-
                                                               hour 98th
              Source and unit                Class I Area     percentile          Subject to BART or exempt
                                                              visibility
                                                              impact (dv)
----------------------------------------------------------------------------------------------------------------
1. American Crystal Sugar Company (Main                LWA            0.04  Exempt.
 Boiler and Lime Kiln).
                                                      TRNP            0.04
2. Great River Energy, Coal Creek Station              LWA            4.04  Subject to BART.
 (Unit 1 and Unit 2).
                                                      TRNP            4.48
3. Great River Energy, Stanton Station                 LWA            1.35  Subject to BART.
 (Unit 1).
                                                      TRNP            1.68
4. Minnkota Power Cooperative, Milton R.               LWA            4.88  Subject to BART.
 Young Station (Unit 1 and Unit 2).
                                                      TRNP            6.69
5. Basin Electric Power Cooperative,                   LWA            5.42  Subject to BART.
 Leland Olds Station (Unit 1 and Unit 2).
                                                      TRNP            6.22
6. Montana Dakota Utilities Resources                  LWA            0.23  Exempt.\13\
 Group, Inc. R.M. Heskett Station (Unit 2).
                                                      TRNP            0.28
7. Tesoro Petroleum Corporation, Mandan                LWA            0.04  Exempt.
 Refinery Carbon Monoxide Furnace.
                                                      TRNP            0.05
----------------------------------------------------------------------------------------------------------------

3. BART Determinations and Federally Enforceable Limits
    The third step of a BART evaluation is to perform the BART 
analysis. The BART Guidelines (70 FR 39164) describe the BART analysis 
as consisting of the following five steps:
     Step 1: Identify All Available Retrofit Control 
Technologies,
     Step 2: Eliminate Technically Infeasible Options,
     Step 3: Evaluate Control Effectiveness of Remaining 
Control Technologies,
     Step 4: Evaluate Impacts and Document the Results, and
     Step 5: Evaluate Visibility Impacts.
    All of the sources presented in Table 4 that are subject to BART 
are fossil-fuel-fired EGUs. North Dakota performed BART determinations 
for all of the sources subject to BART for NOX, 
SO2, and PM. We find that North Dakota adequately considered 
all five steps above in its BART determinations, with the exception of 
its NOX BART determinations for Milton R. Young Station 
Units 1 and 2, Leland Olds Station Unit 2, and Coal Creek Station Units 
1 and 2. We are proposing to disapprove the NOX BART 
determinations for these five units, and we discuss them separately in 
Sections V.D, V.E, and V.F of this proposal. We propose to approve 
North Dakota's

[[Page 58584]]

BART determinations for all remaining cases and summarize them below.
a. Great River Energy, Coal Creek Station
Background
    Coal Creek Station is a two-unit, 1,100 gross MW mine-mouth 
electrical generating plant located near Underwood, North Dakota. It 
consists primarily of two steam generators (both with a 550 MW 
capacity) and associated coal and ash handling systems. Both units are 
identical Combustion Engineering boilers that tangentially fire 
pulverized lignite coal. The expected remaining useful life for each is 
at least 20 years. In addition, the State concluded that there are 24 
BART-eligible material handling transfer operations that are negligible 
sources of PM and five BART-eligible units--consisting of auxiliary or 
emergency equipment--that are negligible sources of PM, SO2, 
and NOX. The State analyzed each pollutant and its effect on 
the visibility in Class I areas. A summary of the State's analyses of 
existing controls and potential BART controls for each pollutant is set 
forth below, except for the discussion of NOX BART for Units 
1 and 2 which we address in section V.D.2.a. Since the Unit 1 and Unit 
2 boilers are identical, the State made a single BART determination 
that is applicable to each unit. The State's BART determination for 
Coal Creek Station is provided in Appendix B.2 of the SIP. The 
visibility impacts noted in the following analyses are derived from the 
company's BART analysis provided in Appendix C.2 of the SIP (refer to 
Technical Support Document for more details).
Unit 1 and Unit 2 Boilers
    SO2 BART Review: Each unit is already equipped with a wet scrubber 
system which removes approximately 90% of the SO2 from 60% 
of the flue gas. In addition, Great River Energy constructed a pilot 75 
tons per hour lignite drying system in 2005 as part of a collaborative 
agreement under the Clean Coal Power Initiative. Lower moisture content 
of the coal provides the following two primary benefits: (1) Enhanced 
scrubber efficiency due to increased boiler efficiency and lower flue 
gas volume, and (2) decreased fuel combustion quantities resulting in 
lower emissions. Great River Energy opted to install the coal drying 
equipment independent of the BART controls chosen for SO2. 
The State used undried coal as the worst case scenario for purposes of 
emissions estimating, explaining that it could not be reasonably sure 
of future coal moisture or British thermal unit (Btu) content. The 
baseline controlled SO2 emissions that North Dakota reported 
in the SIP are 24,604 tons per year per unit.\14\
---------------------------------------------------------------------------

    \14\ North Dakota calculated baseline emissions based on a 
future undried coal sulfur content of 1.10% and provided a detailed 
discussion of this adjustment in the SIP, Appendix B.2, pp. 8-10.
---------------------------------------------------------------------------

    The State identified the following SO2 control options 
as having potential application to the Coal Creek Station boilers: coal 
cleaning/washing, K-Fuel[supreg], TurboSorp[supreg], coal drying, dry 
sorbent injection, spray dryer, wet scrubber modification, and wet 
scrubber replacement. The State eliminated the following options as 
technically infeasible: coal cleaning/washing and K-Fuel. As noted 
above, Great River Energy has elected to install coal drying equipment 
independent of SO2 BART controls. The average cost 
effectiveness of all the remaining control options, as provided by 
Great River Energy, was deemed reasonable with the exception of the 
TurboSorp[supreg] circulating dry scrubber. Since the circulating dry 
scrubber has a lower removal efficiency compared to a new or upgraded 
wet scrubber and costs more than the wet scrubber options, North Dakota 
eliminated a circulating dry scrubber from further consideration. The 
incremental cost effectiveness of a new wet scrubber was deemed 
excessive as it achieved no additional emission reductions as compared 
to the next most effective option of modifying the existing wet 
scrubber. The State did not identify any energy or non-air quality 
effects that would preclude the selection of any of the five 
alternatives. A summary of the State's SO2 BART analysis, 
and the visibility impacts derived from modeling conducted by the 
source, are provided in Table 5.

                                     Table 5--Summary of Coal Creek SO2 BART Analysis for Unit 1 and Unit 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts 1 2
                                                                             Emissions                         Cost      -------------------------------
             Control option                  Control       Emission rate     reduction      Annualized     effectiveness    Visibility
                                          efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)       improvement    Fewer Days >
                                                                                                                            (delta dv)     0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber Replacement...............             95             0.146          20,760           30.76           1,482           1.919              68
Wet Scrubber Modification \3\..........             95             0.146          20,760           11.52             555           1.419              49
Spray Dryer............................             90             0.292          16,915           29.22           1,727  ..............  ..............
Existing Scrubber with 0% Bypass.......             83.1           0.493          11,610            9.84             848  ..............  ..............
Dry Sorbent Injection..................             70             0.875           1,538           12.52           8,140  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Great River Energy modeled combined SO2 and NOX controls. Thus, the results shown include the noted SO2 control option and North Dakota's selected
  NOX BART control, LNB Option 1.
\3\ While wet scrubber modification achieves the same annual SO2 reduction as wet scrubber replacement, Great River Energy modeled wet scrubber
  modification using a much higher 24-hour emission rate. This accounts for the disparity in the modeled visibility improvement between the two options.

    North Dakota determined BART to be modifications to the existing 
wet scrubbers so as to achieve scrubbing of 100% of the flue gas stream 
and adding a new coal dryer serving both units (the addition of a coal 
dryer is clarified in Section 7.4.2 of the SIP). North Dakota specified 
a BART limit as a minimum control efficiency of 95% (30-day rolling 
average) based on the inlet SO2 concentration to the 
scrubber or 0.15 lb/MMBtu (30-day rolling average)

[[Page 58585]]

averaged over both units. The estimated cost of wet scrubber 
modifications was $555 per ton ($/ton) of SO2 removed, and 
the capital and annualized costs were estimated to be $76,220,000, and 
$11,520,000 per year ($/year or $/yr), respectively.
    We are proposing to approve the State's SO2 BART 
determination for Coal Creek Units 1 and 2. The State's assessment of 
costs and other impacts was reasonable. The guidelines do not require 
EGUs with existing flue gas desulfurization (FGD) systems (another term 
for scrubbers) achieving greater than 50 percent control to remove 
these controls and replace them with new controls but do recommend that 
states evaluate upgrades to such existing scrubber systems (70 FR 39133 
and 70 FR 39171). The upgrade to the existing wet scrubbers at Coal 
Creek will result in a stringent level of control comparable to a new 
wet scrubber and will result in a reduction in annual SO2 
emissions from the plant of approximately 20,760 tons. This substantial 
reduction will result in a significant improvement in visibility at 
Theodore Roosevelt, estimated to be 1.419 deciviews and 49 fewer days 
above 0.5 deciviews when combined with the State's selected 
NOX BART controls, separated overfire air (SOFA) + low 
NOX burners (LNB).
    Filterable PM BART Review: Each unit at Coal Creek is already 
equipped with an electrostatic precipitator (ESP) for PM which is 99.5% 
efficient. The baseline controlled PM emissions that North Dakota 
reported in the SIP are 775 tons per year per unit with an emission 
rate of 0.030 lb/MMBtu. The State identified the following PM control 
options as having potential application to the Coal Creek Station 
boilers: multiclone, replacement of the dry ESP, a polishing wet ESP, 
and a baghouse. The State eliminated the multiclone option as 
technically infeasible for controlling PM emissions from the boilers. A 
summary of the State's PM BART analysis is provided in Table 6.

                                Table 6--Summary of Coal Creek Filterable PM BART Analysis for Unit 1 and Unit 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Replacement Dry ESP................................................            99.75            0.015              387            10.06           25,995
Polishing Wet ESP..................................................            99.75            0.015              387             1.92            4,961
Baghouse...........................................................            99.75            0.015              387             7.67           19,819
--------------------------------------------------------------------------------------------------------------------------------------------------------

    North Dakota determined BART to be no additional controls. The 
State predicted the incremental visibility improvement from any of the 
three control options would be less than 0.027 deciviews. The 
alternative with the least cost for reducing filterable PM is the 
polishing wet ESP. This system has a cost effectiveness of $4,961 per 
ton of particulate when compared to the current emission control system 
(ESP operating at 99.5% efficiency). Considering the negligible 
improvement in visibility that would be achieved by adding a polishing 
wet ESP, the State considers this cost, as well as the costs of the 
more expensive options, to be excessive. The State established a BART 
emission limit of 0.07 lb/MMBtu.
    We are proposing to approve the State's filterable PM BART 
determination for Coal Creek Units 1 and 2. The State's assessment of 
costs and other impacts was reasonable. The existing ESP already 
reduces PM emissions by approximately 99.5%, and North Dakota 
reasonably determined that the costs of additional PM controls would be 
excessive given the negligible improvement in visibility that would 
result.
    Condensable PM (PM10) Review: The State provided an 
estimated emission rate for condensable PM of 0.02 lb/MMBtu. This 
emission rate is lower than the current filterable PM emission rate of 
0.03 lb/MMBtu. Thus the State concluded that the visibility impacts 
from condensable PM would be even less than the impacts from filterable 
PM. Condensable PM consists of both organic and inorganic substances. 
Organic condensable PM includes VOCs that are in a gaseous state 
through the air pollution control devices but eventually change to a 
solid or liquid state. The primary inorganic substance from boilers is 
sulfuric acid mist with lesser amounts of hydrogen fluoride and 
ammonium sulfate. Sulfuric acid mist is the largest component of 
condensable PM so controlling it will control most of the condensable 
PM. The options for controlling sulfuric acid mist are the same as the 
options for controlling SO2. BART for SO2--
modification of the existing wet scrubber--will reduce sulfuric acid 
mist by approximately 90%. Changes that would provide additional 
reductions are not warranted given the minimal improvement in 
visibility that would result. The State determined that ongoing good 
combustion controls and the BART limit for SO2 would also 
constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART 
determination for Coal Creek Units 1 and 2. Upgrades to the wet 
scrubbers required as part of SO2 BART will substantially 
reduce sulfuric acid mist, which is the largest component of 
condensable PM. North Dakota reasonably determined that the costs of 
additional condensable PM controls would be excessive given the 
negligible improvement in visibility that would result.
Auxiliary Boilers No. 91 and No. 92, Emergency Generator, Emergency 
Fire Pump, and Material Handling and Fugitive Sources
    The State analyzed and determined BART for these small emissions 
sources at the plant and determined that BART is existing controls with 
no additional controls. The State based its conclusion on the fact that 
further controls would not be cost effective and would have virtually 
no impact on visibility. For further detail, see the State's BART 
analysis.
    We agree with the State's conclusion and are proposing to approve 
its BART determination for these sources.
b. Great River Energy, Stanton Station
Background
    Stanton Station is a 188 MW electrical generating plant located on 
the bank of the Missouri River in eastern Mercer County near Stanton, 
North Dakota. The plant's one main turbine generator is run by the Unit 
1 and Unit 10 boilers. Unit 1, which is the only BART eligible unit at 
Stanton Station, began operation in 1966. An auxiliary boiler was added 
in 1982. Unit 1 has a dry bottom front-wall-fired configuration and is 
permitted to burn both lignite and sub-bituminous Powder River Basin 
(PRB) coal. Unit 1 has an expected remaining useful life of at least 20 
years. Because Great River Energy does not intend to

[[Page 58586]]

blend coals, North Dakota determined BART controls and emission limits 
separately for both each coal type that Unit 1 is permitted to burn. 
The use of two coals with different sulfur contents complicates the 
SO2 BART analysis and determination for Unit 1. Associated 
limits were determined based upon each fuel, cost effectiveness, and 
expected visibility improvements. In addition to the boilers, there are 
13 BART-eligible material handling transfer operations that are 
negligible sources of PM and three other BART-eligible units consisting 
of auxiliary or emergency equipment that are negligible sources of PM, 
SO2, and NOX. The State analyzed each pollutant 
and its effect on the visibility in Class I areas. A summary of the 
State's analyses of existing controls and potential BART controls for 
each pollutant is set forth below. The State's BART determination for 
Stanton Station is provided in Appendix B.3 of the SIP. The visibility 
impacts noted in the following analyses are derived from the company's 
BART analysis provided in Appendix C.3 of the SIP.
Unit 1 Boiler
    SO2 BART Review (Lignite Coal): Unit 1 is not equipped 
with any pollution controls for SO2. The baseline 
uncontrolled SO2 emissions that North Dakota reported in the 
SIP are 8,242 tons per year with an emission rate of 1.70 lb/MMBtu. The 
State identified the following SO2 control options as having 
potential application to the Stanton Station boiler: wet scrubber, 
spray dryer/fabric filter, circulating dry scrubber, flash dryer 
absorber,\15\ wet scrubber with 10% bypass, dry sorbent injection/
fabric filter, dry sorbent injection/existing ESP, Powerspan 
ECO[supreg], coal cleaning, Pahlman ProcessTM, and K-
Fuel[supreg]. The State eliminated the following options as technically 
infeasible: coal cleaning, K-Fuel[supreg], Powerspan ECO[supreg], and 
the Pahlman ProcessTM. The cost of all the technically 
feasible control options was deemed reasonable. The flash dryer 
absorber with a control efficiency of 90% was not carried through the 
analysis as it costs more than a spray dryer with no additional 
emissions reduction. The State determined that there were no energy and 
non-air quality environmental impacts that would preclude the selection 
of any of the control equipment alternatives. However, the State cited 
the environmental impact of a wet scrubber using 20% more water and 
difficulties in expanding on-site pond capacity to accommodate this 
additional water as one reason for not selecting a wet scrubber. In 
addition, the State determined the incremental cost of $10,600 per ton 
for the circulating dry scrubber as compared to a spray dryer was 
excessive. Therefore, it removed the circulating dry scrubber from 
further consideration. The State also found that a wet scrubber would 
only reduce SO2 emissions by 469 tons per year more than the 
spray dryer/fabric filter option and noted that the incremental 
visibility improvement would be 0.112 deciviews. A summary of the 
State's SO2 BART analysis with lignite coal, and the 
visibility impacts derived from modeling conducted by the source, are 
provided in Table 7.
---------------------------------------------------------------------------

    \15\ North Dakota appears to have a typographical error in its 
BART determination. Though flash dryer absorber is not included in 
its list of available control options for lignite coal, flash dryer 
absorber is mentioned in the lignite analysis and is listed in the 
technically feasible options for Powder River Basin coal.

                                    Table 7--Summary of Stanton SO2 BART Analysis for Unit 1 Boiler With Lignite Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts 1 2
                                                                            Emissions                          Cost      -------------------------------
             Control option                  Control      Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)      benefit (delta   Fewer days >
                                                                                                                                dv)         0.5 (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber...........................              95           0.091           8,907           13.18            1,480           1.119              49
Circulating Dry Scrubber...............              93           0.127           8,720           14.22            1,631  ..............  ..............
SD/FF..................................              90           0.181           8,438           11.22            1,330           1.007              43
Wet Scrubber with 10% Bypass...........              86           0.263           8,063            9.49            1,177  ..............  ..............
DSI/FF.................................              55           0.817           5,157            8.43            1,635           0.382              16
DSI/ESP................................              35           1.18            3,282            3.2               975           0.382              16
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Visibility impacts are presented for each SO2 control option with NOX emissions at pre-control emission rates.

    For use of lignite coal, North Dakota determined BART to be a spray 
dryer with a fabric filter. North Dakota specified a BART limit as a 
minimum control efficiency of 90% (30-day rolling average) on the inlet 
SO2 concentration to the pollution control equipment or 0.24 
lb/MMBtu (30-day rolling average). In establishing the 30-day rolling 
average limit, the State increased the calculated annual emissions rate 
of 0.18 lb/MMBtu to 0.24 lb/MMBtu to account for coal variability over 
the shorter averaging period. The estimated average cost effectiveness 
of the spray dryer with a fabric filter was $1,330 per ton of 
SO2 removed, and the capital and annualized costs were 
estimated to be $77,840,000 and $11,220,000 per year, respectively. 
This control option will result in a significant improvement in 
visibility at Theodore Roosevelt, estimated to be 1.007 deciviews and 
43 fewer days above 0.5 deciviews.
    SO2 BART Review (Powder River Basin Coal): North Dakota 
concluded that the technically feasible control options for Unit 1 are 
the same whether the source is burning lignite or Powder River Basin 
coal. North Dakota conducted its analyses based on two different 
baseline SO2 emission limits which vary due to anticipated 
sulfur content variations in the Powder River Basin coal as the result 
of a new coal contract.\16\ The State determined that the incremental 
cost of $16,000 per ton (with a 1.2 lb/MMBtu baseline emission rate) 
for a circulating dry scrubber compared to a spray dryer was excessive. 
In addition, the State considered the incremental cost of over $11,800 
per ton (with a 0.64 lb/MMBtu baseline emission rate) for a wet 
scrubber as compared to a spray dryer

[[Page 58587]]

to be excessive. Therefore, the State removed the wet scrubber and 
circulating dry scrubber from further consideration. The State also 
found that a wet scrubber would only reduce SO2 emissions by 
311 tons per year more than the spray dryer/fabric filter option and 
that the incremental visibility improvement would be less than 0.112 
deciviews, the value for lignite. A summary of the State's 
SO2 BART analysis with Powder River Basin coal is provided 
in Table 8.
---------------------------------------------------------------------------

    \16\ Appendix B.3, pp. 17-22, of the SIP describes the basis for 
the 1.2 lb/MMBtu and 0.64 lb/MMBtu SO2 baseline emission 
rates.

                              Table 8--Summary of Stanton SO2 BART Analysis for Unit 1 Boiler With Powder River Basin Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber.......................................................               95            0.06             5,905            13.18            2,232
Circulating Dry Scrubber...........................................               93            0.084            5,781            14.22            2,460
SD/FF..............................................................               90            0.12             5,594            11.22            2,006
Wet Scrubber with 10% Bypass.......................................               86            0.168            5,346             9.49            1,775
DSI/FF.............................................................               55            0.54             3,419             8.43            2,466
DSI/ESP............................................................               35            0.78             2,176             3.20            1,471
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For use of Powder River Basin coal, North Dakota determined BART to 
be a spray dryer with a fabric filter to achieve a minimum control 
efficiency of 90% (30-day rolling average) on the inlet SO2 
concentration to the pollution control equipment or an emission limit 
of 0.16 lb/MMBtu (30-day rolling average). In establishing the 30-day 
rolling average BART limit, the State increased the calculated annual 
emissions rate of 0.12 lb/MMBtu to 0.16 lb/MMBtu to account for coal 
variability over the shorter averaging period. The estimated cost of a 
spray dryer with a fabric filter was $2,006 per ton of SO2 
removed, and the capital and annualized costs were estimated to be 
$77,840,000 and $11,220,000 per year, respectively. The projected 
visibility improvements from this option, as well as for all other 
control options, when the source burns Powder River Basin coal, are 
anticipated to be less than when the source burns lignite coal.
    We are proposing to approve the State's SO2 BART 
determinations for Stanton Unit 1 for both lignite and Powder River 
Basin coal. The State's assessment of costs and other impacts was 
reasonable. The spray dryer with fabric filter represents a stringent 
level of control and will result in a reduction in annual 
SO2 emissions from the plant of approximately 8,438 tons 
when lignite is burned and 5,594 tons when Powder River Basin coal is 
burned. This substantial reduction will result in a significant 
improvement in visibility at Theodore Roosevelt, estimated to be 1.007 
deciviews and 43 fewer days above 0.5 deciviews. Higher performing 
alternatives (wet scrubber or circulating dry scrubber) would only 
produce a slightly greater reduction in SO2 and improvement 
in visibility, at higher cost. We are proposing to find that, based on 
its consideration of the BART factors, the State's elimination of these 
control options was reasonable.
    NOX BART Review (Lignite Coal): Unit 1 is already 
equipped with LNB for NOX control. North Dakota indicates in 
the SIP that Unit 1 has baseline controlled NOX emissions of 
1,740 tons per year with an emission rate of 0.36 lb/MMBtu. North 
Dakota identified the following control options as having potential 
application as BART: selective catalytic reduction (SCR), low 
temperature oxidation (LTO), non-selective catalytic reduction (NSCR), 
electro-catalytic oxidation (ECO), selective non-catalytic reduction 
(SNCR), rich reagent injection (RRI), external flue gas recirculation 
(FGR), overfire air (OFA), LNB, and the Pahlman Process. The State 
identified the following control options as technically infeasible: 
ECO, NSCR, the Pahlman Process, RRI, and external flue gas 
recirculation. The incremental cost effectiveness of both SCR and LTO 
were deemed excessive at $10,000 and $45,400 per ton, respectively, 
when compared to a combination of LNB, OFA, and SNCR (LNB + OFA + 
SNCR). The State determined that there were no energy and non-air 
quality environmental impacts that would preclude the selection of any 
of the control equipment alternatives. A summary of the State's 
NOX BART analysis with lignite coal, and the visibility 
impacts derived from modeling conducted by the source, are provided in 
Table 9.

                                    Table 9--Summary of Stanton NOX BART Analysis for Unit 1 Boiler With Lignite Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                               Visibility Imacts1 2
                                                                            Emissions                          Cost      -------------------------------
             Control option                  Control      Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost  (MM$)       ($/ton)          benefit      Fewer days >
                                                                                                                            (delta dv)     0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR....................................              90           0.044           1,929           12.49            6,475           1.405              59
LTO....................................              90           0.044           1,929           44.78           23,217  ..............  ..............
LNB + OFA + SNCR.......................              45           0.239             983            3.00            3,052           1.110              52
SNCR...................................              33           0.29              738            2.70            3,658           1.027              43
LNB + OFA..............................  ..............  ..............  ..............  ..............  ...............           1.009              43
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Great River Energy modeled combined SO2 and NOX controls. Thus, the results shown include the noted NOX control option and North Dakota's selected
  SO2 BART control, a spray dryer with fabric filter.

[[Page 58588]]

    For use of lignite coal, North Dakota determined BART to be LNB + 
OFA + SNCR. North Dakota specified a BART limit as a minimum control 
efficiency of 45% and an emission limit of 0.29 lb/MMBtu (30-day 
rolling average). The estimated average cost effectiveness of the 
selected control combination is $3,052 per ton of NOX 
removed. The capital and annualized costs were estimated to be 
$10,660,000 and $3,000,000, respectively. This control option, when 
combined with the spray dryer/fabric filter determined to be BART for 
SO2, will result in a significant improvement in visibility 
at Theodore Roosevelt, estimated to be 1.110 deciviews and 52 fewer 
days above 0.5 deciviews. This represents an incremental visibility 
improvement of 0.103 deciviews and 9 fewer days above 0.5 deciviews 
when compared to use of a spray dryer/fabric filter with the existing 
low NOx burners.
    NOX BART Review (Powder River Basin Coal): The 
technically feasible control options for Powder River Basin coal are 
the same. The costs of both SCR and LTO were deemed excessive. The 
State determined that there were no energy and non-air quality 
environmental impacts that would preclude the selection of any of the 
control equipment alternatives. A summary of the State's NOX 
BART analysis with Powder River Basin coal is provided in Table 10.

                              Table 10--Summary of Stanton NOX BART Analysis for Unit 1 Boiler With Powder River Basin Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         Emissions                             Cost
                          Control option                                Control       Emission rate   reduction (tons/  Annualized cost   effectiveness
                                                                     efficiency (%)     (lb/MMBtu)          yr)              (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR...............................................................               88            0.044            1,530             12.49            8,163
LTO...............................................................               88            0.044            1,530             44.78           29,268
LNB + OFA + SNCR..................................................               45            0.196              794              3.0             3,778
SNCR..............................................................               36            0.230              629              2.7             4,293
LNB + OFA.........................................................               21            0.286              358              0.3               838
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For use of Powder River Basin coal, North Dakota determined BART to 
be LNB + OFA + SNCR with a minimum control efficiency of 45% and an 
emission limit of 0.23 lb/MMBtu (30-day rolling average). The estimated 
cost of the selected control combination is $3,778 per ton of 
NOX removed. The capital and annualized costs were estimated 
to be $10,660,000 and $3,000,000, respectively. The projected 
visibility improvements from this option, as well as for all other 
control options, when the source burns Powder River Basin coal, are 
anticipated to be less than when the source burns lignite coal.
    We are proposing to approve the State's NOX BART 
determinations for Stanton Unit 1 for both lignite and Powder River 
Basin coal. Given the projected incremental visibility improvement of 
just under 0.3 deciviews from the use of SCR or LTO as compared to LNB 
+ OFA + SNCR and the average and incremental cost effectiveness values 
associated with these technologies, the State reasonably concluded that 
the costs associated with SCR and LTO are not warranted.
    Filterable PM BART Review (Lignite Coal): Unit 1 is already 
equipped with an ESP for PM control. The State evaluated the following 
control options as having potential application as BART: baghouse, new 
ESP, and wet ESP. All were deemed technically feasible. The State 
determined all options present excessive costs with the least expensive 
option being the wet ESP at $112,780 per ton of PM removed. North 
Dakota stated there would be negligible visibility improvement with 
additional controls. The State determined BART to be no additional 
controls with an emission limit of 0.07 lb/MMBtu when burning lignite. 
A summary of the State's PM BART analysis with lignite coal is provided 
in Table 11.

                                    Table 11--Summary of Stanton PM BART Analysis for Unit 1 Boiler with Lignite Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission  rate     reduction     Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)       (tons/yr)           (MM$)          ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.015               18             4.98          276,670
New ESP............................................................           99.7              0.015               18             5.80          322,220
Wet ESP............................................................           99.7              0.015               18             2.03          112,780
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Filterable PM BART Review (Powder River Basin Coal): North Dakota 
did not conduct a separate analysis for filterable PM when combusting 
Powder River Basin coal. The State noted that available pollution 
control equipment is expected to control emissions from both lignite 
and Powder River Basin coal down to similar emission rates. North 
Dakota determined that BART for filterable PM when burning Powder River 
Basin coal was the same as when burning lignite: no additional controls 
with an emission limit of 0.07 lb/MMBtu.
    We are proposing to approve the State's filterable PM BART 
determination for Stanton Unit 1. The State's assessment of costs and 
other impacts was reasonable. Existing controls, ESP, already reduce PM 
emissions by approximately 99.5%, and North Dakota reasonably 
determined that the costs of additional PM controls would be excessive 
given the negligible improvement in visibility that would result.
    Condensable PM (PM10) Review (Lignite Coal): The State 
provided an estimated emission rate for condensable PM of 0.02 lb/
MMBtu. This emission rate is about equal to the current filterable PM 
emission rate of 0.019 lb/MMBtu. Based on the negligible visibility 
impacts of filterable PM, the State anticipated that the visibility 
impacts of condensable PM would also be negligible. Condensable PM 
consists of both organic and inorganic substances. Organic condensable 
PM includes VOCs that are in a gaseous

[[Page 58589]]

state through the air pollution control devices but eventually change 
to a solid or liquid state. The primary inorganic substance from 
boilers is sulfuric acid mist with lesser amounts of hydrogen fluoride 
and ammonium sulfate. Sulfuric acid mist is the largest component of 
condensable PM so controlling it will control most of the condensable 
PM. The options for controlling sulfuric acid mist are the same as the 
options for controlling SO2. BART for SO2--spray 
dryer with a fabric filter--will reduce sulfuric acid mist by 
approximately 90%. North Dakota determined that changes that would 
provide additional reductions are not warranted given the negligible 
improvement in visibility that would result. The State determined that 
ongoing good combustion controls and the BART limit for SO2 
would also constitute BART for condensable PM.
    Condensable PM (PM10) Review (Powder River Basin Coal): 
For the same reasons described above for condensable PM when burning 
lignite, North Dakota determined that ongoing good combustion controls 
and the BART limit for SO2 would also constitute BART for 
condensable PM when burning Powder River Basin coal.
    We are proposing to approve the State's condensable PM BART 
determination for Stanton Unit 1. The spray dryer with a fabric filter 
required for SO2 BART will substantially reduce sulfuric 
acid mist, which is the largest component of condensable PM. North 
Dakota reasonably determined that the costs of additional condensable 
PM controls would be excessive given the negligible improvement in 
visibility that would result.
    Auxiliary Boiler, Emergency Generator, Emergency Fire Pump, 
Material Handling and Fugitive Sources
    The State analyzed and determined BART for these small emissions 
sources at the plant and determined that BART is existing controls with 
no additional controls. The State based its conclusion on the fact that 
further controls would not be cost effective and would have virtually 
no impact on visibility. For further detail, see the State's BART 
analysis.
    We agree with the State's conclusion and are proposing to approve 
its BART determination for these sources.
c. Minnkota Power Cooperative, Milton R. Young Station (MRYS)
Background
    Milton R. Young Station is a two-unit 794 MW electrical generating 
plant located near Center, North Dakota. Both units are Babcock & 
Wilcox cyclone boilers burning lignite coal. Commercial operation 
commenced for Unit 1 (277 MW) in 1970 and for Unit 2 (517 MW) in 1977. 
Both units have an expected remaining useful life of at least 20 years. 
In addition, there are ten BART-eligible material handling transfer 
operations that are negligible sources of PM and four other BART-
eligible units consisting of auxiliary or emergency equipment that are 
negligible sources of PM, SO2, and NOX. The State 
analyzed each pollutant and its effect on the visibility in Class I 
areas. A summary of the State's analysis of existing controls and 
potential BART controls is set forth below, except for the discussion 
of NOX BART for Units 1 and 2, which we address in section 
V.D.1 below. The State's BART determination for Milton R. Young Station 
is provided in Appendix B.4 of the SIP. The company's BART analysis is 
provided in Appendix C.4 of the SIP.
Unit 1 Boiler
    SO2 BART Review: Unit 1 had no existing SO2 
control system at the time of the State's BART analysis, but as a 
result of a consent decree resolving alleged New Source Review 
violations at Milton R. Young Station, Minnkota installed a wet 
scrubber in April 2011. The consent decree states that if Minnkota 
installs a wet scrubber, it must comply with a 95% control efficiency 
with no alternative emission limit (lb/MMBtu) limit. The deadline to 
meet the new emission limit is December 31, 2011. The baseline 
uncontrolled SO2 emissions that North Dakota reported in the 
SIP are 21,519 tons per year with an emission rate of approximately 
1.87 lb/MMBtu.
    The State evaluated the following SO2 control options 
for having potential application as BART: wet scrubber, spray dryer, 
circulating dry scrubber, Powerspan ECO, fuel switching, and coal 
cleaning. North Dakota identified Powerspan ECO and coal cleaning as 
technically infeasible. The State also cited a court case as a 
rationale for not further analyzing fuel switching.\17\ The State found 
all three remaining technologies to be cost effective. The State 
determined that there were no energy and non-air quality environmental 
impacts that would preclude the selection of any of the control 
equipment alternatives. A summary of the State's SO2 BART 
analysis, and the visibility impacts derived from modeling conducted by 
the source, are provided in Table 12.
---------------------------------------------------------------------------

    \17\ A decision by the Seventh Circuit Court of Appeals on a 
BACT determination for Prairie Generating Company, LLC indicated 
that fuel switching was not required for mine mouth coal generating 
facilities. The State's position is this would also apply to BART 
determinations. We agree that a State is not required to consider 
switching from coal to natural gas as part of a BART analysis for a 
coal-fired power plant. As EPA noted in the BART Guidelines, we do 
not consider BART as a requirement to redesign the source when 
considering available control alternatives. 79 FR at 39164.

                                    Table 12--Summary of Milton R. Young Station SO2 BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts 1 2
                                                                        Emissions                            Cost      ---------------------------------
          Control option               Control       Emission rate      reduction        Annualized     effectiveness      Visibility
                                    efficiency (%)     (lb/MMBtu)       (tons/yr)       cost  (MM$)        ($/ton)       benefit (delta   Fewer days 0.5
                                                                                                                              dv)           dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber.....................               95             0.10           20,443            22.58            1,105            2.076               71
Circulating Dry Scrubber.........               93             0.14           20,013            24.65            1,232  ...............  ...............
Spray Dryer......................               90             0.20           19,367            23.68            1,222            2.002               62
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Visibility impacts are presented for each SO2 control option with NOX emissions at pre-control emission rates.

    North Dakota determined BART to be a wet scrubber, the most 
efficient control alternative, operating at a minimum 95% control 
efficiency (30-day rolling average). Since the wet scrubber is the most 
efficient

[[Page 58590]]

technology, further evaluation of the other alternatives is not 
necessary. Minnkota did conduct modeling for the 90% and 95% control 
options; the results are included in Table 12. The estimated cost of a 
wet scrubber was $1,105 per ton of SO2 removed, and the 
capital and annualized costs were estimated to be $111,776,000 and 
$22,584,000 per year, respectively.
    We are proposing to approve the State's SO2 BART 
determination for Milton R. Young Station Unit 1. The State selected 
the most efficient control technology at a 95% control level, which we 
consider to be consistent with the most stringent level of control 
currently available. Per our BART Guidelines, a state may skip the 
five-factor analysis if it is imposing the most stringent level of 
control. Nonetheless, we note that the wet scrubber will produce a 
reduction in annual SO2 emissions from the unit of 
approximately 20,443 tons. This substantial reduction will result in a 
significant improvement in visibility at Theodore Roosevelt--estimated 
to be 2.076 deciviews and 71 fewer days above 0.5 deciviews.
    Filterable PM BART Review: Unit 1 is equipped with an ESP rated at 
approximately 99% control efficiency. The baseline controlled PM 
emissions that North Dakota reported in the SIP are 268 tons per year 
with an emission rate of 0.019 lb/MMBtu. The State evaluated the 
following PM control options for having potential application as BART 
with all four being found technically feasible: a new baghouse; a new 
ESP; a compact hybrid particulate collector (CoHPAC); and upgrading the 
existing ESP. All were deemed to have excessive costs. The alternative 
with the least cost was a new baghouse at $39,433 per ton of PM 
removed. The State determined BART to be no additional controls. 
Minnkota is subject to a consent decree limiting PM emissions to 0.030 
lb/MMBtu in the event Minnkota installs a wet scrubber. North Dakota 
stated there would be insignificant visibility improvement with 
additional controls. Since Minnkota has installed a wet scrubber, the 
State proposed that BART is an emission limit of 0.030 lb/MMBtu 
(average of three test runs). A summary of the State's PM BART analysis 
is provided in Table 13.

                                     Table 13--Summary of Milton R. Young Station PM BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              134             5.28           39,433
New ESP............................................................           99.7              0.015               90             4.64           51,589
CoHPAC.............................................................           99.7              0.015               90             3.63           40,355
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We are proposing to approve the State's filterable PM BART 
determination for Milton R. Young Station Unit 1. The State's 
assessment of costs and other impacts was reasonable. Existing 
controls, ESP, already reduce PM emissions by approximately 99%, and 
North Dakota reasonably determined that the costs of additional PM 
controls would be excessive given the negligible improvement in 
visibility that would result.
    Condensable PM (PM10) Review: Sulfuric acid mist is the largest 
component of condensable PM. North Dakota stated that the options for 
controlling sulfuric acid mist are the same as the options for 
controlling SO2. Based on the negligible visibility impacts 
of filterable PM, the State anticipated that the visibility impacts of 
condensable PM would also be negligible. The State determined that 
ongoing good combustion controls and the BART limit for SO2 
would also constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART 
determination for Milton R. Young Station Unit 1. The wet scrubber 
required for SO2 BART will substantially reduce sulfuric 
acid mist, which is the largest component of condensable PM. North 
Dakota's determination is reasonable.
Unit 2 Boiler
    SO2 BART Review: At the time of the State's BART analysis, Unit 2 
was equipped with a wet scrubber system which treated approximately 78% 
of the flue gas with the remaining flue gas by-passed for stack gas 
reheat. The wet scrubber system achieved approximately 75% 
SO2 removal. The baseline controlled SO2 
emissions that North Dakota reported in the SIP are 18,090 tons per 
year with an emission rate of approximately 0.88 lb/MMBtu. The Milton 
R. Young Station consent decree imposed a deadline for Unit 2 to be 
upgraded and achieve 90% control efficiency by December 31, 2010. The 
upgraded scrubber was placed into operation on December 8, 2010.
    The State evaluated the following SO2 control options 
for BART: A new wet scrubber; upgrade to existing scrubber (either to 
90% or 95%); circulating dry scrubber; spray dryer; flash dryer 
absorber; Powerspan ECO; fuel switching; and coal cleaning. The Stated 
found coal cleaning, Powerspan ECO, and fuel switching to be 
technically infeasible. The average cost effectiveness of all remaining 
alternatives was deemed reasonable. The State determined that there 
were no energy and non-air quality environmental impacts that would 
preclude the selection of any of the control equipment alternatives. As 
the 95% control efficiency scrubber upgrade had equal or greater 
control efficiency at lower cost as compared to a new wet scrubber or a 
circulating dry scrubber, and the 90% control efficiency scrubber 
upgrade had equal control efficiency at lower cost as compared to a 
spray dryer or flash dryer, the State reduced the options to the 95% 
and 90% control efficiency scrubber upgrades. A summary of the State's 
SO2 BART analysis, and visibility impacts derived from 
modeling conducted by the source, are provided in Table 14.

[[Page 58591]]

                                    Table 14--Summary of Milton R. Young Station SO2 BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts1 2
                                             Control                        Emissions                         Cost      --------------------------------
             Control option                efficiency     Emission rate     reduction      Annualized     effectiveness    Visibility
                                               (%)         (lb/MMBtu)       (tons/yr)      cost  (MM$)       ($/ton)         benefit       Fewer days >
                                                                                                                           (delta dv)     0.5 dv  (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Upgrade Existing Scrubber..............              95            0.11          16,126            8.41             522           1.627               52
Upgrade Existing Scrubber..............              90            0.23          14,162            7.33             518           1.423               40
--------------------------------------------------------------------------------------------------------------------------------------------------------
1 The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological
  period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the total for the
  modeled 3-year meteorological period at Theodore Roosevelt.
2 Visibility impacts are presented for each SO2 control option with NOX emissions at pre-control emission rates.

    North Dakota determined BART to be the improvements to the wet 
scrubber to achieve a 95% control efficiency (from scrubber inlet to 
outlet, 30-day rolling average). Minnkota would have to comply with 
either the 95% reduction requirement or the 0.15 lb/MMBtu limit, but 
not both. The 90% control efficiency requirement from the consent 
decree resolving the alleged new source review violations is also 
incorporated into the BART permit, which is part of the SIP.
    We are proposing to approve the State's SO2 BART 
determination for Milton R. Young Station Unit 2. The State's 
assessment of costs and other impacts was reasonable. The upgrade to 
the existing wet scrubbers represents a stringent level of control and 
will result in a reduction in annual SO2 emissions from the 
plant of approximately 16,126 tons. This substantial reduction will 
result in a significant improvement in visibility at Theodore 
Roosevelt--estimated to be 1.627 deciviews and 52 fewer days above 0.5 
deciviews.
    Filterable PM BART Review: Unit 2 is equipped with an ESP rated at 
approximately 99% control efficiency with a baseline emission rate of 
0.06 lb/MMBtu. The average emission rate for this unit for 2000-2004 
was 0.028 lb/MMBtu. The baseline controlled PM emissions that North 
Dakota reported in the SIP are 1,135 tons per year. The State evaluated 
the following PM control options for BART and found all four to be 
technically feasible: A new baghouse; a new ESP; a CoHPAC; and upgrades 
to the existing ESP. The cost of all options was deemed excessive, with 
the least expensive being CoHPAC at $6,693 per ton of PM removed. North 
Dakota stated that visibility impacts even at 100% control would be 
minimal due to the low emission reductions of 849 tons per year 
compared to the baseline conditions with the existing 99% efficient 
ESP. The State proposed BART to be no additional controls. The consent 
decree limits PM emissions to 0.030 lb/MMBtu. Therefore, the State 
proposed that BART is an emission limit of 0.030 lb/MMBtu (average of 
three test runs). A summary of the State's PM BART analysis is provided 
in Table 15.

                                     Table 15--Summary of Milton R. Young Station PM BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate      reduction     Annualized cost   effectiveness
                                                                     efficiency  (%)     (lb/MMBtu)       (tons/yr)          (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              887             8.25            9,300
New ESP............................................................           99.7              0.015              849             7.52            8,857
CoHPAC.............................................................           99.7              0.015              849             5.68            6,693
Baseline...........................................................           99.0              0.060  ...............             2.97  ...............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We are proposing to approve the State's filterable PM BART 
determination for Milton R. Young Station Unit 2. The State's 
assessment of costs and other impacts was reasonable. Existing 
controls, ESP, already reduce PM emissions by approximately 99%, and 
North Dakota reasonably determined that the costs of additional PM 
controls would be excessive given the negligible improvement in 
visibility that would result.
    Condensable PM (PM10) Review: Sulfuric acid mist is the largest 
component of condensable PM. North Dakota stated that the options for 
controlling sulfuric acid mist are the same as the options for 
controlling SO2. Based on the negligible visibility impacts 
of filterable PM, the State anticipated that the visibility impacts of 
condensable PM would also be negligible. The State determined that 
ongoing good combustion controls and the BART limit for SO2 
would also constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART 
determination for Milton R. Young Station Unit 2. The wet scrubber 
required for SO2 BART will substantially reduce sulfuric 
acid mist, which is the largest component of condensable PM. North 
Dakota's determination is reasonable.
    Auxiliary Boiler, Emergency Generator, Emergency Fire Pumps, and 
Material Handling and Fugitive Sources
    The State analyzed and determined BART for these small emissions 
sources at the plant and determined that BART is existing controls with 
no additional controls. The State based its conclusion on the fact that 
further controls would not be cost effective and would have virtually 
no impact on visibility. For further detail, see the State's BART 
analysis.
    We agree with the State's conclusion and are proposing to approve 
its BART determination for these sources.
d. Basin Electric Power Cooperative, Leland Olds Station (LOS)
    This is a 656 MW coal-fired electrical generating plant located in 
Stanton, North Dakota with two boiler units. Unit 1 is a Babcock & 
Wilcox wall-fired, dry-bottom, pulverized coal-fired boiler serving a 
turbine generator with a nameplate rating of 216 MW. Unit 2 is a 
Babcock & Wilcox cyclone-fired unit burning crushed coal, with a 
turbine-

[[Page 58592]]

generator name plate rating of 440 MW. Unit 1 began commercial 
operation in 1966 and Unit 2 began operation in 1976. Both boiler units 
burn lignite coal and have an expected remaining useful life of at 
least 20 years. In addition, there are seven BART-eligible material 
handling transfer operations that are negligible sources of PM and two 
other BART-eligible units consisting of auxiliary and emergency 
equipment that are negligible sources of PM, SO2, and 
NOX. Each pollutant and its effect on the visibility in 
Class I areas was analyzed by the State. A summary of the State's 
analysis of existing controls and potential BART controls for each 
pollutant is set forth below, except for the discussion of 
NOX BART for Unit 2, which we address in section V.D.1.c 
below. The State's BART determination for Leland Olds Station is 
provided in Appendix B.1 of the SIP. The company's BART analysis is 
provided in Appendix C.1 of the SIP.
Unit 1 Boiler
    SO2 BART Review: Unit 1 has no existing SO2 control 
system. The baseline uncontrolled SO2 emissions that North 
Dakota reported in the SIP are 34,683 tons per year with an emission 
rate of approximately 3.02 lb/MMBtu. The State evaluated the following 
SO2 control options for BART: Wet scrubber; spray dryer; 
circulating dry scrubber; flash dryer absorber; Powerspan ECO; fuel 
switching; and coal cleaning. Powerspan ECO and coal cleaning were 
identified as technically infeasible. The State conducted a cost 
analysis for the top three options and found all to be cost effective. 
The flash dryer absorber was not included in the analysis because it 
costs more than a spray dryer with no additional emissions reduction. 
The State determined that there were no energy and non-air quality 
environmental impacts that would preclude the selection of any of the 
control equipment alternatives. A summary of the State's SO2 
BART analysis for Unit 1, and visibility impacts derived from modeling 
conducted by the source, are provided in Table 16.

                                      Table 16--Summary of Leland Olds Station SO2 BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                               Visibility impacts1 2
                                             Control                        Emissions                          Cost      -------------------------------
             Control option                efficiency     Emission rate     reduction      Annualized     effectiveness     Visibility
                                               (%)         (lb/MMBtu)       (tons/yr)      cost  (MM$)       ($/ton)          benefit      Fewer days >
                                                                                                                            (delta dv)    0.5 dv  (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber...........................              95            0.15          32,949           19.31              586           1.912              83
Circulating Dry Scrubber...............              93            0.21          32,255           20.72              636           1.743              78
Spray Dryer............................              90            0.30          31,215           18.70              599           1.707              77
--------------------------------------------------------------------------------------------------------------------------------------------------------
1 The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year meteorological
  period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the total for the
  modeled 3-year meteorological period at Theodore Roosevelt.
2 Basin Electric modeled combined SO2 and NOX controls. The results shown include the noted SO2 control option and NOX at the presumptive rate. Given
  that the presumptive NOX emission rate is very close to the pre-control NOX rate, the visibility impacts shown are largely due to the reduction in SO2
  emissions and not the reduction in NOX emissions.

    North Dakota determined BART to be the most efficient control 
option, a wet scrubber operating at 95% control efficiency or below an 
emission limit of 0.15 lb/MMBtu (30-day rolling average). Basin 
Electric would have to comply with either the 95% reduction requirement 
or the 0.15 lb/MMBtu limit, but not both. The estimated average cost 
effectiveness of a wet scrubber was $586 per ton of SO2 
removed, and the capital and annualized costs were estimated to be 
$107,220,000 and $19,310,000 per year, respectively.
    We are proposing to approve the State's SO2 BART 
analysis and determination for Leland Olds Station Unit 1. The State's 
assessment of costs and other impacts was reasonable. The wet scrubber 
represents a stringent level of control and will result in a reduction 
in annual SO2 emissions from the plant of approximately 
32,949 tons. This substantial reduction will result in a significant 
improvement in visibility at Theodore Roosevelt, estimated to be 1.912 
deciviews and 83 fewer days above 0.5 deciviews.
    NOX BART Review: Unit 1 is equipped with LNB (installed in 1995). 
The baseline controlled NOX emissions that North Dakota 
reported in the SIP are 2,967 tons per year with an emission rate of 
approximately 0.285 lb/MMBtu. The State identified the following 
control option combinations for BART:
     Selective catalytic reduction (SCR).
     Electro-catalytic oxidation (ECO).
     Selective non-catalytic reduction (SNCR).
     Hydrocarbon enhanced SNCR (HE-SNCR).
     Rich reagent injection (RRI).
     Rotomix (ROFA + SNCR).
     Conventional gas reburn (CGR).
     CGR + SNCR with SOFA.
     Coal reburn.
     Coal reburn + SNCR.
     Fuel-lean gas reburn (FLGR).
     FLGR + SNCR.
     Rotating overfire air (ROFA).
     Separated overfire air (SOFA).
     New low NOX burners (LNB).
     Combustion improvements.
    The State agreed with Basin Electric's determination that high dust 
SCR is not technically feasible but found that low-dust SCR (LDSCR) and 
tail-end SCR (TESCR) would be technically feasible. North Dakota also 
identified ECO, coal reburn plus SNCR, and RRI as technically 
infeasible for Unit 1. The State determined the average cost 
effectiveness of the four most efficient options to be excessive with 
estimates ranging from $4,400 to $13,600 per ton of NOX 
removed. The State also determined the incremental costs of these 
options to be excessive with estimates ranging from $12,500 to $80,700. 
North Dakota discussed the benefits of pilot testing and based its 
acceptance of cost estimates provided by Basin Electric on the 
inability to mandate pilot testing in the BART process. The State noted 
that EPA, in the BART Guidelines, established a presumptive 
NOX emission limit of 0.29 lb/MMBtu for this type of boiler. 
The State determined that there were no energy and non-air quality 
environmental impacts that would preclude the selection of any of the 
control equipment alternatives. A summary of the State's NOX 
BART analysis for Unit 1 is provided in Table 17.

[[Page 58593]]

                                      Table 17--Summary of Leland Olds Station NOX BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR Low Dust.......................................................               80            0.057            2,374      18.63-26.86     7,849-11,313
SCR Tail End.......................................................               80            0.057            2,374      21.51-31.01     9,061-13,628
Coal Reburn + Boosted SOFA.........................................             48.7            0.146            1,445             7.03            4,866
Coal Reburn + SOFA.................................................             46.2            0.153            1,371             5.98            4,364
SNCR + Boosted SOFA................................................             45.1            0.156            1,338             3.82            2,854
SNCR + Basic SOFA..................................................             42.0            0.165            1,246             3.10            2,487
SNCR + Close Coupled OFA...........................................             24.5            0.215              727             3.36            4,623
Boosted SOFA.......................................................             24.3            0.216              721             1.14            1,577
SOFA...............................................................             19.4            0.230              576             0.14              250
--------------------------------------------------------------------------------------------------------------------------------------------------------

    North Dakota determined BART to be SNCR + basic SOFA with an 
emission limit of 0.19 lb/MMBtu (30-day rolling average). The estimated 
average cost effectiveness for SNCR + SOFA was $2,487 per ton of 
NOX removed, and the capital and annualized costs were 
estimated to be $6,234,000 and $3,099,000 per year, respectively.
    Basin Electric did not provide the modeled visibility impacts of 
SNCR + basic SOFA for Unit 1 individually. Instead, for this control 
option, Basin Electric provided the visibility impacts for Unit 1 and 
Unit 2 combined, with the emissions from Unit 2 held constant. The 
resulting visibility improvement, when compared to no controls at Unit 
1, is estimated to be 0.160 deciviews at Theodore Roosevelt.
    We are proposing to approve the State's NOX BART 
determination for Leland Olds Station Unit 1. Based on our review of 
North Dakota's submission, we are proposing to find that it was 
reasonable for the State to eliminate higher performing control options 
and select SNCR + basic SOFA as BART with an emission limit of 0.19 lb/
MMBtu (30-day rolling average). Three of the other controls under 
consideration--Coal Reburn + Boosted SOFA, Coal Reburn + SOFA, and SNCR 
+ Boosted SOFA--would provide minimal additional reductions of 
NOX, (and presumably relatively small improvements in 
visibility), but have higher dollar per ton values. The incremental 
costs of these options compared to SNCR + basic SOFA are relatively 
high. We note that we do not agree with the State's cost analysis for 
SCR, but nonetheless find the elimination of SCR for this unit to be 
acceptable. As we explain in greater detail in section V.D.1.d below, 
Basin Electric deviated significantly from EPA's control cost manual 
when it estimated costs for SCR for Leland Olds Station Unit 2, and 
substantially overestimated the costs for SCR. The State relied on 
Basin Electric's estimates of the costs for SCR for Unit 2 when it 
estimated the costs for SCR for Unit 1. Thus, we anticipate that the 
State's estimate for Unit 1 also overestimates the costs for SCR. 
Nonetheless, Unit 1 is relatively small compared to Milton R. Young 
Station Units 1 and 2 and Leland Olds Station Unit 2 and has 
substantially lower baseline NOX emissions. And, unlike 
those units, Unit 1 is not a cyclone boiler and so is currently fitted 
with low-NOX burners. Finally, North Dakota has selected an 
emission limit--0.19 lb/MMBtu--based on the use of post-combustion 
controls (SNCR) and combustion controls, that is substantially more 
stringent than the presumptive BART limit for this type of boiler. This 
emission limit represents an adjustment of the annual rate since the 
30-day rolling average is expected to be 5-15% higher. These controls 
will achieve a reduction in NOX emissions of about 1,246 
tons per year. Based on these factors, we are proposing to approve 
North Dakota's NOX BART determination.
    Filterable PM BART Review: Unit 1 is equipped with an ESP rated at 
approximately 99% control efficiency. The baseline controlled PM 
emissions that North Dakota reported in the SIP are 219 tons per year 
with an emission rate of approximately 0.040 lb/MMBtu. The State 
evaluated the following PM control options for BART and found all to be 
technically feasible: A new baghouse; a new ESP; and a CoHPAC. North 
Dakota considered the cost effectiveness for all three options to be 
excessive with the least expensive option being CoHPAC at an average 
cost effectiveness of $11,947 per ton of PM removed. North Dakota 
stated there would be negligible visibility improvement with additional 
controls. The State proposed BART to be no additional controls with an 
emission limit of 0.07 lb/MMBtu (average three test runs). A summary of 
the State's PM BART analysis for Unit 1 is provided in Table 18.

                                       Table 18--Summary of Leland Olds Station PM BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              224             3.26           15,554
New ESP............................................................           99.7              0.013              207             2.63           12,705
CoHPAC.............................................................           99.7              0.013              207             2.47           11,947
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Condensable PM (PM10) Review: Sulfuric acid mist is the 
largest component of condensable PM. The options for controlling 
sulfuric acid mist are the same as the options for controlling 
SO2; therefore, North Dakota determined that BART for 
condensable PM is good SO2 control. The State determined 
that ongoing good combustion controls and the BART limit for 
SO2 would also constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART 
determination for Leland Olds Station Unit 1. The wet scrubber required 
for SO2 BART will substantially reduce sulfuric acid mist, 
which is the largest

[[Page 58594]]

component of condensable PM. North Dakota reasonably determined that 
the costs of additional condensable PM controls would be excessive 
given the negligible improvement in visibility that would result.
Unit 2 Boiler
    SO2 BART Review: Unit 2 has no existing SO2 
control system. The baseline uncontrolled SO2 emissions that 
North Dakota reported in the SIP are 67,858 tons per year with an 
emission rate of approximately 3.02 lb/MMBtu. The State identified the 
following as potential control options: new wet scrubber, spray dryer, 
circulating dry scrubber, flash dryer absorber, Powerspan ECO, fuel 
switching, and coal cleaning. Powerspan ECO and coal cleaning were 
determined to be technically infeasible. A summary of the State's 
SO2 BART analysis for Unit 2, and visibility impacts derived 
from modeling conducted by the source, are provided in Table 19.

                                      Table 19--Summary of Leland Olds Station SO2 BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                               Visibility impacts1 2
                                                                            Emissions                          Cost      -------------------------------
             Control option                  Control      Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)          benefit      Fewer days  >
                                                                                                                            (delta dv)     0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber...........................              95            0.15          64,465           29.84              463           3.479              89
Circulating Dry Scrubber...............              93            0.21          63,108           35.58              564  ..............  ..............
Spray Dryer............................              90            0.30          61,072           32.89              539  ..............  ..............
Flash Dryer Absorber...................              90            0.30          61,072           32.43              531  ..............  ..............
Fuel Switching.........................              77            0.69         <52,251           13.49              258  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Basin Electric modeled combined SO2 and NOX controls. The results shown include the noted SO2 control option and NOX at the SOFA emission rate.
  Given that the NOX emission rate with SOFA is somewhat close to the pre-control NOX rate, the visibility impacts shown are largely due to the
  reduction in SO2 emissions and not the reduction in NOX emissions.

    North Dakota determined BART to be the most efficient control 
option, a wet scrubber operating at 95% control efficiency or below an 
emission limit of 0.15 lb/MMBtu (30-day rolling average). Basin 
Electric would have to comply with either the 95% reduction requirement 
or the 0.15 lb/MMBtu limit, but not both. The estimated average cost 
effectiveness of a wet scrubber was $463 per ton of SO2 
removed, and the capital and annualized costs were estimated to be 
$147,600,000 and $29,840,000 per year, respectively.
    We are proposing to approve the State's SO2 BART 
determination for Leland Olds Station Unit 2. The State's assessment of 
costs and other impacts was reasonable. The wet scrubber represents a 
stringent level of control and will result in a reduction in annual 
SO2 emissions from the plant of approximately 64,465 tons. 
When modeled with modest NOX reductions assumed for SOFA, 
the maximum improvement is estimated to be 3.479 deciviews and 89 fewer 
days above 0.5 deciviews at Theodore Roosevelt.
    Filterable PM BART Review: Unit 2 is equipped with an ESP rated at 
approximately 99% control efficiency. The baseline controlled PM 
emissions that North Dakota reported in the SIP are 627 tons per year 
with an emission rate of approximately 0.034 lb/MMBtu. The State 
evaluated the following PM control options for BART and found all to be 
technically feasible: A new baghouse; a new ESP; and a CoHPAC. North 
Dakota considered the average cost effectiveness for all three options 
to be excessive, with the least expensive option being CoHPAC at 
$12,000 per ton. The average PM emission rate for 2000-2004 was 0.025 
lb/MMBtu. The State noted that eliminating all PM emissions would 
result in a visibility impact of only 0.026 deciviews. The State 
established BART as no additional controls and the existing permitted 
emission limit of 0.07 lb/MMBtu (average three test runs). A summary of 
the State's PM BART analysis for Unit 2 is provided in Table 20.

                                       Table 20--Summary of Leland Olds Station PM BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Emissions                            Cost
                           Control option                                Control       Emission rate      reduction     Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)       (tons/yr)          (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              388             5.89           15,186
New ESP............................................................           99.7              0.015              350             4.95           14,137
CoHPAC.............................................................           99.7              0.015              350             4.21           12,029
Baseline...........................................................           99.3              0.034  ...............  ...............  ...............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We are proposing to approve the State's filterable PM BART 
determination for Leland Olds Station Unit 2. The State's assessment of 
costs and other impacts was reasonable. Existing controls, ESP, already 
reduce PM emissions by approximately 99%, and North Dakota reasonably 
determined that the costs of additional PM controls would be excessive 
given the negligible improvement in visibility that would result.
    Condensable PM (PM10) Review: Sulfuric acid mist is the 
largest component of condensable PM. The options for controlling 
sulfuric acid mist are the same as the options for controlling 
SO2; therefore, North Dakota determined that BART for 
condensable PM is good SO2 control. The State determined 
that ongoing good combustion controls and the BART limit for 
SO2 would also constitute BART for condensable PM.

[[Page 58595]]

    We are proposing to approve the State's condensable PM BART 
determination for Leland Olds Station Unit 2. The wet scrubber required 
for SO2 BART will substantially reduce sulfuric acid mist, 
which is the largest component of condensable PM. North Dakota 
reasonably determined that the costs of additional condensable PM 
controls would be excessive given the negligible improvement in 
visibility that would result.
Auxiliary Boiler, Emergency Fire Pump, and Material Handling and 
Fugitive Sources
    The State analyzed and determined BART for these small emissions 
sources at the plant and determined that BART is existing controls with 
no additional controls. The State based its conclusion on the fact that 
further controls would not be cost effective and would have virtually 
no impact on visibility. For further detail, see the State's BART 
analysis.
    We agree with the State's conclusion and are proposing to approve 
its BART determination for these sources.
e. North Dakota BART Results and Summary
    We have summarized North Dakota's BART determinations that we are 
proposing to approve in Table 21 for SO2 and Table 22 for 
NOX, below. We have not summarized the information for PM as 
it has relatively low impact on visibility.
    North Dakota's Regional Haze Rule requires each source subject to 
BART to install and operate BART no later than 5 years after we approve 
this Regional Haze SIP. NDAC 33-15-25-02.2. This satisfies the 
requirement under 40 CFR 51.308(e)(1)(iv), that ``each source subject 
to BART be 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.''
    As noted previously, to be approvable, the Regional Haze SIP must 
include monitoring, recordkeeping, and reporting requirements to ensure 
that the BART limits are enforceable. North Dakota has included 
individual source permits in its Regional Haze SIP that contain such 
requirements. See SIP Appendix D. We have reviewed these requirements 
and find them to be adequate as they relate to the BART limits we are 
proposing to approve. In particular, for SO2 and 
NOX BART limits, the permits require the use of continuous 
emission monitoring systems (CEMS) to determine compliance, generally 
in accordance with 40 CFR part 75. For the filterable PM BART limits, 
the permits require stack testing and compliance with a compliance 
assurance monitoring (CAM) plan. Adequate recordkeeping and reporting 
requirements are also specified.
    For the reasons discussed above, we propose to find that, with the 
exception of the NOX BART determinations for Milton R. Young 
Station Units 1 and 2, Leland Olds Station Unit 2, and Coal Creek Units 
1 and 2, North Dakota satisfied the BART requirements of 40 CFR 
51.308(e).

                              Table 21--North Dakota BART Determinations for SO2 Emissions that EPA is Proposing to Approve
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  BART level
                                        2000-2004     Baseline    of control                            Emissions     Emission
           Source and unit               average      level of        (%           Control device         after      reduction        Emission limit
                                        emissions    control (%   reduction)                             controls   (tons/yr) 2
                                        (tons/yr)    reduction)       1                                 (tons/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Basin Electric Power Cooperative, LOS       16,666            0           95  New Wet Scrubber.......        1,376       15,290  95% reduction or 0.15
 Unit 1.                                                                                                                          lb/MMBtu, 30-day
                                                                                                                                  rolling average.
Basin Electric Power Cooperative,           30,828            0           95  New Wet Scrubber.......        2,530       28,298  95% reduction or 0.15
 Leland Olds Station Unit 2.                                                                                                      lb/MMBtu, 30-day
                                                                                                                                  rolling average.
Great River Energy, Coal Creek              14,086           68           95  Modified Existing Wet          3,781       10,305  95% reduction or 0.15
 Station Unit 1.                                                               Scrubber and Coal                                  lb/MMBtu, 30-day
                                                                               Dryer.                                             rolling average.
Great River Energy, Coal Creek              12,407           68           95  Modified Existing Wet          3,621        8,786  95% reduction or 0.15
 Station Unit 2.                                                               Scrubber and Coal                                  lb/MMBtu, 30-day
                                                                               Dryer.                                             rolling average.
Great River Energy, Stanton Station          8,312            0           90  New Spray dryer and            1,179        7,133  90% reduction or 0.24
 Unit 1.                                                                       Fabric Filter.                                     lb/MMBtu (lignite), or
                                                                                                                                  0.16 lb/MMBtu (PRB) 30-
                                                                                                                                  day rolling average.
Minnkota Power Cooperative, MRYS Unit       20,148            0           95  New Wet Scrubber.......        1,007       19,141  95% reduction, 30-day
 1.                                                                                                                               rolling average.
Minnkota Power Cooperative, MRYS Unit       12,404           65           95  Modified Existing Wet          2,739        9,665  95% reduction, or 0.15
 2.                                                                            Scrubber.                                          lb/MMBtu, 30-day
                                                                                                                                  rolling average. Also,
                                                                                                                                  90% reduction.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Based on two-year baseline emission rate for BART.
\2\ Based on the average 2000-2004 operating rate.

[[Page 58596]]

                              Table 22--North Dakota BART Determinations for NOX Emissions That EPA Is Proposing to Approve
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  BART level
                                        2000-2004     Baseline    of control                            Emissions     Emission
           Source and unit               average     level  of        (%           Control device         after      reduction        Emission limit
                                        emissions    control (%   reduction)                             controls   (tons/yr) 2
                                        (tons/yr)    reduction)       1                                 (tons/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Stanton Unit 1.......................        2,048            0           45  LNB, Overfire Air and          1,425          623  0.29 lb/106 Btu, 30-day
                                                                               SNCR.                                              rolling average.
Leland Olds Unit 1...................        2,501            0           42  SOFA and SNCR..........        1,744          757  0.19 lb/106 Btu, 30-day
                                                                                                                                  rolling average.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Based on two-year baseline emission rate for BART.
\2\ Based on the average 2000-2004 operating rate.

D. Evaluation of North Dakota's NOX BART Determinations for 
Milton R. Young Station Units 1 and 2, Leland Olds Station Unit 2, and 
Coal Creek Station Units 1 and 2

    The discussion below is limited to the NOX BART 
assessments for Milton R. Young Station Units 1 and 2, Leland Olds 
Station Unit 2, and Coal Creek Units 1 and 2. North Dakota's other BART 
assessments are covered in Section V.C.3, above.
1. Milton R. Young Station Units 1 and 2 and Leland Olds Station Unit 2
a. Milton R. Young Station Unit 1--State Analysis
    At the time Minnkota made its BART submittal upon which the State 
based its analysis, Milton R. Young Station Unit 1 had no existing 
NOX control system. The baseline uncontrolled NOX 
emissions that North Dakota reported in the SIP are 9,032 tons per year 
per unit with an emission rate of 0.849 lb/MMBtu. The Minnkota consent 
decree, discussed in section V.C.3.c, above, required Minnkota to 
install OFA on Unit 1 by December 31, 2009.
    The State has asserted that the Milton R. Young Station units do 
not exceed the 750 MW threshold for mandatory application of the BART 
guidelines and the presumptive NOX BART limits. That 
presumptive limit for a cyclone unit greater than 200 MW burning 
lignite is 0.10 lb/MMBtu. To reach its conclusion, North Dakota relied 
on the nameplate capacity of the units. We propose to disagree based on 
the fact that the actual operating levels for Units 1 and 2 are 277 MW 
and 517 MW, respectively--i.e., in excess of their nameplate 
capacities.\18\ The sum of these permitted levels results in a total 
generating capacity of at least 794 MW, which is above the 750 MW 
capacity threshold established by the CAA and the Regional Haze Rule 
(see 40 CFR 51.308(e)(ii)(B)). We also note that the State's regional 
haze regulations, at NDAC 33-15-25-03, require that facility owners or 
operators for whom the guidelines are not mandatory ``shall use 
appendix y [EPA's BART Guidelines] as guidance for preparing their best 
available control retrofit technology determinations.'' \19\
---------------------------------------------------------------------------

    \18\ See letter from John T. Graves, Environmental 
Superintendent, Minnkota Power Cooperative, Inc., to Dana Mount, 
Director, Division of Environmental Engineering, North Dakota 
Department of Health, Re: Permit to Operate No. F76009, Permit 
Revisions, November 20, 1995.
    \19\ We are proposing to approve the State's regional haze 
regulations as part of this action.
---------------------------------------------------------------------------

    The State identified the following as potential control options: 
SCR, ECO, SNCR, HE-SNCR, RRI, Rotomix (ROFA + SNCR), CGR, CGR + SNCR + 
SOFA, coal reburn, coal reburn + SNCR, FLGR, FLGR + SOFA, ROFA, SOFA, 
advanced separated overfire air (ASOFA), combustion improvements 
(included with SOFA and ASOFA), and oxygen enhanced combustion (OEC). 
The State eliminated the following from further consideration as 
technically infeasible: High dust SCR, ECO, HE-SNCR, RRI, Rotomix (ROFA 
+ SNCR), CGR + SNCR, coal reburn + SNCR, FLGR + SNCR, and OEC.
    A summary of the State's analysis for NOX BART 
alternatives, and modeling results provided by both the source and 
State are provided in Table 23 for Unit 1.

                                    Table 23--Summary of Milton R. Young Station NOX BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts 1 2
                                                                             Emissions                         Cost      -------------------------------
             Control option                   Control      Emission rate     reduction      Annualized     effectiveness    Visibility
                                          efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)     benefit (delta   Fewer days  >
                                                                                                                                dv)        0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LDSCR + ASOFA...........................              90           0.085           8,129     33.53-52.19     4,124-6,421           3.476             114
TESCR + ASOFA...........................              90           0.085           8,129     39.31-56.10     4,835-6,901           3.476             114
SNCR + ASOFA............................            58.1           0.355           5,248            7.47           1,424           2.923              96
Gas Reburn + ASOFA......................              56           0.374           5,058           37.33           7,381  ..............  ..............
Coal Reburn + ASOFA.....................            54.6           0.385           4,931           11.39           2,309  ..............  ..............
FLGR + ASOFA............................            45.9           0.460           4,146           16.99           4,098  ..............  ..............
ASOFA...................................            39.5           0.513           3,568            2.49             698  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Minnkota and the State modeled combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of SO2 scrubbing along
  with the noted NOX control option. More detail on this approach is provided in the Technical Support Document.

    The State determined that the cost of all control options was 
reasonable with the exception of both SCR configurations. The State 
considered the average cost effectiveness and incremental cost 
effectiveness of LDSCR

[[Page 58597]]

and TESCR to be excessive and unreasonable. These control options, when 
combined with wet scrubbing for SO2, would result in a 
significant improvement in visibility at Theodore Roosevelt, estimated 
to be 3.476 deciviews and 114 fewer days above 0.5 deciviews. This 
represents an incremental visibility improvement of 1.400 deciviews and 
43 fewer days above 0.5 deciviews beyond that achieved by wet scrubbing 
alone. Moreover, when compared to SNCR + ASOFA, it would result in an 
incremental visibility improvement of 0.553 deciviews and 18 fewer days 
above 0.5 deciviews. However, the State also stated that single source 
visibility benefits calculated using the EPA modeling guidelines are 
inflated and conducted supplemental cumulative visibility modeling 
(i.e., modeling using degraded background, reflecting emissions from 
all sources). The results of the State's supplemental cumulative 
modeling showed greatly reduced visibility benefits from use of SCR, 
benefits that the State considered to be negligible. The State 
determined that there were no energy and non-air quality environmental 
impacts that would preclude the selection of any of the control 
equipment alternatives. North Dakota determined BART to be SNCR + ASOFA 
(the next most efficient option after SCR), with an emission limit of 
0.36 lb/MMBtu (30-day rolling average) and a separate limit during 
startup of 2070.2 lb/hr (24-hour rolling average). North Dakota 
estimated the cost effectiveness for SNCR + ASOFA to be $1,424 per ton 
of NOX removed, and the capital and annualized costs to be 
$8,113,000 and $7,742,000 per year, respectively.
b. Milton R. Young Station Unit 2--State Analysis
    At the time Minnkota made its BART submittal upon which the State 
based its analysis, Milton R. Young Station Unit 2 was equipped with an 
OFA NOX control system. The baseline controlled 
NOX emissions that North Dakota reported in the SIP were 
15,507 tons per year per unit with an emission rate of approximately 
0.81 lb/MMBtu. The State identified the following as potential control 
options: SCR, ECO, SNCR, HE-SNCR, ASOFA, RRI + SNCR + ASOFA, Rotomix 
(ROFA + SNCR), CGR + SNCR, coal reburn, coal reburn + SNCR, FLGR, FLGR 
+ SOFA, ROFA, SOFA, ASOFA, combustion improvements, and OEC. The State 
eliminated the following from further consideration as technically 
infeasible: High dust SCR, ECO, HE-SNCR, RRI, Rotomix (ROFA + SNCR), 
CGR + SNCR, coal reburn + SNCR, FLGR + SNCR, and OEC. A summary of the 
State's analysis for NOX BART alternatives, and modeling 
results provided by both the source and State, are provided in Table 24 
for Unit 2.

                                    Table 24--Summary of Milton R. Young Station NOX BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts 1 2
                                                                            Emissions                          Cost      -------------------------------
            Control option                  Control       Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)      benefit (delta   Fewer  days >
                                                                                                                                dv)        0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LDSCR + ASOFA.........................             90             0.079          13,956     57.35-89.07      4,109-6,382           3.945             110
TESCR + ASOFA.........................             90             0.079          13,956     66.51-98.81      4,765-7,081           3.945             110
SNCR + ASOFA..........................             58.0           0.330           8,994           11.41            1,268           3.379              89
Gas Reburn + ASOFA....................             55.4           0.350           8,591           63.88            7,436  ..............  ..............
Coal Reburn + ASOFA...................             54.2           0.360           8,405           19.48            2,317  ..............  ..............
FLGR + ASOFA..........................             45             0.432           6,978           29.31            4,201  ..............  ..............
ASOFA.................................             37.7           0.489           5,846            4.38              749  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ Minnkota and the State conducted the modeling with combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of
  SO2 scrubbing along with the noted NOX control option.

    The State determined the average cost effectiveness of all control 
options was reasonable with the exception of both SCR configurations. 
The State considered the average cost effectiveness and incremental 
cost effectiveness of LDSCR and TESCR to be excessive and unreasonable. 
These control options, when combined with wet scrubbing for 
SO2, would result in a significant improvement in visibility 
at Theodore Roosevelt National Park--estimated to be 3.945 deciviews 
and 110 fewer days above the 0.5 dv threshold. This represents an 
incremental visibility improvement of 2.318 deciviews and 58 fewer days 
above the 0.5 dv threshold beyond that achieved by wet scrubbing alone. 
Moreover, when compared to SNCR + ASOFA, SCR + ASOFA would result in an 
incremental visibility improvement of 0.566 deciviews and 21 fewer days 
above the 0.5 dv threshold. However, using the same approach it used 
for Milton R. Young Station Unit 1, the State determined that the 
visibility benefits from use of SCR would be negligible. The State 
determined that there were no energy and non-air quality environmental 
impacts that would preclude the selection of any of the control 
equipment alternatives. North Dakota determined BART to be SNCR + ASOFA 
(the next most efficient option after SCR), with an emission limit of 
0.35 lb/MMBtu (30-day rolling average) and a separate limit during 
startup of 3,995.6 lb/hr (24-hour rolling average). The State estimated 
the cost effectiveness for SNCR + ASOFA to be $1,268 per ton of 
NOX removed, and the capital and annualized costs to be 
$17,128,000 and $11,405,000 per year, respectively.
c. Leland Olds Station Unit 2--State Analysis
    At the time Basin Electric made its BART submittal upon which the 
State based its analysis, Unit 2 had no existing NOX control 
system. ASOFA was installed in November 2009. The State identified the 
following as potential control options: SCR, ECO, SNCR, HE-SNCR, ASOFA, 
RRI + SNCR + ASOFA, Rotomix (ROFA + SNCR), CGR + SNCR, coal reburn, 
coal reburn + SNCR, FLGR, SOFA, ASOFA, ROFA, combustion improvements, 
and OEC. The State eliminated the following from further consideration 
as technically infeasible: High dust SCR, ECO, HE-SNCR, Rotamix, CGR + 
SNCR, coal

[[Page 58598]]

reburn + SNCR, FLGR + SNCR, and OEC.
    A summary of the State's analysis for NOX BART 
alternatives, and modeling results provided by both the source and 
State are provided in Table 25 for Unit 2.

                                      Table 25--Summary of Leland Olds Station NOX BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts 1 2
                                                                            Emissions                          Cost      -------------------------------
            Control option                  Control       Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)      benefit (delta   Fewer days  >
                                                                                                                                dv)        0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low Dust SCR + ASOFA..................             90             0.07           10,821     38.74-55.84      3,581-5,161           4.393             130
Tail End SCR + ASOFA..................             90             0.07           10,821     43.83-63.17      4,050-5,838           4.393             130
RRI + SNCR + ASOFA....................             60.3           0.266           7,250            17.4            2,400           3.963             110
SNCR + ASOFA..........................             54.5           0.305           6,553           10.87            1,659           3.874             105
Coal Reburn + ASOFA...................             51.8           0.323           6,228           14.86            2,386  ..............  ..............
ASOFA.................................             37.7           0.482           3,366            1.24              369           3.479              89
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.
\2\ The visibility modeling that North Dakota (for SCR) and Basin Electric (all scenarios but SCR) performed for Leland Olds Station Unit 2 included SO2
  control (FGD 95%) in addition to the noted NOX control. Thus, these values do not reflect the distinct visibility benefit from the NOX control options
  but do provide the incremental benefit between the options.

    The State determined that the average and incremental cost 
effectiveness of SCR + ASOFA was excessive given its finding that 
visibility improvement would be negligible. SCR + ASOFA, when combined 
with wet scrubbing for SO2 would result in a significant 
improvement in visibility at Theodore Roosevelt, estimated to be 4.393 
deciviews and 130 fewer days above 0.5 deciviews. As the State did not 
provide discrete modeling for individual pollutants, it is not possible 
to describe the incremental visibility benefits of SCR + ASOFA or other 
NOX control options over the selected SO2 BART 
control (FGD at 95%). Nonetheless, when compared to SNCR + ASOFA, SCR 
would result in an incremental visibility improvement of 0.512 
deciviews and 25 fewer days above 0.5 deciviews. However, using the 
same supplemental cumulative modeling it used for Milton R. Young 
Station units 1 and 2, the State determined that visibility benefits 
from use of SCR + ASOFA would be negligible. While the State found that 
RRI + SNCR + ASOFA and SNCR + ASOFA both had reasonable average cost 
effectiveness values, it found the incremental costs for RRI + SNCR + 
ASOFA to be excessive given its finding that incremental visibility 
improvement would be negligible. By reference to its analysis for 
Leland Olds Station Unit 1, North Dakota noted the difficulty in 
accurately predicting costs for SCR based on alleged uncertainties 
regarding catalyst size and life. North Dakota accepted the cost 
estimates provided by Basin Electric. The State determined that there 
were no energy and non-air quality environmental impacts that would 
preclude the selection of any of the control equipment alternatives. 
North Dakota determined BART to be SNCR plus ASOFA with an emission 
limit of 0.35 lb/MMBtu (30-day rolling average). North Dakota estimated 
the cost for SNCR plus ASOFA to be $1,659 per ton of NOX 
removed, and the capital and annualized costs to be $16,800,000 and 
$10,870,000 per year, respectively.
    A summary of the pertinent information related to the State's 
NOX BART determinations for Milton R. Young Station Units 1 
and 2 and Leland Olds Station Unit 1 is provided in Table 26.

          Table 26--North Dakota BART Determinations for NOX Emissions for Milton R. Young Station Units 1 and 2 and Leland Olds Station Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        2000-2004     Baseline    BART level                            Emissions
                                         average      level of    of control                              after       Emission
           Source and unit              emissions    control (%       (%           Control device        controls    reduction        Emission limit
                                        (tons/yr)    reduction)   reduction)                            (tons/yr)    (tons/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
MRYS Unit 1..........................        8,665            0         58.1  ASOFA and SNCR.........        3,857        4,808  0.36 lb/106 Btu, 30-day
                                                                                                                                  rolling average.
MRYS Unit 2..........................       14,705            0           58  ASOFA and SNCR.........        6,392        8,313  0.35 lb/106 Btu, 30-day
                                                                                                                                  rolling average.
LOS Unit 2...........................       10,422            0         54.5  ASOFA and SNCR.........        5,904        4,518  0.35 lb/106 Btu, 30-day
                                                                                                                                  rolling average.
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 58599]]

d. EPA's Evaluation of the State's Cost Analyses for NOX 
BART for Milton R. Young Station Unit 1 and 2 and Leland Olds Station 
Unit 2
    As noted above, North Dakota found that the costs of SCR at Milton 
R. Young Station Units 1 and 2 and Leland Olds Station Unit 2 were 
excessive and eliminated it as a control option. We propose to find 
that North Dakota did not properly follow the requirements of 40 CFR 
51.308(e)(1)(ii)(A) in determining NOX BART for these units. 
Specifically, we propose that North Dakota did not properly or 
reasonably ``take into consideration the costs of compliance.'' 
Instead, North Dakota relied on facility-provided cost estimates that 
greatly overestimated the costs of SCR. Given that SCR is typically 
considered to be a highly cost-effective control option for power 
plants with cyclone boilers burning lignite, and that EPA selected a 
presumptive NOX limit for cyclone units of 0.10 lb/MMBtu 
based on the cost-effectiveness of SCR,\20\ we retained two consultants 
(ERG and RTI, subcontractor Dr. Phyllis Fox) to independently assess 
the costs of installing, operating, and maintaining these controls. 
These consultants found that numerous aspects of the cost estimates for 
SCR at these units, which the State relied on, were much higher than 
their estimates. Our consultants revised the cost analyses using EPA's 
Air Pollution Control Cost Manual,\21\ and where appropriate, costing 
assumptions used in the facility-provided analyses. Their revised 
analyses resulted in cost effectiveness values that are well within the 
range that North Dakota, other states, and we have found cost effective 
in the BART context. We have reviewed and evaluated our consultants' 
reports and agree with their findings regarding SCR at Milton R. Young 
Station Units 1 and 2 and Leland Olds Station Unit 2. Our consultants' 
reports have been incorporated into the Technical Support Document.\22\
---------------------------------------------------------------------------

    \20\ The BART Guidelines state, ``Because of the relatively high 
NOX emission rates of cyclone units, SCR is more cost-
effective than the use of current combustion control technology for 
these units. The use of SCRs at cyclone units burning bituminous 
coal, sub-bituminous coal, and lignite should enable the units to 
cost-effectively meet NOX rates of 0.10 lb/mmbtu. As a 
result, we are establishing a presumptive NOX limit of 
0.10 lb/mmbtu based on the use of SCR for coal-fired cyclone units 
greater than 200 MW located at 750 MW power plants.'' 40 CFR part 
51, appendix Y.
    \21\ U.S. EPA, EPA Air Pollution Control Cost Manual, EPA/452/B-
02-001, 6th Ed., January 2002. The EPA Air Pollution Control Cost 
Manual was formerly known as the OAQPS Control Cost Manual.
    \22\ Dr. Phyllis Fox, Revised BART Cost-Effectiveness Analysis 
for Tail End Selective Catalytic Reduction at Basin Electric Power 
Cooperative Leland Olds Station Unit 2. Report Prepared for U.S. 
EPA, RTI Project Number 0209897.004.095, March 2011.
    ERG Minnkota SCR Cost Summaries, May 2010 and August 2011 and 
EPA Region 8's Letter to Mr. Terry O'Clair dated May 10, 2010 
regarding ``EPA's Comments on the NDDH's [North Dakota's] April 2010 
Draft BACT Determination for NOX for the MRYS.''
---------------------------------------------------------------------------

    Table 27, below, contrasts North Dakota's low-end cost 
effectiveness values for tail end SCR (TESCR) at the three units with 
our estimates.\23\
---------------------------------------------------------------------------

    \23\ The facilities, and hence, North Dakota, presented a range 
of cost effectiveness values for low-dust and tail-end SCR based on 
the alleged uncertainties with estimating costs for SCR. A 
comparison of North Dakota's high-end cost estimates would reflect 
an even greater disparity with our cost estimates.

             Table 27--Contrast of TESCR Cost Effectiveness
------------------------------------------------------------------------
                                        North Dakota
                                       projected cost    EPA's projected
                Plant                    ($/ton NOX      cost ($/ton NOX
                                          removed)          removed)
------------------------------------------------------------------------
MRYS 1..............................            $4,800            $2,600
MRYS 2..............................             4,800             2,700
LOS 2...............................             4,100             1,800
------------------------------------------------------------------------

    Our Technical Support Document provides a detailed comparison 
between the costing methodologies. However, a few general points can be 
made that explain why our costs differ so dramatically from North 
Dakota's. Both North Dakota and we used the facilities' BART 
evaluations as the starting points for the assessments,\24\ and we 
largely relied on the facilities' direct capital equipment costs in our 
analyses.\25\ However, a major issue is that the companies used 
numerous indirect cost and other accounting mechanisms that are not 
included in EPA's Air Pollution Control Cost Manual (``Control Cost 
Manual'') and are not adequately justified. According to the BART 
Guidelines, ``cost estimates should be based on the OAQPS Control Cost 
Manual, where possible'' ``[i]n order to maintain and improve 
consistency.'' 70 FR 39104, 39166. The use of the Control Cost Manual 
provides a reasonable standard for comparison of costs between sources 
and across states, and the BART Guidelines indicate that documentation 
should be provided for ``any * * * element of the calculation that 
differs from Control Cost Manual.'' 70 FR 39166. Most of North Dakota's 
other BART determinations did follow the Control Cost Manual and 
properly provide a basis for comparison to other control equipment 
installations nationally.\26\ In preparing our cost analyses, we 
followed the Control Cost Manual where possible.
---------------------------------------------------------------------------

    \24\ Burns & McDonnell, BART Determination Study for Milton R. 
Young Station Unit 1 and 2, Prepared for Minnkota Power Cooperative, 
Inc., October 2006, Revised August 2007.
     Letter from Cris Miller, Senior Environmental Project 
Administrator, Basin Electric Power Cooperative, to Terry L. 
O'Clair, North Dakota Department of Health, Attaching Letter from 
William DePriest, Senior Vice President, Environmental Services, to 
Cris Miller, Re: BART Evaluation Update--Tail End SCR, May 27, 2009 
(5/27/09 S&L Cost Analysis).
    \25\ For a detailed discussion, the reader should refer to our 
consultants' reports in the Technical Support Document.
    \26\ SIP Appendix C.2, Great River Energy's Coal Creek BART 
Analysis, is an example of a cost analysis submitted to North Dakota 
as part of a BART submittal that does not include many of the 
indirect capital costs and contingencies included in Burns & 
McDonnell's analysis. Although EPA is not in agreement with every 
aspect of the cost analysis in the example, it does illustrate a 
case where the Control Cost Manual format is generally followed and 
the estimated SCR capital costs are far less (by a factor of almost 
4 for LDSCR on Unit 2, which is a smaller unit in comparison to the 
example and should cost less) than what was estimated for MRYS.
---------------------------------------------------------------------------

    In addition to deviating in significant and unjustified ways from 
the Control Cost Manual, the companies adopted unreasonable assumptions 
related to catalyst size and life, catalyst cost, and outage 
requirements for catalyst replacement. Our analyses replaced these 
unreasonable assumptions with reasonable ones.
    In the case of Minnkota's analyses for Milton R. Young Station 
Units 1 and 2, conducted by Minnkota's consultant, Burns & McDonnell, 
the estimated total capital costs are higher by a factor of about 1.8 
than would be calculated using the Control Cost Manual,

[[Page 58600]]

assuming the same base costs for direct capital costs.
    For indirect capital costs, Table 28 identifies the deviations from 
the Control Cost Manual in the Burns & McDonnell estimates.

  Table 28--Comparison of EPA Control Cost Manual and Burns & McDonnell
                        Indirect Capital Costs 27
------------------------------------------------------------------------
                                        Control cost
                                        manual (% of     B&McD analysis
            Indirect cost              direct cap cost  (% of direct cap
                                           ``A'')          cost ``A'')
------------------------------------------------------------------------
General Facilities (Construction              0.05 x A          0.04 x A
 Mgt)...............................
Engineering & Home Office Fees......          0.10 x A          0.15 x A
Startup Expenses....................                 0          0.02 x A
Process Contingency (Scope                    0.05 x A          0.15 x A
 Contingency).......................
Project Contingency (Pricing                  0.18 x A          0.15 x A
 Contingency).......................
                                     -----------------------------------
    Totals..........................          0.38 x A          0.51 x A
------------------------------------------------------------------------

    While this difference is significant, Burns & McDonnell then added 
two more contingencies (``cost escalation during project'' and 
``owner's costs--other'') and included an allowance for funds during 
construction (interest) before calculating the total capital 
investment. The Control Cost Manual allows for ``preproduction costs'' 
of 2% of the sum of the direct capital costs, indirect capital costs, 
and ``project contingency.'' Table 29 below compares these ``other'' 
costs used by Burns & McDonnell to the preproduction costs provided by 
the Control Cost Manual. To normalize these costs with those tabulated 
above, percentages were related back to the direct capital costs 
(``A'').\28\
---------------------------------------------------------------------------

    \27\ Although, Burns & McDonnell stated in its December 11, 2010 
submittal to the State that its BACT cost estimates ``follow the 
outline of Table 2.5 in the SCR Chapter of EPA's Control Cost 
Manual,'' many items do not match in description, so some 
assumptions had to be made. Where there are differences, the Burns & 
McDonnell cost title is in parentheses. Also, this comparison 
assumes that ``project contingency'' of 15% is part of the indirect 
costs, so when applied exclusively to the direct capital costs only, 
it becomes 18%.
    \28\ Preproduction costs are listed as being 2% of the total 
direct (A), indirect (B), and ``project contingency'' (C) costs. 
This becomes 3% of the total direct capital costs. (B = 0.20 * A; C 
= 0.18 * A; A + B + C = 1.38 A; 0.02 * 1.38 A = 0.03).

    Table 29--Comparison of EPA Control Cost Manual & B&McD ``Other''
                              Capital Costs
------------------------------------------------------------------------
                                        Control cost
                                        manual (% of     B&McD analysis
             Other costs               direct cap cost  (% of direct cap
                                           ``A'')          cost ``A'')
------------------------------------------------------------------------
Cost Escalation.....................                 0          0.30 x A
Allowance for Funds During                           0          0.20 x A
 Construction (Interest During
 Construction)......................
Preproduction Costs.................          0.03 x A                 0
Owners Cost--Other (Owner                            0          0.17 x A
 Contingency).......................
                                     -----------------------------------
    Totals..........................          0.03 x A          0.67 x A
------------------------------------------------------------------------

    From these tables, it is clear that Burns & McDonnell included 
contingencies and accounting items that deviate significantly from the 
Control Cost Manual and which it did not justify by reference to any 
need unique to Milton R. Young Station. Although North Dakota asked 
Burns & McDonnell to provide a detailed explanation regarding its high 
indirect capital cost estimates, Burns & McDonnell's February 11, 2010, 
response to this request (see SIP Appendix C.4) fails to justify why 
the Burns & McDonnell cost methodology should be allowed for the Milton 
R. Young Station analysis, when it is not part of the Control Cost 
Manual and is not the standardized methodology used by other sources.
    While the Control Cost Manual does contemplate some flexibility in 
some contingencies (such as degree of retrofit difficulty), Burns & 
McDonnell has not substantiated the need to go beyond standard 
contingencies provided by the Control Cost Manual. As stated in the 
Control Cost Manual, ``[c]ontingencies is a catch-all category that 
covers unforeseen costs that may arise, such as possible redesign and 
modification of equipment, escalation increases in cost of equipment, 
increase in field labor costs, and delays encountered in start-up.'' 
\29\ Thus, the contingency in the Control Cost Manual should already 
account for possible changes in labor costs, and inclusion of a 
contingency plus escalation of costs is redundant according to the 
Control Cost Manual methodology. Escalation of costs should not be 
included as a separate estimate in the estimate of Total Capital 
Investment since it is included as part of the contingency estimate.
---------------------------------------------------------------------------

    \29\ See Control Cost Manual, 2002, Chapter 2, Section 2.3.1.
---------------------------------------------------------------------------

    Also, in Table 2.5 of the SCR chapter of the Control Cost Manual, 
the ``Allowance for Funds During Construction'' (inflation) is 
specifically listed as zero. Therefore, Burns & McDonnell should not 
have added what amounts to 20% of the direct capital costs to cover 
inflation. Including ``owner's costs'' and ``owner's contingency'' is 
also not consistent with the Control Cost Manual methodology and 
appears to be redundant.
    Burns & McDonnell mentioned that it anticipated that significant 
retrofit work would be required that would affect the scope and price 
of the project. However, there have been many SCR retrofits facing much 
more difficult challenges with space limitations and boiler 
modifications than Milton R. Young Station can be expected to face 
installing a LDSCR or TESCR

[[Page 58601]]

downstream of the ESP (or flue gas desulfurization system (FGD)) in a 
rural location. Thus, we find that Burns & McDonnell's contingencies 
for extra retrofit work are not warranted. Instead, we find that the 
contingencies outlined in the Control Cost Manual (5% process 
contingency and 15% project contingency) are reasonable for purposes of 
the Milton R. Young Station NOX BART analyses.
    Our estimate of total installed capital costs with adjusted 
indirect capital costs for TESCR at Milton R. Young Station Unit 1 is 
$120,629,000 in 2009 dollars, compared to Burns & McDonnell's estimate 
of $192,830,000. For Unit 2 our estimate is $216,870,000 and Burns & 
McDonnell's is $329,150,000.
    When it calculated annual costs for SCR at Milton R. Young Station, 
Burns & McDonnell also deviated from the Control Cost Manual without 
reasonable justification and relied on unreasonable operation and 
design assumptions. For example, the Control Cost Manual provides an 
annual maintenance factor of 1.5% of the total capital investment. 
Burns & McDonnell assumed 3%. The Control Cost Manual does not allow 
annual operation and maintenance costs to be ``levelized''--i.e., 
adjusted based on predicted future inflation and other factors. Burns & 
McDonnell levelized these costs, which increased them by about 25%. The 
reason the Control Cost Manual does not use levelized costs is to 
ensure that cost comparisons are made on a current real dollar basis, 
relying on the most accurate information available at current prices. 
(See, Control Cost Manual, Section 1, chapter 1, p. 1-3, footnote 1, 
and Section 4.2, Chapter 2, p. 2-50, example problem.)
    Regarding operation and design assumptions, Burns & McDonnell 
assumed that the SCR catalyst might have to be replaced as frequently 
as three or four times per year. Given that catalyst poisons will be 
removed by the ESP, or ESP and SO2 controls, before reaching 
the SCR in a low-dust or tail-end configuration, Burns & McDonnell's 
assumption about catalyst replacement is unreasonable. While Burns & 
McDonnell's low-end SCR cost numbers are based on a two-year frequency 
for catalyst replacement, our consultants find that a three-year 
frequency is the most reasonable assumption.\30\ Burns & McDonnell also 
used unreasonable assumptions related to catalyst cost and necessary 
outage time and related electricity costs for catalyst replacement. For 
example, Burns & McDonnell failed to consider that catalyst replacement 
could occur during outages already occurring at the plant. Our 
Technical Support Document contains additional details regarding the 
flaws in Burns & McDonnell's analysis.
---------------------------------------------------------------------------

    \30\ Report of Hans Hartenstein: On North Dakota Department of 
Health's April 10, 2010 BACT Determination for Minnkota's M.R. Young 
Station, On Behalf of United States Department of Justice, April 
2010. Report of Phyllis Fox: Revised BART Cost Effectiveness 
Analysis for Tail-End Selective Catalytic Reduction at the Basin 
Electric Power Cooperative Leland Olds Station Unit 2 Final Report, 
March 2011.
---------------------------------------------------------------------------

    Burns & McDonnell's estimate for total annual costs for TESCR at 
Milton R. Young Station Unit 1 was $43,290,000; using the Control Cost 
Manual factors and other reasonable assumptions, our estimate is 
$24,176,000. Burns & McDonnell's estimate for Unit 2 was $73,245,000 
and ours is $40,570,000.
    Sargent & Lundy, Basin Electric's consultant, also employed 
numerous unreasonable assumptions in estimating costs and cost 
effectiveness for NOX BART at Leland Olds Station Unit 2. 
For example, Sargent & Lundy overestimated catalyst volume, catalyst 
cost, outage time for catalyst replacement, and frequency of catalyst 
replacement. Our consultant, Dr. Phyllis Fox, details in her report 
that Sargent & Lundy's estimates are often unsupported and why they are 
unreasonable. Also, like Burns & McDonnell, Sargent & Lundy levelized 
operation and maintenance costs, which increased these costs by about 
20%. As noted above, levelizing these costs is inconsistent with the 
Control Cost Manual. Sargent & Lundy assumed that a sorbent injection 
system might be needed if SCR were installed. As Dr. Fox explains, no 
such system is needed since catalyst formulations are available to 
minimize sulfuric acid mist emissions. In addition, Sargent & Lundy 
used inflated values for the costs of utilities and supplies, including 
NH3,\31\ natural gas, and electricity. Further detail 
regarding these issues is contained in section V.D.1.d of this action 
and in our TSD. Table 30 contains a summary of some of the most 
significant differences between Sargent & Lundy's estimates and Dr. 
Fox's estimates.
---------------------------------------------------------------------------

    \31\ In the case of NH3, Sargent & Lundy evaluated a 
range of costs of $450 per ton to $700 per ton even though it used a 
cost of $475 per ton in a September 2010 BART analysis for the 
Navajo Generating Station. Our consultant used $475 per ton in her 
cost analysis.

 Table 3--Comparison of Sargent & Lundy and Dr. Fox's Tail-End SCR Variable Operation and Maintenance Costs for
                                           Leland Olds Station Unit 2
                                                 [2009 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                               Dr. Fox (MM$/     Sargent & Lundy
                Description                            Cost factor                 year)           (MM$/year)
----------------------------------------------------------------------------------------------------------------
Ammonia....................................  ..............................              2.116             1.655
Catalyst...................................  ..............................              0.321             3.960
Power......................................  ..............................              1.879             2.930
Natural Gas for Flue Gas Reheating.........  ..............................              2.596             7.750
Outage Penalty.............................  ..............................              0                 7.392
Sorbent Injection..........................  ..............................              0                 0.207
                                            --------------------------------------------------------------------
    Total Variable O&M Cost, A.............  Sum of Various Items Listed                 6.913            23.894
                                              Above.
                                            --------------------------------------------------------------------
    Total Fixed O&M Cost, B................  ..............................              0.824             0.827
Total O&M Cost.............................  A + B.........................              7.737            24.721
Levelized for Inflation, Discount Rate, and  (A + B) x 1.193...............  .................            29.496
 Equipment Life \1\.
                                            --------------------------------------------------------------------
    Total Annual Capital Cost, C...........  ..............................             14.361            14.423
                                            --------------------------------------------------------------------

[[Page 58602]]

 
    Total Annual Cost......................  A + B + C.....................             22.098        43.919 \2\
----------------------------------------------------------------------------------------------------------------
\1\ Levelization is included only in the Sargent & Lundy analysis and is not part of the acceptable methods
  presented in the Control Cost Manual.
\2\ Note: The Sargent & Lundy cost breakdown obtained during our review and included in the Technical Support
  Document, when summed, does not exactly match the total annual cost of $43,830,000 provided in SIP Appendices
  B.1 and C.1.

    We also question Sargent & Lundy's estimated capital cost of $373/
kW (2010 dollars) to retrofit SCR at Leland Olds Station. Sargent & 
Lundy provided no documentation for this figure, and it is higher than 
the actual installed cost for existing retrofit SCRs, including those 
with extreme retrofit difficulty and those requiring flue gas reheat. 
Despite our concern about Sargent & Lundy's capital cost estimate, we 
used it in our cost analysis. Thus, we consider our resulting cost 
effectiveness value to be conservative in Basin Electric's favor and to 
represent an upper bound for a reasonable cost effectiveness value for 
SCR (i.e., it is our opinion that the actual cost effectiveness value 
would be lower than our estimate suggests). Our Technical Support 
Document contains additional details regarding our concerns regarding 
Sargent & Lundy's capital cost estimate for SCR.
    Sargent & Lundy's estimate for total annual costs for TESCR at 
Leland Olds Station Unit 2 was $43,830,000; using the Control Cost 
Manual factors and other reasonable assumptions, our estimate is 
$22,098,000.
    North Dakota's estimates for TESCR ($4,100--$7,100), based on 
company-supplied estimates, are roughly two to three times higher than 
estimates that are based on accepted estimating practices.\32\ These 
differences are significant, particularly because our revised cost 
estimates fall within the range that North Dakota, other states, and 
EPA have considered as being cost effective for BART determinations. 
Accordingly, we do not consider North Dakota's cost estimates to be 
consistent with the statutory and regulatory requirement that North 
Dakota consider cost in determining BART. Thus, the BART analyses for 
these units do not meet the requirements of the regional haze 
regulation, and we are proposing to disapprove those analyses and the 
resultant BART determinations.
---------------------------------------------------------------------------

    \32\ They are also much higher than the values EPA relied on in 
determining that SCR is cost effective on coal-fired cyclone units 
for purposes of determining presumptive NOX BART limits 
in the BART Guidelines: ``Our analysis indicated that cost-
effectiveness of applying SCR on coal-fired cyclone units is 
typically less than $1500 a ton, and that the average cost-
effectiveness is $900 per ton.'' 70 FR 39135-39136.
---------------------------------------------------------------------------

e. EPA's Evaluation of the State's Visibility Analyses for 
NOX BART for Milton R. Young Station Unit 1 and 2 and Leland 
Olds Station Unit 2
    Generally, to evaluate visibility improvements associated with 
potential BART control options, North Dakota conducted or relied on 
CALPUFF modeling that was consistent with the recommended approach in 
the BART Guidelines and the State's EPA-approved protocol included in 
Appendix A.1 of its Regional Haze SIP. Such modeling assumes natural 
background conditions--i.e., without emissions from current emissions 
sources. However, for its NOX BART determinations for Milton 
R. Young Station Units 1 and 2 and Leland Olds Station Unit 2, North 
Dakota conducted supplemental cumulative visibility modeling--i.e., 
modeling that included emissions from all other sources in the 
inventory. North Dakota did not use this alternative modeling approach 
for any other pollutant or any other BART units within North Dakota.
    The State attached considerable weight to the results of this 
alternative modeling when it determined NOX BART for the 
three units. SIP appendices B.1 and B.4. The State stated that it 
conducted this supplemental cumulative modeling because ``the single 
source modeling under the BART Guidelines overestimates the visibility 
improvement'' and ``single-source modeling results * * * tend to be 
five to seven times larger'' than results when the same source is 
combined with all other sources in a cumulative analysis. Id. SIP 
Section 7.4.2. Based on its supplemental cumulative modeling, the State 
determined that the visibility improvement that would result from SCR 
would be ``negligible'' and proceeded to eliminate SCR based on ``the 
excessive cost and negligible visibility improvement.'' SIP appendices 
B.1 and B.4.
    The perceived change in visibility from controls on a single source 
is reduced when background contributions from other sources are 
included in the modeling. In other words, cumulative modeling reduces 
the predicted visibility benefit in deciviews from any level of control 
considered. For three units and one pollutant only, North Dakota relies 
on its supplemental cumulative modeling as a partial basis to reject 
SCR as BART. Not only is North Dakota's approach arbitrary, it is 
inconsistent with the purpose of BART and the regional haze program 
generally, as well as the BART modeling approach used by other states 
and EPA.
    The CAA establishes a National goal of eliminating man-made 
visibility impairment from all mandatory Class I Federal areas. Use of 
natural background (i.e., not considering other source emissions) in 
the BART context is consistent with the ultimate goal of the program to 
reach natural background conditions. Also, the modeling of visibility 
improvements from potential control options should be consistent with 
the subject-to-BART modeling, which compares single-source impacts to 
natural conditions. Otherwise, BART, one of the primary requirements 
under the regional haze regulations, could be reduced as to be 
meaningless. Thus, the BART Guidelines direct states to ``[c]alculate 
the model results for each receptor as the change in deciviews compared 
against natural visibility conditions.'' 40 CFR part 51, appendix Y, 
section IV.D, step 5. The consistent use of a clean background in BART 
evaluations in North Dakota and surrounding states will foster emission 
reductions that will speed achievement of natural background 
conditions, and will ensure equity among states in achieving this goal.
    Because North Dakota relied on a visibility modeling method that is 
inconsistent with the BART Guidelines, its own EPA-approved protocol, 
and the purpose of the Regional Haze Rule, we do not consider North 
Dakota's analysis of visibility improvement for NOX

[[Page 58603]]

BART for the three units to be reasonable.\33\ We propose to find that 
North Dakota's analysis is inconsistent with the statutory and 
regulatory requirement that North Dakota consider ``the degree of 
improvement in visibility which may reasonably be anticipated to result 
from the use of such technology.'' Thus, the BART analyses for these 
units do not meet the requirements of the regional haze regulation, and 
we are proposing to disapprove those analyses and the resultant BART 
determinations.\34\
---------------------------------------------------------------------------

    \33\ In fact, by adopting a different set of rules for modeling 
the visibility benefits of SCR at MRYS and LOS, it appears that 
North Dakota singled these units out for preferential treatment 
without a valid justification.
    \34\ In addition to the cost and visibility issues, we disagree 
with North Dakota that separate NOX limits during startup 
at Milton R. Young Station Units 1 and 2 are necessary or represent 
BART. The SIP does not demonstrate that such special treatment is 
appropriate or needed. We find that a 30-day rolling average limit 
is adequate to address emissions variations that may result from 
startup at a facility that is properly managing its operations. We 
also note that no other source sought or was granted a separate 
limit during startup. This forms another basis for our proposed 
disapproval of the NOX BART limits for Milton R. Young 
Station Units 1 and 2.
---------------------------------------------------------------------------

    We are proposing a FIP for NOX BART for these units to 
fill the gap left by our proposed disapproval. We discuss our proposed 
FIP in section V.G, below.
2. Coal Creek Station Units 1 and 2
a. Coal Creek Station Units 1 and 2--State Analysis
    Each unit is already equipped with LNB and SOFA. The State 
identified the following NOX control options as having 
potential application to the Coal Creek Station boilers: FGR, high-dust 
SCR, ECO, Pahlman ProcessTM, LDSCR, TESCR, LTO, SNCR, and 
modified and additional SOFA and LNB. The State eliminated the 
following options as technically infeasible: FGR, ECO, and the Pahlman 
ProcessTM. The State deemed the incremental cost of LTO, 
SCR, and SNCR to be excessive. The State noted SNCR would be cost 
effective except for the loss of fly ash sales due to likely 
NH3 contamination. The loss of fly ash sales would add to 
the cost of SNCR and SCR for Coal Creek Station, which has an 
established market for fly ash to be used in concrete. Four testimonial 
letters from North Dakota fly ash marketers and end-users (included in 
Appendix C.2 of the SIP) attest to problematic NH3 
concentrations in fly ash due to SCR and SNCR control technology. The 
State also noted that loss of fly ash sales would cause the undesirable 
non-air quality environmental impact of additional waste destined for 
landfill disposal. A summary of the State's NOX BART 
analysis, and the modeling results provided by both the source and the 
State, are provided in Table 31 for each unit.

                                     Table 31--Summary of Coal Creek NOX BART Analysis for Unit 1 and Unit 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts \2 3\
                                                                            Emissions                          Cost      -------------------------------
             Control option                  Control      Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)          benefit      Fewer days >
                                                                                                                            (delta dv)     0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LTO....................................              90           0.022           4,821           58.07           12,045           1.853              64
LDSCR..................................              80           0.043           4,286           56.15           13,101           1.760              62
SNCR...................................              50           0.108           2,678           22.9             8,551           1.507              50
SOFA + LNB Option 1 \1\................              30           0.15            1,607           66.0               411           1.419              49
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The State and company also reviewed a less desirable Option 2 which was the same control technology with a lower control efficiency of 21%.
\2\ The visibility modeling that Great River Energy performed for Coal Creek Units 1 and 2 included SO2 control in addition to the noted NOX control.
  The modeling results shown above reflect the chosen SO2 BART control, scrubber modifications, in addition to the noted NOX control option. Thus, these
  values do not reflect the distinct visibility benefit from the NOX control options but do provide the incremental benefit between the options.
\3\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    North Dakota determined BART to be modified and additional SOFA 
plus LNB with emission limits of 0.15 lb/MMBtu on an annual average 
basis and 0.17 lb/MMBtu on a 30-day rolling average basis. North Dakota 
provided that Unit 1 and Unit 2 emissions may be averaged provided the 
average does not exceed the limit. The estimated cost of modified and 
additional SOFA plus LNB was $411 per ton of NOX removed, 
and the capital and annualized costs were estimated to be $5,260,000 
and $660,000 per year, respectively.
b. EPA's Evaluation of the State's NOX BART Review for Coal 
Creek Units 1 and 2
    During review of North Dakota's NOX BART analyses for 
Coal Creek Station, we identified a possible discrepancy with Great 
River Energy's and the State's costs associated with lost fly ash 
sales. Upon our request, subsequent to submittal of the SIP, North 
Dakota obtained additional supporting information from Great River 
Energy for lost fly ash revenue and for the potential cost of fly ash 
NH3 mitigation. The supporting information included an 
updated cost analysis from Great River Energy noting that the correct 
sales price for fly ash was $5 per ton instead of $36 per ton. Great 
River Energy indicated the $36 per ton price was a typographical error. 
The updated analysis included corrected fly ash revenue data and 
NH3 mitigation costs.
    That analysis, dated June 16, 2011, indicated that the average cost 
effectiveness for SNCR at Coal Creek Station Units 1 and 2 would be 
$2,318 per ton of NOX emissions reductions rather than the 
original estimate of $8,551 per ton. While Great River Energy 
subsequently revised this value to $3,198 per ton based on concerns 
regarding the technical feasibility of mitigating the NH3 in 
North Dakota lignite fly ash,\35\ either of these values is 
substantially less than the values North Dakota relied on to make its 
NOX BART determination for Coal Creek Station Units 1 and 2. 
They are also within the cost effectiveness range that North Dakota 
found reasonable for BART controls at other BART sources and that we 
and other states have found reasonable. Great River Energy's error

[[Page 58604]]

also affected the cost effectiveness values for SCR.
---------------------------------------------------------------------------

    \35\ See July 15, 2011 letter from Great River Energy to Terry 
O'Clair.
---------------------------------------------------------------------------

    Because of the significant error underlying the State's cost 
analysis, we are proposing to disapprove the State's NOX 
BART determination for Coal Creek Station Units 1 and 2 and are 
proposing a FIP to establish NOX BART limits for these 
units.

E. Federal Implementation Plan To Address NOX BART for 
Milton R. Young Station Units 1 and 2, and Leland Olds Station Unit 2

 1. Introduction
    As noted above, North Dakota selected SNCR + ASOFA as 
NOX BART for Milton R. Young Station Units 1 and 2 and 
Leland Olds Station Unit 2, but in doing so, inappropriately eliminated 
SCR + ASOFA as potential BART. Thus, in our proposed FIP, we are re-
evaluating these two technologies and associated emission limits as 
potential BART. Our analysis follows our BART Guidelines for both 
facilities. For Milton R. Young Station 1 and 2, the BART Guidelines 
are mandatory. Milton R. Young Station has a capacity of 794 
megawatts.\36\ For Leland Olds Station 2, the guidelines are not 
mandatory, but we are following them because they provide a reasonable 
and consistent approach for determining BART.
---------------------------------------------------------------------------

    \36\ Letter from John T. Graves, Environmental Superintendent, 
Minnkota Power Cooperative, Inc. to Dana Mount, Director, Division 
of Environmental Engineering, North Dakota Department of Health, Re: 
Permit to Operate No. F76009, Permit Revisions, November 20, 1995.
---------------------------------------------------------------------------

2. BART Analysis for Milton R. Young Station 1
    Step 1: Identify All Available Technologies.
    Our analysis only considers SNCR + ASOFA and SCR + ASOFA. Because 
the State selected SNCR +ASOFA as BART, and our concern is that the 
State did not properly evaluate SCR as BART, there is no need to 
consider lower-performing technologies.
    Step 2: Eliminate Technically Infeasible Options.
    We are not eliminating either SNCR or SCR as being technically 
infeasible. Both technologies have been widely employed to control 
NOX emissions from coal-fired power 
plants.37 38 39 The State determined SNCR was technically 
feasible for North Dakota EGUs. We agree with the State that SNCR is 
technically feasible. The State also determined in Section 7 of the SIP 
that two forms of SCR are technically feasible for use on North Dakota 
EGUs burning lignite coal, stating the following:
---------------------------------------------------------------------------

    \37\ Institute of Clean Air Companies (ICAC) White Paper, 
Selective Catalytic Reduction (SCR) Controls of NOX 
Emissions from Fossil Fuel-Fired Electric Power Plants, May 2009, 
pp. 7-8.
    \38\ 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.
    \39\ ICAC White Paper, Selective Non-Catalytic Reduction (SNCR) 
for Controlling NOX Emissions, February 2008, pp. 6-7.

    The seven BART sources determined SCR is not technically 
feasible for installation on boilers in North Dakota burning lignite 
coal. The Department agrees that high dust SCR is not technically 
feasible; however, LDSCR and TESCR are considered technically 
---------------------------------------------------------------------------
feasible.

    The State based its conclusion on an analysis contained in Appendix 
B.5 that the State submitted with its Regional Haze SIP.
    According to our BART Guidelines, a demonstration of technical 
infeasibility must be documented and must show, ``based on physical, 
chemical, or engineering principles, why technical difficulties would 
preclude the successful use of the control option on the emissions unit 
under review.'' 40 CFR part 51, appendix Y, section IV.D, Step 2. Only 
then may a control technology be eliminated from further consideration 
in the BART analysis. Id. The BART Guidelines go on to state that a 
control technology is technically feasible if it is ``available'' and 
``applicable.''
    A technology is considered available if the source owner may obtain 
it through commercial channels, or it is otherwise available in the 
common sense meaning of the word. Id. SCR technology has been available 
through commercial channels for many years, and it could be purchased 
for use at Milton R. Young Station Units 1 and 2. SCR technology is not 
in the ``pilot scale testing stages of development'' for use at coal-
fired power plants, and there is no need for Minnkota ``to conduct 
extended trials to learn how to apply [the] technology on a totally new 
and dissimilar source type.'' Id.
    A technology is considered applicable if it can reasonably be 
installed and operated on the source type under consideration. EPA must 
exercise its technical judgment in making this determination. Id. The 
Guidelines state that a commercially available control option will be 
presumed applicable if it has been used on the same or a similar source 
type. Given that SCR has been deployed at hundreds \40\ of EGUs, 
burning a wide variety of coals, it is presumed that it is applicable 
to the coal-fired EGUs at Milton R. Young Station.
---------------------------------------------------------------------------

    \40\ ICAC White Paper, May 2009.
---------------------------------------------------------------------------

    While Minnkota, the owner of Milton R. Young Station, and more 
recently the State of North Dakota,\41\ have asserted that SCR 
technology is not technically feasible, we cannot reasonably conclude 
that SCR is not available or applicable to Milton R. Young Station. In 
EPA's view, the concerns raised by Minnkota and the State relate only 
to the specific length of catalyst life at Milton R. Young Station, not 
to the commercial availability of SCR, or the ability of SCR to reduce 
NOX emissions from the flue gas stream, at Milton R. Young 
Station Units 1 and 2. Their primary argument is that the fuel used at 
Milton R. Young Station, and in turn the flue gas stream, contain 
relatively high concentrations of certain constituents (primarily 
sodium and potassium) that will deactivate the catalyst relatively 
rapidly and require that the catalyst be replaced too often. We 
consider this to be a cost issue, not a matter of technical 
feasibility. The BART Guidelines state, ``Where the resolution of 
technical difficulties is merely a matter of increased cost, you should 
consider the technology to be technically feasible.'' 40 CFR part 51, 
appendix Y, section IV.D, step 2. As noted above, SCR has a long and 
proven history of successfully reducing NOX emissions from 
coal-fired electric steam generating units.
---------------------------------------------------------------------------

    \41\ In the context of a recent BACT determination for MRYS, the 
State reversed its prior position and decided in that context that 
SCR is technically infeasible on cyclone boilers burning North 
Dakota lignite coal. On July 28, 2011, the State submitted to EPA as 
part of Amendment No. 1 to the regional haze SIP the entire 
administrative record for its BACT determination for MRYS. The 
administrative record consists of at least 259 documents comprising 
over 850 megabytes of information. EPA was unable to consider this 
administrative record/SIP revision in this proposed action; the time 
available under a relevant consent decree deadline did not allow EPA 
to. Note that under the CAA, EPA is not required to act on a SIP 
submittal until 12 months after it is determined to be or deemed 
complete. EPA has individually considered some of the documents 
included in the State's BACT administrative record and has included 
those documents in the docket for this proposed action. We note that 
under the dispute resolution provisions of a separate consent decree 
between EPA, the State of North Dakota, Minnkota Power Cooperative, 
Inc., and Square Butte Electric Cooperative, (Civil Action No. 1:06-
CV-034), EPA has filed a petition with the United States District 
Court for the District of North Dakota disputing the State's PSD 
BACT determination and its finding in that context that SCR is 
technically infeasible at MRYS. Our proposed action here pertains to 
BART, not BACT, is governed by CAA provisions and regulations 
specific to regional haze and BART, and is not governed by such 
consent decree.
---------------------------------------------------------------------------

    We also note that in the BACT context, the State gives great weight 
to the fact that two catalyst vendors queried by Minnkota indicated an 
unwillingness to provide typical catalyst life guarantees without first 
performing catalyst deactivation field

[[Page 58605]]

tests on the coal Minnkota burns at Milton R. Young Station. However, 
as noted in our BART Guidelines, ``lack of a vendor guarantee by itself 
does not present sufficient justification that a control option or an 
emissions limit is technically infeasible.'' 40 CFR part 51, appendix 
Y, section IV.D, step 2. Here, the vendor guarantee for a specific 
catalyst life, or lack thereof, is not relevant to the availability of 
SCR, or its ability to remove NOX from the gas stream at 
Milton R. Young Station, but only to the willingness of two catalyst 
companies to provide a specific catalyst life guarantee without more 
information. Neither vendor contacted by Minnkota indicated it would 
not provide SCR catalyst absent any prior field testing. One of the two 
catalyst vendors contacted by Minnkota is willing to provide full 
performance guarantees on critical operating parameters such as 
NOX reduction, NH3 slip, SO2 to sulfur 
trioxide (SO3) conversion, and pressure drop. This is strong 
evidence that at least one of the two catalyst vendors contacted by 
Minnkota believes NOX can be successfully controlled with 
SCR at Milton R. Young Station and that SCR is commercially available. 
In addition, both catalyst vendors contacted by Minnkota have stated 
they believe a catalyst life guarantee can be offered once the field 
testing data is collected. The fact that some catalyst vendors have not 
yet offered a catalyst life guarantee without field testing of 
deactivation rates is not evidence that SCR is not available or is 
technically infeasible at Milton R. Young Station. Given the record 
before us, the lack of a vendor guarantee for a specific catalyst life 
is not sufficient to overcome the presumption that this commercially 
available technology is applicable to coal-fired power plants, 
including Milton R. Young Station.
    Additional support for our finding that SCR is not technically 
infeasible is contained in Appendix B.5 of the State's SIP. There, the 
State concluded that low-dust and tail-end SCR were technically 
feasible. A LDSCR would be located after the electrostatic precipitator 
(ESP), which removes particulates. Alternatively, a TESCR would be 
located after both the ESP and SO2 scrubber. Testing has 
shown that these control devices would remove a high percentage of the 
ash and catalyst poisons before they would reach the SCR, thereby 
negating the higher concentrations of catalyst poisons in North Dakota 
lignite coal compared to other applications of high-dust SCR at coal-
fired utility boilers.
    North Dakota reviewed PM stack tests at Milton R. Young Station 
Unit 2 (August 2007 and May 2008) that indicated an average sodium and 
potassium removal efficiency of greater than 99% by the ESP and wet 
scrubber, with resulting emission rates at 0.78 milligrams sodium 
sulfate and 0.20 milligrams potassium sulfate per normal cubic meter. 
See Appendix B.5 to the SIP submittal. The State found that these 
loadings of sodium and potassium aerosols, which would enter a LDSCR or 
TESCR at Milton R. Young Station, were significantly lower than the 
concentrations present in the gas streams of boilers burning peat and 
wood that were the subject of experimental and pilot scale testing of 
SCR catalyst life. The State carefully evaluated the results of such 
testing and concluded that a reasonable catalyst life could be achieved 
at Milton R. Young Station.\42\ Id. Appendix B.5 also indicates that 
North Dakota independently consulted three vendors who opined to the 
State that SCR would be technically feasible at Milton R. Young 
Station.\43\ Finally, the State found that existing biomass boilers, 
with flue gas characteristics that approximate those from North Dakota 
lignite, have used TESCR successfully. Id.
---------------------------------------------------------------------------

    \42\ The State concluded that an SCR system would require a 
catalyst life of at least 10,000 hours to be considered an 
applicable technology and technically feasible. We do not agree with 
this arbitrarily-selected bright-line threshold. Catalyst life 
relates to how often the catalyst needs to be replaced to maintain 
the ability of the SCR to successfully reduce NOX 
emissions. Thus, catalyst life is a component of the cost analysis 
for SCR.
    \43\ ``The Department [North Dakota] contacted three of the 
vendors, Ceram Environmental, Haldor Topsoe and Babcock Power. The 
companies generally confirmed the information in the emails to Mr. 
Hartenstein. Babcock Power indicated that they had no worries about 
getting 10,000 hours of catalyst life at the M.R. Young Station. 
However, they recommended `coupon' testing prior to design of the 
SCR. Ceram was convinced it was technically feasible; however, their 
representative did acknowledge that if the sodium and potassium 
aerosols are making it through the ESP and wet scrubber, catalyst 
deactivation could be a problem. Haldor Topsoe indicated that the 
catalyst deactivation at M.R. Young would be manageable if the 
catalyst is kept dry during outages.'' SIP Appendix B.5.
---------------------------------------------------------------------------

    Also, Microbeam Technologies, Inc. (Microbeam) performed PM 
emissions testing for Milton R. Young Station Unit 2 in March of 2009. 
The Microbeam results demonstrate the high removal efficiency of PM and 
the primary catalyst poisons of interest (sodium and potassium) by the 
ESP and scrubber at Milton R. Young Station. The results reflected a PM 
removal efficiency of 99.76%, and that the amount of sodium oxide plus 
potassium oxide was approximately 50-90 times greater entering the ESP 
than exiting the ESP. The results were similar for sodium oxide plus 
potassium oxide entering the ESP versus exiting the wet scrubber. This 
means the loading of sodium oxide plus potassium oxide on a high-dust 
SCR at Milton R. Young Station would be approximately 50-90 times 
higher than on a LDSCR or TESCR. Put another way, the Microbeam results 
showed that the ESP removes at least 98% of the catalyst poisons, which 
would be before the flue gas reaches a LDSCR or TESCR. Thus, any 
differences in fuel quality (especially concentrations of catalyst 
poisons in the ash) of North Dakota lignite compared to other types of 
coal in the United States would be offset at the control percentages 
described because Milton R. Young Station would employ a LDSCR or 
TESCR, whereas the vast majority of SCR installations in the United 
States are configured as high-dust SCRs.
    Step 3: Evaluate Control Effectiveness of Remaining Control 
Technology.
    For the purposes of our SNCR + ASOFA cost analysis, we used a 
control efficiency of 58% and an emission rate of 0.355 lb/MMBtu, the 
same control efficiency that North Dakota used. For our TESCR + ASOFA 
cost analysis we used the control efficiency of 93.8% that Minnkota 
used in its BART analysis and an emission rate of 0.05 lb/MMBtu, 
instead of North Dakota's 90% control efficiency and 0.085 lb/MMBtu 
emission rate. We find that SCR technology, by itself, can achieve 90% 
control efficiency and that the overall NOX reduction would 
be even greater (93.8%) with the use of combustion controls in 
combination with SCR. A summary of emissions projections for the two 
control options is provided in Table 32.

[[Page 58606]]

    Table 32--Summary of EPA NOX BART Analysis Control Technologies for Milton R. Young Station Unit 1 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                                                    Emissions
             Control option                    Control        Emission rate   Emissions  (tons/ reduction (tons/
                                           efficiency (%)      (lb/MMBtu)            yr)               yr)
----------------------------------------------------------------------------------------------------------------
TESCR + ASOFA...........................              93.8             0.053               627             9,410
SNCR + ASOFA............................                58             0.355             3,784             5,248
No Controls (Baseline)..................                 0             0.849        \1\ 10,037  ................
----------------------------------------------------------------------------------------------------------------
\1\ North Dakota used a baseline of 9,032 tons/yr. We changed this to reflect maximum heat input and the
  utilization rate reported by Minnkota.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    SNCR + ASOFA.
    We are not relying on North Dakota's costs for SNCR. Though the 
North Dakota costs derived by Burns & McDonnell are generally 
consistent with the Control Cost Manual, at least one cost, related to 
lost revenue due to outage, is not. The North Dakota costs are also 
based on lower reagent costs which we acknowledge do fluctuate. To 
ensure a fair comparison between the two competing technologies, we 
have re-worked the costs for SNCR. We relied on Minnkota's Burns & 
McDonnell estimate for total capital equipment costs for SNCR. However, 
we have then generally used factors and assumptions provided by the 
Control Cost Manual for the remainder of the SNCR analysis. In the 
absence of a Control Cost Manual method for combustion controls, we 
have used all the costs provided by North Dakota for ASOFA. This 
approach is similar to the one we used to analyze the costs for SCR at 
Milton R. Young Station Unit 1, which enables us to compare the costs 
of the two technologies on a consistent basis. This was not an 
exhaustive effort, but it did result in a downward adjustment in the 
cost estimate for SNCR. We deem the analysis adequate for comparing the 
cost effectiveness values of the two top control options--SCR and SNCR.
    Regarding specific elements in our cost analysis, we used $475 per 
ton to estimate urea costs and did not allow for lost revenue due to 
outage (consistent with Control Cost Manual). To estimate the average 
cost effectiveness (dollars per ton of emissions reductions), we 
divided the total annual cost by the estimated NOX emissions 
reductions. We summarize our costs from our SNCR cost analysis in 
Tables 33, 34, and 35.

   Table 33--Summary of EPA NOX BART Capital Cost Analysis for SNCR on
                  Milton R. Young Station Unit 1 Boiler
------------------------------------------------------------------------
             Description                 Cost factor        Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A.........  ................         4,277,000
Capital Investment SNCR, B..........  ................         4,007,000
Total Capital Investment, TCI                    A + B         8,284,000
 (2009$)............................
------------------------------------------------------------------------

 Table 34--Summary of EPA NOX BART Annual Analysis for SNCR on Milton R.
                       Young Station Unit 1 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........            60,108
Reagent..........................  ...................           949,747
Electricity......................  ...................            21,529
Water............................  ...................               958
Increased Coal...................  ...................            36,845
Increased Ash....................  ...................             2,639
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various              1,071,827
     (TDAC).                        Items Listed Above.
Indirect Annual Cost \1\ (IDAC)..  CRF x TCI..........           378,253
                                  --------------------------------------
    Total Annual Cost SNCR (TACS)  TDAC + IDAC........         1,450,081
                                  --------------------------------------
    Total Annual Cost ASOFA        North Dakota                2,520,719
     (TACA).                        Appendix B.4.
                                  --------------------------------------
    Total Annual Cost SNCR+ASOFA.  TACS + TACA........         3,970,799
------------------------------------------------------------------------
\1\ Capital Recovery Factor (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 35--Summary of EPA NOX BART Costs for SNCR on Milton R. Young Station Unit 1 Boiler
----------------------------------------------------------------------------------------------------------------
                                             Total installed                      Emissions       Average cost
               Control option                  capital cost     Total annual      reductions    effectiveness ($/
                                                  (MM$)          cost (MM$)       (tons/yr)           ton)
----------------------------------------------------------------------------------------------------------------
SNCR + ASOFA...............................           8.284            3.971            5,777               687
----------------------------------------------------------------------------------------------------------------

[[Page 58607]]

    SCR + ASOFA.
    Our contractor, ERG, prepared a cost analysis for SCR for Milton R. 
Young Station Units 1 and 2. As explained below, ERG started with some 
of the cost information in the Burns & McDonnell (Minnkota's 
contractor) BACT cost analyses provided in the NOX BACT 
Analysis Study, Supplemental Reports, for Units 1 and 2 dated February 
2010 and November 2009, respectively. See SIP Appendix C.4.
    ERG used Burns & McDonnell's original SCR equipment costs and other 
costs that were not independently verified by EPA (auxiliaries/balance 
of plant, construction costs, natural gas pipeline, reagent costs, 
natural gas costs), but then calculated total capital costs and annual 
costs for SCR using the applicable Control Cost Manual methodology and 
factors and certain information supplied by EPA. While EPA could not 
independently verify many of the Burns & McDonnell-estimated costs, and 
believes they may overestimate actual costs, the result is a cost 
estimate that should represent the upper end of likely costs for these 
items. EPA provided ERG with information regarding catalyst volume, 
catalyst cost, catalyst replacement frequency, and estimated additional 
outage time for replacing spent catalyst. EPA provided a reasonable 
value for catalyst cost of $6,000 per cubic meter based on vendor data. 
This cost could be significantly reduced if regenerated catalyst were 
used. Contingencies were calculated using the Control Cost Manual 
assumptions. The maintenance costs were adjusted using the cost factor 
in the Control Cost Manual, and annual costs were not ``levelized.'' 
\44\
---------------------------------------------------------------------------

    \44\ As discussed in section V.D., above, the Control Cost 
Manual does not provide for ``levelization'' of annual costs.
---------------------------------------------------------------------------

    To be conservative, ERG calculated four different catalyst 
replacement scenarios. Scenarios 1 through 3 assume catalyst 
replacement of one layer per year, one layer every two years, and one 
layer every three years. ERG's Scenarios 1 through 3 do not include 
additional outage time that Minnkota claimed would be necessary for 
boiler maintenance for solidified slag removal specifically 
attributable to the installation of ASOFA. For Scenario 3, which we 
find most reasonable for reasons further described below, there would 
be no additional unit outage time (and associated electricity costs) 
for catalyst replacement, because all of this work could be completed 
during a regularly scheduled major unit outage event. Despite our 
disagreement about the extent of additional outage time due to ASOFA, 
we had ERG run Scenario 4 as a ``worst-case'' scenario that assumes the 
accuracy of Burns & McDonnell's estimate of additional outage time 
needed for solidified slag removal due to the installation of 
ASOFA.\45\ For all scenarios, ERG modified the amount of time required 
for each catalyst layer replacement from Burns & McDonnell's 
assumptions, recalculated the unit availability using the revised 
downtime, and recalculated electricity costs and corresponding 
NOX emissions using the new availability.
---------------------------------------------------------------------------

    \45\ Minnkota asserts there is a potential reduction in 
reliability and availability of a lignite-fired cyclone boiler as a 
result of installing and operating a separated overfire air system 
due to challenges in maintaining adequate slag layer development and 
flow within the cyclone barrels or furnace bottom compared with non 
air-staged combustion. Minnkota claims the need for forced or 
extended scheduled outages to remove the solidified slag. EPA does 
not agree that these additional outage times for ASOFA are 
legitimate. For further detail regarding this issue, please refer to 
our Technical Support Document.
---------------------------------------------------------------------------

    We find that Scenario 3 is the most reasonable based on the 
following considerations regarding catalyst life:
     An SCR catalyst must be changed out periodically. The 
catalyst lifetime is a function of catalyst activity and NH3 
slip. As catalyst activity decreases over time, NH3 slip 
increases until it reaches the design limit, at which point new 
catalyst is added. One of the two catalyst vendors queried by Minnkota 
prepared a budgetary proposal that estimated a catalyst exchange cycle 
for Milton R. Young Station based on the catalyst design presented in 
the proposal. This catalyst design was developed by the catalyst vendor 
based on the detailed boiler and fuel specifications supplied by 
Minnkota. The catalyst design was also intended to reflect the three 
year planned outage schedule at Milton R. Young Station specified by 
Minnkota. In the budgetary proposal, the catalyst design includes an 
initial fill of two catalyst layers with one empty spare layer. The 
catalyst vendor estimated the two initial catalyst layers would operate 
for 24,000 hours, at which time a third layer of catalyst (in the spare 
layer) would be added. The vendor estimated that the first layer of 
catalyst would need replacement at about 88,000 hours, or over 10 years 
of SCR operation. The second catalyst layer replacement would not be 
needed until approximately 125,000 hours or approximately 15 years of 
SCR operation. Thus, EPA's assumption of replacing a layer of catalyst 
every three years is conservative and a reasonable assumption. Based on 
the catalyst vendor's expected catalyst exchange cycles, the three year 
replacement assumption would overestimate annual costs once the third 
layer of catalyst is added after the third year of operation. At that 
point, the catalyst vendor estimates less frequent need for catalyst 
replacement. While the other catalyst vendor queried by Minnkota 
estimates an approximately two year catalyst replacement cycle, there 
is no reason to give more deference to that proposal.
     SCR catalyst is typically specified to last 16,000 to 
24,000 hours for hot-side (or high dust) SCRs (after the boiler), the 
worst-case location for catalyst life. In the tail-end position, after 
ash and catalyst poisons have been significantly reduced by pollution 
control devices, SCR catalyst typically lasts 50,000 to over 100,000 
hours.\46\
---------------------------------------------------------------------------

    \46\ See, for example, vendor e-mails in Appendix D of the North 
Dakota Report: Selective Catalytic Reduction (SCR) Technical 
Feasibility for M.R. Young Station; McIlvaine, Next Generation SCR 
Choices--High-Dust, Low-Dust and Tail-End, FGD & DeNOx Newsletter, 
no. 369, January 2009; Hans Hartenstein, Steag's Long-Term SCR 
Catalyst Operating Experience and Cost, EPRI SCR Workshop, 2005.
---------------------------------------------------------------------------

     We have assumed the SCR at Milton R. Young Station 1 would 
be located at the tail end, after the ESP and new wet scrubber. As 
noted, these control devices remove the majority of the ash and 
catalyst poisons. Flue gas composition data collected at Milton R. 
Young Station 2, which has an inefficient, older wet scrubber, proves 
that the amount of submicron alkali aerosols is so small that catalyst 
deactivation would not occur rapidly.\47\ Further, any remaining 
soluble alkaline substances would not poison the catalyst at TESCR 
operating temperatures. Significant deactivation only occurs if 
condensed moisture is present at the catalyst surface, i.e., when the 
catalyst is being cooled down to below the water dew point. Unit 
startups and shutdowns do not occur frequently at Milton R. Young 
Station 1. Furthermore, condensation on the catalyst can be prevented 
by bypassing or buttoning up the SCR reactor during forced outages of a 
few days.\48\

[[Page 58608]]

Regardless, catalyst vendors have ample experience preventing moisture 
condensation in SCR catalysts.\49\ In other words, available evidence 
suggests that catalyst life would be relatively long, consistent with 
that experienced at plants burning other types of coal and fuel.
---------------------------------------------------------------------------

    \47\ 1/8/10 EPA Comments, enclosure 2, pp. 24-25 (``As discussed 
extensively in the Minnkota BACT comments, the actual flue gas 
composition analysis data measured downstream of the wet FGD at MRYS 
[Milton R. Young Station] proves that the amount of submicron 
alkalie aerosols is so small that catalyst deactivation does not 
occur rapidly and a relatively long catalyst life can reasonably 
expected (sic) compared to most HDSCR [high dust SCR] 
installations.'')
    \48\ 5/6/08 Cochran (CERAM) E-mail, p. 2 (As to high dust SCR:, 
a worst case: ``Due to the high sodium and iron concentrations it is 
recommended that a full SCR bypass system be installed. During lay-
up periods the catalyst would need to remain warm and dry (above 
condensing conditions), for instance with an air drying or 
dehumidification system. This may necessitate the use of a 
dehumidifier and air lock system to access the reactor.''), in 5/8/
08 Milton R. Young Additional Information.
    \49\ Minnkota Power Cooperative, Inc. and Square Butte Electric 
Cooperative, Additional Information and Discussion of Vendor 
Responses on SCR Technical Feasibility, North Dakota's NOx BACT 
Determination for Milton R. Young Station Units 1 & 2, Appendix A, 
Vendor Emails, Email from John Cochran, CERAM Environmental, Inc., 
to Robert Blakley, Re: Request for Lignite SCR Feasibility 
Commercial and Technical Information, May 6, 2008 (``Sodium is a 
catalyst poison. Concerns reported by Dr. Benson regarding high 
sodium content and fine fume are duly noted, but inadequate evidence 
is presented that this could be a fatal flaw to application of SCR 
considering the flawed pitch and resultant pluggage of the catalyst 
used during the Coyote Station testing [North Dakota lignite]. 
Sodium is not a poison to catalyst at SCR operating temperatures. 
Significant deactivation can occur if condensed moisture transports 
sodium residing at the surface into the catalyst pore structure 
during outage or layup. CERAM has experience with high sodium 
applications to substantiate this effect. Important to avoid 
deactivation from sodium is the need to protect the catalyst from 
going through a condensation event.'')
---------------------------------------------------------------------------

    ERG derived the annual cost of $2,161,000 (2009 dollars) for 
installation, operation, and maintenance of ASOFA for Unit 1 from 
tables 4-6-SF of Minnkota's February 2010 Supplemental BACT Analysis 
for Milton R. Young Station. As we noted above relative to the ASOFA 
slag issue and associated costs due to additional unit outage time 
assumed by Minnkota in calculating annual operating costs, EPA does not 
concur that this cost is entirely representative, but the ERG analysis 
relied on this cost due to time constraints. As with the annual costs 
for SCR, ERG did not ``levelize'' these annual costs for SNCR. ERG 
added the annual costs for ASOFA to the annual costs for SCR to arrive 
at a total cost for the combined controls.
    To estimate the average cost effectiveness (dollars per ton of 
emissions reductions), ERG divided the total annual cost by the 
estimated NOX emissions reductions.
    We summarize our costs from the ERG cost analysis in Tables 36, 37 
and 38. See our Technical Support Document for the full analyses, in 
particular, our letter to Mr. Terry O'Clair, North Dakota Department of 
Health, dated May 10, 2010, and attached spreadsheet.

  Table 36--Summary of EPA NOX BART Capital Cost Analysis for TESCR on
                  Milton R. Young Station Unit 1 Boiler
------------------------------------------------------------------------
                                   Control cost manual
           Description                  factor or          Cost (MM$)
                                       calculation
------------------------------------------------------------------------
Total Direct Capital Costs, A....  ...................             86.32
Indirect Installation Costs
    General Facilities...........  0.05 x A...........              4.32
    Engineering and Home Office    0.10 x A...........              8.63
     Fees.
    Process Contingencies........  0.05 x A...........              4.32
Total Indirect Installation        0.20 x A...........             17.26
 Costs, B.
    Project Contingency, C.......  0.15 x (A + B).....             15.54
Total Plant Cost, D..............  A + B + C..........            119.12
    Preproduction Cost, G........  0.02 x D...........              2.41
    Inventory Capital (Reagent),   ...................             0.087
     H.
    Natural Gas Pipeline.........  ...................              1.50
                                  --------------------------------------
    Total Capital Investment, TCI  ...................            123.13
     = D + G + H.
------------------------------------------------------------------------

Table 37--Summary of EPA NOX BART Annual Costs for TESCR Scenario 3 1 on
                  Milton R. Young Station Unit 1 Boiler
------------------------------------------------------------------------
           Description                 Cost factor        Cost (MM$) 2
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........             1.809
Reagent..........................  ...................             2.716
Catalyst.........................  ...................             0.250
Electricity......................  ...................             2.711
Natural Gas for Flue Gas           ...................             3.756
 Reheating and Urea to Ammonia
 Conversion.
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various                 11.281
     (TDAC).                        Items Listed Above.
    Indirect Annual Cost 3 (IDAC)  CRF x TCI..........            10.735
    Annual ASOFA Cost (AAC)......  ...................             2.161
                                  --------------------------------------
    Total Annual Cost (TAC)......  TDAC + IDAC + AAC..            24.176
------------------------------------------------------------------------
\1\ See Table 38 for an explanation of Scenarios.
\2\ Costs are in 2009 dollars.
\3\ Capital Recovery Factor (CRF) is 0.0872 and is based on a 6%
  interest rate and 20 year equipment life. From Minnkota NOX BACT
  Analysis Study, Milton R. Young Station Unit 1, Table C.1-1, p. C1-4,
  October 2006 (provided in BART Determination Study for Milton R. Young
  Station Unit 1 and 2, October 2006, SIP Appendix C.4).

[[Page 58609]]

  Table 38--Summary of EPA NOX BART Costs for Various TESCR Scenarios on Milton R. Young Station Unit 1 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                  Emissions                        Average cost
              Scenario                      Description          reductions 1     Total annual    effectiveness
                                                                 (tons/year)       cost ($MM)        ($/ton)
----------------------------------------------------------------------------------------------------------------
1...................................  1 layer replaced every             9,418            25.53            2,711
                                       year.
2...................................  1 layer replaced every             9,414            24.73            2,627
                                       2 years.
3...................................  1 layer replaced every             9,410            24.18            2,569
                                       3 years.
4...................................  ASOFA downtime allowed.            9,424            26.23            2,783
----------------------------------------------------------------------------------------------------------------
\1\ Reductions vary based on impacts to boiler availability in each scenario (i.e., lower boiler operating hours
  equate to lower emission reductions).

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and 
operation of the evaluated controls are not significant enough to 
warrant eliminating either SNCR or SCR.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant 
enough to warrant eliminating either SNCR or SCR.
    Factor 4: Remaining useful life.
    The remaining useful life of Milton R. Young Station Unit 1 is at 
least 20 years. Thus, this factor does not impact our BART 
determination.
    Factor 5: Evaluate visibility impacts.
    Minnkota modeled the visibility benefits for SNCR + ASOFA using 
natural background per the BART Guidelines. North Dakota then performed 
additional modeling for the SCR + ASOFA control option. Minnkota and 
North Dakota both provided single-source modeling results using natural 
background conditions, complying with the BART Guidelines. The SCR + 
ASOFA option, when combined with wet scrubbing for SO2, 
would result in a significant improvement in visibility at Theodore 
Roosevelt, estimated to be 3.476 deciviews and 114 fewer days above 0.5 
deciviews. This represents an incremental visibility improvement of 
1.400 deciviews and 43 fewer days above 0.5 deciviews beyond that 
achieved by wet scrubbing alone. Moreover, when compared to SNCR + 
ASOFA, it would result in an incremental visibility improvement of 
0.553 deciviews and 18 fewer days above 0.5 deciviews. North Dakota 
conducted supplemental cumulative modeling for SCR at Milton R. Young 
Station 1 that is discussed in more detail in section V.D.1.e. For the 
reasons described there, we are disregarding North Dakota's alternative 
modeling in our analysis.
    More information on our interpretation of the State's and source's 
modeling information is included in the Technical Support Document.
    Step 5: Select BART.
    We propose to find that BART is SCR + ASOFA at Milton R. Young 
Station 1 with an emission limit of 0.07 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. We 
agree with the State that the other three factors are not relevant to 
this BART determination.
    In our BART analysis for NOX at Milton R. Young Station 
1, we considered SNCR + ASOFA and SCR + ASOFA. The comparison between 
our SNCR analysis and our TESCR Scenario 3 analysis is provided in 
Table 39.

                Table 39--Summary of EPA NOX BART Analysis Comparison of TESCR and SNCR Options for Milton R. Young Station Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts 1 2 4
                                                           Total                                           Incremental   -------------------------------
                                                         installed      Total annual      Average cost         cost         Visibility
                   Control option                      capital cost      cost (MM$)      effectiveness    effectiveness     improvement    Fewer days >
                                                           (MM$)                            ($/ton)          ($/ton)          (delta          0.5 dv
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
TESCR + ASOFA (Scenario 3)..........................      \3\ 123.13             24.18            2,569            4,855           3.476             114
SNCR + ASOFA........................................            8.28              3.97              687  ...............           2.923              96
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Minnkota's and the State's modeling for both SNCR and SCR was based on lower emissions reductions (fewer tons removed) than we anticipate; thus, we
  anticipate slightly greater visibility benefits (delta deciview) than reflected in these values. The visibility benefit shown is for the most impacted
  Class I area, Theodore Roosevelt.
\2\ Minnkota and the State modeled combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of wet scrubbing along
  with the noted NOX control option.
\3\ This installed capital cost estimate does not include the capital cost of ASOFA. The total annualized cost does include the capital cost of ASOFA.
\4\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    We have concluded that SNCR + ASOFA and SCR + ASOFA are both cost 
effective control technologies and that both would provide substantial 
visibility benefits. SNCR + ASOFA has a cost effectiveness value of 
$687 per ton. While SCR + ASOFA is more expensive than SNCR + ASOFA, it 
has a cost effectiveness value of $2,569 per ton of NOX 
emissions reduced. This is well within the range of values we have 
considered reasonable for BART and that states other than North Dakota 
have considered reasonable for BART. Even with more frequent catalyst 
replacement, SCR would still be cost effective even at the high end of 
the range ($2,783 per ton) allowing for the most frequent catalyst 
replacement of one layer per year and allowing for the questionable 
costs of lost power generation revenue in TESCR Scenario 4. We also 
analyzed the SCR costs assuming the same baseline emissions

[[Page 58610]]

of 9,032 tons per year used by North Dakota and determined that the 
high-end cost effectiveness value, assuming the most frequent catalyst 
replacement frequency, would be about $3,115 per ton of NOX 
reduced. All of these cost effectiveness values are well within the 
range of values that North Dakota considered reasonable in several of 
its NOX BART determinations, where predicted visibility 
improvement was considerably lower.
    We have weighed costs against the anticipated visibility impacts at 
Milton R. Young Station 1, as modeled by Minnkota and the State. Both 
sets of controls would have a positive impact on visibility. As 
compared to SNCR + ASOFA, SCR + ASOFA would provide an additional 
visibility benefit 0.553 deciviews and 18 fewer days above 0.5 
deciviews at Theodore Roosevelt. We consider these impacts to be 
substantial, especially in light of the fact that neither of these 
Class I areas is projected to meet the uniform rate of progress. We 
also note that the 0.553 deciview improvement at Theodore Roosevelt is 
greater than the improvement in visibility that North Dakota found 
reasonable to support other NOX BART determinations in the 
SIP despite higher cost effectiveness values for the sources involved 
in these other BART determinations. Given the incremental visibility 
improvement associated with SCR + ASOFA, the relatively low incremental 
cost effectiveness between the two control options ($4,855 per ton), 
and the reasonable average cost effectiveness values for SCR + ASOFA, 
we propose that the NOX BART emission limit for Milton R. 
Young Station 1 should be based on SCR + ASOFA.
    In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted 
the annual design rate of 0.05 lb/MMBtu upwards to allow for a 
sufficient margin of compliance for a 30-day rolling average limit that 
would apply at all times, including startup, shutdown, and 
malfunction.\50\ We are also proposing monitoring, recordkeeping, and 
reporting requirements in regulatory text at the end of this proposal.
---------------------------------------------------------------------------

    \50\ 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.'' Based on the retrofit 
of other SCR installations we have reviewed, we propose a compliance 
deadline of five (5) years from the date our final FIP becomes 
effective.
3. BART analysis for Milton R. Young Station 2
    Step 1: Identify All Available Technologies.
    Our analysis only considers SNCR + ASOFA and SCR + ASOFA. Because 
the State selected SNCR + ASOFA as BART, and our concern is that the 
State did not properly evaluate SCR as BART, there is no need to 
consider lower-performing technologies.
    Step 2: Eliminate Technically Infeasible Options.
    For the reasons described in our BART analysis and determination 
for Milton R. Young Station Unit 1, we are not eliminating either SNCR 
or SCR as being technically infeasible.
    Step 3: Evaluate Control Effectiveness of Remaining Control 
Technology.
    For the purposes of our SNCR + ASOFA cost analysis, we used a 
control efficiency of 58% and an emission rate of 0.355 lb/MMBtu, the 
same control efficiency that North Dakota used. For our TESCR + ASOFA 
cost analysis we used the control efficiency of 93.8% that Minnkota 
used in its BART analysis and an emission rate of 0.05 lb/MMBtu, 
instead of North Dakota's 90% control efficiency and 0.085 lb/MMBtu 
emission rate. We find that SCR technology, by itself, can achieve 90% 
control efficiency and that the overall NOX reduction would 
be even greater (93.8%) with the use of combustion controls in 
combination with SCR. A summary of emissions projections for the two 
control options is provided in Table 40.

    Table 40--Summary of EPA NOX BART Analysis Control Technologies for Milton R. Young Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                                                    Emissions
               Control option                     Control       Emission rate   Emissions (tons/ reduction (tons/
                                              efficiency (%)      (lb/MMBtu)          yr)              yr)
----------------------------------------------------------------------------------------------------------------
TESCR + ASOFA..............................              93.8            0.049              984           14,807
SNCR + ASOFA...............................              58              0.330            6,630            9,162
No Controls (Baseline).....................               0              0.786       \1\ 15,792  ...............
----------------------------------------------------------------------------------------------------------------
\1\ North Dakota used a baseline of 15,507 tons/yr. We adjusted this to reflect maximum heat input and the
  utilization rate reported by Minnkota.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    SNCR + ASOFA.
    For the reasons described in our BART analysis and determination 
for Milton R. Young Station Unit 1, we are not relying on North 
Dakota's costs for SNCR. We have adjusted North Dakota's costs using 
the same methodology we describe in our BART analysis and determination 
for Milton R. Young Station Unit 1.
    We summarize our costs from our SNCR cost analysis in Tables 41, 
42, and 43.

   Table 41--Summary of EPA NOX BART Capital Cost Analysis for SNCR on
                  Milton R. Young Station Unit 2 Boiler
------------------------------------------------------------------------
             Description                 Cost factor        Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A.........  ................        10,008,000
Capital Investment SNCR, B..........  ................         7,437,806
                                     -----------------------------------
    Total Capital Investment, TCI                A + B        17,445,806
     (2009$)........................
------------------------------------------------------------------------

[[Page 58611]]

 Table 42--Summary of EPA NOX BART Annual Analysis for SNCR on Milton R.
                       Young Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........           111,567
Reagent..........................  ...................         1,768,029
Electricity......................  ...................            37,963
Water............................  ...................             1,784
Increased Coal...................  ...................            68,590
Increased Ash....................  ...................             4,913
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various              1,992,847
     (TDAC).                        Items Listed Above.
                                  --------------------------------------
Indirect Annual Cost \1\ (IDAC)..  CRF x TCI..........           702,076
                                  --------------------------------------
    Total Annual Cost SNCR (TACS)  TDAC + IDAC........         2,694,923
                                  --------------------------------------
    Total Annual Cost ASOFA        North Dakota                3,749,684
     (TACA).                        Appendix B.4.
                                  --------------------------------------
    Total Annual Cost SNCR +       TACS + TACA........         6,444,608
     ASOFA.
------------------------------------------------------------------------
\1\ Capital Recovery Factor (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 43--Summary of EPA NOX BART Costs for SNCR on Milton R. Young Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                             Total installed                      Emissions       Average cost
               Control option                  capital cost     Total annual      reductions    effectiveness ($/
                                                  (MM$)          cost (MM$)       (tons/yr)           ton)
----------------------------------------------------------------------------------------------------------------
SNCR + ASOFA...............................           17.46            6.444            9,162               703
----------------------------------------------------------------------------------------------------------------

    SCR + ASOFA.
    Our contractor, ERG, prepared a cost analysis for SCR for Milton R. 
Young Station Units 1 and 2. For a description of the approach/
assumptions ERG used in preparing its cost analysis, please see our 
BART analysis and determination for Milton R. Young Station Unit 1. For 
further detail, please refer to our Technical Support Document.
    For the reasons discussed with respect to Milton R. Young Station 
Unit 1 in section V.E.2., we find that Scenario 3 with a 3-year 
catalyst life is the most reasonable assumption for Milton R. Young 
Station Unit 2.
    ERG derived the annual cost of $3,843,000 (2009 dollars) for 
installation, operation, and maintenance of ASOFA from tables 4-6SF of 
Minnkota's February 2010 Supplement BACT Analysis for Milton R. Young 
Station. As we noted above relative to the ASOFA slag issue, EPA does 
not concur that this cost is representative, but the ERG analysis 
relied on this cost due to time constraints. ERG added the annual costs 
for ASOFA to the annual costs for SCR to arrive at a total cost for the 
combined controls.
    We summarize our costs from the ERG cost analysis in Tables 44 and 
45. See our Technical Support Document for the full analyses, in 
particular, our letter to Mr. Terry O'Clair, North Dakota Department of 
Health, dated May 10, 2010, and attached spreadsheet.

    Table 44--Summary of EPA NOX BART Capital Cost Analysis for TESCR
         Scenario 3 \1\ on Milton R. Young Station Unit 2 Boiler
------------------------------------------------------------------------
                                   Control cost manual
           Description                  factor or          Cost (MM$)
                                       calculation
------------------------------------------------------------------------
Total Direct Capital Costs, A....  ...................            151.97
Indirect Installation Costs        ...................  ................
    General Facilities...........  0.05 x A...........              7.60
    Engineering and Home Office    0.10 x A...........             15.20
     Fees.
    Process Contingencies........  0.05 x A...........              7.60
Total Indirect Installation        0.20 x A...........             30.39
 Costs, B.
Project Contingency, C...........  0.15 x (A + B).....             27.36
Total Plant Cost, D..............  A + B + C..........            212.53
Preproduction Cost, G............  0.02 x D...........              4.25
Inventory Capital (Reagent), H...  ...................             0.087
Natural Gas Pipeline.............  ...................              2.81
                                  --------------------------------------
    Total Capital Investment, TCI  ...................            216.87
     = D + G + H.
------------------------------------------------------------------------
\1\ See Table 46 for an explanation of Scenarios.

[[Page 58612]]

 Table 45--Summary of EPA NOX BART Annual Costs for TESCR Scenario 3 \1\
                            on Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor        Cost ($) \2\
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........              3.25
Reagent..........................  ...................             0.396
Catalyst.........................  ...................             0.425
Electricity......................  ...................              3.96
Natural Gas for Flue Gas           ...................              6.00
 Reheating and Urea to Ammonia
 Conversion.
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various                  17.82
     (TDAC).                        Items Listed Above.
Indirect Annual Cost \3\ (IDAC)..  CRF x TCI..........             18.91
Annual ASOFA Cost (AAC)..........  ...................              3.84
                                  --------------------------------------
    Total Annual Cost (TAC)......  TDAC + IDAC + AAC..             40.57
------------------------------------------------------------------------
\1\ See Table 46 for an explanation of Scenarios.
\2\ Costs are in 2009 dollars.
\3\ Capital Recovery Factor (CRF) is 0.0872 and is based on a 6%
  interest rate and 20 year equipment life. From Minnkota NOX BACT
  Analysis Study, Milton R. Young Station Unit 1, Table C.1-1, p. C1-4,
  October 2006 (provided in BART Determination Study for Milton R. Young
  Station Units 1 and 2, October 2006, SIP Appendix C.4).

  Table 46--Summary of EPA NOX BART Costs for Various TESCR + ASOFA Scenarios on Milton R. Young Station Unit 2
                                                     Boiler
----------------------------------------------------------------------------------------------------------------
                                                                Emissions                         Average cost
              Scenario                    Description        reductions \1\     Total annual    effectiveness ($/
                                                               (tons/year)       cost ($MM)           ton)
----------------------------------------------------------------------------------------------------------------
1..................................  1 layer replaced                 14,825             43.63             2,943
                                      every year.
2..................................  1 layer replaced                 14,816             41.89             2,827
                                      every 2 years.
3..................................  1 layer replaced                 14,807             40.57             2,740
                                      every 3 years.
4..................................  ASOFA downtime                   14,829             42.89             2,892
                                      allowed.
----------------------------------------------------------------------------------------------------------------
\1\ Reductions vary based on impacts to boiler availability in each scenario (i.e., lower boiler operating hours
  equate to lower emissions).

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and 
operation of the evaluated controls are not significant enough to 
warrant eliminating either SNCR or SCR.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant 
enough to warrant eliminating either SNCR or SCR.
    Factor 4: Remaining useful life.
    The remaining useful life of Milton R. Young Station Unit 2 is at 
least 20 years. Thus, this factor does not impact our BART 
determination.
    Factor 5: Evaluate visibility impacts.
    Minnkota modeled the visibility benefits for SNCR + ASOFA using 
natural background per the BART Guidelines, North Dakota then performed 
additional modeling for the SCR + ASOFA control option. Minnkota and 
North Dakota both provided single-source modeling results using natural 
background conditions, complying with the BART Guidelines. The SCR + 
ASOFA option, when combined with wet scrubbing for SO2, 
would result in a significant improvement in visibility at Theodore 
Roosevelt--estimated to be 3.945 deciviews and 110 fewer days above 0.5 
deciviews. This represents an incremental visibility improvement of 
2.318 deciviews and 58 fewer days above 0.5 deciviews beyond that 
achieved by wet scrubbing alone. Moreover, when compared to SNCR + 
ASOFA, it would result in an incremental visibility improvement of 
0.566 deciviews and 21 fewer days above 0.5 deciviews. North Dakota 
conducted supplemental cumulative modeling for SCR at Milton R. Young 
Station 2 that is discussed in more detail in section V.D.1.e. For the 
reasons described there, we are disregarding North Dakota's alternative 
modeling in our analysis. More information on our interpretation of the 
State's and source's modeling information is included in the Technical 
Support Document.
    Step 5: Select BART.
    We propose to find that BART is SCR + ASOFA at Milton R. Young 
Station 2 with an emission limit of 0.07 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. We 
agree with the State that the other three factors are not relevant to 
this BART determination.
    In our BART analysis for NOX at Milton R. Young Station 
2, we considered SNCR + ASOFA and SCR + ASOFA. The comparison between 
our SNCR analysis and our TESCR Scenario 3 analysis is provided in 
Table 47.

                Table 47--Summary of EPA NOX BART Analysis Comparison of TESCR and SNCR Options for Milton R. Young Station Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Visibility impacts 1 2 4
                                                             Total                                         Incremental   -------------------------------
                                                           installed     Total annual     Average cost         cost         Visibility
                    Control option                       capital cost     cost (MM$)     effectiveness    effectiveness     improvement    Fewer days >
                                                             (MM$)                          ($/ton)          ($/ton)          (delta          0.5 dv
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
TESCR + ASOFA (Scenario 3)............................      \3\ 216.9            40.57            2,740            5,695           3.945             110

[[Page 58613]]

 
SNCR + ASOFA..........................................           17.45            6.44              703  ...............           3.379              89
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Minnkota's and the State's modeling for both SNCR and SCR was based on lower emissions reductions (fewer tons removed) than we anticipate; thus, we
  anticipate slightly greater visibility benefits (delta deciview) than reflected in these values. The visibility benefit shown is for the most impacted
  Class I area, Theodore Roosevelt.
\2\ Minnkota and the State conducted the modeling with combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of
  wet scrubbing along with the noted NOX control option.
\3\ This installed capital cost estimate does not include the capital cost of ASOFA. The total annualized cost does include the capital cost of ASOFA.
\4\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    As discussed in more detail in the Technical Support Document, we 
have concluded that SNCR + ASOFA and SCR + ASOFA are both cost 
effective control technologies and that both would provide substantial 
visibility benefits. SNCR + ASOFA has a cost effectiveness value of 
$703 per ton. While SCR + ASOFA is more expensive than SNCR + ASOFA, it 
has a cost effectiveness value of $2,740 per ton of NOX 
emissions reduced. This is well within the range of values we have 
considered reasonable for BART and that states other than North Dakota 
have considered reasonable for BART. Even with more frequent catalyst 
replacement, SCR would still be cost effective even at the high end of 
the range ($2,892 per ton) allowing for the most frequent catalyst 
replacement of one layer per year and allowing for the questionable 
costs of lost power generation revenue in TESCR Scenario 4. We also 
analyzed the SCR costs assuming the same baseline emissions of 15,507 
tons per year used by North Dakota and determined that the high-end 
cost effectiveness value, assuming the most frequent catalyst 
replacement frequency, would be about $2,949 per ton of NOX 
reduced. All of these cost effectiveness values are well within the 
range of values that North Dakota considered reasonable in several of 
its NOX BART determinations, where predicted visibility 
improvement was considerably lower.
    We have weighed costs against the anticipated visibility impacts at 
Milton R. Young Station Unit 2, as modeled by Minnkota and the State. 
Both sets of controls would have a positive impact on visibility. As 
compared to SNCR + ASOFA, SCR + ASOFA would provide an additional 
visibility benefit of 0.566 deciview at Theodore Roosevelt and 21 fewer 
days above 0.5 deciviews. We consider these impacts to be substantial, 
especially in light of the fact that neither of these Class I areas is 
projected to meet the uniform rate of progress. We also note that the 
0.566 deciview improvement at Theodore Roosevelt is greater than the 
improvement in visibility that North Dakota found reasonable to support 
other NOX BART determinations in the SIP, at higher cost 
effectiveness values. Given the visibility improvement associated with 
SCR + ASOFA, the relatively low incremental cost effectiveness between 
the two control options ($6,045 per ton), and the reasonable average 
cost effectiveness values for SCR + ASOFA, we propose that the 
NOX BART emission limit for Milton R. Young Station 2 should 
be based on SCR + ASOFA.
    In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted 
the annual design rate of 0.05 lb/MMBtu upwards to allow for a 
sufficient margin of compliance for a 30-day rolling average limit that 
would apply at all times, including during startup, shutdown, and 
malfunction.\51\ We are also proposing monitoring, recordkeeping, and 
reporting requirements in regulatory text at the end of this proposal.
---------------------------------------------------------------------------

    \51\ 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.'' Based on the retrofit 
of other SCR installations we have reviewed, we propose a compliance 
deadline of five (5) years from the date our final FIP becomes 
effective.
4. BART Analysis for Leland Olds Station 2
    Step 1: Identify All Available Technologies.
    As with the Milton R. Young Station Units, our analysis for Leland 
Olds Unit 2 only considers SNCR + ASOFA and SCR + ASOFA. Because the 
State selected SNCR + ASOFA as BART, and our concern is that the State 
did not properly evaluate SCR as BART, there is no need to consider 
lower-performing technologies.
    Step 2: Eliminate Technically Infeasible Options.
    We are not eliminating either SNCR or SCR as being technically 
infeasible. Both technologies have been widely employed to control 
NOX emissions from coal-fired power plants. The State 
determined SNCR was technically feasible for North Dakota EGUs. We 
agree with the State that SNCR is technically feasible. The State also 
determined, in Section 7 of the SIP, that two forms of SCR are 
technically feasible for use on North Dakota EGUs burning lignite coal. 
The State based its conclusion on an analysis it provided in Appendix 
B.5 to its Regional Haze SIP.
    For further discussion concerning the technical feasibility of SCR, 
please see our NOX BART analysis and determination for 
Milton R. Young Station Unit 1 and our Technical Support Document.
    Step 3: Evaluate Control Effectiveness of Remaining Control 
Technologies.
    For the purposes of our SNCR + ASOFA cost analysis, we used a 
control efficiency of 54% and an emission rate of 0.305 lb/MMBtu, the 
same control efficiency that North Dakota used. For our TESCR + ASOFA 
cost analysis we used a control efficiency of 93% and an emission rate 
of 0.05 lb/MMBtu, instead of North Dakota's 90% control efficiency and 
0.07 lb/MMBtu emission

[[Page 58614]]

rate. We find that SCR technology, by itself, can achieve 90% control 
efficiency and that the overall NOX reduction would be even 
greater (93%) with the use of combustion controls in combination with 
SCR. A summary of emissions and the two control options is provided in 
Table 48.

      Table 48--Summary of EPA NOX BART Analysis Control Technologies for Leland Olds Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                                                    Emissions
             Control option                   Control      Emission rate (lb/ Emissions (tons/  reduction (tons/
                                          efficiency (%)         MMBtu)              yr)               yr)
----------------------------------------------------------------------------------------------------------------
TESCR + ASOFA..........................                93              0.05                900            12,100
SNCR + ASOFA...........................                54              0.305             5,900             7,100
No Controls (Baseline).................                 0              0.67         \1\ 13,000  ................
----------------------------------------------------------------------------------------------------------------
\1\ We calculated our baseline using the same method used by Sargent & Lundy in its May 2009 report, but we
  adjusted the capacity factor downward to 86.5%.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Cost of compliance.
    SNCR + ASOFA.
    We are not relying on North Dakota's costs for SNCR. Though the 
North Dakota costs, developed by Sargent & Lundy on behalf of Basin 
Electric, are generally consistent with the Control Cost Manual, at 
least one cost, related to lost revenue due to outage, is not. To 
ensure a fair comparison between the two competing technologies, we 
have re-worked the costs for SNCR.
    We relied on Sargent & Lundy's estimate for total capital 
investment costs but adjusted them for 2009 dollars.\52\ Then, we 
generally used factors and assumptions for annual costs provided by the 
Control Cost Manual. In the absence of a Control Cost Manual method for 
combustion controls, we used all the costs that North Dakota provided 
for ASOFA.
---------------------------------------------------------------------------

    \52\ We obtained capital costs from the company's BART analysis 
in Appendix C of the SIP. Adjustment to 2009 dollars was 
accomplished using the Chemical Engineering Plant Cost Index (CEPCI) 
for 2009 and 2006 (521.9/499.6=1.044). Available from Chemical 
Engineering Magazine (http://www.che.com).
---------------------------------------------------------------------------

    This is the same approach we used to analyze the costs for TESCR at 
Leland Olds Station 2, which enables us to compare the costs of SNCR 
and TESCR on a consistent basis. Our effort to re-estimate the costs 
for SNCR was not exhaustive, but it did result in a downward adjustment 
in the cost estimate for SNCR. We deem the analysis adequate for 
comparing the cost effectiveness values of the two top control 
options--SCR and SNCR.
    Regarding specific elements in our cost analysis, we used $475 per 
ton to estimate urea costs and did not allow for lost revenue due to 
outage because the Control Cost Manual does not allow for lost revenue 
due to outage. To estimate the average cost effectiveness (dollars per 
ton of emissions reductions), we divided the total annualized cost by 
the estimated NOX emissions reductions. We summarize our 
costs from our SNCR cost analysis in Tables 49, 50, and 51. See the 
Technical Support Document for our full analyses.

   Table 49--Summary of EPA NOX BART Capital Cost Analysis for SNCR on
                    Leland Olds Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A......  ...................        11,440,000
Capital Investment SNCR, B.......  ...................         7,800,000
                                  --------------------------------------
    Total Capital Investment, TCI  A + B..............        19,240,000
     (2009$).
------------------------------------------------------------------------

 Table 50--Summary of EPA NOX BART Annual Costs for SNCR on Leland Olds
                          Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........           117,000
Reagent..........................  ...................         2,704,208
Electricity......................  ...................            44,656
Water............................  ...................             2,183
Increased Coal...................  ...................            83,927
Increased Ash....................  ...................             6,117
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various              2,958,090
     (TDAC).                        Items Listed Above.
                                  --------------------------------------
Indirect Annual Cost \1\ (IDAC)..  CRF x TCI..........           736,265
                                  --------------------------------------
    Total Annual Cost SNCR (TACS)  TDAC + IDAC........         3,694,355
                                  --------------------------------------
    Total Annual Cost ASOFA \2\    ...................         1,256,855
     (TACA).
                                  --------------------------------------
    Total Annual Cost SNCR +       TACS + TACA........         4,951,210
     ASOFA.
------------------------------------------------------------------------
\1\ Capital Recovery Factor (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 58615]]

 
\2\ Calculated from Table 2.5-2, Basin Electric letter, May 29, 2009,
  Appendix C.1.

              Table 51--Summary of EPA NOX BART Costs for SNCR on Leland Olds Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                              Total installed       Total          Emissions       Average cost
               Control option                   capital cost   annualized cost     reductions     effectiveness
                                                   (MM$)            (MM$)          (tons/yr)         ($/ton)
----------------------------------------------------------------------------------------------------------------
SNCR + ASOFA................................           19.24             4.95            7,100              700
----------------------------------------------------------------------------------------------------------------

    TESCR + ASOFA.
    Dr. Phyllis Fox, PhD, PE, as subcontractor to our contractor, RTI, 
prepared a cost analysis for TESCR for Leland Olds Station Unit 2. Dr. 
Fox started with the cost information in the Sargent & Lundy letter 
report dated May 27, 2009 with Basin Electric cover letter dated May 
29, 2009. See SIP Appendix C.1. As described in greater detail below, 
while Dr. Fox relied on Sargent & Lundy's estimate for total capital 
investment for TESCR equipment and for the unit cost for catalyst, she 
adjusted Sargent & Lundy's assumptions for various other costs to make 
them consistent with the Control Cost Manual and reasonable costing 
assumptions.
    TESCR + ASOFA Capital Costs.
    The May 27, 2009 Sargent & Lundy Cost Analysis reports a capital 
cost range of $165,800,000 to $170,800,000 for installed capital costs 
for TESCR + ASOFA in 2009 dollars.\53\ Sargent & Lundy calculated these 
costs from a lump sum unit capital cost estimate expressed in dollars 
per kilowatt of electricity generated. These costs are significantly 
higher than costs reported for similar installations.\54\ We were not 
able to determine the basis for the deviation because Sargent & Lundy 
did not provide support for its unit capital cost estimate. Contrary to 
common practice, Sargent & Lundy did not separately identify equipment 
(e.g., reactor housing, ducts, bypass, NH3 injection system, 
sonic horns, etc.) and installation costs. Nonetheless, we used Sargent 
& Lundy's total capital investment estimate as the basis for our 
analysis, with the exception of the total capital costs for sorbent 
injection.\55\ The result is a cost estimate that should represent the 
upper bound of likely costs.
---------------------------------------------------------------------------

    \53\ 5/27/09 S&L Cost Analysis, Table 2.5-2.
    \54\ Data indicates that Sargent & Lundy's estimate of capital 
costs to retrofit SCR at Leland Olds ($373/kW in 2010 dollars) is 
higher than actual installed costs for existing retrofit SCRs, 
including those with extreme retrofit difficulty and those requiring 
flue gas reheat. For further detail, please see our Technical 
Support Document. Thus, we consider our resulting cost effectiveness 
value to be conservative in favor of Basin Electric and to represent 
an upper bound for installation and operation of an SCR on LOS Unit 
2. Put another way, we believe the cost effectiveness of SCR on LOS 
Unit 2 is more favorable than our estimate suggests.
    \55\ Dr. Fox concluded that a sorbent injection system would not 
be needed to reduce sulfuric acid mist because low conversion 
catalysts are available and because tail-end SCR would operate at a 
much lower temperature than high-dust SCR, which would significantly 
reduce the conversion of SO2 to SO3. Dr. Fox 
concluded that the conversion could be kept below the significance 
level. Our rationale for excluding sorbent injection is further 
discussed in our Technical Support Document.
---------------------------------------------------------------------------

    For our analysis, we used a total installed capital cost estimate 
of $164,676,000 in 2009 dollars. This includes the cost of ASOFA but 
not the cost of a dry sorbent injection control system. This estimate 
is based primarily on the Sargent & Lundy lump sum unit capital cost 
estimate expressed in dollars per kilowatt of electricity generated, 
$350/kW, in 2009 dollars.
    TESCR + ASOFA Annual Costs.
    As previously discussed, the total capital cost is annualized using 
a capital recovery factor. This value is then summed with estimated 
annual operating and maintenance costs to arrive at a value for total 
annual costs.
    Using an appropriate capital recovery factor of 0.08718, Dr. Fox 
calculated an annualized capital cost of $14,356,000 in 2009 dollars. 
Dr. Fox estimated that total annual operating and maintenance costs 
would be $22,090,000. Sargent & Lundy's estimate of variable operating 
and maintenance costs (NH3, catalyst, power, natural gas, 
outage cost, and sorbent injection) was three to five times higher than 
Dr. Fox's estimate.
    Below, we provide further detail regarding some of the major 
assumptions and reasoning underlying our estimate of annual operating 
and maintenance costs.\56\
---------------------------------------------------------------------------

    \56\ Contrary to Sargent & Lundy's approach, Dr. Fox did not 
``levelize'' annual costs. As explained more fully in our evaluation 
of the State's NOx BART determinations for MRYS Units 1 and 2 and 
LOS Unit 2, the Control Cost Manual does not provide for 
levelization of annual costs.
---------------------------------------------------------------------------

Costs Related to Catalyst
Catalyst Lifetime
    As noted already, an SCR catalyst must be changed out periodically. 
Information regarding catalyst life that we relied on for our cost 
analysis for Milton R. Young Station Units 1 and 2 is also relevant 
here. Leland Olds Station Unit 2 burns similar North Dakota lignite in 
a similar cyclone boiler. We note that Dr. Fox examined information 
related to catalyst life at Milton R. Young Station and independently 
considered relevant data and information to conclude that 24,000 hours 
is a reasonable assumption for catalyst life at Leland Olds Station. 
This is what Dr. Fox used for her cost analysis for Leland Olds Station 
Unit 2. Dr. Fox rejected Sargent & Lundy's estimate that catalyst life 
would only be six to 12 months; she found that Sargent & Lundy's 
estimate was based on a number of faulty assumptions. For further 
detail regarding catalyst life, please see our BART analysis and 
determination for Milton R. Young Station Unit 1 and our Technical 
Support Document.
    Although we are confident that 24,000 hours represents a 
conservative assumption for catalyst life at Leland Olds Station Unit 
2, we have also prepared cost estimates using 8,000 and 16,000 hours as 
assumptions for catalyst life in order to determine the sensitivity of 
costs to this variable. Further information is provided below.
Number of Catalyst Layers
    The catalyst volume required to achieve a given NOX 
level is typically divided into layers that can be separately replaced. 
Most SCR designs include an empty layer that can be filled with 
catalyst as the need arises. The most common configuration is two 
active layers with one spare. Initially, two layers are filled with 
catalyst. The third layer is added at the end of the initial catalyst 
lifetime.
    We assumed an initial configuration of two filled and one empty 
layer of catalyst in our cost analysis, which is consistent with the 
design of modern SCRs. The empty layer would be filled after 24,000 
hours, the assumed catalyst life.
Time Value of Money
    The Control Cost Manual explains that the future worth factor 
should be used to amortize catalyst cost over the years preceding the 
actual catalyst purchase. As money is allocated in advance of purchase, 
the sum of the

[[Page 58616]]

annual catalyst replacement cost is less than the purchase price of the 
catalyst. Thus, we have multiplied the catalyst purchase price by a 
future worth factor. Assuming an interest rate of 7%, a catalyst life 
of 24,000 hours, and a capacity factor of 86.5%, the future worth 
factor is 0.31.\57\
---------------------------------------------------------------------------

    \57\ Cost Manual, pdf 489-490, Eqn. 2.52: FWF = 0.07[1/(1.07\3\-
1)] = 0.31. Y = 24,000 hr/(8760)(0.865) = 3.2, rounds to 3.
---------------------------------------------------------------------------

Unit Catalyst Cost
    We have assumed a cost of $7,500 per cubic meter of catalyst ($/
m\3\), which is the same cost assumed in Sargent & Lundy's analysis. 
This is very high compared to values typically quoted by vendors, 
$4,500/m\3\-$6,500/m\3\, depending upon volume per order.\58\ While we 
find that $7,500/m\3\ is high, we did not have access to specific 
vendor quotes for this element due to confidentiality claims. This is 
another element that makes our cost estimate conservatively high.
---------------------------------------------------------------------------

    \58\ Letter from Callie A. Videtich, Director, Air Program, EPA 
Region 8, to Terry O'Clair, Director, Division of Air Quality, North 
Dakota Department of Health, Re: EPA Region 8 Comments on December 
2009 Draft Regional Haze SIP (Public Comment Version), January 8, 
2010, Enclosure 2, p. 28; e-mail from Anthony C. Favale, Director--
SCR Products, Hitachi Power Systems America, Ltd., to Anita Lee, 
U.S. EPA, Region 9, Re: CX Catalyst Question, April 1, 2010 ($5,500/
m\3\ to $6,000/m\3\); e-mail from Flemming Hansen, Manager SCR DeNOx 
Catalyst, Haldor T[oslash]psoe, to Phyllis Fox, P.E., Re: Catalyst 
Cost, January 23, 2008 ($6,000/m\3\).
---------------------------------------------------------------------------

Catalyst Volume
    Sargent & Lundy assumed a catalyst volume of 530 m\3\ in its cost 
calculations.\59\ The Sargent & Lundy spreadsheets produced in response 
to our CAA section 114 request indicate that this figure was derived by 
arbitrarily increasing a catalyst volume of 440 m\3\ by 20%.\60\ The 
source of the starting point (440 m\3\) and the 20% adjustment are not 
disclosed.
---------------------------------------------------------------------------

    \59\ 5/27/09 S&L Cost Analysis, p. 7.
    \60\ See, e.g., Sargent & Lundy spreadsheet: low-high dust scr-
leland old2--Sens2-cat life--05109.xls, cell E25 (440x1.20).
---------------------------------------------------------------------------

    As we commented on the draft Regional Haze SIP, the value of 530 
m\3\ is high for a TESCR. Typically, cyclone fired units require about 
1.5 m\3\ of catalyst per MW for a high-dust SCR, while TESCRs require 
less than half the catalyst volume of a high-dust SCR.\61\ Thus, one 
would expect a catalyst volume of about 330 m\3\ for Leland Olds 
Station Unit 2. However, we used the unadjusted catalyst volume of 440 
m\3\ from Sargent & Lundy's spreadsheets as a highly conservative upper 
bound.
---------------------------------------------------------------------------

    \61\ 1/8/10 EPA Comments, Enclosure 1, p. 27.
---------------------------------------------------------------------------

Catalyst Changeout Time
    First, a special outage to change out the catalyst would not be 
required. The catalyst can be changed out during scheduled major 
outages, which occur every 3 years. The first catalyst change would 
occur 3 years after installation. Thus, careful planning would align 
the first and subsequent changes with major outages, requiring no lost 
generation charges.
    Second, the estimated catalyst exchange rate for a TESCR on the 
similar Milton R. Young Station units was 2.2 days for Unit 1 (257 MW) 
and 3.8 days for Unit 2 (477 MW).\62\ Based on these values, the 
proportional exchange time for Leland Olds Station Unit 2 is 3.6 days. 
This is generally consistent with industry experience. Alternatively, 
as the boiler is typically down for cleaning 3 to 4 times per year for 
a period of about 4 days each time, this downtime would be sufficient 
to exchange a layer should one be required before a major outage. SCR 
systems are designed to minimize unit downtime to minimize operating 
costs.
---------------------------------------------------------------------------

    \62\ Hartenstein Report, April 2010, p. 36.
---------------------------------------------------------------------------

    Thus, we assumed there would be no lost generation during catalyst 
replacement because it would be prudent design and operating practice 
to schedule these events during routinely scheduled maintenance 
outages.
Cost of Utilities and Supplies
    We have included costs for NH3, the reagent used in the 
SCR, and natural gas, used to reheat the flue gas. Our costs for these 
items do not reflect potential changes in future commodity prices. This 
is because cost effectiveness methodology is based on the current 
annualized cost without escalation. The Control Cost Manual approach, 
recommended by the BART Guidelines, explicitly excludes future 
escalation because cost comparisons are made on a current real dollar 
basis. Inflation is not included in cost effectiveness analyses as 
these analyses rely on the most accurate information available at 
current prices and do not try to extrapolate those prices into the 
future.\63\
---------------------------------------------------------------------------

    \63\ See, e.g., Cost Manual, p. 2-36, pdf 50.
---------------------------------------------------------------------------

Ammonia (NH3)
    Recent BART analyses have used values in the range of $450 per ton. 
Black & Veatch, an engineering firm that designs SCRs, used an 
anhydrous ammonia cost of $450 per ton in a September 2010 BART 
analysis for Boardman.\64\ Sargent & Lundy used an anhydrous ammonia 
cost of $475 per ton in a September 2010 BART analysis for the Navajo 
Generating Station.\65\ We used $475 per ton for the cost of 
NH3.
---------------------------------------------------------------------------

    \64\ Black & Veatch, Portland General Electric Boardman Plant, 
Best Available Retrofit Technology (BART)/Reasonable Progress 
Analysis Revision 3: Boardman 2020 Alternative, August 27, 2010, 
Table 2-2.
    \65\ Sargent & Lundy, Salt River Project Navajo Generating 
Station--Units 1, 2, 3, SCR and Baghouse Capital Cost Estimate 
Report, Revision D, August 17, 2010, pdf 58, Table 9-2.
---------------------------------------------------------------------------

Natural Gas
    The temperature of the flue gas exiting the wet scrubber must be 
raised to SCR operating temperature. There is more than one method for 
doing this. One method uses natural gas. The other uses steam. The cost 
of reheating the flue gas is typically one of the most significant 
operating costs for a TESCR.
    Steam has important advantages over natural gas for use in flue gas 
reheating: lower cost, no increase in flue gas flow rate from gas 
combustion byproducts, no moisture condensation on the catalyst, and no 
risk of re-vaporization of catalyst poisons in the flame of a duct 
burner. Most TESCRs in Europe use steam for reheating.\66\ Vendors in 
the Milton R. Young Station case uniformly recommended the use of a 
steam coil in place of natural gas-fired duct burners.\67\ However, 
Sargent & Lundy did not evaluate the use of steam, and we lack the 
information needed to accurately calculate the cost of steam. Thus, we 
assumed the use of natural gas in our cost estimates. This is another 
indication that our estimate is conservative.
---------------------------------------------------------------------------

    \66\ 1/8/10 EPA Comments, Enclosure 1, p. 25.
    \67\ See, e.g., Hartenstein Report, April 2010, pp. 34-35, 40-
43.
---------------------------------------------------------------------------

    Operating experience with numerous TESCRs in Europe over the past 
20 years indicates that an increase of 20 to 25 degrees F is adequate 
for reheat.\68\ Further, an SCR operating temperature of 525-550 
degrees F is sufficient for a TESCR as the flue gas SO2 
concentrations after the wet scrubber are low, eliminating the concern 
with deposition of ammonia salts on the catalyst.\69\ Burns & McDonnell 
estimated a natural gas firing rate of 66.4

[[Page 58617]]

MMBtu/hr for TESCR on Milton R. Young Station Unit 2.\70\ The Burns & 
McDonnell estimate is consistent with European experience. Thus, we 
used 66.4 MMBtu/hr in our cost analysis.
---------------------------------------------------------------------------

    \68\ Hartenstein Report, April 2010, p. 40.
    \69\ McIlvaine, Next Generation SCR Choices--High-Dust, Low-Dust 
and Tail-End, FGD & DeNOx Newsletter, No. 369, January 2009; 5/6/08 
Cochran (CERAM) e-mail, p. 2 (``Ammonia should not be injected below 
the minimum operating temperatures (MOT). Based on the SO2 to SO3 
reported the MOT would be approximately 600 F. For lower sulfur 
fuels [such as ND lignite] and/or reduced NOX removal 
performance a lower MOT would be possible. Additionally, brief 
periods of operation below the MOT would be possible without 
permanent degradation. In no event would any ammonia be allowed to 
be injected below 530 F for any likely combination of reasonable 
sulfur and NOX removal parameters.''), in 5/8/08 Milton 
R. Young Additional Information.
    \70\ Burns & McDonnell, Technology Feasibility Analysis and Cost 
Estimates for Leland Olds Station Unit 1 and 2, Basin Electric Power 
Cooperative, Final Draft, December 2005, p. 86.
---------------------------------------------------------------------------

    Next, we determined an appropriate price assumption for natural 
gas. As noted, BART cost effectiveness analyses are based on the best 
estimate of current costs at the time of the analysis and do not 
consider future escalation. As cost effectiveness is determined 
relative to other similar sources, future escalation in gas prices 
would affect all natural gas users, not just Leland Olds Station.
    The most recent data reported to the Energy Information Agency 
(EIA) indicates that the cost of natural gas to electric power 
consumers in North Dakota has ranged from $4.48/MMBtu (October 2010) to 
$5.37/MMBtu (June 2010).\71\ As very little natural gas is currently 
used in North Dakota, a more reasonable estimate for a dedicated supply 
is the Henry Hub spot price plus transportation cost. The 2010 Henry 
Hub price of natural gas is $4.37/MMBtu.\72\ The expected Henry Hub 
natural gas spot price for 2011 is $4.16/MMBtu, or $0.21/MMBtu lower 
than 2010. The Energy Information Agency expects the natural gas market 
to begin to tighten in 2012, with the Henry Hub spot price increasing 
to an average of $4.58/MMBtu.\73\ Transportation cost is typically less 
than $1/MMBtu. Thus, a reasonable estimate for purposes of our analysis 
is about $5.50/MMBtu.
---------------------------------------------------------------------------

    \71\ EIA, Natural Gas Monthly:http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/natural_gas_monthly/ngm.html.
    \72\ http://tonto.eia.gov/dnav/ng/hist/rngwhhda.htm.
    \73\ http://www.eia.doe.gov/analysis/ and http://www.eia.gov/emeu/steo/pub/contents.html.
---------------------------------------------------------------------------

Power
    An SCR increases power demand for auxiliary equipment, including 
the induced draft fans used to overcome the increase in backpressure 
from the SCR plus electricity to run the NH3 system, 
dilution air blower, dilution air heaters, and seal air fans. Thus, 
auxiliary power is the electricity required to run the plant, or 
electricity not sold.
    This cost is estimated by multiplying the electricity demand in 
kilowatts by the cost of electricity in dollars per megawatt hour 
(MWh). Cost effectiveness analyses are based on the cost to the owner 
to generate electricity, or the busbar cost, not market retail rates. 
The unit cost of electricity used by Sargent & Lundy, $50/MWh, is high 
for a lignite-fired boiler built near its fuel source. Burns & 
McDonnell assumed $38/MWh in the 2005 Feasibility Analysis for Leland 
Olds \74\ and $35/MWh for Milton R. Young Unit 1.\75\ We used $38/MWh, 
the value Burns & McDonnell reported for Leland Olds.
---------------------------------------------------------------------------

    \74\ Burns & McDonnell, Technology Feasibility Analysis and Cost 
Estimate for Leland Olds Station Unit 1 and 2, Basin Electric Power 
Cooperative, Final Draft, December 2005, p. 86.
    \75\ Burns & McDonnell, NOX Best Available Control 
Technology Analysis Study--Supplemental Report for Milton R. Young 
Station Unit 1, Minnkota Power Cooperative, Inc., November 2009, p. 
4-42.
---------------------------------------------------------------------------

Capacity Factor
    The capacity factor is the fraction of the available capacity that 
is actually used. It is calculated as the ratio of the actual 
electrical output to its full capacity, typically over a year. The 
emission reductions and variable operating and maintenance costs are 
both directly proportional to the capacity factor. The higher the 
capacity factor, the larger the emission reductions and the higher the 
variable operating and maintenance costs.
    The BART Guidelines indicate that: ``in the absence of enforceable 
limitations, you calculate baseline emissions based upon continuation 
of past practice.'' \76\ The Sargent & Lundy analysis calculated the 
capacity factor assuming the unit would operate at full capacity at all 
times except during catalyst change-outs. This resulted in capacity 
factors of 92% to 96%, which are higher than operating experience.
---------------------------------------------------------------------------

    \76\ 70 FR 39167 (July 6, 2005).
---------------------------------------------------------------------------

    Dr. Fox calculated a capacity factor of 86.5%. This was based on a 
comparison of Leland Olds Station Unit 2's actual electrical output for 
a baseline period, obtained from monthly Clean Air Markets data, to its 
rated capacity (440 MW).\77\ This 86.5% value was used to calculate 
NOX emission reductions and variable operating and 
maintenance costs.
---------------------------------------------------------------------------

    \77\ Capacity factor = 3,334,426 MWh/[(440)(8760)] = 0.865.
---------------------------------------------------------------------------

NOX Emission Reduction

    In our calculations, we assumed TESCR + ASOFA reduced baseline 
NOX emissions of 0.67 lb/MMBtu \78\ to 0.05 lb/MMBtu. An SCR 
outlet NOX emission rate of 0.05 lb/MMBtu can be readily 
achieved by TESCR + ASOFA. The May 27, 2009 Sargent & Lundy analysis 
and supporting spreadsheets assumed the combination achieved 0.05 lb/
MMBtu. In the Sargent & Lundy analysis, the SCR was specifically 
assumed to reduce NOX from an inlet of 0.48 lb/MMBtu, a 
level consistent with performance of Leland Olds Unit 2 since 
installation of ASOFA, to 0.05 lb/MMBtu or 90% NOX control.
---------------------------------------------------------------------------

    \78\ North Dakota's BART Determination for Leland Olds Station 
Units 1 and 2, SIP Appendix B.1, p. 24.
---------------------------------------------------------------------------

    We added the annual costs for ASOFA to the annual costs for TESCR 
to arrive at a total annual cost for the combined controls. To estimate 
the average cost effectiveness (dollars per ton of emissions 
reductions), we then divided the total annual cost by the estimated 
NOX emission reductions. We summarize our cost estimates in 
Tables 52, 53 and 54. See our Technical Support Document for the full 
analyses.

    Table 52--Summary of EPA NOX BART Capital Cost Analysis for TESCR
             Scenario 3 on Leland Olds Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Capital Investment (2010$) ASOFA,  ...................        11,440,000
 A.
Capital Investment (2010$) SCR, B  ...................       164,121,000
------------------------------------------------------------------------
Total Capital Investment, TCI      A + B..............       175,561,000
 (2010$).
Total Capital Investment, TCI      TCI(2010) x               164,734,423
 (2009$).                           CEPCI(521.9/556.2).
------------------------------------------------------------------------

[[Page 58618]]

Table 53--Summary of Some EPA NOX BART Annual Costs for TESCR Scenario 3
                \1\ on Leland Olds Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor        Cost ($) \2\
------------------------------------------------------------------------
Annual Maintenance...............  .015xTCI...........           823,564
Reagent..........................  ...................         2,115,190
Catalyst.........................  ...................           320,796
Electricity......................  ...................         1,878,814
Natural Gas for Flue Gas           ...................         2,595,446
 Reheating and Urea to Ammonia
 Conversion.
                                  --------------------------------------
    Total Direct Annual Cost       ...................         7,733,810
     (TDAC)..
    Indirect Annual Cost \3\       CRF x TCI..........        14,356,473
     (IDAC).
                                  --------------------------------------
    Total Annual Cost (TAC)......  TDAC + IDAC........        22,090,283
------------------------------------------------------------------------
\1\ See Table 54 for an explanation of Scenarios.
\2\ Costs are in 2009 dollars.
\3\ Capital Recovery Factor (CRF) is 0.08718 and is based on a 6%
  interest rate and 20 year equipment life. From Table 1.2-3, BART
  Determination Study, Leland Olds Units 1 and 2, August 2006, SIP
  Appendix C.1.

Table 54--Summary of EPA NOX BART Costs for Various TESCR + ASOFA Scenarios on Leland Olds Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                Emissions                         Average cost
            Scenario                    Description            reductions     Total annualized    effectiveness
                                                               (tons/year)       cost  ($MM)         ($/ton)
----------------------------------------------------------------------------------------------------------------
1..............................  1 layer replaced every               12,050             24.31             1,892
                                  year.
2..............................  1 layer replaced every 2             12,050             23.74             1,848
                                  years.
3..............................  1 layer replaced every 3             12,050             23.55             1,833
                                  years.
----------------------------------------------------------------------------------------------------------------

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and 
operation of the evaluated controls are not significant enough to 
warrant eliminating either SNCR or SCR.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant 
enough to warrant eliminating either SNCR or SCR.
    Factor 4: Remaining useful life.
    The remaining useful life of Leland Olds Station Unit 2 is at least 
20 years. Thus, this factor does not impact our BART determination.
    Average cost effectiveness for each option.
    To estimate the average annual cost effectiveness (dollars per ton 
of emissions reductions), we divided the total annual cost by the 
estimated NOX emissions reductions. These estimates are 
noted in our summary in Table 55. Our average annual cost effectiveness 
estimate for SNCR + ASOFA at Leland Olds Station Unit 2 is $700 per ton 
of NOX reductions. Our average annual cost effectiveness 
estimate for SCR + ASOFA at Leland Olds Station Unit 2 is $1,833 per 
ton of NOX reductions.
    Step 5: Evaluate Visibility Impacts.
    Basin Electric modeled the visibility benefits for SNCR + ASOFA 
using natural background per the BART Guidelines. North Dakota then 
performed additional modeling for the SCR + ASOFA control option. Basin 
Electric and North Dakota both provided single-source modeling results 
using natural background conditions, complying with the BART 
Guidelines. The SCR + ASOFA option, when combined with FGD at 95% for 
SO2, would result in a significant improvement in visibility 
at Theodore Roosevelt, estimated to be 4.393 deciviews and 130 fewer 
days above 0.5 deciviews. As the State did not provide discrete 
modeling for individual pollutants, it is not possible to describe the 
incremental visibility benefits of SCR + ASOFA or other NOX 
control options over the selected SO2 BART control (FGD at 
95%). Nonetheless, when compared to SNCR + ASOFA, SCR would result in 
an incremental visibility improvement of 0.512 deciviews and 25 fewer 
days above 0.5 deciviews. North Dakota conducted supplemental 
cumulative modeling for SCR at Milton R. Young Station 1 that is 
discussed in more detail in section V.D.1.e. For the reasons described 
there, we are disregarding North Dakota's alternative modeling in our 
analysis.
    More information on our interpretation of the State's and source's 
modeling information is included in the Technical Support Document.
    Step 6: EPA BART Determination for Leland Olds Station 2.
    We propose to find that BART is SCR + ASOFA at Leland Olds Station 
2 with an emission limit of 0.07 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. We agree 
with the State that the other three factors are not relevant to this 
BART determination.
    The comparison between our SNCR + ASOFA analysis and our TESCR + 
ASOFA Scenario 3 analysis is provided in Table 55.

[[Page 58619]]

                  Table 55--Summary of EPA NOX BART Analysis Comparison of TESCR and SNCR Options for Leland Olds Station Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Visibility impacts 1, 2
                                                             Total                                         Incremental   -------------------------------
                                                           installed         Total        Average cost         cost         Visibility
                    Control option                       capital cost     annualized     effectiveness    effectiveness     improvement    Fewer days >
                                                             (MM$)        cost  (MM$)       ($/ton)          ($/ton)          (delta          0.5  dv
                                                                                                                            deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
TESCR + ASOFA (Scenario 3)............................          164.68           22.09            1,833            3,489           4.393             130
SNCR + ASOFA..........................................           19.24            4.95              700  ...............           3.874             105
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility modeling that North Dakota (for SCR) and Basin Electric (all scenarios but SCR) performed for Leland Olds Station Unit 2 included SO2
  control (FGD 95%) in addition to the noted NOX control. Thus, these values do not reflect the distinct visibility benefit from the NOX control options
  but do provide the incremental benefit between the options.
\2\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    We have concluded that SNCR + ASOFA and SCR + ASOFA are both cost 
effective control technologies and that both would provide substantial 
visibility benefits. SNCR + ASOFA has a cost effectiveness value of 
$700 per ton. While SCR + ASOFA is more expensive than SNCR + ASOFA, it 
has a cost effectiveness value of $1,833 per ton of NOX 
emissions reduced. This is well within the range of values we have 
considered reasonable for BART and that states other than North Dakota 
have considered reasonable for BART. Even if we assume a catalyst 
replacement frequency of one layer per year, which we find is highly 
unlikely, SCR would still be cost effective ($1,892 per ton). We also 
analyzed the SCR costs assuming the same baseline emissions of 12,023 
tons per year used by North Dakota and determined that the high-end 
cost effectiveness value, assuming the most frequent catalyst 
replacement frequency, would be about $2,035 per ton of NOX 
reduced. All of these cost effectiveness values are well within the 
range of values that North Dakota considered reasonable in several of 
its NOX BART determinations, where predicted visibility 
improvement was considerably lower.
    We have weighed costs against the anticipated visibility impacts at 
Leland Olds Station 2. Both sets of controls would have a positive 
impact on visibility. As compared to SNCR + ASOFA, SCR + ASOFA would 
provide an additional visibility benefit 0.512 deciviews and 25 fewer 
days above 0.5 deciviews at Theodore Roosevelt. We consider these 
impacts to be substantial, especially in light of the fact that neither 
of these Class I areas are projected to meet the uniform rate of 
progress. We also note that the 0.512 deciview improvement at Theodore 
Roosevelt is greater than the improvement in visibility that North 
Dakota found reasonable to support other NOX BART 
determinations in the SIP, at higher cost effectiveness values. Given 
the appreciable incremental visibility improvement associated with SCR 
+ ASOFA, the relatively low incremental cost effectiveness between the 
two control options ($3,489 per ton), and the reasonable average cost 
effectiveness values for SCR + ASOFA, we propose that the 
NOX BART emission limit for Leland Olds Station 2 should be 
based on SCR + ASOFA.
    In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted 
the annual design rate of 0.05 lb/MMBtu upwards to allow for a 
sufficient margin of compliance for a 30-day rolling average limit that 
would apply at all times, including during startup, shutdown, and 
malfunction.\79\ We are also proposing monitoring, recordkeeping, and 
reporting requirements in regulatory text at the end of this proposal.
---------------------------------------------------------------------------

    \79\ 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.'' Based on the retrofit 
of other SCR installations we have reviewed, we propose a compliance 
deadline of five (5) years from the date our final FIP becomes 
effective.

    Note regarding SCR at Milton R. Young Station Units 1 and 2 and 
Leland Olds Station Unit 2: Our proposal that SCR is BART at Milton 
R. Young Station Units 1 and 2 and Leland Olds Station Unit 2 has 
been thoroughly analyzed and considered. As we indicate above, the 
sources and the State believe that SCR is technically infeasible, 
based on their views regarding catalyst deactivation and the lack of 
firm vendor guarantees of catalyst life. We disagree with the 
sources and the State and have adopted assumptions we and our 
consultants consider reasonable regarding SCR catalyst life at these 
units. We note that, should we finalize our FIP as proposed, 
Minnkota, Basin Electric, and/or the State may request 
reconsideration of our final action based on the potential outcomes 
of any field testing regarding catalyst life they may choose to 
undertake prior to the date the emission limits in our FIP become 
effective.

F. Federal Implementation Plan to Address NOX BART for Coal 
Creek Station Units 1 and 2

1. Introduction
    As noted above, North Dakota selected SOFA + LNB as NOX 
BART for Coal Creek Station Units 1 and 2 but in doing so, 
inappropriately eliminated SNCR + SOFA + LNB and SCR + SOFA + LNB as 
potential BART based on erroneous cost information for Coal Creek 
Station's fly ash sales. Thus, in our proposed FIP, we are re-
evaluating LTO, SCR, SNCR, and low-NOX burners and SOFA as 
potential BART. Our analysis follows our BART Guidelines. For Coal 
Creek Station Units 1 and 2, the BART Guidelines are mandatory. Coal 
Creek Station has a capacity of 1,100 MWs. North Dakota selected low-
NOX burners and SOFA with an associated limit of 0.17 pounds 
per million Btu as NOX BART for Coal Creek.
2. BART analysis for Coal Creek Units 1 and 2
    Since Coal Creek Units 1 and 2 are identical, we are considering 
average historical data for each unit and then proposing a single BART 
determination that applies to each unit.
    Step 1: Identify All Available Technologies.
    Our analysis for Coal Creek Units 1 and 2 considers SOFA + LNB 
(combustion controls), and combustion controls in combination with 
SNCR, SCR, and LTO.

[[Page 58620]]

    Step 2: Eliminate Technically Infeasible Options.
    For the reasons described in our BART analysis and determination 
for Milton R. Young Station Units 1 and 2 and Leland Olds Station 2, we 
are not eliminating either SNCR or SCR as being technically infeasible. 
We are not eliminating any of the other control options as being 
technically infeasible. For ease of comparison, we are evaluating LDSCR 
(downstream of the particulate control device). This is the option that 
North Dakota and Great River Energy (GRE) evaluated, and this location 
for the SCR equipment is preferable to a high-dust location (upstream 
of the particulate control device) for minimizing the amount of ash and 
catalyst poisons that would otherwise be present in the flue gases, 
thus increasing catalyst life and decreasing operating costs. A tail-
end location (downstream of the particulate control and the 
SO2 wet scrubber control devices) is another feasible 
option. (See our BART determinations for Milton R. Young Station and 
Leland Olds Station units in sections V.E.2 and V.E.3 for further 
discussion of LDSCR and TESCR.) The State determined all options to be 
technically feasible, including LDSCR and TESCR, for North Dakota EGUs.
    Step 3: Evaluate Control Effectiveness of Remaining Control 
Technology.
    For the purposes of our SOFA + LNB cost analysis, we used a control 
efficiency of 29% and an emission rate of 0.15 lb/MMBtu. In our SNCR + 
ASOFA cost analysis, we used a control efficiency of 49% and an 
emission rate of 0.108 lb/MMBtu. For our LDSCR + ASOFA cost analysis we 
used a control efficiency of 80% and an emission rate of 0.043 lb/
MMBtu. We used the same emission rates as North Dakota and calculated 
slightly different efficiency ratings based on an emissions baseline 
for years 2000 through 2004. Due to limited time, we did not perform a 
separate cost analysis for LTO and are accepting the Great River Energy 
cost estimates that North Dakota used. These were based on a control 
efficiency of 90% and an emission rate of 0.022 lb/MMBtu. A summary of 
emissions and control options is provided in Table 56.

        Table 56--Summary of EPA Coal Creek BART Analysis Control Technologies for Units 1 and 2 Boilers
----------------------------------------------------------------------------------------------------------------
                                                      Control                                        Emissions
                 Control option                     efficiency     Emission rate     Emissions       reduction
                                                        (%)         (lb/MMBtu)       (tons/yr)       (tons/yr)
----------------------------------------------------------------------------------------------------------------
LTO + SOFA + LNB................................              90           0.022             536           4,821
LDSCR + SOFA + LNB..............................              80           0.043           1,084           4,210
SNCR + SOFA + LNB...............................              49           0.108           2,722           2,572
SOFA + LNB......................................              29           0.150           3,780           1,514
SOFA + LNB (Baseline)...........................               0            0.22        5,294\1\  ..............
----------------------------------------------------------------------------------------------------------------
\1\ Calculated average for historic baseline (2000-2004) for Unit 1. Units 1 and 2 comparable in size and
  emissions.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    SOFA + LNB.
    We relied on North Dakota's and Great River Energy's cost analysis 
for SOFA + LNB. (See SIP, Appendices B.2 and C.2.) Great River Energy 
evaluated two slightly different emissions rates. We find that the 
lower emission rate (higher control efficiency) and associated costs 
are reasonable, and we rely on this information to supplement our other 
control option cost analyses. We used an emission rate of 0.151 lb/
MMBtu, with a resulting capital cost of $5.37 million, a total annual 
cost of $673,100, and an average cost effectiveness of $412 per ton of 
NOX emissions reductions.
    SNCR+ SOFA + LNB.
    We are not relying on North Dakota's costs for SNCR due to the 
erroneous fly ash cost information used by Great River Energy, which 
the State relied on in its analyses. We prepared a cost analysis for 
SNCR for Coal Creek Station Units 1 and 2. As explained below, we have 
used some of the cost information provided in a Great River Energy 
letter from Ms. Mary Jo Roth to Mr. Terry O'Clair dated July 15, 2011. 
The original price for fly ash in Great River Energy's analysis was 
$36.00 per ton. (See SIP, Appendix C.2). In its July 15, 2011 letter, 
Great River Energy corrected this value to $5.00 per ton. We have used 
this value in our analyses.
    Regarding this value for fly ash sales, North Dakota concluded that 
SCR and SNCR use at Coal Creek would likely result in NH3 in 
the fly ash due to NH3 slip which would negatively affect 
fly ash salability. According to Great River Energy and North Dakota, 
fly ash that is currently beneficially used in the production of 
concrete would, instead, be landfilled. While we have opted to agree 
that fly ash will not be saleable for the SNCR and SCR options for 
purposes of our cost analyses, we are seeking comment on this issue, 
particularly related to the levels of NH3 that fly ash 
marketers deem problematic, and the availability, applicability, and 
cost of applying NH3 mitigation techniques to fly ash 
derived from lignite coal.
    We also relied on Great River Energy's estimate for direct capital 
equipment costs for SNCR. We then generally used factors and 
assumptions provided by the Control Cost Manual for the remainder of 
our SNCR analysis, as well as cost estimates we consider to be 
reasonable for certain recurring costs. This is the same approach we 
used to analyze the costs for SCR and SNCR at Leland Olds Station Unit 
2 and Milton R. Young Station Units 1 and 2. This enables us to compare 
the costs of the various technologies on a consistent basis. We 
summarize our costs from our SNCR cost analysis in Tables 57, 58, and 
59.

Table 57--Summary of EPA NOX BART Capital Cost Analysis for SNCR on Coal
                   Creek Station Units 1 and 2 Boilers
------------------------------------------------------------------------
            Description                  Cost factor         Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A.......  ....................       4,913,000
Capital Investment SNCR, B........  ....................       5,374,000
                                   -------------------------------------
Total Capital Investment, TCI       A + B...............      10,287,000
 (2009$).
------------------------------------------------------------------------

[[Page 58621]]

 Table 58--Summary of EPA Annual Cost Analysis for SNCR + ASOFA on Coal
                   Creek Station Units 1 and 2 Boilers
------------------------------------------------------------------------
            Description                  Cost factor         Cost ($)
------------------------------------------------------------------------
Annual Maintenance................  .015xTCI............          80,600
Reagent...........................  ....................       1,000,000
Electricity.......................  ....................          35,600
Water.............................  ....................           1,000
Increased Coal....................  ....................          38,000
Increased Ash.....................  ....................           2,900
Additional Ash Disposal...........  ....................       2,023,700
Lost Ash Sales....................  ....................       2,023,700
                                   -------------------------------------
    Total Direct Annual Cost        Sum of Various Items       5,250,000
     (TDAC).                         Listed Above.
                                   -------------------------------------
    Indirect Annual Cost \1\        CRF x TCI...........         507,000
     (IDAC).
                                   -------------------------------------
    Total Annual Cost SNCR (TACS).  TDAC + IDAC.........       5,760,000
                                   -------------------------------------
    Total Annual Cost ASOFA (TACA)  North Dakota                 673,000
                                     Appendix B.4.
                                   -------------------------------------
    Total Annual Cost SNCR + ASOFA  TACS + TACA.........       6,430,000
------------------------------------------------------------------------
\1\ Capital Recovery Factor (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 59--Summary of EPA Costs for SNCR on Coal Creek Station Units 1 and 2 Boilers
----------------------------------------------------------------------------------------------------------------
                                           Total installed                        Emissions       Average cost
             Control option                 capital cost      Total annual       reductions       effectiveness
                                                (MM$)          cost  (MM$)        (tons/yr)          ($/ton)
----------------------------------------------------------------------------------------------------------------
SNCR + SOFA + LNB.......................            10.29              6.40             2,572            $2,500
----------------------------------------------------------------------------------------------------------------

    SCR+ SOFA + LNB.
    We are not relying on North Dakota's costs for SCR + SOFA + LNB due 
to the erroneous fly ash cost information used by Great River Energy, 
which the State relied on in its analyses. Here again, we used the 
source's corrected sales price for fly ash of $5.00 per ton. As with 
SNCR, we relied on Great River Energy's estimate for direct capital 
equipment costs for SCR. We then generally used factors and assumptions 
provided by the Control Cost Manual for the remainder of our SCR 
analysis, as well as cost estimates we consider to be reasonable for 
certain recurring costs. This is the same approach we used to analyze 
the costs for SCR and SNCR at Leland Olds Station Unit 2 and Milton R. 
Young Station Units 1 and 2. This enables us to compare the costs of 
the various technologies on a consistent basis. We summarize our costs 
from our SCR cost analysis in Tables 60, 61, and 62.

 Table 60--Summary of EPA Capital Cost Analysis for LDSCR on Coal Creek
                      Station Units 1 and 2 Boilers
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A......  ...................         4,913,000
Capital Investment LDSCR, B......  ...................        60,241,000
                                  --------------------------------------
    Total Capital Investment, TCI  A + B..............        65,154,000
     (2009$).
------------------------------------------------------------------------

  Table 61--Summary of EPA Annual Cost Analysis for LDSCR on Coal Creek
                      Station Units 1 and 2 Boilers
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........           903,600
Reagent..........................  ...................           498,000
Electricity......................  ...................           974,000
Catalyst.........................  ...................           708,000
Natural Gas......................  ...................         3,890,000
Additional Ash Disposal..........  ...................         2,023,700
Lost Ash Sales...................  ...................         2,023,700
    Total Direct Annual Cost       Sum of Various             11,021,000
     (TDAC).                        Items Listed Above.
                                  --------------------------------------
    Indirect Annual Cost \1\       CRF x TCI..........         5,686,000
     (IDAC).
                                  --------------------------------------
    Total Annual Cost LDSCR        TDAC + IDAC........        16,707,000
     (TACS).
                                  --------------------------------------
    Total Annual Cost ASOFA        North Dakota                  620,400
     (TACA).                        Appendix B.4.
                                  --------------------------------------

[[Page 58622]]

 
    Total Annual Cost LDSCR +      TACS + TACA........        17,328,000
     ASOFA.
------------------------------------------------------------------------
\1\ Capital Recovery Factor (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 62--Summary of EPA Costs for LDSCR on Coal Creek Station Units 1 and 2 Boilers
----------------------------------------------------------------------------------------------------------------
                                                             Total
                                                           installed      Total      Emissions     Average cost
                     Control option                         capital    annual cost   reductions   effectiveness
                                                          cost  (MM$)      (MM$)     (tons/yr)       ($/ton)
----------------------------------------------------------------------------------------------------------------
LDSCR + SOFA + LNB......................................   65,154,000   17,328,000        4,210            4,116
----------------------------------------------------------------------------------------------------------------

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and 
operation of the evaluated controls are not significant enough to 
warrant eliminating any of the control options.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant 
enough to warrant eliminating any of the options. It is possible that 
fly ash will need to be landfilled if it cannot be sold due to 
NH3 contamination. We have considered this possibility in 
our cost analysis. However, while North Dakota considered this to be of 
some importance in its evaluation of non-air quality environmental 
impacts and its elimination of SNCR as a potential BART option at Coal 
Creek Station, we note that North Dakota has selected SNCR as BART at 
several other units. In those determinations, North Dakota did not 
indicate that landfilling of fly ash would cause any particular non-air 
quality environmental impacts. And given that this is the typical 
practice at many facilities using SCR and SNCR to control 
NOX, we do not find this to be a consideration that warrants 
elimination of SCR or SNCR as potential BART control options.
    Factor 4: Remaining useful life.
    The remaining useful life of Coal Creek Station Units 1 and 2 is at 
least 20 years. Thus, this factor does not impact our BART 
determination.
    Factor 5: Evaluate visibility impacts.
    Great River Energy modeled the visibility benefits for all the 
control options using natural background per the BART Guidelines. The 
SO2 scrubber controls were included with every modeling run 
for the NOX control options. This modeling predicted that 
the visibility improvement would range from 1.853 deciviews with LTO + 
scrubber modifications down to 1.378 deciviews for the least efficient 
technology, SOFA + LNB + scrubber modifications, at Theodore Roosevelt 
(98th percentile). More information on our interpretation of Great 
River Energy's modeling information is included in the Technical 
Support Document.
    Based on Great River Energy's modeling, we anticipate that SNCR + 
SOFA + LNB would provide additional visibility improvement compared to 
SOFA + LNB (higher control option) of about 0.105 deciviews at Theodore 
Roosevelt, Northern Unit, and 0.088 deciviews at Theodore Roosevelt, 
Southern Unit. Also, when compared to SOFA + LNB, SNCR + SOFA + LNB 
would provide six fewer days above 0.5 deciviews at Lostwood, three 
fewer days at Theodore Roosevelt, Northern Unit, and one less day at 
Theodor Roosevelt, Southern Unit.\80\
---------------------------------------------------------------------------

    \80\ In its BART determination, the State presented the deciview 
improvement at Theodore Roosevelt, Northern Unit.
---------------------------------------------------------------------------

    Step 5: Select BART.
    We propose to find that BART is SNCR + SOFA + LNB at Coal Creek 
Station Units 1 and 2 with an emission limit of 0.12 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. As indicated above, we find that the other three factors are 
not significant for this BART determination.
    Our evaluation of the four control options is summarized in Table 
63.

                                 Table 63--Summary of EPA NOX BART Analysis for Coal Creek Station Units 1 and 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                  Visibility impacts1 2
                                                          Total        Total       Emissions     Average cost     Incremental   ------------------------
                    Control option                      installed   annual cost   reductions    effectiveness         cost         Visibility     Fewer
                                                         capital        (MM$)     (tons/year)      ($/ton)       effectiveness     improvement    days >
                                                       cost  (MM$)                                                  ($/ton)        (delta dv)     0.5 dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
LTO + SOFA + LNB.....................................        44.32        58.21         4,821           11,608  ...............           1.853       64
LDSCR + SOFA + LNB \1\...............................        65.15        17.33         4,210            4,116            6,653           1.760       62
SNCR + SOFA + LNB....................................        10.29         6.43         2,572            2,500            5,441           1.507       50
SOFA + LNB...........................................         4.91         0.67         1,517              445  ...............           1.419       49
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility modeling that Great River Energy performed for Coal Creek Units 1 and 2 included SO2 control in addition to the noted NOX control.
  The modeling results shown above reflect the chosen SO2 BART control, scrubber modifications, in addition to the noted NOX control option. Thus, these
  values do not reflect the distinct visibility benefit from the NOX control options but do provide the incremental benefit between the options. Also,
  this table only presents the modeling results for Theodore Roosevelt, Southern Unit, for 2002, because this is where and when Great River Energy
  modeled the largest 98th percentile absolute impact under any scenario. However, as noted in the text and in North Dakota's SIP, Great River Energy
  modeled greater incremental benefit between SOFA + LNB and SNCR + SOFA + LNB at Theodore Roosevelt, Northern Unit for 2002.

[[Page 58623]]

 
\2\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    We have concluded that SOFA + LNB and SNCR + SOFA + LNB are both 
cost effective control technologies and that both would provide 
incremental visibility benefits. SOFA + LNB has a cost effectiveness 
value of $445 per ton of NOX emissions reduced. While SNCR + 
ASOFA is more expensive than SOFA + LNB, it has a cost effectiveness 
value of $2,500 per ton of NOX emissions reduced. We note 
that this figure would be substantially lower--approximately $1,700 per 
ton--if NH3 contamination in the fly ash can be mitigated. 
Either of these values is well within the range of values we have 
considered reasonable for BART and that states other than North Dakota 
have considered reasonable for BART. It is also within the range of 
values that North Dakota considered reasonable in its NOX 
BART determinations, with comparable predicted visibility improvement. 
We note that Great River Energy's July 15, 2011 cost effectiveness 
estimate of $3,198 per ton for SNCR is also within the range that North 
Dakota has considered reasonable in selecting SNCR as BART at other 
EGUs.
    We find the cost effectiveness values for LTO + SOFA + LNB and 
LDSCR + SOFA + LNB to be excessive and are proposing to eliminate these 
options as BART. While the incremental visibility improvement of 0.35 
to 0.25 deciviews compared to the SNCR option is not insignificant, 
both the average and incremental cost effectiveness values associated 
with these options are high. The average cost effectiveness value for 
LTO + SOFA + LNB is $11,608 per ton. We find it is not reasonable to 
impose this cost given the predicted visibility improvement.
    Using the value Great River Energy supplied for installed capital 
cost, we calculated an average cost effectiveness value for SCR + SOFA 
+ LNB of $4,116 per ton. Given the anticipated visibility improvement, 
and the incremental cost effectiveness value of $6,653, we are not 
prepared to impose this option as BART. We also conducted some further 
analysis of costs. We determined that Great River Energy's value for 
installed capital cost equates to approximately $110/kW. This value 
appears to be low based on actual industry experience. For comparison, 
we performed an additional analysis for LDSCR + SOFA + LNB using an 
installed capital cost of $280/kW. We derived this value from EPA's 
Integrated Planning Model.\81\ The analysis resulted in an average cost 
effectiveness value of $6,600 per ton. This analysis provides further 
support for our conclusion that the SCR option is not reasonable.
---------------------------------------------------------------------------

    \81\ http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html.
---------------------------------------------------------------------------

    SNCR, when combined with scrubber modifications achieving 95% 
control, would result in a significant improvement in visibility at 
Theodore Roosevelt, estimated to be 1.507 deciviews and 50 fewer days 
above 0.5 deciviews. As the State did not provide discrete modeling for 
individual pollutants, it is not possible to describe the incremental 
visibility benefits of SNCR, or other NOX control options, 
over the selected SO2 BART control (scrubber modifications 
at 95% control). Nonetheless, when compared to SOFA plus LNB, SNCR 
would result in an incremental visibility improvement of 0.088 
deciviews at Theodore Roosevelt South Unit. North Dakota reports an 
even higher visibility benefit, 0.105 deciviews, at Theodore Roosevelt 
North Unit in Appendix B of the SIP, though this was not the most 
impacted unit in the baseline modeling. We note that the State imposed 
SNCR as BART at Stanton Station, where emission reductions were 
estimated to be 390 tons per year or less compared to the next lower 
control option, incremental visibility improvement was estimated to be 
0.135 deciviews or less compared to the next lower control option, and 
where cost effectiveness values ranged from $3,052 to $3,778 per ton. 
Given the reasonable cost effectiveness value of $2,500 per ton and the 
incremental visibility benefit, we find it reasonable to select SNCR as 
BART, especially in light of the fact that neither of North Dakota's 
Class I areas are projected to meet the uniform rate of progress.
    In proposing a BART emission limit of 0.12 lb/MMBtu, we adjusted 
the annual design rate of 0.108 lb/MMBtu upwards to allow for a 
sufficient margin of compliance for a 30-day rolling average limit that 
would apply at all times, including during startup, shutdown, and 
malfunction.\82\ While we are proposing a BART limit of 0.12 lb/MMBtu, 
we invite comment on whether we should impose a different emission 
limit of 0.14 lb/MMBtu on a 30-day rolling average. Great River Energy 
has suggested in its July 15, 2011 letter that the Coal Creek Station 
units may be able to achieve a limit below 0.14 lb/MMBtu with a coal-
drying process in combination with combustion controls, presumably at a 
lower cost effectiveness value than SNCR plus combustion controls.
---------------------------------------------------------------------------

    \82\ 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.'' Based on the retrofit 
of other SNCR installations we have reviewed, we propose a compliance 
deadline of five (5) years from the date our final FIP becomes 
effective.
    We are also proposing monitoring, recordkeeping, and reporting 
requirements in regulatory text at the end of this proposal.

G. Evaluation of North Dakota's Reasonable Progress Goal

    In order to establish reasonable progress goals for Theodore 
Roosevelt and Lostwood and to determine the controls needed for the 
long-term strategy, North Dakota followed the process established in 
the Regional Haze Rule. First, North Dakota identified the anticipated 
visibility improvement in 2018 in both North Dakota Class I areas using 
the WRAP Community Multi-Scale Air Quality (CMAQ) modeling results. 
This modeling identified the extent of visibility improvement from the 
baseline by pollutant for each Class I area. The modeling relied on 
projected source emission inventories, which included enforceable 
Federal and state regulations already in place and anticipated BART 
controls.
    North Dakota then identified sources and source categories (other 
than BART sources) in North Dakota that are major contributors to 
visibility impairment and considered whether these sources should be 
controlled based on a consideration of the factors identified in the 
CAA and EPA's regulations. See CAA 169A(g)(1) and 40 CFR 
51.308(d)(1)(i)(A). Next, based on controls selected through this 
analysis, North Dakota set the reasonable progress goals for each Class 
I area and compared the reasonable progress goals for each area to the 
2018 uniform rate of progress. The SIP includes North Dakota's analysis 
and conclusion that reasonable progress will be made by

[[Page 58624]]

2018, including an analysis of pollutant trends, emission reductions, 
and improvements expected. The reasonable progress discussion and 
analyses are included in Section 9 of the SIP. We are proposing to 
disapprove North Dakota's submitted reasonable progress goals as 
described more fully below.
1. North Dakota's Visibility Modeling
    The primary tool WRAP relied upon for modeling regional haze 
improvements by 2018, and for estimating North Dakota's Reasonable 
Progress Goals, was the CMAQ model. The CMAQ model was used to estimate 
2018 visibility conditions in North Dakota 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 Regional Modeling Center (RMC) at the University of California 
Riverside conducted the CMAQ modeling under the oversight of the WRAP 
Modeling Forum. The Regional Modeling Center developed air quality 
modeling inputs including annual meteorology and emissions inventories 
for: (1) A 2002 actual emissions base case, (2) a planning case to 
represent the 2000-2004 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 2005. 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. A more detailed description of the CMAQ modeling performed by 
WRAP can be found in Appendix A.5 of the SIP and in the EPA Technical 
Support Document.
    To supplement the WRAP modeling effort, North Dakota conducted 
further analyses using a hybrid modeling approach to address its 
concerns regarding weight of evidence and spatial resolution issues. 
The North Dakota hybrid modeling approach involved nesting a local 
North Dakota CALPUFF domain within the WRAP National CMAQ domain, and 
is explained in detail in Section 8 of the SIP.
    North Dakota indicates its modeling methodology more realistically 
defines plume geometry for local large point sources and discounts the 
impacts of international sources in Canada over which North Dakota has 
no control. North Dakota is the only WRAP State which opted to develop 
its own reasonable progress modeling methodology. Appendix W outlines 
specific criteria for the use of alternate models and it does not 
appear that those criteria have been satisfied for the use of North 
Dakota's hybrid modeling.
2. North Dakota's Reasonable Progress ``Four-Factor'' Analysis
    In determining the measures necessary to make reasonable progress, 
States must take into account the following four factors and 
demonstrate how they were taken into consideration in selecting 
reasonable progress goals for a Class I area:
     Costs of Compliance,
     Time Necessary for Compliance,
     Energy and Non-air Quality Environmental Impacts of 
Compliance, and
     Remaining Useful Life of any Potentially Affected Sources. 
CAA Sec.  169A(g)(1) and 40 CFR 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, the four-factor analysis 
conducted by North Dakota addresses only anthropogenic sources, on the 
assumption that the focus should be on sources that can be 
``controlled.'' In its evaluation of potential sources or source 
categories for reasonable progress, North Dakota primarily considered 
point sources. North Dakota also only considered controls for emissions 
of SO2 and NOX (i.e., sulfate and nitrate) which 
are typically associated with anthropogenic sources. Previous BART 
modeling that the State conducted showed that PM emissions from point 
sources contribute only a minimal amount to the visibility impairment 
in the North Dakota Class I areas. More discussion on sources of 
sulfate and nitrate emissions and the State's rationale for focusing on 
point sources is included in Section 9.4 of the SIP.
    To identify the point sources in North Dakota that potentially 
affect visibility in Class I areas, North Dakota started with the list 
of sources subject to Title V permitting requirements. Based on 2007 
data, the State determined that Title V source emissions represent a 
very high percentage of the point source SO2 and 
NOX emissions in North Dakota--approximately 98 to 99%. 
North Dakota then divided the actual emissions (Q) in tons per year 
from the Title V sources by their distance (D) in kilometers to the 
nearest Class I Federal area. Actual annual emissions were determined 
based on total average emissions for the period 2000-2004 for 
SO2 and NOX combined. North Dakota decided to use 
a Q/D value of 10 as its threshold for further evaluation for 
reasonable progress controls. North Dakota chose this value based on 
the Federal Land Managers' proposed FLAG guidance amendments for 
initial screening criteria, as well as the State's interpretation of 
statements in EPA's BART guidelines.\83\ A comprehensive list of the 
Title V Sources the State reviewed is included in Table 9.4 of the 
North Dakota SIP. The sources with Q/D results greater than 10 are 
listed below in Table 64.
---------------------------------------------------------------------------

    \83\ 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 tons per 
year of NOX or SO2 (or combined NOX 
and SO2), as long as these sources are located more than 
50 kilometers from any Class I area; and sources that emit less than 
1000 tons per year of NOX or SO2 (or combined 
NOX and SO2) that are located more than 100 
kilometers from any Class I area.'' (See 40 CFR 51, appendix Y, 
section III, How to Identify Sources ``Subject to BART.'') The 
values described equate to a Q/D of 10.

                    Table 64--North Dakota Q/D Analysis Sources With Results Greater than 10
----------------------------------------------------------------------------------------------------------------
                                                              SO2 + NOX                Distance to
                                                              2000-2004     Nearest      nearest     Nearest Q/D
               Source                         Owner            Average      class I      class I      (tons/km)
                                                                (tons)        area      area (km)
----------------------------------------------------------------------------------------------------------------
Antelope Valley Station Unit 1.....  Basin Electric........       13,864         TRNP          107         129.6
Antelope Valley Station Unit 2.....  Basin Electric........       12,796         TRNP          107         119.6
Grasslands Gas Plant...............  Bear Paw Energy.......          748         TRNP           38          19.7
Lignite Gas Plant..................  Bear Paw Energy.......          463     Lostwood           15          30.9
Great Plains Synfuels..............  Dakota Gasification Co       10,802         TRNP          107         101.0

[[Page 58625]]

 
Tioga Gas Plant....................  Hess Corporation......        3,655     Lostwood           35         104.4
Heskett Plant Unit 2...............  MDU Company...........        3,411         TRNP          182          18.7
Comp. Station No. 4................  Northern Border                 188         TRNP           18          10.4
                                      Pipeline.
Coyote Station.....................  Otter Tail Power             27,804         TRNP          112         248.3
                                      Company.
Little Knife Gas Plant.............  Petro-Hunt............          422         TRNP           39          10.8
Mandan Refinery....................  Tesoro................        5,757         TRNP          182          31.6
----------------------------------------------------------------------------------------------------------------

    For the reasons described below, the State eliminated from further 
consideration several sources that met the Q/D criteria. After the 
2000-2004 baseline period, Bear Paw Energy began injecting acid gas at 
its Grasslands and Lignite Gas Plants. This has eliminated 
SO2 emissions, except during malfunctions of the injection 
equipment. The gas injection process is included in Bear Paw Energy's 
Title V permits and reduces its Q/D for the two facilities to 9.8 and 
8.1 including malfunction emissions. The Northern Border Pipeline 
Company Compressor Station No. 4 is powered by a natural gas turbine 
that was replaced with a lower emitting turbine in 2005; this reduced 
its Q/D to 6.6. Petro Hunt's Little Knife Gas Plant's SO2 
and NOX emissions are on the decline due to a decrease in 
gas volume and new production coming from the Bakken formation, which 
contains sweet gas. Based on its emissions in 2008, the Little Knife 
Gas Plant had a Q/D of 7.6, and emissions are expected to continue to 
decline in the future. The Tesoro Refining and Marketing Company's 
Mandan Refinery is subject to a consent decree that requires 
substantial emissions reductions. Since the baseline period, Tesoro has 
installed a wet scrubber and ESP to control SO2 emissions 
from the catalytic cracking unit, LNB in the boilers, and other 
improvements that have reduced its Q/D to 7.9.
    North Dakota undertook a more detailed analysis of the remaining 
sources that exceeded a Q/D of 10. These sources are shown below in 
Table 65.

                   Table 65--North Dakota Sources for Reasonable Progress Four-Factor Analyses
----------------------------------------------------------------------------------------------------------------
                                                                                                      SO2 + NOX
                                                                                                      2000-2004
               Source                         Owner              Unit         Type       Capacity      Average
                                                                                                      (tons/yr)
----------------------------------------------------------------------------------------------------------------
Antelope Valley Station............  Basin Electric Power              1          EGU      435 MWe      13,864
                                      Coop..
Antelope Valley Station............  Basin Electric Power              2          EGU      435 MWe      12,796
                                      Coop..
Coyote Station.....................  Otter Tail Power Co...  Main Boiler          EGU      450 MWe      27,804
Great Plains Synfuels Plant........  Dakota Gasification      Boilers A,   Industrial  763 x 10\6\      10,802
                                      Co..                       B and S      Boilers  BTU/hr each
Tioga Gas Plant....................  Hess Corp.............            3       Sulfur          225       1,097
                                                                             Recovery    long tons
                                                                           Unit (SRU)      per day
                                                                                            (LTPD)
Tioga Gas Plant....................  Hess Corp.............    C1-A to F   Compressor    1920-2350       1,353
                                                                              engines     BHp each
Heskett Station \84\...............  Montana Dakota                    2          EGU       78 MWe       3,411
                                      Utilities.
----------------------------------------------------------------------------------------------------------------

    The control options and costs that North Dakota considered were 
derived, in part, from WRAP's report, Supplementary Information for 
Four-Factor Analyses for Selected Individual Facilities in North 
Dakota, May 18, 2009. A copy of this report and other related 
information is included in Appendix I.1 of the SIP. A summary of the 
control options considered along with their corresponding costs is 
provided in Table 67. The State made certain adjustments to WRAP's 
values; these are identified in the SIP.
---------------------------------------------------------------------------

    \84\ Because of a BART applicability issue, North Dakota did not 
complete the reasonable progress analysis for Heskett Unit 2 in time 
for inclusion as part of its March 3, 2010 submittal. The State 
submitted the four factor analysis for Heskett as Supplement No. 1.
---------------------------------------------------------------------------

Four Factor Analysis
Current Controls
    Table 66 shows the current controls in place at each reasonable 
progress source.

        Table 66--Current Control for Reasonable Progress Sources
------------------------------------------------------------------------
             Source                    Pollutant            Control
------------------------------------------------------------------------
Antelope Valley Station 1.......  SO2...............  Spray Dryer.
                                   NOX..............  OFA.
Antelope Valley Station 2.......  SO2...............  Spray Dryer.
                                  NOX...............  OFA.

[[Page 58626]]

 
Coyote..........................  SO2...............  Spray Dryer.
                                  NOX...............  None.
Tioga Gas Plant SRU Engines.....  SO2...............  3 Stage Claus + 4
                                                       bed Cold Bed
                                                       Absorber.
                                  NOX...............  None.
Great Plains Synfuels Plant--     SO2...............  Wet Scrubber.
 Boilers.
                                  NOX...............  None.
Heskett.........................  SO2...............  None.
                                  NOX...............  None.
------------------------------------------------------------------------

    Because upgrades of the spray dryers at Antelope Valley Units 1 and 
2 are already in progress, the State did not consider this option for 
these units during this planning period. The State expects the spray 
dryers to achieve 90% removal efficiency but doesn't expect a reduction 
in emissions because of an anticipated increase in coal sulfur content. 
At the Coyote Station, the State evaluated replacing the existing spray 
dryer. The boilers at Great Plains Synfuels Plant are equipped with an 
NH3 reagent wet scrubbing system followed by a wet ESP. This 
system is achieving 96-97% removal of SO2 from the flue gas. 
The State determined that this removal efficiency is comparable to BACT 
and BART for industrial boilers of this size; thus the State did not 
evaluate additional SO2 controls for this source.
Cost of Compliance
    Table 67 shows the cost of compliance for the control technologies 
evaluated for each of the reasonable progress sources.

                                             Table 67--Control Option Costs for Reasonable Progress Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                               Total
                                                                                                  Control      Emissions    annualized         Cost
             Source                       Unit              Pollutant      Control technology   efficiency    reductions      cost ($     effectiveness
                                                                                                    (%)        (tons/yr)     millions)       ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Antelope Valley Station.........  1..................  SO2...............  New Wet Scrubber..            95         6,780         32.17            4,745
                                                       NOX...............  LNB...............            51         3,889          2.28              586
                                                                           SNCR..............            40         3,050          8.96            2,938
                                                                           LNB + SNCR........            65         4,956         11.24            2,268
                                                                           SCR w/reheat......            80         6,100         44.00            7,213
                                                                           LNB + SCR w/reheat            90         6,863         46.30            6,746
Antelope Valley Station.........  2..................  SO2...............  New Wet Scrubber..            95         5,899         32.17            5,453
                                                       NOX...............  LNB...............            51         3,450          2.28              661
                                                                           SNCR..............            40         2,706          8.96            3,311
                                                                           LNB + SNCR........            65         4,397         11.24            2,556
                                                                           SCR w/reheat......            80         5,411         44.00            8,132
                                                                           LNB + SCR w/reheat            90         6,087         46.30            7,606
                                                       SO2...............  New Wet Scrubber..            95        12,835         33.28            2,593
Coyote Station..................  1..................  NOX...............  ASOFA.............            40         5,223          1.28              246
                                                                           SNCR..............            40         5,223          8.52            1,631
                                                                           ASOFA + SNCR......            55         7,182         11.25            1,566
                                                                           SCR w/reheat......            80        10,446         45.30            4,337
                                                                           ASOFA + SCR w/                90        11,752         46.60            3,965
                                                                            reheat.
Heskett Station.................  2..................  SO2...............  WS + LI...........            96         2,582         13.35            5,171
                                                                           WS................            95         2,556         12.30            4,813
                                                                           CDS/Bag + LI......            95         2,556         11.95            4,673
                                                                           SD/Bag + LI.......            94         2,539         10.86            4,296
                                                                           CDS/Bag...........            92         2,475         10.99            4,402
                                                                           SD/Bag............            90         2,421          9.81            4,054
                                                                           LI................            60         1,614          1.05              651
                                                       NOX...............  LDSCR.............            80           858          5.21            6,079
                                                                           TESCR.............            80           858          6.05            7,050
                                                                           SNCR..............            33           354          1.42            4,023
                                                                           Staged Combustion.            20           215          0.37            1,702
Tioga Gas Plant.................  SRU................  SO2...............  Tail Gas Clean Up.          99.8         1,018          5.80            5,697
                                  1920 Hp Engines....  NOX...............  Air Fuel Ratio                25           305          0.26              852
                                                                            Controller.
                                                                           Ignition Timing               22           268          0.14              522
                                                                            Retard.

[[Page 58627]]

 
                                                                           LEC Retrofit......            85         1,035          0.56              541
                                                                           SCR...............            80           974          1.60            1,643
                                  2350 Hp Engines....  NOX...............  SCR...............            50            34          0.50            1,471
Great Plains Synfuels Plant.....  Boilers              NOX...............  SNCR..............            30           259          1.69            6,525
                                   (information is
                                   per each boiler).
                                                                           SCR...............            80           670          5.50            8,216
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State found that the following control options have excessive 
cost effectiveness values:
     Antelope Valley 1 & 2--Wet scrubber; SCR w/reheat; and LNB 
+ SCR w/reheat.
     Coyote--SCR w/reheat and ASOFA + SCR w/reheat.
     Heskett--Wet scrubber; circulating dry scrubber, with or 
without limestone injection; spray dryer, with or without limestone 
injection; SCR; and SNCR .
     Tioga Gas Plant--Tail Gas Cleanup.
     Great Plains Synfuels Plant--SNCR and SCR.
    Also, at Heskett, the State found that SNCR plus staged combustion 
is not technically feasible. The State expressed concerns that SCR and 
SNCR may not be technically feasible at Great Plains Synfuels Plant. 
The State did not further evaluate the controls that it found had 
excessive cost effectiveness values or that it found were not 
technically feasible.
Time Necessary for Compliance
    Relying on the EC/R report, the State found that up to 6.5 years 
after SIP approval would be necessary to achieve compliance with some 
of the control options and that additional time might be necessary if 
normal maintenance outages did not coincide with projected schedules.
Energy and Non-Air Impacts
    The State found that all of the control technologies for the 
various sources would consume energy and that enhancement of the lb/
MMBtu scrubbing system at Coyote Station would increase the amount of 
solid waste generated. However, the State concluded that the energy and 
non-air impacts would not preclude the selection of any of the 
technologies identified at any of the facilities.
Remaining Useful Life of the Source
    With the exception of the engines at Tioga Gas Plant, the State 
found that the remaining useful life of the sources would be at least 
20 years and would not preclude the selection of any of the control 
options. The State anticipated that the engines at Tioga may need to be 
refurbished before 20 years but that this would extend their remaining 
useful life indefinitely.
Visibility Improvement
    In addition to evaluating the four statutory factors, North Dakota 
also considered the visibility impacts associated with the control 
options for each RP source. However, in modeling visibility impacts, 
North Dakota used a hybrid cumulative modeling approach that is 
inappropriate for determining the visibility impact for individual 
sources. As with the modeling North Dakota conducted for its 
NOX BART analysis for MRYS Units 1 and 2 and LOS Unit 2, the 
approach fails to compare single-source impacts to natural background. 
While there is no requirement that States, when performing RP analyses, 
follow the modeling procedures set out in the BART guidelines, or that 
they consider visibility impacts at all, we find that North Dakota's 
visibility modeling significantly understates the visibility 
improvement that would be realized for the control options under 
consideration. Accordingly, we are disregarding the modeling analysis 
that North Dakota has used to support its RP determinations for 
individual sources. Table 68 shows the State's cost effectiveness and 
visibility modeling results.

           Table 68--North Dakota's Modeled Visibility Improvement for Reasonable Progress Sources \1\
----------------------------------------------------------------------------------------------------------------
                                                                                  Visibility
                                                                               improvement (dv)        Cost
              Source                     Pollutant        Control technology -------------------  effectiveness
                                                                                TRNP      LWA         ($/dv)
----------------------------------------------------------------------------------------------------------------
Antelope Valley Station 1........  NOX.................  LNB + SNCR.........     0.005     0.01    1,124,000,000
Antelope Valley Station 2........  NOX.................  LNB + SNCR.........     0.005     0.01    1,124,000,000
Coyote...........................  SO2 NOX.............  Wet Scrubber ASOFA      0.02      0.04    1,113,000,000
                                                          + SNCR.
Tioga G.P. 1920 BHp Engines 2350   NOX.................  SCR................     0          \2\       21,200,000
 BHp Engines.                                                                              0.05
Heskett..........................  SO2.................  Limestone Injection  ........  .......      116,667,000
                                   NOX.................  SNCR Staged             0.009    0.003      158,222,000
                                                          Combustion.                                 40,667,000
                                   ....................
----------------------------------------------------------------------------------------------------------------
\1\ For Tioga, the visibility improvement is for all engines. The visibility improvement numbers for Coyote and
  Heskett represent the combined benefit from SO2 and NOX. For Heskett, the State modeled one scenario that
  assumed 95% SO2 control and 40% NOX control.
\2\ For Tioga, the SIP indicates the visibility improvement is 0.5 deciviews. The State informed us in a letter
  dated August 3, 2010 that this was an error and that the actual modeled value is 0.05 deciviews.

[[Page 58628]]

3. North Dakota's Conclusions From Its Four-Factor Analysis
    The State determined that requiring additional controls on the 
reasonable progress sources will not substantially improve visibility 
in the Class I Federal Areas. Based on its cumulative modeling for the 
average of the 20% worst days, the State determined that the maximum 
combined improvement from use of the most efficient control options 
carried forward in the analysis for each source would be 0.11 deciviews 
at Lostwood and 0.03 deciviews at Theodore Roosevelt. According to the 
State, this amounts to a 0.17% improvement at Theodore Roosevelt over 
the baseline condition for the most impaired days and 0.56% improvement 
at Lostwood National Wildlife Refuge Wilderness Area. The State 
determined that the cost effectiveness value was over 618 million 
dollars per deciview of improvement at Lostwood and 2.3 billion dollars 
per deciview at Theodore Roosevelt. For all reasonable progress 
sources, the State determined that the cost ($/deciviews) was 
excessive, both on an individual and a cumulative basis. Therefore, the 
State concluded that no additional controls are warranted under 
reasonable progress during this planning period.
Controls at Coyote Station and Heskett Station
    While the State concluded that additional controls are not 
warranted for purposes of meeting reasonable progress, the State 
nonetheless included controls for Coyote Station and Heskett Station in 
the SIP. For Coyote Station, the State reached an agreement with the 
owner/operator to reduce NOX emissions by approximately 
4,213 tons per year from the facility's 2000 to 2004 baseline. This 
represents a decrease of approximately 32%. To effectuate this 
reduction, North Dakota issued a permit to construct to Coyote Station 
and included it in the SIP. See SIP Amendment No. 1, submitted July 28, 
2011. The permit requires that Coyote Station comply with an emissions 
limit of 0.50 lb/MMBtu (30-day rolling average) by July 1, 2018.
    For Heskett Station, the State reached an agreement with the owner/
operator to use limestone injection into the boiler to reduce 
SO2 emissions by approximately 573 tons per year from the 
facility's 2000 to 2004 baseline emissions. This represents a decrease 
of approximately 34% from the facility's 2007 to 2008 baseline 
emissions. To effectuate this reduction, North Dakota issued a permit 
to construct to Heskett Station and included it in the SIP. See SIP 
Supplement No. 1, submitted July 27, 2011. The permit requires that 
Heskett Station achieve a minimum 70% reduction of SO2 (coal 
to stack) or comply with an SO2 emissions limit of 0.60 lb/
MMBtu (12-month rolling average) within five years of EPA's approval of 
the permit to construct as part of the SIP.
4. Establishment of the Reasonable Progress Goal
    40 CFR 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 reasonable progress goals are interim goals that 
must provide for incremental visibility improvement for the most 
impaired visibility days, and ensure no degradation for the least 
impaired visibility days. The reasonable progress goals for the first 
planning period are goals for the year 2018.
    Based on (1) The results of the WRAP CMAQ modeling, (2) the results 
of the four-factor analysis of major North Dakota sources, and (3) the 
emission controls on North Dakota BART sources, North Dakota 
established reasonable progress goals for the most impaired days for 
both of North Dakota's Class I areas, as identified in Table 69 below. 
Also shown in Table 69 is a comparison of the reasonable progress goals 
to the uniform rate of progress for both Class I areas. The reasonable 
progress goals for the 20% worst days fall short of the uniform rate of 
progress by 1.77 and 2.25 deciviews for Theodore Roosevelt and 
Lostwood, respectively. In Sections 8 and 9 of the SIP, the State 
presented additional scenarios that compared the State's hybrid 
modeling results to the WRAP modeling results. The State's hybrid 
modeling approach results in more optimistic estimations of visibility 
improvements. However, even when the State set all North Dakota 
SO2 and NOX emissions to zero in the hybrid 
model, it could not meet the uniform rate of progress.

  Table 69--Comparison of Reasonable Progress Goals to Uniform Rate of Progress on Most Impaired Days for North
                                              Dakota Class I Areas
----------------------------------------------------------------------------------------------------------------
                                              Visibility conditions on 20% worst days  (dv)
                                         ------------------------------------------------------
                                           Average for 20%                                        Percentage of
        North Dakota class I area            worst days                           RPG (WRAP       URP achieved
                                           (baseline 2000-    2018 URP goal      projection)
                                                2004)
----------------------------------------------------------------------------------------------------------------
Theodore Roosevelt National Park........             17.80             15.47             17.24              24.0
Lostwood Wilderness Area................             19.57             16.87             19.12              16.7
----------------------------------------------------------------------------------------------------------------

    North Dakota's reasonable progress goals for Theodore Roosevelt for 
2018 for the 20% worst days represents a 0.6 deciviews improvement over 
baseline and its reasonable progress goals for Lostwood for 2018 
represents a 0.5 deciviews improvement over baseline. North Dakota's 
reasonable progress goals establish a slower rate of progress than the 
uniform rate of progress. North Dakota has calculated that under the 
rate of progress represented by its reasonable progress goals, North 
Dakota would attain natural visibility conditions in 156 years at 
Theodore Roosevelt and 232 years at Lostwood.
    Table 70 provides a comparison of North Dakota's reasonable 
progress goals to baseline conditions on the least impaired days. This 
comparison demonstrates that North Dakota's reasonable progress goals 
will result in no degradation in visibility conditions in the first 
planning period; instead, for the 20% best days, there would be a 
slight improvement in visibility from the baseline for both Class I 
areas.

[[Page 58629]]

Table 70--Comparison of Reasonable Progress Goals to Baseline Conditions on Least Impaired Days for North Dakota
                                                  Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                             Visibility conditions on 20% best
                                                                         days (dv)
                                                           ------------------------------------   Achieved ``no
                 North Dakota class I area                   Average for 20%                    degradation'' (Y/
                                                                best days         RPG (WRAP            N)
                                                             (baseline 2000-     projection)
                                                                  2004)
----------------------------------------------------------------------------------------------------------------
Theodore Roosevelt National Park..........................              7.76              7.67                 Y
Lostwood Wilderness Area..................................              8.19              8.06                 Y
----------------------------------------------------------------------------------------------------------------

    North Dakota believes the reasonable progress goals it established 
for the North Dakota 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 the four-factor analysis along with the State's 
visibility analyses resulted in excessive dollar per deciview costs for 
additional controls.
    2. Sources outside of the modeling domain and in Canada contribute 
50-67% of the sulfate or nitrate to North Dakota's Class I areas. These 
are the pollutants that cause the greatest visibility impairment in 
such areas. Canadian sources are not under the control of North Dakota 
or the surrounding States and will not be significantly controlled by 
2018. North Dakota conducted modeling to emulate 100% control of all 
in-state sources and demonstrated that the uniform rate of progress 
would still not be met.
    3. After sulfate and nitrate, the next largest contributor to 
visibility impairment in North Dakota's Class I areas is organic 
carbon. Much of the organic carbon emissions, which account for 
approximately 15% and 18% of the extinction at Lostwood and Theodore 
Roosevelt, respectively, on the 20% worst days, are from natural fires 
that cannot be controlled.
5. Reasonable Progress Consultation
    North Dakota consulted directly with neighboring states and through 
the WRAP, 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. In addition, North Dakota consulted directly 
with the State of Minnesota through the Minnesota Pollution Control 
Agency. 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.
    40 CFR 51.308(d)(3)(ii) of the Regional Haze Rule 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 reasonable progress goals. Based on the consultation described 
above, North Dakota identified no major contributions that supported 
developing new interstate strategies, mitigation measures, or emission 
reduction obligations. Both North Dakota 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 
reasonable progress goals for their Class I areas, and that future 
consultation would address any new strategies or measures needed.

H. Our Conclusion on North Dakota's Reasonable Progress Goal and Need 
for Additional Controls

    We agree with North Dakota's conclusion that it is not reasonable 
to meet the uniform rate of progress for Theodore Roosevelt and 
Lostwood by 2018. In particular, North Dakota's modeling showed that 
even if all in-State emissions were reduced to zero, North Dakota could 
still not achieve the uniform rate of progress at its Class I areas. We 
also agree with North Dakota's conclusion that it appropriately 
consulted with other states and determined that it needed no further 
controls beyond those already contained in the SIP to address impacts 
on Class I areas in other states. However, we disagree with North 
Dakota's conclusion that no additional controls on non-BART sources are 
reasonable and disagree with North Dakota's selected reasonable 
progress goals.
    Because the reasonable progress goals fall short of the uniform 
rate of progress, North Dakota must demonstrate that its reasonable 
progress goals and rejection of reasonable progress controls is 
reasonable, based on the four factors. 40 CFR 51.308(d)(1)(ii).
    As an initial matter, we disagree with the State's assessment of 
visibility improvement at individual reasonable progress sources. While 
it is reasonable for a state to consider visibility improvement as an 
additional factor in its reasonable progress analysis when evaluating 
visibility benefits from potential control options at individual 
sources, it is not appropriate to assume degraded background 
conditions, as the State did. As we note above, using degraded rather 
than natural background in the modeling produces estimates that greatly 
underestimate the benefits of potential control options. The ultimate 
goal of the regional haze program is to achieve natural visibility 
conditions, not to preserve degraded conditions.
    As a result of North Dakota's inappropriate visibility modeling 
approach, North Dakota greatly understated visibility improvements in 
deciviews.\85\ Thus, cost effectiveness values, when expressed in 
dollars per deciview, were overestimated. Also, it is important to 
recognize that dollars per deciview values will always be significantly 
higher, often by several orders of magnitude, than the more

[[Page 58630]]

commonly used and understood dollars per ton values.
---------------------------------------------------------------------------

    \85\ The SIP includes 98th percentile modeling using natural 
background for the BART sources. Many of the reasonable progress 
sources are also large EGUs that are located in the same general 
area of the State. While we do not have specific BART Guidelines-
compliant modeling for all of the reasonable progress sources, we 
would expect similar emissions reductions at the reasonable progress 
sources would produce visibility benefits of the same order of 
magnitude as at the BART sources. We do not find it reasonable to 
model BART sources one way and then model similar reasonable 
progress sources a different way when the ultimate goal is the 
same--attain natural visibility conditions by 2064.
---------------------------------------------------------------------------

    Below we discuss each reasonable progress source and EPA's 
conclusions regarding the State's reasonable progress determination.
Antelope Valley Station Units 1 and 2
    EPA is proposing to approve the State's conclusion that no 
additional SO2 controls are warranted for these two units 
for this planning period. The cost effectiveness values for a new wet 
scrubber at each unit are $4,735 and $5,453 per ton. Also, the State 
noted that the existing spray dryers are already being upgraded. Based 
on the cost effectiveness values, we find that North Dakota reasonably 
rejected additional SO2 controls during this planning 
period.
    EPA does not agree with the State's conclusion that no additional 
controls are reasonable for NOX for this planning period. In 
particular, the cost effectiveness values for low-NOX 
burners at each unit are $586 and $661 per ton. These values are very 
reasonable and far less than many of the cost effectiveness values the 
State found reasonable in making its BART determinations. Given 
predicted NOX reductions of approximately 3,500 tons per 
unit per year, and the fact that North Dakota's reasonable progress 
goals will not meet the uniform rate of progress, we find that it was 
unreasonable for the State to reject these highly inexpensive controls. 
EPA is proposing NOX controls for these two units in section 
V.I below.
Coyote Station
    EPA is proposing to approve the State's conclusion that no 
additional SO2 control is warranted for this planning 
period. The cost effectiveness value for a new wet scrubber is $2,593 
per ton. While this is within the range of cost effectiveness values 
that North Dakota, other states, and we have considered reasonable in 
the BART context, it is not so low that we are prepared to disapprove 
the State's conclusion in the reasonable progress context. We emphasize 
that Coyote currently employs a spray dryer to control SO2 
emissions at a control efficiency of approximately 66%. The existence 
of these controls has also influenced our decision.
    EPA does not agree with the State's conclusion that no additional 
NOX controls are reasonable for this planning period. In 
particular, the cost effectiveness value for ASOFA is $246 per ton. 
This value is very reasonable and far less than many of the cost 
effectiveness values the State found reasonable in making its BART 
determinations. Given the predicted NOX reduction of 
approximately 5,223 tons per year, and the fact that North Dakota's 
reasonable progress goals will not meet the uniform rate of progress, 
we find that it was unreasonable for the State to reject this highly 
inexpensive control for reasonable progress. However, as noted above, 
the State reached an agreement whereby the owner/operator of Coyote 
Station will meet a NOX emission limit of 0.50 lb/MMBtu by 
July 1, 2018. It is anticipated the source will meet this limit by 
installing OFA. North Dakota has made this limit enforceable through a 
permit to construct that it submitted as part of SIP Amendment No. 1. 
While we disagree with the State's reasoning regarding reasonable 
progress, we find the proposed limit to be reasonable to meet 
reasonable progress requirements at Coyote Station for this initial 
planning period. We are proposing to approve the permit to construct 
that contains this limit.
Tioga Gas Plant
    Based on the relatively small predicted emissions reductions and 
the cost effectiveness values, we are proposing to approve the State's 
determination that no additional SO2 or NOX 
controls are reasonable for this source in this initial planning 
period.
Great Plains Synfuels Plant
    EPA agrees with the State that the current SO2 controls 
are achieving the most stringent level of control; thus, analysis of 
other SO2 controls is not necessary. We also agree with the 
State's determination that additional NOX controls are not 
reasonable during this initial planning period based on the high cost 
effectiveness values for those controls ($6,525 to $8,216 per ton) and 
the relatively modest emissions reductions that would be achieved.
Heskett Station Unit 2
    We find reasonable the State's conclusion that some of the higher 
performing SO2 controls are not reasonable for 
SO2 for this initial planning period. The cost effectiveness 
values for all SO2 control options above limestone injection 
are relatively high, ranging from about $4,000 to $5,000 per ton. We do 
not agree with the State's conclusion that limestone injection, at $651 
per ton, is not reasonable during this planning period. However, as 
noted above, the State reached an agreement whereby the owner/operator 
of Heskett Station will install limestone injection and will reduce 
SO2 by at least 70% (coal to stack, 12-month rolling 
average) or meet an SO2 emissions limit of 0.60 lb/MMBtu 
(12-month rolling average). North Dakota has made this limit 
enforceable through a permit to construct that it submitted as part of 
SIP Supplement No. 1. The permit requires compliance with the emissions 
limits within five years of EPA's approval of the permit. While we 
disagree with the State's reasoning regarding reasonable progress, we 
find the proposed SO2 limits to be reasonable to meet 
reasonable progress requirements at Heskett Station for this initial 
planning period. We are proposing to approve the permit to construct 
that contains these limits.
    EPA is proposing to approve the State's determination that no 
additional NOX controls at Heskett Station Unit 2 are 
reasonable in this planning period. The cost effectiveness values for 
potential NOX controls are too high and/or the emissions 
reductions are too modest.
    Because we are proposing to disapprove North Dakota's reasonable 
progress determination for NOX for Antelope Valley Station 
Units 1 and 2 and setting NOX limits through a FIP, and 
because we are proposing to disapprove North Dakota's NOX 
BART determinations for Milton R. Young Station Units 1 and 2, Leland 
Olds Station Unit 2, and Coal Creek Station Units 1 and 2, we are 
proposing to disapprove North Dakota's reasonable progress goals. North 
Dakota's reasonable progress goals do not represent appropriate 
NOX BART controls at Milton R. Young Station Units 1 and 2, 
Leland Olds Station Unit 2, and Coal Creek Station Units 1 and 2 or 
appropriate NOX reasonable progress controls at Antelope 
Valley Station Units 1 and 2. Accordingly, we are proposing to replace 
North Dakota's reasonable progress goals in our FIP.

I. Federal Implementation Plan To Address Nitrogen Oxides 
(NOX) Reasonable Progress Measures for Antelope Valley 
Station Units 1 and 2 and Reasonable Progress Goals

1. Introduction
    As discussed above, we propose to disapprove North Dakota's 
reasonable progress conclusion that no additional controls at Antelope 
Valley Station Units 1 and 2 are warranted during this planning period. 
To correct the deficiencies identified in our proposed disapproval, we 
are proposing a FIP. Because we are proposing to disapprove North 
Dakota's reasonable progress goals, we are also proposing a FIP to 
replace them.
    In proposing a FIP to address reasonable progress emission 
reductions

[[Page 58631]]

and reasonable progress goals, we must consider the same factors that 
states are required to consider.
2. Reasonable Progress Analysis for Antelope Valley Station Units 1 and 
2
    As noted above in section V.G.2., North Dakota conducted an 
analysis of potential NOX controls at Antelope Valley 
Station. In doing so, it considered the factors identified in the CAA 
and EPA's regulations. See CAA 169A(g)(1) and 40 CFR 
51.308(d)(1)(i)(A). It also considered visibility impacts. Our analysis 
is based on the information provided by North Dakota, except that, as 
we explain below, we are disregarding North Dakota's visibility 
analysis.
    The BART Guidelines recommend that states utilize a five-step 
process for determining BART for EGU sources above 750 MW in size. 
Although this five-step process is not required for making reasonable 
progress determinations, we have elected to largely follow it in our 
reasonable progress analysis because there is some overlap in the 
statutory BART and reasonable progress factors and because it provides 
a reasonable structure for evaluating potential control options.
    Units 1 and 2 are tangentially-fired boilers, each having a 
generating capacity of 435 MW. These boilers are not BART-eligible 
because they commenced operation in the 1980s, after the 15-year period 
specified in the Regional Haze Rule. The boilers burn North Dakota 
lignite.
    Step 1: Identify All Available Technologies.
    Our analysis considers LNB, SNCR, SNCR + LNB, SCR, and SCR + LNB. 
Both boilers are already equipped with OFA systems.
    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.
    A summary of emissions projections for the various control options 
is provided in Table 71.

              Table 71--Summary of Antelope Valley Station NOX Reasonable Progress Analysis Control Technologies for Units 1 and 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Control option                                                           Control     Emissions \1\         Emissions     Emissions \1\         Emissions
                                                                  efficiency (%)         (tons/yr)         reduction         (tons/yr)         reduction
                                                                                                           (tons/yr)                           (tons/yr)
                                                                                 -----------------------------------------------------------------------
                                                                                                Unit 1
                                                                              Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR + LNB.....................................................                90               762             6,863               678             6,087
SCR...........................................................                80             1,525             6,100             1,354             5,411
SNCR + LNB....................................................                65             2,669             4,956             2,368             4,397
SNCR..........................................................                40             4,575             3,050             4,059             2,706
LNB...........................................................                51             3,736             3,889             3,315             3,450
No Controls (Baseline)........................................                 0             7,625  ................             6,765  ................
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Calculated from North Dakota's emissions reductions and control efficiencies.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    Table 72 provides a summary of estimated annual costs for the 
various control options. These values are based on North Dakota's 
estimates in Section 9 of the SIP.

  Table 72--Summary of Antelope Valley Station NOX Reasonable Progress Cost Analysis for Units 1 and 2 Boilers
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
Control option                                             Total Annual \1\               Cost              Cost
                                                               Cost (MM$)        Effectiveness     Effectiveness
                                                           (same for both              ($/ton)           ($/ton)
                                                                   units)
                                                                             -----------------------------------
                                                                                        Unit 1            Unit 2
----------------------------------------------------------------------------------------------------------------
SCR + LNB................................................              46.3              6,746             7,606
SCR......................................................              44                7,213             8,132
SNCR + LNB...............................................              11.24             2,268             2,556
SNCR.....................................................               8.96             2,938             3,311
LNB......................................................               2.28               586               661
----------------------------------------------------------------------------------------------------------------
\1\ North Dakota presented a range of costs for SCR; we are reporting the low end of the range based on our
  position on catalyst life and other considerations discussed in our BART FIP for Milton R. Young Station and
  Leland Olds Station.

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and 
operation of the evaluated controls are not significant enough to 
warrant eliminating any of the control options.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant 
enough to warrant eliminating any of the control options.
    Factor 4: Remaining useful life.
    The remaining useful life of Antelope Valley Units 1 and 2 is at 
least 20 years. Thus, this factor does not impact our reasonable 
progress determination.
    Optional Factor 5: Evaluate visibility impacts.
    Although visibility impact is not one of the four statutory 
factors, North Dakota opted to include the visibility impacts in its 
reasonable progress analysis in Section 9 of the SIP. As explained in 
section V.D.1.e, above, we are disregarding these modeling results 
because the State did not conduct its modeling in a manner that 
properly represents impacts from individual

[[Page 58632]]

sources. (See our Technical Support Document for further explanation of 
our reasoning.) In a document separate from the SIP, North Dakota 
provided results of visibility modeling for Antelope Valley Station 
that was conducted per the BART Guidelines--i.e., assuming natural 
background. This modeling predicts a visibility benefit of 0.754 
deciviews at Theodore Roosevelt from the installation of LNB for both 
units combined.
    Step 6: Select Reasonable Progress Controls.
    Based on our examination of North Dakota's cost estimates and the 
predicted visibility benefit of 0.754 deciviews, we propose to find 
that LNB + SOFA are reasonable controls to address reasonable progress 
for the initial planning period, with an emission limit of 0.17 lb/
MMBtu (30-day rolling average). Of the four reasonable progress factors 
and the optional factor of visibility improvement, cost and visibility 
improvement were the critical ones in our analysis of controls for this 
source. We agree with the State that the other three factors are not 
relevant to this reasonable progress determination. The average cost 
effectiveness values for LNB at each unit are $586 and $661 per ton. 
These values are very reasonable and far less than many of the cost 
effectiveness values the State found reasonable in making its BART 
determinations. Also, the Antelope Valley Station units are comparable 
in size to other large EGUs in North Dakota for which the State 
selected SNCR or combustion controls in the BART context. And, North 
Dakota predicted that installation of LNB would achieve NOX 
reductions of approximately 3,500 tons per unit per year, which is 
substantial. Given the significant predicted visibility benefit, the 
low cost, and the fact that North Dakota's reasonable progress goals 
will not meet the uniform rate of progress, we find that it is 
reasonable to require a reasonable progress limit at Antelope Valley 
Station Units 1 and 2 based on the installation of LNB.
    We have eliminated higher performing options--SNCR + LNB, SCR, and 
SCR + LNB--because their cost effectiveness values are significantly 
higher and/or the emission reductions are not that much higher than 
LNB. Considering the statutory factors, we find that it is not 
reasonable to insist on these higher control levels in this first 
planning period. However, we expect the State to consider such controls 
in the next planning period.
    We are proposing an emission limit of 0.17 lb/MMBtu (30-day rolling 
average) based on a baseline emission rate of 0.35 lb/MMBtu and a 
predicted control efficiency of 51%. We also note that this is the 
presumptive limit in the BART Guidelines for this type of large boiler 
using combustion controls. We find the BART Guidelines' analysis of 
cost effective control technologies/emission limits for similar sources 
useful in assessing achievable emission limits. The emission limit 
would apply on a continuous basis, including during startup, shutdown, 
and malfunction.
    We propose to require that Basin Electric start meeting our 
proposed emission limit at Antelope Valley Station Units 1 and 2 as 
expeditiously as practicable, but no later than July 31, 2018. This is 
consistent with the requirement that the SIP cover an initial planning 
period that ends July 31, 2018. We invite comment on whether a 
different deadline would be appropriate.
    We are proposing monitoring, recordkeeping, and reporting 
requirements for Antelope Valley that are the same as those we are 
proposing for BART for Milton R. Young Station, Leland Olds Station, 
and Coal Creek Station.
 3. Reasonable Progress Goals for North Dakota
    We are proposing to impose reasonable progress controls on Antelope 
Valley Station Units 1 and 2 as described above, as well as more 
stringent BART controls on Milton R. Young Station Units 1 and 2, 
Leland Olds Station Unit 2, and Coal Creek Station Units 1 and 2 than 
North Dakota and WRAP assumed in modeling North Dakota's reasonable 
progress goals. Also, we assume that controls included in the SIP for 
Heskett Station and Coyote Station were not modeled when the reasonable 
progress goals were determined.
    We could not re-run the WRAP modeling due to time and resource 
constraints, but anticipate that the additional controls would result 
in an increase in visibility improvement during the 20% worst 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 
uniform rate of progress at Theodore Roosevelt and Lostwood in 2018. We 
expect the State to quantify the visibility improvement in its next 
Regional Haze SIP revision.
    For purposes of this action, we are proposing reasonable progress 
goals that are consistent with the additional controls we are proposing 
and the Heskett and Coyote controls included in the SIP. While we would 
prefer to quantify the reasonable progress goals, we note that the 
reasonable progress goals themselves are not enforceable values. The 
more critical elements for our FIP are the emissions limits we are 
proposing to impose, which will be enforceable.

J. Long-Term Strategy

    As described in section IV.E of this action, the long-term strategy 
is a compilation of state-specific control measures relied on by the 
state for achieving its reasonable progress goals. The long-term 
strategy must include ``enforceable emissions limitations, compliance 
schedules, and other measures as necessary to achieve the reasonable 
progress goals'' for all Class I areas within, or affected by emissions 
from, the state. 40 CFR 51.308(d)(3). North Dakota's long-term strategy 
for the first implementation period addresses the emissions reductions 
from federal, state, and local controls that take effect in the state 
from the end of the baseline period starting in 2004 until 2018. The 
North Dakota long-term strategy was developed by North Dakota, in 
coordination with the WRAP, through an evaluation of the following 
components: (1) WRAP emission inventories for a 2002 baseline and a 
2018 projection (including reductions from WRAP member state controls 
required or expected under federal and state regulations (including 
BART)); (2) modeling to determine visibility improvement and apportion 
individual state contributions; (3) state consultation; and (4) 
application of the long-term strategy factors. The State's detailed 
long-term strategy is included in Section 10 of the Regional Haze SIP.
1. Emissions Inventories
    40 CFR 51.308(d)(3)(iii) requires that North Dakota 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 it affects. North 
Dakota must identify the baseline emissions inventory on which its 
strategies are based. 40 CFR 51.308(d)(3)(iv) requires that North 
Dakota identify all anthropogenic (human-caused) sources of visibility 
impairment it considered in developing its long-term strategy. This 
includes major and minor stationary

[[Page 58633]]

sources, mobile sources, and area sources. In its efforts to meet these 
requirements, North Dakota relied on technical analyses developed by 
WRAP and approved by all state participants, as described below.
    Emissions within North Dakota are both naturally occurring and man-
made. Two primary sources of naturally occurring emissions include 
wildfires and windblown dust. In North Dakota, 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 North Dakota inventory includes emissions of 
SO2, NOX, PM2.5, PM10, 
organic carbon, elemental carbon, VOCs, and NH3.
    An emissions inventory for each pollutant was developed by WRAP for 
North Dakota for the baseline year 2002 and for 2018, which is the 
first reasonable progress 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. North Dakota made 
some adjustments to area oil and gas to include SO2 
emissions from flaring and lease use of sour gas at well sites. 
Emissions included in the 2018 WRAP inventory for the proposed Gascoyne 
500 coal-fired power plant were removed since the Permit-to-Construct 
application for this facility was withdrawn. North Dakota disagreed 
with the WRAP-estimated NOX emissions for area oil and gas 
production predicted for 2018, and based on discussions with the Oil 
and Gas Division of the North Dakota Industrial Commission and 
representatives of WRAP, adjusted these emissions to 2.5 times the 2002 
emission rate.
    There are ten different emission inventory source categories 
identified in the North Dakota regional haze Plan: Point, area, area 
oil and gas, on-road, off-road, all fire, biogenic, road dust, fugitive 
dust, and windblown dust. Tables 73 through 78 show the 2002 baseline 
emissions, the 2018 projected emissions, and net changes of emissions 
for SO2, NOX, organic carbon, elemental carbon, 
PM2.5, and PM10 by source category in North 
Dakota. The methods that WRAP used to develop these emission 
inventories are described in more detail in Appendix A.5 of the SIP and 
in the EPA Technical Support Document.
    SO2 emissions in North Dakota, shown in Table 73, come 
mostly from coal combustion at electrical generation facilities, with 
smaller amounts coming from the oil and gas industry, natural gas 
combustion, and mobile sources. A 60% statewide reduction in 
SO2 emissions is expected by 2018 due to planned controls on 
existing sources. This includes emission reductions of approximately 
98,000 tons from the installation of SO2 BART controls on 
the EGUs at Milton R. Young Station, Leland Olds Station, Coal Creek 
Station, and Stanton Station.

                          Table 73--North Dakota SO2 Emission Inventory--2002 and 2018
                               [North Dakota statewide SO2 emissions (tons/year)]
----------------------------------------------------------------------------------------------------------------
             Source category                Baseline 2002      Future 2018       Net change      Percent change
----------------------------------------------------------------------------------------------------------------
Point...................................           157,069            59,560           -97,509               -62
All Fire................................               540               337              -203               -38
Biogenic................................                 0                 0                 0                 0
Area....................................             5,557             5,995               438                 8
Area Oil and Gas........................             4,958             4,200              -758               -15
On-Road Mobile..........................               812                81              -731               -90
Off-Road Mobile.........................             7,246               276            -6,970               -96
Road Dust...............................                 3                 3                 0                 0
Fugitive Dust...........................                26                30                 4               15%
Wind Blown Dust.........................                 0                 0                 0                 0
                                         -----------------------------------------------------------------------
    Total...............................           176,211            70,482          -105,729               -60
----------------------------------------------------------------------------------------------------------------

    NOX emissions in North Dakota, shown in Table 74, are 
expected to decline 25% by 2018, primarily due to significant 
improvements in mobile sources. Off-road and on-road vehicle 
NOX emissions are estimated to decline by more than 40,000 
tons per year from the base case emissions total of 80,000 tons per 
year. Also, the State projected emission reductions of over 21,000 tons 
from the installation of NOX BART controls on the EGUs at 
Milton R. Young Station, Leland Olds Station, Coal Creek Station, and 
Stanton Station. Increases in area oil and gas sources are related to 
increased drilling and production activity, which is expected to taper 
off from current levels to 2.5 times the 2002 levels by 2018.

                          Table 74--North Dakota NOX Emission Inventory--2002 and 2018
                               [North Dakota statewide NOX emissions (tons/year)]
----------------------------------------------------------------------------------------------------------------
             Source category                Baseline 2002      Future 2018       Net change      Percent change
----------------------------------------------------------------------------------------------------------------
Point...................................            87,438            62,383           -25,055               -29
All Fire................................             1,774             1,073              -701               -40
Biogenic................................            44,569            44,569                 0                 0
Area....................................            10,833            12,456             1,623                15
Area Oil and Gas........................             4,631            11,577             6,946               150
On-Road Mobile..........................            24,746             4,906           -19,840               -80
Off-Road Mobile.........................            55,502            34,557           -20,945               -38
Road Dust...............................                 3                 3                 0                 0
Fugitive Dust...........................                40                41                 1                 3

[[Page 58634]]

 
Wind Blown Dust.........................                 0                 0                 0                 0
                                         -----------------------------------------------------------------------
    Total...............................           229,536           171,566           -57,970               -25
----------------------------------------------------------------------------------------------------------------

    Most of the organic carbon emissions in North Dakota are from fires 
as shown in Table 75. Natural (non-anthropogenic) wildfire can 
fluctuate greatly from year to year. 2002 was an average year for 
wildfires in North Dakota. Another sizable source is anthropogenic fire 
(human-caused), such as forestry prescribed burning, agricultural field 
burning, and outdoor residential burning. Overall, organic carbon 
emissions are estimated to decline by 19% by 2018.

                     Table 75--North Dakota Organic Carbon Emission Inventory--2002 and 2018
                          [North Dakota statewide organic carbon emissions (tons/year)]
----------------------------------------------------------------------------------------------------------------
             Source category                Baseline 2002      Future 2018       Net change      Percent change
----------------------------------------------------------------------------------------------------------------
Point...................................               262               248               -14                -5
All Fire................................             3,657             2,647            -1,010               -28
Biogenic................................                 0                 0                 0                 0
Area....................................             1,466             1,387               -79                -5
Area Oil and Gas........................                 0                 0                 0                 0
On-Road Mobile..........................               231               151               -80               -35
Off-Road Mobile.........................             1,034               457              -577               -56
Road Dust...............................               201               193                -8                -4
Fugitive Dust...........................             1,989             2,041                52                 3
Wind Blown Dust.........................                 0                 0                 0                 0
                                         -----------------------------------------------------------------------
    Total...............................             8,840             7,124            -1,716               -19
----------------------------------------------------------------------------------------------------------------

    The primary source of elemental carbon is off-road mobile sources 
as shown in Table 76. Another contributor is fire. Other emissions of 
note are area and on-road mobile sources. Elemental carbon emissions 
are estimated to decrease by 52% by 2018 due mostly to new Federal 
mobile source regulations.

                    Table 76--North Dakota Elemental Carbon Emission Inventory--2002 and 2018
                         [North Dakota Statewide Elemental Carbon Emissions (tons/year)]
----------------------------------------------------------------------------------------------------------------
             Source category                Baseline 2002      Future 2018       Net change      Percent change
----------------------------------------------------------------------------------------------------------------
Point...................................                29                32                 3                10
All Fire................................               510               449               -61               -12
Biogenic................................                 0                 0                 0                 0
Area....................................               262               267                 5                 2
Area Oil and Gas........................                 0                 0                 0                 0
On-Road Mobile..........................               272                48              -224               -82
Off-Road Mobile.........................             3,625             1,363            -2,262               -62
Road Dust...............................                15                14                -1                -7
Fugitive Dust...........................               135               139                 4                 3
Wind Blown Dust.........................                 0                 0                 0                 0
                                         -----------------------------------------------------------------------
    Total...............................             4,848             2,312            -2,536               -52
----------------------------------------------------------------------------------------------------------------

    As detailed in Tables 77 and 78, the primary sources of PM (both 
PM10 and PM2.5) are road, fugitive, and windblown 
dust (agriculture, mining, construction, and unpaved and paved roads). 
Overall, PM shows an increase of 2-3% by 2018. North Dakota has 
approximately 38 million acres of farm and ranch land--approximately 
86% of the State's area. Working the land produces significant amounts 
of fugitive and windblown dust. The WRAP estimated that emission 
sources in North Dakota put more than 420,000 tons of PM into the 
atmosphere in 2002. Fugitive dust from agricultural activities and 
windblown dust from farm fields were major contributors to these 
emissions. Although PM emissions were large, the effect on visibility 
in the North Dakota Class I areas was relatively small, but not 
insignificant. At Theodore Roosevelt, coarse mass and soil combined to 
contribute approximately 11% of the total extinction during the 20% 
worst days of the baseline period. At Lostwood, approximately 7% of the 
total extinction was due to coarse mass and soil. North Dakota sources 
contributed approximately 45% of the PM2.5 and 
PM10 at Theodore Roosevelt and approximately 30% at Lostwood 
during the 20% worst days in 2000-2004. North Dakota stated that it 
anticipated an increase in agricultural conservation

[[Page 58635]]

tillage practices by 2018, with a resultant reduction in 
PM2.5 and PM10 emissions; however, North Dakota 
did not adjust the WRAP figures. WRAP figures for potential emission 
sources on the 20% worst visibility days are provided in Section 6 of 
the SIP.

                         Table 77--North Dakota PM2.5 Emission Inventory--2002 and 2018
                              [North Dakota Statewide PM2.5 Emissions (tons/year)]
----------------------------------------------------------------------------------------------------------------
             Source category                Baseline 2002      Future 2018       Net change      Percent change
----------------------------------------------------------------------------------------------------------------
Point...................................             2,002             2,086                84                 4
All Fire................................               821               404              -417               -51
Biogenic................................                 0                 0                 0                 0
Area....................................             1,617             1,647                30                 2
Area Oil and Gas........................                 0                 0                 0                 0
On-Road Mobile..........................                 0                 0                 0                 0
Off-Road Mobile.........................                 0                 0                 0                 0
Road Dust...............................             3,086              2956              -130                -4
Fugitive Dust...........................            36,354             37999             1,645                 5
Wind Blown Dust.........................            17,639             17639                 0                 0
Total...................................            61,519            62,731             1,212                 2
----------------------------------------------------------------------------------------------------------------

               Table 78--North Dakota Coarse Particulate Matter Emission Inventory--2002 and 2018
                    [North Dakota Statewide Coarse Particulate Matter Emissions (tons/year)]
----------------------------------------------------------------------------------------------------------------
             Source category                Baseline 2002      Future 2018       Net change      Percent change
----------------------------------------------------------------------------------------------------------------
Point...................................               565             2,349             1,784               316
All Fire................................               503               460               -43                -9
Biogenic................................                 0                 0                 0                 0
Area....................................               199               216                17                 9
Area Oil and Gas........................                 0                 0                 0                 0
On-Road Mobile..........................               141               111               -30               -21
Off-Road Mobile.........................                 0                 0                 0                 0
Road Dust...............................            28,711            27,478            -1,233                -4
Fugitive Dust...........................           172,606           184,063            11,457                 7
Wind Blown Dust.........................           158,752           158,752                 0                 0
                                         -----------------------------------------------------------------------
    Total...............................           361,477           373,429            11,952                 3
----------------------------------------------------------------------------------------------------------------

2. Sources of Visibility Impairment in North Dakota Class I Areas
    In order to determine the significant sources contributing to haze 
in North Dakota's Class I areas, North Dakota relied upon two source 
apportionment analysis techniques developed by the WRAP. The first 
technique was regional modeling using the Comprehensive Air Quality 
Model (CAMx) and the PM Source Apportionment Technology (PSAT) tool, 
used for the attribution of sulfate and nitrate sources only. The 
second technique was the Weighted Emissions Potential (WEP) tool, used 
for attribution of sources of organic carbon, elemental carbon, 
PM2.5, and PM10. The WEP tool is based on 
emissions and residence time, not modeling.
    PSAT uses the CAMx air quality model to show nitrate-sulfate-
ammonia chemistry and apply this chemistry to a system of tracers or 
``tags'' to track the chemical transformations, transport, and removal 
of NOX and SO2. These two pollutants are 
important because they tend to originate from anthropogenic sources. 
Therefore, the results from this analysis can be useful in determining 
contributing sources that may be controllable, both in-state and in 
neighboring states.
    WEP is a screening tool that helps to identify source regions that 
have the potential to contribute to haze formation at specific Class I 
areas. Unlike PSAT, this method does not account for chemistry or 
deposition. The WEP combines emissions inventories, wind patterns, and 
residence times of air masses over each area where emissions occur, to 
estimate the percent contribution of different pollutants. Like PSAT, 
the WEP tool compares baseline values (2000-2004) to 2018 values, to 
show the improvement expected by 2018, for sulfate, nitrate, organic 
carbon, elemental carbon, PM2.5, and PM10. More 
information on the WRAP modeling methodologies is available in the EPA 
Technical Support Document.
    The PSAT and WEP results presented in Tables 79 and 80 were derived 
from Section 6 of the SIP. Table 79 shows the contribution of different 
pollutant species from North Dakota sources. Sulfates and nitrates are 
the primary pollutants contributing to extinction.

                    Table 79--ND Sources Extinction Contribution 2000-2004 for 20% Worst Days
----------------------------------------------------------------------------------------------------------------
                                                                                                   ND sources
                                                                                   Species       contribution to
           Class I area               Pollutant species    Extinction (Mm-1)   contribution to       species
                                                                              total extinction   extinction (%)
                                                                                     (%)               \1\
----------------------------------------------------------------------------------------------------------------
TRNP..............................  Sulfate..............              17.53                35                21
                                    Nitrate..............              13.74                27                19

[[Page 58636]]

 
                                    OC...................              10.82                21                12
                                    EC...................               2.75                 5                29
                                    PM2.5................               0.9                  2                44
                                    PM10.................               4.82                10                45
                                    Sea Salt.............               0.07                 0                 0
LWA...............................  Sulfate..............              21.4                 34                18
                                    Nitrate..............              22.94                36                13
                                    OC...................              11.05                18                23
                                    EC...................               2.84                 5                35
                                    PM2.5................               0.62                 1                28
                                    PM10.................               3.93                 6                32
                                    Sea Salt.............               0.26                 0                 0
----------------------------------------------------------------------------------------------------------------
\1\ Contribution of sulfate and nitrate based on PSAT; OC, EC, PM2.5, PM10, and Sea Salt contribution based on
  WEP.

    Table 80 shows influences from sources both inside and outside of 
North Dakota. The results for sulfates and nitrates indicate that the 
20% worst days at Lostwood and at Theodore Roosevelt are mostly 
impacted by a combination of sources in North Dakota and Canada, as 
well as sources outside the modeling domain.

                            Table 80--Source Region Apportionment for 20% Worst Days
                                                  [Percentage]
----------------------------------------------------------------------------------------------------------------
                                                                       Class I area
                                         -----------------------------------------------------------------------
            Contributing area                            TRNP                                 LWA
                                         -----------------------------------------------------------------------
                                                 SO4               NO3               SO4               NO3
----------------------------------------------------------------------------------------------------------------
North Dakota............................              21.1              19.1              17.9              13.0
Canada..................................              28.3              31.8              45.9              44.6
Outside Domain..........................              32.6              17.9              20.2              14.0
Montana.................................               3.1              15.0               2.4               9.3
CENRAP..................................               4.9               2.5               5.3               5.1
Other...................................              10.5              13.7               8.3              14.0
----------------------------------------------------------------------------------------------------------------

    See the Technical Support Document for details on how the 2018 
emissions inventory was constructed. WRAP and North Dakota used this 
inventory and other states' 2018 emission inventories to construct 
visibility projection modeling for 2018.
3. Visibility Projection Modeling
    The Regional Modeling Center at the University of California 
Riverside, under the oversight of the WRAP Modeling Forum, performed 
modeling for the regional haze long-term strategy for the WRAP member 
states, including North Dakota. The modeling analysis is a complex 
technical evaluation that began with selection of the modeling system. 
Regional Modeling Center primarily used the CMAQ photochemical grid 
model to estimate 2018 visibility conditions in North Dakota and all 
western Class I areas, based on application of the regional haze 
strategies in the various state plans, including assumed controls on 
BART sources.
    The Regional Modeling Center developed air quality modeling inputs, 
including annual meteorology and emissions inventories for: (1) A 2002 
actual emissions base case, (2) a planning case to represent the 2000-
2004 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 2005. 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. The WRAP states' modeling was developed in accordance with 
our guidance.\86\ A more detailed description of the CMAQ modeling 
performed for the WRAP can be found in Appendix A.5 of the SIP and in 
the Technical Support Document.
---------------------------------------------------------------------------

    \86\ Guidance on the Use of Models and Other Analyses for 
Demonstrating Attainment of Air Quality Goals for Ozone, 
PM2.5, and Regional Haze, (EPA-454/B-07-002), April 2007, 
located at http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf. Emissions Inventory Guidance for Implementation of 
Ozone and Particulate Matter National Ambient Air Quality Standards 
(NAAQS) and Regional Haze Regulations, August 2005, updated November 
2005 (``our Modeling Guidance''), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001.
---------------------------------------------------------------------------

    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 Regional Modeling 
Center examined the model performance of the regional modeling for the 
areas of interest before determining whether the CMAQ model results 
were suitable for use in the regional haze assessment of the long-term 
strategy and for use in the modeling assessment. The 2002

[[Page 58637]]

modeling efforts were used to evaluate air quality/visibility modeling 
for a historical episode--in this case, for calendar year 2002--to 
demonstrate the suitability of the modeling systems for subsequent 
planning, sensitivity, and emissions control strategy modeling. Model 
performance evaluation compares output from model simulations with 
ambient air quality data for the same time period to determine whether 
model performance is sufficiently accurate to justify using the model 
to simulate future conditions. Once the Regional Modeling Center 
determined that model performance was acceptable, it used the model to 
determine the 2018 reasonable progress goals using the current and 
future year air quality modeling predictions, and compared the 
reasonable progress goals to the uniform rate of progress.
    To supplement the WRAP modeling effort, North Dakota conducted 
further analyses using a hybrid modeling approach to address concerns 
pertaining to weight of evidence and spatial resolution issues. The 
North Dakota hybrid modeling approach involved nesting a local North 
Dakota CALPUFF domain within the WRAP National CMAQ domain. This 
approach is explained in detail in Section 8 of the SIP.
    North Dakota believes its modeling methodology more realistically 
defines plume geometry for local large point sources and discounts the 
impacts of international sources in Canada over which North Dakota has 
no control. North Dakota is the only WRAP State which opted to develop 
its own reasonable progress modeling methodology. Appendix W outlines 
specific criteria for the use of alternate models and it does not 
appear that those criteria have been satisfied for the use of North 
Dakota's hybrid modeling. In addition, as modeling science has 
improved, there have been a number of technical changes in the CALPUFF 
modeling system and EPA/Federal Land Managers recommended default 
settings, changes that have been implemented since North Dakota 
proposed the CMAQ/CALPUFF hybrid modeling approach in 2007. In the 
Reasonable Progress modeling, the hybrid CALPUFF/CMAQ modeling results 
were adjusted based on IMPROVE monitoring data, and it is not clear 
whether the use of these obsolete settings affected the weight of 
evidence factors or the Reasonable Progress demonstration. The settings 
North Dakota used in the CALPUFF model within the hybrid modeling 
system would not be considered technically sound if contained in a 
regulatory modeling protocol in future projects. However, in this 
instance it did not make a difference since North Dakota is not able to 
meet the uniform rate of progress with either the WRAP analysis or 
North Dakota's hybrid modeling system.
4. Consultation and Emissions Reductions for Other States' Class I 
Areas
    40 CFR 51.308(d)(3)(i) requires that North Dakota consult with 
another state if its emissions are reasonably anticipated to contribute 
to visibility impairment at that state's Class I area(s), and that 
North Dakota consult with other states if those other states' emissions 
are reasonably anticipated to contribute to visibility impairment at 
Theodore Roosevelt or Lostwood. North Dakota's consultations with other 
states are described in section V.G.5 above. After evaluating whether 
emissions from North Dakota sources contribute to visibility impairment 
in other states' Class I areas, North Dakota concluded there was no 
contribution sufficient to require consultation. North Dakota's 
evaluation relied upon NOX BART and reasonable progress 
reductions as described in the SIP. Nontheless, North Dakota did 
consult with other states and tribes, largely through the WRAP process, 
in order to meet the regulatory requirements.
    40 CFR 51.308(d)(3)(ii) requires that if North Dakota emissions 
cause or contribute to impairment in another state's Class I area, 
North Dakota must demonstrate that it has included in its Regional Haze 
SIP all measures necessary to obtain its share of the emission 
reductions needed to meet the progress goal for that Class I area. 
Section 51.308(d)(3)(ii) also requires that, since North Dakota 
participated in a regional planning process, it must ensure it has 
included all measures needed to achieve its apportionment of emission 
reduction obligations agreed upon through that process. As we state in 
the Regional Haze Rule, North Dakota's commitments to participate in 
WRAP bind it to secure emission reductions agreed to as a result of 
that process, unless it proposes a separate process and performs its 
consultations on the basis of that process. See 64 FR 35735,
    North Dakota accepted and incorporated the WRAP-developed 
visibility modeling into its Regional Haze SIP, and the Regional Haze 
SIP includes the controls assumed in the modeling. North Dakota 
satisfied the Regional Haze Rule's requirements for consultation and 
included controls in the SIP sufficient to address the relevant 
requirements of the Regional Haze Rule related to impacts on Class I 
areas in other states. However, we are proposing to disapprove the 
long-term strategy for other reasons, as described below.
5. Mandatory Long-Term Strategy Factors
    40 CFR 51.308(d)(3)(v) requires that North Dakota, at a minimum, 
consider certain factors in developing its long-term strategy (the 
long-term strategy factors). These are: (a) Emission reductions due to 
ongoing air pollution control programs, including measures to address 
reasonably attributable visibility impairment; (b) measures to mitigate 
the impacts of construction activities; (c) emissions limitations and 
schedules for compliance to achieve the reasonable progress goal; (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 long-term strategy.
a. Reductions Due to Ongoing Air Pollution Programs
    In addition to its BART determinations, North Dakota's long-term 
strategy incorporates emission reductions due to a number of ongoing 
air pollution control programs.
i. Prevention of Significant Deterioration/New Source Review Rules
    The two primary regulatory tools for addressing visibility 
impairment from industrial sources are BART and the Prevention of 
Signification Deterioration New Source Review rules. The Prevention of 
Signification Deterioration rules protect visibility in Class I areas 
from new industrial sources and major changes to existing sources. 
North Dakota's Air Pollution Control Rules (NDAC Chapter 33-15-19) 
contain requirements for visibility impact assessment and mitigation 
associated with emissions from new and modified major stationary 
sources. A primary responsibility of North Dakota under these rules is 
visibility protection. Chapter 33-15-19 describes mechanisms for 
visibility impact assessment and review by North Dakota, as well as 
impact modeling methods and requirements. Typically, this modeling is 
conducted for sources within 300 kilometers of a Class I area. North 
Dakota will not issue an air quality permit to any new major source

[[Page 58638]]

or major modification within this distance that is found through 
modeling to cause significant visibility impairment, unless the impact 
is mitigated.
ii. North Dakota's Phase I Visibility Protection Program
    In 1987 North Dakota adopted NDAC Chapter 33-15-19 for visibility 
protection to address EPA's Phase I visibility rules. Also in 1987, 
North Dakota adopted NDAC Chapter 33-15-04 for open burning 
restrictions; it provides that, except in an emergency, the visibility 
of any class I area cannot be adversely impacted.
iii. On-Going Implementation of State and Federal Mobile Source 
Regulations
    Mobile source annual emissions show a major decrease in 
NOX in North Dakota from 2002 to 2018. This reduction will 
result from numerous ``on the books'' Federal mobile source 
regulations. 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 parts per 
million (ppm) to 15 ppm. Ultra-low sulfur diesel fuel enables the use 
of cleaner technology diesel engines and vehicles with advanced 
emissions control devices, resulting in significantly lower emissions.
    Diesel fuel intended for locomotive, marine, and non-road (farming 
and construction) engines and equipment was required to meet a low 
sulfur diesel fuel maximum specification of 500 ppm sulfur in 2007 
(down from 5000 ppm). By 2010, the ultra-low sulfur diesel fuel 
standard of 15 ppm sulfur applied to all non-road diesel fuel. 
Locomotive and marine diesel fuel will be required to meet the ultra-
low sulfur diesel standard beginning in 2012, resulting in further 
reductions of diesel emissions.
b. Measures To Mitigate the Impacts of Construction Activities
    In developing its long-term strategy, North Dakota has considered 
the impact of construction activities. Based on 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 North Dakota Class I areas, North Dakota 
found that current State regulations adequately address construction 
activities.
    Current rules addressing impacts from construction activities in 
North Dakota include NDAC 33-15-17, which regulates fugitive dust 
emissions. The rule addresses ``fugitive emissions'' from a variety of 
sources applicable to construction activities. This regulation requires 
``reasonable precautions'' be taken to prevent PM from becoming 
airborne from activities such as construction projects. Types of 
actions to be taken include the use of water or chemicals for control 
of dust from demolition, construction operations, unpaved roads at 
construction sites, and material stockpiles. North Dakota requires 
permits for asphalt and concrete plants and rock, sand, and gravel 
plants. The State has committed to re-evaluating emissions from 
construction activities related to the oil and gas industry, including 
construction of oil well pads, compressor stations, and gas plants, in 
future Regional Haze SIP planning periods since this has the potential 
to be a growing source category.
c. Emission Limitation and Schedules of Compliance
    The SIP contains emission limits and schedules of compliance for 
those sources subject to BART: Milton R. Young Station, Leland Olds 
Station, Coal Creek Station, and Stanton Station. The schedules for 
implementation of BART for these sources are identified in Section 7.5 
of the SIP and in permits included in Appendix D of the SIP. While the 
State did not impose any emission limits to meet reasonable progress 
requirements, the State did include emission limits for Coyote Station 
and Heskett Station in the SIP. These ``other'' emission reductions are 
discussed in the long-term strategy under Section 10.6.1 of the SIP and 
the limits and compliance schedules are included in permits contained 
in Appendix A of the SIP. See section V.G.3 of this action for further 
discussion of these limits and schedules.
d. Source Retirement and Replacement Schedules
    The State does not anticipate major source retirements or 
replacements. Replacement of existing facilities will be managed 
according to the existing Prevention of Signification Deterioration 
program. The 2018 modeling that WRAP conducted included three new power 
plants in North Dakota. Two are now unlikely to be built. Construction 
of new power plants or replacement of existing plants prior to 2018 is 
unlikely.
e. Agricultural and Forestry Smoke Management Techniques
    North Dakota has an area of approximately 44.16 million acres. Of 
this total, 26.5 million acres is cropland, 11 million acres is 
pasture/rangeland, and 236,000 acres is woodland/forest, with five 
State forests comprising 13,300 acres. Prescribed burning is governed 
by State rules in NDAC 33-15-04-02 and must be approved in advance. 
Although agricultural crop burning does not require advance approval, 
most agricultural cropland burning takes place in the eastern two-
thirds of the State away from the State's Class I areas. In general, 
prevailing winds carry smoke from cropland burning away from North 
Dakota Class I areas. Table 81, below, shows WRAP's estimate of 
emissions from fire in North Dakota for the 2000-2004 baseline period.

                                                Table 81--Annual Average Emissions From Fire (2000-2004)
                                                                       [Tons/Year]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                   Source                           PM2.5             PM10               NOX               SO2               OC                EC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural.....................................               225               441               773               250             2,214               424
Anthropogenic...............................               596                62              1001               290             1,443                86
                                             -----------------------------------------------------------------------------------------------------------
    Total...................................               821               503              1774               540             3,657               510
--------------------------------------------------------------------------------------------------------------------------------------------------------

    40 CFR 308(d)(3)(v)(E) of the Regional Haze Rule requires the long-
term strategy to address smoke management techniques for agricultural 
and forestry burning. These two sources generally have a very small 
contribution to visibility impairment in North Dakota Class I areas 
except during the worst days in late July and August when organic 
carbon, an indicator of fire emissions, replaces sulfate and nitrate as 
the dominant contributor to

[[Page 58639]]

extinction. Much of these fire emissions are from wildfires, which 
fluctuate significantly from year to year. According to the source 
apportionment analyses conducted by the WRAP, anthropogenic fire 
emissions in North Dakota contribute less than 1% of the total sulfate 
and nitrate concentrations at Theodore Roosevelt and Lostwood. North 
Dakota found that the current smoke management rules are sufficient to 
achieve reasonable progress toward the national visibility goal but 
will reevaluate these rules in future planning periods.
f. Enforceability of North Dakota's Measures
    40 CFR 51.308(d)(3)(v)(F) of the Regional Haze Rule requires States 
to ensure that emission limitations and control measures used to meet 
reasonable progress goals are enforceable. In addition to what is 
required by the Regional Haze Rule, general SIP requirements mandate 
that the SIP must also include adequate monitoring, recordkeeping, and 
reporting requirements for the regional haze emission limits and 
requirements. See CAA section 110(a). As noted, the SIP specifies BART 
and other emission limits and compliance schedules, and North Dakota 
has included such limits and compliance schedules in State-enforceable 
air quality permits that North Dakota has included in the SIP.\87\ (See 
Appendix A and Appendix D of the SIP.) In addition to specifying the 
limits and compliance schedules, these permits specify monitoring, 
recordkeeping, and reporting requirements. North Dakota worked closely 
with EPA in developing these requirements. For SO2 and 
NOX limits, North Dakota has required 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, the SIP 
requires testing in accordance with EPA-approved test methods and 
compliance with a CAM plan approved as part of a Title V permit. The 
SIP requires that relevant records be kept for five years, and that 
sources report excess emissions on a quarterly basis.
---------------------------------------------------------------------------

    \87\ Because they are included in the SIP, these permits will 
remain unchanged for federal purposes unless and until North Dakota 
submits a change to permit terms as a SIP revision, and EPA approves 
such SIP revision.
---------------------------------------------------------------------------

    In addition to these permits, various requirements that are 
relevant to regional haze are codified in North Dakota's regulations, 
including North Dakota's Regional Haze Rule (NDAC 33-15-25, contained 
in Appendix H of the SIP) and its Prevention of Signification 
Deterioration and other provisions mentioned above.
g. Anticipated Net Effect on Visibility Due to Projected Changes
    The anticipated net effect on visibility due to projected changes 
in point, area, and mobile source emissions during this planning period 
is addressed in sections V.J.3 above.
h. Periodic SIP Revisions and 5-Year Progress Reports
    Consistent with 40 CFR 51.308(g), North Dakota committed to submit 
to EPA a progress report, in the form of a SIP revision, every five 
years following the initial submittal of the SIP. The report will 
evaluate progress towards the reasonable progress goal for each 
mandatory Class I Federal area located within the State and in each 
mandatory Class I Federal area located outside the State that may be 
affected by emissions from within the State. These requirements and 
commitment are discussed in detail in section 11.2 of the North Dakota 
SIP.
6. Our Conclusion on North Dakota's Long Term Strategy
    We propose to partially approve and partially disapprove North 
Dakota's long-term strategy. Because we are proposing to disapprove the 
NOX BART determinations for Milton R. Young Station Units 1 
and 2, Leland Olds Station Unit 2, and Coal Creek Station Units 1 and 
2, we are also proposing to disapprove the corresponding permit limits 
and monitoring, recordkeeping, and reporting provisions that North 
Dakota relied on as part of its long-term strategy. Because we are 
proposing to disapprove the reasonable progress determination for 
Antelope Valley Station Units 1 and 2, we are also proposing to 
disapprove the long-term strategy because it does not include 
appropriate NOX reasonable progress emission limits, 
compliance schedule, and corresponding monitoring, recordkeeping, and 
reporting requirements for Antelope Valley Station Units 1 and 2. 
Except for these elements, the long-term strategy satisfies the 
requirements of 40 CFR 51.308(d)(3), and we are proposing to approve 
it.
7. Partial FIP for Long Term Strategy
    We are proposing regulatory language as part of our FIP that 
specifies emission limits, compliance schedules, and monitoring, 
recordkeeping, and reporting requirements for the following sources, 
requirements, and pollutants:
    a. Milton R. Young Station Units 1 and 2, BART, NOX.
    b. Leland Olds Station Unit 2, BART, NOX.
    c. Coal Creek Units 1 and 2, BART, NOX.
    d. Antelope Valley Station Units 1 and 2, reasonable progress, 
NOX.
    We are proposing this regulatory language to fill the gap in the 
long-term strategy that would be left by our proposed partial 
disapproval of the long-term strategy. Our monitoring, recordkeeping, 
and reporting requirements generally mirror those imposed by North 
Dakota, except that all cross-references are to federal regulations 
only, we have modified some of the requirements from 40 CFR part 75, 
and we are not providing a separate limit for startup for Milton R. 
Young Station Units 1 and 2. We note that no other source or unit has 
requested or received a separate limit for startup, and we conclude 
that such a limit is not warranted. The 30-day averaging period for the 
limit already accounts for potential fluctuations due to properly-
conducted startups, and nothing in North Dakota's record convinces us 
that Milton R. Young Station will be unable to comply with the BART 
limits we have selected.

K. Coordination of Reasonably Attributable Visibility Impairment and 
Regional Haze Requirements

    Our visibility regulations direct states to coordinate their 
reasonably attributable visibility impairment long-term strategy and 
monitoring provisions with those for regional haze, as explained in 
section IV.F, above. Under our reasonably attributable visibility 
impairment regulations, the reasonably attributable visibility 
impairment portion of a state SIP must address any integral vistas 
identified by the Federal Land Managers pursuant to 40 CFR 51.304. See 
40 CFR 51.302. An integral vista is defined in 40 CFR 51.301 as a 
``view perceived from within the mandatory Class I Federal area of a 
specific landmark or panorama located outside the boundary of the 
mandatory Class I Federal area.'' Visibility in any mandatory Class I 
Federal area includes any integral vista associated with that area. The 
Federal Land Managers did not identify any integral vistas in North 
Dakota. In addition, neither Class I area in North Dakota is 
experiencing reasonably attributable visibility impairment, nor are any 
North Dakota sources affected by the reasonably attributable visibility 
impairment provisions. The North Dakota Regional Haze SIP, in Sections 
10.6.1 and 4.1, does address the two requirements regarding 
coordination of the regional haze long-term strategy and monitoring

[[Page 58640]]

provisions with the reasonably attributable visibility impairment long-
term strategy and monitoring provisions. As noted in the Regional Haze 
SIP, North Dakota has previously made a commitment to address 
reasonably attributable visibility impairment should a Federal Land 
Manager certify visibility impairment from an individual source. See 
North Dakota visibility SIP revisions to address reasonably 
attributable visibility impairment, (NDAC 13-15-19, EPA approved 
September 28, 1988, 53 FR 37757), and Prevention of Signification 
Deterioration visibility provisions (NDAC 13-15-15, EPA approved July 
19, 2007, 72 FR 39564). We propose to find that the Regional Haze SIP 
appropriately supplements and augments North Dakota's reasonably 
attributable visibility impairment visibility provisions by updating 
the monitoring and long-term strategy provisions to address regional 
haze. We discuss the relevant monitoring provisions further below.

L. Monitoring Strategy and Other SIP Requirements

    40 CFR 51.308(d)(4) requires that the SIP 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 
reasonably attributable visibility impairment. 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 reasonable progress goals to address 
regional haze for all mandatory Class I Federal areas within the state 
are being achieved. Consistent with EPA's monitoring regulations for 
reasonably attributable visibility impairment and regional haze, North 
Dakota indicates in Section 4.2 of the Regional Haze SIP that it will 
rely on the IMPROVE network for compliance purposes, in addition to any 
reasonably attributable visibility impairment monitoring that may be 
needed in the future. The IMPROVE monitors at the North Dakota Class I 
Areas also described in Section 4.2 of the SIP. We propose to find that 
North Dakota has satisfied the requirements in 40 CFR 51.308(d)(4) 
enumerated in this paragraph.
    40 CFR 51.308(d)(4)(ii) requires that North Dakota establish 
procedures by which monitoring data and other information are used in 
determining the contribution of emissions from within North Dakota 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. We 
therefore propose that North Dakota has satisfied this requirement.
    40 CFR 51.308(d)(4)(iv) requires that the SIP provide for the 
reporting of all visibility monitoring data to the Administrator at 
least annually for each mandatory Class I Federal area in the state. To 
the extent possible, North Dakota should report visibility monitoring 
data electronically. 40 CFR 51.308(d)(4)(vi) also requires that the SIP 
provide for other elements, including reporting, recordkeeping, and 
other measures, necessary to assess and report on visibility. We 
propose that North Dakota'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 North Dakota maintain a 
statewide inventory of emissions of pollutants that are reasonably 
anticipated to cause or contribute to visibility impairment in any 
mandatory Class I Federal area. The inventory must include emissions 
for a baseline year, emissions for the most recent year for which data 
are available, and estimates of future projected emissions. The state 
must also include a commitment to update the inventory periodically. 
Please refer to section V.J.1, above, where we discuss North Dakota's 
emission inventory. North Dakota states in Section 4 of the SIP that it 
intends to update the North Dakota statewide emissions inventories 
periodically and review periodic emissions information from other 
states and future emissions projections. We propose that this satisfies 
the requirement.

M. Federal Land Manager Coordination

    Lostwood is managed by the Fish and Wildlife Service, and Theodore 
Roosevelt is managed by the National Park Service; these are the 
respective Federal Land Managers for these North Dakota Class I areas. 
Although the Federal Land Managers are very active in participating in 
the regional planning organizations, the Regional Haze Rule grants the 
Federal Land Managers a special role in the review of the regional haze 
SIPs, summarized in section IV.H, above. The Federal Land Managers and 
the state environmental agencies are our partners in the regional haze 
process.
    Under 40 CFR 51.308(i)(2), North Dakota was obligated to provide 
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 SIP. North Dakota sent a 
draft of its Regional Haze SIP to the Fish and Wildlife Service and the 
National Park Service on August 9, 2009 and at the same time notified 
the Federal Land Managers of the State's January 7, 2010 public 
hearing.
    40 CFR 51.308(i)(3) requires that North Dakota provide in its 
Regional Haze SIP a description of how it addressed any comments 
provided by the Federal Land Managers. The Federal Land Managers 
communicated to the State (and EPA) their dissatisfaction with the BART 
determinations for Milton R. Young Station Units 1 and 2 and Leland 
Olds Station Unit 2 among other issues. They expressed their view that 
SCR, instead of SNCR, is NOX BART for these sources. The 
Federal Land Managers also disagreed with North Dakota's rejection of 
reasonable progress controls. North Dakota responded to the Federal 
Land Managers' comments and concerns in Appendix J of the Regional Haze 
SIP.
    Lastly, 40 CFR 51.308(i)(4) specifies the regional haze SIP must 
provide procedures for continuing consultation between the State and 
Federal Land Managers 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. North Dakota commits in Section 11 of its Regional Haze SIP to 
continue to coordinate and consult with the Federal Land Managers as 
required by 40 CFR 51.308(i)(4). North Dakota states that it intends to 
consult the Federal Land Managers 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 North Dakota and other Class I areas.
    While we disagree with the substance of North Dakota's decisions 
regarding NOX BART for Milton R. Young Station

[[Page 58641]]

Units 1 and 2, Leland Olds Station Unit 2, and Coal Creek Station Units 
1 and 2, and reasonable progress controls for NOX for AVS 
Units 1 and 2, we are proposing that the State complied with the 
requirements of 40 CFR 51.308(i).

N. Periodic SIP Revisions and Five-year Progress Reports

    North Dakota commits in Section 11 of the SIP to complete items 
required in the future by the Regional Haze Rule. North Dakota 
acknowledged its obligation under 40 CFR 51.308(f) to submit periodic 
progress reports and Regional Haze SIP revisions, with the first report 
due by July 31, 2018 and every ten years thereafter.
    North Dakota acknowledged its obligation under 40 CFR 51.308(g) to 
submit a progress report in the form of a SIP revision to us every five 
years following the initial submittal of the Regional Haze SIP. The 
report will evaluate the progress made towards the reasonable progress 
goals for each mandatory Class I area located within North Dakota and 
in each mandatory Class I area located outside North Dakota that may be 
affected by emissions from within North Dakota.

VI. Our Analysis of North Dakota's Interstate Visibility Transport SIP 
Provisions

    In July 1997, EPA promulgated the 1997 8-hour ozone NAAQS and the 
1997 PM2.5 NAAQS. Sections 110(a)(1) and (2) of the CAA 
require states to submit SIPs that provide for the implementation, 
maintenance, and enforcement of a new or revised NAAQS within three 
years following the promulgation of the new or revised standard. Thus, 
states were required to submit SIPs that satisfy the applicable 
requirements under sections 110(a)(1) and (2), including the 
requirements of section 110(a)(2)(D)(i), by July 2000. Among other 
things, section 110(a)(2)(D)(i) requires states to make a submission 
that establishes that the state's SIP contains adequate provisions to 
prevent interference with measures required to be included in the SIPs 
of other states to protect visibility. A state could establish the 
adequacy of its SIP for this purpose by demonstrating that existing 
provisions prevent such interference, by adding new provisions to 
prevent such interference, or by a combination of existing and new 
provisions.
    States, including North Dakota, did not meet the statutory July 
2000 deadline for submission of these SIPs. Accordingly, on April 25, 
2005, EPA made findings of failure to submit, notifying all states, 
including North Dakota, of their failure to make the required SIP 
submission to address interstate transport under section 
110(a)(2)(D)(i). 70 FR 21147. This finding started a 24-month FIP clock 
under section 110(c). Pursuant to section 110(c), EPA is required to 
promulgate a FIP to address the applicable interstate transport 
requirements, unless a state makes the required submission and EPA 
fully approves such submission, within the 24-month period. As noted 
earlier, EPA was sued by WildEarth Guardians for failing to meet its 
statutory FIP obligation for North Dakota by the applicable deadline in 
April of 2007, and is thus under a consent decree deadline to take the 
necessary SIP approval or FIP action.
    EPA issued the 2006 Guidance to make recommendations to states 
about how to make SIP submissions for purposes of section 
110(a)(2)(D)(i), including the visibility prong. Acknowledging that the 
regional haze SIPs were still under development and were not due until 
December 17, 2007, we recommended that states could make a SIP 
submission confirming that it was not possible at that point in time to 
assess whether there was any interference with measures in the 
applicable SIP for another state designed to ``protect visibility'' for 
the 1997 8-hour ozone NAAQS and the 1997 PM2.5 NAAQS. We 
note that our 2006 Guidance was based on the premise that as of the 
time of its issuance in August 2006, it was reasonable for EPA to 
recommend that states could merely indicate that the imminent regional 
haze SIP would be the appropriate means to establish that its SIP 
contained adequate provisions to prevent interference with the 
visibility programs required in other states. Subsequent events have 
demonstrated that we were mistaken in our assumptions that all states 
would submit regional haze SIPs by December of 2007, and mistaken in 
our assumption that all such submissions would meet applicable regional 
haze program requirements and therefore be approved shortly thereafter. 
Our 2006 Guidance was intended to make recommendations that were 
relevant at that point in time, and subsequent events have rendered it 
inappropriate in this specific action. EPA's 2006 Guidance was not 
intended to delay indefinitely the consideration of impacts on other 
states' Class I areas, or to allow the states' failure to submit 
regional haze SIPs on time, or to submit approvable regional haze SIPs, 
to provide an excuse for failing to analyze those impacts in a 
reasonable way. At this point in time, EPA must review the submission 
from the State in light of the actual facts and in light of the 
statutory requirements of section 110(a)(2)(D)(i)(II).
    North Dakota submitted a SIP on April 6, 2009, intended to address 
all four prongs of the interstate transport requirements of CAA 
110(a)(2)(D)(i) for the 1997 8-hour ozone NAAQS and the 1997 
PM2.5 NAAQS. With respect to the visibility prong section in 
110(a)(2)(D)(i)(II), North Dakota merely stated that it was at that 
time working with the WRAP, including associated states and 
stakeholders, to prepare a regional haze SIP. However, North Dakota did 
not explicitly state in its April 6, 2009, submittal that it intended 
that its Regional Haze SIP be used to satisfy the visibility prong, nor 
did it include such a statement in its Regional Haze SIP ultimately 
submitted or in the Governor's letter that accompanied it. The state 
also did not make any other SIP submission indicating that intended to 
meet the requirements of section 110(a)(2)(D)(i)(II) by any other 
means. However, the state did not make the Regional Haze SIP by the 
deadline for such submissions, and the Regional Haze SIP itself does 
not fully meet the requirements of the regional haze program. Hence, we 
are not able to consider the Regional Haze SIP in determining the 
adequacy of North Dakota's SIP vis-[agrave]-vis the visibility prong of 
110(a)(2)(D)(i). Instead, we are considering only the adequacy of North 
Dakota's April 6, 2009 submittal to address the visibility prong.
    The visibility prong, contained in CAA section 110(a)(2)(D)(i)(II), 
requires that states submit a SIP revision containing provisions 
``prohibiting any source or other type of emission activity within the 
state from emitting any air pollutant in amounts which will * * * 
interfere with measures required to be included in the applicable 
implementation plan for any other State under part C [of the CAA] to 
protect visibility.'' Because of the impacts on visibility from the 
interstate transport of pollutants, we interpret the ``good neighbor'' 
provisions of section 110 of the Act described above as requiring 
states to include in their SIPs either measures to prohibit emissions 
that would interfere with the reasonable progress goals required to be 
set to protect Class I areas in other states, or a demonstration that 
emissions from North Dakota sources and activities will not have the 
prohibited impacts.
    The State's April 6, 2009 SIP submission did contain some 
statements concerning the requirements of the

[[Page 58642]]

visibility prong of section 110(a)(2)(D)(i). Section 7.8 of North 
Dakota's submission generally describes the requirements of CAA section 
110(a)(2)(D)(i). With respect to the visibility prong, Section 7.8 
states the following:

    ``In the review process for new or modified stationary sources, 
or other types of emissions activities, the Department will assess 
the impact on neighboring states. * * * With respect to visibility, 
an assessment on Prevention of Signification Deterioration Class I 
area's visibility will be made when a significant impact is 
suspected.''

    It is evident that the State intended this provision to address 
interstate visibility impacts of emissions from new or modified 
sources. This provision was not intended, and is not sufficient, to 
satisfy the requirements of the visibility prong regarding the 
interstate impacts on visibility of emissions from existing North 
Dakota sources.
    Section 7.8.1.D of the SIP specifically addresses interstate 
visibility impacts from existing sources. First, it cites language from 
EPA's 2006 Guidance regarding CAA section 110(a)(2)(D)(i) \88\ that 
reads as follows:
---------------------------------------------------------------------------

    \88\ ``Guidance for State Implementation Plan Submissions to 
Meet Current Outstanding Obligations Under Section 110(a)(2)(D)(i) 
for the 8-Hour Ozone and PM2.5 National Ambient Air 
Quality Standards.''

    ``At this point in time, EPA has made no determination that 
emissions from any State interfere with measures required to be 
included in a plan to address reasonably attributable visibility 
impairment. Further, EPA is not aware of any certification of 
existing reasonably attributable impairments of visibility by a 
Federal Land Manager that has not already been resolved. The EPA 
accordingly believes that States should be able to make a relatively 
simple SIP submission verifying that no source within the State 
emits pollutants that interfere with measures included in the 
---------------------------------------------------------------------------
visibility SIPs under the 1980 regulations.''

    The State responded to EPA's 2006 Guidance by concluding in Section 
7.8.1.D, that ``there are no North Dakota sources of emissions that 
interfere with implementation of visibility SIP [sic] under the 1980 
regulations.'' We find North Dakota's conclusion to be reasonable in so 
far as it addressed the issue of potential adverse visibility impacts 
as contemplated in the 1980 regulations. However, EPA's 2006 Guidance 
also recommended that states address regional haze SIPs under EPA's 
regional haze regulations, and the statute requires a determination 
with respect to measures required in the SIPs of other states.
    Noting that the regional haze SIPs were not due until December 17, 
2007 (over a year after the 2006 Guidance was issued), EPA stated that 
``[t]he States and Regional Planning Organizations are currently 
engaged in the task of identifying those Class I areas impacted by each 
State's emissions and developing strategies for addressing regional 
haze to be included in the States' regional haze SIPs.'' Thus, EPA 
indicated that ``it is currently premature'' to determine whether a 
state's SIP contains adequate provisions to prohibit emissions that 
interfere with measures in other states' regional haze SIPs. EPA 
concluded by saying, ``Accordingly, EPA believes that States may make a 
simple SIP submission confirming that it is not possible at this time 
to assess whether there is any interference with measures in the 
applicable SIP for another State designed to `protect visibility' for 
the 8-hour ozone and PM2.5 NAAQS until regional haze SIPs 
are submitted and approved.'' Thus, EPA's recommendation to states as 
of that particular point in time was that they refer to the imminent 
regional haze SIP submission as the means by which they could address 
the visibility prong of section 110(a)(2)(D)(i).
    Apparently keying off this recommendation, North Dakota included 
the following statement regarding visibility transport and regional 
haze in Section 7.8.1.D:

    ``The State of North Dakota is working with the Western Regional 
Air Partnership, including associated States and stakeholders, to 
prepare a SIP to address the EPA Regional Haze regulation (40 CFR 
51.308). Until regional haze SIPs are submitted and approved, North 
Dakota believes it is not possible at this time to assess whether 
there is any interference with measures in the applicable SIP for 
another state for regional haze.''

    The State's April 6, 2009 SIP submission contains no other 
statements or analysis regarding the impact of emissions from North 
Dakota sources on visibility programs in other states, and in 
particular no other statements concerning impacts on the regional haze 
program in other states.
    North Dakota's April 6, 2009 SIP submission thus suggested that the 
State intended to address the requirements of section 
110(a)(2)(D)(i)(II) by a timely submission of its regional haze SIP by 
December of 2007, but due to intervening circumstances the State did 
not in fact make that submission until March 3, 2010. Moreover, while 
North Dakota ultimately did submit the Regional Haze SIP to address the 
requirements of the regional haze program directly, North Dakota did 
not explicitly specify that it was submitting the Regional Haze SIP 
revision to satisfy the visibility prong of 110(a)(2)(D)(i)(II). Most 
importantly, however, EPA must review the April 6, 2009 submission in 
light of the current facts and circumstances, and the Regional Haze SIP 
revision that the State ultimately submitted does not fully meet the 
substantive requirements of the regional haze program. The State made 
no other SIP submission in which it indicated that it intended to meet 
the visibility prong of section 110(a)(2)(D)(i)(II) in any other way.
    Accordingly, we are proposing to disapprove North Dakota's April 6, 
2009 SIP submittal for the visibility prong of section 
110(a)(2)(D)(i)(II), because that submittal neither contains adequate 
measures to eliminate emissions that would interfere with the required 
visibility programs in other states, nor a demonstration that the 
existing North Dakota SIP already includes measures sufficient to 
eliminate such prohibited impacts. To the extent that the State 
intended to meet the requirement of section 110(a)(2)(D)(i)(II) with 
the Regional Haze SIP, the Regional Haze SIP submission itself is not 
fully approvable.

VII. FIP for Interstate Visibility Transport

    Because we are proposing to disapprove North Dakota's April 6, 2009 
SIP submission with respect to the visibility prong of section 
110(a)(2)(D)(i)(II), we are proposing a FIP to fill the gap that would 
be left by our proposed disapproval. As an initial matter, we note that 
section 110(a)(2)(D)(i)(II) does not explicitly specify how we should 
ascertain whether a state's SIP contains adequate provisions to prevent 
emissions from sources in that state from interfering with measures 
required in another state to protect visibility. Thus, the statute is 
ambiguous on its face, and we must interpret that provision.
    Our 2006 Guidance recommended that a state could meet the 
visibility prong of the transport requirements of section 
110(a)(2)(D)(i)(II) of the CAA by submission of the regional haze SIP, 
due in December 2007. Our reasoning was that the development of the 
regional haze SIPs was intended to occur in a collaborative environment 
among the states. In fact, in developing their respective reasonable 
progress goals, WRAP states consulted with each other through WRAP's 
work groups. As a result of this process, the common understanding was 
that each state would take action to achieve the emissions reductions 
relied upon by other states in their reasonable progress

[[Page 58643]]

demonstrations under the Regional Haze Rule. WRAP states consulted in 
the development of reasonable progress goals, using the products of 
this technical consultation process to co-develop their reasonable 
progress goals. In developing their visibility projections using 
photochemical grid modeling, WRAP states assumed a certain level of 
emissions from sources within North Dakota that coincided with North 
Dakota's BART determinations and North Dakota's existing controls for 
other sources. Although we have not yet received all regional haze 
SIPs, we understand that the WRAP states used the visibility projection 
modeling to establish their own respective reasonable progress goals. 
Thus, we believe that an implementation plan that provides for 
emissions reductions consistent with the assumptions used in those 
states' modeling is one means to ensure that emissions from North 
Dakota sources do not interfere with the measures designed to protect 
visibility in other states.
    North Dakota's Regional Haze SIP submission includes BART 
determinations and reasonable progress conclusions that are consistent 
with the information and assumptions North Dakota provided to the WRAP 
and that other states will have relied upon in the development of their 
own regional haze SIPs. Therefore, North Dakota's Regional Haze SIP, as 
submitted to us, would have been sufficient to obtain North Dakota's 
needed share of emission reductions for interstate transport purposes 
for visibility, if it had been submitted to us for that purpose and if 
it were fully approvable. However, as already noted, North Dakota did 
not specify that it intended to submit its Regional Haze SIP to meet 
the visibility prong of CAA section 110(a)(2)(D)(i)(II). In addition, 
we are proposing to disapprove North Dakota's NOX BART 
determinations for Milton R. Young Station 1 and 2, Leland Olds Station 
2, and Coal Creek Station Units 1 and 2 and North Dakota's 
NOX reasonable progress determination for Antelope Valley 
Station Units 1 and 2, and instead proposing a FIP for purposes of the 
regional haze program. Thus, we are proposing a FIP to meet the 
visibility prong of CAA section 110(a)(2)(D)(i)(II) that relies on the 
combination of the North Dakota Regional Haze SIP provisions that we 
are proposing to approve and the additions to the regional haze program 
for North Dakota that we are proposing in our FIP for NOX 
BART for Milton R. Young Station Units 1 and 2, Leland Olds Station 
Unit 2, and Coal Creek Station Units 1 and 2 and NOX 
reasonable progress for Antelope Valley Station Units 1 and 2. Because 
this combination exceeds the stringency of BART and reasonable progress 
limits that were already factored into the WRAP modeling for reasonable 
progress goals, we propose that this combination meets the visibility 
prong of CAA section 110(a)(2)(D)(i)(II). We propose to find that this 
combination of regional haze controls will ensure that emissions from 
sources in North Dakota do not interfere with other states' visibility 
programs as required by section 110(a)(2)(D)(i)(II) of the CAA.

VIII. Proposed Actions

A. Regional Haze

    We are proposing to partially approve and partially disapprove 
North Dakota's Regional Haze SIP revision that was submitted on March 
3, 2010, SIP Supplement No. 1 that was submitted on July 27, 2010, and 
part of SIP Amendment No. 1 that was submitted on July 28, 2011. 
Specifically, we are proposing to disapprove the following:
    [cir] North Dakota's NOX BART determinations and 
emissions limits for Milton R. Young Station Units 1 and 2, Leland Olds 
Station Unit 2, and Coal Creek Station Units 1 and 2.
    [cir] North Dakota's determination under the reasonable progress 
requirements found at section 40 CFR 51.308(d)(1) that no additional 
NOX emissions controls are warranted at Units 1 and 2 of 
Basin Electric Power Cooperative's Antelope Valley Station.
    [cir] North Dakota's reasonable progress goals.
    [cir] Portions of North Dakota's long-term strategy that rely on or 
reflect other aspects of the Regional Haze SIP we are proposing to 
disapprove.
    We are proposing to approve the remaining aspects of North Dakota's 
Regional Haze SIP revision that was submitted on March 3, 2010 and SIP 
Supplement No. 1 that was submitted on July 27, 2010. We are proposing 
to approve the following parts of SIP Amendment No. 1 that the State 
submitted on July 28, 2011: (1) Amendments to Section 10.6.1.2 
pertaining to Coyote Station, and (2) amendments to Appendix A.4, the 
Permit to Construct of Coyote Station. We are not proposing action on 
the remainder of the July 28, 2011 submittal at this time.
    We are proposing the promulgation of a FIP to address the 
deficiencies in the North Dakota Regional Haze SIP that we have 
identified in this proposal.
    The proposed FIP includes the following elements:
     NOX BART determinations and emission limits for 
Milton R. Young Station Units 1 and 2 and Leland Olds Station Unit 2 of 
0.07 lb/MMBtu that apply singly to each of these units on a 30-day 
rolling average, and a requirement that the owners/operators comply 
with these NOX BART limits within five (5) years of the 
effective date of our final rule.
     NOx BART determination and emission limit for 
Coal Creek Station Units 1 and 2 of 0.12 lb/MMBtu that applies singly 
to each of these units on a 30-day rolling average, but inviting 
comment on whether 0.14 lb/MMBtu should be the limit instead, and a 
requirement that the owners/operators comply with these NOX 
BART limits within five (5) years of the effective date of our final 
rule.
     A reasonable progress determination and NOX 
emission limit for Antelope Valley Station Units 1 and 2 of 0.17 lb/
MMBtu that applies singly to each of these units on a 30-day rolling 
average, and a requirement that the owner/operator meet the limit by 
July 31, 2018.
     Monitoring, recordkeeping, and reporting requirements for 
the above seven units to ensure compliance with these emission 
limitations.
     Reasonable progress goals consistent with the SIP limits 
proposed for approval and proposed FIP limits.
     Long-term strategy elements that reflect the other aspects 
of the proposed FIP.
    In lieu of this proposed FIP, or portion thereof, we are proposing 
approval of a SIP revision if the State submits such a revision in a 
timely way, and the revision matches the terms of our proposed FIP, or 
relevant portion thereof.

B. Interstate Transport of Visibility

    We are also proposing to disapprove a portion of a SIP revision 
submitted by the State of North Dakota for the purpose of addressing 
the ``good neighbor'' provisions of the CAA section 110(a)(2)(D)(i) for 
the 1997 8-hour ozone NAAQS and the 1997 PM2.5 NAAQS. 
Specifically, we propose to disapprove the portion of the April 6, 
2009, SIP in which North Dakota intended to address the requirement of 
section 110(a)(2)(D)(i)(II) that emissions from North Dakota sources do 
not interfere with measures required in the SIP of any other state 
under part C of the CAA to protect visibility. Because of this proposed 
disapproval, we also need to propose a FIP to meet this requirement of 
section 110(a)(2)(D)(i)(II). To meet this FIP duty, we are proposing to 
find that North Dakota sources will be

[[Page 58644]]

sufficiently controlled to eliminate interference with the visibility 
programs of other states by a combination of the measures that we are 
simultaneously proposing to approve as meeting the regional haze SIP 
requirements combined with the additional measures that we are 
proposing to impose in a FIP to meet the remaining regional haze SIP 
requirements.

IX. 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 four facilities. It is 
therefore not a rule of general applicability.

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 four 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. 
The FIP that EPA is proposing for purposes of the visibility prong of 
section 110(a)(2)(D)(i)(II) consists of the combination of the proposed 
approval of the state'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 NOX emissions on specific units at 
three sources in North Dakota, and imposing controls to meet the 
reasonable progress requirement for NOX emissions at one 
additional source in North Dakota. The net result of these two 
simultaneous FIP actions is that EPA is proposing direct emission 
controls on selected units at only four sources. The sources in 
question are each large electric generating plants that 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 1 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 1 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.

[[Page 58645]]

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 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. EPA specifically solicits 
additional comment on this proposed rule from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children from Environmental 
Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to 
any rule that: (1) Is determined to be economically significant as 
defined under Executive Order 12866; and (2) concerns an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children. EPA interprets EO 13045 as 
applying only to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the EO 
has the potential to influence the regulation. This action is not 
subject to EO 13045 because it implements specific standards 
established by Congress in statutes. However, to the extent this 
proposed rule will limit emissions of NOX, the rule will 
have a beneficial effect on children's health by reducing air 
pollution.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act 
(NTTAA) of 1995 requires Federal agencies to evaluate existing 
technical standards when developing a new regulation. To comply with 
NTTAA, EPA must consider and use ``voluntary consensus standards'' 
(VCS) if available and applicable when developing programs and policies 
unless doing so would be inconsistent with applicable law or otherwise 
impractical.
    The EPA believes that VCS are inapplicable to this action. Today's 
action does not require the public to perform activities conducive to 
the use of VCS.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    We have determined that this proposed rule, if finalized, will not 
have disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it increases the 
level of environmental protection for all affected populations without 
having any disproportionately high and adverse human health or 
environmental effects on any population, including any minority or low-
income population. This proposed rule limits emissions of 
NOX from four facilities in North Dakota. The 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.

List of Subjects in 40 CFR Part 52

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

    Dated: September 1, 2011.
James B. Martin,
Regional Administrator, EPA, 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 JJ--North Dakota

    2. Section 52.1820 is amended as follows:
    a. In paragraph (c) by adding entries to the end of the table.
    b. In paragraph (d) by adding entries to the end of the table.
    c. Adding paragraphs (e)(23) through (e)(25).

[[Page 58646]]

Sec.  52.1820  Identification of plan.

* * * * *
    (c) * * *

                                        State of North Dakota Regulations
----------------------------------------------------------------------------------------------------------------
                                                          State
        State citation              Title/subject       effective     EPA  approval date        Explanations
                                                           date         and  citation
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

                                       33-15-25 Regional Haze Requirements
----------------------------------------------------------------------------------------------------------------
                                                          State
        State citation              Title/subject       effective     EPA  approval date        Explanations
                                                           date       and  citation \1\
----------------------------------------------------------------------------------------------------------------
33-15-25-01...................  Definitions..........       1/1/07  .....................  .....................
33-15-25-02...................  Best Available              1/1/07  .....................  .....................
                                 Retrofit Technology.
33-15-25-03...................  Guidelines for Best         1/1/07  .....................  .....................
                                 Available Retrofit
                                 Technology
                                 Determinations Under
                                 the Regional Haze
                                 Rule.
33-15-25-04...................  Monitoring,                 1/1/07  .....................  .....................
                                 Recordkeeping, and
                                 Reporting.
----------------------------------------------------------------------------------------------------------------
\1\ In order to determine the EPA effective date for a specific provision listed in this table, consult the
  Federal Register notice cited in this column for the particular provision.

    (d) * * *

----------------------------------------------------------------------------------------------------------------
                                                          State
        Name of source          Nature of requirement   effective     EPA  approval date        Explanations
                                                           date       and  citation \3\
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Leland Olds Station Units 1     Air Pollution Control      2/23/10  .....................  Excluding the NOX
 and 2.                          Permit to Construct                                        BART limits for Unit
                                 for Best Available                                         2 and corresponding
                                 Retrofit Technology                                        monitoring,
                                 (BART).                                                    recordkeeping, and
                                                                                            reporting
                                                                                            requirements, which
                                                                                            EPA is proposing to
                                                                                            disapprove.
Milton R. Young Station Units   Air Pollution Control      2/23/10  .....................  Excluding the NOX
 1 and 2.                        Permit to Construct                                        BART limits for
                                 for Best Available                                         Units 1 and 2 and
                                 Retrofit Technology                                        corresponding
                                 (BART).                                                    monitoring,
                                                                                            recordkeeping, and
                                                                                            reporting
                                                                                            requirements, which
                                                                                            EPA is proposing to
                                                                                            disapprove.
Coal Creek Station Units 1 and  Air Pollution Control      2/23/10  .....................  Excluding the NOX
 2.                              Permit to Construct                                        BART limits for
                                 for Best Available                                         Units 1 and 2 and
                                 Retrofit Technology                                        corresponding
                                 (BART).                                                    monitoring,
                                                                                            recordkeeping, and
                                                                                            reporting
                                                                                            requirements, which
                                                                                            EPA is proposing to
                                                                                            disapprove.
Stanton Station Unit 1........  Air Pollution Control      2/23/10  .....................  .....................
                                 Permit to Construct
                                 for Best Available
                                 Retrofit Technology
                                 (BART).
Heskett Station Unit 2........  Air Pollution Control      7/22/10  .....................  .....................
                                 Permit to Construct,
                                 PTC10028.
Coyote Station Unit 1.........  Air Pollution Control      3/14/11  .....................  .....................
                                 Permit to Construct,
                                 PTC10008.
----------------------------------------------------------------------------------------------------------------
\3\ In order to determine the EPA effective date for a specific provision listed in this table, consult the
  Federal Register notice cited in this column for the particular provision.

    (e) * * *

[[Page 58647]]

----------------------------------------------------------------------------------------------------------------
                                      Applicable
    Name of nonregulatory SIP     geographic or non-    State submittal    EPA approval date     Explanations
            provision               attainment area    date/adopted date    and citation 3
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
(23) North Dakota State           Statewide.........  Submitted: 3/3/10.  ..................  Excluding
 Implementation Plan for                                                                       [provisions we
 Regional Haze.                                                                                are disapproving
                                                                                               and anything
                                                                                               superseded].
 (24) North Dakota State          Statewide.........  Submitted: 7/27/10  ..................  Excluding
 Implementation Plan for                                                                       [provisions we
 Regional Haze Supplement No. 1.                                                               are disapproving
                                                                                               and anything
                                                                                               superseded].
 (25) North Dakota State          Statewide.........  Submitted: 7/28/11  ..................  Excluding
 Implementation Plan for                                                                       [provisions we
 Regional Haze Amendment No. 1.                                                                are not acting
                                                                                               on].
----------------------------------------------------------------------------------------------------------------
\3\ In order to determine the EPA effective date for a specific provision listed in this table, consult the
  Federal Register notice cited in this column for the particular provision.

    3. New Sec.  52.1825 is added to read as follows:

Sec.  52.1825  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 North Dakota: Milton R. Young Station, Units 1 and 2; Leland 
Olds Station, Unit 2; Coal Creek Station, Units 1 and 2; Antelope 
Valley Station, Units 1 and 2.
    (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 NOX emissions, other pollutant emissions, diluent, 
or stack gas volumetric flow rate.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises an EGU identified in paragraph (a) of this section.
    Unit means any of the EGUs identified in paragraph (a) of this 
section.
    (c) Emissions limitations--(1) The owners/operators subject to this 
section shall not emit or cause to be emitted NOX in excess 
of the following limitations, in pounds per million British thermal 
units (lb/MMBtu), averaged over a rolling 30-day period:

------------------------------------------------------------------------
                                                           NOX Emission
                       Source name                          limit (lb/
                                                              MMBtu)
------------------------------------------------------------------------
Milton R. Young Station, Unit 1.........................            0.07
Milton R. Young Station, Unit 2.........................            0.07
Leland Olds Station Unit 2..............................            0.07
Coal Creek Station, Unit 1..............................            0.12
Coal Creek Station, Unit 2..............................            0.12
Antelope Valley Station, Unit 1.........................            0.17
Antelope Valley Station, Unit 2.........................            0.17
------------------------------------------------------------------------

    (2) These emission limitations shall apply at all times, including 
startups, shutdowns, emergencies, and malfunctions.
    (d) Compliance date. The owners and operators subject to this 
section shall comply with the emissions limitations and other 
requirements of this section by March 11, 2017 unless otherwise 
indicated in specific paragraphs.
    (e) Compliance determination--(1) CEMS. 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 NOX, diluent, and stack gas volumetric 
flow rate from each unit. The CEMS shall be used to determine 
compliance with the emission limitations in paragraph (c) of this 
section for each unit.
    (2) Method. (i) For any hour in which fuel is combusted in a unit, 
the owner/operator of each unit shall calculate the hourly average 
NOX concentration in lb/MMBtu at the CEMS in accordance with 
the requirements of 40 CFR part 75. At the end of each boiler operating 
day, the owner/operator shall calculate and record a new 30-day rolling 
average emission rate in lb/MMBtu from the arithmetic average of all 
valid hourly emission rates from the CEMS for the current boiler 
operating day and the previous 29 successive boiler operating days.
    (ii) An hourly average NOX emission rate in lb/MMBtu is 
valid only if the minimum number of data points, as specified in 40 CFR 
part 75, is acquired by both the NOX pollutant concentration 
monitor and the diluent monitor (O2 or CO2).
    (iii) Data reported to meet the requirements of this section shall 
not include data substituted using the missing data substitution 
procedures of subpart D of 40 CFR part 75, nor shall the data have been 
bias adjusted according to the procedures of 40 CFR part 75.
    (f) Recordkeeping. 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.
    (g) Reporting. All reports under this section 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 shall submit quarterly excess emissions reports 
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),

[[Page 58648]]

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 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, any CEMS repairs or adjustments, and results of any 
CEMS performance tests required by 40 CFR part 75 (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 report.
    (h) Notifications. (1) Owner/operator shall submit notification of 
commencement of construction of any equipment which is being 
constructed to comply with the NOX 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.
    (i) 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.
    (j) 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.

[FR Doc. 2011-23372 Filed 9-20-11; 8:45 am]
BILLING CODE 6560-50-P