58570 Federal Register / Vol. 76, No. 183 / Wednesday, September 21, 2011 / Proposed Rules 

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. 

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: 


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(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 


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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 


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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 longterm 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. 


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1 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

2Areas designated as mandatory Class I Federal 

areas consist of national parks exceeding 6000 

acres, wilderness areas and national memorial parks 

exceeding 5000 acres, and all international parks 

that were in existence on August 7, 1977. 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 

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. 

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 


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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.’’ 

3EPA’s regional haze regulations require 

subsequent updates to the regional haze SIPs. 40 

CFR 51.308(g)–(i). 

results from manmade air pollution.’’ 

CAA § 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. 

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). 

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 § 110(c)(1). 

B. Roles of Agencies in Addressing 

Regional Haze 

Successful implementation of the 

regional haze program will require longterm regional coordination among 

states, tribal governments and various 

federal agencies. 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 


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4The preamble to the Regional Haze Rule 

provides additional details about the deciview. 64 

FR 35714, 35725 (July 1, 1999). 

5 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, 

September 2003, EPA–454/B–03–005, available at 

http://www.epa.gov/ttncaaa1/t1/memoranda/ 

Regional Haze _envcurhr_gd.pdf, (hereinafter 

referred to as ‘‘our 2003 Natural Visibility 

Guidance’’); and Guidance for Tracking Progress 

Under the Regional Haze Rule, (September 2003, 

EPA–454/B–03–004, available at http:// 

www.epa.gov/ttncaaa1/t1/memoranda/ 

rh_tpurhr_gd.pdf, (hereinafter referred to as our 

‘‘2003 Tracking Progress Guidance’’). 

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

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

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 


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6The ‘‘major stationary sources’’ potentially 

subject to BART are listed in CAA section 

169A(g)(7). 

7BART-eligible sources are those sources that 

have the potential to emit 250 tons or more of a 

visibility-impairing air pollutant, were not in 

operation prior to August 7, 1962, but were in 

existence on August 7, 1977, and whose operations 

fall within one or more of 26 specifically listed 

source categories. 40 CFR 51.301. 

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 ‘‘BARTeligible’’ sources that may be 

anticipated to cause or contribute to any 

visibility impairment in a Class I area. 

Rather than requiring source-specific 

BART controls, states also have the 

flexibility to adopt an emissions trading 

program or other alternative program as 

long as the alternative provides greater 

reasonable progress towards improving 

visibility than BART. 

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. 

States must address all visibilityimpairing pollutants emitted by a source 

in the BART determination process. The 

most significant visibility-impairing 

pollutants are SO2, NOX, and PM. 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’ 


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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 ‘‘subjectto-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 longterm 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 


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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. 


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8The 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. 

9The 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. 

10The 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). 

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

North Dakota class I area 

20% Worst days 20% Best days 

2000–2004 

Baseline 

(dv) 

2018 URP 

Goal 

(dv) 

2018 Reduction needed 

(delta dv) 

2064 Natural 

conditions 

(dv) 

2000–2004 

Baseline 

(dv) 

2064 Natural 

conditions 

(dv) 

Theodore Roosevelt National Park ...................... 17.80 15.47 2.33 7.8 7.76 3.04 

Lostwood National Wildlife Refuge Wilderness 

Area .................................................................. 19.57 16.89 2.68 8.0 8.19 2.92 

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. 

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. 

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. 

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 


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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 


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11Note that our reference to CALPUFF 

encompasses the entire CALPUFF modeling system, 

which includes the CALMET, CALPUFF, and 

CALPOST models and other pre and post 

processors. The different versions of CALPUFF 

have corresponding versions of CALMET, 

CALPOST, etc. which may not be compatible with 

previous versions (e.g., the output from a newer 

version of CALMET may not be compatible with an 

older version of CALPUFF). The different versions 

of the CALPUFF modeling system are available 

from the model developer at http://www.src.com/ 

verio/download/download.htm. 

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-eligible source Location BART Source category 

(SC) 

Nearest class I 

area 

1. American Crystal Sugar Company 

(Main Boiler and Lime Kiln).

Drayton, northeastern ........

North Dakota .....................

SC 22—fossil fuel boilers >250 MMBtu/ 

hr heat input and SC 12—lime plants.

LWA 400 km. 

2. Basin Electric Power Cooperative, Leland Olds Station (Unit 1 and Unit 2).Stanton, central .................

North Dakota .....................

SC 1—fossil fuel steam electric plants 

>250 MMBtu/hr heat input.

TRNP 150 km. 

3. Great River Energy, Coal Creek Station 

(Unit 1 and Unit 2).

Falkirk, central ...................

North Dakota .....................

SC 1—fossil fuel steam electric plants 

>250 MMBtu/hr heat input.

TRNP 160 km. 

4. Great River Energy, Stanton Station 

(Unit 1).

Stanton, central .................

North Dakota .....................

SC 1—fossil fuel steam electric plants 

>250 MMBtu/hr heat input.

TRNP 150 km. 

5. Minnkota Power Cooperative, Milton R. 

Young Station (Unit 1 and Unit 2).

Center, central ...................

North Dakota .....................

SC 1—fossil fuel steam electric plants 

>250 MMBtu/hr heat input.

TRNP 150 km. 

6. Montana Dakota Utilities Resources 

Group, Inc. R.M. Heskett Station (Unit 

2).

Mandan, central .................

North Dakota .....................

SC 1—fossil fuel steam electric plants 

>250 MMBtu/hr heat input.

TRNP 180 km. 

7. Tesoro Petroleum Corporation, Mandan 

Refinerry Carbon Monoxide Furnace.

Mandan, central .................

North Dakota .....................

SC 11—petroleum refineries ................... TRNP 180 km. 

2. Identification of Sources Subject to 

BART 

The second step of the BART 

evaluation is to identify those BARTeligible sources that may reasonably be 

anticipated to cause or contribute to any 

visibility impairment at any Class I area, 

i.e. those sources that are subject to 

BART. The BART Guidelines allow 

states to consider exempting some 

BART-eligible sources from further 

BART review because they may not 

reasonably be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. Consistent with the 

BART Guidelines, 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). 

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 


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12See our BART Guidelines, Section III.A.3. 13The 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. 

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 BARTeligible 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. 

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 toBART. 

TABLE 4—INDIVIDUAL BART-ELIGIBLE SOURCE VISIBILITY IMPACTS ON NORTH DAKOTA CLASS I AREAS

Source and unit Class I Area 

Maximum 24- 

hour 98th percentile visibility 

impact (dv) 

Subject to BART or 

exempt 

1. American Crystal Sugar Company (Main Boiler and Lime Kiln) ..................................... LWA 0.04 Exempt. 

TRNP 0.04 

2. Great River Energy, Coal Creek Station (Unit 1 and Unit 2) .......................................... LWA 4.04 Subject to BART. 

TRNP 4.48 

3. Great River Energy, Stanton Station (Unit 1) .................................................................. LWA 1.35 Subject to BART. 

TRNP 1.68 

4. Minnkota Power Cooperative, Milton R. Young Station (Unit 1 and Unit 2) ................... LWA 4.88 Subject to BART. 

TRNP 6.69 

5. Basin Electric Power Cooperative, Leland Olds Station (Unit 1 and Unit 2) .................. LWA 5.42 Subject to BART. 

TRNP 6.22 

6. Montana Dakota Utilities Resources Group, Inc. R.M. Heskett Station (Unit 2) ............. LWA 0.23 Exempt.13

TRNP 0.28 

7. Tesoro Petroleum Corporation, Mandan Refinery Carbon Monoxide Furnace ............... LWA 0.04 Exempt. 

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 fossilfuel-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 


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14North 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. 

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 BARTeligible 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

The State identified the following SO2

control options as having potential 

application to the Coal Creek Station 

boilers: coal cleaning/washing, K-Fuel®, 

TurboSorp®, 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® 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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 1 2

Visibility 

improvement 

(delta dv) 

Fewer Days > 

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 ........................ ........................

1The 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. 2Great 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. 3While 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) 


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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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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 frontwall-fired configuration and is 

permitted to burn both lignite and subbituminous 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 


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15North 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. 

16Appendix 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. 

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®, coal cleaning, Pahlman 

ProcessTM, and K-Fuel®. The State 

eliminated the following options as 

technically infeasible: coal cleaning, 

K-Fuel®, Powerspan ECO®, 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. 

TABLE 7—SUMMARY OF STANTON SO2 BART ANALYSIS FOR UNIT 1 BOILER WITH LIGNITE COAL

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 1 2

Visibility 

benefit 

(delta dv) 

Fewer days > 

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 

1The 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. 2Visibility 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 


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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. 

TABLE 8—SUMMARY OF STANTON SO2 BART ANALYSIS FOR UNIT 1 BOILER WITH POWDER RIVER BASIN COAL

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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), nonselective 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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility Imacts1 2

Visibility 

benefit 

(delta dv) 

Fewer days > 

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 

1The 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. 2Great 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. 


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58588 Federal Register / Vol. 76, No. 183 / Wednesday, September 21, 2011 / Proposed Rules 

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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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

Control option 

Control 

efficiency 

(%) 

Emission 

rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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 


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17A 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. 

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. 

TABLE 12—SUMMARY OF MILTON R. YOUNG STATION SO2 BART ANALYSIS FOR UNIT 1 BOILER

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 1 2

Visibility benefit 

(delta dv) 

Fewer days 0.5 

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 

1The 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. 2Visibility 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 


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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 fivefactor 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

Control option Control 

efficiency (%) 

Emission rate 

(lb/MMBtu) 

Emissions reduction (tons/yr) Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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 bypassed 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. 


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TABLE 14—SUMMARY OF MILTON R. YOUNG STATION SO2 BART ANALYSIS FOR UNIT 2 BOILER

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts1 2

Visibility 

benefit 

(delta dv) 

Fewer days > 

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 

1The 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. 2Visibility 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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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, drybottom, 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 turbineVerDate Mar<15>2010 18:15 Sep 20, 2011 Jkt 223001 PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 E:\FR\FM\21SEP2.SGM 21SEP2

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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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost effectiveness 

($/ton) 

Visibility impacts1 2

Visibility 

benefit 

(delta dv) 

Fewer days > 

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 

1The 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. 2Basin 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 lowdust 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. 


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TABLE 17—SUMMARY OF LELAND OLDS STATION NOX BART ANALYSIS FOR UNIT 1 BOILER

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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 


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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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts1 2

Visibility 

benefit 

(delta dv) 

Fewer days 

> 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 ........................ ........................

1The 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. 2Basin 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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/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. 


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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

Source and unit 

2000–2004 

average 

emissions 

(tons/yr) 

Baseline 

level of 

control 

(% reduction) 

BART level 

of control 

(% reduction) 1

Control device 

Emissions 

after 

controls 

(tons/yr) 

Emission 

reduction 

(tons/yr) 2

Emission limit 

Basin Electric Power 

Cooperative, LOS 

Unit 1.

16,666 0 95 New Wet Scrubber ... 1,376 15,290 95% reduction or 

0.15 lb/MMBtu, 30- 

day rolling average. 

Basin Electric Power 

Cooperative, Leland Olds Station 

Unit 2.

30,828 0 95 New Wet Scrubber ... 2,530 28,298 95% reduction or 

0.15 lb/MMBtu, 30- 

day rolling average. 

Great River Energy, 

Coal Creek Station 

Unit 1.

14,086 68 95 Modified Existing Wet 

Scrubber and Coal 

Dryer.

3,781 10,305 95% reduction or 

0.15 lb/MMBtu, 30- 

day rolling average. 

Great River Energy, 

Coal Creek Station 

Unit 2.

12,407 68 95 Modified Existing Wet 

Scrubber and Coal 

Dryer.

3,621 8,786 95% reduction or 

0.15 lb/MMBtu, 30- 

day rolling average. 

Great River Energy, 

Stanton Station 

Unit 1.

8,312 0 90 New Spray dryer and 

Fabric Filter.

1,179 7,133 90% reduction or 

0.24 lb/MMBtu (lignite), or 0.16 lb/ 

MMBtu (PRB) 30- 

day rolling average. 

Minnkota Power Cooperative, MRYS 

Unit 1.

20,148 0 95 New Wet Scrubber ... 1,007 19,141 95% reduction, 30- 

day rolling average. 

Minnkota Power Cooperative, MRYS 

Unit 2.

12,404 65 95 Modified Existing Wet 

Scrubber.

2,739 9,665 95% reduction, or 

0.15 lb/MMBtu, 30- 

day rolling average. 

Also, 90% reduction. 

1Based on two-year baseline emission rate for BART. 

2Based on the average 2000–2004 operating rate. 


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18See 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. 

19We are proposing to approve the State’s 

regional haze regulations as part of this action. 

TABLE 22—NORTH DAKOTA BART DETERMINATIONS FOR NOX EMISSIONS THAT EPA IS PROPOSING TO APPROVE

Source and unit 

2000–2004 

average 

emissions 

(tons/yr) 

Baseline 

level 

of control 

(% reduction) 

BART level 

of control 

(% reduction) 1

Control device 

Emissions 

after controls 

(tons/yr) 

Emission 

reduction 

(tons/yr) 2

Emission limit 

Stanton Unit 1 ........... 2,048 0 45 LNB, Overfire Air and 

SNCR.

1,425 623 0.29 lb/106 Btu, 30- 

day 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. 

1Based on two-year baseline emission rate for BART. 

2Based 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

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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 1 2

Visibility 

benefit (delta 

dv) 

Fewer days 

> 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 ........................ ........................

1The 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 


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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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 1 2

Visibility 

benefit 

(delta dv) 

Fewer 

days > 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 ........................ ........................

1The 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 


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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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized 

cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 1 2

Visibility 

benefit 

(delta dv) 

Fewer days 

> 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 

1The 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. 2The 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 

Source and unit 

2000–2004 

average 

emissions 

(tons/yr) 

Baseline 

level of 

control 

(% reduction) 

BART level 

of control 

(% reduction) 

Control device 

Emissions 

after 

controls 

(tons/yr) 

Emission 

reduction 

(tons/yr) 

Emission limit 

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. 


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20The 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. 

21U.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 CostEffectiveness 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.’’ 

23The 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. 

24Burns & 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). 

25For a detailed discussion, the reader should 

refer to our consultants’ reports in the Technical 

Support Document. 

26SIP 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. 

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 facilityprovided 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

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

TABLE 27—CONTRAST OF TESCR COST EFFECTIVENESS

Plant 

North Dakota 

projected cost 

($/ton NOX

removed) 

EPA’s projected 

cost 

($/ton NOX

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. 

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, 


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27Although, 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%. 

28Preproduction 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). 

29See Control Cost Manual, 2002, Chapter 2, 

Section 2.3.1. 

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

Indirect cost 

Control cost 

manual 

(% of direct cap 

cost ‘‘A’’) 

B&McD analysis 

(% of direct cap 

cost ‘‘A’’) 

General Facilities (Construction Mgt) .............................................................................................................. 0.05 × A 0.04 × A 

Engineering & Home Office Fees .................................................................................................................... 0.10 × A 0.15 × A 

Startup Expenses ............................................................................................................................................ 0 0.02 × A 

Process Contingency (Scope Contingency) .................................................................................................... 0.05 × A 0.15 × A 

Project Contingency (Pricing Contingency) ..................................................................................................... 0.18 × A 0.15 × A 

Totals ........................................................................................................................................................ 0.38 × A 0.51 × 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

TABLE 29—COMPARISON OF EPA CONTROL COST MANUAL & B&MCD ‘‘OTHER’’ CAPITAL COSTS

Other costs 

Control cost 

manual 

(% of direct cap 

cost ‘‘A’’) 

B&McD analysis 

(% of direct cap 

cost ‘‘A’’) 

Cost Escalation ................................................................................................................................................ 0 0.30 × A 

Allowance for Funds During Construction (Interest During Construction) ...................................................... 0 0.20 × A 

Preproduction Costs ........................................................................................................................................ 0.03 × A 0 

Owners Cost—Other (Owner Contingency) .................................................................................................... 0 0.17 × A 

Totals ........................................................................................................................................................ 0.03 × A 0.67 × 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 startup.’’ 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. 

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 


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30Report 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. 

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. 

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 tailend 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. 

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. 

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] 

Description Cost factor Dr. Fox 

(MM$/year) 

Sargent & Lundy 

(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 Above ....................... 6 .913 23.894 

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 Equipment Life 1.(A + B) × 1.193 ....................................................... .............................. 29.496 

Total Annual Capital Cost, C ............................ .................................................................................. 14 .361 14.423 


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32They 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. 

TABLE 3—COMPARISON OF SARGENT & LUNDY AND DR. FOX’S TAIL-END SCR VARIABLE OPERATION AND MAINTENANCE

COSTS FOR LELAND OLDS STATION UNIT 2—Continued 

[2009 dollars] 

Description Cost factor Dr. Fox 

(MM$/year) 

Sargent & Lundy 

(MM$/year) 

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 companysupplied 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. 

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 EPAapproved 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 singlesource 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


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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. 

35See July 15, 2011 letter from Great River Energy 

to Terry O’Clair. 

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

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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

reduction 

(tons/yr) 

Annualized cost 

(MM$) 

Cost 

effectiveness 

($/ton) 

Visibility impacts 2 3

Visibility 

benefit 

(delta dv) 

Fewer days 

> 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 

1The State and company also reviewed a less desirable Option 2 which was the same control technology with a lower control efficiency of 

21%. 2The 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. 3The 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 


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36Letter 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. 

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. 

38Control 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. 40 ICAC White Paper, May 2009. 

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. 

also affected the cost effectiveness 

values for SCR. 

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 reevaluating 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. 

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: 

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. 

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. 

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 


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42The 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. 

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. 

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 highdust 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. 


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TABLE 32—SUMMARY OF EPA NOX BART ANALYSIS CONTROL TECHNOLOGIES FOR MILTON R. YOUNG STATION UNIT 1 

BOILER

Control option Control efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

(tons/yr) 

Emissions 

reduction 

(tons/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 (2009$) ............................................................................................................ A + B 8,284,000 

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 × TCI ............................................... 60,108 

Reagent ..................................................................................................................... .................................................................. 949,747 

Electricity ................................................................................................................... .................................................................. 21,529 

Water ......................................................................................................................... .................................................................. 958 

Increased Coal .......................................................................................................... .................................................................. 36,845 

Increased Ash ............................................................................................................ .................................................................. 2,639 

Total Direct Annual Cost (TDAC) ....................................................................... Sum of Various Items Listed Above ....... 1,071,827 

Indirect Annual Cost 1 (IDAC) .................................................................................... CRF × TCI ............................................... 378,253 

Total Annual Cost SNCR (TACS) ...................................................................... TDAC + IDAC .......................................... 1,450,081 

Total Annual Cost ASOFA (TACA) .................................................................... North Dakota Appendix B.4 .................... 2,520,719 

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

Control option 

Total installed 

capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Emissions 

reductions 

(tons/yr) 

Average cost 

effectiveness 

($/ton) 

SNCR + ASOFA ............................................................................................ 8.284 3.971 5,777 687 


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44As discussed in section V.D., above, the Control 

Cost Manual does not provide for ‘‘levelization’’ of 

annual costs. 

45Minnkota 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. 

46See, 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. 

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 

Continued 

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 & McDonnellestimated 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

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. 

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 hotside (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

• 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


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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. 

49Minnkota 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.’’) 

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. 

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

Description Control cost manual factor or calculation Cost 

(MM$) 

Total Direct Capital Costs, A ..................................................................................... .................................................................. 86.32 

Indirect Installation Costs 

General Facilities ................................................................................................ 0.05 × A ................................................... 4.32 

Engineering and Home Office Fees ................................................................... 0.10 × A ................................................... 8.63 

Process Contingencies ....................................................................................... 0.05 × A ................................................... 4.32 

Total Indirect Installation Costs, B ............................................................................ 0.20 × A ................................................... 17.26 

Project Contingency, C ...................................................................................... 0.15 × (A + B) .......................................... 15.54 

Total Plant Cost, D .................................................................................................... A + B + C ................................................ 119.12 

Preproduction Cost, G ........................................................................................ 0.02 × D ................................................... 2.41 

Inventory Capital (Reagent), H .......................................................................... .................................................................. 0.087 

Natural Gas Pipeline .......................................................................................... .................................................................. 1.50 

Total Capital Investment, TCI = D + G + H ....................................................... .................................................................. 123.13 

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 × TCI ............................................... 1.809 

Reagent ..................................................................................................................... .................................................................. 2.716 

Catalyst ...................................................................................................................... .................................................................. 0.250 

Electricity ................................................................................................................... .................................................................. 2.711 

Natural Gas for Flue Gas Reheating and Urea to Ammonia Conversion ................ .................................................................. 3.756 

Total Direct Annual Cost (TDAC) ....................................................................... Sum of Various Items Listed Above ....... 11.281 

Indirect Annual Cost 3 (IDAC) ............................................................................. CRF × TCI ............................................... 10.735 

Annual ASOFA Cost (AAC) ............................................................................... .................................................................. 2.161 

Total Annual Cost (TAC) .................................................................................... TDAC + IDAC + AAC .............................. 24.176 

1See 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). 


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TABLE 38—SUMMARY OF EPA NOX BART COSTS FOR VARIOUS TESCR SCENARIOS ON MILTON R. YOUNG STATION

UNIT 1 BOILER

Scenario Description 

Emissions 

reductions 1

(tons/year) 

Total annual 

cost 

($MM) 

Average cost 

effectiveness 

($/ton) 

1 ................................................................... 1 layer replaced every year ........................ 9,418 25.53 2,711 

2 ................................................................... 1 layer replaced every 2 years ................... 9,414 24.73 2,627 

3 ................................................................... 1 layer replaced every 3 years ................... 9,410 24.18 2,569 

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 singlesource 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

Control option 

Total installed 

capital cost 

(MM$) 

Total annual cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts 124

Visibility 

improvement 

(delta 

deciviews) 

Fewer days > 

0.5 dv 

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. 3This installed capital cost estimate does not include the capital cost of ASOFA. The total annualized cost does include the capital cost of 

ASOFA. 4The 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 


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58610 Federal Register / Vol. 76, No. 183 / Wednesday, September 21, 2011 / Proposed Rules 

50As 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. 

of 9,032 tons per year used by North 

Dakota and determined that the highend 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. 

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

Control option Control efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

(tons/yr) 

Emissions 

reduction 

(tons/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 (2009$) ..................................................................................................... A + B 17,445,806 


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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 × 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 (TDAC) ....................................................................... Sum of Various Items Listed Above ....... 1,992,847 

Indirect Annual Cost 1 (IDAC) .................................................................................... CRF × TCI ............................................... 702,076 

Total Annual Cost SNCR (TACS) ...................................................................... TDAC + IDAC .......................................... 2,694,923 

Total Annual Cost ASOFA (TACA) .................................................................... North Dakota Appendix B.4 .................... 3,749,684 

Total Annual Cost SNCR + ASOFA ................................................................... TACS + TACA ......................................... 6,444,608 

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

Control option 

Total installed 

capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Emissions 

reductions 

(tons/yr) 

Average 

cost 

effectiveness 

($/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

Description 

Control cost manual 

factor or 

calculation 

Cost 

(MM$) 

Total Direct Capital Costs, A ..................................................................................... .................................................................. 151.97 

Indirect Installation Costs .................................................................. ............................

General Facilities ................................................................................................ 0.05 × A ................................................... 7.60 

Engineering and Home Office Fees ................................................................... 0.10 × A ................................................... 15.20 

Process Contingencies ....................................................................................... 0.05 × A ................................................... 7.60 

Total Indirect Installation Costs, B ............................................................................ 0.20 × A ................................................... 30.39 

Project Contingency, C .............................................................................................. 0.15 × (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 = D + G + H ....................................................... .................................................................. 216.87 

1See Table 46 for an explanation of Scenarios. 


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58612 Federal Register / Vol. 76, No. 183 / Wednesday, September 21, 2011 / Proposed Rules 

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 × TCI ............................................... 3.25 

Reagent ..................................................................................................................... .................................................................. 0.396 

Catalyst ...................................................................................................................... .................................................................. 0.425 

Electricity ................................................................................................................... .................................................................. 3.96 

Natural Gas for Flue Gas Reheating and Urea to Ammonia Conversion ................ .................................................................. 6.00 

Total Direct Annual Cost (TDAC) ....................................................................... Sum of Various Items Listed Above ....... 17.82 

Indirect Annual Cost 3 (IDAC) .................................................................................... CRF × TCI ............................................... 18.91 

Annual ASOFA Cost (AAC) ....................................................................................... .................................................................. 3.84 

Total Annual Cost (TAC) .................................................................................... TDAC + IDAC + AAC .............................. 40.57 

1See 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

Scenario Description 

Emissions 

reductions 1

(tons/year) 

Total annual 

cost 

($MM) 

Average cost 

effectiveness 

($/ton) 

1 ................................................................ 1 layer replaced every year ..................... 14,825 43.63 2,943 

2 ................................................................ 1 layer replaced every 2 years ................ 14,816 41.89 2,827 

3 ................................................................ 1 layer replaced every 3 years ................ 14,807 40.57 2,740 

4 ................................................................ ASOFA downtime allowed ....................... 14,829 42.89 2,892 

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 singlesource 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

Control option 

Total installed 

capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts 124

Visibility 

improvement 

(delta 

deciviews) 

Fewer 

days > 0.5 

dv 

TESCR + ASOFA (Scenario 3) ......... 3 216 .9 40.57 2,740 5,695 3.945 110 


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Federal Register / Vol. 76, No. 183 / Wednesday, September 21, 2011 / Proposed Rules 58613 

51As discussed in the BART Guidelines, section 

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

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

TABLE 47—SUMMARY OF EPA NOX BART ANALYSIS COMPARISON OF TESCR AND SNCR OPTIONS FOR MILTON R. 

YOUNG STATION UNIT 2 BOILER—Continued 

Control option 

Total installed 

capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts 124

Visibility 

improvement 

(delta 

deciviews) 

Fewer 

days > 0.5 

dv 

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. 3This installed capital cost estimate does not include the capital cost of ASOFA. The total annualized cost does include the capital cost of 

ASOFA. 4The 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 highend 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. 

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 


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52We 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). 

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

Control option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

(tons/yr) 

Emissions 

reduction 

(tons/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 ............................

1We 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. 

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 reestimate 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 (2009$) ............................................................... A + B ....................................................... 19,240,000 

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 × 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 (TDAC) ....................................................................... Sum of Various Items Listed Above ....... 2,958,090 

Indirect Annual Cost 1 (IDAC) .................................................................................... CRF × TCI ............................................... 736,265 

Total Annual Cost SNCR (TACS) ...................................................................... TDAC + IDAC .......................................... 3,694,355 

Total Annual Cost ASOFA2 (TACA) .................................................................. .................................................................. 1,256,855 

Total Annual Cost SNCR + ASOFA ................................................................... TACS + TACA ......................................... 4,951,210 

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/. 


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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. 

56Contrary 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. 

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

Control option 

Total installed 

capital cost 

(MM$) 

Total 

annualized 

cost 

(MM$) 

Emissions 

reductions 

(tons/yr) 

Average cost 

effectiveness 

($/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. 

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

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 


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57Cost Manual, pdf 489–490, Eqn. 2.52: FWF = 

0.07[1/(1.073¥1)] = 0.31. Y = 24,000 hr/ 

(8760)(0.865) = 3.2, rounds to 3. 

58Letter 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/m3 to $6,000/m3); 

e-mail from Flemming Hansen, Manager SCR 

DeNOx Catalyst, Haldor T<psoe, to Phyllis Fox, 

P.E., Re: Catalyst Cost, January 23, 2008 ($6,000/ 

m3). 

59 5/27/09 S&L Cost Analysis, p. 7. 

60See, e.g., Sargent & Lundy spreadsheet: lowhigh dust scr-leland old2—Sens2-cat life_05109.xls, 

cell E25 (440x1.20). 

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

62Hartenstein Report, April 2010, p. 36. 

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

64Black & 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. 65Sargent & 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. 

66 1/8/10 EPA Comments, Enclosure 1, p. 25. 

67See, e.g., Hartenstein Report, April 2010, pp. 

34–35, 40–43. 

68Hartenstein Report, April 2010, p. 40. 

69McIlvaine, 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. 

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

Unit Catalyst Cost 

We have assumed a cost of $7,500 per 

cubic meter of catalyst ($/m3), which is 

the same cost assumed in Sargent & 

Lundy’s analysis. This is very high 

compared to values typically quoted by 

vendors, $4,500/m3¥$6,500/m3, 

depending upon volume per order.58

While we find that $7,500/m3 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. 

Catalyst Volume 

Sargent & Lundy assumed a catalyst 

volume of 530 m3 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 m3 by 20%.60 The source of the 

starting point (440 m3) and the 20% 

adjustment are not disclosed. 

As we commented on the draft 

Regional Haze SIP, the value of 530 m3

is high for a TESCR. Typically, cyclone 

fired units require about 1.5 m3 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 m3 for Leland Olds 

Station Unit 2. However, we used the 

unadjusted catalyst volume of 440 m3

from Sargent & Lundy’s spreadsheets as 

a highly conservative upper bound. 

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. 

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

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. 

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. 

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 


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70Burns & 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. 71EIA, Natural Gas Monthly:http:// 

www.eia.doe.gov/oil_gas/natural_gas/ 

data_publications/natural_gas_monthly/ngm.html. 

72http://tonto.eia.gov/dnav/ng/hist/ 

rngwhhda.htm. 

73http://www.eia.doe.gov/analysis/ and http:// 

www.eia.gov/emeu/steo/pub/contents.html. 74Burns & 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. 

75Burns & 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. 

76 70 FR 39167 (July 6, 2005). 

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

= 0.865. 

78North Dakota’s BART Determination for Leland 

Olds Station Units 1 and 2, SIP Appendix B.1, p. 

24. 

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. 

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. 

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. 

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. 

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. 

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. 

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, A ..................................................................... .................................................................. 11,440,000 

Capital Investment (2010$) SCR, B .......................................................................... .................................................................. 164,121,000 

Total Capital Investment, TCI (2010$) ...................................................................... A + B ....................................................... 175,561,000 

Total Capital Investment, TCI (2009$) ...................................................................... TCI(2010) × CEPCI(521.9/556.2) ............ 164,734,423 


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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 .................................................................................................. .015×TCI .................................................. 823,564 

Reagent ..................................................................................................................... .................................................................. 2,115,190 

Catalyst ...................................................................................................................... .................................................................. 320,796 

Electricity ................................................................................................................... .................................................................. 1,878,814 

Natural Gas for Flue Gas Reheating and Urea to Ammonia Conversion ................ .................................................................. 2,595,446 

Total Direct Annual Cost (TDAC). ...................................................................... .................................................................. 7,733,810 

Indirect Annual Cost 3 (IDAC) ............................................................................. CRF × TCI ............................................... 14,356,473 

Total Annual Cost (TAC) .................................................................................... TDAC + IDAC .......................................... 22,090,283 

1See 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

Scenario Description 

Emissions 

reductions 

(tons/year) 

Total annualized 

cost 

($MM) 

Average cost 

effectiveness 

($/ton) 

1 ........................ 1 layer replaced every year .............................................................. 12,050 24.31 1,892 

2 ........................ 1 layer replaced every 2 years ......................................................... 12,050 23.74 1,848 

3 ........................ 1 layer replaced every 3 years ......................................................... 12,050 23.55 1,833 

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. 


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79As discussed in the BART Guidelines, section 

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

of the CAA, emissions limits such as BART are 

required to be met on a continuous basis. 

TABLE 55—SUMMARY OF EPA NOX BART ANALYSIS COMPARISON OF TESCR AND SNCR OPTIONS FOR LELAND OLDS

STATION UNIT 2 BOILER

Control option 

Total installed 

capital cost 

(MM$) 

Total 

annualized 

cost 

(MM$) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts 1, 2

Visibility 

improvement 

(delta 

deciviews) 

Fewer days > 

0.5 

dv 

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 

1The 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. 2The 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 highend 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. 

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 lowNOX 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. 


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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 option 

Control 

efficiency 

(%) 

Emission rate 

(lb/MMBtu) 

Emissions 

(tons/yr) 

Emissions 

reduction 

(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 5,2941 ........................

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 (2009$) ........................................................... A + B ...................................................................... 10,287,000 


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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 (TDAC) ............................................................ Sum of Various Items Listed Above ...................... 5,250,000 

Indirect Annual Cost 1 (IDAC) .................................................................. CRF x TCI .............................................................. 507,000 

Total Annual Cost SNCR (TACS) ........................................................... TDAC + IDAC ......................................................... 5,760,000 

Total Annual Cost ASOFA (TACA) ......................................................... North Dakota Appendix B.4 ................................... 673,000 

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

Control option 

Total installed 

capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Emissions reductions 

(tons/yr) 

Average cost 

effectiveness 

($/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 (2009$) ............................................................... A + B ....................................................... 65,154,000 

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 × 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 (TDAC) ....................................................................... Sum of Various Items Listed Above ....... 11,021,000 

Indirect Annual Cost 1 (IDAC) ............................................................................. CRF x TCI ............................................... 5,686,000 

Total Annual Cost LDSCR (TACS) .................................................................... TDAC + IDAC .......................................... 16,707,000 

Total Annual Cost ASOFA (TACA) .................................................................... North Dakota Appendix B.4 .................... 620,400 


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80 In its BART determination, the State presented 

the deciview improvement at Theodore Roosevelt, 

Northern Unit. 

TABLE 61—SUMMARY OF EPA ANNUAL COST ANALYSIS FOR LDSCR ON COAL CREEK STATION UNITS 1 AND 2 

BOILERS—Continued 

Description Cost factor Cost ($) 

Total Annual Cost LDSCR + ASOFA ................................................................. TACS + TACA ......................................... 17,328,000 

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 62—SUMMARY OF EPA COSTS FOR LDSCR ON COAL CREEK STATION UNITS 1 AND 2 BOILERS

Control option 

Total installed capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Emissions 

reductions 

(tons/yr) 

Average cost 

effectiveness 

($/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

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

Control option 

Total installed capital cost 

(MM$) 

Total annual 

cost 

(MM$) 

Emissions 

reductions 

(tons/year) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Visibility impacts1 2

Visibility 

improvement 

(delta dv) 

Fewer 

days > 

0.5 dv 

LTO + SOFA + LNB ...................... 44.32 58.21 4,821 11,608 .......................... 1.853 64 

LDSCR + SOFA + LNB1 ............... 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 

1The 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. 


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81http://www.epa.gov/airmarkt/progsregs/epaipm/index.html. 

82As 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. 

2The 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. 

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. 

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 MultiScale 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 


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83The 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. 

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 

§ 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. 

TABLE 64—NORTH DAKOTA Q/D ANALYSIS SOURCES WITH RESULTS GREATER THAN 10 

Source Owner 

SO2 + NOX

2000–2004 

Average 

(tons) 

Nearest 

class I area 

Distance to 

nearest 

class I area 

(km) 

Nearest Q/D 

(tons/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 


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84Because 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. 

TABLE 64—NORTH DAKOTA Q/D ANALYSIS SOURCES WITH RESULTS GREATER THAN 10—Continued 

Source Owner 

SO2 + NOX

2000–2004 

Average 

(tons) 

Nearest 

class I area 

Distance to 

nearest 

class I area 

(km) 

Nearest Q/D 

(tons/km) 

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 Pipeline ........................ 188 TRNP 18 10 .4 

Coyote Station ......................................... Otter Tail Power Company ..................... 27,804 TRNP 112 248 .3 

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

Source Owner Unit Type Capacity 

SO2 + NOX

2000–2004 

Average 

(tons/yr) 

Antelope Valley Station ............................ Basin Electric Power Coop. .................... 1 EGU 435 MWe 13,864 

Antelope Valley Station ............................ Basin Electric Power Coop. .................... 2 EGU 435 MWe 12,796 

Coyote Station ......................................... Otter Tail Power Co. ............................... Main Boiler EGU 450 MWe 27,804 

Great Plains Synfuels Plant ..................... Dakota Gasification Co. .......................... Boilers A, B 

and S 

Industrial 

Boilers 

763 x 106

BTU/hr 

each 

10,802 

Tioga Gas Plant ....................................... Hess Corp. .............................................. 3 Sulfur 

Recovery 

Unit (SRU) 

225 

long tons 

per day 

(LTPD) 

1,097 

Tioga Gas Plant ....................................... Hess Corp. .............................................. C1–A to F Compressor 

engines 

1920–2350 

BHp each 

1,353 

Heskett Station 84 ..................................... Montana Dakota Utilities ......................... 2 EGU 78 MWe 3,411 

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. 

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. 


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TABLE 66—CURRENT CONTROL FOR REASONABLE PROGRESS SOURCES—Continued 

Source Pollutant Control 

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—Boilers .................... SO2 .......................................................... Wet Scrubber. 

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

Source Unit Pollutant Control technology 

Control efficiency (%) 

Emissions reductions 

(tons/yr) 

Total 

annualized 

cost ($ millions) 

Cost effectiveness ($/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/reheat.

90 11,752 46.60 3,965 

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 

Controller.

25 305 0.26 852 

Ignition Timing 

Retard.

22 268 0.14 522 


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TABLE 67—CONTROL OPTION COSTS FOR REASONABLE PROGRESS SOURCES—Continued 

Source Unit Pollutant Control technology 

Control efficiency (%) 

Emissions reductions 

(tons/yr) 

Total 

annualized 

cost ($ millions) 

Cost effectiveness ($/ton) 

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 (information is per 

each boiler).

NOX ................... SNCR ................. 30 259 1.69 6,525 

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 singlesource 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

Source Pollutant Control technology 

Visibility 

improvement (dv) Cost 

effectiveness 

($/dv) TRNP LWA 

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 + SNCR ..... 0 .02 0.04 1,113,000,000 

Tioga G.P. 1920 BHp Engines 

2350 BHp Engines.

NOX ....................................... SCR ................................................ 0 2 0.05 21,200,000 

Heskett ............................................ SO2 ........................................ Limestone Injection ......................... .............. ............ 116,667,000 

NOX ....................................... SNCR Staged Combustion ............. 0 .009 0.003 158,222,000 

40,667,000 

.

1For 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. 2For 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. 


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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

North Dakota class I area 

Visibility conditions on 20% worst days 

(dv) 

Percentage of 

URP achieved Average for 20% 

worst days 

(baseline 2000– 

2004) 

2018 URP goal 

RPG 

(WRAP 

projection) 

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. 


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85The 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. 

TABLE 70—COMPARISON OF REASONABLE PROGRESS GOALS TO BASELINE CONDITIONS ON LEAST IMPAIRED DAYS FOR

NORTH DAKOTA CLASS I AREAS

North Dakota class I area 

Visibility conditions on 20% best 

days 

(dv) Achieved ‘‘no 

degradation’’ 

(Y/N) Average for 20% 

best days 

(baseline 2000– 

2004) 

RPG 

(WRAP 

projection) 

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 inState 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 nonBART 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 


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commonly used and understood dollars 

per ton values. 

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 


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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 efficiency 

(%) 

Emissions 1

(tons/yr) 

Emissions 

reduction 

(tons/yr) 

Emissions 1

(tons/yr) 

Emissions 

reduction 

(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 (MM$) 

(same for both 

units) 

Cost 

Effectiveness 

($/ton) 

Cost 

Effectiveness 

($/ton) 

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 


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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 


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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 


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TABLE 74—NORTH DAKOTA NOX EMISSION INVENTORY—2002 AND 2018—Continued 

[North Dakota statewide NOX emissions (tons/year)] 

Source category Baseline 2002 Future 2018 Net change Percent change 

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 (nonanthropogenic) 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 


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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

Class I area Pollutant species Extinction (Mm¥1) 

Species 

contribution 

to total 

extinction 

(%) 

ND sources 

contribution 

to species 

extinction (%) 1

TRNP ....................................................... Sulfate ..................................................... 17 .53 35 21 

Nitrate ...................................................... 13 .74 27 19 


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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. 

TABLE 79—ND SOURCES EXTINCTION CONTRIBUTION 2000–2004 FOR 20% WORST DAYS—Continued 

Class I area Pollutant species Extinction (Mm¥1) 

Species 

contribution 

to total 

extinction 

(%) 

ND sources 

contribution 

to species 

extinction (%) 1

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] 

Contributing area 

Class I 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. 

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 


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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 longterm strategy (the long-term strategy 

factors). These are: (a) Emission 

reductions due to ongoing air pollution 

control programs, including measures to 

address reasonably attributable visibility 

impairment; (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 longterm 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 


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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 twothirds 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 


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87Because 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. 

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 Stateenforceable 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 EPAapproved 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. 

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 longterm 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 


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provisions with the reasonably 

attributable visibility impairment longterm 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 


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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-a`-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 


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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.’’ 

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: 

‘‘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 


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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 codevelop 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: 

Æ 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. 

Æ 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. 

Æ North Dakota’s reasonable progress 

goals. 

Æ 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 


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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-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. 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 costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

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. 


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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). 


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§ 52.1820 Identification of plan. 

* * * * * 

(c) * * * 

STATE OF NORTH DAKOTA REGULATIONS

State citation Title/subject 

State 

effective 

date 

EPA 

approval date 

and 

citation

Explanations 

*******

33–15–25 REGIONAL HAZE REQUIREMENTS

State citation Title/subject 

State 

effective 

date 

EPA 

approval date 

and 

citation 1

Explanations 

33–15–25–01 ............ Definitions .................................................. 1/1/07 

33–15–25–02 ............ Best Available Retrofit Technology ........... 1/1/07 

33–15–25–03 ............ Guidelines for Best Available Retrofit 

Technology Determinations Under the 

Regional Haze Rule.

1/1/07 

33–15–25–04 ............ Monitoring, Recordkeeping, and Reporting 1/1/07 

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) * * * 

Name of source Nature of requirement 

State 

effective 

date 

EPA 

approval date 

and 

citation 3

Explanations 

*******

Leland Olds Station 

Units 1 and 2.

Air Pollution Control Permit to Construct 

for Best Available Retrofit Technology 

(BART).

2/23/10 ........................... Excluding the NOX BART limits for Unit 2 

and corresponding monitoring, recordkeeping, and reporting requirements, 

which EPA is proposing to disapprove. 

Milton R. Young Station Units 1 and 2.Air Pollution Control Permit to Construct 

for Best Available Retrofit Technology 

(BART).

2/23/10 ........................... Excluding the NOX BART limits for Units 1 

and 2 and corresponding monitoring, 

recordkeeping, and reporting requirements, which EPA is proposing to disapprove. 

Coal Creek Station 

Units 1 and 2.

Air Pollution Control Permit to Construct 

for Best Available Retrofit Technology 

(BART).

2/23/10 ........................... Excluding the NOX BART limits for Units 1 

and 2 and corresponding monitoring, 

recordkeeping, and reporting requirements, which EPA is proposing to disapprove. 

Stanton Station Unit 1 Air Pollution Control Permit to Construct 

for Best Available Retrofit Technology 

(BART).

2/23/10 ...........................

Heskett Station Unit 2 Air Pollution Control Permit to Construct, 

PTC10028.

7/22/10 ...........................

Coyote Station Unit 1 Air Pollution Control Permit to Construct, 

PTC10008.

3/14/11 ...........................

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) * * * 


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Name of nonregulatory SIP 

provision 

Applicable geographic or 

non-attainment area 

State submittal date/adopted date EPA approval date and citation 3 Explanations 

*******

(23) North Dakota State 

Implementation Plan for 

Regional Haze.

Statewide .......................... Submitted: 3/3/10 .............. ........................................... Excluding [provisions we 

are disapproving and 

anything superseded]. 

(24) North Dakota State 

Implementation Plan for 

Regional Haze Supplement No. 1.

Statewide .......................... Submitted: 7/27/10 ............ ........................................... Excluding [provisions we 

are disapproving and 

anything superseded]. 

(25) North Dakota State 

Implementation Plan for 

Regional Haze Amendment No. 1.

Statewide .......................... Submitted: 7/28/11 ............ ........................................... Excluding [provisions we 

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 § 52.1825 is added to read as 

follows: 

§ 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: 

Source name 

NOX Emission 

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 


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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 semiannual 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 


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