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

Federal RegisterSep 21, 2011

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

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

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

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

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:

(i) The words or initials

Act

CAA

mean or refer to the Clean Air Act, unless the context indicates otherwise.

(ii) The words

EPA, we,

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

mean or refer to Reasonable Progress.

(ix) The initials

mean or refer to nitrogen oxides.

(x) The initials

mean or refer to sulfur dioxide.

(xi) The initials

mean or refer to ammonia.

(xii) The initials

2.5

mean or refer to particulate matter with an aerodynamic diameter of less than 2.5 micrometers.

(xiii) The initials

mean or refer to particulate matter with an aerodynamic diameter of less than 10 micrometers.

(xiv) The initials

mean or refer to organic carbon.

(xv) The initials

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

TRNP

mean or refer to Theodore Roosevelt National Park.

(xxx) The initials

Lostwood

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 NO

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 PM

2.5

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 NO

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 NO

BART Determinations for Milton R. Young Station Units 1 and 2, Leland Olds

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 NO

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 NO

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 NO

BART Review for Coal Creek Units 1 and 2

E. Federal Implementation Plan to Address NO

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 NO

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 (NO

) 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 SO

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 SO

BART Analysis for Unit 1 Boiler with Lignite Coal

Table 8. Summary of Stanton SO

BART Analysis for Unit 1 Boiler with Powder River Basin Coal

Table 9. Summary of Stanton NO

BART Analysis for Unit 1 Boiler with Lignite Coal

Table 10. Summary of Stanton NO

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 SO

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 SO

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 SO

BART Analysis for Unit 1 Boiler

Table 17. Summary of Leland Olds Station NO

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 SO

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 SO

Emissions that EPA is Proposing to Approve

Table 22. North Dakota BART Determinations for NO

Emissions that EPA is Proposing to Approve

Table 23. Summary of Milton R. Young Station NO

BART Analysis for Unit 1 Boiler

Table 24. Summary of Milton R. Young Station NO

BART Analysis for Unit 2 Boiler

Table 25. Summary of Leland Olds Station NO

BART Analysis for Unit 2 Boiler

Table 26. North Dakota BART Determinations for NO

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 NO

BART Analysis for Unit 1 and Unit 2 Boilers

Table 32. Summary of EPA NO

BART Analysis Control Technologies for Milton R. Young Station Unit 1 Boiler

Table 33. Summary of EPA NO

BART Capital Cost Analysis for SNCR on Milton R. Young Station Unit 1 Boiler

Table 34. Summary of EPA NO

BART Annual Analysis for SNCR on Milton R. Young Station Unit 1 Boiler

Table 35. Summary of EPA NO

BART Costs for SNCR on Milton R. Young Station Unit 1 Boiler

Table 36. Summary of EPA NO

BART Capital Cost Analysis for TESCR on Milton R. Young Station Unit 1 Boiler

Table 37. Summary of EPA NO

BART Annual Costs for TESCR Scenario 3

on Milton R. Young Station Unit 1 Boiler

Table 38. Summary of EPA NO

BART Costs for Various TESCR Scenarios on Milton R. Young Station Unit 1 Boiler

Table 39. Summary of EPA NO

BART Analysis Comparison of TESCR and SNCR Options for Milton R. Young Station Unit 1 Boiler

Table 40. Summary of EPA NO

BART Analysis Control Technologies for Milton R. Young Station Unit 2 Boiler

Table 41. Summary of EPA NO

BART Capital Cost Analysis for SNCR on Milton R. Young Station Unit 2 Boiler

Table 42. Summary of EPA NO

BART Annual Analysis for SNCR on Milton R. Young Station Unit 2 Boiler

Table 43. Summary of EPA NO

BART Costs for SNCR on Milton R. Young Station Unit 2 Boiler

Table 44. Summary of EPA NO

BART Capital Cost Analysis for TESCR

Scenario 3

on Milton R. Young Station Unit 2 Boiler

Table 45. Summary of EPA NO

BART Annual Costs for TESCR Scenario 3

on Unit 2 Boiler

Table 46. Summary of EPA NO

BART Costs for Various TESCR + ASOFA Scenarios on Milton R. Young Station Unit 2 Boiler

Table 47. Summary of EPA NO

BART Analysis Comparison of TESCR and SNCR Options for Milton R. Young Station Unit 2 Boiler

Table 48. Summary of EPA NO

BART Analysis Control Technologies for Leland Olds Station Unit 2 Boiler

Table 49. Summary of EPA NO

BART Capital Cost Analysis for SNCR on Leland Olds Station Unit 2 Boiler

Table 50. Summary of EPA NO

BART Annual Costs for SNCR on Leland Olds Station Unit 2 Boiler

Table 51. Summary of EPA NO

BART Costs for SNCR on Leland Olds Station Unit 2 Boiler

Table 52. Summary of EPA NO

BART Capital Cost Analysis for TESCR Scenario 3 on Leland Olds Station Unit 2 Boiler

Table 53. Summary of Some EPA NO

BART Annual Costs for TESCR Scenario 3

on Leland Olds Station Unit 2 Boiler

Table 54. Summary of EPA NO

BART Costs for Various TESCR + ASOFA Scenarios on Leland Olds Station Unit 2 Boiler

Table 55. Summary of EPA NO

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 NO

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 NO

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 NO

Reasonable Progress Analysis Control Technologies for Units 1 and 2 Boilers

Table 72. Summary of Antelope Valley Station NO

Reasonable Progress Cost Analysis for Units 1 and 2 Boilers

Table 73. North Dakota SO

Emission Inventory—2002 and 2018

Table 74. North Dakota NO

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 PM

2.5

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 NO

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 NO

emissions controls are warranted at Units 1 and 2 of Basin Electric Power Cooperative's Antelope Valley Station.

• North Dakota's Reasonable Progress Goals (RPGs).

• Portions of North Dakota's long-term strategy that rely on or reflect other aspects of the Regional Haze SIP we are proposing to disapprove.

We are proposing to approve the remaining aspects of North Dakota's Regional Haze SIP revision that was submitted on March 3, 2010 and SIP Supplement No. 1 that was submitted on July 27, 2010. We are proposing to approve the following parts of SIP Amendment No. 1 that the State submitted on July 28, 2011: (1) Amendments to Section 10.6.1.2 pertaining to Coyote Station, and (2) amendments to Appendix A.4, the Permit to Construct of Coyote Station. We are not proposing action on the remainder of the July 28, 2011 submittal at this time.

We are proposing the promulgation of a FIP to address the deficiencies in the North Dakota Regional Haze SIP that we have identified in this proposal.

The proposed FIP includes the following elements:

• NO

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 NO

BART limits within five (5) years of the effective date of our final rule.

• NO

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 NO

BART limits within five (5) years of the effective date of our final rule.

• A reasonable progress determination and NO

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.

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 PM

2.5

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 PM

2.5

(

e.g.,

sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and soil dust) and its precursors (

e.g.,

sulfur dioxide (SO

), NO

and in some cases, ammonia (NH

) and volatile organic compounds (VOCs)). These precursors react in the atmosphere to form PM

2.5

. PM

2.5

impairs visibility by scattering and absorbing light. Visibility impairment reduces the clarity, color, and visible distance that one can see. PM

2.5

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

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.

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

In section 169A of the 1977 Amendments to the CAA, Congress created a program for protecting visibility in the nation's national parks and wilderness areas. This section of the CAA establishes as a national goal the “prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I Federal areas

which impairment

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.

Areas designated as mandatory Class I Federal areas consist of national parks exceeding 6000 acres, wilderness areas and national memorial parks exceeding 5000 acres, and all international parks that were in existence on August 7, 1977.

See

CAA section 162(a). In accordance with section 169A of the CAA, EPA, in consultation with the Department of Interior, promulgated a list of 156 areas where visibility is identified as an important value.

See

44 FR 69122, November 30, 1979. The extent of a

mandatory Class I area includes subsequent changes in boundaries, such as park expansions. CAA section 162(a). Although states and tribes may designate as Class I additional areas which they consider to have visibility as an important value, the requirements of the visibility program set forth in section 169A of the CAA apply only to “mandatory Class I Federal areas.” Each mandatory Class I Federal area is the responsibility of a “Federal Land Manager” (FLM).

See

CAA section 302(i). When we use the term “Class I area” in this action, we mean a “mandatory Class I Federal area.”

Congress added section 169B to the CAA in 1990 to address regional haze issues, and we promulgated regulations addressing regional haze in 1999. 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51, subpart P. The Regional Haze Rule revised the existing visibility regulations to integrate into them provisions addressing regional haze impairment and establish a comprehensive visibility protection program for Class I areas. The requirements for regional haze, found at 40 CFR 51.308 and 51.309, are included in our visibility protection regulations at 40 CFR 51.300-309. Some of the main regional haze requirements are summarized in section IV of this action. The requirement to submit a Regional Haze SIP applies to all 50 states, the District of Columbia and the Virgin Islands. States were required to submit a SIP addressing regional haze visibility impairment no later than December 17, 2007.

40 CFR 51.308(b).

EPA's regional haze regulations require subsequent updates to the regional haze SIPs. 40 CFR 51.308(g)-(i).

Few States submitted a Regional Haze SIP prior to the December 17, 2007 deadline, and on January 15, 2009, EPA found that 37 states, including North Dakota, and the District of Columbia and the Virgin Islands, had failed to submit SIPs addressing the regional haze requirements. 74 FR 2392. Once EPA has found that a State has failed to make a required submission, EPA is required to promulgate a FIP within two years unless the State submits a SIP and the Agency approves it within the two year period. CAA § 110(c)(1).

B. Roles of Agencies in Addressing Regional Haze

Successful implementation of the regional haze program will require long-term regional coordination among states, tribal governments and various federal agencies. Pollution affecting the air quality in Class I areas can be transported over long distances, even hundreds of kilometers. Therefore, to address effectively the problem of visibility impairment in Class I areas, states need to develop strategies in coordination with one another, taking into account the effect of emissions from one jurisdiction on the air quality in another.

Because the pollutants that lead to regional haze can originate from sources located across broad geographic areas, we have encouraged the states and tribes across the United States to address visibility impairment from a regional perspective. Five regional planning organizations (RPOs) were formed to address regional haze and related issues. The regional planning organizations first evaluated technical information to better understand how their states and tribes impact Class I areas across the country, and then pursued the development of regional strategies to reduce emissions of particulate matter (PM) and other pollutants leading to regional haze.

The Western Regional Air Program (WRAP) is a collaborative effort of state governments, tribal governments, and various federal agencies established to conduct data analyses, conduct pollutant transport modeling, and coordinate planning activities among the western states. Member state governments include: Alaska, Arizona, California, Colorado, Idaho, Montana, New Mexico, North Dakota, Oregon, South Dakota, Utah, Washington, and Wyoming. Tribal members include Campo Band of Kumeyaay Indians, Confederated Salish and Kootenai Tribes, Cortina Indian Rancheria, Hopi Tribe, Hualapai Nation of the Grand Canyon, Native Village of Shungnak, Nez Perce Tribe, Northern Cheyenne Tribe, Pueblo of Acoma, Pueblo of San Felipe, and Shoshone-Bannock Tribes of Fort Hall.

C. The 1997 NAAQS for Ozone and PM

2.5

and CAA 110(a)(2)(D)(i)

On July 18, 1997, we promulgated the 1997 8-hour ozone NAAQS and the 1997 PM

2.5

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 PM

2.5

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 PM

2.5

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 PM

2.5

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

measures in the applicable SIP for another state designed to “protect visibility” for the 1997 8-hour ozone NAAQS and the 1997 PM

2.5

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 PM

2.5

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 PM

2.5

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.

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

The deciview is used in expressing reasonable progress goals (which are interim visibility goals towards meeting the national visibility goal), defining baseline, current, and natural conditions, and tracking changes in visibility. The Regional Haze SIPs must contain measures that ensure “reasonable progress” toward the national goal of preventing and remedying visibility impairment in Class I areas caused by manmade air pollution by reducing anthropogenic emissions that cause regional haze. The national goal is a return to natural conditions,

i.e.,

manmade sources of air pollution would no longer impair visibility in Class I areas.

To track changes in visibility over time at each of the 156 Class I areas covered by the visibility program (40 CFR 81.401-437), and as part of the process for determining reasonable progress, states must calculate the degree of existing visibility impairment at each Class I area at the time of each Regional Haze SIP submittal and periodically review progress every five years midway through each 10-year implementation period. To do this, the Regional Haze Rule requires states to determine the degree of impairment (in deciviews) for the average of the 20 percent least impaired (“best”) and the average of the 20 percent most impaired (“worst”) visibility days over a specified time period at each of their Class I areas. In addition, states must also develop an estimate of natural visibility conditions for the purpose of comparing progress toward the national goal. Natural visibility is determined by estimating the natural concentrations of pollutants that cause visibility impairment and then calculating total light extinction based on those estimates. We have provided guidance to states regarding how to calculate baseline, natural and current visibility conditions.

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule,

September 2003, EPA-454/B-03-005,

available

http://www.epa.gov/ttncaaa1/t1/memoranda/Regional Haze _envcurhr_gd.pdf,

(hereinafter referred to as “our 2003 Natural Visibility Guidance”); and

Guidance for Tracking Progress Under the Regional Haze Rule,

(September 2003, EPA-454/B-03-004, available at

http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf,

(hereinafter referred to as our “2003 Tracking Progress Guidance”).

For the first Regional Haze SIPs that were due by December 17, 2007, “baseline visibility conditions” were the starting points for assessing “current” visibility impairment. Baseline visibility conditions represent the degree of visibility impairment for the 20 percent least impaired days and 20 percent most impaired days for each calendar year from 2000 to 2004. Using monitoring data for 2000 through 2004, states are required to calculate the average degree of visibility impairment for each Class I area, based on the average of annual values over the five-year period. The comparison of initial baseline visibility conditions to natural visibility conditions indicates the amount of improvement necessary to attain natural

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

built between 1962 and 1977 procure, install, and operate BART, as determined by the state or by EPA in the case of a plan promulgated under section 110(c) of the CAA. Under the Regional Haze Rule, states are directed to conduct BART determinations for such “BART-eligible” sources that may be anticipated to cause or contribute to any visibility impairment in a Class I area. Rather than requiring source-specific BART controls, states also have the flexibility to adopt an emissions trading program or other alternative program as long as the alternative provides greater reasonable progress towards improving visibility than BART.

The “major stationary sources” potentially subject to BART are listed in CAA section 169A(g)(7).

On July 6, 2005, we published the

Guidelines for BART Determinations Under the Regional Haze Rule

at Appendix Y to 40 CFR part 51 (“BART Guidelines”) to assist states in determining which of their sources should be subject to the BART requirements and in determining appropriate emission limits for each applicable source. 70 FR 39104. In making a BART determination for a fossil fuel-fired electric generating plant with a total generating capacity in excess of 750 megawatts (MW), a state must use the approach set forth in the BART Guidelines. A state is encouraged, but not required, to follow the BART Guidelines in making BART determinations for other types of sources. Regardless of source size or type, a state must meet the requirements of the CAA and our regulations for selection of BART, and the state's BART analysis and determination must be reasonable in light of the overarching purpose of the regional haze program.

The process of establishing BART emission limitations can be logically broken down into three steps: first, states identify those sources which meet the definition of “BART-eligible source” set forth in 40 CFR 51.301;

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.

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

States must address all visibility-impairing pollutants emitted by a source in the BART determination process. The most significant visibility-impairing pollutants are SO

, NO

, and PM. We have stated that states should use their best judgment in determining whether VOC or NH

compounds impair visibility in Class I areas.

Under the BART Guidelines, states may select an exemption threshold value for their BART modeling, below which a BART-eligible source would not be expected to cause or contribute to visibility impairment in any Class I area. The state must document this exemption threshold value in the SIP and must state the basis for its selection of that value. Any source with emissions that model above the threshold value would be subject to a BART determination review. The BART Guidelines acknowledge varying circumstances affecting different Class I areas. States should consider the number of emission sources affecting the Class I areas at issue and the magnitude of the individual sources'

impacts. Any exemption threshold set by the state should not be higher than 0.5 deciviews. 40 CFR part 51, appendix Y, section III.A.1.

In their SIPs, states must identify “BART-eligible sources” and “subject-to-BART sources” and document their BART control determination analyses. The term “BART-eligible source” used in the BART Guidelines means the collection of individual emission units at a facility that together comprises the BART-eligible source. In making BART determinations, section 169A(g)(2) of the CAA requires that states consider the following factors: (1) The costs of compliance; (2) the energy and non-air quality environmental impacts of compliance; (3) any existing pollution control technology in use at the source; (4) the remaining useful life of the source; and (5) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

See also

40 CFR 51.308(e)(1)(ii)(A).

A Regional Haze SIP must include source-specific BART emission limits and compliance schedules for each source subject to BART. Once a state has made its BART determination, the BART controls must be installed and in operation as expeditiously as practicable, but no later than five years after the date of our approval of the Regional Haze SIP. CAA section 169(g)(4) and 40 CFR 51.308(e)(1)(iv). In addition to what is required by the Regional Haze Rule, general SIP requirements mandate that the SIP must also include all regulatory requirements related to monitoring, recordkeeping, and reporting for the BART controls on the source.

See

CAA section 110(a). As noted above, the Regional Haze Rule allows states to implement an alternative program in lieu of BART so long as the alternative program can be demonstrated to achieve greater reasonable progress toward the national visibility goal than would BART.

E. Long-Term Strategy (LTS)

Consistent with the requirement in section 169A(b) of the CAA that states include in their Regional Haze SIP a 10- to 15-year strategy for making reasonable progress, section 51.308(d)(3) of the Regional Haze Rule requires that states include a long-term strategy in their Regional Haze SIPs. The long-term strategy is the compilation of all control measures a state will use during the implementation period of the specific SIP submittal to meet applicable reasonable progress goals. The long-term strategy must include “enforceable emissions limitations, compliance schedules, and other measures as necessary to achieve the reasonable progress goals” for all Class I areas within, or affected by emissions from, the state. 40 CFR 51.308(d)(3).

When a state's emissions are reasonably anticipated to cause or contribute to visibility impairment in a Class I area(s) located in another state or states, the Regional Haze Rule requires the state to consult with the other state(s) in order to develop coordinated emissions management strategies. 40 CFR 51.308(d)(3)(i). Also, a state with a Class I area impacted by emissions from another state must consult with such contributing state, (id.) and must also demonstrate that it has included in its SIP all measures necessary to obtain its share of the emission reductions needed to meet the reasonable progress goals for the Class I area.

Id.

at (d)(3)(ii). The regional planning organizations have provided forums for significant interstate consultation, but additional consultations between states may be required to sufficiently address interstate visibility issues. This is especially true where two states belong to different regional planning organizations.

States should consider all types of anthropogenic sources of visibility impairment in developing their long-term strategy, including stationary, minor, mobile, and area sources. At a minimum, states must describe how each of the following seven factors listed below are taken into account in developing their long-term strategy: (1) Emission reductions due to ongoing air pollution control programs, including measures to address reasonably attributable visibility impairment; (2) measures to mitigate the impacts of construction activities; (3) emissions limitations and schedules for compliance to achieve the reasonable progress goals; (4) source retirement and replacement schedules; (5) smoke management techniques for agricultural and forestry management purposes including plans as currently exist within the state for these purposes; (6) enforceability of emissions limitations and control measures; and (7) the anticipated net effect on visibility due to projected changes in point, area, and mobile source emissions over the period addressed by the long-term strategy. 40 CFR 51.308(d)(3)(v).

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

As part of the Regional Haze Rule, we revised 40 CFR 51.306(c) regarding the long-term strategy for reasonably attributable visibility impairment to require that the reasonably attributable visibility impairment plan must provide for a periodic review and SIP revision not less frequently than every three years until the date of submission of the state's first plan addressing regional haze visibility impairment, which was due December 17, 2007, in accordance with 40 CFR 51.308(b) and (c). On or before this date, the state must revise its plan to provide for review and revision of a coordinated long-term strategy for addressing reasonably attributable visibility impairment and regional haze, and the state must submit the first such coordinated long-term strategy with its first Regional Haze SIP. Future coordinated long-term strategy and periodic progress reports evaluating progress towards reasonable progress goals, must be submitted consistent with the schedule for SIP submission and periodic progress reports set forth in 40 CFR 51.308(f) and 51.308(g), respectively. The periodic review of a state's long-term strategy must report on both regional haze and reasonably attributable visibility impairment and must be submitted to us as a SIP revision.

G. Monitoring Strategy and Other SIP Requirements

Section 51.308(d)(4) of the Regional Haze Rule includes the requirement for a monitoring strategy for measuring, characterizing, and reporting of regional haze visibility impairment that is representative of all mandatory Class I Federal areas within the state. The strategy must be coordinated with the monitoring strategy required in section 51.305 for reasonably attributable visibility impairment. Compliance with this requirement may be met through “participation” in the IMPROVE network,

i.e.,

review and use of monitoring data from the network. The monitoring strategy is due with the first Regional Haze SIP, and it must be reviewed every five (5) years. The monitoring strategy must also provide for additional monitoring sites if the IMPROVE network is not sufficient to determine whether reasonable progress goals will be met.

Under section 51.308(d)(4), the SIP must also provide for the following:

• Procedures for using monitoring data and other information in a state with mandatory Class I areas to determine the contribution of emissions from within the state to regional haze visibility impairment at Class I areas both within and outside the state;

• Procedures for using monitoring data and other information in a state with no mandatory Class I areas to determine the contribution of emissions from within the state to regional haze

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.

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

2000-2004 Baseline

(dv)

2018 URP Goal

(dv)

2018 Reduction needed

(delta dv)

2064 Natural conditions

(dv)

20% Best days

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.

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.

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

For Theodore Roosevelt and Lostwood, North Dakota opted to use WRAP calculations in which the default estimates for the natural conditions were combined with the “new IMPROVE equation.” This is an acceptable approach under our 2003 Natural Visibility Guidance. For Theodore Roosevelt, the default natural visibility value for the 20 percent worst days is 7.31 deciviews and for the 20 percent best days is 2.19 deciviews. For Lostwood, the default natural visibility value for the 20 percent worst days is 7.33 deciviews and for the 20 percent best days is 2.21 deciviews. For Theodore Roosevelt, North Dakota also referred to WRAP calculations using the new IMPROVE equation, finding the “refined” natural visibility value for the 20 percent worst days to be 7.8 deciviews and for the 20 percent best days to be 3.0 deciviews. For Lostwood, the “refined” natural visibility result for the 20 percent worst days is 8.0 deciviews and for the 20 percent best days is 2.9 deciviews. We have reviewed North Dakota's estimate of the natural visibility conditions and propose to find it acceptable using the new IMPROVE equation.

The new IMPROVE equation takes into account the most recent review of the science

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.

The science behind the revised IMPROVE equation is summarized in our Technical Support Document, in the Technical Support Document for Technical Products Prepared by the Western Regional Air Partnership (WRAP) in Support of Western Regional Haze Plans, Februrary 28, 2011, and in numerous published papers. See for example: Hand, J.L., and Malm, W.C., 2006,

Review of the IMPROVE Equation for Estimating Ambient Light Extinction Coefficients—Final Report.

March 2006. Prepared for Interagency Monitoring of Protected Visual Environments (IMPROVE), Colorado State University, Cooperative Institute for Research in the Atmosphere, Fort Collins, Colorado,

available at http://vista.cira.colostate.edu/improve/publications/GrayLit/016_IMPROVEeqReview/IMPROVEeqReview.htm

and Pitchford, Marc., 2006,

Natural Haze Levels II: Application of the New IMPROVE Algorithm to Natural Species Concentrations Estimates.

Final Report of the Natural Haze Levels II Committee to the RPO Monitoring/Data Analysis Workgroup. September 2006,

available at http://vista.cira.colostate.edu/improve/Publications/GrayLit/029_NaturalCondII/naturalhazelevelsIIreport.ppt.

2. Estimating Baseline Visibility Conditions

As required by section 51.308(d)(2)(i) of the Regional Haze Rule and in accordance with our 2003 Natural Visibility Guidance, North Dakota calculated baseline visibility conditions for Theodore Roosevelt and Lostwood. The baseline condition calculation begins with the calculation of light extinction, using the IMPROVE equation. The IMPROVE equation sums the light extinction

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 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, b

ext

expressed in inverse megameters (Mm

−1

), as follows: HI = 10 ln(b

ext

/10).

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

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 NO

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 SO

, NO

, and direct PM (including both coarse particulate matter (PM

) and PM

2.5

) emissions as visibility-impairing pollutants and to exercise their “best judgment to determine whether VOC or NH

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. NH

emissions in North Dakota are primarily due to area sources, such as livestock and fertilizer

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 NH

and VOC emissions are negligible. The emissions inventory prepared for the WRAP modeling demonstrates that NH

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 BART-eligible sources that may reasonably be anticipated to cause or contribute to any visibility impairment at any Class I area,

i.e.

those sources that are subject to BART. The BART Guidelines allow states to consider exempting some BART-eligible sources from further BART review because they may not reasonably be anticipated to cause or contribute to any visibility impairment in a Class I area. Consistent with the BART Guidelines, North Dakota required each of its BART-eligible sources to develop and submit dispersion modeling to assess the extent of their contribution to visibility impairment at surrounding Class I areas.

a. Modeling Methodology

The BART Guidelines provide that states may use the CALPUFF

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).

Note that our reference to CALPUFF encompasses the entire CALPUFF modeling system, which includes the CALMET, CALPUFF, and CALPOST models and other pre and post processors. The different versions of CALPUFF have corresponding versions of CALMET, CALPOST, etc. which may not be compatible with previous versions (

e.g.,

the output from a newer version of CALMET may not be compatible with an older version of CALPUFF). The different versions of the CALPUFF modeling system are available from the model developer at

http://www.src.com/verio/download/download.htm.

The BART Guidelines also recommend that states develop a modeling protocol for making individual source attributions, and suggest that states may want to consult with us and their RPO to address any issues prior to modeling. North Dakota used the CALPUFF model for North Dakota BART sources in accordance with a protocol it developed entitled “Protocol for BART-Related Visibility Impairment Modeling Analyses in North Dakota, November 2005,” which was approved by EPA and the Federal Land Managers and is included in Appendix A.1 of the SIP. The North Dakota protocol follows recommendations for long range transport described in appendix W to 40 CFR part 51, “Guideline on Air Quality Models,” and in EPA's “Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long Range Transport Impacts,” as recommended by the BART Guidelines. 40 CFR part 51, appendix Y, section III.A.3.

To determine if each BART-eligible source has a significant impact on visibility, North Dakota used the CALPUFF model to estimate daily visibility impacts above estimated natural conditions at each Class I area within 300 km of any BART-eligible facility, based on maximum actual 24-hour emissions over a three year period (2000-2002).

North Dakota opted to conduct supplemental modeling for some sources using its own unique modeling approach. Further discussion on this is provided in section V.D and in the Technical Support Document.

b. Contribution Threshold

For states using modeling to determine the applicability of BART to single sources, the BART Guidelines note that the first step is to set a contribution threshold to assess whether the impact of a single source is sufficient to cause or contribute to visibility impairment at a Class I area. The BART Guidelines state that, “[a] single source that is responsible for a 1.0 deciview change or more should be considered to `cause' visibility impairment.” 70 FR 39104, 39161. The BART Guidelines also state that “the appropriate threshold for determining whether a source contributes to visibility impairment may reasonably differ across states,” but, “[a]s a general matter, any threshold that you use for determining whether a source `contributes' to visibility impairment should not be higher than 0.5 deciviews.”

Id.

Further, in setting a contribution threshold, states should “consider the number of emissions sources affecting the Class I areas at issue and the magnitude of the individual sources' impacts.” The Guidelines affirm that states are free to

use a lower threshold if they conclude that the location of a large number of BART-eligible sources in proximity to a Class I area justifies this approach.

North Dakota used a contribution threshold of 0.5 deciviews for determining which sources are subject to BART. The State's decision was based on the following factors: (1) 0.5 Deciviews equates to the 5% extinction threshold for new sources under the Prevention of Signification Deterioration New Source Review rules, (2) 0.5 deciviews represents the limit of perceptible change, (3) most of North Dakota's major point sources are over 100 miles away from Class I areas and are located downwind in the prevailing wind direction, and (4) BART screening modeling indicates the visibility impact of these point sources is either much greater than both 1.0 deciviews and 0.5 deciviews or less than 0.5 deciviews. Although we do not agree that all of the factors considered by North Dakota's Department of Health are relevant in determining whether a source can be considered to cause or contribute to visibility impairment, we propose to approve the State's threshold of 0.5 deciviews. As shown in Table 4, North Dakota exempted four of the seven BART-eligible sources in the state from further review under the BART requirements. The visibility impacts attributable to each of these four sources fell well below 0.5 deciviews. Given the relatively limited impact on visibility from these four sources, we propose to agree with North Dakota's Department of Health that 0.5 deciviews is a reasonable threshold for North Dakota in determining whether its BART-eligible sources are subject to BART.

Because our recommended modeling approach already incorporates choices that tend to lower peak daily visibility impact values,

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.

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

c. Sources Identified by North Dakota as Subject to BART

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

BART.

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

Table 4—Individual BART-Eligible Source Visibility Impacts on North Dakota Class I Areas

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.

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 fossil-fuel-fired EGUs. North Dakota performed BART determinations for all of the sources subject to BART for NO

, SO

, and PM. We find that North Dakota adequately considered all five steps above in its BART determinations, with the exception of its NO

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 NO

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

BART determinations for all remaining cases and summarize them below.

a. Great River Energy, Coal Creek Station

Background

Coal Creek Station is a two-unit, 1,100 gross MW mine-mouth electrical generating plant located near Underwood, North Dakota. It consists primarily of two steam generators (both with a 550 MW capacity) and associated coal and ash handling systems. Both units are identical Combustion Engineering boilers that tangentially fire pulverized lignite coal. The expected remaining useful life for each is at least 20 years. In addition, the State concluded that there are 24 BART-eligible material handling transfer operations that are negligible sources of PM and five BART-eligible units—consisting of auxiliary or emergency equipment—that are negligible sources of PM, SO

, and NO

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

BART Review:

Each unit is already equipped with a wet scrubber system which removes approximately 90% of the SO

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 SO

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 SO

emissions that North Dakota reported in the SIP are 24,604 tons per year per unit.

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

The State identified the following SO

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 SO

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 SO

BART analysis, and the visibility impacts derived from modeling conducted by the source, are provided in Table 5.

Table 5—Summary of Coal Creek SO

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

0.146

20,760

30.76

1,482

1.919

Wet Scrubber Modification

0.146

20,760

11.52

555

1.419

Spray Dryer

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

0.875

1,538

12.52

8,140

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

Great River Energy modeled combined SO

and NO

controls. Thus, the results shown include the noted SO

control option and North Dakota's selected NO

BART control, LNB Option 1.

While wet scrubber modification achieves the same annual SO

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 SO

concentration to the scrubber or 0.15 lb/MMBtu (30-day rolling average)

averaged over both units. The estimated cost of wet scrubber modifications was $555 per ton ($/ton) of SO

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 SO

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 SO

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 NO

BART controls, separated overfire air (SOFA) + low NO

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

(

)

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 SO

BART for SO

—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 SO

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 SO

BART will substantially reduce sulfuric acid mist, which is the largest component of condensable PM. North Dakota reasonably determined that the costs of additional condensable PM controls would be excessive given the negligible improvement in visibility that would result.

Auxiliary Boilers No. 91 and No. 92, Emergency Generator, Emergency Fire Pump, and Material Handling and Fugitive Sources

The State analyzed and determined BART for these small emissions sources at the plant and determined that BART is existing controls with no additional controls. The State based its conclusion on the fact that further controls would not be cost effective and would have virtually no impact on visibility. For further detail, see the State's BART analysis.

We agree with the State's conclusion and are proposing to approve its BART determination for these sources.

b. Great River Energy, Stanton Station

Background

Stanton Station is a 188 MW electrical generating plant located on the bank of the Missouri River in eastern Mercer County near Stanton, North Dakota. The plant's one main turbine generator is run by the Unit 1 and Unit 10 boilers. Unit 1, which is the only BART eligible unit at Stanton Station, began operation in 1966. An auxiliary boiler was added in 1982. Unit 1 has a dry bottom front-wall-fired configuration and is permitted to burn both lignite and sub-bituminous Powder River Basin (PRB) coal. Unit 1 has an expected remaining useful life of at least 20 years. Because Great River Energy does not intend to

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 SO

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, SO

, and NO

. 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

BART Review (Lignite Coal):

Unit 1 is not equipped with any pollution controls for SO

The baseline uncontrolled SO

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 SO

control options as having potential application to the Stanton Station boiler: wet scrubber, spray dryer/fabric filter, circulating dry scrubber, flash dryer absorber,

wet scrubber with 10% bypass, dry sorbent injection/fabric filter, dry sorbent injection/existing ESP, Powerspan ECO®, coal cleaning, Pahlman Process

, and K-Fuel®. The State eliminated the following options as technically infeasible: coal cleaning, K-Fuel®, Powerspan ECO®, and the Pahlman Process

. 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 SO

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 SO

BART analysis with lignite coal, and the visibility impacts derived from modeling conducted by the source, are provided in Table 7.

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

Table 7—Summary of Stanton SO

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

0.091

8,907

13.18

1,480

1.119

Circulating Dry Scrubber

0.127

8,720

14.22

1,631

SD/FF

0.181

8,438

11.22

1,330

1.007

Wet Scrubber with 10% Bypass

0.263

8,063

9.49

1,177

DSI/FF

0.817

5,157

8.43

1,635

0.382

DSI/ESP

1.18

3,282

3.2

975

0.382

Visibility impacts are presented for each SO

control option with NO

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 SO

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 SO

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.

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 SO

emission limits which vary due to anticipated sulfur content variations in the Powder River Basin coal as the result of a new coal contract.

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

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 SO

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 SO

BART analysis with Powder River Basin coal is provided in Table 8.

Appendix B.3, pp. 17-22, of the SIP describes the basis for the 1.2 lb/MMBtu and 0.64 lb/MMBtu SO

baseline emission rates.

Table 8—Summary of Stanton SO

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

0.06

5,905

13.18

2,232

Circulating Dry Scrubber

0.084

5,781

14.22

2,460

SD/FF

0.12

5,594

11.22

2,006

Wet Scrubber with 10% Bypass

0.168

5,346

9.49

1,775

DSI/FF

0.54

3,419

8.43

2,466

DSI/ESP

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 SO

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 SO

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 SO

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 SO

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 SO

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.

BART Review (Lignite Coal):

Unit 1 is already equipped with LNB for NO

control. North Dakota indicates in the SIP that Unit 1 has baseline controlled NO

emissions of 1,740 tons per year with an emission rate of 0.36 lb/MMBtu. North Dakota identified the following control options as having potential application as BART: selective catalytic reduction (SCR), low temperature oxidation (LTO), non-selective catalytic reduction (NSCR), electro-catalytic oxidation (ECO), selective non-catalytic reduction (SNCR), rich reagent injection (RRI), external flue gas recirculation (FGR), overfire air (OFA), LNB, and the Pahlman Process. The State identified the following control options as technically infeasible: ECO, NSCR, the Pahlman Process, RRI, and external flue gas recirculation. The incremental cost effectiveness of both SCR and LTO were deemed excessive at $10,000 and $45,400 per ton, respectively, when compared to a combination of LNB, OFA, and SNCR (LNB + OFA + SNCR). The State determined that there were no energy and non-air quality environmental impacts that would preclude the selection of any of the control equipment alternatives. A summary of the State's NO

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 NO

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 Imacts

1 2

Visibility

benefit

(delta dv)

Fewer days > 0.5 dv (days)

SCR

0.044

1,929

12.49

6,475

1.405

LTO

0.044

1,929

44.78

23,217

LNB + OFA + SNCR

0.239

983

3.00

3,052

1.110

SNCR

0.29

738

2.70

3,658

1.027

LNB + OFA

1.009

Great River Energy modeled combined SO

and NO

controls. Thus, the results shown include the noted NO

control option and North Dakota's selected SO

BART control, a spray dryer with fabric filter.

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 NO

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 SO

, 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.

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 NO

BART analysis with Powder River Basin coal is provided in Table 10.

Table 10—Summary of Stanton NO

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

0.044

1,530

12.49

8,163

LTO

0.044

1,530

44.78

29,268

LNB + OFA + SNCR

0.196

794

3.0

3,778

SNCR

0.230

629

2.7

4,293

LNB + OFA

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 NO

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 NO

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

4.98

276,670

New ESP

99.7

0.015

5.80

322,220

Wet ESP

99.7

0.015

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

(

)

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

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 SO

BART for SO

—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 SO

would also constitute BART for condensable PM.

Condensable PM

(

)

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 SO

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 SO

Auxiliary Boiler, Emergency Generator, Emergency Fire Pump, Material Handling and Fugitive Sources

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, SO

and NO

. 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 NO

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

BART Review:

Unit 1 had no existing SO

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 SO

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 SO

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.

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 SO

BART analysis, and the visibility impacts derived from modeling conducted by the source, are provided in Table 12.

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

Table 12—Summary of Milton R. Young Station SO

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

0.10

20,443

22.58

1,105

2.076

Circulating Dry Scrubber

0.14

20,013

24.65

1,232

Spray Dryer

0.20

19,367

23.68

1,222

2.002

Visibility impacts are presented for each SO

control option with NO

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

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 SO

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 SO

BART determination for Milton R. Young Station Unit 1. The State selected the most efficient control technology at a 95% control level, which we consider to be consistent with the most stringent level of control currently available. Per our BART Guidelines, a state may skip the five-factor analysis if it is imposing the most stringent level of control. Nonetheless, we note that the wet scrubber will produce a reduction in annual SO

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

4.64

51,589

CoHPAC

99.7

0.015

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 (PM

)

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 SO

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 SO

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 SO

BART will substantially reduce sulfuric acid mist, which is the largest component of condensable PM. North Dakota's determination is reasonable.

Unit 2 Boiler

BART Review:

At the time of the State's BART analysis, Unit 2 was equipped with a wet scrubber system which treated approximately 78% of the flue gas with the remaining flue gas by-passed for stack gas reheat. The wet scrubber system achieved approximately 75% SO

removal. The baseline controlled SO

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 SO

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 SO

BART analysis, and visibility impacts derived from modeling conducted by the source, are provided in Table 14.

Table 14—Summary of Milton R. Young Station SO

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)

Upgrade Existing Scrubber

0.11

16,126

8.41

522

1.627

Upgrade Existing Scrubber

0.23

14,162

7.33

518

1.423

Visibility impacts are presented for each SO

control option with NO

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 SO

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 SO

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 (PM

)

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 SO

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 SO

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

We agree with the State's conclusion and are proposing to approve its BART determination for these sources.

d. Basin Electric Power Cooperative, Leland Olds Station (LOS)

This is a 656 MW coal-fired electrical generating plant located in Stanton, North Dakota with two boiler units. Unit 1 is a Babcock & Wilcox wall-fired, dry-bottom, pulverized coal-fired boiler serving a turbine generator with a nameplate rating of 216 MW. Unit 2 is a Babcock & Wilcox cyclone-fired unit burning crushed coal, with a turbine-

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, SO

, and NO

. 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 NO

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

BART Review:

Unit 1 has no existing SO

control system. The baseline uncontrolled SO

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 SO

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 SO

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 SO

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

0.15

32,949

19.31

586

1.912

Circulating Dry Scrubber

0.21

32,255

20.72

636

1.743

Spray Dryer

0.30

31,215

18.70

599

1.707

Basin Electric modeled combined SO

and NO

controls. The results shown include the noted SO

control option and NO

at the presumptive rate. Given that the presumptive NO

emission rate is very close to the pre-control NO

rate, the visibility impacts shown are largely due to the reduction in SO

emissions and not the reduction in NO

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 SO

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 SO

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 SO

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.

BART Review:

Unit 1 is equipped with LNB (installed in 1995). The baseline controlled NO

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 NO

burners (LNB).

• Combustion improvements.

The State agreed with Basin Electric's determination that high dust SCR is not technically feasible but found that low-dust SCR (LDSCR) and tail-end SCR (TESCR) would be technically feasible. North Dakota also identified ECO, coal reburn plus SNCR, and RRI as technically infeasible for Unit 1. The State determined the average cost effectiveness of the four most efficient options to be excessive with estimates ranging from $4,400 to $13,600 per ton of NO

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 NO

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 NO

BART analysis for Unit 1 is provided in Table 17.

Table 17—Summary of Leland Olds Station NO

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

0.057

2,374

18.63-26.86

7,849-11,313

SCR Tail End

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 NO

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 NO

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 NO

, (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 NO

emissions. And, unlike those units, Unit 1 is not a cyclone boiler and so is currently fitted with low-NO

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 NO

emissions of about 1,246 tons per year. Based on these factors, we are proposing to approve North Dakota's NO

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 (PM

) 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 SO

; therefore, North Dakota determined that BART for condensable PM is good SO

control. The State determined that o

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