20894 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R08–OAR–2010–0406; FRL–9648–3] 

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: Final rule. 

SUMMARY: EPA is partially approving 

and partially disapproving 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 

promulgating a Federal Implementation 

Plan (FIP) to address the gaps in the 

plan resulting from our partial 

disapproval of North Dakota’s Regional 

Haze (RH) SIP. 

In addition, EPA is disapproving a 

revision to the North Dakota SIP 

addressing the interstate transport of 

pollutants that the Governor submitted 

on April 6, 2009. We are disapproving 

it because it does not meet the Act’s 

requirements concerning noninterference with programs to protect 

visibility in other states. To address this 

deficiency, we are promulgating a FIP. 

DATES: This final rule is effective May 7, 

2012. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–R08–OAR–2010–0406. All 

documents in the docket are listed on 

the www.regulations.gov Web site. 

Although listed in the index, some 

information is not publicly available, 

e.g., Confidential Business Information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

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, Air Program, Mailcode 8P–AR, 

Environmental Protection Agency, 

Region 8, 1595 Wynkoop Street, Denver, 

Colorado 80202–1129, (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: 

• The word Act or initials CAA mean 

or refer to the Clean Air Act, unless the 

context indicates otherwise. 

• The initials ASOFA mean or refer to 

advanced separated overfire air. 

• The initials AVS mean or refer to 

Antelope Valley Station. 

• The initials BACT mean or refer to 

Best Available Control Technology. 

• The initials BART mean or refer to 

Best Available Retrofit Technology. 

• The initials CAM mean or refer to 

compliance assurance monitoring. 

• The initials CAMx mean or refer to 

Comprehensive Air Quality Model. 

• The initials CCS mean or refer to 

Coal Creek Station. 

• The initials CEMS mean or refer to 

continuous emission monitoring system. 

• The initials CMAQ mean or refer to 

Community Multi-Scale Air Quality 

modeling system. 

• The initials CSAPR mean or refer to 

Cross-State Air Pollution Rule. 

• The initials EGUs mean or refer to 

Electric Generating Units. 

• The words we, us or our or the 

initials EPA mean or refer to the United 

States Environmental Protection 

Agency. 

• The initials FIP mean or refer to 

Federal Implementation Plan. 

• The initials FLMs mean or refer to 

Federal Land Managers. 

• The initials GRE mean or refer to 

Great River Energy. 

• The initials IMPROVE mean or refer 

to Interagency Monitoring of Protected 

Visual Environments monitoring 

network. 

• The initials IWAQM mean or refer 

to Interagency Workgroup on Air 

Quality Modeling. 

• The initials LDSCR mean or refer to 

low-dust SCR. 

• The initials LOS mean or refer to 

Leland Olds Station. 

• The words Lostwood or Lostwood 

Wilderness Area or initials LWA mean 

or refer to Lostwood National Wildlife 

Refuge Wilderness Area. 

• The initials LNB mean or refer to 

low NOX burners. 

• The initials LTS mean or refer to 

Long-Term Strategy. 

• The initials MRYS mean or refer to 

Milton R. Young Station. 

• The initials NAAQS mean or refer 

to National Ambient Air Quality 

Standards. 

• The words North Dakota and State 

mean the State of North Dakota unless 

the context indicates otherwise. 

• The initials NOX mean or refer to 

nitrogen oxides. 

• The initials NPCA mean or refer to 

National Parks Conservation 

Association. 

• The initials NPS mean or refer to 

National Park Service. 

• The initials PM mean or refer to 

particulate matter. 

• The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers or 

course particulate matter. 

• The initials PM2.5 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers or 

fine particulate matter. 

• The initials PRB mean or refer to 

Powder River Basin. 

• The initials PSAT mean or refer to 

Particle Source Apportionment 

Technology. 

• The initials PSD mean or refer to 

Prevention of Signification 

Deterioration. 

• The initials RHR mean or refer to 

the Regional Haze Rule. 

• The initials RH SIP mean or refer to 

North Dakota’s Regional Haze State 

Implementation Plan. 

• The initials RMC mean or refer to 

the Regional Modeling Center at the 

University of California Riverside. 

• The initials RP mean or refer to 

Reasonable Progress. 

• The initials RPG mean or refer to 

Reasonable Progress Goal. 

• The initials SCR mean or refer to 

selective catalytic reduction. 

• The initials SIP mean or refer to 

State Implementation Plan. 

• The initials SNCR mean or refer to 

selective non-catalytic reduction. 

• The initials SO2 mean or refer to 

sulfur dioxide. 

• The initials SOFA mean or refer to 

separated overfire air. 

• The initials TRNP mean or refer to 

Theodore Roosevelt National Park. 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20895 

• The initials TSD mean or refer to 

Technical Support Document. 

• The initials URP mean or refer to 

Uniform Rate of Progress. 

• The initials WEP mean or refer to 

Weighted Emissions Potential. 

• The initials WRAP mean or refer to 

the Western Regional Air Partnership. 

Table of Contents 

I. Background 

A. Regional Haze 

B. Interstate Transport Requirements 

C. Lawsuits 

D. Our Proposal 

1. Regional Haze 

2. Interstate Transport, Visibility Prong 

E. Public Participation 

II. Final Action 

A. Regional Haze 

B. Interstate Transport, Visibility Prong 

III. Changes from Proposed Rule and Reasons 

for the Changes 

A. NOX BART for Milton R. Young Station 

Units 1 and 2 and Leland Olds Station 

Unit 2 

B. NOX BART for Coal Creek Station (CCS) 

Units 1 and 2 

C. Other Resultant Changes 

IV. Basis for Our Final Action 

A. Regional Haze 

B. Interstate Transport, Visibility Prong 

V. Issues Raised by Commenters and EPA’s 

Responses 

A. NOX BART for Milton R. Young Station 

Units 1 and 2 and Leland Olds Station 

Unit 2 

B. Comments on Legal Issues 

1. EPA’s Authority 

2. Interstate Transport Consent Decree 

3. Other General Legal Comments 

C. Comments on Modeling 

D. Comments on Costs 

1. General 

2. Comments Regarding Our Reliance on 

the EPA Air Pollution Control Cost 

Manual 

E. Comments on BART Determinations 

1. General Comments 

2. CCS Units 1 and 2 

a. EPA’s Use of the Control Cost Manual for 

CCS 

b. CCS Emission Limits 

c. CCS Modeling 

d. CCS Coal Ash 

e. CCS Visibility Improvements Are 

Minimal 

f. Comments on Alternative NOX Emission 

Limits 

g. Cost Effectiveness of SNCR and SCR at 

CCS 

h. CCS General Comments 

3. Stanton Station Unit 1 

4. Leland Olds Station Unit 1 

F. General Comments on SO2 and PM 

Controls 

G. Comments on Reasonable Progress and 

North Dakota’s Long-Term Strategy 

H. Comments on Health and Ecosystem 

Benefits, and Other Pollutants 

I. Miscellaneous Comments 

J. Comments Requesting an Extension to 

the Public Comment Period 

K. Comments Generally in Favor of Our 

Proposal 

L. Comments Generally Against Our 

Proposal 

VI. Statutory and Executive Order Reviews 

I. Background 

The CAA requires each state to 

develop plans, referred to as SIPs, to 

meet various air quality requirements. 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). 

This action involves two separate 

requirements under the CAA and EPA’s 

regulations. One is the requirement that 

states have SIPs that address regional 

haze, the other is the requirement that 

states have SIPs that address the 

interstate transport of pollutants that 

may interfere with programs to protect 

visibility in other states. 

A. Regional Haze 

In 1990, Congress added section 169B 

to the CAA 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 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. 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). 

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 section 110(c)(1). 

North Dakota initially submitted a SIP 

addressing regional haze on March 3, 

2010. On July 27, 2010, North Dakota 

submitted a revision to that submittal, 

entitled ‘‘SIP Supplement No. 1.’’ On 

July 28, 2011, North Dakota submitted 

another revision, entitled ‘‘SIP 

Amendment No. 1.’’ 

B. Interstate Transport Requirements 

Section 110(a)(1) of the CAA requires 

states to submit SIPs to address new or 

revised National Ambient Air Quality 

Standards (NAAQS) within 3 years after 

promulgation of such standards, or 

within such shorter period as we may 

prescribe. On July 18, 1997, we 

promulgated the 1997 8-hour ozone 

NAAQS and the 1997 fine particulate 

(PM2.5) NAAQS. 62 FR 38652. 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. 

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. 

On April 25, 2005, we published a 

‘‘Finding of Failure to Submit SIPs for 

Interstate Transport for the 8-hour 

Ozone and PM2.5 NAAQS.’’ 70 FR 

21147. This action included a finding 

that North Dakota and other states had 

failed to submit SIPs to address 

interstate transport of air pollution 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 April 6, 2009, we received a SIP 

revision from North Dakota to address 

the interstate transport provisions of 

CAA 110(a)(2)(D)(i) for the 1997 8-hour 

ozone NAAQS and the 1997 PM2.5

NAAQS. In prior actions, we approved 

this North Dakota SIP submittal for the 

first three prongs of section 

110(a)(2)(D)(i). (75 FR 31290, June 3, 

2010 and 75 FR 71023, November 22, 

2010). This action addresses the fourth 

prong. 

C. Lawsuits 

In two separate lawsuits, one in U.S. 

District Court for the Northern District 

of California and one in the U.S. District 

Court for the District of Colorado, 

environmental groups sued us for our 

failure to timely take action with respect 

to the interstate transport requirements 

and the regional haze requirements of 

the CAA and our regulations. In 

particular, the lawsuits alleged that we 

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20896 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

had failed to promulgate FIPs for these 

requirements within the two-year period 

allowed by CAA section 110(c) or, in the 

alternative, fully approve SIPs 

addressing these requirements. 

As a result of these lawsuits, we 

entered into two separate consent 

decrees in these two jurisdictions. The 

consent decree in the Northern District 

of California, as modified on several 

occasions, required that we sign a notice 

of proposed rulemaking for prong four 

of the interstate transport requirements 

for North Dakota by September 1, 2011. 

As lodged with the court, but before it 

was entered, the proposed consent 

decree in the District of Colorado 

required that we sign a notice of 

proposed rulemaking for regional haze 

requirements for North Dakota by July 

21, 2011. Because the latter consent 

decree was not entered by the court 

until September 27, 2011, and we 

signed our notice of proposed 

rulemaking on September 1, 2011, the 

July 21, 2011 deadline was mooted. 

Both consent decrees, as modified, 

require that we sign a notice of final 

rulemaking addressing the regional haze 

requirements and prong four of the 

interstate transport requirements by 

March 2, 2012. We are meeting that 

requirement with the signing of this 

notice of final rulemaking. 

D. Our Proposal 

We signed our notice of proposed 

rulemaking on September 1, 2011, and 

it was published in the Federal Register 

on September 21, 2011 (76 FR 58570). 

In that notice, we provided a detailed 

description of the various regional haze 

and interstate transport requirements. 

We are not repeating that description 

here; instead, the reader should refer to 

our notice of proposed rulemaking for 

further detail. 

In our proposal, we proposed to take 

the following actions: 

1. Regional Haze 

We proposed to disapprove the 

following parts of North Dakota’s RH 

SIP: 

a. North Dakota’s nitrogen oxides 

(NOX) best available retrofit technology 

(BART) determinations and emissions 

limits for Milton R. Young Station 

(MRYS) Units 1 and 2, Leland Olds 

Station (LOS) Unit 2, and Coal Creek 

Station (CCS) Units 1 and 2. 

b. North Dakota’s determination 

under the reasonable progress 

requirements found at section 40 CFR 

51.308(d)(1) that no additional NOX

emissions controls were warranted at 

Antelope Valley Station (AVS) Units 1 

and 2. 

c. North Dakota’s reasonable progress 

goals (RPGs). 

d. Portions of North Dakota’s longterm strategy (LTS) that relied on or 

reflected other aspects of the RH SIP 

that we were proposing to disapprove. 

We proposed to approve the 

remaining aspects of North Dakota’s RH 

SIP revision that was submitted on 

March 3, 2010 and SIP Supplement No. 

1 that was submitted on July 27, 2010. 

We proposed to approve the following 

parts of SIP Amendment No. 1 that the 

State submitted on July 28, 2011: 

a. Amendments to Section 10.6.1.2 

pertaining to Coyote Station. 

b. Amendments to Appendix A.4, the 

Permit to Construct for Coyote Station. 

We proposed to not act on the 

remainder of the State’s July 28, 2011 

submittal. 

We proposed to promulgate a FIP to 

address the deficiencies in the North 

Dakota RH SIP that we identified in our 

proposal. The proposed FIP included 

the following elements: 

a. NOX BART determinations and 

emission limits for MRYS Units 1 and 

2 and Leland Olds Station Unit 2. 

b. NOX BART determination and 

emission limit for CCS Units 1 and 2. 

c. A reasonable progress 

determination and NOX emission limit 

for AVS Units 1 and 2. 

d. A five-year deadline to meet the 

emission limits and monitoring, 

recordkeeping, and reporting 

requirements for the above seven units 

to ensure compliance. 

e. RPGs consistent with the SIP limits 

proposed for approval and proposed FIP 

limits. 

f. LTS elements that would reflect the 

other aspects of the proposed FIP. 

We also proposed approval of a SIP 

revision in lieu of our regional haze FIP 

if the State submitted a revision in a 

timely way that matched the terms of 

our proposed FIP. 

2. Interstate Transport, Visibility Prong 

We proposed to disapprove the 

portion of North Dakota’s April 6, 2009, 

SIP revision for interstate transport in 

which North Dakota intended to address 

the requirement of section 

110(a)(2)(D)(i)(II) that emissions from 

North Dakota sources not interfere with 

measures required in the SIP of any 

other state under part C of the CAA to 

protect visibility. 

Because of this proposed disapproval, 

we proposed a FIP to meet the visibility 

protection requirement of section 

110(a)(2)(D)(i)(II). To meet this FIP duty, 

we proposed to find that North Dakota 

sources would be sufficiently controlled 

to eliminate interference with the 

visibility programs of other states by a 

combination of the measures that we 

were proposing to approve as meeting 

the regional haze SIP requirements 

combined with the additional measures 

that we were proposing to impose in a 

FIP to meet the remaining regional haze 

SIP requirements. 

We noted that acting on both the 

section 110(a)(2)(D)(i)(II) requirement 

and the regional haze SIP requirement 

simultaneously would ensure the most 

efficient use of resources by the affected 

sources and EPA. 

E. Public Participation 

We requested comments on all 

aspects of our proposed action and 

provided a two-month comment period, 

with the comment period closing on 

November 21, 2011. We also provided a 

public hearing. Initially, we scheduled 

the hearing to last four hours on one 

day. 76 FR 58570. At the request of the 

Governor of North Dakota, we expanded 

the time for the public hearing to 14 

hours over two days and changed the 

venue. 76 FR 60777 (September 30, 

2011). The public hearing was held in 

Bismarck, North Dakota on October 13 

and 14, 2011. 

We received a significant number of 

comments on our proposed rule, both 

from commenters, particularly citizens 

and environmental groups, that 

supported our proposed action, and 

from commenters, primarily from state 

and city agencies, rural power 

cooperatives, and industrial facilities 

and groups, that were critical of our 

proposed action. 

In this action, we are responding to 

the comments we have received, taking 

final rulemaking action, and explaining 

the bases for our action, including any 

changes from our proposed action. 

II. Final Action 

A. Regional Haze 

With this final action we are partially 

approving and partially disapproving 

North Dakota’s RH SIP revision that was 

submitted on March 3, 2010, SIP 

Supplement No. 1 that was submitted 

on July 27, 2010, and part of SIP 

Amendment No. 1 that was submitted 

on July 28, 2011. Specifically we are 

disapproving: 

• North Dakota’s NOX BART 

determinations and emissions limits for 

CCS Units 1 and 2. 

• North Dakota’s determination under 

the reasonable progress requirements 

found at 40 CFR 51.308(d)(1) that no 

additional NOX emissions controls are 

warranted at AVS Units 1 and 2. 

• North Dakota’s RPGs. 

• Portions of North Dakota’s LTS that 

rely on or reflect other aspects of the RH 

SIP that we are disapproving. 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20897 

We are approving the remaining 

aspects of North Dakota’s RH SIP 

revision that was submitted on March 3, 

2010 and SIP Supplement No. 1 that 

was submitted on July 27, 2010. We are 

approving 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 for Coyote Station. 

We are not taking action on the 

remainder of the July 28, 2011 submittal 

at this time. 

We are finalizing a FIP to address the 

deficiencies in the North Dakota RH SIP 

that result from our partial disapproval 

of the SIP. 

The final FIP includes the following 

elements: 

• NOX BART determination and 

emission limit for CCS Units 1 and 2 of 

0.13 lb/MMBtu averaged across the two 

units on a 30-day rolling average, and a 

requirement that the owners/operators 

comply with this NOX BART limit 

within five (5) years of the effective date 

of this final rule. 

• A reasonable progress 

determination and NOX emission limit 

for AVS 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 

four units to ensure compliance with 

these emission limitations. 

• RPGs consistent with the SIP limits 

approved and the final FIP limits. 

• LTS elements that reflect the other 

aspects of the finalized FIP. 

B. Interstate Transport, Visibility Prong 

We are disapproving a portion of a 

SIP revision that North Dakota 

submitted 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 1997 

PM2.5 NAAQS. Specifically, we are 

disapproving the portion of the April 6, 

2009 SIP in which North Dakota 

intended to address the requirement of 

section 110(a)(2)(D)(i)(II) that emissions 

from North Dakota sources do not 

interfere with measures required in the 

SIP of any other state under part C of the 

CAA to protect visibility. Because of 

this disapproval, we are promulgating a 

FIP to meet this requirement of section 

110(a)(2)(D)(i)(II). To meet this FIP duty, 

we are finding that North Dakota 

sources will be sufficiently controlled to 

eliminate interference with the visibility 

programs of other states by a 

combination of the measures in the 

North Dakota SIP that we are 

simultaneously approving as meeting 

the regional haze SIP requirements 

combined with the additional measures 

that we are imposing in a FIP to meet 

the remaining regional haze SIP 

requirements. We note that North 

Dakota always has the discretion to 

revise its SIP and submit the revision to 

us. Should such a revision meet CAA 

requirements, we would replace our FIP 

with North Dakota’s SIP revision. We 

encourage the State to revise its SIP. 

III. Changes From Proposed Rule and 

Reasons for the Changes 

A. NOX BART for Milton R. Young 

Station Units 1 and 2 and Leland Olds 

Station Unit 2 

As noted, we proposed to disapprove 

North Dakota’s NOX BART 

determinations for MRYS 1 and 2 and 

LOS 2 and to promulgate a FIP for NOX

BART for these units to fill the gap that 

would have resulted from our 

disapproval. After considering a recent 

judicial decision, we have decided to 

approve North Dakota’s NOX BART 

determination for MRYS 1 and 2 and 

LOS 2 and to not promulgate a FIP for 

NOX BART for these units. We more 

fully describe the reasons for this 

change below. 

On July 27, 2006, the U.S. District 

Court for the District of North Dakota 

entered a consent decree between EPA, 

the State, and Minnkota Power 

Cooperative (‘‘Minnkota’’). The consent 

decree resulted from an enforcement 

action that EPA and the State brought 

against Minnkota for alleged violations 

of Prevention of Significant 

Deterioration (PSD) permitting 

requirements at MRYS 1 and 2. The 

consent decree called for North Dakota 

to make a best available control 

technology (BACT) determination for 

NOX for MRYS 1 and 2 but also 

provided a dispute resolution procedure 

in the event of disagreement regarding 

the BACT determination. 

In November 2010, North Dakota 

determined BACT for NOX to be limits 

of 0.36 lb/MMBtu for MRYS 1 and 0.35 

lb/MMBtu for MRYS 2 based on the use 

of selective non-catalytic reduction 

(SNCR) technology, with separate limits 

during startup. In reaching this 

decision, North Dakota eliminated 

selective catalytic reduction (SCR), a 

higher performing control technology, 

based on a finding that SCR was not 

technically feasible to control emissions 

from North Dakota lignite coal. In 

particular, North Dakota noted that no 

SCR has ever been employed on an 

electric generating unit (EGU) burning 

North Dakota lignite, that North Dakota 

lignite has unique properties that have 

the potential to quickly degrade the SCR 

catalyst, and that no catalyst vendor 

supplied with the specifications for the 

coal at MRYS 1 and 2 would provide a 

guarantee of catalyst life without first 

conducting slipstream or pilot tests at 

MRYS. 

EPA disagreed with North Dakota’s 

findings and the selection of selective 

non-catalytic reduction (SNCR) as BACT 

and initiated the dispute resolution 

process under the consent decree. 

Under the consent decree, the court was 

tasked with upholding North Dakota’s 

BACT determination unless the 

disputing party was able to demonstrate 

that North Dakota’s decision was 

unreasonable. We have included a copy 

of the consent decree and the court’s 

order in the docket for this action. 

On December 21, 2011, following 

briefing by the parties, and 

consideration of North Dakota’s record 

for its BACT determination, the court 

determined that EPA had not 

demonstrated that North Dakota’s 

findings were unreasonable. The court 

decided that North Dakota, based on the 

administrative record for its BACT 

determination, had a reasonable basis 

for concluding that SCR is not 

technically feasible for treating North 

Dakota lignite at MRYS. The court 

upheld North Dakota’s determination 

that SNCR is BACT. 

There are two critical principles 

expressed in our BART guidelines that 

are relevant here. First, as part of a 

BART analysis, technically infeasible 

control options are eliminated from 

further review. For BART, EPA’s criteria 

for determining whether a control 

option is technically infeasible are 

substantially the same as the criteria 

used for determining technical 

infeasibility in the BACT context. 70 FR 

39165; EPA’s ‘‘New Source Review 

Workshop Manual,’’ pages B.17–B.22. 

Second, the BART guidelines indicate 

that states generally may rely on a BACT 

determination for a source for purposes 

of determining BART for that source, 

unless new technologies have become 

available or best control levels for recent 

retrofits have become more stringent. 70 

FR 39164. As a general rule, the 

selection of a recent BACT level as 

BART is the equivalent of selecting the 

most stringent level of control, and 

consideration of the five statutory BART 

factors becomes unnecessary. 

Over our vigorous challenge of the 

information and analysis relied upon by 

North Dakota, the U.S. District Court 

upheld North Dakota’s recent BACT 

determination based on the same 

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1U.S. EPA, EPA Air Pollution Control Cost 

Manual, EPA/452/B–02–001, 6th Ed., January 2002, 

Section 4.2, Chapter 1, p. 1–3. 

2http://www.ftek.com/en-US/products/apc/ 

noxout/. 

3 Institute of Clean Air Companies, White Paper 

Selective Non-Catalytic Reduction (SNCR) for 

Controlling NOX Emissions, February 2008, p. 9. 

technical feasibility criteria that apply 

in the BART context. In light of the 

court’s decision and the views we have 

expressed in our BART guidelines on 

the relationship of BACT to BART, we 

have concluded that it would be 

inappropriate to proceed with our 

proposed disapproval of SNCR as BART 

and our proposed FIP to impose SCR at 

MRYS 1 and 2 and LOS 2. While LOS 

2 was not the subject of the BACT 

determination, the same reasoning that 

applies to MRYS 1 and 2 also applies to 

LOS 2. It is the same type of boiler 

burning North Dakota lignite coal, and 

North Dakota’s views regarding 

technical infeasibility that the U.S. 

District Court upheld in the MRYS 

BACT case apply to it as well. Thus, 

with this action we are approving North 

Dakota’s NOX BART determinations for 

MRYS 1 and 2 and LOS 2, and no FIP 

for these units is necessary. The 

applicable limits are 0.36 lb/MMBtu for 

MRYS 1 and 0.35 lb/MMBtu for MRYS 

2 and 0.35 lb/MMBtu for LOS 2. 

We note, however, that the State has 

indicated a willingness to pursue the 

conduct of a pilot study at MRYS and/ 

or LOS to analyze the expected 

replacement rate of SCR catalyst 

exposed to flue gas from the combustion 

of North Dakota lignite at these cyclone 

units in a low-dust or tail-end 

configuration. It is our expectation that 

the results of such a study could be used 

to inform further evaluation of SCR as 

a potential control technology when the 

State evaluates reasonable progress in 

the next planning period for regional 

haze. This position is supported by the 

State’s December 20, 2011 letter from 

North Dakota Department of Health 

(NDDH), L. David Glatt, to EPA, Janet 

McCabe. 

B. NOX BART for Coal Creek Station 

(CCS) Units 1 and 2 

We proposed a NOX BART FIP limit 

for CCS 1 and 2 of 0.12 lb/MMBtu that 

would apply to each unit individually 

on 30-day rolling average basis. We 

based this limit on our proposed finding 

that SNCR plus separated overfire air 

(SOFA) plus low NOX burners (LNB) 

was the best available retrofit 

technology. While we continue to find 

that SNCR plus SOFA plus LNB is the 

best available retrofit technology, we are 

changing the emission limit to 0.13 lb/ 

MMBtu averaged over both units on a 

30-day rolling average basis. Evidence 

submitted by commenters and our own 

additional research in evaluating 

comments has led us to conclude that 

this represents a more reasonable limit 

to apply on a 30-day rolling average 

basis. 

This limit represents a control 

efficiency of 48% based on the average 

annual baseline emission rate of 0.22 lb/ 

MMBtu (2003–2004) provided in the 

State’s BART determination. This value 

is slightly lower than the 49% control 

efficiency we assumed in our proposal, 

a value that was based on the State’s 

analysis. Beginning in 2010, CCS 2 

voluntarily started employing LNC3, the 

more stringent level of combustion 

controls that the State evaluated in its 

BART determination. Annual average 

Clean Air Markets data for this unit 

reflects a NOX emission rate of 0.153 lb/ 

MMBtu. We estimate that SNCR would 

achieve an additional 25% reduction, 

equivalent to an emission rate of 0.115 

lb/MMBtu. This compares to a value of 

0.108 lb/MMBtu that the State originally 

estimated. 

Great River Energy (GRE), the owner 

of CCS, asserted in comments that SNCR 

will only achieve a 20% reduction 

beyond LNC3. We find that 25% is a 

conservative and reasonable estimate. 

We considered several sources of 

information in arriving at this value. 

First, the Control Cost Manual states 

that in typical field applications, SNCR 

provides a 30% to 50% NOX reduction. 

The manual provides a scatter plot with 

NOX reduction efficiency plotted as a 

function of boiler size in MMBtu/hr.1

The plot supports GRE’s assertion that 

control efficiency could be lower than 

50%, and could approach 30%, for 

larger boilers such as those at CCS. 

Second, Fuel Tech (one of the most 

recognized SNCR technology suppliers) 

estimates a range of 25% to 50% NOX

reduction with application of SNCR.2

Lastly, ICAC has published information 

that supports a control efficiency of 20 

to 30% for SNCR above LNB/ 

combustion modifications.3 Given this 

range of control efficiencies, we have 

settled on a control efficiency—25%— 

that is lower than the lowest value given 

by the Control Cost Manual, at the low 

end of the range estimated by Fuel Tech, 

and in the middle of the range estimated 

by ICAC. 

To arrive at a final BART emission 

limit, we adjusted the projected annual 

average of 0.115 lb/MMBtu upward by 

10% and then rounded to the nearest 

hundredth to arrive at 0.13 lb/MMBtu. 

In our experience, a 5 to 15% upward 

adjustment is appropriate when 

converting an annual average emission 

rate to a limit that will apply on a 30- 

day rolling average to account for the 

fact that shorter averaging periods result 

in higher variability in emissions due to 

load variation, startup, shutdown, and 

other factors. 

We decided to allow the averaging 

across Units 1 and 2 in response to 

comments we received. The BART 

Guidelines state, ‘‘You should consider 

allowing sources to ‘’average’’ emissions 

across any set of BART-eligible emission 

units within a fenceline, so long as the 

emission reductions from each pollutant 

being controlled for BART would be 

equal to those reductions that would be 

obtained by simply controlling each of 

the BART-eligible units that constitute 

the BART-eligible source.’’ 40 CFR part 

51, appendix Y, section V. This 

principle applies here. 

C. Other Resultant Changes 

Because we are now approving North 

Dakota’s NOX BART determinations for 

MRYS 1 and 2 and LOS 2, the basis for 

our proposed disapproval of North 

Dakota’s RPGs is slightly changed from 

our proposal. Disapproval is still 

warranted because North Dakota’s RPGs 

do not represent our final NOX BART 

FIP limits at CCS 1 and 2 or our final 

NOX reasonable progress FIP limits at 

AVS 1 and 2 (or the Heskett or Coyote 

controls that North Dakota included in 

the SIP). As part of our FIP, we are 

finalizing RPGs that are consistent with 

the controls we are imposing at CCS 1 

and 2 and AVS 1 and 2, and the Heskett 

and Coyote controls that North Dakota 

included in the SIP. For further details 

regarding our rationale, please refer to 

our proposal and to our response to 

comments. 

Similarly, because we are now 

approving North Dakota’s NOX BART 

determinations for MRYS 1 and 2 and 

LOS 2, the basis for our proposed partial 

disapproval of North Dakota’s LTS is 

slightly changed from our proposal. 

Partial disapproval is still warranted 

because we are disapproving North 

Dakota’s NOX BART determination for 

CCS 1 and 2 and NOX reasonable 

progress determination for AVS 1 and 2, 

and the LTS does not reflect our final 

NOX BART FIP limits at CCS 1 and 2 

or our final NOX reasonable progress FIP 

limits at AVS 1 and 2, or corresponding 

compliance provisions. Except for these 

missing elements, the LTS satisfies the 

requirements of 40 CFR 51.308(d)(3), so 

we are approving the remainder of the 

LTS. Our FIP fills the gap left by our 

partial disapproval of the LTS by 

specifying NOX emission limits for CCS 

1 and 2 and AVS 1 and 2, compliance 

schedules, and monitoring, 

recordkeeping, and reporting 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20899 

requirements. For further details 

regarding our rationale, please refer to 

our proposal and our response to 

comments. 

IV. Basis for Our Final Action 

We have fully considered all 

significant comments on our proposal, 

and, except as noted in section III, 

above, have concluded that no other 

changes from our proposal are 

warranted. Our action is based on an 

evaluation of North Dakota’s SIP 

submittals and our FIP against the 

regional haze requirements at 40 CFR 

51.300–51.309 and CAA sections 169A 

and 169B, and against the interstate 

transport requirements concerning 

visibility at CAA section 

110(a)(2)(D)(i)(II). All general SIP 

requirements contained in CAA section 

110, other provisions of the CAA, and 

our regulations applicable to this action 

were also evaluated. The purpose of this 

action is to ensure compliance with 

these requirements. Our authority for 

action on North Dakota’s SIP submittals 

is based on CAA section 110(k). Our 

authority to promulgate our partial FIP 

is based on CAA section 110(c). 

A. Regional Haze 

We are approving most of North 

Dakota’s RH SIP provisions because 

they meet the relevant regional haze 

requirements. Most of the adverse 

comments we received concerning our 

proposed partial approval of the RH SIP 

pertained to North Dakota’s BART and 

reasonable progress determinations. 

With respect to the BART 

determinations that we proposed to 

approve, we understand that there is 

room for disagreement about certain 

aspects of the State’s analyses. 

Furthermore, we may have reached 

different conclusions had we been 

performing the determinations in the 

first instance. However, the comments 

have not convinced us that the State, 

conducting specific case-by-case 

analyses for the relevant units, acted 

unreasonably or that we should be 

disapproving the State’s BART 

determinations that we proposed to 

approve. 

With respect to North Dakota’s 

reasonable progress determinations that 

we proposed to approve, we continue to 

disagree with the manner in which 

North Dakota evaluated visibility 

improvement when it evaluated single 

source controls and have disregarded 

this evaluation in our consideration of 

the reasonableness of North Dakota’s 

reasonable progress control 

determinations. We also disagree with 

some of North Dakota’s legal 

conclusions about the necessity of 

reasonable progress controls for certain 

sources—specifically, for Coyote Station 

for NOX and for Heskett Station 2 for 

sulfur dioxide (SO2). However, in these 

instances, North Dakota nonetheless 

included emission limits in the SIP that 

reflect reasonable levels of control for 

reasonable progress for this initial 

planning period. Here again, we 

understand that there is room for 

disagreement about the State’s analyses 

and appropriate limits. And, again, we 

may have reached different conclusions 

had we been performing the 

determinations. However, the comments 

have not convinced us that the State, 

conducting specific case-by-case 

analyses for the relevant units, made 

unreasonable determinations for this 

initial planning period or that we 

should be disapproving the State’s 

reasonable progress determinations that 

we proposed to approve. 

As noted, we are disapproving North 

Dakota’s NOX BART determination for 

CCS 1 and 2 and its NOX reasonable 

progress determination for AVS 1 and 2 

and promulgating a partial FIP to 

establish the required limits and 

corresponding compliance provisions. 

For CCS 1 and 2, the State relied on 

values for costs of compliance supplied 

by the owner that were admittedly 

erroneous. As explained in detail in our 

response to comments, the comments 

we received have not convinced us that 

our disapproval of the State’s NOX

BART determination for CCS 1 and 2 is 

unreasonable, or that our NOX BART 

FIP determination and limits (as 

modified in this final action) are 

unreasonable. In particular, we 

conclude that GRE’s latest cost estimates 

and cost effectiveness values for SNCR, 

as reflected in its November 2011 

comments, are not based on reasonable 

assumptions and overestimate the costs 

of compliance. Instead, our 

consideration of the five statutory BART 

factors leads us to conclude that SNCR 

plus SOFA plus LNB is BART, with a 

limit of 0.13 lb/MMBtu on a 30-day 

rolling average basis. Also, we continue 

to find that the costs of SCR are not 

reasonable given the projected visibility 

improvement; the comments we 

received on this issue have not 

convinced us otherwise. 

For AVS 1 and 2, consistent with our 

proposal, we are disapproving the 

State’s determination under our 

reasonable progress requirements (40 

CFR 51.308(d)(1)) that no additional 

NOX emissions controls are warranted, 

and we are finalizing a FIP with a 

reasonable progress determination and a 

NOX emission limit for AVS 1 and 2 of 

0.17 lb/MMBtu on a 30-day rolling 

average basis. Nothing in the comments 

has convinced us that the State’s 

determination was reasonable or that 

our proposed FIP was unreasonable. As 

we noted in our proposal, the costs for 

installation and operation of 

combustions controls at AVS 1 and 2 are 

very reasonable ($586 and $661 per ton) 

and the predicted NOX reductions are 

substantial—3,500 tons per unit per 

year. Appropriate single-source 

modeling also indicates that the 

visibility benefits will be substantial— 

0.754 deciviews. Based on these facts, 

and given that North Dakota’s RPGs will 

not meet the uniform rate of progress 

(URP), it was unreasonable for North 

Dakota to reject LNB at AVS 1 and 2. We 

have determined that the State’s 

rejection of this level of control, and the 

corresponding RPGs, are not justifiable 

based on a reasonable consideration of 

the applicable regulatory factors—costs 

of compliance, time necessary for 

compliance, energy and non-air quality 

environmental impacts of compliance, 

and remaining useful life of the source. 

LNB is a modest, widely-used, costefficient means to achieve significant 

NOX reductions, and the resultant 

visibility benefits will be comparable to 

or greater than the benefits achieved 

through selected controls at several 

BART units in North Dakota. We have 

also rejected comments that call for 

more stringent controls at AVS 1 and 2 

in this planning period. While such 

controls may be appropriate in a later 

planning period, we cannot say that the 

State’s rejection of such controls in this 

planning period was unreasonable. For 

further details regarding our rationale, 

please refer to our proposal and our 

response to comments. 

Consistent with our proposal, we are 

approving the remaining elements of 

North Dakota’s RH SIP because such 

elements meet the relevant requirements 

of our regional haze regulations. 

B. Interstate Transport, Visibility Prong 

The basis for this part of our action 

remains unchanged from our proposal. 

Nothing in the comments has convinced 

us that a change from our proposal is 

warranted. North Dakota’s April 6, 2009 

transport submittal contained only a 

cursory reference to CAA section 

110(a)(2)(D)(i)(II)’s requirement for a SIP 

revision that contains adequate 

provisions ‘‘prohibiting any source or 

other type of emission activity within 

the State from emitting any air pollutant 

in amounts which will * * * interfere 

with measures required to be included 

in the applicable implementation plan 

for any other State under part C [of the 

CAA] to protect visibility.’’ Because of 

the impacts on visibility from the 

interstate transport of pollutants, we 

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20900 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

4Some commenters criticized the credibility and 

credentials of one of our sub-contractors. Because 

of their focused nature, we have included a 

response to some of those comments in our docket 

for this action, even though the substance of the 

issues is no longer relevant to our decision. 

interpret the ‘‘good neighbor’’ 

provisions of section 110 of the Act 

described above as requiring states to 

include in their SIPs either measures to 

prohibit emissions that would interfere 

with the RPGs 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. North 

Dakota’s April 6, 2009 submittal 

contains neither. Thus, we are 

disapproving it. To the extent that the 

State intended to meet the requirement 

of section 110(a)(2)(D)(i)(II) with the RH 

SIP, the RH SIP submission itself is not 

fully approvable. 

As required by section 110(c), we are 

promulgating a FIP to satisfy the 

requirements of CAA section 

110(a)(2)(D)(i)(II) concerning visibility 

protection. As explained in section II, 

the FIP relies on the combination of the 

North Dakota RH SIP provisions that we 

are approving and the additions to the 

regional haze program for North Dakota 

that we are promulgating in our FIP for 

NOX BART for CCS 1 and 2 and NOX

reasonable progress for AVS 1 and 2. 

Because this combination exceeds the 

stringency of BART and reasonable 

progress limits that were already 

factored into the Western Regional Air 

Partnership (WRAP) modeling for RPGs, 

this combination meets the visibility 

prong of CAA section 110(a)(2)(D)(i)(II). 

This combination of regional haze 

controls will ensure that emissions from 

sources in North Dakota do not interfere 

with other states’ visibility programs as 

required by section 110(a)(2)(D)(i)(II) of 

the CAA. 

For further details regarding our 

rationale, please refer to our proposal 

and our response to comments. 

V. Issues Raised by Commenters and 

EPA’s Responses 

A. NOX BART for Milton R. Young 

Station Units 1 and 2 and Leland Olds 

Station Unit 2 

As noted in section III of this action, 

in a major change from our proposal, we 

are now approving North Dakota’s NOX

BART determinations for MRYS 1 and 

2 and LOS 2, and we are not proceeding 

with a FIP for NOX BART for these 

units. We explain the basis for this 

change in section III. 

We received numerous comments that 

were specific to the NOX BART 

determinations for MRYS 1 and 2 and 

LOS 2. These related to a variety of 

issues—modeling and visibility 

improvement, costs of compliance, 

technical feasibility, appropriate 

emission limits, and other issues. The 

grounds for our decision to approve 

North Dakota’s NOX BART 

determinations for MRYS 1 and 2 and 

LOS 2 render irrelevant further 

consideration of these issues. 

Essentially, we are approving the State’s 

determination of BART based on a 

federal court’s ruling on our challenge 

to the State’s BACT determination for 

MRYS. In establishing BACT, the State 

established an emission limit based on 

what it considered the maximum degree 

of reduction of NOX, taking into account 

various factors similar to those in a 

BART determination. Thus, while we 

disagree with the vast majority of the 

comments that disputed our technical 

and legal analyses concerning NOX

BART for MRYS 1 and 2 and LOS 2, we 

generally are not summarizing or 

responding to those comments to the 

extent they are specific to the 

assessment of NOX BART for MRYS 1 

and 2 and LOS 2.4 However, we are 

responding to comments that may be 

relevant to other aspects of this action. 

B. Comments on Legal Issues 

1. EPA’s Authority 

Comment: Multiple commenters 

stated that CAA Section 169A and the 

Regional Haze Rule (RHR) give the 

states (North Dakota in this instance) the 

lead in developing their regional haze 

SIPs. Some commenters went further in 

stating that North Dakota is given almost 

complete discretion in creating its RH 

SIP. These commenters argued that, 

because North Dakota is given such 

discretion, EPA lacks the statutory 

authority to disapprove the State’s RH 

SIP. Specifically, some commenters 

pointed to the flexibility the State is 

granted in developing its BART 

determination, RPGs, modeling protocol 

and cost analysis. The State of North 

Dakota, for instance, argued that each 

factor in the five-factor analysis used to 

make its BART determination was 

appropriately weighed based on the 

State’s own discretion. The State 

therefore argues that the EPA has no 

basis on which to disapprove the fivefactor analysis. 

Response: Congress crafted the CAA 

to provide for states to take the lead in 

developing implementation plans, but 

balanced that decision by requiring EPA 

to review the plans to determine 

whether a SIP meets the requirements of 

the CAA. EPA’s review of SIPs is not 

limited to a ministerial type of 

automatic approval of a state’s 

decisions. EPA must consider not only 

whether the State considered the 

appropriate factors but acted reasonably 

in doing so. In undertaking such a 

review, EPA does not ‘‘usurp’’ the 

state’s authority but ensures that such 

authority is reasonably exercised. EPA 

has the authority to issue a FIP either 

when EPA has made a finding that the 

State has failed to timely submit a SIP 

or where EPA has found a SIP deficient. 

Here, EPA has authority on both 

grounds, and we have chosen to 

approve as much of the North Dakota 

SIP as possible and to adopt a FIP only 

to fill the remaining gap. Our action 

today is consistent with the statute. In 

finalizing our proposed determinations, 

we are approving the State’s 

determinations in identifying BART 

eligible sources and largely approving 

the State’s BART determinations for 

seven different emission units subject to 

BART. Also, we are largely approving 

the State’s reasonable progress 

determinations. We are, however, 

disapproving the State’s NOX BART 

determinations for two units—CCS 1 

and 2—and its NOX reasonable progress 

determinations for two units—AVS 1 

and 2. 

The State’s NOX BART 

determinations for CCS 1 and 2 are not 

approvable because North Dakota did 

not properly follow the requirements of 

section 51.308(e)(1)(ii)(A). Specifically, 

North Dakota did not reasonably ‘‘take 

into consideration the costs of 

compliance,’’ when it relied on cost 

estimates that greatly overestimated the 

costs of controls. We have determined 

that the faults in the cost estimates were 

significant enough that they resulted in 

BART determinations for NOX for CCS 

1 and 2 that were both unreasoned and 

unjustified. Accordingly, these 

determinations are not approvable. 

We are disapproving the State’s 

determination that no NOX controls are 

needed at AVS 1 and 2 to achieve 

reasonable progress because the State’s 

determination is not reasonable under 

the relevant statutory and regulatory 

requirements. 

In the absence of approvable NOX

BART determinations in the SIP for CCS 

1 and 2 and in the absence of an 

approvable reasonable progress 

determination concerning NOX controls 

at AVS 1 and 2, we are obliged to 

promulgate a FIP to satisfy the CAA 

requirements. Likewise, in the absence 

of an approvable SIP that addresses the 

requirement that emissions from North 

Dakota sources do not interfere with 

measures required in the SIP of any 

other state to protect visibility, we are 

obliged to promulgate a FIP to address 

the defect. This authority and 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20901 

responsibility exists under CAA section 

110(c)(1). 

We also are required by the terms of 

two separate consent decrees, one in the 

U.S. District Court for the District of 

Colorado and one in the U.S. District 

Court for the Northern District of 

California to ensure that North Dakota’s 

CAA requirements for regional haze and 

for 110(a)(2)(D)(i)(II), respectively, are 

finalized by March 2, 2012. Because we 

have found that the State’s SIP 

submissions do not adequately satisfy 

either requirement in full and because 

we have previously found that North 

Dakota failed to timely submit these SIP 

submissions, we have not only the 

authority, but a duty to promulgate a 

FIP that meets those requirements. 

Our action in large part approves the 

RH SIP submitted by North Dakota. The 

disapproval of the NOX BART and 

reasonable progress determinations and 

imposition of the FIP is not intended to 

encroach on state authority. This action 

is only intended to ensure that CAA 

requirements are satisfied using our 

authority under the CAA. 

Comment: The NDDH commented 

that states are free to deviate from the 

BART guidelines in the preparation of 

their BART analyses, except for power 

plants with a capacity exceeding 750 

megawatts (MW). 

Response: We agree that the BART 

guidelines are only mandatory under 

the regional haze regulations for ‘‘fossilfuel fired power plants having a total 

generating capacity greater than 750 

megawatts.’’ 40 CFR 51.308(e)(1)(ii)(B). 

However, the fact that a state may 

deviate from the guidelines for other 

BART sources does not mean that the 

state has unfettered discretion to act 

unreasonably or inconsistently with the 

CAA and our regulations. Where the 

BART guidelines are not mandatory, a 

state must still meet the requirements of 

the CAA and our regulations. In other 

words, the State must still adopt and 

apply the best available retrofit 

technology, considering the statutory 

factors. 

Our regulations define best available 

retrofit technology to mean ‘‘an 

emission limitation based on the degree 

of reduction achievable through the 

application of the best system of 

continuous emission reduction for each 

pollutant which is emitted by an 

existing stationary facility.’’ 40 CFR 

51.301 (emphasis added). We do not 

consider that this definition can simply 

be dismissed under the mantle of state 

discretion. 

In addition, North Dakota’s own 

regulations, which have been submitted 

for our approval and which we are 

approving with this action, provide as 

follows: 

‘‘33–15–25–03 Guidelines for best available 

retrofit technology determinations under the 

Regional Haze Rule. 

Title 40, Code of Federal Regulations, part 

51, appendix y, as published in the Federal 

Register on July 6, 2005, is incorporated by 

reference into this chapter. The owner or 

operator of a fossil-fuel-fired steam electric 

plant with a generating capacity greater than 

seven hundred fifty megawatts of electricity 

shall comply with the requirements of 

appendix y. All other facility owners or 

operators shall use appendix y as guidance 

for preparing their best available control 

retrofit technology determinations.’’ 

(Emphasis added.) Appendix Y contains 

EPA’s BART guidelines. Our approval of 

this regulation makes it federally 

enforceable. 

North Dakota appears to disavow the 

dictates of its own regulation: 

‘‘EGUs with a capacity of less than 750 

MW * * * are free to deviate from the BART 

Guidelines in the preparation of their BART 

analyses. 

MRYS * * * may use the Guidelines as 

guidance only.’’ 

State of North Dakota’s November 21, 

2011 comments, p. 22 (emphasis 

added). But, the regulation says that 

EGUs less than 750 MW ‘‘shall use’’ 

EPA’s BART guidelines as guidance, not 

that they ‘‘may use’’ them as guidance 

or that they are ‘‘free to deviate’’ from 

them. 

Given that North Dakota’s own 

regulation, which we are making 

federally enforceable with this action, 

requires the use of the BART guidelines 

as guidance for BART analyses, we 

think it reasonable to conclude that any 

deviation from the guidelines must be 

based on a reasonable justification. 

Regardless, the BART guidelines are 

mandatory for CCS, which is the one 

source for which we are disapproving 

the State’s BART determination. 

Comment: North Dakota meets the 

presumptive BART limits for NOX at 

CCS 1 and 2, based on the 2005 BART 

Guidelines. EPA’s rationale for 

disapproving the BART determinations 

at CCS 1 and 2 is therefore flawed and 

contrary to the BART Guidelines. EPA 

appears to be undertaking a national 

effort to change its BART Rule without 

going through notice and comment 

rulemaking to amend or repeal the rule. 

EPA is doing so by ‘‘applying BART 

determinations made for sources in one 

state as a new presumptive limit for all 

states.’’ Commenter cites 76 FR 58623 of 

the proposed rule, where EPA justifies 

a cost/ton ‘‘that states other than North 

Dakota have considered reasonable for 

BART,’’ but is higher than the 

presumptive BART limits. 

Response: We disagree with the 

commenter. First, for each source 

subject to BART, the RHR, at 40 CFR 

51.308(e)(1)(ii)(A), requires that states 

identify the level of control representing 

BART after considering the factors set 

out in CAA section 169A(g), as follows: 

States must identify the best system of 

continuous emission control technology 

for each source subject to BART taking 

into account the technology available, 

the costs of compliance, the energy and 

non-air quality environmental impacts 

of compliance, any pollution control 

equipment in use at the source, the 

remaining useful life of the source, and 

the degree of visibility improvement 

that may be expected from available 

control technology. 70 FR 39158. In 

other words, the presumptive limits do 

not obviate the need to identify the best 

system of continuous emission control 

technology on a case-by-case basis 

considering the five factors. A state may 

not simply ‘‘stop’’ its evaluation of 

potential control levels at the 

presumptive level of control if more 

stringent control technologies or limits 

are technically feasible. We do not read 

the BART guidelines in appendix Y to 

contradict the requirement in our 

regulations to determine ‘‘the degree of 

reduction achievable through the 

application of the best system of 

continuous emission reduction’’ ‘‘on a 

case-by-case basis,’’ considering the five 

factors. 40 CFR 51.301 (definition of 

Best Available Retrofit Technology); 40 

CFR 51.308(e). Also, our interpretation 

is supported by the following language 

in our BART guidelines: 

While these levels may represent current 

control capabilities, we expect that scrubber 

technology will continue to improve and 

control costs continue to decline. You should 

be sure to consider the level of control that 

is currently best achievable at the time that 

you are conducting your BART analysis. 

70 FR 39171. The presumptive limits 

are meaningful as indicating a level of 

control that EPA generally considered 

achievable and cost effective at the time 

it adopted the BART guidelines in 2005, 

but not a value that a state could adopt 

without conducting a five factor 

analysis considering more stringent, 

technically feasible levels of control. 

The commenter focuses on narrow 

passages of the BART guidelines to 

support its view that the presumptive 

limits represent the most stringent 

BART controls that EPA can require for 

regional haze. However, these passages 

must be reconciled with the language of 

the RHR cited above, as well as other 

passages of the BART guidelines and 

associated preamble. A central concept 

expressed in the guidelines is that a 

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state is not required to consider the five 

factors if it has selected the most 

stringent level of control; otherwise, a 

state must fully consider the five factors 

in determining BART. 40 CFR part 51, 

appendix Y, section IV.D.1, step 1.9. 

Undoubtedly, as the commenter notes, 

the presumptive limits for NOX

represent cost effective controls, but it is 

well-understood that limits based on 

combustion controls do not represent 

the most stringent level of control for 

NOX. Thus, a state which selects 

combustion controls and the associated 

presumptive limit for NOX as BART 

may only do so after rejecting more 

stringent control technologies based on 

full consideration of the five factors. 

Our interpretation reasonably reconciles 

the various provisions of our 

regulations. We clearly communicated 

our views on this subject to North 

Dakota while it was developing its RH 

SIP, and, following our interpretation, 

North Dakota conducted an analysis of 

control technologies that would achieve 

a more stringent limit than combustion 

controls. 

While North Dakota conducted a fivefactor analysis to determine BART at 

CCS, its determination was based on 

erroneous values for the costs associated 

with potential loss of fly ash sales due 

to ammonia contamination, something 

the source acknowledged in June of 

2011. 76 FR 58603. A BART 

determination based on substantially 

erroneous cost values does not meet the 

requirements of the CAA or our 

regulations to determine the best system 

of continuous emission control 

technology considering cost and the 

other statutory factors. Because we 

cannot approve the State’s BART 

determination, we are authorized, and 

in this case obligated, to promulgate a 

FIP. 

In promulgating a FIP for CCS, we 

arrived at an emission limit that is more 

stringent than the presumptive limit 

based on consideration of the five 

factors. Contrary to the commenter’s 

suggestion, EPA’s BART guidelines do 

not establish a presumptive cost 

effectiveness level that is a ‘‘safe 

harbor’’ or ‘‘shield’’ for state BART 

determinations, or that EPA, when 

promulgating a FIP, may not exceed in 

determining BART. Once a FIP is 

required, we stand in the state’s shoes. 

In considering the cost factor, it is 

reasonable for us to consider other 

sources of information to inform our 

decision, including the cost values other 

states have considered reasonable. This 

is not EPA establishing a new 

presumptive limit or national rule; it is 

EPA, acting in the state’s shoes, 

conducting a reasonable source-specific 

consideration of cost and the other 

regulatory factors. In addition, although 

not required, we considered cost 

effectiveness values that the State of 

North Dakota had considered to be 

reasonable in reaching its BART 

determinations. See 76 FR 58623 (‘‘It is 

also within the range of values that 

North Dakota considered reasonable in 

its NOX BART determinations * * *’’) 

Comment: EPA has failed to 

articulate, or apply, a SIP review 

standard that preserves state authority 

over BART determinations. EPA can’t 

rely on vague references to the 

overarching purpose of the regional 

haze program to define what’s 

reasonable. The CAA only requires 

consideration of the five statutory 

factors and emission limits that yield a 

reduction in visibility impairment. EPA 

has contradicted prior statements in 

various contexts, such as reports to 

Congress. EPA has provided no 

objective measure to gauge EPA’s 

assessment. EPA’s vague standards 

result in arbitrary and capricious 

decision making. EPA must articulate 

the standard by which it evaluates and 

disapproves a SIP and must support its 

decision with a plausible explanation. 

Response: Our proposal clearly laid 

out the bases for our proposed 

disapproval of the State’s BART and 

reasonable progress determinations, and 

we have relied on the standards 

contained in our regional haze 

regulations and the authority that 

Congress granted us to review and 

determine whether SIPs comply with 

the minimum statutory and regulatory 

requirements. To the extent a cost 

analysis relies on values that are 

inaccurate, a state has not considered 

cost in a reasoned or reasonable fashion. 

To the extent a state has considered 

visibility improvement from potential 

emissions controls in a way that 

substantially understates the 

improvement or does so in a way that 

is not consistent with the CAA, the state 

has not considered visibility 

improvement in a reasoned or 

reasonable fashion. In these 

circumstances, it is reasonable for EPA 

to disapprove the relevant aspects of the 

SIP. In determining SIP adequacy, we 

inevitably exercise our judgment and 

expertise regarding technical issues, and 

it is entirely appropriate that we do so. 

Courts have recognized this necessity 

and deferred to our exercise of 

discretion when reviewing SIPs. See, 

e.g., Connecticut Fund for the Env’t., 

Inc. v. EPA, 696 F.2d 169 (2nd Cir. 

1982); Michigan Dep’t. of Envtl. Quality 

v. Browner, 230 F.3d 181 (6th Cir. 2000); 

Mont. Sulphur & Chem. Co. v. United 

States EPA, 2012 U.S. App. LEXIS 1056 

(9th Cir. Jan. 19, 2012). 

We disagree with the argument that 

we must approve a BART determination 

where the SIP reflects consideration of 

the five factors and the BART selection 

will result in some improvement in 

visibility. We think Congress expected 

more when it required the application of 

‘‘best available retrofit technology.’’ 

While the commenter places great 

emphasis on EPA’s prior statements in 

reports to Congress, these statements 

have no regulatory effect. Also, these 

statements are not as supportive of 

commenter’s position as commenter 

suggests. For example, ‘‘some 

flexibility’’ does not suggest unfettered 

flexibility; a report’s suggestion that a 

cooperative approach would make sense 

does not suggest that EPA will or must 

approve unilateral decision-making by a 

state no matter what. 

Contrary to the commenter’s 

assertion, we have not destroyed the 

State’s primacy. In fact, we have 

approved the vast majority of the State’s 

determinations. We are only rejecting 

the State’s unreasonable analyses and 

decisions. We are authorized to do so. 

Comment: The grounds invoked by 

EPA to disapprove the RH SIP are 

legislative in nature and cannot be 

imposed without advance notice and 

comment rulemaking. EPA’s proposed 

action on North Dakota’s SIP articulates 

a number of grounds not contained in 

CAA section 169A that must be met for 

a SIP to be ‘‘approvable.’’ These 

additional grounds have never been 

defined or promulgated with notice and 

comment rulemaking. For example, 

EPA’s proposed action articulates a two 

pronged test for BART SIP approval: 

first, ‘‘a state must meet the 

requirements of the CAA and our 

regulations for selection of BART’’; and 

second, ‘‘the state’s BART analysis and 

determination must be reasonable in 

light of the overarching purpose of the 

regional haze program.’’ 76 FR 58577. 

The commenter objects to the second 

prong, i.e., that ‘‘the state’s BART 

analysis and determination must be 

reasonable in light of the overarching 

purpose of the regional haze program.’’ 

According to the commenter, this is a 

new ‘‘reasonableness’’ standard that is 

neither defined nor separately set forth 

in the Act. The commenter asserts that 

EPA is proposing to measure a BART 

determination not just against the 

statutory criteria but also against EPA’s 

own subjective view whether the result 

reached is reasonable enough to meet 

the ‘‘overarching goal’’ of the Act. EPA’s 

new subjective reasonable enough 

requirement imposes a new legislative 

standard that either goes beyond or, for 

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the first time, purports to define ‘‘the 

requirements of the Act.’’ This 

empowers EPA to disapprove a state 

BART determination and replace it with 

its own on reasonableness grounds that 

have never been defined or first vetted 

through public notice and comment. 

Response: First, even assuming that 

EPA’s proposed action on the North 

Dakota RH SIP articulated new grounds 

for evaluating a regional haze SIP, the 

proposed action provides the public 

with the opportunity to comment. As 

evidenced by the commenter’s 

submission, the commenter had the 

opportunity to comment on EPA’s 

approach to evaluating the North Dakota 

RH SIP and to identify any concerns 

associated with the statement at issue 

from our proposal and other aspects of 

our action. 

Second, the CAA requires states to 

submit SIPs that contain such measures 

as may be necessary to make reasonable 

progress toward achieving natural 

visibility conditions, including BART. 

The CAA accordingly requires the states 

to submit a regional haze SIP that 

includes BART as one necessary 

measure for achieving natural visibility 

conditions. In view of the statutory 

language, it is hardly a novel idea that 

the reasonableness of the state’s BART 

analysis and determination would be 

evaluated in light of the purpose of the 

regional haze program. In addition, our 

regional haze regulations, at 40 CFR 

51.308(d)(ii), provide that when a state 

has established a RPG that provides for 

a slower rate of improvement in 

visibility than the URP (as has North 

Dakota), the state must demonstrate, 

based on the reasonable progress 

factors—i.e., costs of compliance, time 

necessary for compliance, energy and 

non-air quality environmental impacts 

of compliance, and remaining useful life 

of affected sources—that the rate of 

progress to attain natural visibility 

conditions by 2064 is not reasonable 

and that the progress goal adopted by 

the state is reasonable. 40 CFR 

51.308(d)(iii) provides that, ‘‘in 

determining whether the State’s goal for 

visibility improvement provides for 

reasonable progress towards natural 

visibility conditions, the Administrator 

will evaluate’’ the state’s 

demonstrations under section 

51.308(d)(ii). It is clear that our 

regulations and the CAA require that we 

review the reasonableness of the State’s 

BART determinations in light of the goal 

of achieving natural visibility 

conditions. This approach is also 

inherent in our role as the 

administrative agency empowered to 

review and approve SIPs. Thus, we are 

not establishing a new reasonableness 

standard, as the commenter asserts. 

Comment: EPA established a new 

adequacy criterion when it found that 

North Dakota’s cost analysis did not 

provide a reasonable basis to make a 

NOX BART determination for LOS 2. It 

was illegal for EPA to establish a new 

adequacy criterion without rulemaking. 

Response: While we have decided to 

approve the State’s NOX BART 

determination for LOS 2, this comment 

may be relevant to other aspects of our 

final action. 

Our prior response largely addresses 

this assertion. However, in addition, we 

think the illogic of the commenter’s 

claim is revealed when the potential 

consequences of the commenter’s views 

are examined. The necessary product of 

the commenter’s view is that a state 

could rely on irrational values for any 

of the five factors, and EPA would be 

powerless to disapprove the SIP. We 

reject that view. We are not establishing 

new criteria for approval of a regional 

haze SIP. We are applying the criteria 

and requirements already specified in 

the CAA and our regulations. Cost is 

one of the factors a state must consider 

in determining BART. If North Dakota 

has relied on greatly inflated cost 

estimates in its consideration of the cost 

factor, it has not considered cost in any 

meaningful sense of the word. 

It is also our opinion that the 

commenter, in its effort to put our 

action in a specific legal box—i.e., 

‘‘illegal administrative action’’— 

consistently misrepresents the nature of 

our action. This is a SIP review action, 

and we believe that EPA is not only 

authorized, but required to exercise 

independent technical judgment in 

evaluating the adequacy of the State’s 

RH SIP, including its BART 

determinations, just as EPA must 

exercise such judgment in evaluating 

other SIPs. In evaluating other SIPs, 

EPA is constantly exercising judgment 

about SIP adequacy, not just to meet and 

maintain the NAAQS, but also to meet 

other requirements that do not have a 

numeric value. In this case, Congress 

did not establish NAAQS by which to 

measure visibility improvement; 

instead, it established a reasonable 

progress standard and required that EPA 

assure that such progress be achieved. 

Here, contrary to the commenter’s 

assertion, we are exercising judgment 

within the parameters laid out in the 

CAA and our regulations. Our 

interpretation of our regulations and of 

the CAA, and our technical judgments, 

are entitled to deference. See, e.g., 

Michigan Dep’t. of Envtl. Quality v. 

Browner, 230 F.3d 181 (6th Cir. 2000); 

Connecticut Fund for the Env’t., Inc. v. 

EPA, 696 F.2d 169 (2nd Cir. 1982); 

Voyageurs Nat’l Park Ass’n v. Norton, 

381 F.3d 759 (8th Cir. 2004); Mont. 

Sulphur & Chem. Co. v. United States 

EPA, 2012 U.S. App. LEXIS 1056 (9th 

Cir. Jan. 19, 2012). 

Comment: EPA has no statutory 

authority to disapprove North Dakota’s 

BART determination for LOS 2. CAA 

section 169A(b)(2) leaves that 

determination expressly and exclusively 

in the hands of the State. EPA’s SIP 

approval authority under CAA section 

110 only permits EPA to confirm 

whether the State considered the 

statutory factors; it does not authorize 

EPA to pass judgment on how the State 

considers them. The commenter cites 

the American Corn Growers and UARG 

decisions as support for its comments. 

Nor, according to the commenter, does 

section 110 permit EPA to propose its 

own emission controls. By doing so, 

EPA’s FIP ‘‘run[s] roughshod over the 

procedural prerogatives that the Act has 

reserved to the States’’ (citing 

Bethlehem Steel Corp. v. Gorsuch, 742 

F.2d 1028, 1036 (7th Cir. 1984)). 

Response: While we have decided to 

approve the State’s NOX BART 

determination for LOS 2, this comment 

may be relevant to other aspects of our 

final action. The commenter reads too 

much into the language of 169A. We do 

not agree that the language, ‘‘as 

determined by the State,’’ grants the 

State unlimited discretion or ‘‘sole 

control’’ in making a BART 

determination, any more than the 

accompanying language, ‘‘or the 

Administrator in the case of a plan 

promulgated under section 7410(c) of 

this title,’’ grants EPA unlimited 

discretion in making a BART 

determination in a FIP. 

Instead, while States are assigned the 

primary statutory and regulatory 

authority to determine BART, and have 

significant freedom to determine the 

weight and significance of the statutory 

factors, they have an overriding 

obligation to come to a reasoned 

determination. They may not act 

unreasonably or in an arbitrary and 

capricious fashion, and Congress has 

assigned EPA, as the reviewing agency, 

the role of determining whether a State’s 

BART determination or reasonable 

progress determination is reasonable. 

The commenter’s citations to 

legislative history are unconvincing. 

Among other things, they are 

incomplete. The commenter ignores the 

intent behind the 1977 legislation: 

‘‘The Administrator must promulgate 

regulations which assure attainment of the 

national goal * * * Specifically, the 

regulations must require that States which 

contain mandatory class I areas, and States 

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whose emissions cause or contribute to 

visibility problems in such areas, revise their 

implementation plan to include two 

elements. The first element of the plan 

revision is that the State plan must provide 

for installation of ‘‘best available retrofit 

technology’’ for existing major stationary 

sources which cause or contribute to 

visibility impairment in such areas.’’ 

95 Cong. Conf. Report H. Rept. 564, at 

154. 

Commenters suggest that visibility 

issues are only of state and local 

concern and that is why Congress left 

states with sole control. This is 

inconsistent with the very first sentence 

of the statute: ‘‘Congress hereby declares 

as a national goal the prevention of any 

future, and the remedying of any 

existing, impairment of visibility in 

mandatory class I Federal areas * * *’’ 

CAA section 169A, (emphasis added). It 

is also inconsistent with the legislative 

history, which states: 

‘‘There are certain national lands, 

including national parks, national 

monuments, national recreation areas, 

national primitive areas, and national 

wilderness areas, in which protection of 

clean air quality is obviously a critical 

national concern * * * Indeed, the millions 

of Americans who travel thousands of miles 

each year to visit Yosemite or the Grand 

Canyon or the North Cascades will find little 

enjoyment if, for example, upon reaching the 

Grand Canyon it is difficult if not impossible 

to see across the great chasm. If that were to 

come to pass—and several of our great 

national parks, including the Grand Canyon, 

are threatened today by such a fate—the very 

values which these unique areas were 

established to protect would be irreparably 

diminished, perhaps destroyed.’’ 

95 Cong. House Report 294 at 137. 

Thus, we do not agree that Congress 

assigned us a merely ministerial role; it 

is not evident how such a limited role 

would assure attainment of the national 

goal or the actual imposition of the best 

available retrofit technology where a 

state’s BART determination is 

unreasonable, arbitrary and capricious, 

or not in accordance with the law. 

We also disagree that our proposal is 

inconsistent with the American Corn 

Growers and UARG decisions. These 

cases dealt with EPA’s authority to issue 

generic regulations regarding BART 

determinations. They did not address 

EPA’s authority in reviewing a SIP. 

Contrary to the commenter’s 

assertion, the Bethlehem Steel case is 

inapplicable here. We are promulgating 

BART and reasonable progress limits 

under the authority of CAA section 

110(c), not through our action on North 

Dakota’s SIP. We have authority to 

promulgate our FIP under 110(c) on two 

separate grounds: first, based on our 

January 2009 finding of failure to submit 

the RH SIP; and second, based on our 

partial disapproval of the RH SIP. 

Comment: Commenter stated that EPA 

is incorrect to assert that NDDH did not 

adequately consider all five statutory 

factors for LOS 2. Commenter stated that 

EPA concludes, in its own BART 

evaluation, that SNCR + ASOFA 

(NDDH’s BART selection) is cost 

effective and provides substantial 

visibility benefits. When a state has 

taken into consideration the five 

statutory factors and selected a 

technology that reduces visibility 

impairments, it has complied with the 

statute and EPA must approve the SIP. 

Since EPA’s own FIP analysis proves 

North Dakota’s choice complies with the 

statute, EPA has no basis to disapprove 

it. 

Response: While we have decided to 

approve the State’s NOX BART 

determination for LOS 2, this comment 

may be relevant to other aspects of our 

final action. The commenter cites no 

authority in the CAA or our regulations 

for its assertion that a BART 

determination that considers the five 

statutory factors is adequate as long as 

it provides some reduction in visibility 

impairment. We know of no such 

criterion. Instead, our regulations define 

BART as an emission limitation based 

on the degree of reduction achievable 

through the application of the best 

system of continuous emission 

reduction for each pollutant which is 

emitted by an existing stationary 

facility. The emission limitation must be 

established, on a case-by-case basis, 

taking into consideration the technology 

available, the costs of compliance, the 

energy and non-air quality 

environmental impacts of compliance, 

any pollution control equipment in use 

or in existence at the source, the 

remaining useful life of the source, and 

the degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

Given that the BART limit must reflect 

the ‘‘application of the best system of 

continuous emission reduction,’’ we 

interpret the Act to require a reasonable 

consideration of the five factors, one 

that is not arbitrary and capricious. 

Comment: EPA’s effort to impose 

BART determinations by federal 

rulemaking impermissibly deprives 

source owners of the substantive 

procedural rights they are otherwise 

afforded under State law. The 

commenter notes that the State used a 

permit process to establish BART limits, 

and that a similar source-by-source 

adjudication of such limits must be 

provided by EPA. The commenter also 

asserts that EPA must allow for 

examination and cross-examination of 

witnesses, and that, otherwise, the 

process is not consistent with due 

process. 

Response: While the State has chosen 

to use the permit process to establish 

BART limits for individual sources, 

there is nothing in the CAA or our 

regulations that requires states or EPA to 

use permits or a source-by-source 

adjudicatory proceeding to establish 

BART limits. Both the CAA and our 

regulations require that BART limits be 

contained in a SIP. In the absence of an 

approvable SIP, CAA section 110(c) 

requires us to issue a FIP. We have 

issued a partial FIP pursuant to CAA 

section 307. CAA section 307 provides 

that its provisions apply in lieu of the 

Administrative Procedure Act (APA). 

The procedures provided by CAA 

section 307 are adequate to ensure due 

process to source owners. We have 

provided a substantial opportunity for 

comment (a two-month long comment 

period) and an extensive public hearing 

that lasted 14 hours over two days. The 

commenter submitted over 140 pages of 

comments with several attachments, 

and other commenters submitted 

comments of similar length. It is not 

unusual for FIPs to include sourcespecific limits and requirements. An 

opportunity for examination and crossexamination of witnesses is not required 

by the CAA, nor is it required to ensure 

due process. Individuals and entities 

affected by EPA’s action have had ample 

opportunity to challenge EPA’s 

conclusions. 

Comment: Sole control over BART 

determinations for EGUs under 750 MW 

is left to the states. Congressional intent 

to exclude federal involvement in BART 

determinations for smaller generating 

stations is apparent from the plain text 

of the statute and is binding on EPA. 

EPA may not disapprove a state BART 

determination for an EGU the size of 

Leland Olds. 

Response: EPA disagrees with the 

suggestion that Congress intended to 

totally remove EPA from review of 

BART determinations for EGUs less 

than 750 MW. The statute merely says 

that for EGUs greater than 750 MW, 

BART must be determined in 

accordance with guidelines 

promulgated by EPA. That does not 

obviate the need for the State to select 

BART, after considering the five 

statutory factors. And, it does not 

remove EPA’s review role over SIP 

submittals. 

Comment: North Dakota has the 

authority under the RHR to review the 

new updated cost analyses provided by 

URS and Golder Associates on behalf of 

GRE. 

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Response: Our action does not 

prevent North Dakota from reviewing 

GRE’s updated cost analyses, or from 

submitting a revised SIP. States always 

have the freedom to submit SIP 

revisions to EPA. We need not speculate 

in this action whether such a revision 

would be approvable. However, such a 

SIP revision is not the subject of this 

action, and we are neither obligated nor 

authorized to wait for such a revision 

before we finalize our proposed action. 

To the contrary, we have already 

exceeded the statutory deadline for 

promulgating a FIP or approving a SIP 

for regional haze, and, under two 

separate consent decrees, we must 

finalize this action by March 2, 2012. 

GRE acknowledged in a June 2011 

email that it had made errors in its 

original cost estimates for NOX BART 

for CCS. The State relied on those 

erroneous cost figures in its NOX BART 

analysis and determination for CCS in 

its RH SIP that it submitted on March 

3, 2010. This is the main RH SIP 

submittal that we are acting on today. 

Because of the magnitude of these 

acknowledged errors, it is appropriate to 

disapprove the BART determination for 

CCS 1 and 2 that is contained in the 

March 3, 2010 submittal. We explain in 

response to a prior comment why 

selection of the presumptive limits 

without a valid case-specific analysis 

supporting such limits as BART is not 

sufficient to meet the requirements of 

the regional haze regulations. Based on 

our disapproval of the SIP, and on 

separate grounds related to our January 

2009 finding of failure to submit, we are 

authorized and obligated to promulgate 

a FIP for NOX BART for CCS 1 and 2. 

CAA section 110(c). We have 

considered GRE’s revised cost analyses 

in the context of our proposed FIP and 

address those analyses in a subsequent 

response. 

Comment: Commenter stated that 

EPA’s action is in violation of the 10th 

amendment to the Constitution. 

Response: Our action does not compel 

North Dakota to enforce federal law and 

does not intrude on authority reserved 

to the states. Thus, our action is 

consistent with the 10th amendment to 

the Constitution. 

Comment: Commenter stated that 

EPA’s action is in violation of Article 4 

of the Constitution. 

Response: The comment does not 

specify which aspect of Article 4 we are 

alleged to have violated. However, we 

conclude that our action does not 

violate any aspect of Article 4 of the 

Constitution. 

Comment: Commenter stated that 

Federal Land Managers (FLMs) are 

using their Air Quality Related Values 

Workgroup (FLAG) report, a guidance 

document, in highly inappropriate 

ways. 

Response: This comment appears to 

relate to how the FLMs respond to 

proposed PSD permits rather than EPA’s 

proposed actions here. Accordingly, we 

are not responding to the substance of 

this comment. Contrary to the 

commenter’s assertion, we do not 

consider our own actions to be 

inflexible. We note that we are 

approving the great majority of the 

State’s BART and reasonable progress 

determinations. 

2. Interstate Transport Consent Decree 

Comment: Commenter states that EPA 

wrongly uses the Interstate Transport 

consent decree to justify action by the 

September 1, 2011 deadline. Commenter 

claims that EPA separately 

acknowledged that the Interstate 

Transport consent decree never 

addressed the regional haze plan. North 

Dakota has sought leave of the court that 

issued the consent decree to intervene 

in the case. North Dakota is also seeking 

a declaration from the Court that EPA is 

exceeding its authority under that 

consent decree to use it for justification 

of the regional haze proposal. 

Response: The United States District 

Court for the Northern District of 

California rejected the commenter’s 

arguments in an order dated December 

27, 2011. We agree that the transport 

consent decree does not address the 

regional haze plan. However, as the 

court in California recognized, we made 

an appropriate administrative decision 

to address the CAA’s transport 

requirements and regional haze 

requirements in the same action. Given 

that we faced a September 1, 2011 

deadline for our proposed transport 

action under the transport consent 

decree, and faced an uncertain deadline 

for proposed action and a January 26, 

2011 deadline for final action under the 

then-lodged regional haze consent 

decree, we acted in a prudent and 

reasonable fashion to sign our notice of 

proposed rulemaking by the September 

1, 2011 deadline in the transport 

consent decree. 

Comment: North Dakota’s Interstate 

Transport SIP, specifically the 

‘‘visibility’’ element of CAA Section 

110(A)(2)(D)(i)(II), must be approved. 

North Dakota commented that EPA had 

no reason not to act on the visibility 

portion of the State’s interstate transport 

SIP submission according to EPA’s 2006 

guidance. Another commenter stated 

that the EPA ‘‘admits’’ in the Proposed 

North Dakota RH SIP/FIP that the State 

met the sole obligation of Section 

110(A)(2)(D)(i)(II), and that the EPA’s 

reasons for disapproval therefore lack 

basis. 

Response: We fully explained the 

basis for our proposed disapproval of 

North Dakota’s interstate transport SIP 

in our proposal. See 76 FR 58641– 

58642. We have fully considered the 

comments, but nothing in the comments 

has caused us to change our views. As 

we explained in our proposal, our 2006 

guidance was premised on a certain set 

of assumptions—in particular, that 

states would submit their regional haze 

SIPs by the regulatory deadline and that 

the regional haze SIPs would be the 

appropriate means for states to establish 

that their SIPs contained adequate 

provisions to prevent interference with 

the visibility programs required in other 

states. It turned out we were mistaken 

in our assumptions, and we explained 

in our proposal that subsequent events 

have rendered our 2006 guidance 

inappropriate in this specific action. 

Thus, we appropriately and reasonably 

evaluated the State’s interstate transport 

SIP against the statutory requirements 

and found it deficient. The State 

disagrees with the way in which we 

characterized the State’s transport SIP in 

our proposal at 76 FR 58574, but we 

were clear in our discussion later in our 

notice that ‘‘North Dakota did not 

explicitly state in its April 6, 2009, 

submittal that it intended that its 

Regional Haze SIP be used to satisfy the 

visibility prong * * *’’ 76 FR 58641. 

Basin Electric misrepresents our 

proposed action. While we indicated 

that the State had not explicitly 

indicated that it was submitting the RH 

SIP to meet the interstate transport 

requirements, which left us in an 

uncertain position, that was not the only 

basis for our conclusion that the RH SIP 

did not meet the transport requirements. 

Instead, we stated, ‘‘Most importantly, 

however, EPA must review the April 6, 

2009 submission in light of the current 

facts and circumstances, and the RH SIP 

revision that the State ultimately 

submitted does not fully meet the 

substantive requirements of the regional 

haze program * * * To the extent that 

the State intended to meet the 

requirement of section 110(a)(2)(D)(i)(II) 

with the RH SIP, the RH SIP submission 

itself is not fully approvable.’’ 76 FR 

58642. 

The State and Basin Electric assert 

that we should approve the RH SIP as 

satisfying the transport requirements 

even though we are disapproving the 

SIP as meeting regional haze 

requirements. We disagree. Under the 

suggested approach, EPA would 

simultaneously codify in the Code of 

Federal Regulations disparate and 

conflicting requirements—the SIP limits 

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and associated requirements (or in the 

case of AVS, the lack thereof) for certain 

EGUs and the FIP limits and associated 

requirements for those same EGUs. This 

could lead to confusion regarding the 

requirements applicable to the 

industrial sources affected, including 

confusion in enforcement actions. 

Accordingly, we have decided to 

finalize our proposed disapproval of 

North Dakota’s interstate transport SIP. 

Comment: The NDDH commented 

that EPA has not provided any credible 

evidence that the additional emission 

reductions from the FIP will produce 

any discernible visibility improvement 

in out-of-state Class I areas and has not 

provided any credible evidence that 

these additional emission reductions are 

necessary to prevent North Dakota 

sources from interfering with another 

state’s ability to protect visibility. 

Response: In our proposal, we did not 

claim that our FIP to address the 

requirements of CAA section 

110(a)(2)(D)(i)(II) would result in 

visibility improvement in out-of-state 

areas. We did not have the time or 

resources to re-do the WRAP modeling 

that states in the region had relied on in 

assessing the impacts of emissions 

reductions and in setting their RPGs. 

Instead, we noted that the emission 

limits in our proposed FIP to address 

certain deficiencies in the State’s BART 

and reasonable progress measures in its 

RH SIP would exceed the emissions 

reductions for BART and reasonable 

progress for these sources that had been 

factored into the WRAP modeling for 

RPGs. As a result, we concluded that the 

limits in the FIP, in combination with 

the measures in the SIP that we had 

proposed to approve, would satisfy the 

interstate transport requirements for 

visibility. We continue to find that this 

is a reasonable conclusion. Although 

there may be other acceptable 

approaches to satisfying the 

requirements of CAA section 

110(a)(2)(D)(i)(II) that would require 

additional visibility modeling, the 

approach that we have adopted does not 

require that we assess through modeling 

the visibility improvement that will 

result from our FIP to assure that North 

Dakota’s emissions do not interfere with 

measures required in the plans of other 

states to protect visibility. 

3. Other General Legal Comments 

Comment: Some commenters stated 

that EPA cannot promulgate a FIP until 

it has taken final action on the related 

SIP. 

Response: We have the authority to 

promulgate a FIP concurrently with a 

disapproval action. As has been noted 

in past FIP promulgation actions, if EPA 

‘‘finds that a State has failed to make a 

required submission * * * or * * * 

disapproves a [SIP] in whole or in part,’’ 

CAA Section 110(c)(1) establishes a twoyear period within which we must 

promulgate a FIP, and provides no 

further constraints on timing. See, e.g., 

76 FR 25178, at 25202. North Dakota 

failed to submit its RH SIP to us by 

December 2007, as required by 

Congress. Two years later, North Dakota 

had still not submitted its RH SIP. When 

we made a finding in 2009 that North 

Dakota had failed to submit its RH SIP, 

(see 74 FR 2392), that created an 

obligation for us to promulgate a FIP by 

January 2011. We are promulgating the 

FIP concurrently with our disapproval 

action because of the applicable 

statutory deadlines requiring us at this 

time to promulgate regional haze BART 

determinations and reasonable progress 

(RP) determinations to the extent North 

Dakota’s BART and RP determinations 

are not approvable. 

We also note that North Dakota made 

this same argument to the U.S. District 

Court for the District of Colorado—in a 

motion opposing entry of a consent 

decree containing deadlines for EPA to 

promulgate a FIP for regional haze for 

North Dakota and in comments on the 

proposed consent decree. The court 

rejected North Dakota’s argument. First, 

the court noted that we had proposed 

action on North Dakota’s SIP in our 

September 1, 2011 proposal and we 

were, therefore, not proposing to take 

final action on the regional haze FIP 

before making a determination on North 

Dakota’s SIP revision. Second, the court 

indicated that we would be authorized 

to promulgate the regional haze FIP 

even without taking final action on 

North Dakota’s SIP. As we had argued, 

the court found that the duty to 

promulgate a FIP (triggered by our 2009 

finding of failure to submit an RH SIP) 

remains ‘‘unless the State corrects the 

deficiency, and the Administrator 

approves the plan or plan revision, 

before the Administrator promulgates 

such [FIP].’’ Order Entering Consent 

Decree, WildEarth Guardians v. Jackson, 

Civil Action No. 11–cv–00001–CMA– 

MEH, USDC Colorado, p. 17, citing CAA 

section 110(c) (emphasis and brackets 

added by the court). 

Comment: Commenter stated that EPA 

must review the ‘‘blanket five year 

compliance date’’ to install and operate 

BART to ensure that it is as expeditious 

as practicable, as required by the CAA. 

Response: We have reviewed the 

compliance dates for meeting BART 

limits that are contained in the portions 

of the SIP we are approving and in the 

FIP we are promulgating. These dates 

are reasonable given the magnitude of 

the retrofits being undertaken. We note 

that the State permits that we are 

approving as part of this action provide 

for compliance as expeditiously as 

practicable, but in no event later than 

five years. 

C. Comments on Modeling 

Comment: Several commenters 

questioned aspects of the single-source 

CALPUFF modeling that North Dakota 

included in the SIP and which EPA 

relied upon in our evaluation of 

visibility impacts. Among other things, 

commenters questioned (1) Whether 

CALPUFF overestimates nitrate 

formation, (2) whether newer versions 

of CALPUFF would give more accurate 

results, (3) the method for establishing 

natural visibility background, (4) how to 

establish ammonia background 

concentrations, and (5) the method for 

interpreting model results as they relate 

to visibility improvement. The 

commenters submitted revised singlesource CALPUFF modeling results to 

address what they believed to be 

deficiencies in the single-source 

CALPUFF modeling that North Dakota 

included in the SIP. 

Response: While each of these 

comments is addressed separately in 

detailed responses below, a general 

response is warranted. We note that 

many of these comments were 

submitted by Minnkota and Basin 

Electric and were directed specifically 

to EPA’s proposal regarding SCR at 

MRYS 1 and 2 and LOS 2. As we have 

explained, such comments are not 

relevant to our final action. Nonetheless, 

we are responding to most of the 

comments in the event that they could 

be interpreted as having broader 

application to the assessment of 

visibility improvement from potential 

control options. 

The second point we note is that the 

source owners are essentially 

questioning modeling that they 

conducted and submitted to the State as 

part of their BART evaluations, and that 

the State specifically called for and 

included in the SIP. The State 

established procedures for single-source 

BART modeling used to support its SIP 

in the ‘‘Protocol for BART-Related 

Visibility Impairment Modeling 

Analyses in North Dakota’’ (the BART 

modeling protocol). North Dakota RH 

SIP, Appendix A.1. North Dakota 

intended for the protocol to apply to 

‘‘visibility modeling for both 

identification of sources ‘subject to 

BART’ (i.e., BART screening), and for 

determining the degree of visibility 

improvement related to the selection of 

BART controls.’’ North Dakota RH SIP, 

Appendix A.1, p. 1. In fact, North 

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5There is one aspect of the protocol that does not 

conform to the BART guidelines—North Dakota’s 

inclusion of the 90th percentile modeling results in 

addition to the 98th percentile. The use of the 90th 

percentile modeling results is not consistent with 

the CAA. 70 FR 39121. We provide more detail 

about the deficiency in the use of the 90th 

percentile value in subsequent responses. 

Dakota specifically stated: ‘‘[A]ll BARTrelated single-source modeling for 

sources in North Dakota must follow the 

protocol outlined here. Because of this 

requirement, the NDDH will not expect 

companies which operate BART-eligible 

sources to provide individual protocols 

for their BART-related modeling.’’ Id., p. 

3. North Dakota’s protocol conforms to 

the BART Guidelines.5 It also follows 

recommendations for modeling long 

range transport contained in 40 CFR 

part 51, appendix W (‘‘The Guideline on 

Air Quality Models’’) and EPA’s 

Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary 

Report and Recommendations for 

Modeling Long Range Transport 

Impacts. Furthermore, as discussed in 

Section 3 of the SIP, Plan Development 

and Consultation, the protocol was 

developed in consultation with EPA and 

FLM meteorologists. Adherence to the 

protocol ensures that a consistent 

comparison of visibility improvement 

can be made for potential control 

technologies across different individual 

units and different pollutants. 

As the State’s single-source BART 

modeling followed established guidance 

and was developed in consultation with 

FLMs and EPA, we find that it provides 

a reasonable basis for making control 

technology determinations. We do not 

agree with the sources’ attempt to 

deviate from the established protocol for 

assessing visibility impacts. This is 

because it would lead to a less 

consistent and rational assessment of 

potential control options. Nonetheless, 

we have considered the revised singlesource modeling and the comments 

submitted by the commenters in making 

our final action. We conclude that 

nothing contained in their modeling 

analysis undermines the single-source 

modeling that North Dakota included in 

the SIP. 

Comment: Two commenters stated 

that the receptor-specific approach to 

identifying the 98th percentile result in 

CALPUFF is more technically correct 

than the default day-specific approach. 

The commenters also supplied revised 

CALPUFF modeling based on the 

receptor-specific approach. These 

modeling results suggest that controls 

would achieve less visibility 

improvement than indicated by North 

Dakota’s single-source BART modeling. 

Response: We do not agree that the 

receptor-specific approach is more 

technically correct; it is not part of the 

standard CALPUFF model and merely 

serves to decrease the conservatism of 

the model predictions through the 

creation of 98th percentile values that 

are specific to specific receptor 

locations within a Class I area. The 

standard CALPUFF approach considers 

the daily impacts within a Class I area 

at all receptor points; i.e., the model 

predicts the highest daily value for each 

day of the year from all receptors within 

a Class I area. The 98th percentile 

reflects the eighth highest of these daily 

values. 

In its BART modeling protocol, North 

Dakota stated that ‘‘the context of the 

98th percentile 24-hour delta-deciview 

prediction is with respect to days of the 

year, and is not receptor specific.’’ RH 

SIP, Appendix A.1, Section 4.0, p. 50. 

In addition, in establishing the 98th 

percentile as a reasonable contribution 

threshold in the BART Guidelines, EPA 

intended that the day-specific, or ‘‘dayby-day,’’ approach be used. 70 FR 

39121. This was the approach EPA 

considered appropriate to account for 

the assumptions and uncertainties in 

CALPUFF; the receptor-specific 

approach goes beyond what EPA 

considers appropriate to address these 

assumptions and uncertainties and 

would undermine the goal of achieving 

natural visibility conditions. Therefore, 

we do not consider the revised 

CALPUFF modeling results based on the 

flawed receptor-specific approach that 

were submitted by the commenters to be 

useful in assessing visibility impacts.. 

Comment: Several of the commenters 

argue that it is inappropriate to evaluate 

visibility impacts in comparison to 

natural background visibility 

conditions. Instead, the commenters 

propose to evaluate visibility impacts in 

comparison to current, degraded 

visibility conditions. The commenters 

further argue that EPA’s use of natural 

conditions is inconsistent with section 

169A of the CAA and that EPA should 

amend its BART Guidelines to use 

current, degraded visibility conditions. 

Response: We disagree. EPA’s 

approach is consistent with Congress’s 

intent in passing section 169A, and the 

proposal to use degraded visibility 

conditions is inconsistent with section 

169A. Visibility impacts must always be 

evaluated relative to some reference 

visibility condition, and a given 

reduction in ambient PM2.5 will result in 

smaller relative improvement in 

visibility when compared to polluted 

conditions versus clean conditions. 

Because current degraded visibility 

conditions are considerably worse than 

natural background visibility, 

comparison of a BART source’s impact 

relative to current degraded visibility 

conditions would result in a smaller 

relative benefit than would a 

comparison relative to natural 

background visibility. EPA previously 

considered and responded to the same 

comment in 40 CFR part 51, appendix 

Y, promulgated at 70 FR 39104, July 6, 

2005. After receiving this comment on 

the BART Guidelines, EPA considered 

the approach of assessing a BARTeligible source’s impacts on visibility by 

using current or near-term future 

conditions, and EPA determined that 

BART visibility impacts should be 

evaluated in comparison to natural 

background visibility. In the final 

rulemaking EPA wrote (70 FR 39124): 

‘‘Using existing conditions as the baseline 

for single source visibility impact 

determinations would create the following 

paradox: the dirtier the existing air, the less 

likely it would be that any control is 

required. This is true because of the 

nonlinear nature of visibility impairment. In 

other words, as a Class I area becomes more 

polluted, any individual source’s 

contribution to changes in impairment 

becomes geometrically less. Therefore the 

more polluted the Class I area would become, 

the less control would seem to be needed 

from an individual source. We agree that this 

kind of calculation would essentially raise 

the ‘‘cause or contribute’’ applicability 

threshold to a level that would never allow 

enough emission control to significantly 

improve visibility. Such a reading would 

render the visibility provisions meaningless, 

as EPA and the States would be prevented 

from assuring ‘‘reasonable progress’’ and 

fulfilling the statutorily-defined goals of the 

visibility program. Conversely, measuring 

improvement against clean conditions would 

ensure reasonable progress toward those 

clean conditions.’’ 

See, also, Memorandum from Gail 

Tonnesen, Regional Modeler, to North 

Dakota Regional Haze File, dated 

September 1, 2011, regarding ‘‘Modeling 

Single Source Visibility Impacts.’’ This 

memorandum is included in Appendix 

B of the Technical Support Document 

(TSD) for this action. 

Comment: Two commenters 

performed new CALPUFF simulations 

using EPA’s current regulatory version 

5.881 and submitted these modeling 

results to EPA during the comment 

period. The commenters found lower 

visibility impacts using CALPUFF 

version 5.8 than did the State with an 

earlier CALPUFF version 5.711a. 

Response: For these new model 

results, the commenters did not submit 

a modeling protocol for EPA review and 

did not provide a complete copy of the 

CALPUFF input and output files. As a 

result, EPA was not able to fully review 

the data sets used in this modeling. 

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6Anderson, B., K. Baker, R. Morris, C. Emery, A. 

Hawkins, E. Snyder ‘‘Proof-of-Concept Evaluation 

of Use of Photochemical Grid Model Source 

Apportionment Techniques for Prevention of 

Significant Deterioration of Air Quality Analysis 

Requirements’’ Community Modeling and Analysis 

System (CMAS) 2010 Annual Conference, October 

11–15, 2010, Research Triangle Park, NC. http:// 

www.cmascenter.org/conference/2010/agenda.cfm. 

Moreover, while EPA did approve the 

use of the Rapid Update Cycle 

meteorology for modeling the Heskett 

facility, EPA has not approved this 

alternate modeling protocol for other 

BART sources in North Dakota and has 

not reviewed or approved other 

modifications to the modeling approach 

that the commenters used in developing 

new CALPUFF results. 

From the information that the 

commenters provided, EPA determined 

that the differences in the new 

CALPUFF version 5.8 modeling results 

are due in part to a change in the natural 

background visibility that was used in 

the modeling analysis. The State’s 

modeling protocol called for use of the 

20% best natural visibility days in its 

BART analysis while the commenters’ 

new CALPUFF version 5.8 analysis used 

the annual average natural visibility 

days. If the commenters had adopted the 

same approach as North Dakota and 

compared CALPUFF version 5.8 

visibility impacts to the 20% best 

natural visibility days, the results of the 

new analysis would have been more 

similar to the original modeling 

performed by North Dakota. 

We do not find that the commenters’ 

new modeling demonstrates that singlesource modeling performed according to 

North Dakota’s BART modeling protocol 

should be disregarded. That modeling 

was conducted using the latest version 

of CALPUFF that was available at the 

time, and we are approving the great 

majority of North Dakota’s BART 

determinations that relied on results 

from that modeling. In our FIP, in which 

we are merely filling gaps in the SIP, we 

are not required to conduct new 

modeling using CALPUFF version 5.8 or 

disregard the results of the modeling 

conducted using CALPUFF version 

5.711a. In fact, we find the better course 

is to rely on modeling based on the 

same version of the model that the State 

employed to ensure we are using a 

consistent comparison. See, Mont. 

Sulphur & Chem. Co. v. United States 

EPA, 2012 U.S. App. LEXIS 1056 (9th 

Cir. Jan. 19, 2012). 

Comment: The commenters argue that 

CALPUFF overstates visibility impact 

due to the complexity of the chemistry 

affecting visibility impairment and that 

EPA acknowledges that ‘‘the simplified 

chemistry in the [CALPUFF] model 

tends to magnify the actual visibility 

effects of [a] source.’’ 70 FR 39121. The 

commenters further state that when EPA 

adopted the BART Guidelines, EPA 

concurred with ‘‘the concerns of 

commenters that the chemistry modules 

of the CALPUFF model are less 

advanced than some of the more recent 

atmospheric chemistry simulations.’’ Id. 

at 39123. The commenters also assert 

that several published papers or 

presentations show that CALPUFF over 

predicts nitrate by a factor of 2 to 4 in 

the winter. 

Response: For the reasons already 

stated, EPA’s reliance on the CALPUFF 

modeling results that the State included 

in the SIP is reasonable. In addition, 

EPA has acknowledged that the 

simplified chemistry used in the 

CALPUFF model creates uncertainty in 

the accuracy of the model for predicting 

visibility impacts for pollutants such as 

NOX that are converted from the gas 

phase to aerosol through complex 

photochemical reactions. However, it is 

uncertain whether the simplified 

chemistry will always overpredict 

visibility impacts. For example, 

Anderson et al. (2010) 6 found that the 

CALPUFF model frequently predicted 

lower nitrate concentrations compared 

to the Comprehensive Air Quality 

Model (CAMx) photochemical grid 

model, which has a much more rigorous 

treatment of photochemical reactions. 

EPA recognized the uncertainty in the 

CALPUFF modeling results, and EPA 

made the decision in the final BART 

guidelines that the model should be 

used to estimate the 98th percentile 

visibility impairment rather than the 

highest daily impact value as proposed. 

70 FR 39121. We made the decision to 

consider the less conservative 98th 

percentile (i.e., the eighth highest 24- 

hour deciview impact in a year rather 

than the highest) primarily because the 

chemistry modules in the CALPUFF 

model are simplified and might in some 

cases predict a maximum 24-hour 

impact that is an ‘‘outlier.’’ Id. If recent 

updates to CALPUFF cause the model to 

predict lower visibility impacts, the use 

of the updated model might also require 

EPA to reconsider the choice of the less 

conservative 98th percentile for 

evaluating visibility impacts. In any 

event, our reliance on CALPUFF 

modeling is reasonable for the reasons 

discussed above. 

Comment: Several commenters 

suggested that the State has unlimited 

discretion to consider visibility or cost 

or other factors in any way it wishes, 

even in ways that are inaccurate or 

inconsistent with the purpose of the 

CAA. 

Response: We disagree. We have 

already largely addressed the assertions 

in this comment in our responses to 

comments on our legal authority. 

Furthermore, as a hypothetical example, 

EPA would not defer to a state 

determination that the remaining useful 

life of a source is one year if relevant 

evidence indicates the remaining useful 

life is 20 years. Limits on state 

discretion are inherent in the CAA and 

our regulations; otherwise, states would 

be free to reach decisions that are 

arbitrary and capricious or inconsistent 

with the purpose behind the CAA and 

EPA’s regulations. As we have stated, 

North Dakota’s cumulative modeling 

approach thwarts the goal stated by 

Congress in CAA section 169A and 

underlying the RHR. 

Comment: One commenter claimed 

that pictorial examples demonstrate that 

the visibility benefits which EPA claims 

can be achieved with NOX control 

technologies are not perceptible. The 

commenter compares archived pictures 

copied from the National Park Service 

(NPS) Web site, along with the 

monitored haze index, for days having 

varying levels of visibility impairment. 

For example, the commenter compares 

two pictures from different days for 

which the haze index changes by 1.26 

deciviews and concludes that ‘‘no 

perceptible difference can be seen 

* * *’’ 

Response: We do not expect that a 1.0 

deciview change in visibility, which is 

considered a ‘‘small but noticeable 

change in haziness under most 

circumstances’’ (64 FR 35725), could be 

easily perceived in a small picture on 

the printed page. Moreover, North 

Dakota did not provide visibility 

improvement relative to a pre-control 

baseline as recommended by the BART 

guideline (70 FR 39170), so many of the 

estimates of visibility improvement 

contained in the SIP are misleadingly 

low. Regardless, the BART Guidelines 

establish that predicted visibility 

improvement below perceptibility 

thresholds does not provide a basis to 

automatically eliminate a control 

option: ‘‘Even though the visibility 

improvement from an individual source 

may not be perceptible, it should still be 

considered in setting BART because the 

contribution to haze may be significant 

relative to other source contributions in 

the Class I area. Thus, we disagree that 

the degree of improvement should be 

contingent upon perceptibility. Failing 

to consider less-than-perceptible 

contributions to visibility impairment 

would ignore the CAA’s intent to have 

BART requirements apply to sources 

that contribute to, as well as cause, such 

impairment.’’ 70 FR 39129. The 

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7 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, U.S. 

Environmental Protection Agency, September 2003. 

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

rh_envcurhr_gd.pdf, page 1–1: ‘‘Natural visibility 

conditions represent the long-term degree of 

visibility that is estimated to exist in a given 

mandatory Federal Class I area in the absence of 

human-caused impairment. It is recognized that 

natural visibility conditions are not constant, but 

rather they vary with changing natural processes 

(e.g., windblown dust, fire, volcanic activity, 

biogenic emissions). Specific natural events can 

lead to high short-term concentrations of particulate 

matter and its precursors. However, for the purpose 

of this guidance and implementation of the regional 

haze program, natural visibility conditions 

represents a long-term average condition analogous 

to the 5-year average best- and worst-day conditions 

that are tracked under the regional haze program.’’ 

8 Guidance for Estimating Natural Visibility 

Conditions * * *: ‘‘The preamble further stated 

that ‘with each subsequent SIP revision, the 

estimates of natural conditions for each mandatory 

Federal Class I area may be reviewed and revised 

as appropriate as the technical basis for estimates 

of natural conditions improve.’ ’’ 

9Natural Haze Levels II Committee Report. 

10Settlement Agreement in Utility Air Regulatory 

Group v. EPA, Case No. 06–1056 in the United 

States Court of Appeals for the District of Columbia 

Circuit, April 19, 2006. 

11Tonnesen, G., Omary, M., Wang, Z., Jung, C.J., 

Morris, R., Mansell, G., Jia, Y., Wang, B., Adelman, 

Z., 2006. Report for the Western Regional Air 

Partnership Regional Modeling Center. University 

of California Riverside, Riverside, California, 

November. http://pah.cert.ucr.edu/aqm/308/ 

reports/final/2006/WRAPRMC_2006_report_FINAL.pdf. 

12 Koo, B.; Chien, C.J.; Tonnesen, G.; Morris, R.; 

Johnson, J.; Sakulyanontvittaya, T.; Piyachaturawat, 

P.; Yarwood, G.; Natural emissions for regional 

modeling of background ozone and particulate 

matter and impacts on emissions control strategies, 

Atmos. Env., 44:19, 2372–2382. 

importance of visibility impacts below 

the thresholds of perceptibility cannot 

be ignored given that regional haze (as 

contrasted with reasonably attributable 

visibility impairment) is a problem that 

is produced by a multitude of sources 

and activities which are located across 

a broad geographic area. 

Comment: Commenter states that it 

takes a larger change in pollutant 

emissions to cause a perceptible 

visibility change when the change is 

measured against current degraded 

visibility conditions rather than 

‘‘natural’’ visibility conditions. 

Visibility benefits estimated relative to 

natural background will ‘‘tend to be five 

to seven times larger’’ than the benefits 

estimated relative to current degraded 

visibility. Therefore, using the natural 

background conditions overstates the 

visibility improvement that would be 

achieved by controls at the time of 

installation. 

Response: As noted in our responses 

to other similar comments, it is 

precisely this effect that leads us to 

conclude that the only approach 

consistent with the statutory and 

regulatory goals when considering 

visibility improvement associated with 

potential single-source control options 

is to use natural background values in 

the model. The goal is reasonable 

progress, not stasis. 

Comment: One commenter argues that 

the natural background specified by 

EPA significantly exaggerates how clean 

natural conditions actually are. The 

commenter provides a report on natural 

visibility background which argues that 

EPA’s estimate of natural conditions 

significantly understates the extent of 

natural particulate emissions, including 

dust and wildfires, which are 

uncontrollable. 

Response: EPA recognized that 

variability in natural sources of 

visibility impairment cause variability 

in natural haze levels as described in its 

‘‘Guidance for Estimating Natural 

Visibility Conditions Under the 

Regional Haze Rule.’’ 7 The preamble to 

the BART guidelines (70 FR 39124) 

describes an approach used to measure 

progress toward natural visibility in 

Mandatory Class I Areas that includes a 

URP toward natural conditions for the 

20 percent worst days and no 

degradation of visibility on the 20 

percent best days. The use of the 20 

percent worst natural conditions days in 

the calculation of the URP takes into 

consideration visibility impairment 

from wild fires, windblown dust and 

other natural sources of haze. The 

‘‘Guidance for Estimating Natural 

Visibility’’ also discusses the use of the 

20 percent best and worst estimates of 

natural visibility, provides for revisions 

to these estimates as better data becomes 

available,8 and discusses possible 

approaches for refining natural 

conditions estimates (pages 3–1 to 3–4). 

For the evaluation of visibility 

impacts for BART sources, EPA 

recommended the use of the natural 

visibility baseline for the 20% best days 

for comparison to the ‘‘cause or 

contribute’’ applicability thresholds. 

This estimated baseline is reasonably 

conservative and consistent with the 

goal of attaining natural visibility 

conditions. While EPA recognizes that 

there are natural sources of haze, the use 

of the 20% worst natural visibility days 

is inappropriate for the ‘‘cause or 

contribute’’ applicability thresholds. For 

example, if BART source visibility 

impacts were evaluated in comparison 

to days with very poor natural visibility 

resulting from nearby wild fires or dust 

storms, the BART source impacts would 

be significantly reduced relative to these 

poor natural visibility conditions and 

would not be protective of natural 

visibility on the best 20% days. 

The commenter and the cited report 

on natural visibility by Robert Paine 

appear to suggest that EPA requires the 

use of the best 20% visibility days for 

all aspects of visibility analysis. This 

does not accurately characterize EPA’s 

recommended use of the 20% worst 

natural visibility days for URP 

calculations and the 20% best natural 

visibility days for the ‘‘cause or 

contribute’’ applicability thresholds. For 

example, natural visibility conditions at 

the Badlands National Park for the best 

20%, annual average, and worst 20% 

natural visibility days are 2.9, 5.0, and 

8.1 deciviews, respectively.9 By 

contrast, current visibility conditions at 

the Badlands National Park for the best 

20%, annual average, and worst 20% 

days are 6.9, 11.6 and 17.1 deciviews, 

respectively. The URP calculation uses 

the worst 20% natural visibility value of 

8.1 deciviews, and this value adequately 

represents the impacts of natural 

sources of visibility impairment. 

Finally, as part of the settlement of a 

case brought by the Utility Air 

Regulatory Group challenging the BART 

Guidelines,10 EPA agreed to issue 

guidance clarifying that states may use 

either the 20% best or the annual 

average in estimating natural visibility 

in the evaluation of a BART source’s 

impacts. This guidance makes clear that 

states have the flexibility to use either 

approach in estimating natural 

background conditions. The State was 

not required to use the annual average 

and did not. Similarly, in issuing a FIP, 

we are not required to use the annual 

average either. 

The commenter cited modeling 

studies that purportedly show that the 

model-predicted natural haze levels are 

substantially larger than the natural 

haze levels used by EPA. In fact, the 

results of those studies compare well 

with EPA’s natural background levels. 

The modeling study by Tonnesen et 

al.11 predicted annual average natural 

PM2.5 concentrations in North Dakota in 

the range of 1.9 to 2.5 ug/m3, while the 

Koo et al. study 12 predicted annual 

average natural PM2.5 concentrations in 

the range of 2.5 to 3.1 ug/m3 in North 

Dakota. These model estimates are 

consistent with EPA’s estimated 2.6 ug/ 

m3 annual average PM2.5 concentration 

at Class I Areas in western North 

Dakota. 

Comment: One commenter felt that 

EPA’s decision appears to be driven by 

its desired outcome—more emission 

reductions—and not by any legal basis 

for disapproving the North Dakota SIP. 

Response: Our decision is driven by 

our interpretations of the CAA and our 

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20910 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

13The complete reference is: U.S. Forest Service, 

National Park Service, and U.S. Fish and Wildlife 

Service. 2010. Federal land managers’ air quality 

related values work group (FLAG): phase I report— 

revised (2010). Natural Resource Report NPS/ 

NRPC/NRR—2010/232. National Park Service, 

Denver, Colorado. 

14CALMET/CALPUFF BART Protocol for Class I 

Federal Area Individual Source Attribution 

Visibility Impairment Modeling Analysis, Colorado 

Department of Public Health and Environment, 

October 24, 2005. 

regulations. We note that we are 

approving the vast majority of North 

Dakota’s decisions. 

Comment: One commenter stated that 

EPA should not ignore two of the three 

years of CALPUFF modeling results in 

our review of modeling results 

presented by North Dakota. The 

commenter suggested that this is 

inconsistent with EPA’s typical practice 

of using long-term averages when 

addressing regional haze as is necessary 

to prevent undue influence from shortterm events or unusual meteorological 

events. 

Response: In our review of the singlesource CALPUFF modeling results 

presented by North Dakota, we cited the 

change in the maximum 98th percentile 

impact over the modeled three year 

meteorological period (2001–2003). As 

the 98th percentile value is intended to 

reflect the 8th high value in any year, 

it already eliminates 7 days per year 

from consideration in order to account 

for short-term events, unusual 

meteorological conditions, and any 

over-prediction bias in the model. 

Therefore, the modeling results which 

we cited in our proposal are designed to 

exclude influence from unusual events 

or meteorological conditions and are 

sufficient to address the commenter’s 

concerns. We also note that our 

approach is consistent with the method 

used by North Dakota in identifying 

subject-to-BART sources where a source 

is considered to contribute to 

impairment if it ‘‘exceeds the threshold 

when the ninety-eighth percentile of the 

modeling results based on any one year 

of the three years of meteorological data 

modeled exceeds five-tenths 

deciviews.’’ North Dakota RH SIP, p. 63. 

We find that this is a reasonable method 

for the purposes of evaluating visibility 

improvements associated with potential 

control options. 

Comment: Commenters stated that 

EPA should not ignore the 90th 

percentile impact in our review of the 

CALPUFF visibility results presented by 

North Dakota. 

Response: In the BART Guidelines, 

EPA addressed the appropriate 

interpretation of CALPUFF modeling 

results within the context of subject-toBART modeling. We rejected the use of 

the 90th percentile because it would be 

inconsistent with the Act: ‘‘The use of 

the 90th percentile value would 

effectively allow visibility effects that 

are predicted to occur at the level of the 

threshold (or higher) on 36 or 37 days 

a year. We do not believe that such an 

approach would be consistent with the 

language of the statute.’’ 70 FR 39121. 

On the same page, EPA explained that 

the 98th percentile was sufficient to 

account for any overestimation of 

visibility benefits by CALPUFF. 

While the BART Guidelines do allow 

states to consider the ‘‘frequency, 

duration, and intensity’’ of a source’s 

visibility impact when making control 

determinations, the use of the 90th 

percentile would over-compensate for 

any uncertainties in CALPUFF and 

would underestimate visibility benefits 

from potential control options and 

unduly bias the resulting analysis. 

When the 90th percentile is used to 

assess predicted visibility improvement 

from a potential control option, the 37th 

or 38th highest predicted improvement 

value from 365 predicted daily values is 

selected; higher predicted improvement 

values on 36 or 37 days a year are 

ignored. This is not rational. In the 

actual BART determination, a state 

could so dilute the predicted visibility 

improvement, one of the very goals of 

CAA section 169A, as to nullify its 

initial determination using the 98th 

percentile that the source is subject to 

BART. Accordingly, the BART 

guidelines specifically mention the use 

of the 98th percentile as an option to 

compare pre- and post-control modeling 

runs; use of the 90th percentile is not 

mentioned. 70 FR 39170. Moreover, the 

FLMs have affirmed the use of the 98th 

percentile in their most recent guidance 

for evaluating visibility impacts at Class 

I areas. FLAG 2010, p. 23.13

Comment: One commenter stated that 

CALPUFF overpredicts visibility 

impacts associated with nitrates due to 

incorrect (too high) ammonia 

background. The commenter stated that 

monitored background ammonia data 

from Wyoming shows lower 

concentrations. The commenter also 

cites a study by Colorado Department of 

Public Health and Environment 

(CDPHE) related to the sensitivity of the 

CALPUFF model to ammonia 

background concentrations. 

Response: The monthly ammonia 

background concentrations used by 

North Dakota were derived from data 

collected at the State’s only ammonia 

monitor located near Beulah and range 

from a low of 0.98 ppb to a high of 2.29 

ppb. (BART modeling protocol, Table 3– 

4). Due to their proximity to the North 

Dakota sources and Class I areas, the 

Beulah ammonia background 

concentrations are clearly more 

representative than those which the 

commenter cites for Wyoming that 

‘‘were on the order of only 0.1 ppb.’’ We 

also note that, in its revised modeling, 

the commenter did not use alternate 

ammonia background concentrations 

that would differ from those used by 

North Dakota. 

With regard to the ammonia 

background sensitivity study conducted 

by CDPHE,14 the commenter has not 

shown that the study is relevant to 

North Dakota. CDPHE found that 

visibility impacts are ‘‘not very sensitive 

to the background ammonia 

concentration across the range from 1.0 

ppb to 100.0 ppb.’’ Id at 24. Therefore, 

we disagree with the commenter’s 

assertion that CALPUFF overpredicts 

visibility impacts associated with 

nitrates due to incorrect (too high) 

ammonia background. 

Comment: One commenter cited a 

paper by Terhorst and Berkman (2010) 

regarding the impact of the Mohave 

Generating Station (MGS), also known 

as the Mohave Power Project (MPP), on 

visibility in the Grand Canyon. The 

MGS was located about 115 km from the 

Grand Canyon National Park (‘‘GCNP’’) 

and was shut down in 2005. Based on 

measured values, and after controlling 

for the prevailing environmental and 

anthropogenic factors in the region, the 

authors found virtually no evidence that 

the MGS closure improved visibility in 

the GCNP or that the plant’s operation 

degraded it. This was in contrast to air 

quality transport models, including 

CALPUFF, that predicted visibility 

would have improved by 5% or more 

after closure. 

Response: For the reasons stated in 

our responses to comments earlier in 

this section, our reliance on the 

CALPUFF modeling the State submitted 

in the SIP is reasonable. In addition, the 

study by Terhorst and Berkman does not 

convince us that use of CALPUFF 

modeling is inappropriate for this action 

or that the CALPUFF modeling results 

should be ignored. A model such as 

CALPUFF essentially holds constant a 

number of factors in order to isolate the 

impacts of a single source. As 

acknowledged by the study’s authors, it 

is extremely difficult in observational 

analyses to sufficiently control for all 

factors, including emissions from other 

sources, to be able to isolate the impacts 

of closure of a facility, especially one 

located over 100 km from the Class I 

area at issue. In fact, the paper notes 

that coarse soil mass impacts are an 

omitted variable in the analytical 

analysis and that changes in those 

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15http://vista.cira.colostate.edu/tss/Results/ 

HazePlanning.aspx. 

16http://www.nature.nps.gov/stats/ 

park.cfm?parkid=467. 

17http://vista.cira.colostate.edu/tss/Results/ 

HazePlanning.aspx. 

emissions may have counteracted the 

visibility improvements expected from 

the source shutdown. 

Comment: One commenter noted that 

the BART Guidelines allows states to 

consider if the time of year is important 

(e.g., high impacts are occurring during 

tourist season)’’. 70 FR 39130. The 

commenter provided information that 

shows that 85% of all visits to Theodore 

Roosevelt National Park (TRNP) occur 

during the period from mid-May to midOctober but that nitrate concentrations 

measured at TRNP and Lostwood 

Wilderness Area (LWA) during this 

period are extremely low. 

Response: We agree that our BART 

guidelines acknowledge that states may 

consider the timing of impacts in 

addition to other factors related to 

visibility impairment. However, states 

are not required to do so, and to our 

knowledge, this was not part of North 

Dakota’s analysis. We are not required 

to substitute a source’s desired exercise 

of discretion for that of the State’s. 

Furthermore, for purposes of our FIP, 

we stand in the shoes of the State. In 

that capacity, we are not required to 

consider the seasonality of impacts, and 

we have chosen not to. The experience 

of visitors who come to the Class I areas 

in North Dakota during periods other 

than mid-May to mid-October is not 

discounted. 

As a factual matter, the commenter’s 

assertions are misleading. A review of 

the Interagency Monitoring of Protected 

Visual Environments (IMPROVE) 

monitoring data on the WRAP Technical 

Support System 15 reveals that 

significant nitrate impacts occur during 

periods of high visitation at TRNP. For 

example, the contribution to visibility 

impairment from nitrates in May and 

October of 2002 was 26.9% and 37.9%, 

respectively. There was also relatively 

high visitation to the Park during these 

months.16

Also, the commenter’s reference to 40 

CFR 51.301’s definition of ‘‘adverse 

impact on visibility’’ is misplaced. This 

term is defined for purposes of 40 CFR 

51.307 only and is not used in 40 CFR 

51.308. Section 51.307 applies to new 

source review only, not to the regional 

haze program. 

Comment: One commenter states that 

further controlling NOX emissions from 

North Dakota sources would not 

advance the goal of improving visibility. 

The commenter bases this statement on 

(1) back trajectory analysis that shows 

that emissions from North Dakota point 

sources only impact TRNP and LWA a 

small part of the time, and (2) a 

modeling study of large North Dakota 

point sources of NOX emissions that 

followed North Dakota’s 2005 EPAapproved protocol and shows that these 

sources contribute a very small fraction 

of light extinction attributable to 

nitrates. 

Response: We disagree that 

controlling large NOX point sources in 

North Dakota will not advance the goal 

of improving visibility. 

IMPROVE monitoring data shows that 

nitrates (from all sources) are among the 

highest contributors to visibility 

impairment at TRNP and LWA on the 

worst 20% visibility days. The 

contribution to visibility impairment 

from nitrate at TRNP from 2000–2004 

ranged between 13.8% and 24.1%, with 

nitrate contributing more than any other 

pollutant in 2001 and 2002. Similarly, 

the contribution to visibility impairment 

from nitrate at LWA from 2000–2004 

ranged between 19.2% and 31.5%, with 

nitrate contributing more than any other 

pollutant in 2004. 

In order to help states identify the 

origins of haze-forming pollutants, such 

as nitrates, the WRAP conducted source 

apportionment analyses that identify the 

contribution from source regions and 

types to specific Class I areas. These 

source apportionment methods 

included CAMx Particle Source 

Apportionment Technology (PSAT) and 

the Weighted Emissions Potential 

(WEP). Both of these analysis tools can 

be found on the WRAP Technical 

Support System.17 As described below, 

these analyses clearly demonstrate that 

North Dakota point sources are among 

the largest contributors to nitrates at 

TRNP and LWA on the 20% worst 

visibility days. 

PSAT is a tracer analysis approach 

that utilizes a mass-tracking algorithm 

in the CAMx air quality model to 

explicitly track the chemical 

transformations, transport, and removal 

of haze-forming pollutants associated 

with a particular source region, source 

type, or combination of the two. The 

WRAP PSAT results demonstrate that in 

2002, North Dakota point sources were 

the third and fifth largest contributors to 

nitrate on the worst 20% visibility days 

at TRNP and LWA, respectively (see 

charts and tables contained in docket). 

The WEP analysis relies on an 

integration of gridded emissions data, 

back trajectory residence time data, a 

one-over-distance factor to approximate 

deposition, and a normalization of the 

final results. This method does not 

produce highly accurate results because, 

unlike the CAMx air quality model and 

associated PSAT analysis, it does not 

account for chemistry and removal 

processes. Nonetheless, it is more 

informative than the simpler back 

trajectory analysis submitted by the 

commenter because WEP incorporates 

gridded emissions in addition to back 

trajectory. The WRAP WEP results show 

that the grid cells in which the North 

Dakota BART sources are located have 

among the highest potential to 

contribute to nitrate on the worst 20% 

visibility days at TRNP and LWA (see 

graphics contained in docket). 

Based on the WRAP source 

apportionment analyses, we find that 

there is ample evidence to conclude that 

further controlling NOX emissions from 

North Dakota point sources would 

advance the goal of improving visibility. 

Comment: One commenter submitted 

new single-source modeling for the AVS 

units that are subject to reasonable 

progress. The new modeling included 

results based on the current EPAapproved version of CALPUFF and use 

of annual average natural background 

conditions. 

Response: In our proposal, we noted 

that North Dakota provided modeling 

results showing a ‘‘visibility 

improvement of 0.754 deciviews at 

Theodore Roosevelt [2002] from the 

installation of LNB for both units 

combined.’’ 76 FR 58632. The 

commenter’s new modeling for the two 

units combined shows a visibility 

improvement of 0.39 deciviews at 

Theodore Roosevelt (98th percentile, 

2002). As we have stated elsewhere in 

response to comments, EPA has not 

reviewed or approved the specific 

modeling methodology used by the 

commenter for AVS; because the newly 

submitted modeling uses annual average 

natural background conditions, it is not 

consistent with North Dakota’s protocol 

for single-source modeling in the BART 

context. In our consideration of 

visibility improvement as an additional 

factor to the statutory and regulatory 

reasonable progress factors, we are not 

convinced that we must disregard North 

Dakota’s visibility improvement value of 

0.754 deciviews in favor of the 

commenter’s lower estimate. For 

reasons already explained, we find it 

reasonable to continue to consider and 

rely on single-source CALPUFF 

modeling that has been conducted in 

accordance with North Dakota’s 

modeling protocol for BART sources. 

However, even if we were required to 

consider the commenter’s new modeling 

results, they would not cause us to 

change our opinion about our 

disapproval of the State’s determination 

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18Memorandum from Gail Tonnesen, Regional 

Modeler, to North Dakota Regional Haze File, dated 

September 1, 2011, regarding ‘‘Modeling Single 

Source Visibility Impacts.’’ This memorandum is 

included in Appendix B of the TSD for this action. 

that no NOX controls are needed at AVS 

1 and 2 for purposes of reasonable 

progress or our determination that LNB 

must be installed for purposes of 

reasonable progress. The costs for LNB 

are very reasonable—$586 and $661 per 

ton for AVS 1 and 2, respectively. This 

is well below cost effectiveness values 

the State found reasonable in making 

some of its BART determinations. Also, 

the AVS units are not small EGUs. To 

the contrary, at 435 MW apiece, they are 

comparable to some of the larger EGUs 

in the State, and their NOX emissions 

are considerably greater than emissions 

from some other EGUs in North Dakota. 

North Dakota predicted that LNB at AVS 

would achieve NOX reductions of about 

3,500 tons per unit per year. These 

reductions are substantially greater than 

those that will be achieved at the 

Stanton Station (maximum reduction of 

983 tons per year, based on firing of 

lignite) and LOS 1 (reduction of 1,246 

tons per year reduction), where the State 

selected SNCR as BART, and 

significantly greater than the reductions 

that will be achieved at CCS (reduction 

of 2,572 tons per year, based on our 

FIP), the largest EGU in the State. 

Finally, even the commenter’s new 

modeling predicts combined visibility 

improvement of 0.39 deciviews for LNB 

on both units. Even if one were to 

consider this on a unit-by-unit basis, 0.2 

deciviews per unit is significant, and we 

find that this level of visibility 

improvement, when considered along 

with the four statutory factors under 

reasonable progress, would continue to 

support our selection of LNB for AVS 1 

and 2. 

Comment: One commenter stated that: 

‘‘EPA has no basis in law for rejecting 

the cumulative modeling performed by 

the State for AVS since, as EPA admits, 

there is no requirement that visibility 

impacts be addressed under a fourfactor analysis for a reasonable progress 

source. That is, there is no authority that 

precludes the State from modeling the 

way it did.’’ In addition, EPA ignores 

the fact that reasonable progress is not 

the same as BART. 

Response: The following language 

from 40 CFR 51.308(d)(1)(ii) applies 

because North Dakota established a RPG 

that provides for a slower rate of 

progress than would be needed to attain 

natural conditions by 2064: 

[T]he State must demonstrate, based on the 

factors in paragraph (d)(1)(i)(A) of this 

section, 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. 

The factors in paragraph (d)(1)(i)(A) 

are ‘‘the costs of compliance,’’ ‘‘the time 

necessary for compliance,’’ ‘‘the energy 

and non-air quality environmental 

impacts of compliance,’’ and ‘‘the 

remaining useful life of any potentially 

affected sources.’’ ‘‘Visibility 

improvement’’ is not one of the factors 

listed. EPA is required to determine 

‘‘whether the State’s goal for visibility 

improvement provides for reasonable 

progress towards natural visibility 

conditions.’’ 40 CFR 51.308(d)(1)(iii). In 

doing so, we must ‘‘evaluate the 

demonstrations developed by the State’’ 

pursuant to (d)(1)(ii). There is 

accordingly no explicit requirement for 

the State to take into account visibility 

impacts in determining what measures 

are reasonable. For regional haze, which 

is caused by emissions from numerous 

sources located over a wide geographic 

area, this makes sense. Controls on one 

specific source may have little 

measurable impact on visibility, but 

controls on multiple similar sources 

would likely have an impact on 

improving visibility. We note that states 

are unlikely to reach the national goal 

without, at some point, focusing on 

emissions from a range of sources. In 

these first regional haze SIPs, however, 

states have focused on those individual 

sources with the largest potential 

impacts on visibility. 

When a state considers the visibility 

improvement associated with 

controlling just one source or a small 

handful of sources in attempting to 

demonstrate that its progress goal is 

reasonable, it is not appropriate for the 

state to model visibility improvement 

on a source-by-source basis in a way 

that is inconsistent with the CAA. As 

discussed above, given the nature of 

visibility impairment, a single source’s 

impact on visibility under current, 

degraded visibility conditions is much 

less than when compared against a 

clean background. North Dakota’s 

approach using current degraded 

background would almost always result 

in the conclusion that reducing 

emissions will have little or no impact 

on visibility. 

North Dakota used cumulative 

modeling, which assumed current 

degraded background to evaluate and 

reject single-source control options for 

reasonable progress for every reasonable 

progress source in North Dakota. Such 

an approach to single-source modeling 

is inconsistent with the CAA. As we 

explained in the TSD for our proposal, 

we had previously considered and 

rejected the use of current degraded 

background in promulgating the BART 

Guidelines.18 The central logic of our 

interpretation, as expressed in the BART 

Guidelines, applies with equal force to 

single-source analysis of potential 

control options in the reasonable 

progress context. In the BART 

Guidelines, we said the following: 

In establishing the goal of natural 

conditions, Congress made BART applicable 

to sources which ‘may be reasonably 

anticipated to cause or contribute to any 

impairment of visibility at any Class I area.’ 

Using existing conditions as the baseline for 

single source visibility impact 

determinations would create the following 

paradox: the dirtier the existing air, the less 

likely it would be that any control is 

required. This is true because of the 

nonlinear nature of visibility impairment. In 

other words, as a Class I area becomes more 

polluted, any individual source’s 

contribution to changes in impairment 

becomes geometrically less. Therefore the 

more polluted the Class I area would become, 

the less control would seem to be needed 

from an individual source. We agree that this 

kind of calculation would essentially raise 

the ‘cause or contribute’ applicability 

threshold to a level that would never allow 

enough emission control to significantly 

improve visibility. Such a reading would 

render the visibility provisions meaningless, 

as EPA and the States would be prevented 

from assuring ‘reasonable progress’ and 

fulfilling the statutorily-defined goals of the 

visibility program. Conversely, measuring 

improvement against clean conditions would 

ensure reasonable progress toward those 

clean conditions. 

70 FR 39124. 

In other words, it is our interpretation 

that North Dakota, if it wished to 

consider visibility improvement in 

single-source modeling of potential 

control options, could only reasonably 

do so by modeling those controls against 

natural background conditions. Thus, 

we reject the commenter’s assertion. As 

we stated in our proposal, the statutory 

and regulatory goal is reasonable 

progress toward natural visibility 

conditions, not to preserve degraded 

conditions. 76 FR 58629. The State’s 

and commenter’s approach resulted in 

the rejection of very effective and 

inexpensive controls, and that approach 

could be used to preclude adoption of 

controls indefinitely. For the reasons 

expressed here and in our proposal, that 

is not reasonable. 

Comment: Two commenters stated 

that EPA should consider the dollars per 

deciview ($/deciview) as a measure 

when making either BART or reasonable 

progress determinations. Both 

commenters suggested that EPA relied 

too heavily on cost effectiveness in 

evaluating control options. And both 

commenters claimed that EPA has 

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19See Appendix A of our TSD for detailed 

explanation of the IMPROVE equation. 

endorsed the dollar per deciview 

approach, citing relevant BART and 

reasonable progress guidance. 

Response: For BART, the BART 

Guidelines require that cost 

effectiveness be calculated in terms of 

annualized dollars per ton of pollutant 

removed, or $/ton. 70 FR 739167. The 

commenters are correct in that the 

BART Guidelines list the $/deciview 

ratio as an additional cost effectiveness 

metric that can be employed along with 

$/ton for use in a BART evaluation. 

However, the use of this metric further 

implies that additional thresholds or 

notions of acceptability, separate from 

the $/ton metric, would need to be 

developed for BART determinations. We 

have not used this metric for BART 

purposes because (1) It is unnecessary 

in judging the cost effectiveness of 

BART, (2) it complicates the BART 

analysis, and (3) it is difficult to judge. 

In particular, the $/deciview metric has 

not been widely used and is not wellunderstood as a comparative tool. In our 

experience, $/deciview values tend to 

be very large because the metric is based 

on impacts at one Class I area on one 

day and does not take into account the 

number of affected Class I areas or the 

number of days of improvement that 

result from controlling emissions. In 

addition, the use of the $/deciview 

suggests a level of precision in the 

CALPUFF model that may not be 

warranted. As a result, the $/deciview 

can be misleading. We conclude that it 

is sufficient to analyze the cost 

effectiveness of potential BART controls 

using $/ton, in conjunction with an 

assessment of the modeled visibility 

benefits of the BART control. We also 

note that North Dakota did not rely on 

the $/deciview metric in its evaluation 

of BART controls. 

Within the context of reasonable 

progress, the Guidance for Setting 

Reasonable Progress Goals Under the 

Regional Haze Program, page 5–2, states 

that ‘‘[y]ou should evaluate both average 

and incremental costs.’’ This is 

consistent with the approach under 

BART. As commenters note, the 

guidance then states that ‘‘simple cost 

effectiveness estimates based on a 

dollar-per-ton calculation may not be as 

meaningful as a dollar-per-deciview 

calculation, especially if the strategies 

reduce different groups of pollutants.’’ 

However, the guidance makes this 

statement on the basis that ‘‘different 

pollutants differently impact visibility 

impairment.’’ That is, for example, a one 

ton reduction in SO2 would have a 

greater visibility benefit than a one ton 

reduction of coarse mass. As only SO2

and NOX controls were evaluated for the 

reasonable progress point sources, and 

these pollutants have similar impacts on 

visibility (per the IMPROVE equation),19

the use of the $/deciview is not 

particularly relevant or informative. In 

addition, we did not use the $/deciview 

metric for our evaluation of RP controls 

for largely the same reasons as stated 

above for BART controls. As we noted 

in our proposal, ‘‘it is important to 

recognize that dollars per deciview 

values will always be significantly 

higher, often by several orders of 

magnitude, than the more commonly 

used and understood dollars per ton 

values.’’ 76 FR 58630. North Dakota’s 

use of current degraded background in 

its modeling for potential single-source 

control options had the effect of greatly 

increasing the disparity between $/ 

deciview and $/ton values because the 

modeling significantly underestimated 

the benefits of controls. 

Comment: Commenters performed 

CALPUFF simulations using a revised 

CALPUFF version 6.4 that includes 

updates to the chemical and particle 

transformations and submitted these 

results to EPA during the comment 

period. 

Response: We have already explained 

why we may reasonably rely on the 

modeling performed in accordance with 

the State’s BART modeling protocol. We 

have additional reasons for disagreeing 

that the newer CALPUFF version 6.4 

results should be used in this action to 

determine potential visibility impacts. 

The newer version of CALPUFF has not 

received the level of review required for 

use in regulatory actions subject to EPA 

approval and consideration in a BART 

decision making process. Based on our 

review of the available evidence, we do 

not consider CALPUF version 6.4 to 

have been shown to be sufficiently 

documented, technically valid, and 

reliable for use in a BART decision 

making process. In addition, the 

available evidence would not support 

approval of these models for current 

regulatory use. The newer versions of 

the model introduce additional 

chemical mechanisms that have not 

gone through the public review process 

required for approval by the Agency. 

Comment: North Dakota’s proposed 

RH SIP emission reductions are 

sufficient to meet the CAA’s visibility 

objectives relative to the 2018 

milestone. North Dakota’s BART 

emission reductions properly and 

effectively reduce statewide haze 

production by more than the 23.3% 

fraction of the 60-year RHR timeline (by 

2018). EPA improperly asserts that 

North Dakota cannot meet the 2018 

URP. In fact, the infrequency of the 

winds blowing the major emission 

source plumes toward the Class I areas 

and the zero progress toward controlling 

Canadian and uncontrollable emissions 

(such as wildfires and windblown dust) 

are the cause of the inability for North 

Dakota to meet the 2018 milestone goal, 

not in-state source emissions. EPA 

should not penalize North Dakota and 

reject its RH SIP because North Dakota 

cannot control impacts from sources 

beyond its control. In fact, the RHR and 

the UARG settlement with EPA in 2006 

state that, ‘‘EPA does not expect States 

to restrict emissions from domestic 

sources to offset the impacts of 

international transport of pollution.’’ 

Response: Contrary to the 

commenter’s assertion, the Class I areas 

in North Dakota will not meet the URP 

in 2018, something North Dakota 

acknowledges. We are not penalizing 

North Dakota, and we are not seeking 

controls in North Dakota to offset 

impacts from outside the State. We 

explain elsewhere why we are 

disapproving North Dakota’s NOX BART 

determination for CCS 1 and 2 and its 

reasonable progress determination 

concerning AVS 1 and 2. We are acting 

to ensure that reasonable BART and 

reasonable progress controls are put in 

place. North Dakota may not use out-ofstate emissions as a basis to ignore 

controls on in-state sources where such 

controls are clearly reasonable. We note 

that we are approving the majority of 

North Dakota’s BART and reasonable 

progress determinations and that our 

FIP is modest in scope. 

Comment: One commenter notes that 

EPA’s proposed FIP states that 

‘‘Appendix W outlines specific criteria 

for the use of alternate models and it 

does not appear that those criteria have 

been satisfied for the use of North 

Dakota’s hybrid modeling.’’ 76 FR 58624 

and 58637. The commenter asserts that 

‘‘EPA does not, however, identify any 

criteria North Dakota purportedly did 

not satisfy.’’ The commenter then seeks 

to supply, in retrospect, evidence that 

the criteria for alternative models, as 

specified in Appendix W section 3.2, 

are in fact met. 

Response: As specified in Appendix 

W, ‘‘[d]etermination of acceptability of a 

model is a Regional Office 

responsibility.’’ 70 FR 68232. EPA 

Region 8 has not determined that North 

Dakota’s hybrid modeling (aka 

‘‘cumulative modeling using current 

degraded background’’) is acceptable for 

the purposes of assessing single-source 

visibility impacts under BART. In June 

2007, EPA reviewed the ‘‘Modeling 

Protocol for Regional Haze Reasonable 

Progress Goals in North Dakota.’’ Our 

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review of the protocol at that time was 

within the context of establishing RPGs, 

and not within the context of assessing 

single-source impacts under BART. 

Instead, and as described above, North 

Dakota prepared a separate modeling 

protocol for the purposes of BART. We 

reiterate that, as the State’s single-source 

BART modeling followed established 

modeling guidance and was developed 

in consultation with FLMs and EPA, we 

find that it provides a reasonable basis 

for making control technology 

determinations. 

Comment: Commenter stated that EPA 

notes in the FIP that ‘‘North Dakota is 

the only WRAP State which opted to 

develop its own reasonable progress 

modeling methodology.’’ Commenter 

stated that the NDDH modeling 

approach represents an adjustment, or a 

refinement (for pollutant transport and 

dispersion), of the cumulative 

reasonable progress modeling 

conducted by WRAP for western states. 

In particular, the NDDH modeling 

provides a much better resolution of 

source to receptor locations. Commenter 

stated EPA asserts that ‘‘[t]he settings 

North Dakota used in the CALPUFF 

model within the hybrid modeling 

system would not be considered 

technically sound if contained in a 

regulatory modeling protocol in future 

projects.’’ However, NDDH’s 

modifications to the model settings 

allows North Dakota’s specific 

environment to be considered. 

Response: North Dakota designed its 

cumulative modeling system 

specifically to include transported 

pollutants, in addition to emissions 

from individual BART sources. North 

Dakota then used the model results to 

evaluate BART source visibility impacts 

relative to the cumulative impact of all 

other emissions sources. The State’s 

cumulative approach contradicts the 

model approach recommended by EPA 

in the BART Guidelines in which BART 

source impacts are evaluated relative to 

natural background visibility. As 

discussed in the response to comments 

above, EPA specifically considered and 

rejected cumulative analyses for BART 

sources in the BART Guidelines. The 

effect of North Dakota’s cumulative 

modeling approach is to evaluate BART 

visibility impacts relative to current 

degraded visibility conditions, and as 

described in the BART Guidelines and 

in response to comments above, this 

would create the paradox that, the 

worse the current visibility, the less 

likely it would be that any control 

would be required. The commenter also 

describes the State’s approach as similar 

to the cumulative reasonable progress 

modeling conducted by WRAP for the 

western states. WRAP’s cumulative 

reasonable progress modeling was 

designed to evaluate progress in 

reducing cumulative visibility impacts 

from all emissions sources for the worst 

20% visibility days. WRAP’s cumulative 

modeling did not evaluate the impacts 

from individual BART sources, and 

therefore WRAP also performed single 

source modeling using the CALPUFF 

model to evaluate single source BART 

impacts on the best visibility days. 

Moreover, WRAP followed the BART 

Guidelines in comparing those BART 

visibility impacts to natural visibility 

conditions on the 20% best days. While 

it could be reasonable to perform 

modeling for BART sources using 

CALPUFF with background 

concentration data from the Community 

Multi-Scale Air Quality (CMAQ) model, 

as North Dakota has done, the BART 

source visibility impacts must still be 

evaluated relative to natural background 

visibility. The State’s approach of 

comparing the BART source impacts to 

cumulative visibility impacts is 

essentially the same as comparing those 

results to current degraded visibility 

conditions, and, therefore, does not 

follow the guidelines established by 

EPA and followed by both WRAP and 

all other states. As noted in other 

responses, the reasons for our rejection 

of North Dakota’s modeling approach in 

the BART context also apply to North 

Dakota’s use of that approach to model 

the visibility benefits of single-source 

control options in the reasonable 

progress context. 

Comment: Commenter states that the 

cumulative approach is exemplified in 

the refined visibility modeling 

conducted by WRAP for western states 

(which EPA has endorsed in Appendix 

A of the TSD to its FIP proposal). 

Response: Our applicable response to 

a similar comment is provided 

elsewhere in this section. Such an 

approach is suitable for determining the 

cumulative benefit of an overall control 

strategy vis-a`-vis the URP on the 20% 

worst days. It is not suitable for 

evaluating the benefits of potential 

control options at individual sources. 

Comment: Commenter stated that EPA 

suggests that using single source 

modeling based on natural background 

conditions is appropriate for assessing 

visibility improvement from BART 

controls, because the goal of the regional 

haze program is to ultimately have 

natural background visibility 

conditions. NDDH provides a number of 

technical weaknesses of single source 

modeling with natural background. For 

example, North Dakota asserts the single 

source modeling overstates perceived 

visibility changes and ignores the 

impact of all other sources on 

background visibility. 

Response: We address these assertions 

in our responses to other comments in 

this section. 

Comment: One commenter stated that 

it is appropriate to consider both the 

degree of visibility improvement in a 

given Class I area as well as the 

cumulative effects of improving 

visibility across all of the Class I areas 

affected. The commenter contends that 

not considering the cumulative 

improvement across multiple Class I 

areas ignores impacts to all but the most 

impacted Class I area. 

Response: In its SIP, North Dakota 

considered the visibility improvement 

at both TRNP and LWA. Therefore, the 

modeling analyses presented by North 

Dakota did not ignore the visibility 

improvement that would be achieved at 

areas other than the most impacted 

Class I area. In our proposal, for 

convenience, we generally only cited 

the visibility improvement at Theodore 

Roosevelt, the most impacted Class I 

area in the baseline modeling. However, 

our evaluation of the visibility benefits 

was made in consideration of all of the 

single-source modeling results 

presented in North Dakota’s SIP. 

Comment: One commenter stated that 

they shared our concern that North 

Dakota did not adequately consider the 

visibility benefits of the control 

strategies it evaluated. Specifically, the 

commenter pointed out that for three 

EGUs, North Dakota used incorrect 

techniques to assess (and 

underestimate) visibility improvements. 

That is, instead of evaluating a 

candidate BART strategy by determining 

the visibility improvement that would 

result from that particular strategy 

versus a ‘‘standard’’ baseline (e.g., the 

proposed SO2 control options), the only 

analyses of visibility improvements 

were of the incremental differences 

between competing BART options. 

Response: We agree that the visibility 

improvement of a control technology 

should be assessed relative to a precontrol baseline. As we have noted 

elsewhere in our response to comments, 

this approach is recommended in the 

BART Guidelines. 70 FR 39170. 

However, where North Dakota failed to 

provide this information, we were able 

to rely on the incremental visibility 

improvement over lower control 

options. Our evaluation of the visibility 

benefits for the three EGUs in question 

took into account that the lower 

visibility improvement presented by 

North Dakota was simply an artifact of 

the methodology. 

Comment: One commenter stated that 

North Dakota should have treated TRNP 

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as single Class I area in their modeling 

analyses. 

Response: We concur that TRNP 

should have been treated as a single 

Class I area in the modeling analyses. 

However, we have no evidence that 

doing so would have led to control 

technology determinations different 

than those made by North Dakota or 

EPA. 

Comment: One commenter suggested 

that EPA could have addressed 

modeling issues that it identified in its 

proposal by conducting its own 

modeling analyses, as it did regarding 

BART determinations in other EPA 

regional offices. 

Response: As stated elsewhere in our 

responses to comments in this section, 

we find that North Dakota’s singlesource modeling provides a reasonable 

basis for making control technology 

determinations. Therefore, we did not 

find it necessary to conduct our own 

modeling analyses. 

Comment: From a visibility 

impairment standpoint, it appears to be 

more beneficial to reduce NOX than to 

reduce SO2 in North Dakota’s cool 

climate. However, by placing more 

emphasis upon cost per-ton ($/ton) of 

pollutants removed than on visibility 

improvement, the advantages of 

reducing NOX versus SO2 are 

overlooked if both are measured with 

the same $/ton yardstick. For this 

reason, we recommend that the primary 

emphasis should be placed upon the 

dollars per deciview of improvement. 

EPA has stated in its Guidance for 

Setting Reasonable Progress Goals 

Under the Regional Haze Program (June 

1, 2007), ‘‘in assessing additional 

emissions reduction strategies for source 

categories or individual, large scale 

sources, simple cost effectiveness based 

on a dollar-per-ton calculation may not 

be as meaningful as a dollar per 

deciview calculation.’’ The same logic 

applies to BART. Nevertheless, the 

commenter notes that both North Dakota 

and EPA have based their BART 

determinations on cost-per-ton of 

pollutant removed, and the commenter 

included information to show that the 

EPA BART proposals are internally 

consistent and reasonable. 

Response: As noted elsewhere, 

evidence we have reviewed suggests 

that the relative benefits are similar. In 

any event, we have not ignored 

visibility benefits in our assessments. It 

is not necessary to use dollars per 

deciview to reasonably consider the 

regulatory factors and arrive at 

reasonable control determinations. As 

we have explained in responses to other 

comments in this section, there can be 

significant issues with the use of dollars 

per deciview values. 

Comment: One commenter suggested 

that the modeling issues raised by EPA, 

including the use of a degraded 

background, should be addressed as part 

of North Dakota’s 2013 ‘‘mid-course 

correction’’ and that more emphasis 

should be placed upon the cumulative 

visibility benefits that could be derived 

from the BART program. 

Response: The requirements for 

periodic reports describing progress 

towards the RPGs are contained in the 

RHR (40 CFR 51.308(g)). The RHR does 

not explicitly require that updated 

visibility modeling be included as an 

element of the periodic progress report. 

Nonetheless, to the extent that North 

Dakota chooses to submit updated 

modeling to meet other periodic 

progress reporting requirements, we will 

address it at that time. 

D. Comments on Costs 

1. General 

Comment: Commenter stated that EPA 

cannot replace the State’s site-specific 

cost estimates solely for the purpose of 

ensuring consistency across states. EPA 

also cannot reject cost items because 

EPA deems them atypical. Doing so 

undermines the statute, which provides 

that BART is a state determination. 

Response: As we explain in our 

response to a previous comment, we 

have authority to assess the 

reasonableness of a state’s analysis of 

costs. We are not relegated to a 

ministerial role. We have not replaced 

cost estimates solely for the purpose of 

ensuring consistency across states. 

When a source puts forward costs 

estimates that are atypical, it is 

reasonable for us to scrutinize such 

estimates more closely to determine 

whether they are reasonable or inflated. 

Also, given that the assessment of costs 

is necessarily a comparative analysis, it 

is reasonable to insist that certain 

standardized and accepted costing 

practices be followed absent unique 

circumstances. Thus, our BART 

guidelines state, ‘‘In order to maintain 

and improve consistency, cost estimates 

should be based on the OAQPS Control 

Cost Manual, where possible.’’ 70 FR 

39166. 

Comment: Commenter stated that EPA 

misapplies cost effectiveness to measure 

emissions reductions, because the 

purpose of BART is visibility 

improvement. Citing the BART 

Guidelines, commenter stated that more 

weight should be placed on the 

incremental rather than the average cost 

effectiveness. 

Response: In our review and analyses, 

we have considered cost effectiveness 

values in conjunction with estimates of 

visibility improvement. Our analysis 

methods are consistent with those 

called for by the BART guidelines. We 

have considered both average and 

incremental cost effectiveness. The 

BART guidelines do not require that 

greater weight be placed on incremental 

cost effectiveness and advise the use of 

caution not to misuse the cost 

effectiveness values. 70 FR 39167– 

39168. 

Comment: Commenter stated that EPA 

cannot replace the statutory requirement 

that states weigh costs of compliance 

with a requirement that states select 

BART based on a uniform national cost 

effectiveness metric. Commenter further 

stated that EPA essentially elevated cost 

effectiveness to being a statutory factor 

for BART determinations in the BART 

Guidelines, and that this was incorrect 

based on CAA section 169(A). 

Response: For power plants larger 

than 750 MW, the BART guidelines are 

mandatory and specify that the Control 

Cost Manual should be used to estimate 

costs where possible and that cost 

effectiveness in $/ton be considered. We 

note that it is too late to challenge the 

BART guidelines in this action. That 

said, the BART Guidelines do not, as the 

commenter contends, require states to 

select BART based on a ‘‘uniform 

national cost effectiveness metric’’ 

without consideration of the other 

relevant factors. 

For BART sources other than power 

plants larger than 750 MW, North 

Dakota has specified in its SIP that the 

BART guidelines must be used as 

guidance. Furthermore, any analysis of 

the costs of compliance must be 

reasonable, and the starting point is an 

accurate estimate of the costs of 

potential control options. From there, 

we must have some means to assess the 

reasonableness of the costs, and cost 

effectiveness in $/ton is a widely used 

and understood metric. 

Comment: Commenter stated that, in 

the preamble to the RHR, EPA 

established a cost effectiveness value 

threshold of $1,350/ton for NOX retrofit 

control technologies. Another 

commenter cited appendix Y, alleging 

that it states that NOX control costs 

above $1,500/ton are not cost effective 

for BART. Commenter stated that EPA is 

therefore inaccurate in the FIP for citing 

NOX control costs over $1,500 per ton 

as cost effective. 

Response: EPA disagrees. While EPA 

described various dollar-per-ton costs as 

‘‘cost-effective’’ in various preambles 

(e.g., 70 FR 39135–39136), EPA did not 

establish an upper cost effectiveness 

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20916 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

20See, for example, the NSR Manual, Appendix 

B, which lays out the overnight method currently 

required in the Control Cost Manual. 

21See discussion of this issue in Letter from John 

Bunyak and Sandra V. Silva, Fish & Wildlife 

Service, to Mary Uhl, New Mexico Environmental 

Department, August 17, 2010, p. 5, footnote 9 

(November 7, 2007, statement from EPA Region 8 

to the North Dakota Department of Health: ‘‘* * * 

in order to maintain and improve consistency, cost 

estimates should be based on the OAQPS Cost 

Control Manual. Therefore, these analyses should 

be revised to adhere to the Cost Manual 

methodology.’’), p. 6 (quoting a May 10, 2010 EPA 

letter to North Dakota Department of Health: ‘‘These 

accounting items [owner’s cost] are unauthorized 

under the Cost Control Manual, create an unlevel 

playing field for comparison with other BACT 

analyses and alone account for an increase in 

capital costs from the Cost Control Manual by a 

factor of 1.6.’’). See discussion in: Letter from 

Andrew M. Gaydosh, Assistant Regional 

Administrator, EPA Region 8, to Terry O’Clair, 

Director, Division of Air Quality, North Dakota 

Department of Health, Re: EPA’s Comments on the 

North Dakota Department of Health’s April 2010 

Draft BACT Determination for NOX for the Milton 

R. Young Station, May 10, 2010, pp. 14–16. 

22As explained in the next response, the Control 

Cost Manual allows the use of levelized costing, but 

it is different from the levelized costing that the 

utility industry prefers. 

threshold for BART determinations. We 

note that North Dakota and other states 

have identified NOX control costs well 

over $1,500 per ton of emissions 

reduced as being cost effective, and that 

the relevance of a particular dollar-perton figure for controls will depend on 

consideration of the remaining statutory 

factors. 

2. Comments Regarding Our Reliance on 

the EPA Air Pollution Control Cost 

Manual 

Comment: One commenter stated that 

the Control Cost Manual is in no way 

binding, and that any deviation from the 

manual by the State is no cause for SIP 

disapproval. The commenter also stated 

that cost analyses must take into 

consideration source-specific costs. 

Response: In today’s rule, we are 

disapproving the BART determination 

for one source, CCS. We note that the 

BART guidelines are mandatory for CCS 

because it is larger than 750 MW. The 

BART Guidelines state that ‘‘[i]n order 

to maintain and improve consistency, 

cost estimates should be based on the 

OAQPS Control Cost Manual, [now 

renamed ‘‘EPA Air Pollution Control 

Cost Manual, Sixth Edition, EPA/452/B– 

02–001, January 2002] where possible.’’ 

70 FR at 39166. In addition, the 

preamble to the BART Guidelines states 

that ‘‘[w]e believe that the Control Cost 

Manual provides a good reference tool 

for cost calculations, but if there are 

elements or sources that are not 

addressed by the Control Cost Manual 

or there are additional cost methods that 

could be used, we believe that these 

could serve as useful supplemental 

information.’’ 70 FR 39127 (emphasis 

added). Finally, the BART Guidelines 

are clear that ‘‘cost analysis should also 

take into account any site-specific 

design or other conditions * * * that 

affect the cost of a particular BART 

technology option.’’ 70 FR 39166. 

However, documentation of cost 

estimates is necessary, particularly for 

items that deviate from the Control Cost 

Manual: ‘‘You should include 

documentation for any additional 

information you used for the cost 

calculations, including any information 

supplied by vendors that affects your 

assumptions regarding purchased 

equipment costs, equipment life, 

replacement of major components, and 

any other element of the calculation that 

differs from the Control Cost Manual.’’ 

Id. In sum, the BART Guidelines direct 

states to use the Control Cost Manual 

where possible, but also allow for the 

use of supplemental information and 

site-specific factors, as necessary, as 

long as the latter information is justified 

and documented. 

The Control Cost Manual contains 

two types of information: (1) A generic 

costing methodology, known as the 

overnight method and (2) study level 

capital cost estimates for certain general 

types of pollution control equipment, 

such as SCR. The overnight method has 

been used for decades for regulatory 

control technology cost analyses.20

While we agree that the strict 

application of the study level analysis is 

not required in all cases, we maintain 

that following the overnight method 

ensures equitable BART determinations 

across states and across sources. Cost 

effectiveness is determined by 

comparing annual cost per ton of 

pollutant removed for the source of 

interest to the range of cost effectiveness 

values for other similar facilities 

calculated in the same way. If a given 

cost effectiveness value falls within the 

range of costs borne by others, it is per 

se cost effective unless unusual 

circumstances exist at the source. 70 FR 

39168. Thus, cost effectiveness is a 

relative determination, based on costs 

borne by other similar facilities. To 

compare costs among units, a level 

playing field must be established by 

following the same cost rules in each 

determination.21 Thus, in evaluating 

BART cost effectiveness, it is important 

that a consistent set of rules be used. 

Otherwise, one runs the risk of 

comparing two approaches that cannot 

be validly compared when making the 

cost effectiveness determination. This 

concept of comparability is integral to 

the achievement of the national goal 

specified in CAA section 169A and its 

legislative history as discussed 

elsewhere in our response to 

comments—visibility impairment and 

improvement is not merely a state or 

local concern. It impacts visitors to our 

national parks and wilderness areas 

from all across the United States. 

The cost estimates supplied by North 

Dakota were frequently based on cost 

estimating methods that deviate from 

the overnight method that is used for 

regulatory purposes. As described 

above, these costs are not suitable for 

the purpose of determining whether the 

costs of BART controls are reasonable 

relative to costs incurred at other 

facilities. 

Comment: One commenter stated that 

EPA ignores the disclaimer in the 

Control Cost Manual that the manual 

does not address controls for EGUs. To 

support this position, the commenter 

provides the following quote from the 

Control Cost Manual: 

‘‘Furthermore, this Manual does not 

directly address the controls needed to 

control air pollution at electrical generating 

units (EGUs) because of the differences in 

accounting for utility sources. Electrical 

utilities generally employ the EPRI Technical 

Assistance Guidance (TAG) as the basis for 

their cost estimation processes.’’ 1

The commenter also provides footnote 

1 to this quote which reads as follows: 

‘‘This does not mean that this Manual is an 

inappropriate resource for utilities. In fact, 

many power plant permit applications use 

the Manual to develop their costs. However, 

comparisons between utilities and across the 

industry generally employ a process called 

‘‘levelized costing’’ that is different from the 

methodology used here. (EPA Air Pollution 

Cost Control Manual, Sixth Edition page 

1–3)’’ 

Response: We disagree with the 

commenter’s conclusion regarding this 

quote from the Control Cost Manual. 

The quote is merely a factual 

observation; electric utilities, in their 

planning and cost estimating for their 

own purposes, use a different 

accounting method than required by the 

Control Cost Manual. The footnote 

clarifies that the Control Cost Manual is 

appropriate for utilities for regulatory 

purposes. 

The utility industry uses a method 

known as ‘‘levelized costing’’ to conduct 

its internal comparisons.22 The utility 

industry’s levelized costing methods 

differ from the methods specified by the 

Control Cost Manual. Utilities use 

‘‘levelized costing’’ to allow them to 

recover project costs over a period of 

several years and, as a result, realize a 

reasonable return on their investment. 

The Control Cost Manual uses an 

approach sometimes referred to as 

‘‘overnight costing’’ that treats the costs 

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23 Institute of Clean Air Companies, White Paper 

Selective Non-Catalytic Reduction (SNCR) for 

Controlling NOX Emissions, February 2008, p. 4. 

of a project as if all the materials and 

labor are paid for within a very short 

period of time. The Control Cost Manual 

approach is intended to allow a fair 

comparison of pollution control costs 

between similar applications for 

regulatory purposes. 

Estimates prepared using the utility 

industry’s levelized costing are not 

comparable to estimates prepared using 

the Control Cost Manual. Estimates 

using the utility industry’s levelized 

method are generally higher than EPA 

cost effectiveness estimates since the 

utility industry’s levelized method 

estimates are stated in future dollars and 

include costs not included in the EPA 

method, such as inflation and interest 

during construction. That is why the 

BART guidelines specify the use of the 

Control Cost Manual where possible and 

why it is reasonable for us to insist that 

the Control Cost Manual method be 

used to estimate costs. This is the 

method that has been used to determine 

the reasonableness of cost effectiveness 

values in regulatory settings for many, 

many years; it ensures the use of a 

common, well-understood metric. 

Without a like-to-like comparison, it is 

impossible to draw rational conclusions 

about the reasonableness of the costs of 

compliance for particular control 

options. 

Comment: Commenter stated that 

EPA’s rejection of levelized costs is 

inconsistent with the Control Cost 

Manual. Commenter also cites EPA’s 

New Source Review (NSR) Manual to 

argue that levelized costs are acceptable 

and should not be disapproved. 

Response: The issue here is one of 

semantics rather than a dispute over 

levelization. We agree levelization is 

allowed by the Control Cost Manual, 

and we levelized costs in preparing cost 

estimates for our proposal. However, the 

commenter levelized in nominal dollars, 

while EPA’s consultant levelized in 

constant dollars consistent with the 

Control Cost Manual. The constant 

dollar approach is the correct approach. 

It levelizes O&M costs excluding 

inflation. 

The Control Cost Manual approach 

equalizes all future O&M costs into 

equal annual payments in constant 

dollars over the life of the system, 

translated to year zero using the 

Equivalent Uniform Annual Cash Flow 

method or EUAC. See also NSR Manual, 

p. b.4. The dispute arises over the 

inclusion of inflation. The Control Cost 

Manual ‘‘recommends making cost 

comparisons on a current real dollar 

basis’’ * * *.’’ ‘‘The constant dollar 

approach described in the Control Cost 

Manual annualizes (in constant dollars) 

the cost of installation, maintenance, 

and operation of a pollution control 

system * * *’’ ‘‘The estimator can 

levelize annual O&M costs over the life 

of the project, consistent with the 

manual’s constant dollar approach 

* * *’’ The commenter asserts that the 

NSR Manual directs the use of levelized 

cost in the PSD context, but we note this 

source also clarifies that the interest rate 

used to annualize the cost ‘‘does not 

consider inflation.’’ NSR Manual, p. 

b.11. 

Comment: One commenter stated that 

comparing the State’s and EPA’s cost 

methods is essentially comparing apples 

to oranges. The commenter stated that, 

because EPA uses a cost method which 

is uniform and relied upon nationwide, 

and North Dakota and the utilities’ cost 

method ‘‘markedly deviates from EPA’s 

cost method, reliance on the estimates 

produced by the State are 

unreasonable.’’ 

Response: We agree with the 

commenter that the costs developed by 

the State are in many cases not directly 

comparable to those prepared by EPA. 

In particular, costs developed using the 

overnight cost method for 

(environmental) regulatory purposes are 

not directly comparable to those 

developed using the utility cost method. 

Both approaches are correct for their 

respective purposes, but each must be 

used within the appropriate context. We 

also agree that consistency of methods 

is necessary to ensure that costs are 

assessed equitably. In our proposal, 

where we compared our costs with 

those supplied by North Dakota, we 

identified where different cost methods 

and assumptions were used. While we 

don’t always agree with every detail of 

the State’s cost estimates, we explain in 

other responses the bases for our 

conclusions that the State’s control 

determinations are reasonable or 

unreasonable. 

Comment: Commenter also listed 

several reasons why it believes the 

Control Cost Manual does not provide 

accurate estimates of current SNCR 

costs. 

Response: Our reliance on the Control 

Cost Manual is addressed above. As 

stated, the BART Guidelines direct 

states to use the Control Cost Manual 

where possible, but to also allow for 

supplemental information and take into 

account site-specific factors as 

necessary, as long as the latter 

information is justified and 

documented. Accordingly, where 

appropriately justified and documented, 

we have incorporated site-specific costs 

into our SNCR cost estimates. We also 

note that our SNCR cost effectiveness 

values compare well with the range 

cited by the vendor community of 

$1,500 to 2,500 per ton of NOX

removed.23

E. Comments on BART Determinations 

1. General Comments 

Comment: Commenter stated that 

EPA’s proposed incorporation of a 

‘‘margin of compliance’’ into its BART 

determinations is contrary to the CAA, 

and is not supported by EPA’s own 

regulations and guidance. Commenter 

specifically cited EPA’s proposed 

increase of the MRYS Units 1 and 2 

NOX emission limits from .05 lb/MMBtu 

to .07 lb/MMBtu, stating that this was a 

weakening not allowed by the CAA and 

reliant on factors that were not 

articulated in the CAA. Commenter 

used this rationale in stating that EPA 

must establish BART emission rates of 

.05 lb/MMBtu for MRYS Units 1 and 2 

and LOS Unit 2, and a BART emission 

rate of .108 lb/MMBtu for CCS Units 1 

and 2. Another commenter stated that as 

a general note, in almost every instance 

North Dakota, and by extension EPA, 

has converted the purportedly annual 

emission rate used in the BART 

analyses to a 30-day emission limit by 

increasing it by a seemingly arbitrary 

percentage increase. This has ranged 

from a low percentage up to at least 

40%. There is no support in the record 

for these increases, and it is not always 

clear that the original levels are not 

feasible as 30 day limits. While the 

commenter agreed that there can be 

additional variability in 30-day averages 

as compared to annual, EPA must 

adequately support any changes it 

makes to the emission levels analyzed. 

Response: In keeping with the BART 

Guidelines, we evaluated cost 

effectiveness on an annual basis. 

Specifically, we calculated cost 

effectiveness as the total annualized 

costs of control divided by annual 

emissions reductions. When discussing 

cost effectiveness in our proposal, we 

gave both the emissions reductions and 

emission rates (lb/MMBtu) on an annual 

basis. By contrast, the BART Guidelines 

indicate that EGU BART emission limits 

should be specified as 30-day rolling 

average limits. It is commonly 

understood that shorter averaging 

periods result in higher variability in 

emissions due to load variation, startup, 

shutdown, and other factors. However, 

BART emission limits must be met on 

a continuous basis. Accordingly, we 

have not generally required 30-day 

rolling average emission limits equal to 

the annual emission rates used for 

calculating cost effectiveness. We find it 

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20918 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

24 GRE also included estimates for certain 

elements based on site-specific information. As 

discussed in other responses, some of these 

elements should not be included in the cost 

estimates for CCS. 

25North Dakota RH SIP, Appendix C.2, Great 

River Energy, Coal Creek Stations, Units 1 and 2, 

BART Analysis, Revised December 12, 2007, Table 

4–2, p. 26. 26 Great River Energy Letter, July 15, 2011, Docket 

EPA–R08–OAR–2010–0406–0079, Table A–1a, pdf 

p. 7. 27LNC3 is an EPA acronym for low NOX coaland-air nozzles with close-coupled and separated 

overfire air which is one configuration among 

several that are considered SOFA. GRE used the 

acronyms LNC3 for the controls installed on Unit 

1 and LNC3+ for the additional controls installed 

on Unit 2. For the purposes of our action, we are 

treating both units identically and refer only to 

LNC3. 

is reasonable to allow a margin for 

compliance for the 30-day rolling 

average limits. In our experience, 30-day 

rolling average emission rates are 

approximately 5–15% higher than the 

annual emission rate. Therefore, we 

disagree with the commenter’s assertion 

that North Dakota and EPA arbitrarily 

adjusted the annual emission rates 

when setting 30-day rolling average 

emission limits. 

Comment: Commenter stated that EPA 

is requiring the use of unit-by-unit 

emission limits, though the State is 

within its rights to allow plant-wide 

averaging (citing 70 FR 39172). 

Response: We agree with the 

commenter that unit-by-unit emission 

limits are not strictly required. 

However, it is within the discretion of 

North Dakota to establish unit-by-unit 

emission limits. Where we are 

approving North Dakota’s BART 

determinations, we are accepting the 

basis for emission limits that they 

selected. In the case of Coal Creek, 

which is included under our FIP, we 

have clarified in our final action that 

Unit 1 and Unit 2 emissions may be 

averaged provided that the average does 

not exceed the limit. 

2. CCS Units 1 and 2 

a. EPA’s Use of the Control Cost Manual 

for CCS 

Comment: Commenter (GRE) stated 

that EPA guidelines as provided to 

states in identifying regional haze 

control requirements and as provided in 

EPA’s Control Cost Manual are best 

suited for evaluating average or typical 

installations. Commenter stated that 

because CCS 1 and 2 are uniquely 

designed and employ DryFiningTM

technology, any accurate analysis of 

add-on NOX controls must be sitespecific and not rely on general 

guidelines which might apply to a 

normal facility. 

Response: As required by North 

Dakota, GRE provided a BART analysis 

for CCS to the State in 2007. That 

analysis included an analysis of 

potential NOX controls, including 

SNCR. For several significant elements 

of its analysis of SNCR, GRE relied on 

EPA’s Control Cost Manual.24 This was 

consistent with EPA’s BART Guidelines, 

which are mandatory for CCS and 

which provide that cost estimates 

should be based on the Control Cost 

Manual where possible. 70 FR 39166. 

GRE now essentially criticizes its own 

earlier analysis, claiming that it was 

done only at a screening level. However, 

to the extent GRE believed that unique 

characteristics at CCS required more 

site-specific information or more indepth analysis, GRE could have and 

should have performed that analysis in 

2007. 

Nonetheless, we have evaluated GRE’s 

new analysis. For reasons we explain 

below, we have serious concerns about 

the validity and accuracy of GRE’s new 

analysis and we find it is reasonable for 

us to continue to rely on cost estimates 

based on EPA’s Control Cost Manual, as 

described in our proposal. See 76 FR 

58620. Every facility has unique 

elements; however, we do not agree that 

the elements at CCS are so unique that 

use of the Control Cost Manual is 

inappropriate. Also, we note that 

DryFiningTM was not installed until 

after the baseline period and was 

installed voluntarily, not to meet any 

regulatory requirement. We are not 

required to revisit the baseline controls 

or reconsider cost estimates based on 

voluntarily installed controls. On the 

contrary, there are significant issues 

with such an approach; it would tend to 

reward sources that install lesser 

controls in advance of a BART 

determination in an effort to avoid more 

stringent controls. 

Comment: Commenter stated that the 

removal efficiency for CCS 1 would not 

be 50% as anticipated from the EPA 

Pollution Control Cost Manual and as 

used in GRE’s original BART analysis, 

but would rather be 30% and 20% for 

Units 1 and 2 respectively. The 

commenter asserted that these emission 

estimates clearly change the basis for 

any cost effective determination. The 

commenter references Appendix B to 

GRE’s November 2011 Refined Analysis 

‘‘cost and performance review’’ by URS, 

which provides control efficiency data 

as a function of inlet NOX

concentrations for 55 existing SNCR 

installations. 

Response: We disagree with this 

comment. We proposed a control 

efficiency of 49% for CCS 1 and 2 based 

on the combination of both enhanced 

combustion controls and post 

combustion controls. We have reviewed 

GRE’s refined analysis, and we are not 

convinced that our 49% assumption is 

unreasonable. To the contrary, this level 

of NOX reduction still appears 

achievable. 

The URS report that GRE references to 

support its claim of reduced control 

efficiency values provides a plot in 

which NOX control efficiency is plotted 

as a function of inlet NOX

concentrations. The URS plot does not 

provide the boiler sizes which would be 

necessary for a comparison to the data 

in the Control Cost Manual, or for 

comparison to the control efficiency we 

used in the proposed FIP. Table 3.1, 

‘‘Control Cost Summary,’’ in GRE’s 

Refined Analysis shows control 

efficiencies of 25% and 20% for Units 

1 and 2 respectively, which differ from 

GRE’s assessment of a 50% control 

efficiency in its original August 2007 

BART analysis and its July 2011 

corrected analysis.25 26 GRE’s earlier 

50% control efficiency was a reduction 

from the 0.22 lb/MMBtu baseline 

(which included existing LNB with a 

level of SOFA) to an emission limit of 

0.11 with the addition of only SNCR 

controls (no additional or enhanced 

combustion controls). While we would 

not expect CCS could achieve a 50% 

control efficiency from the installation 

of SNCR alone, we do find our 

estimated 49% control efficiency 

reasonable based on the installation of 

both SNCR and enhanced combustion 

controls (SOFA plus LNB or LNC3).27

We proposed a NOX BART FIP limit 

for CCS 1 and 2 of 0.12 lb/MMBtu that 

would apply to each unit singly on 

30-day rolling average basis. We based 

this limit on our proposed finding that 

SNCR plus SOFA plus LNB was BART. 

While we continue to find that SNCR 

plus SOFA plus LNB is BART, we are 

changing the emission limit to 0.13 lb/ 

MMBtu averaged over both units on a 

30-day rolling average basis. Evidence 

submitted by commenters and our own 

additional analysis in evaluating 

comments has led us to conclude that 

this represents a more reasonable limit 

to apply on a 30-day rolling average 

basis. 

This limit represents a control 

efficiency of 47.8% based on the average 

annual baseline emission rate of 0.22 lb/ 

MMBtu (2003–2004) provided in the 

State’s BART determination. This value 

is slightly lower than the 49% control 

efficiency we assumed in our proposal, 

a value that was based on the State’s 

analysis. Beginning in 2010, CCS 2 

voluntarily started employing LNC3, the 

more stringent level of combustion 

controls that the State evaluated in its 

mstockstill on DSK4VPTVN1PROD with RULES2

Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20919 

28U.S. EPA, EPA Air Pollution Control Cost 

Manual, EPA/452/B–02–001, 6th Ed., January 2002, 

Section 4.2, Chapter 1, p. 1–3. 

29http://www.ftek.com/en-US/products/apc/ 

noxout/. 

30 Institute of Clean Air Companies, White Paper 

Selective Non-Catalytic Reduction (SNCR) for 

Controlling NOX Emissions, February 2008, p. 9. 

BART determination. Annual average 

Clean Air Markets data for this unit 

reflects a NOX emission rate of 0.153 lb/ 

MMBtu. We estimate that SNCR would 

achieve an additional 25% reduction, 

equivalent to an emission rate of 0.115 

lb/MMBtu. This compares to a value of 

0.108 lb/MMBtu that the State originally 

estimated. 

GRE asserted in comments that SNCR 

will only achieve a 20% reduction 

beyond LNC3. We find that 25% is a 

conservative and reasonable estimate. 

We considered several sources of 

information in arriving at this value. 

First, the Control Cost Manual states 

that in typical field applications, SNCR 

provides a 30% to 50% NOX reduction. 

The manual provides a scatter plot with 

NOX reduction efficiency plotted as a 

function of boiler size in MMBtu/hr.28

The plot supports GRE’s assertion that 

control efficiency could be lower than 

50%, and could approach 30%, for 

larger boilers such as those at CCS. 

Second, Fuel Tech (one of the most 

recognized SNCR technology suppliers) 

estimates a range of 25% to 50% NOX

reduction with application of SNCR.29

Lastly, ICAC has published information 

that supports a control efficiency of 20 

to 30% for SNCR above LNB/ 

combustion modifications.30 Given this 

range of control efficiencies, we have 

settled on a control efficiency that is 

lower than the lowest value given by the 

Control Cost Manual, at the low end of 

the range estimated by Fuel Tech, and 

in the middle of the range estimated by 

ICAC. 

To arrive at a final BART emission 

limit, we adjusted the projected annual 

average of 0.115 lb/MMBtu upward by 

10% and then rounded to the nearest 

hundredth to arrive at 0.13 lb/MMBtu. 

In our experience, a 5 to 15% upward 

adjustment is appropriate when 

converting an annual average emission 

rate to a limit that will apply on a 30- 

day rolling average to account for the 

fact that shorter averaging periods result 

in higher variability in emissions due to 

load variation, startup, shutdown, and 

other factors. 

As discussed in another response 

above, we do not agree with GRE that 

it is appropriate to lower the baseline 

emission rate based on GRE’s voluntary 

installation of combustion controls on 

Unit 2 in 2010, well after the State 

established the historic baseline of 

2003–2004 for BART planning. Use of 

such lower baseline rate would 

inappropriately skew the 5-factor BART 

analysis by reducing the emissions 

reductions from combinations of control 

options and increasing the cost 

effectiveness values. 

b. CCS Emission Limits 

Comment: Commenter stated that 

30-day rolling limits are intended to be 

inclusive of unit startup and shutdown 

as well as variability in load. 

Consequently, associated BART limits 

must be higher than stated annual 

averages used for estimating cost 

effectiveness. 

Response: As described in the 

proposed FIP, in proposing a BART 

emission limit of 0.12 lb/MMBtu, we 

adjusted the annual design rate of 0.108 

lb/MMBtu upwards to allow for a 

sufficient margin of compliance for a 

30-day rolling average limit that would 

apply at all times, including during 

startup, shutdown, and malfunction. 

While we proposed a BART limit of 0.12 

lb/MMBtu, we invited comment on 

whether we should impose a different 

emission limit of 0.14 lb/MMBtu on a 

30-day rolling average. After 

considering all comments, we have 

settled on a limit of 0.13 lb/MMBtu on 

a 30-day rolling average. We explain the 

basis for this limit in this section as well 

as in section III above. 

c. CCS Modeling 

Comment: Commenter stated that 

pollutant interaction has an impact on 

modeled visibility impairment and, as 

such, GRE believes that modeling 

changes to NOX emission rates alone 

will not provide visibility modeling 

results that are representative of actual 

emission controls. Commenter asserted 

that this may overstate visibility 

improvement as compared to modeling 

NOX, SO2 and PM2.5 together. However, 

for the purpose of illustrating the 

relative visibility impacts of SNCR and 

LNC3, the commenter presented an 

analysis of the incremental modeled 

impacts. 

Response: Our review of North 

Dakota’s and GRE’s CALPUFF input 

files reveals that SO2, NOX, and 

particulate matter (PM) emission 

changes were in fact modeled together. 

All of the NOX control options were 

modeled along with the SO2 emission 

reductions that would be achieved from 

either a new scrubber or modifications 

to the existing scrubber. However, in 

order to determine the distinct visibility 

improvement from the NOX control 

options, it is necessary to compare the 

modeled impacts to a pre-control 

scenario. This is in fact the approach 

prescribed by the BART Guidelines 

which state that you should ‘‘[a]ssess 

the visibility improvement based on the 

modeled change in visibility impacts for 

the pre-control and post-control 

emission scenarios.’’ 70 FR 39170. As 

noted in our proposal, because North 

Dakota did not provide visibility 

benefits relative to a pre-control 

baseline, ‘‘it [was] not possible to 

describe the incremental visibility 

benefits of SNCR, or other NOX control 

options, over the selected SO2 BART 

control (scrubber modifications at 95% 

control).’’ 76 FR 58623. As a result, we 

were only able to specify the 

incremental visibility benefit between 

NOX control options. In our evaluation 

of BART for NOX at CCS, we weighed 

the visibility factor in consideration of 

the fact that the improvement was 

incremental to lower NOX controls and 

not relative to a pre-control baseline. We 

are not able to assess the visibility 

benefit information the commenter 

provided in Table 3.3.1 of the comments 

due to the lack of documentation and 

detailed explanation of the information 

presented. 

d. CCS Coal Ash 

Comment: GRE references Appendix 

C to its Refined Analysis ‘‘Fly Ash 

Storage and Ammonia Slip Mitigation 

Technology Evaluation.’’ GRE claims 

that its previous estimates of fly ash 

sales and disposal costs were ‘‘screening 

level values’’ and the Appendix C report 

provides a more comprehensive 

assessment of ash implications 

associated with SNCR installation. GRE 

states that the report illustrates that any 

ash impact costs add to the total cost of 

SNCR and make it less cost effective. 

Response: Based on further analysis, 

we are not convinced that the use of 

SNCR will impact GRE’s ash sales. We 

explain this more fully in the responses 

below. Also, regarding specific sales 

price and costs numbers, we are not 

convinced that GRE’s Appendix C 

report, included with its comments, 

provides a more realistic picture of 

these values. We provide more detailed 

information in other responses. 

Comment: GRE stated that mandating 

SNCR will leave GRE in a vulnerable 

position where it would expect to incur 

significantly higher costs from lost ash 

sales and increased landfilling. 

Commenter stated that GRE would 

expect to annually incur between 

$4,435,000 and $8,988,000 in additional 

ash costs. Commenter’s contractor, 

Golder Associates, provided a revised 

analysis that included three potential 

scenarios of SNCR’s impact to fly ash 

sales (GRE Appendix C): A. Sales are 

not affected; B. Worst case scenario—no 

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20920 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

31 Information regarding EC/R and Dr. Staudt’s 

credentials is available in the docket. 

32Staudt, J., Hoover, B., Trautner, P., McCool, S., 

and Frey, J., ‘‘Optimization of Constellation 

Energy’s SNCR System at Crane Units 1 and 2 Using 

Continuous Ammonia Measurement,’’ AWMA, 

EPA, EPRI, DOE Combined Power Plant Air 

Pollution Control ‘‘Mega’’ Symposium, August 30– 

September 2, 2010, Baltimore, MD. 

33 Id. 

34EC/R also received input directly from Fuel 

Tech that its SNCR systems are fully capable of 

being operated so as to avoid detrimental ammonia 

levels in the fly ash. 

35Even should some portion of the CCS fly ash 

be affected by greater levels of ammonia, which we 

find unlikely, we conclude that ammonia slip 

mitigation (ASM) technology or another technology 

could be utilized to address or mitigate ammonia 

in the fly ash. Dr. Ron Sahu, in comments on our 

proposal, mentions three possible systems that 

could be used, and our consultants are aware of no 

technical reasons that ASM technology would not 

be effective to mitigate ammonia on fly ash from 

lignite. 

36http://my.epri.com/portal/server.pt?Abstract_

id=000000000001014269. 

37Staudt, J., Hoover, B., Trautner, P., McCool, S., 

and Frey, J., ‘‘Optimization of Constellation 

Energy’s SNCR System at Crane Units 1 and 2 Using 

Continuous Ammonia Measurement,’’ AWMA, 

EPA, EPRI, DOE Combined Power Plant Air 

Pollution Control ‘‘Mega’’ Symposium, August 30– 

September 2, 2010, Baltimore, MD. 

38EPA–R08–OAR–2010–0406–0077, Letter from 

GRE to NDDH, February 9, 2010. 

39http://www.ag.ndsu.edu/pubs/ageng/safety/

ae1149-1.htm. 

ash sales; and C. 30% reduction in ash 

sales. Commenter asserted that scenario 

A is extremely unlikely, scenario B is a 

likely outcome, and scenario C is 

optimistic. 

Response: In the proposed FIP, EPA 

agreed that use of SNCR might result in 

lost ash sales and the need to landfill fly 

ash due to ammonia contamination. 

These additional costs were included in 

our cost analysis supporting the FIP. 

However, we also invited comment on 

the assumption that use of SNCR would 

result in lost fly ash sales and on the 

availability of ammonia mitigation 

techniques. 76 FR 58620. We received 

responsive comments on both sides of 

the issue. 

In the proposed FIP, EPA included 

costs of $2,023,000 for ‘‘additional ash 

disposal’’ and $2,023,000 for ‘‘lost ash 

sales’’ (76 FR 58621). EPA arrived at 

these values based on information that 

GRE itself supplied in July 2011. Based 

on an analysis performed by a 

consultant, GRE now asserts that the 

information GRE supplied in June and 

July 2011, regarding the sales price for 

fly ash and the costs for fly ash disposal, 

was not accurate. GRE supplied this 

information initially in June 2011 when 

it discovered that the information that it 

supplied to the State regarding these 

values in 2007 was inaccurate. 

As part of our consideration of GRE’s 

comments, and comments submitted by 

others disputing the notion that SNCR 

use would affect fly ash sales, we have 

investigated and analyzed this issue 

further. As part of our effort, we have 

contracted with EC/R, an engineering 

consulting firm, which in turn engaged 

Dr. James Staudt of Andover 

Technology Partners (ATP), who has 

expertise regarding the issue of 

ammonia in fly ash.31

Dr. Staudt recently presented a paper 

at the AWMA, EPA, EPRI, DOE 

Combined Power Plant Air Pollution 

Control ‘‘Mega’’ Symposium, August 

30–September 2, 2010, Baltimore, 

Maryland, which reviewed the 

performance benefits in terms of 

ammonia slip, reagent consumption, 

and fly ash ammonia that is possible 

through optimization of SNCR operation 

using the information from continuous 

and real-time monitoring of ammonia 

slip.32 As explained more fully below, 

current technology has made it possible 

to control ammonia slip from SNCR to 

levels similar to what is achievable with 

SCR, in the range of 2 ppm or less. It 

is widely accepted that ammonia at this 

level does not impact the potential sales 

and use of fly ash in concrete. 

One type of continuous ammonia slip 

analyzer works on the principle of 

tunable diode laser spectroscopy and 

provides continuous, real-time 

indications of ammonia slip in the duct. 

This type of analyzer facilitates 

optimum operation of the SNCR system 

and minimizes ammonia slip.33 In other 

words, GRE would not incur costs for 

lost sales of fly ash or additional ash 

disposal if it employed such a system at 

CCS.34

For these reasons, we conclude that 

charges for lost fly ash sales should not 

be applied to the SNCR system cost 

analysis and that SNCR can be 

successfully deployed at the CCS plant 

at a cost effectiveness level well below 

the estimate in our proposal of $2,500/ 

ton of NOX removed.35

Comment: Commenter stated the 

addition of SNCR will have a negative 

impact on the marketability, value, and 

perception of CCR’s fly ash. The 

commenter further stated that increased 

levels of ammonia in the fly ash with 

SNCR create offensive odors, are 

potentially dangerous to human health, 

and can pose an explosion risk. 

Commenter cited EPA’s Control Cost 

Manual to bolster this position. 

Commenter stated that ammonia slip of 

only 5 ppm, generally accepted as the 

minimum that can be achieved with 

SNCR, can render fly ash unmarketable. 

Response: EPRI performed a study in 

2007 that examined the effects of 

ammonia slip from SCR systems and 

reached the conclusion that ‘‘The survey 

overwhelmingly indicated that 

ammonia contamination is not 

impacting the ability of plants to sell 

ash.’’ 36 Therefore, if an SNCR system 

were to achieve similar ammonia slip 

levels as SCR systems, then an adverse 

impact on fly ash marketability would 

not be expected. 

Commenter’s assertion that 5 ppm is 

the minimum that can be achieved with 

SNCR is not consistent with experience 

with recently installed, state-of-the-art, 

SNCR systems. As noted above, recently 

installed SNCR systems are capable of 

ammonia slip levels in the range of 2 

ppm, and experience at the CP Crane 

Station in Baltimore, Maryland 

demonstrates that ammonia slip can be 

maintained below 2 ppm while also 

ensuring that high ammonia slip 

excursions during load changes and 

other transients are avoided.37

In some cases the testimonials 38

provided by GRE regarding the adverse 

effects of ammonia are highly 

questionable. As an example, one of the 

testimonials from a Mr. Boggs 

incorrectly cautions about the 

explosiveness of ammonia— 

‘‘I would point out that with the storage 

dome at Coal Creek, the ammonia levels that 

could accumulate would be extremely 

hazardous. A little know (sic) fact is that 

ammonia is an explosive gas at certain levels 

when it accumulates with air present’’. 

On the other hand, according to the 

North Dakota State University, 

‘‘Anhydrous ammonia is generally not 

considered to be a flammable hazardous 

product because its temperature of ignition is 

greater than 1,560 degrees F and the 

ammonia/air mixture must be 16 percent to 

25 percent ammonia vapor for ignition.’’ 39

Although, in principle, ammonia can 

be combustible under special 

conditions, these are conditions that are 

highly unlikely to result from ammonia 

in fly ash—even if fly ash ammonia 

concentrations were to reach several 

hundred ppm. In fact, to our knowledge, 

there has never been a fire or explosion 

resulting from ammonia in fly ash. 

In summary, GRE’s comments and 

testimonials generally overstate the real 

concerns regarding ammonia that may 

result in the fly ash of a plant equipped 

with SNCR. 

Comment: Commenter stated that the 

social, economic and environmental 

benefits from re-using ash are not 

outweighed by costs nor are they 

outweighed by the imperceptible 

improvements to visibility. 

Response: As stated above, EPA 

anticipates that application of SNCR at 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20921 

40 Docket EPA–R08–OAR–2010–0406–0201, GRE 

comments, pdf p. 27. 

41The American Coal Ash Association indicates 

that where ash is disposed near the power plant, a 

cost of $5/ton is reasonably expected. 

42Staudt, J., Hoover, B., Trautner, P., McCool, S., 

and Frey, J., ‘‘Optimization of Constellation 

Energy’s SNCR System at Crane Units 1 and 2 Using 

Continuous Ammonia Measurement’’. AWMA, 

EPA, EPRI, DOE Combined Power Plant Air 

Pollution Control ‘‘Mega’’ Symposium, August 30– 

September 2, 2010, Baltimore, MD. 

43This is supported by the Fly Ash Resource 

Center as stated on its Web site, ‘‘Ashes that are 

basic in nature with very low sulfur content adsorbs 

much less ammonia than high sulfur Eastern 

bituminous coal ashes.’’ http://www.rmajko.com/

qualitycontrol.htm. 

44http://www.rmajko.com/suppliers1.html. 

45http://www.azdot.gov/highways/materials/pdf/

materials_source_list_flyash.pdf. 

CCS would not decrease the amount of 

ash re-use. Our FIP is based on a 

reasonable consideration of the five 

BART factors: Costs of compliance, the 

energy and non-air quality 

environmental impacts of compliance, 

any existing pollution control 

technology in use at the source, the 

remaining useful life of the source, and 

the degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

We understand that GRE may have 

reached a different result based on its 

consideration of the statutory factors 

and other factors; that does not mean 

our determination is unreasonable. 

Comment: Commenter asserted that 

changes to the quantity of fly ash 

marketed and sold will have a direct 

impact on fly ash management costs, as 

the revenue currently used to offset fly 

ash management will be lost. The lost 

fly ash sales revenue is based on the 

2010 average price per ton FOB of 

$41.00; with 30% of the sale price going 

to GRE as revenue. 

Response: As stated above, we do not 

agree that fly ash sales would be 

impacted. If there were any lost 

revenue, the lost revenue to GRE is the 

only cost that should be considered, not 

the full FOB price which includes 

revenues to others. This cost was $5/ton 

prior to December 2011 40 as presented 

by GRE in its comments. Were it still 

relevant, we would consider this a 

reasonable price to use. In addition, we 

would consider $5/ton to be a 

reasonable cost to GRE for ash disposal, 

resulting in a total cost to GRE of $10/ 

ton.41 URS increased the ash sales price 

to $12.30 in the refined analysis based 

on GRE’s 2012 ash sales contract price. 

We are not convinced that such an 

increase would be appropriate. GRE did 

not provide any detail on the basis for 

the increased price. Considering this is 

a 2012 contract price, it may even be 

based on projected information. It was 

reasonable for us to rely on the best 

estimates at the time of our proposal. 

We note that GRE itself supplied these 

estimates. 

Comment: Commenter stated that 

EPA’s Control Cost Manual (2002) does 

not allow GRE to include in the BART 

analysis the value of previously 

purchased assets that would be 

rendered useless by the elimination or 

reduction of fly ash sales. GRE claims 

$31 million has been invested on ash 

storage, transportation and distribution 

infrastructure along with their strategic 

partner Headwaters Resources. Of the 

$31 million, GRE has contributed $7 

million. 

Response: Given the availability of 

means to control ammonia levels in the 

fly ash, we do not agree that previously 

purchased storage, transportation, and 

distribution infrastructure would be 

rendered useless. However, the 

commenter is correct that the Control 

Cost Manual does not consider the costs 

of existing infrastructure that would be 

rendered useless as a result of installing 

new or retrofit controls. The Control 

Cost Manual is designed to provide 

methods for estimating the specific costs 

of installation and operation of control 

technologies to allow consistent 

comparison of such costs across 

multiple sources; thus, the ‘‘stranded’’ 

costs for existing infrastructure are not 

accounted for in the cost estimation 

methodology found in the Control Cost 

Manual. 

Comment: Commenter asserted that 

even with a cost effective ASM 

technology installed, there will be times 

when the residual ammonia levels in 

the ash are too high to treat. Ammonia 

injection rates will vary during periods 

of startup and shutdown, in addition to 

variable load operation, in order to 

maintain compliance with the BART 

limits. The commenter stated that 

variable ammonia injection rates and 

associated changes in ash 

concentrations will result in frequent 

testing and periodic rejection of ash 

requiring on-site disposal. The 

commenter further stated that variable 

ammoniated ash levels will put GRE’s 

generated ash in a very vulnerable 

position with respect to competitors in 

the fly ash marketplace, reducing ash 

sales and increasing on-site disposal. 

Response: Testimonials provided by 

GRE cited older SNCR systems, such as 

Eastlake Station in Eastlake, Ohio, as 

causing problems for fly ash 

marketability. (The testimonials also 

reaffirmed that fly ash from boilers with 

SCR systems remained marketable.) The 

Eastlake SNCR system was installed 

several years ago, and current state-ofthe-art SNCR systems have been 

demonstrated to control ammonia slip 

to avoid high ammonia slip transients, 

as described by Staudt, et al.42

Ammonia slip can be consistently 

maintained at low levels in the range of 

2 ppm or less over a wide range of loads 

for load following units, and this was 

demonstrated at the two units at CP 

Crane Station near Baltimore. The 

control system was optimized expressly 

to minimize the effects of ammonia on 

plant fly ash. This was made possible by 

utilizing permanently installed 

ammonia monitoring devices. Both 

units needed to maintain slip at low 

levels while making several rapid load 

changes a day. CP Crane Station has 

continued to control the SNCR system 

in this manner. As described in the 

referenced paper, the accuracy of the 

continuous ammonia instruments were 

shown to be comparable to wet 

chemistry measurements at these low 

levels of ammonia slip and the 

instruments have had good reliability. 

Another aspect of ammonia slip and 

impact on fly ash marketability is that 

the alkalinity of the fly ash will impact 

how much ammonia becomes attracted 

to the fly ash. Fly ash from bituminous 

coals, with more sulfur trioxide, will 

tend to attract more ammonia than fly 

ash with a high alkalinity, such as fly 

ash from North Dakota lignite. As a 

result, ammonia deposition on fly ash at 

CCS is likely to be less of an issue than 

it would be on a bituminous coal unit, 

such as Eastlake, and higher ammonia 

slip levels may be tolerable before fly 

ash marketability is affected.43

Comment: Commenter stated that, to 

GRE’s knowledge, no lignite-fired unit is 

currently operating SNCR and ASM 

technology, and the vendor would not 

guarantee any level of performance for 

a lignite-fired unit. 

Response: Evidence indicates that 

modern SNCR systems can achieve 

ammonia levels of 2 ppm or below, 

which would avoid the need for use of 

ASM technology. 

Our review of EPA Title IV data for 

2010 found that there are three 

tangentially fired coal-fired boilers that 

burn lignite coal and control emissions 

to under 0.14 lb/MMBtu with SNCR. 

These include Big Brown 1 and 

Monticello 1 and 2. According to the Fly 

Ash Resource Center, both the Big 

Brown Plant and the Monticello Plant 

market their fly ash through Boral 

Materials.44 The Monticello fly ash was 

designated an approved material by the 

Arizona Department of Transportation 

(July 2011 45) and Georgia Department of 

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46http://www.dot.state.ga.us/doingbusiness/

materials/qpl/documents/qpl30.pdf. 

47http://www.boralna.com. 

Transportation (January 2012 46). 

According to Boral’s Web site, the Big 

Brown ash has been designated an 

approved material by several state 

departments of transportation.47 Both of 

these plants are selling their fly ash and 

are not experiencing adverse impacts 

with ammonia in the ash. 

This is further evidence that GRE’s 

assumption, that the CCS plant would 

be unable to market its fly ash, is 

unjustified. Also, as indicated above, if 

it were necessary to employ ammonia 

mitigation to the fly ash, we think at 

least one of the available systems could 

be employed at CCS. 

Comment: Commenter stated that the 

BART analysis does not take into 

account the additional regional 

economic impacts resulting from the 

reduction of CCS ash sales. GRE uses 

the freight on board (FOB) price of the 

ash to estimate a loss to the local and 

regional economy from the elimination 

of ash sales of as much as $28.70/ton or 

$11,910,500 per year. 

Response: As we have already 

discussed, we do not agree that ash sales 

would be reduced with the 

implementation of SNCR. Thus, there 

should be no regional economic impacts 

from lost fly ash sales. However, were 

this comment still relevant, we note two 

points. First, the BART Guidelines, 

which are mandatory for CCS, prescribe 

a method for estimating the specific 

costs of installation and operation of 

control technologies to allow consistent 

comparison of such costs across 

multiple sources. This method does not 

include consideration of regional 

economic impacts. If such impacts were 

to be considered, different 

methodologies and different notions of 

cost effectiveness would have to be 

developed. While we are sensitive to 

broader economic impacts, they are not 

part of our focused analysis of the BART 

factors in making a BART 

determination. 

Second, if we were to consider such 

impacts, there is considerable 

uncertainty in the estimate GRE 

provided, which attempts to conduct a 

complex economic assessment based on 

FOB price alone. For example, the 

estimate does not consider the offsetting 

economic impact of replacement 

materials, such as alternative concrete 

admixtures, which would be used by 

concrete manufacturers as an alternative 

to CCS’s ash. 

Comment: Commenter stated that loss 

of ash sales at CCS would negatively 

impact the regional and national 

economy, as well as the regional and 

national infrastructure. The commenter 

stated that the beneficial use of fly ash 

is directly responsible for a large 

number of jobs throughout the country. 

The commenter highlighted the 

importance of fly ash as a component of 

road and bridge construction across the 

country, and cited a report by the 

American Road and Transportation 

Builders Association. According to GRE, 

the research in the report concluded 

that the elimination of fly ash as a 

construction material would increase 

the average annual cost of building 

roads, runways, and bridges in the 

United States by nearly $5.23 billion. 

This total includes $2.5 billion in 

materials price increases, $930 million 

in additional repair work and $1.8 

billion in bridge work. The additional 

costs would total $104.6 billion over 20 

years. 

Response: For the reasons expressed 

in our response to the previous 

comment and in our other responses, we 

do not consider this comment relevant 

to our decisions. We have concluded 

that CCS’s ash sales will remain 

feasible, and find that the impacts cited 

by GRE are impacts that would apply to 

the entire fly ash industry and not just 

CCS. Furthermore, there is not sufficient 

evidence that elimination of CCS’s ash 

sales would result in any of the impacts 

described above. 

Comment: Commenter stated that the 

use of fly ash as a replacement for 

cement has environmental benefits. 

Commenter asserted that as a result of 

the increased use of fly ash, less land is 

disturbed for quarrying raw materials, 

less land is taken out of production for 

landfills, and less carbon dioxide (CO2) 

is emitted into the atmosphere to make 

cement. Commenter argued that there 

will be a 1 to 1 ton increase in CO2

emissions from using more Portland 

cement in place of ash. 

Response: As stated in previous 

responses, we do not agree that the use 

of SNCR will cause GRE to experience 

a reduction in fly ash sales. 

Furthermore, GRE presents no evidence 

to support its claims about CO2

emissions or reduced quarrying. CO2

emissions result from many factors, and 

additional quarrying might be avoided 

through use of alternative sources of fly 

ash. As did the State, we have already 

considered the potential need to landfill 

additional fly ash in our five factor 

analysis, but do not consider that a 

reason to reject SNCR as BART. 

Comment: Commenter stated that the 

landfill cost estimate includes costs for 

the life of the disposal facility including 

engineering, design, and permitting; 

construction; and operations and 

maintenance, including closure and 

post-closure care. 

Response: As we stated in previous 

responses, we are not convinced that the 

use of SNCR will impact GRE’s ash 

sales; thus, requiring additional on-site 

landfill facilities should not be 

necessary. Furthermore, we have noted 

in prior responses that we find a 

disposal cost of $5/ton is reasonable in 

the improbable event that some ash 

would need to be disposed. 

Comment: Commenter stated that the 

ash management costs used in this 

analysis assumes that future ash 

disposal facilities will be designed and 

constructed to meet RCRA subtitle D 

standards. Commenter asserted that this 

cost would increase considerably if EPA 

tightens standards as a result of the 

uniform national disposal standards 

currently being considered. 

Response: As already discussed, we 

do not agree that SNCR will lead to 

increased landfilling. Were this 

comment still relevant, we note that we 

evaluate costs based on the best 

information available concerning 

current costs. We do not know what the 

final coal combustion residuals 

regulations will require with respect to 

RCRA subtitle D and we are not 

required to include speculative costs in 

our estimates. 

e. CCS Visibility Improvements Are 

Minimal 

Comment: Commenter stated that the 

refined analysis demonstrates that the 

installation of SNCR will not result in 

perceptible visibility improvements in 

North Dakota’s Class I areas, and it is 

not justifiable for GRE to incur the 

added cost of SNCR without any 

appreciable improvement in visibility. 

To support these claims, the commenter 

stated that from GRE’s BART analysis, it 

can be estimated that the incremental 

deciview improvements associated with 

the installation of SNCR would range 

from 0.109 to 0.207, which are well 

below what EPA has established as a 

perceptible level to the human eye (0.5 

deciviews). 

Response: There is considerable 

uncertainty in the deciview 

improvements calculated by GRE. GRE 

provides an analysis of the incremental 

modeled impacts and cost per deciview 

in Table 3.3.1 of GRE’s November 2011 

Refined Analysis, but provides no 

further explanation of the table or the 

values contained therein. A January 19, 

2012 NDDH letter to CCS also raises 

concerns about certain aspects of the 

table pertaining to baseline emission 

rates and deciview improvement values. 

In addition, it appears that GRE has 

calculated these values based on new 

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48Source: http://www.wrapair.org/forums/ssjf/ 

pivot.html. 

assumptions, and EPA raises concerns 

about some of these assumptions (e.g., 

control efficiency of SNCR) in other 

comment responses within this 

document. 

Even if the results were correct, as 

noted elsewhere in our response to 

comments, the RHR is clear that 

perceptibility of visibility improvement 

is not a test for the suitability of BART 

controls. Also, as noted elsewhere in 

our response to comments, we have not 

used the dollar-per-deciview metric and 

find that it is reasonable to evaluate 

control options on the basis of the cost 

effectiveness in dollar-per-ton removed 

in conjunction with the modeled 

visibility improvement. 

Concerning our consideration of 

visibility improvement in the CCS 

BART determination, the BART 

Guidelines (40 CFR part 51, appendix Y) 

state that deciview improvements must 

be weighted among the five factors and 

the Guidelines provide flexibility in 

determining the weight and significance 

to be assigned to each factor. Thus, 

achieving a visibility improvement 

greater than the perceptible level of 0.5 

deciviews is not a prerequisite for 

selecting a particular control option as 

BART at CCS. 

Comment: Commenter stated that 

combined utility NOX emissions in 

North Dakota represent approximately 

only 6% of total NOX emissions, and 

therefore, it is understandable that 

proposed and additional BART NOX

reductions from North Dakota utilities 

do not provide more visibility 

improvements in the Class I areas. 

Response: We disagree with the 

commenter’s assertion that the potential 

visibility improvements from NOX

controls on North Dakota EGUs would 

be small. The commenter’s estimate of 

the contribution from utilities to NOX

emissions in North Dakota appears to be 

incorrect. Emission inventories 

developed by the WRAP for the 2000– 

2004 planning period show that EGUs 

contributed 78,995 tons out of a total of 

229,460 tons of NOX for all source 

categories combined.48 Therefore, 

utilities account for some 34.4% of the 

total NOX emissions in North Dakota, 

and more than any other source 

category. 

Furthermore, the RHR states that 

BART determinations are based on 

circumstances such as the distance of 

the source from a Class I area, the type 

and amount of pollutant at issue, and 

the availability and cost of controls (70 

FR 39116). Thus, sources that are closer 

to Class I areas and emit the types of 

pollutants that contribute to regional 

haze are more likely to be subject to 

BART requirements, regardless of their 

percent contribution to the statewide 

NOX emission rate. 

Comment: Commenter (GRE) stated 

that ammonia is a listed state toxic in 

North Dakota, and is viewed as a 

contributor to regional haze because it 

can bond with SO2 and NOX to form 

ammonium sulfate and ammonium 

nitrate aerosols. Commenter further 

stated that additional ammonia slip 

from the proposed SNCR for CCS may 

offset the relatively minor NOX

reduction proposed by EPA. 

Response: GRE does not provide the 

anticipated ammonia emissions for 

comparison to the proposed NOX

reductions and states that this issue is 

outside the scope of its analysis. In the 

RHR, EPA states that there are scientific 

data illustrating that ammonia in the 

atmosphere can be a precursor to the 

formation of particles such as 

ammonium sulfate and ammonium 

nitrate; however, it is less clear whether 

a reduction in ammonia emissions in a 

given location would result in a 

reduction in particles in the atmosphere 

and a concomitant improvement in 

visibility (70 FR 39114). The evaluation 

of whether ammonia slip would offset 

the proposed NOX reductions to some 

degree cannot be calculated due to the 

lack of information provided by GRE, as 

well as the inherent uncertainty in 

estimating the effects of ammonia 

emissions on regional visibility. 

Furthermore, as stated in our previous 

responses, ammonia slip, due to the 

incomplete reaction of the NOX

reducing agent, can be limited to low 

levels through proper design of the 

SNCR system. Design of the SNCR 

system can be optimized by taking into 

account the temperature, NOX

concentration, residence time, and 

reagent distribution. Our recent analysis 

indicates that ammonia slip levels can 

be reduced to below 2 ppm with the 

introduction of the latest monitoring 

technology. Therefore, we disagree that 

any potential ammonia release from 

SNCR at CCS may offset the proposed 

NOX reductions. 

Comment: Commenter stated that 

NOX contributes to ammonium nitrate 

formation, which is predominantly a 

winter ‘‘haze’’ contributor, and for the 

purposes of valuing the welfare effects 

of recreational visibility, it is important 

to consider that the North Dakota 

national parks are generally not in high 

use during the winter season. 

Commenter expressed concern over 

paying an extreme price per deciview 

resulting in imperceptible 

improvements for a time of year when 

the parks are generally not used. 

Response: We addressed this 

comment in our responses to modeling 

comments in section V.C. 

f. Comments on Alternative NOX

Emission Limits 

In our proposal, we asked for 

comments on a possible alternative NOX

BART limit for CCS 1 and 2, based on 

use of combustion controls alone, of 

0.14 lb/MMBtu. This section presents 

the comment summaries and our 

responses related to this issue. 

Comment: Commenter stated that 

because CCS cannot achieve the 30-day 

rolling average emission rate without 

installation of SNCR, it should not be 

considered as an appropriate BART 

emission level. Commenter stated that 

this is consistent with EPA’s own 

determination that a presumptive BART 

emission level of 0.17 lb/MMBtu is costeffective and will result in significant 

visibility improvement. Commenter 

stated that these comments and the 

associated Refined Analysis 

demonstrate that any additional NOX

reductions would neither be costeffective nor would result in perceptible 

visibility improvement in Class I areas. 

Response: EPA does not agree with 

the commenter’s assertions. EPA 

disagrees with certain of GRE’s 

assumptions in its Refined Analysis. 

Please refer to other comment responses 

throughout this document for details 

about each of these assumptions. We 

have reasonably considered the five 

BART factors and have arrived at a 

reasonable BART determination. 

As to the presumptive limits, the 

BART Guidelines state that utility 

boilers should be required to meet the 

presumptive NOX emission limits, 

unless it is determined that an 

alternative control level is justified 

based on consideration of the statutory 

factors. As noted elsewhere, our 

regulations require that a state or EPA 

must consider the five statutory BART 

factors in determining BART and cannot 

simply default to the presumptive 

limits. We have already explained why 

the State’s consideration of the costs of 

compliance was fatally flawed and why 

we must disapprove the State’s BART 

determination. In promulgating our FIP, 

we have reasonably considered the five 

factors and arrived at a reasonable 

BART determination that is more 

stringent than the presumptive BART 

limit. 

Comment: Commenter stated that 

NOX limits should be expressed on an 

annual rather than 30-day basis, to 

account for the full spectrum of 

operations such as variable load, and 

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49See www.regulations.gov, docket EPA–HQ– 

OAR–2009–0491. 

startups or shutdowns not accounted for 

in emission limits based on vendor 

guarantees. The commenter notes that 

an emission limit of 0.14 lb/MMBtu was 

achieved for a period of time, but it is 

not sustainable on a 30-day rolling 

average basis. Commenter cited 

attachment 1, GRE’s operational history, 

as a rationale. 

Response: The BART Guidelines 

require specification of a 30-day rolling 

average limit for EGUs; therefore, all 

averaging times in the proposed FIP 

have been stated on a 30-day rolling 

average basis, including necessary 

upward adjustments from annual 

emission rates to account for potential 

variations in emissions on a 30-day 

basis. For the reasons stated elsewhere, 

we have not changed our determination 

that SNCR plus SOFA plus LNB is 

BART, but we have changed the NOX

BART limit for CCS 1 and 2 to 0.13 lb/ 

MMBtu on a 30-day rolling average 

basis. 

Comment: Commenter argued that the 

NOX emission limits proposed in the 

original BART evaluation for Units 1 

and 2 did not consider that the units 

would experience significant load 

variability. Commenter stated that in 

September 2011, GRE increased the 

cycling range of CCS in response to 

market conditions, which caused 

significant load swinging and impacts to 

NOX control performance. Commenter 

further stated that load variability is 

expected to continue as an operational 

scenario for Units 1 and 2 for the 

foreseeable future, and therefore any 

emission limit must account for this 

additional variability in emissions. The 

commenter asserted that the 

presumptive emission rate of 0.17 lb/ 

MMBtu is achievable, including load 

variability. 

Response: The 0.13 lb/MMBtu limit 

we have selected provides a reasonable 

margin for compliance, not only for load 

variability, but also for startup and 

shutdown conditions. The emission 

limit we have set also takes into 

consideration the control efficiency that 

can be achieved with SNCR. We have 

provided further discussion on this in 

previous responses. 

Comment: Commenter stated that 

reducing NOX to the absolute limits of 

LNC3 and DryFiningTM leads to 

collateral damage to the CCS boilers. 

Specifically, GRE claims that 

installation of the second generation 

LNC3 technology in 2008 on Unit 2 

contributed to circumferential cracking 

on the boiler tubes between the burner 

front and the over-fired air registers, as 

operators attempted to maintain low 

NOX emission rates. GRE further stated 

that the 2010 implementation of 

DryFiningTM technology with LNC3 

accelerated tube leaks at CCS 2, causing 

unplanned outages. The commenter 

asserted that while it has been possible 

to operate at lower NOX emission rates 

during ideal conditions, the risk of 

circumferential cracking increases 

significantly when operating at these 

lower rates. The commenter concluded 

that an emission rate between 0.14 and 

0.17 lb/MMBtu for LNC3 and 

DryFiningTM is not consistently 

achievable as a 30-day rolling emission 

limit; and the commenter firmly 

believes that 0.17 lb/MMBtu is the most 

stringent level. 

Response: We have decided to finalize 

our proposal that SNCR + SOFA + LNB 

is BART. We note that using SNCR 

would alleviate GRE’s concerns about 

circumferential cracking from use of 

LNC3 and DryFiningTM while also 

helping to maintain NOX emissions 

during periods of load variability. We 

provide additional responses pertaining 

to emission limits in this section. 

Comment: Commenter stated that 

from a review of EPA modeling 

information from the Cross-State Air 

Pollution Rule (CSAPR) docket,49 there 

are currently no tangentially-fired utility 

EGUs, in the CSAPR-affected states, 

with LNC3 combustion controls and 

SNCR post-combustion controls that 

operate at or below the presumptive 

BART limit of 0.17 lb/MMBtu for NOX.

The commenter further stated that none 

of the facilities included in the CSAPR 

database operate at or below the 

proposed FIP limit of 0.12 lb/MMBtu. 

Response: The proposed 0.12 lb/ 

MMBtu emission rate was based on the 

information that GRE itself supplied to 

North Dakota in 2007, and which North 

Dakota evaluated in its BART 

determination. Starting from baseline 

emission rates from 2000 to 2004 and 

the 50% SNCR control efficiency that 

GRE estimated, North Dakota arrived at 

an average annual emission rate of 0.108 

lb/MMBtu. We adjusted this to 0.12 lb/ 

MMBtu to arrive at a proposed 30-day 

rolling average emission limit. 

Our analysis focuses on what is 

achievable using SNCR at CCS, based on 

the Control Cost Manual, vendor 

information (Fuel-Tech), the State’s 

analysis, GRE’s analysis, and our own 

analysis and expertise. 

Analysis of emissions data found 

significant discrepancies in Figures 2.2 

and 2.3 of GRE’s November 2011 

Refined Analysis. A review of EPA Title 

IV data for 2010 showed 94 coal-fired 

boilers that do not have SCR achieve 

annual emissions levels below 0.17 lb/ 

MMBtu, with the median slightly under 

0.14 lb/MMBtu (see Figure 1 below). Of 

these, ten of them are using SNCR in 

combination with combustion controls 

to achieve under 0.17 lb/MMBtu. See 

docket for a list of these facilities. Of 

these ten, three are supercritical 

tangentially-fired boilers that use lignite 

coal with emissions below 0.14 lb/ 

MMBtu. These include Big Brown 1 and 

Monticello 1 and 2, as discussed earlier 

in our responses. In addition, the 

NEEDS Database v.4.10 for the Final 

Transport Rule in the CSAPR docket 

includes two tangentially-fired coal/ 

steam units from North Carolina with 

LNC3 and SNCR that had emission rates 

of 0.159 lb/MMBtu and 0.164 lb/ 

MMBtu. 

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50This is based in part on, ‘‘Measuring Ammonia 

Slip from Post Combustion NOX Reduction 

Systems,’’ James E. Staudt, Andover Technology 

Partners, ICAC Forum 2000. 

51The $10/kW capital cost is within the range 

that industry sources find reasonable for typical 

SNCR utility installations. See Institute of Clean Air 

Companies, White Paper Selective Non-Catalytic 

Reduction (SNCR) for Controlling NOX Emissions, 

February 2008, p. 7. 

52We used the $3,627,729 direct capital cost 

provided by the company and adjusted this to 2009 

dollars. We then used the cost factors in the Control 

Cost Manual. 

53We have included our calculations in the 

docket. 

As we explain elsewhere, we have 

decided to revise the BART limit from 

0.12 lb/MMBtu to 0.13 lb/MMBtu on a 

30-day rolling average. 

Comment: Commenter stated that the 

0.14 lb/MMBtu emission rate would 

only be achievable after installation of 

SNCR (and cannot be achieved by LNC3 

alone), and SNCR is not cost-effective 

based on thresholds established by 

North Dakota and already approved by 

EPA. 

Response: We are not aware of any 

cost effectiveness thresholds established 

by North Dakota and already approved 

by EPA. In making a BART 

determination, cost-effectiveness is one 

factor that must be taken into account, 

but the relevance of a particular dollarper-ton figure for controls will depend 

on consideration of the remaining 

statutory factors. As already explained, 

we disagree with a number of GRE’s 

assumptions underlying its cost 

calculations and its assertion that SNCR 

is not cost-effective. 

As noted in prior responses, we no 

longer agree that the use of SNCR at CCS 

would lead to a loss of fly ash sales. 

Accordingly, EPA has revised its cost 

analysis on a per unit basis and has 

determined that SNCR could be 

installed and operated at CCS for 

$1,313/ton. This value assumes no costs 

for lost fly ash sales and no additional 

fly ash disposal costs. This cost includes 

combustion control costs and the 

combined control efficiencies for SNCR 

and combustion controls. Our research 

indicates that the cost of up-front 

ammonia slip control systems would 

likely be included in the control 

package from current SNCR suppliers 

where the need to control ammonia slip 

is identified, so we have not included a 

separate cost for such a control system 

in our revised cost estimate; evidence 

indicates that if there were any 

incremental cost associated with such a 

control system, it would not 

significantly affect the overall cost 

effectiveness of the controls.50 We used 

a total capital investment for SNCR of 

$6.92 million ($10/kW51) that we 

derived from the company’s July 15, 

2011 submittal.52 As explained more 

fully in a subsequent response, we find 

that URS’s November 2011 analysis for 

GRE overestimates the capital costs for 

SNCR, among other things, by including 

a retrofit factor when none is warranted. 

Nonetheless, even if we use URS’s 

inflated estimate of $11.80 million ($21/ 

kW) for the total capital investment of 

SNCR, the resultant cost effectiveness 

value would be $1,524/ton.53 Both the 

$1,313 per ton and $1,524 per ton 

values are well within the range of 

values that EPA and states other than 

North Dakota have considered 

reasonable for BART, and that North 

Dakota itself considered reasonable for 

BART at other North Dakota sources. (76 

FR 58623). 

Comment: Commenter stated that 

only supercritical boilers have shown 

the capability to achieve less than 0.14 

lb/MMBtu, using SNCR and LNBs. 

Commenter further stated that, because 

CCS does not have any supercritical 

boilers and there are no other examples 

of a tangential fired source with only 

LNBs, it is unrealistic to expect any CCS 

unit to attain an annual average of 0.14 

lb/MMBtu, and even more unrealistic to 

obtain this average on a 30-day rolling 

basis, using LNB alone. 

Response: Based on our evaluation of 

data from CCS 2, we have decided that 

combustion controls alone may not be 

able to achieve a 30-day rolling average 

limit of 0.14 lb/MMBtu at CCS on a 

consistent basis. However, we have 

decided to finalize our determination 

that SNCR plus SOFA plus LNB is 

BART and are promulgating a limit of 

0.13 lb/MMBtu on a 30-day rolling 

average basis. 

We note that GRE claimed in its 

refined analysis that data on 

supercritical units does not provide an 

indication of SNCR performance at CCS 

because CCS does not have supercritical 

units. Supercritical units typically 

operate at higher furnace temperatures 

than subcritical units. The higher 

furnace temperature makes NOX

reduction with SNCR more difficult due 

to the competing urea oxidation reaction 

that causes NOX reduction to drop off at 

high temperatures. As a result, one 

would expect SNCR performance to 


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generally be better at a subcritical unit 

than a supercritical unit—all other 

factors being equal. 

g. Cost Effectiveness of SNCR and SCR 

at CCS 

Comment: Commenter stated that, 

when combined, the new analyses 

provided by URS and Golder Associates 

confirm that SNCR is not cost-effective, 

consistent with EPA’s presumptive NOX

analysis. These analyses essentially 

reaffirm GRE’s initial determination that 

DryFiningTM and LNC3 is BART for 

CCS. 

Response: Our prior responses 

address the presumptive emission limits 

and alleged cost effectiveness 

thresholds. We disagree that GRE’s 

consultants’ analyses confirm that SNCR 

is not cost effective or reaffirm GRE’s 

initial BART recommendation. As we 

have noted, our analysis indicates that 

SNCR plus LNC3 is more cost effective 

than we estimated in our proposal. 

Comment: Commenter stated that 

only a site specific evaluation by a 

competent SNCR supplier (URS) should 

be used to estimate emission reductions 

and associated costs. The URS refined 

analysis is provided in Appendix B of 

the GRE document. URS is a preeminent 

engineering consultant in SNCR 

technology, having designed several 

dozen SNCR pollution control systems 

throughout the world. This experience 

qualifies URS to make site-specific 

recommendations on SNCR design. 

Response: EPA agrees that an 

evaluation by a competent SNCR 

supplier may be beneficial but notes 

that GRE has only now brought its 

‘‘refined analysis’’ forward. GRE found 

it sufficient to supply several cost 

estimates to the State without such 

assistance. Regardless, URS is not an 

SNCR technology supplier. While URS 

is an engineering firm, it is not a 

supplier or developer of SNCR 

technology. As indicated in the 

experience list provided by URS, URS’s 

role in these SNCR projects was 

primarily as constructor, performing a 

feasibility study, engineering, or 

procurement. In no cases was URS 

actually the process supplier—the 

company that actually designed the 

process and made the performance 

predictions and guarantees. See docket. 

Depending upon the project shown in 

the list provided by URS, its role may 

have been associated with managing 

project construction activities, 

engineering and location of equipment 

such as piping, tanks, etc., and in some 

cases simply ‘‘feasibility studies,’’ but in 

none of the cases it cites did URS 

actually design the SNCR process and 

develop performance guarantees. 

While location of tanks, routing of 

process piping and other engineering or 

construction activities are important 

aspects of a project, they do not 

determine the process performance. 

Critical aspects of SNCR process design, 

which determine performance (NOX

reduction, reagent use and ammonia 

slip), are design of and location of 

injectors in the furnace, specification of 

reagent type, flowrates and control 

logic. Process design is performed by 

companies such as Fuel Tech, having 

supplied many utility SNCR systems, or 

other companies. For example, some of 

the installations cited by URS in its 

experience list, such as TVA 

Johnsonville and PEPCO were supplied 

by Fuel Tech or Advanced Combustion 

Technology. As indicated in the table 

provided by URS, URS apparently had 

a role in the engineering of these 

projects (location of storage tanks, 

piping between components, etc.), but 

did not develop the process design or 

the performance estimates for the TVA 

or PEPCO installations. Other 

installations cited by URS (new boilers 

at AES Warrior Run and the two Air 

Products installations) were actually 

designed and supplied by the 

circulating fluid bed boiler suppliers, 

with performance and guarantees 

developed by the boiler supplier. The 

balance of the installations cited by URS 

were either feasibility studies, where no 

real process guarantees were made, or 

were actually supplied by other 

companies (Applied Utility Systems, 

ESA, or others). In fact, the study that 

URS has conducted for GRE on CCS is 

essentially a feasibility study. Aside 

from URS’s experience, the analysis 

URS conducted does not support that 

the CCS units are so unique that Control 

Cost Manual estimates of SNCR 

performance and costs are irrelevant. 

Thus, while URS has the expertise to 

provide useful input on the cost 

associated with installing some of the 

associated equipment, it is not in the 

business of providing SNCR process 

designs and performance guarantees— 

and it apparently did not do this on any 

of the projects on its experience list. 

GRE argues that the CCS units are 

unique and thus require evaluation by 

an SNCR process supplier in lieu of an 

analysis based on the Control Cost 

Manual. However, GRE has not 

provided any information from 

companies that actually design SNCR 

systems and have experience providing 

performance guarantees, such as Fuel 

Tech or another company that is an 

experienced SNCR supplier. Thus, 

GRE’s claims about SNCR performance 

are not supported. 

The control efficiency of SNCR is the 

main issue raised by URS because it has 

a significant impact on the overall cost 

effectiveness of SNCR, as further 

explained later in our responses. URS 

also provides a cost estimate which is 

used to support GRE’s own cost 

analysis. While GRE comments that 

‘‘only a site specific evaluation, by a 

competent SNCR supplier (URS), should 

be used to estimate emission reductions 

and associated costs,’’ the evaluation 

provided by URS is based on data from 

other plants. URS extrapolates the SNCR 

control efficiency using CCS data from 

a plot of control efficiency versus inlet 

NOX concentrations for 55 existing 

SNCR installations. This differs from the 

Control Cost Manual, which plots 

control efficiency as a function of boiler 

size. Neither is a definitive ‘‘site 

specific’’ measure of estimating control 

efficiency. Furthermore, there are many 

other factors besides inlet NOX

concentration that affect the efficiency 

of an SNCR system. Thus, GRE has 

provided little support for reducing the 

SNCR control efficiency by 20 to 30 

percentage points from the efficiency 

used in the proposed FIP and from what 

they themselves originally estimated 

(i.e., from 50% down to 30% or 20%). 

Since GRE has not provided any 

information from companies that 

actually design SNCR systems and have 

experience providing performance 

guarantees, GRE’s claims, that its prior 

representations about SNCR 

performance should be disregarded, are 

not supported. 

Comment: Commenter states that 

EPA’s analysis contains faults that, 

when corrected, lead to the conclusion 

that SCR, not SNCR, is BART for the 

CCS units. The faults include, first, that 

the EPA analysis of $4,116/ton is, on its 

own, cost effective and close to the cost 

effectiveness value North Dakota and 

EPA accepted at Stanton Station Unit 1 

of $3,778/ton. Second, EPA retains the 

80% control efficiency for SCR from the 

State’s BART determination when, 

elsewhere in the proposal, EPA 

acknowledges that SCR is capable of 

90% control. The commenter adjusted 

the cost effectiveness value to $3,595 

based on 90% control efficiency which, 

the commenter states, is cost effective 

and below the Stanton Station Unit 1 

cost effectiveness previously mentioned. 

Third, EPA retained costs related to loss 

of sales from fly ash disposal in the SCR 

cost analysis, which is perhaps in error 

as there is no reason a well-designed 

SCR, particularly in the low dust or tail 

end configuration, would impact ash 

sales. SCRs can meet 2 ppm ammonia 

slip, and at that level the ammonia in 

the ash is typically acceptable for all 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20927 

54Hofmann, J.W., von Bergmann, J., Bokenbrink, 

D., Hein, K. ‘‘NOX Control in a Brown Coal-Fired 

Utility Boiler.’’ Presented at the EPRI/EPA 

Symposium on Stationary Combustion NOX

Control, San Francisco, CA, March 8, 1989. 

55Our analysis differs in that we considered 

SNCR combined with combustion controls. 

uses. Additionally, mitigation of 

ammonia in ash is feasible, and is 

probably a less costly option if ammonia 

is, improbably, an issue. 

Response: We disagree with the 

comment regarding the control 

efficiency of SCR at CCS. We have 

determined that the 0.043 lb/MMBtu 

emission rate that North Dakota used in 

its cost analysis based on the 80% 

control efficiency was acceptable and 

probably the best performance 

achievable with SCR technology taking 

into consideration the existing 

combustion controls. Based on our own 

investigation, as discussed in our 

responses to GRE’s comments discussed 

above, we agree with the commenter on 

the issue of fly ash and have revised our 

cost analysis. We have removed the lost 

fly ash sales and fly ash disposal costs. 

We further agree that ammonia levels in 

the ash will not be problematic and are 

not including ammonia mitigation costs 

in our analysis. Our revised analysis 

relies on the $280/kW installed capital 

cost that we discussed in our proposal. 

We used the $280/kW capital cost in 

lieu of the $110/kW figure that is 

derived from GRE’s capital cost 

analysis. As we stated in our proposal, 

$110/kW is unreasonably low compared 

to actual industry experience. Based on 

these changes, we calculate a cost 

effectiveness value for LDSCR + ASOFA 

+ LNB at CCS of $5,603/ton of NOX

removed. We find that this cost is 

excessive in light of the predicted 

visibility improvement. Thus, we are 

not changing our determination that 

SNCR+ASOFA+LNB is NOX BART at 

CCS 1 and 2. 

Comment: Commenter stated that the 

furnace boxes for CCS 1 and 2 are 

unique, as required by the high moisture 

content of Fort Union lignite. 

Commenter stated that the firebox is 

larger than other lower-moisture coalfired units, resulting in a higher cost of 

NOX combustion controls. Specifically, 

the commenter stated that the greater air 

flow distance through the furnace 

requires increased size and type of wall 

nozzles and increased staging 

complexity; and an advanced air 

combustion system added to a larger 

firebox requires additional wall 

openings and redesign to wall water 

tubes, further increasing costs. 

Response: All electric utility boilers 

are built to the owner’s specifications 

and are, therefore, unique. However, the 

information presented by the 

commenter has not convinced us that 

the CCS boilers are so unique that our 

costing assumptions or our overall cost 

estimates are unreasonable. The fuel 

burned at CCS is very low BTU fuel, 

which contributes to the large furnace 

size. Therefore, it is possible that a 

combustion retrofit for CCS might be 

somewhat higher in cost than for a 

similar retrofit for a boiler of similar 

output firing a higher Btu coal. 

Examination of Title IV data shows 

several lignite fired boilers with 

significantly lower emissions than at 

CCS—some using only combustion 

controls and some using combustion 

controls in combination with SNCR. 

The application of SNCR on low-BTU 

fuel utility boilers goes back to the late 

1980’s when it was successfully applied 

to German brown coal boilers.54 The 

larger furnace volume of a lignite or 

other low-Btu furnace actually provides 

more time for the SNCR reaction to 

occur, which should be beneficial for 

mixing and the SNCR reaction. The 

advantage will likely be improved 

reagent utilization. 

Comment: Commenter stated that the 

larger registers installed at CCS 2 further 

reduce NOX emissions as they allow for 

increased primary air which is available 

after installation of DryFiningTM, and 

that larger registers are tentatively 

anticipated to be installed at CCS 1 in 

2014. 

Response: We evaluate potential 

control options based on baseline 

conditions, not on ongoing revisions to 

a facility after the baseline period. It is 

not reasonable to consider controls 

installed after the baseline period in 

determining BART. Such an approach 

would tend to lead to higher cost 

effectiveness values for more effective 

controls and encourage sources to 

voluntarily install lesser controls to 

avoid installing more effective BART 

controls later. 

Comment: Commenter stated that 

URS reviewed and updated both capital 

and operating costs for SNCR, based on 

their expertise and site specific 

investigation. These values were 

relatively consistent with values 

presented to EPA in June and July 2011, 

but are somewhat higher than the 

screening values presented in the 

original BART analysis. 

Response: The higher costeffectiveness ($/ton) of SNCR in GRE’s 

November 2011 submittal can be 

primarily attributed to the lower control 

efficiency value assigned to the 

technology. The July 2011 study 

estimates a control efficiency of 50% for 

SNCR, which yields a cost effectiveness 

value of $3,198/ton for both Units 1 and 

Units 2 (one estimate). The November 

2011 study estimates an SNCR control 

efficiency of 25% for Unit 1 and 20% 

for Unit 2, which yields a cost 

effectiveness value of $7,629/ton and 

$10,506/ton for Units 1 and 2 

respectively. 

It should be noted that the November 

study actually estimates lower capital 

and annual costs of control, each of 

which would independently lower the 

cost effectiveness value. The total 

capital investment for SNCR estimated 

in the July study was $12.72 million, 

compared to $12.18 million and $11.80 

million for Units 1 and 2, respectively, 

in the November study. The annualized 

capital plus operating costs in the July 

study were estimated at $8.91million, 

compared to $8.79 million and $8.12 

million for Units 1 and 2 in the 

November study. One of the main 

reasons that costs are higher in the July 

study is maintenance costs; the annual 

maintenance costs in the July study are 

$1,907,375 compared to approximately 

$180,000 for each Unit in the November 

study. 

The baseline emission rate is another 

factor which would result in higher cost 

effectiveness values in the November 

study. The baseline emission rate in the 

July study was estimated at 0.22 lb/ 

MMBtu, compared to 0.20 lb/MMBtu 

and 0.153 lb/MMBtu for Units 1 and 2 

in the November study. A lower 

emission rate would result in less 

emissions controlled and a higher cost 

effectiveness value. 

The lower SNCR control efficiency in 

the November study results in less NOX

controlled (i.e., 1,152 tons per year (tpy) 

for Unit 1 and 772 tpy for Unit 2 in the 

November study versus 2,786 tpy NOX

controlled in the July study), and a 

higher overall cost effectiveness value. 

The reduced SNCR control efficiency 

outweighs the changes to the cost of 

control, which would otherwise result 

in lower cost effectiveness values.55

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20928 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

56Rini, M.J., J.A. Nicholson, and M.B. Cohen. 

Evaluating the SNCR Process for Tangentially-Fired 

Boilers. Presented at the 1993 Joint Symposium on 

Stationary Combustion NOX Control, Bal Harbor, 

Florida. May 24–27, 1993. 

57Control Cost Manual, Section 4.2, p. 1–4. 

58 It appears that URS overestimated capital costs 

in other ways as well. Consistent with the BART 

Guidelines, and as outlined in our proposal and in 

this action, we have applied the factors permitted 

by EPA’s Control Cost Manual to GRE’s estimate of 

direct capital equipment costs for SNCR to arrive 

at a reasonable estimate of the total capital 

investment. We do not agree with URS’s estimate 

of total capital investment because it relies on 

factors that are inconsistent with the Control Cost 

Manual. 

59URS did not analyze a case with the parameters 

we have determined are most reasonable; we are 

providing the reagent cost review of one of URS’s 

cases to highlight our concerns with the 

methodology. Considering an inlet emission rate of 

0.15 lb/MMBtu and a 25% reduction, the 

parameters we find are reasonable, the reagent cost 

would be $1,304/ton using a similar analysis. 

60EPA and the North Dakota SIP assume 6,112 

MMBtu/hr, but URS assumes 5,900 MMBtu/hr. The 

difference will not affect the conclusion that URS’s 

reagent costs are high. 

TABLE 1—COMPARISON BETWEEN COST EFFECTIVENESS FACTORS IN GRE’S JULY AND NOVEMBER 2011 COST

ESTIMATES FOR CCS 

Study description 

Baseline 

emission rate 

(lb/MMBtu) 

Control 

efficiency 

Emission 

reduction 

(ton/yr) 

Installed 

capital cost 

(MM$/yr) 

Annual 

O&M cost 

(MM$/yr) 

Pollution 

control cost 

($/ton) 

SNCR, July Study, Both Units ................................... 0 .22 50 2,786 12 .72 8.91 3,198 

SNCR, November Study, Unit 1 ................................ 0 .2 25 1,152 .8 12 .18 8.79 7,629 

SNCR, November Study, Unit 2 ................................ 0 .153 20 772 .5 11 .8 8.12 10,506 

We do not agree with the capital and 

operating costs estimated by GRE. First, 

URS has inappropriately applied a 

retrofit factor when calculating capital 

costs for the SNCR system. The Control 

Cost Manual states: 

The costing algorithms in this report are 

based on retrofit applications of SNCR to 

existing coal-fired, dry bottom, wall-fired and 

tangential, balanced draft boilers. There is 

little difference between the cost of SNCR 

retrofit of an existing boiler and SNCR 

installation on a new boiler.56 Therefore, the 

cost estimating procedure is suitable for 

retrofit or new boiler applications of SNCR 

on all types of coal-fired electric utilities and 

large industrial boilers.57

Therefore, retrofit costs are inherent 

in the costs provided by the Control 

Cost Manual method and there is no 

need to introduce a retrofit factor. In 

using a retrofit factor of 1.6, URS 

overestimated capital costs by 60%.58

Another concern we have is that 

URS’s estimate of reagent usage is high. 

The following is an examination of the 

0.20 lb/MMBtu inlet level with 25% 

reduction case in URS’s Table 4.59 Using 

a boiler rating of 5900 MMBtu/hr,60 an 

initial NOX level of 0.20 lb/MMBtu, and 

a normal stoichiometric ratio (NSR) of 

1.0 (30 lb urea/46 lb NO2),61 the hourly 

usage of reagent is: 5900 MMBtu/hr * 

0.20 lbNO2/MMBtu * (30 lb urea/46 lb 

NO2) = 770 lb/hr. 

This is roughly half of what URS 

calculated as the urea usage. In all of the 

cases URS estimated, the result is high. 

Since URS appears to have 

overestimated the reagent cost, it is 

likely that URS overestimated the water 

cost as well. 

In this case, with urea at $500/ton 

delivered, the reagent portion of cost 

would be: 

$500/ton * (1 ton/2000 lb)* 770lb/hr = 

$192/hr. 

The tons removed per hour would 

equal: 

(5900 MMBtu/hr)*(0.20 lb NO2/ 

MMBtu)*(0.25 reduction)*(1 ton/ 

2000 lb) = 0.148 ton/hr. 

The reagent portion of cost is 192/ 

0.148 = $1,300/ton of NOX removed. 

This $/ton for reagent would be the 

same assuming the same cost per ton of 

urea and the same chemical utilization 

(25%, or 25% reduction at an NSR = 

1.0). 

The errors in the URS estimate are 

carried through to GRE’s estimates. 

Comment: Commenter stated that 

with the installation of LNC3, LNC3+, 

and DryFiningTM;, CCS’s NOX emissions 

are greatly reduced with respect to 

‘‘baseline’’ values previously provided; 

and it is necessary to update the 

baseline emissions for Units 1 and 2 for 

this technology evaluation in order to 

reflect current conditions and unit 

performance. Commenter stated that the 

revised baseline emissions for Units 1 

and 2 should be adjusted to 0.201 lb/ 

MMBtu and 0.153 lb/MMBtu, 

respectively. The commenter stated that 

the use of DryFiningTM technology has 

already been implemented for use at 

both units at a cost of $270 million, and 

GRE has made a significant investment 

to achieve multi-pollutant emission 

reductions and visibility improvements 

in the region. 

Response: As stated in our previous 

comments, we reject GRE’s revised 

baseline. We evaluate potential control 

options based on baseline conditions, 

not on ongoing voluntary revisions to a 

facility after the baseline period. It is not 

reasonable to consider voluntary 

controls installed after the baseline 

period in determining BART. Such an 

approach would tend to lead to higher 

cost effectiveness values for more 

effective controls and encourage sources 

to voluntarily install lesser controls to 

avoid more effective BART controls 

later. 

Comment: The refined economic 

impacts analysis provided by GRE 

confirms GRE’s original conclusion that 

SNCR is not a cost effective NOX control 

option. 

Response: We disagree with the cost 

effectiveness analysis provided by GRE 

in the refined analysis. We disagree 

with the control efficiency used for 

SNCR in combination with SOFA plus 

LNB used in the refined analysis, the 

assumed baseline and controlled 

emission rates, and the assumed 

reduction in ash sales. These issues are 

further discussed in the comment 

responses specific to each issue. 

h. CCS General Comments 

Comment: The commenter stated that 

at the time of this submittal, GRE has 

already installed LNC3 combustion 

controls at Unit 2. In 2011 dollars, this 

was at a cost of over $6 million and has 

already resulted in NOX reductions. The 

same system is tentatively scheduled to 

be installed on Unit 1 during the 2014 

outage. 

Response: As stated in our previous 

comments, we reject GRE’s use of a 

revised baseline. 

3. Stanton Station Unit 1 

Comment: Commenter states that the 

BART limits for the Stanton Station are 

contrary to BART requirements. 

Commenter states that both SO2 and 

NOX emission rates would decrease if 

only Powder River Basin (PRB) coal 

were allowed to be burned, because the 

burning of North Dakota lignite coal 

creates higher emissions of both 

pollutants. Commenter also states that 

EPA’s cited 7th Circuit Court of Appeal 

decision (76 FR 58589) would not apply 

to such a requirement because that 

decision only applies to the redesign of 

a source. 

Response: We do not interpret the 

CAA or the regional haze regulations as 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20929 

62Coal Creek Station Units 1 and 2 Best Available 

Retrofit Technology Analysis, Revised December 

12, 2007, p. 8. 

63Revised BART Cost Effectiveness Analysis for 

Tail-End Selective Catalytic Reduction at the Basin 

Electric Power Cooperative, Leland Olds Station 

Unit 2, Final Report, March 2011, docket EPA–R08– 

OAR–2010–0406–0076, p. 8. 

requiring states to consider limiting the 

type of coal burned as a BART control 

technology. We note that we did not cite 

the referenced 7th Circuit decision in 

support of our proposal to approve the 

BART limits for Stanton Station. 

Comment: One commenter states that 

EPA is proposing to approve SNCR + 

OFA + LNB as NOX controls for Stanton 

Station Unit 1. While the commenter 

supports the use of further NOX controls 

at this facility, the commenter asks EPA 

to further evaluate the cost estimates for 

SCR at this facility. According to the 

commenter, the cost estimates for SCR 

that EPA relied on in its proposal 

appear to include, at a minimum, costs 

associated with allowance for funds 

used during construction (AFUDC), 

which is not appropriate under the 

BART Guidelines and Control Cost 

Manual. Further, the underlying 

calculations in Stanton Station’s BART 

submission to North Dakota do not 

clearly support the resulting cost. 

Response: We relied on cost estimates 

submitted by North Dakota in our 

evaluation of the cost effectiveness of 

NOX control options for Stanton Station 

Unit 1. In turn, North Dakota relied on 

costs taken from GRE’s BART analysis 

as found in Appendix C.2 to the SIP. 

GRE asserts that these costs were 

derived ‘‘using the procedures found in 

the EPA Air Pollution Control Cost 

Manual.’’ 62 However, as suggested by 

the commenter, there are irregularities 

in how GRE applied the SCR cost 

methods in the Control Cost Manual. In 

particular, GRE included a line item for 

AFUDC in the amount of $8,232,000. 

However, closer examination reveals 

that this line item represents the cost of 

replacement power associated with a 

purported 10 week outage for 

installation of the SCR, and does not 

represent allowance for funds used 

during construction. Regardless, 

elimination of this line item would only 

lower the cost effectiveness values for 

SCR when burning lignite and PRB coal 

from $6,475/ton to $6,118/ton and 

$8,163/ton to $7,713/ton, respectively. 

In addition, the total capital investment 

stated by GRE for SCR of $55,279,000 

equates to $294/kilowatt (kW). We find 

this cost consistent with the installed 

SCR retrofit costs, ranging from $79/kW 

to $316/kW (2010 dollars), cited in 

recent industry studies.63 We expect 

that the cost at Stanton Station Unit 1 

would be at the higher end of this range 

given its relatively low generation 

capacity of 188 MW. Accordingly, while 

we agree that there are questions 

regarding the underlying calculations, it 

is our opinion that further evaluating 

costs would not change the outcome of 

the BART determination. 

4. Leland Olds Station Unit 1 

Comment: Commenter stated that 

SCR, not SNCR, is BART at LOS 1. 

Commenter further stated that EPA 

assumed that Basin Electric 

overestimated the costs for SCR at this 

unit, but did not re-estimate the costs. 

Commenter analyzed the costs based on 

the revised cost for SCR at Unit 2, and 

considers its lower cost estimate ‘‘well 

within the range of values determined to 

be cost effective in similar regulatory 

proceedings.’’ 

Response: We have included in the 

docket for our final action an SCR cost 

estimate for LOS 1 that was based on 

methods similar to those we used for 

our SNCR cost analyses for MRYS 1 and 

2 and LOS 2. The analysis was not an 

exhaustive effort but was used as a 

check of the analysis provided by North 

Dakota. Our analysis found the cost of 

SCR + SOFA would be approximately 

$5,132/ton of NOX emissions removed 

with an incremental cost effectiveness 

between the SCR and SNCR control 

options of $8,845/ton of NOX emissions 

removed. The cost estimates for SCR at 

LOS 1 that National Parks Conservation 

Association (NPCA) and the NPS 

provided in their comments reflect cost 

effectiveness values greater than $4,000/ 

ton of NOX emissions removed. While 

these various estimates are lower than 

those the State relied on, they are still 

high enough that we are not prepared to 

change our conclusion that the State’s 

BART determination of SNCR + Basic 

SOFA for LOS 1 was reasonable. 

Comment: Commenter stated that 

there is no discussion why SNCR + 

Boosted SOFA was rejected as BART. 

Response: In response to this 

comment, we reviewed the benefits of 

SNCR + Boosted SOFA over SNCR + 

Basic SOFA. We determined that the 

two combustion control options achieve 

very similar results and that the 

incremental cost of the Boosted SOFA 

option at $7,826/ton is excessive 

compared to the 92 tons of additional 

NOX reductions, which we anticipate 

would provide a low visibility benefit. 

F. General Comments on SO2 and PM 

Pollution Controls 

Comment: One commenter stated that 

North Dakota’s BART analyses that EPA 

proposes to approve fail to include the 

most stringent level of control that is 

achievable using scrubber technology 

since scrubbers can achieve 99% control 

efficiency. Commenters also stated that, 

with regard to SO2, EPA should require 

both the lb/MMBtu limit and the 

percent control efficiency limit to be 

met in order to meet BART, rather than 

require that either limit be met as EPA 

proposed. One commenter stated that if 

only the percent reduction limit is set, 

emissions will increase with the sulfur 

content of the fuel unless sulfur content 

is also limited. One commenter 

requested EPA set a numeric limit rather 

than percent reductions. 

Response: We agree that the RHR 

requires states to consider the most 

stringent level of control. We also agree 

that, in most applications, wet or dry 

scrubbers can achieve greater emission 

reductions than those required by North 

Dakota. However, there is very limited 

data on the performance of wet or dry 

scrubbers at units firing lignite, such as 

those in North Dakota. In a 2007 BACT 

determination for two new lignite-fired 

boilers at Oak Grove Station in Texas, 

the Texas Commission on 

Environmental Quality established an 

SO2 emission limit of 0.192 lb/MMBtu 

on a 30-day rolling average. Based on 

this, we find that the emission limits 

established by North Dakota are not 

unreasonable. Also, we would like to 

emphasize that three of the North 

Dakota units have existing controls for 

SO2 and that the emission reductions 

that can be achieved with upgrades to 

these existing controls may not be as 

great as those that can be achieved by 

a new scrubber installation. Finally, on 

the point of allowing either a lb/MMBtu 

or a percent control efficiency limit, we 

typically prefer a single limit. However, 

the BART guidelines list the 

presumptive levels in units of lb/ 

MMBtu or a percent reduction, and we 

cannot say that the State’s approach is 

inconsistent with the guidelines. The 

State chose to take advantage of this 

point and specifically found that it was 

not appropriate to establish limits on a 

lb/MMBtu and percent reduction basis. 

This was in part to allow for the 

potential that higher sulfur coals might 

be burned in the future, in which case 

the State believed that the percent 

reduction basis would extend greater 

flexibility. Based on these factors and 

our consideration of all the 

circumstances involved, we find that 

the SO2 emission limits established by 

North Dakota are not unreasonable and 

we are approving them. 

Comment: Commenters stated that 

North Dakota did not consider 

upgrading ESPs to decrease PM 

emissions, as is required by the BART 

Guidelines. 

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20930 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

Response: As noted in our proposal, 

the ESPs already reduce emissions by 

99% or greater. Where new wet or dry 

scrubbers or modifications to existing 

scrubbers will be installed, additional 

PM emission reductions, particularly of 

sulfuric acid mist, will be achieved. 

Moreover, as noted in North Dakota’s 

SIP, the visibility improvement that can 

be achieved by further reducing PM is 

minor. For example, North Dakota’s 

BART determination for M.R. Young 

Unit 2 shows that the highest visibility 

impact from PM in the baseline was 

0.0165 deciviews (LWA, 2001). SIP, 

Appendix B.4, p. 26. Similarly, North 

Dakota’s BART determination for 

Stanton Station Unit 1 shows that 

reducing PM from 0.1 lb/MMBtu to 

0.015 lb/MMBtu would only improve 

visibility by 0.021deciviews (TRNP–SU, 

2002). SIP, Appendix B.3, p. 9. 

Accordingly, we find that North Dakota 

reasonably eliminated ESP upgrades 

from consideration. 

Comment: One commenter stated that 

the control efficiency for baghouses was 

underestimated. 

Response: We agree that the control 

efficiency for baghouses was 

underestimated. However, this has no 

practical bearing on our evaluation of 

North Dakota’s BART control 

determinations for PM as, consistent 

with the BART Guidelines, North 

Dakota was not required to consider the 

replacement of existing PM control 

devices. Stanton Station is the only 

facility where North Dakota is requiring 

new PM controls, but this is only in 

association with the spray dryer 

absorber needed to control SO2.

Comment: Commenters stated that a 

PM continuous emission monitoring 

system (CEMS) must be installed, 

operated and used to demonstrate 

continuous compliance with the PM 

emission limits on units that are subject 

to BART. 

Response: PM CEMS would provide 

the most robust means of demonstrating 

continuous compliance with the PM 

emission limits. However, we disagree 

that their use is required. We find that 

the monitoring requirements in the RH 

SIP are adequate to demonstrate 

continuous compliance with the PM 

emission limits. 

Comment: BART should be evaluated 

for both course particulate matter (PM10) 

and PM 2.5, but was only evaluated for 

PM10. EPA should therefore impose a 

BART limit on total PM2.5. 

Response: In our BART Guidelines, 

for the purposes of identifying visibility 

impairing pollutants, we allowed states 

to use emissions of PM10 as an indicator 

for PM2.5, as the components of PM2.5

are a subset of PM10. 70 FR 39160. For 

the same reasons, we find that it is 

reasonable for North Dakota to have 

explicitly evaluated BART only for 

PM10. We also note that North Dakota 

did evaluate BART for condensable PM 

which comprises a large portion of the 

PM2.5. 

Comment: Commenter stated that 

North Dakota incorrectly set a limit for 

PM at .07 lbs/MMBtu. Commenter 

stated that the actual emissions from 

most units averaged .03 lbs/MMBtu to 

.05 lbs/MMBtu, and there is therefore no 

support for limits higher than .03 lbs/ 

MMBtu. Additionally, the commenter 

asserted that these limits should be set 

on a unit-by-unit basis. 

Response: As noted in prior responses 

to comments, the visibility 

improvement that could be achieved 

with new or upgraded PM controls is 

negligible. That response also holds true 

within the context of setting tighter 

emission limits. Therefore, we find that 

PM emission limits set by North Dakota 

are not unreasonable. 

Comment: Commenter stated that EPA 

deviates from the BART guidelines in 

failing to establish a clear time period 

(hourly, 24-hour, 30-day or annual) over 

which the proposed PM limits would 

apply. Commenter further stated that 

North Dakota’s BART determinations 

are unenforceable because there are no 

proposed monitoring, recordkeeping 

and reporting requirements that would 

ensure compliance with the filterable 

PM limits. Commenter stated that this 

was contrary to the CAA, because BART 

is defined as based on continuous 

emission reductions, which cannot be 

ensured. 

Response: We disagree with the 

commenter. First, we seek to clarify that 

while emission limits must be 

enforceable as a practical matter, the 

BART Guidelines clearly state that 

CEMs are not required in every instance. 

70 FR 39172. Moreover, the BART 

Guidelines recognize that monitoring 

requirements are in many instances 

governed by other regulations, such as 

compliance assurance monitoring. 

North Dakota established monitoring, 

recordkeeping and reporting 

requirements for PM emission limits in 

permits to construct which are included 

in Appendix D of the SIP. The 

monitoring requirements for PM include 

emission testing using EPA-approved 

test methods, such as Method 5B and 

Method 17. As specified in each permit 

to construct, these tests must consist of 

three test runs, with each test run at 

least 120 minutes in duration. The 

monitoring requirements also require 

the use of a Continuous Assurance 

Monitoring (CAM) Plan developed in 

accordance with NDAC 33–15–14– 

06.10. The CAM Plan will include other 

provisions necessary to show 

compliance. We find that these 

monitoring provisions are adequate to 

ensure continuous emission reductions 

as required under BART. 

G. Comments on Reasonable Progress 

and North Dakota’s Long-Term Strategy 

Comment: Minnkota states that EPA’s 

proposed FIP does not follow EPA 

guidelines for RP determinations. The 

commenter cites, without a page 

number, the Burns & McDonnell report 

attached to the comments. 

Response: EPA is unable to identify 

any support in the Burns & McDonnell 

report for the statement. Standing alone, 

the comment is insufficiently specific to 

warrant a response. Below, EPA 

responds to comments that EPA’s 

disapproval of the State’s RP 

determination for AVS is inconsistent 

with EPA guidelines. 

Comment: Minnkota states that EPA’s 

actions disapproving the State’s RPGs 

and imposing RP controls on MRYS lack 

a basis. 

Response: EPA disagrees with this 

comment. First, as stated in the 

proposal, the disapproval of the State’s 

RPGs is based on the State’s failure to 

demonstrate that the RPGs the State 

selected are reasonable, based on the 

four statutory factors. In particular, the 

State’s use of a degraded background in 

modeling for visibility benefits was 

unreasonable, as was the State’s failure 

to select RP controls for AVS. Second, 

the commenter appears to misinterpret 

the statements made regarding MRYS 

Units 1 and 2 as proposing to impose RP 

controls on those units. In any case, the 

reference to controls on MRYS Units 1 

and 2 is no longer relevant, because we 

have decided to approve North Dakota’s 

NOX BART determination for MRYS 

Units 1 and 2. 

Comment: Minnkota states that EPA’s 

action in disapproving the State’s LTS is 

unreasonable and simplistic. 

Response: EPA disagrees with this 

comment. The LTS is a compilation of 

the State-specific controls relied upon 

by the State for achieving its RPGs. We 

are disapproving the State’s RPGs along 

with certain NOX BART and RP 

determinations and promulgating a FIP 

to impose RPGs that are consistent with 

our FIP NOX BART and RP 

determinations. To the extent that the 

State’s LTS relies on these NOX BART 

and RP determinations, we must also 

disapprove those portions of the LTS. 

Specifically, our partial disapproval of 

the State’s LTS consists of two parts: (1) 

Disapproval of the LTS with regard to 

permit limits and monitoring, 

recordkeeping, and reporting 

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requirements in the State’s submittal 

that correspond to the NOX BART 

determinations we are disapproving; 

and (2) disapproval of the LTS with 

regard to the NOX reasonable progress 

determination for AVS Units 1 and 2, 

and with regard to the corresponding 

monitoring, recordkeeping, and 

reporting requirements. The monitoring, 

recordkeeping, and reporting 

requirements for Antelope Valley are 

necessary to ensure that the emissions 

limitations and control measures to 

meet RPGs are enforceable. See 40 CFR 

51.308(d)(3)(v)(F). In addition, these 

requirements are generally necessary to 

ensure the BART limits are enforceable. 

See CAA 110(a)(2). As these 

requirements are necessary adjuncts to 

the BART and RP limits, our 

disapproval of the State’s requirements 

necessarily flows from our disapproval 

of the NOX BART determinations for 

CCS Units 1 and 2 and the disapproval 

of the State’s NOX RP determination for 

AVS Units 1 and 2. 

Comment: NDDH states that EPA 

incorrectly rejected NDDH’s RP 

modeling methodology. NDDH believes 

that the methodology properly took into 

account effects of international sources, 

as provided for in the RHR. 

Furthermore, the hybrid methodology 

was, in NDDH’s view, necessary to 

accurately simulate transport from large 

point sources. 

Response: Our response to this 

comment is provided with our 

responses to modeling comments in 

section V.C. 

Comment: NDDH states that its 

cumulative modeling methodology more 

accurately reflects the visibility 

improvements from controls at point 

sources. 

Response: Our response to this 

comment is provided with our 

responses to modeling comments in 

section V.C. 

Comment: NDDH notes that EPA 

supported the development of the 

WRAP cumulative modeling, which 

NDDH states involved considerable time 

and resources. NDDH argues that it is 

inappropriate to diminish this extensive 

effort by using what NDDH views as a 

less sophisticated and inconsistent 

single-source approach. 

Response: EPA disagrees with this 

comment. As discussed elsewhere, 

single-source modeling is not ‘‘less 

sophisticated’’ or ‘‘inconsistent.’’ EPA 

supported development of WRAP 

CMAQ modeling in order to assist states 

in developing their RPGs. This support 

does not endorse the use of cumulative 

modeling to determine single-source 

impacts, a faulty approach for the 

reasons discussed above. As discussed 

below in responses to comments later in 

this section, NDDH’s comment conflates 

the requirements for RPGs with the 

requirements for evaluating RP controls 

for single sources. 

Comment: NDDH states that, on a 

dollar-per-ton-removed basis, LNB + 

SNCR appears to be reasonable for AVS. 

However, NDDH argues that its dollarper-deciview evaluation of visibility 

benefits from installing LNB + SNCR at 

AVS shows that the cost is excessive. 

Response: EPA disagrees with this 

comment, to the extent that it can be 

understood to argue against EPA’s 

determination to impose LNB at AVS to 

meet reasonable progress requirements. 

The dollar-per-deciview cost that NDDH 

relies upon is faulty because, as 

discussed elsewhere, it relies on 

modeling using current degraded 

background that greatly underestimates 

the visibility improvement of singlesource controls when compared to 

accepted methodology. It therefore 

provides no basis for determining that 

the cost of LNB + SNCR is excessive, or 

that the cost of LNB alone is excessive. 

Elsewhere, we have also discussed some 

of the difficulties with using dollar-perdeciview cost effectiveness values, and 

how care must be taken not to 

misinterpret such values. EPA does note 

that NDDH describes the dollar-per-ton 

cost of LNB + SNCR as reasonable. 

Using North Dakota’s costs, LNB + 

SNCR has a cost-effectiveness value of 

$2,268 per ton removed at Unit 1 and 

$2,556 per ton removed at Unit 2. By 

comparison, LNB alone, using North 

Dakota’s costs, has a cost-effectiveness 

value of $586 per ton removed at Unit 

1 and $661 per ton removed at Unit 2. 

This indicates that LNB has a very 

reasonable cost effectiveness value on a 

dollar-per-ton-removed basis, the metric 

that is most widely used and 

understood in making control 

technology determinations. 

Comment: NDDH references its 

CALPUFF modeling of visibility 

improvement at AVS from installation 

of LNB. NDDH states that this modeling 

was intended to show greater visibility 

improvement from installation of LNB 

on the two units at Antelope Valley as 

compared to installation of SCR at 

Leland Olds Station. NDDH argues that 

CALPUFF overpredicts visibility 

improvements and does not comply 

with 51.308(d)(1) and EPA’s guidance. 

Response: For reasons expressed 

elsewhere in this action, we disagree 

with North Dakota’s argument that 

CALPUFF overpredicts visibility 

improvements. Our response to the 

argument that use of CALPUFF does not 

comply with 51.308(d)(1) and EPA 

guidance is provided with other 

responses in this section. While NDDH 

may have provided the CALPUFF 

modeling for another purpose, we find 

it informative. The CAA does not limit 

EPA in its action on a SIP submittal to 

considering materials only for the 

purpose for which the materials were 

originally intended. Instead, EPA may 

consider all relevant materials, 

including the CALPUFF modeling of 

visibility improvement from installation 

of LNB at AVS. 

Comment: NDDH notes that even if all 

sources of SO2 and NOX in North Dakota 

were eliminated, North Dakota could 

not achieve the URP. North Dakota 

states that additional controls for AVS 

make almost no difference, and that 

additional controls on sources outside 

of North Dakota are necessary to achieve 

the URP. 

Response: As we stated in our 

proposal, we agree that North Dakota 

could not achieve the URP in the first 

planning period even if all North Dakota 

sources were eliminated. We do not 

agree that this means that North Dakota 

can accordingly do nothing in the first 

planning period to address reasonable 

progress beyond addressing the BART 

requirements or that the State can reject 

otherwise reasonable control measures. 

EPA assumes that NDDH bases its 

statement regarding ‘‘almost no 

difference’’ on the modeling using 

current degraded background 

conditions. The CALPUFF modeling for 

AVS (separately provided by NDDH) 

predicts a visibility benefit at TRNP of 

0.754 deciviews from installation of 

LNB, which EPA does not regard as 

‘‘almost no difference.’’ Regardless of 

whether controls on sources outside of 

North Dakota are necessary in order to 

achieve natural visibility conditions by 

2064, North Dakota is required to 

provide a reasoned analysis of RP 

controls on sources within the State. 

With respect to AVS, the State did not 

do so. 

Comment: North Dakota states that, 

based on the definition of ‘‘most 

impaired days’’ and ‘‘least impaired 

days’’ in 51.301, and the requirement in 

51.308(d)(1) that the RPGs provide for 

improvement in visibility for the most 

impaired days over the planning period 

and ensure no degradation in visibility 

for the least impaired days over the 

planning period, any RP visibility 

analysis must be a cumulative analysis 

and must address the most impaired 

days. NDDH states that it consistently 

modeled BART and RP sources. NDDH 

argues that, under the RHR and EPA 

guidance, progress with respect to the 

URP must be assessed using cumulative 

modeling based on the controls imposed 

on multiple sources. It would be 

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64The ratios of these values equal a Q/D of 10. 

65Further detail regarding North Dakota’s 

analysis can be found in our proposal. 76 FR 

58624–58628. 

66We note that AVS 1 and 2 had Q/D values 

exceeding 100, and Coyote had a Q/D value of 248, 

all far above the threshold Q/D value. 67We note that guidance is not binding on EPA 

and does not supersede relevant statutory and 

regulatory requirements. 68We note that other states—for example, 

Colorado—have also considered reasonable 

progress control options on a source-specific basis 

and that we intend to do so in our FIP for Montana 

for regional haze. 

inconsistent with this approach, NDDH 

asserts, to use single-source modeling to 

determine improvements for the 

controls on an individual source. 

Response: NDDH conflates (as it does 

in the next comment and elsewhere, and 

as do other commenters) the reasonable 

progress requirements for RPGs and for 

determination of controls for a single 

source. The RPGs must provide for 

improvement in visibility for the most 

impaired days over the planning period 

and ensure no degradation in visibility 

for the least impaired days over the 

planning period. In evaluating whether 

the overall RPGs provide for 

improvement in visibility for the most 

impaired days, it is not only 

appropriate, but necessary, to employ 

current degraded background in 

cumulative visibility modeling. This 

allows a comparison of the impact of the 

State’s proposed overall set of regional 

haze controls against the baseline ‘‘most 

impaired days.’’ 

We disagree, however, that it is 

appropriate to analyze and reject 

potential control measures at specific 

sources based on modeling using 

current degraded background 

conditions. Distinct from the 

requirement to show that the overall 

RPGs provide for improvement on the 

most impaired days, it was incumbent 

on North Dakota to show that the URP 

is not a reasonable goal for this planning 

period and that its RPGs and rejection 

of reasonable progress controls was 

reasonable. Just because a state has met 

the requirement to show improvement 

on the most impaired days does not 

mean it has met this separate 

requirement. Our regulations require 

that this showing be based on the four 

statutory reasonable progress factors: 

The costs of compliance, the time 

necessary for compliance, the energy 

and non-air quality environmental 

impacts of compliance, and the 

remaining useful life of any potentially 

affected sources. 40 CFR 51.308(d)(1)(ii). 

We must determine whether the State’s 

showing based on the four factors is 

reasonable. 40 CFR 51.308(d)(1)(iii). 

Here, it is worth noting the process 

North Dakota used to evaluate potential 

reasonable progress controls. North 

Dakota employed certain screening tools 

to identify sources in North Dakota that 

potentially affect visibility in Class I 

areas. It focused mainly on point 

sources, starting with the list of sources 

subject to Title V permitting 

requirements. It further pared this list 

by focusing on the ratio of emissions to 

distance to the nearest Class I area, 

known as Q/D. A Q/D value of 10 was 

chosen as a threshold. North Dakota 

chose this value based on FLM guidance 

and the State’s interpretation of 

statements in EPA’s BART guidelines as 

to sources that could reasonably be 

exempted from the BART review 

process; i.e., for a state with a BART 

contribution threshold of 0.5 deciviews, 

sources emitting less than 500 tons per 

year located more than 50 kilometers 

from a Class I area or emitting less than 

1000 tons per year located more than 

100 kilometers from a Class I area.64 We 

note that North Dakota selected 0.5 

deciviews as its contribution threshold 

for determining which sources are 

subject to BART. 

North Dakota eliminated any source 

with a Q/D less than 10 from further 

consideration for reasonable progress 

controls. Then, North Dakota eliminated 

several sources with a Q/D over 10 that, 

as a result of events after the 2000 to 

2004 baseline period, had reduced 

emissions sufficiently so that the 

sources’ Q/D became less than 10. After 

this paring, seven units remained. We 

note that four of the remaining seven 

units are EGUs, and three of them are 

comparable in size and emissions to 

some of the largest BART sources in 

North Dakota. 

For these seven remaining units only, 

North Dakota considered the four 

statutory reasonable progress factors in 

evaluating potential control 

technologies for reducing SO2 and NOX

emissions. However, when it eliminated 

all reasonable progress controls for these 

pollutants for these units, North Dakota 

relied almost exclusively on its 

cumulative modeling, using current 

degraded background to conclude that 

the cost on a dollar per deciview basis 

was excessive.65

As noted in a prior response, we 

conclude that it was not reasonable for 

North Dakota to model visibility 

improvement for potential individual 

source reasonable progress controls 

using current degraded background. As 

explained, we conclude that the State’s 

approach is inconsistent with the CAA. 

We also note that the State’s use of 

current degraded background to analyze 

single-source controls is facially 

inconsistent with the Q/D threshold it 

used to determine which sources should 

be retained for a detailed evaluation of 

reasonable progress controls. As noted, 

the State selected a Q/D of 10 based in 

part on EPA BART guidance on sources 

that could be considered to contribute to 

visibility impairment. That guidance 

relied on a contribution threshold of 0.5 

deciviews, which was premised on 

CALPUFF modeling using natural 

background. By modeling single-source 

impacts and benefits using current 

degraded background, North Dakota 

employed a completely different metric 

that rendered meaningless its Q/D 

threshold and subsequent analysis of 

the four factors.66

Comment: NDDH notes that EPA’s 

guidance, ‘‘Additional Regional Haze 

Questions,’’ dated August 24, 2006, 

states that the RP demonstration 

involves a test of a strategy and how 

much progress is made through that 

strategy. NDDH also notes that the 

guidance states that RP modeling is tied 

to a strategy and is not a source-specific 

demonstration like the BART 

assessment. NDDH asserts that EPA’s 

rejection of the North Dakota 

cumulative modeling for single source 

visibility benefits arbitrarily ignores this 

guidance. 

Response: We find that this comment, 

like the previous comment, conflates 

two separate aspects of reasonable 

progress: (1) The manner in which the 

overall strategy is modeled for purposes 

of comparison to the URP, and (2) the 

determination of controls for potentially 

affected sources and source categories. 

In the latter context, we conclude that 

our interpretation is reasonable and that 

the State’s consideration of visibility 

improvement based on current degraded 

visibility was unreasonable. 

First, we have refined our guidance 

and our views on reasonable progress 

since the cited document was issued. In 

2007, we issued formal reasonable 

progress guidance, which clearly 

contemplates that controls may be 

evaluated on a source-specific basis.67 It 

is difficult to imagine how the 

reasonableness of a control strategy 

involving large stationary sources could 

be determined without considering the 

reasonableness of controls for the 

specific stationary sources. Second, the 

comment ignores the fact that North 

Dakota itself conducted a sourcespecific analysis of potential control 

options using the four factors.68 It was 

only when it considered the additional 

factor—visibility—that North Dakota 

switched to a cumulative analysis. 

Third, the commenter ignores the cited 

guidance’s repeated admonition that 

reasonable controls based on the four 

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statutory factors (which don’t include 

visibility improvement) must be 

included in the plan. Thus, for example, 

the guidance states: 

‘‘However, the statutory factors must be 

applied before determining whether given 

emission reduction measures are reasonable. 

In particular, the State should adopt a rate of 

progress greater than the glidepath if this is 

found to be reasonable according to the 

statutory factors.’’ 

Guidance at 9. Similarly, the guidance 

states: 

‘‘If after applying the four statutory 

reasonable progress factors, the rate of 

visibility improvement is still less than the 

uniform glide path, States may adopt the 

calculated RPGs, provided that they explain 

in the SIP how achieving the uniform glide 

path is not reasonable based on the 

application of the factors. States must 

demonstrate why the slower rate is 

reasonable * * *’’ 

Guidance at 8–9. 

Comment: Basin Electric states that 

EPA has no statutory authority to 

compel installation of LNB at AVS. 

Basin Electric argues that the regional 

haze program applies only to sources in 

existence before 1977, and that sources 

constructed after that date are subject 

only to the PSD permitting program. 

Basin Electric concludes that EPA 

cannot impose retrofit requirements on 

a source such as Antelope Valley that 

has already been subject to the PSD 

permitting program. 

Response: EPA disagrees with this 

comment. First, the requirements 

established in the RHR provide no basis 

for the commenter’s argument, as 

reasonable progress requirements are 

clearly not limited to sources in 

existence before 1977. In particular, 

section 51.308(d)(1)(i)(A) requires 

consideration of the four statutory 

factors for ‘‘potentially affected 

sources,’’ a term not limited to sources 

in existence before 1977, and also 

requires a demonstration showing how 

the four statutory factors were taken into 

consideration. Section 51.308(d)(1)(iii) 

requires the Administrator to evaluate 

this demonstration, explicit authority 

for the action we are finalizing. Finally, 

section 51.308(d)(3) requires that a state, 

in developing its LTS to achieve the 

RPGs, consider ‘‘major and minor 

stationary sources,’’ a term again not 

limited to sources in existence before 

1977. 

Nor does the CAA itself provide any 

basis for the commenter’s argument. The 

comment is in error in suggesting that 

the existence of requirements regarding 

visibility under the PSD permitting 

program necessarily implies that section 

169A of the CAA cannot apply to 

sources subject to the PSD permitting 

program. As a general matter, it is well 

understood that the CAA frequently 

imposes overlapping requirements on 

sources. Nothing in Subpart I of Part C 

of Title I of the CAA, which provides for 

the PSD permitting program, indicates 

that sources subject to the PSD 

permitting program are somehow 

excluded from the requirements of 

Subpart II. Similarly, nothing in EPA’s 

rules giving the minimum requirements 

for a state’s PSD permit program at 40 

CFR 51.166 or the federal PSD permit 

program at 52.21 supports the notion 

that sources subject to the PSD permit 

program are excluded from the 

requirements of Subpart II. 

Furthermore, any reasonable reading 

of CAA section 169A reveals that 

Congress did not limit the requirements 

to achieve reasonable progress to BART 

and PSD sources. Congress required 

EPA to promulgate regulations to: 

‘‘require each applicable implementation 

plan for a State in which any area listed by 

the Administrator under subsection (a)(2) of 

this section is located * * * to contain such 

emission limits, schedules of compliance and 

other measures as may be necessary to make 

reasonable progress toward meeting the 

national goal specified in subsection (a) of 

this section, including [BART].’’ 

There is nothing in this language to 

suggest that Congress intended to 

exempt sources constructed after 1977, 

or to exempt sources subject to the PSD 

permitting program. 

The commenter argues that CAA 

section 169A(g)(1) supports its view, 

claiming that ‘‘Section 169A(g)(1) 

defines the criteria to be employed in 

determining reasonable progress, but 

limits the application of that criteria to 

‘any existing source.’ ’’ The commenter 

interprets this term to mean sources 

constructed before 1977, but does not 

explain how reasonable progress toward 

the national goal of remedying existing 

impairment of visibility could continue 

to be made under the commenter’s 

interpretation. Instead, the statute and 

our rules contemplate a periodic, 

continuing assessment of reasonable 

progress, including assessment of the 

four statutory factors for existing 

sources at the time of assessment. Thus, 

our regional haze regulations reflect a 

different interpretation—instead of ‘‘any 

existing source,’’ section 

51.308(d)(1)(i)(A) refers to ‘‘potentially 

affected sources.’’ As discussed above, 

there is no suggestion that we intended 

to limit this to only mean sources 

constructed after 1977, and it is too late 

for the commenter to challenge our 

regional haze regulations now. Thus, the 

commenter’s parsing of the statutory 

language and the legislative history is 

irrelevant. Furthermore, EPA’s reports 

to Congress and other sources cited by 

the commenter do not reflect our 

interpretation of the RHR and therefore 

have no regulatory weight. 

Comment: Basin Electric states that, 

under the RHR, if a state proposes an 

RPG that doesn’t meet the URP, all the 

state has to do is explain why meeting 

the URP isn’t reasonable. 

Response: This comment understates 

the requirements of the RHR. If a state 

establishes an RPG that does not meet 

the URP, the state must demonstrate, on 

the basis of the four RP factors, that (1) 

meeting the URP isn’t reasonable; and 

(2) the RPG adopted by the state is 

reasonable. The commenter’s statement 

ignores the requirement to consider the 

four RP factors and to show that the 

RPG is reasonable. EPA therefore 

disagrees with the statement. 

Comment: Basin Electric argues that 

no state has full control over its RPGs, 

because visibility improvements depend 

largely on reductions from other states. 

Response: Even if visibility impacts to 

an in-state Class I area are largely due 

to sources in other states, each state is 

nonetheless obliged to make RP 

determinations for in-state sources 

based on a reasonable analysis of the 

four statutory factors. In this case, 

NDDH’s reliance on current degraded 

background modeling as an additional 

factor was unreasonable. Thus, Basin 

Electric’s argument gives no basis for 

EPA to change its disapproval of the 

State’s RPGs or the NOX RP 

determination for AVS. 

Comment: Basin Electric states that 

visibility improvement cannot be 

ignored in the RP four-factor analysis. 

Response: As we have noted, the four 

RP factors are the costs of compliance, 

the time necessary for compliance, the 

energy and non-air quality 

environmental impacts of compliance, 

and the remaining useful life of any 

potentially affected sources. As we have 

also noted, when visibility benefits are 

considered in the analysis of potential 

single-source controls, such 

consideration must be reasonable. In 

this case, NDDH unreasonably relied on 

modeling using current degraded 

background to reject RP controls for 

AVS. Finally, in imposing LNB to meet 

reasonable progress requirements, EPA 

has considered visibility improvement, 

which, as shown by the CALPUFF 

modeling provided by NDDH, is 0.754 

deciviews at TRNP for installation of 

LNB at AVS. 

Comment: Basin Electric states that 

EPA’s disapproval of North Dakota’s RP 

determination for AVS is based solely 

on EPA’s rejection of the State’s use of 

a degraded background in modeling. 

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Response: The basis for our 

disapproval is fully explained in our 

proposal. 76 FR 58627, 58629–58630. 

We did not rely solely on the State’s use 

of improper modeling. We note that, 

despite the State’s flawed use of current 

degraded background modeling, we 

nonetheless approved several of the 

State’s other reasonable progress 

determinations based on our 

consideration of the statutory reasonable 

progress factors. 

Comment: Basin Electric argues that 

the dollar per deciview benefit of LNB 

+ SNCR at AVS, computed using North 

Dakota’s modeling, is much higher than 

that some FLMs have found acceptable. 

Basin Electric states that EPA does not 

object to the use of dollar per deciview 

in making an RP determination. Instead, 

EPA objects only to the modeling itself. 

Response: EPA guidance indicates 

that it may be reasonable to evaluate the 

dollar per deciview value in appropriate 

circumstances. However, EPA has not 

established a threshold, required or 

recommended, below which such value 

is considered reasonable and above 

which it is considered unreasonable. 

Nor have we endorsed or accepted any 

values the FLMs may have found 

acceptable. Under our regulations, we 

determine whether a state’s rejection of 

reasonable progress controls is 

reasonable based on the reasonable 

progress factors. We have explained in 

response to other comments why North 

Dakota’s modeling using current 

degraded background and dollar per 

deciview values based on that modeling 

are not reasonable. In addition, EPA is 

imposing only LNB, not LNB + SNCR, 

at AVS. Thus, the dollar per deciview 

benefit of LNB + SNCR is not directly 

relevant. We provide further detail 

regarding use of dollars per deciview 

values in our response to prior 

comments. 

Comment: Basin Electric states that 

EPA has no basis to disregard the State’s 

cumulative modeling of visibility 

improvements at AVS. Basin Electric 

argues that the reasoning for using 

degraded background conditions in 

BART modeling applies equally to RP 

modeling, because the horizon for RP 

sources is 2018 (similar to the five-year 

horizon for BART). 

Response: As noted elsewhere, the 

reasoning for using current degraded 

background conditions in BART 

modeling is faulty. That reasoning 

therefore gives no basis for using current 

degraded background conditions in RP 

modeling. 

Comment: Basin Electric states that 

EPA admits that there is no requirement 

that states, when performing RP 

analysis, follow the modeling 

procedures set out in the BART 

guidelines. Basin Electric states that 

EPA does not cite any statute or rule 

that the North Dakota RP modeling 

violates. 

Response: As we have noted, our 

regulations require consideration of four 

factors in reasonable progress 

determinations; visibility improvement 

is not one of the specified factors. As we 

have indicated, when a state considers 

visibility improvement as an additional 

factor in evaluating single-source 

control options, that consideration must 

be reasonable in light of the explicit 

goals established by Congress in CAA 

section 169A. 

Comment: Basin Electric states that 

EPA is in error in asserting that North 

Dakota modeled BART sources one way 

and RP sources another way. Basin 

Electric argues that even if EPA is 

correct, there is no authority that 

requires the State to model BART and 

RP sources the same way. 

Response: We disagree with the 

commenter. North Dakota relied on 

CALPUFF modeling using natural 

background for almost all BART 

sources. The only exceptions were 

MRYS 1 and 2 and LOS 2, and then only 

for NOX. We explained in our proposal 

why North Dakota’s alternative 

modeling for these BART units for NOX

was unreasonable. Despite the similarity 

of several of the reasonable progress 

units to the BART units, North Dakota 

modeled visibility improvement for 

potential control options on individual 

reasonable progress sources using 

current degraded background. We have 

explained in our other responses and in 

our proposal why this was 

unreasonable. 

Comment: Basin Electric argues that 

states have the responsibility to set 

RPGs and evaluate RP controls. Basin 

Electric states that nothing prohibits the 

State from using degraded background 

conditions. 

Response: For the reasons already 

expressed, we disagree with the import 

of this comment. We agree that the 

states have the responsibility to set 

RPGs and evaluate RP controls in the 

first instance, but EPA must determine 

if a state’s determinations for RPGs and 

for controls satisfy the requirements of 

the RHR and are reasonable. In the case 

of AVS 1 and 2, the State’s 

determination was unreasonable. 

Comment: Basin Electric argues that, 

in considering the CALPUFF modeling 

results for AVS, EPA should use the 

90th percentile values, not the 98th 

percentile values, and should use the 

three year average, not the worst-case 

year. 

Response: For the same reasons 

expressed in our responses to similar 

comments related to BART in section 

V.C, we disagree. 

Comment: Basin Electric argues that 

the case for using 90th percentile values 

is stronger for RP, as RP is determined 

based on improvement for the most 

impaired days, which is defined as the 

average impairment for the 20% of days 

with the highest impairment. Basin 

Electric states that use of the 98th 

percentile is inconsistent with this 

provision. 

Response: EPA disagrees with this 

comment, which conflates and misstates 

requirements of the RHR. Reasonable 

progress is not ‘‘determined’’ based on 

improvement for the most impaired 

days; instead, improvement for the most 

impaired days is one, and not the only, 

requirement for reasonable progress. 

Separately, states are required to 

evaluate, considering the four statutory 

RP factors, controls for potentially 

affected sources. In this separate 

determination, when a state considers 

visibility benefits as an additional 

factor, a state’s assessment and analysis 

of visibility benefits must be reasonable. 

Use of the 90th percentile, which 

seriously understates visibility benefits, 

is unreasonable, and cannot be justified 

by reference to the separate requirement 

regarding the most impaired days. 

Comment: Basin Electric notes that 

EPA evaluated the cost of controls for 

AVS Units 1 and 2 separately, but 

evaluated the visibility benefits 

combined. Basin Electric argues that 

this is an invalid, apples-to-oranges 

comparison. 

Response: Given that AVS 1 and 2 are 

the same size and are co-located, and 

reductions would be similar from each, 

we do not agree that it is invalid to 

consider the combined visibility 

benefits. There is no requirement, when 

considering visibility benefits as an 

additional factor, to separately model 

co-located and similar units. 

Furthermore, dollar-per-ton values 

would not change significantly if costs 

were evaluated for the two units 

combined. Finally, EPA notes that, even 

if the visibility benefits were evenly 

divided between the two units, EPA 

would still consider LNB appropriate at 

each unit, based on the four statutory 

factors and the additional factor of 

visibility benefits. 

Comment: Basin Electric references 

additional modeling, provided by Basin 

Electric, that shows that the visibility 

benefits (using 90th percentile, threeyear average, and a receptor-by-receptor 

approach) for LNB at AVS Units 1 and 

2 combined is 0.07 deciviews. Divided 

between the units equally, this would be 

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0.035 deciviews. Basin Electric argues 

that these improvements do not support 

imposing LNB, especially when the 

dollars per deciview improvement is 

considered. 

Response: As discussed elsewhere, we 

find it reasonable to use the 98th 

percentile, worst-of-three-year modeled 

benefit over all receptors. The use of the 

90th percentile, the three-year average, 

and the receptor-by-receptor approach 

understates the visibility benefits of 

controls. As a result, the dollar-perdeciview value computed using that 

approach, found in Table 8 of Basin 

Electric’s comments and from which 

Basin Electric derives the 0.07 deciview 

figure, is not reasonable or persuasive. 

Comment: Basin Electric argues that 

EPA’s justification for disapproving 

North Dakota’s RPGs is insufficient. 

Basin Electric asserts that, even if EPA 

is correctly determining BART and RP 

limits for the individual facilities, EPA 

must provide some additional basis for 

disapproving the RPGs, such as: (1) 

North Dakota is not providing for 

improvement for the worst 20% days; or 

(2) North Dakota is not ensuring no 

further degradation for the best 20% 

days. Basin Electric also notes that EPA 

did not assess how far short 

(presumably quantitatively) North 

Dakota’s selected goals fall from 

reasonable progress. 

Response: EPA disagrees with this 

comment. The bases suggested by Basin 

Electric as necessary for disapproval 

(improvement for the worst 20% days 

and no further degradation for the best 

20% days) are requirements of the RHR, 

but they are not the only requirements. 

As noted in the proposal, if a state’s 

RPGs do not meet the URP, the state 

must demonstrate that the RPGs are 

reasonable, based on consideration of 

the four statutory factors, and that 

meeting the URP is unreasonable. The 

State’s failure to satisfy this requirement 

(and not the requirements noted by the 

commenter) is the basis for the 

disapproval of the State’s RPGs. In 

particular, the State’s use of current 

degraded background in modeling for 

visibility benefits was unreasonable, as 

was the State’s failure to select 

reasonable RP controls for AVS Units 1 

and 2. It is unnecessary to quantify how 

far short North Dakota’s selected goals 

fall from the RPGs proposed by EPA in 

order to determine that the State’s 

analysis was unreasonable. Nonetheless, 

EPA notes that the proposed NOX RP 

limit, based on installation of LNB, for 

AVS Units 1 and 2 will result in 

combined emissions reductions of over 

7,000 tons per year of NOX, with a 

visibility benefit of 0.754 deciviews at 

TRNP. Due to time and resource 

constraints, we lacked the capability to 

re-do the WRAP modeling to precisely 

re-calculate the RPGs. 

Comment: Basin Electric states that 

the values for cost effectiveness of LNB 

at AVS Units 1 and 2 do not reflect upto-date costs, which would be higher. 

However, Basin Electric specifically 

disclaims that up-to-date costs, standing 

alone, would provide a sufficient reason 

to reject LNB. 

Response: In its FIP, EPA is relying in 

part on costs provided by North Dakota 

in its RH SIP to meet the requirements 

of the RHR. In promulgating the FIP, it 

is not necessary to regenerate the costs 

for AVS 1 and 2. Nonetheless, EPA 

agrees that regenerated costs for LNB at 

AVS Units 1 and 2 would likely support 

EPA’s determination. LNB is a widely 

used, inexpensive control option to 

reduce NOX emissions. 

Comment: Citing 40 CFR 51.308(d), 

Basin Electric states that EPA does not 

propose a true FIP for RPGs, because 

RPGs are defined by rule as a rate of 

visibility improvement. Basin Electric 

alleges that rerunning the WRAP CMAQ 

modeling with the controls imposed to 

quantify the rate of improvement would 

cost a modest amount of money, and 

states that this amount of money should 

be contrasted with the cost of controls 

that will, according to Basin Electric, 

result in negligible visibility 

improvements. 

Response: As discussed elsewhere, 

the visibility improvements from AVS 

alone will not be negligible, as shown 

by the CALPUFF modeling provided by 

North Dakota, and even the CALPUFF 

modeling provided by Basin Electric 

with its comments. We assume Basin 

Electric bases its statement about 

negligible visibility improvements on 

the modeling using current degraded 

background relied on by North Dakota, 

which, as discussed elsewhere, we are 

disregarding. As discussed in the notice 

of proposed action, we would have 

preferred to quantify the rate of 

improvement, but time and resource 

constraints prevented this. Re-running 

the WRAP CMAQ modeling would not 

change our conclusion about the 

reasonableness of LNB at AVS 1 and 2. 

Comment: Basin Electric states that, 

without modeling, there is no basis for 

EPA to state that our FIP would increase 

the rate of visibility improvement on the 

20% worst days. Basin Electric asserts 

that emissions reductions from the FIP 

sources are miniscule compared with 

the total reductions assumed in the 

WRAP CMAQ modeling for RPGs. Basin 

Electric notes that that modeling 

showed an overall 0.6 deciview 

improvement at TRNP and a 0.5 

deciview improvement at LWA. 

Response: It is logical to infer that the 

considerable emissions reductions at 

CCS and AVS will increase the visibility 

improvement on the 20% worst days. 

We acknowledged in our proposal that 

this improvement would not be 

sufficient to achieve the URP (76 FR 

58632) and agree that the improvement 

will likely be small given that the 

starting point for the cited modeling is 

current degraded conditions. But the 

same could be said for BART sources, 

yet North Dakota has acknowledged that 

such sources contribute to visibility 

impairment in the Class I areas in North 

Dakota. 

Comment: Basin Electric states that 

the disapproval of North Dakota’s RPGs 

and our FIP have no meaningful effect. 

Response: As we stated in our 

proposal, the RPGs are not enforceable 

values. To that extent, they do not 

impose requirements on anyone. 

However, we are required to disapprove 

the RPGs because they do not reflect 

reasonable controls at CCS and AVS, 

and we are required to impose a FIP in 

lieu of the State’s unapprovable RPGs. 

Our reasonable progress controls at AVS 

and our BART controls at CCS do 

impose enforceable requirements. 

Comment: Basin Electric asserts that, 

because EPA has no basis for our 

disapprovals and FIPs at individual 

facilities, EPA also has no basis for our 

FIP for RPGs. 

Response: See our responses to prior 

comments. We have explained the bases 

for our disapprovals. 

Comment: NPCA comments that it is 

unreasonable for EPA to give Basin 

Electric until July 31, 2018 to install 

LNB at Antelope Valley because that 

date is not ‘‘as expeditious as possible.’’ 

NPCA states that the deadline should be 

January 26, 2013, which NPCA believes 

represents a reasonable amount of time 

to install the combustion controls. 

Response: EPA disagrees with this 

comment. First, unlike for BART 

sources, the RHR and the CAA do not 

explicitly require that limits for RP 

sources be met as expeditiously as 

practicable. Furthermore, the 

commenter misstates the deadline: The 

proposed FIP requires Basin Electric to 

meet the proposed NOX emissions limit 

at Antelope Valley ‘‘as expeditiously as 

practicable, but in any event no later 

than July 31, 2018.’’ Thus, Basin Electric 

is under an obligation to install the 

combustion controls as expeditiously as 

practicable. The cutoff date of July 31, 

2018 ensures that the RP limit for 

Antelope Valley is met by the end of the 

planning period, thereby also ensuring 

that the proposed RPGs are met. 

Comment: NPCA states that EPA 

should reevaluate the cost estimate for 

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SCR + reheat at AVS. NPCA argues that 

North Dakota’s cost estimate is flawed 

in the same way as for LOS 2 and MRYS 

2. EPA proposed to disapprove the costs 

for Leland Olds Unit 2; NPCA argues 

that EPA therefore cannot rely on the 

same costs in determining RP controls 

for Antelope Valley. 

Response: While EPA agrees that the 

cost estimates for SCR at LOS 2 and 

MRYS 2 are flawed, the costs for AVS 

nonetheless present a sufficient basis for 

EPA’s RP determination. EPA accepts, 

and NPCA does not question, the costs 

for LNB alone. Even if the cost estimate 

for SCR + reheat was redone, it would 

likely remain considerably more costly 

than LNB. LNB is very cost-effective and 

achieves reductions of about 78% of 

SNCR + LNB and 64% of SCR with 

reheat. Given the extreme costeffectiveness of LNB and reductions of 

at least 64% of more expensive controls, 

and taking into account the four 

statutory factors as well as visibility 

benefits of LNB, EPA has determined 

that it is reasonable to impose LNB at 

Antelope Valley in this planning period. 

Of course, the imposition of LNB at AVS 

does not rule out the imposition of postcombustion controls in the next 

planning period. 

Comment: NPCA states that North 

Dakota’s cost estimates for SCR + reheat 

and ASOFA + SCR + reheat at Coyote 

Station are flawed. NPCA argues that 

EPA should redo the RP analysis for 

Coyote, and that a revised RP four-factor 

analysis would show that SCR + reheat 

is reasonable. In addition, NPCA notes 

that the facility is fairly close to TRNP, 

the State cannot meet the URP, and SCR 

+ reheat would reduce emissions by 

over 10,000 tpy. 

The NPS states similar concerns with 

North Dakota’s use of inappropriate 

dollar per deciview estimates as a basis 

for determining that no additional 

controls were appropriate under RP for 

Coyote Station. NPS notes that EPA has 

recognized that the methods North 

Dakota used to reach that conclusion, 

both for estimating costs and visibility 

improvement, are invalid. NPS infers 

that North Dakota has not met its 

responsibility to conduct a valid RP 

analysis and that EPA must therefore 

assume that responsibility. An NPS 

analysis indicates SCR at Coyote would 

be more cost effective than at any other 

North Dakota EGU. NPS concludes that 

EPA must impose an RP emissions limit 

for Coyote of 0.07 lb/MMBtu (the same 

as for MRYS 1 and 2, and LOS 2). 

Response: EPA has now decided that 

the rejection of SCR at Coyote is 

appropriate regardless of the State’s cost 

analysis, based on the court’s upholding 

of North Dakota’s determination in the 

BACT proceeding for MRYS that SCR is 

technically infeasible. Like MRYS, 

Coyote is a cyclone unit burning North 

Dakota lignite. Thus, based on current 

evidence, we cannot conclude that 

North Dakota’s rejection of SCR at 

Coyote was unreasonable. 

Comment: NPCA states that the record 

shows that a wet scrubber would be cost 

effective at Coyote Station, and believes 

that the actual cost effectiveness may be 

better. NPCA computes that a 99% 

efficient wet scrubber would remove 

about 13,000 tons per year of SO2. The 

cost overestimates made by other 

facilities indicate that EPA should 

revisit this cost analysis. 

Response: EPA disagrees with this 

comment. First, NPCA did not identify 

any cost overestimates related to wet 

scrubbers. The issues EPA identified in 

its proposal related to costs of SCR, 

which provides no basis for inferring 

cost overestimates for wet scrubbers. As 

far as the record, Table 9.8 in North 

Dakota’s RH SIP submittal shows a cost 

effectiveness value of $2,593 per ton of 

SO2 removed at a control efficiency of 

95%. As stated in our proposal, while 

this value is within the range of cost 

effectiveness values that North Dakota, 

other states, and we have considered 

reasonable in the BART context, it is not 

so low that we are prepared to 

disapprove the State’s conclusion in the 

reasonable progress context. In addition, 

Coyote Station currently employs a 

spray dryer to control SO2 emissions at 

a control efficiency of approximately 

66%. The existence of this control 

supports our approval of the State’s 

determination. Analogous to our policy 

in the BART context, we do not expect 

sources to install entirely new SO2

controls where they are already 

achieving reductions greater than 50%. 

Comment: NPCA notes EPA’s 

response to a petition from the Dakota 

Resource Council regarding violations of 

PSD Class I SO2 increments, in which 

EPA stated that a SIP call would not 

achieve any better result than other 

pending actions, including regional 

haze actions. NPCA argues that, based 

on this response, EPA should require 

SO2 controls at Coyote Station to reduce 

consumed Class I SO2 increment. 

Response: EPA disagrees with this 

comment. As discussed extensively in 

our response to a prior comment, PSD 

permit program requirements in Subpart 

I, Part C of title I of the CAA are separate 

from visibility protection requirements 

in Subpart II of Part C. Therefore, Class 

I SO2 increments are not relevant to our 

action on North Dakota’s RH SIP 

submittal to meet the requirements of 

CAA section 169A and the RHR. 

Nonetheless, EPA notes that SO2

emissions will be substantially reduced 

by our action on the North Dakota RH 

SIP, as detailed in Table 21 of our notice 

proposing action. 

Comment: NPCA argues that 

limestone injection at Heskett Station is 

a cost effective and reasonable RP 

control that would achieve SO2

reductions of 1614 tons per year. 

However, NPCA notes that the 

agreement between North Dakota and 

the facility only requires reductions of 

573 tons per year of SO2. NPCA 

concludes that EPA should require 

Heskett to achieve an SO2 limit that 

reflects the capabilities of limestone 

injection. 

Response: EPA considers the State’s 

determination to impose the stated 

reductions in the permit included in SIP 

Supplement No. 1 to be reasonable and 

to satisfy reasonable progress 

requirements in this initial planning 

period. Further reductions may be 

appropriate in a subsequent planning 

period. 

Comment: NPCA argues that staged 

combustion is a cost effective control for 

NOX at Heskett Station at $1,700/ton. 

Even though the emission reduction is 

only 215 tons per year, NPCA argues 

that EPA must consider all potential 

sources that can contribute to achieving 

RPGs, including NOX reductions from 

Heskett Station. 

Response: EPA disagrees with this 

comment. In the first instance, it is the 

responsibility of the State to consider 

the four statutory factors for potentially 

affected sources. EPA’s task is to 

determine if the State’s analysis of 

controls satisfies the requirements of the 

RHR and is reasonable. In this case, the 

State did consider the four statutory 

factors, as well as an additional factor— 

visibility improvement based on 

modeling using current degraded 

background. While EPA does not 

consider the State’s use of modeling 

based on current degraded background 

reasonable, EPA nonetheless considers 

the result of the State’s analysis in this 

instance to be reasonable, based on the 

relatively low emissions reductions and 

the costs of controls. 

Comment: NPCA states that several 

NOX control options for Tioga Gas Plant 

are cost effective, with the lowest at 

$521/ton. Although the emissions 

reductions are lower, NPCA argues that 

EPA should consider all potential 

sources that can contribute to achieving 

RPGs. In addition, NPCA notes that the 

facility is only 35 km from LWA and is 

also near TRNP. 

Response: EPA disagrees with this 

comment for the same reasons discussed 

in response to the prior comment. 

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Comment: NPCA states that EPA 

should re-run the WRAP CMAQ 

modeling with emissions that reflect the 

BART and RP controls that EPA 

proposes to approve or impose through 

a FIP. NPCA argues that EPA and the 

State should track actual visibility 

improvements versus projected 

visibility improvements, and that this 

would assist in estimating visibility 

improvements from other measures. 

Response: As stated in our notice of 

proposed action, we could not re-run 

the WRAP modeling due to time and 

resource constraints. We expect the 

State to quantify the visibility 

improvement in its next RH SIP 

revision. 

Comment: The NPS stated that North 

Dakota did not meet its responsibility to 

perform a valid RP analysis, as the 

State’s cost analysis and modeling for 

RP sources were flawed. Although the 

NPS stated that this was a general issue, 

the comment specifically noted flaws in 

the State’s cost analysis for Coyote 

Station. The NPS argued that EPA must 

redo the analysis, and cannot propose to 

approve any RP determinations. 

Response: EPA disagrees with the 

conclusion of this comment. Although 

EPA agrees that the State’s cost analysis 

for SCR at Coyote Station was flawed, 

and that the State’s modeling of 

visibility benefits of controls on RP 

sources using degraded background 

conditions was flawed, there is a 

sufficient basis for EPA’s actions. As 

noted in a prior response, EPA has now 

decided that the rejection of SCR at 

Coyote is appropriate regardless of the 

State’s cost analysis, based on the 

court’s upholding of North Dakota’s 

determination in the BACT proceeding 

for MRYS that SCR is technically 

infeasible. Like MRYS, Coyote is a 

cyclone unit burning North Dakota 

lignite. 

As noted, with respect to other 

reasonable progress units, we have 

disregarded the State’s visibility 

analysis in our review of the State’s 

reasonable progress determinations and 

instead focused on the four reasonable 

progress factors. Except for AVS 1 and 

2, we have determined that the State’s 

reasonable progress determinations 

were not unreasonable. 

Comment: The NPS stated that the RP 

analysis of SCR for Coyote Station was 

cursory. The NPS noted that, under the 

0.50 lb/MMBtu annual rate agreed to by 

the State, Coyote Station would still 

have the highest controlled emissions 

rate of any EGU in North Dakota and 

would be the 13th largest emitter of 

NOX among all EGUs, using 2010 rates 

in the Clean Air Markets Division 

database. NPS argues that, as a result, 

SCR should have been given more 

consideration. 

Response: First, EPA disagrees with 

some of the NPS computations. Based 

on 2010 Clean Air Markets Division 

data, Coyote Station was the 124th 

largest emitter of NOX among EGUs at 

13,691 tons. At the rate of 0.50 lb/ 

MMBtu agreed to by the State, the 

emissions (with the same heat input) 

would have been 8,800 tons, which 

would have made Coyote Station the 

183rd largest emitter of NOX for that 

year. This represents a reduction of over 

4,800 tons per year. In any case, the 

relative rank of a facility among other 

facilities nationwide in overall 

emissions is not a necessary component 

of the RP analysis. 

We have already explained why we 

are not disapproving the State’s 

rejection of SCR at Coyote. 

Comment: The NPS noted that the RP 

analysis for Coyote Station did not 

consider upgrades to the existing dry 

scrubber. 

Response: In making an RP 

determination, the State must consider 

a reasonable range of controls. For SO2,

the State considered a new wet 

scrubber. While EPA agrees that 

upgrades to the existing dry scrubber 

should have been considered, starting 

with feasibility, EPA is not prepared to 

determine, on the basis of this 

consideration, that the State was 

unreasonable in addressing RP 

requirements for Coyote Station through 

imposing the 0.50 lb/MMBtu NOX limit 

and not imposing an SO2 limit. EPA 

does expect the State to revisit the range 

of controls in the next planning period. 

Comment: NPS provided cost 

estimates for installation of SCR at 

Coyote Station, showing a cost 

effectiveness value of $1,600 per ton 

removed and an incremental cost 

effectiveness value of $2,300 per ton 

removed. NPS stated that these costs are 

lower than those for SCR at LOS 2 and 

MRYS 1 and 2. NPS argued that, for 

consistency, EPA must impose SCR at 

Coyote Station. 

Response: The basis for our decision 

regarding the State’s rejection of SCR at 

Coyote is explained in prior responses. 

H. Comments on Health and Ecosystem 

Benefits, and Other Pollutants 

Comment: Several commenters stated 

that haze pollution significantly impacts 

human health and ecosystem health, in 

addition to obscuring scenic vistas. 

Specifically, commenters asserted that 

haze pollution contributes to heart 

attacks, asthma attacks, chronic 

bronchitis and respiratory illness, 

increased hospital admissions, lost work 

days, and even premature death. One 

commenter noted the specific haze 

pollutants NOX, SO2 and PM, which the 

commenter stated are all harmful to the 

human body. 

Some commenters cited a 2009 Clean 

Air Task Force report in stating that 

coal-fired power plants in North Dakota 

put 207 people at risk of premature 

death, 321 people at risk of a heart 

attack, and 3,500 at risk of an asthma 

attack each year. Several commenters 

encouraged EPA to finalize the regional 

haze proposal citing their own health 

problems, most notably individuals 

with asthma or respiratory problems, 

seniors, and parents of asthmatic 

children. One commenter stated the rate 

of asthma in North Dakota children is 

increasing rapidly. 

Some commenters stated that haze 

pollution negatively impacts ecosystem 

health. Commenters expressed concern 

for the effects of haze pollution on 

wildlife, farm animals, plants including 

crops, and water bodies. Several 

commenters generally expressed their 

disapproval of coal as an energy source 

because it is dirty, with some insisting 

that North Dakota invest in cleaner 

energy. 

Response: We appreciate the 

commenters’ concerns regarding the 

negative health impacts of emissions 

from the coal-fired power plants in 

North Dakota. We agree that the same 

PM2.5 emissions that cause visibility 

impairment can be inhaled deep into 

lungs, which can cause respiratory 

problems, decreased lung function, 

aggravated asthma, bronchitis, and 

premature death. We also agree that the 

same NOX emissions that cause 

visibility impairment also contribute to 

the formation of ground-level ozone, 

which has been linked with respiratory 

problems, aggravated asthma, and even 

permanent lung damage. We agree that 

these pollutants can have negative 

impacts on plants and ecosystems, 

damaging plants, trees and other 

vegetation, and reducing forest growth 

and crop yields, which could have a 

negative effect on species diversity in 

ecosystems. However, for purposes of 

this action, we are not authorized to 

consider these impacts in evaluating the 

State’s RH SIP and promulgating our 

FIP, and we have not done so. 

Comment: Some commenters stated 

that regional haze is not a health-based 

standard. 

Response: We agree that regional haze 

is not a health-based standard. 

I. Miscellaneous Comments 

Comment: Several commenters stated 

that the large economic costs of 

installing pollution controls stated by 

electricity providers failed to consider 

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20938 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

69The American Lung Association State of the 

Air report is available at www.stateoftheair.org. 

the significant offsets of those costs. One 

commenter stated that TRNP is an 

economic engine, further stating that the 

park logged over 580,000 recreational 

visits, was responsible for 500 jobs and 

$27.4 million in expenditures in 2009 

alone. Another commenter stated that, 

while the installation of pollution 

controls costs money, it also stimulates 

the economy by providing jobs in 

construction and installation. Others 

stated a willingness to pay the expected 

increase in their utility costs, with one 

commenter stating that North Dakota’s 

electricity is amongst the least 

expensive in the U.S. 

Response: We agree with the 

comments. Although we did not 

consider the potential positive benefits 

to the local and national economies in 

making our decision today, we do 

expect that improved visibility would 

have a positive impact on tourismdependent local economies. Also, 

retrofitting CCS with SNCR is a large 

construction project that we expect to 

take 5 years to complete. This project, 

along with the other pollution control 

upgrades proposed in the SIP, will 

require well-paid, skilled labor which 

can potentially be drawn from the local 

area, which is expected to benefit the 

economy. 

Comment: Multiple commenters 

stated that North Dakota is one of only 

12 states in the U.S. who meet all 

NAAQS. 

Response: While the relative air 

quality in North Dakota is considered 

good compared to many other states, as 

further discussed elsewhere in our 

responses, our actions pertaining to the 

RHR are governed by the national 

visibility goal established by Congress 

in the CAA. The goal is to return the 

visibility conditions in Class I areas 

back to natural conditions. And 

visibility in Class I areas in North 

Dakota is impaired by pollution from 

industrial sources within the state. 

There is no direct correlation between 

natural visibility conditions and the 

current NAAQS. 

Comment: Several commenters stated 

that the American Lung Association 

ranked Mercer County, North Dakota, 

home to several coal-fired power plants, 

as one of the 25 cleanest counties in the 

U.S., and ranked Billings County, North 

Dakota, home to TRNP, the third 

cleanest county in the United States. 

Response: The commenters are 

referring to the 2010 State of the Air 

Report, which assigns letter grades for 

counties with air quality monitors for 

ozone and particulate pollution.69 The 

report, issued every year by the 

American Lung Association, did give 

the mentioned counties an ‘‘A’’ grade in 

2010 for ground level ozone. The State 

of the Air Report does not, however, 

address regional haze. The RHR relies 

on a combination of monitoring data to 

assess current visibility conditions and 

modeling of predicted visibility impacts 

at federal Class I areas (primarily 

national parks and wilderness areas), 

which is a different methodology than 

direct measurement of ozone and 

particulate pollution, which is the 

approach relied on by the American 

Lung Association. Current visibility 

impacts at TRNP and LWA are over 

double the impacts estimated for natural 

conditions, and North Dakota’s Class I 

areas are not projected to meet the URP 

in the initial planning period. 

Comment: Commenter cited the NPS’s 

Web page for TRNP, which states that 

the park has better air quality than every 

other U.S. national park aside from 

Denali National Park in Alaska. 

Response: In our action, we are 

responding to the national visibility goal 

established by Congress in the CAA. 

The goal is to return to natural visibility 

conditions. TRNP is not meeting the 

URP for returning the park to natural 

visibility conditions. The NPS’ Web 

page for TRNP does state that air quality 

is relatively good, but it also discusses 

the fact that pollution sometimes causes 

haze and may affect other sensitive 

resources in the park. For current 

information on TRNP’s air quality visit 

http://www.nps.gov/thro/naturescience/

airquality.htm. 

Comment: Commenter insisted that 

CCS and LOS should be retired, as they 

are respectively rated the 3rd and 19th 

most polluting coal plants in the U.S. 

(Citing sourcewatch.org.) 

Response: While we respect the 

commenter’s opinion, a regulatory 

process has been established under the 

CAA and our regulations for considering 

pollution controls to address visibility 

impairment, and our action follows that 

process. 

Comment: Many commenters 

generally stated that the costs of EPA’s 

proposed rule are high when compared 

to benefits. They stated that NDDH’s SIP 

costs much less to implement than does 

EPA’s plan, and produces similar 

benefits. High costs were cited both 

with respect to capital costs of the 

controls as well as increased costs (retail 

price per kilowatt hour) to consumers 

particularly fixed and lower-income 

consumers. Negative economic impacts 

to agriculture and oil and gas industries 

were cited, noting that the success of 

these industries is dependent on lowcost and reliable electric power. Several 

commenters specifically mentioned a 

cost of $700 million to install EPA’s 

proposed controls and the potential for 

lost jobs. Some commenters expressed a 

willingness to pay the potential increase 

in their electric bills because they 

supported EPA’s action. 

Response: While we disagree with a 

number of the commenters’ assertions, 

these comments are largely no longer 

relevant because we have decided to 

approve North Dakota’s NOX BART 

determinations for MRYS 1 and 2 and 

LOS 2 on grounds explained elsewhere. 

To the degree that some of these 

comments extend to our FIP for CCS 

and AVS, EPA’s evaluation of capital 

and annual expenses associated with 

implementation of the FIP shows such 

expenses to be justified by the degree of 

improvement in visibility in 

relationship to the cost of 

implementation. 

We take our duty to estimate the cost 

of controls very seriously, and make 

every attempt to make a thoughtful and 

well informed determination. However, 

we do not consider a potential increase 

in electricity rates to be the most 

appropriate type of analysis for 

considering the costs of compliance in 

a BART determination. Nevertheless, 

our analysis indicates that the annual 

costs to CCS and AVS associated with 

our FIP will be relatively modest 

considering the size of the plants, and 

impacts to rate payers should be much 

lower than anticipated by commenters. 

Comment: Commenter cited EPA’s 

Clean Air Markets database, which 

states that North Dakota ranked #12 in 

SO2 emissions and #19 in NOX

emissions. The commenter also 

provided the SO2 and NOX rankings for 

the seven North Dakota EGUs discussed 

in the SIP. 

Response: We appreciate the 

commenter providing the SO2 and NOX

rankings for North Dakota and its EGUs. 

We do not disagree with the information 

provided and acknowledge the data 

suggest the North Dakota plants rank 

relatively high in the amount of SO2 and 

NOX emissions compared to other 

states. However, we note that BART and 

RP determinations involve case-by-case 

determinations considering the relevant 

statutory factors, which do not include 

the relative emissions rankings. 

Comment: Commenter requests that 

EPA set limits on ammonia slip where 

SNCR or SCR is required for BART. 

Response: In Section 7.1.2 of the SIP, 

North Dakota concluded that ammonia 

is not a visibility impairing pollutant of 

concern as ammonia emissions (and 

associated regional haze impacts) from 

BART-eligible sources are negligible. 

We concur with this conclusion. 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20939 

Accordingly, there is no basis to set 

limits on ammonia slip to address 

concerns related to regional haze 

impacts. Nor is it necessary to set limits 

on ammonia slip to ensure compliance 

with NOX emission limits because NOX

CEMS will be used. 

J. Comments Requesting an Extension to 

the Public Comment Period 

Comment: One commenter requested 

that the comment period be extended to 

December 21, 2011 and Governor 

Dalrymple and Senator Hoeven 

requested the time allotted for the 

public hearings be increased. 

Response: The comment period for 

our proposal closed on November 21, 

2011. We carefully considered the 

request for an extension to the comment 

period. We took into consideration how 

an extension might affect our ability to 

consider comments received on the 

proposed action and still comply with 

our consent decree deadlines. We do 

note that our October 13 and 14, 2011, 

public hearing in Bismarck, North 

Dakota was well attended and provided 

an opportunity for people to comment 

on our proposal. Also regarding the 

public hearings, we agreed to Governor 

Dalrymple’s and Senator Hoeven’s 

requests to extend the length of the 

public hearing and to allow as much 

time as needed for state representatives 

to present their comments. 

K. Comments Generally in Favor of Our 

Proposal 

Comment: Overall, we received more 

than 24,000 comment letters in support 

of our rulemaking from members 

representing various organizations, 

concerned citizens, and tribal members. 

These comments were received at the 

Public Hearing in Bismarck, North 

Dakota, by internet, and through the 

mail. Each of these commenters was 

generally in favor of portions of our 

proposed decision for North Dakota 

regional haze. These comments 

included comments urging us to require 

the most effective pollution control 

technology, SCR, at LOS 2, and MRYS 

1 and 2 and additional emission 

reductions from CCS 1 and 2 and AVS 

1 and 2. Some of these comments also 

discussed the detrimental health effects 

of haze pollution and the economic 

impacts of these health effects. Some of 

these comments urged us to keep or 

lower our proposed numeric limits on 

NOX for MRYS and LOS 2 in our final 

decision. These letters also asked us to 

require other units at LOS, Heskett 

Station, and Stanton Station to 

modernize and reduce their air 

pollution impacts. 

Response: We acknowledge the 

support of these commenters for our 

proposed action. We note that several of 

the control technology determinations 

and emissions limits supported by these 

commenters in the proposal have been 

changed in this final action based on the 

Minnkota BACT court decision and all 

of the information received during the 

comment period. Please see the docket 

associated with this action for 

additional detail. To the extent the 

comments asserted the need for more 

stringent controls, we address those 

comments in other responses. 

L. Comments Generally Against Our 

Proposal 

Comment: Various commenters 

generally stated they did not support the 

proposed rulemaking. Their reasons 

included: it will affect the town’s 

economy, affect the coal power plant 

industry, electricity costs will increase, 

they have no direct health problems 

from actual emissions, direct and 

indirect jobs/businesses would be 

affected, North Dakota already meets air 

quality standards, that there will be no 

benefit to the community, that our 

decision relies on unproven technology, 

and that it will not result in noticeable 

visibility improvements. 

We received three resolutions from 

cities in Minnesota, including Roseau, 

Big Falls, and Little Fork, which 

opposed our rulemaking. These 

resolutions included comments about 

the proposed FIP for SCR technology at 

MRYS, including comments about the 

high cost, that the technology had not 

been shown to work at similar plants, 

and that there would be no humanly 

perceptible visibility improvements 

over the State’s plan. The resolutions 

also noted that Minnkota had already 

incurred significant costs for installing 

SNCR and contracting for renewable 

sources, and that these expenditures 

were resulting in rate increases. 

We received petitions and mass 

mailer letters from nine rural power 

cooperative associations and over 3,000 

comments generated through a Web site 

established by an organization named 

Partners for Affordable Energy. 

Comments from these letters and emails 

included the following: that Congress 

left the primary responsibility for SIPs 

with states, that states have superior 

knowledge of local conditions and 

needs, and that EPA’s plan would 

provide imperceptible visibility benefits 

at huge costs. The comments also urged 

EPA to allow North Dakota to make its 

own decisions regarding its clean air 

programs. 

Response: We acknowledge these 

general comments that opposed our 

proposed action. We provide responses 

that address these issues elsewhere in 

this action. We have made changes from 

our proposal, as noted elsewhere in this 

action. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). As discussed in detail 

in section C below, the FIP applies to 

only two facilities. It is therefore not a 

rule of general applicability. 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. Under the 

Paperwork Reduction Act, a ‘‘collection 

of information’’ is defined as a 

requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *.’’ 44 U.S.C. 3502(3)(A). 

Because the FIP applies to just two 

facilities, the Paperwork Reduction Act 

does not apply. See 5 CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid 

Office of Management and Budget 

(OMB) control number. The OMB 

control numbers for our regulations in 

40 CFR are listed in 40 CFR Part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

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20940 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

I certify that this proposed action will 

not have a significant economic impact 

on a substantial number of small 

entities. The FIP that EPA is finalizing 

for purposes of the visibility prong of 

section 110(a)(2)(D)(i)(II) consists of the 

combination of the approval of the 

State’s RH SIP submission and the 

Regional Haze FIP by EPA that adds 

additional controls to certain sources. 

The Regional Haze FIP that EPA is 

finalizing for purposes of the regional 

haze program consists of imposing 

federal controls to meet the BART 

requirement for NOX emissions at one 

source in North Dakota, and imposing 

controls to meet the reasonable progress 

requirement for NOX emissions at one 

additional source in North Dakota. The 

net result of these two simultaneous FIP 

actions is that EPA is proposing direct 

emission controls on selected units at 

only two sources. The sources in 

question are each large electric 

generating plants that are not owned by 

small entities, and therefore are not 

small entities. The partial approval of 

the SIP merely approves state law as 

meeting Federal requirements and 

imposes no additional requirements 

beyond those imposed by state law. See 

Mid-Tex Electric Cooperative, Inc. v. 

FERC, 773 F.2d 327 (D.C. Cir. 1985). 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 

inflation) in any 1 year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and to 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this rule does not 

contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

1 year. In addition, this rule does not 

contain a significant Federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

affect small governments. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 

1999) revokes and replaces Executive 

Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental 

Partnership). Executive Order 13132 

requires EPA to develop an accountable 

process to ensure ‘‘meaningful and 

timely input by State and local officials 

in the development of regulatory 

policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ Under 

Executive Order 13132, EPA may not 

issue a regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by State and local 

governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

regulation. EPA also may not issue a 

regulation that has federalism 

implications and that preempts State 

law unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

This rule will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

merely addresses the State not fully 

meeting its obligation to prohibit 

emissions from interfering with other 

states’ measures to protect visibility 

established in the CAA and not fully 

meeting its obligation to adopt a SIP that 

meets the regional haze requirements 

under the CAA. Thus, Executive Order 

13132 does not apply to this action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

Consultation and Coordination with 

Indian Tribal Governments (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ We believe this rule does 

not have tribal implications, as specified 

in Executive Order 13175, and will not 

have substantial direct effects on tribal 

governments. Thus, Executive Order 

13175 does not apply to this rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children from Environmental Health 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20941 

Risks and Safety Risks (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. EPA 

interprets EO 13045 as applying only to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this rule will limit emissions of 

NOX, the rule will have a beneficial 

effect on children’s health by reducing 

air pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires Federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. 

The EPA believes that VCS are 

inapplicable to this action. Today’s 

action does not require the public to 

perform activities conducive to the use 

of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this rule 

will not have disproportionately high 

and adverse human health or 

environmental effects on minority or 

low-income populations because it 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 

high and adverse human health or 

environmental effects on any 

population, including any minority or 

low-income population. This rule limits 

emissions of NOX from two facilities in 

North Dakota. The partial approval of 

the SIP merely approves state law as 

meeting Federal requirements and 

imposes no additional requirements 

beyond those imposed by state law. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this action and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). This rule 

will be effective on May 7, 2012. 

L. Judicial Review 

Under section 307(b)(1) of the CAA, 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by June 5, 2012. Pursuant to CAA 

section 307(d)(1)(B), this action is 

subject to the requirements of CAA 

section 307(d) as it promulgates a FIP 

under CAA section 110(c). Filing a 

petition for reconsideration by the 

Administrator of this final rule does not 

affect the finality of this action for the 

purposes of judicial review nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such rule or action. This action may not 

be challenged later in proceedings to 

enforce its requirements. See CAA 

section 307(b)(2). 

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. 

Final Rule. (EPA–R08–OAR–2010–0406) 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Intergovernmental 

relations, Incorporation by reference, 

Nitrogen dioxides, Particulate matter, 

Reporting and recordkeeping 

requirements, Sulfur dioxide, Volatile 

organic compounds. 

Dated: March 1, 2012. 

Lisa P. Jackson, 

Administrator. 

40 CFR part 52 is amended as follows: 

PART 52—[AMENDED] 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart JJ—North Dakota 

■ 2. Section 52.1820 is amended by: 

■ a. Adding to the table in paragraph (c) 

an entry entitled ‘‘33–15–25 Regional 

Haze Requirements’’ at the end of the 

table. 

■ b. Revising the table in paragraph (d). 

■ c. Adding to the table in paragraph 

(e)entries ‘‘(23),’’ ‘‘(24),’’ and ‘‘(25)’’ in 

numerical order at the end of the table. 

The revisions and additions read as 

follows: 

§ 52.1820 Identification of plan. 

* * * * * 

(c) * * * 

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20942 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

State citation Title/subject State effective 

date 

EPA approval date and 

citation 1 Explanations 

*******

33–15–25 Regional Haze Requirements 

33–15–25–01 ............................... Definitions .................................... 1/1/07 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

33–15–25–02 ............................... Best available retrofit technology 1/1/07 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

33–15–25–03 ............................... Guidelines for best available retrofit technology determinations 

under the regional haze rule.

1/1/07 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

33–15–25–04 ............................... Monitoring, recordkeeping, and 

reporting.

1/1/07 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

1 In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column for the particular provision. 

* * * * * (d) * * * 

Name of source Nature of requirement State effective 

date 

EPA approval date and 

citation 3 Explanations 

Leland Olds Station Unit 1 .......... SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10004.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Leland Olds Station Unit 2 .......... SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10004.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Milton R. Young Station Unit 1 .... SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10007.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Milton R. Young Station Unit 2 .... Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10007.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Coal Creek Station Unit 1 ........... Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10005.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Excluding the NOX BART 

emissions limits for Unit 

1 and corresponding 

monitoring, recordkeeping, and reporting 

requirements, which 

EPA disapproved. 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20943 

Name of source Nature of requirement State effective 

date 

EPA approval date and 

citation 3 Explanations 

Coal Creek Station Unit 2 ........... Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10005.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Excluding the NOX BART 

emissions limits for Unit 

2 and corresponding 

monitoring, recordkeeping, and reporting 

requirements, which 

EPA disapproved. 

Stanton Station Unit 1 ................. SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Air pollution control permit to 

construct for best available retrofit technology (BART), 

PTC10006.

2/23/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Heskett Station Unit 1 ................. SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Heskett Station Unit 2 ................. SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Air Pollution Control Permit to 

Construct, PTC10028.

7/22/10 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Coyote Station Unit 1 .................. Air Pollution Control Permit to 

Construct, PTC10008.

3/14/11 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

American Crystal Sugar at 

Drayton.

SIP Chapter 8, Section 8.3, Continuous Emission Monitoring 

Requirements for Existing Stationary Sources, including 

amendments to Permits to Operate and Department Order.

5/6/77 10/17/77, 42 FR 55471. 

Tesoro Mandan Refinery ............. SIP Chapter 8, Section 8.3.1, 

Continuous Opacity Monitoring 

for Fluid Bed Catalytic Cracking Units: Tesoro Refining and 

Marketing Co., Mandan Refinery.

2/27/07 5/27/08, 73 FR 30308. 

3 In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column for the particular provision. 

* * * * * (e) * * * 

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20944 Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 

Name of nonregulatory SIP 

provision 

Applicable geographic or 

nonattainment area 

State submittal date/ 

adopted date 

EPA approval date and 

citation 3 Explanations 

*******

(23) North Dakota State 

Implementation Plan for 

Regional Haze.

Statewide ........................... Submitted: 3/3/10 ............. 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Excluding portions of the 

following: Sections 7.4, 

9.5, 9.7, and 10.6, and 

Appendices B.2, and 

D.2, and all of Appendix 

A.4, because EPA disapproved the NOX

BART determination for 

Coal Creek Station Units 

1 and 2, the reasonable 

progress determination 

for Antelope Valley Station Units 1 and 2 regarding NOX controls, 

the reasonable progress 

goals, and parts of the 

long-term strategy, and 

because the provisions 

applicable to Coyote 

Station were superseded 

by a later submittal. 

(24) North Dakota State 

Implementation Plan for 

Regional Haze Supplement No. 1.

Statewide ........................... Submitted: 7/27/10 ........... 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

(25) North Dakota State 

Implementation Plan for 

Regional Haze Amendment No. 1.

Statewide ........................... Submitted: 7/28/11 ........... 4/6/12, [Insert Federal 

Register page number 

where the document begins.].

Including only Section 

10.6.1.2, Appendix A.4, 

and introductory elements that pertain to the 

NOX requirements for 

Coyote Station; excluding all other portions of 

the submittal. 

3 In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column for the particular provision. 

* * * * * 

■ 3. Section 52.1825 is added as follows: 

§ 52.1825 Federal Implementation Plan for 

Regional Haze. 

(a) Applicability. This section applies 

to each owner and operator of the 

following coal-fired electric generating 

units (EGUs) in the State of North 

Dakota: Coal Creek Station, Units 1 and 

2; Antelope Valley Station, Units 1 and 

2. 

(b) Definitions. Terms not defined 

below shall have the meaning given 

them in the Clean Air Act or EPA’s 

regulations implementing the Clean Air 

Act. For purposes of this section: 

(1) Boiler operating day means a 24- 

hour period between 12 midnight and 

the following midnight during which 

any fuel is combusted at any time in the 

EGU. It is not necessary for fuel to be 

combusted for the entire 24-hour period. 

(2) Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of NOX

emissions, other pollutant emissions, 

diluent, or stack gas volumetric flow 

rate. 

(3) NOX means nitrogen oxides. 

(4) Owner/operator means any person 

who owns or who operates, controls, or 

supervises an EGU identified in 

paragraph (a) of this section. 

(5) Unit means any of the EGUs 

identified in paragraph (a) of this 

section. 

(c) Emissions limitations. (1) The 

owners/operators subject to this section 

shall not emit or cause to be emitted 

NOX in excess of the following 

limitations, in pounds per million 

British thermal units (lb/MMBtu), 

averaged over a rolling 30-day period: 

Source name NOX Emission limit 

(lb/MMBtu) 

Coal Creek Station, 

Units 1 and 2.

0.13, averaged across 

both units. 

Antelope Valley Station, Unit 1.0.17. 

Antelope Valley Station, Unit 2.0.17. 

(2) These emission limitations shall 

apply at all times, including startups, 

shutdowns, emergencies, and 

malfunctions. 

(d) Compliance date. The owners and 

operators of Coal Creek Station shall 

comply with the emissions limitation 

and other requirements of this section 

within five (5) years of the effective date 

of this rule, unless otherwise indicated 

in specific paragraphs. The owners and 

operators of Antelope Valley Station 

shall comply with the emissions 

limitations and other requirements of 

this section as expeditiously as 

practicable, but no later than July 31, 

2018, unless otherwise indicated in 

specific paragraphs. 

(e) Compliance determination—(1) 

CEMS. At all times after the compliance 

date specified in paragraph (d) of this 

section, the owner/operator of each unit 

shall maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR part 75, 

to accurately measure NOX, diluent, and 

stack gas volumetric flow rate from each 

unit. The CEMS shall be used to 

determine compliance with the 

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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations 20945 

emission limitations in paragraph (c) of 

this section for each unit. 

(2) Method. (i) For any hour in which 

fuel is combusted in a unit, the owner/ 

operator of each unit shall calculate the 

hourly average NOX concentration in lb/ 

MMBtu at the CEMS in accordance with 

the requirements of 40 CFR part 75. At 

the end of each boiler operating day, the 

owner/operator shall calculate and 

record a new 30-day rolling average 

emission rate in lb/MMBtu from the 

arithmetic average of all valid hourly 

emission rates from the CEMS for the 

current boiler operating day and the 

previous 29 successive boiler operating 

days. 

(ii) An hourly average NOX emission 

rate in lb/MMBtu is valid only if the 

minimum number of data points, as 

specified in 40 CFR part 75, is acquired 

by both the NOX pollutant concentration 

monitor and the diluent monitor (O2 or 

CO2). 

(iii) Data reported to meet the 

requirements of this section shall not 

include data substituted using the 

missing data substitution procedures of 

subpart D of 40 CFR part 75, nor shall 

the data have been bias adjusted 

according to the procedures of 40 CFR 

part 75. 

(f) Recordkeeping. Owner/operator 

shall maintain the following records for 

at least five years: 

(1) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(2) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 75. 

(3) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(4) Any other records required by 40 

CFR part 75. 

(g) Reporting. All reports under this 

section shall be submitted to the 

Director, Office of Enforcement, 

Compliance and Environmental Justice, 

U.S. Environmental Protection Agency, 

Region 8, Mail Code 8ENF–AT, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129. 

(1) Owner/operator shall submit 

quarterly excess emissions reports no 

later than the 30th day following the 

end of each calendar quarter. Excess 

emissions means emissions that exceed 

the emissions limits specified in 

paragraph (c) of this section. The reports 

shall include the magnitude, date(s), 

and duration of each period of excess 

emissions, specific identification of 

each period of excess emissions that 

occurs during startups, shutdowns, and 

malfunctions of the unit, the nature and 

cause of any malfunction (if known), 

and the corrective action taken or 

preventative measures adopted. 

(2) Owner/operator shall submit 

quarterly CEMS performance reports, to 

include dates and duration of each 

period during which the CEMS was 

inoperative (except for zero and span 

adjustments and calibration checks), 

reason(s) why the CEMS was 

inoperative and steps taken to prevent 

recurrence, any CEMS repairs or 

adjustments, and results of any CEMS 

performance tests required by 40 CFR 

part 75 (Relative Accuracy Test Audits, 

Relative Accuracy Audits, and Cylinder 

Gas Audits). 

(3) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, such information 

shall be stated in the report. 

(h) Notifications. (1) Owner/operator 

shall submit notification of 

commencement of construction of any 

equipment which is being constructed 

to comply with the NOX emission limits 

in paragraph (c) of this section. 

(2) Owner/operator shall submit semiannual progress reports on construction 

of any such equipment. 

(3) Owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(i) Equipment operation. At all times, 

owner/operator shall maintain each 

unit, including associated air pollution 

control equipment, in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. 

(j) Credible Evidence. Nothing in this 

section shall preclude the use, including 

the exclusive use, of any credible 

evidence or information, relevant to 

whether a source would have been in 

compliance with requirements of this 

section if the appropriate performance 

or compliance test procedures or 

method had been performed. 

[FR Doc. 2012–6586 Filed 4–5–12; 8:45 am] 

BILLING CODE 6560–50–P 

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