[Federal Register Volume 77, Number 67 (Friday, April 6, 2012)]
[Rules and Regulations]
[Pages 20894-20945]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-6586]



[[Page 20893]]

Vol. 77

Friday,

No. 67

April 6, 2012

Part II





Environmental Protection Agency





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40 CFR Part 52





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

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

[[Page 20894]]


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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.

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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 non-interference 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 <a href="/cdn-cgi/l/email-protection#8ceaede0e0e3e2a2ebede5e0cce9fceda2ebe3fa"><span class="__cf_email__" data-cfemail="7214131e1e1d1c5c15131b1e321702135c151d04">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION:

Definitions

    For the purpose of this document, we are giving meaning to certain 
words or initials as follows:
    <bullet> The word Act or initials CAA mean or refer to the Clean 
Air Act, unless the context indicates otherwise.
    <bullet> The initials ASOFA mean or refer to advanced separated 
overfire air.
    <bullet> The initials AVS mean or refer to Antelope Valley Station.
    <bullet> The initials BACT mean or refer to Best Available Control 
Technology.
    <bullet> The initials BART mean or refer to Best Available Retrofit 
Technology.
    <bullet> The initials CAM mean or refer to compliance assurance 
monitoring.
    <bullet> The initials CAMx mean or refer to Comprehensive Air 
Quality Model.
    <bullet> The initials CCS mean or refer to Coal Creek Station.
    <bullet> The initials CEMS mean or refer to continuous emission 
monitoring system.
    <bullet> The initials CMAQ mean or refer to Community Multi-Scale 
Air Quality modeling system.
    <bullet> The initials CSAPR mean or refer to Cross-State Air 
Pollution Rule.
    <bullet> The initials EGUs mean or refer to Electric Generating 
Units.
    <bullet> The words we, us or our or the initials EPA mean or refer 
to the United States Environmental Protection Agency.
    <bullet> The initials FIP mean or refer to Federal Implementation 
Plan.
    <bullet> The initials FLMs mean or refer to Federal Land Managers.
    <bullet> The initials GRE mean or refer to Great River Energy.
    <bullet> The initials IMPROVE mean or refer to Interagency 
Monitoring of Protected Visual Environments monitoring network.
    <bullet> The initials IWAQM mean or refer to Interagency Workgroup 
on Air Quality Modeling.
    <bullet> The initials LDSCR mean or refer to low-dust SCR.
    <bullet> The initials LOS mean or refer to Leland Olds Station.
    <bullet> The words Lostwood or Lostwood Wilderness Area or initials 
LWA mean or refer to Lostwood National Wildlife Refuge Wilderness Area.
    <bullet> The initials LNB mean or refer to low NO<INF>X</INF> 
burners.
    <bullet> The initials LTS mean or refer to Long-Term Strategy.
    <bullet> The initials MRYS mean or refer to Milton R. Young 
Station.
    <bullet> The initials NAAQS mean or refer to National Ambient Air 
Quality Standards.
    <bullet> The words North Dakota and State mean the State of North 
Dakota unless the context indicates otherwise.
    <bullet> The initials NOX mean or refer to nitrogen oxides.
    <bullet> The initials NPCA mean or refer to National Parks 
Conservation Association.
    <bullet> The initials NPS mean or refer to National Park Service.
    <bullet> The initials PM mean or refer to particulate matter.
    <bullet> The initials PM10 mean or refer to particulate matter with 
an aerodynamic diameter of less than 10 micrometers or course 
particulate matter.
    <bullet> The initials PM2.5 mean or refer to particulate matter 
with an aerodynamic diameter of less than 2.5 micrometers or fine 
particulate matter.
    <bullet> The initials PRB mean or refer to Powder River Basin.
    <bullet> The initials PSAT mean or refer to Particle Source 
Apportionment Technology.
    <bullet> The initials PSD mean or refer to Prevention of 
Signification Deterioration.
    <bullet> The initials RHR mean or refer to the Regional Haze Rule.
    <bullet> The initials RH SIP mean or refer to North Dakota's 
Regional Haze State Implementation Plan.
    <bullet> The initials RMC mean or refer to the Regional Modeling 
Center at the University of California Riverside.
    <bullet> The initials RP mean or refer to Reasonable Progress.
    <bullet> The initials RPG mean or refer to Reasonable Progress 
Goal.
    <bullet> The initials SCR mean or refer to selective catalytic 
reduction.
    <bullet> The initials SIP mean or refer to State Implementation 
Plan.
    <bullet> The initials SNCR mean or refer to selective non-catalytic 
reduction.
    <bullet> The initials SO2 mean or refer to sulfur dioxide.
    <bullet> The initials SOFA mean or refer to separated overfire air.
    <bullet> The initials TRNP mean or refer to Theodore Roosevelt 
National Park.

[[Page 20895]]

    <bullet> The initials TSD mean or refer to Technical Support 
Document.
    <bullet> The initials URP mean or refer to Uniform Rate of 
Progress.
    <bullet> The initials WEP mean or refer to Weighted Emissions 
Potential.
    <bullet> 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. NO<INF>X</INF> BART for Milton R. Young Station Units 1 and 2 
and Leland Olds Station Unit 2
    B. NO<INF>X</INF> 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. NO<INF>X</INF> 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 NO<INF>X</INF> 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 SO<INF>2</INF> 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 
(PM<INF>2.5</INF>) 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 PM<INF>2.5</INF> 
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 PM<INF>2.5</INF> 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

[[Page 20896]]

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 (NO<INF>X</INF>) 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 
NO<INF>X</INF> 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 long-term 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. NO<INF>X</INF> BART determinations and emission limits for MRYS 
Units 1 and 2 and Leland Olds Station Unit 2.
    b. NO<INF>X</INF> BART determination and emission limit for CCS 
Units 1 and 2.
    c. A reasonable progress determination and NO<INF>X</INF> 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:
    <bullet> North Dakota's NO<INF>X</INF> BART determinations and 
emissions limits for CCS Units 1 and 2.
    <bullet> North Dakota's determination under the reasonable progress 
requirements found at 40 CFR 51.308(d)(1) that no additional 
NO<INF>X</INF> emissions controls are warranted at AVS Units 1 and 2.
    <bullet> North Dakota's RPGs.
    <bullet> Portions of North Dakota's LTS that rely on or reflect 
other aspects of the RH SIP that we are disapproving.

[[Page 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:
    <bullet> NO<INF>X</INF> 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 NO<INF>X</INF> BART limit within five (5) years of the 
effective date of this final rule.
    <bullet> A reasonable progress determination and NO<INF>X</INF> 
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.
    <bullet> Monitoring, record-keeping, and reporting requirements for 
the above four units to ensure compliance with these emission 
limitations.
    <bullet> RPGs consistent with the SIP limits approved and the final 
FIP limits.
    <bullet> 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 PM<INF>2.5</INF> 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 NO<INF>X</INF> 
BART determinations for MRYS 1 and 2 and LOS 2 and to promulgate a FIP 
for NO<INF>X</INF> 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 NO<INF>X</INF> BART 
determination for MRYS 1 and 2 and LOS 2 and to not promulgate a FIP 
for NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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

[[Page 20898]]

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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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% NO<INF>X</INF> reduction. The manual provides a scatter plot 
with NO<INF>X</INF> 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% 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \1\ U.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.
    \2\ http://www.ftek.com/en-US/products/apc/noxout/.
    \3\ Institute of Clean Air Companies, White Paper Selective Non-
Catalytic Reduction (SNCR) for Controlling NO<INF>X</INF> Emissions, 
February 2008, p. 9.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 NO<INF>X</INF> BART FIP limits at CCS 1 and 2 
or our final NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
BART determination for CCS 1 and 2 and NO<INF>X</INF> reasonable 
progress determination for AVS 1 and 2, and the LTS does not reflect 
our final NO<INF>X</INF> BART FIP limits at CCS 1 and 2 or our final 
NO<INF>X</INF> 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 NO<INF>X</INF> emission 
limits for CCS 1 and 2 and AVS 1 and 2, compliance schedules, and 
monitoring, recordkeeping, and reporting

[[Page 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 
NO<INF>X</INF> and for Heskett Station 2 for sulfur dioxide 
(SO<INF>2</INF>). 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 NO<INF>X</INF> BART 
determination for CCS 1 and 2 and its NO<INF>X</INF> 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 
NO<INF>X</INF> BART determination for CCS 1 and 2 is unreasonable, or 
that our NO<INF>X</INF> 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 NO<INF>X</INF> emissions 
controls are warranted, and we are finalizing a FIP with a reasonable 
progress determination and a NO<INF>X</INF> 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 NO<INF>X</INF> 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, 
cost-efficient means to achieve significant NO<INF>X</INF> 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

[[Page 20900]]

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 NO<INF>X</INF> BART for 
CCS 1 and 2 and NO<INF>X</INF> 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 NO<INF>X</INF> BART 
determinations for MRYS 1 and 2 and LOS 2, and we are not proceeding 
with a FIP for NO<INF>X</INF> BART for these units. We explain the 
basis for this change in section III.
    We received numerous comments that were specific to the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF>, 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \4\ Some 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.
---------------------------------------------------------------------------

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 five-factor 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 NO<INF>X</INF> BART determinations for two units--CCS 1 and 2--
and its NO<INF>X</INF> reasonable progress determinations for two 
units--AVS 1 and 2.
    The State's NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> BART determinations in 
the SIP for CCS 1 and 2 and in the absence of an approvable reasonable 
progress determination concerning NO<INF>X</INF> 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

[[Page 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 NO<INF>X</INF> 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 ``fossil-fuel 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 
NO<INF>X</INF> 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

[[Page 20902]]

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 NO<INF>X</INF> 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 
NO<INF>X</INF>. Thus, a state which selects combustion controls and the 
associated presumptive limit for NO<INF>X</INF> 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 five-factor 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 NO<INF>X</INF> 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

[[Page 20903]]

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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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

[[Page 20904]]

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 
NO<INF>X</INF> 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 source-specific limits 
and requirements. An opportunity for examination and cross-examination 
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.

[[Page 20905]]

    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 NO<INF>X</INF> BART for CCS. The State 
relied on those erroneous cost figures in its NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 20906]]

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 two-year 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 single-source 
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

[[Page 20907]]

Dakota specifically stated: ``[A]ll BART-related 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.
---------------------------------------------------------------------------

    \5\ There 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.
---------------------------------------------------------------------------

    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 
single-source 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 ``day-by-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 PM<INF>2.5</INF> 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 BART-eligible 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.

[[Page 20908]]

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 
single-source 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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \6\ Anderson, 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.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> 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

[[Page 20909]]

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

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

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

    \9\ Natural Haze Levels II Committee Report.
    \10\ Settlement 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.
---------------------------------------------------------------------------

    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 
PM<INF>2.5</INF> concentrations in North Dakota in the range of 1.9 to 
2.5 ug/m\3\, while the Koo et al. study \12\ predicted annual average 
natural PM<INF>2.5</INF> concentrations in the range of 2.5 to 3.1 ug/
m\3\ in North Dakota. These model estimates are consistent with EPA's 
estimated 2.6 ug/m\3\ annual average PM<INF>2.5</INF> concentration at 
Class I Areas in western North Dakota.
---------------------------------------------------------------------------

    \11\ Tonnesen, 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/WRAP-RMC_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.
---------------------------------------------------------------------------

    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

[[Page 20910]]

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 short-term events or unusual meteorological events.
    Response: In our review of the single-source 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-to-BART 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\
---------------------------------------------------------------------------

    \13\ The 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.
---------------------------------------------------------------------------

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

    \14\ CALMET/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.
---------------------------------------------------------------------------

    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

[[Page 20911]]

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 mid-
October 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\
---------------------------------------------------------------------------

    \15\ http://vista.cira.colostate.edu/tss/Results/HazePlanning.aspx.
    \16\ http://www.nature.nps.gov/stats/park.cfm?parkid=467.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> 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 
NO<INF>X</INF> emissions that followed North Dakota's 2005 EPA-approved 
protocol and shows that these sources contribute a very small fraction 
of light extinction attributable to nitrates.
    Response: We disagree that controlling large NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \17\ http://vista.cira.colostate.edu/tss/Results/HazePlanning.aspx.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 
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 EPA-approved 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

[[Page 20912]]

that no NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions are considerably greater than emissions from some other EGUs 
in North Dakota. North Dakota predicted that LNB at AVS would achieve 
NO<INF>X</INF> 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 four-factor 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:
---------------------------------------------------------------------------

    \18\ 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 TSD for this action.

    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

[[Page 20913]]

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 
well-understood 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 SO<INF>2</INF> would have a greater visibility benefit 
than a one ton reduction of coarse mass. As only SO<INF>2</INF> and 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \19\ See Appendix A of our TSD for detailed explanation of the 
IMPROVE equation.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> 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-of-state 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

[[Page 20914]]

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-[agrave]-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 SO<INF>2</INF> 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 pre-control 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

[[Page 20915]]

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 single-source 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 NO<INF>X</INF> than to reduce SO<INF>2</INF> 
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 NO<INF>X</INF> versus 
SO<INF>2</INF> 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 
NO<INF>X</INF> retrofit control technologies. Another commenter cited 
appendix Y, alleging that it states that NO<INF>X</INF> control costs 
above $1,500/ton are not cost effective for BART. Commenter stated that 
EPA is therefore inaccurate in the FIP for citing NO<INF>X</INF> 
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

[[Page 20916]]

threshold for BART determinations. We note that North Dakota and other 
states have identified NO<INF>X</INF> control costs well over $1,500 
per ton of emissions reduced as being cost effective, and that the 
relevance of a particular dollar-per-ton 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.
---------------------------------------------------------------------------

    \20\ See, for example, the NSR Manual, Appendix B, which lays 
out the overnight method currently required in the Control Cost 
Manual.
    \21\ See 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 NO<INF>X</INF> for the Milton R. Young Station, 
May 10, 2010, pp. 14-16.
---------------------------------------------------------------------------

    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

[[Page 20917]]

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

    \22\ As 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.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> removed.\23\
---------------------------------------------------------------------------

    \23\ Institute of Clean Air Companies, White Paper Selective 
Non-Catalytic Reduction (SNCR) for Controlling NO<INF>X</INF> 
Emissions, February 2008, p. 4.
---------------------------------------------------------------------------

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 NO<INF>X</INF> 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

[[Page 20918]]

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 DryFining\TM\ technology, any 
accurate analysis of add-on NO<INF>X</INF> controls must be site-
specific 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 NO<INF>X</INF> 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 in-depth analysis, GRE could have and 
should have performed that analysis in 2007.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 DryFining\TM\ 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> reduction still appears achievable.
    The URS report that GRE references to support its claim of reduced 
control efficiency values provides a plot in which NO<INF>X</INF> 
control efficiency is plotted as a function of inlet NO<INF>X</INF> 
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.<SUP>25 26</SUP> 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\
---------------------------------------------------------------------------

    \25\ North 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.
    \27\ LNC3 is an EPA acronym for low NO<INF>X</INF> coal-and-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.
---------------------------------------------------------------------------

    We proposed a NO<INF>X</INF> 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

[[Page 20919]]

BART determination. Annual average Clean Air Markets data for this unit 
reflects a NO<INF>X</INF> 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% NO<INF>X</INF> 
reduction. The manual provides a scatter plot with NO<INF>X</INF> 
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% NO<INF>X</INF> 
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.
---------------------------------------------------------------------------

    \28\ U.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.
    \29\ http://www.ftek.com/en-US/products/apc/noxout/.
    \30\ Institute of Clean Air Companies, White Paper Selective 
Non-Catalytic Reduction (SNCR) for Controlling NO<INF>X</INF> 
Emissions, February 2008, p. 9.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 NO<INF>X,</INF> 
SO<INF>2</INF> and PM<INF>2.5</INF> 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 SO<INF>2,</INF> NO<INF>X</INF>, and particulate 
matter (PM) emission changes were in fact modeled together. All of the 
NO<INF>X</INF> control options were modeled along with the 
SO<INF>2</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> control options, 
over the selected SO<INF>2</INF> BART control (scrubber modifications 
at 95% control).'' 76 FR 58623. As a result, we were only able to 
specify the incremental visibility benefit between NO<INF>X</INF> 
control options. In our evaluation of BART for NO<INF>X</INF> at CCS, 
we weighed the visibility factor in consideration of the fact that the 
improvement was incremental to lower NO<INF>X</INF> 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

[[Page 20920]]

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

    \31\ Information regarding EC/R and Dr. Staudt's credentials is 
available in the docket.
---------------------------------------------------------------------------

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

    \32\ Staudt, 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.
---------------------------------------------------------------------------

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

    \33\ Id.
    \34\ EC/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.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> removed.\35\
---------------------------------------------------------------------------

    \35\ Even 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.
---------------------------------------------------------------------------

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

    \36\ http://my.epri.com/portal/server.pt?Abstract_id=000000000001014269.
---------------------------------------------------------------------------

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

    \37\ Staudt, 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.
---------------------------------------------------------------------------

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

    \38\ EPA-R08-OAR-2010-0406-0077, Letter from GRE to NDDH, 
February 9, 2010.

    ``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\
---------------------------------------------------------------------------

    \39\ http://www.ag.ndsu.edu/pubs/ageng/safety/ae1149-1.htm.

    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

[[Page 20921]]

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

    \40\ Docket EPA-R08-OAR-2010-0406-0201, GRE comments, pdf p. 27.
    \41\ The American Coal Ash Association indicates that where ash 
is disposed near the power plant, a cost of $5/ton is reasonably 
expected.
---------------------------------------------------------------------------

    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-of-the-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.
---------------------------------------------------------------------------

    \42\ Staudt, 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.
---------------------------------------------------------------------------

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

    \43\ This 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.
---------------------------------------------------------------------------

    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

[[Page 20922]]

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

    \44\ http://www.rmajko.com/suppliers1.html.
    \45\ http://www.azdot.gov/highways/materials/pdf/materials_source_list_flyash.pdf.
    \46\ http://www.dot.state.ga.us/doingbusiness/materials/qpl/documents/qpl30.pdf.
    \47\ http://www.boralna.com.
---------------------------------------------------------------------------

    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 (CO<INF>2</INF>) is emitted into the 
atmosphere to make cement. Commenter argued that there will be a 1 to 1 
ton increase in CO<INF>2</INF> 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 
CO<INF>2</INF> emissions or reduced quarrying. CO<INF>2</INF> 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

[[Page 20923]]

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 NO<INF>X</INF> 
emissions in North Dakota represent approximately only 6% of total 
NO<INF>X</INF> emissions, and therefore, it is understandable that 
proposed and additional BART NO<INF>X</INF> 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 NO<INF>X</INF> controls on North 
Dakota EGUs would be small. The commenter's estimate of the 
contribution from utilities to NO<INF>X</INF> 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 NO<INF>X</INF> for all source 
categories combined.\48\ Therefore, utilities account for some 34.4% of 
the total NO<INF>X</INF> emissions in North Dakota, and more than any 
other source category.
---------------------------------------------------------------------------

    \48\ Source: http://www.wrapair.org/forums/ssjf/pivot.html.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 SO<INF>2</INF> and NO<INF>X</INF> 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 NO<INF>X</INF> reduction proposed by EPA.
    Response: GRE does not provide the anticipated ammonia emissions 
for comparison to the proposed NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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, NO<INF>X</INF> 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 NO<INF>X</INF> 
reductions.
    Comment: Commenter stated that NO<INF>X</INF> 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 NO<INF>X</INF> Emission Limits
    In our proposal, we asked for comments on a possible alternative 
NO<INF>X</INF> 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 cost-
effective and will result in significant visibility improvement. 
Commenter stated that these comments and the associated Refined 
Analysis demonstrate that any additional NO<INF>X</INF> reductions 
would neither be cost-effective 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 20924]]

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 
NO<INF>X</INF> BART limit for CCS 1 and 2 to 0.13 lb/MMBtu on a 30-day 
rolling average basis.
    Comment: Commenter argued that the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> to the 
absolute limits of LNC3 and DryFining<SUP>TM</SUP> 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 NO<INF>X</INF> emission rates. GRE further stated that the 
2010 implementation of DryFining<SUP>TM</SUP> 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 
NO<INF>X</INF> 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 DryFining<SUP>TM</SUP> 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 
DryFining<SUP>TM</SUP> while also helping to maintain NO<INF>X</INF> 
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 NO<INF>X.</INF> 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.
---------------------------------------------------------------------------

    \49\ See www.regulations.gov, docket EPA-HQ-OAR-2009-0491.
---------------------------------------------------------------------------

    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.

[[Page 20925]]

[GRAPHIC] [TIFF OMITTED] TR06AP12.000

    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 dollar-per-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/kW \51\) 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).
---------------------------------------------------------------------------

    \50\ This is based in part on, ``Measuring Ammonia Slip from 
Post Combustion NO<INF>X</INF> Reduction Systems,'' James E. Staudt, 
Andover Technology Partners, ICAC Forum 2000.
    \51\ The $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 NO<INF>X</INF> Emissions, 
February 2008, p. 7.
    \52\ We 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.
    \53\ We have included our calculations in the docket.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> reduction 
with SNCR more difficult due to the competing urea oxidation reaction 
that causes NO<INF>X</INF> reduction to drop off at high temperatures. 
As a result, one would expect SNCR performance to

[[Page 20926]]

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 NO<INF>X</INF> analysis. 
These analyses essentially reaffirm GRE's initial determination that 
DryFining<SUP>TM</SUP> 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 
(NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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

[[Page 20927]]

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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 coal-fired units, resulting in a higher cost of NO<INF>X</INF> 
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.
---------------------------------------------------------------------------

    \54\ Hofmann, J.W., von Bergmann, J., Bokenbrink, D., Hein, K. 
``NO<INF>X</INF> Control in a Brown Coal-Fired Utility Boiler.'' 
Presented at the EPRI/EPA Symposium on Stationary Combustion 
NO<INF>X</INF> Control, San Francisco, CA, March 8, 1989.
---------------------------------------------------------------------------

    Comment: Commenter stated that the larger registers installed at 
CCS 2 further reduce NO<INF>X</INF> emissions as they allow for 
increased primary air which is available after installation of 
DryFining\TM\, 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 cost-effectiveness ($/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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \55\ Our analysis differs in that we considered SNCR combined 
with combustion controls.

[[Page 20928]]



  Table 1--Comparison Between Cost Effectiveness Factors in GRE's July and November 2011 Cost Estimates for CCS
----------------------------------------------------------------------------------------------------------------
                                   Baseline                                                           Pollution
                                   emission      Control      Emission      Installed    Annual O&M    control
       Study description           rate (lb/    efficiency    reduction   capital cost   cost (MM$/    cost ($/
                                    MMBtu)                    (ton/yr)      (MM$/yr)        yr)          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\
---------------------------------------------------------------------------

    \56\ Rini, 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 NO<INF>X</INF> Control, Bal 
Harbor, Florida. May 24-27, 1993.
    \57\ Control Cost Manual, Section 4.2, p. 1-4.

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

    \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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> level of 0.20 lb/MMBtu, 
and a normal stoichiometric ratio (NSR) of 1.0 (30 lb urea/46 lb 
NO<INF>2</INF>),\61\ the hourly usage of reagent is: 5900 MMBtu/hr * 
0.20 lbNO<INF>2</INF>/MMBtu * (30 lb urea/46 lb NO<INF>2</INF>) = 770 
lb/hr.
---------------------------------------------------------------------------

    \59\ URS 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.
    \60\ EPA 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.
---------------------------------------------------------------------------

    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 NO<INF>2</INF>/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 
NO<INF>X</INF> 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 DryFining<SUP>TM</SUP>;, CCS's NO<INF>X</INF> 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 DryFining<SUP>TM</SUP> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
SO<INF>2</INF> and NO<INF>X</INF> 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

[[Page 20929]]

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 NO<INF>X</INF> controls for Stanton Station Unit 1. 
While the commenter supports the use of further NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \62\ Coal Creek Station Units 1 and 2 Best Available Retrofit 
Technology Analysis, Revised December 12, 2007, p. 8.
    \63\ Revised BART Cost Effectiveness Analysis for Tail-End 
Selective Catalytic Reduction at the Basin Electric Power 
Cooperative, Leland Olds Station Unit 2, Final Report, March 2011, 
docket EPA-R08-OAR-2010-0406-0076, p. 8.
---------------------------------------------------------------------------

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 NO<INF>X</INF> emissions 
removed with an incremental cost effectiveness between the SCR and SNCR 
control options of $8,845/ton of NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 SO<INF>2,</INF> 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 SO<INF>2</INF> 
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 SO<INF>2</INF> 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 SO<INF>2</INF> 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.

[[Page 20930]]

    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 SO<INF>2.</INF>
    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 (PM<INF>10</INF>) and PM <INF>2.5,</INF> but was only evaluated 
for PM<INF>10</INF>. EPA should therefore impose a BART limit on total 
PM<INF>2.5</INF>.
    Response: In our BART Guidelines, for the purposes of identifying 
visibility impairing pollutants, we allowed states to use emissions of 
PM<INF>10</INF> as an indicator for PM<INF>2.5,</INF> as the components 
of PM<INF>2.5</INF> are a subset of PM<INF>10</INF>. 70 FR 39160. For 
the same reasons, we find that it is reasonable for North Dakota to 
have explicitly evaluated BART only for PM<INF>10</INF>. We also note 
that North Dakota did evaluate BART for condensable PM which comprises 
a large portion of the PM<INF>2.5</INF>.
    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 NO<INF>X</INF> 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 
NO<INF>X</INF> BART and RP determinations and promulgating a FIP to 
impose RPGs that are consistent with our FIP NO<INF>X</INF> BART and RP 
determinations. To the extent that the State's LTS relies on these 
NO<INF>X</INF> 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

[[Page 20931]]

requirements in the State's submittal that correspond to the 
NO<INF>X</INF> BART determinations we are disapproving; and (2) 
disapproval of the LTS with regard to the NO<INF>X</INF> 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 NO<INF>X</INF> BART determinations for CCS Units 1 
and 2 and the disapproval of the State's NO<INF>X</INF> 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 
dollar-per-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 single-source 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-per-deciview 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 SO<INF>2</INF> and 
NO<INF>X</INF> 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

[[Page 20932]]

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

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

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

    \65\ Further detail regarding North Dakota's analysis can be 
found in our proposal. 76 FR 58624-58628.
---------------------------------------------------------------------------

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

    \66\ We 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.
---------------------------------------------------------------------------

    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 
source-specific 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

[[Page 20933]]

statutory factors (which don't include visibility improvement) must be 
included in the plan. Thus, for example, the guidance states:
---------------------------------------------------------------------------

    \67\ We note that guidance is not binding on EPA and does not 
supersede relevant statutory and regulatory requirements.
    \68\ We 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.

    ``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 
NO<INF>X</INF> 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.

[[Page 20934]]

    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 
NO<INF>X.</INF> We explained in our proposal why North Dakota's 
alternative modeling for these BART units for NO<INF>X</INF> 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, three-year 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

[[Page 20935]]

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-per-deciview 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 NO<INF>X</INF> 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 NO<INF>X,</INF> 
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 up-to-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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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

[[Page 20936]]

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 
cost-effectiveness 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 post-combustion 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 SO<INF>2.</INF> 
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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 
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 
SO<INF>2</INF> controls at Coyote Station to reduce consumed Class I 
SO<INF>2</INF> 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 
SO<INF>2</INF> 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 SO<INF>2</INF> 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 
SO<INF>2</INF> 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 SO<INF>2.</INF> NPCA concludes that 
EPA should require Heskett to achieve an SO<INF>2</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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.

[[Page 20937]]

    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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 SO<INF>2,</INF> 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 NO<INF>X</INF> limit and not 
imposing an SO<INF>2</INF> 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 NO<INF>X,</INF> SO<INF>2</INF> 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 PM<INF>2.5</INF> 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 
NO<INF>X</INF> 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

[[Page 20938]]

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 tourism-dependent 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.
---------------------------------------------------------------------------

    \69\ The American Lung Association State of the Air report is 
available at www.stateoftheair.org.
---------------------------------------------------------------------------

    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 low-cost 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 NO<INF>X</INF> 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 <greek-i>12 in SO<INF>2</INF> emissions 
and <greek-i>19 in NO<INF>X</INF> emissions. The commenter also 
provided the SO<INF>2</INF> and NO<INF>X</INF> rankings for the seven 
North Dakota EGUs discussed in the SIP.
    Response: We appreciate the commenter providing the SO<INF>2</INF> 
and NO<INF>X</INF> 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 
SO<INF>2</INF> and NO<INF>X</INF> 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.

[[Page 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 NO<INF>X</INF> 
emission limits because NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 20940]]

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 
NO<INF>X</INF> emissions at one source in North Dakota, and imposing 
controls to meet the reasonable progress requirement for NO<INF>X</INF> 
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 cost-effective, or 
least burdensome alternative that achieves the objectives of the rule. 
The provisions of section 205 of UMRA do not apply when they are 
inconsistent with applicable law. Moreover, section 205 of UMRA allows 
EPA to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator 
publishes with the final rule an explanation why that alternative was 
not adopted. Before EPA establishes any regulatory requirements that 
may significantly or uniquely affect small governments, including 
Tribal governments, it must have developed under section 203 of UMRA a 
small government agency plan. The plan must provide for notifying 
potentially affected small governments, enabling officials of affected 
small governments to have meaningful and timely input in the 
development of EPA regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    Under Title II of UMRA, EPA has determined that this 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

[[Page 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 NO<INF>X,</INF> 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 NO<INF>X</INF> 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]

0
1. The authority citation for part 52 continues to read as follows:

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

Subpart JJ--North Dakota

0
2. Section 52.1820 is amended by:
0
a. Adding to the table in paragraph (c) an entry entitled ``33-15-25 
Regional Haze Requirements'' at the end of the table.
0
b. Revising the table in paragraph (d).
0
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:


Sec.  52.1820  Identification of plan.

* * * * *
    (c) * * *

[[Page 20942]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                State
          State citation                Title/subject      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                 1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                     retrofit technology.                   number where the document begins.].
33-15-25-03.......................  Guidelines for best            1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                     available retrofit                     number where the document begins.].
                                     technology
                                     determinations under
                                     the regional haze
                                     rule.
33-15-25-04.......................  Monitoring,                    1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                     recordkeeping, and                     number where the document begins.].
                                     reporting.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column
  for the particular provision.

* * * * *
    (d) * * *

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                State
          Name of source            Nature of requirement  effective date    EPA approval date and  citation \3\                Explanations
--------------------------------------------------------------------------------------------------------------------------------------------------------
Leland Olds Station Unit 1........  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10004.
Leland Olds Station Unit 2........  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10004.
Milton R. Young Station Unit 1....  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10007.
Milton R. Young Station Unit 2....  Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10007.
Coal Creek Station Unit 1.........  Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   Excluding the NOX BART emissions
                                     permit to construct                    number where the document begins.].     limits for Unit 1 and corresponding
                                     for best available                                                             monitoring, recordkeeping, and
                                     retrofit technology                                                            reporting requirements, which EPA
                                     (BART), PTC10005.                                                              disapproved.

[[Page 20943]]

 
Coal Creek Station Unit 2.........  Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   Excluding the NOX BART emissions
                                     permit to construct                    number where the document begins.].     limits for Unit 2 and corresponding
                                     for best available                                                             monitoring, recordkeeping, and
                                     retrofit technology                                                            reporting requirements, which EPA
                                     (BART), PTC10005.                                                              disapproved.
Stanton Station Unit 1............  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10006.
Heskett Station Unit 1............  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
Heskett Station Unit 2............  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air Pollution Control         7/22/10  4/6/12, [Insert Federal Register page   .....................................
                                     Permit to Construct,                   number where the document begins.].
                                     PTC10028.
Coyote Station Unit 1.............  Air Pollution Control         3/14/11  4/6/12, [Insert Federal Register page   .....................................
                                     Permit to Construct,                   number where the document begins.].
                                     PTC10008.
American Crystal Sugar at Drayton.  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
Tesoro Mandan Refinery............  SIP Chapter 8,                2/27/07  5/27/08, 73 FR 30308.                   .....................................
                                     Section 8.3.1,
                                     Continuous Opacity
                                     Monitoring for Fluid
                                     Bed Catalytic
                                     Cracking Units:
                                     Tesoro Refining and
                                     Marketing Co.,
                                     Mandan Refinery.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\3\ In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column
  for the particular provision.

* * * * *
    (e) * * *

[[Page 20944]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        Applicable
    Name of nonregulatory SIP          geographic or       State submittal date/adopted date    EPA approval date and  citation \3\      Explanations
            provision               nonattainment area
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
                                                                      * * * * * * *
(23) North Dakota State            Statewide...........  Submitted: 3/3/10...................  4/6/12, [Insert Federal Register      Excluding portions
 Implementation Plan for Regional                                                               page number where the document        of the following:
 Haze.                                                                                          begins.].                             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            Statewide...........  Submitted: 7/27/10..................  4/6/12, [Insert Federal Register
 Implementation Plan for Regional                                                               page number where the document
 Haze Supplement No. 1.                                                                         begins.].
(25) North Dakota State            Statewide...........  Submitted: 7/28/11..................  4/6/12, [Insert Federal Register      Including only
 Implementation Plan for Regional                                                               page number where the document        Section 10.6.1.2,
 Haze Amendment No. 1.                                                                          begins.].                             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.

* * * * *

0
3. Section 52.1825 is added as follows:


Sec.  52.1825  Federal Implementation Plan for Regional Haze.

    (a) Applicability. This section applies to each owner and operator 
of the following coal-fired electric generating units (EGUs) in the 
State of North Dakota: 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 NO<INF>X</INF> 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 NO<INF>X</INF> in excess 
of the following limitations, in pounds per million British thermal 
units (lb/MMBtu), averaged over a rolling 30-day period:

------------------------------------------------------------------------
                                               NOX Emission limit (lb/
                Source name                            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 NO<INF>X</INF>, diluent, and stack gas volumetric 
flow rate from each unit. The CEMS shall be used to determine 
compliance with the

[[Page 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 
NO<INF>X</INF> concentration in lb/MMBtu at the CEMS in accordance with 
the requirements of 40 CFR part 75. At the end of each boiler operating 
day, the owner/operator shall calculate and record a new 30-day rolling 
average emission rate in lb/MMBtu from the arithmetic average of all 
valid hourly emission rates from the CEMS for the current boiler 
operating day and the previous 29 successive boiler operating days.
    (ii) An hourly average NO<INF>X</INF> emission rate in lb/MMBtu is 
valid only if the minimum number of data points, as specified in 40 CFR 
part 75, is acquired by both the NO<INF>X</INF> pollutant concentration 
monitor and the diluent monitor (O<INF>2</INF> or CO<INF>2</INF>).
    (iii) Data reported to meet the requirements of this section shall 
not include data substituted using the missing data substitution 
procedures of subpart D of 40 CFR part 75, nor shall the data have been 
bias adjusted according to the procedures of 40 CFR part 75.
    (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 NO<INF>X</INF> emission limits in 
paragraph (c) of this section.
    (2) Owner/operator shall submit semi-annual progress reports on 
construction of any such equipment.
    (3) Owner/operator shall submit notification of initial startup of 
any such equipment.
    (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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