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, 20894-20945 [2012-6586]
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20894
Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[EPA–R08–OAR–2010–0406; FRL–9648–3]
Approval and Promulgation of
Implementation Plans; North Dakota;
Regional Haze State Implementation
Plan; Federal Implementation Plan for
Interstate Transport of Pollution
Affecting Visibility and Regional Haze
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
EPA is partially approving
and partially disapproving a revision to
the North Dakota State Implementation
Plan (SIP) addressing regional haze
submitted by the Governor of North
Dakota on March 3, 2010, along with
SIP Supplement No. 1 submitted on July
27, 2010, and part of SIP Amendment
No. 1 submitted on July 28, 2011. These
SIP revisions were submitted to address
the requirements of the Clean Air Act
(CAA or Act) and our rules that require
states to prevent any future and remedy
any existing man-made impairment of
visibility in mandatory Class I areas
caused by emissions of air pollutants
from numerous sources located over a
wide geographic area (also referred to as
the ‘‘regional haze program’’). EPA is
promulgating a Federal Implementation
Plan (FIP) to address the gaps in the
plan resulting from our partial
disapproval of North Dakota’s Regional
Haze (RH) SIP.
In addition, EPA is disapproving a
revision to the North Dakota SIP
addressing the interstate transport of
pollutants that the Governor submitted
on April 6, 2009. We are disapproving
it because it does not meet the Act’s
requirements concerning noninterference with programs to protect
visibility in other states. To address this
deficiency, we are promulgating a FIP.
DATES: This final rule is effective May 7,
2012.
ADDRESSES: EPA has established a
docket for this action under Docket ID
No. EPA–R08–OAR–2010–0406. All
documents in the docket are listed on
the www.regulations.gov Web site.
Although listed in the index, some
information is not publicly available,
e.g., Confidential Business Information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
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SUMMARY:
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available either electronically through
www.regulations.gov, or in hard copy at
the Air Program, Environmental
Protection Agency (EPA), Region 8,
1595 Wynkoop Street, Denver, Colorado
80202–1129. EPA requests that if at all
possible, you contact the individual
listed in the FOR FURTHER INFORMATION
CONTACT section to view the hard copy
of the docket. You may view the hard
copy of the docket Monday through
Friday, 8 a.m. to 4 p.m., excluding
Federal holidays.
FOR FURTHER INFORMATION CONTACT: Gail
Fallon, Air Program, Mailcode 8P–AR,
Environmental Protection Agency,
Region 8, 1595 Wynkoop Street, Denver,
Colorado 80202–1129, (303) 312–6281,
or fallon.gail@epa.gov.
SUPPLEMENTARY INFORMATION:
Definitions
For the purpose of this document, we
are giving meaning to certain words or
initials as follows:
• The word Act or initials CAA mean
or refer to the Clean Air Act, unless the
context indicates otherwise.
• The initials ASOFA mean or refer to
advanced separated overfire air.
• The initials AVS mean or refer to
Antelope Valley Station.
• The initials BACT mean or refer to
Best Available Control Technology.
• The initials BART mean or refer to
Best Available Retrofit Technology.
• The initials CAM mean or refer to
compliance assurance monitoring.
• The initials CAMx mean or refer to
Comprehensive Air Quality Model.
• The initials CCS mean or refer to
Coal Creek Station.
• The initials CEMS mean or refer to
continuous emission monitoring system.
• The initials CMAQ mean or refer to
Community Multi-Scale Air Quality
modeling system.
• The initials CSAPR mean or refer to
Cross-State Air Pollution Rule.
• The initials EGUs mean or refer to
Electric Generating Units.
• The words we, us or our or the
initials EPA mean or refer to the United
States Environmental Protection
Agency.
• The initials FIP mean or refer to
Federal Implementation Plan.
• The initials FLMs mean or refer to
Federal Land Managers.
• The initials GRE mean or refer to
Great River Energy.
• The initials IMPROVE mean or refer
to Interagency Monitoring of Protected
Visual Environments monitoring
network.
• The initials IWAQM mean or refer
to Interagency Workgroup on Air
Quality Modeling.
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• The initials LDSCR mean or refer to
low-dust SCR.
• The initials LOS mean or refer to
Leland Olds Station.
• The words Lostwood or Lostwood
Wilderness Area or initials LWA mean
or refer to Lostwood National Wildlife
Refuge Wilderness Area.
• The initials LNB mean or refer to
low NOX burners.
• The initials LTS mean or refer to
Long-Term Strategy.
• The initials MRYS mean or refer to
Milton R. Young Station.
• The initials NAAQS mean or refer
to National Ambient Air Quality
Standards.
• The words North Dakota and State
mean the State of North Dakota unless
the context indicates otherwise.
• The initials NOX mean or refer to
nitrogen oxides.
• The initials NPCA mean or refer to
National Parks Conservation
Association.
• The initials NPS mean or refer to
National Park Service.
• The initials PM mean or refer to
particulate matter.
• The initials PM10 mean or refer to
particulate matter with an aerodynamic
diameter of less than 10 micrometers or
course particulate matter.
• The initials PM2.5 mean or refer to
particulate matter with an aerodynamic
diameter of less than 2.5 micrometers or
fine particulate matter.
• The initials PRB mean or refer to
Powder River Basin.
• The initials PSAT mean or refer to
Particle Source Apportionment
Technology.
• The initials PSD mean or refer to
Prevention of Signification
Deterioration.
• The initials RHR mean or refer to
the Regional Haze Rule.
• The initials RH SIP mean or refer to
North Dakota’s Regional Haze State
Implementation Plan.
• The initials RMC mean or refer to
the Regional Modeling Center at the
University of California Riverside.
• The initials RP mean or refer to
Reasonable Progress.
• The initials RPG mean or refer to
Reasonable Progress Goal.
• The initials SCR mean or refer to
selective catalytic reduction.
• The initials SIP mean or refer to
State Implementation Plan.
• The initials SNCR mean or refer to
selective non-catalytic reduction.
• The initials SO2 mean or refer to
sulfur dioxide.
• The initials SOFA mean or refer to
separated overfire air.
• The initials TRNP mean or refer to
Theodore Roosevelt National Park.
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• The initials TSD mean or refer to
Technical Support Document.
• The initials URP mean or refer to
Uniform Rate of Progress.
• The initials WEP mean or refer to
Weighted Emissions Potential.
• The initials WRAP mean or refer to
the Western Regional Air Partnership.
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Table of Contents
I. Background
A. Regional Haze
B. Interstate Transport Requirements
C. Lawsuits
D. Our Proposal
1. Regional Haze
2. Interstate Transport, Visibility Prong
E. Public Participation
II. Final Action
A. Regional Haze
B. Interstate Transport, Visibility Prong
III. Changes from Proposed Rule and Reasons
for the Changes
A. NOX BART for Milton R. Young Station
Units 1 and 2 and Leland Olds Station
Unit 2
B. NOX BART for Coal Creek Station (CCS)
Units 1 and 2
C. Other Resultant Changes
IV. Basis for Our Final Action
A. Regional Haze
B. Interstate Transport, Visibility Prong
V. Issues Raised by Commenters and EPA’s
Responses
A. NOX BART for Milton R. Young Station
Units 1 and 2 and Leland Olds Station
Unit 2
B. Comments on Legal Issues
1. EPA’s Authority
2. Interstate Transport Consent Decree
3. Other General Legal Comments
C. Comments on Modeling
D. Comments on Costs
1. General
2. Comments Regarding Our Reliance on
the EPA Air Pollution Control Cost
Manual
E. Comments on BART Determinations
1. General Comments
2. CCS Units 1 and 2
a. EPA’s Use of the Control Cost Manual for
CCS
b. CCS Emission Limits
c. CCS Modeling
d. CCS Coal Ash
e. CCS Visibility Improvements Are
Minimal
f. Comments on Alternative NOX Emission
Limits
g. Cost Effectiveness of SNCR and SCR at
CCS
h. CCS General Comments
3. Stanton Station Unit 1
4. Leland Olds Station Unit 1
F. General Comments on SO2 and PM
Controls
G. Comments on Reasonable Progress and
North Dakota’s Long-Term Strategy
H. Comments on Health and Ecosystem
Benefits, and Other Pollutants
I. Miscellaneous Comments
J. Comments Requesting an Extension to
the Public Comment Period
K. Comments Generally in Favor of Our
Proposal
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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.’’
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B. Interstate Transport Requirements
Section 110(a)(1) of the CAA requires
states to submit SIPs to address new or
revised National Ambient Air Quality
Standards (NAAQS) within 3 years after
promulgation of such standards, or
within such shorter period as we may
prescribe. On July 18, 1997, we
promulgated the 1997 8-hour ozone
NAAQS and the 1997 fine particulate
(PM2.5) NAAQS. 62 FR 38652. Section
110(a)(2) of the CAA lists the elements
that such new SIPs must address, as
applicable, including section
110(a)(2)(D)(i), which pertains to the
interstate transport of certain emissions.
Section 110(a)(2)(D)(i) contains four
distinct requirements or ‘‘prongs’’
related to the impacts of interstate
transport. The SIP must prevent sources
in the state from emitting pollutants in
amounts which will: (1) Contribute
significantly to nonattainment of the
NAAQS in other states; (2) interfere
with maintenance of the NAAQS in
other states; (3) interfere with provisions
to prevent significant deterioration of air
quality in other states; or (4) interfere
with efforts to protect visibility in other
states.
On April 25, 2005, we published a
‘‘Finding of Failure to Submit SIPs for
Interstate Transport for the 8-hour
Ozone and PM2.5 NAAQS.’’ 70 FR
21147. This action included a finding
that North Dakota and other states had
failed to submit SIPs to address
interstate transport of air pollution and
started a 2-year clock for the
promulgation of a FIP by us, unless a
state made a submission to meet the
requirements of section 110(a)(2)(D)(i),
and we approved the submission, prior
to that time. Id.
On April 6, 2009, we received a SIP
revision from North Dakota to address
the interstate transport provisions of
CAA 110(a)(2)(D)(i) for the 1997 8-hour
ozone NAAQS and the 1997 PM2.5
NAAQS. In prior actions, we approved
this North Dakota SIP submittal for the
first three prongs of section
110(a)(2)(D)(i). (75 FR 31290, June 3,
2010 and 75 FR 71023, November 22,
2010). This action addresses the fourth
prong.
C. Lawsuits
In two separate lawsuits, one in U.S.
District Court for the Northern District
of California and one in the U.S. District
Court for the District of Colorado,
environmental groups sued us for our
failure to timely take action with respect
to the interstate transport requirements
and the regional haze requirements of
the CAA and our regulations. In
particular, the lawsuits alleged that we
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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:
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1. Regional Haze
We proposed to disapprove the
following parts of North Dakota’s RH
SIP:
a. North Dakota’s nitrogen oxides
(NOX) best available retrofit technology
(BART) determinations and emissions
limits for Milton R. Young Station
(MRYS) Units 1 and 2, Leland Olds
Station (LOS) Unit 2, and Coal Creek
Station (CCS) Units 1 and 2.
b. North Dakota’s determination
under the reasonable progress
requirements found at section 40 CFR
51.308(d)(1) that no additional NOX
emissions controls were warranted at
Antelope Valley Station (AVS) Units 1
and 2.
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c. North Dakota’s reasonable progress
goals (RPGs).
d. Portions of North Dakota’s longterm strategy (LTS) that relied on or
reflected other aspects of the RH SIP
that we were proposing to disapprove.
We proposed to approve the
remaining aspects of North Dakota’s RH
SIP revision that was submitted on
March 3, 2010 and SIP Supplement No.
1 that was submitted on July 27, 2010.
We proposed to approve the following
parts of SIP Amendment No. 1 that the
State submitted on July 28, 2011:
a. Amendments to Section 10.6.1.2
pertaining to Coyote Station.
b. Amendments to Appendix A.4, the
Permit to Construct for Coyote Station.
We proposed to not act on the
remainder of the State’s July 28, 2011
submittal.
We proposed to promulgate a FIP to
address the deficiencies in the North
Dakota RH SIP that we identified in our
proposal. The proposed FIP included
the following elements:
a. NOX BART determinations and
emission limits for MRYS Units 1 and
2 and Leland Olds Station Unit 2.
b. NOX BART determination and
emission limit for CCS Units 1 and 2.
c. A reasonable progress
determination and NOX emission limit
for AVS Units 1 and 2.
d. A five-year deadline to meet the
emission limits and monitoring,
recordkeeping, and reporting
requirements for the above seven units
to ensure compliance.
e. RPGs consistent with the SIP limits
proposed for approval and proposed FIP
limits.
f. LTS elements that would reflect the
other aspects of the proposed FIP.
We also proposed approval of a SIP
revision in lieu of our regional haze FIP
if the State submitted a revision in a
timely way that matched the terms of
our proposed FIP.
2. Interstate Transport, Visibility Prong
We proposed to disapprove the
portion of North Dakota’s April 6, 2009,
SIP revision for interstate transport in
which North Dakota intended to address
the requirement of section
110(a)(2)(D)(i)(II) that emissions from
North Dakota sources not interfere with
measures required in the SIP of any
other state under part C of the CAA to
protect visibility.
Because of this proposed disapproval,
we proposed a FIP to meet the visibility
protection requirement of section
110(a)(2)(D)(i)(II). To meet this FIP duty,
we proposed to find that North Dakota
sources would be sufficiently controlled
to eliminate interference with the
visibility programs of other states by a
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combination of the measures that we
were proposing to approve as meeting
the regional haze SIP requirements
combined with the additional measures
that we were proposing to impose in a
FIP to meet the remaining regional haze
SIP requirements.
We noted that acting on both the
section 110(a)(2)(D)(i)(II) requirement
and the regional haze SIP requirement
simultaneously would ensure the most
efficient use of resources by the affected
sources and EPA.
E. Public Participation
We requested comments on all
aspects of our proposed action and
provided a two-month comment period,
with the comment period closing on
November 21, 2011. We also provided a
public hearing. Initially, we scheduled
the hearing to last four hours on one
day. 76 FR 58570. At the request of the
Governor of North Dakota, we expanded
the time for the public hearing to 14
hours over two days and changed the
venue. 76 FR 60777 (September 30,
2011). The public hearing was held in
Bismarck, North Dakota on October 13
and 14, 2011.
We received a significant number of
comments on our proposed rule, both
from commenters, particularly citizens
and environmental groups, that
supported our proposed action, and
from commenters, primarily from state
and city agencies, rural power
cooperatives, and industrial facilities
and groups, that were critical of our
proposed action.
In this action, we are responding to
the comments we have received, taking
final rulemaking action, and explaining
the bases for our action, including any
changes from our proposed action.
II. Final Action
A. Regional Haze
With this final action we are partially
approving and partially disapproving
North Dakota’s RH SIP revision that was
submitted on March 3, 2010, SIP
Supplement No. 1 that was submitted
on July 27, 2010, and part of SIP
Amendment No. 1 that was submitted
on July 28, 2011. Specifically we are
disapproving:
• North Dakota’s NOX BART
determinations and emissions limits for
CCS Units 1 and 2.
• North Dakota’s determination under
the reasonable progress requirements
found at 40 CFR 51.308(d)(1) that no
additional NOX emissions controls are
warranted at AVS Units 1 and 2.
• North Dakota’s RPGs.
• Portions of North Dakota’s LTS that
rely on or reflect other aspects of the RH
SIP that we are disapproving.
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We are approving the remaining
aspects of North Dakota’s RH SIP
revision that was submitted on March 3,
2010 and SIP Supplement No. 1 that
was submitted on July 27, 2010. We are
approving the following parts of SIP
Amendment No. 1 that the State
submitted on July 28, 2011: (1)
Amendments to Section 10.6.1.2
pertaining to Coyote Station, and (2)
amendments to Appendix A.4, the
Permit to Construct for Coyote Station.
We are not taking action on the
remainder of the July 28, 2011 submittal
at this time.
We are finalizing a FIP to address the
deficiencies in the North Dakota RH SIP
that result from our partial disapproval
of the SIP.
The final FIP includes the following
elements:
• NOX BART determination and
emission limit for CCS Units 1 and 2 of
0.13 lb/MMBtu averaged across the two
units on a 30-day rolling average, and a
requirement that the owners/operators
comply with this NOX BART limit
within five (5) years of the effective date
of this final rule.
• A reasonable progress
determination and NOX emission limit
for AVS Units 1 and 2 of 0.17 lb/MMBtu
that applies singly to each of these units
on a 30-day rolling average, and a
requirement that the owner/operator
meet the limit as expeditiously as
practicable, but no later than July 31,
2018.
• Monitoring, record-keeping, and
reporting requirements for the above
four units to ensure compliance with
these emission limitations.
• RPGs consistent with the SIP limits
approved and the final FIP limits.
• LTS elements that reflect the other
aspects of the finalized FIP.
B. Interstate Transport, Visibility Prong
We are disapproving a portion of a
SIP revision that North Dakota
submitted for the purpose of addressing
the ‘‘good neighbor’’ provisions of CAA
section 110(a)(2)(D)(i) for the 1997
8-hour ozone NAAQS and the 1997
PM2.5 NAAQS. Specifically, we are
disapproving the portion of the April 6,
2009 SIP in which North Dakota
intended to address the requirement of
section 110(a)(2)(D)(i)(II) that emissions
from North Dakota sources do not
interfere with measures required in the
SIP of any other state under part C of the
CAA to protect visibility. Because of
this disapproval, we are promulgating a
FIP to meet this requirement of section
110(a)(2)(D)(i)(II). To meet this FIP duty,
we are finding that North Dakota
sources will be sufficiently controlled to
eliminate interference with the visibility
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programs of other states by a
combination of the measures in the
North Dakota SIP that we are
simultaneously approving as meeting
the regional haze SIP requirements
combined with the additional measures
that we are imposing in a FIP to meet
the remaining regional haze SIP
requirements. We note that North
Dakota always has the discretion to
revise its SIP and submit the revision to
us. Should such a revision meet CAA
requirements, we would replace our FIP
with North Dakota’s SIP revision. We
encourage the State to revise its SIP.
III. Changes From Proposed Rule and
Reasons for the Changes
A. NOX BART for Milton R. Young
Station Units 1 and 2 and Leland Olds
Station Unit 2
As noted, we proposed to disapprove
North Dakota’s NOX BART
determinations for MRYS 1 and 2 and
LOS 2 and to promulgate a FIP for NOX
BART for these units to fill the gap that
would have resulted from our
disapproval. After considering a recent
judicial decision, we have decided to
approve North Dakota’s NOX BART
determination for MRYS 1 and 2 and
LOS 2 and to not promulgate a FIP for
NOX BART for these units. We more
fully describe the reasons for this
change below.
On July 27, 2006, the U.S. District
Court for the District of North Dakota
entered a consent decree between EPA,
the State, and Minnkota Power
Cooperative (‘‘Minnkota’’). The consent
decree resulted from an enforcement
action that EPA and the State brought
against Minnkota for alleged violations
of Prevention of Significant
Deterioration (PSD) permitting
requirements at MRYS 1 and 2. The
consent decree called for North Dakota
to make a best available control
technology (BACT) determination for
NOX for MRYS 1 and 2 but also
provided a dispute resolution procedure
in the event of disagreement regarding
the BACT determination.
In November 2010, North Dakota
determined BACT for NOX to be limits
of 0.36 lb/MMBtu for MRYS 1 and 0.35
lb/MMBtu for MRYS 2 based on the use
of selective non-catalytic reduction
(SNCR) technology, with separate limits
during startup. In reaching this
decision, North Dakota eliminated
selective catalytic reduction (SCR), a
higher performing control technology,
based on a finding that SCR was not
technically feasible to control emissions
from North Dakota lignite coal. In
particular, North Dakota noted that no
SCR has ever been employed on an
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electric generating unit (EGU) burning
North Dakota lignite, that North Dakota
lignite has unique properties that have
the potential to quickly degrade the SCR
catalyst, and that no catalyst vendor
supplied with the specifications for the
coal at MRYS 1 and 2 would provide a
guarantee of catalyst life without first
conducting slipstream or pilot tests at
MRYS.
EPA disagreed with North Dakota’s
findings and the selection of selective
non-catalytic reduction (SNCR) as BACT
and initiated the dispute resolution
process under the consent decree.
Under the consent decree, the court was
tasked with upholding North Dakota’s
BACT determination unless the
disputing party was able to demonstrate
that North Dakota’s decision was
unreasonable. We have included a copy
of the consent decree and the court’s
order in the docket for this action.
On December 21, 2011, following
briefing by the parties, and
consideration of North Dakota’s record
for its BACT determination, the court
determined that EPA had not
demonstrated that North Dakota’s
findings were unreasonable. The court
decided that North Dakota, based on the
administrative record for its BACT
determination, had a reasonable basis
for concluding that SCR is not
technically feasible for treating North
Dakota lignite at MRYS. The court
upheld North Dakota’s determination
that SNCR is BACT.
There are two critical principles
expressed in our BART guidelines that
are relevant here. First, as part of a
BART analysis, technically infeasible
control options are eliminated from
further review. For BART, EPA’s criteria
for determining whether a control
option is technically infeasible are
substantially the same as the criteria
used for determining technical
infeasibility in the BACT context. 70 FR
39165; EPA’s ‘‘New Source Review
Workshop Manual,’’ pages B.17–B.22.
Second, the BART guidelines indicate
that states generally may rely on a BACT
determination for a source for purposes
of determining BART for that source,
unless new technologies have become
available or best control levels for recent
retrofits have become more stringent. 70
FR 39164. As a general rule, the
selection of a recent BACT level as
BART is the equivalent of selecting the
most stringent level of control, and
consideration of the five statutory BART
factors becomes unnecessary.
Over our vigorous challenge of the
information and analysis relied upon by
North Dakota, the U.S. District Court
upheld North Dakota’s recent BACT
determination based on the same
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technical feasibility criteria that apply
in the BART context. In light of the
court’s decision and the views we have
expressed in our BART guidelines on
the relationship of BACT to BART, we
have concluded that it would be
inappropriate to proceed with our
proposed disapproval of SNCR as BART
and our proposed FIP to impose SCR at
MRYS 1 and 2 and LOS 2. While LOS
2 was not the subject of the BACT
determination, the same reasoning that
applies to MRYS 1 and 2 also applies to
LOS 2. It is the same type of boiler
burning North Dakota lignite coal, and
North Dakota’s views regarding
technical infeasibility that the U.S.
District Court upheld in the MRYS
BACT case apply to it as well. Thus,
with this action we are approving North
Dakota’s NOX BART determinations for
MRYS 1 and 2 and LOS 2, and no FIP
for these units is necessary. The
applicable limits are 0.36 lb/MMBtu for
MRYS 1 and 0.35 lb/MMBtu for MRYS
2 and 0.35 lb/MMBtu for LOS 2.
We note, however, that the State has
indicated a willingness to pursue the
conduct of a pilot study at MRYS and/
or LOS to analyze the expected
replacement rate of SCR catalyst
exposed to flue gas from the combustion
of North Dakota lignite at these cyclone
units in a low-dust or tail-end
configuration. It is our expectation that
the results of such a study could be used
to inform further evaluation of SCR as
a potential control technology when the
State evaluates reasonable progress in
the next planning period for regional
haze. This position is supported by the
State’s December 20, 2011 letter from
North Dakota Department of Health
(NDDH), L. David Glatt, to EPA, Janet
McCabe.
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B. NOX BART for Coal Creek Station
(CCS) Units 1 and 2
We proposed a NOX BART FIP limit
for CCS 1 and 2 of 0.12 lb/MMBtu that
would apply to each unit individually
on 30-day rolling average basis. We
based this limit on our proposed finding
that SNCR plus separated overfire air
(SOFA) plus low NOX burners (LNB)
was the best available retrofit
technology. While we continue to find
that SNCR plus SOFA plus LNB is the
best available retrofit technology, we are
changing the emission limit to 0.13 lb/
MMBtu averaged over both units on a
30-day rolling average basis. Evidence
submitted by commenters and our own
additional research in evaluating
comments has led us to conclude that
this represents a more reasonable limit
to apply on a 30-day rolling average
basis.
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This limit represents a control
efficiency of 48% based on the average
annual baseline emission rate of 0.22 lb/
MMBtu (2003–2004) provided in the
State’s BART determination. This value
is slightly lower than the 49% control
efficiency we assumed in our proposal,
a value that was based on the State’s
analysis. Beginning in 2010, CCS 2
voluntarily started employing LNC3, the
more stringent level of combustion
controls that the State evaluated in its
BART determination. Annual average
Clean Air Markets data for this unit
reflects a NOX emission rate of 0.153 lb/
MMBtu. We estimate that SNCR would
achieve an additional 25% reduction,
equivalent to an emission rate of 0.115
lb/MMBtu. This compares to a value of
0.108 lb/MMBtu that the State originally
estimated.
Great River Energy (GRE), the owner
of CCS, asserted in comments that SNCR
will only achieve a 20% reduction
beyond LNC3. We find that 25% is a
conservative and reasonable estimate.
We considered several sources of
information in arriving at this value.
First, the Control Cost Manual states
that in typical field applications, SNCR
provides a 30% to 50% NOX reduction.
The manual provides a scatter plot with
NOX reduction efficiency plotted as a
function of boiler size in MMBtu/hr.1
The plot supports GRE’s assertion that
control efficiency could be lower than
50%, and could approach 30%, for
larger boilers such as those at CCS.
Second, Fuel Tech (one of the most
recognized SNCR technology suppliers)
estimates a range of 25% to 50% NOX
reduction with application of SNCR.2
Lastly, ICAC has published information
that supports a control efficiency of 20
to 30% for SNCR above LNB/
combustion modifications.3 Given this
range of control efficiencies, we have
settled on a control efficiency—25%—
that is lower than the lowest value given
by the Control Cost Manual, at the low
end of the range estimated by Fuel Tech,
and in the middle of the range estimated
by ICAC.
To arrive at a final BART emission
limit, we adjusted the projected annual
average of 0.115 lb/MMBtu upward by
10% and then rounded to the nearest
hundredth to arrive at 0.13 lb/MMBtu.
In our experience, a 5 to 15% upward
adjustment is appropriate when
converting an annual average emission
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 https://www.ftek.com/en-US/products/apc/
noxout/.
3 Institute of Clean Air Companies, White Paper
Selective Non-Catalytic Reduction (SNCR) for
Controlling NOX Emissions, February 2008, p. 9.
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rate to a limit that will apply on a 30day rolling average to account for the
fact that shorter averaging periods result
in higher variability in emissions due to
load variation, startup, shutdown, and
other factors.
We decided to allow the averaging
across Units 1 and 2 in response to
comments we received. The BART
Guidelines state, ‘‘You should consider
allowing sources to ‘’average’’ emissions
across any set of BART-eligible emission
units within a fenceline, so long as the
emission reductions from each pollutant
being controlled for BART would be
equal to those reductions that would be
obtained by simply controlling each of
the BART-eligible units that constitute
the BART-eligible source.’’ 40 CFR part
51, appendix Y, section V. This
principle applies here.
C. Other Resultant Changes
Because we are now approving North
Dakota’s NOX BART determinations for
MRYS 1 and 2 and LOS 2, the basis for
our proposed disapproval of North
Dakota’s RPGs is slightly changed from
our proposal. Disapproval is still
warranted because North Dakota’s RPGs
do not represent our final NOX BART
FIP limits at CCS 1 and 2 or our final
NOX reasonable progress FIP limits at
AVS 1 and 2 (or the Heskett or Coyote
controls that North Dakota included in
the SIP). As part of our FIP, we are
finalizing RPGs that are consistent with
the controls we are imposing at CCS 1
and 2 and AVS 1 and 2, and the Heskett
and Coyote controls that North Dakota
included in the SIP. For further details
regarding our rationale, please refer to
our proposal and to our response to
comments.
Similarly, because we are now
approving North Dakota’s NOX BART
determinations for MRYS 1 and 2 and
LOS 2, the basis for our proposed partial
disapproval of North Dakota’s LTS is
slightly changed from our proposal.
Partial disapproval is still warranted
because we are disapproving North
Dakota’s NOX BART determination for
CCS 1 and 2 and NOX reasonable
progress determination for AVS 1 and 2,
and the LTS does not reflect our final
NOX BART FIP limits at CCS 1 and 2
or our final NOX reasonable progress FIP
limits at AVS 1 and 2, or corresponding
compliance provisions. Except for these
missing elements, the LTS satisfies the
requirements of 40 CFR 51.308(d)(3), so
we are approving the remainder of the
LTS. Our FIP fills the gap left by our
partial disapproval of the LTS by
specifying NOX emission limits for CCS
1 and 2 and AVS 1 and 2, compliance
schedules, and monitoring,
recordkeeping, and reporting
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requirements. For further details
regarding our rationale, please refer to
our proposal and our response to
comments.
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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
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reasonable progress controls for certain
sources—specifically, for Coyote Station
for NOX and for Heskett Station 2 for
sulfur dioxide (SO2). However, in these
instances, North Dakota nonetheless
included emission limits in the SIP that
reflect reasonable levels of control for
reasonable progress for this initial
planning period. Here again, we
understand that there is room for
disagreement about the State’s analyses
and appropriate limits. And, again, we
may have reached different conclusions
had we been performing the
determinations. However, the comments
have not convinced us that the State,
conducting specific case-by-case
analyses for the relevant units, made
unreasonable determinations for this
initial planning period or that we
should be disapproving the State’s
reasonable progress determinations that
we proposed to approve.
As noted, we are disapproving North
Dakota’s NOX BART determination for
CCS 1 and 2 and its NOX reasonable
progress determination for AVS 1 and 2
and promulgating a partial FIP to
establish the required limits and
corresponding compliance provisions.
For CCS 1 and 2, the State relied on
values for costs of compliance supplied
by the owner that were admittedly
erroneous. As explained in detail in our
response to comments, the comments
we received have not convinced us that
our disapproval of the State’s NOX
BART determination for CCS 1 and 2 is
unreasonable, or that our NOX BART
FIP determination and limits (as
modified in this final action) are
unreasonable. In particular, we
conclude that GRE’s latest cost estimates
and cost effectiveness values for SNCR,
as reflected in its November 2011
comments, are not based on reasonable
assumptions and overestimate the costs
of compliance. Instead, our
consideration of the five statutory BART
factors leads us to conclude that SNCR
plus SOFA plus LNB is BART, with a
limit of 0.13 lb/MMBtu on a 30-day
rolling average basis. Also, we continue
to find that the costs of SCR are not
reasonable given the projected visibility
improvement; the comments we
received on this issue have not
convinced us otherwise.
For AVS 1 and 2, consistent with our
proposal, we are disapproving the
State’s determination under our
reasonable progress requirements (40
CFR 51.308(d)(1)) that no additional
NOX emissions controls are warranted,
and we are finalizing a FIP with a
reasonable progress determination and a
NOX emission limit for AVS 1 and 2 of
0.17 lb/MMBtu on a 30-day rolling
average basis. Nothing in the comments
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20899
has convinced us that the State’s
determination was reasonable or that
our proposed FIP was unreasonable. As
we noted in our proposal, the costs for
installation and operation of
combustions controls at AVS 1 and 2 are
very reasonable ($586 and $661 per ton)
and the predicted NOX reductions are
substantial—3,500 tons per unit per
year. Appropriate single-source
modeling also indicates that the
visibility benefits will be substantial—
0.754 deciviews. Based on these facts,
and given that North Dakota’s RPGs will
not meet the uniform rate of progress
(URP), it was unreasonable for North
Dakota to reject LNB at AVS 1 and 2. We
have determined that the State’s
rejection of this level of control, and the
corresponding RPGs, are not justifiable
based on a reasonable consideration of
the applicable regulatory factors—costs
of compliance, time necessary for
compliance, energy and non-air quality
environmental impacts of compliance,
and remaining useful life of the source.
LNB is a modest, widely-used, costefficient means to achieve significant
NOX reductions, and the resultant
visibility benefits will be comparable to
or greater than the benefits achieved
through selected controls at several
BART units in North Dakota. We have
also rejected comments that call for
more stringent controls at AVS 1 and 2
in this planning period. While such
controls may be appropriate in a later
planning period, we cannot say that the
State’s rejection of such controls in this
planning period was unreasonable. For
further details regarding our rationale,
please refer to our proposal and our
response to comments.
Consistent with our proposal, we are
approving the remaining elements of
North Dakota’s RH SIP because such
elements meet the relevant requirements
of our regional haze regulations.
B. Interstate Transport, Visibility Prong
The basis for this part of our action
remains unchanged from our proposal.
Nothing in the comments has convinced
us that a change from our proposal is
warranted. North Dakota’s April 6, 2009
transport submittal contained only a
cursory reference to CAA section
110(a)(2)(D)(i)(II)’s requirement for a SIP
revision that contains adequate
provisions ‘‘prohibiting any source or
other type of emission activity within
the State from emitting any air pollutant
in amounts which will * * * interfere
with measures required to be included
in the applicable implementation plan
for any other State under part C [of the
CAA] to protect visibility.’’ Because of
the impacts on visibility from the
interstate transport of pollutants, we
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interpret the ‘‘good neighbor’’
provisions of section 110 of the Act
described above as requiring states to
include in their SIPs either measures to
prohibit emissions that would interfere
with the RPGs required to be set to
protect Class I areas in other states, or
a demonstration that emissions from
North Dakota sources and activities will
not have the prohibited impacts. North
Dakota’s April 6, 2009 submittal
contains neither. Thus, we are
disapproving it. To the extent that the
State intended to meet the requirement
of section 110(a)(2)(D)(i)(II) with the RH
SIP, the RH SIP submission itself is not
fully approvable.
As required by section 110(c), we are
promulgating a FIP to satisfy the
requirements of CAA section
110(a)(2)(D)(i)(II) concerning visibility
protection. As explained in section II,
the FIP relies on the combination of the
North Dakota RH SIP provisions that we
are approving and the additions to the
regional haze program for North Dakota
that we are promulgating in our FIP for
NOX BART for CCS 1 and 2 and NOX
reasonable progress for AVS 1 and 2.
Because this combination exceeds the
stringency of BART and reasonable
progress limits that were already
factored into the Western Regional Air
Partnership (WRAP) modeling for RPGs,
this combination meets the visibility
prong of CAA section 110(a)(2)(D)(i)(II).
This combination of regional haze
controls will ensure that emissions from
sources in North Dakota do not interfere
with other states’ visibility programs as
required by section 110(a)(2)(D)(i)(II) of
the CAA.
For further details regarding our
rationale, please refer to our proposal
and our response to comments.
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V. Issues Raised by Commenters and
EPA’s Responses
A. NOX BART for Milton R. Young
Station Units 1 and 2 and Leland Olds
Station Unit 2
As noted in section III of this action,
in a major change from our proposal, we
are now approving North Dakota’s NOX
BART determinations for MRYS 1 and
2 and LOS 2, and we are not proceeding
with a FIP for NOX BART for these
units. We explain the basis for this
change in section III.
We received numerous comments that
were specific to the NOX BART
determinations for MRYS 1 and 2 and
LOS 2. These related to a variety of
issues—modeling and visibility
improvement, costs of compliance,
technical feasibility, appropriate
emission limits, and other issues. The
grounds for our decision to approve
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North Dakota’s NOX BART
determinations for MRYS 1 and 2 and
LOS 2 render irrelevant further
consideration of these issues.
Essentially, we are approving the State’s
determination of BART based on a
federal court’s ruling on our challenge
to the State’s BACT determination for
MRYS. In establishing BACT, the State
established an emission limit based on
what it considered the maximum degree
of reduction of NOX, taking into account
various factors similar to those in a
BART determination. Thus, while we
disagree with the vast majority of the
comments that disputed our technical
and legal analyses concerning NOX
BART for MRYS 1 and 2 and LOS 2, we
generally are not summarizing or
responding to those comments to the
extent they are specific to the
assessment of NOX BART for MRYS 1
and 2 and LOS 2.4 However, we are
responding to comments that may be
relevant to other aspects of this action.
B. Comments on Legal Issues
1. EPA’s Authority
Comment: Multiple commenters
stated that CAA Section 169A and the
Regional Haze Rule (RHR) give the
states (North Dakota in this instance) the
lead in developing their regional haze
SIPs. Some commenters went further in
stating that North Dakota is given almost
complete discretion in creating its RH
SIP. These commenters argued that,
because North Dakota is given such
discretion, EPA lacks the statutory
authority to disapprove the State’s RH
SIP. Specifically, some commenters
pointed to the flexibility the State is
granted in developing its BART
determination, RPGs, modeling protocol
and cost analysis. The State of North
Dakota, for instance, argued that each
factor in the five-factor analysis used to
make its BART determination was
appropriately weighed based on the
State’s own discretion. The State
therefore argues that the EPA has no
basis on which to disapprove the fivefactor analysis.
Response: Congress crafted the CAA
to provide for states to take the lead in
developing implementation plans, but
balanced that decision by requiring EPA
to review the plans to determine
whether a SIP meets the requirements of
the CAA. EPA’s review of SIPs is not
limited to a ministerial type of
automatic approval of a state’s
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.
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decisions. EPA must consider not only
whether the State considered the
appropriate factors but acted reasonably
in doing so. In undertaking such a
review, EPA does not ‘‘usurp’’ the
state’s authority but ensures that such
authority is reasonably exercised. EPA
has the authority to issue a FIP either
when EPA has made a finding that the
State has failed to timely submit a SIP
or where EPA has found a SIP deficient.
Here, EPA has authority on both
grounds, and we have chosen to
approve as much of the North Dakota
SIP as possible and to adopt a FIP only
to fill the remaining gap. Our action
today is consistent with the statute. In
finalizing our proposed determinations,
we are approving the State’s
determinations in identifying BART
eligible sources and largely approving
the State’s BART determinations for
seven different emission units subject to
BART. Also, we are largely approving
the State’s reasonable progress
determinations. We are, however,
disapproving the State’s NOX BART
determinations for two units—CCS 1
and 2—and its NOX reasonable progress
determinations for two units—AVS 1
and 2.
The State’s NOX BART
determinations for CCS 1 and 2 are not
approvable because North Dakota did
not properly follow the requirements of
section 51.308(e)(1)(ii)(A). Specifically,
North Dakota did not reasonably ‘‘take
into consideration the costs of
compliance,’’ when it relied on cost
estimates that greatly overestimated the
costs of controls. We have determined
that the faults in the cost estimates were
significant enough that they resulted in
BART determinations for NOX for CCS
1 and 2 that were both unreasoned and
unjustified. Accordingly, these
determinations are not approvable.
We are disapproving the State’s
determination that no NOX controls are
needed at AVS 1 and 2 to achieve
reasonable progress because the State’s
determination is not reasonable under
the relevant statutory and regulatory
requirements.
In the absence of approvable NOX
BART determinations in the SIP for CCS
1 and 2 and in the absence of an
approvable reasonable progress
determination concerning NOX controls
at AVS 1 and 2, we are obliged to
promulgate a FIP to satisfy the CAA
requirements. Likewise, in the absence
of an approvable SIP that addresses the
requirement that emissions from North
Dakota sources do not interfere with
measures required in the SIP of any
other state to protect visibility, we are
obliged to promulgate a FIP to address
the defect. This authority and
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responsibility exists under CAA section
110(c)(1).
We also are required by the terms of
two separate consent decrees, one in the
U.S. District Court for the District of
Colorado and one in the U.S. District
Court for the Northern District of
California to ensure that North Dakota’s
CAA requirements for regional haze and
for 110(a)(2)(D)(i)(II), respectively, are
finalized by March 2, 2012. Because we
have found that the State’s SIP
submissions do not adequately satisfy
either requirement in full and because
we have previously found that North
Dakota failed to timely submit these SIP
submissions, we have not only the
authority, but a duty to promulgate a
FIP that meets those requirements.
Our action in large part approves the
RH SIP submitted by North Dakota. The
disapproval of the NOX BART and
reasonable progress determinations and
imposition of the FIP is not intended to
encroach on state authority. This action
is only intended to ensure that CAA
requirements are satisfied using our
authority under the CAA.
Comment: The NDDH commented
that states are free to deviate from the
BART guidelines in the preparation of
their BART analyses, except for power
plants with a capacity exceeding 750
megawatts (MW).
Response: We agree that the BART
guidelines are only mandatory under
the regional haze regulations for ‘‘fossilfuel fired power plants having a total
generating capacity greater than 750
megawatts.’’ 40 CFR 51.308(e)(1)(ii)(B).
However, the fact that a state may
deviate from the guidelines for other
BART sources does not mean that the
state has unfettered discretion to act
unreasonably or inconsistently with the
CAA and our regulations. Where the
BART guidelines are not mandatory, a
state must still meet the requirements of
the CAA and our regulations. In other
words, the State must still adopt and
apply the best available retrofit
technology, considering the statutory
factors.
Our regulations define best available
retrofit technology to mean ‘‘an
emission limitation based on the degree
of reduction achievable through the
application of the best system of
continuous emission reduction for each
pollutant which is emitted by an
existing stationary facility.’’ 40 CFR
51.301 (emphasis added). We do not
consider that this definition can simply
be dismissed under the mantle of state
discretion.
In addition, North Dakota’s own
regulations, which have been submitted
for our approval and which we are
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approving with this action, provide as
follows:
‘‘33–15–25–03 Guidelines for best available
retrofit technology determinations under the
Regional Haze Rule.
Title 40, Code of Federal Regulations, part
51, appendix y, as published in the Federal
Register on July 6, 2005, is incorporated by
reference into this chapter. The owner or
operator of a fossil-fuel-fired steam electric
plant with a generating capacity greater than
seven hundred fifty megawatts of electricity
shall comply with the requirements of
appendix y. All other facility owners or
operators shall use appendix y as guidance
for preparing their best available control
retrofit technology determinations.’’
(Emphasis added.) Appendix Y contains
EPA’s BART guidelines. Our approval of
this regulation makes it federally
enforceable.
North Dakota appears to disavow the
dictates of its own regulation:
‘‘EGUs with a capacity of less than 750
MW * * * are free to deviate from the BART
Guidelines in the preparation of their BART
analyses.
MRYS * * * may use the Guidelines as
guidance only.’’
State of North Dakota’s November 21,
2011 comments, p. 22 (emphasis
added). But, the regulation says that
EGUs less than 750 MW ‘‘shall use’’
EPA’s BART guidelines as guidance, not
that they ‘‘may use’’ them as guidance
or that they are ‘‘free to deviate’’ from
them.
Given that North Dakota’s own
regulation, which we are making
federally enforceable with this action,
requires the use of the BART guidelines
as guidance for BART analyses, we
think it reasonable to conclude that any
deviation from the guidelines must be
based on a reasonable justification.
Regardless, the BART guidelines are
mandatory for CCS, which is the one
source for which we are disapproving
the State’s BART determination.
Comment: North Dakota meets the
presumptive BART limits for NOX at
CCS 1 and 2, based on the 2005 BART
Guidelines. EPA’s rationale for
disapproving the BART determinations
at CCS 1 and 2 is therefore flawed and
contrary to the BART Guidelines. EPA
appears to be undertaking a national
effort to change its BART Rule without
going through notice and comment
rulemaking to amend or repeal the rule.
EPA is doing so by ‘‘applying BART
determinations made for sources in one
state as a new presumptive limit for all
states.’’ Commenter cites 76 FR 58623 of
the proposed rule, where EPA justifies
a cost/ton ‘‘that states other than North
Dakota have considered reasonable for
BART,’’ but is higher than the
presumptive BART limits.
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Response: We disagree with the
commenter. First, for each source
subject to BART, the RHR, at 40 CFR
51.308(e)(1)(ii)(A), requires that states
identify the level of control representing
BART after considering the factors set
out in CAA section 169A(g), as follows:
States must identify the best system of
continuous emission control technology
for each source subject to BART taking
into account the technology available,
the costs of compliance, the energy and
non-air quality environmental impacts
of compliance, any pollution control
equipment in use at the source, the
remaining useful life of the source, and
the degree of visibility improvement
that may be expected from available
control technology. 70 FR 39158. In
other words, the presumptive limits do
not obviate the need to identify the best
system of continuous emission control
technology on a case-by-case basis
considering the five factors. A state may
not simply ‘‘stop’’ its evaluation of
potential control levels at the
presumptive level of control if more
stringent control technologies or limits
are technically feasible. We do not read
the BART guidelines in appendix Y to
contradict the requirement in our
regulations to determine ‘‘the degree of
reduction achievable through the
application of the best system of
continuous emission reduction’’ ‘‘on a
case-by-case basis,’’ considering the five
factors. 40 CFR 51.301 (definition of
Best Available Retrofit Technology); 40
CFR 51.308(e). Also, our interpretation
is supported by the following language
in our BART guidelines:
While these levels may represent current
control capabilities, we expect that scrubber
technology will continue to improve and
control costs continue to decline. You should
be sure to consider the level of control that
is currently best achievable at the time that
you are conducting your BART analysis.
70 FR 39171. The presumptive limits
are meaningful as indicating a level of
control that EPA generally considered
achievable and cost effective at the time
it adopted the BART guidelines in 2005,
but not a value that a state could adopt
without conducting a five factor
analysis considering more stringent,
technically feasible levels of control.
The commenter focuses on narrow
passages of the BART guidelines to
support its view that the presumptive
limits represent the most stringent
BART controls that EPA can require for
regional haze. However, these passages
must be reconciled with the language of
the RHR cited above, as well as other
passages of the BART guidelines and
associated preamble. A central concept
expressed in the guidelines is that a
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state is not required to consider the five
factors if it has selected the most
stringent level of control; otherwise, a
state must fully consider the five factors
in determining BART. 40 CFR part 51,
appendix Y, section IV.D.1, step 1.9.
Undoubtedly, as the commenter notes,
the presumptive limits for NOX
represent cost effective controls, but it is
well-understood that limits based on
combustion controls do not represent
the most stringent level of control for
NOX. Thus, a state which selects
combustion controls and the associated
presumptive limit for NOX as BART
may only do so after rejecting more
stringent control technologies based on
full consideration of the five factors.
Our interpretation reasonably reconciles
the various provisions of our
regulations. We clearly communicated
our views on this subject to North
Dakota while it was developing its RH
SIP, and, following our interpretation,
North Dakota conducted an analysis of
control technologies that would achieve
a more stringent limit than combustion
controls.
While North Dakota conducted a fivefactor analysis to determine BART at
CCS, its determination was based on
erroneous values for the costs associated
with potential loss of fly ash sales due
to ammonia contamination, something
the source acknowledged in June of
2011. 76 FR 58603. A BART
determination based on substantially
erroneous cost values does not meet the
requirements of the CAA or our
regulations to determine the best system
of continuous emission control
technology considering cost and the
other statutory factors. Because we
cannot approve the State’s BART
determination, we are authorized, and
in this case obligated, to promulgate a
FIP.
In promulgating a FIP for CCS, we
arrived at an emission limit that is more
stringent than the presumptive limit
based on consideration of the five
factors. Contrary to the commenter’s
suggestion, EPA’s BART guidelines do
not establish a presumptive cost
effectiveness level that is a ‘‘safe
harbor’’ or ‘‘shield’’ for state BART
determinations, or that EPA, when
promulgating a FIP, may not exceed in
determining BART. Once a FIP is
required, we stand in the state’s shoes.
In considering the cost factor, it is
reasonable for us to consider other
sources of information to inform our
decision, including the cost values other
states have considered reasonable. This
is not EPA establishing a new
presumptive limit or national rule; it is
EPA, acting in the state’s shoes,
conducting a reasonable source-specific
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consideration of cost and the other
regulatory factors. In addition, although
not required, we considered cost
effectiveness values that the State of
North Dakota had considered to be
reasonable in reaching its BART
determinations. See 76 FR 58623 (‘‘It is
also within the range of values that
North Dakota considered reasonable in
its NOX BART determinations * * *’’)
Comment: EPA has failed to
articulate, or apply, a SIP review
standard that preserves state authority
over BART determinations. EPA can’t
rely on vague references to the
overarching purpose of the regional
haze program to define what’s
reasonable. The CAA only requires
consideration of the five statutory
factors and emission limits that yield a
reduction in visibility impairment. EPA
has contradicted prior statements in
various contexts, such as reports to
Congress. EPA has provided no
objective measure to gauge EPA’s
assessment. EPA’s vague standards
result in arbitrary and capricious
decision making. EPA must articulate
the standard by which it evaluates and
disapproves a SIP and must support its
decision with a plausible explanation.
Response: Our proposal clearly laid
out the bases for our proposed
disapproval of the State’s BART and
reasonable progress determinations, and
we have relied on the standards
contained in our regional haze
regulations and the authority that
Congress granted us to review and
determine whether SIPs comply with
the minimum statutory and regulatory
requirements. To the extent a cost
analysis relies on values that are
inaccurate, a state has not considered
cost in a reasoned or reasonable fashion.
To the extent a state has considered
visibility improvement from potential
emissions controls in a way that
substantially understates the
improvement or does so in a way that
is not consistent with the CAA, the state
has not considered visibility
improvement in a reasoned or
reasonable fashion. In these
circumstances, it is reasonable for EPA
to disapprove the relevant aspects of the
SIP. In determining SIP adequacy, we
inevitably exercise our judgment and
expertise regarding technical issues, and
it is entirely appropriate that we do so.
Courts have recognized this necessity
and deferred to our exercise of
discretion when reviewing SIPs. See,
e.g., Connecticut Fund for the Env’t.,
Inc. v. EPA, 696 F.2d 169 (2nd Cir.
1982); Michigan Dep’t. of Envtl. Quality
v. Browner, 230 F.3d 181 (6th Cir. 2000);
Mont. Sulphur & Chem. Co. v. United
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States EPA, 2012 U.S. App. LEXIS 1056
(9th Cir. Jan. 19, 2012).
We disagree with the argument that
we must approve a BART determination
where the SIP reflects consideration of
the five factors and the BART selection
will result in some improvement in
visibility. We think Congress expected
more when it required the application of
‘‘best available retrofit technology.’’
While the commenter places great
emphasis on EPA’s prior statements in
reports to Congress, these statements
have no regulatory effect. Also, these
statements are not as supportive of
commenter’s position as commenter
suggests. For example, ‘‘some
flexibility’’ does not suggest unfettered
flexibility; a report’s suggestion that a
cooperative approach would make sense
does not suggest that EPA will or must
approve unilateral decision-making by a
state no matter what.
Contrary to the commenter’s
assertion, we have not destroyed the
State’s primacy. In fact, we have
approved the vast majority of the State’s
determinations. We are only rejecting
the State’s unreasonable analyses and
decisions. We are authorized to do so.
Comment: The grounds invoked by
EPA to disapprove the RH SIP are
legislative in nature and cannot be
imposed without advance notice and
comment rulemaking. EPA’s proposed
action on North Dakota’s SIP articulates
a number of grounds not contained in
CAA section 169A that must be met for
a SIP to be ‘‘approvable.’’ These
additional grounds have never been
defined or promulgated with notice and
comment rulemaking. For example,
EPA’s proposed action articulates a two
pronged test for BART SIP approval:
first, ‘‘a state must meet the
requirements of the CAA and our
regulations for selection of BART’’; and
second, ‘‘the state’s BART analysis and
determination must be reasonable in
light of the overarching purpose of the
regional haze program.’’ 76 FR 58577.
The commenter objects to the second
prong, i.e., that ‘‘the state’s BART
analysis and determination must be
reasonable in light of the overarching
purpose of the regional haze program.’’
According to the commenter, this is a
new ‘‘reasonableness’’ standard that is
neither defined nor separately set forth
in the Act. The commenter asserts that
EPA is proposing to measure a BART
determination not just against the
statutory criteria but also against EPA’s
own subjective view whether the result
reached is reasonable enough to meet
the ‘‘overarching goal’’ of the Act. EPA’s
new subjective reasonable enough
requirement imposes a new legislative
standard that either goes beyond or, for
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the first time, purports to define ‘‘the
requirements of the Act.’’ This
empowers EPA to disapprove a state
BART determination and replace it with
its own on reasonableness grounds that
have never been defined or first vetted
through public notice and comment.
Response: First, even assuming that
EPA’s proposed action on the North
Dakota RH SIP articulated new grounds
for evaluating a regional haze SIP, the
proposed action provides the public
with the opportunity to comment. As
evidenced by the commenter’s
submission, the commenter had the
opportunity to comment on EPA’s
approach to evaluating the North Dakota
RH SIP and to identify any concerns
associated with the statement at issue
from our proposal and other aspects of
our action.
Second, the CAA requires states to
submit SIPs that contain such measures
as may be necessary to make reasonable
progress toward achieving natural
visibility conditions, including BART.
The CAA accordingly requires the states
to submit a regional haze SIP that
includes BART as one necessary
measure for achieving natural visibility
conditions. In view of the statutory
language, it is hardly a novel idea that
the reasonableness of the state’s BART
analysis and determination would be
evaluated in light of the purpose of the
regional haze program. In addition, our
regional haze regulations, at 40 CFR
51.308(d)(ii), provide that when a state
has established a RPG that provides for
a slower rate of improvement in
visibility than the URP (as has North
Dakota), the state must demonstrate,
based on the reasonable progress
factors—i.e., costs of compliance, time
necessary for compliance, energy and
non-air quality environmental impacts
of compliance, and remaining useful life
of affected sources—that the rate of
progress to attain natural visibility
conditions by 2064 is not reasonable
and that the progress goal adopted by
the state is reasonable. 40 CFR
51.308(d)(iii) provides that, ‘‘in
determining whether the State’s goal for
visibility improvement provides for
reasonable progress towards natural
visibility conditions, the Administrator
will evaluate’’ the state’s
demonstrations under section
51.308(d)(ii). It is clear that our
regulations and the CAA require that we
review the reasonableness of the State’s
BART determinations in light of the goal
of achieving natural visibility
conditions. This approach is also
inherent in our role as the
administrative agency empowered to
review and approve SIPs. Thus, we are
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not establishing a new reasonableness
standard, as the commenter asserts.
Comment: EPA established a new
adequacy criterion when it found that
North Dakota’s cost analysis did not
provide a reasonable basis to make a
NOX BART determination for LOS 2. It
was illegal for EPA to establish a new
adequacy criterion without rulemaking.
Response: While we have decided to
approve the State’s NOX BART
determination for LOS 2, this comment
may be relevant to other aspects of our
final action.
Our prior response largely addresses
this assertion. However, in addition, we
think the illogic of the commenter’s
claim is revealed when the potential
consequences of the commenter’s views
are examined. The necessary product of
the commenter’s view is that a state
could rely on irrational values for any
of the five factors, and EPA would be
powerless to disapprove the SIP. We
reject that view. We are not establishing
new criteria for approval of a regional
haze SIP. We are applying the criteria
and requirements already specified in
the CAA and our regulations. Cost is
one of the factors a state must consider
in determining BART. If North Dakota
has relied on greatly inflated cost
estimates in its consideration of the cost
factor, it has not considered cost in any
meaningful sense of the word.
It is also our opinion that the
commenter, in its effort to put our
action in a specific legal box—i.e.,
‘‘illegal administrative action’’—
consistently misrepresents the nature of
our action. This is a SIP review action,
and we believe that EPA is not only
authorized, but required to exercise
independent technical judgment in
evaluating the adequacy of the State’s
RH SIP, including its BART
determinations, just as EPA must
exercise such judgment in evaluating
other SIPs. In evaluating other SIPs,
EPA is constantly exercising judgment
about SIP adequacy, not just to meet and
maintain the NAAQS, but also to meet
other requirements that do not have a
numeric value. In this case, Congress
did not establish NAAQS by which to
measure visibility improvement;
instead, it established a reasonable
progress standard and required that EPA
assure that such progress be achieved.
Here, contrary to the commenter’s
assertion, we are exercising judgment
within the parameters laid out in the
CAA and our regulations. Our
interpretation of our regulations and of
the CAA, and our technical judgments,
are entitled to deference. See, e.g.,
Michigan Dep’t. of Envtl. Quality v.
Browner, 230 F.3d 181 (6th Cir. 2000);
Connecticut Fund for the Env’t., Inc. v.
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EPA, 696 F.2d 169 (2nd Cir. 1982);
Voyageurs Nat’l Park Ass’n v. Norton,
381 F.3d 759 (8th Cir. 2004); Mont.
Sulphur & Chem. Co. v. United States
EPA, 2012 U.S. App. LEXIS 1056 (9th
Cir. Jan. 19, 2012).
Comment: EPA has no statutory
authority to disapprove North Dakota’s
BART determination for LOS 2. CAA
section 169A(b)(2) leaves that
determination expressly and exclusively
in the hands of the State. EPA’s SIP
approval authority under CAA section
110 only permits EPA to confirm
whether the State considered the
statutory factors; it does not authorize
EPA to pass judgment on how the State
considers them. The commenter cites
the American Corn Growers and UARG
decisions as support for its comments.
Nor, according to the commenter, does
section 110 permit EPA to propose its
own emission controls. By doing so,
EPA’s FIP ‘‘run[s] roughshod over the
procedural prerogatives that the Act has
reserved to the States’’ (citing
Bethlehem Steel Corp. v. Gorsuch, 742
F.2d 1028, 1036 (7th Cir. 1984)).
Response: While we have decided to
approve the State’s NOX BART
determination for LOS 2, this comment
may be relevant to other aspects of our
final action. The commenter reads too
much into the language of 169A. We do
not agree that the language, ‘‘as
determined by the State,’’ grants the
State unlimited discretion or ‘‘sole
control’’ in making a BART
determination, any more than the
accompanying language, ‘‘or the
Administrator in the case of a plan
promulgated under section 7410(c) of
this title,’’ grants EPA unlimited
discretion in making a BART
determination in a FIP.
Instead, while States are assigned the
primary statutory and regulatory
authority to determine BART, and have
significant freedom to determine the
weight and significance of the statutory
factors, they have an overriding
obligation to come to a reasoned
determination. They may not act
unreasonably or in an arbitrary and
capricious fashion, and Congress has
assigned EPA, as the reviewing agency,
the role of determining whether a State’s
BART determination or reasonable
progress determination is reasonable.
The commenter’s citations to
legislative history are unconvincing.
Among other things, they are
incomplete. The commenter ignores the
intent behind the 1977 legislation:
‘‘The Administrator must promulgate
regulations which assure attainment of the
national goal * * * Specifically, the
regulations must require that States which
contain mandatory class I areas, and States
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whose emissions cause or contribute to
visibility problems in such areas, revise their
implementation plan to include two
elements. The first element of the plan
revision is that the State plan must provide
for installation of ‘‘best available retrofit
technology’’ for existing major stationary
sources which cause or contribute to
visibility impairment in such areas.’’
95 Cong. Conf. Report H. Rept. 564, at
154.
Commenters suggest that visibility
issues are only of state and local
concern and that is why Congress left
states with sole control. This is
inconsistent with the very first sentence
of the statute: ‘‘Congress hereby declares
as a national goal the prevention of any
future, and the remedying of any
existing, impairment of visibility in
mandatory class I Federal areas * * *’’
CAA section 169A, (emphasis added). It
is also inconsistent with the legislative
history, which states:
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‘‘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
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the RH SIP; and second, based on our
partial disapproval of the RH SIP.
Comment: Commenter stated that EPA
is incorrect to assert that NDDH did not
adequately consider all five statutory
factors for LOS 2. Commenter stated that
EPA concludes, in its own BART
evaluation, that SNCR + ASOFA
(NDDH’s BART selection) is cost
effective and provides substantial
visibility benefits. When a state has
taken into consideration the five
statutory factors and selected a
technology that reduces visibility
impairments, it has complied with the
statute and EPA must approve the SIP.
Since EPA’s own FIP analysis proves
North Dakota’s choice complies with the
statute, EPA has no basis to disapprove
it.
Response: While we have decided to
approve the State’s NOX BART
determination for LOS 2, this comment
may be relevant to other aspects of our
final action. The commenter cites no
authority in the CAA or our regulations
for its assertion that a BART
determination that considers the five
statutory factors is adequate as long as
it provides some reduction in visibility
impairment. We know of no such
criterion. Instead, our regulations define
BART as an emission limitation based
on the degree of reduction achievable
through the application of the best
system of continuous emission
reduction for each pollutant which is
emitted by an existing stationary
facility. The emission limitation must be
established, on a case-by-case basis,
taking into consideration the technology
available, the costs of compliance, the
energy and non-air quality
environmental impacts of compliance,
any pollution control equipment in use
or in existence at the source, the
remaining useful life of the source, and
the degree of improvement in visibility
which may reasonably be anticipated to
result from the use of such technology.
Given that the BART limit must reflect
the ‘‘application of the best system of
continuous emission reduction,’’ we
interpret the Act to require a reasonable
consideration of the five factors, one
that is not arbitrary and capricious.
Comment: EPA’s effort to impose
BART determinations by federal
rulemaking impermissibly deprives
source owners of the substantive
procedural rights they are otherwise
afforded under State law. The
commenter notes that the State used a
permit process to establish BART limits,
and that a similar source-by-source
adjudication of such limits must be
provided by EPA. The commenter also
asserts that EPA must allow for
examination and cross-examination of
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witnesses, and that, otherwise, the
process is not consistent with due
process.
Response: While the State has chosen
to use the permit process to establish
BART limits for individual sources,
there is nothing in the CAA or our
regulations that requires states or EPA to
use permits or a source-by-source
adjudicatory proceeding to establish
BART limits. Both the CAA and our
regulations require that BART limits be
contained in a SIP. In the absence of an
approvable SIP, CAA section 110(c)
requires us to issue a FIP. We have
issued a partial FIP pursuant to CAA
section 307. CAA section 307 provides
that its provisions apply in lieu of the
Administrative Procedure Act (APA).
The procedures provided by CAA
section 307 are adequate to ensure due
process to source owners. We have
provided a substantial opportunity for
comment (a two-month long comment
period) and an extensive public hearing
that lasted 14 hours over two days. The
commenter submitted over 140 pages of
comments with several attachments,
and other commenters submitted
comments of similar length. It is not
unusual for FIPs to include sourcespecific limits and requirements. An
opportunity for examination and crossexamination of witnesses is not required
by the CAA, nor is it required to ensure
due process. Individuals and entities
affected by EPA’s action have had ample
opportunity to challenge EPA’s
conclusions.
Comment: Sole control over BART
determinations for EGUs under 750 MW
is left to the states. Congressional intent
to exclude federal involvement in BART
determinations for smaller generating
stations is apparent from the plain text
of the statute and is binding on EPA.
EPA may not disapprove a state BART
determination for an EGU the size of
Leland Olds.
Response: EPA disagrees with the
suggestion that Congress intended to
totally remove EPA from review of
BART determinations for EGUs less
than 750 MW. The statute merely says
that for EGUs greater than 750 MW,
BART must be determined in
accordance with guidelines
promulgated by EPA. That does not
obviate the need for the State to select
BART, after considering the five
statutory factors. And, it does not
remove EPA’s review role over SIP
submittals.
Comment: North Dakota has the
authority under the RHR to review the
new updated cost analyses provided by
URS and Golder Associates on behalf of
GRE.
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Response: Our action does not
prevent North Dakota from reviewing
GRE’s updated cost analyses, or from
submitting a revised SIP. States always
have the freedom to submit SIP
revisions to EPA. We need not speculate
in this action whether such a revision
would be approvable. However, such a
SIP revision is not the subject of this
action, and we are neither obligated nor
authorized to wait for such a revision
before we finalize our proposed action.
To the contrary, we have already
exceeded the statutory deadline for
promulgating a FIP or approving a SIP
for regional haze, and, under two
separate consent decrees, we must
finalize this action by March 2, 2012.
GRE acknowledged in a June 2011
email that it had made errors in its
original cost estimates for NOX BART
for CCS. The State relied on those
erroneous cost figures in its NOX BART
analysis and determination for CCS in
its RH SIP that it submitted on March
3, 2010. This is the main RH SIP
submittal that we are acting on today.
Because of the magnitude of these
acknowledged errors, it is appropriate to
disapprove the BART determination for
CCS 1 and 2 that is contained in the
March 3, 2010 submittal. We explain in
response to a prior comment why
selection of the presumptive limits
without a valid case-specific analysis
supporting such limits as BART is not
sufficient to meet the requirements of
the regional haze regulations. Based on
our disapproval of the SIP, and on
separate grounds related to our January
2009 finding of failure to submit, we are
authorized and obligated to promulgate
a FIP for NOX BART for CCS 1 and 2.
CAA section 110(c). We have
considered GRE’s revised cost analyses
in the context of our proposed FIP and
address those analyses in a subsequent
response.
Comment: Commenter stated that
EPA’s action is in violation of the 10th
amendment to the Constitution.
Response: Our action does not compel
North Dakota to enforce federal law and
does not intrude on authority reserved
to the states. Thus, our action is
consistent with the 10th amendment to
the Constitution.
Comment: Commenter stated that
EPA’s action is in violation of Article 4
of the Constitution.
Response: The comment does not
specify which aspect of Article 4 we are
alleged to have violated. However, we
conclude that our action does not
violate any aspect of Article 4 of the
Constitution.
Comment: Commenter stated that
Federal Land Managers (FLMs) are
using their Air Quality Related Values
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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
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reasons for disapproval therefore lack
basis.
Response: We fully explained the
basis for our proposed disapproval of
North Dakota’s interstate transport SIP
in our proposal. See 76 FR 58641–
58642. We have fully considered the
comments, but nothing in the comments
has caused us to change our views. As
we explained in our proposal, our 2006
guidance was premised on a certain set
of assumptions—in particular, that
states would submit their regional haze
SIPs by the regulatory deadline and that
the regional haze SIPs would be the
appropriate means for states to establish
that their SIPs contained adequate
provisions to prevent interference with
the visibility programs required in other
states. It turned out we were mistaken
in our assumptions, and we explained
in our proposal that subsequent events
have rendered our 2006 guidance
inappropriate in this specific action.
Thus, we appropriately and reasonably
evaluated the State’s interstate transport
SIP against the statutory requirements
and found it deficient. The State
disagrees with the way in which we
characterized the State’s transport SIP in
our proposal at 76 FR 58574, but we
were clear in our discussion later in our
notice that ‘‘North Dakota did not
explicitly state in its April 6, 2009,
submittal that it intended that its
Regional Haze SIP be used to satisfy the
visibility prong * * *’’ 76 FR 58641.
Basin Electric misrepresents our
proposed action. While we indicated
that the State had not explicitly
indicated that it was submitting the RH
SIP to meet the interstate transport
requirements, which left us in an
uncertain position, that was not the only
basis for our conclusion that the RH SIP
did not meet the transport requirements.
Instead, we stated, ‘‘Most importantly,
however, EPA must review the April 6,
2009 submission in light of the current
facts and circumstances, and the RH SIP
revision that the State ultimately
submitted does not fully meet the
substantive requirements of the regional
haze program * * * To the extent that
the State intended to meet the
requirement of section 110(a)(2)(D)(i)(II)
with the RH SIP, the RH SIP submission
itself is not fully approvable.’’ 76 FR
58642.
The State and Basin Electric assert
that we should approve the RH SIP as
satisfying the transport requirements
even though we are disapproving the
SIP as meeting regional haze
requirements. We disagree. Under the
suggested approach, EPA would
simultaneously codify in the Code of
Federal Regulations disparate and
conflicting requirements—the SIP limits
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and associated requirements (or in the
case of AVS, the lack thereof) for certain
EGUs and the FIP limits and associated
requirements for those same EGUs. This
could lead to confusion regarding the
requirements applicable to the
industrial sources affected, including
confusion in enforcement actions.
Accordingly, we have decided to
finalize our proposed disapproval of
North Dakota’s interstate transport SIP.
Comment: The NDDH commented
that EPA has not provided any credible
evidence that the additional emission
reductions from the FIP will produce
any discernible visibility improvement
in out-of-state Class I areas and has not
provided any credible evidence that
these additional emission reductions are
necessary to prevent North Dakota
sources from interfering with another
state’s ability to protect visibility.
Response: In our proposal, we did not
claim that our FIP to address the
requirements of CAA section
110(a)(2)(D)(i)(II) would result in
visibility improvement in out-of-state
areas. We did not have the time or
resources to re-do the WRAP modeling
that states in the region had relied on in
assessing the impacts of emissions
reductions and in setting their RPGs.
Instead, we noted that the emission
limits in our proposed FIP to address
certain deficiencies in the State’s BART
and reasonable progress measures in its
RH SIP would exceed the emissions
reductions for BART and reasonable
progress for these sources that had been
factored into the WRAP modeling for
RPGs. As a result, we concluded that the
limits in the FIP, in combination with
the measures in the SIP that we had
proposed to approve, would satisfy the
interstate transport requirements for
visibility. We continue to find that this
is a reasonable conclusion. Although
there may be other acceptable
approaches to satisfying the
requirements of CAA section
110(a)(2)(D)(i)(II) that would require
additional visibility modeling, the
approach that we have adopted does not
require that we assess through modeling
the visibility improvement that will
result from our FIP to assure that North
Dakota’s emissions do not interfere with
measures required in the plans of other
states to protect visibility.
3. Other General Legal Comments
Comment: Some commenters stated
that EPA cannot promulgate a FIP until
it has taken final action on the related
SIP.
Response: We have the authority to
promulgate a FIP concurrently with a
disapproval action. As has been noted
in past FIP promulgation actions, if EPA
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‘‘finds that a State has failed to make a
required submission * * * or * * *
disapproves a [SIP] in whole or in part,’’
CAA Section 110(c)(1) establishes a twoyear period within which we must
promulgate a FIP, and provides no
further constraints on timing. See, e.g.,
76 FR 25178, at 25202. North Dakota
failed to submit its RH SIP to us by
December 2007, as required by
Congress. Two years later, North Dakota
had still not submitted its RH SIP. When
we made a finding in 2009 that North
Dakota had failed to submit its RH SIP,
(see 74 FR 2392), that created an
obligation for us to promulgate a FIP by
January 2011. We are promulgating the
FIP concurrently with our disapproval
action because of the applicable
statutory deadlines requiring us at this
time to promulgate regional haze BART
determinations and reasonable progress
(RP) determinations to the extent North
Dakota’s BART and RP determinations
are not approvable.
We also note that North Dakota made
this same argument to the U.S. District
Court for the District of Colorado—in a
motion opposing entry of a consent
decree containing deadlines for EPA to
promulgate a FIP for regional haze for
North Dakota and in comments on the
proposed consent decree. The court
rejected North Dakota’s argument. First,
the court noted that we had proposed
action on North Dakota’s SIP in our
September 1, 2011 proposal and we
were, therefore, not proposing to take
final action on the regional haze FIP
before making a determination on North
Dakota’s SIP revision. Second, the court
indicated that we would be authorized
to promulgate the regional haze FIP
even without taking final action on
North Dakota’s SIP. As we had argued,
the court found that the duty to
promulgate a FIP (triggered by our 2009
finding of failure to submit an RH SIP)
remains ‘‘unless the State corrects the
deficiency, and the Administrator
approves the plan or plan revision,
before the Administrator promulgates
such [FIP].’’ Order Entering Consent
Decree, WildEarth Guardians v. Jackson,
Civil Action No. 11–cv–00001–CMA–
MEH, USDC Colorado, p. 17, citing CAA
section 110(c) (emphasis and brackets
added by the court).
Comment: Commenter stated that EPA
must review the ‘‘blanket five year
compliance date’’ to install and operate
BART to ensure that it is as expeditious
as practicable, as required by the CAA.
Response: We have reviewed the
compliance dates for meeting BART
limits that are contained in the portions
of the SIP we are approving and in the
FIP we are promulgating. These dates
are reasonable given the magnitude of
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the retrofits being undertaken. We note
that the State permits that we are
approving as part of this action provide
for compliance as expeditiously as
practicable, but in no event later than
five years.
C. Comments on Modeling
Comment: Several commenters
questioned aspects of the single-source
CALPUFF modeling that North Dakota
included in the SIP and which EPA
relied upon in our evaluation of
visibility impacts. Among other things,
commenters questioned (1) Whether
CALPUFF overestimates nitrate
formation, (2) whether newer versions
of CALPUFF would give more accurate
results, (3) the method for establishing
natural visibility background, (4) how to
establish ammonia background
concentrations, and (5) the method for
interpreting model results as they relate
to visibility improvement. The
commenters submitted revised singlesource CALPUFF modeling results to
address what they believed to be
deficiencies in the single-source
CALPUFF modeling that North Dakota
included in the SIP.
Response: While each of these
comments is addressed separately in
detailed responses below, a general
response is warranted. We note that
many of these comments were
submitted by Minnkota and Basin
Electric and were directed specifically
to EPA’s proposal regarding SCR at
MRYS 1 and 2 and LOS 2. As we have
explained, such comments are not
relevant to our final action. Nonetheless,
we are responding to most of the
comments in the event that they could
be interpreted as having broader
application to the assessment of
visibility improvement from potential
control options.
The second point we note is that the
source owners are essentially
questioning modeling that they
conducted and submitted to the State as
part of their BART evaluations, and that
the State specifically called for and
included in the SIP. The State
established procedures for single-source
BART modeling used to support its SIP
in the ‘‘Protocol for BART-Related
Visibility Impairment Modeling
Analyses in North Dakota’’ (the BART
modeling protocol). North Dakota RH
SIP, Appendix A.1. North Dakota
intended for the protocol to apply to
‘‘visibility modeling for both
identification of sources ‘subject to
BART’ (i.e., BART screening), and for
determining the degree of visibility
improvement related to the selection of
BART controls.’’ North Dakota RH SIP,
Appendix A.1, p. 1. In fact, North
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Dakota specifically stated: ‘‘[A]ll BARTrelated single-source modeling for
sources in North Dakota must follow the
protocol outlined here. Because of this
requirement, the NDDH will not expect
companies which operate BART-eligible
sources to provide individual protocols
for their BART-related modeling.’’ Id., p.
3. North Dakota’s protocol conforms to
the BART Guidelines.5 It also follows
recommendations for modeling long
range transport contained in 40 CFR
part 51, appendix W (‘‘The Guideline on
Air Quality Models’’) and EPA’s
Interagency Workgroup on Air Quality
Modeling (IWAQM) Phase 2 Summary
Report and Recommendations for
Modeling Long Range Transport
Impacts. Furthermore, as discussed in
Section 3 of the SIP, Plan Development
and Consultation, the protocol was
developed in consultation with EPA and
FLM meteorologists. Adherence to the
protocol ensures that a consistent
comparison of visibility improvement
can be made for potential control
technologies across different individual
units and different pollutants.
As the State’s single-source BART
modeling followed established guidance
and was developed in consultation with
FLMs and EPA, we find that it provides
a reasonable basis for making control
technology determinations. We do not
agree with the sources’ attempt to
deviate from the established protocol for
assessing visibility impacts. This is
because it would lead to a less
consistent and rational assessment of
potential control options. Nonetheless,
we have considered the revised singlesource modeling and the comments
submitted by the commenters in making
our final action. We conclude that
nothing contained in their modeling
analysis undermines the single-source
modeling that North Dakota included in
the SIP.
Comment: Two commenters stated
that the receptor-specific approach to
identifying the 98th percentile result in
CALPUFF is more technically correct
than the default day-specific approach.
The commenters also supplied revised
CALPUFF modeling based on the
receptor-specific approach. These
modeling results suggest that controls
would achieve less visibility
improvement than indicated by North
Dakota’s single-source BART modeling.
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.
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Response: We do not agree that the
receptor-specific approach is more
technically correct; it is not part of the
standard CALPUFF model and merely
serves to decrease the conservatism of
the model predictions through the
creation of 98th percentile values that
are specific to specific receptor
locations within a Class I area. The
standard CALPUFF approach considers
the daily impacts within a Class I area
at all receptor points; i.e., the model
predicts the highest daily value for each
day of the year from all receptors within
a Class I area. The 98th percentile
reflects the eighth highest of these daily
values.
In its BART modeling protocol, North
Dakota stated that ‘‘the context of the
98th percentile 24-hour delta-deciview
prediction is with respect to days of the
year, and is not receptor specific.’’ RH
SIP, Appendix A.1, Section 4.0, p. 50.
In addition, in establishing the 98th
percentile as a reasonable contribution
threshold in the BART Guidelines, EPA
intended that the day-specific, or ‘‘dayby-day,’’ approach be used. 70 FR
39121. This was the approach EPA
considered appropriate to account for
the assumptions and uncertainties in
CALPUFF; the receptor-specific
approach goes beyond what EPA
considers appropriate to address these
assumptions and uncertainties and
would undermine the goal of achieving
natural visibility conditions. Therefore,
we do not consider the revised
CALPUFF modeling results based on the
flawed receptor-specific approach that
were submitted by the commenters to be
useful in assessing visibility impacts..
Comment: Several of the commenters
argue that it is inappropriate to evaluate
visibility impacts in comparison to
natural background visibility
conditions. Instead, the commenters
propose to evaluate visibility impacts in
comparison to current, degraded
visibility conditions. The commenters
further argue that EPA’s use of natural
conditions is inconsistent with section
169A of the CAA and that EPA should
amend its BART Guidelines to use
current, degraded visibility conditions.
Response: We disagree. EPA’s
approach is consistent with Congress’s
intent in passing section 169A, and the
proposal to use degraded visibility
conditions is inconsistent with section
169A. Visibility impacts must always be
evaluated relative to some reference
visibility condition, and a given
reduction in ambient PM2.5 will result in
smaller relative improvement in
visibility when compared to polluted
conditions versus clean conditions.
Because current degraded visibility
conditions are considerably worse than
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natural background visibility,
comparison of a BART source’s impact
relative to current degraded visibility
conditions would result in a smaller
relative benefit than would a
comparison relative to natural
background visibility. EPA previously
considered and responded to the same
comment in 40 CFR part 51, appendix
Y, promulgated at 70 FR 39104, July 6,
2005. After receiving this comment on
the BART Guidelines, EPA considered
the approach of assessing a BARTeligible source’s impacts on visibility by
using current or near-term future
conditions, and EPA determined that
BART visibility impacts should be
evaluated in comparison to natural
background visibility. In the final
rulemaking EPA wrote (70 FR 39124):
‘‘Using existing conditions as the baseline
for single source visibility impact
determinations would create the following
paradox: the dirtier the existing air, the less
likely it would be that any control is
required. This is true because of the
nonlinear nature of visibility impairment. In
other words, as a Class I area becomes more
polluted, any individual source’s
contribution to changes in impairment
becomes geometrically less. Therefore the
more polluted the Class I area would become,
the less control would seem to be needed
from an individual source. We agree that this
kind of calculation would essentially raise
the ‘‘cause or contribute’’ applicability
threshold to a level that would never allow
enough emission control to significantly
improve visibility. Such a reading would
render the visibility provisions meaningless,
as EPA and the States would be prevented
from assuring ‘‘reasonable progress’’ and
fulfilling the statutorily-defined goals of the
visibility program. Conversely, measuring
improvement against clean conditions would
ensure reasonable progress toward those
clean conditions.’’
See, also, Memorandum from Gail
Tonnesen, Regional Modeler, to North
Dakota Regional Haze File, dated
September 1, 2011, regarding ‘‘Modeling
Single Source Visibility Impacts.’’ This
memorandum is included in Appendix
B of the Technical Support Document
(TSD) for this action.
Comment: Two commenters
performed new CALPUFF simulations
using EPA’s current regulatory version
5.881 and submitted these modeling
results to EPA during the comment
period. The commenters found lower
visibility impacts using CALPUFF
version 5.8 than did the State with an
earlier CALPUFF version 5.711a.
Response: For these new model
results, the commenters did not submit
a modeling protocol for EPA review and
did not provide a complete copy of the
CALPUFF input and output files. As a
result, EPA was not able to fully review
the data sets used in this modeling.
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Moreover, while EPA did approve the
use of the Rapid Update Cycle
meteorology for modeling the Heskett
facility, EPA has not approved this
alternate modeling protocol for other
BART sources in North Dakota and has
not reviewed or approved other
modifications to the modeling approach
that the commenters used in developing
new CALPUFF results.
From the information that the
commenters provided, EPA determined
that the differences in the new
CALPUFF version 5.8 modeling results
are due in part to a change in the natural
background visibility that was used in
the modeling analysis. The State’s
modeling protocol called for use of the
20% best natural visibility days in its
BART analysis while the commenters’
new CALPUFF version 5.8 analysis used
the annual average natural visibility
days. If the commenters had adopted the
same approach as North Dakota and
compared CALPUFF version 5.8
visibility impacts to the 20% best
natural visibility days, the results of the
new analysis would have been more
similar to the original modeling
performed by North Dakota.
We do not find that the commenters’
new modeling demonstrates that singlesource modeling performed according to
North Dakota’s BART modeling protocol
should be disregarded. That modeling
was conducted using the latest version
of CALPUFF that was available at the
time, and we are approving the great
majority of North Dakota’s BART
determinations that relied on results
from that modeling. In our FIP, in which
we are merely filling gaps in the SIP, we
are not required to conduct new
modeling using CALPUFF version 5.8 or
disregard the results of the modeling
conducted using CALPUFF version
5.711a. In fact, we find the better course
is to rely on modeling based on the
same version of the model that the State
employed to ensure we are using a
consistent comparison. See, Mont.
Sulphur & Chem. Co. v. United States
EPA, 2012 U.S. App. LEXIS 1056 (9th
Cir. Jan. 19, 2012).
Comment: The commenters argue that
CALPUFF overstates visibility impact
due to the complexity of the chemistry
affecting visibility impairment and that
EPA acknowledges that ‘‘the simplified
chemistry in the [CALPUFF] model
tends to magnify the actual visibility
effects of [a] source.’’ 70 FR 39121. The
commenters further state that when EPA
adopted the BART Guidelines, EPA
concurred with ‘‘the concerns of
commenters that the chemistry modules
of the CALPUFF model are less
advanced than some of the more recent
atmospheric chemistry simulations.’’ Id.
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at 39123. The commenters also assert
that several published papers or
presentations show that CALPUFF over
predicts nitrate by a factor of 2 to 4 in
the winter.
Response: For the reasons already
stated, EPA’s reliance on the CALPUFF
modeling results that the State included
in the SIP is reasonable. In addition,
EPA has acknowledged that the
simplified chemistry used in the
CALPUFF model creates uncertainty in
the accuracy of the model for predicting
visibility impacts for pollutants such as
NOX that are converted from the gas
phase to aerosol through complex
photochemical reactions. However, it is
uncertain whether the simplified
chemistry will always overpredict
visibility impacts. For example,
Anderson et al. (2010) 6 found that the
CALPUFF model frequently predicted
lower nitrate concentrations compared
to the Comprehensive Air Quality
Model (CAMx) photochemical grid
model, which has a much more rigorous
treatment of photochemical reactions.
EPA recognized the uncertainty in the
CALPUFF modeling results, and EPA
made the decision in the final BART
guidelines that the model should be
used to estimate the 98th percentile
visibility impairment rather than the
highest daily impact value as proposed.
70 FR 39121. We made the decision to
consider the less conservative 98th
percentile (i.e., the eighth highest 24hour deciview impact in a year rather
than the highest) primarily because the
chemistry modules in the CALPUFF
model are simplified and might in some
cases predict a maximum 24-hour
impact that is an ‘‘outlier.’’ Id. If recent
updates to CALPUFF cause the model to
predict lower visibility impacts, the use
of the updated model might also require
EPA to reconsider the choice of the less
conservative 98th percentile for
evaluating visibility impacts. In any
event, our reliance on CALPUFF
modeling is reasonable for the reasons
discussed above.
Comment: Several commenters
suggested that the State has unlimited
discretion to consider visibility or cost
or other factors in any way it wishes,
even in ways that are inaccurate or
inconsistent with the purpose of the
CAA.
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. https://
www.cmascenter.org/conference/2010/agenda.cfm.
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Response: We disagree. We have
already largely addressed the assertions
in this comment in our responses to
comments on our legal authority.
Furthermore, as a hypothetical example,
EPA would not defer to a state
determination that the remaining useful
life of a source is one year if relevant
evidence indicates the remaining useful
life is 20 years. Limits on state
discretion are inherent in the CAA and
our regulations; otherwise, states would
be free to reach decisions that are
arbitrary and capricious or inconsistent
with the purpose behind the CAA and
EPA’s regulations. As we have stated,
North Dakota’s cumulative modeling
approach thwarts the goal stated by
Congress in CAA section 169A and
underlying the RHR.
Comment: One commenter claimed
that pictorial examples demonstrate that
the visibility benefits which EPA claims
can be achieved with NOX control
technologies are not perceptible. The
commenter compares archived pictures
copied from the National Park Service
(NPS) Web site, along with the
monitored haze index, for days having
varying levels of visibility impairment.
For example, the commenter compares
two pictures from different days for
which the haze index changes by 1.26
deciviews and concludes that ‘‘no
perceptible difference can be seen
* * *’’
Response: We do not expect that a 1.0
deciview change in visibility, which is
considered a ‘‘small but noticeable
change in haziness under most
circumstances’’ (64 FR 35725), could be
easily perceived in a small picture on
the printed page. Moreover, North
Dakota did not provide visibility
improvement relative to a pre-control
baseline as recommended by the BART
guideline (70 FR 39170), so many of the
estimates of visibility improvement
contained in the SIP are misleadingly
low. Regardless, the BART Guidelines
establish that predicted visibility
improvement below perceptibility
thresholds does not provide a basis to
automatically eliminate a control
option: ‘‘Even though the visibility
improvement from an individual source
may not be perceptible, it should still be
considered in setting BART because the
contribution to haze may be significant
relative to other source contributions in
the Class I area. Thus, we disagree that
the degree of improvement should be
contingent upon perceptibility. Failing
to consider less-than-perceptible
contributions to visibility impairment
would ignore the CAA’s intent to have
BART requirements apply to sources
that contribute to, as well as cause, such
impairment.’’ 70 FR 39129. The
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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
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7 Guidance
for Estimating Natural Visibility
Conditions Under the Regional Haze Rule, U.S.
Environmental Protection Agency, September 2003.
https://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
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the BART guidelines (70 FR 39124)
describes an approach used to measure
progress toward natural visibility in
Mandatory Class I Areas that includes a
URP toward natural conditions for the
20 percent worst days and no
degradation of visibility on the 20
percent best days. The use of the 20
percent worst natural conditions days in
the calculation of the URP takes into
consideration visibility impairment
from wild fires, windblown dust and
other natural sources of haze. The
‘‘Guidance for Estimating Natural
Visibility’’ also discusses the use of the
20 percent best and worst estimates of
natural visibility, provides for revisions
to these estimates as better data becomes
available,8 and discusses possible
approaches for refining natural
conditions estimates (pages 3–1 to 3–4).
For the evaluation of visibility
impacts for BART sources, EPA
recommended the use of the natural
visibility baseline for the 20% best days
for comparison to the ‘‘cause or
contribute’’ applicability thresholds.
This estimated baseline is reasonably
conservative and consistent with the
goal of attaining natural visibility
conditions. While EPA recognizes that
there are natural sources of haze, the use
of the 20% worst natural visibility days
is inappropriate for the ‘‘cause or
contribute’’ applicability thresholds. For
example, if BART source visibility
impacts were evaluated in comparison
to days with very poor natural visibility
resulting from nearby wild fires or dust
storms, the BART source impacts would
be significantly reduced relative to these
poor natural visibility conditions and
would not be protective of natural
visibility on the best 20% days.
The commenter and the cited report
on natural visibility by Robert Paine
appear to suggest that EPA requires the
use of the best 20% visibility days for
all aspects of visibility analysis. This
does not accurately characterize EPA’s
recommended use of the 20% worst
natural visibility days for URP
calculations and the 20% best natural
visibility days for the ‘‘cause or
contribute’’ applicability thresholds. For
example, natural visibility conditions at
the Badlands National Park for the best
20%, annual average, and worst 20%
natural visibility days are 2.9, 5.0, and
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.’ ’’
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20909
8.1 deciviews, respectively.9 By
contrast, current visibility conditions at
the Badlands National Park for the best
20%, annual average, and worst 20%
days are 6.9, 11.6 and 17.1 deciviews,
respectively. The URP calculation uses
the worst 20% natural visibility value of
8.1 deciviews, and this value adequately
represents the impacts of natural
sources of visibility impairment.
Finally, as part of the settlement of a
case brought by the Utility Air
Regulatory Group challenging the BART
Guidelines,10 EPA agreed to issue
guidance clarifying that states may use
either the 20% best or the annual
average in estimating natural visibility
in the evaluation of a BART source’s
impacts. This guidance makes clear that
states have the flexibility to use either
approach in estimating natural
background conditions. The State was
not required to use the annual average
and did not. Similarly, in issuing a FIP,
we are not required to use the annual
average either.
The commenter cited modeling
studies that purportedly show that the
model-predicted natural haze levels are
substantially larger than the natural
haze levels used by EPA. In fact, the
results of those studies compare well
with EPA’s natural background levels.
The modeling study by Tonnesen et
al.11 predicted annual average natural
PM2.5 concentrations in North Dakota in
the range of 1.9 to 2.5 ug/m3, while the
Koo et al. study 12 predicted annual
average natural PM2.5 concentrations in
the range of 2.5 to 3.1 ug/m3 in North
Dakota. These model estimates are
consistent with EPA’s estimated 2.6 ug/
m3 annual average PM2.5 concentration
at Class I Areas in western North
Dakota.
Comment: One commenter felt that
EPA’s decision appears to be driven by
its desired outcome—more emission
reductions—and not by any legal basis
for disapproving the North Dakota SIP.
Response: Our decision is driven by
our interpretations of the CAA and our
9 Natural
Haze Levels II Committee Report.
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.
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. https://pah.cert.ucr.edu/aqm/308/
reports/final/2006/WRAPRMC_2006_report_FINAL.pdf.
12 Koo, B.; Chien, C.J.; Tonnesen, G.; Morris, R.;
Johnson, J.; Sakulyanontvittaya, T.; Piyachaturawat,
P.; Yarwood, G.; Natural emissions for regional
modeling of background ozone and particulate
matter and impacts on emissions control strategies,
Atmos. Env., 44:19, 2372–2382.
10 Settlement
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regulations. We note that we are
approving the vast majority of North
Dakota’s decisions.
Comment: One commenter stated that
EPA should not ignore two of the three
years of CALPUFF modeling results in
our review of modeling results
presented by North Dakota. The
commenter suggested that this is
inconsistent with EPA’s typical practice
of using long-term averages when
addressing regional haze as is necessary
to prevent undue influence from shortterm events or unusual meteorological
events.
Response: In our review of the singlesource CALPUFF modeling results
presented by North Dakota, we cited the
change in the maximum 98th percentile
impact over the modeled three year
meteorological period (2001–2003). As
the 98th percentile value is intended to
reflect the 8th high value in any year,
it already eliminates 7 days per year
from consideration in order to account
for short-term events, unusual
meteorological conditions, and any
over-prediction bias in the model.
Therefore, the modeling results which
we cited in our proposal are designed to
exclude influence from unusual events
or meteorological conditions and are
sufficient to address the commenter’s
concerns. We also note that our
approach is consistent with the method
used by North Dakota in identifying
subject-to-BART sources where a source
is considered to contribute to
impairment if it ‘‘exceeds the threshold
when the ninety-eighth percentile of the
modeling results based on any one year
of the three years of meteorological data
modeled exceeds five-tenths
deciviews.’’ North Dakota RH SIP, p. 63.
We find that this is a reasonable method
for the purposes of evaluating visibility
improvements associated with potential
control options.
Comment: Commenters stated that
EPA should not ignore the 90th
percentile impact in our review of the
CALPUFF visibility results presented by
North Dakota.
Response: In the BART Guidelines,
EPA addressed the appropriate
interpretation of CALPUFF modeling
results within the context of subject-toBART modeling. We rejected the use of
the 90th percentile because it would be
inconsistent with the Act: ‘‘The use of
the 90th percentile value would
effectively allow visibility effects that
are predicted to occur at the level of the
threshold (or higher) on 36 or 37 days
a year. We do not believe that such an
approach would be consistent with the
language of the statute.’’ 70 FR 39121.
On the same page, EPA explained that
the 98th percentile was sufficient to
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account for any overestimation of
visibility benefits by CALPUFF.
While the BART Guidelines do allow
states to consider the ‘‘frequency,
duration, and intensity’’ of a source’s
visibility impact when making control
determinations, the use of the 90th
percentile would over-compensate for
any uncertainties in CALPUFF and
would underestimate visibility benefits
from potential control options and
unduly bias the resulting analysis.
When the 90th percentile is used to
assess predicted visibility improvement
from a potential control option, the 37th
or 38th highest predicted improvement
value from 365 predicted daily values is
selected; higher predicted improvement
values on 36 or 37 days a year are
ignored. This is not rational. In the
actual BART determination, a state
could so dilute the predicted visibility
improvement, one of the very goals of
CAA section 169A, as to nullify its
initial determination using the 98th
percentile that the source is subject to
BART. Accordingly, the BART
guidelines specifically mention the use
of the 98th percentile as an option to
compare pre- and post-control modeling
runs; use of the 90th percentile is not
mentioned. 70 FR 39170. Moreover, the
FLMs have affirmed the use of the 98th
percentile in their most recent guidance
for evaluating visibility impacts at Class
I areas. FLAG 2010, p. 23.13
Comment: One commenter stated that
CALPUFF overpredicts visibility
impacts associated with nitrates due to
incorrect (too high) ammonia
background. The commenter stated that
monitored background ammonia data
from Wyoming shows lower
concentrations. The commenter also
cites a study by Colorado Department of
Public Health and Environment
(CDPHE) related to the sensitivity of the
CALPUFF model to ammonia
background concentrations.
Response: The monthly ammonia
background concentrations used by
North Dakota were derived from data
collected at the State’s only ammonia
monitor located near Beulah and range
from a low of 0.98 ppb to a high of 2.29
ppb. (BART modeling protocol, Table 3–
4). Due to their proximity to the North
Dakota sources and Class I areas, the
Beulah ammonia background
concentrations are clearly more
representative than those which the
commenter cites for Wyoming that
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.
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‘‘were on the order of only 0.1 ppb.’’ We
also note that, in its revised modeling,
the commenter did not use alternate
ammonia background concentrations
that would differ from those used by
North Dakota.
With regard to the ammonia
background sensitivity study conducted
by CDPHE,14 the commenter has not
shown that the study is relevant to
North Dakota. CDPHE found that
visibility impacts are ‘‘not very sensitive
to the background ammonia
concentration across the range from 1.0
ppb to 100.0 ppb.’’ Id at 24. Therefore,
we disagree with the commenter’s
assertion that CALPUFF overpredicts
visibility impacts associated with
nitrates due to incorrect (too high)
ammonia background.
Comment: One commenter cited a
paper by Terhorst and Berkman (2010)
regarding the impact of the Mohave
Generating Station (MGS), also known
as the Mohave Power Project (MPP), on
visibility in the Grand Canyon. The
MGS was located about 115 km from the
Grand Canyon National Park (‘‘GCNP’’)
and was shut down in 2005. Based on
measured values, and after controlling
for the prevailing environmental and
anthropogenic factors in the region, the
authors found virtually no evidence that
the MGS closure improved visibility in
the GCNP or that the plant’s operation
degraded it. This was in contrast to air
quality transport models, including
CALPUFF, that predicted visibility
would have improved by 5% or more
after closure.
Response: For the reasons stated in
our responses to comments earlier in
this section, our reliance on the
CALPUFF modeling the State submitted
in the SIP is reasonable. In addition, the
study by Terhorst and Berkman does not
convince us that use of CALPUFF
modeling is inappropriate for this action
or that the CALPUFF modeling results
should be ignored. A model such as
CALPUFF essentially holds constant a
number of factors in order to isolate the
impacts of a single source. As
acknowledged by the study’s authors, it
is extremely difficult in observational
analyses to sufficiently control for all
factors, including emissions from other
sources, to be able to isolate the impacts
of closure of a facility, especially one
located over 100 km from the Class I
area at issue. In fact, the paper notes
that coarse soil mass impacts are an
omitted variable in the analytical
analysis and that changes in those
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.
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emissions may have counteracted the
visibility improvements expected from
the source shutdown.
Comment: One commenter noted that
the BART Guidelines allows states to
consider if the time of year is important
(e.g., high impacts are occurring during
tourist season)’’. 70 FR 39130. The
commenter provided information that
shows that 85% of all visits to Theodore
Roosevelt National Park (TRNP) occur
during the period from mid-May to midOctober but that nitrate concentrations
measured at TRNP and Lostwood
Wilderness Area (LWA) during this
period are extremely low.
Response: We agree that our BART
guidelines acknowledge that states may
consider the timing of impacts in
addition to other factors related to
visibility impairment. However, states
are not required to do so, and to our
knowledge, this was not part of North
Dakota’s analysis. We are not required
to substitute a source’s desired exercise
of discretion for that of the State’s.
Furthermore, for purposes of our FIP,
we stand in the shoes of the State. In
that capacity, we are not required to
consider the seasonality of impacts, and
we have chosen not to. The experience
of visitors who come to the Class I areas
in North Dakota during periods other
than mid-May to mid-October is not
discounted.
As a factual matter, the commenter’s
assertions are misleading. A review of
the Interagency Monitoring of Protected
Visual Environments (IMPROVE)
monitoring data on the WRAP Technical
Support System 15 reveals that
significant nitrate impacts occur during
periods of high visitation at TRNP. For
example, the contribution to visibility
impairment from nitrates in May and
October of 2002 was 26.9% and 37.9%,
respectively. There was also relatively
high visitation to the Park during these
months.16
Also, the commenter’s reference to 40
CFR 51.301’s definition of ‘‘adverse
impact on visibility’’ is misplaced. This
term is defined for purposes of 40 CFR
51.307 only and is not used in 40 CFR
51.308. Section 51.307 applies to new
source review only, not to the regional
haze program.
Comment: One commenter states that
further controlling NOX emissions from
North Dakota sources would not
advance the goal of improving visibility.
The commenter bases this statement on
(1) back trajectory analysis that shows
that emissions from North Dakota point
15 https://vista.cira.colostate.edu/tss/Results/
HazePlanning.aspx.
16 https://www.nature.nps.gov/stats/
park.cfm?parkid=467.
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sources only impact TRNP and LWA a
small part of the time, and (2) a
modeling study of large North Dakota
point sources of NOX emissions that
followed North Dakota’s 2005 EPAapproved protocol and shows that these
sources contribute a very small fraction
of light extinction attributable to
nitrates.
Response: We disagree that
controlling large NOX point sources in
North Dakota will not advance the goal
of improving visibility.
IMPROVE monitoring data shows that
nitrates (from all sources) are among the
highest contributors to visibility
impairment at TRNP and LWA on the
worst 20% visibility days. The
contribution to visibility impairment
from nitrate at TRNP from 2000–2004
ranged between 13.8% and 24.1%, with
nitrate contributing more than any other
pollutant in 2001 and 2002. Similarly,
the contribution to visibility impairment
from nitrate at LWA from 2000–2004
ranged between 19.2% and 31.5%, with
nitrate contributing more than any other
pollutant in 2004.
In order to help states identify the
origins of haze-forming pollutants, such
as nitrates, the WRAP conducted source
apportionment analyses that identify the
contribution from source regions and
types to specific Class I areas. These
source apportionment methods
included CAMx Particle Source
Apportionment Technology (PSAT) and
the Weighted Emissions Potential
(WEP). Both of these analysis tools can
be found on the WRAP Technical
Support System.17 As described below,
these analyses clearly demonstrate that
North Dakota point sources are among
the largest contributors to nitrates at
TRNP and LWA on the 20% worst
visibility days.
PSAT is a tracer analysis approach
that utilizes a mass-tracking algorithm
in the CAMx air quality model to
explicitly track the chemical
transformations, transport, and removal
of haze-forming pollutants associated
with a particular source region, source
type, or combination of the two. The
WRAP PSAT results demonstrate that in
2002, North Dakota point sources were
the third and fifth largest contributors to
nitrate on the worst 20% visibility days
at TRNP and LWA, respectively (see
charts and tables contained in docket).
The WEP analysis relies on an
integration of gridded emissions data,
back trajectory residence time data, a
one-over-distance factor to approximate
deposition, and a normalization of the
final results. This method does not
17 https://vista.cira.colostate.edu/tss/Results/
HazePlanning.aspx.
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20911
produce highly accurate results because,
unlike the CAMx air quality model and
associated PSAT analysis, it does not
account for chemistry and removal
processes. Nonetheless, it is more
informative than the simpler back
trajectory analysis submitted by the
commenter because WEP incorporates
gridded emissions in addition to back
trajectory. The WRAP WEP results show
that the grid cells in which the North
Dakota BART sources are located have
among the highest potential to
contribute to nitrate on the worst 20%
visibility days at TRNP and LWA (see
graphics contained in docket).
Based on the WRAP source
apportionment analyses, we find that
there is ample evidence to conclude that
further controlling NOX emissions from
North Dakota point sources would
advance the goal of improving visibility.
Comment: One commenter submitted
new single-source modeling for the AVS
units that are subject to reasonable
progress. The new modeling included
results based on the current EPAapproved version of CALPUFF and use
of annual average natural background
conditions.
Response: In our proposal, we noted
that North Dakota provided modeling
results showing a ‘‘visibility
improvement of 0.754 deciviews at
Theodore Roosevelt [2002] from the
installation of LNB for both units
combined.’’ 76 FR 58632. The
commenter’s new modeling for the two
units combined shows a visibility
improvement of 0.39 deciviews at
Theodore Roosevelt (98th percentile,
2002). As we have stated elsewhere in
response to comments, EPA has not
reviewed or approved the specific
modeling methodology used by the
commenter for AVS; because the newly
submitted modeling uses annual average
natural background conditions, it is not
consistent with North Dakota’s protocol
for single-source modeling in the BART
context. In our consideration of
visibility improvement as an additional
factor to the statutory and regulatory
reasonable progress factors, we are not
convinced that we must disregard North
Dakota’s visibility improvement value of
0.754 deciviews in favor of the
commenter’s lower estimate. For
reasons already explained, we find it
reasonable to continue to consider and
rely on single-source CALPUFF
modeling that has been conducted in
accordance with North Dakota’s
modeling protocol for BART sources.
However, even if we were required to
consider the commenter’s new modeling
results, they would not cause us to
change our opinion about our
disapproval of the State’s determination
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that no NOX controls are needed at AVS
1 and 2 for purposes of reasonable
progress or our determination that LNB
must be installed for purposes of
reasonable progress. The costs for LNB
are very reasonable—$586 and $661 per
ton for AVS 1 and 2, respectively. This
is well below cost effectiveness values
the State found reasonable in making
some of its BART determinations. Also,
the AVS units are not small EGUs. To
the contrary, at 435 MW apiece, they are
comparable to some of the larger EGUs
in the State, and their NOX emissions
are considerably greater than emissions
from some other EGUs in North Dakota.
North Dakota predicted that LNB at AVS
would achieve NOX reductions of about
3,500 tons per unit per year. These
reductions are substantially greater than
those that will be achieved at the
Stanton Station (maximum reduction of
983 tons per year, based on firing of
lignite) and LOS 1 (reduction of 1,246
tons per year reduction), where the State
selected SNCR as BART, and
significantly greater than the reductions
that will be achieved at CCS (reduction
of 2,572 tons per year, based on our
FIP), the largest EGU in the State.
Finally, even the commenter’s new
modeling predicts combined visibility
improvement of 0.39 deciviews for LNB
on both units. Even if one were to
consider this on a unit-by-unit basis, 0.2
deciviews per unit is significant, and we
find that this level of visibility
improvement, when considered along
with the four statutory factors under
reasonable progress, would continue to
support our selection of LNB for AVS 1
and 2.
Comment: One commenter stated that:
‘‘EPA has no basis in law for rejecting
the cumulative modeling performed by
the State for AVS since, as EPA admits,
there is no requirement that visibility
impacts be addressed under a fourfactor analysis for a reasonable progress
source. That is, there is no authority that
precludes the State from modeling the
way it did.’’ In addition, EPA ignores
the fact that reasonable progress is not
the same as BART.
Response: The following language
from 40 CFR 51.308(d)(1)(ii) applies
because North Dakota established a RPG
that provides for a slower rate of
progress than would be needed to attain
natural conditions by 2064:
[T]he State must demonstrate, based on the
factors in paragraph (d)(1)(i)(A) of this
section, that the rate of progress for the
implementation plan to attain natural
conditions by 2064 is not reasonable; and
that the progress goal adopted by the State is
reasonable.
The factors in paragraph (d)(1)(i)(A)
are ‘‘the costs of compliance,’’ ‘‘the time
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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
18 Memorandum
from Gail Tonnesen, Regional
Modeler, to North Dakota Regional Haze File, dated
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interpretation, as expressed in the BART
Guidelines, applies with equal force to
single-source analysis of potential
control options in the reasonable
progress context. In the BART
Guidelines, we said the following:
In establishing the goal of natural
conditions, Congress made BART applicable
to sources which ‘may be reasonably
anticipated to cause or contribute to any
impairment of visibility at any Class I area.’
Using existing conditions as the baseline for
single source visibility impact
determinations would create the following
paradox: the dirtier the existing air, the less
likely it would be that any control is
required. This is true because of the
nonlinear nature of visibility impairment. In
other words, as a Class I area becomes more
polluted, any individual source’s
contribution to changes in impairment
becomes geometrically less. Therefore the
more polluted the Class I area would become,
the less control would seem to be needed
from an individual source. We agree that this
kind of calculation would essentially raise
the ‘cause or contribute’ applicability
threshold to a level that would never allow
enough emission control to significantly
improve visibility. Such a reading would
render the visibility provisions meaningless,
as EPA and the States would be prevented
from assuring ‘reasonable progress’ and
fulfilling the statutorily-defined goals of the
visibility program. Conversely, measuring
improvement against clean conditions would
ensure reasonable progress toward those
clean conditions.
70 FR 39124.
In other words, it is our interpretation
that North Dakota, if it wished to
consider visibility improvement in
single-source modeling of potential
control options, could only reasonably
do so by modeling those controls against
natural background conditions. Thus,
we reject the commenter’s assertion. As
we stated in our proposal, the statutory
and regulatory goal is reasonable
progress toward natural visibility
conditions, not to preserve degraded
conditions. 76 FR 58629. The State’s
and commenter’s approach resulted in
the rejection of very effective and
inexpensive controls, and that approach
could be used to preclude adoption of
controls indefinitely. For the reasons
expressed here and in our proposal, that
is not reasonable.
Comment: Two commenters stated
that EPA should consider the dollars per
deciview ($/deciview) as a measure
when making either BART or reasonable
progress determinations. Both
commenters suggested that EPA relied
too heavily on cost effectiveness in
evaluating control options. And both
commenters claimed that EPA has
September 1, 2011, regarding ‘‘Modeling Single
Source Visibility Impacts.’’ This memorandum is
included in Appendix B of the TSD for this action.
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endorsed the dollar per deciview
approach, citing relevant BART and
reasonable progress guidance.
Response: For BART, the BART
Guidelines require that cost
effectiveness be calculated in terms of
annualized dollars per ton of pollutant
removed, or $/ton. 70 FR 739167. The
commenters are correct in that the
BART Guidelines list the $/deciview
ratio as an additional cost effectiveness
metric that can be employed along with
$/ton for use in a BART evaluation.
However, the use of this metric further
implies that additional thresholds or
notions of acceptability, separate from
the $/ton metric, would need to be
developed for BART determinations. We
have not used this metric for BART
purposes because (1) It is unnecessary
in judging the cost effectiveness of
BART, (2) it complicates the BART
analysis, and (3) it is difficult to judge.
In particular, the $/deciview metric has
not been widely used and is not wellunderstood as a comparative tool. In our
experience, $/deciview values tend to
be very large because the metric is based
on impacts at one Class I area on one
day and does not take into account the
number of affected Class I areas or the
number of days of improvement that
result from controlling emissions. In
addition, the use of the $/deciview
suggests a level of precision in the
CALPUFF model that may not be
warranted. As a result, the $/deciview
can be misleading. We conclude that it
is sufficient to analyze the cost
effectiveness of potential BART controls
using $/ton, in conjunction with an
assessment of the modeled visibility
benefits of the BART control. We also
note that North Dakota did not rely on
the $/deciview metric in its evaluation
of BART controls.
Within the context of reasonable
progress, the Guidance for Setting
Reasonable Progress Goals Under the
Regional Haze Program, page 5–2, states
that ‘‘[y]ou should evaluate both average
and incremental costs.’’ This is
consistent with the approach under
BART. As commenters note, the
guidance then states that ‘‘simple cost
effectiveness estimates based on a
dollar-per-ton calculation may not be as
meaningful as a dollar-per-deciview
calculation, especially if the strategies
reduce different groups of pollutants.’’
However, the guidance makes this
statement on the basis that ‘‘different
pollutants differently impact visibility
impairment.’’ That is, for example, a one
ton reduction in SO2 would have a
greater visibility benefit than a one ton
reduction of coarse mass. As only SO2
and NOX controls were evaluated for the
reasonable progress point sources, and
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these pollutants have similar impacts on
visibility (per the IMPROVE equation),19
the use of the $/deciview is not
particularly relevant or informative. In
addition, we did not use the $/deciview
metric for our evaluation of RP controls
for largely the same reasons as stated
above for BART controls. As we noted
in our proposal, ‘‘it is important to
recognize that dollars per deciview
values will always be significantly
higher, often by several orders of
magnitude, than the more commonly
used and understood dollars per ton
values.’’ 76 FR 58630. North Dakota’s
use of current degraded background in
its modeling for potential single-source
control options had the effect of greatly
increasing the disparity between $/
deciview and $/ton values because the
modeling significantly underestimated
the benefits of controls.
Comment: Commenters performed
CALPUFF simulations using a revised
CALPUFF version 6.4 that includes
updates to the chemical and particle
transformations and submitted these
results to EPA during the comment
period.
Response: We have already explained
why we may reasonably rely on the
modeling performed in accordance with
the State’s BART modeling protocol. We
have additional reasons for disagreeing
that the newer CALPUFF version 6.4
results should be used in this action to
determine potential visibility impacts.
The newer version of CALPUFF has not
received the level of review required for
use in regulatory actions subject to EPA
approval and consideration in a BART
decision making process. Based on our
review of the available evidence, we do
not consider CALPUF version 6.4 to
have been shown to be sufficiently
documented, technically valid, and
reliable for use in a BART decision
making process. In addition, the
available evidence would not support
approval of these models for current
regulatory use. The newer versions of
the model introduce additional
chemical mechanisms that have not
gone through the public review process
required for approval by the Agency.
Comment: North Dakota’s proposed
RH SIP emission reductions are
sufficient to meet the CAA’s visibility
objectives relative to the 2018
milestone. North Dakota’s BART
emission reductions properly and
effectively reduce statewide haze
production by more than the 23.3%
fraction of the 60-year RHR timeline (by
2018). EPA improperly asserts that
North Dakota cannot meet the 2018
19 See Appendix A of our TSD for detailed
explanation of the IMPROVE equation.
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URP. In fact, the infrequency of the
winds blowing the major emission
source plumes toward the Class I areas
and the zero progress toward controlling
Canadian and uncontrollable emissions
(such as wildfires and windblown dust)
are the cause of the inability for North
Dakota to meet the 2018 milestone goal,
not in-state source emissions. EPA
should not penalize North Dakota and
reject its RH SIP because North Dakota
cannot control impacts from sources
beyond its control. In fact, the RHR and
the UARG settlement with EPA in 2006
state that, ‘‘EPA does not expect States
to restrict emissions from domestic
sources to offset the impacts of
international transport of pollution.’’
Response: Contrary to the
commenter’s assertion, the Class I areas
in North Dakota will not meet the URP
in 2018, something North Dakota
acknowledges. We are not penalizing
North Dakota, and we are not seeking
controls in North Dakota to offset
impacts from outside the State. We
explain elsewhere why we are
disapproving North Dakota’s NOX BART
determination for CCS 1 and 2 and its
reasonable progress determination
concerning AVS 1 and 2. We are acting
to ensure that reasonable BART and
reasonable progress controls are put in
place. North Dakota may not use out-ofstate emissions as a basis to ignore
controls on in-state sources where such
controls are clearly reasonable. We note
that we are approving the majority of
North Dakota’s BART and reasonable
progress determinations and that our
FIP is modest in scope.
Comment: One commenter notes that
EPA’s proposed FIP states that
‘‘Appendix W outlines specific criteria
for the use of alternate models and it
does not appear that those criteria have
been satisfied for the use of North
Dakota’s hybrid modeling.’’ 76 FR 58624
and 58637. The commenter asserts that
‘‘EPA does not, however, identify any
criteria North Dakota purportedly did
not satisfy.’’ The commenter then seeks
to supply, in retrospect, evidence that
the criteria for alternative models, as
specified in Appendix W section 3.2,
are in fact met.
Response: As specified in Appendix
W, ‘‘[d]etermination of acceptability of a
model is a Regional Office
responsibility.’’ 70 FR 68232. EPA
Region 8 has not determined that North
Dakota’s hybrid modeling (aka
‘‘cumulative modeling using current
degraded background’’) is acceptable for
the purposes of assessing single-source
visibility impacts under BART. In June
2007, EPA reviewed the ‘‘Modeling
Protocol for Regional Haze Reasonable
Progress Goals in North Dakota.’’ Our
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review of the protocol at that time was
within the context of establishing RPGs,
and not within the context of assessing
single-source impacts under BART.
Instead, and as described above, North
Dakota prepared a separate modeling
protocol for the purposes of BART. We
reiterate that, as the State’s single-source
BART modeling followed established
modeling guidance and was developed
in consultation with FLMs and EPA, we
find that it provides a reasonable basis
for making control technology
determinations.
Comment: Commenter stated that EPA
notes in the FIP that ‘‘North Dakota is
the only WRAP State which opted to
develop its own reasonable progress
modeling methodology.’’ Commenter
stated that the NDDH modeling
approach represents an adjustment, or a
refinement (for pollutant transport and
dispersion), of the cumulative
reasonable progress modeling
conducted by WRAP for western states.
In particular, the NDDH modeling
provides a much better resolution of
source to receptor locations. Commenter
stated EPA asserts that ‘‘[t]he settings
North Dakota used in the CALPUFF
model within the hybrid modeling
system would not be considered
technically sound if contained in a
regulatory modeling protocol in future
projects.’’ However, NDDH’s
modifications to the model settings
allows North Dakota’s specific
environment to be considered.
Response: North Dakota designed its
cumulative modeling system
specifically to include transported
pollutants, in addition to emissions
from individual BART sources. North
Dakota then used the model results to
evaluate BART source visibility impacts
relative to the cumulative impact of all
other emissions sources. The State’s
cumulative approach contradicts the
model approach recommended by EPA
in the BART Guidelines in which BART
source impacts are evaluated relative to
natural background visibility. As
discussed in the response to comments
above, EPA specifically considered and
rejected cumulative analyses for BART
sources in the BART Guidelines. The
effect of North Dakota’s cumulative
modeling approach is to evaluate BART
visibility impacts relative to current
degraded visibility conditions, and as
described in the BART Guidelines and
in response to comments above, this
would create the paradox that, the
worse the current visibility, the less
likely it would be that any control
would be required. The commenter also
describes the State’s approach as similar
to the cumulative reasonable progress
modeling conducted by WRAP for the
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western states. WRAP’s cumulative
reasonable progress modeling was
designed to evaluate progress in
reducing cumulative visibility impacts
from all emissions sources for the worst
20% visibility days. WRAP’s cumulative
modeling did not evaluate the impacts
from individual BART sources, and
therefore WRAP also performed single
source modeling using the CALPUFF
model to evaluate single source BART
impacts on the best visibility days.
Moreover, WRAP followed the BART
Guidelines in comparing those BART
visibility impacts to natural visibility
conditions on the 20% best days. While
it could be reasonable to perform
modeling for BART sources using
CALPUFF with background
concentration data from the Community
Multi-Scale Air Quality (CMAQ) model,
as North Dakota has done, the BART
source visibility impacts must still be
evaluated relative to natural background
visibility. The State’s approach of
comparing the BART source impacts to
cumulative visibility impacts is
essentially the same as comparing those
results to current degraded visibility
conditions, and, therefore, does not
follow the guidelines established by
EPA and followed by both WRAP and
all other states. As noted in other
responses, the reasons for our rejection
of North Dakota’s modeling approach in
the BART context also apply to North
Dakota’s use of that approach to model
the visibility benefits of single-source
control options in the reasonable
progress context.
Comment: Commenter states that the
cumulative approach is exemplified in
the refined visibility modeling
conducted by WRAP for western states
(which EPA has endorsed in Appendix
A of the TSD to its FIP proposal).
Response: Our applicable response to
a similar comment is provided
elsewhere in this section. Such an
approach is suitable for determining the
cumulative benefit of an overall control
`
strategy vis-a-vis the URP on the 20%
worst days. It is not suitable for
evaluating the benefits of potential
control options at individual sources.
Comment: Commenter stated that EPA
suggests that using single source
modeling based on natural background
conditions is appropriate for assessing
visibility improvement from BART
controls, because the goal of the regional
haze program is to ultimately have
natural background visibility
conditions. NDDH provides a number of
technical weaknesses of single source
modeling with natural background. For
example, North Dakota asserts the single
source modeling overstates perceived
visibility changes and ignores the
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impact of all other sources on
background visibility.
Response: We address these assertions
in our responses to other comments in
this section.
Comment: One commenter stated that
it is appropriate to consider both the
degree of visibility improvement in a
given Class I area as well as the
cumulative effects of improving
visibility across all of the Class I areas
affected. The commenter contends that
not considering the cumulative
improvement across multiple Class I
areas ignores impacts to all but the most
impacted Class I area.
Response: In its SIP, North Dakota
considered the visibility improvement
at both TRNP and LWA. Therefore, the
modeling analyses presented by North
Dakota did not ignore the visibility
improvement that would be achieved at
areas other than the most impacted
Class I area. In our proposal, for
convenience, we generally only cited
the visibility improvement at Theodore
Roosevelt, the most impacted Class I
area in the baseline modeling. However,
our evaluation of the visibility benefits
was made in consideration of all of the
single-source modeling results
presented in North Dakota’s SIP.
Comment: One commenter stated that
they shared our concern that North
Dakota did not adequately consider the
visibility benefits of the control
strategies it evaluated. Specifically, the
commenter pointed out that for three
EGUs, North Dakota used incorrect
techniques to assess (and
underestimate) visibility improvements.
That is, instead of evaluating a
candidate BART strategy by determining
the visibility improvement that would
result from that particular strategy
versus a ‘‘standard’’ baseline (e.g., the
proposed SO2 control options), the only
analyses of visibility improvements
were of the incremental differences
between competing BART options.
Response: We agree that the visibility
improvement of a control technology
should be assessed relative to a precontrol baseline. As we have noted
elsewhere in our response to comments,
this approach is recommended in the
BART Guidelines. 70 FR 39170.
However, where North Dakota failed to
provide this information, we were able
to rely on the incremental visibility
improvement over lower control
options. Our evaluation of the visibility
benefits for the three EGUs in question
took into account that the lower
visibility improvement presented by
North Dakota was simply an artifact of
the methodology.
Comment: One commenter stated that
North Dakota should have treated TRNP
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as single Class I area in their modeling
analyses.
Response: We concur that TRNP
should have been treated as a single
Class I area in the modeling analyses.
However, we have no evidence that
doing so would have led to control
technology determinations different
than those made by North Dakota or
EPA.
Comment: One commenter suggested
that EPA could have addressed
modeling issues that it identified in its
proposal by conducting its own
modeling analyses, as it did regarding
BART determinations in other EPA
regional offices.
Response: As stated elsewhere in our
responses to comments in this section,
we find that North Dakota’s singlesource modeling provides a reasonable
basis for making control technology
determinations. Therefore, we did not
find it necessary to conduct our own
modeling analyses.
Comment: From a visibility
impairment standpoint, it appears to be
more beneficial to reduce NOX than to
reduce SO2 in North Dakota’s cool
climate. However, by placing more
emphasis upon cost per-ton ($/ton) of
pollutants removed than on visibility
improvement, the advantages of
reducing NOX versus SO2 are
overlooked if both are measured with
the same $/ton yardstick. For this
reason, we recommend that the primary
emphasis should be placed upon the
dollars per deciview of improvement.
EPA has stated in its Guidance for
Setting Reasonable Progress Goals
Under the Regional Haze Program (June
1, 2007), ‘‘in assessing additional
emissions reduction strategies for source
categories or individual, large scale
sources, simple cost effectiveness based
on a dollar-per-ton calculation may not
be as meaningful as a dollar per
deciview calculation.’’ The same logic
applies to BART. Nevertheless, the
commenter notes that both North Dakota
and EPA have based their BART
determinations on cost-per-ton of
pollutant removed, and the commenter
included information to show that the
EPA BART proposals are internally
consistent and reasonable.
Response: As noted elsewhere,
evidence we have reviewed suggests
that the relative benefits are similar. In
any event, we have not ignored
visibility benefits in our assessments. It
is not necessary to use dollars per
deciview to reasonably consider the
regulatory factors and arrive at
reasonable control determinations. As
we have explained in responses to other
comments in this section, there can be
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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.
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20915
Response: In our review and analyses,
we have considered cost effectiveness
values in conjunction with estimates of
visibility improvement. Our analysis
methods are consistent with those
called for by the BART guidelines. We
have considered both average and
incremental cost effectiveness. The
BART guidelines do not require that
greater weight be placed on incremental
cost effectiveness and advise the use of
caution not to misuse the cost
effectiveness values. 70 FR 39167–
39168.
Comment: Commenter stated that EPA
cannot replace the statutory requirement
that states weigh costs of compliance
with a requirement that states select
BART based on a uniform national cost
effectiveness metric. Commenter further
stated that EPA essentially elevated cost
effectiveness to being a statutory factor
for BART determinations in the BART
Guidelines, and that this was incorrect
based on CAA section 169(A).
Response: For power plants larger
than 750 MW, the BART guidelines are
mandatory and specify that the Control
Cost Manual should be used to estimate
costs where possible and that cost
effectiveness in $/ton be considered. We
note that it is too late to challenge the
BART guidelines in this action. That
said, the BART Guidelines do not, as the
commenter contends, require states to
select BART based on a ‘‘uniform
national cost effectiveness metric’’
without consideration of the other
relevant factors.
For BART sources other than power
plants larger than 750 MW, North
Dakota has specified in its SIP that the
BART guidelines must be used as
guidance. Furthermore, any analysis of
the costs of compliance must be
reasonable, and the starting point is an
accurate estimate of the costs of
potential control options. From there,
we must have some means to assess the
reasonableness of the costs, and cost
effectiveness in $/ton is a widely used
and understood metric.
Comment: Commenter stated that, in
the preamble to the RHR, EPA
established a cost effectiveness value
threshold of $1,350/ton for NOX retrofit
control technologies. Another
commenter cited appendix Y, alleging
that it states that NOX control costs
above $1,500/ton are not cost effective
for BART. Commenter stated that EPA is
therefore inaccurate in the FIP for citing
NOX control costs over $1,500 per ton
as cost effective.
Response: EPA disagrees. While EPA
described various dollar-per-ton costs as
‘‘cost-effective’’ in various preambles
(e.g., 70 FR 39135–39136), EPA did not
establish an upper cost effectiveness
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threshold for BART determinations. We
note that North Dakota and other states
have identified NOX control costs well
over $1,500 per ton of emissions
reduced as being cost effective, and that
the relevance of a particular dollar-perton figure for controls will depend on
consideration of the remaining statutory
factors.
2. Comments Regarding Our Reliance on
the EPA Air Pollution Control Cost
Manual
Comment: One commenter stated that
the Control Cost Manual is in no way
binding, and that any deviation from the
manual by the State is no cause for SIP
disapproval. The commenter also stated
that cost analyses must take into
consideration source-specific costs.
Response: In today’s rule, we are
disapproving the BART determination
for one source, CCS. We note that the
BART guidelines are mandatory for CCS
because it is larger than 750 MW. The
BART Guidelines state that ‘‘[i]n order
to maintain and improve consistency,
cost estimates should be based on the
OAQPS Control Cost Manual, [now
renamed ‘‘EPA Air Pollution Control
Cost Manual, Sixth Edition, EPA/452/B–
02–001, January 2002] where possible.’’
70 FR at 39166. In addition, the
preamble to the BART Guidelines states
that ‘‘[w]e believe that the Control Cost
Manual provides a good reference tool
for cost calculations, but if there are
elements or sources that are not
addressed by the Control Cost Manual
or there are additional cost methods that
could be used, we believe that these
could serve as useful supplemental
information.’’ 70 FR 39127 (emphasis
added). Finally, the BART Guidelines
are clear that ‘‘cost analysis should also
take into account any site-specific
design or other conditions * * * that
affect the cost of a particular BART
technology option.’’ 70 FR 39166.
However, documentation of cost
estimates is necessary, particularly for
items that deviate from the Control Cost
Manual: ‘‘You should include
documentation for any additional
information you used for the cost
calculations, including any information
supplied by vendors that affects your
assumptions regarding purchased
equipment costs, equipment life,
replacement of major components, and
any other element of the calculation that
differs from the Control Cost Manual.’’
Id. In sum, the BART Guidelines direct
states to use the Control Cost Manual
where possible, but also allow for the
use of supplemental information and
site-specific factors, as necessary, as
long as the latter information is justified
and documented.
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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
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 NOX for the Milton
R. Young Station, May 10, 2010, pp. 14–16.
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local concern. It impacts visitors to our
national parks and wilderness areas
from all across the United States.
The cost estimates supplied by North
Dakota were frequently based on cost
estimating methods that deviate from
the overnight method that is used for
regulatory purposes. As described
above, these costs are not suitable for
the purpose of determining whether the
costs of BART controls are reasonable
relative to costs incurred at other
facilities.
Comment: One commenter stated that
EPA ignores the disclaimer in the
Control Cost Manual that the manual
does not address controls for EGUs. To
support this position, the commenter
provides the following quote from the
Control Cost Manual:
‘‘Furthermore, this Manual does not
directly address the controls needed to
control air pollution at electrical generating
units (EGUs) because of the differences in
accounting for utility sources. Electrical
utilities generally employ the EPRI Technical
Assistance Guidance (TAG) as the basis for
their cost estimation processes.’’ 1
The commenter also provides footnote
1 to this quote which reads as follows:
‘‘This does not mean that this Manual is an
inappropriate resource for utilities. In fact,
many power plant permit applications use
the Manual to develop their costs. However,
comparisons between utilities and across the
industry generally employ a process called
‘‘levelized costing’’ that is different from the
methodology used here. (EPA Air Pollution
Cost Control Manual, Sixth Edition page
1–3)’’
Response: We disagree with the
commenter’s conclusion regarding this
quote from the Control Cost Manual.
The quote is merely a factual
observation; electric utilities, in their
planning and cost estimating for their
own purposes, use a different
accounting method than required by the
Control Cost Manual. The footnote
clarifies that the Control Cost Manual is
appropriate for utilities for regulatory
purposes.
The utility industry uses a method
known as ‘‘levelized costing’’ to conduct
its internal comparisons.22 The utility
industry’s levelized costing methods
differ from the methods specified by the
Control Cost Manual. Utilities use
‘‘levelized costing’’ to allow them to
recover project costs over a period of
several years and, as a result, realize a
reasonable return on their investment.
The Control Cost Manual uses an
approach sometimes referred to as
‘‘overnight costing’’ that treats the costs
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.
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of a project as if all the materials and
labor are paid for within a very short
period of time. The Control Cost Manual
approach is intended to allow a fair
comparison of pollution control costs
between similar applications for
regulatory purposes.
Estimates prepared using the utility
industry’s levelized costing are not
comparable to estimates prepared using
the Control Cost Manual. Estimates
using the utility industry’s levelized
method are generally higher than EPA
cost effectiveness estimates since the
utility industry’s levelized method
estimates are stated in future dollars and
include costs not included in the EPA
method, such as inflation and interest
during construction. That is why the
BART guidelines specify the use of the
Control Cost Manual where possible and
why it is reasonable for us to insist that
the Control Cost Manual method be
used to estimate costs. This is the
method that has been used to determine
the reasonableness of cost effectiveness
values in regulatory settings for many,
many years; it ensures the use of a
common, well-understood metric.
Without a like-to-like comparison, it is
impossible to draw rational conclusions
about the reasonableness of the costs of
compliance for particular control
options.
Comment: Commenter stated that
EPA’s rejection of levelized costs is
inconsistent with the Control Cost
Manual. Commenter also cites EPA’s
New Source Review (NSR) Manual to
argue that levelized costs are acceptable
and should not be disapproved.
Response: The issue here is one of
semantics rather than a dispute over
levelization. We agree levelization is
allowed by the Control Cost Manual,
and we levelized costs in preparing cost
estimates for our proposal. However, the
commenter levelized in nominal dollars,
while EPA’s consultant levelized in
constant dollars consistent with the
Control Cost Manual. The constant
dollar approach is the correct approach.
It levelizes O&M costs excluding
inflation.
The Control Cost Manual approach
equalizes all future O&M costs into
equal annual payments in constant
dollars over the life of the system,
translated to year zero using the
Equivalent Uniform Annual Cash Flow
method or EUAC. See also NSR Manual,
p. b.4. The dispute arises over the
inclusion of inflation. The Control Cost
Manual ‘‘recommends making cost
comparisons on a current real dollar
basis’’ * * *.’’ ‘‘The constant dollar
approach described in the Control Cost
Manual annualizes (in constant dollars)
the cost of installation, maintenance,
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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
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$1,500 to 2,500 per ton of NOX
removed.23
E. Comments on BART Determinations
1. General Comments
Comment: Commenter stated that
EPA’s proposed incorporation of a
‘‘margin of compliance’’ into its BART
determinations is contrary to the CAA,
and is not supported by EPA’s own
regulations and guidance. Commenter
specifically cited EPA’s proposed
increase of the MRYS Units 1 and 2
NOX emission limits from .05 lb/MMBtu
to .07 lb/MMBtu, stating that this was a
weakening not allowed by the CAA and
reliant on factors that were not
articulated in the CAA. Commenter
used this rationale in stating that EPA
must establish BART emission rates of
.05 lb/MMBtu for MRYS Units 1 and 2
and LOS Unit 2, and a BART emission
rate of .108 lb/MMBtu for CCS Units 1
and 2. Another commenter stated that as
a general note, in almost every instance
North Dakota, and by extension EPA,
has converted the purportedly annual
emission rate used in the BART
analyses to a 30-day emission limit by
increasing it by a seemingly arbitrary
percentage increase. This has ranged
from a low percentage up to at least
40%. There is no support in the record
for these increases, and it is not always
clear that the original levels are not
feasible as 30 day limits. While the
commenter agreed that there can be
additional variability in 30-day averages
as compared to annual, EPA must
adequately support any changes it
makes to the emission levels analyzed.
Response: In keeping with the BART
Guidelines, we evaluated cost
effectiveness on an annual basis.
Specifically, we calculated cost
effectiveness as the total annualized
costs of control divided by annual
emissions reductions. When discussing
cost effectiveness in our proposal, we
gave both the emissions reductions and
emission rates (lb/MMBtu) on an annual
basis. By contrast, the BART Guidelines
indicate that EGU BART emission limits
should be specified as 30-day rolling
average limits. It is commonly
understood that shorter averaging
periods result in higher variability in
emissions due to load variation, startup,
shutdown, and other factors. However,
BART emission limits must be met on
a continuous basis. Accordingly, we
have not generally required 30-day
rolling average emission limits equal to
the annual emission rates used for
calculating cost effectiveness. We find it
23 Institute of Clean Air Companies, White Paper
Selective Non-Catalytic Reduction (SNCR) for
Controlling NOX Emissions, February 2008, p. 4.
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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.
mstockstill on DSK4VPTVN1PROD with RULES2
2. CCS Units 1 and 2
a. EPA’s Use of the Control Cost Manual
for CCS
Comment: Commenter (GRE) stated
that EPA guidelines as provided to
states in identifying regional haze
control requirements and as provided in
EPA’s Control Cost Manual are best
suited for evaluating average or typical
installations. Commenter stated that
because CCS 1 and 2 are uniquely
designed and employ DryFiningTM
technology, any accurate analysis of
add-on NOX controls must be sitespecific and not rely on general
guidelines which might apply to a
normal facility.
Response: As required by North
Dakota, GRE provided a BART analysis
for CCS to the State in 2007. That
analysis included an analysis of
potential NOX controls, including
SNCR. For several significant elements
of its analysis of SNCR, GRE relied on
EPA’s Control Cost Manual.24 This was
consistent with EPA’s BART Guidelines,
which are mandatory for CCS and
which provide that cost estimates
should be based on the Control Cost
Manual where possible. 70 FR 39166.
GRE now essentially criticizes its own
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.
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earlier analysis, claiming that it was
done only at a screening level. However,
to the extent GRE believed that unique
characteristics at CCS required more
site-specific information or more indepth analysis, GRE could have and
should have performed that analysis in
2007.
Nonetheless, we have evaluated GRE’s
new analysis. For reasons we explain
below, we have serious concerns about
the validity and accuracy of GRE’s new
analysis and we find it is reasonable for
us to continue to rely on cost estimates
based on EPA’s Control Cost Manual, as
described in our proposal. See 76 FR
58620. Every facility has unique
elements; however, we do not agree that
the elements at CCS are so unique that
use of the Control Cost Manual is
inappropriate. Also, we note that
DryFiningTM was not installed until
after the baseline period and was
installed voluntarily, not to meet any
regulatory requirement. We are not
required to revisit the baseline controls
or reconsider cost estimates based on
voluntarily installed controls. On the
contrary, there are significant issues
with such an approach; it would tend to
reward sources that install lesser
controls in advance of a BART
determination in an effort to avoid more
stringent controls.
Comment: Commenter stated that the
removal efficiency for CCS 1 would not
be 50% as anticipated from the EPA
Pollution Control Cost Manual and as
used in GRE’s original BART analysis,
but would rather be 30% and 20% for
Units 1 and 2 respectively. The
commenter asserted that these emission
estimates clearly change the basis for
any cost effective determination. The
commenter references Appendix B to
GRE’s November 2011 Refined Analysis
‘‘cost and performance review’’ by URS,
which provides control efficiency data
as a function of inlet NOX
concentrations for 55 existing SNCR
installations.
Response: We disagree with this
comment. We proposed a control
efficiency of 49% for CCS 1 and 2 based
on the combination of both enhanced
combustion controls and post
combustion controls. We have reviewed
GRE’s refined analysis, and we are not
convinced that our 49% assumption is
unreasonable. To the contrary, this level
of NOX reduction still appears
achievable.
The URS report that GRE references to
support its claim of reduced control
efficiency values provides a plot in
which NOX control efficiency is plotted
as a function of inlet NOX
concentrations. The URS plot does not
provide the boiler sizes which would be
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necessary for a comparison to the data
in the Control Cost Manual, or for
comparison to the control efficiency we
used in the proposed FIP. Table 3.1,
‘‘Control Cost Summary,’’ in GRE’s
Refined Analysis shows control
efficiencies of 25% and 20% for Units
1 and 2 respectively, which differ from
GRE’s assessment of a 50% control
efficiency in its original August 2007
BART analysis and its July 2011
corrected analysis.25 26 GRE’s earlier
50% control efficiency was a reduction
from the 0.22 lb/MMBtu baseline
(which included existing LNB with a
level of SOFA) to an emission limit of
0.11 with the addition of only SNCR
controls (no additional or enhanced
combustion controls). While we would
not expect CCS could achieve a 50%
control efficiency from the installation
of SNCR alone, we do find our
estimated 49% control efficiency
reasonable based on the installation of
both SNCR and enhanced combustion
controls (SOFA plus LNB or LNC3).27
We proposed a NOX BART FIP limit
for CCS 1 and 2 of 0.12 lb/MMBtu that
would apply to each unit singly on
30-day rolling average basis. We based
this limit on our proposed finding that
SNCR plus SOFA plus LNB was BART.
While we continue to find that SNCR
plus SOFA plus LNB is BART, we are
changing the emission limit to 0.13 lb/
MMBtu averaged over both units on a
30-day rolling average basis. Evidence
submitted by commenters and our own
additional analysis in evaluating
comments has led us to conclude that
this represents a more reasonable limit
to apply on a 30-day rolling average
basis.
This limit represents a control
efficiency of 47.8% based on the average
annual baseline emission rate of 0.22 lb/
MMBtu (2003–2004) provided in the
State’s BART determination. This value
is slightly lower than the 49% control
efficiency we assumed in our proposal,
a value that was based on the State’s
analysis. Beginning in 2010, CCS 2
voluntarily started employing LNC3, the
more stringent level of combustion
controls that the State evaluated in its
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 coalX
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.
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mstockstill on DSK4VPTVN1PROD with RULES2
BART determination. Annual average
Clean Air Markets data for this unit
reflects a NOX emission rate of 0.153 lb/
MMBtu. We estimate that SNCR would
achieve an additional 25% reduction,
equivalent to an emission rate of 0.115
lb/MMBtu. This compares to a value of
0.108 lb/MMBtu that the State originally
estimated.
GRE asserted in comments that SNCR
will only achieve a 20% reduction
beyond LNC3. We find that 25% is a
conservative and reasonable estimate.
We considered several sources of
information in arriving at this value.
First, the Control Cost Manual states
that in typical field applications, SNCR
provides a 30% to 50% NOX reduction.
The manual provides a scatter plot with
NOX reduction efficiency plotted as a
function of boiler size in MMBtu/hr.28
The plot supports GRE’s assertion that
control efficiency could be lower than
50%, and could approach 30%, for
larger boilers such as those at CCS.
Second, Fuel Tech (one of the most
recognized SNCR technology suppliers)
estimates a range of 25% to 50% NOX
reduction with application of SNCR.29
Lastly, ICAC has published information
that supports a control efficiency of 20
to 30% for SNCR above LNB/
combustion modifications.30 Given this
range of control efficiencies, we have
settled on a control efficiency that is
lower than the lowest value given by the
Control Cost Manual, at the low end of
the range estimated by Fuel Tech, and
in the middle of the range estimated by
ICAC.
To arrive at a final BART emission
limit, we adjusted the projected annual
average of 0.115 lb/MMBtu upward by
10% and then rounded to the nearest
hundredth to arrive at 0.13 lb/MMBtu.
In our experience, a 5 to 15% upward
adjustment is appropriate when
converting an annual average emission
rate to a limit that will apply on a 30day 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
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 https://www.ftek.com/en-US/products/apc/
noxout/.
30 Institute of Clean Air Companies, White Paper
Selective Non-Catalytic Reduction (SNCR) for
Controlling NOX Emissions, February 2008, p. 9.
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2003–2004 for BART planning. Use of
such lower baseline rate would
inappropriately skew the 5-factor BART
analysis by reducing the emissions
reductions from combinations of control
options and increasing the cost
effectiveness values.
b. CCS Emission Limits
Comment: Commenter stated that
30-day rolling limits are intended to be
inclusive of unit startup and shutdown
as well as variability in load.
Consequently, associated BART limits
must be higher than stated annual
averages used for estimating cost
effectiveness.
Response: As described in the
proposed FIP, in proposing a BART
emission limit of 0.12 lb/MMBtu, we
adjusted the annual design rate of 0.108
lb/MMBtu upwards to allow for a
sufficient margin of compliance for a
30-day rolling average limit that would
apply at all times, including during
startup, shutdown, and malfunction.
While we proposed a BART limit of 0.12
lb/MMBtu, we invited comment on
whether we should impose a different
emission limit of 0.14 lb/MMBtu on a
30-day rolling average. After
considering all comments, we have
settled on a limit of 0.13 lb/MMBtu on
a 30-day rolling average. We explain the
basis for this limit in this section as well
as in section III above.
c. CCS Modeling
Comment: Commenter stated that
pollutant interaction has an impact on
modeled visibility impairment and, as
such, GRE believes that modeling
changes to NOX emission rates alone
will not provide visibility modeling
results that are representative of actual
emission controls. Commenter asserted
that this may overstate visibility
improvement as compared to modeling
NOX, SO2 and PM2.5 together. However,
for the purpose of illustrating the
relative visibility impacts of SNCR and
LNC3, the commenter presented an
analysis of the incremental modeled
impacts.
Response: Our review of North
Dakota’s and GRE’s CALPUFF input
files reveals that SO2, NOX, and
particulate matter (PM) emission
changes were in fact modeled together.
All of the NOX control options were
modeled along with the SO2 emission
reductions that would be achieved from
either a new scrubber or modifications
to the existing scrubber. However, in
order to determine the distinct visibility
improvement from the NOX control
options, it is necessary to compare the
modeled impacts to a pre-control
scenario. This is in fact the approach
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20919
prescribed by the BART Guidelines
which state that you should ‘‘[a]ssess
the visibility improvement based on the
modeled change in visibility impacts for
the pre-control and post-control
emission scenarios.’’ 70 FR 39170. As
noted in our proposal, because North
Dakota did not provide visibility
benefits relative to a pre-control
baseline, ‘‘it [was] not possible to
describe the incremental visibility
benefits of SNCR, or other NOX control
options, over the selected SO2 BART
control (scrubber modifications at 95%
control).’’ 76 FR 58623. As a result, we
were only able to specify the
incremental visibility benefit between
NOX control options. In our evaluation
of BART for NOX at CCS, we weighed
the visibility factor in consideration of
the fact that the improvement was
incremental to lower NOX controls and
not relative to a pre-control baseline. We
are not able to assess the visibility
benefit information the commenter
provided in Table 3.3.1 of the comments
due to the lack of documentation and
detailed explanation of the information
presented.
d. CCS Coal Ash
Comment: GRE references Appendix
C to its Refined Analysis ‘‘Fly Ash
Storage and Ammonia Slip Mitigation
Technology Evaluation.’’ GRE claims
that its previous estimates of fly ash
sales and disposal costs were ‘‘screening
level values’’ and the Appendix C report
provides a more comprehensive
assessment of ash implications
associated with SNCR installation. GRE
states that the report illustrates that any
ash impact costs add to the total cost of
SNCR and make it less cost effective.
Response: Based on further analysis,
we are not convinced that the use of
SNCR will impact GRE’s ash sales. We
explain this more fully in the responses
below. Also, regarding specific sales
price and costs numbers, we are not
convinced that GRE’s Appendix C
report, included with its comments,
provides a more realistic picture of
these values. We provide more detailed
information in other responses.
Comment: GRE stated that mandating
SNCR will leave GRE in a vulnerable
position where it would expect to incur
significantly higher costs from lost ash
sales and increased landfilling.
Commenter stated that GRE would
expect to annually incur between
$4,435,000 and $8,988,000 in additional
ash costs. Commenter’s contractor,
Golder Associates, provided a revised
analysis that included three potential
scenarios of SNCR’s impact to fly ash
sales (GRE Appendix C): A. Sales are
not affected; B. Worst case scenario—no
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mstockstill on DSK4VPTVN1PROD with RULES2
ash sales; and C. 30% reduction in ash
sales. Commenter asserted that scenario
A is extremely unlikely, scenario B is a
likely outcome, and scenario C is
optimistic.
Response: In the proposed FIP, EPA
agreed that use of SNCR might result in
lost ash sales and the need to landfill fly
ash due to ammonia contamination.
These additional costs were included in
our cost analysis supporting the FIP.
However, we also invited comment on
the assumption that use of SNCR would
result in lost fly ash sales and on the
availability of ammonia mitigation
techniques. 76 FR 58620. We received
responsive comments on both sides of
the issue.
In the proposed FIP, EPA included
costs of $2,023,000 for ‘‘additional ash
disposal’’ and $2,023,000 for ‘‘lost ash
sales’’ (76 FR 58621). EPA arrived at
these values based on information that
GRE itself supplied in July 2011. Based
on an analysis performed by a
consultant, GRE now asserts that the
information GRE supplied in June and
July 2011, regarding the sales price for
fly ash and the costs for fly ash disposal,
was not accurate. GRE supplied this
information initially in June 2011 when
it discovered that the information that it
supplied to the State regarding these
values in 2007 was inaccurate.
As part of our consideration of GRE’s
comments, and comments submitted by
others disputing the notion that SNCR
use would affect fly ash sales, we have
investigated and analyzed this issue
further. As part of our effort, we have
contracted with EC/R, an engineering
consulting firm, which in turn engaged
Dr. James Staudt of Andover
Technology Partners (ATP), who has
expertise regarding the issue of
ammonia in fly ash.31
Dr. Staudt recently presented a paper
at the AWMA, EPA, EPRI, DOE
Combined Power Plant Air Pollution
Control ‘‘Mega’’ Symposium, August
30–September 2, 2010, Baltimore,
Maryland, which reviewed the
performance benefits in terms of
ammonia slip, reagent consumption,
and fly ash ammonia that is possible
through optimization of SNCR operation
using the information from continuous
and real-time monitoring of ammonia
slip.32 As explained more fully below,
current technology has made it possible
31 Information regarding EC/R and Dr. Staudt’s
credentials is available in the docket.
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.
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to control ammonia slip from SNCR to
levels similar to what is achievable with
SCR, in the range of 2 ppm or less. It
is widely accepted that ammonia at this
level does not impact the potential sales
and use of fly ash in concrete.
One type of continuous ammonia slip
analyzer works on the principle of
tunable diode laser spectroscopy and
provides continuous, real-time
indications of ammonia slip in the duct.
This type of analyzer facilitates
optimum operation of the SNCR system
and minimizes ammonia slip.33 In other
words, GRE would not incur costs for
lost sales of fly ash or additional ash
disposal if it employed such a system at
CCS.34
For these reasons, we conclude that
charges for lost fly ash sales should not
be applied to the SNCR system cost
analysis and that SNCR can be
successfully deployed at the CCS plant
at a cost effectiveness level well below
the estimate in our proposal of $2,500/
ton of NOX removed.35
Comment: Commenter stated the
addition of SNCR will have a negative
impact on the marketability, value, and
perception of CCR’s fly ash. The
commenter further stated that increased
levels of ammonia in the fly ash with
SNCR create offensive odors, are
potentially dangerous to human health,
and can pose an explosion risk.
Commenter cited EPA’s Control Cost
Manual to bolster this position.
Commenter stated that ammonia slip of
only 5 ppm, generally accepted as the
minimum that can be achieved with
SNCR, can render fly ash unmarketable.
Response: EPRI performed a study in
2007 that examined the effects of
ammonia slip from SCR systems and
reached the conclusion that ‘‘The survey
overwhelmingly indicated that
ammonia contamination is not
impacting the ability of plants to sell
ash.’’ 36 Therefore, if an SNCR system
were to achieve similar ammonia slip
levels as SCR systems, then an adverse
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.
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.
36 https://my.epri.com/portal/server.pt?Abstract_
id=000000000001014269.
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impact on fly ash marketability would
not be expected.
Commenter’s assertion that 5 ppm is
the minimum that can be achieved with
SNCR is not consistent with experience
with recently installed, state-of-the-art,
SNCR systems. As noted above, recently
installed SNCR systems are capable of
ammonia slip levels in the range of 2
ppm, and experience at the CP Crane
Station in Baltimore, Maryland
demonstrates that ammonia slip can be
maintained below 2 ppm while also
ensuring that high ammonia slip
excursions during load changes and
other transients are avoided.37
In some cases the testimonials 38
provided by GRE regarding the adverse
effects of ammonia are highly
questionable. As an example, one of the
testimonials from a Mr. Boggs
incorrectly cautions about the
explosiveness of ammonia—
‘‘I would point out that with the storage
dome at Coal Creek, the ammonia levels that
could accumulate would be extremely
hazardous. A little know (sic) fact is that
ammonia is an explosive gas at certain levels
when it accumulates with air present’’.
On the other hand, according to the
North Dakota State University,
‘‘Anhydrous ammonia is generally not
considered to be a flammable hazardous
product because its temperature of ignition is
greater than 1,560 degrees F and the
ammonia/air mixture must be 16 percent to
25 percent ammonia vapor for ignition.’’ 39
Although, in principle, ammonia can
be combustible under special
conditions, these are conditions that are
highly unlikely to result from ammonia
in fly ash—even if fly ash ammonia
concentrations were to reach several
hundred ppm. In fact, to our knowledge,
there has never been a fire or explosion
resulting from ammonia in fly ash.
In summary, GRE’s comments and
testimonials generally overstate the real
concerns regarding ammonia that may
result in the fly ash of a plant equipped
with SNCR.
Comment: Commenter stated that the
social, economic and environmental
benefits from re-using ash are not
outweighed by costs nor are they
outweighed by the imperceptible
improvements to visibility.
Response: As stated above, EPA
anticipates that application of SNCR at
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.
38 EPA–R08–OAR–2010–0406–0077, Letter from
GRE to NDDH, February 9, 2010.
39 https://www.ag.ndsu.edu/pubs/ageng/safety/
ae1149-1.htm.
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CCS would not decrease the amount of
ash re-use. Our FIP is based on a
reasonable consideration of the five
BART factors: Costs of compliance, the
energy and non-air quality
environmental impacts of compliance,
any existing pollution control
technology in use at the source, the
remaining useful life of the source, and
the degree of improvement in visibility
which may reasonably be anticipated to
result from the use of such technology.
We understand that GRE may have
reached a different result based on its
consideration of the statutory factors
and other factors; that does not mean
our determination is unreasonable.
Comment: Commenter asserted that
changes to the quantity of fly ash
marketed and sold will have a direct
impact on fly ash management costs, as
the revenue currently used to offset fly
ash management will be lost. The lost
fly ash sales revenue is based on the
2010 average price per ton FOB of
$41.00; with 30% of the sale price going
to GRE as revenue.
Response: As stated above, we do not
agree that fly ash sales would be
impacted. If there were any lost
revenue, the lost revenue to GRE is the
only cost that should be considered, not
the full FOB price which includes
revenues to others. This cost was $5/ton
prior to December 2011 40 as presented
by GRE in its comments. Were it still
relevant, we would consider this a
reasonable price to use. In addition, we
would consider $5/ton to be a
reasonable cost to GRE for ash disposal,
resulting in a total cost to GRE of $10/
ton.41 URS increased the ash sales price
to $12.30 in the refined analysis based
on GRE’s 2012 ash sales contract price.
We are not convinced that such an
increase would be appropriate. GRE did
not provide any detail on the basis for
the increased price. Considering this is
a 2012 contract price, it may even be
based on projected information. It was
reasonable for us to rely on the best
estimates at the time of our proposal.
We note that GRE itself supplied these
estimates.
Comment: Commenter stated that
EPA’s Control Cost Manual (2002) does
not allow GRE to include in the BART
analysis the value of previously
purchased assets that would be
rendered useless by the elimination or
reduction of fly ash sales. GRE claims
$31 million has been invested on ash
storage, transportation and distribution
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.
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infrastructure along with their strategic
partner Headwaters Resources. Of the
$31 million, GRE has contributed $7
million.
Response: Given the availability of
means to control ammonia levels in the
fly ash, we do not agree that previously
purchased storage, transportation, and
distribution infrastructure would be
rendered useless. However, the
commenter is correct that the Control
Cost Manual does not consider the costs
of existing infrastructure that would be
rendered useless as a result of installing
new or retrofit controls. The Control
Cost Manual is designed to provide
methods for estimating the specific costs
of installation and operation of control
technologies to allow consistent
comparison of such costs across
multiple sources; thus, the ‘‘stranded’’
costs for existing infrastructure are not
accounted for in the cost estimation
methodology found in the Control Cost
Manual.
Comment: Commenter asserted that
even with a cost effective ASM
technology installed, there will be times
when the residual ammonia levels in
the ash are too high to treat. Ammonia
injection rates will vary during periods
of startup and shutdown, in addition to
variable load operation, in order to
maintain compliance with the BART
limits. The commenter stated that
variable ammonia injection rates and
associated changes in ash
concentrations will result in frequent
testing and periodic rejection of ash
requiring on-site disposal. The
commenter further stated that variable
ammoniated ash levels will put GRE’s
generated ash in a very vulnerable
position with respect to competitors in
the fly ash marketplace, reducing ash
sales and increasing on-site disposal.
Response: Testimonials provided by
GRE cited older SNCR systems, such as
Eastlake Station in Eastlake, Ohio, as
causing problems for fly ash
marketability. (The testimonials also
reaffirmed that fly ash from boilers with
SCR systems remained marketable.) The
Eastlake SNCR system was installed
several years ago, and current state-ofthe-art SNCR systems have been
demonstrated to control ammonia slip
to avoid high ammonia slip transients,
as described by Staudt, et al.42
Ammonia slip can be consistently
maintained at low levels in the range of
2 ppm or less over a wide range of loads
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.
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20921
for load following units, and this was
demonstrated at the two units at CP
Crane Station near Baltimore. The
control system was optimized expressly
to minimize the effects of ammonia on
plant fly ash. This was made possible by
utilizing permanently installed
ammonia monitoring devices. Both
units needed to maintain slip at low
levels while making several rapid load
changes a day. CP Crane Station has
continued to control the SNCR system
in this manner. As described in the
referenced paper, the accuracy of the
continuous ammonia instruments were
shown to be comparable to wet
chemistry measurements at these low
levels of ammonia slip and the
instruments have had good reliability.
Another aspect of ammonia slip and
impact on fly ash marketability is that
the alkalinity of the fly ash will impact
how much ammonia becomes attracted
to the fly ash. Fly ash from bituminous
coals, with more sulfur trioxide, will
tend to attract more ammonia than fly
ash with a high alkalinity, such as fly
ash from North Dakota lignite. As a
result, ammonia deposition on fly ash at
CCS is likely to be less of an issue than
it would be on a bituminous coal unit,
such as Eastlake, and higher ammonia
slip levels may be tolerable before fly
ash marketability is affected.43
Comment: Commenter stated that, to
GRE’s knowledge, no lignite-fired unit is
currently operating SNCR and ASM
technology, and the vendor would not
guarantee any level of performance for
a lignite-fired unit.
Response: Evidence indicates that
modern SNCR systems can achieve
ammonia levels of 2 ppm or below,
which would avoid the need for use of
ASM technology.
Our review of EPA Title IV data for
2010 found that there are three
tangentially fired coal-fired boilers that
burn lignite coal and control emissions
to under 0.14 lb/MMBtu with SNCR.
These include Big Brown 1 and
Monticello 1 and 2. According to the Fly
Ash Resource Center, both the Big
Brown Plant and the Monticello Plant
market their fly ash through Boral
Materials.44 The Monticello fly ash was
designated an approved material by the
Arizona Department of Transportation
(July 2011 45) and Georgia Department of
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.’’ https://www.rmajko.com/
qualitycontrol.htm.
44 https://www.rmajko.com/suppliers1.html.
45 https://www.azdot.gov/highways/materials/pdf/
materials_source_list_flyash.pdf.
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Transportation (January 2012 46).
According to Boral’s Web site, the Big
Brown ash has been designated an
approved material by several state
departments of transportation.47 Both of
these plants are selling their fly ash and
are not experiencing adverse impacts
with ammonia in the ash.
This is further evidence that GRE’s
assumption, that the CCS plant would
be unable to market its fly ash, is
unjustified. Also, as indicated above, if
it were necessary to employ ammonia
mitigation to the fly ash, we think at
least one of the available systems could
be employed at CCS.
Comment: Commenter stated that the
BART analysis does not take into
account the additional regional
economic impacts resulting from the
reduction of CCS ash sales. GRE uses
the freight on board (FOB) price of the
ash to estimate a loss to the local and
regional economy from the elimination
of ash sales of as much as $28.70/ton or
$11,910,500 per year.
Response: As we have already
discussed, we do not agree that ash sales
would be reduced with the
implementation of SNCR. Thus, there
should be no regional economic impacts
from lost fly ash sales. However, were
this comment still relevant, we note two
points. First, the BART Guidelines,
which are mandatory for CCS, prescribe
a method for estimating the specific
costs of installation and operation of
control technologies to allow consistent
comparison of such costs across
multiple sources. This method does not
include consideration of regional
economic impacts. If such impacts were
to be considered, different
methodologies and different notions of
cost effectiveness would have to be
developed. While we are sensitive to
broader economic impacts, they are not
part of our focused analysis of the BART
factors in making a BART
determination.
Second, if we were to consider such
impacts, there is considerable
uncertainty in the estimate GRE
provided, which attempts to conduct a
complex economic assessment based on
FOB price alone. For example, the
estimate does not consider the offsetting
economic impact of replacement
materials, such as alternative concrete
admixtures, which would be used by
concrete manufacturers as an alternative
to CCS’s ash.
Comment: Commenter stated that loss
of ash sales at CCS would negatively
impact the regional and national
46 https://www.dot.state.ga.us/doingbusiness/
materials/qpl/documents/qpl30.pdf.
47 https://www.boralna.com.
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economy, as well as the regional and
national infrastructure. The commenter
stated that the beneficial use of fly ash
is directly responsible for a large
number of jobs throughout the country.
The commenter highlighted the
importance of fly ash as a component of
road and bridge construction across the
country, and cited a report by the
American Road and Transportation
Builders Association. According to GRE,
the research in the report concluded
that the elimination of fly ash as a
construction material would increase
the average annual cost of building
roads, runways, and bridges in the
United States by nearly $5.23 billion.
This total includes $2.5 billion in
materials price increases, $930 million
in additional repair work and $1.8
billion in bridge work. The additional
costs would total $104.6 billion over 20
years.
Response: For the reasons expressed
in our response to the previous
comment and in our other responses, we
do not consider this comment relevant
to our decisions. We have concluded
that CCS’s ash sales will remain
feasible, and find that the impacts cited
by GRE are impacts that would apply to
the entire fly ash industry and not just
CCS. Furthermore, there is not sufficient
evidence that elimination of CCS’s ash
sales would result in any of the impacts
described above.
Comment: Commenter stated that the
use of fly ash as a replacement for
cement has environmental benefits.
Commenter asserted that as a result of
the increased use of fly ash, less land is
disturbed for quarrying raw materials,
less land is taken out of production for
landfills, and less carbon dioxide (CO2)
is emitted into the atmosphere to make
cement. Commenter argued that there
will be a 1 to 1 ton increase in CO2
emissions from using more Portland
cement in place of ash.
Response: As stated in previous
responses, we do not agree that the use
of SNCR will cause GRE to experience
a reduction in fly ash sales.
Furthermore, GRE presents no evidence
to support its claims about CO2
emissions or reduced quarrying. CO2
emissions result from many factors, and
additional quarrying might be avoided
through use of alternative sources of fly
ash. As did the State, we have already
considered the potential need to landfill
additional fly ash in our five factor
analysis, but do not consider that a
reason to reject SNCR as BART.
Comment: Commenter stated that the
landfill cost estimate includes costs for
the life of the disposal facility including
engineering, design, and permitting;
construction; and operations and
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maintenance, including closure and
post-closure care.
Response: As we stated in previous
responses, we are not convinced that the
use of SNCR will impact GRE’s ash
sales; thus, requiring additional on-site
landfill facilities should not be
necessary. Furthermore, we have noted
in prior responses that we find a
disposal cost of $5/ton is reasonable in
the improbable event that some ash
would need to be disposed.
Comment: Commenter stated that the
ash management costs used in this
analysis assumes that future ash
disposal facilities will be designed and
constructed to meet RCRA subtitle D
standards. Commenter asserted that this
cost would increase considerably if EPA
tightens standards as a result of the
uniform national disposal standards
currently being considered.
Response: As already discussed, we
do not agree that SNCR will lead to
increased landfilling. Were this
comment still relevant, we note that we
evaluate costs based on the best
information available concerning
current costs. We do not know what the
final coal combustion residuals
regulations will require with respect to
RCRA subtitle D and we are not
required to include speculative costs in
our estimates.
e. CCS Visibility Improvements Are
Minimal
Comment: Commenter stated that the
refined analysis demonstrates that the
installation of SNCR will not result in
perceptible visibility improvements in
North Dakota’s Class I areas, and it is
not justifiable for GRE to incur the
added cost of SNCR without any
appreciable improvement in visibility.
To support these claims, the commenter
stated that from GRE’s BART analysis, it
can be estimated that the incremental
deciview improvements associated with
the installation of SNCR would range
from 0.109 to 0.207, which are well
below what EPA has established as a
perceptible level to the human eye (0.5
deciviews).
Response: There is considerable
uncertainty in the deciview
improvements calculated by GRE. GRE
provides an analysis of the incremental
modeled impacts and cost per deciview
in Table 3.3.1 of GRE’s November 2011
Refined Analysis, but provides no
further explanation of the table or the
values contained therein. A January 19,
2012 NDDH letter to CCS also raises
concerns about certain aspects of the
table pertaining to baseline emission
rates and deciview improvement values.
In addition, it appears that GRE has
calculated these values based on new
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assumptions, and EPA raises concerns
about some of these assumptions (e.g.,
control efficiency of SNCR) in other
comment responses within this
document.
Even if the results were correct, as
noted elsewhere in our response to
comments, the RHR is clear that
perceptibility of visibility improvement
is not a test for the suitability of BART
controls. Also, as noted elsewhere in
our response to comments, we have not
used the dollar-per-deciview metric and
find that it is reasonable to evaluate
control options on the basis of the cost
effectiveness in dollar-per-ton removed
in conjunction with the modeled
visibility improvement.
Concerning our consideration of
visibility improvement in the CCS
BART determination, the BART
Guidelines (40 CFR part 51, appendix Y)
state that deciview improvements must
be weighted among the five factors and
the Guidelines provide flexibility in
determining the weight and significance
to be assigned to each factor. Thus,
achieving a visibility improvement
greater than the perceptible level of 0.5
deciviews is not a prerequisite for
selecting a particular control option as
BART at CCS.
Comment: Commenter stated that
combined utility NOX emissions in
North Dakota represent approximately
only 6% of total NOX emissions, and
therefore, it is understandable that
proposed and additional BART NOX
reductions from North Dakota utilities
do not provide more visibility
improvements in the Class I areas.
Response: We disagree with the
commenter’s assertion that the potential
visibility improvements from NOX
controls on North Dakota EGUs would
be small. The commenter’s estimate of
the contribution from utilities to NOX
emissions in North Dakota appears to be
incorrect. Emission inventories
developed by the WRAP for the 2000–
2004 planning period show that EGUs
contributed 78,995 tons out of a total of
229,460 tons of NOX for all source
categories combined.48 Therefore,
utilities account for some 34.4% of the
total NOX emissions in North Dakota,
and more than any other source
category.
Furthermore, the RHR states that
BART determinations are based on
circumstances such as the distance of
the source from a Class I area, the type
and amount of pollutant at issue, and
the availability and cost of controls (70
FR 39116). Thus, sources that are closer
to Class I areas and emit the types of
48 Source: https://www.wrapair.org/forums/ssjf/
pivot.html.
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pollutants that contribute to regional
haze are more likely to be subject to
BART requirements, regardless of their
percent contribution to the statewide
NOX emission rate.
Comment: Commenter (GRE) stated
that ammonia is a listed state toxic in
North Dakota, and is viewed as a
contributor to regional haze because it
can bond with SO2 and NOX to form
ammonium sulfate and ammonium
nitrate aerosols. Commenter further
stated that additional ammonia slip
from the proposed SNCR for CCS may
offset the relatively minor NOX
reduction proposed by EPA.
Response: GRE does not provide the
anticipated ammonia emissions for
comparison to the proposed NOX
reductions and states that this issue is
outside the scope of its analysis. In the
RHR, EPA states that there are scientific
data illustrating that ammonia in the
atmosphere can be a precursor to the
formation of particles such as
ammonium sulfate and ammonium
nitrate; however, it is less clear whether
a reduction in ammonia emissions in a
given location would result in a
reduction in particles in the atmosphere
and a concomitant improvement in
visibility (70 FR 39114). The evaluation
of whether ammonia slip would offset
the proposed NOX reductions to some
degree cannot be calculated due to the
lack of information provided by GRE, as
well as the inherent uncertainty in
estimating the effects of ammonia
emissions on regional visibility.
Furthermore, as stated in our previous
responses, ammonia slip, due to the
incomplete reaction of the NOX
reducing agent, can be limited to low
levels through proper design of the
SNCR system. Design of the SNCR
system can be optimized by taking into
account the temperature, NOX
concentration, residence time, and
reagent distribution. Our recent analysis
indicates that ammonia slip levels can
be reduced to below 2 ppm with the
introduction of the latest monitoring
technology. Therefore, we disagree that
any potential ammonia release from
SNCR at CCS may offset the proposed
NOX reductions.
Comment: Commenter stated that
NOX contributes to ammonium nitrate
formation, which is predominantly a
winter ‘‘haze’’ contributor, and for the
purposes of valuing the welfare effects
of recreational visibility, it is important
to consider that the North Dakota
national parks are generally not in high
use during the winter season.
Commenter expressed concern over
paying an extreme price per deciview
resulting in imperceptible
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improvements for a time of year when
the parks are generally not used.
Response: We addressed this
comment in our responses to modeling
comments in section V.C.
f. Comments on Alternative NOX
Emission Limits
In our proposal, we asked for
comments on a possible alternative NOX
BART limit for CCS 1 and 2, based on
use of combustion controls alone, of
0.14 lb/MMBtu. This section presents
the comment summaries and our
responses related to this issue.
Comment: Commenter stated that
because CCS cannot achieve the 30-day
rolling average emission rate without
installation of SNCR, it should not be
considered as an appropriate BART
emission level. Commenter stated that
this is consistent with EPA’s own
determination that a presumptive BART
emission level of 0.17 lb/MMBtu is costeffective and will result in significant
visibility improvement. Commenter
stated that these comments and the
associated Refined Analysis
demonstrate that any additional NOX
reductions would neither be costeffective nor would result in perceptible
visibility improvement in Class I areas.
Response: EPA does not agree with
the commenter’s assertions. EPA
disagrees with certain of GRE’s
assumptions in its Refined Analysis.
Please refer to other comment responses
throughout this document for details
about each of these assumptions. We
have reasonably considered the five
BART factors and have arrived at a
reasonable BART determination.
As to the presumptive limits, the
BART Guidelines state that utility
boilers should be required to meet the
presumptive NOX emission limits,
unless it is determined that an
alternative control level is justified
based on consideration of the statutory
factors. As noted elsewhere, our
regulations require that a state or EPA
must consider the five statutory BART
factors in determining BART and cannot
simply default to the presumptive
limits. We have already explained why
the State’s consideration of the costs of
compliance was fatally flawed and why
we must disapprove the State’s BART
determination. In promulgating our FIP,
we have reasonably considered the five
factors and arrived at a reasonable
BART determination that is more
stringent than the presumptive BART
limit.
Comment: Commenter stated that
NOX limits should be expressed on an
annual rather than 30-day basis, to
account for the full spectrum of
operations such as variable load, and
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startups or shutdowns not accounted for
in emission limits based on vendor
guarantees. The commenter notes that
an emission limit of 0.14 lb/MMBtu was
achieved for a period of time, but it is
not sustainable on a 30-day rolling
average basis. Commenter cited
attachment 1, GRE’s operational history,
as a rationale.
Response: The BART Guidelines
require specification of a 30-day rolling
average limit for EGUs; therefore, all
averaging times in the proposed FIP
have been stated on a 30-day rolling
average basis, including necessary
upward adjustments from annual
emission rates to account for potential
variations in emissions on a 30-day
basis. For the reasons stated elsewhere,
we have not changed our determination
that SNCR plus SOFA plus LNB is
BART, but we have changed the NOX
BART limit for CCS 1 and 2 to 0.13 lb/
MMBtu on a 30-day rolling average
basis.
Comment: Commenter argued that the
NOX emission limits proposed in the
original BART evaluation for Units 1
and 2 did not consider that the units
would experience significant load
variability. Commenter stated that in
September 2011, GRE increased the
cycling range of CCS in response to
market conditions, which caused
significant load swinging and impacts to
NOX control performance. Commenter
further stated that load variability is
expected to continue as an operational
scenario for Units 1 and 2 for the
foreseeable future, and therefore any
emission limit must account for this
additional variability in emissions. The
commenter asserted that the
presumptive emission rate of 0.17 lb/
MMBtu is achievable, including load
variability.
Response: The 0.13 lb/MMBtu limit
we have selected provides a reasonable
margin for compliance, not only for load
variability, but also for startup and
shutdown conditions. The emission
limit we have set also takes into
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consideration the control efficiency that
can be achieved with SNCR. We have
provided further discussion on this in
previous responses.
Comment: Commenter stated that
reducing NOX to the absolute limits of
LNC3 and DryFiningTM leads to
collateral damage to the CCS boilers.
Specifically, GRE claims that
installation of the second generation
LNC3 technology in 2008 on Unit 2
contributed to circumferential cracking
on the boiler tubes between the burner
front and the over-fired air registers, as
operators attempted to maintain low
NOX emission rates. GRE further stated
that the 2010 implementation of
DryFiningTM technology with LNC3
accelerated tube leaks at CCS 2, causing
unplanned outages. The commenter
asserted that while it has been possible
to operate at lower NOX emission rates
during ideal conditions, the risk of
circumferential cracking increases
significantly when operating at these
lower rates. The commenter concluded
that an emission rate between 0.14 and
0.17 lb/MMBtu for LNC3 and
DryFiningTM is not consistently
achievable as a 30-day rolling emission
limit; and the commenter firmly
believes that 0.17 lb/MMBtu is the most
stringent level.
Response: We have decided to finalize
our proposal that SNCR + SOFA + LNB
is BART. We note that using SNCR
would alleviate GRE’s concerns about
circumferential cracking from use of
LNC3 and DryFiningTM while also
helping to maintain NOX emissions
during periods of load variability. We
provide additional responses pertaining
to emission limits in this section.
Comment: Commenter stated that
from a review of EPA modeling
information from the Cross-State Air
Pollution Rule (CSAPR) docket,49 there
are currently no tangentially-fired utility
EGUs, in the CSAPR-affected states,
with LNC3 combustion controls and
49 See www.regulations.gov, docket EPA–HQ–
OAR–2009–0491.
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SNCR post-combustion controls that
operate at or below the presumptive
BART limit of 0.17 lb/MMBtu for NOX.
The commenter further stated that none
of the facilities included in the CSAPR
database operate at or below the
proposed FIP limit of 0.12 lb/MMBtu.
Response: The proposed 0.12 lb/
MMBtu emission rate was based on the
information that GRE itself supplied to
North Dakota in 2007, and which North
Dakota evaluated in its BART
determination. Starting from baseline
emission rates from 2000 to 2004 and
the 50% SNCR control efficiency that
GRE estimated, North Dakota arrived at
an average annual emission rate of 0.108
lb/MMBtu. We adjusted this to 0.12 lb/
MMBtu to arrive at a proposed 30-day
rolling average emission limit.
Our analysis focuses on what is
achievable using SNCR at CCS, based on
the Control Cost Manual, vendor
information (Fuel-Tech), the State’s
analysis, GRE’s analysis, and our own
analysis and expertise.
Analysis of emissions data found
significant discrepancies in Figures 2.2
and 2.3 of GRE’s November 2011
Refined Analysis. A review of EPA Title
IV data for 2010 showed 94 coal-fired
boilers that do not have SCR achieve
annual emissions levels below 0.17 lb/
MMBtu, with the median slightly under
0.14 lb/MMBtu (see Figure 1 below). Of
these, ten of them are using SNCR in
combination with combustion controls
to achieve under 0.17 lb/MMBtu. See
docket for a list of these facilities. Of
these ten, three are supercritical
tangentially-fired boilers that use lignite
coal with emissions below 0.14 lb/
MMBtu. These include Big Brown 1 and
Monticello 1 and 2, as discussed earlier
in our responses. In addition, the
NEEDS Database v.4.10 for the Final
Transport Rule in the CSAPR docket
includes two tangentially-fired coal/
steam units from North Carolina with
LNC3 and SNCR that had emission rates
of 0.159 lb/MMBtu and 0.164 lb/
MMBtu.
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As we explain elsewhere, we have
decided to revise the BART limit from
0.12 lb/MMBtu to 0.13 lb/MMBtu on a
30-day rolling average.
Comment: Commenter stated that the
0.14 lb/MMBtu emission rate would
only be achievable after installation of
SNCR (and cannot be achieved by LNC3
alone), and SNCR is not cost-effective
based on thresholds established by
North Dakota and already approved by
EPA.
Response: We are not aware of any
cost effectiveness thresholds established
by North Dakota and already approved
by EPA. In making a BART
determination, cost-effectiveness is one
factor that must be taken into account,
but the relevance of a particular dollarper-ton figure for controls will depend
on consideration of the remaining
statutory factors. As already explained,
we disagree with a number of GRE’s
assumptions underlying its cost
calculations and its assertion that SNCR
is not cost-effective.
As noted in prior responses, we no
longer agree that the use of SNCR at CCS
would lead to a loss of fly ash sales.
Accordingly, EPA has revised its cost
analysis on a per unit basis and has
determined that SNCR could be
installed and operated at CCS for
$1,313/ton. This value assumes no costs
for lost fly ash sales and no additional
fly ash disposal costs. This cost includes
combustion control costs and the
combined control efficiencies for SNCR
and combustion controls. Our research
indicates that the cost of up-front
ammonia slip control systems would
likely be included in the control
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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
50 This is based in part on, ‘‘Measuring Ammonia
Slip from Post Combustion NOX 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 NOX 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.
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20925
reasonable for BART, and that North
Dakota itself considered reasonable for
BART at other North Dakota sources. (76
FR 58623).
Comment: Commenter stated that
only supercritical boilers have shown
the capability to achieve less than 0.14
lb/MMBtu, using SNCR and LNBs.
Commenter further stated that, because
CCS does not have any supercritical
boilers and there are no other examples
of a tangential fired source with only
LNBs, it is unrealistic to expect any CCS
unit to attain an annual average of 0.14
lb/MMBtu, and even more unrealistic to
obtain this average on a 30-day rolling
basis, using LNB alone.
Response: Based on our evaluation of
data from CCS 2, we have decided that
combustion controls alone may not be
able to achieve a 30-day rolling average
limit of 0.14 lb/MMBtu at CCS on a
consistent basis. However, we have
decided to finalize our determination
that SNCR plus SOFA plus LNB is
BART and are promulgating a limit of
0.13 lb/MMBtu on a 30-day rolling
average basis.
We note that GRE claimed in its
refined analysis that data on
supercritical units does not provide an
indication of SNCR performance at CCS
because CCS does not have supercritical
units. Supercritical units typically
operate at higher furnace temperatures
than subcritical units. The higher
furnace temperature makes NOX
reduction with SNCR more difficult due
to the competing urea oxidation reaction
that causes NOX reduction to drop off at
high temperatures. As a result, one
would expect SNCR performance to
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generally be better at a subcritical unit
than a supercritical unit—all other
factors being equal.
g. Cost Effectiveness of SNCR and SCR
at CCS
Comment: Commenter stated that,
when combined, the new analyses
provided by URS and Golder Associates
confirm that SNCR is not cost-effective,
consistent with EPA’s presumptive NOX
analysis. These analyses essentially
reaffirm GRE’s initial determination that
DryFiningTM and LNC3 is BART for
CCS.
Response: Our prior responses
address the presumptive emission limits
and alleged cost effectiveness
thresholds. We disagree that GRE’s
consultants’ analyses confirm that SNCR
is not cost effective or reaffirm GRE’s
initial BART recommendation. As we
have noted, our analysis indicates that
SNCR plus LNC3 is more cost effective
than we estimated in our proposal.
Comment: Commenter stated that
only a site specific evaluation by a
competent SNCR supplier (URS) should
be used to estimate emission reductions
and associated costs. The URS refined
analysis is provided in Appendix B of
the GRE document. URS is a preeminent
engineering consultant in SNCR
technology, having designed several
dozen SNCR pollution control systems
throughout the world. This experience
qualifies URS to make site-specific
recommendations on SNCR design.
Response: EPA agrees that an
evaluation by a competent SNCR
supplier may be beneficial but notes
that GRE has only now brought its
‘‘refined analysis’’ forward. GRE found
it sufficient to supply several cost
estimates to the State without such
assistance. Regardless, URS is not an
SNCR technology supplier. While URS
is an engineering firm, it is not a
supplier or developer of SNCR
technology. As indicated in the
experience list provided by URS, URS’s
role in these SNCR projects was
primarily as constructor, performing a
feasibility study, engineering, or
procurement. In no cases was URS
actually the process supplier—the
company that actually designed the
process and made the performance
predictions and guarantees. See docket.
Depending upon the project shown in
the list provided by URS, its role may
have been associated with managing
project construction activities,
engineering and location of equipment
such as piping, tanks, etc., and in some
cases simply ‘‘feasibility studies,’’ but in
none of the cases it cites did URS
actually design the SNCR process and
develop performance guarantees.
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While location of tanks, routing of
process piping and other engineering or
construction activities are important
aspects of a project, they do not
determine the process performance.
Critical aspects of SNCR process design,
which determine performance (NOX
reduction, reagent use and ammonia
slip), are design of and location of
injectors in the furnace, specification of
reagent type, flowrates and control
logic. Process design is performed by
companies such as Fuel Tech, having
supplied many utility SNCR systems, or
other companies. For example, some of
the installations cited by URS in its
experience list, such as TVA
Johnsonville and PEPCO were supplied
by Fuel Tech or Advanced Combustion
Technology. As indicated in the table
provided by URS, URS apparently had
a role in the engineering of these
projects (location of storage tanks,
piping between components, etc.), but
did not develop the process design or
the performance estimates for the TVA
or PEPCO installations. Other
installations cited by URS (new boilers
at AES Warrior Run and the two Air
Products installations) were actually
designed and supplied by the
circulating fluid bed boiler suppliers,
with performance and guarantees
developed by the boiler supplier. The
balance of the installations cited by URS
were either feasibility studies, where no
real process guarantees were made, or
were actually supplied by other
companies (Applied Utility Systems,
ESA, or others). In fact, the study that
URS has conducted for GRE on CCS is
essentially a feasibility study. Aside
from URS’s experience, the analysis
URS conducted does not support that
the CCS units are so unique that Control
Cost Manual estimates of SNCR
performance and costs are irrelevant.
Thus, while URS has the expertise to
provide useful input on the cost
associated with installing some of the
associated equipment, it is not in the
business of providing SNCR process
designs and performance guarantees—
and it apparently did not do this on any
of the projects on its experience list.
GRE argues that the CCS units are
unique and thus require evaluation by
an SNCR process supplier in lieu of an
analysis based on the Control Cost
Manual. However, GRE has not
provided any information from
companies that actually design SNCR
systems and have experience providing
performance guarantees, such as Fuel
Tech or another company that is an
experienced SNCR supplier. Thus,
GRE’s claims about SNCR performance
are not supported.
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The control efficiency of SNCR is the
main issue raised by URS because it has
a significant impact on the overall cost
effectiveness of SNCR, as further
explained later in our responses. URS
also provides a cost estimate which is
used to support GRE’s own cost
analysis. While GRE comments that
‘‘only a site specific evaluation, by a
competent SNCR supplier (URS), should
be used to estimate emission reductions
and associated costs,’’ the evaluation
provided by URS is based on data from
other plants. URS extrapolates the SNCR
control efficiency using CCS data from
a plot of control efficiency versus inlet
NOX concentrations for 55 existing
SNCR installations. This differs from the
Control Cost Manual, which plots
control efficiency as a function of boiler
size. Neither is a definitive ‘‘site
specific’’ measure of estimating control
efficiency. Furthermore, there are many
other factors besides inlet NOX
concentration that affect the efficiency
of an SNCR system. Thus, GRE has
provided little support for reducing the
SNCR control efficiency by 20 to 30
percentage points from the efficiency
used in the proposed FIP and from what
they themselves originally estimated
(i.e., from 50% down to 30% or 20%).
Since GRE has not provided any
information from companies that
actually design SNCR systems and have
experience providing performance
guarantees, GRE’s claims, that its prior
representations about SNCR
performance should be disregarded, are
not supported.
Comment: Commenter states that
EPA’s analysis contains faults that,
when corrected, lead to the conclusion
that SCR, not SNCR, is BART for the
CCS units. The faults include, first, that
the EPA analysis of $4,116/ton is, on its
own, cost effective and close to the cost
effectiveness value North Dakota and
EPA accepted at Stanton Station Unit 1
of $3,778/ton. Second, EPA retains the
80% control efficiency for SCR from the
State’s BART determination when,
elsewhere in the proposal, EPA
acknowledges that SCR is capable of
90% control. The commenter adjusted
the cost effectiveness value to $3,595
based on 90% control efficiency which,
the commenter states, is cost effective
and below the Stanton Station Unit 1
cost effectiveness previously mentioned.
Third, EPA retained costs related to loss
of sales from fly ash disposal in the SCR
cost analysis, which is perhaps in error
as there is no reason a well-designed
SCR, particularly in the low dust or tail
end configuration, would impact ash
sales. SCRs can meet 2 ppm ammonia
slip, and at that level the ammonia in
the ash is typically acceptable for all
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uses. Additionally, mitigation of
ammonia in ash is feasible, and is
probably a less costly option if ammonia
is, improbably, an issue.
Response: We disagree with the
comment regarding the control
efficiency of SCR at CCS. We have
determined that the 0.043 lb/MMBtu
emission rate that North Dakota used in
its cost analysis based on the 80%
control efficiency was acceptable and
probably the best performance
achievable with SCR technology taking
into consideration the existing
combustion controls. Based on our own
investigation, as discussed in our
responses to GRE’s comments discussed
above, we agree with the commenter on
the issue of fly ash and have revised our
cost analysis. We have removed the lost
fly ash sales and fly ash disposal costs.
We further agree that ammonia levels in
the ash will not be problematic and are
not including ammonia mitigation costs
in our analysis. Our revised analysis
relies on the $280/kW installed capital
cost that we discussed in our proposal.
We used the $280/kW capital cost in
lieu of the $110/kW figure that is
derived from GRE’s capital cost
analysis. As we stated in our proposal,
$110/kW is unreasonably low compared
to actual industry experience. Based on
these changes, we calculate a cost
effectiveness value for LDSCR + ASOFA
+ LNB at CCS of $5,603/ton of NOX
removed. We find that this cost is
excessive in light of the predicted
visibility improvement. Thus, we are
not changing our determination that
SNCR+ASOFA+LNB is NOX BART at
CCS 1 and 2.
Comment: Commenter stated that the
furnace boxes for CCS 1 and 2 are
unique, as required by the high moisture
content of Fort Union lignite.
Commenter stated that the firebox is
larger than other lower-moisture coalfired units, resulting in a higher cost of
NOX combustion controls. Specifically,
the commenter stated that the greater air
flow distance through the furnace
requires increased size and type of wall
nozzles and increased staging
complexity; and an advanced air
combustion system added to a larger
firebox requires additional wall
openings and redesign to wall water
tubes, further increasing costs.
Response: All electric utility boilers
are built to the owner’s specifications
and are, therefore, unique. However, the
information presented by the
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commenter has not convinced us that
the CCS boilers are so unique that our
costing assumptions or our overall cost
estimates are unreasonable. The fuel
burned at CCS is very low BTU fuel,
which contributes to the large furnace
size. Therefore, it is possible that a
combustion retrofit for CCS might be
somewhat higher in cost than for a
similar retrofit for a boiler of similar
output firing a higher Btu coal.
Examination of Title IV data shows
several lignite fired boilers with
significantly lower emissions than at
CCS—some using only combustion
controls and some using combustion
controls in combination with SNCR.
The application of SNCR on low-BTU
fuel utility boilers goes back to the late
1980’s when it was successfully applied
to German brown coal boilers.54 The
larger furnace volume of a lignite or
other low-Btu furnace actually provides
more time for the SNCR reaction to
occur, which should be beneficial for
mixing and the SNCR reaction. The
advantage will likely be improved
reagent utilization.
Comment: Commenter stated that the
larger registers installed at CCS 2 further
reduce NOX emissions as they allow for
increased primary air which is available
after installation of DryFiningTM, and
that larger registers are tentatively
anticipated to be installed at CCS 1 in
2014.
Response: We evaluate potential
control options based on baseline
conditions, not on ongoing revisions to
a facility after the baseline period. It is
not reasonable to consider controls
installed after the baseline period in
determining BART. Such an approach
would tend to lead to higher cost
effectiveness values for more effective
controls and encourage sources to
voluntarily install lesser controls to
avoid installing more effective BART
controls later.
Comment: Commenter stated that
URS reviewed and updated both capital
and operating costs for SNCR, based on
their expertise and site specific
investigation. These values were
relatively consistent with values
presented to EPA in June and July 2011,
but are somewhat higher than the
screening values presented in the
original BART analysis.
54 Hofmann, J.W., von Bergmann, J., Bokenbrink,
D., Hein, K. ‘‘NOX Control in a Brown Coal-Fired
Utility Boiler.’’ Presented at the EPRI/EPA
Symposium on Stationary Combustion NOX
Control, San Francisco, CA, March 8, 1989.
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20927
Response: The higher costeffectiveness ($/ton) of SNCR in GRE’s
November 2011 submittal can be
primarily attributed to the lower control
efficiency value assigned to the
technology. The July 2011 study
estimates a control efficiency of 50% for
SNCR, which yields a cost effectiveness
value of $3,198/ton for both Units 1 and
Units 2 (one estimate). The November
2011 study estimates an SNCR control
efficiency of 25% for Unit 1 and 20%
for Unit 2, which yields a cost
effectiveness value of $7,629/ton and
$10,506/ton for Units 1 and 2
respectively.
It should be noted that the November
study actually estimates lower capital
and annual costs of control, each of
which would independently lower the
cost effectiveness value. The total
capital investment for SNCR estimated
in the July study was $12.72 million,
compared to $12.18 million and $11.80
million for Units 1 and 2, respectively,
in the November study. The annualized
capital plus operating costs in the July
study were estimated at $8.91million,
compared to $8.79 million and $8.12
million for Units 1 and 2 in the
November study. One of the main
reasons that costs are higher in the July
study is maintenance costs; the annual
maintenance costs in the July study are
$1,907,375 compared to approximately
$180,000 for each Unit in the November
study.
The baseline emission rate is another
factor which would result in higher cost
effectiveness values in the November
study. The baseline emission rate in the
July study was estimated at 0.22 lb/
MMBtu, compared to 0.20 lb/MMBtu
and 0.153 lb/MMBtu for Units 1 and 2
in the November study. A lower
emission rate would result in less
emissions controlled and a higher cost
effectiveness value.
The lower SNCR control efficiency in
the November study results in less NOX
controlled (i.e., 1,152 tons per year (tpy)
for Unit 1 and 772 tpy for Unit 2 in the
November study versus 2,786 tpy NOX
controlled in the July study), and a
higher overall cost effectiveness value.
The reduced SNCR control efficiency
outweighs the changes to the cost of
control, which would otherwise result
in lower cost effectiveness values.55
55 Our analysis differs in that we considered
SNCR combined with combustion controls.
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TABLE 1—COMPARISON BETWEEN COST EFFECTIVENESS FACTORS IN GRE’S JULY AND NOVEMBER 2011 COST
ESTIMATES FOR CCS
Baseline
emission rate
(lb/MMBtu)
Study description
SNCR, July Study, Both Units ...................................
SNCR, November Study, Unit 1 ................................
SNCR, November Study, Unit 2 ................................
0.22
0.2
0.153
Control
efficiency
50
25
20
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Installed
capital cost
(MM$/yr)
2,786
1,152.8
772.5
0.20 lbNO2/MMBtu * (30 lb urea/46 lb
NO2) = 770 lb/hr.
This is roughly half of what URS
calculated as the urea usage. In all of the
cases URS estimated, the result is high.
Since URS appears to have
overestimated the reagent cost, it is
The costing algorithms in this report are
likely that URS overestimated the water
based on retrofit applications of SNCR to
existing coal-fired, dry bottom, wall-fired and cost as well.
tangential, balanced draft boilers. There is
In this case, with urea at $500/ton
little difference between the cost of SNCR
delivered, the reagent portion of cost
retrofit of an existing boiler and SNCR
would be:
installation on a new boiler.56 Therefore, the
$500/ton * (1 ton/2000 lb)* 770lb/hr =
cost estimating procedure is suitable for
$192/hr.
retrofit or new boiler applications of SNCR
on all types of coal-fired electric utilities and
The tons removed per hour would
large industrial boilers.57
equal:
Therefore, retrofit costs are inherent
(5900 MMBtu/hr)*(0.20 lb NO2/
in the costs provided by the Control
MMBtu)*(0.25 reduction)*(1 ton/
Cost Manual method and there is no
2000 lb) = 0.148 ton/hr.
need to introduce a retrofit factor. In
The reagent portion of cost is 192/
using a retrofit factor of 1.6, URS
0.148 = $1,300/ton of NOX removed.
overestimated capital costs by 60%.58
This $/ton for reagent would be the
Another concern we have is that
same assuming the same cost per ton of
URS’s estimate of reagent usage is high.
urea and the same chemical utilization
The following is an examination of the
(25%, or 25% reduction at an NSR =
0.20 lb/MMBtu inlet level with 25%
1.0).
reduction case in URS’s Table 4.59 Using
The errors in the URS estimate are
60 an
a boiler rating of 5900 MMBtu/hr,
carried through to GRE’s estimates.
initial NOX level of 0.20 lb/MMBtu, and
Comment: Commenter stated that
a normal stoichiometric ratio (NSR) of
with the installation of LNC3, LNC3+,
1.0 (30 lb urea/46 lb NO2),61 the hourly
and DryFiningTM;, CCS’s NOX emissions
usage of reagent is: 5900 MMBtu/hr *
are greatly reduced with respect to
‘‘baseline’’ values previously provided;
56 Rini, M.J., J.A. Nicholson, and M.B. Cohen.
and it is necessary to update the
Evaluating the SNCR Process for Tangentially-Fired
Boilers. Presented at the 1993 Joint Symposium on
baseline emissions for Units 1 and 2 for
Stationary Combustion NOX Control, Bal Harbor,
this technology evaluation in order to
Florida. May 24–27, 1993.
reflect current conditions and unit
57 Control Cost Manual, Section 4.2, p. 1–4.
performance. Commenter stated that the
58 It appears that URS overestimated capital costs
revised baseline emissions for Units 1
in other ways as well. Consistent with the BART
Guidelines, and as outlined in our proposal and in
and 2 should be adjusted to 0.201 lb/
this action, we have applied the factors permitted
MMBtu and 0.153 lb/MMBtu,
by EPA’s Control Cost Manual to GRE’s estimate of
respectively. The commenter stated that
direct capital equipment costs for SNCR to arrive
the use of DryFiningTM technology has
at a reasonable estimate of the total capital
investment. We do not agree with URS’s estimate
already been implemented for use at
of total capital investment because it relies on
both units at a cost of $270 million, and
factors that are inconsistent with the Control Cost
GRE has made a significant investment
Manual.
59 URS did not analyze a case with the parameters
to achieve multi-pollutant emission
we have determined are most reasonable; we are
reductions and visibility improvements
providing the reagent cost review of one of URS’s
in the region.
cases to highlight our concerns with the
Response: As stated in our previous
methodology. Considering an inlet emission rate of
comments, we reject GRE’s revised
0.15 lb/MMBtu and a 25% reduction, the
parameters we find are reasonable, the reagent cost
baseline. We evaluate potential control
would be $1,304/ton using a similar analysis.
options based on baseline conditions,
60 EPA and the North Dakota SIP assume 6,112
not on ongoing voluntary revisions to a
MMBtu/hr, but URS assumes 5,900 MMBtu/hr. The
facility after the baseline period. It is not
difference will not affect the conclusion that URS’s
reagent costs are high.
reasonable to consider voluntary
We do not agree with the capital and
operating costs estimated by GRE. First,
URS has inappropriately applied a
retrofit factor when calculating capital
costs for the SNCR system. The Control
Cost Manual states:
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Emission
reduction
(ton/yr)
12.72
12.18
11.8
Annual
O&M cost
(MM$/yr)
8.91
8.79
8.12
Pollution
control cost
($/ton)
3,198
7,629
10,506
controls installed after the baseline
period in determining BART. Such an
approach would tend to lead to higher
cost effectiveness values for more
effective controls and encourage sources
to voluntarily install lesser controls to
avoid more effective BART controls
later.
Comment: The refined economic
impacts analysis provided by GRE
confirms GRE’s original conclusion that
SNCR is not a cost effective NOX control
option.
Response: We disagree with the cost
effectiveness analysis provided by GRE
in the refined analysis. We disagree
with the control efficiency used for
SNCR in combination with SOFA plus
LNB used in the refined analysis, the
assumed baseline and controlled
emission rates, and the assumed
reduction in ash sales. These issues are
further discussed in the comment
responses specific to each issue.
h. CCS General Comments
Comment: The commenter stated that
at the time of this submittal, GRE has
already installed LNC3 combustion
controls at Unit 2. In 2011 dollars, this
was at a cost of over $6 million and has
already resulted in NOX reductions. The
same system is tentatively scheduled to
be installed on Unit 1 during the 2014
outage.
Response: As stated in our previous
comments, we reject GRE’s use of a
revised baseline.
3. Stanton Station Unit 1
Comment: Commenter states that the
BART limits for the Stanton Station are
contrary to BART requirements.
Commenter states that both SO2 and
NOX emission rates would decrease if
only Powder River Basin (PRB) coal
were allowed to be burned, because the
burning of North Dakota lignite coal
creates higher emissions of both
pollutants. Commenter also states that
EPA’s cited 7th Circuit Court of Appeal
decision (76 FR 58589) would not apply
to such a requirement because that
decision only applies to the redesign of
a source.
Response: We do not interpret the
CAA or the regional haze regulations as
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requiring states to consider limiting the
type of coal burned as a BART control
technology. We note that we did not cite
the referenced 7th Circuit decision in
support of our proposal to approve the
BART limits for Stanton Station.
Comment: One commenter states that
EPA is proposing to approve SNCR +
OFA + LNB as NOX controls for Stanton
Station Unit 1. While the commenter
supports the use of further NOX controls
at this facility, the commenter asks EPA
to further evaluate the cost estimates for
SCR at this facility. According to the
commenter, the cost estimates for SCR
that EPA relied on in its proposal
appear to include, at a minimum, costs
associated with allowance for funds
used during construction (AFUDC),
which is not appropriate under the
BART Guidelines and Control Cost
Manual. Further, the underlying
calculations in Stanton Station’s BART
submission to North Dakota do not
clearly support the resulting cost.
Response: We relied on cost estimates
submitted by North Dakota in our
evaluation of the cost effectiveness of
NOX control options for Stanton Station
Unit 1. In turn, North Dakota relied on
costs taken from GRE’s BART analysis
as found in Appendix C.2 to the SIP.
GRE asserts that these costs were
derived ‘‘using the procedures found in
the EPA Air Pollution Control Cost
Manual.’’ 62 However, as suggested by
the commenter, there are irregularities
in how GRE applied the SCR cost
methods in the Control Cost Manual. In
particular, GRE included a line item for
AFUDC in the amount of $8,232,000.
However, closer examination reveals
that this line item represents the cost of
replacement power associated with a
purported 10 week outage for
installation of the SCR, and does not
represent allowance for funds used
during construction. Regardless,
elimination of this line item would only
lower the cost effectiveness values for
SCR when burning lignite and PRB coal
from $6,475/ton to $6,118/ton and
$8,163/ton to $7,713/ton, respectively.
In addition, the total capital investment
stated by GRE for SCR of $55,279,000
equates to $294/kilowatt (kW). We find
this cost consistent with the installed
SCR retrofit costs, ranging from $79/kW
to $316/kW (2010 dollars), cited in
recent industry studies.63 We expect
that the cost at Stanton Station Unit 1
would be at the higher end of this range
given its relatively low generation
capacity of 188 MW. Accordingly, while
we agree that there are questions
regarding the underlying calculations, it
is our opinion that further evaluating
costs would not change the outcome of
the BART determination.
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.
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
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4. Leland Olds Station Unit 1
Comment: Commenter stated that
SCR, not SNCR, is BART at LOS 1.
Commenter further stated that EPA
assumed that Basin Electric
overestimated the costs for SCR at this
unit, but did not re-estimate the costs.
Commenter analyzed the costs based on
the revised cost for SCR at Unit 2, and
considers its lower cost estimate ‘‘well
within the range of values determined to
be cost effective in similar regulatory
proceedings.’’
Response: We have included in the
docket for our final action an SCR cost
estimate for LOS 1 that was based on
methods similar to those we used for
our SNCR cost analyses for MRYS 1 and
2 and LOS 2. The analysis was not an
exhaustive effort but was used as a
check of the analysis provided by North
Dakota. Our analysis found the cost of
SCR + SOFA would be approximately
$5,132/ton of NOX emissions removed
with an incremental cost effectiveness
between the SCR and SNCR control
options of $8,845/ton of NOX emissions
removed. The cost estimates for SCR at
LOS 1 that National Parks Conservation
Association (NPCA) and the NPS
provided in their comments reflect cost
effectiveness values greater than $4,000/
ton of NOX emissions removed. While
these various estimates are lower than
those the State relied on, they are still
high enough that we are not prepared to
change our conclusion that the State’s
BART determination of SNCR + Basic
SOFA for LOS 1 was reasonable.
Comment: Commenter stated that
there is no discussion why SNCR +
Boosted SOFA was rejected as BART.
Response: In response to this
comment, we reviewed the benefits of
SNCR + Boosted SOFA over SNCR +
Basic SOFA. We determined that the
two combustion control options achieve
very similar results and that the
incremental cost of the Boosted SOFA
option at $7,826/ton is excessive
compared to the 92 tons of additional
NOX reductions, which we anticipate
would provide a low visibility benefit.
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achievable using scrubber technology
since scrubbers can achieve 99% control
efficiency. Commenters also stated that,
with regard to SO2, EPA should require
both the lb/MMBtu limit and the
percent control efficiency limit to be
met in order to meet BART, rather than
require that either limit be met as EPA
proposed. One commenter stated that if
only the percent reduction limit is set,
emissions will increase with the sulfur
content of the fuel unless sulfur content
is also limited. One commenter
requested EPA set a numeric limit rather
than percent reductions.
Response: We agree that the RHR
requires states to consider the most
stringent level of control. We also agree
that, in most applications, wet or dry
scrubbers can achieve greater emission
reductions than those required by North
Dakota. However, there is very limited
data on the performance of wet or dry
scrubbers at units firing lignite, such as
those in North Dakota. In a 2007 BACT
determination for two new lignite-fired
boilers at Oak Grove Station in Texas,
the Texas Commission on
Environmental Quality established an
SO2 emission limit of 0.192 lb/MMBtu
on a 30-day rolling average. Based on
this, we find that the emission limits
established by North Dakota are not
unreasonable. Also, we would like to
emphasize that three of the North
Dakota units have existing controls for
SO2 and that the emission reductions
that can be achieved with upgrades to
these existing controls may not be as
great as those that can be achieved by
a new scrubber installation. Finally, on
the point of allowing either a lb/MMBtu
or a percent control efficiency limit, we
typically prefer a single limit. However,
the BART guidelines list the
presumptive levels in units of lb/
MMBtu or a percent reduction, and we
cannot say that the State’s approach is
inconsistent with the guidelines. The
State chose to take advantage of this
point and specifically found that it was
not appropriate to establish limits on a
lb/MMBtu and percent reduction basis.
This was in part to allow for the
potential that higher sulfur coals might
be burned in the future, in which case
the State believed that the percent
reduction basis would extend greater
flexibility. Based on these factors and
our consideration of all the
circumstances involved, we find that
the SO2 emission limits established by
North Dakota are not unreasonable and
we are approving them.
Comment: Commenters stated that
North Dakota did not consider
upgrading ESPs to decrease PM
emissions, as is required by the BART
Guidelines.
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Response: As noted in our proposal,
the ESPs already reduce emissions by
99% or greater. Where new wet or dry
scrubbers or modifications to existing
scrubbers will be installed, additional
PM emission reductions, particularly of
sulfuric acid mist, will be achieved.
Moreover, as noted in North Dakota’s
SIP, the visibility improvement that can
be achieved by further reducing PM is
minor. For example, North Dakota’s
BART determination for M.R. Young
Unit 2 shows that the highest visibility
impact from PM in the baseline was
0.0165 deciviews (LWA, 2001). SIP,
Appendix B.4, p. 26. Similarly, North
Dakota’s BART determination for
Stanton Station Unit 1 shows that
reducing PM from 0.1 lb/MMBtu to
0.015 lb/MMBtu would only improve
visibility by 0.021deciviews (TRNP–SU,
2002). SIP, Appendix B.3, p. 9.
Accordingly, we find that North Dakota
reasonably eliminated ESP upgrades
from consideration.
Comment: One commenter stated that
the control efficiency for baghouses was
underestimated.
Response: We agree that the control
efficiency for baghouses was
underestimated. However, this has no
practical bearing on our evaluation of
North Dakota’s BART control
determinations for PM as, consistent
with the BART Guidelines, North
Dakota was not required to consider the
replacement of existing PM control
devices. Stanton Station is the only
facility where North Dakota is requiring
new PM controls, but this is only in
association with the spray dryer
absorber needed to control SO2.
Comment: Commenters stated that a
PM continuous emission monitoring
system (CEMS) must be installed,
operated and used to demonstrate
continuous compliance with the PM
emission limits on units that are subject
to BART.
Response: PM CEMS would provide
the most robust means of demonstrating
continuous compliance with the PM
emission limits. However, we disagree
that their use is required. We find that
the monitoring requirements in the RH
SIP are adequate to demonstrate
continuous compliance with the PM
emission limits.
Comment: BART should be evaluated
for both course particulate matter (PM10)
and PM 2.5, but was only evaluated for
PM10. EPA should therefore impose a
BART limit on total PM2.5.
Response: In our BART Guidelines,
for the purposes of identifying visibility
impairing pollutants, we allowed states
to use emissions of PM10 as an indicator
for PM2.5, as the components of PM2.5
are a subset of PM10. 70 FR 39160. For
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the same reasons, we find that it is
reasonable for North Dakota to have
explicitly evaluated BART only for
PM10. We also note that North Dakota
did evaluate BART for condensable PM
which comprises a large portion of the
PM2.5.
Comment: Commenter stated that
North Dakota incorrectly set a limit for
PM at .07 lbs/MMBtu. Commenter
stated that the actual emissions from
most units averaged .03 lbs/MMBtu to
.05 lbs/MMBtu, and there is therefore no
support for limits higher than .03 lbs/
MMBtu. Additionally, the commenter
asserted that these limits should be set
on a unit-by-unit basis.
Response: As noted in prior responses
to comments, the visibility
improvement that could be achieved
with new or upgraded PM controls is
negligible. That response also holds true
within the context of setting tighter
emission limits. Therefore, we find that
PM emission limits set by North Dakota
are not unreasonable.
Comment: Commenter stated that EPA
deviates from the BART guidelines in
failing to establish a clear time period
(hourly, 24-hour, 30-day or annual) over
which the proposed PM limits would
apply. Commenter further stated that
North Dakota’s BART determinations
are unenforceable because there are no
proposed monitoring, recordkeeping
and reporting requirements that would
ensure compliance with the filterable
PM limits. Commenter stated that this
was contrary to the CAA, because BART
is defined as based on continuous
emission reductions, which cannot be
ensured.
Response: We disagree with the
commenter. First, we seek to clarify that
while emission limits must be
enforceable as a practical matter, the
BART Guidelines clearly state that
CEMs are not required in every instance.
70 FR 39172. Moreover, the BART
Guidelines recognize that monitoring
requirements are in many instances
governed by other regulations, such as
compliance assurance monitoring.
North Dakota established monitoring,
recordkeeping and reporting
requirements for PM emission limits in
permits to construct which are included
in Appendix D of the SIP. The
monitoring requirements for PM include
emission testing using EPA-approved
test methods, such as Method 5B and
Method 17. As specified in each permit
to construct, these tests must consist of
three test runs, with each test run at
least 120 minutes in duration. The
monitoring requirements also require
the use of a Continuous Assurance
Monitoring (CAM) Plan developed in
accordance with NDAC 33–15–14–
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06.10. The CAM Plan will include other
provisions necessary to show
compliance. We find that these
monitoring provisions are adequate to
ensure continuous emission reductions
as required under BART.
G. Comments on Reasonable Progress
and North Dakota’s Long-Term Strategy
Comment: Minnkota states that EPA’s
proposed FIP does not follow EPA
guidelines for RP determinations. The
commenter cites, without a page
number, the Burns & McDonnell report
attached to the comments.
Response: EPA is unable to identify
any support in the Burns & McDonnell
report for the statement. Standing alone,
the comment is insufficiently specific to
warrant a response. Below, EPA
responds to comments that EPA’s
disapproval of the State’s RP
determination for AVS is inconsistent
with EPA guidelines.
Comment: Minnkota states that EPA’s
actions disapproving the State’s RPGs
and imposing RP controls on MRYS lack
a basis.
Response: EPA disagrees with this
comment. First, as stated in the
proposal, the disapproval of the State’s
RPGs is based on the State’s failure to
demonstrate that the RPGs the State
selected are reasonable, based on the
four statutory factors. In particular, the
State’s use of a degraded background in
modeling for visibility benefits was
unreasonable, as was the State’s failure
to select RP controls for AVS. Second,
the commenter appears to misinterpret
the statements made regarding MRYS
Units 1 and 2 as proposing to impose RP
controls on those units. In any case, the
reference to controls on MRYS Units 1
and 2 is no longer relevant, because we
have decided to approve North Dakota’s
NOX BART determination for MRYS
Units 1 and 2.
Comment: Minnkota states that EPA’s
action in disapproving the State’s LTS is
unreasonable and simplistic.
Response: EPA disagrees with this
comment. The LTS is a compilation of
the State-specific controls relied upon
by the State for achieving its RPGs. We
are disapproving the State’s RPGs along
with certain NOX BART and RP
determinations and promulgating a FIP
to impose RPGs that are consistent with
our FIP NOX BART and RP
determinations. To the extent that the
State’s LTS relies on these NOX BART
and RP determinations, we must also
disapprove those portions of the LTS.
Specifically, our partial disapproval of
the State’s LTS consists of two parts: (1)
Disapproval of the LTS with regard to
permit limits and monitoring,
recordkeeping, and reporting
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requirements in the State’s submittal
that correspond to the NOX BART
determinations we are disapproving;
and (2) disapproval of the LTS with
regard to the NOX reasonable progress
determination for AVS Units 1 and 2,
and with regard to the corresponding
monitoring, recordkeeping, and
reporting requirements. The monitoring,
recordkeeping, and reporting
requirements for Antelope Valley are
necessary to ensure that the emissions
limitations and control measures to
meet RPGs are enforceable. See 40 CFR
51.308(d)(3)(v)(F). In addition, these
requirements are generally necessary to
ensure the BART limits are enforceable.
See CAA 110(a)(2). As these
requirements are necessary adjuncts to
the BART and RP limits, our
disapproval of the State’s requirements
necessarily flows from our disapproval
of the NOX BART determinations for
CCS Units 1 and 2 and the disapproval
of the State’s NOX RP determination for
AVS Units 1 and 2.
Comment: NDDH states that EPA
incorrectly rejected NDDH’s RP
modeling methodology. NDDH believes
that the methodology properly took into
account effects of international sources,
as provided for in the RHR.
Furthermore, the hybrid methodology
was, in NDDH’s view, necessary to
accurately simulate transport from large
point sources.
Response: Our response to this
comment is provided with our
responses to modeling comments in
section V.C.
Comment: NDDH states that its
cumulative modeling methodology more
accurately reflects the visibility
improvements from controls at point
sources.
Response: Our response to this
comment is provided with our
responses to modeling comments in
section V.C.
Comment: NDDH notes that EPA
supported the development of the
WRAP cumulative modeling, which
NDDH states involved considerable time
and resources. NDDH argues that it is
inappropriate to diminish this extensive
effort by using what NDDH views as a
less sophisticated and inconsistent
single-source approach.
Response: EPA disagrees with this
comment. As discussed elsewhere,
single-source modeling is not ‘‘less
sophisticated’’ or ‘‘inconsistent.’’ EPA
supported development of WRAP
CMAQ modeling in order to assist states
in developing their RPGs. This support
does not endorse the use of cumulative
modeling to determine single-source
impacts, a faulty approach for the
reasons discussed above. As discussed
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below in responses to comments later in
this section, NDDH’s comment conflates
the requirements for RPGs with the
requirements for evaluating RP controls
for single sources.
Comment: NDDH states that, on a
dollar-per-ton-removed basis, LNB +
SNCR appears to be reasonable for AVS.
However, NDDH argues that its dollarper-deciview evaluation of visibility
benefits from installing LNB + SNCR at
AVS shows that the cost is excessive.
Response: EPA disagrees with this
comment, to the extent that it can be
understood to argue against EPA’s
determination to impose LNB at AVS to
meet reasonable progress requirements.
The dollar-per-deciview cost that NDDH
relies upon is faulty because, as
discussed elsewhere, it relies on
modeling using current degraded
background that greatly underestimates
the visibility improvement of singlesource controls when compared to
accepted methodology. It therefore
provides no basis for determining that
the cost of LNB + SNCR is excessive, or
that the cost of LNB alone is excessive.
Elsewhere, we have also discussed some
of the difficulties with using dollar-perdeciview cost effectiveness values, and
how care must be taken not to
misinterpret such values. EPA does note
that NDDH describes the dollar-per-ton
cost of LNB + SNCR as reasonable.
Using North Dakota’s costs, LNB +
SNCR has a cost-effectiveness value of
$2,268 per ton removed at Unit 1 and
$2,556 per ton removed at Unit 2. By
comparison, LNB alone, using North
Dakota’s costs, has a cost-effectiveness
value of $586 per ton removed at Unit
1 and $661 per ton removed at Unit 2.
This indicates that LNB has a very
reasonable cost effectiveness value on a
dollar-per-ton-removed basis, the metric
that is most widely used and
understood in making control
technology determinations.
Comment: NDDH references its
CALPUFF modeling of visibility
improvement at AVS from installation
of LNB. NDDH states that this modeling
was intended to show greater visibility
improvement from installation of LNB
on the two units at Antelope Valley as
compared to installation of SCR at
Leland Olds Station. NDDH argues that
CALPUFF overpredicts visibility
improvements and does not comply
with 51.308(d)(1) and EPA’s guidance.
Response: For reasons expressed
elsewhere in this action, we disagree
with North Dakota’s argument that
CALPUFF overpredicts visibility
improvements. Our response to the
argument that use of CALPUFF does not
comply with 51.308(d)(1) and EPA
guidance is provided with other
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responses in this section. While NDDH
may have provided the CALPUFF
modeling for another purpose, we find
it informative. The CAA does not limit
EPA in its action on a SIP submittal to
considering materials only for the
purpose for which the materials were
originally intended. Instead, EPA may
consider all relevant materials,
including the CALPUFF modeling of
visibility improvement from installation
of LNB at AVS.
Comment: NDDH notes that even if all
sources of SO2 and NOX in North Dakota
were eliminated, North Dakota could
not achieve the URP. North Dakota
states that additional controls for AVS
make almost no difference, and that
additional controls on sources outside
of North Dakota are necessary to achieve
the URP.
Response: As we stated in our
proposal, we agree that North Dakota
could not achieve the URP in the first
planning period even if all North Dakota
sources were eliminated. We do not
agree that this means that North Dakota
can accordingly do nothing in the first
planning period to address reasonable
progress beyond addressing the BART
requirements or that the State can reject
otherwise reasonable control measures.
EPA assumes that NDDH bases its
statement regarding ‘‘almost no
difference’’ on the modeling using
current degraded background
conditions. The CALPUFF modeling for
AVS (separately provided by NDDH)
predicts a visibility benefit at TRNP of
0.754 deciviews from installation of
LNB, which EPA does not regard as
‘‘almost no difference.’’ Regardless of
whether controls on sources outside of
North Dakota are necessary in order to
achieve natural visibility conditions by
2064, North Dakota is required to
provide a reasoned analysis of RP
controls on sources within the State.
With respect to AVS, the State did not
do so.
Comment: North Dakota states that,
based on the definition of ‘‘most
impaired days’’ and ‘‘least impaired
days’’ in 51.301, and the requirement in
51.308(d)(1) that the RPGs provide for
improvement in visibility for the most
impaired days over the planning period
and ensure no degradation in visibility
for the least impaired days over the
planning period, any RP visibility
analysis must be a cumulative analysis
and must address the most impaired
days. NDDH states that it consistently
modeled BART and RP sources. NDDH
argues that, under the RHR and EPA
guidance, progress with respect to the
URP must be assessed using cumulative
modeling based on the controls imposed
on multiple sources. It would be
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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
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and the State’s interpretation of
statements in EPA’s BART guidelines as
to sources that could reasonably be
exempted from the BART review
process; i.e., for a state with a BART
contribution threshold of 0.5 deciviews,
sources emitting less than 500 tons per
year located more than 50 kilometers
from a Class I area or emitting less than
1000 tons per year located more than
100 kilometers from a Class I area.64 We
note that North Dakota selected 0.5
deciviews as its contribution threshold
for determining which sources are
subject to BART.
North Dakota eliminated any source
with a Q/D less than 10 from further
consideration for reasonable progress
controls. Then, North Dakota eliminated
several sources with a Q/D over 10 that,
as a result of events after the 2000 to
2004 baseline period, had reduced
emissions sufficiently so that the
sources’ Q/D became less than 10. After
this paring, seven units remained. We
note that four of the remaining seven
units are EGUs, and three of them are
comparable in size and emissions to
some of the largest BART sources in
North Dakota.
For these seven remaining units only,
North Dakota considered the four
statutory reasonable progress factors in
evaluating potential control
technologies for reducing SO2 and NOX
emissions. However, when it eliminated
all reasonable progress controls for these
pollutants for these units, North Dakota
relied almost exclusively on its
cumulative modeling, using current
degraded background to conclude that
the cost on a dollar per deciview basis
was excessive.65
As noted in a prior response, we
conclude that it was not reasonable for
North Dakota to model visibility
improvement for potential individual
source reasonable progress controls
using current degraded background. As
explained, we conclude that the State’s
approach is inconsistent with the CAA.
We also note that the State’s use of
current degraded background to analyze
single-source controls is facially
inconsistent with the Q/D threshold it
used to determine which sources should
be retained for a detailed evaluation of
reasonable progress controls. As noted,
the State selected a Q/D of 10 based in
part on EPA BART guidance on sources
that could be considered to contribute to
visibility impairment. That guidance
relied on a contribution threshold of 0.5
deciviews, which was premised on
64 The
ratios of these values equal a Q/D of 10.
detail regarding North Dakota’s
analysis can be found in our proposal. 76 FR
58624–58628.
65 Further
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CALPUFF modeling using natural
background. By modeling single-source
impacts and benefits using current
degraded background, North Dakota
employed a completely different metric
that rendered meaningless its Q/D
threshold and subsequent analysis of
the four factors.66
Comment: NDDH notes that EPA’s
guidance, ‘‘Additional Regional Haze
Questions,’’ dated August 24, 2006,
states that the RP demonstration
involves a test of a strategy and how
much progress is made through that
strategy. NDDH also notes that the
guidance states that RP modeling is tied
to a strategy and is not a source-specific
demonstration like the BART
assessment. NDDH asserts that EPA’s
rejection of the North Dakota
cumulative modeling for single source
visibility benefits arbitrarily ignores this
guidance.
Response: We find that this comment,
like the previous comment, conflates
two separate aspects of reasonable
progress: (1) The manner in which the
overall strategy is modeled for purposes
of comparison to the URP, and (2) the
determination of controls for potentially
affected sources and source categories.
In the latter context, we conclude that
our interpretation is reasonable and that
the State’s consideration of visibility
improvement based on current degraded
visibility was unreasonable.
First, we have refined our guidance
and our views on reasonable progress
since the cited document was issued. In
2007, we issued formal reasonable
progress guidance, which clearly
contemplates that controls may be
evaluated on a source-specific basis.67 It
is difficult to imagine how the
reasonableness of a control strategy
involving large stationary sources could
be determined without considering the
reasonableness of controls for the
specific stationary sources. Second, the
comment ignores the fact that North
Dakota itself conducted a sourcespecific analysis of potential control
options using the four factors.68 It was
only when it considered the additional
factor—visibility—that North Dakota
switched to a cumulative analysis.
Third, the commenter ignores the cited
guidance’s repeated admonition that
reasonable controls based on the four
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.
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.
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statutory factors (which don’t include
visibility improvement) must be
included in the plan. Thus, for example,
the guidance states:
‘‘However, the statutory factors must be
applied before determining whether given
emission reduction measures are reasonable.
In particular, the State should adopt a rate of
progress greater than the glidepath if this is
found to be reasonable according to the
statutory factors.’’
Guidance at 9. Similarly, the guidance
states:
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‘‘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
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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
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to Congress and other sources cited by
the commenter do not reflect our
interpretation of the RHR and therefore
have no regulatory weight.
Comment: Basin Electric states that,
under the RHR, if a state proposes an
RPG that doesn’t meet the URP, all the
state has to do is explain why meeting
the URP isn’t reasonable.
Response: This comment understates
the requirements of the RHR. If a state
establishes an RPG that does not meet
the URP, the state must demonstrate, on
the basis of the four RP factors, that (1)
meeting the URP isn’t reasonable; and
(2) the RPG adopted by the state is
reasonable. The commenter’s statement
ignores the requirement to consider the
four RP factors and to show that the
RPG is reasonable. EPA therefore
disagrees with the statement.
Comment: Basin Electric argues that
no state has full control over its RPGs,
because visibility improvements depend
largely on reductions from other states.
Response: Even if visibility impacts to
an in-state Class I area are largely due
to sources in other states, each state is
nonetheless obliged to make RP
determinations for in-state sources
based on a reasonable analysis of the
four statutory factors. In this case,
NDDH’s reliance on current degraded
background modeling as an additional
factor was unreasonable. Thus, Basin
Electric’s argument gives no basis for
EPA to change its disapproval of the
State’s RPGs or the NOX RP
determination for AVS.
Comment: Basin Electric states that
visibility improvement cannot be
ignored in the RP four-factor analysis.
Response: As we have noted, the four
RP factors are the costs of compliance,
the time necessary for compliance, the
energy and non-air quality
environmental impacts of compliance,
and the remaining useful life of any
potentially affected sources. As we have
also noted, when visibility benefits are
considered in the analysis of potential
single-source controls, such
consideration must be reasonable. In
this case, NDDH unreasonably relied on
modeling using current degraded
background to reject RP controls for
AVS. Finally, in imposing LNB to meet
reasonable progress requirements, EPA
has considered visibility improvement,
which, as shown by the CALPUFF
modeling provided by NDDH, is 0.754
deciviews at TRNP for installation of
LNB at AVS.
Comment: Basin Electric states that
EPA’s disapproval of North Dakota’s RP
determination for AVS is based solely
on EPA’s rejection of the State’s use of
a degraded background in modeling.
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Response: The basis for our
disapproval is fully explained in our
proposal. 76 FR 58627, 58629–58630.
We did not rely solely on the State’s use
of improper modeling. We note that,
despite the State’s flawed use of current
degraded background modeling, we
nonetheless approved several of the
State’s other reasonable progress
determinations based on our
consideration of the statutory reasonable
progress factors.
Comment: Basin Electric argues that
the dollar per deciview benefit of LNB
+ SNCR at AVS, computed using North
Dakota’s modeling, is much higher than
that some FLMs have found acceptable.
Basin Electric states that EPA does not
object to the use of dollar per deciview
in making an RP determination. Instead,
EPA objects only to the modeling itself.
Response: EPA guidance indicates
that it may be reasonable to evaluate the
dollar per deciview value in appropriate
circumstances. However, EPA has not
established a threshold, required or
recommended, below which such value
is considered reasonable and above
which it is considered unreasonable.
Nor have we endorsed or accepted any
values the FLMs may have found
acceptable. Under our regulations, we
determine whether a state’s rejection of
reasonable progress controls is
reasonable based on the reasonable
progress factors. We have explained in
response to other comments why North
Dakota’s modeling using current
degraded background and dollar per
deciview values based on that modeling
are not reasonable. In addition, EPA is
imposing only LNB, not LNB + SNCR,
at AVS. Thus, the dollar per deciview
benefit of LNB + SNCR is not directly
relevant. We provide further detail
regarding use of dollars per deciview
values in our response to prior
comments.
Comment: Basin Electric states that
EPA has no basis to disregard the State’s
cumulative modeling of visibility
improvements at AVS. Basin Electric
argues that the reasoning for using
degraded background conditions in
BART modeling applies equally to RP
modeling, because the horizon for RP
sources is 2018 (similar to the five-year
horizon for BART).
Response: As noted elsewhere, the
reasoning for using current degraded
background conditions in BART
modeling is faulty. That reasoning
therefore gives no basis for using current
degraded background conditions in RP
modeling.
Comment: Basin Electric states that
EPA admits that there is no requirement
that states, when performing RP
analysis, follow the modeling
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procedures set out in the BART
guidelines. Basin Electric states that
EPA does not cite any statute or rule
that the North Dakota RP modeling
violates.
Response: As we have noted, our
regulations require consideration of four
factors in reasonable progress
determinations; visibility improvement
is not one of the specified factors. As we
have indicated, when a state considers
visibility improvement as an additional
factor in evaluating single-source
control options, that consideration must
be reasonable in light of the explicit
goals established by Congress in CAA
section 169A.
Comment: Basin Electric states that
EPA is in error in asserting that North
Dakota modeled BART sources one way
and RP sources another way. Basin
Electric argues that even if EPA is
correct, there is no authority that
requires the State to model BART and
RP sources the same way.
Response: We disagree with the
commenter. North Dakota relied on
CALPUFF modeling using natural
background for almost all BART
sources. The only exceptions were
MRYS 1 and 2 and LOS 2, and then only
for NOX. We explained in our proposal
why North Dakota’s alternative
modeling for these BART units for NOX
was unreasonable. Despite the similarity
of several of the reasonable progress
units to the BART units, North Dakota
modeled visibility improvement for
potential control options on individual
reasonable progress sources using
current degraded background. We have
explained in our other responses and in
our proposal why this was
unreasonable.
Comment: Basin Electric argues that
states have the responsibility to set
RPGs and evaluate RP controls. Basin
Electric states that nothing prohibits the
State from using degraded background
conditions.
Response: For the reasons already
expressed, we disagree with the import
of this comment. We agree that the
states have the responsibility to set
RPGs and evaluate RP controls in the
first instance, but EPA must determine
if a state’s determinations for RPGs and
for controls satisfy the requirements of
the RHR and are reasonable. In the case
of AVS 1 and 2, the State’s
determination was unreasonable.
Comment: Basin Electric argues that,
in considering the CALPUFF modeling
results for AVS, EPA should use the
90th percentile values, not the 98th
percentile values, and should use the
three year average, not the worst-case
year.
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Response: For the same reasons
expressed in our responses to similar
comments related to BART in section
V.C, we disagree.
Comment: Basin Electric argues that
the case for using 90th percentile values
is stronger for RP, as RP is determined
based on improvement for the most
impaired days, which is defined as the
average impairment for the 20% of days
with the highest impairment. Basin
Electric states that use of the 98th
percentile is inconsistent with this
provision.
Response: EPA disagrees with this
comment, which conflates and misstates
requirements of the RHR. Reasonable
progress is not ‘‘determined’’ based on
improvement for the most impaired
days; instead, improvement for the most
impaired days is one, and not the only,
requirement for reasonable progress.
Separately, states are required to
evaluate, considering the four statutory
RP factors, controls for potentially
affected sources. In this separate
determination, when a state considers
visibility benefits as an additional
factor, a state’s assessment and analysis
of visibility benefits must be reasonable.
Use of the 90th percentile, which
seriously understates visibility benefits,
is unreasonable, and cannot be justified
by reference to the separate requirement
regarding the most impaired days.
Comment: Basin Electric notes that
EPA evaluated the cost of controls for
AVS Units 1 and 2 separately, but
evaluated the visibility benefits
combined. Basin Electric argues that
this is an invalid, apples-to-oranges
comparison.
Response: Given that AVS 1 and 2 are
the same size and are co-located, and
reductions would be similar from each,
we do not agree that it is invalid to
consider the combined visibility
benefits. There is no requirement, when
considering visibility benefits as an
additional factor, to separately model
co-located and similar units.
Furthermore, dollar-per-ton values
would not change significantly if costs
were evaluated for the two units
combined. Finally, EPA notes that, even
if the visibility benefits were evenly
divided between the two units, EPA
would still consider LNB appropriate at
each unit, based on the four statutory
factors and the additional factor of
visibility benefits.
Comment: Basin Electric references
additional modeling, provided by Basin
Electric, that shows that the visibility
benefits (using 90th percentile, threeyear average, and a receptor-by-receptor
approach) for LNB at AVS Units 1 and
2 combined is 0.07 deciviews. Divided
between the units equally, this would be
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0.035 deciviews. Basin Electric argues
that these improvements do not support
imposing LNB, especially when the
dollars per deciview improvement is
considered.
Response: As discussed elsewhere, we
find it reasonable to use the 98th
percentile, worst-of-three-year modeled
benefit over all receptors. The use of the
90th percentile, the three-year average,
and the receptor-by-receptor approach
understates the visibility benefits of
controls. As a result, the dollar-perdeciview value computed using that
approach, found in Table 8 of Basin
Electric’s comments and from which
Basin Electric derives the 0.07 deciview
figure, is not reasonable or persuasive.
Comment: Basin Electric argues that
EPA’s justification for disapproving
North Dakota’s RPGs is insufficient.
Basin Electric asserts that, even if EPA
is correctly determining BART and RP
limits for the individual facilities, EPA
must provide some additional basis for
disapproving the RPGs, such as: (1)
North Dakota is not providing for
improvement for the worst 20% days; or
(2) North Dakota is not ensuring no
further degradation for the best 20%
days. Basin Electric also notes that EPA
did not assess how far short
(presumably quantitatively) North
Dakota’s selected goals fall from
reasonable progress.
Response: EPA disagrees with this
comment. The bases suggested by Basin
Electric as necessary for disapproval
(improvement for the worst 20% days
and no further degradation for the best
20% days) are requirements of the RHR,
but they are not the only requirements.
As noted in the proposal, if a state’s
RPGs do not meet the URP, the state
must demonstrate that the RPGs are
reasonable, based on consideration of
the four statutory factors, and that
meeting the URP is unreasonable. The
State’s failure to satisfy this requirement
(and not the requirements noted by the
commenter) is the basis for the
disapproval of the State’s RPGs. In
particular, the State’s use of current
degraded background in modeling for
visibility benefits was unreasonable, as
was the State’s failure to select
reasonable RP controls for AVS Units 1
and 2. It is unnecessary to quantify how
far short North Dakota’s selected goals
fall from the RPGs proposed by EPA in
order to determine that the State’s
analysis was unreasonable. Nonetheless,
EPA notes that the proposed NOX RP
limit, based on installation of LNB, for
AVS Units 1 and 2 will result in
combined emissions reductions of over
7,000 tons per year of NOX, with a
visibility benefit of 0.754 deciviews at
TRNP. Due to time and resource
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constraints, we lacked the capability to
re-do the WRAP modeling to precisely
re-calculate the RPGs.
Comment: Basin Electric states that
the values for cost effectiveness of LNB
at AVS Units 1 and 2 do not reflect upto-date costs, which would be higher.
However, Basin Electric specifically
disclaims that up-to-date costs, standing
alone, would provide a sufficient reason
to reject LNB.
Response: In its FIP, EPA is relying in
part on costs provided by North Dakota
in its RH SIP to meet the requirements
of the RHR. In promulgating the FIP, it
is not necessary to regenerate the costs
for AVS 1 and 2. Nonetheless, EPA
agrees that regenerated costs for LNB at
AVS Units 1 and 2 would likely support
EPA’s determination. LNB is a widely
used, inexpensive control option to
reduce NOX emissions.
Comment: Citing 40 CFR 51.308(d),
Basin Electric states that EPA does not
propose a true FIP for RPGs, because
RPGs are defined by rule as a rate of
visibility improvement. Basin Electric
alleges that rerunning the WRAP CMAQ
modeling with the controls imposed to
quantify the rate of improvement would
cost a modest amount of money, and
states that this amount of money should
be contrasted with the cost of controls
that will, according to Basin Electric,
result in negligible visibility
improvements.
Response: As discussed elsewhere,
the visibility improvements from AVS
alone will not be negligible, as shown
by the CALPUFF modeling provided by
North Dakota, and even the CALPUFF
modeling provided by Basin Electric
with its comments. We assume Basin
Electric bases its statement about
negligible visibility improvements on
the modeling using current degraded
background relied on by North Dakota,
which, as discussed elsewhere, we are
disregarding. As discussed in the notice
of proposed action, we would have
preferred to quantify the rate of
improvement, but time and resource
constraints prevented this. Re-running
the WRAP CMAQ modeling would not
change our conclusion about the
reasonableness of LNB at AVS 1 and 2.
Comment: Basin Electric states that,
without modeling, there is no basis for
EPA to state that our FIP would increase
the rate of visibility improvement on the
20% worst days. Basin Electric asserts
that emissions reductions from the FIP
sources are miniscule compared with
the total reductions assumed in the
WRAP CMAQ modeling for RPGs. Basin
Electric notes that that modeling
showed an overall 0.6 deciview
improvement at TRNP and a 0.5
deciview improvement at LWA.
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Response: It is logical to infer that the
considerable emissions reductions at
CCS and AVS will increase the visibility
improvement on the 20% worst days.
We acknowledged in our proposal that
this improvement would not be
sufficient to achieve the URP (76 FR
58632) and agree that the improvement
will likely be small given that the
starting point for the cited modeling is
current degraded conditions. But the
same could be said for BART sources,
yet North Dakota has acknowledged that
such sources contribute to visibility
impairment in the Class I areas in North
Dakota.
Comment: Basin Electric states that
the disapproval of North Dakota’s RPGs
and our FIP have no meaningful effect.
Response: As we stated in our
proposal, the RPGs are not enforceable
values. To that extent, they do not
impose requirements on anyone.
However, we are required to disapprove
the RPGs because they do not reflect
reasonable controls at CCS and AVS,
and we are required to impose a FIP in
lieu of the State’s unapprovable RPGs.
Our reasonable progress controls at AVS
and our BART controls at CCS do
impose enforceable requirements.
Comment: Basin Electric asserts that,
because EPA has no basis for our
disapprovals and FIPs at individual
facilities, EPA also has no basis for our
FIP for RPGs.
Response: See our responses to prior
comments. We have explained the bases
for our disapprovals.
Comment: NPCA comments that it is
unreasonable for EPA to give Basin
Electric until July 31, 2018 to install
LNB at Antelope Valley because that
date is not ‘‘as expeditious as possible.’’
NPCA states that the deadline should be
January 26, 2013, which NPCA believes
represents a reasonable amount of time
to install the combustion controls.
Response: EPA disagrees with this
comment. First, unlike for BART
sources, the RHR and the CAA do not
explicitly require that limits for RP
sources be met as expeditiously as
practicable. Furthermore, the
commenter misstates the deadline: The
proposed FIP requires Basin Electric to
meet the proposed NOX emissions limit
at Antelope Valley ‘‘as expeditiously as
practicable, but in any event no later
than July 31, 2018.’’ Thus, Basin Electric
is under an obligation to install the
combustion controls as expeditiously as
practicable. The cutoff date of July 31,
2018 ensures that the RP limit for
Antelope Valley is met by the end of the
planning period, thereby also ensuring
that the proposed RPGs are met.
Comment: NPCA states that EPA
should reevaluate the cost estimate for
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SCR + reheat at AVS. NPCA argues that
North Dakota’s cost estimate is flawed
in the same way as for LOS 2 and MRYS
2. EPA proposed to disapprove the costs
for Leland Olds Unit 2; NPCA argues
that EPA therefore cannot rely on the
same costs in determining RP controls
for Antelope Valley.
Response: While EPA agrees that the
cost estimates for SCR at LOS 2 and
MRYS 2 are flawed, the costs for AVS
nonetheless present a sufficient basis for
EPA’s RP determination. EPA accepts,
and NPCA does not question, the costs
for LNB alone. Even if the cost estimate
for SCR + reheat was redone, it would
likely remain considerably more costly
than LNB. LNB is very cost-effective and
achieves reductions of about 78% of
SNCR + LNB and 64% of SCR with
reheat. Given the extreme costeffectiveness of LNB and reductions of
at least 64% of more expensive controls,
and taking into account the four
statutory factors as well as visibility
benefits of LNB, EPA has determined
that it is reasonable to impose LNB at
Antelope Valley in this planning period.
Of course, the imposition of LNB at AVS
does not rule out the imposition of postcombustion controls in the next
planning period.
Comment: NPCA states that North
Dakota’s cost estimates for SCR + reheat
and ASOFA + SCR + reheat at Coyote
Station are flawed. NPCA argues that
EPA should redo the RP analysis for
Coyote, and that a revised RP four-factor
analysis would show that SCR + reheat
is reasonable. In addition, NPCA notes
that the facility is fairly close to TRNP,
the State cannot meet the URP, and SCR
+ reheat would reduce emissions by
over 10,000 tpy.
The NPS states similar concerns with
North Dakota’s use of inappropriate
dollar per deciview estimates as a basis
for determining that no additional
controls were appropriate under RP for
Coyote Station. NPS notes that EPA has
recognized that the methods North
Dakota used to reach that conclusion,
both for estimating costs and visibility
improvement, are invalid. NPS infers
that North Dakota has not met its
responsibility to conduct a valid RP
analysis and that EPA must therefore
assume that responsibility. An NPS
analysis indicates SCR at Coyote would
be more cost effective than at any other
North Dakota EGU. NPS concludes that
EPA must impose an RP emissions limit
for Coyote of 0.07 lb/MMBtu (the same
as for MRYS 1 and 2, and LOS 2).
Response: EPA has now decided that
the rejection of SCR at Coyote is
appropriate regardless of the State’s cost
analysis, based on the court’s upholding
of North Dakota’s determination in the
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BACT proceeding for MRYS that SCR is
technically infeasible. Like MRYS,
Coyote is a cyclone unit burning North
Dakota lignite. Thus, based on current
evidence, we cannot conclude that
North Dakota’s rejection of SCR at
Coyote was unreasonable.
Comment: NPCA states that the record
shows that a wet scrubber would be cost
effective at Coyote Station, and believes
that the actual cost effectiveness may be
better. NPCA computes that a 99%
efficient wet scrubber would remove
about 13,000 tons per year of SO2. The
cost overestimates made by other
facilities indicate that EPA should
revisit this cost analysis.
Response: EPA disagrees with this
comment. First, NPCA did not identify
any cost overestimates related to wet
scrubbers. The issues EPA identified in
its proposal related to costs of SCR,
which provides no basis for inferring
cost overestimates for wet scrubbers. As
far as the record, Table 9.8 in North
Dakota’s RH SIP submittal shows a cost
effectiveness value of $2,593 per ton of
SO2 removed at a control efficiency of
95%. As stated in our proposal, while
this value is within the range of cost
effectiveness values that North Dakota,
other states, and we have considered
reasonable in the BART context, it is not
so low that we are prepared to
disapprove the State’s conclusion in the
reasonable progress context. In addition,
Coyote Station currently employs a
spray dryer to control SO2 emissions at
a control efficiency of approximately
66%. The existence of this control
supports our approval of the State’s
determination. Analogous to our policy
in the BART context, we do not expect
sources to install entirely new SO2
controls where they are already
achieving reductions greater than 50%.
Comment: NPCA notes EPA’s
response to a petition from the Dakota
Resource Council regarding violations of
PSD Class I SO2 increments, in which
EPA stated that a SIP call would not
achieve any better result than other
pending actions, including regional
haze actions. NPCA argues that, based
on this response, EPA should require
SO2 controls at Coyote Station to reduce
consumed Class I SO2 increment.
Response: EPA disagrees with this
comment. As discussed extensively in
our response to a prior comment, PSD
permit program requirements in Subpart
I, Part C of title I of the CAA are separate
from visibility protection requirements
in Subpart II of Part C. Therefore, Class
I SO2 increments are not relevant to our
action on North Dakota’s RH SIP
submittal to meet the requirements of
CAA section 169A and the RHR.
Nonetheless, EPA notes that SO2
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emissions will be substantially reduced
by our action on the North Dakota RH
SIP, as detailed in Table 21 of our notice
proposing action.
Comment: NPCA argues that
limestone injection at Heskett Station is
a cost effective and reasonable RP
control that would achieve SO2
reductions of 1614 tons per year.
However, NPCA notes that the
agreement between North Dakota and
the facility only requires reductions of
573 tons per year of SO2. NPCA
concludes that EPA should require
Heskett to achieve an SO2 limit that
reflects the capabilities of limestone
injection.
Response: EPA considers the State’s
determination to impose the stated
reductions in the permit included in SIP
Supplement No. 1 to be reasonable and
to satisfy reasonable progress
requirements in this initial planning
period. Further reductions may be
appropriate in a subsequent planning
period.
Comment: NPCA argues that staged
combustion is a cost effective control for
NOX at Heskett Station at $1,700/ton.
Even though the emission reduction is
only 215 tons per year, NPCA argues
that EPA must consider all potential
sources that can contribute to achieving
RPGs, including NOX reductions from
Heskett Station.
Response: EPA disagrees with this
comment. In the first instance, it is the
responsibility of the State to consider
the four statutory factors for potentially
affected sources. EPA’s task is to
determine if the State’s analysis of
controls satisfies the requirements of the
RHR and is reasonable. In this case, the
State did consider the four statutory
factors, as well as an additional factor—
visibility improvement based on
modeling using current degraded
background. While EPA does not
consider the State’s use of modeling
based on current degraded background
reasonable, EPA nonetheless considers
the result of the State’s analysis in this
instance to be reasonable, based on the
relatively low emissions reductions and
the costs of controls.
Comment: NPCA states that several
NOX control options for Tioga Gas Plant
are cost effective, with the lowest at
$521/ton. Although the emissions
reductions are lower, NPCA argues that
EPA should consider all potential
sources that can contribute to achieving
RPGs. In addition, NPCA notes that the
facility is only 35 km from LWA and is
also near TRNP.
Response: EPA disagrees with this
comment for the same reasons discussed
in response to the prior comment.
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Comment: NPCA states that EPA
should re-run the WRAP CMAQ
modeling with emissions that reflect the
BART and RP controls that EPA
proposes to approve or impose through
a FIP. NPCA argues that EPA and the
State should track actual visibility
improvements versus projected
visibility improvements, and that this
would assist in estimating visibility
improvements from other measures.
Response: As stated in our notice of
proposed action, we could not re-run
the WRAP modeling due to time and
resource constraints. We expect the
State to quantify the visibility
improvement in its next RH SIP
revision.
Comment: The NPS stated that North
Dakota did not meet its responsibility to
perform a valid RP analysis, as the
State’s cost analysis and modeling for
RP sources were flawed. Although the
NPS stated that this was a general issue,
the comment specifically noted flaws in
the State’s cost analysis for Coyote
Station. The NPS argued that EPA must
redo the analysis, and cannot propose to
approve any RP determinations.
Response: EPA disagrees with the
conclusion of this comment. Although
EPA agrees that the State’s cost analysis
for SCR at Coyote Station was flawed,
and that the State’s modeling of
visibility benefits of controls on RP
sources using degraded background
conditions was flawed, there is a
sufficient basis for EPA’s actions. As
noted in a prior response, EPA has now
decided that the rejection of SCR at
Coyote is appropriate regardless of the
State’s cost analysis, based on the
court’s upholding of North Dakota’s
determination in the BACT proceeding
for MRYS that SCR is technically
infeasible. Like MRYS, Coyote is a
cyclone unit burning North Dakota
lignite.
As noted, with respect to other
reasonable progress units, we have
disregarded the State’s visibility
analysis in our review of the State’s
reasonable progress determinations and
instead focused on the four reasonable
progress factors. Except for AVS 1 and
2, we have determined that the State’s
reasonable progress determinations
were not unreasonable.
Comment: The NPS stated that the RP
analysis of SCR for Coyote Station was
cursory. The NPS noted that, under the
0.50 lb/MMBtu annual rate agreed to by
the State, Coyote Station would still
have the highest controlled emissions
rate of any EGU in North Dakota and
would be the 13th largest emitter of
NOX among all EGUs, using 2010 rates
in the Clean Air Markets Division
database. NPS argues that, as a result,
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SCR should have been given more
consideration.
Response: First, EPA disagrees with
some of the NPS computations. Based
on 2010 Clean Air Markets Division
data, Coyote Station was the 124th
largest emitter of NOX among EGUs at
13,691 tons. At the rate of 0.50 lb/
MMBtu agreed to by the State, the
emissions (with the same heat input)
would have been 8,800 tons, which
would have made Coyote Station the
183rd largest emitter of NOX for that
year. This represents a reduction of over
4,800 tons per year. In any case, the
relative rank of a facility among other
facilities nationwide in overall
emissions is not a necessary component
of the RP analysis.
We have already explained why we
are not disapproving the State’s
rejection of SCR at Coyote.
Comment: The NPS noted that the RP
analysis for Coyote Station did not
consider upgrades to the existing dry
scrubber.
Response: In making an RP
determination, the State must consider
a reasonable range of controls. For SO2,
the State considered a new wet
scrubber. While EPA agrees that
upgrades to the existing dry scrubber
should have been considered, starting
with feasibility, EPA is not prepared to
determine, on the basis of this
consideration, that the State was
unreasonable in addressing RP
requirements for Coyote Station through
imposing the 0.50 lb/MMBtu NOX limit
and not imposing an SO2 limit. EPA
does expect the State to revisit the range
of controls in the next planning period.
Comment: NPS provided cost
estimates for installation of SCR at
Coyote Station, showing a cost
effectiveness value of $1,600 per ton
removed and an incremental cost
effectiveness value of $2,300 per ton
removed. NPS stated that these costs are
lower than those for SCR at LOS 2 and
MRYS 1 and 2. NPS argued that, for
consistency, EPA must impose SCR at
Coyote Station.
Response: The basis for our decision
regarding the State’s rejection of SCR at
Coyote is explained in prior responses.
H. Comments on Health and Ecosystem
Benefits, and Other Pollutants
Comment: Several commenters stated
that haze pollution significantly impacts
human health and ecosystem health, in
addition to obscuring scenic vistas.
Specifically, commenters asserted that
haze pollution contributes to heart
attacks, asthma attacks, chronic
bronchitis and respiratory illness,
increased hospital admissions, lost work
days, and even premature death. One
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commenter noted the specific haze
pollutants NOX, SO2 and PM, which the
commenter stated are all harmful to the
human body.
Some commenters cited a 2009 Clean
Air Task Force report in stating that
coal-fired power plants in North Dakota
put 207 people at risk of premature
death, 321 people at risk of a heart
attack, and 3,500 at risk of an asthma
attack each year. Several commenters
encouraged EPA to finalize the regional
haze proposal citing their own health
problems, most notably individuals
with asthma or respiratory problems,
seniors, and parents of asthmatic
children. One commenter stated the rate
of asthma in North Dakota children is
increasing rapidly.
Some commenters stated that haze
pollution negatively impacts ecosystem
health. Commenters expressed concern
for the effects of haze pollution on
wildlife, farm animals, plants including
crops, and water bodies. Several
commenters generally expressed their
disapproval of coal as an energy source
because it is dirty, with some insisting
that North Dakota invest in cleaner
energy.
Response: We appreciate the
commenters’ concerns regarding the
negative health impacts of emissions
from the coal-fired power plants in
North Dakota. We agree that the same
PM2.5 emissions that cause visibility
impairment can be inhaled deep into
lungs, which can cause respiratory
problems, decreased lung function,
aggravated asthma, bronchitis, and
premature death. We also agree that the
same NOX emissions that cause
visibility impairment also contribute to
the formation of ground-level ozone,
which has been linked with respiratory
problems, aggravated asthma, and even
permanent lung damage. We agree that
these pollutants can have negative
impacts on plants and ecosystems,
damaging plants, trees and other
vegetation, and reducing forest growth
and crop yields, which could have a
negative effect on species diversity in
ecosystems. However, for purposes of
this action, we are not authorized to
consider these impacts in evaluating the
State’s RH SIP and promulgating our
FIP, and we have not done so.
Comment: Some commenters stated
that regional haze is not a health-based
standard.
Response: We agree that regional haze
is not a health-based standard.
I. Miscellaneous Comments
Comment: Several commenters stated
that the large economic costs of
installing pollution controls stated by
electricity providers failed to consider
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the significant offsets of those costs. One
commenter stated that TRNP is an
economic engine, further stating that the
park logged over 580,000 recreational
visits, was responsible for 500 jobs and
$27.4 million in expenditures in 2009
alone. Another commenter stated that,
while the installation of pollution
controls costs money, it also stimulates
the economy by providing jobs in
construction and installation. Others
stated a willingness to pay the expected
increase in their utility costs, with one
commenter stating that North Dakota’s
electricity is amongst the least
expensive in the U.S.
Response: We agree with the
comments. Although we did not
consider the potential positive benefits
to the local and national economies in
making our decision today, we do
expect that improved visibility would
have a positive impact on tourismdependent local economies. Also,
retrofitting CCS with SNCR is a large
construction project that we expect to
take 5 years to complete. This project,
along with the other pollution control
upgrades proposed in the SIP, will
require well-paid, skilled labor which
can potentially be drawn from the local
area, which is expected to benefit the
economy.
Comment: Multiple commenters
stated that North Dakota is one of only
12 states in the U.S. who meet all
NAAQS.
Response: While the relative air
quality in North Dakota is considered
good compared to many other states, as
further discussed elsewhere in our
responses, our actions pertaining to the
RHR are governed by the national
visibility goal established by Congress
in the CAA. The goal is to return the
visibility conditions in Class I areas
back to natural conditions. And
visibility in Class I areas in North
Dakota is impaired by pollution from
industrial sources within the state.
There is no direct correlation between
natural visibility conditions and the
current NAAQS.
Comment: Several commenters stated
that the American Lung Association
ranked Mercer County, North Dakota,
home to several coal-fired power plants,
as one of the 25 cleanest counties in the
U.S., and ranked Billings County, North
Dakota, home to TRNP, the third
cleanest county in the United States.
Response: The commenters are
referring to the 2010 State of the Air
Report, which assigns letter grades for
counties with air quality monitors for
ozone and particulate pollution.69 The
69 The American Lung Association State of the
Air report is available at www.stateoftheair.org.
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report, issued every year by the
American Lung Association, did give
the mentioned counties an ‘‘A’’ grade in
2010 for ground level ozone. The State
of the Air Report does not, however,
address regional haze. The RHR relies
on a combination of monitoring data to
assess current visibility conditions and
modeling of predicted visibility impacts
at federal Class I areas (primarily
national parks and wilderness areas),
which is a different methodology than
direct measurement of ozone and
particulate pollution, which is the
approach relied on by the American
Lung Association. Current visibility
impacts at TRNP and LWA are over
double the impacts estimated for natural
conditions, and North Dakota’s Class I
areas are not projected to meet the URP
in the initial planning period.
Comment: Commenter cited the NPS’s
Web page for TRNP, which states that
the park has better air quality than every
other U.S. national park aside from
Denali National Park in Alaska.
Response: In our action, we are
responding to the national visibility goal
established by Congress in the CAA.
The goal is to return to natural visibility
conditions. TRNP is not meeting the
URP for returning the park to natural
visibility conditions. The NPS’ Web
page for TRNP does state that air quality
is relatively good, but it also discusses
the fact that pollution sometimes causes
haze and may affect other sensitive
resources in the park. For current
information on TRNP’s air quality visit
https://www.nps.gov/thro/naturescience/
airquality.htm.
Comment: Commenter insisted that
CCS and LOS should be retired, as they
are respectively rated the 3rd and 19th
most polluting coal plants in the U.S.
(Citing sourcewatch.org.)
Response: While we respect the
commenter’s opinion, a regulatory
process has been established under the
CAA and our regulations for considering
pollution controls to address visibility
impairment, and our action follows that
process.
Comment: Many commenters
generally stated that the costs of EPA’s
proposed rule are high when compared
to benefits. They stated that NDDH’s SIP
costs much less to implement than does
EPA’s plan, and produces similar
benefits. High costs were cited both
with respect to capital costs of the
controls as well as increased costs (retail
price per kilowatt hour) to consumers
particularly fixed and lower-income
consumers. Negative economic impacts
to agriculture and oil and gas industries
were cited, noting that the success of
these industries is dependent on lowcost and reliable electric power. Several
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commenters specifically mentioned a
cost of $700 million to install EPA’s
proposed controls and the potential for
lost jobs. Some commenters expressed a
willingness to pay the potential increase
in their electric bills because they
supported EPA’s action.
Response: While we disagree with a
number of the commenters’ assertions,
these comments are largely no longer
relevant because we have decided to
approve North Dakota’s NOX BART
determinations for MRYS 1 and 2 and
LOS 2 on grounds explained elsewhere.
To the degree that some of these
comments extend to our FIP for CCS
and AVS, EPA’s evaluation of capital
and annual expenses associated with
implementation of the FIP shows such
expenses to be justified by the degree of
improvement in visibility in
relationship to the cost of
implementation.
We take our duty to estimate the cost
of controls very seriously, and make
every attempt to make a thoughtful and
well informed determination. However,
we do not consider a potential increase
in electricity rates to be the most
appropriate type of analysis for
considering the costs of compliance in
a BART determination. Nevertheless,
our analysis indicates that the annual
costs to CCS and AVS associated with
our FIP will be relatively modest
considering the size of the plants, and
impacts to rate payers should be much
lower than anticipated by commenters.
Comment: Commenter cited EPA’s
Clean Air Markets database, which
states that North Dakota ranked #12 in
SO2 emissions and #19 in NOX
emissions. The commenter also
provided the SO2 and NOX rankings for
the seven North Dakota EGUs discussed
in the SIP.
Response: We appreciate the
commenter providing the SO2 and NOX
rankings for North Dakota and its EGUs.
We do not disagree with the information
provided and acknowledge the data
suggest the North Dakota plants rank
relatively high in the amount of SO2 and
NOX emissions compared to other
states. However, we note that BART and
RP determinations involve case-by-case
determinations considering the relevant
statutory factors, which do not include
the relative emissions rankings.
Comment: Commenter requests that
EPA set limits on ammonia slip where
SNCR or SCR is required for BART.
Response: In Section 7.1.2 of the SIP,
North Dakota concluded that ammonia
is not a visibility impairing pollutant of
concern as ammonia emissions (and
associated regional haze impacts) from
BART-eligible sources are negligible.
We concur with this conclusion.
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Accordingly, there is no basis to set
limits on ammonia slip to address
concerns related to regional haze
impacts. Nor is it necessary to set limits
on ammonia slip to ensure compliance
with NOX emission limits because NOX
CEMS will be used.
J. Comments Requesting an Extension to
the Public Comment Period
Comment: One commenter requested
that the comment period be extended to
December 21, 2011 and Governor
Dalrymple and Senator Hoeven
requested the time allotted for the
public hearings be increased.
Response: The comment period for
our proposal closed on November 21,
2011. We carefully considered the
request for an extension to the comment
period. We took into consideration how
an extension might affect our ability to
consider comments received on the
proposed action and still comply with
our consent decree deadlines. We do
note that our October 13 and 14, 2011,
public hearing in Bismarck, North
Dakota was well attended and provided
an opportunity for people to comment
on our proposal. Also regarding the
public hearings, we agreed to Governor
Dalrymple’s and Senator Hoeven’s
requests to extend the length of the
public hearing and to allow as much
time as needed for state representatives
to present their comments.
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K. Comments Generally in Favor of Our
Proposal
Comment: Overall, we received more
than 24,000 comment letters in support
of our rulemaking from members
representing various organizations,
concerned citizens, and tribal members.
These comments were received at the
Public Hearing in Bismarck, North
Dakota, by internet, and through the
mail. Each of these commenters was
generally in favor of portions of our
proposed decision for North Dakota
regional haze. These comments
included comments urging us to require
the most effective pollution control
technology, SCR, at LOS 2, and MRYS
1 and 2 and additional emission
reductions from CCS 1 and 2 and AVS
1 and 2. Some of these comments also
discussed the detrimental health effects
of haze pollution and the economic
impacts of these health effects. Some of
these comments urged us to keep or
lower our proposed numeric limits on
NOX for MRYS and LOS 2 in our final
decision. These letters also asked us to
require other units at LOS, Heskett
Station, and Stanton Station to
modernize and reduce their air
pollution impacts.
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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
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proposed action. We provide responses
that address these issues elsewhere in
this action. We have made changes from
our proposal, as noted elsewhere in this
action.
VI. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is not a ‘‘significant
regulatory action’’ under the terms of
Executive Order 12866 (58 FR 51735,
October 4, 1993) and is therefore not
subject to review under Executive
Orders 12866 and 13563 (76 FR 3821,
January 21, 2011). As discussed in detail
in section C below, the FIP applies to
only two facilities. It is therefore not a
rule of general applicability.
B. Paperwork Reduction Act
This action does not impose an
information collection burden under the
provisions of the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. Under the
Paperwork Reduction Act, a ‘‘collection
of information’’ is defined as a
requirement for ‘‘answers to * * *
identical reporting or recordkeeping
requirements imposed on ten or more
persons * * *.’’ 44 U.S.C. 3502(3)(A).
Because the FIP applies to just two
facilities, the Paperwork Reduction Act
does not apply. See 5 CFR 1320(c).
Burden means the total time, effort, or
financial resources expended by persons
to generate, maintain, retain, or disclose
or provide information to or for a
Federal agency. This includes the time
needed to review instructions; develop,
acquire, install, and utilize technology
and systems for the purposes of
collecting, validating, and verifying
information, processing and
maintaining information, and disclosing
and providing information; adjust the
existing ways to comply with any
previously applicable instructions and
requirements; train personnel to be able
to respond to a collection of
information; search data sources;
complete and review the collection of
information; and transmit or otherwise
disclose the information.
An agency may not conduct or
sponsor, and a person is not required to
respond to a collection of information
unless it displays a currently valid
Office of Management and Budget
(OMB) control number. The OMB
control numbers for our regulations in
40 CFR are listed in 40 CFR Part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA)
generally requires an agency to prepare
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a regulatory flexibility analysis of any
rule subject to notice and comment
rulemaking requirements under the
Administrative Procedure Act or any
other statute unless the agency certifies
that the rule will not have a significant
economic impact on a substantial
number of small entities. Small entities
include small businesses, small
organizations, and small governmental
jurisdictions.
For purposes of assessing the impacts
of today’s rule on small entities, small
entity is defined as: (1) A small business
as defined by the Small Business
Administration’s (SBA) regulations at 13
CFR 121.201; (2) a small governmental
jurisdiction that is a government of a
city, county, town, school district or
special district with a population of less
than 50,000; and (3) a small
organization that is any not-for-profit
enterprise which is independently
owned and operated and is not
dominant in its field.
After considering the economic
impacts of this action on small entities,
I certify that this proposed action will
not have a significant economic impact
on a substantial number of small
entities. The FIP that EPA is finalizing
for purposes of the visibility prong of
section 110(a)(2)(D)(i)(II) consists of the
combination of the approval of the
State’s RH SIP submission and the
Regional Haze FIP by EPA that adds
additional controls to certain sources.
The Regional Haze FIP that EPA is
finalizing for purposes of the regional
haze program consists of imposing
federal controls to meet the BART
requirement for NOX emissions at one
source in North Dakota, and imposing
controls to meet the reasonable progress
requirement for NOX emissions at one
additional source in North Dakota. The
net result of these two simultaneous FIP
actions is that EPA is proposing direct
emission controls on selected units at
only two sources. The sources in
question are each large electric
generating plants that are not owned by
small entities, and therefore are not
small entities. The partial approval of
the SIP merely approves state law as
meeting Federal requirements and
imposes no additional requirements
beyond those imposed by state law. See
Mid-Tex Electric Cooperative, Inc. v.
FERC, 773 F.2d 327 (D.C. Cir. 1985).
D. Unfunded Mandates Reform Act
(UMRA)
Title II of the Unfunded Mandates
Reform Act of 1995 (UMRA), Public
Law 104–4, establishes requirements for
Federal agencies to assess the effects of
their regulatory actions on State, local,
and Tribal governments and the private
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sector. Under section 202 of UMRA,
EPA generally must prepare a written
statement, including a cost-benefit
analysis, for proposed and final rules
with ‘‘Federal mandates’’ that may
result in expenditures to State, local,
and Tribal governments, in the
aggregate, or to the private sector, of
$100 million or more (adjusted for
inflation) in any 1 year. Before
promulgating an EPA rule for which a
written statement is needed, section 205
of UMRA generally requires EPA to
identify and consider a reasonable
number of regulatory alternatives and to
adopt the least costly, most costeffective, or least burdensome
alternative that achieves the objectives
of the rule. The provisions of section
205 of UMRA do not apply when they
are inconsistent with applicable law.
Moreover, section 205 of UMRA allows
EPA to adopt an alternative other than
the least costly, most cost-effective, or
least burdensome alternative if the
Administrator publishes with the final
rule an explanation why that alternative
was not adopted. Before EPA establishes
any regulatory requirements that may
significantly or uniquely affect small
governments, including Tribal
governments, it must have developed
under section 203 of UMRA a small
government agency plan. The plan must
provide for notifying potentially
affected small governments, enabling
officials of affected small governments
to have meaningful and timely input in
the development of EPA regulatory
proposals with significant Federal
intergovernmental mandates, and
informing, educating, and advising
small governments on compliance with
the regulatory requirements.
Under Title II of UMRA, EPA has
determined that this rule does not
contain a Federal mandate that may
result in expenditures that exceed the
inflation-adjusted UMRA threshold of
$100 million by State, local, or Tribal
governments or the private sector in any
1 year. In addition, this rule does not
contain a significant Federal
intergovernmental mandate as described
by section 203 of UMRA nor does it
contain any regulatory requirements
that might significantly or uniquely
affect small governments.
E. Executive Order 13132: Federalism
Federalism (64 FR 43255, August 10,
1999) revokes and replaces Executive
Orders 12612 (Federalism) and 12875
(Enhancing the Intergovernmental
Partnership). Executive Order 13132
requires EPA to develop an accountable
process to ensure ‘‘meaningful and
timely input by State and local officials
in the development of regulatory
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policies that have federalism
implications.’’ ‘‘Policies that have
federalism implications’’ is defined in
the Executive Order to include
regulations that have ‘‘substantial direct
effects on the States, on the relationship
between the national government and
the States, or on the distribution of
power and responsibilities among the
various levels of government.’’ Under
Executive Order 13132, EPA may not
issue a regulation that has federalism
implications, that imposes substantial
direct compliance costs, and that is not
required by statute, unless the Federal
government provides the funds
necessary to pay the direct compliance
costs incurred by State and local
governments, or EPA consults with
State and local officials early in the
process of developing the proposed
regulation. EPA also may not issue a
regulation that has federalism
implications and that preempts State
law unless the Agency consults with
State and local officials early in the
process of developing the proposed
regulation.
This rule will not have substantial
direct effects on the States, on the
relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132, because it
merely addresses the State not fully
meeting its obligation to prohibit
emissions from interfering with other
states’ measures to protect visibility
established in the CAA and not fully
meeting its obligation to adopt a SIP that
meets the regional haze requirements
under the CAA. Thus, Executive Order
13132 does not apply to this action.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
Executive Order 13175, entitled
Consultation and Coordination with
Indian Tribal Governments (65 FR
67249, November 9, 2000), requires EPA
to develop an accountable process to
ensure ‘‘meaningful and timely input by
tribal officials in the development of
regulatory policies that have tribal
implications.’’ We believe this rule does
not have tribal implications, as specified
in Executive Order 13175, and will not
have substantial direct effects on tribal
governments. Thus, Executive Order
13175 does not apply to this rule.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
Executive Order 13045: Protection of
Children from Environmental Health
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Risks and Safety Risks (62 FR 19885,
April 23, 1997), applies to any rule that:
(1) Is determined to be economically
significant as defined under Executive
Order 12866; and (2) concerns an
environmental health or safety risk that
we have reason to believe may have a
disproportionate effect on children. EPA
interprets EO 13045 as applying only to
those regulatory actions that concern
health or safety risks, such that the
analysis required under section 5–501 of
the EO has the potential to influence the
regulation. This action is not subject to
EO 13045 because it implements
specific standards established by
Congress in statutes. However, to the
extent this rule will limit emissions of
NOX, the rule will have a beneficial
effect on children’s health by reducing
air pollution.
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not subject to Executive
Order 13211 (66 FR 28355 (May 22,
2001)), because it is not a significant
regulatory action under Executive Order
12866.
I. National Technology Transfer and
Advancement Act
Section 12 of the National Technology
Transfer and Advancement Act
(NTTAA) of 1995 requires Federal
agencies to evaluate existing technical
standards when developing a new
regulation. To comply with NTTAA,
EPA must consider and use ‘‘voluntary
consensus standards’’ (VCS) if available
and applicable when developing
programs and policies unless doing so
would be inconsistent with applicable
law or otherwise impractical.
The EPA believes that VCS are
inapplicable to this action. Today’s
action does not require the public to
perform activities conducive to the use
of VCS.
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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
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federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority
populations and low-income
populations in the United States.
We have determined that this rule
will not have disproportionately high
and adverse human health or
environmental effects on minority or
low-income populations because it
increases the level of environmental
protection for all affected populations
without having any disproportionately
high and adverse human health or
environmental effects on any
population, including any minority or
low-income population. This rule limits
emissions of NOX from two facilities in
North Dakota. The partial approval of
the SIP merely approves state law as
meeting Federal requirements and
imposes no additional requirements
beyond those imposed by state law.
K. Congressional Review Act
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. EPA will submit a
report containing this action and other
required information to the U.S. Senate,
the U.S. House of Representatives, and
the Comptroller General of the United
States prior to publication of the rule in
the Federal Register. A major rule
cannot take effect until 60 days after it
is published in the Federal Register.
This action is not a ‘‘major rule’’ as
defined by 5 U.S.C. 804(2). This rule
will be effective on May 7, 2012.
L. Judicial Review
Under section 307(b)(1) of the CAA,
petitions for judicial review of this
action must be filed in the United States
Court of Appeals for the appropriate
circuit by June 5, 2012. Pursuant to CAA
section 307(d)(1)(B), this action is
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20941
subject to the requirements of CAA
section 307(d) as it promulgates a FIP
under CAA section 110(c). Filing a
petition for reconsideration by the
Administrator of this final rule does not
affect the finality of this action for the
purposes of judicial review nor does it
extend the time within which a petition
for judicial review may be filed, and
shall not postpone the effectiveness of
such rule or action. This action may not
be challenged later in proceedings to
enforce its requirements. See CAA
section 307(b)(2).
Approval and Promulgation of
Implementation Plans; North Dakota;
Regional Haze State Implementation
Plan; Federal Implementation Plan for
Interstate Transport of Pollution
Affecting Visibility and Regional Haze.
Final Rule. (EPA–R08–OAR–2010–0406)
List of Subjects in 40 CFR Part 52
Environmental protection, Air
pollution control, Intergovernmental
relations, Incorporation by reference,
Nitrogen dioxides, Particulate matter,
Reporting and recordkeeping
requirements, Sulfur dioxide, Volatile
organic compounds.
Dated: March 1, 2012.
Lisa P. Jackson,
Administrator.
40 CFR part 52 is amended as follows:
PART 52—[AMENDED]
1. The authority citation for part 52
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
Subpart JJ—North Dakota
2. Section 52.1820 is amended by:
a. Adding to the table in paragraph (c)
an entry entitled ‘‘33–15–25 Regional
Haze Requirements’’ at the end of the
table.
■ b. Revising the table in paragraph (d).
■ c. Adding to the table in paragraph
(e)entries ‘‘(23),’’ ‘‘(24),’’ and ‘‘(25)’’ in
numerical order at the end of the table.
The revisions and additions read as
follows:
■
■
§ 52.1820
*
Identification of plan.
*
*
(c) * * *
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*
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Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations
State citation
State effective
date
Title/subject
*
*
EPA approval date and
citation 1
*
*
*
33–15–25 Regional Haze Requirements
33–15–25–01 ...............................
Definitions ....................................
1/1/07
33–15–25–02 ...............................
Best available retrofit technology
1/1/07
33–15–25–03 ...............................
Guidelines for best available retrofit technology determinations
under the regional haze rule.
1/1/07
33–15–25–04 ...............................
Monitoring, recordkeeping, and
reporting.
1/1/07
*
Explanations
*
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
1 In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column for the particular provision.
*
*
*
*
*
(d) * * *
State effective
date
Name of source
Nature of requirement
Leland Olds Station Unit 1 ..........
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10004.
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10004.
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10007.
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10007.
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10005.
Leland Olds Station Unit 2 ..........
Milton R. Young Station Unit 1 ....
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Milton R. Young Station Unit 2 ....
Coal Creek Station Unit 1 ...........
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2/23/10
5/6/77
2/23/10
5/6/77
2/23/10
2/23/10
2/23/10
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EPA approval date and
citation 3
Explanations
10/17/77, 42 FR 55471.
4/6/12, [Insert Federal
Register page number
where the document begins.].
10/17/77, 42 FR 55471.
4/6/12, [Insert Federal
Register page number
where the document begins.].
10/17/77, 42 FR 55471.
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
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Excluding the NOX BART
emissions limits for Unit
1 and corresponding
monitoring, recordkeeping, and reporting
requirements, which
EPA disapproved.
Federal Register / Vol. 77, No. 67 / Friday, April 6, 2012 / Rules and Regulations
State effective
date
Name of source
Nature of requirement
Coal Creek Station Unit 2 ...........
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10005.
2/23/10
Stanton Station Unit 1 .................
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
Air pollution control permit to
construct for best available retrofit
technology
(BART),
PTC10006.
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
Air Pollution Control Permit to
Construct, PTC10028.
5/6/77
Heskett Station Unit 1 .................
Heskett Station Unit 2 .................
2/23/10
4/6/12, [Insert Federal
Register page number
where the document begins.].
Excluding the NOX BART
emissions limits for Unit
2 and corresponding
monitoring, recordkeeping, and reporting
requirements, which
EPA disapproved.
10/17/77, 42 FR 55471.
5/6/77
10/17/77, 42 FR 55471.
7/22/10
3/14/11
American Crystal
Drayton.
SIP Chapter 8, Section 8.3, Continuous Emission Monitoring
Requirements for Existing Stationary
Sources,
including
amendments to Permits to Operate and Department Order.
SIP Chapter 8, Section 8.3.1,
Continuous Opacity Monitoring
for Fluid Bed Catalytic Cracking Units: Tesoro Refining and
Marketing Co., Mandan Refinery.
5/6/77
Tesoro Mandan Refinery .............
Explanations
5/6/77
Air Pollution Control Permit to
Construct, PTC10008.
at
EPA approval date and
citation 3
4/6/12, [Insert Federal
Register page number
where the document begins.].
10/17/77, 42 FR 55471.
Coyote Station Unit 1 ..................
Sugar
20943
2/27/07
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
10/17/77, 42 FR 55471.
5/27/08, 73 FR 30308.
3 In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column for the particular provision.
mstockstill on DSK4VPTVN1PROD with RULES2
*
*
*
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*
*
16:58 Apr 05, 2012
(e) * * *
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Name of nonregulatory SIP
provision
Applicable geographic or
nonattainment area
State submittal date/
adopted date
EPA approval date and
citation 3
Explanations
*
(23) North Dakota State
Implementation Plan for
Regional Haze.
*
*
Statewide ...........................
*
Submitted: 3/3/10 .............
*
*
4/6/12, [Insert Federal
Register page number
where the document begins.].
*
Excluding portions of the
following: Sections 7.4,
9.5, 9.7, and 10.6, and
Appendices B.2, and
D.2, and all of Appendix
A.4, because EPA disapproved the NOX
BART determination for
Coal Creek Station Units
1 and 2, the reasonable
progress determination
for Antelope Valley Station Units 1 and 2 regarding NOX controls,
the reasonable progress
goals, and parts of the
long-term strategy, and
because the provisions
applicable to Coyote
Station were superseded
by a later submittal.
(24) North Dakota State
Implementation Plan for
Regional Haze Supplement No. 1.
(25) North Dakota State
Implementation Plan for
Regional Haze Amendment No. 1.
Statewide ...........................
Submitted: 7/27/10 ...........
Statewide ...........................
Submitted: 7/28/11 ...........
4/6/12, [Insert Federal
Register page number
where the document begins.].
4/6/12, [Insert Federal
Register page number
where the document begins.].
Including only Section
10.6.1.2, Appendix A.4,
and introductory elements that pertain to the
NOX requirements for
Coyote Station; excluding all other portions of
the submittal.
3 In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column for the particular provision.
*
■
*
*
*
*
3. Section 52.1825 is added as follows:
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 24hour 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
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(DAHS)), a permanent record of NOX
emissions, other pollutant emissions,
diluent, or stack gas volumetric flow
rate.
(3) NOX means nitrogen oxides.
(4) Owner/operator means any person
who owns or who operates, controls, or
supervises an EGU identified in
paragraph (a) of this section.
(5) Unit means any of the EGUs
identified in paragraph (a) of this
section.
(c) Emissions limitations. (1) The
owners/operators subject to this section
shall not emit or cause to be emitted
NOX in excess of the following
limitations, in pounds per million
British thermal units (lb/MMBtu),
averaged over a rolling 30-day period:
Source name
NOX Emission limit
(lb/MMBtu)
Coal Creek Station,
Units 1 and 2.
Antelope Valley Station, Unit 1.
Antelope Valley Station, Unit 2.
0.13, averaged across
both units.
0.17.
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0.17.
Sfmt 4700
(2) These emission limitations shall
apply at all times, including startups,
shutdowns, emergencies, and
malfunctions.
(d) Compliance date. The owners and
operators of Coal Creek Station shall
comply with the emissions limitation
and other requirements of this section
within five (5) years of the effective date
of this rule, unless otherwise indicated
in specific paragraphs. The owners and
operators of Antelope Valley Station
shall comply with the emissions
limitations and other requirements of
this section as expeditiously as
practicable, but no later than July 31,
2018, unless otherwise indicated in
specific paragraphs.
(e) Compliance determination—(1)
CEMS. At all times after the compliance
date specified in paragraph (d) of this
section, the owner/operator of each unit
shall maintain, calibrate, and operate a
CEMS, in full compliance with the
requirements found at 40 CFR part 75,
to accurately measure NOX, diluent, and
stack gas volumetric flow rate from each
unit. The CEMS shall be used to
determine compliance with the
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mstockstill on DSK4VPTVN1PROD with RULES2
emission limitations in paragraph (c) of
this section for each unit.
(2) Method. (i) For any hour in which
fuel is combusted in a unit, the owner/
operator of each unit shall calculate the
hourly average NOX concentration in lb/
MMBtu at the CEMS in accordance with
the requirements of 40 CFR part 75. At
the end of each boiler operating day, the
owner/operator shall calculate and
record a new 30-day rolling average
emission rate in lb/MMBtu from the
arithmetic average of all valid hourly
emission rates from the CEMS for the
current boiler operating day and the
previous 29 successive boiler operating
days.
(ii) An hourly average NOX emission
rate in lb/MMBtu is valid only if the
minimum number of data points, as
specified in 40 CFR part 75, is acquired
by both the NOX pollutant concentration
monitor and the diluent monitor (O2 or
CO2).
(iii) Data reported to meet the
requirements of this section shall not
include data substituted using the
missing data substitution procedures of
subpart D of 40 CFR part 75, nor shall
the data have been bias adjusted
according to the procedures of 40 CFR
part 75.
(f) Recordkeeping. Owner/operator
shall maintain the following records for
at least five years:
(1) All CEMS data, including the date,
place, and time of sampling or
measurement; parameters sampled or
measured; and results.
(2) Records of quality assurance and
quality control activities for emissions
measuring systems including, but not
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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
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20945
adjustments, and results of any CEMS
performance tests required by 40 CFR
part 75 (Relative Accuracy Test Audits,
Relative Accuracy Audits, and Cylinder
Gas Audits).
(3) When no excess emissions have
occurred or the CEMS has not been
inoperative, repaired, or adjusted during
the reporting period, such information
shall be stated in the report.
(h) Notifications. (1) Owner/operator
shall submit notification of
commencement of construction of any
equipment which is being constructed
to comply with the NOX emission limits
in paragraph (c) of this section.
(2) Owner/operator shall submit semiannual progress reports on construction
of any such equipment.
(3) Owner/operator shall submit
notification of initial startup of any such
equipment.
(i) Equipment operation. At all times,
owner/operator shall maintain each
unit, including associated air pollution
control equipment, in a manner
consistent with good air pollution
control practices for minimizing
emissions.
(j) Credible Evidence. Nothing in this
section shall preclude the use, including
the exclusive use, of any credible
evidence or information, relevant to
whether a source would have been in
compliance with requirements of this
section if the appropriate performance
or compliance test procedures or
method had been performed.
[FR Doc. 2012–6586 Filed 4–5–12; 8:45 am]
BILLING CODE 6560–50–P
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Agencies
[Federal Register Volume 77, Number 67 (Friday, April 6, 2012)]
[Rules and Regulations]
[Pages 20894-20945]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-6586]
[[Page 20893]]
Vol. 77
Friday,
No. 67
April 6, 2012
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
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]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R08-OAR-2010-0406; FRL-9648-3]
Approval and Promulgation of Implementation Plans; North Dakota;
Regional Haze State Implementation Plan; Federal Implementation Plan
for Interstate Transport of Pollution Affecting Visibility and Regional
Haze
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: EPA is partially approving and partially disapproving a
revision to the North Dakota State Implementation Plan (SIP) addressing
regional haze submitted by the Governor of North Dakota on March 3,
2010, along with SIP Supplement No. 1 submitted on July 27, 2010, and
part of SIP Amendment No. 1 submitted on July 28, 2011. These SIP
revisions were submitted to address the requirements of the Clean Air
Act (CAA or Act) and our rules that require states to prevent any
future and remedy any existing man-made impairment of visibility in
mandatory Class I areas caused by emissions of air pollutants from
numerous sources located over a wide geographic area (also referred to
as the ``regional haze program''). EPA is promulgating a Federal
Implementation Plan (FIP) to address the gaps in the plan resulting
from our partial disapproval of North Dakota's Regional Haze (RH) SIP.
In addition, EPA is disapproving a revision to the North Dakota SIP
addressing the interstate transport of pollutants that the Governor
submitted on April 6, 2009. We are disapproving it because it does not
meet the Act's requirements concerning 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 fallon.gail@epa.gov.
SUPPLEMENTARY INFORMATION:
Definitions
For the purpose of this document, we are giving meaning to certain
words or initials as follows:
The word Act or initials CAA mean or refer to the Clean
Air Act, unless the context indicates otherwise.
The initials ASOFA mean or refer to advanced separated
overfire air.
The initials AVS mean or refer to Antelope Valley Station.
The initials BACT mean or refer to Best Available Control
Technology.
The initials BART mean or refer to Best Available Retrofit
Technology.
The initials CAM mean or refer to compliance assurance
monitoring.
The initials CAMx mean or refer to Comprehensive Air
Quality Model.
The initials CCS mean or refer to Coal Creek Station.
The initials CEMS mean or refer to continuous emission
monitoring system.
The initials CMAQ mean or refer to Community Multi-Scale
Air Quality modeling system.
The initials CSAPR mean or refer to Cross-State Air
Pollution Rule.
The initials EGUs mean or refer to Electric Generating
Units.
The words we, us or our or the initials EPA mean or refer
to the United States Environmental Protection Agency.
The initials FIP mean or refer to Federal Implementation
Plan.
The initials FLMs mean or refer to Federal Land Managers.
The initials GRE mean or refer to Great River Energy.
The initials IMPROVE mean or refer to Interagency
Monitoring of Protected Visual Environments monitoring network.
The initials IWAQM mean or refer to Interagency Workgroup
on Air Quality Modeling.
The initials LDSCR mean or refer to low-dust SCR.
The initials LOS mean or refer to Leland Olds Station.
The words Lostwood or Lostwood Wilderness Area or initials
LWA mean or refer to Lostwood National Wildlife Refuge Wilderness Area.
The initials LNB mean or refer to low NOX
burners.
The initials LTS mean or refer to Long-Term Strategy.
The initials MRYS mean or refer to Milton R. Young
Station.
The initials NAAQS mean or refer to National Ambient Air
Quality Standards.
The words North Dakota and State mean the State of North
Dakota unless the context indicates otherwise.
The initials NOX mean or refer to nitrogen oxides.
The initials NPCA mean or refer to National Parks
Conservation Association.
The initials NPS mean or refer to National Park Service.
The initials PM mean or refer to particulate matter.
The initials PM10 mean or refer to particulate matter with
an aerodynamic diameter of less than 10 micrometers or course
particulate matter.
The initials PM2.5 mean or refer to particulate matter
with an aerodynamic diameter of less than 2.5 micrometers or fine
particulate matter.
The initials PRB mean or refer to Powder River Basin.
The initials PSAT mean or refer to Particle Source
Apportionment Technology.
The initials PSD mean or refer to Prevention of
Signification Deterioration.
The initials RHR mean or refer to the Regional Haze Rule.
The initials RH SIP mean or refer to North Dakota's
Regional Haze State Implementation Plan.
The initials RMC mean or refer to the Regional Modeling
Center at the University of California Riverside.
The initials RP mean or refer to Reasonable Progress.
The initials RPG mean or refer to Reasonable Progress
Goal.
The initials SCR mean or refer to selective catalytic
reduction.
The initials SIP mean or refer to State Implementation
Plan.
The initials SNCR mean or refer to selective non-catalytic
reduction.
The initials SO2 mean or refer to sulfur dioxide.
The initials SOFA mean or refer to separated overfire air.
The initials TRNP mean or refer to Theodore Roosevelt
National Park.
[[Page 20895]]
The initials TSD mean or refer to Technical Support
Document.
The initials URP mean or refer to Uniform Rate of
Progress.
The initials WEP mean or refer to Weighted Emissions
Potential.
The initials WRAP mean or refer to the Western Regional
Air Partnership.
Table of Contents
I. Background
A. Regional Haze
B. Interstate Transport Requirements
C. Lawsuits
D. Our Proposal
1. Regional Haze
2. Interstate Transport, Visibility Prong
E. Public Participation
II. Final Action
A. Regional Haze
B. Interstate Transport, Visibility Prong
III. Changes from Proposed Rule and Reasons for the Changes
A. NOX BART for Milton R. Young Station Units 1 and 2
and Leland Olds Station Unit 2
B. NOX BART for Coal Creek Station (CCS) Units 1 and
2
C. Other Resultant Changes
IV. Basis for Our Final Action
A. Regional Haze
B. Interstate Transport, Visibility Prong
V. Issues Raised by Commenters and EPA's Responses
A. NOX BART for Milton R. Young Station Units 1 and 2
and Leland Olds Station Unit 2
B. Comments on Legal Issues
1. EPA's Authority
2. Interstate Transport Consent Decree
3. Other General Legal Comments
C. Comments on Modeling
D. Comments on Costs
1. General
2. Comments Regarding Our Reliance on the EPA Air Pollution
Control Cost Manual
E. Comments on BART Determinations
1. General Comments
2. CCS Units 1 and 2
a. EPA's Use of the Control Cost Manual for CCS
b. CCS Emission Limits
c. CCS Modeling
d. CCS Coal Ash
e. CCS Visibility Improvements Are Minimal
f. Comments on Alternative NOX Emission Limits
g. Cost Effectiveness of SNCR and SCR at CCS
h. CCS General Comments
3. Stanton Station Unit 1
4. Leland Olds Station Unit 1
F. General Comments on SO2 and PM Controls
G. Comments on Reasonable Progress and North Dakota's Long-Term
Strategy
H. Comments on Health and Ecosystem Benefits, and Other
Pollutants
I. Miscellaneous Comments
J. Comments Requesting an Extension to the Public Comment Period
K. Comments Generally in Favor of Our Proposal
L. Comments Generally Against Our Proposal
VI. Statutory and Executive Order Reviews
I. Background
The CAA requires each state to develop plans, referred to as SIPs,
to meet various air quality requirements. A state must submit its SIPs
and SIP revisions to us for approval. Once approved, a SIP is
enforceable by EPA and citizens under the CAA, also known as being
federally enforceable. If a state fails to make a required SIP
submittal or if we find that a state's required submittal is incomplete
or unapprovable, then we must promulgate a FIP to fill this regulatory
gap. CAA section 110(c)(1).
This action involves two separate requirements under the CAA and
EPA's regulations. One is the requirement that states have SIPs that
address regional haze, the other is the requirement that states have
SIPs that address the interstate transport of pollutants that may
interfere with programs to protect visibility in other states.
A. Regional Haze
In 1990, Congress added section 169B to the CAA to address regional
haze issues, and we promulgated regulations addressing regional haze in
1999. 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51, subpart
P. The requirements for regional haze, found at 40 CFR 51.308 and
51.309, are included in our visibility protection regulations at 40 CFR
51.300-309. The requirement to submit a regional haze SIP applies to
all 50 states, the District of Columbia and the Virgin Islands. States
were required to submit a SIP addressing regional haze visibility
impairment no later than December 17, 2007. 40 CFR 51.308(b).
Few states submitted a regional haze SIP prior to the December 17,
2007 deadline, and on January 15, 2009, EPA found that 37 states,
including North Dakota, and the District of Columbia and the Virgin
Islands, had failed to submit SIPs addressing the regional haze
requirements. 74 FR 2392. Once EPA has found that a state has failed to
make a required submission, EPA is required to promulgate a FIP within
two years unless the state submits a SIP and the Agency approves it
within the two year period. CAA section 110(c)(1).
North Dakota initially submitted a SIP addressing regional haze on
March 3, 2010. On July 27, 2010, North Dakota submitted a revision to
that submittal, entitled ``SIP Supplement No. 1.'' On July 28, 2011,
North Dakota submitted another revision, entitled ``SIP Amendment No.
1.''
B. Interstate Transport Requirements
Section 110(a)(1) of the CAA requires states to submit SIPs to
address new or revised National Ambient Air Quality Standards (NAAQS)
within 3 years after promulgation of such standards, or within such
shorter period as we may prescribe. On July 18, 1997, we promulgated
the 1997 8-hour ozone NAAQS and the 1997 fine particulate
(PM2.5) NAAQS. 62 FR 38652. Section 110(a)(2) of the CAA
lists the elements that such new SIPs must address, as applicable,
including section 110(a)(2)(D)(i), which pertains to the interstate
transport of certain emissions.
Section 110(a)(2)(D)(i) contains four distinct requirements or
``prongs'' related to the impacts of interstate transport. The SIP must
prevent sources in the state from emitting pollutants in amounts which
will: (1) Contribute significantly to nonattainment of the NAAQS in
other states; (2) interfere with maintenance of the NAAQS in other
states; (3) interfere with provisions to prevent significant
deterioration of air quality in other states; or (4) interfere with
efforts to protect visibility in other states.
On April 25, 2005, we published a ``Finding of Failure to Submit
SIPs for Interstate Transport for the 8-hour Ozone and PM2.5
NAAQS.'' 70 FR 21147. This action included a finding that North Dakota
and other states had failed to submit SIPs to address interstate
transport of air pollution and started a 2-year clock for the
promulgation of a FIP by us, unless a state made a submission to meet
the requirements of section 110(a)(2)(D)(i), and we approved the
submission, prior to that time. Id.
On April 6, 2009, we received a SIP revision from North Dakota to
address the interstate transport provisions of CAA 110(a)(2)(D)(i) for
the 1997 8-hour ozone NAAQS and the 1997 PM2.5 NAAQS. In
prior actions, we approved this North Dakota SIP submittal for the
first three prongs of section 110(a)(2)(D)(i). (75 FR 31290, June 3,
2010 and 75 FR 71023, November 22, 2010). This action addresses the
fourth prong.
C. Lawsuits
In two separate lawsuits, one in U.S. District Court for the
Northern District of California and one in the U.S. District Court for
the District of Colorado, environmental groups sued us for our failure
to timely take action with respect to the interstate transport
requirements and the regional haze requirements of the CAA and our
regulations. In particular, the lawsuits alleged that we
[[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 (NOX) best available
retrofit technology (BART) determinations and emissions limits for
Milton R. Young Station (MRYS) Units 1 and 2, Leland Olds Station (LOS)
Unit 2, and Coal Creek Station (CCS) Units 1 and 2.
b. North Dakota's determination under the reasonable progress
requirements found at section 40 CFR 51.308(d)(1) that no additional
NOX emissions controls were warranted at Antelope Valley
Station (AVS) Units 1 and 2.
c. North Dakota's reasonable progress goals (RPGs).
d. Portions of North Dakota's 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. NOX BART determinations and emission limits for MRYS
Units 1 and 2 and Leland Olds Station Unit 2.
b. NOX BART determination and emission limit for CCS
Units 1 and 2.
c. A reasonable progress determination and NOX emission
limit for AVS Units 1 and 2.
d. A five-year deadline to meet the emission limits and monitoring,
recordkeeping, and reporting requirements for the above seven units to
ensure compliance.
e. RPGs consistent with the SIP limits proposed for approval and
proposed FIP limits.
f. LTS elements that would reflect the other aspects of the
proposed FIP.
We also proposed approval of a SIP revision in lieu of our regional
haze FIP if the State submitted a revision in a timely way that matched
the terms of our proposed FIP.
2. Interstate Transport, Visibility Prong
We proposed to disapprove the portion of North Dakota's April 6,
2009, SIP revision for interstate transport in which North Dakota
intended to address the requirement of section 110(a)(2)(D)(i)(II) that
emissions from North Dakota sources not interfere with measures
required in the SIP of any other state under part C of the CAA to
protect visibility.
Because of this proposed disapproval, we proposed a FIP to meet the
visibility protection requirement of section 110(a)(2)(D)(i)(II). To
meet this FIP duty, we proposed to find that North Dakota sources would
be sufficiently controlled to eliminate interference with the
visibility programs of other states by a combination of the measures
that we were proposing to approve as meeting the regional haze SIP
requirements combined with the additional measures that we were
proposing to impose in a FIP to meet the remaining regional haze SIP
requirements.
We noted that acting on both the section 110(a)(2)(D)(i)(II)
requirement and the regional haze SIP requirement simultaneously would
ensure the most efficient use of resources by the affected sources and
EPA.
E. Public Participation
We requested comments on all aspects of our proposed action and
provided a two-month comment period, with the comment period closing on
November 21, 2011. We also provided a public hearing. Initially, we
scheduled the hearing to last four hours on one day. 76 FR 58570. At
the request of the Governor of North Dakota, we expanded the time for
the public hearing to 14 hours over two days and changed the venue. 76
FR 60777 (September 30, 2011). The public hearing was held in Bismarck,
North Dakota on October 13 and 14, 2011.
We received a significant number of comments on our proposed rule,
both from commenters, particularly citizens and environmental groups,
that supported our proposed action, and from commenters, primarily from
state and city agencies, rural power cooperatives, and industrial
facilities and groups, that were critical of our proposed action.
In this action, we are responding to the comments we have received,
taking final rulemaking action, and explaining the bases for our
action, including any changes from our proposed action.
II. Final Action
A. Regional Haze
With this final action we are partially approving and partially
disapproving North Dakota's RH SIP revision that was submitted on March
3, 2010, SIP Supplement No. 1 that was submitted on July 27, 2010, and
part of SIP Amendment No. 1 that was submitted on July 28, 2011.
Specifically we are disapproving:
North Dakota's NOX BART determinations and
emissions limits for CCS Units 1 and 2.
North Dakota's determination under the reasonable progress
requirements found at 40 CFR 51.308(d)(1) that no additional
NOX emissions controls are warranted at AVS Units 1 and 2.
North Dakota's RPGs.
Portions of North Dakota's LTS that rely on or reflect
other aspects of the RH SIP that we are disapproving.
[[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:
NOX BART determination and emission limit for
CCS Units 1 and 2 of 0.13 lb/MMBtu averaged across the two units on a
30-day rolling average, and a requirement that the owners/operators
comply with this NOX BART limit within five (5) years of the
effective date of this final rule.
A reasonable progress determination and NOX
emission limit for AVS Units 1 and 2 of 0.17 lb/MMBtu that applies
singly to each of these units on a 30-day rolling average, and a
requirement that the owner/operator meet the limit as expeditiously as
practicable, but no later than July 31, 2018.
Monitoring, record-keeping, and reporting requirements for
the above four units to ensure compliance with these emission
limitations.
RPGs consistent with the SIP limits approved and the final
FIP limits.
LTS elements that reflect the other aspects of the
finalized FIP.
B. Interstate Transport, Visibility Prong
We are disapproving a portion of a SIP revision that North Dakota
submitted for the purpose of addressing the ``good neighbor''
provisions of CAA section 110(a)(2)(D)(i) for the 1997 8-hour ozone
NAAQS and the 1997 PM2.5 NAAQS. Specifically, we are
disapproving the portion of the April 6, 2009 SIP in which North Dakota
intended to address the requirement of section 110(a)(2)(D)(i)(II) that
emissions from North Dakota sources do not interfere with measures
required in the SIP of any other state under part C of the CAA to
protect visibility. Because of this disapproval, we are promulgating a
FIP to meet this requirement of section 110(a)(2)(D)(i)(II). To meet
this FIP duty, we are finding that North Dakota sources will be
sufficiently controlled to eliminate interference with the visibility
programs of other states by a combination of the measures in the North
Dakota SIP that we are simultaneously approving as meeting the regional
haze SIP requirements combined with the additional measures that we are
imposing in a FIP to meet the remaining regional haze SIP requirements.
We note that North Dakota always has the discretion to revise its SIP
and submit the revision to us. Should such a revision meet CAA
requirements, we would replace our FIP with North Dakota's SIP
revision. We encourage the State to revise its SIP.
III. Changes From Proposed Rule and Reasons for the Changes
A. NOX BART for Milton R. Young Station Units 1 and 2 and Leland Olds
Station Unit 2
As noted, we proposed to disapprove North Dakota's NOX
BART determinations for MRYS 1 and 2 and LOS 2 and to promulgate a FIP
for NOX BART for these units to fill the gap that would have
resulted from our disapproval. After considering a recent judicial
decision, we have decided to approve North Dakota's NOX BART
determination for MRYS 1 and 2 and LOS 2 and to not promulgate a FIP
for NOX BART for these units. We more fully describe the
reasons for this change below.
On July 27, 2006, the U.S. District Court for the District of North
Dakota entered a consent decree between EPA, the State, and Minnkota
Power Cooperative (``Minnkota''). The consent decree resulted from an
enforcement action that EPA and the State brought against Minnkota for
alleged violations of Prevention of Significant Deterioration (PSD)
permitting requirements at MRYS 1 and 2. The consent decree called for
North Dakota to make a best available control technology (BACT)
determination for NOX for MRYS 1 and 2 but also provided a
dispute resolution procedure in the event of disagreement regarding the
BACT determination.
In November 2010, North Dakota determined BACT for NOX
to be limits of 0.36 lb/MMBtu for MRYS 1 and 0.35 lb/MMBtu for MRYS 2
based on the use of selective non-catalytic reduction (SNCR)
technology, with separate limits during startup. In reaching this
decision, North Dakota eliminated selective catalytic reduction (SCR),
a higher performing control technology, based on a finding that SCR was
not technically feasible to control emissions from North Dakota lignite
coal. In particular, North Dakota noted that no SCR has ever been
employed on an electric generating unit (EGU) burning North Dakota
lignite, that North Dakota lignite has unique properties that have the
potential to quickly degrade the SCR catalyst, and that no catalyst
vendor supplied with the specifications for the coal at MRYS 1 and 2
would provide a guarantee of catalyst life without first conducting
slipstream or pilot tests at MRYS.
EPA disagreed with North Dakota's findings and the selection of
selective non-catalytic reduction (SNCR) as BACT and initiated the
dispute resolution process under the consent decree. Under the consent
decree, the court was tasked with upholding North Dakota's BACT
determination unless the disputing party was able to demonstrate that
North Dakota's decision was unreasonable. We have included a copy of
the consent decree and the court's order in the docket for this action.
On December 21, 2011, following briefing by the parties, and
consideration of North Dakota's record for its BACT determination, the
court determined that EPA had not demonstrated that North Dakota's
findings were unreasonable. The court decided that North Dakota, based
on the administrative record for its BACT determination, had a
reasonable basis for concluding that SCR is not technically feasible
for treating North Dakota lignite at MRYS. The court upheld North
Dakota's determination that SNCR is BACT.
There are two critical principles expressed in our BART guidelines
that are relevant here. First, as part of a BART analysis, technically
infeasible control options are eliminated from further review. For
BART, EPA's criteria for determining whether a control option is
technically infeasible are substantially the same as the criteria used
for determining technical infeasibility in the BACT context. 70 FR
39165; EPA's ``New Source Review Workshop Manual,'' pages B.17-B.22.
Second, the BART guidelines indicate that states generally may rely on
a BACT determination for a source for purposes of determining BART for
that source, unless new technologies have become available or best
control levels for recent retrofits have become more stringent. 70 FR
39164. As a general rule, the selection of a recent BACT level as BART
is the equivalent of selecting the most stringent level of control, and
consideration of the five statutory BART factors becomes unnecessary.
Over our vigorous challenge of the information and analysis relied
upon by North Dakota, the U.S. District Court upheld North Dakota's
recent BACT determination based on the same
[[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 NOX BART
determinations for MRYS 1 and 2 and LOS 2, and no FIP for these units
is necessary. The applicable limits are 0.36 lb/MMBtu for MRYS 1 and
0.35 lb/MMBtu for MRYS 2 and 0.35 lb/MMBtu for LOS 2.
We note, however, that the State has indicated a willingness to
pursue the conduct of a pilot study at MRYS and/or LOS to analyze the
expected replacement rate of SCR catalyst exposed to flue gas from the
combustion of North Dakota lignite at these cyclone units in a low-dust
or tail-end configuration. It is our expectation that the results of
such a study could be used to inform further evaluation of SCR as a
potential control technology when the State evaluates reasonable
progress in the next planning period for regional haze. This position
is supported by the State's December 20, 2011 letter from North Dakota
Department of Health (NDDH), L. David Glatt, to EPA, Janet McCabe.
B. NOX BART for Coal Creek Station (CCS) Units 1 and 2
We proposed a NOX BART FIP limit for CCS 1 and 2 of 0.12
lb/MMBtu that would apply to each unit individually on 30-day rolling
average basis. We based this limit on our proposed finding that SNCR
plus separated overfire air (SOFA) plus low NOX burners
(LNB) was the best available retrofit technology. While we continue to
find that SNCR plus SOFA plus LNB is the best available retrofit
technology, we are changing the emission limit to 0.13 lb/MMBtu
averaged over both units on a 30-day rolling average basis. Evidence
submitted by commenters and our own additional research in evaluating
comments has led us to conclude that this represents a more reasonable
limit to apply on a 30-day rolling average basis.
This limit represents a control efficiency of 48% based on the
average annual baseline emission rate of 0.22 lb/MMBtu (2003-2004)
provided in the State's BART determination. This value is slightly
lower than the 49% control efficiency we assumed in our proposal, a
value that was based on the State's analysis. Beginning in 2010, CCS 2
voluntarily started employing LNC3, the more stringent level of
combustion controls that the State evaluated in its BART determination.
Annual average Clean Air Markets data for this unit reflects a
NOX emission rate of 0.153 lb/MMBtu. We estimate that SNCR
would achieve an additional 25% reduction, equivalent to an emission
rate of 0.115 lb/MMBtu. This compares to a value of 0.108 lb/MMBtu that
the State originally estimated.
Great River Energy (GRE), the owner of CCS, asserted in comments
that SNCR will only achieve a 20% reduction beyond LNC3. We find that
25% is a conservative and reasonable estimate. We considered several
sources of information in arriving at this value. First, the Control
Cost Manual states that in typical field applications, SNCR provides a
30% to 50% NOX reduction. The manual provides a scatter plot
with NOX reduction efficiency plotted as a function of
boiler size in MMBtu/hr.\1\ The plot supports GRE's assertion that
control efficiency could be lower than 50%, and could approach 30%, for
larger boilers such as those at CCS. Second, Fuel Tech (one of the most
recognized SNCR technology suppliers) estimates a range of 25% to 50%
NOX reduction with application of SNCR.\2\ Lastly, ICAC has
published information that supports a control efficiency of 20 to 30%
for SNCR above LNB/combustion modifications.\3\ Given this range of
control efficiencies, we have settled on a control efficiency--25%--
that is lower than the lowest value given by the Control Cost Manual,
at the low end of the range estimated by Fuel Tech, and in the middle
of the range estimated by ICAC.
---------------------------------------------------------------------------
\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\ https://www.ftek.com/en-US/products/apc/noxout/.
\3\ Institute of Clean Air Companies, White Paper Selective Non-
Catalytic Reduction (SNCR) for Controlling NOX Emissions,
February 2008, p. 9.
---------------------------------------------------------------------------
To arrive at a final BART emission limit, we adjusted the projected
annual average of 0.115 lb/MMBtu upward by 10% and then rounded to the
nearest hundredth to arrive at 0.13 lb/MMBtu. In our experience, a 5 to
15% upward adjustment is appropriate when converting an annual average
emission rate to a limit that will apply on a 30-day rolling average to
account for the fact that shorter averaging periods result in higher
variability in emissions due to load variation, startup, shutdown, and
other factors.
We decided to allow the averaging across Units 1 and 2 in response
to comments we received. The BART Guidelines state, ``You should
consider allowing sources to `'average'' emissions across any set of
BART-eligible emission units within a fenceline, so long as the
emission reductions from each pollutant being controlled for BART would
be equal to those reductions that would be obtained by simply
controlling each of the BART-eligible units that constitute the BART-
eligible source.'' 40 CFR part 51, appendix Y, section V. This
principle applies here.
C. Other Resultant Changes
Because we are now approving North Dakota's NOX BART
determinations for MRYS 1 and 2 and LOS 2, the basis for our proposed
disapproval of North Dakota's RPGs is slightly changed from our
proposal. Disapproval is still warranted because North Dakota's RPGs do
not represent our final NOX BART FIP limits at CCS 1 and 2
or our final NOX reasonable progress FIP limits at AVS 1 and
2 (or the Heskett or Coyote controls that North Dakota included in the
SIP). As part of our FIP, we are finalizing RPGs that are consistent
with the controls we are imposing at CCS 1 and 2 and AVS 1 and 2, and
the Heskett and Coyote controls that North Dakota included in the SIP.
For further details regarding our rationale, please refer to our
proposal and to our response to comments.
Similarly, because we are now approving North Dakota's
NOX BART determinations for MRYS 1 and 2 and LOS 2, the
basis for our proposed partial disapproval of North Dakota's LTS is
slightly changed from our proposal. Partial disapproval is still
warranted because we are disapproving North Dakota's NOX
BART determination for CCS 1 and 2 and NOX reasonable
progress determination for AVS 1 and 2, and the LTS does not reflect
our final NOX BART FIP limits at CCS 1 and 2 or our final
NOX reasonable progress FIP limits at AVS 1 and 2, or
corresponding compliance provisions. Except for these missing elements,
the LTS satisfies the requirements of 40 CFR 51.308(d)(3), so we are
approving the remainder of the LTS. Our FIP fills the gap left by our
partial disapproval of the LTS by specifying NOX emission
limits for CCS 1 and 2 and AVS 1 and 2, compliance schedules, and
monitoring, recordkeeping, and reporting
[[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
NOX and for Heskett Station 2 for sulfur dioxide
(SO2). However, in these instances, North Dakota nonetheless
included emission limits in the SIP that reflect reasonable levels of
control for reasonable progress for this initial planning period. Here
again, we understand that there is room for disagreement about the
State's analyses and appropriate limits. And, again, we may have
reached different conclusions had we been performing the
determinations. However, the comments have not convinced us that the
State, conducting specific case-by-case analyses for the relevant
units, made unreasonable determinations for this initial planning
period or that we should be disapproving the State's reasonable
progress determinations that we proposed to approve.
As noted, we are disapproving North Dakota's NOX BART
determination for CCS 1 and 2 and its NOX reasonable
progress determination for AVS 1 and 2 and promulgating a partial FIP
to establish the required limits and corresponding compliance
provisions. For CCS 1 and 2, the State relied on values for costs of
compliance supplied by the owner that were admittedly erroneous. As
explained in detail in our response to comments, the comments we
received have not convinced us that our disapproval of the State's
NOX BART determination for CCS 1 and 2 is unreasonable, or
that our NOX BART FIP determination and limits (as modified
in this final action) are unreasonable. In particular, we conclude that
GRE's latest cost estimates and cost effectiveness values for SNCR, as
reflected in its November 2011 comments, are not based on reasonable
assumptions and overestimate the costs of compliance. Instead, our
consideration of the five statutory BART factors leads us to conclude
that SNCR plus SOFA plus LNB is BART, with a limit of 0.13 lb/MMBtu on
a 30-day rolling average basis. Also, we continue to find that the
costs of SCR are not reasonable given the projected visibility
improvement; the comments we received on this issue have not convinced
us otherwise.
For AVS 1 and 2, consistent with our proposal, we are disapproving
the State's determination under our reasonable progress requirements
(40 CFR 51.308(d)(1)) that no additional NOX emissions
controls are warranted, and we are finalizing a FIP with a reasonable
progress determination and a NOX emission limit for AVS 1
and 2 of 0.17 lb/MMBtu on a 30-day rolling average basis. Nothing in
the comments has convinced us that the State's determination was
reasonable or that our proposed FIP was unreasonable. As we noted in
our proposal, the costs for installation and operation of combustions
controls at AVS 1 and 2 are very reasonable ($586 and $661 per ton) and
the predicted NOX reductions are substantial--3,500 tons per
unit per year. Appropriate single-source modeling also indicates that
the visibility benefits will be substantial--0.754 deciviews. Based on
these facts, and given that North Dakota's RPGs will not meet the
uniform rate of progress (URP), it was unreasonable for North Dakota to
reject LNB at AVS 1 and 2. We have determined that the State's
rejection of this level of control, and the corresponding RPGs, are not
justifiable based on a reasonable consideration of the applicable
regulatory factors--costs of compliance, time necessary for compliance,
energy and non-air quality environmental impacts of compliance, and
remaining useful life of the source. LNB is a modest, widely-used,
cost-efficient means to achieve significant NOX reductions,
and the resultant visibility benefits will be comparable to or greater
than the benefits achieved through selected controls at several BART
units in North Dakota. We have also rejected comments that call for
more stringent controls at AVS 1 and 2 in this planning period. While
such controls may be appropriate in a later planning period, we cannot
say that the State's rejection of such controls in this planning period
was unreasonable. For further details regarding our rationale, please
refer to our proposal and our response to comments.
Consistent with our proposal, we are approving the remaining
elements of North Dakota's RH SIP because such elements meet the
relevant requirements of our regional haze regulations.
B. Interstate Transport, Visibility Prong
The basis for this part of our action remains unchanged from our
proposal. Nothing in the comments has convinced us that a change from
our proposal is warranted. North Dakota's April 6, 2009 transport
submittal contained only a cursory reference to CAA section
110(a)(2)(D)(i)(II)'s requirement for a SIP revision that contains
adequate provisions ``prohibiting any source or other type of emission
activity within the State from emitting any air pollutant in amounts
which will * * * interfere with measures required to be included in the
applicable implementation plan for any other State under part C [of the
CAA] to protect visibility.'' Because of the impacts on visibility from
the interstate transport of pollutants, we
[[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 NOX BART for
CCS 1 and 2 and NOX reasonable progress for AVS 1 and 2.
Because this combination exceeds the stringency of BART and reasonable
progress limits that were already factored into the Western Regional
Air Partnership (WRAP) modeling for RPGs, this combination meets the
visibility prong of CAA section 110(a)(2)(D)(i)(II). This combination
of regional haze controls will ensure that emissions from sources in
North Dakota do not interfere with other states' visibility programs as
required by section 110(a)(2)(D)(i)(II) of the CAA.
For further details regarding our rationale, please refer to our
proposal and our response to comments.
V. Issues Raised by Commenters and EPA's Responses
A. NOX BART for Milton R. Young Station Units 1 and 2 and Leland Olds
Station Unit 2
As noted in section III of this action, in a major change from our
proposal, we are now approving North Dakota's NOX BART
determinations for MRYS 1 and 2 and LOS 2, and we are not proceeding
with a FIP for NOX BART for these units. We explain the
basis for this change in section III.
We received numerous comments that were specific to the
NOX BART determinations for MRYS 1 and 2 and LOS 2. These
related to a variety of issues--modeling and visibility improvement,
costs of compliance, technical feasibility, appropriate emission
limits, and other issues. The grounds for our decision to approve North
Dakota's NOX BART determinations for MRYS 1 and 2 and LOS 2
render irrelevant further consideration of these issues. Essentially,
we are approving the State's determination of BART based on a federal
court's ruling on our challenge to the State's BACT determination for
MRYS. In establishing BACT, the State established an emission limit
based on what it considered the maximum degree of reduction of
NOX, taking into account various factors similar to those in
a BART determination. Thus, while we disagree with the vast majority of
the comments that disputed our technical and legal analyses concerning
NOX BART for MRYS 1 and 2 and LOS 2, we generally are not
summarizing or responding to those comments to the extent they are
specific to the assessment of NOX BART for MRYS 1 and 2 and
LOS 2.\4\ However, we are responding to comments that may be relevant
to other aspects of this action.
---------------------------------------------------------------------------
\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 NOX BART determinations for two units--CCS 1 and 2--
and its NOX reasonable progress determinations for two
units--AVS 1 and 2.
The State's NOX BART determinations for CCS 1 and 2 are
not approvable because North Dakota did not properly follow the
requirements of section 51.308(e)(1)(ii)(A). Specifically, North Dakota
did not reasonably ``take into consideration the costs of compliance,''
when it relied on cost estimates that greatly overestimated the costs
of controls. We have determined that the faults in the cost estimates
were significant enough that they resulted in BART determinations for
NOX for CCS 1 and 2 that were both unreasoned and
unjustified. Accordingly, these determinations are not approvable.
We are disapproving the State's determination that no
NOX controls are needed at AVS 1 and 2 to achieve reasonable
progress because the State's determination is not reasonable under the
relevant statutory and regulatory requirements.
In the absence of approvable NOX BART determinations in
the SIP for CCS 1 and 2 and in the absence of an approvable reasonable
progress determination concerning NOX controls at AVS 1 and
2, we are obliged to promulgate a FIP to satisfy the CAA requirements.
Likewise, in the absence of an approvable SIP that addresses the
requirement that emissions from North Dakota sources do not interfere
with measures required in the SIP of any other state to protect
visibility, we are obliged to promulgate a FIP to address the defect.
This authority and
[[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 NOX BART and reasonable
progress determinations and imposition of the FIP is not intended to
encroach on state authority. This action is only intended to ensure
that CAA requirements are satisfied using our authority under the CAA.
Comment: The NDDH commented that states are free to deviate from
the BART guidelines in the preparation of their BART analyses, except
for power plants with a capacity exceeding 750 megawatts (MW).
Response: We agree that the BART guidelines are only mandatory
under the regional haze regulations for ``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
NOX at CCS 1 and 2, based on the 2005 BART Guidelines. EPA's
rationale for disapproving the BART determinations at CCS 1 and 2 is
therefore flawed and contrary to the BART Guidelines. EPA appears to be
undertaking a national effort to change its BART Rule without going
through notice and comment rulemaking to amend or repeal the rule. EPA
is doing so by ``applying BART determinations made for sources in one
state as a new presumptive limit for all states.'' Commenter cites 76
FR 58623 of the proposed rule, where EPA justifies a cost/ton ``that
states other than North Dakota have considered reasonable for BART,''
but is higher than the presumptive BART limits.
Response: We disagree with the commenter. First, for each source
subject to BART, the RHR, at 40 CFR 51.308(e)(1)(ii)(A), requires that
states identify the level of control representing BART after
considering the factors set out in CAA section 169A(g), as follows:
States must identify the best system of continuous emission control
technology for each source subject to BART taking into account the
technology available, the costs of compliance, the energy and non-air
quality environmental impacts of compliance, any pollution control
equipment in use at the source, the remaining useful life of the
source, and the degree of visibility improvement that may be expected
from available control technology. 70 FR 39158. In other words, the
presumptive limits do not obviate the need to identify the best system
of continuous emission control technology on a case-by-case basis
considering the five factors. A state may not simply ``stop'' its
evaluation of potential control levels at the presumptive level of
control if more stringent control technologies or limits are
technically feasible. We do not read the BART guidelines in appendix Y
to contradict the requirement in our regulations to determine ``the
degree of reduction achievable through the application of the best
system of continuous emission reduction'' ``on a case-by-case basis,''
considering the five factors. 40 CFR 51.301 (definition of Best
Available Retrofit Technology); 40 CFR 51.308(e). Also, our
interpretation is supported by the following language in our BART
guidelines:
While these levels may represent current control capabilities,
we expect that scrubber technology will continue to improve and
control costs continue to decline. You should be sure to consider
the level of control that is currently best achievable at the time
that you are conducting your BART analysis.
70 FR 39171. The presumptive limits are meaningful as indicating a
level of control that EPA generally considered achievable and cost
effective at the time it adopted the BART guidelines in 2005, but not a
value that a state could adopt without conducting a five factor
analysis considering more stringent, technically feasible levels of
control.
The commenter focuses on narrow passages of the BART guidelines to
support its view that the presumptive limits represent the most
stringent BART controls that EPA can require for regional haze.
However, these passages must be reconciled with the language of the RHR
cited above, as well as other passages of the BART guidelines and
associated preamble. A central concept expressed in the guidelines is
that a
[[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 NOX represent cost effective
controls, but it is well-understood that limits based on combustion
controls do not represent the most stringent level of control for
NOX. Thus, a state which selects combustion controls and the
associated presumptive limit for NOX as BART may only do so
after rejecting more stringent control technologies based on full
consideration of the five factors. Our interpretation reasonably
reconciles the various provisions of our regulations. We clearly
communicated our views on this subject to North Dakota while it was
developing its RH SIP, and, following our interpretation, North Dakota
conducted an analysis of control technologies that would achieve a more
stringent limit than combustion controls.
While North Dakota conducted a 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 NOX BART determinations
* * *'')
Comment: EPA has failed to articulate, or apply, a SIP review
standard that preserves state authority over BART determinations. EPA
can't rely on vague references to the overarching purpose of the
regional haze program to define what's reasonable. The CAA only
requires consideration of the five statutory factors and emission
limits that yield a reduction in visibility impairment. EPA has
contradicted prior statements in various contexts, such as reports to
Congress. EPA has provided no objective measure to gauge EPA's
assessment. EPA's vague standards result in arbitrary and capricious
decision making. EPA must articulate the standard by which it evaluates
and disapproves a SIP and must support its decision with a plausible
explanation.
Response: Our proposal clearly laid out the bases for our proposed
disapproval of the State's BART and reasonable progress determinations,
and we have relied on the standards contained in our regional haze
regulations and the authority that Congress granted us to review and
determine whether SIPs comply with the minimum statutory and regulatory
requirements. To the extent a cost analysis relies on values that are
inaccurate, a state has not considered cost in a reasoned or reasonable
fashion. To the extent a state has considered visibility improvement
from potential emissions controls in a way that substantially
understates the improvement or does so in a way that is not consistent
with the CAA, the state has not considered visibility improvement in a
reasoned or reasonable fashion. In these circumstances, it is
reasonable for EPA to disapprove the relevant aspects of the SIP. In
determining SIP adequacy, we inevitably exercise our judgment and
expertise regarding technical issues, and it is entirely appropriate
that we do so. Courts have recognized this necessity and deferred to
our exercise of discretion when reviewing SIPs. See, e.g., Connecticut
Fund for the Env't., Inc. v. EPA, 696 F.2d 169 (2nd Cir. 1982);
Michigan Dep't. of Envtl. Quality v. Browner, 230 F.3d 181 (6th Cir.
2000); Mont. Sulphur & Chem. Co. v. United States EPA, 2012 U.S. App.
LEXIS 1056 (9th Cir. Jan. 19, 2012).
We disagree with the argument that we must approve a BART
determination where the SIP reflects consideration of the five factors
and the BART selection will result in some improvement in visibility.
We think Congress expected more when it required the application of
``best available retrofit technology.''
While the commenter places great emphasis on EPA's prior statements
in reports to Congress, these statements have no regulatory effect.
Also, these statements are not as supportive of commenter's position as
commenter suggests. For example, ``some flexibility'' does not suggest
unfettered flexibility; a report's suggestion that a cooperative
approach would make sense does not suggest that EPA will or must
approve unilateral decision-making by a state no matter what.
Contrary to the commenter's assertion, we have not destroyed the
State's primacy. In fact, we have approved the vast majority of the
State's determinations. We are only rejecting the State's unreasonable
analyses and decisions. We are authorized to do so.
Comment: The grounds invoked by EPA to disapprove the RH SIP are
legislative in nature and cannot be imposed without advance notice and
comment rulemaking. EPA's proposed action on North Dakota's SIP
articulates a number of grounds not contained in CAA section 169A that
must be met for a SIP to be ``approvable.'' These additional grounds
have never been defined or promulgated with notice and comment
rulemaking. For example, EPA's proposed action articulates a two
pronged test for BART SIP approval: first, ``a state must meet the
requirements of the CAA and our regulations for selection of BART'';
and second, ``the state's BART analysis and determination must be
reasonable in light of the overarching purpose of the regional haze
program.'' 76 FR 58577. The commenter objects to the second prong,
i.e., that ``the state's BART analysis and determination must be
reasonable in light of the overarching purpose of the regional haze
program.'' According to the commenter, this is a new ``reasonableness''
standard that is neither defined nor separately set forth in the Act.
The commenter asserts that EPA is proposing to measure a BART
determination not just against the statutory criteria but also against
EPA's own subjective view whether the result reached is reasonable
enough to meet the ``overarching goal'' of the Act. EPA's new
subjective reasonable enough requirement imposes a new legislative
standard that either goes beyond or, for
[[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 NOX BART determination for LOS 2. It was illegal for
EPA to establish a new adequacy criterion without rulemaking.
Response: While we have decided to approve the State's
NOX BART determination for LOS 2, this comment may be
relevant to other aspects of our final action.
Our prior response largely addresses this assertion. However, in
addition, we think the illogic of the commenter's claim is revealed
when the potential consequences of the commenter's views are examined.
The necessary product of the commenter's view is that a state could
rely on irrational values for any of the five factors, and EPA would be
powerless to disapprove the SIP. We reject that view. We are not
establishing new criteria for approval of a regional haze SIP. We are
applying the criteria and requirements already specified in the CAA and
our regulations. Cost is one of the factors a state must consider in
determining BART. If North Dakota has relied on greatly inflated cost
estimates in its consideration of the cost factor, it has not
considered cost in any meaningful sense of the word.
It is also our opinion that the commenter, in its effort to put our
action in a specific legal box--i.e., ``illegal administrative
action''--consistently misrepresents the nature of our action. This is
a SIP review action, and we believe that EPA is not only authorized,
but required to exercise independent technical judgment in evaluating
the adequacy of the State's RH SIP, including its BART determinations,
just as EPA must exercise such judgment in evaluating other SIPs. In
evaluating other SIPs, EPA is constantly exercising judgment about SIP
adequacy, not just to meet and maintain the NAAQS, but also to meet
other requirements that do not have a numeric value. In this case,
Congress did not establish NAAQS by which to measure visibility
improvement; instead, it established a reasonable progress standard and
required that EPA assure that such progress be achieved. Here, contrary
to the commenter's assertion, we are exercising judgment within the
parameters laid out in the CAA and our regulations. Our interpretation
of our regulations and of the CAA, and our technical judgments, are
entitled to deference. See, e.g., Michigan Dep't. of Envtl. Quality v.
Browner, 230 F.3d 181 (6th Cir. 2000); Connecticut Fund for the Env't.,
Inc. v. EPA, 696 F.2d 169 (2nd Cir. 1982); Voyageurs Nat'l Park Ass'n
v. Norton, 381 F.3d 759 (8th Cir. 2004); Mont. Sulphur & Chem. Co. v.
United States EPA, 2012 U.S. App. LEXIS 1056 (9th Cir. Jan. 19, 2012).
Comment: EPA has no statutory authority to disapprove North
Dakota's BART determination for LOS 2. CAA section 169A(b)(2) leaves
that determination expressly and exclusively in the hands of the State.
EPA's SIP approval authority under CAA section 110 only permits EPA to
confirm whether the State considered the statutory factors; it does not
authorize EPA to pass judgment on how the State considers them. The
commenter cites the American Corn Growers and UARG decisions as support
for its comments. Nor, according to the commenter, does section 110
permit EPA to propose its own emission controls. By doing so, EPA's FIP
``run[s] roughshod over the procedural prerogatives that the Act has
reserved to the States'' (citing Bethlehem Steel Corp. v. Gorsuch, 742
F.2d 1028, 1036 (7th Cir. 1984)).
Response: While we have decided to approve the State's
NOX BART determination for LOS 2, this comment may be
relevant to other aspects of our final action. The commenter reads too
much into the language of 169A. We do not agree that the language, ``as
determined by the State,'' grants the State unlimited discretion or
``sole control'' in making a BART determination, any more than the
accompanying language, ``or the Administrator in the case of a plan
promulgated under section 7410(c) of this title,'' grants EPA unlimited
discretion in making a BART determination in a FIP.
Instead, while States are assigned the primary statutory and
regulatory authority to determine BART, and have significant freedom to
determine the weight and significance of the statutory factors, they
have an overriding obligation to come to a reasoned determination. They
may not act unreasonably or in an arbitrary and capricious fashion, and
Congress has assigned EPA, as the reviewing agency, the role of
determining whether a State's BART determination or reasonable progress
determination is reasonable.
The commenter's citations to legislative history are unconvincing.
Among other things, they are incomplete. The commenter ignores the
intent behind the 1977 legislation:
``The Administrator must promulgate regulations which assure
attainment of the national goal * * * Specifically, the regulations
must require that States which contain mandatory class I areas, and
States
[[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
NOX BART determination for LOS 2, this comment may be
relevant to other aspects of our final action. The commenter cites no
authority in the CAA or our regulations for its assertion that a BART
determination that considers the five statutory factors is adequate as
long as it provides some reduction in visibility impairment. We know of
no such criterion. Instead, our regulations define BART as an emission
limitation based on the degree of reduction achievable through the
application of the best system of continuous emission reduction for
each pollutant which is emitted by an existing stationary facility. The
emission limitation must be established, on a case-by-case basis,
taking into consideration the technology available, the costs of
compliance, the energy and non-air quality environmental impacts of
compliance, any pollution control equipment in use or in existence at
the source, the remaining useful life of the source, and the degree of
improvement in visibility which may reasonably be anticipated to result
from the use of such technology. Given that the BART limit must reflect
the ``application of the best system of continuous emission
reduction,'' we interpret the Act to require a reasonable consideration
of the five factors, one that is not arbitrary and capricious.
Comment: EPA's effort to impose BART determinations by federal
rulemaking impermissibly deprives source owners of the substantive
procedural rights they are otherwise afforded under State law. The
commenter notes that the State used a permit process to establish BART
limits, and that a similar source-by-source adjudication of such limits
must be provided by EPA. The commenter also asserts that EPA must allow
for examination and cross-examination of witnesses, and that,
otherwise, the process is not consistent with due process.
Response: While the State has chosen to use the permit process to
establish BART limits for individual sources, there is nothing in the
CAA or our regulations that requires states or EPA to use permits or a
source-by-source adjudicatory proceeding to establish BART limits. Both
the CAA and our regulations require that BART limits be contained in a
SIP. In the absence of an approvable SIP, CAA section 110(c) requires
us to issue a FIP. We have issued a partial FIP pursuant to CAA section
307. CAA section 307 provides that its provisions apply in lieu of the
Administrative Procedure Act (APA). The procedures provided by CAA
section 307 are adequate to ensure due process to source owners. We
have provided a substantial opportunity for comment (a two-month long
comment period) and an extensive public hearing that lasted 14 hours
over two days. The commenter submitted over 140 pages of comments with
several attachments, and other commenters submitted comments of similar
length. It is not unusual for FIPs to include 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 NOX BART for CCS. The State
relied on those erroneous cost figures in its NOX BART
analysis and determination for CCS in its RH SIP that it submitted on
March 3, 2010. This is the main RH SIP submittal that we are acting on
today.
Because of the magnitude of these acknowledged errors, it is
appropriate to disapprove the BART determination for CCS 1 and 2 that
is contained in the March 3, 2010 submittal. We explain in response to
a prior comment why selection of the presumptive limits without a valid
case-specific analysis supporting such limits as BART is not sufficient
to meet the requirements of the regional haze regulations. Based on our
disapproval of the SIP, and on separate grounds related to our January
2009 finding of failure to submit, we are authorized and obligated to
promulgate a FIP for NOX BART for CCS 1 and 2. CAA section
110(c). We have considered GRE's revised cost analyses in the context
of our proposed FIP and address those analyses in a subsequent
response.
Comment: Commenter stated that EPA's action is in violation of the
10th amendment to the Constitution.
Response: Our action does not compel North Dakota to enforce
federal law and does not intrude on authority reserved to the states.
Thus, our action is consistent with the 10th amendment to the
Constitution.
Comment: Commenter stated that EPA's action is in violation of
Article 4 of the Constitution.
Response: The comment does not specify which aspect of Article 4 we
are alleged to have violated. However, we conclude that our action does
not violate any aspect of Article 4 of the Constitution.
Comment: Commenter stated that Federal Land Managers (FLMs) are
using their Air Quality Related Values Workgroup (FLAG) report, a
guidance document, in highly inappropriate ways.
Response: This comment appears to relate to how the FLMs respond to
proposed PSD permits rather than EPA's proposed actions here.
Accordingly, we are not responding to the substance of this comment.
Contrary to the commenter's assertion, we do not consider our own
actions to be inflexible. We note that we are approving the great
majority of the State's BART and reasonable progress determinations.
2. Interstate Transport Consent Decree
Comment: Commenter states that EPA wrongly uses the Interstate
Transport consent decree to justify action by the September 1, 2011
deadline. Commenter claims that EPA separately acknowledged that the
Interstate Transport consent decree never addressed the regional haze
plan. North Dakota has sought leave of the court that issued the
consent decree to intervene in the case. North Dakota is also seeking a
declaration from the Court that EPA is exceeding its authority under
that consent decree to use it for justification of the regional haze
proposal.
Response: The United States District Court for the Northern
District of California rejected the commenter's arguments in an order
dated December 27, 2011. We agree that the transport consent decree
does not address the regional haze plan. However, as the court in
California recognized, we made an appropriate administrative decision
to address the CAA's transport requirements and regional haze
requirements in the same action. Given that we faced a September 1,
2011 deadline for our proposed transport action under the transport
consent decree, and faced an uncertain deadline for proposed action and
a January 26, 2011 deadline for final action under the then-lodged
regional haze consent decree, we acted in a prudent and reasonable
fashion to sign our notice of proposed rulemaking by the September 1,
2011 deadline in the transport consent decree.
Comment: North Dakota's Interstate Transport SIP, specifically the
``visibility'' element of CAA Section 110(A)(2)(D)(i)(II), must be
approved. North Dakota commented that EPA had no reason not to act on
the visibility portion of the State's interstate transport SIP
submission according to EPA's 2006 guidance. Another commenter stated
that the EPA ``admits'' in the Proposed North Dakota RH SIP/FIP that
the State met the sole obligation of Section 110(A)(2)(D)(i)(II), and
that the EPA's reasons for disapproval therefore lack basis.
Response: We fully explained the basis for our proposed disapproval
of North Dakota's interstate transport SIP in our proposal. See 76 FR
58641-58642. We have fully considered the comments, but nothing in the
comments has caused us to change our views. As we explained in our
proposal, our 2006 guidance was premised on a certain set of
assumptions--in particular, that states would submit their regional
haze SIPs by the regulatory deadline and that the regional haze SIPs
would be the appropriate means for states to establish that their SIPs
contained adequate provisions to prevent interference with the
visibility programs required in other states. It turned out we were
mistaken in our assumptions, and we explained in our proposal that
subsequent events have rendered our 2006 guidance inappropriate in this
specific action. Thus, we appropriately and reasonably evaluated the
State's interstate transport SIP against the statutory requirements and
found it deficient. The State disagrees with the way in which we
characterized the State's transport SIP in our proposal at 76 FR 58574,
but we were clear in our discussion later in our notice that ``North
Dakota did not explicitly state in its April 6, 2009, submittal that it
intended that its Regional Haze SIP be used to satisfy the visibility
prong * * *'' 76 FR 58641.
Basin Electric misrepresents our proposed action. While we
indicated that the State had not explicitly indicated that it was
submitting the RH SIP to meet the interstate transport requirements,
which left us in an uncertain position, that was not the only basis for
our conclusion that the RH SIP did not meet the transport requirements.
Instead, we stated, ``Most importantly, however, EPA must review the
April 6, 2009 submission in light of the current facts and
circumstances, and the RH SIP revision that the State ultimately
submitted does not fully meet the substantive requirements of the
regional haze program * * * To the extent that the State intended to
meet the requirement of section 110(a)(2)(D)(i)(II) with the RH SIP,
the RH SIP submission itself is not fully approvable.'' 76 FR 58642.
The State and Basin Electric assert that we should approve the RH
SIP as satisfying the transport requirements even though we are
disapproving the SIP as meeting regional haze requirements. We
disagree. Under the suggested approach, EPA would simultaneously codify
in the Code of Federal Regulations disparate and conflicting
requirements--the SIP limits
[[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 PM2.5 will
result in smaller relative improvement in visibility when compared to
polluted conditions versus clean conditions. Because current degraded
visibility conditions are considerably worse than natural background
visibility, comparison of a BART source's impact relative to current
degraded visibility conditions would result in a smaller relative
benefit than would a comparison relative to natural background
visibility. EPA previously considered and responded to the same comment
in 40 CFR part 51, appendix Y, promulgated at 70 FR 39104, July 6,
2005. After receiving this comment on the BART Guidelines, EPA
considered the approach of assessing a 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
NOX that are converted from the gas phase to aerosol through
complex photochemical reactions. However, it is uncertain whether the
simplified chemistry will always overpredict visibility impacts. For
example, Anderson et al. (2010) \6\ found that the CALPUFF model
frequently predicted lower nitrate concentrations compared to the
Comprehensive Air Quality Model (CAMx) photochemical grid model, which
has a much more rigorous treatment of photochemical reactions. EPA
recognized the uncertainty in the CALPUFF modeling results, and EPA
made the decision in the final BART guidelines that the model should be
used to estimate the 98th percentile visibility impairment rather than
the highest daily impact value as proposed. 70 FR 39121. We made the
decision to consider the less conservative 98th percentile (i.e., the
eighth highest 24-hour deciview impact in a year rather than the
highest) primarily because the chemistry modules in the CALPUFF model
are simplified and might in some cases predict a maximum 24-hour impact
that is an ``outlier.'' Id. If recent updates to CALPUFF cause the
model to predict lower visibility impacts, the use of the updated model
might also require EPA to reconsider the choice of the less
conservative 98th percentile for evaluating visibility impacts. In any
event, our reliance on CALPUFF modeling is reasonable for the reasons
discussed above.
---------------------------------------------------------------------------
\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. https://www.cmascenter.org/conference/2010/agenda.cfm.
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Comment: Several commenters suggested that the State has unlimited
discretion to consider visibility or cost or other factors in any way
it wishes, even in ways that are inaccurate or inconsistent with the
purpose of the CAA.
Response: We disagree. We have already largely addressed the
assertions in this comment in our responses to comments on our legal
authority. Furthermore, as a hypothetical example, EPA would not defer
to a state determination that the remaining useful life of a source is
one year if relevant evidence indicates the remaining useful life is 20
years. Limits on state discretion are inherent in the CAA and our
regulations; otherwise, states would be free to reach decisions that
are arbitrary and capricious or inconsistent with the purpose behind
the CAA and EPA's regulations. As we have stated, North Dakota's
cumulative modeling approach thwarts the goal stated by Congress in CAA
section 169A and underlying the RHR.
Comment: One commenter claimed that pictorial examples demonstrate
that the visibility benefits which EPA claims can be achieved with
NOX control technologies are not perceptible. The commenter
compares archived pictures copied from the National Park Service (NPS)
Web site, along with the monitored haze index, for days having varying
levels of visibility impairment. For example, the commenter compares
two pictures from different days for which the haze index changes by
1.26 deciviews and concludes that ``no perceptible difference can be
seen * * *''
Response: We do not expect that a 1.0 deciview change in
visibility, which is considered a ``small but noticeable change in
haziness under most circumstances'' (64 FR 35725), could be easily
perceived in a small picture on the printed page. Moreover, North
Dakota did not provide visibility improvement relative to a pre-control
baseline as recommended by the BART guideline (70 FR 39170), so many of
the estimates of visibility improvement contained in the SIP are
misleadingly low. Regardless, the BART Guidelines establish that
predicted visibility improvement below perceptibility thresholds does
not provide a basis to automatically eliminate a control option: ``Even
though the visibility improvement from an individual source may not be
perceptible, it should still be considered in setting BART because the
contribution to haze may be significant relative to other source
contributions in the Class I area. Thus, we disagree that the degree of
improvement should be contingent upon perceptibility. Failing to
consider less-than-perceptible contributions to visibility impairment
would ignore the CAA's intent to have BART requirements apply to
sources that contribute to, as well as cause, such impairment.'' 70 FR
39129. The
[[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).
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\7\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, U.S. Environmental Protection Agency,
September 2003. https://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.
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\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.
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The commenter cited modeling studies that purportedly show that the
model-predicted natural haze levels are substantially larger than the
natural haze levels used by EPA. In fact, the results of those studies
compare well with EPA's natural background levels. The modeling study
by Tonnesen et al.\11\ predicted annual average natural
PM2.5 concentrations in North Dakota in the range of 1.9 to
2.5 ug/m\3\, while the Koo et al. study \12\ predicted annual average
natural PM2.5 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 PM2.5 concentration at
Class I Areas in western North Dakota.
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\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.
https://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.
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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\
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\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.
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\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\
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\15\ https://vista.cira.colostate.edu/tss/Results/HazePlanning.aspx.
\16\ https://www.nature.nps.gov/stats/park.cfm?parkid=467.
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Also, the commenter's reference to 40 CFR 51.301's definition of
``adverse impact on visibility'' is misplaced. This term is defined for
purposes of 40 CFR 51.307 only and is not used in 40 CFR 51.308.
Section 51.307 applies to new source review only, not to the regional
haze program.
Comment: One commenter states that further controlling
NOX emissions from North Dakota sources would not advance
the goal of improving visibility. The commenter bases this statement on
(1) back trajectory analysis that shows that emissions from North
Dakota point sources only impact TRNP and LWA a small part of the time,
and (2) a modeling study of large North Dakota point sources of
NOX emissions that followed North Dakota's 2005 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 NOX point
sources in North Dakota will not advance the goal of improving
visibility.
IMPROVE monitoring data shows that nitrates (from all sources) are
among the highest contributors to visibility impairment at TRNP and LWA
on the worst 20% visibility days. The contribution to visibility
impairment from nitrate at TRNP from 2000-2004 ranged between 13.8% and
24.1%, with nitrate contributing more than any other pollutant in 2001
and 2002. Similarly, the contribution to visibility impairment from
nitrate at LWA from 2000-2004 ranged between 19.2% and 31.5%, with
nitrate contributing more than any other pollutant in 2004.
In order to help states identify the origins of haze-forming
pollutants, such as nitrates, the WRAP conducted source apportionment
analyses that identify the contribution from source regions and types
to specific Class I areas. These source apportionment methods included
CAMx Particle Source Apportionment Technology (PSAT) and the Weighted
Emissions Potential (WEP). Both of these analysis tools can be found on
the WRAP Technical Support System.\17\ As described below, these
analyses clearly demonstrate that North Dakota point sources are among
the largest contributors to nitrates at TRNP and LWA on the 20% worst
visibility days.
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\17\ https://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 NOX
emissions from North Dakota point sources would advance the goal of
improving visibility.
Comment: One commenter submitted new single-source modeling for the
AVS units that are subject to reasonable progress. The new modeling
included results based on the current 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 NOX controls are needed at AVS 1 and 2 for purposes
of reasonable progress or our determination that LNB must be installed
for purposes of reasonable progress. The costs for LNB are very
reasonable--$586 and $661 per ton for AVS 1 and 2, respectively. This
is well below cost effectiveness values the State found reasonable in
making some of its BART determinations. Also, the AVS units are not
small EGUs. To the contrary, at 435 MW apiece, they are comparable to
some of the larger EGUs in the State, and their NOX
emissions are considerably greater than emissions from some other EGUs
in North Dakota. North Dakota predicted that LNB at AVS would achieve
NOX reductions of about 3,500 tons per unit per year. These
reductions are substantially greater than those that will be achieved
at the Stanton Station (maximum reduction of 983 tons per year, based
on firing of lignite) and LOS 1 (reduction of 1,246 tons per year
reduction), where the State selected SNCR as BART, and significantly
greater than the reductions that will be achieved at CCS (reduction of
2,572 tons per year, based on our FIP), the largest EGU in the State.
Finally, even the commenter's new modeling predicts combined visibility
improvement of 0.39 deciviews for LNB on both units. Even if one were
to consider this on a unit-by-unit basis, 0.2 deciviews per unit is
significant, and we find that this level of visibility improvement,
when considered along with the four statutory factors under reasonable
progress, would continue to support our selection of LNB for AVS 1 and
2.
Comment: One commenter stated that: ``EPA has no basis in law for
rejecting the cumulative modeling performed by the State for AVS since,
as EPA admits, there is no requirement that visibility impacts be
addressed under a 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:
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\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 SO2 would have a greater visibility benefit
than a one ton reduction of coarse mass. As only SO2 and
NOX controls were evaluated for the reasonable progress
point sources, and these pollutants have similar impacts on visibility
(per the IMPROVE equation),\19\ the use of the $/deciview is not
particularly relevant or informative. In addition, we did not use the
$/deciview metric for our evaluation of RP controls for largely the
same reasons as stated above for BART controls. As we noted in our
proposal, ``it is important to recognize that dollars per deciview
values will always be significantly higher, often by several orders of
magnitude, than the more commonly used and understood dollars per ton
values.'' 76 FR 58630. North Dakota's use of current degraded
background in its modeling for potential single-source control options
had the effect of greatly increasing the disparity between $/deciview
and $/ton values because the modeling significantly underestimated the
benefits of controls.
---------------------------------------------------------------------------
\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
NOX BART determination for CCS 1 and 2 and its reasonable
progress determination concerning AVS 1 and 2. We are acting to ensure
that reasonable BART and reasonable progress controls are put in place.
North Dakota may not use out-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 SO2 control
options), the only analyses of visibility improvements were of the
incremental differences between competing BART options.
Response: We agree that the visibility improvement of a control
technology should be assessed relative to a 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 NOX than to reduce SO2
in North Dakota's cool climate. However, by placing more emphasis upon
cost per-ton ($/ton) of pollutants removed than on visibility
improvement, the advantages of reducing NOX versus
SO2 are overlooked if both are measured with the same $/ton
yardstick. For this reason, we recommend that the primary emphasis
should be placed upon the dollars per deciview of improvement. EPA has
stated in its Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program (June 1, 2007), ``in assessing additional
emissions reduction strategies for source categories or individual,
large scale sources, simple cost effectiveness based on a dollar-per-
ton calculation may not be as meaningful as a dollar per deciview
calculation.'' The same logic applies to BART. Nevertheless, the
commenter notes that both North Dakota and EPA have based their BART
determinations on cost-per-ton of pollutant removed, and the commenter
included information to show that the EPA BART proposals are internally
consistent and reasonable.
Response: As noted elsewhere, evidence we have reviewed suggests
that the relative benefits are similar. In any event, we have not
ignored visibility benefits in our assessments. It is not necessary to
use dollars per deciview to reasonably consider the regulatory factors
and arrive at reasonable control determinations. As we have explained
in responses to other comments in this section, there can be
significant issues with the use of dollars per deciview values.
Comment: One commenter suggested that the modeling issues raised by
EPA, including the use of a degraded background, should be addressed as
part of North Dakota's 2013 ``mid-course correction'' and that more
emphasis should be placed upon the cumulative visibility benefits that
could be derived from the BART program.
Response: The requirements for periodic reports describing progress
towards the RPGs are contained in the RHR (40 CFR 51.308(g)). The RHR
does not explicitly require that updated visibility modeling be
included as an element of the periodic progress report. Nonetheless, to
the extent that North Dakota chooses to submit updated modeling to meet
other periodic progress reporting requirements, we will address it at
that time.
D. Comments on Costs
1. General
Comment: Commenter stated that EPA cannot replace the State's site-
specific cost estimates solely for the purpose of ensuring consistency
across states. EPA also cannot reject cost items because EPA deems them
atypical. Doing so undermines the statute, which provides that BART is
a state determination.
Response: As we explain in our response to a previous comment, we
have authority to assess the reasonableness of a state's analysis of
costs. We are not relegated to a ministerial role. We have not replaced
cost estimates solely for the purpose of ensuring consistency across
states. When a source puts forward costs estimates that are atypical,
it is reasonable for us to scrutinize such estimates more closely to
determine whether they are reasonable or inflated. Also, given that the
assessment of costs is necessarily a comparative analysis, it is
reasonable to insist that certain standardized and accepted costing
practices be followed absent unique circumstances. Thus, our BART
guidelines state, ``In order to maintain and improve consistency, cost
estimates should be based on the OAQPS Control Cost Manual, where
possible.'' 70 FR 39166.
Comment: Commenter stated that EPA misapplies cost effectiveness to
measure emissions reductions, because the purpose of BART is visibility
improvement. Citing the BART Guidelines, commenter stated that more
weight should be placed on the incremental rather than the average cost
effectiveness.
Response: In our review and analyses, we have considered cost
effectiveness values in conjunction with estimates of visibility
improvement. Our analysis methods are consistent with those called for
by the BART guidelines. We have considered both average and incremental
cost effectiveness. The BART guidelines do not require that greater
weight be placed on incremental cost effectiveness and advise the use
of caution not to misuse the cost effectiveness values. 70 FR 39167-
39168.
Comment: Commenter stated that EPA cannot replace the statutory
requirement that states weigh costs of compliance with a requirement
that states select BART based on a uniform national cost effectiveness
metric. Commenter further stated that EPA essentially elevated cost
effectiveness to being a statutory factor for BART determinations in
the BART Guidelines, and that this was incorrect based on CAA section
169(A).
Response: For power plants larger than 750 MW, the BART guidelines
are mandatory and specify that the Control Cost Manual should be used
to estimate costs where possible and that cost effectiveness in $/ton
be considered. We note that it is too late to challenge the BART
guidelines in this action. That said, the BART Guidelines do not, as
the commenter contends, require states to select BART based on a
``uniform national cost effectiveness metric'' without consideration of
the other relevant factors.
For BART sources other than power plants larger than 750 MW, North
Dakota has specified in its SIP that the BART guidelines must be used
as guidance. Furthermore, any analysis of the costs of compliance must
be reasonable, and the starting point is an accurate estimate of the
costs of potential control options. From there, we must have some means
to assess the reasonableness of the costs, and cost effectiveness in $/
ton is a widely used and understood metric.
Comment: Commenter stated that, in the preamble to the RHR, EPA
established a cost effectiveness value threshold of $1,350/ton for
NOX retrofit control technologies. Another commenter cited
appendix Y, alleging that it states that NOX control costs
above $1,500/ton are not cost effective for BART. Commenter stated that
EPA is therefore inaccurate in the FIP for citing NOX
control costs over $1,500 per ton as cost effective.
Response: EPA disagrees. While EPA described various dollar-per-ton
costs as ``cost-effective'' in various preambles (e.g., 70 FR 39135-
39136), EPA did not establish an upper cost effectiveness
[[Page 20916]]
threshold for BART determinations. We note that North Dakota and other
states have identified NOX control costs well over $1,500
per ton of emissions reduced as being cost effective, and that the
relevance of a particular dollar-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 NOX 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
NOX removed.\23\
---------------------------------------------------------------------------
\23\ Institute of Clean Air Companies, White Paper Selective
Non-Catalytic Reduction (SNCR) for Controlling NOX
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 NOX emission limits from .05 lb/MMBtu to .07 lb/
MMBtu, stating that this was a weakening not allowed by the CAA and
reliant on factors that were not articulated in the CAA. Commenter used
this rationale in stating that EPA must establish BART emission rates
of .05 lb/MMBtu for MRYS Units 1 and 2 and LOS Unit 2, and a BART
emission rate of .108 lb/MMBtu for CCS Units 1 and 2. Another commenter
stated that as a general note, in almost every instance North Dakota,
and by extension EPA, has converted the purportedly annual emission
rate used in the BART analyses to a 30-day emission limit by increasing
it by a seemingly arbitrary percentage increase. This has ranged from a
low percentage up to at least 40%. There is no support in the record
for these increases, and it is not always clear that the original
levels are not feasible as 30 day limits. While the commenter agreed
that there can be additional variability in 30-day averages as compared
to annual, EPA must adequately support any changes it makes to the
emission levels analyzed.
Response: In keeping with the BART Guidelines, we evaluated cost
effectiveness on an annual basis. Specifically, we calculated cost
effectiveness as the total annualized costs of control divided by
annual emissions reductions. When discussing cost effectiveness in our
proposal, we gave both the emissions reductions and emission rates (lb/
MMBtu) on an annual basis. By contrast, the BART Guidelines indicate
that EGU BART emission limits should be specified as 30-day rolling
average limits. It is commonly understood that shorter averaging
periods result in higher variability in emissions due to load
variation, startup, shutdown, and other factors. However, BART emission
limits must be met on a continuous basis. Accordingly, we have not
generally required 30-day rolling average emission limits equal to the
annual emission rates used for calculating cost effectiveness. We find
it
[[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 NOX 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 NOX controls, including SNCR. For several
significant elements of its analysis of SNCR, GRE relied on EPA's
Control Cost Manual.\24\ This was consistent with EPA's BART
Guidelines, which are mandatory for CCS and which provide that cost
estimates should be based on the Control Cost Manual where possible. 70
FR 39166. GRE now essentially criticizes its own earlier analysis,
claiming that it was done only at a screening level. However, to the
extent GRE believed that unique characteristics at CCS required more
site-specific information or more 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
NOX concentrations for 55 existing SNCR installations.
Response: We disagree with this comment. We proposed a control
efficiency of 49% for CCS 1 and 2 based on the combination of both
enhanced combustion controls and post combustion controls. We have
reviewed GRE's refined analysis, and we are not convinced that our 49%
assumption is unreasonable. To the contrary, this level of
NOX reduction still appears achievable.
The URS report that GRE references to support its claim of reduced
control efficiency values provides a plot in which NOX
control efficiency is plotted as a function of inlet NOX
concentrations. The URS plot does not provide the boiler sizes which
would be necessary for a comparison to the data in the Control Cost
Manual, or for comparison to the control efficiency we used in the
proposed FIP. Table 3.1, ``Control Cost Summary,'' in GRE's Refined
Analysis shows control efficiencies of 25% and 20% for Units 1 and 2
respectively, which differ from GRE's assessment of a 50% control
efficiency in its original August 2007 BART analysis and its July 2011
corrected analysis.25 26 GRE's earlier 50% control
efficiency was a reduction from the 0.22 lb/MMBtu baseline (which
included existing LNB with a level of SOFA) to an emission limit of
0.11 with the addition of only SNCR controls (no additional or enhanced
combustion controls). While we would not expect CCS could achieve a 50%
control efficiency from the installation of SNCR alone, we do find our
estimated 49% control efficiency reasonable based on the installation
of both SNCR and enhanced combustion controls (SOFA plus LNB or
LNC3).\27\
---------------------------------------------------------------------------
\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 NOX 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 NOX BART FIP limit for CCS 1 and 2 of 0.12
lb/MMBtu that would apply to each unit singly on 30-day rolling average
basis. We based this limit on our proposed finding that SNCR plus SOFA
plus LNB was BART. While we continue to find that SNCR plus SOFA plus
LNB is BART, we are changing the emission limit to 0.13 lb/MMBtu
averaged over both units on a 30-day rolling average basis. Evidence
submitted by commenters and our own additional analysis in evaluating
comments has led us to conclude that this represents a more reasonable
limit to apply on a 30-day rolling average basis.
This limit represents a control efficiency of 47.8% based on the
average annual baseline emission rate of 0.22 lb/MMBtu (2003-2004)
provided in the State's BART determination. This value is slightly
lower than the 49% control efficiency we assumed in our proposal, a
value that was based on the State's analysis. Beginning in 2010, CCS 2
voluntarily started employing LNC3, the more stringent level of
combustion controls that the State evaluated in its
[[Page 20919]]
BART determination. Annual average Clean Air Markets data for this unit
reflects a NOX emission rate of 0.153 lb/MMBtu. We estimate
that SNCR would achieve an additional 25% reduction, equivalent to an
emission rate of 0.115 lb/MMBtu. This compares to a value of 0.108 lb/
MMBtu that the State originally estimated.
GRE asserted in comments that SNCR will only achieve a 20%
reduction beyond LNC3. We find that 25% is a conservative and
reasonable estimate. We considered several sources of information in
arriving at this value. First, the Control Cost Manual states that in
typical field applications, SNCR provides a 30% to 50% NOX
reduction. The manual provides a scatter plot with NOX
reduction efficiency plotted as a function of boiler size in MMBtu/
hr.\28\ The plot supports GRE's assertion that control efficiency could
be lower than 50%, and could approach 30%, for larger boilers such as
those at CCS. Second, Fuel Tech (one of the most recognized SNCR
technology suppliers) estimates a range of 25% to 50% NOX
reduction with application of SNCR.\29\ Lastly, ICAC has published
information that supports a control efficiency of 20 to 30% for SNCR
above LNB/combustion modifications.\30\ Given this range of control
efficiencies, we have settled on a control efficiency that is lower
than the lowest value given by the Control Cost Manual, at the low end
of the range estimated by Fuel Tech, and in the middle of the range
estimated by ICAC.
---------------------------------------------------------------------------
\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\ https://www.ftek.com/en-US/products/apc/noxout/.
\30\ Institute of Clean Air Companies, White Paper Selective
Non-Catalytic Reduction (SNCR) for Controlling NOX
Emissions, February 2008, p. 9.
---------------------------------------------------------------------------
To arrive at a final BART emission limit, we adjusted the projected
annual average of 0.115 lb/MMBtu upward by 10% and then rounded to the
nearest hundredth to arrive at 0.13 lb/MMBtu. In our experience, a 5 to
15% upward adjustment is appropriate when converting an annual average
emission rate to a limit that will apply on a 30-day rolling average to
account for the fact that shorter averaging periods result in higher
variability in emissions due to load variation, startup, shutdown, and
other factors.
As discussed in another response above, we do not agree with GRE
that it is appropriate to lower the baseline emission rate based on
GRE's voluntary installation of combustion controls on Unit 2 in 2010,
well after the State established the historic baseline of 2003-2004 for
BART planning. Use of such lower baseline rate would inappropriately
skew the 5-factor BART analysis by reducing the emissions reductions
from combinations of control options and increasing the cost
effectiveness values.
b. CCS Emission Limits
Comment: Commenter stated that 30-day rolling limits are intended
to be inclusive of unit startup and shutdown as well as variability in
load. Consequently, associated BART limits must be higher than stated
annual averages used for estimating cost effectiveness.
Response: As described in the proposed FIP, in proposing a BART
emission limit of 0.12 lb/MMBtu, we adjusted the annual design rate of
0.108 lb/MMBtu upwards to allow for a sufficient margin of compliance
for a 30-day rolling average limit that would apply at all times,
including during startup, shutdown, and malfunction. While we proposed
a BART limit of 0.12 lb/MMBtu, we invited comment on whether we should
impose a different emission limit of 0.14 lb/MMBtu on a 30-day rolling
average. After considering all comments, we have settled on a limit of
0.13 lb/MMBtu on a 30-day rolling average. We explain the basis for
this limit in this section as well as in section III above.
c. CCS Modeling
Comment: Commenter stated that pollutant interaction has an impact
on modeled visibility impairment and, as such, GRE believes that
modeling changes to NOX emission rates alone will not
provide visibility modeling results that are representative of actual
emission controls. Commenter asserted that this may overstate
visibility improvement as compared to modeling NOX,
SO2 and PM2.5 together. However, for the purpose
of illustrating the relative visibility impacts of SNCR and LNC3, the
commenter presented an analysis of the incremental modeled impacts.
Response: Our review of North Dakota's and GRE's CALPUFF input
files reveals that SO2, NOX, and particulate
matter (PM) emission changes were in fact modeled together. All of the
NOX control options were modeled along with the
SO2 emission reductions that would be achieved from either a
new scrubber or modifications to the existing scrubber. However, in
order to determine the distinct visibility improvement from the
NOX control options, it is necessary to compare the modeled
impacts to a pre-control scenario. This is in fact the approach
prescribed by the BART Guidelines which state that you should
``[a]ssess the visibility improvement based on the modeled change in
visibility impacts for the pre-control and post-control emission
scenarios.'' 70 FR 39170. As noted in our proposal, because North
Dakota did not provide visibility benefits relative to a pre-control
baseline, ``it [was] not possible to describe the incremental
visibility benefits of SNCR, or other NOX control options,
over the selected SO2 BART control (scrubber modifications
at 95% control).'' 76 FR 58623. As a result, we were only able to
specify the incremental visibility benefit between NOX
control options. In our evaluation of BART for NOX at CCS,
we weighed the visibility factor in consideration of the fact that the
improvement was incremental to lower NOX controls and not
relative to a pre-control baseline. We are not able to assess the
visibility benefit information the commenter provided in Table 3.3.1 of
the comments due to the lack of documentation and detailed explanation
of the information presented.
d. CCS Coal Ash
Comment: GRE references Appendix C to its Refined Analysis ``Fly
Ash Storage and Ammonia Slip Mitigation Technology Evaluation.'' GRE
claims that its previous estimates of fly ash sales and disposal costs
were ``screening level values'' and the Appendix C report provides a
more comprehensive assessment of ash implications associated with SNCR
installation. GRE states that the report illustrates that any ash
impact costs add to the total cost of SNCR and make it less cost
effective.
Response: Based on further analysis, we are not convinced that the
use of SNCR will impact GRE's ash sales. We explain this more fully in
the responses below. Also, regarding specific sales price and costs
numbers, we are not convinced that GRE's Appendix C report, included
with its comments, provides a more realistic picture of these values.
We provide more detailed information in other responses.
Comment: GRE stated that mandating SNCR will leave GRE in a
vulnerable position where it would expect to incur significantly higher
costs from lost ash sales and increased landfilling. Commenter stated
that GRE would expect to annually incur between $4,435,000 and
$8,988,000 in additional ash costs. Commenter's contractor, Golder
Associates, provided a revised analysis that included three potential
scenarios of SNCR's impact to fly ash sales (GRE Appendix C): A. Sales
are not affected; B. Worst case scenario--no
[[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
NOX 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\ https://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\ https://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.'' https://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\ https://www.rmajko.com/suppliers1.html.
\45\ https://www.azdot.gov/highways/materials/pdf/materials_source_list_flyash.pdf.
\46\ https://www.dot.state.ga.us/doingbusiness/materials/qpl/documents/qpl30.pdf.
\47\ https://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 (CO2) is emitted into the
atmosphere to make cement. Commenter argued that there will be a 1 to 1
ton increase in CO2 emissions from using more Portland
cement in place of ash.
Response: As stated in previous responses, we do not agree that the
use of SNCR will cause GRE to experience a reduction in fly ash sales.
Furthermore, GRE presents no evidence to support its claims about
CO2 emissions or reduced quarrying. CO2 emissions
result from many factors, and additional quarrying might be avoided
through use of alternative sources of fly ash. As did the State, we
have already considered the potential need to landfill additional fly
ash in our five factor analysis, but do not consider that a reason to
reject SNCR as BART.
Comment: Commenter stated that the landfill cost estimate includes
costs for the life of the disposal facility including engineering,
design, and permitting; construction; and operations and maintenance,
including closure and post-closure care.
Response: As we stated in previous responses, we are not convinced
that the use of SNCR will impact GRE's ash sales; thus, requiring
additional on-site landfill facilities should not be necessary.
Furthermore, we have noted in prior responses that we find a disposal
cost of $5/ton is reasonable in the improbable event that some ash
would need to be disposed.
Comment: Commenter stated that the ash management costs used in
this analysis assumes that future ash disposal facilities will be
designed and constructed to meet RCRA subtitle D standards. Commenter
asserted that this cost would increase considerably if EPA tightens
standards as a result of the uniform national disposal standards
currently being considered.
Response: As already discussed, we do not agree that SNCR will lead
to increased landfilling. Were this comment still relevant, we note
that we evaluate costs based on the best information available
concerning current costs. We do not know what the final coal combustion
residuals regulations will require with respect to RCRA subtitle D and
we are not required to include speculative costs in our estimates.
e. CCS Visibility Improvements Are Minimal
Comment: Commenter stated that the refined analysis demonstrates
that the installation of SNCR will not result in perceptible visibility
improvements in North Dakota's Class I areas, and it is not justifiable
for GRE to incur the added cost of SNCR without any appreciable
improvement in visibility. To support these claims, the commenter
stated that from GRE's BART analysis, it can be estimated that the
incremental deciview improvements associated with the installation of
SNCR would range from 0.109 to 0.207, which are well below what EPA has
established as a perceptible level to the human eye (0.5 deciviews).
Response: There is considerable uncertainty in the deciview
improvements calculated by GRE. GRE provides an analysis of the
incremental modeled impacts and cost per deciview in Table 3.3.1 of
GRE's November 2011 Refined Analysis, but provides no further
explanation of the table or the values contained therein. A January 19,
2012 NDDH letter to CCS also raises concerns about certain aspects of
the table pertaining to baseline emission rates and deciview
improvement values. In addition, it appears that GRE has calculated
these values based on new
[[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 NOX
emissions in North Dakota represent approximately only 6% of total
NOX emissions, and therefore, it is understandable that
proposed and additional BART NOX reductions from North
Dakota utilities do not provide more visibility improvements in the
Class I areas.
Response: We disagree with the commenter's assertion that the
potential visibility improvements from NOX controls on North
Dakota EGUs would be small. The commenter's estimate of the
contribution from utilities to NOX emissions in North Dakota
appears to be incorrect. Emission inventories developed by the WRAP for
the 2000-2004 planning period show that EGUs contributed 78,995 tons
out of a total of 229,460 tons of NOX for all source
categories combined.\48\ Therefore, utilities account for some 34.4% of
the total NOX emissions in North Dakota, and more than any
other source category.
---------------------------------------------------------------------------
\48\ Source: https://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 NOX emission
rate.
Comment: Commenter (GRE) stated that ammonia is a listed state
toxic in North Dakota, and is viewed as a contributor to regional haze
because it can bond with SO2 and NOX to form
ammonium sulfate and ammonium nitrate aerosols. Commenter further
stated that additional ammonia slip from the proposed SNCR for CCS may
offset the relatively minor NOX reduction proposed by EPA.
Response: GRE does not provide the anticipated ammonia emissions
for comparison to the proposed NOX reductions and states
that this issue is outside the scope of its analysis. In the RHR, EPA
states that there are scientific data illustrating that ammonia in the
atmosphere can be a precursor to the formation of particles such as
ammonium sulfate and ammonium nitrate; however, it is less clear
whether a reduction in ammonia emissions in a given location would
result in a reduction in particles in the atmosphere and a concomitant
improvement in visibility (70 FR 39114). The evaluation of whether
ammonia slip would offset the proposed NOX reductions to
some degree cannot be calculated due to the lack of information
provided by GRE, as well as the inherent uncertainty in estimating the
effects of ammonia emissions on regional visibility.
Furthermore, as stated in our previous responses, ammonia slip, due
to the incomplete reaction of the NOX reducing agent, can be
limited to low levels through proper design of the SNCR system. Design
of the SNCR system can be optimized by taking into account the
temperature, NOX concentration, residence time, and reagent
distribution. Our recent analysis indicates that ammonia slip levels
can be reduced to below 2 ppm with the introduction of the latest
monitoring technology. Therefore, we disagree that any potential
ammonia release from SNCR at CCS may offset the proposed NOX
reductions.
Comment: Commenter stated that NOX contributes to
ammonium nitrate formation, which is predominantly a winter ``haze''
contributor, and for the purposes of valuing the welfare effects of
recreational visibility, it is important to consider that the North
Dakota national parks are generally not in high use during the winter
season. Commenter expressed concern over paying an extreme price per
deciview resulting in imperceptible improvements for a time of year
when the parks are generally not used.
Response: We addressed this comment in our responses to modeling
comments in section V.C.
f. Comments on Alternative NOX Emission Limits
In our proposal, we asked for comments on a possible alternative
NOX BART limit for CCS 1 and 2, based on use of combustion
controls alone, of 0.14 lb/MMBtu. This section presents the comment
summaries and our responses related to this issue.
Comment: Commenter stated that because CCS cannot achieve the 30-
day rolling average emission rate without installation of SNCR, it
should not be considered as an appropriate BART emission level.
Commenter stated that this is consistent with EPA's own determination
that a presumptive BART emission level of 0.17 lb/MMBtu is cost-
effective and will result in significant visibility improvement.
Commenter stated that these comments and the associated Refined
Analysis demonstrate that any additional NOX reductions
would neither be 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
NOX emission limits, unless it is determined that an
alternative control level is justified based on consideration of the
statutory factors. As noted elsewhere, our regulations require that a
state or EPA must consider the five statutory BART factors in
determining BART and cannot simply default to the presumptive limits.
We have already explained why the State's consideration of the costs of
compliance was fatally flawed and why we must disapprove the State's
BART determination. In promulgating our FIP, we have reasonably
considered the five factors and arrived at a reasonable BART
determination that is more stringent than the presumptive BART limit.
Comment: Commenter stated that NOX limits should be
expressed on an annual rather than 30-day basis, to account for the
full spectrum of operations such as variable load, and
[[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
NOX BART limit for CCS 1 and 2 to 0.13 lb/MMBtu on a 30-day
rolling average basis.
Comment: Commenter argued that the NOX emission limits
proposed in the original BART evaluation for Units 1 and 2 did not
consider that the units would experience significant load variability.
Commenter stated that in September 2011, GRE increased the cycling
range of CCS in response to market conditions, which caused significant
load swinging and impacts to NOX control performance.
Commenter further stated that load variability is expected to continue
as an operational scenario for Units 1 and 2 for the foreseeable
future, and therefore any emission limit must account for this
additional variability in emissions. The commenter asserted that the
presumptive emission rate of 0.17 lb/MMBtu is achievable, including
load variability.
Response: The 0.13 lb/MMBtu limit we have selected provides a
reasonable margin for compliance, not only for load variability, but
also for startup and shutdown conditions. The emission limit we have
set also takes into consideration the control efficiency that can be
achieved with SNCR. We have provided further discussion on this in
previous responses.
Comment: Commenter stated that reducing NOX to the
absolute limits of LNC3 and DryFiningTM leads to collateral
damage to the CCS boilers. Specifically, GRE claims that installation
of the second generation LNC3 technology in 2008 on Unit 2 contributed
to circumferential cracking on the boiler tubes between the burner
front and the over-fired air registers, as operators attempted to
maintain low NOX emission rates. GRE further stated that the
2010 implementation of DryFiningTM technology with LNC3
accelerated tube leaks at CCS 2, causing unplanned outages. The
commenter asserted that while it has been possible to operate at lower
NOX emission rates during ideal conditions, the risk of
circumferential cracking increases significantly when operating at
these lower rates. The commenter concluded that an emission rate
between 0.14 and 0.17 lb/MMBtu for LNC3 and DryFiningTM is
not consistently achievable as a 30-day rolling emission limit; and the
commenter firmly believes that 0.17 lb/MMBtu is the most stringent
level.
Response: We have decided to finalize our proposal that SNCR + SOFA
+ LNB is BART. We note that using SNCR would alleviate GRE's concerns
about circumferential cracking from use of LNC3 and
DryFiningTM while also helping to maintain NOX
emissions during periods of load variability. We provide additional
responses pertaining to emission limits in this section.
Comment: Commenter stated that from a review of EPA modeling
information from the Cross-State Air Pollution Rule (CSAPR) docket,\49\
there are currently no tangentially-fired utility EGUs, in the CSAPR-
affected states, with LNC3 combustion controls and SNCR post-combustion
controls that operate at or below the presumptive BART limit of 0.17
lb/MMBtu for NOX. The commenter further stated that none of
the facilities included in the CSAPR database operate at or below the
proposed FIP limit of 0.12 lb/MMBtu.
---------------------------------------------------------------------------
\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 NOX 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 NOX 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 NOX reduction
with SNCR more difficult due to the competing urea oxidation reaction
that causes NOX reduction to drop off at high temperatures.
As a result, one would expect SNCR performance to
[[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 NOX analysis.
These analyses essentially reaffirm GRE's initial determination that
DryFiningTM and LNC3 is BART for CCS.
Response: Our prior responses address the presumptive emission
limits and alleged cost effectiveness thresholds. We disagree that
GRE's consultants' analyses confirm that SNCR is not cost effective or
reaffirm GRE's initial BART recommendation. As we have noted, our
analysis indicates that SNCR plus LNC3 is more cost effective than we
estimated in our proposal.
Comment: Commenter stated that only a site specific evaluation by a
competent SNCR supplier (URS) should be used to estimate emission
reductions and associated costs. The URS refined analysis is provided
in Appendix B of the GRE document. URS is a preeminent engineering
consultant in SNCR technology, having designed several dozen SNCR
pollution control systems throughout the world. This experience
qualifies URS to make site-specific recommendations on SNCR design.
Response: EPA agrees that an evaluation by a competent SNCR
supplier may be beneficial but notes that GRE has only now brought its
``refined analysis'' forward. GRE found it sufficient to supply several
cost estimates to the State without such assistance. Regardless, URS is
not an SNCR technology supplier. While URS is an engineering firm, it
is not a supplier or developer of SNCR technology. As indicated in the
experience list provided by URS, URS's role in these SNCR projects was
primarily as constructor, performing a feasibility study, engineering,
or procurement. In no cases was URS actually the process supplier--the
company that actually designed the process and made the performance
predictions and guarantees. See docket. Depending upon the project
shown in the list provided by URS, its role may have been associated
with managing project construction activities, engineering and location
of equipment such as piping, tanks, etc., and in some cases simply
``feasibility studies,'' but in none of the cases it cites did URS
actually design the SNCR process and develop performance guarantees.
While location of tanks, routing of process piping and other
engineering or construction activities are important aspects of a
project, they do not determine the process performance. Critical
aspects of SNCR process design, which determine performance
(NOX reduction, reagent use and ammonia slip), are design of
and location of injectors in the furnace, specification of reagent
type, flowrates and control logic. Process design is performed by
companies such as Fuel Tech, having supplied many utility SNCR systems,
or other companies. For example, some of the installations cited by URS
in its experience list, such as TVA Johnsonville and PEPCO were
supplied by Fuel Tech or Advanced Combustion Technology. As indicated
in the table provided by URS, URS apparently had a role in the
engineering of these projects (location of storage tanks, piping
between components, etc.), but did not develop the process design or
the performance estimates for the TVA or PEPCO installations. Other
installations cited by URS (new boilers at AES Warrior Run and the two
Air Products installations) were actually designed and supplied by the
circulating fluid bed boiler suppliers, with performance and guarantees
developed by the boiler supplier. The balance of the installations
cited by URS were either feasibility studies, where no real process
guarantees were made, or were actually supplied by other companies
(Applied Utility Systems, ESA, or others). In fact, the study that URS
has conducted for GRE on CCS is essentially a feasibility study. Aside
from URS's experience, the analysis URS conducted does not support that
the CCS units are so unique that Control Cost Manual estimates of SNCR
performance and costs are irrelevant.
Thus, while URS has the expertise to provide useful input on the
cost associated with installing some of the associated equipment, it is
not in the business of providing SNCR process designs and performance
guarantees--and it apparently did not do this on any of the projects on
its experience list.
GRE argues that the CCS units are unique and thus require
evaluation by an SNCR process supplier in lieu of an analysis based on
the Control Cost Manual. However, GRE has not provided any information
from companies that actually design SNCR systems and have experience
providing performance guarantees, such as Fuel Tech or another company
that is an experienced SNCR supplier. Thus, GRE's claims about SNCR
performance are not supported.
The control efficiency of SNCR is the main issue raised by URS
because it has a significant impact on the overall cost effectiveness
of SNCR, as further explained later in our responses. URS also provides
a cost estimate which is used to support GRE's own cost analysis. While
GRE comments that ``only a site specific evaluation, by a competent
SNCR supplier (URS), should be used to estimate emission reductions and
associated costs,'' the evaluation provided by URS is based on data
from other plants. URS extrapolates the SNCR control efficiency using
CCS data from a plot of control efficiency versus inlet NOX
concentrations for 55 existing SNCR installations. This differs from
the Control Cost Manual, which plots control efficiency as a function
of boiler size. Neither is a definitive ``site specific'' measure of
estimating control efficiency. Furthermore, there are many other
factors besides inlet NOX concentration that affect the
efficiency of an SNCR system. Thus, GRE has provided little support for
reducing the SNCR control efficiency by 20 to 30 percentage points from
the efficiency used in the proposed FIP and from what they themselves
originally estimated (i.e., from 50% down to 30% or 20%).
Since GRE has not provided any information from companies that
actually design SNCR systems and have experience providing performance
guarantees, GRE's claims, that its prior representations about SNCR
performance should be disregarded, are not supported.
Comment: Commenter states that EPA's analysis contains faults that,
when corrected, lead to the conclusion that SCR, not SNCR, is BART for
the CCS units. The faults include, first, that the EPA analysis of
$4,116/ton is, on its own, cost effective and close to the cost
effectiveness value North Dakota and EPA accepted at Stanton Station
Unit 1 of $3,778/ton. Second, EPA retains the 80% control efficiency
for SCR from the State's BART determination when, elsewhere in the
proposal, EPA acknowledges that SCR is capable of 90% control. The
commenter adjusted the cost effectiveness value to $3,595 based on 90%
control efficiency which, the commenter states, is cost effective and
below the Stanton Station Unit 1 cost effectiveness previously
mentioned. Third, EPA retained costs related to loss of sales from fly
ash disposal in the SCR cost analysis, which is perhaps in error as
there is no reason a well-designed SCR, particularly in the low dust or
tail end configuration, would impact ash sales. SCRs can meet 2 ppm
ammonia slip, and at that level the ammonia in the ash is typically
acceptable for all
[[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
NOX removed. We find that this cost is excessive in light of
the predicted visibility improvement. Thus, we are not changing our
determination that SNCR+ASOFA+LNB is NOX BART at CCS 1 and
2.
Comment: Commenter stated that the furnace boxes for CCS 1 and 2
are unique, as required by the high moisture content of Fort Union
lignite. Commenter stated that the firebox is larger than other lower-
moisture coal-fired units, resulting in a higher cost of NOX
combustion controls. Specifically, the commenter stated that the
greater air flow distance through the furnace requires increased size
and type of wall nozzles and increased staging complexity; and an
advanced air combustion system added to a larger firebox requires
additional wall openings and redesign to wall water tubes, further
increasing costs.
Response: All electric utility boilers are built to the owner's
specifications and are, therefore, unique. However, the information
presented by the commenter has not convinced us that the CCS boilers
are so unique that our costing assumptions or our overall cost
estimates are unreasonable. The fuel burned at CCS is very low BTU
fuel, which contributes to the large furnace size. Therefore, it is
possible that a combustion retrofit for CCS might be somewhat higher in
cost than for a similar retrofit for a boiler of similar output firing
a higher Btu coal.
Examination of Title IV data shows several lignite fired boilers
with significantly lower emissions than at CCS--some using only
combustion controls and some using combustion controls in combination
with SNCR.
The application of SNCR on low-BTU fuel utility boilers goes back
to the late 1980's when it was successfully applied to German brown
coal boilers.\54\ The larger furnace volume of a lignite or other low-
Btu furnace actually provides more time for the SNCR reaction to occur,
which should be beneficial for mixing and the SNCR reaction. The
advantage will likely be improved reagent utilization.
---------------------------------------------------------------------------
\54\ Hofmann, J.W., von Bergmann, J., Bokenbrink, D., Hein, K.
``NOX Control in a Brown Coal-Fired Utility Boiler.''
Presented at the EPRI/EPA Symposium on Stationary Combustion
NOX Control, San Francisco, CA, March 8, 1989.
---------------------------------------------------------------------------
Comment: Commenter stated that the larger registers installed at
CCS 2 further reduce NOX emissions as they allow for
increased primary air which is available after installation of
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 $180,000 for each Unit in the November study.
The baseline emission rate is another factor which would result in
higher cost effectiveness values in the November study. The baseline
emission rate in the July study was estimated at 0.22 lb/MMBtu,
compared to 0.20 lb/MMBtu and 0.153 lb/MMBtu for Units 1 and 2 in the
November study. A lower emission rate would result in less emissions
controlled and a higher cost effectiveness value.
The lower SNCR control efficiency in the November study results in
less NOX controlled (i.e., 1,152 tons per year (tpy) for
Unit 1 and 772 tpy for Unit 2 in the November study versus 2,786 tpy
NOX controlled in the July study), and a higher overall cost
effectiveness value. The reduced SNCR control efficiency outweighs the
changes to the cost of control, which would otherwise result in lower
cost effectiveness values.\55\
---------------------------------------------------------------------------
\55\ Our analysis differs in that we considered SNCR combined
with combustion controls.
[[Page 20928]]
Table 1--Comparison Between Cost Effectiveness Factors in GRE's July and November 2011 Cost Estimates for CCS
----------------------------------------------------------------------------------------------------------------
Baseline Pollution
emission Control Emission Installed Annual O&M control
Study description rate (lb/ efficiency reduction capital cost cost (MM$/ 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 NOX 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 NOX level of 0.20 lb/MMBtu,
and a normal stoichiometric ratio (NSR) of 1.0 (30 lb urea/46 lb
NO2),\61\ the hourly usage of reagent is: 5900 MMBtu/hr *
0.20 lbNO2/MMBtu * (30 lb urea/46 lb NO2) = 770
lb/hr.
---------------------------------------------------------------------------
\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 NO2/MMBtu)*(0.25 reduction)*(1 ton/
2000 lb) = 0.148 ton/hr.
The reagent portion of cost is 192/0.148 = $1,300/ton of
NOX removed.
This $/ton for reagent would be the same assuming the same cost per
ton of urea and the same chemical utilization (25%, or 25% reduction at
an NSR = 1.0).
The errors in the URS estimate are carried through to GRE's
estimates.
Comment: Commenter stated that with the installation of LNC3,
LNC3+, and DryFiningTM;, CCS's NOX emissions are
greatly reduced with respect to ``baseline'' values previously
provided; and it is necessary to update the baseline emissions for
Units 1 and 2 for this technology evaluation in order to reflect
current conditions and unit performance. Commenter stated that the
revised baseline emissions for Units 1 and 2 should be adjusted to
0.201 lb/MMBtu and 0.153 lb/MMBtu, respectively. The commenter stated
that the use of DryFiningTM technology has already been
implemented for use at both units at a cost of $270 million, and GRE
has made a significant investment to achieve multi-pollutant emission
reductions and visibility improvements in the region.
Response: As stated in our previous comments, we reject GRE's
revised baseline. We evaluate potential control options based on
baseline conditions, not on ongoing voluntary revisions to a facility
after the baseline period. It is not reasonable to consider voluntary
controls installed after the baseline period in determining BART. Such
an approach would tend to lead to higher cost effectiveness values for
more effective controls and encourage sources to voluntarily install
lesser controls to avoid more effective BART controls later.
Comment: The refined economic impacts analysis provided by GRE
confirms GRE's original conclusion that SNCR is not a cost effective
NOX control option.
Response: We disagree with the cost effectiveness analysis provided
by GRE in the refined analysis. We disagree with the control efficiency
used for SNCR in combination with SOFA plus LNB used in the refined
analysis, the assumed baseline and controlled emission rates, and the
assumed reduction in ash sales. These issues are further discussed in
the comment responses specific to each issue.
h. CCS General Comments
Comment: The commenter stated that at the time of this submittal,
GRE has already installed LNC3 combustion controls at Unit 2. In 2011
dollars, this was at a cost of over $6 million and has already resulted
in NOX reductions. The same system is tentatively scheduled
to be installed on Unit 1 during the 2014 outage.
Response: As stated in our previous comments, we reject GRE's use
of a revised baseline.
3. Stanton Station Unit 1
Comment: Commenter states that the BART limits for the Stanton
Station are contrary to BART requirements. Commenter states that both
SO2 and NOX emission rates would decrease if only
Powder River Basin (PRB) coal were allowed to be burned, because the
burning of North Dakota lignite coal creates higher emissions of both
pollutants. Commenter also states that EPA's cited 7th Circuit Court of
Appeal decision (76 FR 58589) would not apply to such a requirement
because that decision only applies to the redesign of a source.
Response: We do not interpret the CAA or the regional haze
regulations as
[[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 NOX controls for Stanton Station Unit 1.
While the commenter supports the use of further NOX controls
at this facility, the commenter asks EPA to further evaluate the cost
estimates for SCR at this facility. According to the commenter, the
cost estimates for SCR that EPA relied on in its proposal appear to
include, at a minimum, costs associated with allowance for funds used
during construction (AFUDC), which is not appropriate under the BART
Guidelines and Control Cost Manual. Further, the underlying
calculations in Stanton Station's BART submission to North Dakota do
not clearly support the resulting cost.
Response: We relied on cost estimates submitted by North Dakota in
our evaluation of the cost effectiveness of NOX control
options for Stanton Station Unit 1. In turn, North Dakota relied on
costs taken from GRE's BART analysis as found in Appendix C.2 to the
SIP. GRE asserts that these costs were derived ``using the procedures
found in the EPA Air Pollution Control Cost Manual.'' \62\ However, as
suggested by the commenter, there are irregularities in how GRE applied
the SCR cost methods in the Control Cost Manual. In particular, GRE
included a line item for AFUDC in the amount of $8,232,000. However,
closer examination reveals that this line item represents the cost of
replacement power associated with a purported 10 week outage for
installation of the SCR, and does not represent allowance for funds
used during construction. Regardless, elimination of this line item
would only lower the cost effectiveness values for SCR when burning
lignite and PRB coal from $6,475/ton to $6,118/ton and $8,163/ton to
$7,713/ton, respectively. In addition, the total capital investment
stated by GRE for SCR of $55,279,000 equates to $294/kilowatt (kW). We
find this cost consistent with the installed SCR retrofit costs,
ranging from $79/kW to $316/kW (2010 dollars), cited in recent industry
studies.\63\ We expect that the cost at Stanton Station Unit 1 would be
at the higher end of this range given its relatively low generation
capacity of 188 MW. Accordingly, while we agree that there are
questions regarding the underlying calculations, it is our opinion that
further evaluating costs would not change the outcome of the BART
determination.
---------------------------------------------------------------------------
\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 NOX emissions
removed with an incremental cost effectiveness between the SCR and SNCR
control options of $8,845/ton of NOX emissions removed. The
cost estimates for SCR at LOS 1 that National Parks Conservation
Association (NPCA) and the NPS provided in their comments reflect cost
effectiveness values greater than $4,000/ton of NOX
emissions removed. While these various estimates are lower than those
the State relied on, they are still high enough that we are not
prepared to change our conclusion that the State's BART determination
of SNCR + Basic SOFA for LOS 1 was reasonable.
Comment: Commenter stated that there is no discussion why SNCR +
Boosted SOFA was rejected as BART.
Response: In response to this comment, we reviewed the benefits of
SNCR + Boosted SOFA over SNCR + Basic SOFA. We determined that the two
combustion control options achieve very similar results and that the
incremental cost of the Boosted SOFA option at $7,826/ton is excessive
compared to the 92 tons of additional NOX reductions, which
we anticipate would provide a low visibility benefit.
F. General Comments on SO2 and PM Pollution Controls
Comment: One commenter stated that North Dakota's BART analyses
that EPA proposes to approve fail to include the most stringent level
of control that is achievable using scrubber technology since scrubbers
can achieve 99% control efficiency. Commenters also stated that, with
regard to SO2, EPA should require both the lb/MMBtu limit
and the percent control efficiency limit to be met in order to meet
BART, rather than require that either limit be met as EPA proposed. One
commenter stated that if only the percent reduction limit is set,
emissions will increase with the sulfur content of the fuel unless
sulfur content is also limited. One commenter requested EPA set a
numeric limit rather than percent reductions.
Response: We agree that the RHR requires states to consider the
most stringent level of control. We also agree that, in most
applications, wet or dry scrubbers can achieve greater emission
reductions than those required by North Dakota. However, there is very
limited data on the performance of wet or dry scrubbers at units firing
lignite, such as those in North Dakota. In a 2007 BACT determination
for two new lignite-fired boilers at Oak Grove Station in Texas, the
Texas Commission on Environmental Quality established an SO2
emission limit of 0.192 lb/MMBtu on a 30-day rolling average. Based on
this, we find that the emission limits established by North Dakota are
not unreasonable. Also, we would like to emphasize that three of the
North Dakota units have existing controls for SO2 and that
the emission reductions that can be achieved with upgrades to these
existing controls may not be as great as those that can be achieved by
a new scrubber installation. Finally, on the point of allowing either a
lb/MMBtu or a percent control efficiency limit, we typically prefer a
single limit. However, the BART guidelines list the presumptive levels
in units of lb/MMBtu or a percent reduction, and we cannot say that the
State's approach is inconsistent with the guidelines. The State chose
to take advantage of this point and specifically found that it was not
appropriate to establish limits on a lb/MMBtu and percent reduction
basis. This was in part to allow for the potential that higher sulfur
coals might be burned in the future, in which case the State believed
that the percent reduction basis would extend greater flexibility.
Based on these factors and our consideration of all the circumstances
involved, we find that the SO2 emission limits established
by North Dakota are not unreasonable and we are approving them.
Comment: Commenters stated that North Dakota did not consider
upgrading ESPs to decrease PM emissions, as is required by the BART
Guidelines.
[[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 SO2.
Comment: Commenters stated that a PM continuous emission monitoring
system (CEMS) must be installed, operated and used to demonstrate
continuous compliance with the PM emission limits on units that are
subject to BART.
Response: PM CEMS would provide the most robust means of
demonstrating continuous compliance with the PM emission limits.
However, we disagree that their use is required. We find that the
monitoring requirements in the RH SIP are adequate to demonstrate
continuous compliance with the PM emission limits.
Comment: BART should be evaluated for both course particulate
matter (PM10) and PM 2.5, but was only evaluated
for PM10. EPA should therefore impose a BART limit on total
PM2.5.
Response: In our BART Guidelines, for the purposes of identifying
visibility impairing pollutants, we allowed states to use emissions of
PM10 as an indicator for PM2.5, as the components
of PM2.5 are a subset of PM10. 70 FR 39160. For
the same reasons, we find that it is reasonable for North Dakota to
have explicitly evaluated BART only for PM10. We also note
that North Dakota did evaluate BART for condensable PM which comprises
a large portion of the PM2.5.
Comment: Commenter stated that North Dakota incorrectly set a limit
for PM at .07 lbs/MMBtu. Commenter stated that the actual emissions
from most units averaged .03 lbs/MMBtu to .05 lbs/MMBtu, and there is
therefore no support for limits higher than .03 lbs/MMBtu.
Additionally, the commenter asserted that these limits should be set on
a unit-by-unit basis.
Response: As noted in prior responses to comments, the visibility
improvement that could be achieved with new or upgraded PM controls is
negligible. That response also holds true within the context of setting
tighter emission limits. Therefore, we find that PM emission limits set
by North Dakota are not unreasonable.
Comment: Commenter stated that EPA deviates from the BART
guidelines in failing to establish a clear time period (hourly, 24-
hour, 30-day or annual) over which the proposed PM limits would apply.
Commenter further stated that North Dakota's BART determinations are
unenforceable because there are no proposed monitoring, recordkeeping
and reporting requirements that would ensure compliance with the
filterable PM limits. Commenter stated that this was contrary to the
CAA, because BART is defined as based on continuous emission
reductions, which cannot be ensured.
Response: We disagree with the commenter. First, we seek to clarify
that while emission limits must be enforceable as a practical matter,
the BART Guidelines clearly state that CEMs are not required in every
instance. 70 FR 39172. Moreover, the BART Guidelines recognize that
monitoring requirements are in many instances governed by other
regulations, such as compliance assurance monitoring. North Dakota
established monitoring, recordkeeping and reporting requirements for PM
emission limits in permits to construct which are included in Appendix
D of the SIP. The monitoring requirements for PM include emission
testing using EPA-approved test methods, such as Method 5B and Method
17. As specified in each permit to construct, these tests must consist
of three test runs, with each test run at least 120 minutes in
duration. The monitoring requirements also require the use of a
Continuous Assurance Monitoring (CAM) Plan developed in accordance with
NDAC 33-15-14-06.10. The CAM Plan will include other provisions
necessary to show compliance. We find that these monitoring provisions
are adequate to ensure continuous emission reductions as required under
BART.
G. Comments on Reasonable Progress and North Dakota's Long-Term
Strategy
Comment: Minnkota states that EPA's proposed FIP does not follow
EPA guidelines for RP determinations. The commenter cites, without a
page number, the Burns & McDonnell report attached to the comments.
Response: EPA is unable to identify any support in the Burns &
McDonnell report for the statement. Standing alone, the comment is
insufficiently specific to warrant a response. Below, EPA responds to
comments that EPA's disapproval of the State's RP determination for AVS
is inconsistent with EPA guidelines.
Comment: Minnkota states that EPA's actions disapproving the
State's RPGs and imposing RP controls on MRYS lack a basis.
Response: EPA disagrees with this comment. First, as stated in the
proposal, the disapproval of the State's RPGs is based on the State's
failure to demonstrate that the RPGs the State selected are reasonable,
based on the four statutory factors. In particular, the State's use of
a degraded background in modeling for visibility benefits was
unreasonable, as was the State's failure to select RP controls for AVS.
Second, the commenter appears to misinterpret the statements made
regarding MRYS Units 1 and 2 as proposing to impose RP controls on
those units. In any case, the reference to controls on MRYS Units 1 and
2 is no longer relevant, because we have decided to approve North
Dakota's NOX BART determination for MRYS Units 1 and 2.
Comment: Minnkota states that EPA's action in disapproving the
State's LTS is unreasonable and simplistic.
Response: EPA disagrees with this comment. The LTS is a compilation
of the State-specific controls relied upon by the State for achieving
its RPGs. We are disapproving the State's RPGs along with certain
NOX BART and RP determinations and promulgating a FIP to
impose RPGs that are consistent with our FIP NOX BART and RP
determinations. To the extent that the State's LTS relies on these
NOX BART and RP determinations, we must also disapprove
those portions of the LTS. Specifically, our partial disapproval of the
State's LTS consists of two parts: (1) Disapproval of the LTS with
regard to permit limits and monitoring, recordkeeping, and reporting
[[Page 20931]]
requirements in the State's submittal that correspond to the
NOX BART determinations we are disapproving; and (2)
disapproval of the LTS with regard to the NOX reasonable
progress determination for AVS Units 1 and 2, and with regard to the
corresponding monitoring, recordkeeping, and reporting requirements.
The monitoring, recordkeeping, and reporting requirements for Antelope
Valley are necessary to ensure that the emissions limitations and
control measures to meet RPGs are enforceable. See 40 CFR
51.308(d)(3)(v)(F). In addition, these requirements are generally
necessary to ensure the BART limits are enforceable. See CAA 110(a)(2).
As these requirements are necessary adjuncts to the BART and RP limits,
our disapproval of the State's requirements necessarily flows from our
disapproval of the NOX BART determinations for CCS Units 1
and 2 and the disapproval of the State's NOX RP
determination for AVS Units 1 and 2.
Comment: NDDH states that EPA incorrectly rejected NDDH's RP
modeling methodology. NDDH believes that the methodology properly took
into account effects of international sources, as provided for in the
RHR. Furthermore, the hybrid methodology was, in NDDH's view, necessary
to accurately simulate transport from large point sources.
Response: Our response to this comment is provided with our
responses to modeling comments in section V.C.
Comment: NDDH states that its cumulative modeling methodology more
accurately reflects the visibility improvements from controls at point
sources.
Response: Our response to this comment is provided with our
responses to modeling comments in section V.C.
Comment: NDDH notes that EPA supported the development of the WRAP
cumulative modeling, which NDDH states involved considerable time and
resources. NDDH argues that it is inappropriate to diminish this
extensive effort by using what NDDH views as a less sophisticated and
inconsistent single-source approach.
Response: EPA disagrees with this comment. As discussed elsewhere,
single-source modeling is not ``less sophisticated'' or
``inconsistent.'' EPA supported development of WRAP CMAQ modeling in
order to assist states in developing their RPGs. This support does not
endorse the use of cumulative modeling to determine single-source
impacts, a faulty approach for the reasons discussed above. As
discussed below in responses to comments later in this section, NDDH's
comment conflates the requirements for RPGs with the requirements for
evaluating RP controls for single sources.
Comment: NDDH states that, on a dollar-per-ton-removed basis, LNB +
SNCR appears to be reasonable for AVS. However, NDDH argues that its
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 SO2 and
NOX in North Dakota were eliminated, North Dakota could not
achieve the URP. North Dakota states that additional controls for AVS
make almost no difference, and that additional controls on sources
outside of North Dakota are necessary to achieve the URP.
Response: As we stated in our proposal, we agree that North Dakota
could not achieve the URP in the first planning period even if all
North Dakota sources were eliminated. We do not agree that this means
that North Dakota can accordingly do nothing in the first planning
period to address reasonable progress beyond addressing the BART
requirements or that the State can reject otherwise reasonable control
measures. EPA assumes that NDDH bases its statement regarding ``almost
no difference'' on the modeling using current degraded background
conditions. The CALPUFF modeling for AVS (separately provided by NDDH)
predicts a visibility benefit at TRNP of 0.754 deciviews from
installation of LNB, which EPA does not regard as ``almost no
difference.'' Regardless of whether controls on sources outside of
North Dakota are necessary in order to achieve natural visibility
conditions by 2064, North Dakota is required to provide a reasoned
analysis of RP controls on sources within the State. With respect to
AVS, the State did not do so.
Comment: North Dakota states that, based on the definition of
``most impaired days'' and ``least impaired days'' in 51.301, and the
requirement in 51.308(d)(1) that the RPGs provide for improvement in
visibility for the most impaired days over the planning period and
ensure no degradation in visibility for the least impaired days over
the planning period, any RP visibility analysis must be a cumulative
analysis and must address the most impaired days. NDDH states that it
consistently modeled BART and RP sources. NDDH argues that, under the
RHR and EPA guidance, progress with respect to the URP must be assessed
using cumulative modeling based on the controls imposed on multiple
sources. It would be
[[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 SO2 and NOX
emissions. However, when it eliminated all reasonable progress controls
for these pollutants for these units, North Dakota relied almost
exclusively on its cumulative modeling, using current degraded
background to conclude that the cost on a dollar per deciview basis was
excessive.\65\
---------------------------------------------------------------------------
\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
NOX RP determination for AVS.
Comment: Basin Electric states that visibility improvement cannot
be ignored in the RP four-factor analysis.
Response: As we have noted, the four RP factors are the costs of
compliance, the time necessary for compliance, the energy and non-air
quality environmental impacts of compliance, and the remaining useful
life of any potentially affected sources. As we have also noted, when
visibility benefits are considered in the analysis of potential single-
source controls, such consideration must be reasonable. In this case,
NDDH unreasonably relied on modeling using current degraded background
to reject RP controls for AVS. Finally, in imposing LNB to meet
reasonable progress requirements, EPA has considered visibility
improvement, which, as shown by the CALPUFF modeling provided by NDDH,
is 0.754 deciviews at TRNP for installation of LNB at AVS.
Comment: Basin Electric states that EPA's disapproval of North
Dakota's RP determination for AVS is based solely on EPA's rejection of
the State's use of a degraded background in modeling.
[[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
NOX. We explained in our proposal why North Dakota's
alternative modeling for these BART units for NOX was
unreasonable. Despite the similarity of several of the reasonable
progress units to the BART units, North Dakota modeled visibility
improvement for potential control options on individual reasonable
progress sources using current degraded background. We have explained
in our other responses and in our proposal why this was unreasonable.
Comment: Basin Electric argues that states have the responsibility
to set RPGs and evaluate RP controls. Basin Electric states that
nothing prohibits the State from using degraded background conditions.
Response: For the reasons already expressed, we disagree with the
import of this comment. We agree that the states have the
responsibility to set RPGs and evaluate RP controls in the first
instance, but EPA must determine if a state's determinations for RPGs
and for controls satisfy the requirements of the RHR and are
reasonable. In the case of AVS 1 and 2, the State's determination was
unreasonable.
Comment: Basin Electric argues that, in considering the CALPUFF
modeling results for AVS, EPA should use the 90th percentile values,
not the 98th percentile values, and should use the three year average,
not the worst-case year.
Response: For the same reasons expressed in our responses to
similar comments related to BART in section V.C, we disagree.
Comment: Basin Electric argues that the case for using 90th
percentile values is stronger for RP, as RP is determined based on
improvement for the most impaired days, which is defined as the average
impairment for the 20% of days with the highest impairment. Basin
Electric states that use of the 98th percentile is inconsistent with
this provision.
Response: EPA disagrees with this comment, which conflates and
misstates requirements of the RHR. Reasonable progress is not
``determined'' based on improvement for the most impaired days;
instead, improvement for the most impaired days is one, and not the
only, requirement for reasonable progress. Separately, states are
required to evaluate, considering the four statutory RP factors,
controls for potentially affected sources. In this separate
determination, when a state considers visibility benefits as an
additional factor, a state's assessment and analysis of visibility
benefits must be reasonable. Use of the 90th percentile, which
seriously understates visibility benefits, is unreasonable, and cannot
be justified by reference to the separate requirement regarding the
most impaired days.
Comment: Basin Electric notes that EPA evaluated the cost of
controls for AVS Units 1 and 2 separately, but evaluated the visibility
benefits combined. Basin Electric argues that this is an invalid,
apples-to-oranges comparison.
Response: Given that AVS 1 and 2 are the same size and are co-
located, and reductions would be similar from each, we do not agree
that it is invalid to consider the combined visibility benefits. There
is no requirement, when considering visibility benefits as an
additional factor, to separately model co-located and similar units.
Furthermore, dollar-per-ton values would not change significantly if
costs were evaluated for the two units combined. Finally, EPA notes
that, even if the visibility benefits were evenly divided between the
two units, EPA would still consider LNB appropriate at each unit, based
on the four statutory factors and the additional factor of visibility
benefits.
Comment: Basin Electric references additional modeling, provided by
Basin Electric, that shows that the visibility benefits (using 90th
percentile, 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 NOX RP limit, based
on installation of LNB, for AVS Units 1 and 2 will result in combined
emissions reductions of over 7,000 tons per year of NOX,
with a visibility benefit of 0.754 deciviews at TRNP. Due to time and
resource constraints, we lacked the capability to re-do the WRAP
modeling to precisely re-calculate the RPGs.
Comment: Basin Electric states that the values for cost
effectiveness of LNB at AVS Units 1 and 2 do not reflect 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 NOX
emissions.
Comment: Citing 40 CFR 51.308(d), Basin Electric states that EPA
does not propose a true FIP for RPGs, because RPGs are defined by rule
as a rate of visibility improvement. Basin Electric alleges that
rerunning the WRAP CMAQ modeling with the controls imposed to quantify
the rate of improvement would cost a modest amount of money, and states
that this amount of money should be contrasted with the cost of
controls that will, according to Basin Electric, result in negligible
visibility improvements.
Response: As discussed elsewhere, the visibility improvements from
AVS alone will not be negligible, as shown by the CALPUFF modeling
provided by North Dakota, and even the CALPUFF modeling provided by
Basin Electric with its comments. We assume Basin Electric bases its
statement about negligible visibility improvements on the modeling
using current degraded background relied on by North Dakota, which, as
discussed elsewhere, we are disregarding. As discussed in the notice of
proposed action, we would have preferred to quantify the rate of
improvement, but time and resource constraints prevented this. Re-
running the WRAP CMAQ modeling would not change our conclusion about
the reasonableness of LNB at AVS 1 and 2.
Comment: Basin Electric states that, without modeling, there is no
basis for EPA to state that our FIP would increase the rate of
visibility improvement on the 20% worst days. Basin Electric asserts
that emissions reductions from the FIP sources are miniscule compared
with the total reductions assumed in the WRAP CMAQ modeling for RPGs.
Basin Electric notes that that modeling showed an overall 0.6 deciview
improvement at TRNP and a 0.5 deciview improvement at LWA.
Response: It is logical to infer that the considerable emissions
reductions at CCS and AVS will increase the visibility improvement on
the 20% worst days. We acknowledged in our proposal that this
improvement would not be sufficient to achieve the URP (76 FR 58632)
and agree that the improvement will likely be small given that the
starting point for the cited modeling is current degraded conditions.
But the same could be said for BART sources, yet North Dakota has
acknowledged that such sources contribute to visibility impairment in
the Class I areas in North Dakota.
Comment: Basin Electric states that the disapproval of North
Dakota's RPGs and our FIP have no meaningful effect.
Response: As we stated in our proposal, the RPGs are not
enforceable values. To that extent, they do not impose requirements on
anyone. However, we are required to disapprove the RPGs because they do
not reflect reasonable controls at CCS and AVS, and we are required to
impose a FIP in lieu of the State's unapprovable RPGs. Our reasonable
progress controls at AVS and our BART controls at CCS do impose
enforceable requirements.
Comment: Basin Electric asserts that, because EPA has no basis for
our disapprovals and FIPs at individual facilities, EPA also has no
basis for our FIP for RPGs.
Response: See our responses to prior comments. We have explained
the bases for our disapprovals.
Comment: NPCA comments that it is unreasonable for EPA to give
Basin Electric until July 31, 2018 to install LNB at Antelope Valley
because that date is not ``as expeditious as possible.'' NPCA states
that the deadline should be January 26, 2013, which NPCA believes
represents a reasonable amount of time to install the combustion
controls.
Response: EPA disagrees with this comment. First, unlike for BART
sources, the RHR and the CAA do not explicitly require that limits for
RP sources be met as expeditiously as practicable. Furthermore, the
commenter misstates the deadline: The proposed FIP requires Basin
Electric to meet the proposed NOX emissions limit at
Antelope Valley ``as expeditiously as practicable, but in any event no
later than July 31, 2018.'' Thus, Basin Electric is under an obligation
to install the combustion controls as expeditiously as practicable. The
cutoff date of July 31, 2018 ensures that the RP limit for Antelope
Valley is met by the end of the planning period, thereby also ensuring
that the proposed RPGs are met.
Comment: NPCA states that EPA should reevaluate the cost estimate
for
[[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 SO2.
The cost overestimates made by other facilities indicate that EPA
should revisit this cost analysis.
Response: EPA disagrees with this comment. First, NPCA did not
identify any cost overestimates related to wet scrubbers. The issues
EPA identified in its proposal related to costs of SCR, which provides
no basis for inferring cost overestimates for wet scrubbers. As far as
the record, Table 9.8 in North Dakota's RH SIP submittal shows a cost
effectiveness value of $2,593 per ton of SO2 removed at a
control efficiency of 95%. As stated in our proposal, while this value
is within the range of cost effectiveness values that North Dakota,
other states, and we have considered reasonable in the BART context, it
is not so low that we are prepared to disapprove the State's conclusion
in the reasonable progress context. In addition, Coyote Station
currently employs a spray dryer to control SO2 emissions at
a control efficiency of approximately 66%. The existence of this
control supports our approval of the State's determination. Analogous
to our policy in the BART context, we do not expect sources to install
entirely new SO2 controls where they are already achieving
reductions greater than 50%.
Comment: NPCA notes EPA's response to a petition from the Dakota
Resource Council regarding violations of PSD Class I SO2
increments, in which EPA stated that a SIP call would not achieve any
better result than other pending actions, including regional haze
actions. NPCA argues that, based on this response, EPA should require
SO2 controls at Coyote Station to reduce consumed Class I
SO2 increment.
Response: EPA disagrees with this comment. As discussed extensively
in our response to a prior comment, PSD permit program requirements in
Subpart I, Part C of title I of the CAA are separate from visibility
protection requirements in Subpart II of Part C. Therefore, Class I
SO2 increments are not relevant to our action on North
Dakota's RH SIP submittal to meet the requirements of CAA section 169A
and the RHR. Nonetheless, EPA notes that SO2 emissions will
be substantially reduced by our action on the North Dakota RH SIP, as
detailed in Table 21 of our notice proposing action.
Comment: NPCA argues that limestone injection at Heskett Station is
a cost effective and reasonable RP control that would achieve
SO2 reductions of 1614 tons per year. However, NPCA notes
that the agreement between North Dakota and the facility only requires
reductions of 573 tons per year of SO2. NPCA concludes that
EPA should require Heskett to achieve an SO2 limit that
reflects the capabilities of limestone injection.
Response: EPA considers the State's determination to impose the
stated reductions in the permit included in SIP Supplement No. 1 to be
reasonable and to satisfy reasonable progress requirements in this
initial planning period. Further reductions may be appropriate in a
subsequent planning period.
Comment: NPCA argues that staged combustion is a cost effective
control for NOX at Heskett Station at $1,700/ton. Even
though the emission reduction is only 215 tons per year, NPCA argues
that EPA must consider all potential sources that can contribute to
achieving RPGs, including NOX reductions from Heskett
Station.
Response: EPA disagrees with this comment. In the first instance,
it is the responsibility of the State to consider the four statutory
factors for potentially affected sources. EPA's task is to determine if
the State's analysis of controls satisfies the requirements of the RHR
and is reasonable. In this case, the State did consider the four
statutory factors, as well as an additional factor--visibility
improvement based on modeling using current degraded background. While
EPA does not consider the State's use of modeling based on current
degraded background reasonable, EPA nonetheless considers the result of
the State's analysis in this instance to be reasonable, based on the
relatively low emissions reductions and the costs of controls.
Comment: NPCA states that several NOX control options
for Tioga Gas Plant are cost effective, with the lowest at $521/ton.
Although the emissions reductions are lower, NPCA argues that EPA
should consider all potential sources that can contribute to achieving
RPGs. In addition, NPCA notes that the facility is only 35 km from LWA
and is also near TRNP.
Response: EPA disagrees with this comment for the same reasons
discussed in response to the prior comment.
[[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 NOX among all EGUs, using
2010 rates in the Clean Air Markets Division database. NPS argues that,
as a result, SCR should have been given more consideration.
Response: First, EPA disagrees with some of the NPS computations.
Based on 2010 Clean Air Markets Division data, Coyote Station was the
124th largest emitter of NOX among EGUs at 13,691 tons. At
the rate of 0.50 lb/MMBtu agreed to by the State, the emissions (with
the same heat input) would have been 8,800 tons, which would have made
Coyote Station the 183rd largest emitter of NOX for that
year. This represents a reduction of over 4,800 tons per year. In any
case, the relative rank of a facility among other facilities nationwide
in overall emissions is not a necessary component of the RP analysis.
We have already explained why we are not disapproving the State's
rejection of SCR at Coyote.
Comment: The NPS noted that the RP analysis for Coyote Station did
not consider upgrades to the existing dry scrubber.
Response: In making an RP determination, the State must consider a
reasonable range of controls. For SO2, the State considered
a new wet scrubber. While EPA agrees that upgrades to the existing dry
scrubber should have been considered, starting with feasibility, EPA is
not prepared to determine, on the basis of this consideration, that the
State was unreasonable in addressing RP requirements for Coyote Station
through imposing the 0.50 lb/MMBtu NOX limit and not
imposing an SO2 limit. EPA does expect the State to revisit
the range of controls in the next planning period.
Comment: NPS provided cost estimates for installation of SCR at
Coyote Station, showing a cost effectiveness value of $1,600 per ton
removed and an incremental cost effectiveness value of $2,300 per ton
removed. NPS stated that these costs are lower than those for SCR at
LOS 2 and MRYS 1 and 2. NPS argued that, for consistency, EPA must
impose SCR at Coyote Station.
Response: The basis for our decision regarding the State's
rejection of SCR at Coyote is explained in prior responses.
H. Comments on Health and Ecosystem Benefits, and Other Pollutants
Comment: Several commenters stated that haze pollution
significantly impacts human health and ecosystem health, in addition to
obscuring scenic vistas. Specifically, commenters asserted that haze
pollution contributes to heart attacks, asthma attacks, chronic
bronchitis and respiratory illness, increased hospital admissions, lost
work days, and even premature death. One commenter noted the specific
haze pollutants NOX, SO2 and PM, which the
commenter stated are all harmful to the human body.
Some commenters cited a 2009 Clean Air Task Force report in stating
that coal-fired power plants in North Dakota put 207 people at risk of
premature death, 321 people at risk of a heart attack, and 3,500 at
risk of an asthma attack each year. Several commenters encouraged EPA
to finalize the regional haze proposal citing their own health
problems, most notably individuals with asthma or respiratory problems,
seniors, and parents of asthmatic children. One commenter stated the
rate of asthma in North Dakota children is increasing rapidly.
Some commenters stated that haze pollution negatively impacts
ecosystem health. Commenters expressed concern for the effects of haze
pollution on wildlife, farm animals, plants including crops, and water
bodies. Several commenters generally expressed their disapproval of
coal as an energy source because it is dirty, with some insisting that
North Dakota invest in cleaner energy.
Response: We appreciate the commenters' concerns regarding the
negative health impacts of emissions from the coal-fired power plants
in North Dakota. We agree that the same PM2.5 emissions that
cause visibility impairment can be inhaled deep into lungs, which can
cause respiratory problems, decreased lung function, aggravated asthma,
bronchitis, and premature death. We also agree that the same
NOX emissions that cause visibility impairment also
contribute to the formation of ground-level ozone, which has been
linked with respiratory problems, aggravated asthma, and even permanent
lung damage. We agree that these pollutants can have negative impacts
on plants and ecosystems, damaging plants, trees and other vegetation,
and reducing forest growth and crop yields, which could have a negative
effect on species diversity in ecosystems. However, for purposes of
this action, we are not authorized to consider these impacts in
evaluating the State's RH SIP and promulgating our FIP, and we have not
done so.
Comment: Some commenters stated that regional haze is not a health-
based standard.
Response: We agree that regional haze is not a health-based
standard.
I. Miscellaneous Comments
Comment: Several commenters stated that the large economic costs of
installing pollution controls stated by electricity providers failed to
consider
[[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 https://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 NOX BART
determinations for MRYS 1 and 2 and LOS 2 on grounds explained
elsewhere. To the degree that some of these comments extend to our FIP
for CCS and AVS, EPA's evaluation of capital and annual expenses
associated with implementation of the FIP shows such expenses to be
justified by the degree of improvement in visibility in relationship to
the cost of implementation.
We take our duty to estimate the cost of controls very seriously,
and make every attempt to make a thoughtful and well informed
determination. However, we do not consider a potential increase in
electricity rates to be the most appropriate type of analysis for
considering the costs of compliance in a BART determination.
Nevertheless, our analysis indicates that the annual costs to CCS and
AVS associated with our FIP will be relatively modest considering the
size of the plants, and impacts to rate payers should be much lower
than anticipated by commenters.
Comment: Commenter cited EPA's Clean Air Markets database, which
states that North Dakota ranked 12 in SO2 emissions
and 19 in NOX emissions. The commenter also
provided the SO2 and NOX rankings for the seven
North Dakota EGUs discussed in the SIP.
Response: We appreciate the commenter providing the SO2
and NOX rankings for North Dakota and its EGUs. We do not
disagree with the information provided and acknowledge the data suggest
the North Dakota plants rank relatively high in the amount of
SO2 and NOX emissions compared to other states.
However, we note that BART and RP determinations involve case-by-case
determinations considering the relevant statutory factors, which do not
include the relative emissions rankings.
Comment: Commenter requests that EPA set limits on ammonia slip
where SNCR or SCR is required for BART.
Response: In Section 7.1.2 of the SIP, North Dakota concluded that
ammonia is not a visibility impairing pollutant of concern as ammonia
emissions (and associated regional haze impacts) from BART-eligible
sources are negligible. We concur with this conclusion.
[[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 NOX
emission limits because NOX CEMS will be used.
J. Comments Requesting an Extension to the Public Comment Period
Comment: One commenter requested that the comment period be
extended to December 21, 2011 and Governor Dalrymple and Senator Hoeven
requested the time allotted for the public hearings be increased.
Response: The comment period for our proposal closed on November
21, 2011. We carefully considered the request for an extension to the
comment period. We took into consideration how an extension might
affect our ability to consider comments received on the proposed action
and still comply with our consent decree deadlines. We do note that our
October 13 and 14, 2011, public hearing in Bismarck, North Dakota was
well attended and provided an opportunity for people to comment on our
proposal. Also regarding the public hearings, we agreed to Governor
Dalrymple's and Senator Hoeven's requests to extend the length of the
public hearing and to allow as much time as needed for state
representatives to present their comments.
K. Comments Generally in Favor of Our Proposal
Comment: Overall, we received more than 24,000 comment letters in
support of our rulemaking from members representing various
organizations, concerned citizens, and tribal members. These comments
were received at the Public Hearing in Bismarck, North Dakota, by
internet, and through the mail. Each of these commenters was generally
in favor of portions of our proposed decision for North Dakota regional
haze. These comments included comments urging us to require the most
effective pollution control technology, SCR, at LOS 2, and MRYS 1 and 2
and additional emission reductions from CCS 1 and 2 and AVS 1 and 2.
Some of these comments also discussed the detrimental health effects of
haze pollution and the economic impacts of these health effects. Some
of these comments urged us to keep or lower our proposed numeric limits
on NOX for MRYS and LOS 2 in our final decision. These
letters also asked us to require other units at LOS, Heskett Station,
and Stanton Station to modernize and reduce their air pollution
impacts.
Response: We acknowledge the support of these commenters for our
proposed action. We note that several of the control technology
determinations and emissions limits supported by these commenters in
the proposal have been changed in this final action based on the
Minnkota BACT court decision and all of the information received during
the comment period. Please see the docket associated with this action
for additional detail. To the extent the comments asserted the need for
more stringent controls, we address those comments in other responses.
L. Comments Generally Against Our Proposal
Comment: Various commenters generally stated they did not support
the proposed rulemaking. Their reasons included: it will affect the
town's economy, affect the coal power plant industry, electricity costs
will increase, they have no direct health problems from actual
emissions, direct and indirect jobs/businesses would be affected, North
Dakota already meets air quality standards, that there will be no
benefit to the community, that our decision relies on unproven
technology, and that it will not result in noticeable visibility
improvements.
We received three resolutions from cities in Minnesota, including
Roseau, Big Falls, and Little Fork, which opposed our rulemaking. These
resolutions included comments about the proposed FIP for SCR technology
at MRYS, including comments about the high cost, that the technology
had not been shown to work at similar plants, and that there would be
no humanly perceptible visibility improvements over the State's plan.
The resolutions also noted that Minnkota had already incurred
significant costs for installing SNCR and contracting for renewable
sources, and that these expenditures were resulting in rate increases.
We received petitions and mass mailer letters from nine rural power
cooperative associations and over 3,000 comments generated through a
Web site established by an organization named Partners for Affordable
Energy. Comments from these letters and emails included the following:
that Congress left the primary responsibility for SIPs with states,
that states have superior knowledge of local conditions and needs, and
that EPA's plan would provide imperceptible visibility benefits at huge
costs. The comments also urged EPA to allow North Dakota to make its
own decisions regarding its clean air programs.
Response: We acknowledge these general comments that opposed our
proposed action. We provide responses that address these issues
elsewhere in this action. We have made changes from our proposal, as
noted elsewhere in this action.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011). As discussed in detail in section C
below, the FIP applies to only two facilities. It is therefore not a
rule of general applicability.
B. Paperwork Reduction Act
This action does not impose an information collection burden under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Under the Paperwork Reduction Act, a ``collection of information'' is
defined as a requirement for ``answers to * * * identical reporting or
recordkeeping requirements imposed on ten or more persons * * *.'' 44
U.S.C. 3502(3)(A). Because the FIP applies to just two facilities, the
Paperwork Reduction Act does not apply. See 5 CFR 1320(c).
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid Office of Management and Budget (OMB) control number.
The OMB control numbers for our regulations in 40 CFR are listed in 40
CFR Part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare
[[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
NOX emissions at one source in North Dakota, and imposing
controls to meet the reasonable progress requirement for NOX
emissions at one additional source in North Dakota. The net result of
these two simultaneous FIP actions is that EPA is proposing direct
emission controls on selected units at only two sources. The sources in
question are each large electric generating plants that are not owned
by small entities, and therefore are not small entities. The partial
approval of the SIP merely approves state law as meeting Federal
requirements and imposes no additional requirements beyond those
imposed by state law. See Mid-Tex Electric Cooperative, Inc. v. FERC,
773 F.2d 327 (D.C. Cir. 1985).
D. Unfunded Mandates Reform Act (UMRA)
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and Tribal
governments and the private sector. Under section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and Tribal governments, in
the aggregate, or to the private sector, of $100 million or more
(adjusted for inflation) in any 1 year. Before promulgating an EPA rule
for which a written statement is needed, section 205 of UMRA generally
requires EPA to identify and consider a reasonable number of regulatory
alternatives and to adopt the least costly, most 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 NOX, the rule will have a beneficial
effect on children's health by reducing air pollution.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not subject to Executive Order 13211 (66 FR 28355
(May 22, 2001)), because it is not a significant regulatory action
under Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12 of the National Technology Transfer and Advancement Act
(NTTAA) of 1995 requires Federal agencies to evaluate existing
technical standards when developing a new regulation. To comply with
NTTAA, EPA must consider and use ``voluntary consensus standards''
(VCS) if available and applicable when developing programs and policies
unless doing so would be inconsistent with applicable law or otherwise
impractical.
The EPA believes that VCS are inapplicable to this action. Today's
action does not require the public to perform activities conducive to
the use of VCS.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994), establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
We have determined that this rule will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it increases the level of environmental
protection for all affected populations without having any
disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. This rule limits emissions of NOX from two
facilities in North Dakota. The partial approval of the SIP merely
approves state law as meeting Federal requirements and imposes no
additional requirements beyond those imposed by state law.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on May 7, 2012.
L. Judicial Review
Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by June 5, 2012. Pursuant to CAA section
307(d)(1)(B), this action is subject to the requirements of CAA section
307(d) as it promulgates a FIP under CAA section 110(c). Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. See CAA section 307(b)(2).
Approval and Promulgation of Implementation Plans; North Dakota;
Regional Haze State Implementation Plan; Federal Implementation Plan
for Interstate Transport of Pollution Affecting Visibility and Regional
Haze. Final Rule. (EPA-R08-OAR-2010-0406)
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Intergovernmental
relations, Incorporation by reference, Nitrogen dioxides, Particulate
matter, Reporting and recordkeeping requirements, Sulfur dioxide,
Volatile organic compounds.
Dated: March 1, 2012.
Lisa P. Jackson,
Administrator.
40 CFR part 52 is amended as follows:
PART 52--[AMENDED]
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 NOX emissions, other pollutant
emissions, diluent, or stack gas volumetric flow rate.
(3) NOX means nitrogen oxides.
(4) Owner/operator means any person who owns or who operates,
controls, or supervises an EGU identified in paragraph (a) of this
section.
(5) Unit means any of the EGUs identified in paragraph (a) of this
section.
(c) Emissions limitations. (1) The owners/operators subject to this
section shall not emit or cause to be emitted NOX in excess
of the following limitations, in pounds per million British thermal
units (lb/MMBtu), averaged over a rolling 30-day period:
------------------------------------------------------------------------
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 NOX, 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
NOX concentration in lb/MMBtu at the CEMS in accordance with
the requirements of 40 CFR part 75. At the end of each boiler operating
day, the owner/operator shall calculate and record a new 30-day rolling
average emission rate in lb/MMBtu from the arithmetic average of all
valid hourly emission rates from the CEMS for the current boiler
operating day and the previous 29 successive boiler operating days.
(ii) An hourly average NOX emission rate in lb/MMBtu is
valid only if the minimum number of data points, as specified in 40 CFR
part 75, is acquired by both the NOX pollutant concentration
monitor and the diluent monitor (O2 or CO2).
(iii) Data reported to meet the requirements of this section shall
not include data substituted using the missing data substitution
procedures of subpart D of 40 CFR part 75, nor shall the data have been
bias adjusted according to the procedures of 40 CFR part 75.
(f) Recordkeeping. Owner/operator shall maintain the following
records for at least five years:
(1) All CEMS data, including the date, place, and time of sampling
or measurement; parameters sampled or measured; and results.
(2) Records of quality assurance and quality control activities for
emissions measuring systems including, but not limited to, any records
required by 40 CFR part 75.
(3) Records of all major maintenance activities conducted on
emission units, air pollution control equipment, and CEMS.
(4) Any other records required by 40 CFR part 75.
(g) Reporting. All reports under this section shall be submitted to
the Director, Office of Enforcement, Compliance and Environmental
Justice, U.S. Environmental Protection Agency, Region 8, Mail Code
8ENF-AT, 1595 Wynkoop Street, Denver, Colorado 80202-1129.
(1) Owner/operator shall submit quarterly excess emissions reports
no later than the 30th day following the end of each calendar quarter.
Excess emissions means emissions that exceed the emissions limits
specified in paragraph (c) of this section. The reports shall include
the magnitude, date(s), and duration of each period of excess
emissions, specific identification of each period of excess emissions
that occurs during startups, shutdowns, and malfunctions of the unit,
the nature and cause of any malfunction (if known), and the corrective
action taken or preventative measures adopted.
(2) Owner/operator shall submit quarterly CEMS performance reports,
to include dates and duration of each period during which the CEMS was
inoperative (except for zero and span adjustments and calibration
checks), reason(s) why the CEMS was inoperative and steps taken to
prevent recurrence, any CEMS repairs or adjustments, and results of any
CEMS performance tests required by 40 CFR part 75 (Relative Accuracy
Test Audits, Relative Accuracy Audits, and Cylinder Gas Audits).
(3) When no excess emissions have occurred or the CEMS has not been
inoperative, repaired, or adjusted during the reporting period, such
information shall be stated in the report.
(h) Notifications. (1) Owner/operator shall submit notification of
commencement of construction of any equipment which is being
constructed to comply with the NOX emission limits in
paragraph (c) of this section.
(2) Owner/operator shall submit 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