Approval and Promulgation of Implementation Plans; State of Kansas: Regional Haze, 80754-80760 [2011-32998]
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80754
Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations
0260. See paragraph (c)(139)(i)(A) of this
section.
■ 3. Section 52.1987 is revised to read
as follows:
■
§ 52.1987
quality.
(a) EPA approves the portion of
Oregon’s SIP revision submitted June
23, 2010, and December 22, 2010
(referenced in § 52.1989(a)) addressing
the requirement in Clean Air Act section
110(a)(2)(D)(i)(II) that a state not
interfere with any other state’s required
measures to prevent significant
deterioration (PSD) of its air quality (the
third PSD element).
(b) [Reserved]
Significant deterioration of air
(a) The Oregon Department of
Environmental Quality rules for the
prevention of significant deterioration of
air quality (provisions of OAR Chapter
340, Divisions 200, 202, 209, 212, 216,
222, 224, 225 (except 225–0090(2)(a)(C)
on interpollutant offset ratios), and 268,
as in effect on May 1, 2011, are
approved as meeting the requirements
of title I, part C, subpart 1 of the Clean
Air Act, as in effect on July 1, 2011, for
preventing significant deterioration of
air quality.
(b) The Lane Regional Air Pollution
Authority rules for permitting new and
modified major stationary sources (Title
38 New Source Review) are approved,
in conjunction with the Oregon
Department of Environmental Quality
rules, in order for the Lane Regional Air
Pollution Authority to issue prevention
of significant deterioration permits
within Lane County.
(c) The requirements of sections 160
through 165 of the Clean Air Act are not
met for Indian reservations since the
plan does not include approvable
procedures for preventing the
significant deterioration of air quality on
Indian reservations and, therefore, the
provisions in § 52.21 except paragraph
(a)(1) are hereby incorporated and made
part of the applicable plan for Indian
reservations in the State of Oregon.
■ 4. In § 52.1989, paragraph (a) is
revised to read as follows:
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§ 52.1989 Interstate Transport for the 1997
8-hour ozone NAAQS and 1997 24-hour
PM2.5 NAAQS.
(a) On June 23, 2010 and December
22, 2010, the Oregon Department of
Environmental Quality submitted a SIP
revision, adopted by the Oregon
Environmental Quality Commission on
April 30, 2010, to meet the requirements
of Clean Air Act section 110(a)(2)(D)(i).
EPA approves the portion of this
submittal relating to significant
contribution to nonattainment of the
NAAQS in any other state and
interference with maintenance of the
NAAQS by any other state. EPA also
approves the portion of the submittal
addressing the requirement in Clean Air
Act section 110(a)(2)(D)(i)(II) that a state
not interfere with any other state’s
required measures to prevent significant
deterioration (PSD) of its air quality (the
third PSD element).
*
*
*
*
*
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5. Section 52.1990 is added to read as
follows:
§ 52.1990 Interstate Transport for the 2006
24-hour PM2.5 NAAQS.
[FR Doc. 2011–33012 Filed 12–23–11; 8:45 am]
BILLING CODE 6560–50–P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[EPA–R07–OAR–2011–0675; FRL–9611–3]
Approval and Promulgation of
Implementation Plans; State of
Kansas: Regional Haze
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
EPA is taking final action to
approve a revision to the State
Implementation Plan (SIP) for Kansas,
submitted by the Kansas Department of
Health and Environment on October 26,
2009, that addresses Regional Haze for
the first implementation period. EPA
has determined that the plan submitted
by Kansas satisfies the requirements of
the Clean Air Act (CAA or Act), for
states to prevent any future and remedy
and existing anthropogenic impairment
of visibility in Class I areas caused by
emissions of air pollutants located over
a wide geographic area (also known as
the ‘‘regional haze’’ program). EPA
proposed to approve these revisions on
August 23, 2011 (76 FR 52604).
DATES: Effective Date: This rule will be
effective January 26, 2012.
ADDRESSES: EPA has established a
docket for this action under Docket
Identification No. EPA–R07–OAR–
2011–0675. All documents in the docket
are listed on the https://
www.regulations.gov Web site. Although
listed in the index, some information is
not publicly available, i.e., 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
SUMMARY:
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materials are available either
electronically through https://
www.regulations.gov or in hard copy at
the Air Planning and Development
Branch, Air and Waste Management
Division, U.S. Environmental Protection
Agency, Region 7, 901 North 5th Street,
Kansas City, KS 66101. EPA requests
that if at all possible, you contact the
person listed in the FOR FURTHER
INFORMATION CONTACT section for further
information. The regional office’s
official hours of business are Monday
through Friday, 8:30 to 4:30, excluding
Federal holidays.
FOR FURTHER INFORMATION CONTACT:
Chrissy Wolfersberger, Air Planning and
Development Branch, U.S.
Environmental Protection Agency,
Region 7, 901 N. 5th Street, Kansas City,
Kansas 66101; by telephone at (913)
551–7864; or by email at
wolfersberger.chris@epa.gov.
SUPPLEMENTARY INFORMATION:
Throughout this document, the terms
‘‘we,’’ ‘‘us,’’ and ‘‘our’’ refer to EPA.
Table of Contents
I. Background
II. Public comments and EPA responses
III. Final action
IV. Statutory and Executive Order reviews
I. Background
On August 23, 2011 (76 FR 52604),
EPA published a notice of proposed
rulemaking (NPR) for the State of
Kansas, proposing approval of Kansas’
regional haze plan for the first
implementation period (through 2018).
A detailed explanation of the CAA’s
visibility requirements and the regional
haze rule as it applies to Kansas was
provided in the NPR and will not be
restated here. EPA’s rationale for
proposing approval of the Kansas SIP
revision was described in detail in the
proposal, and is further described in
this final rulemaking.
II. Public comments and EPA responses
The publication of EPA’s proposed
rule on August 23, 2011 initiated a 30
day public comment period that ended
on September 22, 2011. During the
public comment period we received
written comments from the State of
Colorado, the Kansas Department of
Health and Environment on behalf of
the State of Kansas (State), Kansas City
Power & Light, Westar Energy, and the
National Parks Conservation
Association (NPCA). We have
summarized the comments and
provided our responses below. Full
copies of the comment letters are
available in the docket for this
rulemaking.
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Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations
Comment #1: The State of Colorado
submitted comments supportive of
EPA’s proposed approval and
applauding the State of Kansas’ efforts
to evaluate and promulgate cost
effective emission controls that will
improve visibility in a number of Class
I areas, including Rocky Mountain
National Park and Great Sand Dunes
National Park & Preserve.
Response #1: We appreciate the State
of Colorado’s comments on our
proposed action.
Comment #2: The State and Westar
Energy noted some transcription errors
in table 7 of the proposed notice, titled
‘‘Control or work practice strategies for
Westar units to meet Kansas long term
strategy requirements.’’ Some limits for
sulfur dioxide (SO2) were recorded as
limits for nitrogen oxides (NOX), and
vice versa. The specific errors were:
• Lawrence Unit 3: the limit of 0.18
lbs/mmBtu is for NOX, not SO2
• Lawrence Unit 4: the limit of 0.18
lbs/mmBtu is for NOX, not SO2; and the
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limit of 0.15 lbs/mmBtu is for SO2, not
NOX
• Tecumseh Unit 7/9: the limit of
0.18 lbs/mmBtu is for NOX, not SO2
• Tecumseh Unit 8/10: limit of 0.18
lbs/mmBtu for NOX, not SO2.
Response #2: EPA agrees that there
were transcription errors in table 7.
Table 7 is corrected to read as follows:
Facility/unit
Emission rate or work practice
Gordon Evans Energy Center—Unit 1 ........................
a fuel switch to natural gas at all times, with the exception of a gas curtailment order
from the gas supplier, in which case the facility will be allowed to utilize backup #6 fuel
oil.
a fuel switch to natural gas at all times, with the exception of a gas curtailment order
from the gas supplier, in which case the facility will be allowed to utilize backup #6 fuel
oil.
a fuel switch to natural gas at all times, with the exception of a gas curtailment order
from the gas supplier, in which case the facility will be allowed to utilize backup #6 fuel
oil.
a fuel switch to natural gas at all times, with the exception of a gas curtailment order
from the gas supplier, in which case the facility will be allowed to utilize backup #6 fuel
oil.
an emission limit of 0.15 lbs/MMBtu for both SO2 and NOX.
an emission limit of 0.18 lbs/MMBtu for NOX.
an emission limit of 0.18 lbs/MMBtu for NOX; an emission limit of 0.15 lbs/MMBtu for
SO2.
an emission limit of 0.15 lbs/MMBtu for both SO2 and NOX.
an emission limit of 0.18 lbs/MMBtu for NOX.
an emission limit of 0.18 lbs/MMBtu for NOX.
Hutchinson—Unit 4 ......................................................
Murray Gill—Units 1, 2, 3 and 4 ..................................
Neosho—Unit 7 ...........................................................
Jeffrey Energy Center—Unit 3 ....................................
Lawrence—Unit 3 ........................................................
Lawrence—Unit 4 ........................................................
Lawrence—Unit 5 ........................................................
Tecumseh—Units 7/9 ..................................................
Tecumseh—Units 8/10 ................................................
Comment #3: Westar Energy noted
errors in table 8 of the proposed
approval, titled, ‘‘Estimated NOX and
SO2 emission reductions for
implementation of controls or work
practices required by Kansas’ long term
Facility
strategy’’. Errors in table 8 included
listing the 2002 SO2 emissions for
Lawrence Unit 5 as 4,546.3 tons (the
correct value is 4,353.7 tons), and listing
the post-control NOX emissions for
2002 NOX
Emissions
(tpy)
Unit
2002 SO2
Emissions
(tpy)
Lawrence Unit 4 at 835.4 tons (the
correct value is 1002.4 tons).
Response #3: EPA agrees that there
were errors in table 8. Table 8 is
corrected as follows:
Post control
NOX
(tpy)
Post control
SO2
(tpy)
NOX
Reductions
(tpy)
SO2
Reductions
(tpy)
1
4
3
3
4
5
1
2
3
4
7
7
8
258.7
267.1
10,807.4
728.4
1,986.5
3,546.3
0.0
4.5
181.6
103.8
0.0
1,530.6
1,876.9
617.7
734.3
23,206.0
1,965.4
1,430.0
4,353.7
0.0
0.0
452.1
333.3
0.0
2,692.7
4,514.9
211.9
158.5
4,913.1
0.0
1,002.4
2,564.7
0.0
4.0
148.6
85.2
0.0
691.6
1,103.1
0.5
0.6
4,913.1
1,965.4
835.4
2,564.7
0.0
0.0
0.3
0.2
0.0
2,692.7
4,514.9
46.8
108.5
5,894.3
728.4
984.1
981.6
0.0
0.5
33.0
18.7
0.0
839.0
773.8
617.2
733.7
18,292.9
0.0
594.7
1,789.0
0.0
0.0
451.8
333.1
0.0
0.0
0.0
Total ..........................................................
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Gordon Evans ..................................................
Hutchinson .......................................................
Jeffrey ..............................................................
Lawrence ..........................................................
Lawrence ..........................................................
Lawrence ..........................................................
Gill ....................................................................
Gill ....................................................................
Gill ....................................................................
Gill ....................................................................
Neosho .............................................................
Tecumseh ........................................................
Tecumseh ........................................................
............
....................
....................
....................
....................
10,408.7
22,812.5
Comment #4: As noted in the
proposal, the State entered into Consent
Agreements with Kansas City Power and
Light and Westar Energy to incorporate
the Best Available Retrofit Technology
(BART) emission rates, compliance
schedules, monitoring, recordkeeping,
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reporting, and enforceability
requirements. EPA proposed to
disapprove specific startup, shutdown
and malfunction (SSM) provisions in
the State’s regional haze Consent
Agreements with Westar Energy and
Kansas City Power and Light that were
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submitted as part of the regional haze
SIP. The State commented that EPA’s
proposed exclusion of periods of SSM
from the Consent Agreements has the
effect of making the BART emission
limits more stringent. The State
requested that EPA consider fully
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Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations
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approving the SIP revision. Kansas City
Power and Light commented that the
proposed approval of the Kansas
Regional Haze SIP excluding the SSM
provisions fundamentally changes the
basis of the emission limits, and because
the SSM provisions were agreed to
through good faith negotiations with the
State, Kansas City Power and Light
asked that the Agreements be
renegotiated. Westar Energy made
similar comments, disagreeing with the
proposed disapproval of the SSM
provisions in the Consent Agreement
between the State and Westar Energy.
Response #4: As EPA explained in the
proposed notice, the Consent
Agreements exempted periods of startup
and shutdown for both Kansas City
Power and Light and Westar Energy
from compliance with applicable
emission limits, which were not
narrowly defined, and exempted
periods of malfunction for Westar
Energy. EPA proposed to disapprove the
exemptions because they are
inconsistent with the Clean Air Act and
EPA’s September 20, 1999, guidance,
‘‘State Implementation Plans: Policy
Regarding Excess Emissions during
Malfunctions, Startup and Shutdown.’’ 1
EPA subsequently received a letter
from the State dated December 1, 2011,
withdrawing the SSM provisions in the
Consent Agreements in their entirety
from the regional haze SIP. Specifically,
the following four provisions were
withdrawn from EPA’s consideration for
approval in the regional haze SIP:
1. All references to, ‘‘excluding
periods of startup and shutdown’’ in
Paragraph 23 of the Kansas City Power
and Light Company regional haze
agreement;
2. The reference to, ‘‘excluding
periods of startup, shutdown and
malfunction’’ in footnote 1 of Appendix
A to the Westar Energy, Inc. regional
haze agreement;
3. All references to, ‘‘excluding
periods of startup and shutdown’’ in
Chapter 9.3.1 of the Kansas regional
haze SIP;
4. And the sentence, ‘‘The
Agreements between KDHE and the
affected BART sources currently
exclude emissions associated with
startup, shutdowns, and malfunctions
(SSM) in the agreed upon emission
limits’’ in Chapter 9.5 of the Kansas
regional haze SIP.
1 Steven Herman, Assistant Administrator for
Enforcement and Compliance Assurance, and
Robert Perciasepe, Assistant Administrator for Air
and Radiation, ‘‘State Implementation Plans (SIPs):
Policy Regarding Excess Emissions During
Malfunctions, Startup, and Shutdown,’’ September
20, 1999; and 52 FR (45109 November 24, 1987).
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Since the SSM provisions were
withdrawn by the State, and are
therefore no longer before EPA, neither
EPA’s proposed disapproval of these
exemptions nor the comments on that
proposed disapproval are relevant to
this final action.
Comment #5: NPCA commented that
Kansas’ regional haze plan is
incomplete and insufficient, because of
what NPCA considers an incomplete
five step BART analysis at Westar
Energy Jeffrey Energy Center Units 1
and 2, and at Kansas City Power and
Light La Cygne Units 1 and 2. NPCA
states that requiring presumptive limits
does not negate the need for a State to
determine BART for each source subject
to BART on a case-by-case basis through
a five factor analysis. NPCA stated that
the most stringent emissions rate the
various technologies are capable of
achieving needs to be analyzed for cost
and visibility improvement in order to
make an adequate BART determination.
NPCA offered a number of specific
comments about these units, which are
listed and addressed separately below.
NPCA asserted that selective catalytic
reduction (SCR) is a cost-effective
technology to control NOX emissions.
As such, NPCA believes that SCR
should be required as BART for Westar
Energy Jeffrey Units 1 and 2. The
original BART analysis for these units
examined SCR at an emission rate of
0.10 lbs/MMBtu and determined that
the cost effectiveness was $2,211/ton of
NOX removed and $1,738/ton of NOX
removed for Units 1 and 2, respectively.
NPCA states that these costs, while
reasonable, are improperly inflated due
to the State’s low control efficiency
assumptions; and that SCR is capable of
achieving a lower emissions rate than
what the State assumed in its BART
analysis, such as 0.05 lbs/MMBtu.
Response #5: On December 1, 2011,
the State provided supplemental
information on incremental cost and
visibility improvement for various
control strategies for Westar Energy
Jeffrey Energy Center Units 1 and 2, and
Kansas City Power and Light La Cygne
Units 1 and 2. This information is
available in the docket for this
rulemaking. The supplemental
dispersion modeling provided by the
State was conducted with the CALPUFF
model using the same inputs that were
used during the original BART analysis,
except that the emissions rates were
changed to determine visibility
improvement from various control
options. Visibility impacts were
evaluated at five Class I areas: Caney
Creek and Upper Buffalo in Arkansas,
Hercules Glades and Mingo in Missouri,
and Wichita Mountains in Oklahoma.
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The State also obtained or developed
annualized costs for the additional
equipment that would be required to be
installed in order to achieve lower
emission rates.
The BART cost analysis for SCR at
Jeffrey Units 1 and 2 was performed
based on an emission limit of 0.10 lbs/
MMBtu, which is within the range of
effectiveness that the State believed to
be reasonable as a retrofit control on
older tangential-fired units. The State
assumed a control efficiency of 79–80
percent, which is in the mid-range of
control efficiencies demonstrated for
SCR, as noted by NPCA in their
comments. EPA believes the State’s
decision to choose a control efficiency
within the middle of the range for the
purpose of estimating cost is a
reasonable approach and is acceptable
according to the BART Guidelines.2 In
the BART analysis, SCR operated at a
rate of 0.10 lbs/MMBtu was evaluated
for incremental cost improvements and
was excluded as BART based on the
high incremental cost for the associated
low incremental visibility
improvements.
The State subsequently provided
additional cost and visibility
information for SCR at Jeffrey Units 1
and 2, assuming an emissions rate of
0.08 lbs/MMBtu. The State asserted that
the 0.05 lb/MMBtu rate was not
reasonable to evaluate as retrofit for 35
year old tangential-fired units. The
difference in modeled impact for Jeffrey
Unit 1 between the SCR scenario (0.08
lbs NOX/MMBtu) and the low NOX
burner (LNB) scenario (0.15 lbs NOX/
MMBtu) at Hercules Glades, the most
impacted Class I area, is 0.048
deciviews (dv) of additional
improvement. The difference in the
cumulative improvement across all five
Class I areas for this scenario is 0.161
dv. The annualized incremental cost of
these controls is $13,362,820 in 2005
dollars, which we calculated to be
$5,374 per ton.
The use of SCR at Jeffrey Unit 2 has
similar incremental costs as for Jeffrey
Unit 1, but less visibility improvement.
Incremental visibility improvement
resulting from tightening the
presumptive NOX rate of 0.15 lbs/
MMBtu to a rate of 0.08 lbs/MMBtu is
0.042 dv at Upper Buffalo, and 0.153 dv
cumulatively across the five Class I
areas. The incremental annual cost of
these controls is $13,345,950, for an
incremental cost per ton of $5,367.
The State concluded that these
additional NOX reduction costs are high
2 40 CFR part 51, Appendix Y: Guidelines for
BART Determinations Under the Regional Haze
Rule.
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for the associated low incremental
visibility improvements for Jeffrey Units
1 and 2, and changes to the proposed
BART emission limits are not
warranted. EPA agrees that based on the
low visibility improvements and high
costs of additional control, it is
reasonable to determine that no changes
to the proposed BART emission limits
are warranted. It is also consistent with
the BART Guidelines, which provide
the State flexibility to determine the
weight and significance of the five
factors. EPA finds little support in the
State’s information for the statement
that a rate of 0.05 lbs/MMBtu is not
reasonable to evaluate for older
tangential-fired units. However, it is
reasonable to conclude that the costs
and visibility improvement of SCR
operated at a rate of 0.05 lbs/MMBtu
would lead to a similar conclusion that
the additional costs would be high for
the associated low incremental visibility
improvement. Therefore, EPA finds that
no changes to the BART determinations
or to the SIP are needed in response to
this comment.
In addition, EPA notes that following
the State’s BART determinations and
submission of the regional haze SIP,
Westar Energy, EPA, and the State
entered into a Federal Consent Decree in
resolution of alleged violations of the
Clean Air Act.3 Under the Consent
Decree, Westar Energy is required to
install an SCR on Jeffrey Unit 1, 2, or 3
by December 31, 2014 in order to
achieve and maintain a 30-day rolling
average unit emission rate for NOX of no
greater than 0.080 lbs/MMBtu. By
December 31, 2012 Westar Energy must
elect to install a second SCR on one of
the other two Jeffrey units, or meet a
0.100 lbs/MMBtu plant-wide 12-month
rolling average emission rate for NOX. If
Westar Energy elects to install the
second SCR, it is to be installed by
December 31, 2016 to achieve and
maintain a 30-day rolling average unit
emission rate for NOX of no greater than
0.070 lbs/MMBtu. Additionally, the
Jeffrey plant must comply with a plantwide 12 month rolling tonnage
limitation of 9600 tons. Therefore,
following implementation of the
regional haze requirements and the
Consent Decree provisions, the Westar
Jeffrey Units will be well controlled for
NOX.
Comment #6: NPCA commented that
overfire air and selective non-catalytic
reduction (SNCR) were determined to be
feasible technologies during the BART
analysis, but were not evaluated for cost
3 United States and Kansas v. Westar Energy, Inc.,
Civil Action No. 09–CV–2059 JAR/DJW (D. Kan.
March 26, 2010).
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Jkt 226001
or visibility impacts at Jeffrey Units 1
and 2. NPCA commented that LNB or
ultra LNB with SCR was likewise not
evaluated, despite the BART analysis
noting that such combinations can
achieve reductions up to 97 percent.
Response #6: Overfire air was
considered along with LNB, so this
combination of controls was included in
the cost and visibility analysis
submitted by the State. Likewise, LNB
was included with the consideration of
SCR, as it makes the SCR less expensive
to build.
The State subsequently provided cost
and visibility information for SNCR
operated at 0.10 lbs/MMBtu at these
units. For Jeffrey Unit 1, the change in
visibility improvement between the
SNCR scenario (0.10 lbs NOX/MMBtu)
and the LNB scenario (0.15 lbs NOX/
MMBtu) at Hercules Glades was 0.030
dv. The difference in the cumulative
improvement across all five Class I areas
for this scenario was 0.090 dv. The
annual incremental cost of these
controls is $3,103,877, for an
incremental cost per ton of $1,748.
The results for SNCR at Jeffrey Unit 2
are similar—0.020 dv of improvement at
Wichita Mountains and 0.080 dv
cumulative improvement across all five
Class I areas. The annual incremental
cost of these controls is $3,103,877, for
an incremental cost per ton of $1,478.
The State concluded that the
additional NOX reduction costs are high
for the associated low incremental
visibility improvements for Jeffrey Units
1 and 2, and do not warrant changes to
the proposed BART controls. Although
the costs are likely cost effective on a
per ton basis, the BART Guidelines
provide the State flexibility to
determine the weight and significance
of the five factors, and EPA agrees that
the State reasonably determined that the
costs of further control are not
warranted based on the low additional
visibility improvements. Therefore, EPA
finds that no changes to the BART
determinations or to the SIP are needed
in response to this comment.
Comment #7: NPCA commented that
the BART determinations for La Cygne
Units 1 and 2 were flawed due to an
incomplete analysis of SCR and other
NOX control options. La Cygne Unit 1
has an existing SCR, but NPCA asserted
that the most stringent rate the SCR is
capable of achieving at Unit 1 was not
analyzed. NPCA commented that a
control technology has not actually been
selected for Unit 2; rather, an overall
emissions rate was established as BART.
NPCA claims that SCR with the lowest
achievable emissions rate should be
evaluated as BART for Unit 2 and would
likely be shown to be cost effective.
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NPCA commented that other
combinations of NOX controls should
also be evaluated for Unit 2, including
overfire air, LNB, and the combination
of SCR with feasible combustion
controls.
Response #7: The State’s evaluation of
the BART analysis for La Cygne Units 1
and 2 for NOX resulted in the decision
that establishing a combined emissions
limit for both units with a rate of 0.13
lbs/MMBtu was BART.
For Unit 1, as a part of the BART
analysis, the State reviewed EPA’s Clean
Air Markets Division and the Energy
Information Agency’s databases for
emissions data on cyclone boilers
equipped with SCR technology. A
relatively small number of cyclone
boilers were so equipped at that time
and their emission rates varied both
above and below the presumptive NOX
rate. Based on this information, the
State determined that a rate of 0.10 lbs/
MMBtu was a reasonably stringent rate
to evaluate for the existing control.
NPCA is correct that SCR was not
specified as BART for Unit 2; rather, a
combined rate for La Cygne Units 1 and
2 was specified as BART. While a range
of control technologies must be
evaluated in order to make a BART
determination, EPA believes that it is
acceptable to establish an enforceable
emission limit as BART, rather than
specifying a control technology to
achieve it.
The State subsequently provided
additional visibility and cost
information to show the incremental
visibility improvement that would
result from requiring lower NOX
emission rates for Unit 2. The
annualized cost for SCR on Kansas City
Power and Light La Cygne Unit 2 was
obtained from Table 5.5 of the BART
analysis.4 The State claimed that in
order to achieve a lower emissions rate,
the size of the SCR would need to be
scaled up, resulting in concurrent
increases in electrical demand, in raw
materials, and maintenance. The
incremental annualized cost for these
additional capital and operational costs
was estimated to be 20 percent greater
than the initial cost projection for the
SCR. The change in visibility
improvement between the proposed
BART emission rate (0.23 lbs NOX/
MMBtu) and the Unit 2 SCR scenario
(0.08 lbs NOX/MMBtu) was 0.082 dv for
Upper Buffalo. The difference in the
cumulative improvement across all five
Class I areas is 0.25 dv. The annualized
incremental cost of controls in this
4 BART Five Factor Analysis for Kansas City
Power and Light La Cygne Generating Station,
prepared by Trinity Consultants, August 2007.
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scenario is $2,981,706, for an
incremental cost per ton of $548.
As with the Jeffrey units, overfire air
was considered along with LNB, so this
combination of control technologies has
already been evaluated.
The annualized cost for SNCR control
on Kansas City Power and Light La
Cygne Unit 2 was determined by using
SNCR costs obtained from Jeffrey Unit 1,
and scaling the dollar amount using
heat input and NOX rates. The change
in visibility improvement between the
proposed BART emissions rate (0.23 lbs
NOX/MMBtu) and the Unit 2 SNCR
scenario (0.14 lbs NOX/MMBtu) is 0.044
dv for Hercules Glades. The difference
in the cumulative improvement across
all five Class I areas is 0.12 dv. The
annualized incremental cost of controls
in this scenario is $972,747, for an
incremental cost per ton of $298.
The State concluded that the
additional NOX reduction costs are high
for the associated low incremental
visibility improvements for La Cygne
Units 1 and 2, and do not warrant
changes to the proposed BART controls.
The BART Guidelines provide the State
the flexibility to determine the weight
and significance of the five factors.
Although the costs appear to be
reasonable on a cost per ton basis, EPA
has some concern with the scaling
methodology utilized by the State to
arrive at cost estimates for the lower
NOX rates. However, given the low
visibility improvements associated with
the additional control, EPA agrees it is
reasonable to determine that the costs of
further control are not warranted and no
changes to the BART determinations or
to the SIP are needed in response to this
comment.
EPA also notes that since the time of
the State’s BART determinations and
submission of the regional haze SIP,
Kansas City Power and Light applied for
a permit to install SCR on La Cygne Unit
2. The permit was effective March 16,
2011.5 In order for the permit to remain
valid, Kansas City Power and Light must
commence construction within
18 months of the permit’s effective date
(by September 2012).
Comment #8: NPCA commented that
while La Cygne Units 1 and 2 and
Jeffrey Units 1 and 2 have proposed to
either install or upgrade scrubbers at all
four units to control SO2 emissions, the
State’s analysis was incomplete in that
it lacked an evaluation of the most
stringent emission limits the technology
is capable of achieving. NPCA claims
that scrubbers, both wet and dry, are
5 Construction Permit issued to Kansas City
Power and Light Company for the La Cygne
Generating Station. Permit effective March 16, 2011.
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capable of emission reductions below
the proposed BART emission rates of
0.15 lbs/MMBtu at Jeffrey and 0.10 lbs/
MMBtu at La Cygne. NPCA suggests that
scrubbers are capable of achieving 0.03
to 0.05 lbs/MMBtu at each unit.
Response #8: The State’s evaluation of
the BART analysis for Jeffrey Units 1
and 2 for SO2 resulted in the
determination that rebuilding the
existing wet scrubber units and meeting
a rate of 0.15 lbs/mmBtu was BART.
The State did not believe that it was
feasible to achieve an emissions rate of
0.05 lbs/MMBtu with rebuilt
technology, so costs and visibility
improvements were subsequently
provided for the installation of a new
scrubber operating at 0.05 lbs/MMBtu
for both Jeffrey units. The State obtained
annualized costs for new scrubbers on
Jeffrey Units 1 and 2 from Westar
Energy. The change in visibility
improvement between the new wet
scrubber scenario (0.05 lbs SO2/MMBtu)
and the proposed BART emission limit
(0.15 lbs SO2/MMBtu) for Jeffrey Unit 1
was 0.052 dv at Hercules Glades. The
difference in the cumulative
improvement across all five Class I areas
is 0.168 dv. The annualized incremental
cost of controls in this scenario is
$23,567,203, for an incremental cost per
ton of $6,635.
The differences for Jeffrey Unit 2
under these scenarios are comparable to
Unit 1—0.057 dv improvement at
Hercules Glades, and 0.160
cumulatively. The annualized
incremental cost of controls in this
scenario was $23,567,203, for an
incremental cost per ton of $6,635.
The State concluded that the
additional SO2 reduction costs are high
given the low incremental visibility
improvements for Jeffrey Units 1 and 2,
and do not warrant changes to the
proposed BART emission rates. EPA has
some concern with the assumptions
used by the State in arriving at the cost
estimates, however, given the very low
visibility improvement modeled for the
additional control, consistent with the
BART Guidelines which provide the
State flexibility to determine the weight
and significance of the five factors, EPA
agrees it is reasonable to determine that
the costs of further control are not
warranted and no changes to the BART
determinations or to the SIP are needed
in response to this comment.
EPA also notes, as was referenced
above, since the time of the State’s
BART determinations and submission of
the regional haze SIP, Westar Energy,
EPA and the State entered into a Federal
Consent Decree in resolution of alleged
violations of the Clean Air Act. The
Consent Decree requires that Jeffrey
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Units 1 and 2 each meet a 30-day rolling
average unit removal efficiency for SO2
of at least 97 percent or a 30-day rolling
average unit emission rate for SO2 of
0.070 lbs/MMBtu. Therefore, following
implementation of the regional haze
requirements and the Consent Decree,
Jeffrey Units 1 and 2 will be well
controlled for SO2.
The State’s evaluation of the BART
analysis for La Cygne Units 1 and 2 for
SO2 resulted in the determination that a
combined emissions limit for both units
at rate of 0.10 lbs/MMBtu was BART.
Unit 1 has an existing scrubber that will
be modified to separate the PM control
from the SO2 control resulting in
increased SO2 removal efficiency. Unit
2, which did not have an existing
scrubber, will be retrofitted with a new
scrubber. The combined BART emission
rate chosen for SO2 controls is within
the range of expected removal
efficiencies, considering one unit is a
retrofitted scrubber.
The State subsequently provided
additional cost and visibility
information to further evaluate lower
SO2 emission rates. The State estimated
the incremental annualized cost
estimate to be 20 percent greater than
the initial cost projection for the
scrubber, because of the increased
electrical demand, raw material costs,
and maintenance costs associated with
achieving a more stringent emissions
rate.
For the Unit 1 scrubber at La Cygne,
the change in visibility improvement
from the presumptive BART emissions
rate (0.15 lbs SO2/MMBtu) to a lower
rate (0.05 lbs SO2/mmBtu) is 0.04 dv at
Caney Creek. The difference in the
cumulative improvement across all five
Class I areas for this scenario is 0.12 dv.
The annualized incremental cost of
controls in this scenario is $6,098,239,
for an incremental cost per ton of
$1,495. The La Cygne Unit 2 scrubber
scenario is comparable: 0.04 dv
improvement at Hercules Glades, and
0.097 dv cumulative improvement. The
annualized incremental cost of controls
in this scenario is $5,427,642, for an
incremental cost per ton of $1,495.
The State concluded that the
additional SO2 reduction costs are high
given the associated low incremental
visibility improvements for La Cygne
Units 1 and 2, and changes to the
proposed BART controls are not
warranted. Although the costs appear to
be reasonable on a cost per ton basis,
EPA has some concern with the scaling
methodology utilized by the State to
arrive at the cost estimates for the lower
SO2 rate. However, given the low
additional visibility improvement,
consistent with the BART Guidelines
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which provide the State flexibility to
determine the weight and significance
of the five factors, EPA agrees it is
reasonable to determine that the costs of
further control are not warranted and no
changes to the BART determinations or
to the SIP are needed in response to this
comment.
Comment #9: NPCA commented that
the proposed SIP fails to address
cumulative impact of Kansas BART
sources on all Class I areas impacted.
NPCA says that the modeling results
presented in the proposed approval do
not provide for a determination of the
cumulative impact from Jeffrey Units 1
and 2 or La Cygne Units 1 and 2. NPCA
notes that the four BART units
mentioned above impact nine Class I
areas, but the State only provided
visibility information for five Class I
areas.
Response #9: In order to keep the size
of the modeling domain manageable, the
State chose to conduct refined modeling
on the five most impacted Class I areas.
Given the level of the modeled impacts
at these five Class I areas, EPA does not
believe that the State was unreasonable
in streamlining its modeling exercise to
exclude the other four Class I areas from
its visibility analysis. Given the overall
modeled impacts at the most impacted
Class I areas, taking into account the
impacts at the other four areas would
have been unlikely to significantly
change the State’s conclusions about
BART emission limits. Therefore, EPA
believes that no changes to the BART
determinations or to the SIP are needed
in response to this comment.
III. Final Action
EPA is taking final action to approve
the State of Kansas’ Regional Haze SIP,
submitted on November 9, 2009, with
supplemental information provided in
December 2011, including a letter dated
December 1, 2011, in which the State
withdrew specific SSM provisions of
the regional haze SIP from EPA’s
consideration. EPA finds that the
Kansas regional haze SIP submittal
meets all of the applicable Regional
Haze requirements set forth in section
169A and 169B of the Act and in the
Federal regulations codified at 40 CFR
51.300–308, and the requirements of 40
CFR Part 51, Subpart F and Appendix
V.
IV. Statutory and Executive Order
Reviews
Under the Clean Air Act, the
Administrator is required to approve a
SIP submission that complies with the
provisions of the Act and applicable
Federal regulations. 42 U.S.C. 7410(k);
40 CFR 52.02(a). Thus, in reviewing SIP
submissions, EPA’s role is to approve
State choices, provided that they meet
the criteria of the CAA. Accordingly,
this action merely approves State law as
meeting Federal requirements and does
not impose additional requirements
beyond those imposed by State law. For
that reason, this action:
• Is not a ‘‘significant regulatory
action’’ subject to review by the Office
of Management and Budget under
Executive Order 12866 (58 FR 51735,
October 4, 1993);
• Does not impose an information
collection burden under the provisions
of the Paperwork Reduction Act (44
U.S.C. 3501 et seq.);
• Is certified as not having a
significant economic impact on a
substantial number of small entities
under the Regulatory Flexibility Act (5
U.S.C. 601 et seq.);
• Does not contain any unfunded
mandate or significantly or uniquely
affect small governments, as described
in the Unfunded Mandates Reform Act
of 1995 (Pub. L. 104–4);
• Does not have Federalism
implications as specified in Executive
Order 13132 (64 FR 43255, August 10,
1999);
• Is not an economically significant
regulatory action based on health or
safety risks subject to Executive Order
13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action
subject to Executive Order 13211 (66 FR
28355, May 22, 2001);
• Is not subject to requirements of
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (15 U.S.C. 272 note) because
application of those requirements would
be inconsistent with the CAA; and
80759
• Does not provide EPA with the
discretionary authority to address, as
appropriate, disproportionate human
health or environmental effects, using
practicable and legally permissible
methods, under Executive Order 12898
(59 FR 7629, February 16, 1994).
Executive Order 13175, entitled
‘‘Consultation and Coordination with
Indian Tribal Governments’’ (65 FR
67249, November 9, 2000), requires EPA
to develop an accountable process to
ensure ‘‘meaningful and timely input by
tribal officials in the development of
regulatory policies that have tribal
implications.’’ This rule does not have
tribal implications, as specified in
Executive Order 13175. It will not have
substantial direct effects on tribal
governments. Thus, Executive Order
13175 does not apply to this rule.
List of Subjects in 40 CFR Part 52
Air pollution control, Environmental
protection, Incorporation by reference,
Intergovernmental relations, Nitrogen
oxides, Particulate matter, Reporting
and recordkeeping requirements, Sulfur
dioxide, Volatile organic compounds.
Dated: December 15, 2011.
Karl Brooks,
Regional Administrator, Region 7.
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 R—Kansas
2. In § 52.870:
a. The table in paragraph (d) is
amended by revising the table headings
and adding entries (3) and (4) in
numerical order.
■ b. The table in paragraph (e) is
amended by adding entry (33) in
numerical order.
The revisions and additions read as
follows:
■
■
§ 52.870
*
Identification of plan.
*
*
(d) * * *
*
*
EPA—APPROVED KANSAS SOURCE—SPECIFIC REQUIREMENTS
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Name of source
Permit or
case No.
*
*
(3) Kansas City Power and Light
Company.
State
effective
date
*
........................
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12/5/07
Frm 00031
EPA approval date
Explanation
*
*
12/27/11, [Insert Federal Register
citation].
*
*
Certain provisions withdrawn from
plan as identified in letter dated
12/1/11 from Kansas.
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Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations
EPA—APPROVED KANSAS SOURCE—SPECIFIC REQUIREMENTS—Continued
State
effective
date
Name of source
Permit or
case No.
(4) Westar Energy, Inc ....................
........................
*
*
*
*
*
*
Explanation
12/27/11, [Insert Federal Register
citation].
2/29/08
*
*
EPA approval date
Certain provisions withdrawn from
plan as identified in letter dated
12/1/11 from Kansas.
*
*
*
*
(e) * * *
EPA—APPROVED KANSAS NONREGULATORY PROVISIONS
Name of nonregulatory SIP
provision
Applicable geographic or nonattainment area
State submittal
date
EPA approval date
*
*
*
(33) Regional Haze Plan for
Statewide ...............................
the first implementation period.
*
11/9/09
*
12/27/11, [Insert Federal
Register citation].
Reduce Interstate Transport of Fine
Particulate Matter and Ozone in 27
States; Correction of SIP Approvals for
22 States) to sources in Iowa, Michigan,
Missouri, Oklahoma, and Wisconsin. In
addition, this action finalizes the
budgets; associated variability limits,
new unit set-asides, and Indian country
new unit set-asides; and unit-level
allowance allocations for each state
under the FIPs.
[FR Doc. 2011–32998 Filed 12–23–11; 8:45 am]
BILLING CODE 6560–50–P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 52 and 97
[EPA–HQ–OAR–2009–0491; FRL–9609–9]
RIN 2060–AR01
Federal Implementation Plans for Iowa,
Michigan, Missouri, Oklahoma, and
Wisconsin and Determination for
Kansas Regarding Interstate Transport
of Ozone
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
In this final rule, EPA is
concluding that emissions from Iowa,
Kansas, Michigan, Missouri, Oklahoma,
and Wisconsin significantly contribute
to downwind nonattainment or interfere
with maintenance of the 1997 ozone
National Ambient Air Quality Standards
(NAAQS)in other states. Each of these
states except Oklahoma is already
included in the annual NOX program
that was finalized in July 2011.
However, this rule does not affect that
program.
EPA is finalizing Federal
Implementation Plans (FIPs) to address
the emissions in each of these states
except for Kansas, for which EPA is not
finalizing a FIP at this time. The FIPs
apply the requirements of the ozone
season NOX program in the Transport
Rule (Federal Implementation Plans to
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SUMMARY:
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This final rule is effective on
January 26, 2012.
DATES:
EPA has established a
docket for this action under Docket ID
No. OAR–EPA–HQ–OAR–2009–0491.
All documents in the docket are listed
on the https://www.regulations.gov Web
site. Although listed on the index, some
information is not publicly available,
e.g., CBI or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, 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
https://www.regulations.gov or in hard
copy at the EPA Docket Center, EPA
West, Room B102, 1301 Constitution
Ave. NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to
4:30 p.m., Monday through Friday,
excluding legal holidays. The telephone
number for the Public Reading Room is
(202) 566–1744, and the telephone
number for the Air Docket is (202) 566–
1742. This Docket Facility is open from
8 a.m. to 5:30 p.m., Monday through
Friday, excluding legal holidays. The
ADDRESSES:
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Explanation
*
*
Certain provisions withdrawn
from plan as identified in
letter dated 12/1/11 from
Kansas.
Docket telephone number is (929) 566–
1742, fax (202) 566–1741.
FOR FURTHER INFORMATION CONTACT: For
general questions concerning this
action, contact Ms. Gabrielle Stevens,
Clean Air Markets Division, Office of
Atmospheric Programs, Mail Code
6204J, Environmental Protection
Agency, 1200 Pennsylvania Avenue
NW., Washington, DC 20460; telephone
number: (202) 343–9252; fax number:
(202) 343–2356; email address:
stevens.gabrielle@epa.gov.
SUPPLEMENTARY INFORMATION:
I. Glossary of Terms and Abbreviations
The following are abbreviations of
terms used in final rule:
CFR Code of Federal Regulations
EGU Electric Generating Unit
FIP Federal Implementation Plan
FR Federal Register
EPA U.S. Environmental Protection Agency
ICR Information Collection Request
NAAQS National Ambient Air Quality
Standards
NODA Notice of Data Availability
NOX Nitrogen Oxides
SIP State Implementation Plan
OMB Office of Management and Budget
PM2.5 Fine Particulate Matter, Less Than 2.5
Micrometers
PM Particulate Matter
RIA Regulatory Impact Analysis
SNPR Supplemental Notice of Proposed
Rulemaking
SO2 Sulfur Dioxide
TSD Technical Support Document
II. General Information
A. Does this action apply to me?
Regulated Entities. Entities regulated
by this action primarily are fossil fuel-
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]]>Agencies
[Federal Register Volume 76, Number 248 (Tuesday, December 27, 2011)]
[Rules and Regulations]
[Pages 80754-80760]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-32998]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R07-OAR-2011-0675; FRL-9611-3]
Approval and Promulgation of Implementation Plans; State of
Kansas: Regional Haze
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: EPA is taking final action to approve a revision to the State
Implementation Plan (SIP) for Kansas, submitted by the Kansas
Department of Health and Environment on October 26, 2009, that
addresses Regional Haze for the first implementation period. EPA has
determined that the plan submitted by Kansas satisfies the requirements
of the Clean Air Act (CAA or Act), for states to prevent any future and
remedy and existing anthropogenic impairment of visibility in Class I
areas caused by emissions of air pollutants located over a wide
geographic area (also known as the ``regional haze'' program). EPA
proposed to approve these revisions on August 23, 2011 (76 FR 52604).
DATES: Effective Date: This rule will be effective January 26, 2012.
ADDRESSES: EPA has established a docket for this action under Docket
Identification No. EPA-R07-OAR-2011-0675. All documents in the docket
are listed on the https://www.regulations.gov Web site. Although listed
in the index, some information is not publicly available, i.e.,
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 https://www.regulations.gov or in hard copy at the Air Planning and Development
Branch, Air and Waste Management Division, U.S. Environmental
Protection Agency, Region 7, 901 North 5th Street, Kansas City, KS
66101. EPA requests that if at all possible, you contact the person
listed in the FOR FURTHER INFORMATION CONTACT section for further
information. The regional office's official hours of business are
Monday through Friday, 8:30 to 4:30, excluding Federal holidays.
FOR FURTHER INFORMATION CONTACT: Chrissy Wolfersberger, Air Planning
and Development Branch, U.S. Environmental Protection Agency, Region 7,
901 N. 5th Street, Kansas City, Kansas 66101; by telephone at (913)
551-7864; or by email at wolfersberger.chris@epa.gov.
SUPPLEMENTARY INFORMATION: Throughout this document, the terms ``we,''
``us,'' and ``our'' refer to EPA.
Table of Contents
I. Background
II. Public comments and EPA responses
III. Final action
IV. Statutory and Executive Order reviews
I. Background
On August 23, 2011 (76 FR 52604), EPA published a notice of
proposed rulemaking (NPR) for the State of Kansas, proposing approval
of Kansas' regional haze plan for the first implementation period
(through 2018). A detailed explanation of the CAA's visibility
requirements and the regional haze rule as it applies to Kansas was
provided in the NPR and will not be restated here. EPA's rationale for
proposing approval of the Kansas SIP revision was described in detail
in the proposal, and is further described in this final rulemaking.
II. Public comments and EPA responses
The publication of EPA's proposed rule on August 23, 2011 initiated
a 30 day public comment period that ended on September 22, 2011. During
the public comment period we received written comments from the State
of Colorado, the Kansas Department of Health and Environment on behalf
of the State of Kansas (State), Kansas City Power & Light, Westar
Energy, and the National Parks Conservation Association (NPCA). We have
summarized the comments and provided our responses below. Full copies
of the comment letters are available in the docket for this rulemaking.
[[Page 80755]]
Comment #1: The State of Colorado submitted comments supportive of
EPA's proposed approval and applauding the State of Kansas' efforts to
evaluate and promulgate cost effective emission controls that will
improve visibility in a number of Class I areas, including Rocky
Mountain National Park and Great Sand Dunes National Park & Preserve.
Response #1: We appreciate the State of Colorado's comments on our
proposed action.
Comment #2: The State and Westar Energy noted some transcription
errors in table 7 of the proposed notice, titled ``Control or work
practice strategies for Westar units to meet Kansas long term strategy
requirements.'' Some limits for sulfur dioxide (SO2) were
recorded as limits for nitrogen oxides (NOX), and vice
versa. The specific errors were:
Lawrence Unit 3: the limit of 0.18 lbs/mmBtu is for
NOX, not SO2
Lawrence Unit 4: the limit of 0.18 lbs/mmBtu is for
NOX, not SO2; and the limit of 0.15 lbs/mmBtu is
for SO2, not NOX
Tecumseh Unit 7/9: the limit of 0.18 lbs/mmBtu is for
NOX, not SO2
Tecumseh Unit 8/10: limit of 0.18 lbs/mmBtu for
NOX, not SO2.
Response #2: EPA agrees that there were transcription errors in
table 7. Table 7 is corrected to read as follows:
------------------------------------------------------------------------
Facility/unit Emission rate or work practice
------------------------------------------------------------------------
Gordon Evans Energy Center--Unit 1..... a fuel switch to natural gas at
all times, with the exception
of a gas curtailment order
from the gas supplier, in
which case the facility will
be allowed to utilize backup
6 fuel oil.
Hutchinson--Unit 4..................... a fuel switch to natural gas at
all times, with the exception
of a gas curtailment order
from the gas supplier, in
which case the facility will
be allowed to utilize backup
6 fuel oil.
Murray Gill--Units 1, 2, 3 and 4....... a fuel switch to natural gas at
all times, with the exception
of a gas curtailment order
from the gas supplier, in
which case the facility will
be allowed to utilize backup
6 fuel oil.
Neosho--Unit 7......................... a fuel switch to natural gas at
all times, with the exception
of a gas curtailment order
from the gas supplier, in
which case the facility will
be allowed to utilize backup
6 fuel oil.
Jeffrey Energy Center--Unit 3.......... an emission limit of 0.15 lbs/
MMBtu for both SO2 and NOX.
Lawrence--Unit 3....................... an emission limit of 0.18 lbs/
MMBtu for NOX.
Lawrence--Unit 4....................... an emission limit of 0.18 lbs/
MMBtu for NOX; an emission
limit of 0.15 lbs/MMBtu for
SO2.
Lawrence--Unit 5....................... an emission limit of 0.15 lbs/
MMBtu for both SO2 and NOX.
Tecumseh--Units 7/9.................... an emission limit of 0.18 lbs/
MMBtu for NOX.
Tecumseh--Units 8/10................... an emission limit of 0.18 lbs/
MMBtu for NOX.
------------------------------------------------------------------------
Comment #3: Westar Energy noted errors in table 8 of the proposed
approval, titled, ``Estimated NOX and SO2
emission reductions for implementation of controls or work practices
required by Kansas' long term strategy''. Errors in table 8 included
listing the 2002 SO2 emissions for Lawrence Unit 5 as
4,546.3 tons (the correct value is 4,353.7 tons), and listing the post-
control NOX emissions for Lawrence Unit 4 at 835.4 tons (the
correct value is 1002.4 tons).
Response #3: EPA agrees that there were errors in table 8. Table 8
is corrected as follows:
--------------------------------------------------------------------------------------------------------------------------------------------------------
2002 NOX 2002 SO2 Post Post NOX SO2
Facility Unit Emissions Emissions control NOX control SO2 Reductions Reductions
(tpy) (tpy) (tpy) (tpy) (tpy) (tpy)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gordon Evans..................................................... 1 258.7 617.7 211.9 0.5 46.8 617.2
Hutchinson....................................................... 4 267.1 734.3 158.5 0.6 108.5 733.7
Jeffrey.......................................................... 3 10,807.4 23,206.0 4,913.1 4,913.1 5,894.3 18,292.9
Lawrence......................................................... 3 728.4 1,965.4 0.0 1,965.4 728.4 0.0
Lawrence......................................................... 4 1,986.5 1,430.0 1,002.4 835.4 984.1 594.7
Lawrence......................................................... 5 3,546.3 4,353.7 2,564.7 2,564.7 981.6 1,789.0
Gill............................................................. 1 0.0 0.0 0.0 0.0 0.0 0.0
Gill............................................................. 2 4.5 0.0 4.0 0.0 0.5 0.0
Gill............................................................. 3 181.6 452.1 148.6 0.3 33.0 451.8
Gill............................................................. 4 103.8 333.3 85.2 0.2 18.7 333.1
Neosho........................................................... 7 0.0 0.0 0.0 0.0 0.0 0.0
Tecumseh......................................................... 7 1,530.6 2,692.7 691.6 2,692.7 839.0 0.0
Tecumseh......................................................... 8 1,876.9 4,514.9 1,103.1 4,514.9 773.8 0.0
--------------------------------------------------------------------------------------
Total........................................................ ....... ........... ........... ........... ........... 10,408.7 22,812.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Comment #4: As noted in the proposal, the State entered into
Consent Agreements with Kansas City Power and Light and Westar Energy
to incorporate the Best Available Retrofit Technology (BART) emission
rates, compliance schedules, monitoring, recordkeeping, reporting, and
enforceability requirements. EPA proposed to disapprove specific
startup, shutdown and malfunction (SSM) provisions in the State's
regional haze Consent Agreements with Westar Energy and Kansas City
Power and Light that were submitted as part of the regional haze SIP.
The State commented that EPA's proposed exclusion of periods of SSM
from the Consent Agreements has the effect of making the BART emission
limits more stringent. The State requested that EPA consider fully
[[Page 80756]]
approving the SIP revision. Kansas City Power and Light commented that
the proposed approval of the Kansas Regional Haze SIP excluding the SSM
provisions fundamentally changes the basis of the emission limits, and
because the SSM provisions were agreed to through good faith
negotiations with the State, Kansas City Power and Light asked that the
Agreements be renegotiated. Westar Energy made similar comments,
disagreeing with the proposed disapproval of the SSM provisions in the
Consent Agreement between the State and Westar Energy.
Response #4: As EPA explained in the proposed notice, the Consent
Agreements exempted periods of startup and shutdown for both Kansas
City Power and Light and Westar Energy from compliance with applicable
emission limits, which were not narrowly defined, and exempted periods
of malfunction for Westar Energy. EPA proposed to disapprove the
exemptions because they are inconsistent with the Clean Air Act and
EPA's September 20, 1999, guidance, ``State Implementation Plans:
Policy Regarding Excess Emissions during Malfunctions, Startup and
Shutdown.'' \1\
---------------------------------------------------------------------------
\1\ Steven Herman, Assistant Administrator for Enforcement and
Compliance Assurance, and Robert Perciasepe, Assistant Administrator
for Air and Radiation, ``State Implementation Plans (SIPs): Policy
Regarding Excess Emissions During Malfunctions, Startup, and
Shutdown,'' September 20, 1999; and 52 FR (45109 November 24, 1987).
---------------------------------------------------------------------------
EPA subsequently received a letter from the State dated December 1,
2011, withdrawing the SSM provisions in the Consent Agreements in their
entirety from the regional haze SIP. Specifically, the following four
provisions were withdrawn from EPA's consideration for approval in the
regional haze SIP:
1. All references to, ``excluding periods of startup and shutdown''
in Paragraph 23 of the Kansas City Power and Light Company regional
haze agreement;
2. The reference to, ``excluding periods of startup, shutdown and
malfunction'' in footnote 1 of Appendix A to the Westar Energy, Inc.
regional haze agreement;
3. All references to, ``excluding periods of startup and shutdown''
in Chapter 9.3.1 of the Kansas regional haze SIP;
4. And the sentence, ``The Agreements between KDHE and the affected
BART sources currently exclude emissions associated with startup,
shutdowns, and malfunctions (SSM) in the agreed upon emission limits''
in Chapter 9.5 of the Kansas regional haze SIP.
Since the SSM provisions were withdrawn by the State, and are
therefore no longer before EPA, neither EPA's proposed disapproval of
these exemptions nor the comments on that proposed disapproval are
relevant to this final action.
Comment #5: NPCA commented that Kansas' regional haze plan is
incomplete and insufficient, because of what NPCA considers an
incomplete five step BART analysis at Westar Energy Jeffrey Energy
Center Units 1 and 2, and at Kansas City Power and Light La Cygne Units
1 and 2. NPCA states that requiring presumptive limits does not negate
the need for a State to determine BART for each source subject to BART
on a case-by-case basis through a five factor analysis. NPCA stated
that the most stringent emissions rate the various technologies are
capable of achieving needs to be analyzed for cost and visibility
improvement in order to make an adequate BART determination. NPCA
offered a number of specific comments about these units, which are
listed and addressed separately below.
NPCA asserted that selective catalytic reduction (SCR) is a cost-
effective technology to control NOX emissions. As such, NPCA
believes that SCR should be required as BART for Westar Energy Jeffrey
Units 1 and 2. The original BART analysis for these units examined SCR
at an emission rate of 0.10 lbs/MMBtu and determined that the cost
effectiveness was $2,211/ton of NOX removed and $1,738/ton
of NOX removed for Units 1 and 2, respectively. NPCA states
that these costs, while reasonable, are improperly inflated due to the
State's low control efficiency assumptions; and that SCR is capable of
achieving a lower emissions rate than what the State assumed in its
BART analysis, such as 0.05 lbs/MMBtu.
Response #5: On December 1, 2011, the State provided supplemental
information on incremental cost and visibility improvement for various
control strategies for Westar Energy Jeffrey Energy Center Units 1 and
2, and Kansas City Power and Light La Cygne Units 1 and 2. This
information is available in the docket for this rulemaking. The
supplemental dispersion modeling provided by the State was conducted
with the CALPUFF model using the same inputs that were used during the
original BART analysis, except that the emissions rates were changed to
determine visibility improvement from various control options.
Visibility impacts were evaluated at five Class I areas: Caney Creek
and Upper Buffalo in Arkansas, Hercules Glades and Mingo in Missouri,
and Wichita Mountains in Oklahoma. The State also obtained or developed
annualized costs for the additional equipment that would be required to
be installed in order to achieve lower emission rates.
The BART cost analysis for SCR at Jeffrey Units 1 and 2 was
performed based on an emission limit of 0.10 lbs/MMBtu, which is within
the range of effectiveness that the State believed to be reasonable as
a retrofit control on older tangential-fired units. The State assumed a
control efficiency of 79-80 percent, which is in the mid-range of
control efficiencies demonstrated for SCR, as noted by NPCA in their
comments. EPA believes the State's decision to choose a control
efficiency within the middle of the range for the purpose of estimating
cost is a reasonable approach and is acceptable according to the BART
Guidelines.\2\ In the BART analysis, SCR operated at a rate of 0.10
lbs/MMBtu was evaluated for incremental cost improvements and was
excluded as BART based on the high incremental cost for the associated
low incremental visibility improvements.
---------------------------------------------------------------------------
\2\ 40 CFR part 51, Appendix Y: Guidelines for BART
Determinations Under the Regional Haze Rule.
---------------------------------------------------------------------------
The State subsequently provided additional cost and visibility
information for SCR at Jeffrey Units 1 and 2, assuming an emissions
rate of 0.08 lbs/MMBtu. The State asserted that the 0.05 lb/MMBtu rate
was not reasonable to evaluate as retrofit for 35 year old tangential-
fired units. The difference in modeled impact for Jeffrey Unit 1
between the SCR scenario (0.08 lbs NOX/MMBtu) and the low
NOX burner (LNB) scenario (0.15 lbs NOX/MMBtu) at
Hercules Glades, the most impacted Class I area, is 0.048 deciviews
(dv) of additional improvement. The difference in the cumulative
improvement across all five Class I areas for this scenario is 0.161
dv. The annualized incremental cost of these controls is $13,362,820 in
2005 dollars, which we calculated to be $5,374 per ton.
The use of SCR at Jeffrey Unit 2 has similar incremental costs as
for Jeffrey Unit 1, but less visibility improvement. Incremental
visibility improvement resulting from tightening the presumptive
NOX rate of 0.15 lbs/MMBtu to a rate of 0.08 lbs/MMBtu is
0.042 dv at Upper Buffalo, and 0.153 dv cumulatively across the five
Class I areas. The incremental annual cost of these controls is
$13,345,950, for an incremental cost per ton of $5,367.
The State concluded that these additional NOX reduction
costs are high
[[Page 80757]]
for the associated low incremental visibility improvements for Jeffrey
Units 1 and 2, and changes to the proposed BART emission limits are not
warranted. EPA agrees that based on the low visibility improvements and
high costs of additional control, it is reasonable to determine that no
changes to the proposed BART emission limits are warranted. It is also
consistent with the BART Guidelines, which provide the State
flexibility to determine the weight and significance of the five
factors. EPA finds little support in the State's information for the
statement that a rate of 0.05 lbs/MMBtu is not reasonable to evaluate
for older tangential-fired units. However, it is reasonable to conclude
that the costs and visibility improvement of SCR operated at a rate of
0.05 lbs/MMBtu would lead to a similar conclusion that the additional
costs would be high for the associated low incremental visibility
improvement. Therefore, EPA finds that no changes to the BART
determinations or to the SIP are needed in response to this comment.
In addition, EPA notes that following the State's BART
determinations and submission of the regional haze SIP, Westar Energy,
EPA, and the State entered into a Federal Consent Decree in resolution
of alleged violations of the Clean Air Act.\3\ Under the Consent
Decree, Westar Energy is required to install an SCR on Jeffrey Unit 1,
2, or 3 by December 31, 2014 in order to achieve and maintain a 30-day
rolling average unit emission rate for NOX of no greater
than 0.080 lbs/MMBtu. By December 31, 2012 Westar Energy must elect to
install a second SCR on one of the other two Jeffrey units, or meet a
0.100 lbs/MMBtu plant-wide 12-month rolling average emission rate for
NOX. If Westar Energy elects to install the second SCR, it
is to be installed by December 31, 2016 to achieve and maintain a 30-
day rolling average unit emission rate for NOX of no greater
than 0.070 lbs/MMBtu. Additionally, the Jeffrey plant must comply with
a plant-wide 12 month rolling tonnage limitation of 9600 tons.
Therefore, following implementation of the regional haze requirements
and the Consent Decree provisions, the Westar Jeffrey Units will be
well controlled for NOX.
---------------------------------------------------------------------------
\3\ United States and Kansas v. Westar Energy, Inc., Civil
Action No. 09-CV-2059 JAR/DJW (D. Kan. March 26, 2010).
---------------------------------------------------------------------------
Comment #6: NPCA commented that overfire air and selective non-
catalytic reduction (SNCR) were determined to be feasible technologies
during the BART analysis, but were not evaluated for cost or visibility
impacts at Jeffrey Units 1 and 2. NPCA commented that LNB or ultra LNB
with SCR was likewise not evaluated, despite the BART analysis noting
that such combinations can achieve reductions up to 97 percent.
Response #6: Overfire air was considered along with LNB, so this
combination of controls was included in the cost and visibility
analysis submitted by the State. Likewise, LNB was included with the
consideration of SCR, as it makes the SCR less expensive to build.
The State subsequently provided cost and visibility information for
SNCR operated at 0.10 lbs/MMBtu at these units. For Jeffrey Unit 1, the
change in visibility improvement between the SNCR scenario (0.10 lbs
NOX/MMBtu) and the LNB scenario (0.15 lbs NOX/
MMBtu) at Hercules Glades was 0.030 dv. The difference in the
cumulative improvement across all five Class I areas for this scenario
was 0.090 dv. The annual incremental cost of these controls is
$3,103,877, for an incremental cost per ton of $1,748.
The results for SNCR at Jeffrey Unit 2 are similar--0.020 dv of
improvement at Wichita Mountains and 0.080 dv cumulative improvement
across all five Class I areas. The annual incremental cost of these
controls is $3,103,877, for an incremental cost per ton of $1,478.
The State concluded that the additional NOX reduction
costs are high for the associated low incremental visibility
improvements for Jeffrey Units 1 and 2, and do not warrant changes to
the proposed BART controls. Although the costs are likely cost
effective on a per ton basis, the BART Guidelines provide the State
flexibility to determine the weight and significance of the five
factors, and EPA agrees that the State reasonably determined that the
costs of further control are not warranted based on the low additional
visibility improvements. Therefore, EPA finds that no changes to the
BART determinations or to the SIP are needed in response to this
comment.
Comment #7: NPCA commented that the BART determinations for La
Cygne Units 1 and 2 were flawed due to an incomplete analysis of SCR
and other NOX control options. La Cygne Unit 1 has an
existing SCR, but NPCA asserted that the most stringent rate the SCR is
capable of achieving at Unit 1 was not analyzed. NPCA commented that a
control technology has not actually been selected for Unit 2; rather,
an overall emissions rate was established as BART. NPCA claims that SCR
with the lowest achievable emissions rate should be evaluated as BART
for Unit 2 and would likely be shown to be cost effective. NPCA
commented that other combinations of NOX controls should
also be evaluated for Unit 2, including overfire air, LNB, and the
combination of SCR with feasible combustion controls.
Response #7: The State's evaluation of the BART analysis for La
Cygne Units 1 and 2 for NOX resulted in the decision that
establishing a combined emissions limit for both units with a rate of
0.13 lbs/MMBtu was BART.
For Unit 1, as a part of the BART analysis, the State reviewed
EPA's Clean Air Markets Division and the Energy Information Agency's
databases for emissions data on cyclone boilers equipped with SCR
technology. A relatively small number of cyclone boilers were so
equipped at that time and their emission rates varied both above and
below the presumptive NOX rate. Based on this information,
the State determined that a rate of 0.10 lbs/MMBtu was a reasonably
stringent rate to evaluate for the existing control.
NPCA is correct that SCR was not specified as BART for Unit 2;
rather, a combined rate for La Cygne Units 1 and 2 was specified as
BART. While a range of control technologies must be evaluated in order
to make a BART determination, EPA believes that it is acceptable to
establish an enforceable emission limit as BART, rather than specifying
a control technology to achieve it.
The State subsequently provided additional visibility and cost
information to show the incremental visibility improvement that would
result from requiring lower NOX emission rates for Unit 2.
The annualized cost for SCR on Kansas City Power and Light La Cygne
Unit 2 was obtained from Table 5.5 of the BART analysis.\4\ The State
claimed that in order to achieve a lower emissions rate, the size of
the SCR would need to be scaled up, resulting in concurrent increases
in electrical demand, in raw materials, and maintenance. The
incremental annualized cost for these additional capital and
operational costs was estimated to be 20 percent greater than the
initial cost projection for the SCR. The change in visibility
improvement between the proposed BART emission rate (0.23 lbs
NOX/MMBtu) and the Unit 2 SCR scenario (0.08 lbs
NOX/MMBtu) was 0.082 dv for Upper Buffalo. The difference in
the cumulative improvement across all five Class I areas is 0.25 dv.
The annualized incremental cost of controls in this
[[Page 80758]]
scenario is $2,981,706, for an incremental cost per ton of $548.
---------------------------------------------------------------------------
\4\ BART Five Factor Analysis for Kansas City Power and Light La
Cygne Generating Station, prepared by Trinity Consultants, August
2007.
---------------------------------------------------------------------------
As with the Jeffrey units, overfire air was considered along with
LNB, so this combination of control technologies has already been
evaluated.
The annualized cost for SNCR control on Kansas City Power and Light
La Cygne Unit 2 was determined by using SNCR costs obtained from
Jeffrey Unit 1, and scaling the dollar amount using heat input and
NOX rates. The change in visibility improvement between the
proposed BART emissions rate (0.23 lbs NOX/MMBtu) and the
Unit 2 SNCR scenario (0.14 lbs NOX/MMBtu) is 0.044 dv for
Hercules Glades. The difference in the cumulative improvement across
all five Class I areas is 0.12 dv. The annualized incremental cost of
controls in this scenario is $972,747, for an incremental cost per ton
of $298.
The State concluded that the additional NOX reduction
costs are high for the associated low incremental visibility
improvements for La Cygne Units 1 and 2, and do not warrant changes to
the proposed BART controls. The BART Guidelines provide the State the
flexibility to determine the weight and significance of the five
factors. Although the costs appear to be reasonable on a cost per ton
basis, EPA has some concern with the scaling methodology utilized by
the State to arrive at cost estimates for the lower NOX
rates. However, given the low visibility improvements associated with
the additional control, EPA agrees it is reasonable to determine that
the costs of further control are not warranted and no changes to the
BART determinations or to the SIP are needed in response to this
comment.
EPA also notes that since the time of the State's BART
determinations and submission of the regional haze SIP, Kansas City
Power and Light applied for a permit to install SCR on La Cygne Unit 2.
The permit was effective March 16, 2011.\5\ In order for the permit to
remain valid, Kansas City Power and Light must commence construction
within 18 months of the permit's effective date (by September 2012).
---------------------------------------------------------------------------
\5\ Construction Permit issued to Kansas City Power and Light
Company for the La Cygne Generating Station. Permit effective March
16, 2011.
---------------------------------------------------------------------------
Comment #8: NPCA commented that while La Cygne Units 1 and 2 and
Jeffrey Units 1 and 2 have proposed to either install or upgrade
scrubbers at all four units to control SO2 emissions, the
State's analysis was incomplete in that it lacked an evaluation of the
most stringent emission limits the technology is capable of achieving.
NPCA claims that scrubbers, both wet and dry, are capable of emission
reductions below the proposed BART emission rates of 0.15 lbs/MMBtu at
Jeffrey and 0.10 lbs/MMBtu at La Cygne. NPCA suggests that scrubbers
are capable of achieving 0.03 to 0.05 lbs/MMBtu at each unit.
Response #8: The State's evaluation of the BART analysis for
Jeffrey Units 1 and 2 for SO2 resulted in the determination
that rebuilding the existing wet scrubber units and meeting a rate of
0.15 lbs/mmBtu was BART. The State did not believe that it was feasible
to achieve an emissions rate of 0.05 lbs/MMBtu with rebuilt technology,
so costs and visibility improvements were subsequently provided for the
installation of a new scrubber operating at 0.05 lbs/MMBtu for both
Jeffrey units. The State obtained annualized costs for new scrubbers on
Jeffrey Units 1 and 2 from Westar Energy. The change in visibility
improvement between the new wet scrubber scenario (0.05 lbs
SO2/MMBtu) and the proposed BART emission limit (0.15 lbs
SO2/MMBtu) for Jeffrey Unit 1 was 0.052 dv at Hercules
Glades. The difference in the cumulative improvement across all five
Class I areas is 0.168 dv. The annualized incremental cost of controls
in this scenario is $23,567,203, for an incremental cost per ton of
$6,635.
The differences for Jeffrey Unit 2 under these scenarios are
comparable to Unit 1--0.057 dv improvement at Hercules Glades, and
0.160 cumulatively. The annualized incremental cost of controls in this
scenario was $23,567,203, for an incremental cost per ton of $6,635.
The State concluded that the additional SO2 reduction
costs are high given the low incremental visibility improvements for
Jeffrey Units 1 and 2, and do not warrant changes to the proposed BART
emission rates. EPA has some concern with the assumptions used by the
State in arriving at the cost estimates, however, given the very low
visibility improvement modeled for the additional control, consistent
with the BART Guidelines which provide the State flexibility to
determine the weight and significance of the five factors, EPA agrees
it is reasonable to determine that the costs of further control are not
warranted and no changes to the BART determinations or to the SIP are
needed in response to this comment.
EPA also notes, as was referenced above, since the time of the
State's BART determinations and submission of the regional haze SIP,
Westar Energy, EPA and the State entered into a Federal Consent Decree
in resolution of alleged violations of the Clean Air Act. The Consent
Decree requires that Jeffrey Units 1 and 2 each meet a 30-day rolling
average unit removal efficiency for SO2 of at least 97
percent or a 30-day rolling average unit emission rate for
SO2 of 0.070 lbs/MMBtu. Therefore, following implementation
of the regional haze requirements and the Consent Decree, Jeffrey Units
1 and 2 will be well controlled for SO2.
The State's evaluation of the BART analysis for La Cygne Units 1
and 2 for SO2 resulted in the determination that a combined
emissions limit for both units at rate of 0.10 lbs/MMBtu was BART. Unit
1 has an existing scrubber that will be modified to separate the PM
control from the SO2 control resulting in increased
SO2 removal efficiency. Unit 2, which did not have an
existing scrubber, will be retrofitted with a new scrubber. The
combined BART emission rate chosen for SO2 controls is
within the range of expected removal efficiencies, considering one unit
is a retrofitted scrubber.
The State subsequently provided additional cost and visibility
information to further evaluate lower SO2 emission rates.
The State estimated the incremental annualized cost estimate to be 20
percent greater than the initial cost projection for the scrubber,
because of the increased electrical demand, raw material costs, and
maintenance costs associated with achieving a more stringent emissions
rate.
For the Unit 1 scrubber at La Cygne, the change in visibility
improvement from the presumptive BART emissions rate (0.15 lbs
SO2/MMBtu) to a lower rate (0.05 lbs SO2/mmBtu)
is 0.04 dv at Caney Creek. The difference in the cumulative improvement
across all five Class I areas for this scenario is 0.12 dv. The
annualized incremental cost of controls in this scenario is $6,098,239,
for an incremental cost per ton of $1,495. The La Cygne Unit 2 scrubber
scenario is comparable: 0.04 dv improvement at Hercules Glades, and
0.097 dv cumulative improvement. The annualized incremental cost of
controls in this scenario is $5,427,642, for an incremental cost per
ton of $1,495.
The State concluded that the additional SO2 reduction
costs are high given the associated low incremental visibility
improvements for La Cygne Units 1 and 2, and changes to the proposed
BART controls are not warranted. Although the costs appear to be
reasonable on a cost per ton basis, EPA has some concern with the
scaling methodology utilized by the State to arrive at the cost
estimates for the lower SO2 rate. However, given the low
additional visibility improvement, consistent with the BART Guidelines
[[Page 80759]]
which provide the State flexibility to determine the weight and
significance of the five factors, EPA agrees it is reasonable to
determine that the costs of further control are not warranted and no
changes to the BART determinations or to the SIP are needed in response
to this comment.
Comment #9: NPCA commented that the proposed SIP fails to address
cumulative impact of Kansas BART sources on all Class I areas impacted.
NPCA says that the modeling results presented in the proposed approval
do not provide for a determination of the cumulative impact from
Jeffrey Units 1 and 2 or La Cygne Units 1 and 2. NPCA notes that the
four BART units mentioned above impact nine Class I areas, but the
State only provided visibility information for five Class I areas.
Response #9: In order to keep the size of the modeling domain
manageable, the State chose to conduct refined modeling on the five
most impacted Class I areas. Given the level of the modeled impacts at
these five Class I areas, EPA does not believe that the State was
unreasonable in streamlining its modeling exercise to exclude the other
four Class I areas from its visibility analysis. Given the overall
modeled impacts at the most impacted Class I areas, taking into account
the impacts at the other four areas would have been unlikely to
significantly change the State's conclusions about BART emission
limits. Therefore, EPA believes that no changes to the BART
determinations or to the SIP are needed in response to this comment.
III. Final Action
EPA is taking final action to approve the State of Kansas' Regional
Haze SIP, submitted on November 9, 2009, with supplemental information
provided in December 2011, including a letter dated December 1, 2011,
in which the State withdrew specific SSM provisions of the regional
haze SIP from EPA's consideration. EPA finds that the Kansas regional
haze SIP submittal meets all of the applicable Regional Haze
requirements set forth in section 169A and 169B of the Act and in the
Federal regulations codified at 40 CFR 51.300-308, and the requirements
of 40 CFR Part 51, Subpart F and Appendix V.
IV. Statutory and Executive Order Reviews
Under the Clean Air Act, the Administrator is required to approve a
SIP submission that complies with the provisions of the Act and
applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a).
Thus, in reviewing SIP submissions, EPA's role is to approve State
choices, provided that they meet the criteria of the CAA. Accordingly,
this action merely approves State law as meeting Federal requirements
and does not impose additional requirements beyond those imposed by
State law. For that reason, this action:
Is not a ``significant regulatory action'' subject to
review by the Office of Management and Budget under Executive Order
12866 (58 FR 51735, October 4, 1993);
Does not impose an information collection burden under the
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
Is certified as not having a significant economic impact
on a substantial number of small entities under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.);
Does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4);
Does not have Federalism implications as specified in
Executive Order 13132 (64 FR 43255, August 10, 1999);
Is not an economically significant regulatory action based
on health or safety risks subject to Executive Order 13045 (62 FR
19885, April 23, 1997);
Is not a significant regulatory action subject to
Executive Order 13211 (66 FR 28355, May 22, 2001);
Is not subject to requirements of Section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272
note) because application of those requirements would be inconsistent
with the CAA; and
Does not provide EPA with the discretionary authority to
address, as appropriate, disproportionate human health or environmental
effects, using practicable and legally permissible methods, under
Executive Order 12898 (59 FR 7629, February 16, 1994).
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This rule does not have
tribal implications, as specified in Executive Order 13175. It will not
have substantial direct effects on tribal governments. Thus, Executive
Order 13175 does not apply to this rule.
List of Subjects in 40 CFR Part 52
Air pollution control, Environmental protection, Incorporation by
reference, Intergovernmental relations, Nitrogen oxides, Particulate
matter, Reporting and recordkeeping requirements, Sulfur dioxide,
Volatile organic compounds.
Dated: December 15, 2011.
Karl Brooks,
Regional Administrator, Region 7.
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 R--Kansas
0
2. In Sec. 52.870:
0
a. The table in paragraph (d) is amended by revising the table headings
and adding entries (3) and (4) in numerical order.
0
b. The table in paragraph (e) is amended by adding entry (33) in
numerical order.
The revisions and additions read as follows:
Sec. 52.870 Identification of plan.
* * * * *
(d) * * *
EPA--Approved Kansas Source--Specific Requirements
----------------------------------------------------------------------------------------------------------------
State
Name of source Permit or effective EPA approval date Explanation
case No. date
----------------------------------------------------------------------------------------------------------------
* * * * * * *
(3) Kansas City Power and Light .............. 12/5/07 12/27/11, [Insert Certain provisions
Company. Federal Register withdrawn from plan
citation]. as identified in
letter dated 12/1/11
from Kansas.
[[Page 80760]]
(4) Westar Energy, Inc............ .............. 2/29/08 12/27/11, [Insert Certain provisions
Federal Register withdrawn from plan
citation]. as identified in
letter dated 12/1/11
from Kansas.
* * * * * * *
----------------------------------------------------------------------------------------------------------------
* * * * *
(e) * * *
EPA--Approved Kansas Nonregulatory Provisions
----------------------------------------------------------------------------------------------------------------
Applicable
Name of nonregulatory SIP geographic or State EPA approval date Explanation
provision nonattainment area submittal date
----------------------------------------------------------------------------------------------------------------
* * * * * * *
(33) Regional Haze Plan for the Statewide.......... 11/9/09 12/27/11, [Insert Certain provisions
first implementation period. Federal Register withdrawn from
citation]. plan as identified
in letter dated 12/
1/11 from Kansas.
----------------------------------------------------------------------------------------------------------------
[FR Doc. 2011-32998 Filed 12-23-11; 8:45 am]
BILLING CODE 6560-50-P
