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 Significant deterioration of air 

quality. 

(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: 

§ 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). 

* * * * * 

■ 5. Section 52.1990 is added to read as 

follows: 

§ 52.1990 Interstate Transport for the 2006 

24-hour PM2.5 NAAQS. 

(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] 

[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 

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 http:// 

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 http:// 

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 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: 

Facility Unit 

2002 NOX

Emissions 

(tpy) 

2002 SO2

Emissions 

(tpy) 

Post control 

NOX

(tpy) 

Post control 

SO2

(tpy) 

NOX

Reductions 

(tpy) 

SO2

Reductions 

(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 


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80756 Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations 

1Steven 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). 

2 40 CFR part 51, Appendix Y: Guidelines for 

BART Determinations Under the Regional Haze 

Rule. 

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. 

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. 

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 


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Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations 80757 

3United States and Kansas v. Westar Energy, Inc., 

Civil Action No. 09–CV–2059 JAR/DJW (D. Kan. 

March 26, 2010). 

4BART Five Factor Analysis for Kansas City 

Power and Light La Cygne Generating Station, 

prepared by Trinity Consultants, August 2007. 

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 

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 


erowe on DSK2VPTVN1PROD with RULES
80758 Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations 

5Construction Permit issued to Kansas City 

Power and Light Company for the La Cygne 

Generating Station. Permit effective March 16, 2011. 

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 

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 


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Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations 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] 

■ 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

Name of source Permit or 

case No. 

State 

effective 

date 

EPA approval date Explanation 

*******

(3) Kansas City Power and Light 

Company.

........................ 12/5/07 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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80760 Federal Register / Vol. 76, No. 248 / Tuesday, December 27, 2011 / Rules and Regulations 

EPA—APPROVED KANSAS SOURCE—SPECIFIC REQUIREMENTS—Continued 

Name of source Permit or 

case No. 

State 

effective 

date 

EPA approval date Explanation 

(4) Westar Energy, Inc .................... ........................ 2/29/08 12/27/11, [Insert Federal Register 

citation].

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 Explanation 

*******

(33) Regional Haze Plan for 

the first implementation period.

Statewide ............................... 11/9/09 12/27/11, [Insert Federal 

Register citation].

Certain provisions withdrawn 

from 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 

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 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: 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 

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. 

DATES: This final rule is effective on 

January 26, 2012. 

ADDRESSES: 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 http://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 

http://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 

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 fuelVerDate Mar<15>2010 14:56 Dec 23, 2011 Jkt 226001 PO 00000 Frm 00032 Fmt 4700 Sfmt 4700 E:\FR\FM\27DER1.SGM 27DER1

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