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DOCKET NUMBER EPA-HQ-OAR-2009-0491

Response to Comments on the Proposed 

 

Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone 

77 FR 10350; February 21, 2012 
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Table of Contents 

1. American Electric Power (AEP) .......................................................................... 3

2. ARIPPA ............................................................................................................... 9

3. Florida Electric Power Coordinating Group (FCG) ............................................ 29

4. MEAG Power .................................................................................................... 33

5. Wisconsin Department of Natural Resources ................................................... 38

6. Duke Energy ..................................................................................................... 42

7. Georgia Department of Natural Resources ....................................................... 46

8. Luminant ........................................................................................................... 48

9. Utility Air Regulatory Group (UARG) ................................................................. 49

10. Earth Justice ................................................................................................... 56

11. Georgia Power ................................................................................................ 60

12. GenOn ............................................................................................................. 63
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1. American Electric Power (AEP) 

[Letter: American Electric Power (EPA-HQ-OAR-2009-0491-4975)] 

COMMENT: The corrections to adjust for emissions controls not in-service, incorrect control 

removal efficiency, units unavailable for operation, new units in-service and units needed to 

support grid operation are all necessary corrections to the final rule. AEP supports all of the 

corrections identified in the direct final rule. Many were based on errors identified by AEP and 

directly impact the state budgets where AEP’s facilities are located. 

RESPONSE: EPA acknowledges AEP’s general support for the revisions made in the direct final 

rule. 

COMMENT: In addition to the corrections already proposed by EPA, AEP previously identified 

within its comments on the Technical Revisions a number of other technical corrections and/or 

adjustments that should be made to address other situations in which modeled emissions do not 

reflect the actual operation of the power system. The proposed corrections identified by AEP are 

related to low NOX burners, biomass, coal sourcing, and FGD and DSI installations contained in 

the modeled policy case. These proposed corrections were not addressed or acknowledged by 

EPA either within the Final Revisions rule or the Direct Final Rule, leaving state emission 

budgets still woefully inadequate to support appropriate levels of cost-effectiveness and 

reliability. 

The process of promulgating a direct final rule that includes some limited revisions without 

acknowledging the other broader issues and significant inadequacies identified by individual 

commenters further perpetuates a fundamentally flawed rule. AEP requests that EPA recognize 

and respond to these broader issues and correct its models to account for these fundamental flaws 

before finalizing the CSAPR program. 

AEP previously identified several additional assumptions or projections that are equally 

inaccurate, and for which an appropriate remedy would be to increase the state budgets in 2012 

and/or 2014. These comments were not addressed by EPA in the Final Revisions Rule or in the 

Direct Final Rule. AEP again requests that EPA directly address these corrections. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012 (77 FR 10350). The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA did in fact consider and respond to AEP’s comments and notes that these comments are 

almost verbatim to those prior comments (see Response to Comments on the Proposed Revisions 
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to FIPs to Reduce Interstate Transport of Fine PM and Ozone; EPA-HQ-OAR-2009-0491-4963 

and the responses below). EPA notes that not all comments received warranted revisions to state 

budgets or allocations. 

COMMENT: A. Low NOX Burners 

EPA assumes that a significant number of Low NOX Burner (LNBs) installations could occur by 

2012 within the CSAPR policy case. As a result of this assumption, annual NOX emissions are 

reduced by 22,199 tons and seasonal NOX emissions are reduced by 14,804 tons (EPA-HQOAR-2009-0491-4302) relative to the base case. However, completing LNB installations on this 

large number of units by 2012 is technically infeasible due to permitting issues, equipment 

availability, and construction scheduling issues stemming from such a short-time frame until 

implementation. EPA has since recognized this technical infeasibility in Final Supplemental 

Action on the Cross-State Air Pollution Rule and subsequently adjusted the 2012 Ozone Season 

NOX budget in Oklahoma. 

 

However, EPA has not addressed AEP’s previous comment that the installation of this 

equipment on certain units represents a cost far in excess of the cost-effectiveness thresholds 

used to establish the state-level budgets. For example, among the units projected to install new 

LNBs were Northeastern Units 3-4 in Oklahoma. Using EPA’s data, AEP calculated the 

approximate levelized cost of removal for this project at greater than $1800/ton (see table). This 

indicates that these controls would not be cost effective at the $500/ton threshold established by 

EPA for seasonal NOX reductions. While the calculations shown in the table are for Northeastern 

3, its sister unit, Northeastern 4, has almost identical operating characteristics and thus the cost of 

removal is very similar. 

 

The high cost of these NOX reductions, in addition to the previously mentioned timing issues, 

indicates that this project should never have been included in the policy case as it is not costeffective. Accordingly, if EPA finalizes the supplemental proposal, the emission reductions 

associated with these retrofits, 1,749 tons of seasonal NOX, should be added back into the 

Oklahoma state budget. 1,749 tons represents the difference in seasonal NOX emissions between 

the base case and the policy case exclusively for Northeastern Units 3 and 4. Furthermore, AEP 

requests that EPA carefully review the cost-effectiveness calculations for all LNB projects 

included in the 2012 policy case as it is not readily apparent that they meet the cost effectiveness 

threshold established by EPA. 

 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012 (77 FR 10350). The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 
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EPA previously responded to a similar comment, particularly the LNB installation at 

Northeastern 3 and 4. See page 71 of “Response to Comments on the Proposed Revisions to FIPs 

to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963), as 

well as section VII of the final Transport Rule preamble (76 FR 48208, August 8, 2011) for a 

discussion of the feasibility of LNB installation and 2012 compliance. The Supplemental Notice 

of Final Rulemaking describes the unique circumstances regarding the timing of Oklahoma’s 

inclusion in the Transport Rule: “Because of the timing of this final action, the units in 

Oklahoma would have to shut down to install the LNBs during the ozone season—the summer 

peak demand period for electricity in Oklahoma... EPA’s policy case modeling suggests that this 

reduction in available capacity could shift this subregion below its assured planning reserve 

margin” (76 FR 80765). No such situation applies to any other state under the Transport Rule, all 

of whom had at least 6 months of notification from signature of a final action to the scheduled 

commencement of the first Transport Rule control period, and several months in addition before 

peak electricity demand periods in those states, allowing adequate time for LNB installations as 

supported by the Agency’s analysis and the Transport Rule’s record (see “Installation Timing for 

Low NOX Burners,” EPA-HQ-OAR-2009-0491-0051). 

Even though it is outside of the scope of this action, in further response, looking at the 

commenter’s calculations, the assumption of $33/KW used by the commenter appears incorrect. 

$33/KW is the capital cost value in the documentation prescribed for the complete installation of 

LNC 2 (Low NOX Coal-and-Air nozzles with separated overfire air) at a unit. However, the 

Northeastern unit being addressed by commenter is not making such a new LNC2 installation. 

Rather, the Northeastern upgrade is from existing LNC1 (Low NOX Coal-and-Air nozzles with 

close-coupled overfire air) to LNC 3 (Low NOX Coal-and-Air nozzles with close-coupled and 

separated overfire air), at a much lower cost of $14/kW. The commenter similarly mistakenly 

assumed the entire O&M cost for LNC2, not the difference between the O&M costs of LNC3 

and LNC1. Therefore, in assuming the cost of a new installation instead of the incremental cost 

of an upgrade in its calculation, the commenter has significantly overestimated the expected cost. 

 

Finally, the IPM modeling is very consistent with the historic behavior observed in the power 

sector. When faced with any economic incentive to reduce NOX emissions, LNB installation or 

upgrade has consistently been one of the first and least costly abatement strategies; nearly all of 

the units in the Transport Rule states that were also under CAIR or NOX SIP call have previously 

adopted these emission reduction strategies. EPA believes it is entirely reasonable to expect that 

states entering a federal control program for NOX for the first time (e.g., Oklahoma) will have an 

incentive to pursue similar behavior. Moreover, commenters have confirmed that many of the 

LNB installations, upgrades, and emission reductions assumed in the policy scenario are indeed 

already planned or under construction due to various state rules, consent decrees or regional haze 

efforts. ([EPA-HQ-OAR-2009-0491-2606.1, p.5], [EPA-HQ-OAR-2009-0491-3886],[EPA-HQOAR-2009-0491-4600]). 

COMMENT: B. Biomass 

 

AEP also recommends a technical correction be made to the state budgets based on the use of 

biomass within coal fired facilities. AEP noted in its petition for reconsideration that the IPM 
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outputs for the 2012 final remedy case for Cardinal 3, Clifty Creek 1-6, Clinch River 1-3, 

Conesville 3, Glen Lyn 5-6, Kammer 1-3, Kanawha River 1-2, Muskingum River 3-5, 

Oklaunion, Spom 1-4, Rockport 1-2, Tanners Creek 1-4 and Beckjord 6 all have some 

‘“missing" coal heat input which is described by EPA as “other fuel". AEP Request for 

Reconsideration and Stay, pp. 17-18 (October 3, 2011). It is our understanding that this "other 

fuel" is biomass in most cases. As noted in the request for reconsideration, none of these units 

currently have a reliable source of biomass fuel, they have not been permitted to burn biomass by 

the state regulatory authorities, nor have they implemented any physical improvements to allow 

proper handling of these materials. Id. The provided table shows the incremental allocations that 

should be made to eliminate the emission reductions associated with the use of biomass at these 

units, amounting to 11,536 tons SO2 emissions that should be reestablished in state budgets for 

the 2012-2013 compliance years. 

 

Though AEP cannot positively assert that biomass cannot be utilized in units outside of 

its control, AEP’s experience is similar to that of other utilities with whom this issue has been 

discussed. Accordingly, AEP suggests that unless EPA has affirmative evidence that biomass has 

been approved as fuel for a particular unit, that there is a reliable and ample supply of biomass 

available and that a unit has actual experience utilizing biomass as fuel, no assumption should be 

made that these units will be equipped to burn or permitted to burn biomass in 2012 and beyond. 

Based on IPM’s projected total biomass use at coal-fired units of 240 TBtu, AEP calculates that 

up to 47,000 tons of SO2 emissions should be restored to state budgets based on these erroneous 

assumptions. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA previously responded to this comment. See page 72 of “Response to Comments on the 

Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963) 

COMMENT: C. Coal Sourcing 

 

Several units within Indiana in which AEP has an ownership interest, Clifty Creek Units 

1-6 and Rockport Units 1-2, are projected to utilize 100% subbituminous coal in the 2012 policy 

case. As noted in AEP’s request for reconsideration, this result is based on an erroneous 

determination that these units have recently utilized 100% subbituminous coal blends. AEP 

Request for Reconsideration and Stay, pp. 16-17 (October 3, 2011). Historically, these units have 

burned coal blends that include just 75% subbituminous and 85% subbituminous coals, 
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respectively. Additionally, Cardinal unit 3 is also projected to use 100% PRB coal, however it 

current maximum blend ratio is 20%. Based on existing coal supply contracts, safety 

considerations that arise with higher ratios of low sulfur coal and other operational limitations 

that may impede higher blending ratios, AEP recommends that the existing blending ratios 

should be retained as a basis for calculating state budgets during the 2012 and 2013 compliance 

years. 

 

In addition to incorrect blends of subbituminous coal being projected for the Rockport 

units 1-2, Clifty Creek units 1-6 and Cardinal unit 3, these units also are projected to use very 

low sulfur subbituminous coal in the 2012 policy case for 100% of their coal use. As noted in 

AEP’s petition for reconsideration, this coal is only produced from a select number of mines in 

Wyoming and Montana and AEP questions whether the assumption in the 2012 policy case 

showing a 20% increase in production is technically feasible. AEP Request for Reconsideration 

and Stay, pp. 13-16 (October 3, 2011). A more reasonable technical assumption is that units 

could only rely on this very low-sulfur subbituminous coal in 2012 to the extent they have used it 

historically, due to production, contractual and transportation issues. The provided table contains 

the approximate 2011 use of very low sulfur coal at the aforementioned units and recommended 

changes to emission budgets based on the very limited availability of this very low sulfur fuel 

and AEP’s recommendation to keep the blend ratios at historic levels. 

 

AEP recommends that EPA follow similar logic for the rest of the United States and assume that 

incremental fuel switching to very low sulfur coals could not occur by 2012. 

According to IPM data, the policy case assumes an additional 694 TBtu of very low sulfur 

subbituminous coal could be produced by next year and delivered for use at generating stations 

all over the region. Based on our experience, significant increases in production of this coal 

cannot occur by next year, it is most likely that a much broader range of low sulfur 

subbituminous coals will be utilized. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. (77 FR 10350) The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA previously responded to this comment. See pages 203-204 of “Response to Comments on 

the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPAHQ-OAR-2009-0491-4963). 

Additionally, EPA notes that the commenter’s analysis of low-sulfur coal use is flawed. While 

the use of low-sulfur coal, which is produced almost entirely in the Powder River Basin (PRB), 

increases roughly 700 TBtu (equivalent to about 40 million tons) between EPA’s Base Case and 
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Remedy Case in 2012, the commenter does not consider how EPA’s projected coal use compares 

to recent PRB coal production. Comparing 2010 actual production of very low sulfur coal from 

the PRB to EPA’s 2012 Base Case and 2012 Remedy Case, shows that 462 million tons were 

produced in 2010, compared to 238 million tons in the Base Case and 278 tons in the Remedy 

Case. This data shows that the level of PRB coal production projected in IPM is readily 

achievable by the industry. 

COMMENT: D. FGD and DSI Installations 

 

A number of AEP units are projected to be retrofit with either flue gas desulfurization 

systems (FGDs) or dry sorbent injection (DSI) in the 2014 policy case. As stated in AEP’s 

Petition for Reconsideration, AEP does not believe that it is technically feasible to install FGDs 

by 2014 unless they are already under construction. AEP Request for Reconsideration and Stay, 

pp. 19-20 (October 3, 2011). Particularly with respect to AEP’s units, AEP has not received the 

necessary regulatory approvals for any of the projects. Regulatory approval is a pre-requisite to 

detailed engineering and procurement, which precedes the construction phase. Additionally, AEP 

has no operational experience using DSI for SO2 reductions, and the U.S. power industry as a 

whole has little experience using this technology to achieve emission reductions of the 

magnitude assumed in the IPM modeling. As noted in AEP’s petition for reconsideration, none 

of the AEP units identified in the IPM runs are currently anticipated to be equipped with DSI 

technology. AEP Request for Reconsideration and Stay, p. 18 (October 3, 2011). Without unit 

specific testing and technology validation, EPA has not made a sufficient record to justify 

including DSI as a universally available solution. AEP requests the technical corrections in the 

provided tables be made to the 2014 state SO2 budgets based on the unavailability of the FGD 

and DSI technology. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA previously responded to this comment. See page 71 -72 of “Response to Comments on the 

Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone.” (EPA-HQOAR-2009-0491-4963) Also see page 55 of “Documentation Supplement for USEPA Base Case 

v.4.10_FTransport - Updates for Final Transport Rule” (EPA-HQ-OAR-2009-0491-4385) for 

background on EPA’s inclusion of DSI as a retrofit option in IPM v.4.10_FTransport. 

Additionally, EPA discusses the commercial viability and reliability of using DSI to control acid 

gas emissions, including SO2, in the final rule “National Emission Standards for Hazardous Air 

Pollutants From Coal and Oil-Fired Electric Utility Steam Generating Units and Standards of 
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Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and 

Small Industrial-Commercial-Institutional Steam Generating Units.” (77 FR 9411) 

COMMENT: E. Turk Plant 

 

While AEP appreciates the inclusion of the Turk Plant into the Arkansas new unit set- aside 

ozone season NOX budget beginning in 2014, the unit is planned for startup in late 2012. The 

subject rule identified the increase in the new unit set-aside ozone season NOX budget to begin in 

2014 since the allocations were already distributed for 2012 and 2013. With the stay of this rule 

and the continuation of the CAIR rule, these allocations are no longer distributed for use until the 

stay is lifted. As such, AEP requests that US EPA make adjustments in the 2012 and 2013 

Arkansas new unit set-aside ozone season NOX budget to account for the projected start-up of the 

Turk Plant beginning in late 2012. 

RESPONSE: See section 5.1 of the Preamble for this rulemaking for EPA’s response to 

comments on Turk Unit 1. 

2. ARIPPA 

[Letter: ARIPPA (EPA-HQ-OAR-2009-0491-4981)] 

COMMENT: I. Introduction 

 

In August 2011, EPA promulgated the final rule “Federal Implementation Plans: 

Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals", for 

the “Cross-State Air Pollution Rule" (herein "CSAPR"). 76 Fed. Reg. 48,208 (Aug. 8, 2011) (to 

be codified at 40 C.F.R. pts. 51, 52, 72, 78, and 97).1 In October 2011, EPA issued a proposed 

rule, entitled "Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone", to correct errors in CSAPR related to EPA's calculation of certain 

state emission budgets and unit-specific allowance allocations under CSAPR (the "Proposed 

Errors Rule"). 76 Fed. Reg. 63,860 (proposed Oct. 14, 2011) (to be codified at 40 C.F.R. pts. 52 

and 97). ARIPPA submitted comments to EPA on the Proposed Errors Rule in November 2011. 

EPA finalized the Proposed Errors Rule on February 21, 2012. 77 Fed. Reg. 10,324. 

 

On February 21, 2012, EPA published in the Federal Register a proposed rule to make additional 

revisions to certain portions of CSAPR, based on information EPA received in response to the 

Proposed Errors Rule (the "Proposed Supplemental CSAPR Revision Rule"). 77 Fed. Reg. 

10,350 (to be codified at 40 C.F.R. pt. 97). Simultaneously with its issuance of the Proposed 

Supplement CSAPR Revision Rule, EPA took direct final action on its proposed additional 

revisions to CSAPR by publishing a direct final rule in the Federal Register (the "Direct Final 

 

1

 ARIPPA filed a Petition for Reconsideration of CSAPR with EPA in October 2011. ARIPPA's Petition for

Reconsideration included certain analyses, which are specifically referenced in these comments. In 

addition to its Petition for Reconsideration, ARIPPA filed a Petition for Review of CSAPR with the United 

States Court of Appeals for the D.C. Circuit to preserve its rights to seek judicial review of the rule. 
FIP Revisions – RTC 

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Supplemental CSAPR Revision Rule"). 77 Fed. Reg. 10,342 (to be codified at 40 CFR. Part 97).2 

Both the Proposed Supplemental CSAPR Revision Rule and the Direct Final Supplemental 

CSAPR Revision Rule are entitled "Revisions to Federal Implementation Plans to Reduce 

Interstate Transport of Fine Particulate Matter and Ozone". 

 

Both the Proposed Supplemental CSAPR Revision Rule and the Direct Final Supplemental 

CSAPR Revision Rule direct interested parties to submit comments on these rulemaking actions 

to EPA's Air and Radiation Docket, Docket ID No. EPA-HQ- OAR-2009-0491. 77 Fed. Reg. 

10,350, 10,342. ARIPPA hereby submits these comments on both the Proposed Supplemental 

CSAPR Revision Rule and the Direct Final Supplemental CSAPR Revision Rule, which shall 

hereinafter be referred to collectively as the "Proposed and Direct Final Supplemental CSAPR 

Revision Rules". ARIPPA appreciates this opportunity to comment. 

 

EPA expressly stated that, through the Proposed Errors Rule, EPA sought to implement 

“technical fixes [to] maintain [CSAPR’s] ability to achieve the elimination of significant 

contribution and interference with maintenance as quantified by the proper application of these 

methodologies” 76 Fed. Reg. 63,861. According to EPA, the "changes [in the Proposed Errors 

Rule] represent the proper application of the methodology established in [CSAPR]." 76 Fed. 

Reg. 63,862. EPA further stated that it intended, through the Proposed Errors Rule, "to conduct a 

. . . process by which any similarly justified revisions to the [CSAPR] state budgets are identified 

and effectuated in a timely and expeditious manner." 76 Fed. Reg. 63,863. 

Consistent with EPA’s stated objectives for the Proposed Errors Rule, ARIPPA submitted 

comments on that rulemaking action to EPA. Among other things, ARIPPA commented that 

EPA should recognize the need to implement changes to CSAPR in order to consistently 

implement EPA's stated methodology for CSAPR, and therefore correct EPA's incorrect 

determination that SO2 emissions from ARIPPA‘s coal refuse-fired circulating fluidized bed 

("CFB") boilers can be cost-effectively controlled. As explained in detail below, because 

ARIPPA’s CFB units cannot be cost-effectively controlled in a manner relevant to CSAPR, such 

units do not significantly contribute to downwind nonattainment and, therefore, should not be 

regulated under CSAPR. Notwithstanding the relevance of ARIPPA’s comments to EPA's stated 

objectives with respect to the Proposed Errors Rule, EPA failed to address, or even adequately 

consider, ARIPPA’s comments in the final version of the Proposed Errors Rule. 

 

According to EPA, the purpose of the Proposed and Direct Final Supplemental CSAPR Revision 

Rules is to make "additional corrections" to CSAPR that "are needed as a result of comments 

received on the [Proposed Errors Rule]." 77 Fed. Reg. 10,343. EPA has therefore determined 

that, even with the corrections implemented through the now-final Errors Rule, CSAPR still fails 

to fully implement the proper application of the methodologies established by EPA in the 

regulation. Consequently, EPA recognizes that additional revisions — beyond those identified in 

the Errors Rule - are necessary to fully implement required "technical fixes" to the rule, and to 

 

2

 EPA explains that if it "receives adverse comment" on the direct final rule, EPA "will publish a timely withdrawal 

in the Federal Register informing the public that this direct final rule will not take effect." 77 Fed. Reg. 10,324. 
FIP Revisions – RTC 

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ensure consistency with EPA’s primary regulatory objectives of elimination of significant 

contribution and proper application of the methodologies underlying CSAPR. However, the 

Proposed and Direct Final Supplemental CSPR Revision Rules fails to fulfill, or even 

demonstrate consistency with, EPA’s stated purpose for this rulemaking action, because the 

rulemaking does not address the comments ARIPPA provided in response to the Proposed Errors 

Rule. Therefore, EPA errs in stating that it "has calculated the corrections in this rulemaking in a 

fully consistent manner with the approach developed through public comment on the [Proposed 

Errors Rule] and finalized revisions rule." 77 Fed. Reg. 10,343. 

 

Accordingly, ARIPPA is providing the following comments on the Proposed and Direct Final 

Supplemental CSAPR Revision Rules, which go directly to EPA’s objective for this rulemaking 

action of making additional corrections to CSAPR to ensure that the regulation represents the 

proper application of the methodologies established by EPA under CSAPR. These comments 

reflect that- as to ARlPPA’s coal refuse-fired CFB units - EPA did not correctly apply its stated 

methodology for implementing CSAPR. As ARIPPA demonstrates below, if EPA had applied its 

methodology correctly, then the ARIPPA boilers would be excluded from regulation under 

CSAPR on the basis that it is neither technologically feasible nor (as EPA has separately 

acknowledged) cost effective for the ARIPPA plants to further reduce SO2 emissions from their 

CFB units. Moreover, the aggregate emissions from the ARIPPA plants comprise a de minimis 

fraction of the SO2 emissions from sources regulated under CSAPR; accordingly, the underlying 

objectives of CSAPR would not be compromised if the ARIPPA plants’ CFB units were 

excluded from regulation under CSAPR. 

 

Therefore, in order to implement the remaining "technical fixes" necessary to achieve both the 

elimination of "significant contribution", as defined by EPA for purposes of CSAPR, and the 

proper application of the methodologies devised by EPA under the rule, the Agency should 

further revise CSAPR to exclude coal refuse-fired CFB combustion units from the applicability 

provisions of the regulation. 

To the extent that EPA determines not to exclude the ARIPPA plants from regulation under 

CSAPR, EPA should ensure that the allocation of allowances to the ARIPPA units is consistent 

with the methodology identified by EPA under CSAPR. Specifically, the allowance allocations 

should reflect the emission levels for the plants after consideration of the application of costeffective controls. Because, as EPA has separately concluded, cost-effective controls are not 

available to further reduce SO2 emissions from existing coal refuse-fired CFBs,3

 the allowance 

allocations for such sources should be consistent with established emission rates. Of course, such 

adjustment to the unit-specific allocations for such sources must be directly reflected in EPA‘s 

federal implementation plan and result in a corresponding increase in the states' SO2 allowance 

budgets. 

 

 

3

 Indeed, the combustion units operated by the ARIPPA members reflect a fundamentally different design in which 

SO2 emission control is achieved in the combustion chamber, resulting in substantially lower emissions from the 

combustion zone than conventional coal-fired EGUs. 
FIP Revisions – RTC 

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Page 12 

For the reasons discussed below, ARIPPA specifically objects to the Proposed and Direct Final 

Supplemental CSAPR Revision Rules because EPA has failed through such rulemaking effort to 

properly revise CSAPR in a manner consistent with EPA‘s stated objectives for both the final 

Errors Rule and the Proposed and Direct Final Supplemental CSAPR Revision Rules. Instead, 

EPA should use the current rulemaking vehicle of the Proposed and Direct Final Supplemental 

CSAPR Revision Rules to make the necessary revisions to CSAPR to reflect the proper 

application of the methodologies established by EPA to the ARIPPA CFB boilers. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

As explained in greater detail below, the commenter’s first argument is a comment on the 

applicability provisions established in the final Transport Rule and the commenter’s second 

argument is a comment on the methodology used in the final Transport Rule Federal 

Implementation Plans (FIPs) to allocate allowances to existing sources. EPA provided ample 

opportunity to comment on both issues during the rulemaking process for the Transport Rule and 

has neither proposed any revisions to those provisions nor reopened them for additional public 

comment in this rulemaking. Comments on these issues are outside the scope of and not relevant 

to this rulemaking. Furthermore, the commenter alleges that “the [allowance allocation] 

methodology identified by EPA under CSAPR... should reflect the emission levels for the 

[ARIPPA] plants after consideration of the application of cost-effective controls.” This 

interpretation has no basis in the record of the final Transport Rule. The Agency has clearly 

explained that allowance allocations to existing units under the final Transport Rule are based on 

a combination of historic heat input and historic emissions data. Therefore, even if the Agency 

were considering unit-level allowance allocations in this action, the commenter has provided no 

information on which the Agency would find any basis to make revisions. 

Contrary to the commenter’s assertion, EPA considered and addressed ARIPPA’s comments on 

the proposed TR revisions rule, “Revisions to Federal Implementation Plans To Reduce 

Interstate Transport of Fine Particulate Matter and Ozone” (76 FR 63860; October 14, 2011). 

EPA responded to the substance of ARIPPA’s comments in the response to comments (RTC) 

document for that proposal, entitled, “Response to Comments on the Proposed Revisions to FIPs 

to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963). See 

further discussion below. 

COMMENT: II. Background 

 
FIP Revisions – RTC 

June 5, 2012 

Page 13 

Organized in 1988, ARIPPA is a non-profit trade association based in Camp Hill, Pennsylvania. 

Its membership is comprised of electric generating plants, producing alternative electrical energy 

and/or steam. Most ARIPPA member plants are currently located in or near the anthracite or 

bituminous coal regions of the United States. 

ARIPPA plants are designed and operated to convert large quantities of coal refuse into 

alternative electricity, sewing the energy needs of hundreds of thousands of households and 

businesses. Member plants generate electricity using environmentally- friendly CFB boiler 

technology to convert coal refuse and/or other alternative fuels such as biomass into alternative 

energy and steam. Indeed, the fundamental purpose of the ARIPPA plants is to combust coal 

refuse material in order to reclaim abandoned lands, while generating alternative energy. 

Moreover, the industry addresses the severe environmental threat posed by coal refuse without 

shifting such costs to public sources. 

 

The environmental benefits of the combustion of coal refuse have been recognized by EPA, the 

Pennsylvania Department of Environmental Protection (“PADEP"), and the Office of Surface 

Mining Reclamation and Enforcement alike. In particular, EPA recently recognized the 

environmental benefits provided by coal refuse-fired plants in the context of its proposed 

"National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric 

Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric 

Utility, Industrial—Commercial-Institutional, and Small Industrial-Commercial-Institutional 

Steam Generating Units", 76 Fed. Reg. 24,976 (the "Proposed Utility MACT and NSPS"), 

stating that "[u]nits that burn coal refuse provide multimedia environmental benefits by 

combining the production of energy with the removal of coal refuse piles and by reclaiming land 

for productive use. Consequently, because of the unique environmental benefits that coal refusefired EGUs provide, these units warrant special consideration,... " 76 Fed. Reg. 25,066. 

 

With this background in mind, ARIPPA requests that the Agency consider the following 

comments on the Proposed and Direct Final Supplemental CSAPR Revision Rules below. 

ARIPPA’s comments are offered specifically on behalf of the ARIPPA member plants. ARIPPA 

is aware of a small number of additional coal-refuse fired facilities which are identified as 

affected sources under CSAPR. Although ARlPPA’s comments may extend equally to such few 

additional sources, ARIPPA does not have sufficient information to represent the accuracy or 

applicability of these comments as applied to such units. 

RESPONSE: As noted above, comments on applicability provisions of the Transport Rule are 

outside the scope of this rulemaking. In this rule, EPA is taking final action on the revisions 

proposed on February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It 

proposed to determine that the unit-level adjustments described in the preamble to the direct final 

(77 FR 10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments 

included in the direct final rule and did not reopen any other issues for comment. In sum, and as 

explained in greater detail on page 54 of this RTC, comments such as these, which relate to 

issues other than the adjustments proposed in the February 21, 2012 parallel proposal, are outside 

the scope of and not relevant to this final action. 
FIP Revisions – RTC 

June 5, 2012 

Page 14 

Further, the language that the commenter cites (76 Fed. Reg. 25066) appears in a separate 

unrelated rulemaking, speaks only to the how coal refuse-fired EGUs should be treated in that 

rule, and is not relevant to the question of whether ARIPPA facilities warrant special 

consideration in the Transport Rule. Further the commenter’s excerpt is incomplete. It excludes 

the second half of the sentence which emphasizes the limited nature of the statement and the 

context in which it was made. An NSPS determines specific control levels for new (which is 

defined to include modified, and reconstructed) individual emission sources. In contrast, the 

Transport Rule determines state-level emission requirements and provides individual sources 

with substantial compliance flexibility, including the trading of emissions allowances. As such, 

the commenter is inappropriately and incorrectly characterizing an EPA statement regarding the 

Agency’s consideration of sources under a separate, different, and unrelated regulatory 

obligation, as being somehow relevant to the Transport Rule when there is in fact no relevance 

here. 

EPA observes that the commenter’s request is unusual in that the scope of the request is defined 

according to membership in a trade association rather than by type of unit. EPA believes that 

treating these sources differently from other sources on the basis of their membership in a trade 

association would be inappropriate; however, this point is rendered moot in this context because 

the comment in no way addressed the adjustments proposed by the agency on February 21, 2012 

and thus outside the scope of the rulemaking. 

COMMENT: III. Specific Comments 

 

A. CSAPR should not apply to ARIPPA’s coal refuse-fired CFB boilers, because EPA has not 

justified a finding of significant contribution as to these units. 

 

In the context of the Proposed Errors Rule, EPA requested comments on its revised calculation 

of allowance allocations for specific states and source types, particularly in reference to errors or 

inconsistencies relative to EPA's analysis in promulgating the final CSAPR regulation. EPA 

expressly noted its objective of implementing "technical fixes [to] maintain [CSAPR's] ability to 

achieve the elimination of significant contribution and interference with maintenance as 

quantified by the proper application of these methodologies." 76 Fed. Reg. 63861. Based on 

comments it received in response to the Proposed Errors Rule, EPA has determined that it is 

necessary to implement additional corrections to CSAPR in order to satisfy the Agency’s stated 

objective for the Proposed Errors Rule - i.e., to ensure CSAPR's ability to achieve the 

elimination of significant contribution though the proper application of the methodologies 

established by EPA. EPA intends to implement these additional corrections through the Proposed 

and Direct Final Supplemental CSAPR Revision Rules. 

Consistent with EPA’s stated purpose for the Proposed and Direct Final Supplemental CSAPR 

Revision Rules, ARIPPA requests that the Agency further revise CSAPR to ensure that the 

identification of affected sources, and allocation of allowances to such sources, is consistent with 

the methodology employed by the Agency in evaluating the extent of "significant contribution" 

relevant to this regulatory scheme. 

 
FIP Revisions – RTC 

June 5, 2012 

Page 15 

In developing an approach for controlling emissions under CSAPR, EPA concluded that the 

objectives of the rule would most cost-effectively be achieved by regulating only a single 

category of sources - EGUs. In the preamble to CSAPR, EPA explains that "[al]though the cost 

curves presented in [the final] rule only include EGU reductions, EPA also assessed the cost of 

SO2 and NOX emission reductions available for source categories other than EGUs in the 

proposed rulemaking. This preliminary assessment in the rule proposal suggested that there 

likely would not be very large emission reductions available from EGUs before costs reach the 

point for which non-EGU sources have available reductions .... EPA revisited these non-EGU 

reduction cost levels in this final rulemaking and verified that there are little or no reductions 

available from non-EGUs at costs lower than the thresholds that EPA has chosen ($500/ton for 

NOX, $2,300/ton for SO2)." 76 Fed. Reg. 48,249. 

 

For the reasons discussed below, EPA‘s categorization of the ARIPPA facilities under CSAPR is 

inconsistent with EPA‘s objectives for the rule, and the Proposed and Direct Final Supplemental 

CSAPR Revision Rules, and results in distinctions in applicability of the regulation that are not 

supported by EPA's analysis.4 Therefore, in order to implement the "technical fixes" necessary 

to achieve both the elimination of "significant contribution," as defined by EPA for purposes of 

this regulation, and the proper application of the methodologies devised by EPA under CSAPR, 

the Agency should revise CSAPR to eliminate coal refuse-fired CFB combustion units from the 

applicability provisions of the regulation. 

 

(i) The CFB units used by the ARIPPA plants exhibit unique characteristics that distinguish them 

from traditional EGUs. 

Although EPA‘s promulgation of CSAPR reflects a determination to distinguish among sources 

of SO2 and NOX emissions based upon the opportunities available to such sources for applying 

cost-effective controls, EPA makes no effort to analyze relevant distinctions among EGUs within 

CSAPR, including on the basis of emissions characteristics, fuel source, operational design, 

emissions control options, or any other criteria. Instead, CSAPR applies to any stationary fossil 

fuel-fired boiler or combustion turbine qualifying as an affected EGU under the final rule.5

 

EPA's approach of regulating all EGUs under CSAPR, without considering significant 

distinguishing characteristics among those EGUs, is contrary to the objectives and 

methodologies underlying the rule, and results in unsupportable applicability determinations. 

 

4

 ARIPPA's comments in response to the Proposed and Direct Final Supplemental CSAPR Revision

Rules are limited to the SO2 provisions of the regulation. CSAPR includes allocations for NOX emissions 

for the coal refuse-fired circulating fluidized bed combustion units that are consistent with emission rates 

reflective of application of cost effective controls to this source category. Therefore, the determination 

reflected in the CSAPR regulation relative to NOX allowance allocations appears to be consistent with 

EPA's stated methodology to address significant contribution under the regulation. 

5

 Under CSAPR, the following units would qualify as EGUs subject to regulation: "[a]ny stationary, fossil-fuel-fired 

boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of

November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate 

capacity of more than 25 MWe producing electricity for sale." See, e.g., 76 Fed. Reg. 48,385. 
FIP Revisions – RTC 

June 5, 2012 

Page 16 

 

The CFB combustion units operated by the ARIPPA plants exhibit numerous unique 

characteristics that distinguish them from traditional EGUs. First, CFB technology is inherently 

cleaner-burning and, therefore, more environmentally friendly than traditional coal combustion 

technology. The CFB technology can properly be classified as "cleaner-burning" because the 

concentrations of SO2 and NOX in the gases exiting the combustion chamber are materially lower 

than the combustion emissions from conventional coal-fired EGUs. These lower emission rates 

reflect the incorporation of emission control systems into the basic design of the CFB 

combustion unit, reflecting a fundamentally different methodology for limiting SO2 and NOX

emissions associated with the combustion process. Therefore, the emission characteristics, 

including for NOX and SO2, of the coal refuse-fired CFB units are distinguishable from 

traditional EGUs. 

 

Second, emission control is primarily achieved through careful management of the combustion 

zone. For example, the introduction of limestone into the circulating fluidized bed allows for the 

absorption of SO2 and significant reductions in SO2 emissions. For this reason, CFB operators 

must maintain strict control over combustion zone characteristics in order to simultaneously 

control multiple pollutants. For the same reason, the ability to achieve even further SO2 

reductions through the addition of limestone, is asymptotically restricted — not only would the 

introduction of additional limestone interfere with maintenance of the optimal operating 

envelope for energy production and emission control, but, after a point, addition of substantial 

additional limestone would achieve limited, if any, further reduction in SO2 emission rates. 

 

Indeed, these plants were designed and built to achieve specific levels of SO2 control (generally 

exceeding 90% SO2 reduction) through limestone addition, in order to meet the Best Available 

Control Technology (“BACT") emission limits established when the plants were permitted. With 

respect to NOX, strict management of combustion zone characteristics limit the formation of 

NOX. Additionally, many ARIPPA plants employ selective non-catalytic reduction ("SNCR") to 

achieve enhanced NOX reductions. In all cases, the CFB technology emits substantially lower 

SO2 and NOX emissions - per ton of fuel, per MMBtu/hr of heat input and per MW/hr energy 

output- than conventional coal-fired EGUs. 

 

These distinct emission control characteristics are significant with respect to CSAPR in at least 

two respects. First, the emission control technologies considered by EPA for application to 

EGUs under CSAPR do not readily extend to CFB technology, in the same manner and extent as 

applied to traditional coal-fired units. While back-end emission control technology can be 

applied to CFB units under certain situations, unique boiler design and operational criteria create 

additional challenges to effective operation of these emission control systems. More 

significantly, the cost-effectiveness of such back-end controls is dramatically affected by these 

technology distinctions. Because the CFB technologies are inherently cleaner burning, the 

quantity of emissions available for back-end control is substantially reduced. In this way, the 

denominator of the cost-effectiveness calculation is substantially lower, on a relative scale. By 

contrast, the capital and operational costs associated with the back-end controls are not 

materially less for these smaller facilities, because of the inherent fixed capital cost requirements 

of these systems, and unique challenges posed by the distinct CFB technology. 
FIP Revisions – RTC 

June 5, 2012 

Page 17 

 

Second, the CFB technology designed for use by the ARIPPA member facilities was specifically 

intended to combust coal refuse as the primary or exclusive fuel source for energy generation. As 

stated above, the application of the technology for this alternative energy generation constituted a 

response to the immense challenges posed by thousands of tons of coal refuse, creating acid mine 

drainage and polluting miles of streams and rivers. The CFB technology was designed to 

effectively combust coal refuse from past and current mining activities, thereby clearing 

thousands of acres of land, reclaiming previously abandoned mine lands and steams, and 

eliminating a major source of acid mine drainage. 

 

Not only are these CFB units specifically designed to combust coal refuse rather than other fuel 

sources, the ARIPPA member facilities are generally subject to legal requirements to combust 

coal refuse, at least as a primary fuel component. These legal requirements derive not only from 

contractual commitments, but also standards imposed by the Federal Energy Regulatory 

Commission ("FERC") as part of the designation of these facilities as QFs; the QF designation is 

a condition of the facilities' financing contracts for the CFB units. 

 

In evaluating emission control options under CSAPR, EPA considered opportunities available to 

regulated sources to engage in fuel switching, and such opportunities supported EPA's 

conclusion that EGUs may cost-effectively reduce SO2 emissions. See 76 Fed. Reg. 48,283-84, 

EPA’s analysis of the cost-effectiveness of fuel switching as an emission control option did not 

extend beyond bituminous and subbituminous coal; EPA’s analysis certainly did not consider 

non-traditional coal used as fuel, notably including coal refuse, which is distinguishable from 

other coal species in terms of sulfur content and other key characteristics. For these 

technological, legal, economic, environmental and practical reasons, the ARIPPA facilities 

cannot simply elect to convert their fuel source from coal refuse to a lower-sulfur fuel in order to 

reduce emissions, as contemplated by EPA under CSAPR.6 Indeed, the fundamental purpose of 

the ARIPPA plants is to combust coal refuse to reclaim former mining lands while allowing for 

the production of electricity; switching fuels would therefore be directly inconsistent with this 

purpose. Further, EPA has itself acknowledged, within the Proposed Utility MACT and NSPS, 

that "coal refuse from some piles has sulfur contents at such high levels that they present 

potential economic and technical difficulties in achieving the same SO2 standards that we are 

proposing for higher quality coals". 76 Fed. Reg. 24,976, 25,066. 

 

Although EPA’s stated methodology for evaluating "significant contribution" under 

CSAPR is premised (as EPA repeatedly states) on the application of cost-effective controls, 

EPA’s cost-effectiveness analysis under CSAPR fails to consider these significant distinctions in 

coal refuse-fired CFB units. In this regard, EPA‘s determination that EGUs - as a single, broad 

category of sources - can be cost-effectively controlled consistent with the objectives of CSAPR 

 

6

 Although the ARIPPA facilities cannot substitute lower sulfur fuels for coal refuse in the operation of the

CFB units, it should be noted that many of these facilities are nonetheless subject to permit-based 

limitations which (typically) limit the fuel sulfur content or require at least 90% reduction in sulfur based on 

the concentration in the fuel source and post-combustion emission rates. 
FIP Revisions – RTC 

June 5, 2012 

Page 18 

does not, in fact, apply to the CFB technology utilized by ARIPPA facilities, any more than it 

would apply to non-EGU stationary sources excluded by EPA from regulation under CSAPR. 

 

As previously reported to EPA, ARIPPA conducted an evaluation of the relative costeffectiveness of the compliance options available to the ARIPPA plants for reducing SO2

emissions to the levels reflected in the allowance allocations provided during Phase II of 

CSAPR. The analysis reflects consideration of the control options theoretically available to the 

ARIPPA facilities to reduce SO2 emissions: reduce fuel sulfur, increase the use of limestone, or 

employ an add-on SO2 emission control device, such as dry sorbent injection ("DSI") or spray 

drying absorption ("SDA"). Because of the unique characteristics of ARIPPA’s coal refuse-fired 

CFB units, the ARIPPA plants cannot feasibly achieve material SO2 reductions by either 

reducing fuel sulfur or increasing limestone utilization. Accordingly, the only theoretical option 

among these three SO2 reduction scenarios through which the ARIPPA plants might limit SO2

emissions to levels commensurate with the Phase II allocation rates is installation of an add-on 

control device. 

 

In EPA’s recently-issued Proposed Utility MACT and NSPS, the Agency apparently assumes 

that DSI is an available technology for reducing SO2 and acid gas emissions from coal refusefired CFB boilers. In fact, however, ARIPPA is not aware of a single commercially demonstrated 

application of add-on, back-end DSI for the control of SO2 emissions from a coal refuse-fired 

CFB unit anywhere in the United States. Under established CAA precedent, therefore, DSI 

cannot be considered a "technically feasible" control option for the reduction of SO2 emissions 

from this source type. 

 

Moreover, even to the extent that such emission control technology could be considered 

technically feasible (and for the reasons discussed above, post-combustion SO2 emission control 

technology cannot be considered "available" for a retrofit application to an existing coal refusefired CFB unit), both EPA's and ARIPPA’s analyses demonstrate that such technology could not 

be considered economically feasible. In the context of publishing the Proposed Utility MACT 

and NSPS, EPA specifically commented that, "[w]e have concluded that it is not generally cost 

effective to add additional post-combustion SO2 controls for modified fluidized beds." 76 Fed. 

Reg. 25,066, Therefore, EPA has already reached the conclusion that any post-combustion SO2

controls would not be cost effective when applied to this source type.7

Similarly, ARIPPA’s analysis of the cost-effectiveness of utilizing DSI to reduce SO2 emissions 

demonstrates that it would cost at least $3,300 per ton removed for a typical 80 MW ARIPPA 

plant to reduce SO2 emissions to the extent needed to satisfy the applicable 2014 emission 

 

7

 Nonetheless, for purposes of developing the final emission reduction requirements under CSAPR, EPA

determined that it is cost-effective for all EGUs in Group 1 states to control SO2 emissions beginning in 

2014 at rates up to $2,300/ton. See 76 Fed. Reg., 48,249. See also 76 Fed. Reg. 48,252 ("The cost curves 

demonstrate that sources begin to build significant ... additional dry sorbent injection (DSI) retrofits at an SO2 cost 

threshold of $2,300 per ton."). 
FIP Revisions – RTC 

June 5, 2012 

Page 19 

reduction requirements.8 This is a conservative, "best case" projection, however, based on the 

assumption that DSI will indeed provide the required emission reductions at a relatively low 

sorbent injection rate. In fact, recent applications of DSI (both permanent and test applications) 

to coal-fired combustion units other than coal refuse-fired CFB units9

 have demonstrated that 

significantly higher sorbent injection rates are required for effective SO2 control, and therefore 

employing DSI to achieve the required SO2 reductions would actually cost more than $6,400 per 

ton removed. Therefore, contrary to EPA’s assumptions in the preamble to the final rule, it 

would not be cost-effective for ARIPPA's coal refuse-fired CFB units to install and operate DSI 

to reduce SO2 emissions, applying EPA’s own threshold for identifying cost-effective controls. 

The underlying data supporting this conclusion are detailed in ARIPPA's Petition for 

Reconsideration, which was previously submittal to EPA.10 

ARIPPA also evaluated the potential application of SDA as an SO2 emission control option, 

notwithstanding that, as with DSI, ARIPPA is not aware of a single commercially demonstrated 

retrofit application of SDA for the control of SO2 emissions from a coal refuse-fired CFB unit 

anywhere in the United States. For a typical 80 MW ARIPPA plant, the control cost for reducing 

SO2 emissions to meet the Phase II reduction requirements using SDA would be nearly $9,000 

per ton removed. As previously submitted to EPA, ARIPPA's cost estimate includes the annual 

operating costs for an SDA system, which would be significant, including sorbent and water use, 

consumptive power demands, system operation and maintenance, and additional waste disposal 

costs. Clearly, this cost estimate substantially exceeds the control cost threshold selected by EPA 

as cost-effective for reducing SO2 emissions from all EGUs under CSAPR. 

 

Based on the results of ARIPPA’s analysis, it is clear that there are no controls that are both 

technologically and economically available to the ARIPPA plants for reducing SO2 emissions to 

the levels required under CSAPR in 2014. ARIPPA’s evaluation also demonstrates that the 

 

8

 This analysis is based on a typical ARIPPA coal refuse-fired CFB plant, which was the subject of a recent EPAsponsored study of DSI costs.

9

 As stated above, ARIPPA is not aware of any applications of DSI technology in a retrofit context for a coal refusefired CFB unit.

10 Moreover, the results of this cost-effectiveness analysis are limited to the direct costs of installation and operation 

of the emission control device. In fact, application of such technology (if technologically feasible for this 

application) would likely significantly degrade the quality of ash generated by coal refuse-fired CFB units. 

Currently, such ash is beneficially used for the reclamation of abandoned mines. This management process not only 

provides environmental benefits in terms of mine reclamation, but substantially reduces the cost otherwise required 

for ash disposal. The addition of significantly greater amounts of sorbent is likely to impair the quality of the ash, in 

terms of pH, leachability of metals, increased chlorides, sulfates, and other characteristics. The resulting ash 

parameters would likely dictate the need for disposal in lined landfills, rather than mine reclamation, at a current 

cost of approximately $28 to $40 per ton, based on EPA’s own estimates for landfill disposal costs, as reflected in 

the Sargent & Lundy report. Taking into account this additional ash disposal cost (which, based on information 

available to ARIPPA, likely understates the actual probable disposal costs), the cost per ton for reducing SO2

emissions would increase to more than $11,500 per ton removed -- five times the $2,300 cost threshold identified by 

EPA as cost-effective for this purpose.
FIP Revisions – RTC 

June 5, 2012 

Page 20 

effectiveness of using back-end controls to reduce SO2 emissions from coal refuse-fired CFB 

units is currently uncertain at best, with most current applications still in experimental stages. 

Such uncertainty only exacerbates the challenges faced by these plants as a result of the 

virtually-immediate applicability of the final rule. This conclusion is consistent with EPA’s 

recent determination (as articulated in the context of EPA’s proposed New Source Performance 

Standards for fossil fuel-fired electric utility units) that it is not cost-effective to add additional 

post-combustion SO2 controls to modified fluidized bed combustion sources. See 76 Fed. Reg. 

25,066. 

 

In the context of EPA’s current rulemaking action, considering EPA’s ongoing objective of 

implementing additional technical fixes to ensure consistency with the elimination of "significant 

contribution" and proper application of the methodologies identified by EPA under CSAPR, the 

Agency should recognize the need to implement changes to the regulation in order to correct the 

determination - inconsistent with its stated methodology - that further SO2 emissions can be cost 

effectively achieved for existing coal refuse-fired CFB EGUs, and, therefore, that such units 

significantly contribute to downwind nonattainment and should be regulated under CSAPR. 

(ii) Absent a showing that emissions can be cost-effectively controlled from coal refuse-fired 

CFB units, EPA has not justified a finding of significant contribution from the ARIPPA plants. 

 

Given the distinguishing characteristics of the ARIPPA facilities (based primarily on use of CFB 

technology and combustion of coal refuse), as detailed above, it is clear that EPA has not 

properly applied its methodology for determining "significant contribution" under CSAPR to the 

ARIPPA plants, and, as such, even further corrections to the regulations are therefore warranted, 

in addition to those implemented through the Proposed Errors Rule. Specifically, EPA‘s 

methodology depends, in material part, upon an evaluation of the emission characteristics and 

the cost-effectiveness of available controls for EGUs. In the context of emission impacts, the 

emissions from the ARIPPA facilities are materially less than traditional coal-fired EGUs. 

Therefore, to the extent that EPA evaluated the air quality impacts from EGUs as a single 

category, without distinction for the unique emission profiles of these facilities, EPA 

inappropriately and inaccurately concluded that the ARIPPA EGUs contribute to downwind 

nonattainment to the same extent as traditional EGUs. Instead, the emission characteristics of the 

ARIPPA CFB units distinguish these sources from traditional coal-fired EGUs. Under a proper 

application of EPA’s methodology, evaluation of emission characteristics more closely aligns the 

ARIPPA facilities with the many emission sources that EPA has determined to exclude from 

regulation under CSAPR. 

 

Further, emissions from the ARIPPA plants comprise a de minimis portion of the total SO2

emissions budget under CSAPR for Group 1 states. Indeed, the collective SO2 emissions from 

the ARIPPA plants in Pennsylvania and West Virginia represent less than 1% of the aggregate 

SO2 emissions from the Group 1 states. As such, a determination that the ARIPPA facilities are 

among a relatively small percentage of facilities significantly contributing to downwind 

nonattainment is not consistent with an accurate analysis of the emission inventory for the 

relevant states, including Pennsylvania. Similarly, exclusion of the ARIPPA facilities from 

regulation under CSAPR would not have a meaningful impact on the overall emissions budget 
FIP Revisions – RTC 

June 5, 2012 

Page 21 

under CSAPR, including for individual states such as Pennsylvania and West Virginia, or EPA’s 

analysis of the projected downwind impact from the State. 

 

Likewise, under the second part of EPA’s "significant contribution" analysis, EPA’s 

determination that EGUs may be cost-effectively controlled is based on an incorrect application, 

or the absence of any application, of EPA’s established CSAPR methodology to the ARIPPA 

facilities. Most significantly, the emission reduction techniques identified by EPA are either 

inapplicable to the ARIPPA facilities or would necessitate a substantially different control 

analysis. 

 

Application of EPA’s methodology under CSAPR supported the conclusion that 

non-EGUs cannot achieve comparable cost-effective emissions reductions. Specifically, EPA 

states in the preamble to the proposed Transport Rule, that its "review of the costs of EGU and 

non-EGU controls resulted in a conclusion that substantial SO2 and NOX reductions from EGUs 

are available at a cost per ton that is lower than the cost per ton of non-EGU controls." 75 Fed. 

Reg. 45,300. Because EPA has developed a methodology for identifying affected sources under 

CSAPR which distinguishes among source categories on the basis that specific design and/or 

operating characteristics make it economically infeasible for non-EGU source categories to 

comply with the emission reduction requirements in CSAPR, the proper and consistent 

application of that methodology requires the conclusion that ARIPPA’s CFB units should not be 

included among the sources subject to regulation under CSAPR. 

 

For these reasons, EPA’s analysis as reflected in CSAPR cannot support a finding that the 

ARIPPA facilities significantly contribute to nonattainment in downwind states, nor that 

emissions from ARIPPA facilities can be cost-effectively controlled. EPA should therefore 

correct the final rule in the context of the current rulemaking effort to ensure the proper 

application of its methodology for identifying sources that significantly contribute to 

nonattainment and therefore warrant control under CSAPR. 

 

In addition, within the preamble to the proposed version of CSAPR, EPA sets 

forth several objectives for the development of this regulation. These stated objectives 

further demonstrate the inapplicability of EPA’s regulatory analysis to the ARIPPA 

plants. Specifically, EPA carefully enumerates "key guiding principles" for determining 

to regulate specific sources. 75 Fed. Reg. 45,226-27. Among these guiding principles, EPA states 

that its proposed regulatory approach would provide for "cost effectiveness,“ and would provide 

incentives and flexibility to the regulated community. These guiding principles are not satisfied 

with respect to the ARIPPA facilities, predominately because the proposed emission reductions 

cannot be achieved cost-effectively, and the regulatory standards not only afford no flexibility to 

the ARIPPA plants, but would instead establish requirements that these facilities cannot readily 

satisfy. The fact that EPA‘s guiding principles for CSAPR would not be served through 

regulation of the ARIPPA facilities provides further evidence that the final CSAPR regulation is 

inconsistent with proper application of EPA’s established methodology, reflected in the 

rulemaking development process, for determining which sources should be subject to EPA’s 

approach toward interstate transport regulation. 

 
FIP Revisions – RTC 

June 5, 2012 

Page 22 

For the foregoing reasons, EPA should determine that proper application of its methodology for 

identifying sources that significantly contribute to downwind nonattainment, and therefore 

should be regulated under CSAPR, confirms that such designation cannot properly extend to the 

ARIPPA facilities. EPA should therefore revise CSAPR, through the Proposed and Direct Final 

Supplemental CSAPR Revision Rules, based on this analysis, to ensure that the rule reflects 

accurate and consistent application of the methodology developed by EPA for purposes of the 

rule, and implement the additional technical corrections necessary to address its concerns 

regarding significant contribution in a manner consistent with the stated methodology and 

objectives of the underlying rule. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

Comments on the Transport Rule applicability provisions are outside the scope of this 

rulemaking. The commenter raises its applicability concern in the context of an argument 

regarding the Transport Rule’s approach to determine a state’s significant contribution to 

nonattainment and interference with maintenance downwind. The commenter’s request, 

however, is that that EPA exclude ARIPPA member facilities from the SO2 requirements of the 

Transport Rule. As such, it is a comment on and a request for a revision to the Transport Rule 

applicability provisions. EPA did not propose any revisions to the final Transport Rule 

applicability provisions or reopen them for comment in this rulemaking. This comment therefore 

is outside the scope of this rulemaking. 

ARIPPA's Petition for Reconsideration raises related concerns. See section 4.5 of the Preamble 

for this rulemaking for a discussion of Petitions for Reconsideration of the Transport Rule. 

EPA provided a full opportunity to comment on the Transport Rule applicability provisions 

during the course of that rulemaking. ARIPPA commented on the proposed applicability 

provisions -- requesting that ARIPPA facilities be excluded -- and EPA responded in the Primary 

Response to Comments (RTC) document for the final Transport Rule (EPA-HQ-OAR-2009-

0491-4513, pages 961-963). 

In its comments on the proposed revisions to the Transport Rule, “Revisions to Federal 

Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone” (76 

FR 63860; October 14, 2011), ARIPPA raised similar applicability arguments as raised in its 

comments addressed herein. EPA addressed the applicability-related comments in the RTC for 

the October 14, 2011 proposal (EPA-HQ-OAR-2009-0491-4963, page 178), also explaining that 

the comments were outside the scope of that rulemaking. That the Agency responded to the 
FIP Revisions – RTC 

June 5, 2012 

Page 23 

substance of ARIPPA’s comment without identifying ARIPPA as the commenter is of no 

consequence. 

The Transport Rule determines the quantity of emissions from each covered state that constitutes 

the state’s significant contribution to nonattainment and interference with maintenance 

downwind with respect to the 1997 annual and 2006 24-hour PM2.5 NAAQS and the 1997 ozone 

NAAQS (76 FR 48246-48270). EPA analyzed each upwind state’s contributions to downwind 

air quality problems and applied a threshold to identify states with relatively large contributions 

to downwind problems (76 FR 48222-48246)--that analysis is based on consideration of all 

emissions categories in a state and is not limited only to EGUs (e.g., the emissions inventories 

include non-EGU point sources, mobile sources, marine sources, and nonpoint sources). EPA 

then defined the quantity of emissions from each covered state that constitutes the state’s 

significant contribution to nonattainment and interference with maintenance as the emission 

reductions available from EGUs collectively in the state at a particular cost threshold (76 FR 

48248-48265). 

The Transport Rule’s approach is based on the emission reductions available from EGUs 

collectively in a state at the specified cost thresholds; this does not imply that every EGU in each 

covered state will reduce emissions at the specified cost thresholds. The Transport Rule does not 

quantify significant contribution and interference with maintenance for individual emissions 

sources. EPA’s Transport Rule analysis determined that electric generating units (EGUs) as a 

category have cost-effective emission reductions available. ARIPPA facilities are included in 

EPA’s modeling which showed that EGUs -- as a group -- have cost-effective reductions 

available. 

In response to a comment from ARIPPA, the Agency stated in the Primary RTC document for 

the final Transport Rule that, “EPA maintains that it is reasonable to consider the electricity 

generation sector as a whole in determining the cost of available emission reductions and in 

determining a state's significant contribution and interference with maintenance.” (EPA-HQOAR-2009-0491-4513, page 961). EPA maintains that the inclusion of ARIPPA-member waste 

coal-fired CFBs is fully consistent with the Transport Rule’s approach for determining each 

state’s significant contribution to nonattainment and interference with maintenance. 

EPA’s determination in the Transport Rule that it is appropriate to include EGUs as a broad 

category is consistent with Congress’ action in Title IV of the Clean Air Act Amendments. Title 

IV includes the power sector as a broad class of units in the Acid Rain Program--including 

certain types of units that would not necessarily be expected to cost-effectively reduce SO2

emissions on an individual basis, e.g., combined-cycle gas turbines. In both the Transport Rule 

and the Acid Rain Program, EGUs as a broad class of units are included in an emission reduction 

program that provides the flexibility of allowance trading. 

Also, the commenter purports to show that the actual cost per ton “for a typical 80 MW ARIPPA 

plant to reduce SO2 emissions to the extent needed to satisfy the applicable 2014 emission 

reduction requirements” is higher than the $2,300 cost per ton threshold EPA selected as a basis 

on which to define significant contribution for SO2 emissions in Group 1 states. However, the 
FIP Revisions – RTC 

June 5, 2012 

Page 24 

commenter does not explain how “the applicable 2014 emission reduction requirements” were 

defined for the purposes of these calculated levels of cost-effectiveness, and EPA notes that the 

Transport Rule does not, in fact, define any unit-specific emission reduction requirements. As 

such, the commenter’s cost-effectiveness calculations are unsupported and they do not 

demonstrate that such a unit is incapable of achieving any SO2 reductions at a cost at or below 

$2,300 per ton. For example, the cost of a particular application of dry sorbent injection 

technology can vary depending on how much sorbent is injected, which in turn is a function of 

how much SO2 removal is desired. The commenter’s calculations appear to have pre-determined 

the “required” SO2 reductions at the hypothetical unit (with no basis in actual Transport Rule 

requirements), which unnecessarily prevents consideration of other levels of SO2 control at that 

unit that could be achieved more cost-effectively. The Transport Rule is structured specifically 

to allow individual units to consider a broad spectrum of emission control strategies that EPA 

modeling shows would yield a broad “equilibrium” cost-per-ton threshold of $2,300 per ton 

when taking into account emission reductions available across all covered sources. The 

commenter’s isolated and unsupported calculations do not offer any evidence to contradict 

EPA’s reliance on this cost per ton threshold and the resulting quantification of state budgets 

under the rule. 

EPA fully responded to ARIPPA’s request for exclusion of ARIPPA facilities from the Transport 

Rule in the Primary RTC document for the final Transport Rule (EPA-HQ-OAR-2009-0491-

4513, pages 961-963). 

COMMENT: B. To the extent that EPA determines not to exclude the ARIPPA plants from 

regulation under CSAPR, then EPA should increase the allowance allocations to the ARIPPA 

units to reflect the emission levels reflective of the application of cost-effective controls for 

reducing emissions from coal refuse-fired CFB units. 

 

EPA has described its methodology for determining state-specific emission budgets as 

constituting the aggregate emissions from affected sources located within the state during an 

average year, once the emissions associated with significant contribution to nonattainment and 

interference with maintenance are eliminated from the emission inventory for such sources. 76 

Fed. Reg. 48,249. EPA identified the amount of emissions representing significant contribution 

to nonattainment and interference with maintenance within each state by focusing on "different 

‘cost thresholds’ - places where there was a noticeable change on the cost curve because 

emission reductions occur- and examining the corresponding impact on air quality." 76 Fed. Reg. 

48,255. The cost thresholds EPA ultimately selected for Group 1 states (including Pennsylvania) 

- i.e., $500/ton for NOX and SO2 in 2012, and $500 for NOX and $2,300/ton for SO2 in 2014 - 

apply equally to all EGUs. See 76 Fed. Reg. 48,249-52. Therefore, EPA’s methodology for 

calculating the final state-specific emission budgets under CSAPR is founded on the proper 

determination of the emission rate - following the application of cost-effective controls - for each 

affected EGU based on these same cost thresholds. 

 

As demonstrated above, relative to the cost thresholds identified in EPA’s methodology, there 

are no cost-effective controls available to the ARIPPA plants to further reduce SO2 emissions 

from coal refuse-fired CFB units. Accordingly, to the extent that EPA determines not to exclude 
FIP Revisions – RTC 

June 5, 2012 

Page 25 

the ARIPPA plants from regulation under CSAPR, proper application of EPA’s CSAPR 

methodology requires that the allowance allocations for the ARIPPA plants correspond to current 

emission levels for such sources. Specifically, because no "cost effective" control is available for 

application to existing coal refuse-fired CFBs, under the methodology applied by EPA under 

CSAPR, there are no emissions from these sources that "significantly contribute" to downwind 

nonattainment. Therefore, under the methodology reflected in CSAPR, the calculation of the SO2

allowance allocations for these sources cannot include a reduction in SO2 emissions to offset the 

sources’ "significant" contribution to nonattainment in another state (i.e., the SO2 emission level 

for these sources that significantly contribute to downwind nonattainment is zero). 

 

This consistent application of EPA’s CSAPR methodology would require a corresponding 

increase in the total emission budgets for Pennsylvania. Revising the emission budgets for 

Pennsylvania in this manner would be consistent with EPA‘s current proposal to increase the 

budgets for certain states in order to correct improper assumptions about the operation of existing 

and planned controls by affected sources in these states, as well as the increases in emission 

budgets for certain states which EPA implemented through the Proposed Errors Rule. 

 

To the extent that EPA properly applies its methodology under the regulation and excludes any 

calculation of required emission reductions from the ARIPPA plants in the context of CSAPR‘s 

significant contribution analysis, EPA must also adjust its unit-specific allocation approach for 

Pennsylvania under the FIP to ensure consistency with the objectives for CSAPR. Under EPA's 

current allowance allocation approach, all covered EGUs in Pennsylvania receive a proportionate 

share of the state‘s budget as unit-specific allocations, subject only to some unit-specific 

imitations reflective of established historic emission rates for certain sources. Because the 

increase in Pennsylvania’s budget under the approach proposed in these comments is specifically 

intended to ensure that the allocation determination for all regulated sources corresponds to 

emission rates after the application of cost effective controls, source specific allocations are 

necessary to properly reflect the distinguishing characteristics of ARIPPA’s coal refuse-fired 

CFB units. 

 

Therefore, in order to ensure the allocation of allowances consistent with EPA's stated 

methodology, EPA should revise the CSAPR FIP to allocate directly to the ARIPPA units the 

"additional" allowances allocated to Pennsylvania, corresponding to the emission rates from 

coal-fired CFBs reflecting application of cost-effective controls for such sources. Because the 

current level of control for the ARIPPA sources qualities as the limit of cost-effective controls 

under EPA's CSAPR methodology, the ARIPPA units should receive allowance allocations that 

are commensurate with the units’ historic emission rates; as demonstrated above, the current 

CSAPR allocations to the ARIPPA plants are based on improper assumptions about the 

availability of cost-effective controls. Implementation of this proposed approach would be 

consistent with EPA’s methodology under CSAPR, since the ARIPPA sources' allowance rates 

cannot justifiably be reduced to account for the application of cost-effective controls for reducing 

emissions of SO2 from coal refuse-fired CFB boilers. Moreover, allocating allowances to the 

ARIPPA plants on this basis would enable EPA — and, ultimately Pennsylvania, once its SIP is 

effective - to ensure consistent application of the methodology underlying CSAPR, without 

reducing allowance allocations to other affected sources in Pennsylvania (in order to allocate to 
FIP Revisions – RTC 

June 5, 2012 

Page 26 

the ARIPPA plants a number of allowances that properly reflects their sources’ emission rates 

after application of cost-effective controls). 

 

For these reasons, to the extent that EPA determines not to exclude the ARIPPA units from 

regulation under CSAPR, consistent application of EPA’s methodology under CSAPR would 

dictate that EPA should revise CSAPR to (1) increase the Pennsylvania emission budgets and (2) 

adjust unit-specific allocations under the FIP to increase allowance levels for the ARIPPA plants, 

such that these sources receive allowance allocations that are reflective of historic operating 

rates. These adjustments would allow the regulation to reflect the absence of availability of 

additional cost-effective controls for further reducing emissions from ARIPPA’s coal refusefired CFB units. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

Comments on the Transport Rule FIPs’ method for allocating emission allowances to existing 

units are outside the scope of this rulemaking. EPA provided full opportunity to comment on the 

existing-unit allocation methodology in the Transport Rule rulemaking. In fact, in response to 

comments from ARIPPA and others on the proposed allocation methodology requesting that 

allowances be allocated based on historic heat input instead of on projected emissions as 

proposed, EPA issued a Notice of Data Availability to seek comment on historic heat inputbased allocation methodologies (76 FR 1109). The historic heat-input allocation method that 

EPA finalized in the Transport Rule, which is consistent with the approach requested by 

ARIPPA and other commenters, is based on each unit’s share of its state’s historic heat input, 

subject to a maximum allocation limit based on a unit’s maximum historic emissions (76 FR 

48284-48290). EPA did not propose any revisions to the Transport Rule FIP allocation 

methodology or reopen it for comment in this rulemaking. For these reasons, this comment is 

beyond the scope of this rulemaking. 

It is worth noting, nonetheless, that ARIPPA’s assertion that the Transport Rule FIP allocation 

methodology “requires that allowance allocations correspond to the emission levels reflective of 

the application of cost-effective controls for reducing emissions from coal refuse-fired CFB 

units” is simply false. The final Transport Rule FIP method for allocating allowances to existing 

units is not based on “emission levels reflective of the application of cost-effective controls.” 

The commenter implies that EPA defined significant contribution on a unit level and then 

allocated emission allowances based on each unit’s significant contribution. However, EPA 

defined significant contribution at the state level (as discussed above) and allocated allowances 
FIP Revisions – RTC 

June 5, 2012 

Page 27 

to individual units based on each unit’s share of historic heat input subject to a maximum based 

on historic emissions. 

The comments seem to be based on the false premise that each unit is required to reduce 

emissions to the level of its allowance allocations. This is false; the allowance allocation is not a 

reduction requirement. Further, as discussed in the Technical Support Document for the final 

Transport Rule titled “Allowance Allocation Final Rule TSD,” all EGUs must factor in the price 

of emitting a ton (as reflected by the allowance price) under a trading program when selling 

power no matter the original pattern of initial allocations (EPA-HQ-OAR-2009-0491-4517, see 

Appendix A). The incorporation of this “price to emit” under the program is the economic 

incentive by which all sources will act to make all cost-effective emission reductions available 

up to that cost per ton level; soures will make this cost-effective control decision based on the 

allowance price, not based upon initial unit-level allowance allocations. 

In its comments on the proposed revisions to the Transport Rule, “Revisions to Federal 

Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone” (76 

FR 63860; October 14, 2011), ARIPPA similarly suggested using an alternative methodology to 

allocate a greater number of SO2 allowances to ARIPPA units (with related increases in state 

budget). EPA addressed comments on the allocation methodology in the RTC for the October 

14, 2011 proposal (EPA-HQ-OAR-2009-0491-4963, page 178) indicating that such comments 

were outside the scope of the rulemaking. That the Agency responded to the substance of 

ARIPPA’s comment without identifying ARIPPA as the commenter is of no consequence. 

COMMENT: IV. Conclusion 

 

In the context of its current efforts to implement additional corrections to CSAPR to ensure 

consistent application of the rule‘s methodologies and pursuit of the rule’s objectives, EPA 

should not finalize the terms of the Proposed and Direct Final Supplemental CSAPR Revision 

Rules without making additional adjustments to the regulation to fully realize EPA’s objectives 

for CSAPR. Under EPA’s methodology, ARIPPA's coal refuse-fired CFB boilers do not 

significantly contribute to downwind nonattainment, as evaluated under CSAPR. Therefore, 

under both the objectives and methodology underlying CSAPR, the ARIPPA sources should not 

be made subject to the obligations of CSAPR. Revising CSAPR in the manner proposed by 

these comments would be consistent with EPA’s objectives for the Proposed Errors Rule and the 

Supplemental Proposed and Direct Final CSAPR Revision Rules of implementing technical fixes 

to ensure consistency with the elimination of significant contribution and proper application of 

the methodologies identified by EPA under CSAPR. 

 

Despite EPA’s determination in the context of developing CSAPR that multiple source 

categories generate material rates of NOX and SO2 emissions, EPA concluded that the objectives 

of CSAPR can most cost-effectively be achieved by regulating only EGUs. However, EPA failed 

to distinguish within CSAPR among categories of EGUs, including on the basis of emissions 

characteristics, fuel source, operational design, emissions control options, or any other criteria. 

This approach is inappropriate and results in applicability determinations that are inconsistent 
FIP Revisions – RTC 

June 5, 2012 

Page 28 

with EPA’s stated methodologies and objectives for the rule, particularly with respect to the 

ARIPPA facilities, which exhibit certain fundamentally distinct characteristics relative to EGUs. 

 

The CFB units used by the ARIPPA plants exhibit distinct emission control characteristics; the 

emission control technologies considered by EPA for application to EGUs under CSAPR do not 

readily extend to CFB technology. However, EPA’s cost-effectiveness analysis under CSAPR 

fails to account for these significant distinctions in coal refuse-fired CFB units, and, therefore, 

EPA’s determination that EGUs can be cost-effectively controlled consistent with the objectives 

of CSAPR does not, in fact, apply to the CFB technology used by the ARIPPA facilities. Indeed, 

EPA reached the conclusion in the context of a separate contemporaneous rulemaking effort that 

additional SO2 emission reductions cannot be cost effectively achieved for existing coal refusefired CFB units. 

 

Consistent with EPA’s conclusion, ARIPPA’s analysis of the relative cost-effectiveness of the 

compliance options theoretically available to ARIPPA plants for reducing SO2 emissions 

demonstrates that neither DSI nor SDA are both technically and economically available to the 

ARIPPA plants for further reducing SO2 emissions to the levels required under CSAPR. In the 

absence of a showing that emissions can be cost-effectively controlled from coal refuse-fired 

CFB units, consistent application of EPA’s methodology under CSAPR requires a finding that 

the ARIPPA plants do not significantly contribute to downwind nonattainment. Accordingly, 

EPA should revise CSAPR to exclude such units on this basis. 

 

To the extent that EPA nonetheless determines not to exclude the ARIPPA plants from 

regulation under CSAPR, EPA should adjust the SO2 allowance allocations to the ARIPPA units 

to ensure proper application of EPA’s CSAPR methodology. Such methodology requires that 

allowance allocations correspond to the emission levels reflective of the application of costeffective controls for reducing emissions from coal refuse-fired CFB units. For purposes of 

developing CSAPR, EPA identified the amount of emissions representing significant 

contribution to nonattainment and interference with maintenance within each state by focusing 

on specific cost thresholds and the corresponding impact on air quality. As such, the 

methodology for calculating the final state-specific budgets under CSAPR is founded on the 

proper determination of the source-specific emission rate, following the application of costeffective controls. However, relative to the cost thresholds identified in EPA’s methodology, 

there are no cost-effective controls available to the ARIPPA plants to further reduce SO2

emissions from coal refuse-fired CFB units. Therefore, proper application of EPA’s CSAPR 

methodology requires that the allowance allocations for the ARIPPA plants correspond to current 

emission levels for such sources. Such adjustments to both state and unit-specific allowance 

allocation budgets under CSAPR are not only consistent with, but in fact constitute, the 

fundamental objective of the Proposed and Direct Final Supplemental CSAPR Revision Rules. 

For this reason, Finalizing such rulemaking without addressing the necessary adjustments for the 

ARIPPA plants is entirely inconsistent with the rulemaking effort and EPA's expressly stated 

regulatory objectives. 

RESPONSE: See above responses to comments by ARIPPA. 
FIP Revisions – RTC 

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3. Florida Electric Power Coordinating Group (FCG) 

[Letter: Florida Electric Power Coordinating Group (EPA-HQ-OAR-2009-0491-4978)] 

COMMENT:1)The Errors Identified by the FCG Merit Correction. 

 

In response to EPA's Revisions Part I proposal, the FCG described a number of errors that 

materially impacted EPA's establishment of Florida's ozone-season NOX budget. The FCG also 

calculated the budget using the accurate information. The errors related to: (i) unit-level NOX

emission rate assumptions; (ii) certain localized minimum voltage requirements; (iii) natural gas 

capacity constraints; (iv) import transmission capacity constraints; and (v) the anticipated in 

service date for the Crystal River Unit 3 nuclear unit. 

 

EPA's responses to the FCG's comments are unavailing, and have yet to be referenced or noticed 

in the Federal Register. In many instances, EPA fails to address the actual issue raised. The 

same is true for EPA's treatment of other submitted comments, like Lakeland Electric's.11

 The FCG expended considerable effort to develop supporting data and calculations (based on 

EPA's own methods) and to demonstrate the material impact- an additional 10,794 allowances - 

from these corrections. Importantly, the errors identified by the FCG are largely the same type of 

out-of-merit-order errors EPA has already corrected. For example, EPA approved an ozoneseason NOX budget correction for New York based on import capacity constraints affecting a 

Long Island based facility. Other corrections similar to the FCG's comments related to 

transmission constraints affecting facilities in Texas, Louisiana, Mississippi, and Kansas.

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action.

EPA did in fact respond to comments previously submitted by FCG and Lakeland Electric in 

section 1.1 of the document “Response to Comments on the Proposed Revisions to FIPs to 

Reduce Interstate Transport of Fine PM and Ozone.” (EPA-HQ-OAR-2009-0491-4963), and the 

Primary Response to Comments document in the docket for the final rulemaking. EPA is not 

required to publish all responses to comments on a rulemaking in the Federal Register; instead, 

its usual practice is to respond to most comments in a separate response to comments document 

accompanying the rulemaking and included in the docket for the appropriate rulemaking as is the 

case in this instance.

 

11 See Docket ID: EPA-HQ-OAR-2009-0491-4770.
FIP Revisions – RTC 

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COMMENT: The FCG's comments describe comparable transmission capacity constraints but 

on an even more significant scale, affecting not just select facilities, but the entire state. Florida's 

unique peninsular geography further highlights the significance of gas capacity and transmission 

constraint issues in our state. Given the significant reliability issues at stake, EPA should revisit 

its dismissal of the errors the FCG has presented. Indeed, as EPA is aware, the need for agency 

attention to the reliability impacts posed by CSAPR and other recent EPA regulatory actions has 

been acknowledged by both the Federal Energy Regulatory Commission and the North American 

Electric Reliability Corporation.12

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA previously responded to this comment. See page 7-8 of “Response to Comments on the 

Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963). In that response, EPA identified several erroneous assumptions in 

FCG’s claims that IPM somehow incorrectly represented the limits on both interstate 

transmission of electricity (id. at 7-8) and natural gas (id. at p. 5-7). 

Furthermore, as discussed in the previous responses to FCG’s comments on this topic, FCG does 

not actually challenge Florida’s electricity transmission limits in IPM. The commenter correctly 

notes that IPM represents the upper-bound transmission capacity into Florida13 is 3600 MW; the 

commenter does not question this transmission capacity assumption. Rather, the commenter 

selects a separate electricity demand assumption made by the Florida Reliability Coordinating 

Council (FRCC) for 2012, compares it to EPA’s modeling projections for generation within the 

 

12 See Federal Energy Regulatory Commission, Notice of Technical Conference, Docket No. AD12-1-000 (October 

7, 2011) (noticing technical conference in November 2011 to discuss reliability issues, including reliability concerns 

related to "compliance with Environmental Protection Agency regulations"); North American Electric Reliability 

Corporation, Potential Impacts of Future Environmental Regulations, November 2011 (recommending that "more 

time is needed in certain areas to ensure resource adequacy and local reliability requirements" and that "EPA .. 

employ the array of tools at their disposal and their regulatory authority to preserve bulk power system reliability . . . 

").

13 It should be noted that the 3600 MW transmission capacity limit in IPM is the electricity imports into the FRCC 

IPM region. This region is geographically identical to the state of Florida, with the exception of not including a 

small piece of the Florida panhandle. For clarity, EPA is referring to the import region in this case as “Florida” to 

distinguish it from the Florida Reliability Coordinating Council which is mentioned in this response. 
FIP Revisions – RTC 

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Page 31 

state of Florida in 2012, and then argues that IPM has violated Florida’s import capacity by 

relying on “too much” imported electricity to satisfy electricity demand. EPA finds this 

comparison to mix apples and oranges, yielding an invalid criticism of the modeling results on 

which EPA based the quantification of Florida’s state budgets. FCG is in fact supplanting the 

electricity demand assumption that EPA incorporated into its IPM modeling (based on 

projections made by the Energy Information Administration (EIA)) with a higher electricity 

demand assumption (based on projections made by the FRCC). Because FCG ignores the fact 

that IPM uses a different, EIA-based assumption for 2012 electricity demand but still compares 

the FRCC-based electricity demand assumption with IPM generation projections, FCG 

erroneously concludes that IPM-projected electricity imports into Florida would exceed the 

state’s transmission import capacity. 

EPA’s IPM projections of electricity imports into Florida are bounded by the transmission 

constraint of 3600 MW, which is described in Section 3.3.1 and Table 3-4 of the 

“Documentation for EPA Base Case v.4.10 using the Integrated Planning Model.” (EPA-HQOAR-2009-0491-0309). Therefore, EPA has properly included the transmission constraint the 

commenter described. 

FCG is implicitly claiming that IPM is flawed because its projected electricity supply (generation 

within Florida plus generation that can be imported into Florida) is inadequate to meet 2012 

electricity demand. FCG bases this argument on its FRCC-based electricity demand assumption. 

EPA believes it is more accurate to use the EIA-based assumption for 2012 electricity demand, 

as contained in the Transport Rule modeling, because it consistently applied across all regions in 

the IPM model, as opposed to using individual regionally determined demand projections that 

may be based upon inconsistent methodologies and assumptions. 

Furthermore, it is reasonable to base IPM’s regional electricity demand assumptions on EIA’s 

demand projections. Besides EIA being an authoritative source in the energy modeling 

community, the EIA projections are based on comprehensive assumptions about short- and longterm economic growth that incorporate detailed data on regional, national, and global energy 

markets (such as the price of various fuels). EPA therefore believes the EIA-based assumptions 

of future electricity demand adopted in its IPM modeling are reasonable and yield electricity 

generation projections that respect the transmission capacity import limitations identified by 

FCG. As such, EPA finds no basis in this commenter’s argument for revising the Florida 

budgets. 

FCG references the study “Potential Impacts of Future Environmental Regulations,” released by 

North American Electric Reliability Corporation (NERC). EPA notes that in this study, NERC 

found that in a moderate case, CSAPR resulted in no retirements through 2018. Only in the 

strictest case did NERC project that CSAPR would result in a modest retirement of 3.5 GW in 

2013.14 It should be noted that the NERC “Strict Case” did not model CSAPR as finalized, but 

 

14 “Potential Impacts of Future Environmental Regulations.” North American Electric Reliability Corporation. 

November, 2011. Page 117
FIP Revisions – RTC 

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Page 32 

rather arbitrarily increased costs by 25% and assumed less flexible trading.15 The NERC report 

even acknowledges EPA’s February 21, 2012 Revisions Rule that addressed out-of-merit-order 

dispatch issues, saying the revisions “will help mitigate the impact of the rule [on reliability], 

particularly in 2012 and 2013.” 

Additionally, EPA notes that the recommendations from the NERC report that FCG quotes are 

broad recommendations based on analysis of four EPA regulations, in addition to other factors 

facing the industry. NERC’s own analysis found that CSAPR would have little to no impact on 

the reliability of the bulk power system. EPA reiterates that it has considered electric reliability 

in the context of the Final Rule in the technical support document “Resource Adequacy and 

Reliability in the IPM projections for the CSAPR,” in addition to carefully reviewing comments 

on the rule and making revisions for out-of-merit-order dispatch when necessary. 

COMMENT: Also, while EPA's final Revisions Part I corrects Florida's 2012 budget to account 

for Crystal River Unit 3's uncertain in-service date, EPA should extend that correction to the 

2014 budget as part of its Revisions Part II for the reasons stated in the FCG's November 28th 

comment letter. EPA's decision to limit this correction to Florida's 2012 budget does not address 

the speculative nature of projecting the unit's in-service date and mischaracterizes both the nature 

of the required repairs (equating it to a less involved, less expensive repair16) and the operator's 

projection for an in-service date (stating the operator intends to return the unit to service "by 

2014" as opposed to "in 2014"). Moreover, recent developments further suggest that" [i]t is 

virtually certain that 2014 will not happen."17 EPA should thus increase Florida's 2014 budget by 

819; the facts do not support limiting Florida's budget forever based on EPA's speculative and 

unlikely in-service date. 

 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action.

 

15 id. pg 125

16 Compare http :1/www. reuters.com/article/2011/10/17/utilities-operations-firstenergydavisidUSN1E79GOKR20111017 (noting the 2002 Davis-Besse reactor head repair cost approximately $600 

million, including purchasing replacement power), with 

http://www.tampabay.com/news/business/energy/upcoming-pschearingon-progress-energys-25-billion-repair-bill-is/1207622 (noting estimated $2.5 billion cost of Crystal River 

Unit 3 repairs, including purchasing replacement power). 

17 See http://www.tampabay.com/news/business/energy/deciding-who-pays-repair-bill-could-delay-the-reopeningofthe-crvstal/1215722 (quoting Charles Rehwinkel, Deputy State Public Counsel with the Office of Public Counsel). 
FIP Revisions – RTC 

June 5, 2012 

Page 33 

EPA has previously responded to claims that Florida’s 2014 budget should be adjusted for the 

potential that Crystal River is not returned to service in 2014 (see section IV of the preamble to 

the final Revisions Rule (76 FR 10328-9, February 21, 2012)). Additionally, EPA notes that 

Progress Energy maintained the 2014 timeframe for completing the repairs to Crystal River unit 

3 in its February 29, 2012 10-K (http://phx.corporate-ir.net/phoenix.zhtml?c=106559&p=irolsec10K, accessed April 11, 2012). This supports EPA’s expectations of Crystal River unit 3 

being returned to service in 2014 and the quantification of Florida’s 2014 budget. 

COMMENT: 2) EPA Must Re-Run its Modeling to Address Identified Errors. 

 

In its November 28th comments concerning the Revisions Part I proposal, the FCG explained 

why EPA must re-run its Integrated Planning Model ("IPM") to address the errors in its data and 

assumptions. Given the additional errors identified in the Revisions Part II proposal, and the 

significant errors provided in comments that EPA should still correct (such as those identified by 

the FCG), the FCG reiterates that EPA must re-run its models to re-determine state budgets.18

EPA has acknowledged significant errors in the budgets of 17 states, but has not yet offered any 

justification for correcting these errors without determining how these changes affect the 

methodology and modeling that is the foundation for every budget. Given IPM's sensitivity, 

EPA's acknowledgment of significant errors in model inputs and assumptions, and the 

underlying importance of those inputs and assumptions to CSAPR's IPM-based budget 

determinations, EPA's failure to re-run its modeling and methodology is arbitrary and capricious. 

 

RESPONSE: See section 4.3 of the Preamble for this rulemaking for EPA’s response to 

comments that suggesting that EPA should re-execute full power sector modeling using the 

Integrated Planning Model (IPM) to determine state budgets. 

4. MEAG Power 

[Letter: MEAG (EPA-HQ-OAR-2009-0491-4976)] 

COMMENT: On November 22, 2011, MEAG submitted comments to this docket in connection 

with EPA's request in its Proposed Rule titled Revisions to Federal Implementation Plans to 

Reduce Interstate Transport of Fine Particulate Matter and Ozone, 76 Fed. Reg. 63,860, 63,868 

(Oct. 14, 2011). See Document ID No. EPA-HQ-OAR-2009-0491-4753. MEAG's comments,19

which incorporated its October 6, 2011 Request for Partial Reconsideration and Stay of the Final 

Transport Rule,20 established that EPA must revise Georgia's 2012 S02 emission budget and the 

allocation of such allowances to units owned or co-owned by MEAG in order to restore 

Georgia's 2012 state S02 emission budget and unit allocations to the levels in the August 2010 

 

18 See also, Lakeland Electric Comments, Docket ID: EPA-HQ-OAR-2009-0491-4770.

19 MEAG incorporates its comments in Document ID No. EPA-HQ-OAR-2009-0491-4753 as if set forth

fully herein. 

20 EPA has not acted on MEAG's Request for Partial Reconsideration and Stay of the Final Transport Rule

and it remains pending before the agency. 
FIP Revisions – RTC 

June 5, 2012 

Page 34 

proposed Transport Rule and in the January 2011 Notice of Data Availability ("NODA"), 

respectively. 

The Direct Final Rule fails to address MEAG’s comments. It leaves MEAG in the same position 

it has been since promulgation of the final Transport Rule: MEAG cannot determine why EPA 

dramatically reduced Georgia’s 2012 SO2 emission budget by greater than thirty percent (30%) 

from the proposed Transport Rule budget. See MEAG’s Req. for Partial Recons.; MEAG’s Mot. 

for a Partial Stay of EPA’s Final Transport Rule in MEAG v. EPA, Case No. 11-1379 (D.C. Cir. 

Oct. 14, 2011).21 Further, nothing in the Direct Final Rule addresses the final Transport Rule’s 

underlying fatal flaws, which have been extensively documented in the briefing filed in EME 

Homer City Generation, LP. v. EPA, Case No, 11-1302 (D.C. Cir. Aug. 23, 2011).22

RESPONSE: EPA has responded to MEAG’s comments on the proposed revisions rule, see pp. 

85-86 of the “Response to Comments on the Proposed Revisions to FIPs to Reduce Interstate 

Transport of Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963). Further, the commenters’ 

assertion that “EPA must revise Georgia's 2012 S02 emission budget and the allocation of such 

allowances to units owned or co-owned by MEAG in order to restore Georgia's 2012 state S02 

emission budget and unit allocations to the levels in the August 2010 proposed Transport Rule 

and in the January 2011 Notice of Data Availability ("NODA"), respectively” is rather novel. 

The commenter appears to be suggesting that EPA was required to ignore comments submitted 

on the proposed Transport Rule and the January 2011 NODA and was prohibited from making 

updates, corrections and revisions between proposal and final. The commenter, however, offers 

no support for such a novel assertion. The commenter does not identify any data or 

methodological basis on which EPA would have cause to revert to the state budgets and unitlevel allowance allocations estimated at the time of original Transport Rule proposal. The state 

budgets and unit-level allowance allocations EPA estimated at proposal were not determined in a 

vacuum, nor were they simply selected as program parameters with some kind of inherent 

preferential value in them of themselves. Instead, the proposal’s estimates of state budgets and 

unit-level allowance allocations were derived from detailed modeling and data analyses and were 

calculated by following computational methodologies that EPA laid out in detail at proposal. 

EPA solicited and received extensive public comment on the data and models used in the 

proposed Transport Rule as well as on the methodologies EPA applied to quantify state budgets 

and unit-level allowance allocations. If, as this commenter advocates, EPA had subsequently 

issued a final Transport Rule with identical state budgets and unit-level allowance allocations to 

those proposed, it would have suggested that EPA found no basis, in any of the thousands of 

 

21 This Motion is attached hereto and incorporated as if set forth fully herein. (The exhibits to the Motion are

being submitted electronically only, with the exception of statutory addenda, which have been omitted.) 

22 Attached hereto and incorporated in these comments as if set forth fully herein are the following briefs:

Industry/Labor Petitioners' Final Brief (Mar. 16, 2012); State and Local Petitioners' Final Opening Brief 

(Mar. 16,2012); Final Reply Brief of Industry and Labor Petitioners (Mar. 16, 2012); and Final Reply Brief of 

State and Local Petitioners (Mar. 16, 2012). (The exhibits and addenda to the foregoing Briefs are being 

submitted electronically only, with the exception of statutory and standing addenda, which have been 

omitted.) 
FIP Revisions – RTC 

June 5, 2012 

Page 35 

public comments received on the proposed Transport Rule, to adjust any modeling, any data, or 

any methodologies by which the Agency calculated state budgets and unit-level allowance 

allocations. In short, this commenter is simply expressing a preference for the endpoints EPA 

calculated at proposal (in terms of Georgia’s state budget and this commenter’s unit-level 

allowance allocations) as compared with those endpoints EPA re-calculated at final as it adjusted 

its data and methodologies based on public comments on the rule. However, the ends do not 

justify the means, and the expressed preference of the commenter is an insufficient basis on 

which to “revise” these endpoints to match those calculated in prior actions where the Agency 

was specifically seeking further information before subsequently finalizing an action.

In regards to the petition for reconsideration incorporated by reference, see the section 4.5 of the 

Preamble for this rulemaking for a discussion of petitions for reconsideration of the Transport 

Rule. 

COMMENT: At a minimum, MEAG requests that EPA act on clear technical errors in the Final 

Transport Rule that, if remedied, would likely result in an increase to Georgia’s 2012 SO2

emission budget. First, as explained below, EPA’s Response to Comments on the Proposed 

Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone," Document ID No. 

EPA-HQ-OAR-2009-0491-4963 (the "FIP Revisions RTC”), acknowledges that the 2012 Base 

Case incorrectly assumes that Plant Scherer Unit Nos. 1 and 2, which are Subpart D New Source 

Performance Standard units, switch from the historic use of 100% sub- bituminous coal to partial 

use of higher-sulfur and costlier bituminous coal. See id. at 85-86.

Second, as also explained below, the FIP Revisions RTC acknowledges that the 2012 Base Case 

incorrectly assumes that Plant Wansley Unit Nos. 1 and 2, which already use FGD systems, 

nearly triple their sulfur dioxide lb/MMBtu emission rates compared with such units’ 2010 actual 

emission rates.23 See id. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page p. 54 of this RTC, comments such as these, which relate to issues other 

than the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope 

of and not relevant to this final action. 

As stated on pp. 85-86 and pp. 203 of the “Response to Comments on the Proposed Revisions to 

FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963), 

coal switching in the base case is not meant to reflect historic operation. It reflects a scenario in 

 

23 The 2012 Base and Remedy Cases also erroneously show MEAG's well-controlled NSPS and scrubbed

units all operating less in 2012 than in 2010. 
FIP Revisions – RTC 

June 5, 2012 

Page 36 

which there is no CAIR. In this scenario, there are different economic incentives influencing coal 

choice. EPA did not and does not now acknowledge any error regarding Scherer coal switching. 

EPA confirmed that the Base Case is a scenario without CAIR that may reflect a coal choices 

differing from actual data due to the lack of CAIR. This parameter would also account for the 

difference in the Wansley Units’ emissions rates. Again, these are not errors, the base case may 

reflect fuel choices in the absence of CAIR that are different from actual. See pp. 203-204 of the 

“Response to Comments on the Proposed Revisions to FIPs to Reduce Interstate Transport of 

Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963) for further information on this point. 

COMMENT: EPA’s 2012 base case rests on the erroneous assumptions that MEAG’s use of 

100% sub-bituminous coal at Plant Scherer Unit Nos. 1 and 2 and MEAG’s use of high 

efficiency FGD systems at Plant Wansley Unit Nos. 1 and 2 are solely driven by the Clean Air 

Interstate Rule (CAIR). This is plain from EPA’s justification for its base case coal-switching 

assumptions as stated in the FIP Revisions RTC: “In regard to coal switching in the base case, 

the base case is not simply meant to reflect historic operation. It reflects a scenario in which there 

is no CAIR. In this scenario, there are different economic incentives influencing coal choice.” Id. 

at 86.

 

EPA’s base case assumptions concerning Plants Scherer and Wansley are not only counterfactual 

but also strain credulity. Plant Scherer Unit Nos. 1 and 2 switched to 100% sub-bituminous coal 

in 2003 in anticipation of the Regional NOX SIP Call requirements (the use of sub-bituminous 

coal rather than bituminous coal results in lower NOX emission rates for the units). Both units 

have burned such coal since January 2004. CAIR played no role in this historic fuel switch. And, 

given that the coal switch to sub-bituminous coal was driven by Regional NOX SIP Call 

requirements and continued use of sub-bituminous coal was driven by a Georgia ozone SIP rule, 

see Ga. Comp. R. & Regs. 391-3-.02(2)(jjj), all economic (and regulatory) incentives point to the 

units’ continued use of sub-bituminous coal in any realistic base case for the final Transport 

Rule. For EPA to have assumed otherwise lacks any basis in fact or reality. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page p. 54 of this RTC, comments such as these, which relate to issues other 

than the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope 

of and not relevant to this final action. 

Please see the response above regarding why Scherer and Wansley coal switching and emissions 

rates in 2012 base case modeling may differ from actuals. The Scherer units may have originally 

switched to sub-bituminous coal in response to the Regional NOX SIP Call, but in the absence of 

CAIR or the Transport Rule, EPA’s modeling projects that fuel choice would change. Any 

applicable SIP requirements outside of CAIR that are currently in place are assumed in the IPM 

Base Case, see Chapter 3 of the “Documentation for EPA Base Case v.4.10: Using the Integrated 
FIP Revisions – RTC 

June 5, 2012 

Page 37 

Planning Model” (Docket No. EPA-HQ-OAR-2009-0491-0309) which states, “Unit-level SO2

regulations arising out of State Implementation Plan (SIP) requirements, which are not only state 

specific but also county specific, are captured at model set-up in the coal choices given to coal 

fired existing units in EPA Base Case v.4.10. The SIP requirements define ‘regulatory SO2 3-18 

emission rates.’ Since SO2 emissions are dependent on the sulfur content of the fuel used, the 

regulatory SO2 emission rates are used in IPM to define fuel capabilities.” (Ch. 3 pp. 17-18) 

Furthermore, the commenter’s criticisms of EPA’s base case emission projections (without the 

Transport Rule in place) have no relevance to the Agency’s quantification of Georgia’s state 

budgets or unit-level allowance allocations under the Transport Rule, which is the subject of this 

rulemaking.

COMMENT: Similarly, MEAG installed FGD systems at Plant Wansley Unit Nos. 1 and 2 in 

order to comply with the mandates of Georgia’s Multipollutant Control Rule, which required the 

operation of FGD at Plant Wansley Unit 1 by December 31, 2008 and the operation of FGD at 

Unit 2 by December 31, 2009. See Ga. Comp. R. & Regs. 391-3-.02(2)(sss)(1)(iii) and 393-3-

.02(2)(sss)(3)(ii). In light of this fact, EPA cannot realistically assume that the absence of CAIR 

in the base case scenario would have resulted in economic incentives that would have driven 

MEAG to drastically change its historic operations of Plant Wansley Units 1 and 2 in a way that 

would result in the non-operation of FGD (in violation of Georgia law), the less efficient 

operation of FGD, and/or the use of coal with a higher sulfur content. EPA simply lacks any 

basis, factual or otherwise, in the administrative record to make such assumptions.

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page p. 54 of this RTC, comments such as these, which relate to issues other 

than the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope 

of and not relevant to this final action. 

 

The commenter incorrectly assumes that the 2012 base case does not run the FGD units at 

Wansley. The base case assumes operation of the Wansley Unit 1 and 2 FGD controls, as 

reflected in SO2 emission rates (see WebReady_ParsedFile_TR_Base_Case_Final_2012 (Docket 

No. EPA-HQ-OAR-2009-0491-4420). The difference in emissions rates are due to coal 

switching that the model implemented in the base case, and as stated in the response above and 

in the referenced response to comment (see pp. 203-204 of the “Response to Comments on the 

Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963), the base case is not meant to reflect historic operation. It reflects a 

scenario in which there is no CAIR. 

COMMENT: EPA’s erroneous base case assumptions likely resulted in a significant reduction to 

Georgia’s final 2012 SO2 emission budget and a correspondingly severe reduction in the 

allocation of SO2 emission allowances to MEAG units. For EPA to have ignored these errors in 
FIP Revisions – RTC 

June 5, 2012 

Page 38 

the Direct Final Rule, while simultaneously making changes to other state budgets to correct 

similar errors, is arbitrary, capricious, an abuse of its discretion and contrary to law. see 77 Fed. 

Reg. at 10,343 (revising Georgia’s 2014 SO2 and NOX emission budgets to correct pollution 

control equipment assumptions); at 10,344 (revising Ohio’s 2012 and 2014 NOX emission 

budgets to correct pollution control equipment assumptions); at 10,344 (revising Nebraska’s 

2012 and 2014 SO2 emission budgets to correct FGD pollution control technology assumptions); 

at 10,345 (revising South Carolina’s 2012 and 2014 SO2 emission budgets to correct FGD 

pollution control technology assumptions). This is particularly the case when, from 2000 to 

2010, MEAG invested approximately $302.7 million in the above and other environmental 

projects to achieve compliance with the Clean Air Act and Georgia air regulatory requirements; 

none of the amount invested was primarily driven by CAIR.

MEAG again requests that EPA revise Georgia’s 2012 SO2 emission budget and the allocation of 

such allowances to units owned or co-owned by MEAG - in order to restore Georgia’s 2012 SO2

emission budget and unit allocations to the levels in the proposed Transport Rule and in the 

January 2011 NODA, respectively. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page p. 54 of this RTC, comments such as these, which relate to issues other 

than the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope 

of and not relevant to this final action. 

EPA has responded to these comments in this response to comment and on pp. 85-86 of the 

“Response to Comments on the Proposed Revisions to FIPs to Reduce Interstate Transport of 

Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963). The base case includes all investments 

related to the Clean Air Act, with the exception of CAIR related investments. Regarding 

investment relevant to Georgia requirements, EPA described in the Final Rule how it treated 

extant capital investments resulting from state laws in control technologies as “sunk” capital 

costs (76 FR 48223-48224).

5. Wisconsin Department of Natural Resources 

[Letter: Wisconsin Department of Natural Resources (EPA-HQ-OAR-2009-0491-4977)] 

COMMENT: Under this notice EPA is proposing additional technical corrections to Cross-State 

Air Pollution Rule (CSAPR) emission budgets for several states based on comments received in 

response to the October 14, 2011 CSAPR emission budget notice. EPA is not proposing any 

additional corrections to the Wisconsin emissions budgets. 

 

However, based on the corrections EPA is proposing in this notice, we believe EPA must make 

similar corrections to Wisconsin's CSAPR emission budgets as presented in the following 
FIP Revisions – RTC 

June 5, 2012 

Page 39 

discussion. We also identified these Wisconsin specific corrections in response to the same 

October 2011 emissions budget notice. The Department's comments to the October notice, 

including suggested unit emission levels, are included for reference as Attachment 1. 

 

Omitted Generating Units — In this notice EPA is proposing to add emissions to represent the 

operation of generation units which were omitted from the IPM projected emission budgets. In 

our comments to the October 2011 notice, Table 6, we identified a number of Wisconsin 

generation units that were not included in the IPM modeling effort. The omitted Wisconsin units 

are Manitowoc Public Utilities Unit 8 and Xcel Energy Bayfront Units 1, 2, and 5. Similar to 

actions proposed for other states, we request that EPA add emissions for these generation units. 

We recommend using operational and emission levels based on 2011 data reported to the Clean 

Air Markets Division (CAMD). 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

As explained on page 29 of the RTC Document for the revisions rule, the Manitowoc and 

Bayfront units were included in the IPM modeling effort. Commenters’ claim that these units 

were not included is not accurate (see Response to Comments on the Proposed Revisions to FIPs 

to Reduce Interstate Transport of Fine PM and Ozone; EPA-HQ-OAR-2009-0491-4963 and the 

NEEDS inventory of EGUs used in the modeling at EPA-HQ-OAR-2009-0491-4507). 

Moreover, commenter’s assertion that EPA is increasing budgets based on omitted units in other 

states is incorrect and commenter provides no such list of omitted units for which they claim 

EPA has made such adjustments. EPA has adjusted certain state budgets to reflect immediateterm out-of-merit-order dispatch from units where such dispatched generation (at units that were 

represented in EPA’s modeling) was not previously accounted for in EPA’s analysis. These 

budget adjustments have all pertained to units included in the model, not “omitted” units. 

COMMENT: Non-Economic Dispatch Units — EPA determined the CSAPR emission budgets 

by allowing the integrated planning model (IPM) to dispatch electric generating units on an 

economic basis. EPA is now proposing to increase emission budgets in a number of states to 

account for numerous generating units which in reality are dispatched based on non-economic 

factors and at operating levels higher than predicted by IPM. 

 

In our comments to the October notice, Table 5, we identified that the We Energies Valley plant 

is dispatched based on non-economic factors. This plant produces steam that is used for both 

electricity generation and for district heating and cooling to customers in downtown Milwaukee. 
FIP Revisions – RTC 

June 5, 2012 

Page 40 

Currently, there are no other options in meeting this district steam service and Valley must 

therefore meet these minimum demand loads. The IPM model, however, predicts that the Valley 

plant will not operate at all by 2014 and beyond. Therefore, consistent with EPA's proposed 

changes for non-economic dispatch in other states, we believe that EPA needs to account for 

minimum operation of the Valley plant. We suggest that EPA apply the operational levels 

demonstrated by data reported to the CAMD database. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

See page 29 of the Response to Comments on the Proposed Revisions to FIPs to Reduce 

Interstate Transport of Fine PM and Ozone; EPA-HQ-OAR-2009-0491-4963 where EPA 

addressed the commenter’s comment on the October 2011 proposal.24 Furthermore, the 

commenter has not provided sufficient data on how often this non-economic generation is 

necessitated in the ozone-season and calendar year, as specifically requested in the October 2011 

proposal (76 FR 63868). While the commenter suggests using historic operation levels as the 

basis for a revision, it is not clear that this data represents non-economic generation or “must 

run” levels. For instance, the commenter suggests using 2008-2010 heat input or projected 2012 

heat input levels as a surrogate for 2014 heat input. Doing so and adjusting the budget 

accordingly, they claim, would accurately capture the “must run” operating requirements of the 

Valley Plant. However, the commenters very own 2011 reported data demonstrates that the plant 

can and does operate at levels below these claimed “must run” levels (CAMD Air Markets 

Program Data (AMPD)). The Valley coal facility’s 2011 heat input (11 Tbtus) is approximately 

20% lower than its 2009 heat input (13.8 Tbtus), thus contradicting the notion that 2009 levels 

are “must run” operating levels. 

 

COMMENT: Deadlines for Existing Requirements and Committed Control Equipment — EPA 

is proposing to increase emission levels to be consistent with "reductions that occur due to state 

rules, consent decrees, and other planned changes in generation patterns that occur after 2012, 

but during or prior to 2014". EPA is specifically proposing that Georgia's 2014 emission budgets 

be increased to reflect that the compliance date for a state rule is after 2014 and that equipment 

currently being installed for that purpose should not be reflected in the 2014 emissions budget. 

 

24 “The 2014 state budgets are based on a distinct set of emission projections specifically tied to modeling of a 

least-cost equilibrium between electricity supply and demand in that year. The model does not simply assume that 

2014 operation of a particular unit will mirror 2012 operation, as suggested by commenter, as that would imply a 

static industry (unchanging over time).”
FIP Revisions – RTC 

June 5, 2012 

Page 41 

We believe EPA is correct in adjusting Georgia's emission budget. This approach acknowledges 

that installation of equipment is scheduled in order to meet the compliance deadlines and allows 

for delayed construction, contingencies and a shakedown period before reliable emission 

reductions can be expected. A situation where installation of control equipment is proceeding or 

scheduled in the near term is significantly different from existing control equipment with an 

established operating history. 

 

Similar to the Georgia case, control equipment is currently being installed at several Wisconsin 

power plants in order to meet future regulatory requirements. However, EPA is counting the 

anticipated emission reductions from this control equipment towards the 2012 and 2014 CSAPR 

emission budgets, earlier than the installation and compliance schedules. We believe, based on 

the Georgia proposal, that EPA should correct the following cases. These corrections were 

initially identified in Table 2 of our comments to the October emission budget notice. 

 

1) Currently, the 2012 Wisconsin CSAPR emission budget includes reductions from a SCR 

system currently being installed at the Edgewater 5 unit. The most recent schedule is to have the 

SCR connected by January 2013 and fully operating by May 1, 2013 in order to meet the 

Wisconsin NO„ reasonably available control technology (RACT) rule compliance date. This 

schedule is very similar to the schedule Alliant Energy stated in their comments to the October 

2011 CSAPR emission budget notice. Clearly emission reductions should not be counted 

towards the 2012 CSAPR emission budget. 

 

2) The 2012 Wisconsin CSAPR emission budget counts emission reductions from both selective 

catalytic reduction (SCR) and SO2 wet scrubber systems being constructed at the Oak Creek 7 

and 8 generation units. This equipment is still under construction and is intended to meet the We 

Energies Consent Decree compliance date of December 31, 2012. EPA should not count 

emission reductions at Oak Creek 7 and 8 for 2012 based on a compliance date on the very last 

day of the year. 

 

3) In another case, dry SO2 scrubbers are being installed on the two Columbia generation units 1 

and 2. This equipment was approved in March 2011 by the Wisconsin Public Service 

Commission and scheduled with the intention of meeting the CAR 2015 emission budgets and a 

Wisconsin 2015 mercury control requirement. Initially, we commented that emission reductions 

could be counted towards CSAPR emission budgets for both scrubber units beginning May 2014 

(Table 2, October comments). But a different schedule applies as discussed below. 

 

The current installation schedule for Columbia, as approved by the Midwest Independent System 

Operators (MISO), requires the two unit outages to be staged with the first scrubber coming 

online by April 30, 2014 and the second scrubber coming online by June 30, 2014. Alliant 

Energy, the operator of the Columbia Plant, has stated that they believe a six month period 

should be allowed for start-up and shakedown before counting on reliable emission reductions. 

We fully support this assertion for a shakedown period based on experience with other recent 

Wisconsin power plant scrubber installations. Alliant Energy identified a similar installation 

schedule and the six month shakedown time in their comments to the October 2011 CSAPR 

emission budget notice. 
FIP Revisions – RTC 

June 5, 2012 

Page 42 

 

On this basis, full control from the second scrubber should not be expected until the originally 

targeted CAIR 2015 compliance year. Clearly circumstances similar to the Georgia case apply to 

the Columbia scrubbers and on this basis we believe emission reductions resulting from both 

scrubbers should not be counted towards the 2014 CSAPR emission budget. At a minimum, EPA 

must consider that emission reductions from the first scrubber should not be relied on before 

November 2014 (April, 2014 + six months). 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA has previously responded to these comments (see Response to Comments on the Proposed 

Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone; EPA-HQ-OAR-2009-

0491-4963, p. 36). EPA also responds to comments regarding budget adjustments based on 

control installation timing in section IV.4 of the Preamble for this rulemaking. 

 

COMMENT: We appreciate EPA's continued effort to evaluate and implement corrections to 

the CSAPR emission budgets. Beyond these corrections based on actions in EPA's current 

notice, we request that EPA also address incorrect emission rates and fuel switching assumptions 

which we identified in Tables 2 and 3 of our comments to the October notice. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA previously responded to these comments on pages 30-35 of the document “Response to 

Comments on the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and 

Ozone.” (EPA-HQ-OAR-2009-0491-4963) 

6. Duke Energy 

[Letter: Duke Energy (EPA-HQ-OAR-2009-0491-4979)] 
FIP Revisions – RTC 

June 5, 2012 

Page 43 

COMMENT: In its comments, Duke Energy identified technical corrections that needed to be 

made at W S Lee units 1-3 in South Carolina and R Gallagher units 2 and 4 and Gibson unit 5 in 

Indiana. In the Agency’s Direct Final Rule EPA made adjustments to the South Carolina and 

Indiana 2012 and 2014 SO2 budgets that accurately reflect the corrections at W S Lee and R 

Gallagher that Duke Energy identified. Duke Energy therefore agrees with the SO2 budget 

adjustments EPA has made for South Carolina and Indiana with respect to these two facilities. 

 

In its Direct Final Rule, EPA also made an adjustment to the Indiana 2012 and 2014 SO2 budgets 

related to Gibson unit 5. The adjustment EPA made is based on the fact that a small amount of 

the flue gas (indicated at 2% in EIA Form 860) at Gibson unit 5 bypasses the scrubber. EPA 

therefore adjusted the SO2 emissions for Gibson unit 5 to reflect this amount of flue gas 

bypassing the scrubber by increasing the Indiana 2012 and 2014 SO2 budgets by the difference 

between EPA’s calculated revised SO2 emissions of 6,801 tons and 4,928 tons of SO2 emissions 

for the unit from the final Transport Rule remedy for 2012 (TR_Remedy_Final).2 Duke Energy 

had overlooked in its November 28th comments the fact some of the flue gas at Gibson Unit 5 

bypasses the scrubber, and appreciates EPA recognizing this fact and making an adjustment for 

it. The problem is, however, that EPA continues to use a 95% SO2 removal rate for the Gibson 

unit 5 scrubber, which as Duke Energy explained in its November 28, 2011 comments to the 

Agency, and explains again in these comments, is entirely inappropriate. The removal efficiency 

EPA should be using for Gibson unit 5 is 85%; the same removal efficiency EPA had used for 

the unit throughout the Cross State Air Pollution Rule (CSAPR) rulemaking up until the final 

rule when EPA either inadvertently or arbitrarily and incorrectly revised the efficiency up to 

95%. 

As shown in the following table, which is a recreation of Table C.3.b from EPA’s February 2012 

Final Revisions Rule State Budgets and New Unit Set-Asides TSD for the Final Revisions to the 

Transport Rule (“TR Final Revisions TSD”), using an 85% SO2 removal efficiency instead of 

95%, and accounting for the 2% flue gas bypass, yields a Net Budget Revision for Gibson unit 5 

of 11.532 thousand tons instead of the 1.873 thousand tons EPA has included in its Direct Final 

Rule for Gibson unit 5. EPA should therefore add 9.659 thousand tons (the difference between 

11.532 thousand tons and 1.873 thousand tons) to the 5.338 thousand tons EPA added in the 

Direct Final Rule to Indiana’s 2012 and 2014 CSAPR SO2 budgets. 

In both the NEEDSv3.02 database and the NEEDSv4.10 database that EPA put out for public 

comment on September 1, 2010, the Gibson unit 5 scrubber was appropriately shown at 85% 

efficiency. In the proposed Transport Rule EPA switched Gibson 5 to a 1.4 lb sulfur coal that 

along with the 85% scrubber efficiency produced a 0.21 lbs/mmBtu SO2 emission rate. Duke 

Energy commented that the unit was not capable of burning a 1.4 lb sulfur coal without costly 

equipment upgrades that couldn’t be completed by 2012. In the final Transport Rule EPA 

appropriately increased the sulfur content of the coal assigned to Gibson unit 5 to 4.2 lb sulfur, 

but then arbitrarily increased the unit’s scrubber efficiency from 85% to 95%, as reflected in the 

NEEDSv410_FTransport.xls file. The combination of the higher sulfur content coal and higher 

efficiency produce the same 0.21 lbs/mmBtu SO2 emission rate that was modeled as part of the 

proposed Transport Rule. This seems an odd coincidence. 
FIP Revisions – RTC 

June 5, 2012 

Page 44 

The Gibson unit 5 scrubber is not capable of achieving 95% removal efficiency, because of its 

initial design. The scrubber is made up of 4 identical absorbers that are oriented horizontally 

instead of vertically, as almost all other FGD absorbers are. The absorbers have a rectangular 

cross section. A separate tank (reaction tank) is located below each of the absorbers and the 

slurry from each absorber drains into the reaction tank through large rubber hoses. The slurry in 

the reaction tank is agitated to keep the solids suspended. Prior to an upgrade in 2008 the reagent 

(limestone slurry) was sprayed into each absorber through nozzles located in the top or ceiling of 

the absorber. The spray traveling downward pushed the flue gas toward the bottom of the duct 

resulting in high gas flow at the bottom of the duct and ineffective contact between the slurry and 

the flue gas. The high velocity at the bottom of the mist eliminators caused carry over into the 

ductwork downstream and plugged the mist eliminators. The plugged mist eliminators required 

frequent absorber outages for cleaning. The typical SO2 removal achieved by the original 

scrubber was 80%. 

In 2008 the absorbers were upgraded to increase SO2 removal and improve reliability at a cost of 

$40M. The slurry nozzles in the top of the absorber were replaced with slurry headers and high 

efficiency nozzles inside the absorber, oriented such that the nozzle flow was in the same plane 

as the flue gas, not perpendicular to it. The slurry pump capacity was increased and the mist 

eliminator design and wash system were upgraded. Oxidation air was added to the reaction tanks 

to reduce scale growth and DBA chemical feed system was added to maximize SO2 removal. 

Performance has increased so that an 85% removal can be routinely achieved, but only with the 

addition of DBA. 

The upgrade did improve the overall performance but it missed the goal of reaching >90% SO2

removal, and the scrubber still has reliability problems, many of which are caused by its initial 

design. The absorbers are too short. There is not enough distance between the slurry nozzles and 

the mist eliminators, so the mist eliminators continue to plug. Thus additional slurry headers 

can’t be added to increase SO2 removal. The slurry header arrangement is such that most of the 

slurry drains into the reaction tank at one end which causes pH variations across the reaction tank 

and reduced SO2 removal. After extensive analysis, Duke Energy has concluded that due to these 

physical and chemical constraints, it is impractical to correct these problems and achieve a 95% 

removal rate. The only alternative that would achieve a 95% removal rate would be to totally 

replace the scrubber which obviously cannot be achieved by 2012 or 2014. 

Based on this information, assigning 95% removal efficiency to the Gibson unit 5 scrubber is 

clearly in error. Duke Energy requests that EPA both change the efficiency of the Gibson unit 5 

scrubber back to 85%, maintain the same coal sulfur content (4.2 lbs.) assigned to the unit in the 

final Transport Rule, and make the appropriate adjustments to the Indiana SO2 budget, assurance 

level, and unit level allocations. 

In EPA’s October 14, 2011 Revisions to Federal Implementation Plans to Reduce Interstate 

Transport of Fine Particulate Matter and Ozone proposed rule (76 Fed. Reg. 63860), EPA 

proposed to make revisions to the SO2 emission rates and emissions of several units in Texas 

based on 2008 EIA 923 reported data.4 As a result of EPA’s proposal to use 2008 data from EIA 

Form 923, Duke Energy reviewed that data for its Gibson unit 5. As a result of its review of the 
FIP Revisions – RTC 

June 5, 2012 

Page 45 

2008 scrubber efficiency data in Schedule 8F of EIA Form 923 for Gibson unit 5, Duke Energy 

discovered two errors. The first was that Duke Energy transposed the scrubber efficiency 

numbers for Gibson units 3 and 5 when submitting them to EIA. The second was that Duke 

Energy made an error in its calculation of the annual scrubber efficiency for Gibson unit 5 for 

2008. The efficiency Duke Energy initially reported to EIA for 2008 for Gibson 3, which was 

actually the efficiency for unit 5, was 89.3%. Upon correcting the error that was made in the 

initial calculation of that number, the 89.3% should have been 83.3%. Duke Energy immediately 

notified EIA of these reporting errors and what the correct numbers should be, and was notified 

that the corrections had been made. 

Looking at more recent EIA 923 data, the scrubber efficiency Duke Energy submitted to EIA for 

Gibson unit 5 for 2009 was 84.7%, and for 2010 it was 81.4%. The 2008, 2009, and 2010 data 

points for the efficiency of the Gibson unit 5 scrubber, each of which is below 85%, support 

Duke Energy’s request that EPA reduce the scrubber efficiency of Gibson unit 5 from 95% back 

to 85% while maintaining the same coal sulfur content assigned to the unit in the final Transport 

Rule, and make the appropriate adjustments to the Indiana SO2 budget, assurance level, and unit 

level allocations. 

In its Direct Final Rule, EPA seems to have moved away from the use of EIA 923 data in favor 

of EIA 860 data.6 Table C.3.b.: Calculation to Determine Indiana SO2 Budget Adjustment – 

Assuming Revised SO2 removal Rates at FGD from EPA’s TR Final Revisions TSD shows that 

for Gibson unit 5 EPA used the 2008 SO2 removal rate of 95% from EIA 860. Duke Energy 

cannot render an opinion as to the appropriateness of using EIA 860 data for other units, but for 

Gibson unit 5, the use of EIA 860 data instead of EIA 923 data is entirely inappropriate. As 

stated on the reporting form for EIA 860 (SCHEDULE 6. PART H. FLUE GAS 

DESULFURIZARION UNIT INFORMATION, DESIGN PARAMETERS), the data to be 

reported for the removal efficiency of SO2 is to reflect the “Design Specifications of Flue Gas 

Desulfurization Unit at 100 Percent Generator Load.” In the case of Gibson unit 5, and as 

indicated above, the design removal efficiency for the 2008 scrubber upgrade was in fact 95%. 

Also as indicated above, the Gibson unit 5 scrubber upgrade failed to come close to achieve the 

design removal efficiency, and it continues to significantly underperform relative to that target as 

evidenced by recent EIA 923 data. 

EIA 923 data is the appropriate data for EPA to use to calculate the Gibson unit 5 Net Budget 

Revision because it reflects actual SO2 removal rates, not design specifications as reported in 

EIA 860 that in this instance are not at all representative of actual performance. It is arbitrary for 

EPA to ignore actual operating data in favor of design data that has clearly been shown not to be 

representative of the SO2 removal efficiency of the Gibson unit 5 scrubber. 

 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. (77 FR 10350) The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 
FIP Revisions – RTC 

June 5, 2012 

Page 46 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

EPA responded to this comment regarding the scrubber efficiency at Gibson unit 5 in section V.3 

of the Preamble for this rulemaking and explained why EIA 860 was used instead of EIA 923 

data. Because EPA did not rely on EIA 923 data, the commenter’s assertion that it erred twice 

when reporting EIA 923 data is not relevant. 

 

7. Georgia Department of Natural Resources 

[Letter: Georgia Department of Natural Resources (EPA-HQ-OAR-2009-0491-4980)]

COMMENT: U.S. EPA states that the revisions are the result of adjustments to unit-specific 

operational information, including post-combustion pollution control equipment. While EPD 

does not have the details regarding the adjustments made to the unit-specific information for 

Georgia, it appears that U.S. EPA corrected the installation date for controls on a number of units 

from 2014 to 2015. 

RESPONSE: EPA acknowledges Georgia Department of Natural Resource’s comment 

COMMENT: This error and other errors had been previously brought to U.S. EPA’s attention.25

While U.S. EPA’s Direct Final Rule and Proposed Rule correct Georgia’s budgets for one type 

of unit-specific error, EPD’s comments and Georgia’s Petition show there are other significant 

errors in the Cross-State Transport Rule as it applies to Georgia, including but not limited to: 

 

(1) The projected SO2 emissions from EGUs used by U.S. EPA in its modeling for CSAPR 

(406,279 tons) are one and one-half times higher than EPD’s projected emissions (232,952 tons). 

See Petition at 10-11. 

 

(2) U.S. EPA took into account emission reductions achieved by the installation of controls in 

the future required by Georgia’s rule, “Multipollutant Control for Electric Utility Steam 

Generating Units,” Ga. Comp. R. & Regs. r. 391-3-1-.02(2)(sss), but gave $0 credit against 

CSAPR’s remedy cost thresholds of $500 per ton. Id. at 27-28. The effect is that CSAPR 

 

25 EPD submitted comments on (1) U.S. EPA’s proposed rule, “Federal Implementation Plans to Reduce Interstate 

Transport of Fine Particulate Matter and Ozone” (referred to herein as the “Proposed Transport Rule”), published at 

75 Fed. Reg. 45310 (Aug. 2, 2010), see Document I.D. No. EPA-HQ-OAR-2009-0491-2647; (2) on U.S. EPA’s 

proposed rule, “Approval and Promulgation of Air Quality Implementation Plans; Georgia; Disapproval of Interstate 

Transport Submission for the 2006 24-Hour PM2.5 Standard” (referred to herein as the “Proposed SIP Disapproval 

Rule”), published at 76 Fed. Reg. 4584 (Jan. 26, 2011); see Document I.D. No. EPA-R04-OAR-2010-1012-0004; 

and (3) on U.S. EPA’s proposed rule, “Revisions to Federal Implementation Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone,” published at 76 Fed. Reg. 63860 (Oct. 14, 2011), see Document I.D. No. EPAHQ-OAR-2009-0491-4756. In addition, the State of Georgia submitted a Petition for Reconsideration and Stay on 

the Cross-State Air Pollution Rule (“Petition”) to U.S. EPA on October 6, 2011, which is still pending. EPD’s 

comments and the Petition are incorporated herein as if fully set forth.
FIP Revisions – RTC 

June 5, 2012 

Page 47 

requires EGUs in Georgia to “over-reduce” emissions and penalizes Georgia for enacting a state 

rule requiring reductions. 

As a result of these errors, Georgia’s budgets as revised by the Direct Final Rule and the 

Proposed Rule are still too low. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final (77 FR 

10342) were merited. See 77 FR 10350. It was narrowly focused on the adjustments included in 

the direct final rule and did not reopen any other issues for comment. In sum, and as explained in 

greater detail on page 54 of this RTC, comments such as these, which relate to issues other than 

the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and 

not relevant to this final action. 

 

The commenter raises issues that are similar to those raised in Georgia’s Petition for 

Reconsideration. See section 4.5 of the Preamble for this rulemaking for a discussion of 

Petitions for Reconsideration of the Transport Rule. 

Moreover, these comments were previously submitted in response to the October 14, 2011 

proposed CSAPR Revisions Rule and EPA provided response to those comments in sections 1.8 

and 1.9 of the “Response to Comments on the Proposed Revisions to FIPs to Reduce Interstate 

Transport of Fine PM and Ozone.” (EPA-HQ-OAR-2009-0491-4963) As described in the 

preamble to the final Transport Rule on page 76 FR 48223, EPA did not include CAIR emission 

reductions in the 2012 baseline. Specifically, and in addition, in the preamble to the final 

Transport Rule on page 76 FR 48224 EPA explained that it did not include emission reductions 

unless those reductions were mandated by existing emission limitation requirements The 

development of the emission inventories is described in 76 FR 48224 through 48227 and in the 

Emission Inventory Final Rule TSD (EPA-HQ-OAR-2009-0491-4522). Thus, estimates of 

expected emissions based on current conditions, or estimates of 2012 with CAIR in place, are not 

comparable to the estimated emissions in the Transport Rule base case where emission 

reductions directly related to CAIR are not included. 

In response to the second comment raised, on 76 FR 48223 and 48224, EPA described how it 

treated extant capital investments resulting from state laws in control technologies as “sunk” 

capital costs. 

Consequently, EPA has properly accounted for emission reductions for Georgia to eliminate its 

significant contribution and interference with maintenance. 

 

COMMENT: Because of these significant adverse comments, EPD requests that U.S. EPA 

withdraw the Direct Final Rule. See 77 Fed. Reg. 10342. Should U.S. EPA not withdraw the 

Direct Final Rule, EPD requests that the rule be stayed for the reasons set forth herein and 

because the CSAPR has been stayed by the United States Court of Appeals for the District of 
FIP Revisions – RTC 

June 5, 2012 

Page 48 

Columbia Circuit. See EME Homer City Generation, L.P. v. EPA, Case No. 11-1302, Order 

(D.C. Cir. Dec. 30, 2011). 

 

RESPONSE: The direct final rule was withdrawn on May 16, 2012. (77 FR 28785) 

8. Luminant 

[Letter: Luminant (EPA-HQ-OAR-2009-0491-4982)] 

COMMENT: Insofar as they go, Luminant supports the additional revisions to CSAPR made in 

the Proposed Rule and Direct Final Rule. As to Texas, where Luminant operates, the Proposed 

Rule adjusts Texas’s NOX annual and ozone season budgets to 137,701 and 65,560 tons, 

respectively, in order to “account for operational constraints at six plants based on comments 

received on the revisions rule.” 77 Fed. Reg. at 10,345, 10,347–78. Luminant agrees that these 

increases in Texas’s NOX budgets are appropriate and should be finalized. 

 

Further, Luminant does not understand the Proposed Rule or Direct Final Rule to take or propose 

action (either accepting or rejecting) on Luminant’s request for reconsideration dated August 5, 

2011 (as supplemented on September 9 and 28, 2011), or Luminant’s comments on the Final 

Revisions Rule. See Luminant’s Comments on Revisions to Federal Implementation Plans to 

Reduce Interstate Transport of Fine Particulate Matter and Ozone, 76 Fed. Reg. 63,860 (Oct. 14, 

2011), Document EPA-HQ-OAR-2009-0491-4818. Based on EPA’s Response to Comments for 

the Final Revisions Rule, Luminant understands that EPA took final action to deny both its 

request for reconsideration and its comments and proposed additional revisions when it took 

final action on the Final Revisions Rule published at 77 Fed. Reg. 10,324 (Feb. 21, 2012). See 

Response to Comments, Document No. EPA-HQ-OAR-2009-0491-4963, at 48–69, 73–74, 82, 

145, 152, 161, 170, 174, 199–201 (Feb. 3, 2012); see also 77 Fed. Reg. at 10,325 (“EPA also 

addressed some of the issues and concerns raised in many of the petitions for administrative 

reconsideration of the final Transport Rule.”). 

 

Even though these matters were dealt with in the Final Revisions Rule, to the extent that EPA 

withdraws the Direct Final Rule and, as part of its action on the Proposed Rule, considers 

comments on previously-decided aspects of CSAPR or revisions to emissions budgets other than 

the specific revisions addressed in the Direct Final Rule, Luminant is protectively resubmitting 

and renewing its request for reconsideration and its comments on the Revisions Rule for the 

agency’s consideration as part of that proceeding. 

RESPONSE: EPA published a withdrawal of the Direct Final Rulemaking in the Federal 

Register on May 16, 2012 (77 FR 28785) and is now taking final action on the parallel proposal 

that was published simultaneously with the direct final rule. EPA previously considered and 

responded to Luminant’s comments on the proposed revisions (see Response to Comments on 

the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone; EPA-HQOAR-2009-0491-4963). The commenter is not offering any comments on this direct 

final/parallel proposal that were not previously submitted to the Agency. 
FIP Revisions – RTC 

June 5, 2012 

Page 49 

Further, contrary to the commenter’s suggestion, EPA has taken no final action to deny 

Luminant’s petition for reconsideration. Section 307(d)(7)(B) of the Clean Air Act provides a 

procedural mechanism for parties to petition the Agency to reconsider a rule. The section directs 

the Administrator to convene a proceeding for reconsideration only if the petitioner can 

demonstrate that it was impracticable to raise a particular objection within the comment period or 

that the grounds for the objection arose after the period for public comment (but within the time 

specified for judicial review) and that the objection is of central relevance to the outcome of the 

rule. EPA is in the process of reviewing all petitions for reconsideration received on the 

Transport Rule, including the petition referenced by the commenter to determine if they meet 

this standard and will take appropriate action in due course. 

 

The commenter references EPA’s Response to Comments for the Final Revisions Rule, and 

states that based on that document, it “understands that EPA took final action to deny... its 

request for reconsideration.” However, as the comment notes, the response to comments 

document, merely notes that the Final Revisions Rule published at 77 Fed. Reg. 10,324 (Feb. 21, 

2012) ”also addressed some of the issues and concerns raised in many of the petitions for 

administrative reconsideration of the final Transport Rule.” Among other things, the RTC does 

not even mention the criteria that must be applied to determine when reconsideration is 

warranted – that is whether the petition demonstrates that it was impracticable to raise the 

objection during the comment period or whether the objection is of central relevance to the 

outcome of the rule. 

 

The Response to Comments document for the final revisions rule only addressed comments on 

the proposed final revisions rule. EPA did not take action, as commenter asserts, in that or any 

other RTC to deny any aspect of the commenter’s Petition for Reconsideration. EPA recognizes 

that, because the criteria for evaluating petitions for reconsideration focus on whether it was 

practicable for the commenter to raise a particular objection during the comment period for a 

rule, the additional opportunity for comment provided in the revisions rule may have rendered 

portions of particular Petitions for Reconsideration moot. However, EPA has neither specifically 

identified any such Petitions nor discrete issues contained therein as moot, nor acted to deny any 

aspect of the Petition for Reconsideration submitted by the commenter. 

9. Utility Air Regulatory Group (UARG) 

[Letter: Utility Air Regulatory Group (EPA-HQ-OAR-2009-0491-4985)] 

COMMENT: The Utility Air Regulatory Group (“UARG”)26 submits the following comments 

on EPA’s February 21, 2012 direct final rule on “Revisions to Federal Implementation Plans To 

Reduce Interstate Transport of Fine Particulate Matter and Ozone” (“Direct Final Rule”). 77 Fed. 

 

26 UARG is a voluntary, not-for-profit association of electric generating companies and organizations and national 

trade associations. UARG’s purpose is to participate on behalf of its members collectively in EPA’s rulemakings 

and other Clean Air Act proceedings that affect the interests of electric generators and in litigation arising from 

those proceedings. 
FIP Revisions – RTC 

June 5, 2012 

Page 50 

Reg. 10342.27 This is the second set of revisions EPA has made to correct errors in its CrossState Air Pollution Rule (“Cross-State Rule”), which EPA published at 76 Fed. Reg. 48208 

(Aug. 8, 2011). EPA proposed the first set of corrections on October 14, 2011, 76 Fed. Reg. 

63860, and promulgated them in final form on the same day it proposed these additional 

revisions, 77 Fed. Reg. 10324 (Feb. 21, 2012) (“Error Corrections Rule”). 

 

UARG has commented throughout EPA’s rulemaking proceedings on the Cross-State Rule28 and 

supports EPA’s continuing effort to correct significant errors in the Cross-State Rule. including 

errors addressed in the Error Corrections Rule and the Direct Final Rule. The present comments, 

therefore, are not adverse -- and should not be construed as being adverse -- to the Direct Final 

Rule. As explained below, however, the revisions EPA has made to the Cross-State Rule to date 

do not address many of the unit-level errors that UARG and others have identified and described 

in comments and petitions for administrative reconsideration. It is important that EPA correct the 

remaining unit-level errors because they can skew inputs to EPA’s modeling for the Cross-State 

Rule and therefore affect upwind-state-to-downwind-state “linkages,” state emission budgets, 

and allowance allocations. 

 

In its proposed Error Corrections Rule, EPA invited comments on any additional errors in unitlevel data and assumptions that were not addressed in that proposed rule. 76 Fed. Reg. at 

63863/1. The corrections described in the Direct Final Rule generally address comments EPA 

received on additional errors, 77 Fed. Reg. at 10342/1, and make revisions to thirteen states’ 

 

27 EPA published a proposed rule in parallel with the Direct Final Rule, and announced a public comment period 

ending March 22, 2012. 77 Fed. Reg. 10350 (Feb. 21, 2012). 

28 See Comments of the Utility Air Regulatory Group on the Proposed Federal Implementation Plans to Reduce 

Interstate Transport of Fine Particulate Matter and Ozone (Proposed Air Pollution Transport Rule), EPA-HQ-OAR2009-0491-2756 (Oct. 1, 2010) (“UARG PTR Comments”); Comments of the Utility Air Regulatory Group on the 

Notice of Data Availability Supporting the Proposed Federal Implementation Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone, EPA-HQ-OAR-2009-0491-3773 (Oct. 15, 2010) (“UARG NODA 1 

Comments”); Comments of the Utility Air Regulatory Group on the Second Notice of Data Availability Supporting 

the Proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, 

EPA-HQ-OAR-2009-0491-3853 (Nov. 24, 2010); Comments of the Utility Air Regulatory Group on the Third 

Notice of Data Availability Supporting the Proposed Federal Implementation Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone, EPA-HQ-OAR-2009-0491-3979 (Feb. 7, 2011); Comments of the Utility Air 

Regulatory Group on the Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone, EPA-HQ-OAR-2009- 0491-4823 (Nov. 28, 2011) (“UARG Error Corrections Rule 

Comments”). Each of the above referenced UARG comment documents is incorporated by reference herein. In 

addition, after EPA published the final Cross-State Rule, UARG on October 7, 2011, filed with EPA a petition 

for administrative reconsideration of the rule (“UARG Petition for Reconsideration”) (Attachment I to the UARG 

Error Corrections Rule comments and incorporated by reference herein); that petition remains pending before EPA. 

On October 3, 2011, UARG filed a petition for review of the Cross-State Rule in the U.S. Court of Appeals for the 

D.C. Circuit. Utility Air Regulatory Group v. EPA, No. 11-1358 (consolidated with lead case No. 11-1302 and other 

consolidated cases). On December 30, 2011, the D.C. Circuit stayed the Cross-State Rule in its entirety pending 

resolution of the litigation. 
FIP Revisions – RTC 

June 5, 2012 

Page 51 

budgets29 and three states’ new unit set-asides.30 These revisions, however, likely correct only a 

fraction of remaining unit-level errors and do not address many errors identified in petitions for 

reconsideration and rulemaking comments submitted to EPA. 

 

Throughout EPA’s rulemakings on the Cross-State Rule, UARG and UARG members provided 

EPA with detailed comments regarding unit-level errors in EPA’s calculations. See, e.g., UARG 

PTR Comments at 75-85; UARG NODA 1 Comments at 17-21. After EPA published the final 

rule, based on reports from UARG members and from states indicating that EPA had made 

significant unit-level errors in its modeling for the rule, UARG retained James Marchetti Inc. 

(“JMI”) to undertake a limited analysis of unit-level errors in the data EPA used for modeling the 

Cross-State Rule. Because there was insufficient time to evaluate data for all units covered in 

EPA’s modeling, UARG asked JMI to focus its analysis on eight states as to which available 

information suggested EPA likely had made a number of unit-level errors: Florida (ozone only), 

Georgia, Kansas, Louisiana (ozone only), Michigan, Ohio, Texas, and Wisconsin. In this limited 

analysis, JMI identified widespread errors in the assumptions EPA made in its modeling for the 

final rule for the eight states JMI analyzed. UARG discussed the findings of the JMI analysis in 

its October 7, 2011 petition for reconsideration of the Cross-State Rule and attached to the 

petition a copy of the JMI report summarizing the results of that analysis. That report is referred 

to hereinafter as the “JMI Analysis” and is incorporated by reference herein. 

 

After EPA issued its proposed Error Corrections Rule, UARG -- recognizing that that proposed 

rule purported to address certain unit-specific errors in five of the eight states evaluated in the 

JMI Analysis -- retained JMI to analyze the proposed changes with respect to units located in 

those five “overlap” states: Florida, Louisiana, Michigan, Texas, and Wisconsin. In particular, 

UARG asked JMI to determine whether EPA’s proposed corrections would resolve the unit-level 

errors that the JMI Analysis had identified for sources in those five states. UARG submitted 

JMI’s findings based on this analysis in a separate, additional report, which was Attachment II to 

the UARG Error Corrections Rule Comments submitted on November 28, 2011. That additional 

report (referred to hereinafter as the “JMI Addendum” and incorporated by reference herein) 

found that, although EPA’s proposed rule identified and appeared to correct some of the unitlevel errors identified in the JMI Analysis, EPA failed to address many of the previously 

identified errors in the five states. Most important for purposes of the present comments, several 

of the errors identified for a second time in the JMI Addendum remain uncorrected by the Direct 

Final Rule. 

 

The following are examples of errors that JMI identified in the eight states considered in its 

analysis that, as far as UARG has been able to determine, are not corrected in either the final 

Error Corrections Rule or the Direct Final Rule: 

 

29 These states are Arkansas, Georgia, Indiana, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New York, 

Ohio, Oklahoma, South Carolina, and Texas. 77 Fed. Reg. at 10342/1. 

30 These states are Arkansas, Louisiana, and Missouri. 77 Fed. Reg. at 10342/1.
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Florida: Errors remain concerning (i) projections regarding the overall level of seasonal NOX

emissions in the state; and (ii) NOX emission rates for Crist Units 4 and 5, Smith Unit 1, and 

Scholz Units 1 and 2. See JMI Analysis at 4-5; JMI Addendum at 2. 

Georgia: Errors remain concerning (i) SO2 emission rates used for Harlee Branch Units 1-4; (ii) 

the amount of time it will take for several coal-fired units, including Harlee Branch Units 1-4, 

Kraft Units 1-3, and Yates Units 2-5, to switch from burning higher- to lower-sulfur bituminous 

coal; and (iii) EPA’s retirement date for McDonough Units 1 and 2 and the replacement of those 

units with two 850-MW combined cycle units in EPA’s final rule base case modeling run for 

2012. See JMI Analysis at 5-6. 

Kansas: Errors remain with regard to EPA’s assumptions about SO2 emission rates at several 

Kansas units, including Quindaro Unit 2, Nearman Creek Unit 1, Holcomb, LaCygne Unit 2, 

Lawrence Units 3-5, and Tecumseh Units 9 and 10. See JMI Analysis at 7. 

Louisiana: Errors remain concerning (i) the operation of (and NOX emissions from) Bonin Units 

1 and 2 and Louisiana Electric & Power Authority’s Houma and Morgan City electric generating 

units; (ii) projected heat inputs for TJ Labbe Units 1 and 2 and Hargis-Hebert Units 1 and 2; and 

(iii) the Integrated Planning Model’s underestimate of the use of oil- and gas-fired units 

statewide. See JMI Analysis at 7-8; JMI Addendum at 2. 

 

Michigan: Errors remain concerning (i) the timing of flue gas desulfurization (“FGD”) system 

installations at Monroe Units 1 and 2; (ii) SO2 and NOX emission rates at Trenton Channel Units 

16-19 and 9A and Eckert Station Unit 2; and (iii) SO2 emission rates at River Rouge Units 2 and 

3, St. Clair Units 1-4 and 6-7, and Erickson Unit 1. See JMI Analysis at 8-9; JMI Addendum at 3. 

Ohio: Errors remain concerning (i) EPA’s assumption that Conesville Unit 3 will operate as a 

coal-fired unit after 2012; (ii) SO2 emission rates at Conesville Units 5 and 6; (iii) EPA’s failure 

to recognize that all boilers at the Richard Gorsuch Power Plant were shut down permanently as 

of November 2010; (iv) the mix of coals being burned at Eastlake Units 1-5 and the resulting 

SO2 emission rates for these units; and (v) SO2 emission rates for Sammis Units 1-7. See JMI 

Analysis at 9-11. 

Texas: Errors remain concerning (i) the operation of the FGD system at Gibbons Creek, which 

will be in operation in 2012; (ii) the operation of gas-fired units at several plants that have been 

retired and cannot be brought back online, including Bryan, CE Newman, Colin, Laredo Units 1-

3, Leon Creek, Mountain Creek Units 2 and 3, North Lake Units 1-3, North Texas Unit 3, and 

WB Tuttle Units 1, 3, and 4; (iii) the operation (and SO2 emission rate) of San Miguel Unit 1; 

(iv) the status of Spruce Unit 2 as a new unit; and (v) the exclusion of 16 new units of gas-fired 

generation. See JMI Analysis at 11-13; JMI Addendum at 3-4. 

Wisconsin: Errors remain concerning (i) the operational date of dry FGD systems at Columbia 

Units 1 and 2; (ii) retrofit dates for wet FGD systems and selective catalytic reduction (“SCR”) 

systems at Oak Creek Units 5 and 6; (iii) installation and operation of SCR systems at Valley 

Units 1 and 2; (iv) coal blends being burned at Alma Units 4 and 5; (v) NOX rates achievable for 
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Pulliam Units 5-8; (vi) SO2 emission rates for Edgewater Units 3-5; and (vii) the status of Elm 

Road Units 1 and 2 and units at the DTE Stoneman facility as new units. See JMI Analysis at 13-

14; JMI Addendum at 4-5. 

Moreover, the foregoing list likely does not address all of the errors that remain in the CrossState Rule, including errors that UARG members previously identified with respect to units 

located in states that JMI did not review. For example, Duke Energy explained in its comments 

on the proposed Error Corrections Rule that the accurate SO2 removal efficiency percentage for 

the FGD equipment at its Gibson Unit 5 in Indiana is 85 percent. See Comments of Duke Energy 

on the Revisions to Federal Implementation Plans To Reduce Interstate Transport of Fine 

Particulate Matter and Ozone Proposed Rule at 5-8, EPA-HQ-OAR-2009-0491-4768 (Nov. 28, 

2011). This is the removal efficiency that EPA used for Gibson Unit 5 throughout the 

rulemaking, until it erroneously changed the assumed removal efficiency to 95 percent in the 

final rule. Id. at 5. Although EPA in the Direct Final Rule adjusted Indiana’s 2012 and 2014 SO2

budgets based on a correct determination that a small amount of flue gas bypasses the FGD 

equipment at Gibson Unit 5, see 77 Fed. Reg. at 10343/3-10344/1, it failed to correct the FGD 

removal efficiency percentage.31 In addition, American Electric Power (“AEP”) explains in its 

comments on EPA’s proposal regarding its Direct Final Rule that a number of errors that AEP 

identified in its petition for reconsideration of the Cross-State Rule and its comments on the 

proposed Error Corrections Rule are not corrected in the Direct Final Rule.32

 

In sum, in the Direct Final Rule, EPA has taken the appropriate and commendable step of 

correcting certain additional errors in the Cross-State Rule. EPA, however, has failed to address 

and correct numerous other errors in the rule that were identified by UARG and others in 

previous rulemaking comments and petitions for reconsideration submitted to EPA. If and when 

the stay of the Cross-State Rule is lifted, EPA should not require electric generators to comply 

until after EPA has corrected all identified errors in the rule. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012 (77 FR 10350). The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final rule (77 FR 

10342) were merited. See 77 FR 10350. The proposal was narrowly focused on the adjustments 

included in the direct final rule and did not reopen any other issues for comment. In sum, and as 

explained in greater detail below, comments such as these, which relate to issues other than the 

adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope of and not 

relevant to this final action. 

 

 

31 See Comments of Duke Energy on the Revisions to Federal Implementation Plans To Reduce Interstate Transport 

of Fine Particulate Matter and Ozone Proposed Rule, EPA-HQ-OAR-2009-0491-4979 (Mar. 22, 2012). 

32 See AEP Comments on Revisions to Federal Implementation Plans To Reduce Interstate Transport of Fine 

Particulate Matter and Ozone Proposed Rule, 77 Fed. Reg. 10350 (February 21, 2012) Direct Final Rule, 77 Fed. 

Reg. 10342 (February 21, 2012), EPA-HQ-OAR-2009-0491-4975 (Mar. 20, 2012). 
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The February 21, 2012 proposal, on its face, was very limited in scope and only provided an 

opportunity for comment on the specific adjustments proposed therein. It did not reopen for 

comment any other issues that had been resolved in the Final Transport rule published on August 

8, 2011, or the final revisions rule published on February 21, 2012. It is important to note that 

the final revisions rule published on February 21, 2012 was a final action taken in response to an 

October 2011 proposal and was distinct from the February 21, 2012 direct final rule and the 

February 21, 2012 parallel proposal. On October 6, 2011, EPA published a proposal which both 

proposed specific adjustments to the Transport Rule and solicited additional comments on 

narrowly defined closely related issues. In response to the October 2011 proposal and the 

comments received in response, we published three actions on February 21, 2012 – a final rule, a 

direct final rule, and a parallel proposal. The February 21, 2012 final revisions rule made certain 

specific adjustments to the Transport Rule. In particular, it finalized adjustments that had been 

specifically proposed in the October 2011 proposal. In the response to comments document for 

that final rule, we responded to all relevant comments received in response to the October 2011 

proposal, including comments suggesting that other similar adjustments were warranted. In 

some instances, but not all, EPA agreed with commenters who suggested additional similar 

adjustments to state budgets were warranted. Where EPA disagreed with a comment suggesting 

that an additional adjustment was warranted, the reasons for EPA’s determination that the 

suggested adjustment was not appropriate were presented in the response to comments document 

for the February 21, 2012 final rule. Where EPA agreed with comments suggesting additional 

adjustments were warranted, EPA issued a direct final rule to make the appropriate changes. At 

the same time, we issued a parallel proposal, which proposed to find that the changes in the 

direct final rule were warranted. The February 21, 2012 direct final rule and parallel proposal 

were both narrow in scope and addressed only specific adjustments EPA determined were 

appropriate. Nothing in the February 21, 2012 direct final or the February 21, 2012 parallel 

proposal reopened any other issues for public comment. We indicated that if we received 

adverse comment we would withdraw the direct final and take final action on the parallel 

proposal without providing an additional opportunity for public comment. We received adverse 

comment and thus withdrew the direct final rule on May 16, 2012 (77 FR 28785). In this final 

action, we respond to all comments relevant to the February 21, 2012 proposal and take action to 

finalize the adjustments proposed therein. Comments on issues not related to the adjustments 

proposed on February 21, 2012 are not relevant to this action as the February 21, 2012 parallel 

proposal was narrowly focused on the adjustments included in the direct final rule and did not 

reopen any other issues for comment. Accordingly, the comments presented by UARG are not 

relevant to this final action. UARG, in fact argues that the comments should not be construed as 

being adverse to the changes actually made in the direct final rule. Instead, they argue solely that 

additional adjustments are necessary. UARG also acknowledges that the comments presented 

were previously presented to EPA in comments on other rules and/or in petitions for 

reconsideration that are pending before the agency. 

 

EPA not only provided numerous opportunities for the submission of information, such as that 

included in the comments above, but, in fact, previously received this information and responded 

to it. EPA has previously responded to all the comments presented by UARG here including 

their unit-level comments from the JMI analysis. The responses to these comments appear on 

pp. 9-10, 21-22, 24-25, 27-28, 30, 31-32, 38, 39, 67-68, 69, 92, 100, 101, 103, 107, 202-203 of 
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the “Response to Comments on the Proposed Revisions to FIPs to Reduce Interstate Transport of 

Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963). Responses to any other comments 

from UARG, generally referred to in the comment above, are addressed on pp. 97-98 of the same 

document. 

Further, EPA will respond to issues raised in the petitions for reconsideration, as appropriate, in 

actions on those petitions. Section 307(d)(7)(B) of the Clean Air act provides a procedural 

mechanism for parties to petition the Agency to reconsider a rule. This section directs the 

Administrator to convene a proceeding for reconsideration only if the petitioner can demonstrate 

that it was impracticable to raise a particular objection within the comment period of that the 

grounds for the objection arose after the period for public comment (but within the time specified 

for judicial review) and that the objection is of central relevance to the outcome of the rule. EPA 

is in the process of reviewing all petitions for reconsideration received on the Transport Rule, 

including the petition submitted by the commenter, to determine if they meet this standard and 

will take action, as appropriate, in due course. 

Further, to the extent the commenter is suggesting changes to the allocation methodology used 

by EPA to allocate allowances to individual units, EPA notes that nothing in the October 6, 2011 

proposal or the February 21, 2012 parallel proposal reopened the allocation methodology for 

public comment. EPA finalized an allocation methodology in the final transport rule after 

providing ample opportunity for comment on the methodology to be used. EPA also provided 

notice of its intent to use historic heat input data, and the data sources that would be used to 

obtain that data. The October 11, 2011 proposal provided an opportunity to comment on a 

narrow issue regarding the adjustment of individual unit-level allowance allocations to respect 

the impact of consent decrees on a specific subset of units, but did not reopen the methodology 

for public comment generally. See Section 6.5 of “Response to Comments on the Proposed 

Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQ-OAR-2009-

0491-4963). 

For example, the commenter argues, among other things, that EPA has failed to account for the 

retirement of the Gorsuch plant. However, as described on p. 103 of the “Response to 

Comments on the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and 

Ozone” (EPA-HQ-OAR-2009-0491-4963), EPA notes that this retirement is accounted for as 

part of a broader compliance strategy with a consent decree that imposes broad emission caps on 

multiple sources. EPA’s power sector modeling accurately incorporated the emission reduction 

requirements of those overarching emission caps established by the relevant consent decree. 

Therefore, the Transport Rule modeling results (and hence the state budgets that rely upon them) 

remain consistent with the legal requirements of that consent decree, because the retirement of 

this plant is accounted for by the cap restrictions that IPM implements. As such, EPA believes 

that this individual plant retirement is consistent with the overarching emission projections EPA 

relied upon to quantify state budgets under the Transport Rule programs. 

Regarding the Gibson 5 item, please see pp. 91-92 in the “Response to Comments on the 

Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963) and the response in this document to the comment from Duke Energy. 
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Regarding comments previously submitted, please see pp. 97-98 of the first revisions rule 

response to comments document referred to above. 

10. Earth Justice 

[Letter: Earth Justice (EPA-HQ-OAR-2009-0491-4987)] 

COMMENT: We are writing primarily to express our concerns about the effect of these 

revisions on EPA’s recent proposal (1) to exempt states subject to CSAPR from applying sourcespecific Best Available Retrofit Technology (“BART”) requirements under the Clean Air Act’s 

regional haze program; and (2) to adopt Federal Implementation Plans (“FIPs”) for several states 

that would expressly authorize reliance on CSAPR to avoid BART requirements. See 76 Fed. 

Reg. 82219 (Dec. 30, 2011). 

The revisions to the state emission budgets under the Direct Final Rule affect whether CSAPR 

can properly be deemed better than BART. As a result of this Direct Rule, CSPAR will now 

yield lesser emissions reductions in key states where EPA’s own analysis has demonstrated that 

CSPAR will not achieve visibility reductions comparable to what BART would achieve. In 

weakening CSPAR, this rule further undermines EPA’s efforts to demonstrate that CSPAR can 

deliver greater reasonable progress toward Clean Air Act visibility goals than BART. 

...The emission budget increases have direct implications for the “better than BART” rule. Given 

the substantially reduced emission reductions under the Direct Final Rule, any action on the 

“better than BART rule” would be premature and arbitrary in the absence of further analysis of 

the Direct Final Rule’s impacts on visibility in a scenario where CSPAR is substituted for 

BART. Specifically, EPA has not followed its own regulations, which would require the agency 

to evaluate whether, in light of the Direct Final Rule, CSAPR is better than BART. See 40 C.F.R. 

§ 51.308(e)(3). As the distribution of emissions under BART and CSPAR respectively are 

substantially different, EPA must conduct dispersion modeling to show the difference in 

visibility under each program for each impacted Class I area on the worst and best 20 percent of 

days. See 40 C.F.R. § 51.308(e)(3); see also Technical Support Document for Demonstration of 

the Transport Rule as a BART Alternative (“TSD”), EPA Dkt. No. EPA-HQ-OAR-2011-0729, at 

3 (explaining that the distribution of emissions is different under CSAPR and BART). This 

modeling will demonstrate greater reasonable progress only if: (1) “visibility does not decline in 

any Class I area;” and (2) “[t]here is an overall improvement in visibility, determined by 

comparing the average differences between BART and the alternative over all affected Class I 

areas.” 40 C.F.R. § 51.308(e)(3)(i)-(ii). In evaluating the second prong of this regulatory test 

pertaining to overall visibility improvement, EPA is required to undertake a state-by-state 

analysis (which the agency has failed so far to do). See 40 C.F.R. § 51.308(e)(2)(i) (requiring 

“[a] demonstration that the emissions trading program or other alternative measure will achieve 

greater reasonable progress than would have resulted from the installation and operation of 

BART at all sources subject to BART in the State and covered by the alternative program”). 

 

THE DIRECT FINAL RULE WEAKENS CSAPR, RENDERING CSAPR AN IMPROPER 

BART SUBSTITUTE 
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Putting aside the question of whether it was proper to increase the state emissions 

allocations for Arkansas, Georgia, Indiana, Kansas, Louisiana, Mississippi, Missouri, New York, 

Nebraska, Ohio, Oklahoma, South Carolina, and Texas, these increases undermine EPA’s 

proposed finding that CSAPR is better than BART under 40 C.F.R. § 51.308(e)(3). 

Fundamentally, increasing the emission budgets in 13 states under any of the emission trading 

programs under CSAPR weakens CSAPR such that CSAPR may not prevent a decline in 

visibility over BART at any affected Class I area, per 40 C.F.R. §51.308(e)(3)(i), and may not in 

fact provide greater visibility improvement across all Class I areas, or on a statewide basis, per 

40 C.F.R. §51.308(e)(3)(ii). EPA cannot weaken CSAPR and at the same time continue to rely 

on the program as a substitute for BART under the Clean Air Act’s Regional Haze program 

without undertaking further analysis of the reasonable progress, if any, that CSPAR will now 

achieve in states affected by the Final Direct Rule. 

 

In fact, these newly authorized emission increases likely preclude CSAPR from achieving 

greater reasonable progress than BART at many Class I areas. For example, the substantial 

increases in Georgia’s 2014 emission budget for the annual SO2, annual NOX, and ozone-season 

NOX trading programs—40,334, 13,198, and 5,762 tons respectively—affects whether CSAPR 

will be better than BART at the Class I areas in Georgia, namely Okefenokee, Cohutta, and Wolf 

Island Wilderness Areas, as well as the out-of-state Class I areas impacted by Georgia sources, 

such as Great Smoky Mountains National Park (Tennessee/North Carolina), Shining Rock 

Wilderness Area (North Carolina), Joyce-Kilmer Wilderness Area (Tennessee/North Carolina), 

Cape Romain Wilderness Area (South Carolina), Sipsey Wilderness Area (Alabama), St. Marks 

Wilderness Area (Florida), and Chassahowitzka Wilderness Area (Florida). See 77 Fed. Reg. at 

10343; Georgia Regional Haze SIP Submittal, January 25, 2010, Table 7.7.2-1. 

 

Similarly, increasing Ohio’s CSAPR emissions budget and relying on CSAPR in lieu of 

source-specific BART controls could exacerbate Ohio’s impacts on the MANE-VU Class I 

areas. Of the 167 stacks determined to be reasonably anticipated to cause or contribute to 

visibility impairments in the MANE-VU Class I Areas, 28 are at 14 plants in Ohio.133 Yet, under 

the Direct Final Rule, Ohio’s 2012 and 2014 budgets for annual SO2 will increase by 5,163 tons, 

its annual NOX budgets will increase by 2,765 tons, and its ozone-season NOX budgets will 

increase by 1,221 tons, without regard to the potential effect on impacted Class I areas. See 77 

Fed. Reg. at 10344. 

 

This story repeats itself in New York and South Carolina. In New York, under the Direct 

Final Rule, EPA allotted New York 5,444 more tons of emissions for the 2012 and 2014 SO2

annual trading program, 694 more tons under the 2012 and 2014 NOX annual trading program, 

and 127 more tons under the 2012 and 2014 ozone-season NOX trading program. See 77 Fed. 

 

33 1 See Comments on Proposed Limited Approval of Revisions to the Ohio State Implementation Plan for Regional 

Haze, Document ID EPA-R05-OAR-2011-0329-0004, at 6-8, filed Feb. 24, 2012 in Docket No. EPA-R05-OAR2011-0239.
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Reg. at 10345. The substantial SO2 increases, combined with the NOX increases, can be expected 

to affect New York’s impact on Acadia National Park in Maine, Brigantine Wildlife Refuge in 

New Jersey, Great Gulf Wilderness Area and Presidential Range-Dry River Wilderness Area in 

New Hampshire, Lye Brook Wilderness Area in Vermont, Moosehorn National Wildlife Refuge 

and Roosevelt-Campobello International Park in Maine, and Shenandoah National Park in 

Virginia. See New York State Department of Environmental Conservation, Proposed Regional 

Haze Plan Revision § 1.4 (Nov. 2009). 

 

In South Carolina, EPA approved an 8,013 ton increase to the state’s 2012 and 2014 

annual SO2 budgets. See 77 Fed. Reg. at 10345. Notably, 6,001 of the 8,013 annual tonnage 

increase are allocated to sources that EPA assumed were BART-eligible in the “better than 

BART” rule, meaning that BART may well be better than CSAPR at these plants, and across the 

state.234 At a minimum, EPA cannot increase CSAPR state budgets without revising its better 

than BART calculations. 

 

Newly authorized emissions increases also make clear that CSAPR as revised cannot be better 

than BART in states where EPA’s own data showed that CSAPR in its original form was not 

better than BART per 40 C.F.R. § 51.308(e)(3)(ii). As discussed in comments submitted by 

undersigned counsel on the “better-than-BART” proposal,35 and shown in Table 1 below, EPA’s 

own modeling analysis demonstrates that a “Nationwide BART”36 scenario provides greater 

visibility improvement than the agency’s alternative “Transport Rule + BART-elsewhere”37 

scenario on either the best 20% of days or the worst 20% of days at a number of Class I areas. 

 

<<Table 1. Class I Areas Where EPA’s Modeling Shows “Nationwide BART” to Have Greater 

Visibility Improvement Compared to the “Transport Rule + BART-elsewhere>>38

 

Visibility at these Class I areas will further decline under CSAPR as revised in the Direct 

Final Rule because EPA authorized states that impact these Class I areas to increase their 

emissions. For example, in the Direct Final Rule, EPA increased Arkansas’s 2012 and 2014 

 

34See Comments Addressing State-Specific Impacts from EPA’s Proposed CSAPR “Better-Than-BART” Rule in 

Alabama, Mississippi, North Carolina, and South Carolina, Document ID EPA-HQ-OAR-2011-0729-0245, at 12-14, 

filed Feb. 28, 2012 in Docket ID EPA-HQ-OAR-2011-0729. 

35 See Document ID EPA-HQ-OAR-2011-0729-0246, Section VII.A, filed Feb. 28, 2012 in EPA Docket ID No. 

EPA-HQ-OAR-2011-0729 (the “February 28 Comments”).

36 The “Nationwide BART” scenario estimated the effect of applying BART controls at specific BART-eligible 

sources across the entire nation, including sources in the CSAPR region in the east and sources in the non-CSAPR 

region in the west. 

37 EPA’s “Transport Rule + BART-elsewhere” scenario estimated the effect of relying on CSAPR, or the Transport 

Rule, in CSAPR states, yet applying BART at BART-eligible sources outside of the CSAPR region.

38 This Table is also included in the Expert Report of D. Howard Gebhart, submitted as Attachment 2 to the 

February 28 Comments. See D. Howard Gebhart, Expert Report: Technical Review of US Environmental Protection 

Agency Dispersion Modeling Supporting the “Transport Rule is Better than BART” Analysis 7-9 & Table 3-1 (Feb. 

21, 2012).
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emission budget for ozone-season NOX by 73 tons. See 77 Fed. Reg. at 10343. Arkansas is home 

to Caney Creek Wilderness and Upper Buffalo Wilderness, Class I areas where EPA predicted 

that CSAPR with its original emission budgets would be worse than BART. In addition, sources 

in Arkansas likely impact Class I areas in neighboring Missouri, including Hercules-Glades 

Wilderness, another area where CSAPR prior to revisions would not be better than BART. 

 

Similarly, EPA increased Nebraska’s annual SO2 emission budget for 2012 and 2014 by 

3,110 tons. See 77 Fed. Reg. at 10344-45. Sources in Nebraska likely impact Badlands National 

Park and Wind Cave National Park in neighboring South Dakota and also have the potential to 

affect Theodore Roosevelt National Park in nearby North Dakota, Caney Creek Wilderness and 

Upper Buffalo Wilderness in Arkansas and Hercules-Glades Wilderness in Missouri—all Class I 

areas which EPA expected would see a decline in visibility under CSAPR as compared to BART 

prior to the revisions in the Final Direct Rule. 

 

Likewise, EPA increased Missouri’s annual NOX emission budget and ozone-season 

emission budget for 2012 and 2014 by 26 tons. See 77 Fed. Reg. at 10344. Even this modest 

increase can affect visibility at Missouri’s Hercules-Glades Wilderness, where CSAPR, prior to 

the emission budget increase, was shown to be worse than BART. Missouri sources also have a 

greater potential to cause a decline in visibility under CSAPR, as revised, at Caney Creek 

Wilderness and Upper Buffalo Wilderness in neighboring Arkansas. 

 

Increases in Oklahoma’s ozone-season NOX emission budget for 2013 and 2014, and in Texas’s 

annual and ozone-season NOX emission budgets also further undermine CSAPR’s viability as a 

BART alternative at Caney Creek Wilderness and Upper Buffalo Wilderness in Arkansas, 

Hercules-Glades Wilderness in Missouri, and Bandelier National Monument, Salt Creek 

Wilderness, San Pedro Parks Wilderness, and White Mountains Wilderness in New Mexico. 

Under the Direct Final Rule, EPA increased Texas’s annual NOX budget for 2012 and 2014 by 

2,731 tons and its ozone-season NOX budget by 1,142 tons. See 77 Fed. Reg. at 10345. 

Similarly, Oklahoma is being allotted 859 more tons under the ozone-season NOX trading 

program. See id.

 

Finally, EPA is increasing emissions under various CSAPR trading programs in Indiana, 

Kansas, Louisiana, and Mississippi. Sources in these states have the potential to affect Class I 

areas, including Caney Creek Wilderness and Upper Buffalo Wilderness in Arkansas and 

Hercules-Glades Wilderness in Missouri. Again, these are Class I areas for which CSAPR was 

not predicted to be better than BART even before the emission increases were authorized in the 

Final Direct Rule. In particular, Indiana’s emission budget for the annual SO2 trading program 

will increase by 5,338 tons for 2012 and 2014. See 77 Fed. Reg. at 10343-44. Kansas’s annual 

SO2 emission budget would increase by 452 tons for 2012 and 2014, whereas its annual NOX

emissions budget would increase by 640 tons for 2012, and 5,794 tons for 2014. See id. At 

10344. Both Louisiana and Mississippi were allowed increases to their ozone season NOX

budgets for 2012 and 2014. Under the Direct Final Rule, Louisiana can emit 89 tons more NOX

per ozone season while Mississippi can emit 115 tons more. See id.

 
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Given these increases in emissions, it is highly unlikely that CSAPR could be better than BART 

in the states containing these Class I areas, or in the states affecting these Class I areas. As 

explained in the comments by the undersigned on the “better than BART” rule, EPA cannot 

discount the many instances in which BART yields greater progress toward visibility goals than 

CSAPR by averaging visibility impacts across the entire CSAPR region, much less the entire 

country. Instead, EPA must determine whether a given program is better than BART on a 

stateby- state basis having considered what an alternative would achieve in the way of emissions 

reductions relative to BART at each relevant source. See 40 C.F.R. § 51.308(e)(2)(i) (requiring a 

state-by-state analysis). EPA has apparently failed to undertake any analysis at all in connection 

with either this rulemaking or the “better than BART” rulemaking that assesses the visibility 

impacts of weakening the CSAPR program—either under its flawed national and regional 

averaging approach, or under the proper state-by-state approach. 

 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012. 77 FR 10350. The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final rule (77 FR 

10342) were merited. See 77 FR 10350. The proposal was narrowly focused on the adjustments 

included in the direct final rule and did not reopen any other issues for comment. In sum, and as 

explained in greater detail on page 54 of this RTC, comments such as these, which relate to 

issues other than the adjustments proposed in the February 21, 2012 parallel proposal, are outside 

the scope of and not relevant to this final action. 

 

Moreover, these comments address an issue that was not addressed in the final Transport Rule, 

the final revisions rule, or the February 21, 2012 proposal. The comments, on their face, are 

directed not at the revisions to the Transport Rule proposed on February 21, 2012, but at the 

“better than BART rule” proposed in December 2011. 76 Fed. Reg. 82,219 (Dec. 30, 2011). 

This rule does not address any issues regarding the relationship between the Transport Rule 

(CSAPR) and BART. As such, the comments are outside the scope of this rulemaking. 

 

 

11. Georgia Power 

[Letter: Georgia Power (EPA-HQ-OAR-2009-0491-4984)] 

COMMENT: Georgia Power Company submits the following comments on the Environmental 

Protection Agency’s Revisions to Federal Implementation Plans to Reduce Interstate Transport 

of Fine Particulate Matter and Ozone, Direct Final Rule, 77 Fed. Reg. 10,342 (February 21, 

2012). 

 

Georgia Power has participated extensively in the many comment periods associated with EPA’s 

Cross-State Air Pollution Rule. At each stage, the Company has identified numerous errors. 
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Page 61 

While Georgia Power is pleased that EPA has corrected some of the identified errors with its 

direct final rule, the Company urges the Agency to fix all identified errors.39 As noted in 

Southern Company’s public comments on EPA’s proposed "Corrections Rule,"40. EPA does not 

have discretion to correct only some errors. And by implementing the Cross-State Rule with 

known errors, EPA is acting arbitrarily, capriciously and not in accordance with its authority. 

 

Again, the Company is pleased that EPA has corrected some errors. As noted in Southern 

Company’s initial comments on the proposed Transport Rule,41 EPA erroneously assumed, in 

both the proposed Transport Rule and final Cross-State Rule, that state law required advanced 

pollution controls to be installed and operational on several electric generating units in Georgia 

by January 1, 2014. EPA’s direct final rule corrects most of these plain errors and increases 

Georgia’s emission budgets accordingly. The Company fully supports these corrections. 

 

EPA has, however, not corrected numerous additional errors that have been brought to its 

attention. Rather than repeat the detailed descriptions of those errors, the Company incorporates 

Southern Company’s petition for reconsideration and administrative stay of the final Cross-State 

Rule42 and its public comments on the proposed Corrections Rule,43 as if set forth fully here. 

These documents, including all attachments thereto, outline numerous errors, which the 

Company resubmits by reference for the Agency’s consideration.44 In its Response to Comments 

on the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone,45EPA 

 

39 These comments should not be construed as “negative” with respect to the error corrections that EPA 

affirmatively made for Georgia in the direct final rule. Rather, these comments urge EPA to fix the many remaining 

errors, through this rulemaking, a subsequent error correction rulemaking or on reconsideration fo the Cross-State 

Rule. See Petition for Reconsideration and Stay by Southern Company Services, Inc. attached as Exhibit A to 

Southern Company Revisions Rule Comments, see note 5 below. Southern Company’s Petition for Reconsideration 

and Stay is in the docket as Docket/Document ID No. EPA-HQ-OAR-2009-0491-4745 and is available 

electronically at http://www.epa.gov/crossstaterule/petitions.html.

40 U.S. Environmental Protection Agency, Revisions to Federal Implementation Plans to Reduce Interstate Transport 

of Fine Particulate Matter and Ozone, Proposed Rule, 76 Fed. Reg. 63,860 (October 14,2011)

41 Comments of Southern Company on EPA’s Proposed Rule on Federal Implementation Plans to Reduce Interstate 

Transport of Fine Particulate Matter and Ozone (75 Fed. Reg. 45,210 (August 2, 2010), Docket/Document ID EPAHQ-OAR-2009-0491-2864 (Oct. 1, 2010). See in particular, Attachment B thereto (excerpting the Georgia 

Multipollutant Rule, Ga. Comp. R & Regs & 391-3-1-.02 (sss)). 

42 See, Southern Company Petition for Reconsideration and Stay, infra note 1. 

43 Comments of Southern Company on Revisions to Federal Implementation Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone (76. Fed. Reg. 63,860 (October 14, 2011)), Docket/Document ID No. EPA-HQOAR-2009-0491-4474 (Nov.14, 2011) 

44 See in particular, Southern Company Petition for Reconsideration and Stay, infra note 1, at 5-18; Southern 

Company Revisions Rule Comments, infra note 5, at 3-13. 

45 Docket/Document ID No. EPA-HQ-OAR-2009-0491-4963 (“FIP Revisions RTC”) 
FIP Revisions – RTC 

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fails to adequately respond to these comments.46 The Company urges EPA to fix the many 

remaining errors, through this rulemaking, a subsequent error correction rulemaking or on 

reconsideration of the Cross-State Rule. 

RESPONSE: EPA has considered and responded to all comments submitted during this 

rulemaking process by Georgia Power, Southern Company, and other parties (see Response to 

Comments (RTC) on the Proposed Revisions to FIPs to Reduce Interstate Transport of Fine PM 

and Ozone; EPA-HQ-OAR-2009-0491-4963 and other RTCs at EPA-HQ-OAR-2009-0491-

4398, 4512, 4529). 

EPA disagrees with the assertion that it “inadequately” responded to previously submitted 

comments. While EPA neither agreed with all of the comments submitted by Georgia Power 

and Southern Company, nor accepted all of their suggested changes, EPA fully responded to all 

comments received and made updates and revisions where appropriate. The commenter does not 

identify any specific parts of EPA’s response as inadequate. The fact that on some issues EPA’s 

response was different than the one desired by the commenter does not in and of itself constitute 

in inadequacy or an “arbitrary and capricious” action. Finally, some of the commenter’s 

perceived “inadequate responses” may stem from a misunderstanding of the model’s output 

and/or its use. As noted in the aforementioned RTC, the model projections are not intended to 

replicate historic operation at a particular unit (although the model is informed by historic 

operations). The model simultaneously factors in future market and policy conditions that may 

influence economic decisions regarding dispatch or fuel use that are different than those 

observed in the past. This is consistent with the dynamic nature of power sector operations that 

involves fluctuations over time in dispatch, emissions, and fuel choice among electricity 

generating units. 

These comments are outside the scope of the February 21, 2012 proposal and not relevant to this 

final action. In this rule, EPA is taking final action on the revisions proposed on February 21, 

2012. 77 FR 10350. The scope of that proposal was limited. It proposed to determine that the 

unit-level adjustments described in the preamble to the direct final (77 FR 10342) were merited. 

See 77 FR 10350. It was narrowly focused on the adjustments included in the direct final rule 

and did not reopen any other issues for comment. In sum, and as explained in greater detail on 

page 54 of this RTC, comments such as these, which relate to issues other than the adjustments 

proposed in the February 21, 2012 parallel proposal, are outside the scope of and not relevant to 

this final action. 

In the October 14, 2011 proposal, EPA proposed specific adjustments to the CSAPR and 

solicited additional comments on narrowly defined closely related issues. In response to that 

proposal and the comments received in response, we took three actions on February 21, 2012. 

First, we issued a final rule making certain specific adjustments to CSAPR. This rule focused on 

 

46 Compare Southern Company Petition for Reconsideration and Stay, infra note 1, at 5-18 and Southern Company 

Revisions Rule Comments, infra note 5, 3-13., with FIP Revisions RTC, infra note 7, at Id. at 23-25, 73-75, 78-

79,84-87, 203-04 (and sources cited therein).
FIP Revisions – RTC 

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Page 63 

the adjustments that had been specifically proposed on October 14, 2011. In addition, in the 

response to comments document for that action, we responded to all relevant comments received 

in response to the October 14, 2011 proposal including comments suggesting additional 

adjustments to the CSAPR were necessary. Second, and in response to comments received on 

the October 14, 2011proposal suggesting additional adjustments to CSAPR were appropriate, we 

issued a direct final rule to make some additional adjustments to the CSAPR. Third we issued a 

parallel proposal, proposing to find that the adjustments made in the direct final were merited. 

We indicated that if we received adverse comment we would withdraw the direct final and take 

final action on the parallel proposal without providing an additional opportunity for public 

comment. We received adverse comment and thus withdrew the direct final rule on May 16, 

2012. (77 FR 28785) In this final action, we respond to all comments relevant to the February 

21, 2012 proposal and take action to finalize the proposed adjustments to CSAPR. We have 

considered and responded to all comments relevant to the adjustments proposed on February 21, 

2012. Comments on issues not related to the adjustments proposed on February 21, 2012 are not 

relevant to this action as the February 21, 2012 parallel proposal was narrowly focused on the 

adjustments included in the direct final rule and did not reopen any other issues for comment. 

Accordingly, EPA will not address any issues outside the scope of this action. The public has 

been afforded ample opportunity to comment on the underlying Cross State Air Pollution Rule, 

the related Notices of Data Availability (75 FR 53613, 75 FR 66066, 76 FR 1109, 76 FR 42055), 

a Supplemental Notice of Proposed Rulemaking (76 FR 80760) and Proposed Revisions to the 

Cross-State Air Pollution rule (76 FR 63860). EPA believes it has reviewed and responded to all 

of Georgia Power’s previously submitted comments that fall into these categories, and the 

Agency has made changes to the Transport Rule where appropriate based on information 

contained in those comments. 

EPA has also received a number of petitions for reconsideration of CSAPR including the petition 

for reconsideration that the commenter attached with these comments. These petitions are 

pending before the EPA. We will evaluate all such petitions according to the criteria provided in 

section 307(d)(7)(B) of the Clean Air Act and will respond to the petitions, as appropriate, in a 

separate action or actions. Section 307(d)(7)(B) provides a procedural mechanism for parties to 

petition the Agency to reconsider a rule. The section directs the Administrator to convene a 

proceeding for reconsideration only if the petitioner can demonstrate that it was impracticable to 

raise a particular objection within the comment period or that the grounds for the objection arose 

after the period for public comment (but within the time specified for judicial review) and that 

the objection is of central relevance to the outcome of the rule. EPA notes that commenter did 

not file a Petition for Reconsideration of the Cross-State Air Pollution Rule on its own behalf but 

resubmits with its comments a petition filed by Southern Company Services, Inc. This 

Response to Comments document only addresses comments on the February 21, 2012 proposal 

and EPA is not taking action on any Petition for Reconsideration at this time. 

12. GenOn 

[Letter: GenOn(EPA-HQ-OAR-2009-0491-4986)] 

COMMENT: GenOn recognizes that the Direct Final Rule is another effort by EPA to address 

some of the problems created by CSAPR. As discussed below, however, it also creates new ones. 
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In addition, it highlights the problems that have been created by EPA’s piecemeal approach to 

this rulemaking, which has included a proposed rule, three different Notices of Data Availability 

(NODAs) that substantially changed key parts of the proposal (although the impact of these 

changes was not ascertainable until the final rule was released), a final rule (which was 

substantially different from the proposal), a supplemental rule to add states to various parts of the 

program, a revisions rule to correct acknowledged mistakes in the final rule, and now a direct 

final rule to make further changes. 

Because the Clean Air Implementation Rule (CAIR) remained in place during this rulemaking 

and remains in place today, there is no environmental justification for this piecemeal approach or 

the rush to impose new requirements without allowing for meaningful analysis. In order to 

develop a sound program for replacing CAIR (and the NOX SIP Call, as well as the Acid Rain 

Program for much of the country), EPA should prepare a comprehensive proposal that includes 

the information provided in the Direct Final Rule, the Final Revisions Rule, the Supplemental 

Rule, and the three NODAs, in a way that allows for meaningful public review and comment on 

a fully coherent proposal. Only in this way can EPA develop an effective, equitable, and legally 

defensible program to address cross-state air pollution issues. 

RESPONSE: This comment is premised, at least in part, on incorrect assumptions. First, the 

commenter suggests that because the Clean Air Interstate Rule (CAIR) remains in place there is 

no environmental justification for timely implementation of the Transport Rule. This is 

incorrect, as explained in greater detail in the December 1, 2011 Declaration of Sam Napolitano 

(Docket No. EPA-HQ-OAR-2009-0491-4834), the environmental and public health benefits of 

the Transport Rule are significant and implementation of CAIR is insufficient to secure those 

benefits (see Napolitano Declaration Nos. 82-84, 120-130). 

 

Second, the comment suggests that the Transport Rule will replace not only the CAIR, but the 

NOX SIP Call and the Acid Rain Program. This is incorrect. The Transport Rule and the 

Transport Rule FIPs were promulgated to replace CAIR and the CAIR FIPs. The requirements 

of the NOX SIP Call and the Acid Rain Program, on the other hand, are not impacted by the 

Transport Rule. All states and sources must continue to comply with all applicable NOX SIP 

Call requirements and Acid Rain Program requirements. CAIR replaced the NOX Budget 

Trading Program created in the NOX SIP Call with the CAIR ozone-season trading program, but 

did not excuse any state or source from complying with the requirements in the NOX SIP Call. 

The interaction between CAIR and both the Acid Rain Program and the NOX SIP Call are 

discussed in greater detail in section IX of the preamble to the final CAIR (70 FR 25289-25299). 

For this rulemaking for EPA’s response to this comment requesting an additional proposal, see 

section 4.1 of the Preamble. 

 

COMMENT: EPA properly characterizes an “out-of-merit-order dispatch area” as one in which 

power generating units “are frequently dispatched out of regional economic order as a result of 

short-run limitations on the ability to meet local electricity demand with generation from outside 

the area.’’ 77 Fed. Reg. at 10343. In the Direct Final Rule, EPA adjusted a number of state 
FIP Revisions – RTC 

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budgets based on comments from companies and ISOs that have out-of-merit generation, but the 

Agency made no effort to understand whether the need for out-of-merit dispatch is temporary or 

permanent or where the generation will come from if and when the out-of-merit dispatch is no 

longer required. 

In most cases, the need for such dispatch is caused by transmission constraints, and there are 

ongoing efforts to resolve such constraints throughout the CSAPR region. It is likely that some 

or even many of these constraints will be eliminated by 2014, but the Direct Final Rule 

essentially locks them into the program. Although this may help some generators by providing a 

few “extra” allowances to the states in which they operate, it may shortchange generators in 

other states that will be called upon to generate more electricity when the constraints have been 

resolved. EPA simply assumes the generation that gets reduced or offset because of the need for 

out-of-merit dispatch is located in the same state as the unit that benefits from the constraint, but 

this assumption will be incorrect in many cases. A unit that gets loaded to resolve a constraint 

may not be in the same state as the unit that will be called upon once the constraint is resolved. 

Given the unit-by-unit modeling approach that EPA has adopted under CSAPR, the Agency must 

analyze the various out-of-merit dispatch areas and tailor the program accordingly. 

RESPONSE: EPA’s methodology for dealing with out-of-merit-order adjustments is discussed in 

section 6.1.a of the “Response to Comments on the Proposed Revisions to FIPs to Reduce 

Interstate Transport of Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963). The out-ofmerit-order adjustments made in the revisions are intended to account for immediate-term future 

generation from a unit most likely to be driven by non-economic reasons, which encompasses 

2012 and 2014. Regarding offsetting of out-of-merit-order adjustments, please see section 6.1.b 

of the same document. As stated in previous response to comments, EPA offset increased 

generation with generation at natural gas combined cycle units in the affected state, which are 

most like to be operating at the margin in electricity supply from capacity available in state. 

EPA has increased the budgets of the states in which out-of-merit-order adjustments have been 

made, thus acknowledging the near-term non-economic generation which is likely to take place 

in the state based on information supplied by commenters. This approach does not affect the 

budgets in other states; in particular, it does not decrease the number of allowances available to 

other states. The market now has sufficient allowances to compensate for the emissions from 

that out-of-merit-order generation. 

EPA believes this approach is reasonable as it maintains the balance between electricity supply 

and demand while accounting for the revised near-term operation of units identified by 

commenters. The commenter’s concern that this approach, “may shortchange generators in other 

states that will be called upon to generate more electricity when the constraints have been 

resolved,” is misplaced, as it ignores the fact that in this rulemaking, EPA confined these nearterm out-of-merit-order dispatch adjustments to the states in which such constraints were 

identified. In other words, EPA has not reduced any state’s budget on the basis of near-term outof-merit-order operational constraints identified at a unit in a different state; instead, EPA has 

quantified the net increase in near-term emissions expected from these adjusted unit-level 

operations and has added an equivalent number of allowances into the system accordingly, and 
FIP Revisions – RTC 

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these additional allowances do not come “at the expense” of any other generator in the system. 

EPA believes that this approach integrates all of the technical information provided by 

commenters into a reliable estimate of state-level emissions remaining in 2012 and 2014 after the 

appropriate cost-effective emission reductions have been made, which is the basis for 

establishing state budgets under the Transport Rule. 

COMMENT: Dissimilar Treatment of Similar Sources 

One of the most notable aspects of the Direct Final Rule is the way in which it simply lowers the 

burden on some states because those states have adopted regulatory requirements that do not 

require installation of pollution controls until after 2014. For example, the Direct Final Rule 

states that, in the final CSAPR, EPA had “inadvertently” included pollution control installation 

requirements from a Georgia state rule whose deadlines at certain units actually extend beyond 

2014. To correct the alignment of the Georgia 2014 state budgets with the requirements for 

affected units in Georgia to install controls by the state rule’s deadlines, EPA is increasing 

Georgia’s 2014 state budgets by 40,334 tons of SO2, 13,198 tons of annual NOX, and 5,762 tons 

of ozone-season NOX.” 

Id. at 10343.

 

It appears that Georgia’s deadlines were based on a realistic analysis of the time needed to install 

controls on multiple units while still maintaining reliability. EPA, however, did not do any such 

analysis for generating units located in Ohio or Pennsylvania, where many of GenOn’s coal-fired 

units are located. GenOn and many other companies have pointed out that CSAPR’s deadlines 

simply do not allow enough time for companies to install post-combustion controls on coal-fired 

power plants. In the Direct Final Rule, EPA essentially acknowledges this fact – at least in the 

case of Georgia. 

 

The Direct Final Rule gives coal-fired units in Georgia sufficient time – beyond 2014 – to install 

advanced emission controls. Yet coal-fired units in Pennsylvania and Ohio, where many of 

GenOn’s units are located, are essentially forced to shut down until they can install the very 

same controls. It is arbitrary for EPA to treat similarly situated units in such different ways. 

 

Kansas provides another example. The Direct Final Rule states that “EPA inadvertently included 

an emission rate requirement from a consent decree affecting a Kansas facility whose deadline 

actually extends beyond 2014. To correct the alignment of the Kansas 2014 state budget with the 

requirements for affected units in Kansas to meet the emission rate limitation by the consent 

decree’s deadlines, EPA is increasing the Kansas 2014 annual NOX budget by an additional 

5,154 tons. Id. at 10344. 

 

We can find nothing in the record to indicate that EPA did any kind of analysis to determine 

whether the emission rate limits could actually be achieved by 2014. As far as the record shows, 

EPA has simply taken the position that, where a unit is covered by an existing requirements that 

does not become effective until after 2014, CSAPR will not assume or require any emission 
FIP Revisions – RTC 

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Page 67 

reductions from that unit. Again, this treats similar units very differently based solely on whether 

they are subject to existing requirements. This is arbitrary and unreasonable. 

RESPONSE: This comment is based on several unfounded assumptions. First, the commenter 

states that, “In the Direct Final Rule, EPA essentially acknowledges this fact... that CSAPR’s 

deadlines simply do not allow enough time for companies to install post-combustion controls on 

coal-fired power plants.” This statement is incorrect. EPA has in no way “acknowledged” or 

made any such finding, and the rule’s record clearly demonstrates that sources have adequate 

time under the Transport Rule to install post-combustion controls. EPA has never stated or 

suggested that the adjustments made in the direct final rule were made because, as the 

commenter suggests, EPA concluded that there was insufficient time for companies to install 

post-combustion controls on coal fired power plants. To the contrary, EPA even conducted 

modeling of the final Transport Rule demonstrating that sources could cost-effectively meet the 

state budgets even if they did not add a single scrubber to the fleet (beyond those already 

underway at the time of EPA rulemaking) (See the following modeling documents in the Docket: 

TR_No_FGD_in2014_Scenario_Final (EPA-HQ-OAR-2009-0491-4422), 

TR_No_FGD_in2014_Scenario_Final State Emissions (EPA-HQ-OAR-2009-0491-4423), 

TR_Remedy_Sensitivity_final_variability_limits_no2014_FGD (EPA-HQ-OAR-2009-0491-

4463) and TR_Remedy_Sensitivity_final_variability_limits_no2014_FGD State Emissions 

(EPA-HQ-OAR-2009-0491-4467). That modeling clearly refutes the commenter’s incorrect 

assertion that “coal-fired units in Pennsylvania and Ohio... are essentially forced to shut down 

[by the Transport Rule] until they can install [advanced emissions] controls.” 

Second, the commenter misreads the Agency’s clearly stated rationale for revising Georgia’s 

state budgets, namely to adjust for revisions to the Georgia Multi-Pollutant State Rule. The 

commenter attempts to characterize its units located in other states (Pennsylvania and Ohio) as 

being “similarly situated” to the units in Georgia that provided the basis for the revisions to 

Georgia’s state budgets. This effort fails as it is based on a misreading of the rationale for 

revising the Georgia state budgets. The commenter’s units in Pennsylvania and Ohio are not 

“similarly situated” to the units in Georgia. First of all, the Transport Rule itself makes units in 

Pennsylvania and Ohio subject to different criteria from those in Georgia - namely, that 

Pennsylvania and Ohio are Group 1 states whereas Georgia is in Group 2 for SO2 control. EPA’s 

decision to increase the state budget was in no way based on a judgment about the capability of 

sources in Georgia to add post-combustion control equipment under any particular schedule. 

Instead, because Georgia is a Group 2 state, its budget is based on an analysis of what emissions 

remain in the state in 2014 after all available emission reductions have been made up to the $500 

per ton cost threshold – a cost threshold that is too low to incentivize the construction of any 

post-combustion controls. In other words, if there is no non-Transport Rule related reason for a 

source to install post-combustion controls (e.g. the Georgia Multi-Pollutant State Rule), EPA 

will not assume such controls are installed. The commenter stated that, “It appears that 

Georgia’s deadlines were based on a realistic analysis of the time needed to install controls on 

multiple units while still maintaining reliability,” is incorrect and unsupported. EPA made 

adjustments to the Georgia budgets because it concluded that, because Georgia was a Group 2 

states, there were no incentives, absent the Georgia Multi-Pollutant State Law, for a source in 
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June 5, 2012 

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Georgia to install post-combustion SO2 controls or to install such controls more rapidly than 

required under state law. This conclusion does not hold true for sources in Group 1 states. 

The corrections to which the comments refer were made to correct assumptions regarding 

regulatory requirements to which sources in these states were subject. The IPM Base Case for 

the final Transport Rule modeled decisions that would have been made in the absence of the 

Transport Rule or CAIR, see Federal Implementation Plans: Interstate Transport of Fine 

Particulate Matter and Ozone and Correction of SIP Approvals (76 FR 48223). This necessarily 

includes both state rules and other EPA rules outside of the Transport Rule that would exist 

whether or not states are subject to CAIR or Transport Rule requirements, particularly controls 

that sources would be required to have installed. If these other rules were not included in the 

Base Case, the IPM Base Case would not reflect accurate assumptions about the regulatory 

environment requiring controls in the absence of the rule. Regarding the Georgia adjustments, 

EPA adjusted budgets to correct for the assumption in the final Transport Rule analysis that 

particular Georgia Multi-Pollutant State Rule control deadlines for FGD/SCR retrofits at Branch, 

Scherer, and Yates facilities would deliver emission reductions in 2014, whereas those 

reductions are in fact not required to occur until December 31, 2014 or later (See pp. 61-64, Final 

Revisions Rule State Budgets and New Unit Set-Asides TSD, Docket No. EPA-HQ-OAR-2009-

0491-4962). Regarding the Kansas adjustments, EPA adjusted for the assumption that particular 

Westar consent decree emission rate and tonnage cap requirements begin in 2015, not 2014 as 

assumed in the final rule analysis (See pp. 60-61, Final Revisions Rule State Budgets and New 

Unit Set-Asides TSD, Docket No. EPA-HQ-OAR-2009-0491-4962). These adjustments to the 

budgets approximate what IPM modeling would have shown if the updated assumptions had 

been originally included. Thus the contributions of all states under the rule are analyzed based 

on an accurate reflection of the regulatory obligations to which they must respond outside of 

CAIR or CSAPR. 

The state budgets are then determined based on what controls eliminate significant contributions 

within the cost thresholds applicable to that state, based on IPM’s least cost modeling. The cost 

curves factor in the time required for controls to come online (see Final Rule 76 FR 48249). 

The revisions for Georgia and Kansas were not based on any finding that the adjusted units could 

not in fact feasibly achieve the originally modeled reductions in that timeframe; instead, 

revisions made for Georgia and Kansas reflect that those units would not make such reductions 

in 2014 in response to either legal requirements or to the relevant cost threshold to which those 

states are subject under the Transport Rule’s quantification of significant contribution. The 

commenter does not provide any evidence of a legal requirement that is not represented 

accurately in the Base Case assumptions, much less provide an argument that any assumption 

needs to be altered because it incorrectly assumes controls that would not be justified by Group 1 

cost thresholds. 

It should also be noted that Georgia and Kansas, as Group 2 states, differ in their sulfur dioxide 

emissions reduction requirements from Ohio and Pennsylvania, which are Group 1 states that are 

subject to a higher cost threshold for eliminating their significant contribution. For sulfur 

dioxide, different states faced different cost thresholds based on whether the significant 

contribution to nonattainment or interference with maintenance in 2014 was eliminated at 
FIP Revisions – RTC 

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Page 69 

$2300/ton (Group 1) or $500/ton (Group 2). The commenter’s allegation that “where a unit is 

covered by an existing requirements that does not become effective until after 2014, CSAPR will 

not assume or require any emission reductions from that unit” is incorrect. To the contrary, EPA 

is quantifying the emissions remaining from units after they have made all emission reductions 

available at the relevant cost threshold to which their state is subject under the Transport Rule. It 

is entirely reasonable to expect that units in Group 1 states would take greater action to reduce 

emissions by 2014 than units in Group 2 states, given the difference in the Transport Rule’s cost 

thresholds between those states. For further response on the difference in stringency between 

Group 1 and Group 2, see the response above to Wisconsin Department of Natural Resources. 

COMMENT: Need to Update Heat Input Assumptions 

 

We can find nothing in the record to indicate that, when the various state budgets were adjusted 

in the Direct Final Rule, there were also commensurate adjustments to the heat input of the units. 

If this is the case, then the unit level allocations in the FIPs will be incorrect. 

RESPONSE: These comments are outside the scope of the February 21, 2012 proposal and not 

relevant to this final action. In this rule, EPA is taking final action on the revisions proposed on 

February 21, 2012 (77 FR 10350). The scope of that proposal was limited. It proposed to 

determine that the unit-level adjustments described in the preamble to the direct final rule (77 FR 

10342) were merited. See 77 FR 10350. The proposal was narrowly focused on the adjustments 

included in the direct final rule and did not reopen any other issues (e.g. issues relating to the 

methodology used to allocate allowances under the FIPs) for comment. In sum, and as explained 

in greater detail on page 54 of this RTC, comments such as these, which relate to issues other 

than the adjustments proposed in the February 21, 2012 parallel proposal, are outside the scope 

of and not relevant to this final action. 

Moreover, this comment is based upon on an incorrect understanding of the allocations 

methodology. The commenter appears to assume that unit-level allocations are based, at least in 

part, on projected heat input and that therefore changes in projected heat input assumptions 

would directly affect the distribution of allowances among units in the state. This is incorrect, 

unit-level allocations to existing units are based on historic data and not based upon projected

heat input. The unit-level allocation methodology for existing units uses historic heat input, as 

described in Final Rule Section VII.D. (76 FR 48289-48290). EPA selects the three highest 

historic heat input values for each unit for the period 2006-2010 and averages them. This 3-year 

average heat input is calculated for all units in a state. The 3-year average heat input for each 

unit is then divided by the state’s total 3-year average heat input (a sum of the 3-year average 

heat inputs for all the existing units in the state) to determine each unit’s share of the total 3-year 

average heat input. This share is then multiplied by the state budget to determine the unit’s 

initial allocation, which is then adjusted, if needed, based upon historic emissions. Neither unitlevel or state-level projected heat inputs are used in the unit-level allocations methodology for 

existing units. 
FIP Revisions – RTC 

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COMMENT: Need to Model the Final Rule as Modified 

 

EPA has made a number of substantial changes to CSAPR since it was finalized – in both the 

Revisions Rule and the Direct Final Rule. It does not appear, however, that the Agency has 

actually modeled these changes to determine their impacts on air quality or the power sector. 

CSAPR is now very different from the original proposal. Again, we urge EPA to do a 

comprehensive analysis of the whole CSAPR program and to allow for meaningful public 

comment on it. 

RESPONSE: See section 4.2 of the Preamble for this rulemaking for EPA’s response to 

comments that suggesting that EPA should redo its air quality modeling in light of the revisions. 

See section 4.3 of the Preamble for this rulemaking for EPA’s response to comments that 

suggesting that EPA should re-execute full power sector modeling using the Integrated Planning 

Model (IPM) to determine state budgets.