FIP Revisions – RTC
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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, 2012FIP Revisions – RTC
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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 ............................................................................................................. 63FIP Revisions – RTC
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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 operati on, new units in-service and units needed to support grid operation are all neces sary 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 wh ere AEP’s facilitie s are located.

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

COMMENT: In addition to the corrections already pr oposed by EPA, AEP previously identified
within its comments on the Technical Revi sions a number of other tec hnical corrections and/or adjustments that should be made to address ot her 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 NO X burners, biomass, coal sourcing, and F GD and DSI installations contained in the modeled policy case. These proposed corr ections were not addr essed or acknowledged by
EPA either within the Final Revisions rule or the Direct Final Rule, leaving state emission budgets still woefully inadequa te to support appropriate leve ls of cost-effectiveness and reliability.

The process of promulgating a di rect final rule that includes some limited revisions without acknowledging the other broader i ssues and significan t 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 mode ls to account for these fundamental flaws before finalizing the CSAPR program.

AEP previously identified several additional a ssumptions 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 RevisionsFIP Revisions – RTC
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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 a ll comments received warran ted revisions to state budgets or allocations.

COMMENT: A. Low NO X Burners EPA assumes that a significant number of Low NO X Burner (LNBs) installations could occur by 2012 within the CSAPR policy case. As a result of this assumption, annual NO X emissions are reduced by 22,199 tons and seasonal NO X emissions are reduced by 14,804 tons (EPA-HQOAR-2009-0491-4302) relative to the ba se case. However, completing LNB installations on this large number of units by 2012 is technically in feasible due to permitting issues, equipment availability, and construction scheduling issues stemming from such a short-time frame until implementation. EPA has since recognized this t echnical infeasibility in Final Supplemental
Action on the Cross-State Air Pollution Rule a nd subsequently adjusted the 2012 Ozone Season

NO X budget in Oklahoma.

However, EPA has not addressed AEP’s previo us 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-leve l 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 NO X reductions. While the calculations show n in the table are for Northeastern 3, its sister unit, Northeastern 4, has almost identical operating char acteristics and thus the cost of removal is very similar.

The high cost of these NO X reductions, in addition to the pr eviously mentioned timing issues, indicates that this project should never have been included in the policy ca se as it is not costeffective. Accordingly, if EPA finalizes the supplemental proposal, the emission reductions associated with these retrofits, 1,749 tons of seasonal NO X , should be added back into the Oklahoma state budget. 1,749 tons repres ents the differen ce in seasonal NO X emissions between the base case and the policy case exclusively fo r Northeastern Units 3 and 4. Furthermore, AEP requests that EPA carefully review the cost-e ffectiveness calculations for all LNB projects included in the 2012 policy case as it is not readily a pparent 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.FIP Revisions – RTC
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EPA previously responded to a similar comm ent, 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 Trans port 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 installa tion and 2012 compliance. The Supplemental Notice of Final Rulemaking describes the unique circ umstances regarding th e 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 a ssured 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 contro l period, and several months in addition before peak electricity demand periods in those states, allowing adequate time fo r LNB installations as supported by the Agency’s analysis and the Tran sport Rule’s record (s ee “Installation Timing for

Low NO X Burners,” EPA-HQ-OAR-2009-0491-0051).

Even though it is outsid e of the scope of this action, in further re sponse, 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 documenta tion prescribed for the co mplete installation of LNC 2 (Low NO X Coal-and-Air nozzles with separated ove rfire 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 NO X Coal-and-Air nozzles with close-coupled overfire air) to LNC 3 (Low NO X 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 th e 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 ha s significantly overestimated the expected cost.

Finally, the IPM modeling is very consistent with the historic be havior observed in the power sector. When faced with any economic incentive to reduce NO X emissions, LNB installation or upgrade has consistently been one of the first and least costly abatement st rategies; nearly all of the units in the Transport Rule stat es that were also under CAIR or NO X SIP call have previously adopted these emission reduction strategies. EPA belie ves it is entirely reas onable to expect that states entering a federa l control program for NO X 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 constructio n due to various state rules, c onsent 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 facili ties. AEP noted in its petition for reconsideration that the IPMFIP Revisions – RTC
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outputs for the 2012 final remedy case for Cardin al 3, Clifty Creek 1-6, Clinch River 1-3, Conesville 3, Glen Lyn 5-6, Kammer 1-3, Ka nawha River 1-2, Muskingum River 3-5, Oklaunion, Spom 1-4, Rockport 1-2, Tanners Cr eek 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 th e request for reconsiderat ion, none of these units currently have a reliable source of biomass fuel, they have not been permitted to burn biomass by the state regulatory auth orities, nor have they implemente d 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 us e of biomass at these units, amounting to 11,536 tons SO 2 emissions that should be rees tablished 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 w hom 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, th at there is a reliable a nd ample supply of biomass
available and that a unit has act ual 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 SO 2 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

EPA previously responded to this comment. S ee page 72 of “Response to Comments on the Proposed Revisions to FIPs to Reduce Intersta te Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963)

COMMENT: C. Coal Sourcing

Several units within Indiana in which AEP ha s an ownership interest, Clifty Creek Units 1-6 and Rockport Units 1-2, are pr ojected to utilize 100% subbitu minous coal in the 2012 policy case. As noted in AEP’s request for reconsider ation, 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). Histor ically, these units have
burned coal blends that in clude just 75% subbituminous and 85% subbituminous coals,FIP Revisions – RTC
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respectively. Additionally, Cardin al 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 calculat ing state budgets during the 2012 and 2013 compliance

years.

In addition to incorrect blends of subbitu minous 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 cas e 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 wh ether the assumption in the 2012 policy case showing a 20% increase in produc tion is technica lly 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 exte nt they have used it historically, due to production, co ntractual and transportation issu es. The provided table contains the approximate 2011 use of very low sulfur co al at the aforementione d units and recommended changes to emission budgets based on the very limite d 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 lo w sulfur coals could not occur by 2012. According to IPM data, the policy case assume s 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 ex perience, 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 Inters tate Transport of Fine PM and Ozone” (EPAHQ-OAR-2009-0491-4963).

Additionally, EPA notes that the commenter’s analys is of low-sulfur coal use is flawed. While the use of low-sulfur coal, which is produced al most entirely in the Powder River Basin (PRB), increases roughly 700 TBtu (equivalent to about 40 million tons) between EPA’s Base Case andFIP Revisions – RTC
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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 Reme dy 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 th e 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 re trofit with either flue gas desulfurization systems (FGDs) or dry sorbent injection (DS I) in the 2014 policy case. As stated in AEP’s Petition for Reconsideration, AEP doe s not believe that it is technica lly feasible to install FGDs by 2014 unless they are alre ady under construction. AEP Request for Reconsideration and Stay

, pp. 19-20 (October 3, 2011). Particularly with resp ect to AEP’s units, AEP has not received the necessary regulatory approvals for any of the proj ects. Regulatory approval is a pre-requisite to detailed engineering and procurement, which pr ecedes the construction phase. Additionally, AEP has no operational experience using DSI for SO 2 reductions, and the U.S. power industry as a whole has little experience us ing 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 ar e 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 solutio n. AEP requests the technical corrections in the provided tables be made to the 2014 state SO 2 budgets based on the unava ilability 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

EPA previously responded to this comment. S ee 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 “Docum entation Supplement for USEPA Base Case v.4.10_FTransport - Updates for Final Trans port 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 comm ercial 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 Ut ility Steam Generating Units and Standards ofFIP Revisions – RTC
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Performance for Fossil-Fuel-Fired Electric Util ity, Industrial-Commer cial-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 NO X budget beginning in 2014, the unit is pl anned for startup in late 2012. The subject rule identified the increase in the new unit set-aside ozone season NO X budget to begin in
2014 since the allocations were al ready distributed for 2012 and 2013. With the stay of this rule
and the continuation of the CAIR rule, these allocations are no l onger 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 NO X 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 th is 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 Impl ementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals", for
the “Cross-State Air Pollu tion 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 Implementati on Plans to Reduce Intersta te Transport of Fine Particulate Matter and Ozone", to correct errors in CSAPR related to EPA's calculation of certain state emission budgets and unit-sp ecific 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 Suppl emental CSAPR Revision Rule"). 77 Fed. Reg. 10,350 (to be codified at 40 C.F.R. pt. 97). Simu ltaneously with its issu ance of the Proposed Supplement CSAPR Revision Rule, EPA took dir ect final action on its proposed additional revisions to CSAPR by publis hing a direct final rule in the Fe deral Register (the "Direct Final

1 ARIPPA filed a Petition for Reconsideration of CSAP R with EPA in October 2011. ARIPPA's Petition for Reconsideration included certain analyses, which ar e 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 Revisi on 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 Revisi on 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, Dock et 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 Di rect Final Supplemental CSAPR Revision Rule, which shall hereinafter be referred to collectively as th e "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 EP A, the "changes [in the Proposed Errors Rule] represent the proper a pplication of the methodology esta blished 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 revi sions to the [CSAPR] st ate budgets are identified and effectuated in a timely and expeditious manner." 76 Fed. Reg. 63,863.

Consistent with EPA’s stated objectives fo r 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 ch anges to CSAPR in order to consistently implement EPA's stated methodology for CSAP R, and therefore correct EPA's incorrect
determination that SO 2 emissions from ARIPPA‘s coal refu se-fired circulating fluidized bed ("CFB") boilers can be cost-effectively contro lled. As explained in detail below, because
ARIPPA’s CFB units cannot be co st-effectively controlled in a ma nner relevant to CSAPR, such units do not significantly contri bute to downwind nonattainment a nd, therefore, should not be regulated under CSAPR. Notwithstanding the rele vance of ARIPPA’s comments to EPA's stated objectives with respect to the Proposed Errors Ru le, 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 CSAP R 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 th rough 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 r ecognizes that additional revisi ons — beyond those identified in the Errors Rule - are necessary to fully implemen t 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 dire ct 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 meth odologies underlying CS APR. However, the Proposed and Direct Final Supplemental CSPR Revision Rules fails to fulfill, or even demonstrate consistency with, EPA’s stated pur pose 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 stati ng that it "has calculated the co rrections in this rulemaking in a fully consistent manner with the approach de veloped through public comment on the [Proposed Errors Rule] and finalized revisions rule." 77 Fed. Reg. 10,343.

Accordingly, ARIPPA is providing the followi ng comments on the Proposed and Direct Final Supplemental CSAPR Revision Rules, which go dire ctly to EPA’s objective for this rulemaking action of making additional correc tions to CSAPR to ensure that the regulation represents the proper application of the me thodologies 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 de monstrates 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 ne ither technologically feasible nor (as EPA has separately acknowledged) cost effective for the AR IPPA plants to further reduce SO 2 emissions from their CFB units. Moreover, the aggregate emissions from the ARIPPA plants comprise a de minimis
fraction of the SO 2 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 met hodologies devised by EPA under the rule, the Agency should
further revise CSAPR to exclude coal refuse-fired CFB combusti on units from the applicability provisions of the regulation.

To the extent that EPA determines not to ex clude the ARIPPA plants from regulation under CSAPR, EPA should ensure that th e allocation of allowances to the ARIPPA units is consistent with the methodology identified by EPA under CSAP R. Specifically, the allowance allocations should reflect the emission levels for the plants after consideration of th e application of costeffective controls. Because, as EPA has separa tely concluded, cost-effe ctive controls are not
available to further reduce SO 2 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 increas e in the states' SO 2 allowance budgets.

3 Indeed, the combustion units operated by the ARIPPA me mbers reflect a fundamentally different design in which

SO 2 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
June 5, 2012 Page 12

For the reasons discussed below, ARIPPA specifica lly 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 w ith EPA‘s stated objectives for both the final Errors Rule and the Proposed and Direct Fi nal 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 estab lished 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 Transpor t 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 allowa nces to existing sources. EPA provided ample opportunity to comment on both issu es during the rulemaking proce ss for the Transport Rule and has neither proposed any revisions to those prov isions nor reopened them for additional public comment in this rulemaking. Comments on these issu es are outside the scope of and not relevant to this rulemaking. Furthermore, the comment er alleges that “the [allowance allocation] methodology identified by EPA und er CSAPR... should reflect the emission levels for the [ARIPPA] plants after consideration of the a pplication of cost-effec tive controls.” This interpretation has no basis in the record of th e 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 i nput and historic emissi ons 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 c onsidered and addressed ARIPPA’s comments on the proposed TR revisions rule, “Revisions to Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Ma tter 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, entitl ed, “Response to Comments on the Proposed Revisions to FIPs
to Reduce Interstate Trans port of Fine PM and Ozone” (EPA-HQ-OAR-2009-0491-4963). See
further discussion below.

COMMENT : II. BackgroundFIP Revisions – RTC
June 5, 2012 Page 13

Organized in 1988, ARIPPA is a non-profit trade a ssociation based in Camp Hill, Pennsylvania. Its membership is comprised of electric generatin g plants, producing alternative electrical energy
and/or steam. Most ARIPPA memb er plants are currently located in or near the anthracite or bituminous coal regions of the United States.

ARIPPA plants are designed and operated to co nvert large quantities of coal refuse into alternative electricity, sewing the energy need s of hundreds of thousands of households and businesses. Member plants generate electric ity 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 abandone d 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 Pr otection (“PADEP"), and the Office of Surface Mining Reclamation and Enforcement alike. In particular, EPA recently recognized the environmental benefits provided by coal refuse-f ired plants in the c ontext 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 rem oval of coal refuse pi les and by reclaiming land for productive use. Consequently, because of the unique environmental benefits that coal refusefired EGUs provide, these units warrant special consideratio n,... " 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 S upplemental 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 suffici ent information to repr esent 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 th e 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 issu es for comment. In sum, and as explained in greater detail on page 54 of this RT C, comments such as these, which relate to issues other than the adjustments proposed in the February 21, 2012 para llel proposal, are outside the scope of and not releva nt to this final action.FIP Revisions – RTC
June 5, 2012 Page 14

Further, the language that the commenter c ites (76 Fed. Reg. 25066) a ppears 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 ARI PPA 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 determin es specific control levels for new (which is defined to include modified, and reconstructed) individual emission source s. In contrast, the Transport Rule determines state-level emissi on requirements and provide s 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 s ources under a separate, different, and unrelated regulatory obligation, as being somehow relevant to the Tran sport 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 rath er than by type of unit. EPA believes that treating these sources differently from other sour ces 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 adjustme nts 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, particul arly in reference to errors or inconsistencies relative to EPA's analysis in promulgating the final CSAPR regulation. EPA expressly noted its objective of implementing "tec hnical fixes [to] maintain [CSAPR's] ability to
achieve the elimination of si gnificant contribution and interference with maintenance as quantified by the proper app lication 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 c ontribution though the proper appl ication of the methodologies established by EPA. EPA intends to implement these additional correctio ns through the Proposed and Direct Final Supplemental CSAPR Revision Rules.

Consistent with EPA’s stated purpose for th e 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 su ch sources, is consistent with the methodology employed by the Agency in evaluati ng 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-effec tively be achieved by regulating only a single category of sources - EGUs. In the preamble to CSAPR, EPA explains th at "[al]though the cost curves presented in [the final] rule only incl ude EGU reductions, EPA also assessed the cost of

SO 2 and NO X 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 availabl e reductions .... EPA revisited these non-EGU
reduction cost levels in this fi nal 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

NO X , $2,300/ton for SO 2 )." 76 Fed. Reg. 48,249.

For the reasons discussed below, EPA‘s categori zation of the ARIPPA fa cilities under CSAPR is inconsistent with EPA‘s objectiv es for the rule, and the Propose d 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 implem ent the "technical fixes" necessary to achieve both the elimination of "significant co ntribution," as defined by EPA for purposes of this regulation, and the proper application of the methodologies devise d by EPA under CSAPR, the Agency should revise CSAPR to eliminate co al refuse-fired CFB combustion units from the applicability provision s 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 SO 2 and NO X emissions based upon the opportunities av ailable 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 char acteristics, fuel s ource, operational design, emissions control options, or any other criteria. Instead, CSAPR a pplies to any stationary fossil
fuel-fired boiler or combusti on turbine qualifying as an aff ected EGU under the final rule. 5
EPA's approach of regulating all EGUs unde r CSAPR, without considering significant distinguishing characteristics among those E GUs, is contrary to the objectives and methodologies underlying the rule, and results in unsupportable applicab ility determinations.

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

Rules are limited to the SO 2 provisions of the regulation. CSAPR includes allocations for NO X 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 sour ce category. Therefore, the determination
reflected in the CSAPR regulation relative to NO X allowance allocations appears to be consistent with
EPA's stated methodology to address sign ificant 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 pr oducing 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 trad itional EGUs. First, CFB technology is inherently cleaner-burning and, therefore, more environmenta lly friendly than traditional coal combustion technology. The CFB technology can pr operly be classified as "c leaner-burning" because the
concentrations of SO 2 and NO X in the gases exiting the combus tion chamber are materially lower
than the combustion emissions fr om conventional coal-fired E GUs. These lower emission rates reflect the incorporation of emission control systems into the basic design of the CFB combustion unit, reflecting a fundamental ly different methodology for limiting SO 2 and NO X emissions associated with the combustion process. Therefore, the emission characteristics, including for NO X and SO 2 , 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 th e circulating fluidized bed allows for the absorption of SO 2 and significant reductions in SO 2 emissions. For this reason, CFB operators
must maintain strict control over combustion zo ne characteristics in order to simultaneously control multiple pollutants. For the same r eason, the ability to achieve even further SO 2 reductions through the addition of limestone, is as ymptotically restricted — not only would the
introduction of additional limestone interfer e with maintenance of the optimal operating envelope for energy production a nd emission control, but, after a point, addition of substantial
additional limestone would achieve li mited, if any, further reduction in SO 2 emission rates.

Indeed, these plants were designed and built to achieve specific levels of SO 2 control (generally exceeding 90% SO 2 reduction) through limestone addition, in order to meet the Best Available Control Technology (“BACT") emission limits establ ished when the plants were permitted. With respect to NO X , strict management of combustion zone characteristics limit the formation of

NO X . Additionally, many ARIPPA plants employ se lective non-catalytic reduction ("SNCR") to
achieve enhanced NO X reductions. In all cases, the CFB technology emits substantially lower

SO 2 and NO X 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 tec hnologies considered by EPA for application to EGUs under CSAPR do not readily extend to CFB t echnology, in the same manner and extent as applied to traditional coal-f ired units. While back-end emi ssion control technology can be applied to CFB units under certain situations, unique boiler design and operational criteria create additional challenges to eff ective operation of these emission control systems. More significantly, the cost-effectiveness of such back-e nd controls is dramatic ally affected by these technology distinctions. Because the CFB technol ogies are inherently cleaner burning, the quantity of emissions available for back-end cont rol 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 opera tional costs associated with the back-end controls are not materially less for these smaller facilities, because of the inhere nt fixed capital cost requirements of these systems, and unique challeng es 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 facili ties 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 fo r this alternative ener gy 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 a nd rivers. The CFB technology was designed to effectively combust coal refuse from past and current mining activit ies, thereby clearing thousands of acres of land, reclaiming prev iously 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 fac ilities are generally subject to legal requirements to combust coal refuse, at least as a primary fuel compone nt. These legal requirements derive not only from contractual commitments, but also standard s imposed by the Federal Energy Regulatory Commission ("FERC") as part of th e designation of these facilities as QFs; the QF designation is
a condition of the facilities' fina ncing contracts for the CFB units.

In evaluating emission control options under CSAP R, EPA considered opportunities available to regulated sources to engage in fuel sw itching, and such opportunities supported EPA's conclusion that EGUs may cost-effectively reduce SO 2 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 certain ly did not consider non-traditional coal used as fuel, notably includ ing 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 thei r 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; switchi ng fuels would therefore be dir ectly inconsistent with this purpose. Further, EPA has itself acknowledged, w ithin the Proposed Utility MACT and NSPS, that "coal refuse from some piles has sulfur c ontents at such high levels that they present potential economic and technical diffi culties in achieving the same SO 2 standards that we are proposing for higher quality coals". 76 Fed. Reg. 24,976, 25,066.

Although EPA’s stated methodology for evalua ting "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 cont rolled consistent with the objectives of CSAPR

6 Although the ARIPPA facilities cannot substitute lower su lfur fuels for coal refuse in the operation of the CFB units, it should be noted that many of thes e facilities are nonetheless subject to permit-based limitations which (typically) limit the fuel sulfur conten t 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 uti lized by ARIPPA facilities, any more than it would apply to non-EGU stationary sources excluded by EPA from re gulation under CSAPR.

As previously reported to EPA, ARIPPA c onducted an evaluation of the relative costeffectiveness of the compliance options avai lable to the ARIPPA plants for reducing SO 2 emissions to the levels reflected in the a llowance allocations provi ded during Phase II of CSAPR. The analysis reflects consideration of th e control options theoreti cally available to the
ARIPPA facilities to reduce SO 2 emissions: reduce fuel sulfur, in crease the use of limestone, or employ an add-on SO 2 emission control device, such as dr y sorbent injection ("DSI") or spray drying absorption ("SDA"). Because of the unique ch aracteristics of ARIPPA’s coal refuse-fired CFB units, the ARIPPA plants canno t feasibly achieve material SO 2 reductions by either reducing fuel sulfur or increasi ng limestone utilization. Accordi ngly, the only theoretical option among these three SO 2 reduction scenarios through which the ARIPPA plants might limit SO 2 emissions to levels commensurate with the Phas e 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 availabl e technology for reducing SO 2 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-e nd DSI for the control of SO 2 emissions from a coal refuse-fired CFB unit anywhere in the United States. Under established CAA precedent, therefore, DSI cannot be considered a "technically feasib le" control option for the reduction of SO 2 emissions from this source type.

Moreover, even to the extent that such em ission control technology could be considered technically feasible (and for the reas ons discussed above, post-combustion SO 2 emission control technology cannot be considered "ava ilable" for a retrofit applicati on to an existing coal refusefired CFB unit), both EPA's and ARIPPA’s analys es demonstrate that su ch technology could not be considered economically feasible. In the co ntext of publishing the Proposed Utility MACT and NSPS, EPA specifically commented that, "[w]e ha ve concluded that it is not generally cost
effective to add additi onal post-combustion SO 2 controls for modified fluidized beds." 76 Fed. Reg. 25,066, Therefore, EPA has already reached the conclusion that any post-combustion SO 2 controls would not be cost effectiv e when applied to this source type. 7

Similarly, ARIPPA’s analysis of the cost-e ffectiveness of utilizing DSI to reduce SO 2 emissions
demonstrates that it would co st at least $3,300 per ton removed for a typical 80 MW ARIPPA plant to reduce SO 2 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 SO 2 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 SO 2 cost threshold of $2,300 per ton.").FIP Revisions – RTC
June 5, 2012 Page 19

reduction requirements. 8 This is a conservative, "best cas e" 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 othe r than coal refuse-fired CFB units 9 have demonstrated that significantly higher sorbent injection rates are required for effective SO 2 control, and therefore employing DSI to achieve the required SO 2 reductions would actually cost more than $6,400 per ton removed. Therefore, contrary to EPA’s assu mptions in the preamble to the final rule, it
would not be cost-effective for ARIPPA's coal re fuse-fired CFB units to install and operate DSI
to reduce SO 2 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 pr eviously submittal to EPA. 10

ARIPPA also evaluated the potenti al application of SDA as an SO 2 emission control option, notwithstanding that, as with DSI, ARIPPA is not aware of a si ngle commercially demonstrated retrofit application of SDA for the control of SO 2 emissions from a coal refuse-fired CFB unit anywhere in the United States. Fo r a typical 80 MW ARIPPA plant, the control cost for reducing

SO 2 emissions to meet the Phase II reduction re quirements using SDA would be nearly $9,000 per ton removed. As previously submitted to EP A, ARIPPA's cost estim ate 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 ex ceeds the control cost th reshold selected by EPA as cost-effective for reducing SO 2 emissions from all EGUs under CSAPR.

Based on the results of ARIPPA’s analysis, it is clear that ther e are no controls that are both technologically and economi cally available to the ARIPPA plants for reducing SO 2 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 ar e 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, in creased chlorides, sulfates, and othe r characteristics. The resulting ash parameters would likely dictate the need for disposal in lin ed 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 SO 2 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 SO 2 emissions from coal refuse-fired CFB units is currently uncertain at best, with most cu rrent applications still in experimental stages. Such uncertainty only exacerbates the challenge s faced by these plants as a result of the virtually-immediate applicability of the final ru le. This conclusion is consistent with EPA’s recent determination (as articulated in the cont ext 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 SO 2 controls to modified fluidized be d combustion sources. See 76 Fed. Reg. 25,066.

In the context of EPA’s current rulemaki ng action, considering EPA’s ongoing objective of implementing additional technical fi xes to ensure consistency with the elimination of "significant contribution" and proper application of the me thodologies identified by EPA under CSAPR, the Agency should recognize the need to implement changes to the regul ation in order to correct the
determination - inconsistent with its stated methodology - that further SO 2 emissions can be cost effectively achieved for existing coal refuse-fir ed CFB EGUs, and, therefore, that such units significantly contribute to dow nwind nonattainment and should be regulated under CSAPR.

(ii) Absent a showing that emi ssions can be cost-effectively controlled from coal refuse-fired CFB units, EPA has not justified a finding of si gnificant contribution from the ARIPPA plants.

Given the distinguishing characteristics of the AR IPPA 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 "s ignificant contributio n" under CSAPR to the ARIPPA plants, and, as such, even further correct ions 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 ev aluation of the emissi on characteristics and
the cost-effectiveness of available controls for EGUs. In the context of emission impacts, the
emissions from the ARIPPA facilities are materi ally 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 fo r the unique emission profiles of these facilities, EPA inappropriately and inaccurately concluded th at the ARIPPA EGUs contribute to downwind
nonattainment to the same extent as traditional E GUs. Instead, the emission characteristics of the ARIPPA CFB units distinguish th ese sources from traditional co al-fired EGUs. Under a proper application of EPA’s methodology, ev aluation of emission characterist ics 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 SO 2 emissions budget under CSAPR for Group 1 states. Indeed, the collective SO 2 emissions from the ARIPPA plants in Pennsylvania and West Virg inia represent less than 1% of the aggregate

SO 2 emissions from the Group 1 states. As such, a determination that the ARIPPA facilities are among a relatively small percentage of fac ilities 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 mean ingful impact on the overall emissions budgetFIP Revisions – RTC
June 5, 2012 Page 21

under CSAPR, including for individu al states such as Pennsylvani a and West Virginia, or EPA’s analysis of the projected downw ind impact from the State.

Likewise, under the second part of EPA’s "significant contribution" analysis, EPA’s determination that EGUs may be cost-effectively contro lled is based on an in correct application, or the absence of any application, of EPA’ s established CSAPR me thodology to the ARIPPA facilities. Most significantly, the emission reduction techniques identified by EPA are either inapplicable to the ARIPPA facilities or woul d necessitate a substantially different control analysis.

Application of EPA’s methodology under CSAPR supported the conclusion that non-EGUs cannot achieve comparable cost-eff ective 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 SO 2 and NO X reductions from EGUs are available at a cost per ton that is lower than the cost pe r ton of non-EGU controls." 75 Fed. Reg. 45,300. Because EPA has developed a methodol ogy for identifying affected sources under CSAPR which distinguishes among source categories on the basis that sp ecific design and/or operating characteristics make it economically infeasible for non-E GU source categories to comply with the emission reduction requireme nts in CSAPR, the proper and consistent application of that methodology requires the conc lusion that ARIPPA’s CF B units should not be included among the sources subjec t to regulation under CSAPR.

For these reasons, EPA’s analys is as reflected in CSAPR ca nnot support a finding that the ARIPPA facilities sign ificantly contribute to nonattainment in downwind states, nor that
emissions from ARIPPA facili ties can be cost-effectively co ntrolled. 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 signifi cantly contribute to
nonattainment and therefore wa rrant control under CSAPR.

In addition, within the pr eamble 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 enumerat es "key guiding principles" for determining to regulate specific sources. 75 Fed. Reg. 45,226-27. Among these guid ing principles, EPA states that its proposed regulatory appr oach would provide for "cost e ffectiveness,“ and would provide incentives and flexibility to the regulated comm unity. These guiding principles are not satisfied with respect to the ARIPPA facilities, predom inately because the proposed emission reductions cannot be achieved cost-effectively, and the regulato ry standards not only afford no flexibility to the ARIPPA plants, but would inst ead establish requirements that these facilities cannot readily satisfy. The fact that EPA‘s guiding principl es for CSAPR would not be served through regulation of the ARIPPA facilities provides furthe r evidence that the final CSAPR regulation is inconsistent with proper app lication of EPA’s establishe d methodology, reflected in the rulemaking development process, for determini ng which sources should be subject to EPA’s approach toward intersta te 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 signi ficantly contribute to downwi nd nonattainment, and therefore should be regulated under CSAPR, confirms that such designati on cannot properly extend to the
ARIPPA facilities. EPA should th erefore revise CSAPR, through th e 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 additiona l technical correctio ns necessary to address its concerns regarding significant contributi on in a manner consistent wi th 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 applicabil ity concern in the context of an argument regarding the Transport Rule’s approach to determine a state’ s significant c ontribution to
nonattainment and interference with maintena nce downwind. The commenter’s request, however, is that that EPA exclude AR IPPA member facilities from the SO 2 requirements of the Transport Rule. As such, it is a comment on and a request for a revision to the Transport Rule applicability provisions. EP A did not propose any revisions to the final Transport Rule applicability provisi ons or reopen them for co mment in this rulemaking. This comment therefore is outside the scope of this rulemaking.

ARIPPA's Petition for Reconsideration raises re lated 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 th e Transport Rule applicability provisions during the course of that rulemaking. ARI PPA commented on the proposed applicability provisions -- requesting that AR IPPA facilities be excluded -- a nd 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 Trans port of Fine Particulat e 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 theFIP Revisions – RTC
June 5, 2012 Page 23

substance of ARIPPA’s comment without iden tifying 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 interfe rence with maintenance downwind with respect to th e 1997 annual and 2006 24-hour PM 2.5 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 an alysis is based on co nsideration of all emissions categories in a state and is not limite d 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 nonatta inment and interference with maintenance as the emission
reductions available from EGUs collectively in the state at a particular co st 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 speci fied 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 contributi on and interference with mainte nance for individual emissions sources. EPA’s Transport Rule analysis determin ed that electric generating units (EGUs) as a
category have cost-effective emission reductions avai lable. 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 Ag ency 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 nonattain ment 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 Congr ess’ 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 necessari ly be expected to cost-effectively reduce SO 2 emissions on an individual basis, e.g., combined-c ycle gas turbines. In both the Transport Rule and the Acid Rain Program, EGUs as a broad clas s of units are included in an emission reduction program that provides the flexibility of allowance trading.

Also, the commenter purports to show that the ac tual cost per ton “for a typical 80 MW ARIPPA plant to reduce SO 2 emissions to the extent needed to satisfy the applicable 2014 emission reduction requirements” is higher than the $2,300 cost pe r ton threshold EPA selected as a basis on which to define signi ficant contribution for SO 2 emissions in Group 1 states. However, theFIP Revisions – RTC
June 5, 2012 Page 24

commenter does not explain how “the applicab le 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 cal culations are unsuppor ted and they do not
demonstrate that such a un it is incapable of achieving any SO 2 reductions at a cost at or below $2,300 per ton. For example, the cost of a part icular application of dry sorbent injection technology can vary depending on how much sorbent is injected, whic h in turn is a function of
how much SO 2 removal is desired. The commenter’s calc ulations appear to have pre-determined the “required” SO 2 reductions at the hypotheti cal unit (with no basis in actual Transport Rule requirements), which unnecessarily prevents consideration of other levels of SO 2 control at that
unit that could be achieved more cost-effectively. The Transport Ru le is structured specifically
to allow individual units to cons ider a broad spectrum of emissi on control strategies that EPA modeling shows would yield a br oad “equilibrium” cost-per-t on threshold of $2,300 per ton when taking into account emission reductions available across all covered sources. The commenter’s isolated and unsuppor ted calculations do not offer any evidence to contradict EPA’s reliance on this cost per ton threshold an d the resulting quantific ation of state budgets
under the rule.

EPA fully responded to ARIPPA’s request for excl usion of ARIPPA facili ties 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 increas e the allowance alloca tions to the ARIPPA
units to reflect the emission levels reflective of the application of cost-effective controls for reducing emissions from co al refuse-fired CFB units.

EPA has described its methodology for determin ing state-specific emission budgets as constituting the aggregate emissions from affect ed sources located within the state during an average year, once the emissions associated w ith significant contributio n to nonattainment and
interference with maintenance are eliminated fr om the emission inventory for such sources. 76 Fed. Reg. 48,249. EPA identified the amount of emi ssions representing significant contribution
to nonattainment and interference with maintenan ce 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 select ed for Group 1 states (including Pennsylvania) - i.e., $500/ton for NO X and SO 2 in 2012, and $500 for NO X and $2,300/ton for SO 2 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-effec tive 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 SO 2 emissions from coal refuse-fired CFB units. Accordingly, to the extent that EPA determines not to excludeFIP Revisions – RTC
June 5, 2012 Page 25

the ARIPPA plants from regulation under CSAPR, proper application of EPA’s CSAPR methodology requires that the allowa nce allocations for the ARIPPA plants correspond to current emission levels for such sources. Specifically, becau se 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 source s that "significantly co ntribute" to downwind nonattainment. Therefore, under th e methodology reflected in CSAPR, the calculation of the SO 2 allowance allocations for these sour ces cannot include a reduction in SO 2 emissions to offset the sources’ "significant" contri bution to nonattainment in another state (i.e., the SO 2 emission level for these sources that significantly cont ribute to downwind nonattainment is zero).

This consistent application of EPA’s CS APR methodology would re quire a corresponding increase in the total emission budgets for Pe nnsylvania. 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 im proper assumptions about the operation of existing and planned controls by affected sources in these states, as we ll as the increases in emission budgets for certain states which EPA impl emented through the Proposed Errors Rule.

To the extent that EPA properly applies its methodology under the regulation and excludes any calculation of required emission re ductions from the ARIPPA plants in the context of CSAPR‘s significant contribution anal ysis, EPA must also adjust its un it-specific allocation approach for Pennsylvania under the FIP to ensu re consistency with the objectives for CSAPR. Under EPA's current allowance allocation appr oach, all covered EGUs in Penns ylvania receive a proportionate share of the state‘s budget as unit-specific allocations, subj ect only to some unit-specific
imitations reflective of established historic emission rates for certain sources. Because the increase in Pennsylvania’s budget under the appro ach proposed in these comments is specifically
intended to ensure that the allocation determin ation for all regulated sources corresponds to emission rates after the application of cost eff ective 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 Pennsylva nia, corresponding to th e emission rates from coal-fired CFBs reflecting application of cost-e ffective 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 s hould receive allowan ce allocations that
are commensurate with the units’ historic emi ssion 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 a pplication of cost-effective controls for reducing
emissions of SO 2 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 consis tent application of the met hodology underlying CSAPR, without reducing allowance allocations to other affected s ources in Pennsylvania (in order to allocate toFIP Revisions – RTC
June 5, 2012 Page 26

the ARIPPA plants a number of allowances th at properly reflects thei r sources’ emission rates after application of co st-effective controls).

For these reasons, to the extent that EPA dete rmines not to exclude the ARIPPA units from regulation under CSAPR, consistent appli cation of EPA’s met hodology 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 regulati on to reflect the absen ce of availability of
additional cost-effective controls for further re ducing 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

Comments on the Transport Rule FIPs’ method for allocating emission al lowances to existing units are outside the scope of this rulemaking. EPA provided full opportunity to comment on the existing-unit allocation methodology in the Transpor t Rule rulemaking. In fact, in response to comments from ARIPPA and others on the pr oposed allocation methodol ogy requesting that
allowances be allocated based on historic heat input instead of on projected emissions as proposed, EPA issued a Notice of Data Availabi lity 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 un it’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 rule making. For these reasons, this comment is beyond the scope of this rulemaking.

It is worth noting, nonetheless, th at ARIPPA’s assertion that th e Transport Rule FIP allocation methodology “requires that allowanc e 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 leve ls reflective of the application of cost-effective controls.”

The commenter implies that EPA defined signi ficant contribution on a unit level and then
allocated emission allowances based on each un it’s significant contribution. However, EPA defined significant contribution at the state level (as discussed above) and allocated allowancesFIP Revisions – RTC
June 5, 2012 Page 27

to individual units based on each unit’s share of hi storic heat input subject to a maximum based
on historic emissions.

The comments seem to be based on the false pr emise 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 allowan ce 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 “pri ce to emit” under the pr ogram is the economic incentive by which all sources wi ll 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 initia l unit-level allowance allocations.

In its comments on the proposed revisions to the Transport Rule, “Revisions to Federal Implementation Plans To Reduce Interstate Trans port of Fine Particulat e Matter and Ozone” (76 FR 63860; October 14, 2011), ARIPPA similarly s uggested using an alternative methodology to allocate a greater number of SO 2 allowances to ARIPPA units (with related increases in state budget). EPA addressed comments on the alloca tion 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. Th at 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 methodolog ies and pursuit of the rule’s objectives, EPA
should not finalize the terms of the Proposed and Direct Fina l Supplemental CSAPR Revision Rules without making additional adjustments to th e 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 dow nwind nonattainment, as evalua ted under CSAPR. Therefore, under both the objectives and methodology underlyi ng CSAPR, the ARIPPA sources should not be made subject to the obligations of CSAP R. 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 Re vision Rules of implementing technical fixes to ensure consistency with the elimination of significant contribution a nd proper application of the methodologies identified by EPA under CSAPR.

Despite EPA’s determination in the contex t of developing CSAPR that multiple source categories generate material rates of NO X and SO 2 emissions, EPA concluded that the objectives of CSAPR can most cost-effectively be achieve d 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, em issions control options, or any other criteria. This approach is inappropriate and results in applicability determinations that are inconsistentFIP Revisions – RTC
June 5, 2012 Page 28

with EPA’s stated methodologies and objectives fo r 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 an alysis under CSAPR fails to account for these signifi cant distinctions in coal refuse -fired CFB units, and, therefore,
EPA’s determination that EGUs can be cost-effec tively 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 se parate contemporaneous rulemaking effort that
additional SO 2 emission reductions cannot be cost effec tively achieved for existing coal refusefired CFB units.

Consistent with EPA’s conclusi on, ARIPPA’s analysis of the re lative cost-effec tiveness of the compliance options theoretically available to ARIPPA plants for reducing SO 2 emissions
demonstrates that neither DSI nor SDA are both technically and economical ly available to the ARIPPA plants for further reducing SO 2 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 contri bute 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 SO 2 allowance allocations to the ARIPPA units to ensure proper application of EPA’s CS APR 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 identif ied the amount of emissions representing significant
contribution to nonattainment and interference wi th maintenance within each state by focusing on specific cost thresholds and the corres ponding impact on air qua lity. As such, the methodology for calculating the final state-spec ific budgets under CSAPR is founded on the proper determination of the source-specific emi ssion 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 SO 2 emissions from coal refuse-fired CFB units. Th erefore, proper applic ation of EPA’s CSAPR methodology requires that the allowa nce allocations for the ARIPPA plants correspond to current emission levels for such sources. Such adjustme nts to both state and uni t-specific allowance allocation budgets under CSAPR are not only cons istent with, but in fact constitute, the fundamental objective of the Proposed and Dire ct Final Supplemental CSAPR Revision Rules. For this reason, Finalizing such rulemaking wit hout 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
June 5, 2012 Page 29

3. Florida Electric Power Coordinating Group (FCG) [Letter: Florida Electric Power Coordinating Group (EPA-HQ-OAR-2009-0491-4978)]

COMMENT :1)The Errors Identified b y 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 NO X budget. The FCG also calculated the budget using the accurate informa tion. The errors related to: (i) unit-level NO X 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 unavail ing, 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 othe r submitted comments, like Lakeland Electric's. 11

The FCG expended considerable effort to deve lop supporting data and calculations (based on EPA's own methods) and to demonstrate th e 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 co rrected. For example, EPA approved an ozoneseason NO X 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 facili ties 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

EPA did in fact respond to comments previous ly submitted by FCG and Lakeland Electric in
section 1.1 of the document “Response to Comments on the Pr oposed Revisions to FIPs to Reduce Interstate Transport of Fine PM and Ozone.” (E PA-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 commen ts 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
June 5, 2012 Page 30

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 th e significance of gas capacity and transmission
constraint issues in our state. Given the significant reliability issu es 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 CS APR and other recent EPA regulatory actions has been acknowledged by both the Federal Energy Re gulatory 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

EPA previously responded to this comment. S ee page 7-8 of “Response to Comments on the Proposed Revisions to FIPs to Reduce Intersta te 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 res ponses 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 Florida 13 is 3600 MW; the commenter does not question this transmission capacity assumption. Rather, the commenter selects a separate electricity demand assumpti on made by the Florida Reliability Coordinating Council (FRCC) for 2012, compares it to EPA’s m odeling 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 Ag ency 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 ad equacy 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 stat e of Florida, with the exception of not including a small piece of the Florida panhandle. For clarity, EPA is refe rring 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
June 5, 2012 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 quantificati on of Florida’s state budgets. FC G is in fact supplanting the electricity demand assumption that EPA inco rporated into its IPM modeling (based on projections made by the Energy Information Ad ministration (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 electric ity demand but still compares the FRCC-based electricity demand assumpti on 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 elect ricity imports into Florid a are bounded by the transmission constraint of 3600 MW, which is describe d 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 tr ansmission constraint the
commenter described.

FCG is implicitly claiming that IPM is flawed be cause its projected electr icity supply (generation within Florida plus generation that can be impor ted 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, becaus e it consistently applie d 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 au thoritative source in the energy modeling community, the EIA projections are based on comp rehensive assumptions about short- and longterm economic growth that incorporate detailed data on regional, nati onal, and global energy markets (such as the price of va rious fuels). EPA therefore be lieves the EIA-based assumptions of future electricity demand adopted in its IP M modeling are reasonable and yield electricity generation projections that re spect 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 Corporati on (NERC). EPA notes that in this study, NERC found that in a moderate case, CSAPR result ed in no retirements through 2018. Only in the strictest case did NERC project that CSAPR would resu lt 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.” N orth American Electric Reliability Corporation.
November, 2011. Page 117FIP Revisions – RTC
June 5, 2012 Page 32

rather arbitrarily increased costs by 25% and assumed less flexible trading. 15 The NERC report even acknowledges EPA’s February 21, 2012 Revisi ons Rule that addressed out-of-merit-order dispatch issues, saying the revisions “will help m itigate the impact of the rule [on reliability], particularly in 2012 and 2013.”

Additionally, EPA notes that th e recommendations from the NERC report that FCG quotes are broad recommendations based on analysis of four EPA regulations, in ad dition to other factors facing the industry. NERC’s own analysis found th at CSAPR would have little to no impact on the reliability of the bulk power system. EPA reite rates that it has considered electric reliability
in the context of the Final Rule in the t echnical support document “Resource Adequacy and Reliability in the IPM projections for the CSAP R,” in addition to caref ully 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 stat ed in the FCG's November 28th
comment letter. EPA's decision to limit this co rrection to Florida's 2012 budget does not address the speculative nature of projecti ng the unit's in-service date and mischaracterizes both the nature of the required repairs (equating it to a less invol ved, less expensive repair 16 ) and the operator's projection for an in-service date (stating the opera tor 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

15 id. pg 125

16 Compare http :1/www. reuters.com/artic le/2011/10/17/utilities-operations-firstenergydavisidUSN1E79G OKR20111017 (noting the 2002 Da vis-Besse reactor head repair cost approximately $600
million, including purchasi ng replacement power), withhttp://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/deci ding-who-pays-repair-bill-could-delay-the-reopeningofthe-crvstal/1215722 (quoting Charles Rehwinkel, Deputy St ate 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 no t returned to service in 2014 (see section IV of the preamble to the final Revisions Rule (76 FR 10328-9, Febr uary 21, 2012)). Additionally, EPA notes that Progress Energy maintained the 2014 timeframe fo r completing the repairs to Crystal River unit 3 in its February 29, 2012 10-K ( http://phx.corporate-ir.net/p hoenix.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 th e quantification of Florida’s 2014 budget.

COMMENT : 2) EPA Must Re-Run its Modeli ng 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 e rrors in its data and assumptions. Given the additional errors identif ied in the Revisions Part II proposal, and the significant errors provided in comments that EPA should still correct (suc h as those identified by the FCG), the FCG reiterates that EPA must re-ru n its models to re-determine state budgets. 18
EPA has acknowledged significant erro rs in the budgets of 17 states, but has not yet offered any justification for correc ting these errors withoutdetermining how these changes affect the methodology and modeling that is the foundation for every budget. Given IPM's sensitivity

, EPA's acknowledgment of signifi cant 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 a nd methodology is arbitr ary and capricious.

RESPONSE : See section 4.3 of the Preamble for th is rulemaking for EPA’s response to comments that suggesting that EPA should re-e xecute 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. EP A-HQ-OAR-2009-0491-475 3. 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 owne d or co-owned by MEAG in order to restore Georgia's 2012 state S02 emission budget and unit al locations 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 SO 2 emission budget by greater th an 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 Ru le in MEAG v. EPA, Case No. 11-1379 (D.C. Cir. Oct. 14, 2011). 21 Further, nothing in the Di rect Final Rule addresses the final Transport Rule’s underlying fatal flaws, which have been extens ively documented in the briefing filed in EME Homer City Generation, LP. v. EPA, Ca se 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). Furthe r, 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 ME AG in order to restore Georgia's 2012 state S02 emission budget and unit allocations to the leve ls in the August 2010 proposed Transport Rule and in the January 2011 Notice of Data Availabi lity ("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 proh ibited 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 cau se 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 es timated at proposal were not determined in a vacuum, nor were they simply selected as pr ogram parameters with some kind of inherent preferential value in them of themselves. Inst ead, the proposal’s estimate s 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 co mment on the data and models used in the proposed Transport Rule as well as on the me thodologies EPA applied to quantify state budgets and unit-level allowance allocations. If, as th is commenter advocates, EPA had subsequently issued a final Transport Rule w ith identical state budge ts and unit-level allowance allocations to those proposed, it would have suggested that EP A 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, 20 12); State and Local Petitioners' Final Opening Brief (Mar. 16,2012); Final Reply Brief of Industry and Labo r Petitioners (Mar. 16, 2012); and Final Reply Brief of
State and Local Petitioners (Mar. 16, 2012). (The exhi bits 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 calcula ted state budgets and unit-level allowance allocations. In short, this commenter is si mply expressing a preference for the endpoints EPA calculated at proposal (in term s of Georgia’s state budget and this commenter’s unit-level allowance allocations) as compared with those endpoints EPA re-calcu lated at final as it adjusted its data and methodologies based on public comme nts 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 acti ons where the Agency was specifically seeking further information before subsequently finalizing an action.

In regards to the petition for r econsideration incorporated by refe rence, see the section 4.5 of the Preamble for this rulemaking for a discussion of petitions for reconsider ation 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 likel y result in an increas e to Georgia’s 2012 SO 2 emission budget. First, as explained below, EPA’s Response to Comments on the Proposed
Revisions to FIPs to Reduce Interstate Trans port of Fine PM and Ozone," Document ID No. EPA-HQ-OAR-2009-0491-4963 (the "FIP Revisions RT C”), acknowledges that the 2012 Base Case incorrectly assumes that Plant Scherer Un it Nos. 1 and 2, which are Subpart D New Source Performance Standard units, switch from the historic use of 100% sub- bitu minous coal to partial use of higher-sulfur and costlier bituminous coal. See id. at 85-86.

Second, as also explained below, the FIP Revi sions RTC acknowledges that the 2012 Base Case incorrectly assumes that Plant Wansley Unit No s. 1 and 2, which already use FGD systems, nearly triple their sulfur dioxi de lb/MMBtu emission rates comp ared 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 ope ration. It reflects a scenario in

23 The 2012 Base and Remedy Cases also erroneou sly 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 ar e different economic incen tives 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 CA IR. 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 CA IR 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 errone ous 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 EP A’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 histor ic operation. It reflects a scenario in which there is no CAIR. In this scenario, there are different economic incentives infl uencing 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 NO X SIP Call requirements (t he use of sub-bituminous
coal rather than bituminous coal results in lower NO X emission rates for the units). Both units have burned such coal since January 2004. CAIR play ed no role in this historic fuel switch. And, given that the coal switch to sub-bi tuminous coal was driven by Regional NO X 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 ec onomic (and regulatory) incentives point to the
units’ continued use of sub-bitu minous coal in any realistic ba se case for the final Transport
Rule. For EPA to have assumed otherwis e 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 re garding why Scherer and Wansle y coal switching and emissions
rates in 2012 base case mode ling may differ from actuals

. The Scherer units ma y have originally
switched to sub-bituminous coal in response to the Regional NO X SIP Call, but in the absence of CAIR or the Transport Rule, EPA’s modeli ng projects that fuel choice would change. Any applicable SIP requirements outside of CAIR th at 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 IntegratedFIP Revisions – RTC
June 5, 2012 Page 37

Planning Model” (Docket No. EPA-HQ-OAR- 2009-0491-0309) which states, “Unit-level SO 2 regulations arising out of State Implementation Plan (SIP) require ments, 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 SO 2 3-18
emission rates.’ Since SO 2 emissions are dependent on the sulf ur content of the fuel used, the regulatory SO 2 emission rates are used in IPM to defi ne fuel capabilities .” (Ch. 3 pp. 17-18) Furthermore, the commenter’s criticisms of EP A’s base case emission projections (without the Transport Rule in place) have no relevance to the Agency’s quantifica tion of Georgia’s state budgets or unit-level allowance allo cations 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 De cember 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 operation s of Plant Wansley Units 1 and 2 in a way that would result in the non-operation of FGD (in vi olation 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 SO 2 emission rates (see WebReady_ParsedFile_TR_Bas e_Case_Final_2012 (Docket No. EPA-HQ-OAR-2009-0491-4420) . The difference in emi ssions rates are due to coal switching that the model implemente d in the base case, and as st ated 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 Intersta te Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963), the base case is not meant to reflect historic ope ration. It reflects a
scenario in which there is no CAIR.

COMMENT : EPA’s erroneous base case assumptions lik ely resulted in a significant reduction to Georgia’s final 2012 SO 2 emission budget and a correspondi ngly severe reduction in the
allocation of SO 2 emission allowances to MEAG units. For EPA to have ignored these errors inFIP Revisions – RTC
June 5, 2012 Page 38

the Direct Final Rule, while simultaneously ma king changes to other state budgets to correct similar errors, is arbitrary, capricious, an a buse of its discretion and contrary to law. see 77 Fed. Reg. at 10,343 (revising Georgia’s 2014 SO 2 and NO X emission budgets to correct pollution control equipment assumptions); at 10,344 (revising Ohio’s 2012 and 2014 NO X emission budgets to correct pollution control equipment assumptions); at 10,344 (revising Nebraska’s
2012 and 2014 SO 2 emission budgets to correct FGD pollu tion control technology assumptions); at 10,345 (revising South Carolina’s 2012 and 2014 SO 2 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 Ai r Act and Georgia air regulatory requirements; none of the amount invested was primarily driven by CAIR.

MEAG again requests that EP A revise Georgia’s 2012 SO 2 emission budget and the allocation of
such allowances to units owned or co-owned by MEAG - in order to restore Georgia’s 2012 SO 2 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 incl udes 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 resu lting from state laws in contro l 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 se veral states based on comments received in response to the October 14, 2011 CSAPR emissi on budget notice. EPA is not proposing any
additional corrections to th e Wisconsin emissions budgets.

However, based on the corrections EPA is proposi ng in this notice, we believe EPA must make
similar corrections to Wisconsin's CSAPR em ission budgets as presented in the followingFIP 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 Depa rtment's comments to the October notice, including suggested un it emission levels, are included fo r 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 omitte d from the IPM projected emission budgets. In our comments to the October 2011 notice, Ta ble 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 th at EPA add emissions for these generation units. We recommend using operational and emission le vels 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 modeli ng 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 Trans port 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 comment er provides no such list of omitt ed units for which they claim EPA has made such adjustments. EPA has adju sted certain state budgets to reflect immediateterm out-of-merit-order dispatch fr om units where such dispatched generation (at units that were represented in EPA’s modeling) was not previously accounted fo r in EPA’s analysis. These budget adjustments have all pertained to units in cluded in the model, not “omitted” units.

COMMENT : Non-Economic Dispatch Units — EPA determined the CSAPR emission budgets by allowing the integrated planni ng model (IPM) to dispatch el ectric generating units on an economic basis. EPA is now proposing to increas e 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 dist rict heating and cooling to cu stomers 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. Th e IPM model, however, predicts that the Valley plant will not operate at all by 2014 and beyond. Therefore, cons istent 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 su ggest that EPA apply the operational levels demonstrated by data reporte d 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 a nd Ozone; EPA-HQ-OAR-2009-0491-4963 where EPA
addressed the commenter’s comm ent 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 specifica lly requested in the October 2011 proposal (76 FR 63868). While the commenter sugge sts using historic operation levels as the basis for a revision, it is not clea r that this data represents non-economic generation or “must run” levels. For instance, the commenter s uggests using 2008-2010 heat input or projected 2012 heat input levels as a surroga te 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 ow n 2011 reported data demonstrates that the plant can and does operate at levels below these cl aimed “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 cons istent with "reductions that occur due to state rules, consent decrees, and other planned cha nges in generation patterns that occur after 2012, but during or prior to 2014". EPA is specifica lly 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 installe d for that purpose should not be re flected 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 Geor gia's emission budget. This approach acknowledges that installation of equipment is scheduled in or der 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 inst allation 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 installe d at several Wisconsin power plants in order to meet future regulat ory requirements. However, EPA is counting the anticipated emission reductions from this co ntrol equipment towards the 2012 and 2014 CSAPR emission budgets, earlier than th e installation and compliance sc hedules. We believe, based on the Georgia proposal, that EPA should correct the following cas es. These corrections were initially identified in Table 2 of our comm ents to the October emission budget notice.

1) Currently, the 2012 Wisconsin CSAPR emi ssion 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 opera ting by May 1, 2013 in order to meet the Wisconsin NO„ reasonably available control te chnology (RACT) rule compliance date. This schedule is very similar to the schedule Allian t Energy stated in their comments to the October 2011 CSAPR emission budget notice. Clearly emi ssion reductions should not be counted towards the 2012 CSAPR emission budget.

2) The 2012 Wisconsin CSAPR emission budget count s emission reductions from both selective catalytic reduction (SCR) and SO 2 wet scrubber systems being c onstructed at the Oak Creek 7 and 8 generation units. This equipment is still un der 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 SO 2 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. Init ially, we commented that emission reductions could be counted towards CSAPR emission budge ts 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 be fore counting on reliable emission reductions. We fully support this assertion for a shakedow n period based on experience with other recent Wisconsin power plant scrubber installations. Allia nt 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 circum stances 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 th e 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 Tr ansport of Fine PM and Ozone; EPA-HQ-OAR-2009- 0491-4963, p. 36). EPA also responds to commen ts regarding budget adjustments based on control installation timing in section IV.4 of the Pream ble for this rulemaking.

COMMENT : We appreciate EPA's continued effort to evaluate and implement corrections to the CSAPR emission budgets. Beyond these corr ections 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 Tran sport 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 an d R Gallagher units 2 and 4 and Gibson unit 5 in Indiana. In the Agency’s Direct Final Rule EP A made adjustments to the South Carolina and
Indiana 2012 and 2014 SO 2 budgets that accurately reflect the corrections at W S Lee and R Gallagher that Duke Energy identified. Duke Energy ther efore agrees with the SO 2 budget adjustments EPA has made for South Carolina and Indiana with respect to these two facilities.

In its Direct Final Rule, EP A also made an adjustment to the Indiana 2012 and 2014 SO 2 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 SO 2 emissions for Gibson unit 5 to re flect this amount of flue gas bypassing the scrubber by increa sing the Indiana 2012 and 2014 SO 2 budgets by the difference
between EPA’s calculated revised SO 2 emissions of 6,801 tons and 4,928 tons of SO 2 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 apprecia tes EPA recognizing this fact and making an adjustment for it. The problem is, however, that EPA continues to use a 95% SO 2 removal rate for the Gibson unit 5 scrubber, which as Duke Energy explai ned 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%; th e 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 arbitrar ily and incorrectly revise d 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% SO 2 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 ad d 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 SO 2 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 sw itched Gibson 5 to a 1.4 lb sulfur coal that along with the 85% scrubber effici ency produced a 0.21 lbs/mmBtu SO 2 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 comple ted by 2012. In the final Transport Rule EPA appropriately increased the sulfur content of th e 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 c ontent coal and higher efficiency produce the same 0.21 lbs/mmBtu SO 2 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 ach ieving 95% removal effici ency, because of its initial design. The scrubber is made up of 4 iden tical 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 reactio n tank through large rubber hoses. The slurry in the reaction tank is agitat ed to keep the solids suspended. Pr ior 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 pushe d the flue gas toward the bottom of the duct resulting in high gas flow at th e bottom of the duct and ineffectiv e 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 elimin ators. The plugged mist eliminators required frequent absorber outages for cleaning. The typical SO 2 removal achieved by the original
scrubber was 80%.

In 2008 the absorbers were upgraded to increase SO 2 removal and improve reliability at a cost of $40M. The slurry nozzles in the top of the absorb er 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 perpendicu lar to it. The slurry pump capaci ty was increased and the mist eliminator design and wash system were upgrade d. Oxidation air was adde d to the reaction tanks to reduce scale growth and DBA chemical feed system was added to maximize SO 2 removal.
Performance has increased so that an 85% remova l 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% SO 2 removal, and the scrubber still has reliability pr oblems, many of which ar e caused by its initial design. The absorbers are too short. There is no t enough distance between th e slurry nozzles and the mist eliminators, so the mist eliminators c ontinue to plug. Thus a dditional slurry headers
can’t be added to increase SO 2 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 SO 2 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 alternativ e that would achieve a 95% rem oval rate would be to totally replace the scrubber which obviously cannot be achieved by 2012 or 2014.

Based on this information, assigning 95% removal e fficiency to the Gibson unit 5 scrubber is clearly in error. Duke Energy requests that EP A both change the efficiency of the Gibson unit 5 scrubber back to 85%, maintain the same coal sulf ur content (4.2 lbs.) assi gned to the unit in the final Transport Rule, and make the appr opriate adjustments to the Indiana SO 2 budget, assurance level, and unit level allocations.

In EPA’s October 14, 2011 Revisions to Federa l Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter a nd Ozone proposed rule (76 Fed. Reg. 63860), EPA proposed to make revisions to the SO 2 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 theFIP 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 submitti ng them to EIA. The second was that Duke Energy made an error in its calc ulation of the annual scrubber efficiency for Gibson unit 5 for 2008. The efficiency Duke Energy initially re ported 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 nu mber, the 89.3% should have been 83.3%. Duke Energy immediately notified EIA of these reporting errors and what the correct nu mbers 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 scrubbe r efficiency of Gibson unit 5 from 95% back to 85% while maintaining the same coal sulfur cont ent assigned to the unit in the final Transport Rule, and make the appropriate adjustments to the Indiana SO 2 budget, assurance level, and unit
level allocations. In its Direct Final Rule, EPA seems to have m oved away from the use of EIA 923 data in favor
of EIA 860 data.6 Table C.3.b.: Calc ulation to Determine Indiana SO 2 Budget Adjustment – Assuming Revised SO 2 removal Rates at FGD from EPA’s TR Final Revisions TSD shows that
for Gibson unit 5 EPA used the 2008 SO 2 removal rate of 95% from EIA 860. Duke Energy cannot render an opinion as to the appropriatene ss 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, DE SIGN PARAMETERS), the data to be reported for the removal efficiency of SO 2 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 Gi bson unit 5 scrubber upgrade failed to come close to achieve the design removal efficiency, and it continues to signifi cantly underperform relati ve 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 SO 2 removal rates, not design spec ifications 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 de sign data that has clearly been shown not to be representative of the SO 2 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other thanFIP Revisions – RTC
June 5, 2012 Page 46

the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside the scope of and
not relevant to this final action.

EPA responded to this comment regarding the scr ubber efficiency at Gibson unit 5 in section V.3 of the Preamble for this rulemaking and expl ained 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 Na tural Resources (EPA-HQ-OAR-2009-0491-4980)]

COMMENT : U.S. EPA states that the revisions are th e result of adjustments to unit-specific operational information, including post-combus tion pollution control e quipment. While EPD does not have the details regarding the adjustme nts made to the unit-specific information for Georgia, it appears that U.S. EP A 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 pr eviously 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 Geor gia’s Petition show there are other significant errors in the Cross-State Transport Rule as it ap plies to Georgia, includi ng but not limited to:

(1) The projected SO 2 emissions from EGUs used by U.S. EPA in its modeling for CSAPR (406,279 tons) are one and one-half times higher th an EPD’s projected emissions (232,952 tons).

See Petition at 10-11.

(2) U.S. EPA took into account emission reductions achieved by the installa tion of controls in the future required by Georgia’s rule, “Multipo llutant 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 Im plementation 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 Federa l 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 Geor gia 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” emissi ons 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, EP A 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 describe d in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was na rrowly 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 su ch as these, which relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel proposal, are ou tside 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 Pream ble 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 provide d response to those comments in sections 1.8 and 1.9 of the “Response to Comments on the Propos ed 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, an d in addition, in the preamble to the final Transport Rule on page 76 FR 4822 4 EPA explained that it did not include emission reductions unless those reductions were mandated by ex isting 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 rais ed, 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 emi ssion reductions for Georgia to eliminate its significant contribution and inte rference with maintenance.

COMMENT : Because of these significant adverse comments, EPD requests that U.S. EPA
withdraw the Direct Final Rule. See 77 Fe d. Reg. 10342. Should U.S. EPA not withdraw the Direct Final Rule, EPD requests th at the rule be stayed for th e reasons set forth herein and because the CSAPR has been stayed by the United States Court of Appeals for the District ofFIP Revisions – RTC
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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 w ithdrawn on May 16, 2012. (77 FR 28785)

8. Luminant [Letter: Luminant (EPA-HQ-OAR-2009-0491-4982)]

COMMENT : Insofar as they go, Luminant supports th e 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 “acc ount for operational constraints at six plants based on comments
received on the revisions rule.” 77 Fed. Re g. at 10,345, 10,347–78. Luminant agrees that these increases in Texas’s NOX budgets are a ppropriate and should be finalized.

Further, Luminant does not understand the Proposed Ru le or Direct Final Ru le to take or propose action (either accepting or rejecti ng) 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 a nd 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 a nd 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 N o. 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 rais ed in many of the petiti ons for administrative reconsideration of the final Transport Rule.”).

Even though these matters were dealt with in th e 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 r econsideration and its comments on the Revisions Rule for the agency’s consideration as part of that proceeding.

RESPONSE : EPA published a withdrawal of the Di rect Final Rulemaking in the Federal Register on May 16, 2012 (77 FR 28785) and is now taking final acti on on the parallel proposal that was published simultaneously with the direct final rule. EPA previously considered and responded to Luminant’s comments on the propose d revisions (see Response to Comments on the Proposed Revisions to FIPs to Reduce Inters tate 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 pr eviously submitted to the Agency.FIP Revisions – RTC
June 5, 2012 Page 49

Further, contrary to the commenter’s sugge stion, EPA has taken no final action to deny Luminant’s petition for reconsideration. Sec tion 307(d)(7)(B) of the Cl ean Air Act provides a procedural mechanism for parties to petition the Agency to reconsid er a rule. The section directs the Administrator to convene a proceeding fo r 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 th e 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 a ll 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 “unders tands 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 Revi sions Rule published at 77 Fed. Reg. 10,324 (Feb. 21, 2012) ”also addressed some of the issues and co ncerns raised in many of the petitions for
administrative reconsideration of the final Tran sport 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 demonstr ates that it was impracticable to raise the objection during the comment period or whether th e objection is of central relevance to the
outcome of the rule.

The Response to Comments document for the fina l revisions rule only addressed comments on the proposed final revisions rule. EPA did not take action, as commenter asse rts, 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 petiti ons for reconsideration focus on whether it was practicable for the commenter to raise a partic ular objection during the comment period for a rule, the additional opportunity for comment provi ded in the revisions rule may have rendered portions of particular Petitions for Reconsiderat ion moot. However, EPA has neither specifically identified any such Petitions nor discrete issues contained therei n as moot, nor acted to deny any aspect of the Petition for Reconsid eration submitted by the commenter.

9. Utility Air Regulatory Group (UARG) [Letter: Utility Air Regula tory 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 “R evisions to Federal Implementation Plans To Reduce Interstate Transpor t 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 intere sts 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 Ru le”), 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 rulema king proceedings on the Cross-State Rule 28 and supports EPA’s continuing effort to correct signifi cant 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 c onstrued 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 sk ew inputs to EPA’s mode ling for the Cross-State Rule and therefore affect upwind-state-to-dow nwind-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 addr essed 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 103 42/1, and make revisions to thirteen states’

27 EPA published a proposed rule in parallel with the Dir ect 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 Oz one (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 Inters tate 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, EP A-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 Reconsid eration”) (Attachment I to the UARG Error Corrections Rule comments and incorporated by refe rence herein); that petition re mains pending before EPA. On October 3, 2011, UARG filed a petition for review of th e 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

budgets 29 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-Stat e Rule, UARG and UARG members provided EPA with detailed comments regarding un it-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 a nd 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 anal ysis of unit-level errors in th e data EPA used for modeling the
Cross-State Rule. Because there was insufficient tim e to evaluate data for all units covered in EPA’s modeling, UARG asked JMI to focus its anal ysis on eight states as to which available information suggested EPA likely had made a numbe r of unit-level errors: Florida (ozone only), Georgia, Kansas, Louisiana (ozone only), Michig an, Ohio, Texas, and Wisconsin. In this limited analysis, JMI identified widespread errors in th e assumptions EPA made in its modeling for the final rule for the eight states JMI analyzed. UAR G 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 resu lts of that analysis. That report is referred
to hereinafter as the “JMI Analysis” and is incorpor ated by reference herein.

After EPA issued its proposed Error Corrections Rule, UARG -- r ecognizing that that proposed rule purported to address certain unit-specific erro rs in five of the eight states evaluated in the JMI Analysis -- retained JMI to analyze the propo sed 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 propos ed 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 anal ysis in a separate, additional re port, 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 inco rporated by reference herein) found that, although EPA’s proposed rule identified and appeared to corr ect 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 impor tant for purposes of the present comments, several
of the errors identified for a second time in th e JMI Addendum remain uncorrected by the Direct
Final Rule.

The following are examples of errors that JMI id entified in the eight states considered in its analysis that, as far as UARG has been able to determine, are not correct ed 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.FIP Revisions – RTC
June 5, 2012 Page 52

Florida: Errors remain concer ning (i) projections regarding th e overall level of seasonal NO X emissions in the state; and (ii) NO X 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) SO 2 emission rates used for Harl ee 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 switc h from burning higher- to lower-sulfur bituminous coal; and (iii) EPA’s retirement date for Mc Donough Units 1 and 2 and the replacement of those
units with two 850-MW combined cycle units in EPA’s final ru le base case modeling run for

2012. See JMI Analysis at 5-6.

Kansas: Errors remain with regard to EPA’s assumptions about SO 2 emission rates at several Kansas units, including Quindaro Unit 2, N earman 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 con cerning (i) the operation of (and NO X 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 M odel’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 timi ng of flue gas desulfurization (“FGD”) system installations at Monroe Units 1 and 2; (ii) SO 2 and NO X emission rates at Trenton Channel Units
16-19 and 9A and Eckert Stat ion Unit 2; and (iii) SO 2 emission rates at River Rouge Units 2 and 3, St. Clair Units 1-4 an d 6-7, and Erickson Unit 1. See JMI Analysis at 8-9; JMI Addendum at 3.

Ohio: Errors remain concerning (i) EPA’s assump tion that Conesville Un it 3 will operate as a coal-fired unit after 2012; (ii) SO 2 emission rates at Conesville Un its 5 and 6; (iii) EPA’s failure to recognize that all boilers at the Richard Go rsuch 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

SO 2 emission rates for these units; and (v) SO 2 emission rates for Sammis Units 1-7. See JMI Analysis at 9-11.

Texas: Errors remain concerning (i) the operatio n 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, in cluding 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 SO 2 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 ope rational date of dry FGD systems at Columbia Units 1 and 2; (ii) retrofit dates for wet FGD sy stems and selective catalytic reduction (“SCR”) systems at Oak Creek Units 5 and 6; (iii) inst allation and operation of SCR systems at Valley Units 1 and 2; (iv) coal blends bein g burned at Alma Units 4 and 5; (v) NO X rates achievable forFIP Revisions – RTC
June 5, 2012 Page 53

Pulliam Units 5-8; (vi) SO 2 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 expl ained in its comments on the proposed Error Corrections Rule that the accurate SO 2 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 Plan s To Reduce Interstate Transport of Fine
Particulate Matter and Oz one 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 Fina l Rule adjusted Indiana’s 2012 and 2014 SO 2 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 fa iled 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 Fi nal 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 erro rs in the rule that were id entified by UARG and others in previous rulemaking comments and petitions for r econsideration submitted to EPA. If and when the stay of the Cross-State Rule is lifted, EPA s hould 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, EP A 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 adju stments described in the preamble to the direct final rule (77 FR 10342) were merited. See 77 FR 10350. The propos al was narrowly focused on the adjustments
included in the direct final rule and did not reopen any other issu es 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 parall el 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).FIP Revisions – RTC
June 5, 2012 Page 54

The February 21, 2012 proposal, on its face, was ve ry limited in scope and only provided an opportunity for comment on the spec ific adjustments proposed therein. It did not reopen for comment any other issues that had been resolved in the Final Transpor t rule published on August 8, 2011, or the final revisions rule published on Fe bruary 21, 2012. It is im portant 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 th e February 21, 2012 direct final rule and the February 21, 2012 parallel proposal. On Oct ober 6, 2011, EPA published a proposal which both proposed specific adjustments to the Transpor t Rule and solicited additional comments on narrowly defined closely related issues. In response to the Octobe r 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 fi nal revisions rule made certain specific adjustments to the Trans port Rule. In particular, it fina lized adjustments that had been specifically proposed in the Oc tober 2011 proposal. In the res ponse 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 othe r 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 appr opriate were presented in the response to comments document for the February 21, 2012 final rule. Where EP A agreed with comments suggesting additional adjustments were warranted, EPA issued a direct fi nal rule to make the appropriate changes. At the same time, we issued a pa rallel proposal, which proposed to find that the changes in the direct final rule were warranted. The February 21, 2012 direct final ru le 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 co mment. 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. Commen ts 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 in cluded in the direct final rule and did not reopen any other issues for co mment. Accordingly, the comments presented by UARG are not relevant to this final action. UARG, in fact ar gues that the comments s hould 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 al so acknowledges that the comments presented were previously presented to EPA in comme nts on other rules and/or in petitions for reconsideration that are pe nding before the agency.

EPA not only provided numerous opportunities for th e submission of information, such as that included in the comments above, but, in fact, prev iously received this information and responded to it. EPA has previously responded to al l 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 ofFIP Revisions – RTC
June 5, 2012 Page 55

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 comm ent above, are addressed on pp. 97-98 of the same
document.

Further, EPA will respond to issues raised in th e 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 reconsid eration 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 centra l 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 sugge sting changes to the al location 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 propos al reopened the allo cation methodology for public comment. EPA finalized an allocation me thodology 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 histor ic 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 indivi dual unit-level allowance allocations to respect the impact of consent decrees on a specific s ubset 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 Tran sport 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 Tran sport 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 budget s 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 retire ment is consistent with the ove rarching 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 Intersta te Transport of Fine PM and Ozone” (EPA-HQOAR-2009-0491-4963) and the response in this docum ent to the comment from Duke Energy.FIP Revisions – RTC
June 5, 2012 Page 56

Regarding comments previously submitted, pleas e see pp. 97-98 of the first revisions rule response to comments document referred to above.

10. Earth Justice [Letter: Earth Justi ce (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 (“BA RT”) requirements under the Clean Air Act’s regional haze program; and (2) to adopt Federal Im plementation Plans (“FIPs”) for several states that would expressly authori ze reliance on CSAPR to avoid BA RT 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 an alysis 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 Cl ean Air Act visibility goals than BART.

...The emission budget increases have direct impli cations for the “better than BART” rule. Given the substantially reduced emission reductions un der the Direct Final Rule, any action on the “better than BART rule” would be premature and ar bitrary in the absence of further analysis of the Direct Final Rule’s impacts on visibility in a scenario where CSPA R is substituted for BART. Specifically, EPA has not followed its own regulations, which woul d require the agency to evaluate whether, in light of the Dire ct Final Rule, CSAPR is better than BART. See 40 C.F.R. § 51.308(e)(3). As the distribution of emissi ons under BART and CSPAR respectively are substantially different, EPA must conduct disp ersion 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 distribu tion of emissions is different under CSAPR and BART). This modeling will demonstrate greater reasonable progre ss 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 eval uating 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 pr ogram or other alternative measure will achieve greater reasonable progress than would have re sulted 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 CSAP R, RENDERING CSAPR AN IMPROPER
BART SUBSTITUTEFIP Revisions – RTC
June 5, 2012 Page 57

Putting aside the questio n of whether it was proper to increase the state emissions allocations for Arkansas, Georgia, Indiana, Kans as, Louisiana, Mississippi, Missouri, New York, Nebraska, Ohio, Oklahoma, South Carolina, a nd 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 th at 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 visi bility improvement across all Class I areas, or on a statewide basis, per 40 C.F.R. §51.308(e)(3)(ii). EPA cannot weaken CS APR 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 reas onable progress, if any, that CSPAR will now achieve in states affected by the Final Direct Rule.

In fact, these newly authorized emission in creases 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 SO 2 , annual NO X , and ozone-season

NO X 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-st ate 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 Chassa howitzka 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 emissi ons budget and relying on CSAPR in lieu of source-specific BART controls could exacerbate Ohio’s im pacts on the MANE-VU Class I
areas. Of the 167 stacks determined to be reason ably anticipated to cause or contribute to visibility impairments in the MANE-VU Cl ass I Areas, 28 are at 14 plants in Ohio.1 33 Yet, under the Direct Final Rule, Ohio’s 2012 and 2014 budgets for annual SO 2 will increase by 5,163 tons,
its annual NO X budgets will increase by 2,765 tons, and its ozone-season NO X 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 SO 2 annual trading program, 694 more tons under the 2012 and 2014 NO X annual trading program,
and 127 more tons under the 2012 and 2014 ozone-season NO X 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-R0 5-OAR-2011-0329-0004, at 6- 8, filed Feb. 24, 2012 in Docket No. EPA-R05-OAR2011-0239.FIP Revisions – RTC
June 5, 2012 Page 58

Reg. at 10345. The substantial SO 2 increases, combined with the NO X 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 Pres idential Range-Dry River Wilderness Area in New Hampshire, Lye Brook Wilderness Area in Ve rmont, Moosehorn National Wildlife Refuge and Roosevelt-Campobello International Park in Maine, and Shenandoah National Park in Virginia. See New York State Department of Envir onmental 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 SO 2 budgets. See 77 Fed. Reg. at 10345. Notably, 6,001 of the 8,013 annual tonnage
increase are allocated to sources that EPA a ssumed 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.2 34 At a minimum, EPA cannot increase CSAP R state budgets without revising its better
than BART calculations.

Newly authorized emissions increases also make clear that CSAPR as re vised cannot be better
than BART in states where EPA’s own data show ed 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 “b etter-than-BART” proposal, 35 and shown in Table 1 below, EPA’s own modeling analysis demonstrat es that a “Nationwide BART” 36 scenario provides greater visibility improvement than the agency’s al ternative “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 ar eas will further decline under CSAP R 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 Fina l Rule, EPA increased Arkansas’s 2012 and 2014

34 See Comments Addressing St ate-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 estim ated 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 estimat ed 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).FIP Revisions – RTC
June 5, 2012 Page 59

emission budget for ozone-season NO X 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 w ould be worse than BART. In addition, sources in Arkansas likely impact Class I areas in ne ighboring Missouri, incl uding Hercules-Glades Wilderness, another area where CSAPR prior to revisions would not be better than BART.

Similarly, EPA increased Nebraska’s annual SO 2 emission budget for 2012 and 2014 by 3,110 tons. See 77 Fed. Reg. at 10344-45. Sources in Nebras ka 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 ne arby North Dakota, Caney Creek Wilderness and Upper Buffalo Wilderness in Arkansas and Herc ules-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 NO X 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 Herc ules-Glades Wilderness, where CSAPR, prior to the emission budget increase, was shown to be wo rse than BART. Missouri sources also have a greater potential to cause a decline in visibili ty under CSAPR, as revised, at Caney Creek Wilderness and Upper Buffalo Wild erness in neighboring Arkansas.

Increases in Oklahoma’s ozone-season NO X emission budget for 2013 and 2014, and in Texas’s
annual and ozone-season NO X 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 NO X budget for 2012 and 2014 by 2,731 tons and its ozone-season NO X budget by 1,142 tons. See 77 Fed. Reg. at 10345. Similarly, Oklahoma is being allotted 859 more tons under the ozone-season NO X trading

program. See id.

Finally, EPA is increasing emissions under vari ous 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 befo re the emission increases were authorized in the Final Direct Rule. In particular, In diana’s emission budget for the annual SO 2 trading program will increase by 5,338 tons for 2012 and 2014. See 77 Fed. Reg. at 10343-44. Kansas’s annual

SO 2 emission budget would increase by 452 t ons for 2012 and 2014, whereas its annual NO X emissions budget would increase by 640 tons for 2012, and 5,794 tons for 2014. See id. At 10344. Both Louisiana and Mississippi were a llowed increases to their ozone season NO X budgets for 2012 and 2014. Under the Direct Final Rule, Louisiana can emit 89 tons more NO X per ozone season while Mississi ppi can emit 115 tons more. See id.FIP Revisions – RTC
June 5, 2012 Page 60

Given these increases in emissions , it is highly unlikely that CSAP R 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 undersigne d on the “better than BART” rule, EPA cannot discount the many instances in whic h BART yields greater progress toward visibility goals than CSAPR by averaging visibility impacts across the entire CSAP R 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 al ternative 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 a ny 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—eit her 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, EP A 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 adju stments described in the preamble to the direct final rule (77 FR 10342) were merited. See 77 FR 10350. The propos al was narrowly focused on the adjustments
included in the direct final rule and did not reopen any other issu es for comment. In sum, and as explained in greater detail on page 54 of this RT C, comments such as these, which relate to issues other than the adjustments proposed in the February 21, 2012 para llel proposal, are outside the scope of and not releva nt 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 Transpor t Rule proposed on February 21, 2012, but at the “better than BART rule” proposed in D ecember 2011. 76 Fed. Reg. 82,219 (Dec. 30, 2011).
This rule does not address a ny issues regarding the relations hip 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 fo llowing comments on the Environmental Protection Agency’s Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, Di rect 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.FIP Revisions – RTC
June 5, 2012 Page 61

While Georgia Power is pleased that EPA has corre cted some of the identified errors with its direct final rule, the Company urges th e 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. A nd by implementing the Cross-State Rule with known errors, EPA is acting arbitrarily, capricious ly 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 Cros s-State Rule, that stat e law required advanced pollution controls to be instal led and operational on several elect ric generating units in Georgia by January 1, 2014. EPA’s direct final rule correct s most of these plain errors and increases Georgia’s emission budgets accordingly. The Company fully supports these corrections.

EPA has, however, not corrected numerous add itional errors that have been brought to its
attention. Rather than re peat the detailed descri ptions of those errors, the Company incorporates Southern Company’s petition for reconsideration a nd administrative stay of the final Cross-State
Rule 42 and its public comments on the proposed Corrections Rule, 43 as if set forth fully here. These documents, including all attachments th ereto, 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 In terstate Transport of Fine PM and Ozone, 45 EPA

39 These comments should not be construed as “negative” with respect to the error corrections that EPA affirmatively made for Georgia in the di rect 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.g ov/crossstaterule/petitions.html.

40 U.S. Environmental Protection Agency, Revisions to Fede ral 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 InterstateTransport 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 ofFine 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 Recons ideration 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
June 5, 2012 Page 62

fails to adequately respond to these comments. 46 The Company urges EPA to fix the many remaining errors, through this rulemaking, a subsequent erro r 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 “ina dequately” 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 revision s 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 th e commenter does not in and of itself constitute in inadequacy or an “arbitrary and caprici ous” action. Finally, some of the commenter’s perceived “inadequate responses” may stem fr om a misunderstanding of the model’s output
and/or its use. As noted in the aforementione d 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 th e dynamic nature of power sector operations that involves fluctuations over time in dispatc h, emissions, and fuel choice among electricity generating units.

These comments are outside the scope of the Febr uary 21, 2012 proposal and not relevant to this final action. In this rule, EP A 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 desc ribed in the preamble to the direct final (77 FR 10342) were merited. See 77 FR 10350. It was narrowly focused on the adju stments included in th e 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, wh ich relate to issues other than the adjustments proposed in the February 21, 2012 pa rallel 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 cl osely 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 specif ic adjustments to CSAPR. This rule focused on

46 Compare Southern Company Petition for Reconsideration an d 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
June 5, 2012 Page 63

the adjustments that had been specifically proposed on Oct ober 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. S econd, and in response to comments received on the October 14, 2011proposal suggesting additional ad justments to CSAPR were appropriate, we
issued a direct final rule to ma ke some additional adjustments to the CSAPR. Third we issued a parallel proposal, proposing to fi nd that the adjustments made in the direct final were merited.
We indicated that if we received adverse commen t we would withdraw the direct final and take final action on the parallel pr oposal 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 adjust ments to CSAPR. We have considered and responded to all comments releva nt 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 a nd did not reopen any other issues for comment. Accordingly, EPA will not address any issues outs ide 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 re viewed and responded to all of Georgia Power’s previously submitted commen ts 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 fo r reconsideration of CS APR including the petition
for reconsideration that the commenter attached with these comments. These petitions are pending before the EPA. We will evaluate all su ch 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. Sec tion 307(d)(7)(B) provides a proce dural mechanism for parties to petition the Agency to reconsider a rule. The section directs the Admi nistrator to convene a proceeding for reconsideration only if the petitioner can demonstrate that it was impracticable to raise a particular object ion within the comment pe riod or that the grounds for the objection arose after the period for public comment (but within th e time specified for judicial review) and that the objection is of central releva nce to the outcome of the rule. EPA notes that commenter did
not file a Petition for Reconsideration of the Cr oss-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 addre sses comments on the February 21, 2012 proposal and EPA is not taking action on any Petiti on for Reconsideration at this time.

12. GenOn [Letter: GenOn(EP A-HQ-OAR-2009-0491-4986)]

COMMENT : GenOn recognizes that the Di rect Final Rule is another effort by EPA to address some of the problems created by CSAPR. As discu ssed below, however, it also creates new ones.FIP Revisions – RTC
June 5, 2012 Page 64

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 ru le was released), a final rule (which was substantially different from the pr oposal), a supplemental rule to add states to various parts of the program, a revisions rule to co rrect acknowledged mistakes in th e final rule, and now a direct final rule to make further changes.

Because the Clean Air Implementation Rule (CAI R) remained in place during this rulemaking and remains in place today, there is no environmen tal justification for this piecemeal approach or the rush to impose new requirements without a llowing for meaningful analysis. In order to develop a sound program for replacing CAIR (and the NO X 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 Ru le, 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 EP A 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 assu mptions. First, the commenter suggests that because the Clean Air Inte rstate Rule (CAIR) remains in place there is no environmental justification for timely impl ementation 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 envir onmental and public health benefits of the Transport Rule are significant and implementa tion of CAIR is insufficient to secure those benefits (see Napolitano D eclaration Nos. 82-84, 120-130).

Second, the comment suggests that the Transport Rule will replace not only the CAIR, but the

NO X 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 NO X 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 NO X SIP Call requirements and Acid Rain Progra m requirements. CAIR replaced the NO X Budget Trading Program created in the NO X SIP Call with the CAIR ozone -season trading program, but did not excuse any state or source from complying with the requirements in the NO X SIP Call.
The interaction between CAIR and both the Acid Rain Program and the NO X 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-me rit-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 loca l electricity demand with generation from outside the area.’’ 77 Fed. Reg. at 10343. In the Direct Final Rule, EPA adjusted a number of stateFIP Revisions – RTC
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budgets based on comments from companies and IS Os 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 c onstraints throughout the CSAPR re gion. 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 ge ts 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 wi ll be called upon once the constraint is resolved. Given the unit-by-unit modeling ap proach 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-me rit-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 fo r immediate-term future generation from a unit most likely to be driv en by non-economic reasons, which encompasses 2012 and 2014. Regarding offsetting of out-of-meri t-order adjustments, please see section 6.1.b of the same document. As stated in previ ous response to comments, EPA offset increased generation with generation at natu ral gas combined cycle units in the affected state, which are most like to be operating at the margin in electr icity supply from capacity available in state.

EPA has increased the budgets of the states in which out-of-mer it-order adjustments have been made, thus acknowledging the near-term non-economi c generation which is likely to take place in the state based on information supplied by comme nters. This approach does not affect the budgets in other states; in partic ular, it does not decrease the number of allowances available to
other states. The market now has sufficient al lowances to compensate for the emissions from that out-of-merit-order generation.

EPA believes this approach is re asonable as it maintains the ba lance 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 i gnores the fact that in this ru lemaking, 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 emi ssions expected from these adjusted unit-level operations and has added an equivalent number of allowances into the system accordingly, andFIP Revisions – RTC
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these additional allowances do not come “at the expense” of any other gene rator in the system. EPA believes that this approach integrates all of the technical information provided by
commenters into a reliable estim ate of state-level emissions re maining 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 Fina l Rule is the way in which it simply lowers the
burden on some states because t hose 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 “ina dvertently” include d pollution contro l installation requirements from a Georgia state rule whose deadlines at certain uni ts 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 budge ts by 40,334 tons of SO 2 , 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 analys is 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 companie s have pointed out that CSAPR’s deadlines simply do not allow enough time for companies to install post-combustion c ontrols on coal-fired power plants. In the Direct Final Rule, EPA essen tially 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 un its 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 Fina l Rule states that “EPA inadvertently included an emission rate requirement from a consent d ecree affecting a Kansas facility whose deadline actually extends beyond 2014. To corre ct the alignment of the Kans as 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 th e 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 c ould 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, CSAP R will not assume or require any emissionFIP Revisions – RTC
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Page 67

reductions from that unit. Again, this treats simila r units very differently based solely on whether they are subject to existin g requirements. This is arbitrary and unreasonable.

RESPONSE : This comment is based on several unf ounded assumptions. First, the commenter states that, “In the Direct Final Rule, EPA e ssentially acknowledges this fact... that CSAPR’s deadlines simply do not allow enough time for co mpanies 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 di rect final rule were made because, as the commenter suggests, EPA conclude d that there was insufficient time for companies to install post-combustion controls on coal fired power pl ants. To the contrary, EPA even conducted modeling of the final Transport Rule demonstrati ng that sources could cost-effectively meet the state budgets even if they did not add a singl e scrubber to the fleet (beyond those already underway at the time of EPA rulemaking) (See th e 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_variabili ty_limits_no2014_FGD (EPA-HQ-OAR-2009-0491- 4463) and TR_Remedy_Sensitivity_final_vari ability_limits_no2014_FGD State Emissions (EPA-HQ-OAR-2009-0491-4467). That modeling clea rly 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 clear ly 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 loca ted in other states (Pe nnsylvania and Ohio) as being “similarly situated” to the units in Georgi a that provided the basis for the revisions to Georgia’s state budgets. This effo rt fails as it is based on a misreading of the rationale for revising the Georgia state budgets. The comment er’s units in Pennsylvania and Ohio are not “similarly situated” to the units in Georgia. Firs t of all, the Transport Rule itself makes units in Pennsylvania and Ohio subject to different cr iteria from those in Georgia - namely, that Pennsylvania and Ohio are Group 1 states whereas Georgia is in Group 2 for SO 2 control. EPA’s decision to increase the state budget was in no wa y based on a judgment about the capability of sources in Georgia to add post-combustion cont rol equipment under any particular schedule. Instead, because Georgia is a Group 2 state, its b udget 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 th ere 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 st ated that, “It appears that Georgia’s deadlines were based on a realistic analys is of the time needed to install controls on multiple units while still maintaining reliabi lity,” 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 inFIP Revisions – RTC
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Georgia to install post-combustion SO 2 controls or to install such controls more rapidly than required under state law. This conclusion doe s 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 so urces in these states were subj ect. 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 Implemen tation Plans: Interstate Transport of Fine
Particulate Matter and Ozone a nd Correction of SIP Approvals ( 76 FR 48223). This necessarily
includes both state rules and other EPA rules outsi de of the Transport Rule that would exist whether or not states are subject to CAIR or Tr ansport 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 refl ect accurate assumptions about the regulatory environment requiring controls in the absence of the rule. Rega rding the Georgia adjustments, EPA adjusted budgets to correct for the assumpti on in the final Transport Rule analysis that particular Georgia Multi-Pollutant State Rule co ntrol deadlines for FGD/S CR retrofits at Branch, Scherer, and Yates facilities would deliv er emission reductions in 2014, whereas those reductions are in fact not required to occur until December 31, 2014 or la ter (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 requirem ents 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 obliga tions to which they must respond outside of

CAIR or CSAPR.

The state budgets are then determined based on wh at controls eliminate significant contributions within the cost thresholds applicable to that st ate, based on IPM’s least cost modeling. The cost curves factor in the time requi red for controls to come online (see Final Rule 76 FR 48249). The revisions for Georgia and Kansas were not ba sed on any finding that th e adjusted units could not in fact feasibly achieve the originally modeled reductions in that timeframe; instead, revisions made for Georgia and Kansas reflect th at 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 signi ficant 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 assume s controls that would no t be justified by Group 1
cost thresholds.

It should also be noted that Ge orgia 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 elimina ting their significant c ontribution. For sulfur dioxide, different states faced different cost thresholds based on wh ether the significant
contribution to nonattainment or interference with maintenance in 2014 was eliminated atFIP Revisions – RTC
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$2300/ton (Group 1) or $500/ton (Group 2). The co mmenter’s allegation th at “where a unit is covered by an existing requirements that does no t 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, give n 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 H eat Input Assumptions

We can find nothing in the record to indicate that, when the vari ous state budgets were adjusted in the Direct Final Rule, there were also commensu rate 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, EP A 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 adju stments described in the preamble to the direct final rule (77 FR 10342) were merited. See 77 FR 10350. The propos al was narrowly focused on the adjustments
included in the direct final rule and did not reopen any other issu es (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 ar e based, at least in part, on projected heat input a nd that therefore changes in pr ojected heat input assumptions would directly affect the distribut ion 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 sel ects the three highest historic heat input values fo r 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 aver age 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 multipli ed by the state budget to determine the unit’s initial allocation, which is then adjusted, if needed, based upon hi storic 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 thei r impacts on air quality or the power sector. CSAPR is now very different from the orig inal 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 th is 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 rule making 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.