### COMMENTS OF THE UTILIT Y AIR REGULATORY GROUP
on the NOTICE OF DATA AVAILABILITY SUPPORTING THE PROPOSED FEDERAL IMPLEMENTATION PLANS TO REDUCE INTERSTATE TRANS PORT OF FINE PARTICULATE MATTER AND OZONE

75 Fed. Reg. 53613 (Sept. 1, 2010); Docket ID No . EPA-HQ-OAR-2009-0491

HUNTON & WILLIAMS LLP Andrea Bear Field Norman W. Fichthorn James D. Elliott E. Carter Chandler Clements 1900 K Street, N.W. Washington, D.C. 20006 (202) 955-1500 Counsel for the Utility Air Regulatory Group

October 15, 2010i TABLE OF CONTENTS

I. Introduction................................................................................................................ ..........1 II. The Comment Period on the NODA Is Inadequate To Allow for Adequate Public Review of the Extensive Material Associated with It. .............................................4 III. Despite the Quantity of New Informa tion Added to the Docket Pursuant to the NODA, EPA Has Failed To Provide Data Necessary To Allow Meaningful Comment on That Information.........................................................................5 IV. EPA’s Decision To Base 2014 SO2 A llowance Allocations for Units in Group 1 States on the Same State-Leve l Emission Caps Used in the PTR - - Even Though Revised Data and an Updated Modeling Tool Were Available -- Is Arbitrary and Unjustified...........................................................................10 V. Several of the Revisions to NEED S and IPM that Are Reflected in the NODA Are Inappropriate or Inadequately Explained. ......................................................13 A. EPA’s Upward Adjustment of Its Assumption Regarding FGD Maximum Removal Efficiency Is Unjustified and Inaccurate. .............................13 B. Units with Generating Capacity Less than 100 MW Cannot Properly Be Assumed To Be Candidates for Installation of FGD or SCR........................................................................................................................15 C. EPA May Well Be Understating SCR Capital Costs.............................................16 D. EPA’s Revised NEEDS Database and IPM Platform Still Contain Numerous Errors and Have Introduced Additional Inaccurate Assumptions...........................................................................................................17 VI. In Making the Changes Represen ted in the NODA, EPA Continues To Ignore the Effects of CAIR and Local Controls. ...............................................................21 A. EPA Should Have Considered the Effects of CAIR..............................................22 B. EPA Should Have Considered the Effects of Local Controls................................23 VII. The Availability of NEEDS v.4.10 and IPM v.4.10 and the Central Role These Items Play in the Structur e of EPA’s PTR Warrant a New or Supplemental Proposed Rule Based on the Results of the New Data and Modeling....................................................................................................................... .....241 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 75 Fed. Reg. 53613 (Sept. 1, 2010); Do cket ID No. EPA-HQ-OAR-2009-0491 October 15, 2010

______________________________________________________________________ I. Introduction On September 1, 2010, the U.S. Environmental Protection Agency (“EPA” or the “Agency”) published its Notice of Data Availa bility Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Partic ulate Matter and Ozone (“NODA”). 75 Fed. Reg. 53613 (Sept. 1, 2010). The NODA supplements EPA’ s Proposed Air Pollution Transport Rule (“Proposed Transport Rule” or “PTR”), publis hed in the Federal Register on August 2, 2010, which was the subject of a 60-day public co mment period that ended on October 1, 2010. 75 Fed. Reg. 45210 (Aug. 2, 2010). The Proposed Transport Rule is intended to replace the Clean Air Interstate Rule (“CAIR”), which EPA promul gated in 2005 and the U.S. Court of Appeals for the D.C. Circuit held to be “fundamentally flawed,” initially vacated and remanded to the Agency in 2008, and then allowed to remain in place pending completion of EPA’s remand rulemaking. See North Carolina v. EPA , 531 F.3d 896, 929 (D.C. Cir. 2008), modified on petitions for rehearing , 550 F.3d 1176 (D.C. Cir. 2008). Li ke CAIR, the Proposed Transport Rule primarily addresses emissions from elect ric generating units (“E GUs”) and is based on EPA’s interpretation and applica tion of section 110(a )(2)(D)(i)(I) of the Cl ean Air Act (“CAA” or “Act”), which requires, in relevant part, th at each state’s plan for attaining the national ambient air quality standards (“NAAQS”) “contain adequate provisions . . . prohibiting . . . any source or other type of emissions activity within the State from emitting any air pollutant in2 amounts which will . . . contri bute significantly to nonattainment in, or interfere with maintenance by, any other State w ith respect to any [NAAQS].” The Utility Air Regulatory Group (“UARG”) submits the following comments on the NODA. UARG is a voluntary, not-for-profit group of electric utilities, ot her electric generating companies, and national trade associations. UAR G’s purpose is to participate on behalf of its members collectively in EPA rulemakings under th e CAA and other proceedi ngs that affect the interests of electric generators and in related litigation. Becau se the Proposed Transport Rule specifically -- and exclusively -- targets nitr ogen oxide (“NOx”) and sulfur dioxide (“SO 2 ”) emissions from EGUs for regulation, UARG and its members have a compelling interest in the present proceeding. These comments supplement comments that UARG submitted on the PTR on October 1, 2010, Docket ID No. EPA-HQ-OAR-2009-0491-2756.1 (“UARG’s PTR Comments”), which are incorpor ated herein by reference. The NODA announces EPA’s placement in the docket of this rulemaking several new documents and computer runs that bear direct ly on the PTR. For example, the NODA announces the placement in the docket of information on a new version of the Integrated Planning Model (“IPM v4.10”) that EPA is now using in the ru lemaking on the Transport Rule; modeling results from the use of that new version; new emissi on inventory information; and new information on key cost and other assumptions to be used in EPA’s rulemaking analyses. The new information adds hundreds of pages of documentation to the docket for this rulemaking. The NODA provides a 45-day comment period, until Octobe r 15, 2010, on the new information but states, without explanation, that EPA will not extend the comment period on the Proposed Transport Rule beyond the October 1, 2010 comment deadline.3 UARG reiterates its objection, made in UAR G’s comments on the PTR, that Agency decisions have made participati on in this rulemaking unreasonably and unnecessarily difficult. The information released pursuant to the NODA am ounts to a substantially revised set of new data that provides at least a potential basis for changing virtually every aspect of the PTR. As UARG explained in its co mments on the PTR, the comment pe riod on that lengthy and complex proposed rule was itself inadequate, and EPA’s d ecision to maintain two separate but largely overlapping periods for public comments -- one on the PTR and the information posted in the docket contemporaneously with it, and another, ending only two weeks after the PTR comment deadline, on the information released pursuan t to the NODA -- has made it extraordinarily challenging to provide comprehensive comm ents on both the PTR and the NODA. On September 10, 2010, EPA denied UARG’s August 19, 2010 request for an extension of the comment period on the PTR, and on October 5, 2010, the Agency denied UARG’s September 10, 2010 request for a comment deadline extensio n for the NODA as well as for the PTR itself. 1 In light of the significant differences between th e data on which EPA based (or says it based) the PTR and the data EPA released later pursuan t to the NODA, EPA should withdraw the PTR, revise the PTR using the NODA data or what ever other data EPA may now deem most appropriate -- while addressing as well the ma ny other deficiencies discussed in UARG’s comments on the PTR and the present comments -- and publish a complete, properly supported proposal for public comment with an adequate comment period.

1 UARG incorporates its August 19, 2010 a nd September 10, 2010 letters herein by reference.4 II. The Comment Period on the NODA Is Inadequate To Allow for Adequate Public Review of the Extensive Mate rial Associated with It. As discussed above, EPA published the NODA midway through the inadequate public comment period on the PTR and denied UARG’s reque sts for extensions of the comment periods on the PTR and the NODA. The NODA represents th e addition of an extensive amount of new material to the docket for this rulemaking. Fo r example, the new “Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model” (“Base Case v.4.10 Documentation”) alone is 487 pages long and includes references to several new or revised databases. See EPA, “Documentation for EPA Base Case v.4.10 Using th e Integrated Planning Model” (Aug. 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0309, available at http://www.epa.gov/airmarkets/progsregs/epa-i pm/BaseCasev410.html. Despite this large quantity of new information, the NODA provides onl y an additional 14 days for public comment beyond the comment deadline that UARG and othe r members of the public were required to meet for the PTR. This does not allow enough time for a comprehensive review of the new material provided, much less enough time to analy ze the material, determine its implications for the underlying rule, and develop and submit complete comments. The substantial impact of the NODA on the Pr oposed Transport Rule was apparent in recent comments by EPA representatives. During an EPA webinar held on September 22, 2010, in response to a question regard ing which aspects of the PTR w ould be affected by the NODA, a representative of EPA’s Clean Ai r Markets Division indicated that the information contained in the NODA would affect, among other things, EPA’ s “significant contribution” analysis, the creation and evaluation of the “cost curves” in EPA’s multi-factor analysis for determining emission reduction obligations under the PTR, and the cost-effectiveness “breakpoints” for emission controls that EPA will select based on th e cost curves and the multi-factor analysis.5 This EPA representative acknowledged that the NODA may result in changes in EPA’s determinations of which states are regulated under the Transport Rule, which states will be classified as group 1 rather than as gr oup 2 states with respect to additional SO 2 emission control obligations in the second phase of the program , the emission budgets to which regulated states will be subject, and unit-level allowance allocatio ns. These matters are far from tangential to EPA’s development of the Transport Rule. To th e contrary, they go to the very heart of the rulemaking. Yet, EPA provided only 14 days for public comment on the NODA beyond the comment period on the PTR. Equally important, as discussed below, EPA has unreasonably withheld information necessary to allow UARG, memb ers of UARG, other members of the public, and states to develop and provide meaningful and comp rehensive comments on the NODA and on the Proposed Transport Rule itself. The following sections of these comments address new and continuing inadequacies and omissions in the reco rd that UARG urges EPA to correct before the Agency continues with this rulemaking.
III. Despite the Quantity of New Information Added to the Docket Pursuant to the NODA, EPA Has Failed To Provide Data N ecessary To Allow Meaningful Comment on That Information. The problems associated with the unreasona bly abbreviated period EPA has provided for comment on the voluminous and complex info rmation issued pursuant to the NODA are exacerbated by EPA’s failure to provide much of the information necessary to evaluate and meaningfully comment on the NODA. The docke t omits much of the information that is necessary to properly evaluate th e nature and extent of the cha nges that are likely to the PTR based on the addition to the docket of the data listed in the NODA. In support of the PTR, EPA provided in the docket the results of 48 IPM runs. These runs provided the public at least some basis fo r evaluating and commenting on the various steps6 in EPA’s process of developing unit-specific allowa nce allocations. In cont rast, in support of the NODA, EPA provided the results of only eight IPM r uns. Of these eight runs, four relate to an entirely new alternative propos al based on the Energy Informa tion Administration’s (“EIA”) Annual Energy Outlook 2010 natural gas resource assumptions -- leaving only four IPM runs that constitute a repeat of runs used to support the PTR. The paucity of IPM runs that EPA has provided with the NODA, using th e revised National Electric Energy Data System (“NEEDS”) inventory and IPM v.4.10 frustrates the public’s ability to comment knowledgeably on the effects on the PTR of the updated N EEDS database and IPM platform. See section VII infra

. Despite EPA’s limited use of the revised NEED S inventory and IPM model in the allowance allocation step of its analysis, 2 EPA still has not provided the IP M runs necessary for electric generating companies and others, including st ates, to understand and comment knowledgeably on the impact of the NODA on statewide emission budgets and unit-specific allocations. In addition to failing to provide many cr itical updated IPM runs using the NODA information, EPA has failed to provi de key summary tables that it did provide in conjunction with the PTR. The key summary tables provid ed in support of the PT R include the “Allocation Table - Technical Support Document for the Tr ansport Rule - State B udgets, Unit Allocations, and Unit Emission Rates” (EPA-HQ-OAR-2009- 0491-0057.1) and the “Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit Emission Rates” (EPA-HQ-OAR-2009-0491-

2 UARG notes that, as it stat es in its comments on the PTR, EPA lacks authority under the CAA to impose unit-specific allowance allocati ons because the CAA “left to the states ‘the power to [initially] determine which sources would be burdened by regulation and to what extent .’” Michigan v. EPA , 213 F.3d 663, 686 (D.C. Cir. 2001) (quoting Union Elec. Co. v. EPA , 427 U.S. 246, 269 (1976)) (alterati on and emphases in original); see also Virginia v. EPA , 108 F.3d 1397, 1408 (D.C. Cir. 1997) (same). See UARG’s PTR Comments at 19-27 (discussing the ways in which the PTR upsets the statutorily established relationship between the federal government and the states with respect to development of plans to address interstate pollution control under the CAA).7 0074.1). In the PTR, these tables provided im portant guidance regard ing a unit’s allowance allocations under the PTR and provided electric generating companies at least some ability to evaluate the accuracy of EPA’s assumptions (or apparent assumptions) with respect to their individual units. For reasons that UARG explained in its comments on the PTR, EPA’s calculation of allowance allocations in the PTR wa s hardly a model of clarity. But EPA’s failure to provide with the NODA tables comparable to the above-described PT R tables leaves UARG members and other electric utilit ies and electric generating compan ies even further in the dark about what their unit allowan ce allocations will be, based on the outcome of EPA’s 2012 allowance allocation determinations using the updated NEEDS database and the updated IPM platform. Perhaps the single most important file EPA did not provide with the NODA was a file comparable to the PTR “Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit Emission Rates” (EPA-HQ-OAR-2009-0491-007 4.1) (an Excel spreadsheet entitled “BADetailedData.xls”). Without this file, electric generating companies cannot determine the impact of the NODA on their allo wance allocations. Although EPA did provide a new “IPM Run – TR Base Case v.4.10 – 2012 Parsed File” and a new “IPM Run-TR SB Limited Trading v.4.10 – 2014 Parsed File,” without critically important additional information, electric generating companies cannot calculate the SO 2 or NOx allowance allocations for their units for 2012 or (where applicable) 2014. EPA made “adjustments” to the IPM-proj ected unit-specific emissions for 2012, and provided these adjustments in the BADe tailedData.xls file for the PTR. See BADetailedData.xls at the “Adjustments” tab. In addition to providi ng these EPA adjustments to the IPM results, the BADetailedData.xls file provi ded the projected unit-speci fic operating parameters ( e.g. , heat8 rates, emission rates, and controls) in one lo cation, allowing electric generating companies to check EPA’s assumptions and better understand how EPA calculated each unit’s allocations. The BADetailedData.xls file also clarif ied whether a state’s annual 2012 NOx and SO 2 unit allocations and seasonal NOx unit allocations we re based on reported data or on the 2012 IPM projections. As described in EPA’s Technica l Support Document (“TS D”) on “State Budgets, Unit Allocations, and Unit Emissions Rates” (“State Budgets TSD”), 3 EPA based the 2012 budgets (annual SO 2 and NOx and seasonal NOx) on the lowe r of the recent actual emissions (essentially the 2009 reported emissions for exis ting units, aggregated by state) or the 2012 IPMprojected base case emissions at the state level. In the BADeta iledData.xls file, EPA indicated which emission amount was lower for each state a nd, thus, whether the 2009 “reported” emission amount or the 2012 “projected” emission amount served as the basis for the allowance allocations in that state. Without the BADeta iledData.xls file, it is no t possible to determine from the NODA the statewide budgets and the unit allowance allocations for 2012. 4 EPA should not proceed further with this ru lemaking until it has provided this critical information for public review and comment. In addition to not providing information need ed to evaluate the effects of the NODA on state budgets and unit allowance allocations, EPA st ates in the NODA that it intends to change the NOx emission rates used in its calculations again before it take s final action in this rulemaking:

3 EPA, “State Budgets, Unit Allocations, and Un it Emissions Rates” TSD (July 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0057, available at http://www.epa.gov/airquality/transpo rt/pdfs/TSD_StateBudgets_July152010.pdf.

4 Counsel for UARG e-mailed EPA’s Clean Air Markets Division to request information regarding whether there was any way to cal culate the 2012 statewide budgets from the information provided with the NODA, but EPA never responded to that request.9 EPA intends to update the NOx rates for fossil-fuel fired units in the final rule to reflect the more recent 2009 data. IPM v.4.10 and the previous version of IPM used for the Proposed Transport Rule analysis relied on 2007 unit level NOx rates. The updated NOx rates will more accurately portray the unit level control installa tions that have occurred at power plants during the past several years. 5 These changes in the NOx rates will result in addi tional changes to the final unit-level allowance allocations. Electric generating companies wi ll have no opportunity to review the new NOx rates assigned to their units and, thus, no opportunity to evalua te whether EPA made correct adjustments. Thus, EPA should also provide this information for public review and comment before proceeding to final action. For the reasons discussed above and in UARG’s PTR Comments, th e proposed NOx and
SO 2 allocations are likely to change due to a numb er of factors, including the many errors and illfounded assumptions contained in NEEDS and IP M and reflected in the NODA information. EPA will presumably make at least some of th e corrections requested in comments on the PTR and NODA. Fluctuation of allowa nce allocations prevents electr ic generating companies from planning for the future, which further exacerbates the problems associated with the extremely compressed schedule under EPA’s proposal for instal lation of controls -- a matter discussed in detail in UARG’s PTR comments. In a stakeholder meeting held shortly after EPA issued the PTR but before its publication in the Federal Register, EPA requested that electric generating companies provide detailed comments correcting any inaccurate data or ill-f ounded assumptions that EPA made with respect to specific units. Publication of the NODA, wh ich changes much of the information and many of the assumptions on which the PTR was based, has required electric generating companies to start over and to attempt, at considerable cost and w ith great difficulty, to re peat the same process --

5 75 Fed. Reg. at 53614/3 - 53615/1.10 to the extent it is even possi ble to do so based on the limited and incomplete information provided by EPA. Yet EPA has, without explana tion, failed to provide the information that would be necessary for companies to complete re views similar to those th at they undertook with respect to the PTR. Without the detailed information rega rding key IPM runs and the assumptions associated with statewide budgets and unit-specific alloca tions discussed above, electric generating companies lack the informa tion necessary to comment meaningfully on the impact of the NODA on the PTR. Thus, EPA has failed to provide an adequate opportunity for public review and comment on its proposal.
IV. EPA’s Decision To Base 2014 SO 2 Allowance Allocations for Units in Group 1 States on the Same State-Level Emission Caps Used in the PTR -- Even Though Revised Data and an Updated Modeling Tool Were Available -- Is Arbitrary and Unjustified. The primary purpose of the NODA was ostens ibly to announce “an updated version of the power sector modeling platform that EPA pr oposes to use to support the final rule . . . consist[ing] of updated unit level input data ( [NEEDS v4.10]) and a set of model run results with the updated modeli ng platform ([IPM] v4.10).” 6 The “set” of model run results that EPA elected to provide pursuant to the NODA was, in f act, seriously deficient, for reasons discussed in these comments. With respect to UARG’s comments in section VII below, which urge EPA to redo its entire analysis using the updated N EEDS database and revised IPM platform, EPA’s decision not to provide an upda ted “TR SO2 2000” IPM run, usi ng the revised database and modeling platform, to establish new proposed 2014 SO 2 state budgets provides one of the clearest example of the fl aws in EPA’s process. EPA stated in its State Budgets TSD that “[ g]roup 1 state budgets are based on reductions projected to be cost-effec tive at $2000 per ton of SO 2 . . . [based on] . . . the IPM run [ i.e. , TR

6 75 Fed. Reg. at 53613/1 (emphasis added).11 SO2 2000].” 7 EPA did not state directly in the NODA th at this critically im portant run would be omitted from the new data “set,” but it got that point across nonetheless: These policy runs [ i.e. , the limited set of runs that EPA provided] include the same State-level caps that EPA modeled in the Proposed Transport Rule. The caps have not been modified to account for any changes that the new modeling might suggest; th ey are merely provided for informational purposes to allow co mmenters to understand the impact that changes in the model platform have on the projected impacts of the caps

. 8 The “State-level caps” to which EPA apparently refers, i.e. , the 2014 SO 2 budgets for group 1 states, are the results of the TR SO2 2000 IPM run. The results of that run are input to the IPM Run – TR SB Limited Trading – Summary Report run and the unit-level parsed file for 2014. The practical effect of holding the 2014 SO 2 budgets for group 1 states constant and re-running the TR SB Limited Trading runs with the updated NEEDS database and IPM platform is that an individual unit’s percentage of the state budget changes but the state budget does not -- i.e. , a unit’s share of the “pie” changes but the size of the pie (artificiall y) remains the same. It would be far more relevant and more useful for el ectric generating companie s (and states) to have access not only to the informa tion provided with the NODA but also to a model run that demonstrates the effects of the updated database and modeling platform on the size of the state budgets. EPA must have known that “new mode ling” of state budgets based on the updated NEEDS and IPM platform would not me rely “suggest” revised emission caps 9 -- that new modeling in fact would plainly re sult in establishment of new caps at levels different from those proposed under the PTR. EPA provides no justifi cation for its decision not to provide a TR SO2 2000 IPM run using the updated NEEDS database a nd IPM platform. In short, EPA’s decision

7 State Budgets TSD at 10.

8 75 Fed. Reg. at 53614/3 (emphasis added).

9 Id.12 to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database and updated IPM platform while leaving state budgets the same -- based on the un revised data and IPM platform used in the PTR -- is illogical and arbitrary. Although EPA’s failure to provide the updated 2014 SO 2 budgets for group 1 states based on IPM v.4.10 undermines the public’s ability to understand the impact of the updated NEEDS database and IPM platform on the state-level caps for 2014, even a cursory comparison of the limited set of new IPM runs provided with the NODA demonstrates that the impact of the updated NEEDS database and updated IPM platform must be significant. Among the few IPM runs based on the updated NEEDS database and updated IPM platform that EPA did provide in the NODA are the TR SB Limited Trading Summary reports for 2012, 2015, 2020, and 2030. The following comparisons of these reports w ith reports based on the corresponding IPM run using the earlier versions of NEEDS and IPM illu strate the dramatic im pacts of using the new information:

• The total projected demand for power in 2015 is reduced by 230 GWh -- from 4,333 GWh in the PTR to 4,103 GWh in the NODA.

• The PTR projected 23.7 GW of new genera tion capacity from coal and 2.3 GW of new generation capacity from wind by 2015. The NODA projects only 2 GW of new generation capacity from coal and 22 GW of new generation capacity from wind by 2015 -- almost the exact inverse of EPA’s projection for these two energy sources in the PTR.

• The PTR projected a total of 80.3 GW of flue gas desulfurization (“FGD”) unit retrofits by 2015, while the NODA projects a total of only 49 GW of FGD retrofits by 2015. 10 These very substantial changes in EPA’s projec tions of the demand for power, the projected mix of new generation capacity, and projected pollution control retrofits sugges t that it would be

10 Compare “IPM Run – TR SB Limited Trad ing – Summary Repor t” (EPA-HQ-OAR2009-0491-0088) with “IPM Run – TR SB Limited Trading v.4.10 – Summary Report” (EPAHQ-OAR-2009-0491-0305).13 reasonable to expect signif icant changes in the 2014 SO 2 budgets for group 1 states (as well as the 2012 SO 2 and NOx budgets) if those budgets are base d on the revised versions of NEEDS and IPM. EPA thus should promptly provide th e results of a re-run TR SO2 2000 using the new NEEDS and IPM versions.
V. Several of the Revisions to NEEDS and IPM that Are Reflected in the NODA Are Inappropriate or Inadequately Explained. A. EPA’s Upward Adjustment of Its Assumption Regarding FGD Maximum Removal Efficiency Is Unjustified and Inaccurate. EPA states in its IPM v.4.10 Document ation that it assumes a maximum SO 2 emission removal efficiency for wet FGDs of 98%, repres enting an increase of three percentage points over the maximum percentage removal assumpti on used in the version of IPM on which EPA relied in developing the PTR. Compare IPM v.4.10 Documentation at 5-2 with EPA, “Updates to EPA Base Case v.3.02 EISA Using the Integrat ed Planning Model” (“Base Case v.3.02 TSD”) at 8 n.3 (July 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0052, available at http://www.epa.gov/airquality/trans port/tech.html. EPA does not pr ovide an explanation or any justification for this upward revi sion in assumed wet FGD removal efficiency, other than to say that, in transferring data from the EIA’s Form 767 for use in IPM v.4.10, “changes were made.” Base Case v.4.10 Documentation at 5-2. EPA stat es further that, in modeling the effects of installing wet FGDs, EPA assumed that the new scrubbers would operate at maximum efficiency. Id. (“existing units that are selected to be retrofitted by the model with [wet] scrubbers are given the maximum removal efficienc[ y] of 98% . . . . Pote ntial (new) coal-fired units built by the model are also assumed with a [wet] scrubber achieving a removal efficiency of 98% . . . .”). In the absence of a more e xplicit explanation by EPA, commenters can only presume that this is an assumption of continuous control efficiency of 98%. It is unreasonable for EPA to assume that new FGDs will always operate at maximum efficiency, regardless of the14 percentage of SO 2 that is estimated to be removed at maximum efficiency. Equally important, the level at which EPA assumes wet FGDs will operate -- 98% -- is unrealistic. A recent study of the best-performing FGD equipment -- evaluating the removal performance of the ten lowest SO 2 emitting units nationwide -- concluded that “none of these ‘top performing’ wet FGD systems was able to achi eve a removal efficiency of 98% or greater in every month of the year.” See Cichanowicz, J.E., “Overview of Information on Projected Control Technology Costs and Performance as De veloped for EPA’s Integrated Planning Model (IPM),” at 4 (Oct. 15, 2010) (her einafter “Cichanowicz Report”) 11 (quoting Weilert, C.V., et al., “Emissions Control Performance Achieved in Pr actice by Electric Utility FGD Systems in the United States,” at 12, proceedings of the 2010 Power Plant Air Pollutant Control MEGA Symposium (Aug. 30-Sept. 2, 2010, Baltimore, Maryland )). In fact, the available data suggest that even top-performing wet FGD units are unable to achieve consistent, annual average reduction levels of more th an perhaps 95% to 96% SO 2 removal. Id. EPA’s assumption that the “new” scrubbers th at IPM projects will be installed in the coming years will operate continuously and consistently at 98% efficiency -- a level perhaps 2 to 3 percentage points above the efficiency level that they may be likely to actually achieve on an annual average -- will result in an insufficient nu mber of allowances being allocated to units projected to add new FGD. Thus, based on EPA’ s proposal, units projected to be retrofit with wet scrubbers will have insufficient allowances at the start of each control year and will be forced to purchase allowances to make up the difference. This effect of EPA’s unrealistic assumption re garding the removal efficiency of new wet FGDs is exacerbated by the fact that EPA propos es to reduce allowance allocations by 3% to

11 The Cichanowicz Report was prepared to suppor t these comments. It is attached and is incorporated herein by reference.15 create an allowance set-aside for new units befo re distributing allowances to existing units. See 75 Fed. Reg. at 45309/1. Given that EPA plans to set aside 3% of each state’s allowance budget for new units and distribute the remaining 97% among existing units, the Agency should be all the more careful to avoid making unrealisticall y aggressive assumpti ons regarding removal efficiency. 12 EPA should adjust its assumpti on regarding the control effici ency at which new scrubbers will operate to reflect a more realistic annual-average maximum-removal assumption of 95% to 96% and recalculate state budgets and un it-level allocations accordingly.
B. Units with Generating Capacity Less than 100 MW Cannot Properly Be Assumed To Be Candidates for Installation of FGD or SCR. EPA explains in its Base Case v.4.10 Documentation that IPM v.4.10 assumes that units with generating capacities between 25 MW and 100 MW are candidates for installation of FGD and selective catalyt ic reduction (“SCR”). 13 However, in the base case for the PTR, EPA assumed that “coal-fired EGUs under 100 MW capacity [did] not have the option of retrofitting
FGD or SCR .” Base Case v.3.02 TSD at 20 (emphasi s added). EPA fails to provide any plausible explanation for changing this assumption. In fact, EPA’s new assumption that units with capacities betw een 25 MW and 100 MW can be retrofit with FGD and SCR is unrealistic. In many cases, it is impossible to retrofit units

12 The same point applies to assumptions re garding other emission controls, including NOx controls.

13 Base Case v.4.10 Documentation at 5-13. For modeling purposes, IPM v.4.10 effectively assumes that the cost of adding emi ssion controls to units in this MW range is equivalent to the cost of adding controls to a 100 MW unit. This assumption is based on the notion that several small units are likely to be ducted to share a common control, and that single units that are not ducted are likely to have the option of installing hybrid multi-pollutant controls, which are currently under development. Id. at 5-13 to 5-14; see also Cichanowicz Report at 10- 11 (discussing treatment of smaller units in control-cost analysis).16 with capacity below 100 MW with FGD and SCR. And in cases where it is technically possible to do so, it would rarely, if ever, be cost-effective. EPA acknowledged in its Base Case v.3.02 TSD that “FGD and SCR retrofits to such small units are very costly in any case.” Id. The emission reduction (and air quality improvement) benefits to be gained from such a large expense are quite limited due to the low emission amounts from “such small units.” Thus, even in cases where below-100 MW units theoretically could be retrofit with FGD or SCR, it would not be an economic choice to do so, at le ast in the great majority of cases. EPA should recalculate its base case emission inventories to remove the assumption that small units, with capacities be tween 25 MW and 100 MW, can be retrofit with FGD and SCR. At a minimum, EPA should explain its reasoni ng for changing its assumption regarding small unit retrofits in the NODA. C. EPA May Well Be Understating SCR Capital Costs. UARG supports EPA’s decision to retain Sarg ent & Lundy (“S&L”) to estimate control technology costs for the Proposed Transport Rule based on S&L’s database of component costs and installation charges. Using a firm that specializes in de termining the average costs of installation, operation, and main tenance of electric power generation and emission control equipment is likely to produce data that is more accurate than if EPA had pursued certain other cost-estimation approaches. See Cichanowicz Report at 1. Although UARG believes that many of S&L’s cost estimates are reasonable and likely to be accurate, or close to accurate, see generally id. , S&L’s projected capital cost of adding SCR appears likely to be an underestimate. See id. at 7-9 (describing di fferences between S&L’s estimates and those provided as a result of a recent UARG survey and discussing possible reasons for those differences).17 This apparent underestimate of SCR costs can affect the calculati ons and assumptions on which EPA relies in the Proposed Transport Rule , including the creation and evaluation of cost curves in EPA’s multi-factor analysis for de termining emission reduction obligations under the PTR and the selection of “breakpoints” for em ission controls, based on the cost curves. Furthermore, the S&L estimates reflected in th e NODA differ from the c ontrol cost estimates that EPA used for its analyses in the PTR. EPA’ s use of these different cost estimates will affect EPA’s analyses, regardless of whether the new cost estimates are more or less accurate than the estimates used for the PTR. See also section VII infra . EPA should therefore revise its analyses using appropriate control cost estimates and allow for public comment on the results.
D. EPA’s Revised NEEDS Database and IP M Platform Still Contain Numerous Errors and Have Introduced Addi tional Inaccurate Assumptions. As discussed in section VIII of UARG’s comments on the PTR, NEEDS v.3.02 and IPM v.3.02 contained many inaccurate inputs, in the fo rm of errors in NEEDS, inaccurate IPM constraints, and inaccurate outputs. Despite the limited time provided for UARG members to check the accuracy of the “updated” N EEDS v.4.10 and IPM v.4.10, UARG and its members have discovered that it app ears that EPA has introduced addi tional errors and inaccurate assumptions in the updated versions, while le aving many earlier probl ems uncorrected. As illustrated by the discussion in section V.A supra , certain systemic adjustments to EPA’s assumptions regarding new FGD control efficiencies are inconsistent with real-world experience and would result in inadequate allowance allocations. Moreover , unit-specific examples of changed assumptions are provided below. In ad dition to the same cate gories of errors and assumptions catalogued in UARG’s comments on the PTR, new assumptions in IPM v.4.10 regarding fuel prices and the cost of control technologies appear to have resulted in a new18 category of errors -- errors related to, for exampl e, the retirement of co al-fired units and the controls that existing units are projected to install. 14 Examples of errors and incorrect assumptions in NEEDS v.4.10 include:

• NEEDS v.4.10 reports that Units 1-3 at th e Baldwin Energy Complex in Illinois are currently equipped with wet FGD systems. That is incorrect. As a result of a consent decree, Unit 1 is required to install a dry FGD system by the end of 2011, Unit 2 is required to install a dry FGD system by the e nd of 2012, and Unit 3 is required to install a dry FGD system by the end of 2013. NEEDS al so assumes a 98% removal efficiency for wet FGD, which, for reasons set forth above, could not be assumed to be achievable on an annual basis even if th ese units were to install wet rather than dry FGD.

• NEEDS v.4.10 reports that Units 1-3 at th e Baldwin Energy Complex in Illinois are currently equipped with cold-s ide electrostatic precipitato rs (“ESPs”) and baghouses. This is incorrect. Although these units are currently equi pped with ESPs, Unit 1, Unit 2, and Unit 3 are not required to construc t baghouses until the end of 2011, 2012 and 2013, respectively.

• NEEDS v.4.10 reports that Units 1 and 2 at th e Baldwin Energy Complex in Illinois have an uncontrolled NOx rate of 0.0723 lb/ mmBtu. Based on continuous emission monitoring system (“CEMS”) data previously reported to EPA, the uncontrolled rate of these units is 0.61 lb/mmBtu.

• NEEDS v.4.10 reports that Unit 9 at the Hava na Station in Illinoi s has an uncontrolled NOx rate of 0.0723 lb/mmBtu. Based on CEMS data previously reported to EPA, the uncontrolled rate of this unit is 0.61 lb/mmBtu.

• NEEDS v.4.10 reports that Unit 2 at the Ghent facility in Kentucky had an SCR installed as of 2009. That unit does not have an SCR, and installation of SC R is not planned at that unit.

• NEEDS v.4.10 reports that two units at th e Armstrong power station in Pennsylvania have installed selective noncatalytic reduc tion (“SNCR”). A Mobotech Rotamix system was installed in 2003 in an effort to redu ce NOx, but the equipment was ineffective and was removed.

• NEEDS v.4.10 reports FGD removal efficiency at the Mitchell power station in Pennsylvania as 99.9% and at the Pleasants pow er station in West Virginia as 97%. These removal efficiencies are incorrect. Ac tual removal efficiency at the Mitchell

14 For additional discussion of issues associated with retire ment of coal-fired generation and erroneous control assumpti ons for coal-fired generation, see Comments of the Midwest Ozone Group on the NODA.19 power station averages 97% and actual remova l efficiency at the Pleasants power station averages 95%. Examples of errors in IPM outputs and erroneous IPM inputs include:

• IPM v.4.10 reports in both the TR_SB_Limited_Tra ding parsed files that the primary fuel for Units 1 and 2 at the Danskammer power st ation in New York is natural gas. The primary fuel for both units is oil.

• IPM v.4.10 reports in both the TR_SB_Limited_Tra ding parsed files that the primary fuel for Units 1 and 2 at the Roseton power station in New York is natural gas. The primary fuel for both units is oil.

• IPM v.4.10 reports NOx controls for Unit 4 at the Scherer power station in Georgia consisting of low NOx burners and separated overfire air. This is inaccurate -- only overfire air is installed at that unit.

• IPM v.4.10 reports in the 2014 TR_SB_Limited_Tra ding parsed file th at the coal-fired Unit 3 at the Sibley power st ation in Missouri will retire early. SCR was installed in 2009, making it highly unlikely that th e unit will retire in or by 2014.

• IPM v.4.10 reports in the 2014 TR_SB_Limited_Tra ding parsed file th at the coal-fired Mount Tom power station in Massachusetts wi ll retire early. Dry FGD was installed in 2009, making it highly unlikely that that facility will retire in or by 2014.

• IPM v.4.10 reports in the 2014 TR_SB_Limited_Tra ding parsed file th at the coal-fired Unit 4 at the Indian River power station in Dela ware will retire early. Installation of dry FGD is planned for 2012, making it unlikely th at the unit will retire in or by 2014. The specific errors cited above are provided as examples of the types of mistakes found in the updated NEEDS and IPM mo deling -- they repres ent a mere sampling of the problems found by electric generating companies. In order to provide an adequate opportunity to comment on proposed unit-level allowance allocations, EPA should correct these errors and publish a revised allocation table for comment. In addition to the flawed IPM outputs for specific units, other outputs provided on a regional scale in the IPM Run – TR SB Lim ited Trading v.4.10 – Summary Report do not seem plausible and call into question the accuracy and validity of the modeling results. Two examples20 are (1) IPM’s forecast for additional wind ge neration by 2015 and (2) IPM’s projected SO 2 allowance price. As mentioned above, the IPM Run – TR SB Limited Trading – Summary Report projected 23.7 GW of new generation capacity from coal and 2.3 GW of new generation capacity from wind in 2015. The IPM Run – TR SB Limi ted Trading v.4.10 – Summary Report projects only 2 GW of new generation capacity from coal and 22 GW of new generation capacity from wind in 2015. The magnitude of the projecte d increase in predicted new wind generation between successive versions of th e model calls into question the valid ity of the model results. In any event, even if there is some “logical” just ification for IPM’s proj ection of 22 GW of new wind generation, there are certain pr acticalities that make that proj ection doubtful. As of January 1, 2010, the total installed wind generation capac ity in the United St ates stood at 35 GW. 15 IPM predicts that 21 of the 22 GW of projected new wind generation will be online by 2012. Thus, the additional wind generation that EPA projects would constitute a 60% increase in the United States capacity in approximately three years. 16 Considering that the av erage-sized wind farm in 2009 had generation capacity of 91 MW, 17 that would mean that approximately 231 averagesized wind farms would have to be permitted and built by 2012. According to the American Wind Energy Association, it takes approximately 18 months to two years to permit and build

15 U.S. Department of Energy, “2009 Wind T echnologies Market Report” at iii (Aug. 2010) (“2009 Wind Report”), available at http://www1.eere.energy.gov/windandhydro/.

16 IPM results provide no indication of wher e this additional wind generation will be located. Thus, there is no way to determine whethe r it will be located within the states regulated by the PTR.

17 2009 Wind Report at v.21 even relatively small (50 MW) wind farms. 18 The dramatic change in generation mix between successive versions of IPM and practical consider ations of actually permitting and building that many new wind farms in a very short period call for explanation and addi tional justification by EPA of this very substantia l change in its projections. Finally, the IPM Run – TR SB Limited Trading v.4.10 – Summary Report provides estimates of SO 2 allowance prices for group 1 and group 2 states at $313 and $184, respectively. 19 Although it is not possible to compare th ese prices to projections from the IPM Run – TR SB Limited Trading – Summary Report because allowance price projections were not provided in that report, a report by James Ma rchetti for the Midwest Ozone Group (“MOG”) and submitted with MOG’s comments on the NODA notes that the co st in 2015 of SO 2 allowances in a group 1 state under an intra-state-only tradi ng regime was estimated at approximately $1,900 per allowance. 20 At best, this analysis demonstr ates that the IPM projection of 2015 SO 2 allowance prices is considerably underestimated. At worst, this analysis suggest a flaw in IPM’s methodology.
VI. In Making the Changes Represented in the NODA, EPA Continues To Ignore the Effects of CAIR and Local Controls. EPA indicates that IPM v.4.10 takes into ac count all existing federal and state air emission regulations (except for CAIR), as we ll as new source review (“NSR”) and other settlements, that were in effect or we re final as of August 2010. Base Case v.4.10

18 See “Wind Energy Basics” from the American Wind Energy Association, available at http://www.awea.org/faq/wwt_basics.html.

19 See “IPM Run – TR SB Limited Tradi ng v.4.10 – Summary Report” (EPA-HQ-OAR2009-0491-0305).

20 See Marchetti, J., “Final Report: MOG Comments on the NODA,” at 9-10 (Oct. 15, 2010), submitted to the docket for this rulemaki ng as an attachment to MOG’s comments on the NODA.22 Documentation at 1-1. 21 By contrast, the previous version of IPM, used to model the PTR, took into account these same factors effective as of February 3, 2009. 75 Fed. Reg. at 45243/2. Despite this updating by about 18 mo nths with respect to EGU emission limitations, EPA in the NODA improperly continues to ignore the eff ects of CAIR and local emission controls, including controls affecting emissions from non-EGU point s ources and nonpoint stationary

sources. A. EPA Should Have Considered the Effects of CAIR. As UARG explained in its comments on the PT R, EPA should have included CAIR in its base case modeling because it remains binding la w until it is replaced by a valid rule. See UARG’s PTR Comments at 50-53. According to the terms of the D.C. Circuit’s December 2008 opinion on rehearing in North Carolina v. EPA , CAIR will remain binding law until a new rule is in place. Thus, it is appropriate for EPA to concl ude in this rulemaking that there will be no time when neither CAIR nor a CAIR repl acement rule will be in effect. See id. at 50-51. Additionally, EPA has not demonstrated that EGUs in the few states that were regulated under CAIR but may not be regulated und er the Transport Rule, as propose d, are likely to increase their emissions when CAIR expires, or that such in creases would be permitted under state law. In reality, these EGUs have already made reductions pursuant to CAIR and it is very unlikely that they will increase their emissions to pre-CAIR levels once CAIR expires. Based on these factors, as well as the downward trend that EPA has acknowledged in PM 2.5 and ozone

21 See also Base Case v.4.10 Documentation at Appendix 3-2 (“State Power Sector Regulations [I]ncluded in EPA Base Case v.4.10” ), Appendix 3-3 (“[NSR] Settlements in EPA Base Case v.4.10”), Appendix 3-4 (“State Settlem ents in EPA Base Case v.4.10”), Appendix 3-5 (“Citizen Settlements in EPA Base Case v.4.10”), Appendix 3-6 (“Renewable Portfolio Standards in EPA Base Case v. 4.10”).23 concentrations nationwide, 22 it is far more realistic to assume that CAIR applies than it is to assume that it does not. See UARG’s PTR Comments at 52-53.
B. EPA Should Have Considered the Effects of Local Controls. UARG also explained in its comments on th e PTR that EPA’s proposal improperly failed to account for local emission contro ls. Section 107(a) of the CAA st ates that “[e]ach State shall have the primary responsibility for assuring ai r quality within the entire geographic area comprising such State.” 42 U.S.C. § 7407(a). See UARG’s PTR Comments at 64-66. Thus, EPA’s proposal to promulgate and implement a rule that regulates sources of transported pollutants without considering th e effects of local controls, see 75 Fed. Reg. at 45226/3, is contrary to the Act. EPA attempted to explain its failure to account for local controls in the PTR by asserting that “nonattainment areas for the 1997 PM 2.5 and ozone standards were not announced until 2004 and 2005 respectively, and the corresponding [SIPs] were not due until 2007 and 2008, thereby preventing the inclusion of these local measures in the 2005 emissions inventory.” EPA, “Emissions Inventories” TSD (“Emissions TSD”) at 11 (June 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0050, available at http://www.epa.gov/airquality/trans port/tech.html. As UARG noted in its comments on the PTR, however, the unavailability of this information in 2005 does not explain EPA’s failure to account for it in its future base case projections. See UARG’s PTR Comments at 65 n.39. Again, despite the many updates reflected in the NODA, EPA fails to account for local controls. EPA must consider the effects of local controls on its modeling and on air quality and attainment and interference with maintenance of the NAAQS.

22 See EPA, “Our Nation’s Air Status a nd Trends Through 2008,” 1-2 (Feb. 2010), available at http://www.epa.gov/airtrends/2010/index.html.24 Moreover, even if one were to accept that EPA had insufficient time to account for local controls in the entire proposed control regi on before issuing the PTR, EPA could and should have at least considered the effects of local controls on the areas surr ounding the six monitors with perceived maintenance problems that led to EPA’s proposed designation of the group 1 states that are subject to additional SO 2 reduction requirements in 2014. See UARG’s PTR Comments at 61-64 (discussing EPA’ s classification of group 1 states based on six monitors with perceived maintenance problems). EPA certainly has the resources to consider the effects of local controls in the areas surrounding these six monitors. 23 Such consideration of local controls may have eliminated the need (as determined by EPA) for additional SO 2 reduction requirements in 2014, or at least may have reduced the number of group 1 states.
VII. The Availability of NEEDS v.4.10 and IPM v.4.10 and the Central Role These Items Play in the Structure of EPA’s PTR Warrant a New or Supplemental Proposed Rule Based on the Results of the New Data and Modeling. EPA’s PTR depends in substantial measure on the validity, reliabili ty, and accuracy of IPM. No other tool has as great an influence on key elements of the PTR. Indeed, the results of IPM runs have a direct or indirect effect on every major step in EPA’ s PTR methodology. In the NODA, EPA acknowledged as much by stating: Changes from the projections relied on in the proposed rule, from using an updated model, could impact the fina l rulemaking in a number of ways including, but not limited to: 1. Changing emission projections that were used to determine which downwind areas have air quality concerns ( i.e. , non-attainment or maintenance) absent this rulemaki ng and to determine which States contribute to those problems. 2. Changing cost and emission projections used in the multi-factor [ e.g. , cost curve] test to determine th e amount of emissions that represent significant contribution.

23 In fact, UARG notes that two of the six monitors are located in Allegheny County, Pennsylvania. Thus, EPA would have had to consid er local controls in only five local areas.25 75 Fed. Reg. at 53614/3. If anything, EPA unders tates the potential im pact of the updated database and platform. The NEEDS inventory a nd the output of IPM substantially influence the fundamental components of the PTR: the analyses of air quality; the linkage s of upwind states to downwind problem areas; the definition of si gnificant contribution to nonattainment and interference with maintenance; and the estab lishment of statewide budgets and unit-specific allocations. Despite the central role of IPM in each of these components, EPA elected to provide a very limited number of runs using the updated NEEDS database and revised IPM platform and then further qualified the import of the runs by stating that “they are merely provided for informational purposes to allow commenters to understand the impact that changes in the model platform have on the projected impacts of the caps.” 24 It is unclear why EPA tries to downplay the potential impact of the updated NEEDS data base and IPM platform when EPA clearly “proposes to use this version of the IPM m odel [IPM v.4.10] in the final Transport Rule.” 25 As discussed in section IV above , a cursory comparison of the NODA IPM runs with the PTR IPM runs demonstrates that changing the NEEDS emission inventory and using an updated IPM version result in significan tly different outcomes. UARG appreciates that enti rely redoing EPA’s analys is using the updated NEEDS database and IPM platform takes significant time and resources. EPA should, however, conduct its analysis using the most curr ent model and information at its disposal, and then should make all the results available to the public and allow an adequate time for public review and comment before taking any final acti on in this rulemaking.

24 75 Fed. Reg. 53614/3.

25 Id

.26 In all its complexity, EPA’s PTR methodol ogy can be broken down into approximately eight major steps. In each of these steps, IPM provides information critical to the accuracy and validity of EPA’s analysis. The purpose of reviewing each of these steps is to demonstrate EPA’s thoroughgoing reliance in this rule making on IPM and the importance of EPA undertaking a full analysis with the revised modeling tool and data, and allowing a full opportunity for public comment on the methodol ogy and results of that analysis. The following paragraphs describe the ei ght major steps in EPA’s methodology, as reflected in the PTR, and discuss wh y these steps depend on IPM results:
1. EPA created four emission inventory cas es to support air quality modeling

. EPA created four “complete” emission s cases to support its air quality modeling and analysis. The principal i nput to the Comprehensive Air Quality Model with Extensions (“CAMx”), wh ich EPA used for its air quality modeling, is the emission inventory for each source sector. EPA refers to its four inventory cases as the 2005 base case, the 2012 base case, the 2014 base case, and the 2014 control/policy case. 26 These emissions cases are complete in that they contain estimates of emissions for each of the main source sectors: EGUs, non-EGU point sources, nonpoint (area) stationary sources, onroad mobile sources, nonroad mobile sources, and fires. The EGU portion of the SO 2 emissions constitutes a majority of the total SO 2 emissions for 2005 ( e.g. , for the 2005 base case in the PTR, 10,019,774 tons of the total 13,380,267 tons of SO 2 emissions). 27 The EGU portion of the NOx emissions represents about a fifth of the overall NOx emissions for 2005 (3,223,184 tons of the total 15,943,047 tons of NOx emissions for the base case). 28 For the three future emissions cases (the 2012 base case, the 2014 base case, and the 2014 control/policy case), EPA relied on IPM to project the EGU portion of the complete emission inventory. 29 Thus, IPM is the source of the emission

26 Emissions TSD at 6.

27 75 Fed. Reg. at 45240 (Table IV.C-1).

28 Id . at 45240-41 (Table IV.C-2).

29 Emissions TSD at 11, 37.27 estimates for two of the most significant precursors to PM 2.5 and ozone formation in the CAMx atmospheric modeling. 30

2. The IPM-dependent CAMx modeling was used to project future downwind PM 2.5 and ozone nonattainment and maintenance problems . A critical first step in predicting future nonattainment and maintenance problem monitors for the annual PM 2.5 , 24-hour PM 2.5 , and 8-hour ozone NAAQS involved calculating the relative changes from the 2005 base case modeling results from CAMx to the 2012 base case model run results. 31 The CAMx atmospheric modeling runs depend in c onsiderable part on the IPM emission projections for 2005 and 2012 because t hose are among the most influential inputs to the modeling, and changes to the 2012 base case model run results due to changes in IPM will affect the resu lts of this step of the analysis. 3. EPA used IPM-dependent CAMx modeling to assess interstate contributions to nonattainment and maintenance . After EPA used CAMx to model future nonattainment and maintenance problems at downwind monitors, EPA used the photochemical source apportionment feature of CAMx to “quantify the impact of emissions in specific upwind st ates on air quality concentrations in projected downwind nonattainment and maintenance locations.” 32 As discussed in step 1, EGU emissions make up the large majority of SO 2 emissions and approximately one-fifth of NOx emissions. Consequently, one of the most influential emission source cat egories in shaping the results of the CAMx source apportionment modeling is the EGU source sector, whose estimated emissions depend on IPM projections. 4. After establishing state linkages to downwind nonattainment and maintenance sites, EPA’s first step to quantify significant contribution -- i.e. , creation of emission reduction cost curves -- de pends entirely on IPM modeling results

. EPA’s first step in “determining the quant ity of emissions that represents each state’s significant contribution is to id entify reductions available at different costs.” 33 EPA developed “cost curves” that are intended to show the available emission reductions from EGUs at va rious dollar-per-ton cost increments. EPA derived the amount of emission reductions available at each cost

30 For this and the subsequent steps describe d in this section of UARG’s comments on the NODA, UARG recognizes that it is conceivabl e that EPA has used this new, updated information in its analyses -- but, critically, if EPA has done so, it has not disclosed that fact in the NODA information and has not pr ovided the results to the public for review and comment.

31 75 Fed. Reg. at 45246/3 - 45247/3 (annual PM 2.5 methodology); id. at 45248/1 - 45249/3 (24-hour PM 2.5 methodology); id. at 45252/1-3 (8-hour ozone methodology).

32 Id . at 45253/1.

33 Id . at 45272/2.28 increment from IPM; the cost curves are a direct output of IPM. 34 The relevance and accuracy of the cost curves thus depend on IPM. 5. EPA used its air quality assessment t ool (“AQAT”) to estimate the air quality benefits of upwind emission reductions on downwind ambient concentrations of PM 2.5 and ozone . Instead of using CAMx as a primary tool to evaluate the downwind benefit of upwind emission reductions, EPA created its AQAT. Unlike CAMx, AQAT is not a dynamic air quality model but is essentially an Excel spreadsheet that generates esti mates of downwind ambient pollutant concentrations based on the amounts of em issions from an upwind state. “For each downwind area with a nonattainm ent and/or maintenance problem, it shows the total improvement in air qualit y for each cost level and associated pollutant reduction . . . .” 35 The amount of the pollu tant reduction that is available at each cost level is a dire ct output of the IPM model runs. In addition to the updates to the NEEDS emi ssion inventory that is input to IPM, one of the changes from IPM v.3.02 to IPM v.4.10 was a “major update of emission control technology assumptions [],” which in turn involved changes to the estimates of costs associated with NOx and SO 2 emission controls. 36 Consequently, in this step perhaps more than in any other, the updates reflected in the latest version of IPM w ould have produced different results. 6. EPA evaluated the results of the IPM- dependent AQAT to establish control cost thresholds, or “breakpoints.” EPA evaluated the air quality benefits predicted by AQAT at the various cost le vels on the cost curv es and identified “breakpoints” -- “places where there is a noticeable change on one of the cost curves, such as a point where a large reduction occurs because a certain type of emissions control becomes cost-effective.” 37 EPA selected a breakpoint of $2,000/ton for SO 2 and a breakpoint of $500/ton for NOx. 38 The cost curves and results of the AQAT would be different if EPA had used the latest version of IPM. When the assumed costs of c ontrol technologies ch ange, as they did pursuant to the NODA information, there is every reason to believe that the “breakpoints,” where large emission re ductions become available because a technology becomes cost-effectiv e, also would change. 7. EPA established SO 2 emission budgets for group 1 states based on an IPM run; IPM runs also influen ced 2012 state budgets for both SO 2 and NOx

. Using its cost-curve breakpoint for SO 2 , EPA set the group 1 statewide 2014

34 Id

. 35 Id . at 45273/3.

36 Base Case v.4.10 Documentation at 5-1.

37 75 Fed. Reg. at 45271/1-2.

38 Id . at 45281/2-3 (SO 2 ); id. at 45288/2 (NOx).29 SO 2 emission budgets based on the emissi on reductions projected to be costeffective at $2,000 per ton of SO 2 . The state budgets were a direct output from a single IPM run, referred to as “TR SO2 2000.” 39 The 2012 SO 2 and NOx budgets are also influenced by the NEEDS inventory and IPM because EPA calculated budgets based on the opera tion of existing controls, controls that EPA projects to be operational by 2012, and EPA-projected switches to lower-sulfur coal. 40 The calculation of these budgets is dependent on the accuracy of both the NEEDS emissions inventory and the IPM assumptions regarding when installation or use of va rious controls is economical and the level of emission reductions that can be achieved by those controls. 8. EPA established unit-specific NOx and SO 2 allowance allocations . For units in group 1 states, EPA establ ished 2014 unit-specific SO 2 allocations as “a proportional share of the state’ s budget based on projected SO 2 emissions from fossil-fired greater than 25 MW capacity units in the [2014] TR SB Limited Trading IPM run, as apportioned to the unit level in the 2014 parsed file” (minus 3% of the emissions that EPA allocated to establish the new unit set-asides). 41 EPA based the 2012 unit-specific allocations for annual SO 2 emissions, annual NOx emissions, and seasonal NOx emission on the lower of either the most recent actual reported cumulative emissions from all affected EGUs within a state or the cumulativ e 2012 IPM base case projection for each state. “The proposed un it-level allocations are cal culated analogous[ly] with the way each state budget is calculate d -- each unit receives a proportional share of its state budget ba sed on that unit’s share of state emissions assumed in developing the budget [minus 3% to establish the new unit set-aside].” 42 If a state’s 2012 budget was based on the IPM 2012 projection (because the state’s 2012 projected emissions were lower than its actual reported emissions), then the individual allocations for units in that state were based on the projected emissions for units in the same IPM Run-Parsed File SB Limited Trading run that contained the 2012 un it-level emissions. Yet, without offering any particular explanation as to why it replicated certain portions of this step using the new IPM version even though it did not do so for earlier steps, EPA recalculated the 2014 unit-level SO 2 emissions for units in group 1 states in a new “SB Limited Trading v.4.10 – 2014 Parsed File” 43 -- but

39 State Budgets TSD at 10.

40 75 Fed. Reg. at 45290/3. The State Budgets TSD clarifies that the 2012 NOx and SO 2 “budgets are the lower of the recent actual em issions [approximately 2009] or projected base emissions, at the state level.” State Budgets TSD at 9.

41 State Budgets TSD at 12.

42 Id. at 11.

43 IPM Run – TR SB Limited Trading v.4.10 – 2014 Parsed File (EPA-HQ-OAR-2009- 0491-0312).30 apparently limited by the original pr oposed state emission budgets derived from the PTR IPM-based TR_2000_SO2. Without explanation, EPA elected not to provide for public review and co mment the parsed results for 2012 unitspecific emissions based on the updated NEEDS database and IPM platform. As the discussion above indicates, at every major step in EPA’s methodology -- e.g. , creating emission inventory cases as inputs to CAMx modeling, projecting future nonattainment and maintenance problem areas, establishing linkages of upwind states to downwind nonattainment and maintenance problem areas , defining significant contribution to nonattainment and interference with maintenance, and establishing unit-sp ecific allocations -- IPM played an indisputably critical role in ultimately determining unit-specific allowance allocations. Although EPA states in the NODA that it proposes to use IPM v.4.10 (along with NEEDS v.4.10) “in the final Transport Rule,” 44 the NODA is unclear as to exactly where and how EPA intends to use it. EPA should clarify these issues for the public and should revisit the basis for its proposal if it intends to proceed wi th this rulemaking and to continue to use its proposed approach to implementi ng section 110(a)(2)(D)(i)(I) of the Act. In doing so, EPA should redo each step of its methodology as described above using the updated NEEDS inventory and IPM platform. EPA then should is sue the results of its new analysis for public review and comment, providing an adequate comment period.

44 75 Fed. Reg. at 53614/3.OVERVIEW OF INFORMATION ON PRO JECTED CONTROL TECHNOLOGY COSTS AND PERFORMANCE AS DEVELOPED FOR EPA’S INTEGR ATED PLANNING MODEL (IPM)

October 15, 2010

Prepared by J. Edward Cichanowicz

Prepared for the Utility Air Regulatory GroupOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

1 OVERVIEW OF INFORMATION ON PRO JECTED CONTROL TECHNOLOGY COSTS AND PERFORMANCE AS DEVELOPED FOR EPA’S INTEGRATED PLANNING MODEL

INTRODUCTION This document reviews and respon ds to information on projected SO2 and NOx control technology costs as deve loped by Sargent & Lundy Engine ers (S&L) for the Environmental Protection Agency (EPA), for use in a new version (v.4.10) of the Integrated Planning Model (IPM), and as reported by EPA (EPA, 2 010a).  S&L’s information on costs and perform ance is reviewed and compared t o other recent data derived for similar control technologies.  For example, S& L’s cost data are compared to cost data developed in a 2009 survey of utility ind ustry operators and reported by the Utility Air Regu latory Group (UARG, 2010).  S&L ’s information on the performance of control techn ologies is evaluated and compar ed to other recent data, including data from a recent study of the best‐performing wet and dry FGD equipment (Weilert, 2010). The control technologies addresse d are wet and dry flue gas des ulfurization (FGD) for control of SO2; and selectiv e catalytic reduction (SCR), se lective non‐catalytic reduction (SNCR), and combustion controls for control of NOx. (The referenced EPA report also address costs for co ntrol of mercury (Hg), but the cost of equipment for reducing Hg emissions is not reviewed in this analysis.)

APPROACH EPA’s approach to acquiring cost data for use in v. 4.10 of IPM is very different from the approach the Agency took in conducting past studies to deve lop the same information.  In the present case, EPA engaged S&L to develop s uch inputs. Historically, EPA either derived such costs with internal staff , after discussions with control equipment suppliers, or em ployed contractors that had l imited access to information on equipment cost and performance.  By engaging an architectural/engineering firm w ith broad experience working wi th electric generating companies, EPA accessed an authentic database of com ponent and installed costs. S&L applied their in‐house database of control technology compo nent costs and their knowledge of installation requirements and maintenance du ties to project realistic cost estimates.  S&L t hen used this database to estim ate fixed and variable O&M costs for the different categories of control technology. Once the size of the control equipment was determined, and the coal composition was considered, S&LOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

2 applied conventional cost indices for installation of delivered equipment to determine final costs.  This approach replicates the steps in a commercial project. Table 5‐3 in the S&L report list s the factors considered in the cost evaluation.  This table comprises a representative and comprehensive list. S&L note that by adopting these most recent cost estimates into the IPM, EPA is apparently accepting th at the escalation in capital costs for c ontrol equipment that was experienced in 2009 is permanent, with costs not expected t o revert to levels preceding the 2009 installation window.  Such an approach (EPA’ s adoption of the S&L projected costs into the IPM ) is consistent with UARG’s pro jection of FGD and SCR capital costs (UARG, 2010). The following sections describe a nd evaluate S&L’s data concern ing the cost and performance of control technolog y for removing sulfur dioxide ( SO2) and nitrogen oxide (NOx) emissions from power plants. FLUE GAS DESULFURIZATION (SO2 CONTROL) PROCESS EQUIPMENT Both conventional wet and dry fl ue gas desulfurization (FGD) ar e addressed.  The specifics of the cost evaluation for wet FGD and dry FGD are de scribed in companion documents prepared by S&L (EPA, 2010b, and EPA, 2010c).

Wet FGD Estimated Costs . The capital cost for wet FGD process equipment as projected b y S&L is shown in Figure 1, depict ing capital cost ($/kW) as a fu nction of generating capacity.  Figure 1 presents dat a sets or curve‐fits of data se ts for three sources of wet FGD costs.  S&L’s projected capital costs are described by the blue line that is curve‐fit through square data po ints, which reflect the 2010 IP M update costs described by EPA (2010b).  This curve is labeled “2010 EPA IPM Projections”. The red curve‐fit through the locus of red triangle points represen ts capital costs for analogous wet FGD equipment, as reported in the 2010 UARG surve y.  This curve is labeled “2008‐2010 Operating Unit s” and describes cost data tha t represent units at which the controls began commerc ial operation in that timeframe . Finally, the light blue curve reflects EPA’s 2006 pr ojected capital costs for wet FGD; these costs were used in EPA’s previous IPM analysis (EPA, 2006). The cost data in Figure 1 for the EPA 2006 study case have been adjusted to a 2008 dollar basis. Figure 1 shows that the wet FGD capital costs projected by S&L exceed by approximately 20‐25% an average of the capital costs reported t o UARG by plant owners.   However, the curve‐fit for S&L’s projected costs resi des within a portion of the UARG‐reported cost data points for approximately 20 individ ual installations. Consequently, the difference in cost as reflected by the UARG a nd S&L curves –Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

3 although notable – is not consid ered significant.  Given the pa ucity of data, either curve could be correct. The capital costs in the two upper lines ‐‐ the 2010 EPA IPM Pr ojections and Operating Units:  2008‐2010 ( i.e. , the costs reported for units at which the controls began commercial operation in 2 008‐2010) ‐‐ are significantly h igher than the capital costs used in the 2006 EPA IPM analysis.

Figure 1. EPA‐IPM Input for Wet FGD Capital Cost vs. UARG Surve y Data Fixed operating and variable ope rating costs for wet FGD equipm ent were also projected by S&L.  For the range of generating capacity evaluat ed by S&L, the fixed operating costs projected by S&L are identical to UARG’s estima tes of fixed operating costs. S&L estimated variable operating costs only fo r one specific coal (3 lbs SO2/MBtu); this cost of 2.03 mills/kWh is within 10% of the projected cost in the UARG evaluation (2.2 mills/kWh). SO2 Removal Assumption .  The S&L analysis assumes 98% SO2 removal by wet FGD equipment, based on an annual ave rage, with a minimum “floor” S O2 emission rate of 0.06 lbs/MBtu.  Although pres ent‐generation wet FGD equipmen t can be capable of such high removal rates for a bbreviated periods of time, the available dataOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

4 suggest that such a level of pe rformance cannot be achieved for each month of the year, for all coals. A recent study of the best–perfo rming wet FGD equipment suggest s that 98% removal cannot be widely achieved on lower sulfur coals (Weiler t, 2010). Specifically, Weilert evaluated the removal performance of the ten lowest SO2 emitting generating units in the U.S.  Using the EPA Clean Air Markets Division database, the investigators calculated rolling SO2 outlet avera ges for periods of 3 hours, 24 hours, and 30 days.  These averages excluded periods of startup or shutdown. These data were used in conjunction with monthly fuel use reported to the Energy Information Agency (E IA) of the Department of Energy (DOE), allowing investigators to calculate the m onthly average of SO2 removal e fficiency for wet FGD equipment.  This exercise was re peated for dry FGD process equi pment and is discussed in a subsequent sectio n of this report.  The authors offer the following observation: “......none of these ‘top performing’ wet FGD systems was able to achieve a removal efficiency of 98% or greater in every month of the year.” The authors note some of the ina bility to achieve 98% removal w as due to the predominant use of low sulfur co al by the ten lowest SO2 emitti ng units and the process challenges presented by low inlet SO2 content.  The “fl oor” of 0.06 lbs/MBtu recognizes the difficulties inher ent in attaining high SO2 remo val percentages for coals of lower sulfur content.  However, the units considered a re the top ten performing units in the U.S. – n ot a random sample.   This data set demonstrates that the ten best performing units co uld not achieve 98% SO2 removal in each month of a year.   And because the data se t described by Weilert indicat es that the best‐ performing wet FGD units are una ble to achieve annual average r eduction levels of more than perhaps 95 or 96% SO2 r emoval, then all wet FGD units (including those at plants burning higher sulfur coals) may be unlikely to be ab le to achieve monthly or annual removal levels of m ore than approximately 95%. Evaluated Per Ton Removal Cost .  Cost assumptions play a s ignificant role in the IPM modeling done by EPA.  One measure of the influence of cost ass umptions can be deduced from comparing SO2 remov al cost per ton ($/ton) using b oth the S&L‐ derived and UARG cost premises. To do this, one can determine the SO2 removal cost for a range of reference un its that were described in the S&L study.  For example, one can evaluate the SO 2 removal costs for a (a) 500 M W unit, with plant heat rate of 10,000 Btu/kWh, and c oal sulfur content of 3 lbs ( as SO2) /MBtu; (b) 100 MW unit operating at a lower capacity factor more typical o f smaller, perhaps higher heat rate units; and (c) 500 MW unit firing low sulfur ( e.g., Powder River Basin (PRB)) coal. Calculations were conducted for a process ca pital recovery factor of 11.3% and SO2 removal of 95‐ 98%.  For a 500 MW unit operatin g at an 80% capacity factor and 98% SO2 removal, the SO2 removal costs deri ved with the S&LOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

5 premises would be $715/ton; the costs derived with the UARG pre mises would be $645/ton, a difference of approx imately 10%.   For a 100 MW uni t operating at a 60% capacity factor and 98% SO2 removal, the SO2 removal costs are approximately $1,450‐1,575/ton, again with S&L premises derivin g 10% higher costs.  For a 500 MW plant operati ng at an 80% capacity factor and 95% SO2 removal, and firing PRB of 1.2 l bs SO2/MBtu, the removal cost i s approximately $1,750‐1,950/ton, with S&L premis es deriving 10% higher costs. These projected costs would be about 20% higher if a capital recovery factor re flecting the typical 15‐20 year life for retrofit equipment were used, instead of th e EPA‐proposed value (0.113) that is appropriate for new generation. In summary, the S&L projected ca pital costs somewhat exceed tho se costs recently projected by UARG, but both the S&L projected fixed and the S&L projected variable operating costs are similar to U ARG estimates.  The net influen ce on calculated SO2 removal costs per ton – for the same reference unit, operating conditions, and financial premises – is that the S&L estimates are approximatel y 10% higher than the UARG estimates. Dry FGD Estimated Cost. The projected capital cost for dry FGD process equipment, incl uding a fabric filter for particulate matter removal, is shown in Fig ure 2, depicting capital cost ($/kW) as a function of gen erating capacity.  The S&L proj ected costs – depicted as the blue line through square calculated data points ‐ are co mpared to capital costs for similar equipment reported in the 2010 UARG survey.  Figure 2 shows a red curve‐fit through a locus of cos t data that represent both (a) actual costs incurred for units operating or under construction (triangle green point s), or (b) estimates of costs based on detailed engineer ing studies (diamond blue point s).  Figure 2 shows S&L projected dry FGD capital co sts that exceed the costs repor ted to UARG by plant owners by approximately 20% for smaller and 40% for larger unit s. Typically the maximum processing c apacity of dry FGD equipment installed to date – and that expected for dry FGD equipment in most future applic ations – is approximately 400 MW.  It is not clear why S&L and reported UAR G costs diverge at generating capacities larger tha n about 400 MW.  The data can b e interpreted in two ways.  First, either there is an economy‐of‐scale with larger g enerating capacities that S&L estimates do not recogn ize; or second, there are desig n complications at larger capacities that UARG data do not recognize.  Although th is point is not overtly stated in the background documents, S&L may have developed the dry FGD process design for units of 500 MW capacit y and greater by utilizing tw o spray dryer absorbers in parallel.  This process design would decrease econ omies of scale and elevate capital cost at higher capacities.Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

6 Figure 2. EPA‐IPM Input for Dry FGD Capital Cost vs. UARG Surve y Data It should be noted Figure 2 contains actual incurred costs for only three units; the remainder are projections. Fixed and variable operating cos ts for dry FGD process equipmen t were also projected by S&L.  The fixed ope rating costs are essentially id entical to UARG estimates. S&L projected variable operating costs for a specifi c coal (2 lbs SO2/MBtu); this variable cost of 2.60 mills/kWh is a factor of two higher than the 1.1 mills/kWh cost determined in the UARG study for PRB coal. One contributor to the difference in cost estimated by S&L are assumptions of cost for lime reagent and for solid byproduct disposal.  S&L’s estimate of the delivered cost for lime appears higher than historical values ($ 95/ton compared to historical v alues of $60/ton) but could be representative of lime reagent costs in the future.  G iven the uncertainty in solid byproduct disposal costs and challenges in siting a landf ill, it is possible that S&L’s estimate of byproduct mana gement costs could be realized. In summary, the S&L projected ca pital costs for dry FGD exceed those recently projected by UARG, and S&L’s fix ed and variable operating cost estimates are notably higher than UARG’s estimates. This will elevate the cal culated cost per ton of SO2 removed for dry FGD, and perhaps reduce its role as an alte rnative to wet FGD.Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

7 SO2 Removal Assumption . The S&L analysis assumes 95% SO2 removal by dry FGD equipment, based on an annual ave rage, with a minimum “floor” S O2 emission rate of 0.08 lbs/MBtu.  Weilert (2010) evaluated the SO2 performance capabilities of dry FGD using an approach similar to that used to evaluate wet FGD process equipment. Weilert identified the lowest te n SO2 emitting units equipped w ith dry FGD and calculated rolling averages of S O2 outlet emissions on a 3‐hour , 24‐hour, and 30‐day basis.   These SO2 data were used in conjunction with fuel inpu t data reported to the EIA to calculate SO2 removal on a percentage basis.   Weilert c oncludes the data set does not support a 95% SO2 removal efficiency in each month of the year, based on the coals used in the ten units examined.  Although this point is not explicitly addressed, the data from the pla nts evaluated by Weilert sugges t it may be possible to achieve a 93% SO2 removal eff iciency on an annual basis. Sim ilar to the case of wet FGD, however, the data set e valuated by Weilert is not repr esentative of industry practice.  The units represent only the top ten perfor ming units in this category, i.e. , those units that are already achieving low outlet values of S O2.  Thus, many dry FGD units are unlikely to be able to achieve monthly o r annual removal levels of as much as 93%. CONTROL EQUIPMENT FOR NOx NOx control process equipment ‐‐ selective catalytic reduction (SCR), selective non‐ catalytic reduction (SNCR), and combustion controls ‐‐ are addr essed in these analyses. Selective Catalytic Reduction (SCR) Estimated Cost . The specifics of the cost evaluation for SCR are described in a document prepared by S&L (EPA, 2010d). The capital costs for SCR process equipment as projected by S&L are shown in Figure 3, depicting capital cost s ($/kW) as a function of gener ating capacity.  Figure 3 presents data sets or curve‐fits of data sets for three sourc es of SCR costs.  S&L’s projected capital costs are desc ribed by the blue line that is curve‐fit through blue square data points, which reflect the 2010 IPM update described by EPA (2010d). This curve is labeled “2010 EPA IPM Projections”. The red curve ‐fit through the locus of red square points represents capital costs for SCR pro cess equipment as reported in the 2010 UARG survey.  This curve is labeled “2008‐ 2010 Operating Units”, noting all cost data representing units at which the SC R became commercially operational in that timeframe. Finally, the gray c urve reflects SCR costs projected by EPA in 2004 (K han, 2004). This curve was der ived in 2004, but used in the 2006 IPM analyses, and is thus labeled “2006 EPA IP M Projections”. It is not clear why the S&L SCR capital cost estimates are 20‐2 5% lower than recent UARG‐derived costs.  Perhaps part of the reason for the differe nce is that S&LOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

8 determined installed capital cost by applying a cost multiplier , with a subjective degree of retrofit difficulty, t o estimated process capital. Th e approach of using retrofit difficulty factors to a ssess installed cost, although widely used, is known to provide faulty cost estimates, particularly for SCR.  SCR cost estimates using retrofit difficulty factors are particula rly prone to error as such fact ors frequently do not capture the true complexity of a site, or the limitations on pr oductivity of installation labor in a constr ained (e.g., sellers’) market.  S &L also stated that actual incurred SCR costs were used in t he analysis reported by the Mi dwest Ozone Group in a document submitted to the Lake Michigan Air Directors Cons ortium (Marchetti, 2007).  The SCR capital costs contained in that referenced docu ment, however, reflect installations prior to 2006, and not the most recent in stallation window. Thus, S&L costs may be influenced by 2006‐vintage experience.

Figure 3. EPA‐IPM Input for SCR Capital Cost vs. UARG Survey Da ta S&L estimates of fixed O&M costs are similar to those in the UA RG analysis.  The S&L analysis projects SCR fixed O&M costs to be $2.5/kW‐yr for a 50 0 MW unit; UARG’s estimate of 0.75% of process capi tal for a 500 MW unit (requiri ng a capital cost of $265/kW) translates into an equiv alent cost of about $2.1/kW‐yr

. Variable O&M costs projected by S&L for SCR are 1.1‐1.3 mills/k Wh. The UARG analysis estimates the variable O&M costs to be 0.67‐1.3 mills/ kWh; however, the variable O&M costs in the UARG e stimates that are most relevant to the coal and boiler NOx emissions used for the S&L reference case are in the range of 0.77‐0.90Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

9 mills/kWh.  The differences in these operating costs – at most about 10% ‐ are likely due to the delivered price of bo th reagent and replacement cata lyst, and the frequency of catalyst exchange. NOx Control Performance . Recognizing that there is a limit to the lowest NOx emission rate that can be achieved with SCR, the S&L analysis r ecommends the establishment of NOx emission rate “floors” with use of SCR.  S &L assumed NOx outlet emissions cannot be less than 0.05 and 0.07 lbs/MBtu, re spectively, for sub‐ bituminous and bituminous coals. It is possible that these “flo ors” may represent minimum emission rates that are achievable over short‐term aver aging periods for high‐performing SCRs at certain units, although SCRs at other u nits may not be capable of achieving rates that low. Evaluated Per Ton Removal Cost .  One measure of the influence of cost assumptions is to compare the NOx removal co st per ton ($/ton) using both t he S&L‐derived and UARG cost premises.  The NOx removal cost was determined for a reference unit described in the S&L study docum entation:  a 500 MW unit, with a plant heat rate of 10,000 Btu/kWh, and a boiler NOx emission rate of 0.40 lbs/MBtu (typifying NOx emissions from burning bituminou s coal).   Calculations were co nducted for an 80% capacity factor, a process capita l recovery factor of 11.3%, an d NOx control to 0.07 lbs/MBtu (83% NOx removal). The N Ox removal costs derived with the S&L premises ($2,552/ton) are about 18% less than those derived wit h UARG premises ($3,117/ton). The most significant source of the differences in evaluated cost using S&L versus UARG‐reported premise s is the difference in capital requirement. Similar to the case with wet FGD , projected costs for SCR insta llations would be approximately 20% higher if one u sed a capital recovery factor reflecting the typical 15‐20 year life for retrofits to existing units, instead of the value proposed by EPA (0.113) that is appropriate for new generation. In summary, the S&L‐projected capital costs for SCR are notably less than those recently projected by UARG.  S&L and UARG fixed O&M costs are s imilar, but S&L’s variable O&M costs are higher th an those UARG derived from disc ussions with plant owners.  Based on these differen ces in cost estimates, using th e S&L SCR cost premises generates a calculated NOx removal cost per ton that i s about 18% below that derived with UARG premises, for the same reference unit, o perating conditions, and financial premises.

SNCR S&L estimate that the SNCR capit al cost for units less than 300 MW will be $45/kW. This number is consistent with, although generally somewhat hig her than, the cost derived by UARG of $20‐45/kW for units less than 300 MW. Variab le O&M costs of about 1 mills/kWh are projected b y S&L.  These costs are simila r to UARG’s estimates of variable O&M costs, which ‐‐ depending on unit siz e and initial NOxOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

10 emission rate ‐‐ are 0.5‐1 mills/kWh.  For most applications th e variable O&M costs are anticipated to be near the higher end of the UARG estimated range.  Fixed O&M costs for SNCR are negligible. S&L assume SNCR control efficien cy to be 25%, similar to UARG p rojections.  S&L also limit the application of S NCR to 100‐300 MW at this NOx re moval capability. (UARG’s projections permit applyi ng SNCR to larger units, but e stimate that NOx removal at those units would be restricted to less than 25%.) Combustion Controls (Low NOx Burners) S&L estimates the capital cost o f low NOx burners (LNB) to be $ 24‐45/kW, depending on the gener ating capacity of the boiler to which the LNB is retrofit. These estimates are accepted as reflecting recent industry expe rience. UARG‐ derived estimates of LNB costs a verage $20/kW; for a 300 MW uni t, the UARG $20/kW estimate approximates S&L ’s $24/kW estimate. S&L also as sign a small fixed cost and variable cost to the operation of this equipment

. ROLE OF SMALL UNITS EPA predicts generating units that are less than about 200 MW i n size will install SO2 and NOx controls.  Specifically, EPA projects that 15 units of less than 225 MW will install FGD, and that 6 unit s of less than 220 MW will cho ose to install SCR.  To date, the number of generating u nits in the U.S. of this capaci ty that have deployed either conventional FGD or SCR is small.  The smallest generati ng units with SCR are the 80 MW Dahlman units at City o f Springfield Power & Light. T he smallest with FGD are the dry‐FGD‐equipped 57 MW Cogentrix units.  These unit s were retrofit with control technology at a tim e when demand for such systems was low – i.e., a buyers’ market.  The reported costs for these units – such as $ 175/kW for the 80 MW Dahlman units – are unlikely to be replicated in the anticip ated market for 2012 and 2014 compliance. S&L recognize that retrofitting SCR and FGD to units less than about 200 MW capacity would be prohibitively costly.  S&L suggest that in li ght of this cost penalty, the owners of such units would c hoose to retrofit an alternativ e control option such as that recently tested in a DOE ‐funded demonstration (Connell, 2009).  S&L propose the cost for this altern ative option to be lower than t he cost associated with retrofitting SCR or FGD.  S&L do not have data to derive a cost algorithm for this alternative control technology, but propose a means to approxim ate such costs. Specifically, S&L propose to use the cost algorithm developed f or FGD and SCR; however, S&L use a higher capaci ty to assign the cost per unit ($/kW) generating capacity. S&L state that the absolute magnitude of capital cost ($M) for SCR and FGD for a 100 MW unit – when using a 200 MW basis to derive unit co st ($/kW), and using 100 MW to calculate the actual cost magnitude ($M) – by c oincidence providesOverview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

11 about the right cost estimate fo r this scenario.  Although this approach is imperfect, S&L submit that the approach per mits a reasonable cost number t o be used in IPM while still recognizing that SCR and FGD will likely not be app lied to 100 MW units. S&L are correct in recognizing that the cost to retrofit SCR an d FGD on small units is prohibitive and thus that owners of smaller units might well ch oose to retire units rather than retrofit them with a ny additional controls. This is particularly the case as long as alternative NOx and S O2 control options are few and are offered by only one or two suppliers (and those suppliers have little experienc e in installing the alternative technologies).  Suc h options might be applied in is olated cases but broad deployment within the mandated time frame is unlikely.

SUMMARY EPA has revised the cost inputs for IPM based on information pr epared by a knowledgeable architect/engineering company:  Sargent & Lundy E ngineers (S&L). EPA has also derived control technology costs based on an S&L d atabase of component costs and installation charges.  This report has comp ared the capital and operating costs derived from the newly‐compiled work by S&L wit h the capital and operating costs summarized by UAR G in a recent survey of costs incurred by power plant owners that have installed similar control technologies ( UARG, 2010).  This report also has evaluated information presented by S&L concerni ng the performance of various control technologies for reducing SO2 an d NOx.   The following is a summary of th is report’s findings. The S&L‐projected capital costs associated with installing wet FGD systems can be 20‐25% higher than the capital c osts for FGD installations as e stimated by UARG. S&L’s estimates of fixed and var iable operating and maintenance costs are generally similar to those summarized by U ARG.  The S&L analysis assumes wet FGD systems can achieve an annual average SO2 removal capacity of 98%, with a “floor” of 0.06 lbs/MBtu.  A detailed statisti cal study by Weilert (2010), howe ver, suggests that, at least when burning lower sulfur coals, even the best‐performing units cannot achieve 98% SO2 removal over long averaging times ( e.g. , months or a full year). The data were not evaluated to determine the annual average; bu t for the units addressed it is possible the annu al SO2 reduction would be limi ted to 95 or 96%. For dry FGD, the S&L‐derived cap ital and operating costs are bo th higher than UARG’s estimated costs, with the former most divergent for larg e generating capacity.   S&L propose a dry FGD annual SO2 removal target of 95% with a “floor” of 0.08 lbs/MBtu.  The recent an alysis of the SO2 emissions con trol performance data from dry FGD operating at t he ten lowest SO2‐emitting unit s in the U.S. (Weilert, 2010) shows that 95% r emoval efficiency could not be achieved. The data were not evaluated to determine the annual average; but for the units addressed it is possible the annual SO2 reduc tion would be limited to about 93%.Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

12 The S&L estimates of the evaluat ed cost of SCR NOx control – on a $/ton basis of NOx removed – are approximately 20% less than the evaluated cos t reported to UARG by owners that installed SC R systems in the past three yea rs.  Most of this difference is due to lower estim ates of capital cost, which can be 20‐25% less than costs reported by owners.  The S &L‐estimated operating costs fo r SCR systems exceed those estimated by UARG b y not more than 10%.  As far as SCR performance is concerned, the S&L analysis recognizes that there is a limit to the lowest NOx emission rate that can be achieved with SCR.  S&L assumed NOx o utlet emissions cannot be less than 0.05 and 0.07 lbs/MBtu, respectively, for s ub‐bituminous and bituminous coals.  These perform ance levels may represent minim um emission rates over short‐term averaging periods for certain high‐perfor ming SCRs, but SCRs at other units may not be capabl e of achieving rates that low, particularly over longer averaging times.Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

13 Author, Date Reference Connell, 2009  Connell, D., et al., “Greenidge Multi‐Pollutant C ontrol Project: Final Public Design Report”, Prepared for U.S. Department of Energy, Cooperative Agreement DE‐FC26‐ 06NT41426, January, 2009. EPA, 2006  EPA, “Documentation fo r EPA Base Case 2006 (v.3.0) Us ing the Integrated Planning Model”, Prepared by the Air & Radiation Division, November, 2006. EPA, 2010a  EPA, “Documentation f or EPA Base Case v.4.10 Using t he Integrated Planning Model”, Prepared by the Air & Radiation Division, August, 2010. EPA, 2010b  EPA, “IPM Model – Revisions to Cost and Performance for APC Technologies: Wet FGD Cost Development Methodology”, Final Report for Project 12301‐007, prepared by Sargent & Lundy, August, 2010. EPA, 2010c  EPA, “IPM Model – Revisions to Cost and Performance for APC Technologies: Dry FGD Cost Development Methodology”, Final Report for Project 12301‐007, prepared by Sargent & Lundy, August, 2010. EPA, 2010d  EPA, “IPM Model – Rev isions to Cost and Performance for APC Technologies: SCR Cost Development Methodology”, Final Report for Project 12301‐007, prepared by Sargent & Lundy, August, 2010. Khan, 2004  Khan, S. et. al., “Upd ating Performance and Cost of NOx Control Models in the IPM Mode l,” paper presented to the 2004 Combined Power Plant Air Pollutant Control “Mega” Symposium”, August 30‐September 2, 2004, Baltimore, MD.Overview of Projected Cost for Control Technology for EPA’s IPM October 15, 2010

14 Author, Date Reference Marchetti, 2007  Marchetti, J. et . al., “Analysis of MOG and LAD CO’s FGD and SCR Capacity and Cost Assump tions in the Evaluation of Proposed EGU 1 and EGU 2 Emission Controls”, paper prepared for the Midwest Ozone Group, January, 2007. UARG, 2010  UARG, “Current Cost an d Cost Effectiveness of Power Plant Emissions Control Technology”, prepared by J.E. Cichanowicz for the Utility Air Regulatory Group, January, 2010. Weilert, 2010 Weilert, C.V. et. al., “Emissions Control Performance Achieved in Practice by Electr ic Utility FGD Systems in the United States”, proceedings of the 2010 Mega‐Symposium, August 30‐September 2, 2010, Baltimore, MD.