### COMMENTS OF THE UTILIT Y AIR REGULATORY GROUP
on the PROPOSED FEDERAL IMPLEMENTATION PLANS TO REDUCE INTERSTATE TRANS PORT OF FINE PARTICULATE MATTER AND OZONE (PROPOSED AIR POLLUTION TRANSPORT RULE) 75 Fed. Reg. 45210 (Aug. 2, 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 1, 2010TABLE OF CONTENTS

I. Introduction................................................................................................................ ..........4 II. UARG Agrees with Certain Aspect s of the Proposed Transport Rule. ...............................5 A. EPA’s Proposal, in Its Preferred Remedy Option, To Allow Some Degree of Interstate Allowance Trading. .............................................................................5 B. Permitting Banking of Allowances Beginning in the First Year of the Program....................................................................................................................7 C. EPA’s Decision Not To Auction Allowances Under the Proposed Remedy Option. ...................................................................................................................10 III. The Proposed Transport Rule Should No t Include an Initia l Compliance Deadline of 2012. ....................................................................................................................... .......11 A. An Initial Compliance Deadline of 2012 Will Not Allow Enough Time for Sources To Make the Changes Necessa ry To Comply with the Transport Rule, or for States To Develop Implementation Plans. .........................................12 B. A Compliance Deadline in 2012 Is Ne ither Necessary Nor Appropriate..............14 IV. The Proposed Transport Rule Would Un lawfully Supplant the Role of States Under the Act.................................................................................................................. ...19 A. EPA Has No Authority To Promulgate a FIP To Replace CAIR..........................19 B. EPA Lacks Authority To Impose Any Unit-Specific Emission Rate Limits -- Such as the Limits in the Di rect Control Remedy Option -- Under Section 110(a)(2)(D)(i)(I). .....................................................................................27 V. The January 2012 and January 2014 Comp liance Deadlines Set Forth in the Proposed Transport Rule Are Un reasonable and Unrealistic. ...........................................27 A. Background............................................................................................................31 1. Step One Requires More Than C onducting an Engineering Review. .......32 2. A Construction Permit Is Only One of the Many Authorizations that Affected Plant Owners May Need. ............................................................34 3. The Actual Construction of FGD and SCR Systems at Existing Sites Will Take Longer than EPA Suggests. ..............................................................37ii B. EPA Relies Upon Incomplete and Ou tdated Information in Concluding that FGD and SCR Retrofits Can Be In stalled in a Total of Less than 30 Months. ..................................................................................................................38 C. FGD Installations: Real-World Examples Demonstrate that EPA Has Substantially Underestim ated How Long It Typically Takes To Retrofit FGD Systems at Power Plants. ..............................................................................41 D. SCR Installations: Real-World Examples Demonstrate that EPA Has Substantially Underestim ated How Long It Typically Takes To Retrofit SCR Systems at Power Plants................................................................................44 E. Summary and Conclusions. ...................................................................................46 VI. EPA’s Analysis Significantly Unders tates the Amount of Electric Generating Capacity that Would Have To Under go FGD and SCR Retrofits in the 2012-2014 Period and the Associated Demands on Resources; Constraints on Labor Resources Make Compliance With the PTR’s Timeline Impossible.................................48 VII. Many of the Judgments and Policy D ecisions Underlying the Structure of the Proposed Transport Rule Are Inappropriate and Unjustified. ...........................................50 A. EPA’s Base Case Modeling Should Have Included CAIR....................................50
B. EPA Should Return to Its “Mon itored-Plus-Model ed” Approach.........................53 C. EPA’s Proposed Air Quality C ontribution Threshold Is Flawed...........................55
D. The Method EPA Used To Determine “Interference With Maintenance” in the Proposed Rule Overestimates Actual Future Design Values...........................57 E. The Process EPA Used To Classify Ce rtain States as “Group 1” States Is Inadequately Explained and Misguided.................................................................61 F. EPA’s Determinations of “Signifi cant Contribution” and “Interference with Maintenance” Improperly Presuppose Upwind-State EGU Emissions as the Primary Cause of Downwind Nonattainment Problems and Inappropriately Underestimate the C ontribution of Local Sources from a Variety of Emission Sectors...................................................................................64 1. EPA’s Approach Places an Undue and Unlawful Burden on Sources in Upwind States To Reduce Emissions. .......................................................64iii 2. EPA’s Air Quality Assessment Improperly Overestimated the Marginal Benefit of Emission Reductions Above Relatively Low Dollar-Per-Ton Levels.........................................................................................................66 G. EPA Has Failed To Explain Why It Did Not Use 2008 Heat Input Data in Calculating SO2 Emission Budgets.......................................................................73 VIII. EPA’s Use of Inaccurate Inputs and A ssumptions for -- and Unrealistic Outputs from -- EPA’s Use of the Integrated Planning Model Makes the Proposed Transport Rule Inadequate for Public Comment. ..............................................................75 A. Many of the IPM Inputs for Individual Units Are Inaccurate. ..............................77 B. EPA’s IPM Outcomes Do Not Reflect Actual Source Operations........................80 IX. Certain EPA Assumptions and Determin ations Do Not Account Adequately for the Interaction Between the Proposed Rule and Other CAA Programs. ...........................85 A. Contrary to EPA’s Assumpti on, Permitting Requirements Cannot Be Expected To Be Met in Time To Satisfy the Proposed Transport Rule’s Compliance Schedule.............................................................................................85
B. EPA Should Provide Justification for Its Unsupported Assertion that It Is “Very Unlikely” that Pollution Control Projects Would Cause GHG Emission Increases in Excess of th e PSD Emission Thresholds in the Agency’s June 2010 GHG Tailoring Rule.............................................................86 X. EPA Should Amend the Proposed Tran sport Rule To Allow for Increased Flexibility in Compliance and Allowance Trading............................................................87 A. The Variability Limits and Assu rance Provisions Pr oposed by EPA Are Unduly Stringent and Should Be Adjusted............................................................87 1. Variability Limits.......................................................................................87 2. Assurance Provisions.................................................................................89 B. Units Should Be Permitted To Borrow Allowances From Future Year Allowance Accounts, at Least on a Limited Basis. ...............................................90 C. EPA Should Not Establish Any Government-Run Allowance Auctions. .............90 XI. Requirements for Electronic Reporting of Quarterly Reports ...........................................91 A. Electronic Reporting Format..................................................................................91iv B. Adjustments to Certified Information by the Administrator..................................94 C. Correction and Resubmission of Quarterly Reports ..............................................94 XII. As a Matter of CAA Procedural Re quirements, the Proposed Rule’s Unfounded Assumptions, Errors, and Apparent Anoma lies -- and EPA’s Failure To Explain Adequately Critical Aspects of the Pr oposal and To Include in the Docket Information that Would Enable Repli cation of EPA’s Process -- Make the Proposed Rule Inadequate for Public Comment................................................................96 XIII. Conclusion. .............................................................................................................. ..........98COMMENTS OF THE UTILITY AIR REGULATORY GROUP on the PROPOSED FEDERAL IMPLEMEN TATION PLANS TO REDUCE INTERSTATE TRANSPORT OF FINE PARTICULATE MATTER AND OZONE 75 Fed. Reg. 45210 (Aug. 2, 2010); Dock et ID No. EPA-HQ-OAR-2009-0491 October 1, 2010

___________________________________________________________________________ On August 2, 2010, the U.S. Environmental Prot ection Agency (“EPA” or the “Agency”) published its Federal Implementation Plans To Redu ce Interstate Transport of Fine Particulate Matter and Ozone; Proposed Rule (“Proposed Transport Rule” or “PTR”) and announced a 60- day public comment period on the proposal, ending on October 1, 2010. 75 Fed. Reg. 45210/1 (Aug. 2, 2010). The Utility Air Regulatory Group (“UARG”) submits the following comments on the Proposed Transport Rule. UARG is a voluntar y, not-for-profit group of electric utilities, other electric generating companies, and natio nal trade associations. UARG’s purpose is to participate on behalf of its members collectiv ely in EPA rulemakings under the Clean Air Act (“CAA” or “Act”) and other proceed ings that affect the interests of electric generators and in related litigation. Because the Proposed Transpor t Rule specifically -- an d exclusively -- targets nitrogen oxide (“NOx”) and sulfur dioxide (“SO 2 ”) emissions from electric generating units (“EGUs”) for regulation, UARG and its members have a compelling interest in the present rulemaking. UARG submits these comments against a back ground of Agency decisions that has made participation in this proceeding exceedingly di fficult. Specifically, on September 1, 2010, EPA published a separate Notice of Data Availabili ty (“NODA”) for the Proposed Transport Rule. 75 Fed. Reg. 53613. The NODA announces additional EP A modeling runs and other information that “EPA proposes to use to support the final rule ,” as well as “a list of further planned updates to support the final rulemaking.” Id. EPA announced a separate comment period for the2 NODA, extending until October 15, 2010 (and may have separate comment periods for other subsequently posted information), but refused to extend the comment period for the underlying proposal. EPA’s decision to maintain two sepa rate deadlines for public comments -- one on the Proposed Transport Rule and the information poste d in the docket contemporaneously with it, and another for the information released pur suant to the NODA -- makes it extraordinarily challenging to provide comprehensive commen ts on EPA’s proposal. In addition, EPA on September 10, 2010, denied UARG’s August 19, 2010 re quest for an extension of the comment period on the Proposed Transport Rule to November 30, 2010, and did not respond to a September 10, 2010 UARG request for a comment deadline extension to November 30, 2010, for both the proposed rule and the NODA. 1 In light of the significant differences between the data on which EPA based (or says it based) the propo sed rule and the data EPA released later pursuant to the NODA, EPA should withdraw the Proposed Transport Rule, revise it using whatever data EPA deems most appropriate (and addressing th e proposed rule’s many other deficiencies as discussed in these comments) and republish it for public comment with an adequate comment period. The Proposed Transport Rule is intended to replace the Clean Air Interstate Rule, 70 Fed. Reg. 25162 (May 12, 2005) (“CAIR”), which EPA pr omulgated in 2005 and the U.S. Court of Appeals for the D.C. Circuit found to be “fundame ntally flawed,” initia lly 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). Like CAIR, the Proposed Transport Rule primarily addresses EGUs and is based on EPA’s interpretation and application of section

1 UARG incorporates its August 19, 2010 a nd September 10, 2010 letters herein by reference.3 110(a)(2)(D)(i)(I) of the Act, which requires, in re levant part, each state’s plan for attaining the national ambient air quality st andards (“NAAQS”) to “contain adequate provisions . . . prohibiting . . . any source or other type of emi ssions activity within the State from emitting any air pollutant in amounts which will . . . contribut e significantly to nonattai nment in, or interfere with maintenance by, any other State with respect to any [NAAQS].” The Proposed Transport Rule is structured as a federal implementation plan (“FIP”) and would regulate emissions from EGUs in 32 stat es. 75 Fed. Reg. at 45210/1. According to the proposal, EPA plans to promulga te a final rule in spring 2011, 2 imposing an initial compliance date of January 1, 2012 (May 1, 2012 for the ozone season 3 NOx program), and a further SO 2 reduction requirement on January 1, 2014, for many st ates (which EPA calls “group 1” states) subject to the program. 75 Fed. Reg. at 45213/2, 45215/3. UARG notes that it plans to file addi tional comments on EPA’s September 1, 2010 NODA and on any subsequently published EP A updates to support the final rulemaking. Because the information in the NODA is inextricab ly linked with information in the PTR, some

2 Although the Proposed Transport Rule states only that EPA antic ipates publishing a final rule in “spring 2011,” see, e.g. , 75 Fed. Reg. at 45213/2, the Agency has announced that it anticipates taking final action in the rulemaking in June 2011. See, e.g. , EPA, Proposed Air Pollution Transport Rule -- “Overview Presenta tion 7/26/2010,” at slide 29 (July 26, 2010), available at http://www.epa.gov/airquality /transport/actions.html.

3 EPA requests comments on whether the ozone season should be longer than the fivemonth season used in the NOx SIP Call rule, 63 Fed. Reg. 57356 (Oct 27, 1998), and CAIR (May 1 through September 30), perhaps to corres pond to the ozone monitoring season for each state. 75 Fed. Reg. at 45292/1. UARG does not be lieve EPA has provided an adequate basis for expanding the ozone season for purposes of this rule, however, if EPA expands the ozone season for some or all states, it would need to consid er carefully how such an expansion would affect the proposed program, and at a minimum would have to increase the NOx ozone season budgets in proportion to the additional time in the season for affected states. Any such change should be addressed in a supplemental notice of proposed rulemaking.4 of UARG’s comments on the PTR necessarily relate to information associated with the NODA and UARG’s comments on the NODA w ill be relevant to the PTR.
I. Introduction. EPA’s task in developing this proposed rule was to remedy the deficiencies identified by the court in North Carolina v. EPA . To an extent, EPA appears to have attempted to discharge that obligation. Indeed, as disc ussed in section II of these comme nts, UARG agrees with certain aspects of the proposal. For example, UARG supports EPA’s preferre d option of permitting some degree of emission allowance trading (a lthough, as discussed subsequently in the comments, UARG urges EPA to consider expanding the margin for trading). Yet in other respects, EPA’s proposed approach is seriously misguide d. The decision to impose FIPs rather than allow states time to develop state implementation plans (“SIPs”) to implement section 110(a)(2)(D)(i)( I) obligations rests on an unlawf ul view of the CAA and the federal-state cooperative relationship under the Act. The PTR’s compliance schedule is wholly unreasonable, particularly its imposition of a January 1, 2012 initial compliance deadline that will fall only a few months after EPA plans to take final action in this rulemaking. EPA has failed to propose a defensible methodology fo r determining statew ide emission reduction obligations and has required additional emissi on reductions even where they have not been shown to be needed to meet the air quality obj ectives that EPA asserts. And EPA in this proposed rule has arrogated to itself, in contrave ntion of the law, the ri ght and responsibility to determine how a state’s emission reduction require ments must be accomplished, thereby assuming an exceptionally heavy burden to show th at it has applied its unit allowance allocation methodology accurately and consistently. Re view of the PTR’s supporting information, however, reveals that EPA’s approach on this sc ore is anything but accurate and consistent. Moreover, in many respects, EPA’s explanation of the elements of the PTR, and its information5 and calculations offered in support of the PTR, ar e opaque to the point of incomprehensibility. These points are explained further below. For these reasons, UARG believes that the PT R is inadequate as a proposed rule to replace CAIR. EPA should develop and offer for comment a new proposal that corrects the serious flaws in the PTR.
II. UARG Agrees with Certain Aspects of the Proposed Transport Rule. UARG understands that development of a re placement rule for CAIR that properly responds to the court’s decision in North Carolina v. EPA is in some respects a challenging task. Although, as discussed above and in the following s ections of these comments, the proposed rule contains a number of serious flaws that must be remedied before EPA could continue with this rulemaking, UARG agrees with and supports certain aspects of the PTR. These include (i) the proposal to permit some degree of interstate allowa nce trading, (ii) the proposal to permit allowance banking beginning in the first year of th e program, and (iii) the proposal not to auction allowances (in the proposed interstate trading remedy). 4 UARG discusses these points below, along with some suggestions to further stre ngthen these elements of the proposed rule.
A. EPA’s Proposal, in Its Preferred Reme dy Option, To Allow Some Degree of Interstate Allowance Trading. EPA’s Proposed Remedy Option allows limited interstate allowance trading, while its two alternative options would not allow any in terstate trading. UARG supports EPA’s proposal to permit at least some degree of allowance tr ading. Permitting intersta te allowance trading would provide for increased flexibility and pe rmit more cost-effectiv e compliance options. Increased flexibility will be particularly important in the early years of the program, especially if

4 As discussed below, UARG opposes the pr oposed allowance auction feature of the proposed Intrastate Trading Remedy Option (and i ndeed opposes that remedy option altogether).6 EPA does not change the proposed rule’s unr easonably accelerated compliance schedule as suggested in these comments. UARG believes that the interstate trading program described in the proposal should resolve the problems with the CAIR program’s unrestricting trading that the court cited in North Carolina v. EPA . The court held that the CAIR intersta te trading program was inconsistent with the Act, based mainly on the program’s region wide approach. Noting that “EPA is not exercising its section 110(a)(2)(D)(i)(I) duty unl ess it is promulgating a rule that achieves something measurable toward the goal of prohib iting sources ‘within the State’ from contributing to nonattainment or interfering with maintenan ce ‘in any other State,’” the court held that “EPA’s apportionment decisions have nothing to do w ith each state’s ‘signi ficant contribution.’” 531 F.3d at 907. Although the Proposed Transport Rule is flawed for reasons discussed elsewhere in these comments, the Proposed Remedy Option incorporates a mechanism for addressing the significant contribution of indi vidual states to downwind nonattainment and maintenance problems. In developing the Proposed Transpor t Rule, EPA used photochemical source apportionment modeling to identify the impact of emissions from specific upwind states on downwind areas projected to be in nonattainment or to have maintenance problems in 2012. 75 Fed. Reg. at 45253/1. Then, EPA determined each state’s significant co ntribution to nonattainment and interference with maintenan ce based on the emissions that EPA projected could be eliminated from that st ate for a specific cost (in dollars per ton of reduced emissions), in conjunction with an analysis of air quality benefits at various cost levels, and set state budgets accordingly. 75 Fed. Reg. at 45271/1-2. Thus, a lthough UARG disagrees with many aspects of the data and methodology that EPA used in this analysis, EPA’s methodology does, as a general7 matter, attempt to address the EPA-projected co ntribution to nonattainment and interference with maintenance in downwind states from emissions from particular upwind states. At least in broad terms, the PTR’s focus on state-specific data sh ould align with the cour t’s characterization of states’ section 110(a )(2)(D)(i)(I) duties. 5 In addition, if EPA retains its propos ed two-phased compliance schedule, 6 UARG supports EPA’s proposal not to apply variability limits and assurance provisions before 2014. 75 Fed. Reg at 45296/1, 45305/3. EPA states that a ssurance provisions will not be necessary to limit interstate trading during the first two year s of the program because during those years, “state-specific budgets are base d on known air pollution controls and thus a high level of certainty exists about where reductions will occu r.” 75 Fed. Reg. at 45306/1. Given the nature of EPA’s proposal, EPA’s reasoning is sound: If the state budgets are based on reductions that EPA expects will occur based on use of control equi pment that will be installed and operational by that time, there is no need for assu rance provisions during this time period. 7
B. Permitting Banking of Allowances Be ginning in the First Year of the Program. The Proposed Transport Rule properly rec ognizes the important environmental and economic benefits of allowance banking, a featur e of CAIR that was not challenged in the litigation on that rule and that the court’s opinion in no way undermines. The ability of sources

5 Furthermore, as the court recognized, although North Carolina challenged the CAIR interstate trading program, North Carolina did no t argue -- and the court did not hold -- that interstate trading was per se unlawful. North Carolina , 531 F.3d at 906.

6 EPA has not justified its proposed complia nce schedule and should not, for example, impose an initial compliance deadline as early as 2012. See section III infra

. 7 However, as explained elsewhere in th ese comments, many of EPA’s assumptions regarding which controls will be installed a nd operational by the beginning of 2012 are illfounded. EPA thus should revise its calculations based on an accurate accounting of the controls that will be operational by the beginning of 2012, if EPA retains the 2012 deadline.8 to use banked allowances for compliance with the program encourages them to make early emission reductions to the extent that cost-effec tive early reductions are possible. Unfortunately, the nature and stringency of the proposed ru le’s emission reduction requirements and its proposed compliance schedule woul d make it very difficult for most sources to make extra emission reductions during the early years of the program. See sections III and V infra for UARG’s comments on the compliance schedule. Permitting allowance banking in conjunction with an adjustment to the compliance schedule that would allow sources adequate time to comply with the program (and that would give st ates adequate time to develop SIPs) could well result in greater amounts of early emission reductions and, most likely, greater emission reductions over the long run. UARG also emphasizes, however, that it suppor ts approaches that would permit the use of banked CAIR NOx allowances for compliance w ith the Proposed Transport Rule. In the final rule, EPA should provide that it will transfer all CAIR NOx an nual and ozone season allowances held in each source’s complian ce accounts for the final complianc e period of CAIR into that source’s compliance accounts for th e new program (to the extent th e source is subject to the new program’s annual or ozone season NOx requirements, or both). This could readily be accomplished because, for purposes of compliance with the new program, EPA proposes to use the same Allowance Management System (“AMS”) that it used for compliance with CAIR. 75 Fed. Reg. at 45312/1. There is no reason not to allow sources to use their CAIR allowances (including allowances that they bought or othe rwise acquired from others) for compliance with the new program. EPA’s concern that some may view an appro ach that authorizes sources to use banked CAIR NOx allowances as unfairly permitting some sources a larger share of allowances due to9 CAIR’s use of fuel adjustment factors, which the North Carolina decision found EPA had not adequately justified, is no basis to bar use of these allowances already allocated. The court’s opinion in no way bars use of these already-allocated allowa nces, on a banked basis, in a new program. Moreover, if EPA disallows use of ba nked CAIR NOx allowances at this juncture, it will be to the detriment of all sources that hold banked CAIR NOx allowances at the time that CAIR expires. It would be far better to allow all sources the benefit of their banked allowances than to render them worthless at the end of the CAIR program. 8 Indeed, there are many compelling reasons to allow sources to us e their banked CAIR NOx allowances for compliance with the proposed rule. First, as noted above, nothing in the
court’s North Carolina opinion precludes -- and in fact, no party challenged -- use of banked CAIR NOx allowances. The only flaw identif ied by the court with respect to CAIR NOx allowances was the way EPA established NOx a llowance budgets. Second, as EPA suggests, permitting use of banked CAIR NOx allowances would promote the continuation in 2010 and 2011 of the reductions that occurred under CAIR. Id. at 45339/1. Likewise, it would avoid creating an incentive for sources to “use up” CAIR NOx allowances, thereby potentially increasing their NOx emissions temporarily, because those allowances would -- in the absence of a provision allowing use of banked CAIR NOx allo wances in the new program -- have no value after the allowance tran sfer deadline for the final CAIR annual and ozone season compliance periods. Third, allowing use of banked CAIR NOx allowances would provide a modest degree

8 If EPA is concerned that the amount of ba nked CAIR NOx allowances is or will be so great that it may reduce the amount of emission reductions that would otherwise be achieved under the proposed rule, see 75 Fed. Reg. at 45339/1, there are bett er ways to avoid that outcome than to invalidate the allowances in whole or in part. EPA s hould allow sources the full benefit of their banked CAIR NOx allowa nces. If EPA determines that some limitations on use of those allowances are necessary, EPA should at least permit use of a substantial amount of the allowances over at least the firs t few years of the new program.10 of increased flexibility for sources during the early years of the new program, an especially important consideration if EPA requires compliance with the Transport Rule according to the unreasonably accelerated schedule se t forth in its proposal. Indeed, the issue of use of banked CAIR NOx allowances is one example of the reasons why, EPA should design the transition to the Tran sport Rule as a seamless regulatory process to ensure that the mechanisms remain in pl ace for continuous compliance and assurance of continued emission reductions. The D.C. Circu it, in its December 2008 decision, determined that CAIR could remain in place while EPA de veloped a replacement rule, specifically because of concerns that the emission reductions attr ibutable to CAIR would not occur during the transition period if CAIR were vacated. Because th e court allowed CAIR to remain in place, it is possible for EPA to retain aspects of CAIR that will assure full compliance and that will promote the effective and seamless transition to the new rule, without the possibi lity of short-term backsliding. This would also leave in place, for example, the CAIR 2015 phase II control requirements until the Transport Rule can be implemented. This approach will provide additional time for EPA to complete the curren t rulemaking and permit an adequate compliance schedule under the new rule, even while electric generating companies ar e required to continue to plan for further emission reductions to meet the CAIR 2015 deadline. C. EPA’s Decision Not To Auction Allowances Under the Proposed Remedy Option. UARG supports EPA’s proposal not to incl ude any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule’s emission reduction re quirements. If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that UARG does not support, EPA should remove from that option the proposed provisions for a llowance auctions. It11 is entirely possible to accomplish the objectives of those proposed auctions through distribution of allowances free of charge. This is particularly true if states are provided the time to develop SIPs that will allow each state to determine how best to make allocations that address that state’s specific needs. As explained in section X.C below, government auctioning of allowances is contrary to the principle that regulated sources are not subject to any obligation to emit below their allowance allocation levels established by the pr ogram. Revenues from the allowance auctions that EPA describes in the Intrastate Trading Remedy Option would be deposited into the U.S. Treasury. 75 Fed. Reg. at 45327/2. The effect of su ch auctions, in which proceeds accrue to the government, is to force affected sources to pay not only for emissions that exceed their emission allocation levels but also for the right to emit below those levels. There is no legal basis for charging sources for the right to emit tons of emissions that are within their allowance allocation levels -- indeed, the very word “allowance” denote s that a source is allowed to emit within the limits of its allowance allocations -- and provi ding revenue to the U.S. Treasury is not a legitimate purpose of section 110(a )(2)(D)(i)(I). Moreover, EPA has not shown that any legal authority exists for EPA to auction allowances and thereby impose what amounts to a tax, with tax revenue flowing to the federal government.
III. The Proposed Transport Rule Should Not In clude an Initial Compliance Deadline of 2012. Many of the flaws in the Proposed Transport Ru le, described in the sections that follow, could be resolved or at least somewhat amelio rated by deferring the in itial 2012 compliance date and having CAIR’s allowance tr ading and enforcement mechanisms remain in effect pending implementation of the Transport Rule. It is unre asonable and unrealistic, for example, to expect12 emission reductions required by the proposal to be achieved by January 1, 2012, barely six months after the date on which EPA exp ects to issue a final Transport Rule.
A. An Initial Compliance Deadline of 2012 Will Not Allow Enough Time for Sources To Make the Changes Necessa ry To Comply with the Transport Rule, or for States To Deve lop Implementation Plans. An initial compliance deadline of Januar y 1, 2012, will not allow sufficient time for sources to make the adjustments necessary to co mply with the rule. For example, a compliance deadline of 2012, following a mid-2011 date for final promulgation of the rule, 9 would not allow enough time for sources to install low NOx burne rs (“LNBs”), and in many cases, would not allow sufficient time for sources to sw itch to burning lower sulfur coal. See section V infra

. Additionally, much of the modeling that EPA used to develop the proposed rule is flawed, due to the approach that EPA adopted, as well as many of the assumptions EPA made with respect to issues such as the emission controls that will be installed on, and retirement of, specific units by 2012. EPA must resolve and correct these problems, and either w ithdraw the proposed rule and reinitiate rulemaking with a new proposal or i ssue a supplemental notice of proposed rulemaking for public comment. Under these circumstances, rulemaking could not be completed before the beginning of 2012. The tight implementation schedul e that EPA proposes is in e ffect made even tighter by the fact that EPA is already ch anging the terms of the proposed rule. As discussed above, on September 1, 2010, midway through the public comment period on the proposed rule, EPA published its NODA, announcing information that in e ffect will result in substantial changes to the proposed rule and noting that further cha nges are to come. Among other things, the NODA

9 As discussed in these comments, the NODA be lies any argument that sources (or states) could possibly rely on the proposed rule’s budgets and allowance allocations to develop SIPs or, much less, source compliance plans.13 announced the release of (i) an updated version of the National Electric Energy Data System (“NEEDS”), which provides the unit-level EGU characteristics used as inputs for the Integrated Planning Model (“IPM”), (ii) results of new ba se case and policy case modeling runs using an updated version of IPM, and (iii) results of new base case and policy case modeling runs using an updated version of IPM and including data from the Energy Information Administration’s Annual Energy Outlook 2010 natural gas resource assumptions. 75 Fed. Reg. at 53614/2-3. It also announces the release of “[a] summary of other planned input updates to be implemented in the final rulemaking.” 75 Fed. Reg. at 53614/3. The data released in connection with the NODA will, when applied by EPA, change substantially the statewide budgets and allowance allocations for 2012 and the allowance allocations for 2014, 10 and there will presumably be additional changes leading up to promulgation of a final ru le based on the planned input updates that EPA says will be implemented later. The scope of the impact that the new data will have is clear at a glance. For example, the parsed file that EPA released in connection wi th the proposed rule, show ing the initial IPM run, indicates that IPM projected a bout 23,723 MW of new coal genera tion from unidentified plants yet to be built in 10 different states. See IPM Run File “TR SB Limited Trading”, available at http://www.epa.gov/airmarkets/pro gsregs/epa-ipm/transport.html. 11 By contrast, the updated parsed file that EPA added to the docket in connection with the NODA app ears to indicate that IPM projected only about 2,001 MW of new coal ge neration from unidentified plants yet to be

10 EPA did not update the state budgets for 2014. See 75 Fed. Reg. at 53614/3 (“The [state-level emissions] caps have not been modi fied to account for any changes that the new modeling might suggest”).

11 This spreadsheet is listed in the docket at Document No. EPA-HQ-OAR-2009-0491- 0092, but that document number is linked to a su mmary report, and not the full spreadsheet. See http://www.regulations.gov/search/Regs/ home.html#docketDetail?R=EPA-HQ-OAR-2009- 0491.14 built in four states. See Docket ID No. EPA-HQ-OAR- 2009-0491-0312, IPM Run - TR SB Limited Trading v.4.10 - 2014 Parsed File (Sept. 1, 2010), available at http://www.regulations.gov/search/Regs/ home.html#docketDetail?R=EPA-HQ-OAR-2009- 0491. This is likely to be merely one indicator of the substantial changes in EPA’s proposal that will result from use of the NODA information, and the impact of the future changes that EPA anticipates remains to be seen. Clearly, ther e is no way for sources to begin planning for compliance based on the information that EPA has provided in the docket. In addition, EPA states in the proposed rule th at it intends to propose additional interstate transport determinations in the future as EPA revises the NAAQS for PM 2.5 and ozone, and that these proposals “could require greater emissions reductions from states covered by [the Proposed Transport Rule] and/or require re ductions from states not covere d” by the current proposal. 75 Fed. Reg. at 45213/3. It would be very difficult for states and el ectric generating companies to plan for compliance with a rule under which the standards of compliance change along with the frequent changes to the ambient standards. EPA should keep state budgets (and allowance allocations, to the extent EPA sets allowance allo cations) as constant as possible, revising them only when essential and in a way that provides ample time for compliance, rather than changing them sporadically each time EPA revises a NAAQS. Finally, the proposed rule -- a nd especially its 2012 first- phase compliance date -- is fundamentally inconsistent with the CAA because it effectively deprives states of the time they need to develop, submit, and receive EPA appr oval of SIPs before the program begins. See section IV infra

. B. A Compliance Deadline in 2012 Is Neit her Necessary Nor Appropriate. In any event, EPA has provided no reasonable justification for its proposal to require a compliance date as early as 2012. To begin with, according to statements by EPA15 representatives, the emission levels required in the 2012 phase for the most part reflect the emission reductions that would occur even in th e absence of the Transport Rule. However, as noted above, in a number of cases, EPA has ma de incorrect assumptions regarding emission reductions that, in the absence of this new rule, would occur at units by 2012. See section VIII.A infra

. Additionally, notwithstanding th ese assertions that the em ission reductions required in 2012 would occur even without th e Proposed Transport Rule, EPA indicated in a presentation given in July 2010, when it announced the proposed ru le, that it projects th at the proposed rule would reduce SO 2 emissions by an additional one million tons per year (“TPY”) in 2012 beyond what CAIR would have accomplished: from an emission level of 5.1 million TPY under CAIR to 4.1 million TPY under the proposed rule. 12 In fact, during a meeting held shortly after EPA issued the proposed rule but before its public ation in the Federal Register, EPA acknowledged that, according to the Agency’s projections, the 2012 state budge ts in the Proposed Transport Rule would reduce SO 2 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. EPA failed to explain this apparently substantial discrepancy or how over a million additional tons of emissions would be eliminated in a phase of the program that is intended merely to replicate what would have occurred anyway. Moreover, EPA has not shown that emission reductions beyond those required by CAIR are necessary. EPA’s own data show that existi ng controls are working to reduce emissions; the result is that concentrations of SO 2 and NOx in the ambient air have declined steadily in recent

12 See Table V-1 at section V infra , based on a table included in EPA’s “Overview Presentation 7/26/10,” at slide 33, available at http://www.epa.gov/airquality/tra nsport/actions.html and repr oduced at 75 Fed. Reg. at 45217 (Table III.A-4).16 years. 13 The D.C. Circuit’s opinion in North Carolina v. EPA did not require, or even remotely suggest, that the overall degree of emission reduc tions required under CAIR was less than that necessary to comply with CAA section 110(a)(2)( D)(i)(I). Nor did the court include in its opinion any mandate that the replacement rule fo r CAIR must include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation. 14

13 EPA’s most recent Status and Trends Report indicates that nationwide concentrations of nitrogen dioxide (NO 2 ) decreased by 27 percent between 2001 and 2008 and by 35 percent between 1990 and 2008, and that na tionwide concentrations of SO 2 decreased by 30 percent between 2001 and 2008 and by 59 percent betw een 1990 and 2008. EPA, “Our Nation’s Air Status and Trends Through 2008,” 1, 31 (Feb. 2010) (“EPA’s Trends Report”), available at http://www.epa.gov/airtrends/2010/index.html. A dditionally, according to EPA, nationwide 8- hour concentrations of ozone decreased by 10 percent between 2001 and 2008 and by 14 percent between 1990 and 2008, and nationwide annua l and 24-hour concentrations of PM 2.5 decreased by 17 and 19 percent, respectively, between 2001 and 2008. Id. at 1, 15, 20.

14 The D.C. Circuit’s finding th at the 2015 compliance deadli ne for the second phase of CAIR was unlawful because “EPA did not make any effort to harmonize CAIR’s Phase Two deadline for upwind contributors to eliminate thei r significant contribution with the attainment deadlines for downwind areas,” 531 F.3d at 912, doe s not mandate a 2012 compliance deadline. In the preamble to the proposed rule, EPA a ttempts to justify its proposed 2012 compliance deadline in part by asser ting that it is coordinated with th e attainment deadline for the 8-hour ozone NAAQS. In doing so, EPA focuses on the June 2013 maximum deadline for areas classified as “serious” nonattainment for 8-hour ozone, but acknowledges that “[areas] that have not yet attained the [8-hour ozone] standard ha ve maximum attainment dates ranging from 2010 . . . to 2018.” 75 Fed. Reg. at 45301/1. EPA also relies heavily on the statement in CAA section 172(a)(2)(A) that the attainment date for nonatta inment areas “shall be the date by which attainment can be achieved as expeditiously as practicable” to justif y the proposed 2012 and 2014 compliance deadlines. See, e.g. , id. at 45300/2 (“EPA chose these dates to coordinate with the NAAQS attainment deadlines and to assure th at reductions are made as expeditiously as practicable”); id. at 45300/3 (“EPA believes that [the 2014] deadline is as expeditious as practicable for the installation of th e controls needed for compliance”); id. at 45301/2 (in addition to being coordinated with the 2013 maximum attainment deadline for serious ozone nonattainment areas, the 2012 deadline “is also consis tent with the requirement that states attain the NAAQS as expeditiously as pract icable”). This requirement, th at attainment be achieved as expeditiously as practicable, must be read in the context of the remainder of the Act. It does not give EPA the authority to impose a FIP before allowing states the opportunity to develop and submit SIPs. Neither the CAA nor the court’s opinion in North Carolina v. EPA requires EPA to accelerate the PTR’s compliance da tes to the extent proposed.17 EPA should not adopt the 2012 compliance dead line in the Proposed Transport Rule and should not in any event consider an y compliance date earlier than 2015. 15 In any event, if EPA promulgates a Transport Rule that, like the propo sed rule, includes requirements more stringent than CAIR, the compliance deadline must reflect the degree of stri ngency of those requirements. UARG is not alone in its con cern regarding the initial comp liance date. Last year, for example, the Lake Michigan Air Directors C onsortium (“LADCO”) strongly recommended that any CAIR replacement rule include an initia l compliance date no earlier than 2017 for any significant additional emission reduction requirements. See Letter from LADCO to Administrator Jackson (Sept. 10, 2009) (“LADC O Letter”) at 1. LADCO explained in its recommendations to EPA that it had conducted a state-by-state an alysis that indicated that installation of significant new NOx and SO 2 controls -- specificall y, installation of selective catalytic reduction systems (“ SCRs”) and flue gas desulfur ization systems (“FGDs” or “scrubbers”) -- would not be possibl e in LADCO states before 2017. Id. at 1, attachment at 4-
5. 16 Moreover, EPA ignores the fact that many electric generating companies are not in a position to undertake fuel switching in the near term because of binding fuel contracts. Many electric generating companies may also face cap ital-access or other constraints that would prevent them from undertaking emission control projects, except perhaps at prohibitively high

15 Nothing in these comments should be cons trued as suggesting th at a compliance date as early as 2015 is necessarily a ppropriate or could be justified.

16 According to LADCO, a fundamental assump tion for this state-by-state analysis was a July 2012 start date for the planning, engineer ing, and construction of any new NOx or SO 2 controls, reflecting a January 2011 promulgation date for the final Transport Rule and another 18 months for adoption of SIPs. See id. at 1, attachment at 4. T hus, LADCO properly recognized that a substantial amount of time would be necessary after promulgation of EPA’s final rule for states to develop SIPs and s ubmit them to EPA for approval.18 interest rates, in the near term. In additi on, electric generating companies have fiduciary obligations that prevent them fr om making commitments to capita l projects while the nature and scope of emission reductions remain uncertain. As described above in section III.A, the scope of emission reductions that will ultimately be requir ed under the Transport Rule is far from certain. Despite EPA’s suggestions to the contrary, promulgation of compliance dates later than those that EPA proposes would not result in incr eased emissions. CAIR could remain in place and would continue to maintain a strong and effective program of emission reductions pending the initial compliance deadline fo r the Transport Rule. In fact , electric generating companies will continue to have an obligation to achieve CAIR emission reduction requirements, including the phase II requirements, pending imple mentation of the Transport Rule. UARG further notes that it would be possi ble for EPA to encourage early emission reductions beginning in 2012 under the proposed rule even if the in itial binding compliance date under the rule was not until some years later. One possible approach would be to set “shadow” allowance allocations, using the be st data available, for 2012 and each subsequent year until the new program begins. Then, during the peri od leading up to the new program’s initial compliance year, EPA (or, more properly, a st ate) could credit s ources with additional allowances corresponding to the number of tons they emitted below their shadow allowance allocation levels in those years, with those allo wances eligible to be banked and used beginning in the first compliance year. The ability to ea rn allowances -- usable once the new program begins -- for early reductions would give sources a meani ngful incentive to reduce their emissions prior to the start of the program, while allowing them the time they need to make the adjustments necessary for compliance, and afford ing states sufficient time to develop and submit SIPs consistent with the Act.19 In sum, the fact that EPA’s proposal to set an initial compliance deadline of January 1, 2012, is so fraught with difficulty and uncertainty is a stark illustration of the ill-advised nature of this attempt to force implementation of su ch a complex and demanding rule in only six months. EPA should take the time necessary to correct the many errors in the proposed rule, as described in these comments, and allow adequate time for states to develop SIPs and for sources to make the adjustments necessary to comply with the rule, rather than rushing to implementation as it proposes to do.
IV. The Proposed Transport Rule Would Unlawf ully Supplant the Role of States Under the Act. A. EPA Has No Authority To Promulgate a FIP To Replace CAIR. EPA unabashedly proposes the Transport Rule as a FIP rule. Indeed, promulgation and implementation of the Transport Rule pursuant to the schedule that EP A proposes would make it nearly impossible for states to develop, submit, a nd receive EPA approval of SIPs in time to use them for implementation of the first phase of th e program. EPA’s assertion that promulgation of FIPs “would in no way affect the right of states to submit . . . a SIP that replaces the federal requirements of the FIP with state requirement s,” 75 Fed. Reg. at 45342/2, misses the point. The opportunity to replace federal require ments with a state plan at some point in the future does not satisfy the requirement that EPA allow the opportunity for states to develop their own plans, at the outset of the program, to comply with the Tr ansport Rule. EPA’s pr oposal would effectively bypass the states, at least with respect to the fi rst phase of the program. This is unsupported by anything in the proposed rule a nd is contrary to the Act. The CAA contemplates that states must be given a meaningful opportunity to develop SIPs and to submit them to EPA for review a nd approval before implementation of a new or revised NAAQS. CAA § 110(a)(1). See also CAA § 101(a)(3) (“air pollution control at its20 source is the primary responsibility of States and local governments”); CAA § 107(a) (“Each State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State by submitting an impl ementation plan for such State which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained within each air qua lity control region in su ch State”). The CAA provides that EPA may promulga te a FIP within two years after the Administrator (i) finds that a state has failed to submit a SIP or has submitted a SIP that does not satisfy the minimum criteria set forth in section 110 of the Act, or (ii) disapproves a SIP in whole or in part, unless the state has corrected the deficiency and the Administra tor has approved the SIP. CAA § 110(c)(1). With respect to interstate air pollu tion, section 110(a)(2) pr ovides that each state shall, in the first instance, submit a SIP to EPA that “contain[s] adequate provisions” prohibiting the emissions proscribed by section 110(a )(2)(D)(i). And section 110(k)(5 ) of the Act states that: Whenever the Administrator finds that the [SIP] for any area is substantially inadequate to attain or maintain the relevant [NAAQS], to mitigate adequately the inte rstate pollutant transport described in [section 176A or section 184 of the Act], or to otherwise comply with any requirement of [the Act], the Administra tor shall require the State to revise the plan as necessary to correct su ch inadequacies. The Administrator shall notify the State of the inade quacies, and may establish reasonable deadlines . . . for the submission of such plan revisions. CAA § 110(k)(5) (emphasis added). Although EPA undoubtedly has a role in impl ementation of NAAQS, including interstate transport requirements, that role is plainly “secondary.” Train v. Natural Res. Def. Council , 421 U.S. 60, 79 (1975). The D.C. Circuit has interpreted the “partnership between EPA and the states for the attainment and maintenance of nationa l air quality goals,” as se t forth in the Act, as follows: “The states are responsible in the first instance for meeting the NAAQS through statedesigned plans that provide for attainment, ma intenance and enforcement of the NAAQS.”21 Natural Res. Def. Council v. Browner , 57 F.3d 1122, 1123 (D.C. Cir. 1995). The court noted further that the Act’s SIP provisi ons give states “authority to ma ke the many sensitive technical and political choices that a pollu tion control regime demands.” Id. at 1124. Here, the authority of states to develop SIPs and submit them to EPA for approval would allow the states to determine, based on state-specific concerns and th e specialized knowledge of state officials, how best to achieve the emission reductions that may be necessary to satisfy section 110(a)(2)(D) by allocating allowances to sources within the st ate. EPA lacks the knowledge of state-specific conditions that state agencies can bring to b ear in developing implementation plans. For example, within a state, various agencies and regulatory bodies may have input to the process for setting policy for allocating allo wances, to assure not only envi ronmental protection but also effective energy policies and electric reliability. EPA may issue a FIP, “res cind[ing] state authority,” id. , only after a state fails to develop and submit a complete SIP and receive Agency appr oval of it. CAA § 110(c )(1). The Act grants no authority to EPA to promulgate a FIP without first giving the st ates adequate time and a real opportunity to develop and submit SI Ps that reflect each state’s “sen sitive . . . choices” on how to implement section 110 (a)(2)(D)(i)(I). 57 F.3d at 1124. In other words, EPA has no “roving commission” to leapfrog over the SIP process and impose its own choices on states and regulated parties. Michigan v. EPA , 268 F.3d 1075, 1084 (D.C. Cir. 2001). As noted above, it is a bedrock principle that , under the CAA, EPA’s role is a decidedly “secondary” one -- one that requires the Agen cy to give states room and time to act: [EPA] is relegated by the Act to a secondary role in the process of determining and enforcing the sp ecific, source-by-source emission limitations which are necessary if the national standards it has set are to be met. Under [CAA] § 110( a)(2), the Agency is re quired to approve a state plan which provides for the timely a ttainment and subsequent maintenance of ambient air standards, and which also satisfies that section’s other22 general requirements . The Act gives the Agency no authority to question the wisdom of a State’s choices of emi ssion limitations if they are part of a plan which satisfies the standards of § 110(a)(2), and the Agency may devise and promulgate a specific plan of its own only if a State fails to submit an implementation plan which satisfies those standards. § 110(c). Thus, so long as the ultimate eff ect of a State’s choice of emission limitations is compliance with the nati onal standards for ambient air, the State is at liberty to adopt whatev er mix of emission limitations it deems best suited to its pa rticular situation.
Train , 421 U.S. at 79 (emphases added) (footnote omitted); see id . at n.16 (listing exceptions to this principle, where specific CAA provisions authorize EPA to determine emission limitations; none of those provisions apply here ). Indeed, the D.C. Circuit a nd other courts of appeals have recognized repeatedly and consistently the well -established relationship between the federal government and the states with respect to inters tate pollution regulation -- and the limited scope of federal authority. As the D.C. Circuit explained, EPA determines the ends--the standard s of air quality--but Congress has given the states the ini tiative and a broad respons ibility regarding [the] means to achieve those ends thr ough state implementation plans and timetables of compliance . . . . The Clean Air Act is an experiment in federalism, and the EPA may not run roughshod over the procedural prerogatives that the Act has reserved to the states. Virginia v. EPA , 108 F.3d 1397, 1408 (D.C. Cir. 1997) (quoting Bethlehem Steel Corp. v. Gorsuch , 742 F.2d 1028, 1037-38 (7th Cir. 1984)); 17 see also Michigan v. EPA , 213 F.3d 663, 687 (D.C. Cir. 2000) (noting that the validity of the statewide emission budget program that was the central feature of EPA’s NOx SIP Call rule depended on “whether the program constitutes an impermissible source-specific means rather than a permissible end goal”; the court affirmed that rule because it “merely provide[d] the levels to be achieved by state-determined compliance

17 In Virginia , the D.C. Circuit held unlawful an EPA rule designed to reduce regional ozone pollution in the northeastern United States because it required the aff ected states to adopt either California’s vehicle emission program or a more stringent program. The court held that EPA had exceeded its authority under section 110 by mandating the means of compliance with the Act, which is a decision committed to the states. 108 F.3d at 1414-15.23 mechanisms” and allowed states “real choice with regard to the c ontrol measure options available to them to meet the budget requirements” (emphasis added)). The principle that it is the right and responsibility of the states to de velop plans to implement the Act’s requirements could not be more clear. 18 The Proposed Transport Rule makes equally clear, however, that EPA’s proposal would violate this principle. The proposal’s preamble articulates the view that EPA has broad responsibility to determin e exactly what states, and sources in the states, must do to comply with section 110(a)(2)(D)(i)(I). EPA explains th at its proposal “iden tifies emission reduction responsibilities of upwind states, and also propos es enforceable FIPs to achieve the required emissions reductions in each st ate through cost-effective and flex ible requirements for power plants,” and that “[e]ach state w ill have the option of replacing the [FIP with a SIP] to achieve the required amount of emissions reductions from sources selected by the state.” 75 Fed. Reg. at 45212/3. In other words, under EPA’s new appro ach, the states and their sources would be required to comply with the FIP unless and unt il -- after the prolonged period needed for SIP development -- SIPs are in fact developed, s ubmitted, and approved by EPA (if and when EPA decides to approve them). This scheme is plainl y contrary to the terms ofthe Act and the statesfirst principle recognized and enforced by the cour ts. EPA’s passing reference to states’ right to “replace[] the federal requirements of the FIP with state requirements,” 75 Fed. Reg. at 45342/2, is not an acknowledgement of the righ t granted to states in sec tion 110 of the Act. Congress gave the states the right to develop and s ubmit SIPs implementing the Act’s requirements in the

18 EPA acknowledged this principle in its final action on its NOx SIP Call rule. See 63 Fed. Reg. at 57369/1-2 (“Relying on Train v. NRDC . . ., the [D.C. Circuit in] Virginia . . . found that under title I of the CAA, EPA is required to establish the overall air quality standards, but the States are primarily responsible for determini ng the mix of control measures needed to meet those standards and the sources th at must implement controls, as well as the applicable level of control for those sources”).24 first instance , based on state-specific considerations. No amount of expediency can justify violation of the terms of the Ac t and upsetting the balance that Congress struck between federal and state government. As the Supreme Court no ted decades ago, “the Agency may devise and promulgate a specific plan of its own only if a State fails to submit an implementation plan which satisfies [the standa rds of § 110(a)(2)].” Train , 421 U.S. at 79 (emphasis added). EPA claims that its findings regarding the pre-CAIR SIPs, see 75 Fed. Reg. at 45341/3- 45342/2, justify the Agency’s proposal to supplant the role of the states under the Act. EPA’s error is perhaps most starkly rev ealed by this attempt to assign blame to the states for faithfully implementing the underlying section 110(a)(2)(D )(i)(I) rule -- CAIR -- that EPA itself promulgated to guide the states’ implementati on of that CAA provision. In CAIR, EPA took it upon itself, much as it had done in the NOx SIP Call rule, to set broad parameters -- in the form of statewide emission budgets -- for the states’ im plementation of their se ction 110(a)(2)(D)(i)(I) obligations. That EPA rule was later held unlawful through no fault of the states that worked to implement it. Thus, EPA’s justif ication in the proposed rule fo r not allowing states sufficient time to develop new SIPs, and to submit them to EPA for review and approval, before implementation of the program begins is contrary to the Act as construed by the Supreme Court and the D.C. Circuit. In particular, EPA’s position that its 2005 findi ngs that CAIR states had failed to submit SIPs satisfying their section 110(a)(2 )(D)(i)(I) obligati ons for the 1997 PM 2.5 and ozone NAAQS provide a legal basis for the Proposed Transport Rule FIPs, see 75 Fed. Reg. at 45341/3 –25 45342/1, is without merit. 19 EPA attempts to justify this conclusion by explaining that, under
CAIR: EPA concluded that the states in the CAIR region would meet their section 110(a)(2)(D)(i) obligatio ns . . . by complying with the CAIR requirements. Consequently, states within the CA IR region did not need to submit a separate SIP revision to satisfy th e section 110(a)(2)(D)(i) requirements provided they submitted a SIP revision to satisfy CAIR . . . . [T]he Court granted several petitions for the review of . . . CAIR and found . . . that EPA had not demonstrated that . . . CAIR effectuates the statutory mandate of section 110(a )(2)(D)(i)(I). The EPA approvals of the CAIR SIPs preceded the remand of . . . CAIR . . . . Therefore, because the D.C. Circuit found CAIR and the CAIR FIPs unlawful, EPA’s approval of the provisions of a state’s SIP submittal as addressing the requirements of . . . CAIR could not satisfy the state’s section 110(a)(2)(D )(i)(I) obligation. 75 Fed. Reg. at 45341/3. This explana tion -- that the states are in default of their SIP obligations because the D.C. Circuit held that EPA’s promul gation of CAIR was unlawful -- is nonsensical. The states had no choice but to comply with CA IR or else to default on their EPA-determined SIP obligation. States cannot be penalized, or lose their right under the CAA to decide how to implement a CAIR replacement rule, because they complied with an EPA rule that, as later determined by the D.C. Circuit, violated the Act. The D.C. Circuit has held that, where stat es have been prevente d from meeting their statutory obligations due to the failure of EPA to comply with applicable CAA provisions, the deadline clock for states to s ubmit SIPs should be restarted. See, e.g., Natural Res. Def. Council
v. EPA , 22 F.3d 1125, 1137 (D.C. Cir. 1994) (“we think it would be unfair to penalize states that reasonably relied on and complied with the EPA’s [re gulatory decision] . . . . [W]e direct that the sanction clock for . . . SIPs start, if necessar y, from the time of SIP disapproval in accordance

19 Some states may have already satisfied a ny obligation that they have under section 110(a)(2)(D)(i)(I) for thes e NAAQS and the 2006 PM 2.5 NAAQS. If a state were to have already implemented, under state law, the emission reducti ons necessary to satisf y the requirements of the Transport Rule, there would not even arguabl y be any basis for EPA to impose a FIP on that state.26 with the statutory scheme”); see also Natural Res. Def. Council v. Thomas , 805 F.2d 410, 435 (D.C. Cir. 1986) (holding that EPA was require d to extend the deadline for compliance with automobile NOx emissions standards when EPA wa s a year late in promulgating the standards, and explaining that, “[a]lthough fully cognizant of the frustration the drafters would have felt, could they have foreseen the course of events, we nonetheless find that th ey enacted a four year leadtime requirement and we have no alternativ e but to enforce it, unless or until Congress decrees otherwise”). Thus, the th ree-year deadline for CAA secti on 110(a)(2)(D)(i)(I) interstate transport SIP submissions for the 1997 NAAQS should be restarted due to EPA’s unlawful adoption of CAIR, and should begin to run upon EPA’s promulgation of a valid final rule replacing CAIR. Likewise, EPA’s explanation that, with respect to the 2006 24-hour PM 2.5 NAAQS, it will finalize FIPs for states that have not s ubmitted SIPs and those for which EPA finds the previously-submitted SIPs to be incomple te or inadequate, 75 Fed. Reg. at 45342/2, 20 lacks merit and is contradicted by EPA’s own underlying justif ication for proposing the Transport Rule. In the proposed rule (as in CAIR), EPA plainly takes the position that it has th e authority, if not the obligation, to set the overall terms for states’ implementation of secti on 110(a)(2)(D)(i)(I) with respect to any new or revised NAAQS. Given this circumstance, therefore, the affected states’ section 110(a)(2)(D)(i)(I) obligati on with respect to the 2006 24-hour PM 2.5 NAAQS should be deemed to begin to run only upon EPA’s promulgati on of a valid final rule setting guidelines (in the form of statewide emi ssion budgets) for the states ( e.g. , a final CAIR replacement rule that is consistent with the CAA).

20 See 75 Fed. Reg. 32673 (June 9, 2010) (finding that certain states had failed to submit SIPs satisfying CAA § 110(a)(2)(D)(i)( I) with respect to the 2006 24-hour PM 2.5 NAAQS).27 B. EPA Lacks Authority To Impose Any Un it-Specific Emission Rate Limits -- Such as the Limits in the Direct Cont rol Remedy Option -- Under Section 110(a)(2)(D)(i)(I). With respect to EPA’s Direct Control Re medy Option, the second alternative option on which EPA requests comment in the Proposed Tr ansport Rule, EPA explains that it would regulate individual units directly by assigning emission rate limits to individual units. 75 Fed. Reg. at 45330/1. As discussed above, EPA is without authority to dictate how a state implements section 110(a)(2)(D)(i)(I). As LADCO aptly observed in 2009 in its recommendations to EPA, “unit-specific perfor mance standards go beyond the requirements of section 110 [of the Act] and the scope of th e CAIR replacement rule.” LADCO Letter, attachment at 5. Indeed, all su ch matters are reserved to the states in the first instance. See, e.g., Michigan , 213 F.3d at 686 (“section 110 left to the st ates ‘the power to [initially] determine
which sources would be burdened by regulation and to what extent .’”) (quoting Union Elec. Co.
v. EPA , 427 U.S. 246, 269 (1976)) (alterati on and emphases in original); Virginia , 108 F.3d at 1408 (same). Consistent with those cases, EP A at most can determine what overall emission tonnage level a state must achieve; it may not im pose any unit-specific rules or requirements.
V. The January 2012 and January 2014 Compliance Deadlines Set Forth in the Proposed Transport Rule Are Unreasonable and Unrealistic. In materials prepared to expl ain its Proposed Transport Rule, 21 EPA made the following assumptions about how low SO 2 and NOx emission levels from EG Us would be as a result of (a) the implementation of CAIR and other on-the-bo oks regulations, and (b) the implementation of the Proposed Transport Rule:

21 This table is based on a table included in EPA’s “Overview Presentation 7/26/10,” at slide 33, available at http://www.epa.gov/airquality/transport/a ctions.html. A table with the same emission numbers appears at 75 Fed. Reg. at 45217 (Table III.A-4).28 Table V-1 2005 2012 2014
Actual CAIR Transport Rule CAIR Transport Rule SO 2 (Million Tons) 9.5 5.1 4.1 4.6 3.3 NOx Annual 2.9 1.7 1.6 1.7 1.6 (Million

Tons) Ozone Season 1.0 0.8 0.7 0.8 0.7

Table V-1 demonstrates that EPA expects its PTR to require substantial additional EGU emission reductions beyond those that have b een (or would be) achieved through implementation of CAIR. Despite how much EPA expects its PTR to accomplish in terms of achieving additional emission reductions, however, EPA proposes to give affected s ources very little time to achieve those additional reductions. Specifically, EPA assumes that affected EGUs will be able to reduce their SO 2 emissions from 5.1 million tons per year to 4.1 million tons per year between mid-2011 (when EPA expects to take final action on the PTR 22 ) and January 1, 2012. This reduction, says EPA, can be

22 In presenting the schedule that affected source owners would face in making the additional emission reductions that the final Transport Rule w ill impose, EPA implies throughout the PTR preamble that the appropriate time for source owners to initiate work on any emission controls that are needed to meet the rule’s requi rements is when the Transport Rule is finalized. For example, at 75 Fed. Reg. at 45273/1, EPA ma kes “mid-2011 (when the Agency anticipates finalizing this rule)” the start of the time pe riod in which source owners are to design and construct additional FGD and SCR systems at th eir plants. EPA is correct in taking this approach. It would be entirely in appropriate for EPA either to requi re affected source owners to initiate serious work on additional control syst ems, or to assume that source owners will voluntarily start such efforts, befo re the Transport Rule is final. Indeed, it would be imprudent for regulated sources, and inconsistent with fi duciary obligations for any affected electric generator, to start making in th e near term any major investment s in the design and construction of controls that may or may not be needed de pending on the terms of the final Transport Rule and the terms of other emission control rules th at are scheduled to be published by EPA in the near future and that could affect the control options faced by power plant owners. This is particularly so given the uncertainty as to th e outcome of the present rulemaking that EPA has29 accomplished if affected companies (a) just comp lete the installations of FGD units that are already underway, and (b) supplement the emissi on reductions from those controls by switching some of their units to burn ing lower sulfur fuels. See 75 Fed. Reg. at 45273/2. Then, relying in large part on information from a March 2005 study, 23 EPA takes pieces of information from retrofit experiences at two power st ations and uses those scant data to conclude that it is possible for owners of EGUs to reduce their emissions even further (down to 3.3 million tons annually) by January 1, 2014, through the installation of additional FGD units, which -- EPA claims -- can be designed, permitted, and constructed in just 27 months. Id. at 45273/1. Similarly, EPA assumes power plant owners will be able to reduce their EGUs’ annual and seasonal NOx emissions by substantial am ounts by January 1, 2012, by completing alreadyin-the-pipeline projects to install SCR reactor s and by constructing more LNB systems that -- according to EPA -- can be installed in the few months between the time that the PTR is scheduled to be finalized in mid-2011 and January 1, 2012. And if any additional NOx reductions are needed (although EPA’s projections as summarized in Table V-1 above suggest that no such additional NOx reductions will be needed), then affected electric generating companies can install additional SCR units by January 1, 2014, because -- according to EPA (again relying on its 2005 Report) -- it takes only “approximately 21 months” to design, permit, and construct SCR units. Id. at 45273/1. As discussed in greater detail in other porti ons of these comments and in the comments being filed by indivi dual UARG members, EP A has substantially over estimated the number of created by publishing the NODA and indicating that the em ission budgets and allowance allocations in the final Transport Rule could be very different from those that EPA has proposed.

23 EPA, “Boilermaker Labor Analysis and Installation Timing” (March 2005), available at

www.epa.gov/interstateairquality/pdfs/finalt ech05.pdf (hereinafter “2005 EPA Report” or “2005 Report”).30 FGD and SCR installations that are now under construction and can be operational by January 1, 2012. Therefore, the Agency has greatly under estimated the number of FGD and SCR installations that affected u tilities would have to undertake and complete between January 1. 2012, and January 1, 2014, to meet the PTR’s requ irements. Even worse than this, though, EPA has vastly underestimated the amount of time that it takes utilities to desi gn, permit, construct, and start up new FGD and SCR units. It will ta ke longer than 30 months -- in some cases significantly longer than 30 months -- for companies to retrofit FGD and SCR units at existing EGUs. For all of these reasons, it will not be possible for affected EGUs to achieve the substantial SO 2 and NOx emission reductions that -- unde r the terms of the PTR -- must be achieved by that rule’s January 2012 and January 2014 deadlines. In light of this, EPA should decide not to ca ll for the steep additional emission reductions demanded by the PTR because, as discussed elsewhere in these comments, such additional reductions are not needed to reduce significant re gional contributions to downwind nonattainment and interference with maintenance. In the alternative, EPA should extend the PTR’s emission reduction deadlin es by at least a two-year period beyond the proposed 2014 compliance date (plus an additional interval of ti me that reflects (i) any additional time that EPA takes to complete this rulemaking beyond mid-2011 and (ii) the reasonable period of time needed by states to implement emission budgets through SI P revisions after final promulgation of EPA’s rule). The following subsections of this pa rt of UARG’s comments pr ovide more detailed information on the unreasonableness of the em ission reduction requirements that EPA has proposed. Section V.A provides an overview of the many steps that power plant owners must follow in order to retrofit their power plants wi th control equipment like FGD and SCR units. A more detailed discussion of these steps is provided in a separate report, wh ich is attached hereto31 as Attachment I, and is incorporated by refere nce herein: Cichanowicz, J.E., “Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfur ization (FGD) Process Equipment” (Oct. 1, 2010) (hereinafter “I mplementation Schedules Report”). The Implementation Schedules Report was prepared by J. Edward Cichanowicz, who has been involved in -- and has first-ha nd knowledge of the challenges th at can be posed by -- the design, permitting, and construction of FGD and SCR retr ofits at many power plants throughout the United States. Next, section V.B of these comm ents directly addresses the few examples and arguments that EPA has made in support of its highly abbreviated compliance deadlines. Then sections V.C and V.D of these comments provide a broad range of more current examples ofFGD and SCR retrofits, respectively. These examples demonstrate the complexity and timeconsuming nature of the retrofit installation processes at most si tes. EPA’s failure to understand this has led the Agency to systematically undere stimate the length of time it now takes to retrofit FGD and SCR systems at power plants. A. Background. EPA places all FGD and SCR installation activi ties into one of essentially three broad overlapping categories: (1) conduc ting an engineering review of the facility and awarding a procurement contract; (2) obtaining a construction permit; and (3) installing the control technology. EPA, “Engineering a nd Economic Factors Affecting the Installation of Control Technologies for Multipoint St rategies” (2002) at 7-8, 20, available at www.epa.gov/clearskies/pdfs/multi102902.pdf (hereinafter “2002 EPA Report”). 24 Categorizing the numerous activities involved in installing FGD and SCR systems in such a general way,

24 The 2002 EPA Report also notes that sour ce owners must obtain an operating permit for new control equipment but does not suggest that the process of applying for and obtaining such a permit will add months to the overall pr ocess of getting SCR and FGD equipment ready to operate. This step can in f act add many months to the timelin e for pollution control retrofits.32 however, tends to mask the overall complexity of the numerous steps that electric generating companies must actually follow in order to de sign, permit, and construct FGD and SCR systems at their power stations. The following is a more detailed discussion of all the steps that power plant owners typically take when they retrofit F GD and SCR systems at their stations.
1. Step One Requires More Than Conducting an Engineering Review. EPA makes the first step of the process seem simple and straightforward: conduct an engineering review. And EPA then claims that step can be completed in no more than four months. In fact, as explaine d in the Implementation Schedules Report and in the comments of individual UARG members, EPA’s “first step” is actually quite a few steps, including (1) doing design work extensive enough to allow the preparat ion of detailed specif ications concerning the actual control equipment to be installed, the e quipment’s control efficiency, potential byproduct species, and project capital a nd operating costs; (2) identifyi ng qualified control equipment vendors and qualified contractors fo r project construction; (3) solic iting and reviewing bids and then selecting vendors and cont ractors; and (4) ne gotiating contract terms and issuing the requisite contracts. There is no basis for EPA’s suggestion that a ll these activities can be completed in four months or less even at sites with few complications or in situations where companies are able to develop system-wide designs fo r parts of the installations. 25 The Implementation Schedules Report cites many reasons why this part of the process takes much longer than four months, including (but not limited to) the existence of unusual spatial limita tions or related challenges at

25 The Implementation Schedules Report (i n section 2.2.1) describes how several companies have used system engineering approach es to reduce their engi neering timelines to a year or just under a year -- stil l far longer than EPA’s suggested four-month schedule. And not all plant owners can use system-wide engineering approaches in any event. Id.33 a particular site ( e.g. , little room to maneuver during constr uction activities or physical features at the site that require more-extensive-than-norma l activities to secure a place to put physically large structures like the SO 2 absorber towers that are part of FGD systems); the possibility that a source owner could use new fuel sources (particul arly for FGD installations, which may make possible the burning of coals with higher sulfur content than have historically been used at a station); and the existence of ot her unusual site conditions -- such as soil characteristics, the presence of underground utilities, and available wa ter -- that will influence the selection of the precise equipment to be installed. Also wort h noting is that engineering and design work becomes more complicated when companies try to design FGD and SCR systems that will not only work immediately upon start-up but also will be compatible with additional control systems that might later be installed at the same site in response to fu ture regulatory programs requiring reductions in emissions of other pollutants ( e.g. , mercury, particulate matter, and acid mist). At a substantial percentage of affected sites -- includi ng where FGD or SCR systems have not previously been installe d because of site-specific complexities -- the need to consider and address these factors means that it will t ypically take 6 to 12 months to complete the engineering step of FGD and SCR installati ons. As explained in section 2.2.1 of the Implementation Schedules Report, taking 6 to 12 months (or longer) on this step is a prudent way to minimize risk and avoid cost overruns. Once engineering and process design work is done -- and before actual construction can begin -- it is also necessary for plant owners to identify a number of qualified bidders (seeking multiple qualified bidders allows plant owners to take advantage of the competitive forces that can reduce the price of a project) ; solicit and review bids and th en select the winning bids (a detailed process that, among other things, requires plant owners to host bidder meetings and site34 inspections as well as to review all submittals in detail); and negotiate final contracts (which can take considerable time, particularly where a pl ant owner and contractor have not previously worked together or if there are to be non-standard terms in the cont ract). As set out in sections 2.2.2 through 2.2.4 of the Implementation Schedules Re port, it can take another 6 to 12 months to complete these steps. In short, it often takes a much more extensiv e effort to “conduct an engineering review” than the four months suggested in the 2002 EPA Repor t. Indeed, as discussed in more detail in the accompanying Implementation Schedules Re port and the comments of individual UARG members, completing these initial steps typically takes at least 12 months. And it is not unusual -- or unreasonable -- for companies to take even more time at the very beginning of such substantial projects to identify as broad a range of project pitfalls as possible and to try to address them then. Getting things “right” at the outset often means avoiding having to pay for mistakes all the way through the rest of the project.
2. A Construction Permit Is Only One of the Many Authorizations that Affected Plant Owners May Need. Similarly, EPA underestimates the complex ity of its second step: obtaining a construction permit. Rather than merely get ting a single “construction permit” -- which arguably may have been a relatively quick-and-easy pr ocess at the time of the writing of the 2002 EPA Report -- those retrofitting FGD and SCR systems today must a pply for and obtain numerous authorizations before they can undertake cons truction or start operating those new systems, including authorizations and permits that were no t required a decade ago or that did not take as long to get at that time as they do today. Consider, for example, the increased comple xity involved in gett ing a CAA new source review (“NSR”) preconstruction permit to cover “i ncreased emissions” from the installation of35 FGD and SCR systems. Such a pe rmit may be needed because ev en though the operation of FGD and SCR units will significantly reduce emissions of SO 2 and NOx, respectively, the operation of that pollution control equipment may sometimes result in a “collateral increase” in the emission rate of a pollutant other than SO 2 or NOx. Thus, the operation of wet scrubbers and SCR -- while reducing SO 2 and NOx emissions -- may in some cases increase sulfuric acid mist by more than insignificant amounts. Also, operating lo w NOx burners will reduce NOx emissions but has been thought in some cases to increase carbon monoxide emissions. 26 In short, NSR preconstruction permitting requirements can be tr iggered by projects that will result in a significant net emissions increase of one or more “collateral” regulated pollutants. Prior to late 2005, sources that installed control equipment did not thereby trigger the time-consuming NSR preconstruction permitting process because such projects were subject to the pollution control project exclusion (“PCP” ex clusion) in EPA’s NSR rules. In December 2005, a D.C. Circuit decision vacated the PCP exclusion. New York v. EPA , 413 F.3d 3 (D.C. Cir. 2005). As a result, the NSR permitting proce ss may be triggered by a project to install an FGD, SCR, or LNB system if the operation of th at control system may re sult in the increase of a pollutant other than the pollutant being controlle d by the FGD, SCR, or LNB equipment. And an obligation to apply for and obtai n an NSR permit, even if the permit itself does not require any additional emission controls, woul d delay installation of the new control system because of the elaborate and time-consuming procedures associated with NSR permitting. For example, as discussed in section 2.2.5 of the Implementation Schedules Report and comments of UARG members, the process of obtaining an NSR permit before beginning

26 Recent installations of LNBs, in conjuncti on with advanced combustion controls such as overfire air, have not incr eased carbon monoxide emission rates, but an assessment of this issue may still need to be undertaken before work can begin on the installation of an LNB system at a power station.36 construction for FGD or SCR units, even if that pr ocess ultimately amounts to little more than a paper exercise, can add many months to the overall process. A nd if a full-blown NSR proceeding is needed -- perhaps to evaluate emissions of carbon dioxide and other greenhouse gases once the NSR process is scheduled to star t applying to greenhouse ga ses in January 2011 -- that could add a year or more to the process. As also noted in the Implementation Schedules Report, although this was not a problem faced by co mpanies installing pollution control projects in the first part of the last decade (due to th e existence of the PCP ex clusion), it is a problem

now. Also as noted in the Implementation Schedules Report, power plant owners must secure permits to address other environmental conseque nces of operating polluti on control equipment,

e.g. , permits for the treatment and/or storage of byproducts of both wet and semi-dry FGD systems, including the benign byproducts of those systems, such as gypsum. Securing a land use management permit for scrubber byproducts can take longer than four or even five years. See section 3 of the Implementation Schedules Report. Individual electric ge nerating companies also point to other, more site-specific permitting issues that have arisen or are likely to arise when they seek permits to install FGD or SCR systems. For example, some companies report that the operation of pollution control equipment will result in discharges that will trigger the need for revisions to sources’ Clean Water Act permits . Other companies point to the regulatory complications involved in locati ng, constructing, and operating pl ants (and associated pollution control equipment) in urban areas, where they face zoning challenges, restriction on the truck traffic related to such operations, and even height restrictions if equipment is to be located near an airport.37 In addition, unmentioned in the 2002 EPA Report is that many electric utility companies cannot proceed with the installation of new F GD or SCR systems unless and until they receive authorization from their public utility commi ssions to do so. And as described in the Implementation Schedules Report and in comments of individual UARG members, this, too, can be a time-consuming process. There is another “permit-related” point to k eep in mind: source ow ners may not be able to start actual on-site construction of FGD and S CR systems until they have at least some of the above-listed authorizations in hand. In part icular, this is the case where FGD and SCR installations are subject to the requirements of the NSR preconstruction permitting program. The NSR program limits the activities that source owne rs can conduct on-site prior to getting their final NSR permits. Thus, even though it may be possible to take some of the EPA-listed installation steps concurrently, some stages of the process -- including getting some of the needed regulatory approvals -- must be co mpleted before work can begin on subsequent installation steps. And that can easily take many years, making this step alone a major impediment to the completion of FGD and S CR installations in less than 30 months.
3. The Actual Construction of FGD a nd SCR Systems at Existing Sites Will Take Longer than EPA Suggests. EPA suggests that the construction phase of FGD and SCR systems can be accomplished in 20 months and 15 months, respectively. 27 As discussed below and in section 5 of the Implementation Schedules Report, however, EPA reached this conclusion based on its initial review of only a few installations that took place in the 1999-2001 timeframe. This was a time when relatively few installations were being done . (The FGD and SCR installations in that

27 See 2002 EPA Report, at A-2 (Exhibit A-1, indicating 20 months for engineering, fabrication, delivery, and pre- hookup of FGD systems) and A- 4 (Exhibit A-3, indicating 15 months for engineering, fabrication, delivery, and pre-hookup of SCR systems).38 period were applied to only five GW of generation.) Also, th ose installations were largely special cases, i.e. , where shortcuts were taken in steps 1 and 2 and where there was an abundant labor force available to work on and oversee the construction of these systems. Now, 10 years later -- when scores of project s are underway simultaneously -- su ch shortcuts are not available or are not prudent to take. Also, with so many installations underway at the same time, there is no longer an oversupply of skilled labor to work on and oversee each project. EPA’s projected schedules also fail to take into account the site-s pecific complications that companies face at power stations. The earli est installations may have been at sites with sufficient space and access that construction coul d proceed in a straightforward way, without interfering with other pl ant operations. Today’s installations are typically more challenging: they are at sites that were not retrofit in the first or second roun ds of such activities because of the challenges they posed. Specific examples of the challenges faced by power plant owners are summarized below and are also presented in the Implementation Schedules Report and in comments of UARG members. These real-world examples -- recent and numerous -- demonstrate that on average, actual construction schedules are likely to be cl oser to approximately two years for SCR systems (rather than the 15 months suggested by EPA) and three years (not 20 months) for FGD systems. And where there are greater complications at a site, construction schedules will be longer, perhaps much longer.
B. EPA Relies Upon Incomplete and Outdat ed Information in Concluding that FGD and SCR Retrofits Can Be Installed in a Total of Less than 30 Months. As discussed below and in section 5 of th e Implementation Schedules Report, the sole support for EPA’s belief that FGD and SCR installati ons can be completed in a total of less than 30 months appears to be partial information from work at a few installations that do not reflect39 the variety of conditions one can expect to find at all the sites now bei ng evaluated for control equipment retrofits. The implementation schedu les presented in the Implementation Schedules Report (and discussed below) demonstrate that each site is unique and each site presents its own retrofit challenges. Also, the examples cited by EPA took place in the 1999-2001 timeframe, when (a) relatively few installations were bei ng done (the SCR and FGD installations in that period were applied to only five GW of generation); (b) it was possible to take shortcuts in engineering, procurement, and permitting; and (c )an abundant labor force was available to work on and oversee the construction of these systems. Finally, the projects cited by EPA in support of its short installation deadlines may be incomplete. Additi onal information suggests that, in fact, some of the projects cited by EPA took longer to complete than suggested by EPA. All of these factors were at play in the case of the Cent ralia FGD project, which was completed in November 2001. Although EPA claims that the installation was completed in only 24 months, information in the public domain indicates that it took a total of almost three years to do all the work to install the FGD system for Unit 1 at Centralia, and it to ok a total of 48 months to complete work on the second Centralia unit. In addition, Centralia’s situation may be considered atypical, because the contract for th e engineering and construc tion work at Centralia was part of a unique “partnering” agreement between the owners of Centralia and the contractor. As noted in the Implementation Schedules Re port, this type of relationship can speed subcontracting and procurement act ivities, but it can also require significant upfr ont negotiations and arrangements, and there can be pitfalls to an y approach that does not set aside adequate time prior to the start of construction to ensure that the project design and engineering are done right. Similarly, the installation of Tampa Electri c Company’s FGD systems on Big Bend Units 1 and 2 -- also an early generation project -- ap pears to have taken more than 27 months to40 complete. Information in the public domain i ndicates that the 27-mont h schedule cited by EPA does not take into account that Tampa El ectric took an additional 15 months before commencement of the installation work to apply for project permits and to conduct preliminary cost assessments and prepare the FGD procurement sp ecification. This all i ndicates that the total amount of time needed to design, permit, and construct the FGD system was closer to a 42- month schedule than to a 27-month schedule. In addition, it was possibl e for Tampa Electric to accelerate the installation schedule at Big Bend by building upon the FGD installations that were already located at the site and in use at Bi g Bend Units 3 and 4. The reagent receiving and processing equipment and dewatering apparatus for the FGD equipment on Units 3 and 4 could – with some limited modification – be used in the new FGD installations at Units 1 and 2. Also, the land use permit for solid byproduct manageme nt already existed at Big Bend and likely received less scrutiny, which is very different from the situation faced today by those seeking permits for new, “greenfield” byproduct management sites. There is even less information available c oncerning the SCR installations at Reliant Energy’s (now NRG’s) Keystone station in Pennsylvania an d the AES Kintigh (previously Somerset) station in New York. These are the pr ojects that EPA claims were completed in a total of approximately 21 months. Even if t hose projects did take less than 30 months to complete (and it is not clear that th ey did), there is nothing to sugge st that they are typical of the construction challenges faced by those now undertaki ng SCR retrofits. For example, there is no evidence that the Kintigh project was competitiv ely bid, and the contractor may have been selected because it had provided the boiler and plant ancillary components. This “nontraditional” approach to selecting a contractor did not entail the open, competitive bid process generally mandated for an investor-owned util ity or public agency. Also, the non-traditional41 Kintigh facility approach generally does not make sense for the much more complicated installations that companies now face. More complex projects require more effort to be taken up-front in the planning process -- before actual constr uction begins -- in order to minimize problems on the back end. Further, as noted in the Implementation Schedules Report, those involved in the Kintigh project faced far fewe r regulatory obstacles 10 years ago than plant owners face today. In short, the scant amount of data that EPA has offered in support of its highly accelerated installation deadlines is far outweighed by the vast amount of recent information to the contrary. This information is presented in the Implementation Schedules Report and in the comments submitted by individual UARG members. An overview of some of that information is presented below. C. FGD Installations: Real-World E xamples Demonstrate that EPA Has Substantially Underestimated How Long It Typically Takes To Retrofit FGD Systems at Power Plants. A broad range of recent FGD retrofits is de scribed in section 3 of the Implementation Schedules Report. Specifically, the Implementa tion Schedules Report presents information on a variety of single- and multiple-FGD retrofits, including those installations at Alabama Power Company’s Barry Unit 5 (which took 53 months); the retrofit of an FGD system at Georgia Power Company’s Hammond facility (which took 40 m onths); the retrofit of an FGD system at American Electric Power’s (“AEP” ) Mountaineer facility (which took 42 months to complete); the installation of FGD at Salt River Project’ s Coronado Unit 2 (which took 44 months even though the plant owner was willing to pay additional local agency fees and assign contactors to expedite the permitting process and accelerate revi ew); the retrofit of tw o FGD units at Duke Energy Company’s Belews Creek Units 1 and 2 (whi ch took a total of 49 m onths: 12 months of project work and 37 months of construction for th e first unit to be operabl e); the installation of42 FGD systems at Duke Energy’s Cayuga Units 1 and 2 (54 months: 9 months of project work and 45 months of construction); and the installati on of three or more FGD systems at Allegheny Energy’s Hatfield’s Ferry facility (45 months), First Energy’s Sa mmis facility (56 months), and Alabama Power’s Gorgas facility (61 months). These examples demonstrate that in the most straightforward, uncomplicated situations, it may take as little as a total of 40 months to co mplete an FGD installati on, but that at the most challenging sites, it can take more than 60 months ( i.e. , five years). Typica lly, it takes a total of at least approximately 48 months to complete the retrofit of an FGD installation, but in many cases significantly more time than that is needed. The case of Georgia Power’s Plant Hammond in stallation is the example of a recent FGD installation that was completed in only 40 months. The single F GD module for the four boilers at Hammond could be installed on an abbreviated schedule due to several factors. First, the plant’s owner was able to apply at Hammond th e process and absorber design developed for other sites, which shortened the period for proc uring contracts. Second, certain design tasks were accelerated as they were le veraged on previous, similar applic ations. Third, as described in greater detail in comments being filed separa tely by Southern Compa ny, ample and accessible space was available to allow simultaneous construc tion of equipment such as the absorber and reagent preparation facilities. In contrast, the insta llation of a single FGD unit each at Alabama Power’s Barry Unit 5 and Gaston Unit 5 took a tota l of 53 months and 64 m onths, respectively. The complications -- and length of installation schedules -- increase with the construction of multiple FGD modules at a plant site. A notable case is that of Sammis Units 1-7. Figure 3-2 in the Implementation Schedules Report depicts the Sammis site layout, adjacent to the Ohio River, with Ohio State Route 7 located below the el ectrostatic precipitators and fabric filters built43 in the 1980s for these units, and three 800-MW FGD absorber towers. Flue gas from the entire station – all 7 units – is treated by these thr ee absorber towers. (SCR process equipment is located on Units 6 and 7.) The extremely tight si te -- bounded by the Ohio River and a rail line – constrained construction activit ies and contributed to an in stallation time of 56 months. The retrofit of FGD at Alabama Power’s Gorg as Units 8-10 is another example of the hurdles faced by source owners tryi ng to install FGD systems at existing plant sites. Several reasons contributed to the fact that it took over five years to comple te the work at Gorgas. First, the Gorgas retrofit was the owner’s initial FGD project, which meant th at significant time was required to do project engineeri ng and to negotiate contracts. S econd, the site required extensive modifications, including literally moving a small mountain to crea te adequate space for the FGD equipment. The limit on space forced the new stack to be constructed sequentially, and not in parallel with other equipment. Also, at the Go rgas site, it was necessary to make significant improvements to the plant’s flue gas handling sy stem in conjunction with the control equipment retrofit. All these factors (and ot hers) contributed to the fact that it took a total of 61 months to complete the work at Gorgas The Implementation Schedules Report also notes that retrofit schedul es may be affected by whether the plant owner operates a large fleet of plants or only a few units. Owners in the latter category -- without the market power of, for example, large, multi-state operators -- are likely to have less leverage over suppliers and can expect longer installation times. The relatively small market presence of Dairyland Power Cooperati ve was at least one factor contributing to the 50-month installation schedule for retrofit of a semi-dry FGD unit at a Dairyland facility. The common theme in all these retrofit examples is the extensive number of activities to be conducted within a limited, c onfined space, which requires many phases of the process to be44 conducted sequentially rather than in parallel. This produces FGD retrofit schedules of between 40 months and over 60 months.
D. SCR Installations: Real-World E xamples Demonstrate that EPA Has Substantially Underestimated How Long It Typically Takes To Retrofit SCR Systems at Power Plants. As noted above, relying on a small (and inco mplete) amount of information concerning retrofits that two companies undertook a decade ago, EPA concludes that owners of EGUs can be expected to complete retrofits of SCRs at all power plant sites in only 21 months. The overwhelming amount of available data, however, dem onstrates that it takes an average of a total of 39-40 months to complete such retrofits, and ca n -- at the most challeng ing sites -- take as long as 60 months to retrofit SCR at a power station. The Implementation Schedules Report presents information on a variety of SCR retrofits. Examples of cases in which owners have retrofi tted a single SCR reactor at a site include the work done at Alabama Power’s Barry Unit 5 (50 months) and Gaston Unit 5 (40 months), AEP’s Conesville Unit 4 (42 months), Duke’s Marshall Unit 3 (46 mont hs), Georgia Power’s Hammond Unit 4 (28 months), and Gulf Power’s Crist Unit 7 (42 months). Examples of multiple SCR retrofits at a site include First Energy’s Sammis Plant (where retrofits on Units 6 and 7 required a total of 60 months); Alabama Powe r’s Miller Station (w here retrofits on Units 1 and 2 each took a total of 42 months and retrofits on Units 3 a nd 4 each took a total of 34 months); AEP’s Kyger Creek Plant (where there was a retrofit of five SCR units, with the first operable within 31 months); Progress Energy’s Crysta l River Station (where SCR retr ofits on Units 4 and 5 took 37 months); and Georgia Power’s Scherer station pr oject (which includes work on SCR for Units 1 through 4, and where the SCR system closest to completion is that for Unit 3, which is scheduled to be completed in a total of 50 months).45 As in the case of FGD retrofits, the time it has taken to complete SCR installations has varied greatly due to a number of factors, the mo st important of which is the configuration of the plant site. For example, AEP was able to retrof it five SCR reactors at th e Kyger Creek Station in a period of approximately 31 months because th e units on which the SCR equipment was being retrofit were virtually identical to each other, allowing engineer ing to be expedited. Also, the modest generating capacity (220 MW per unit) did not require large quantitie s of material to be installed or relocated. The use of cranes within the compact site, and small distances over which to transfer materials, also contributed to e xpeditious installation. A lthough the plant site is constrained, the units are small and it was possible to stage the construction in a serial manner. At the other end of the spectrum, however, are th e Sammis and Scherer retrofits, which took (or are taking) more than 50 months to complete because of the complexities of and congestion at those sites. The Implementation Schedules Report also pr esents information on the time it takes to install low NOx burner systems at power plants . LNB systems are less complex than SCR or FGD systems; however, as is the case with F GD and SCR installations, the time it takes to complete an LNB installation will depend on conditi ons at the specific site , including details of the application, the engineering a nd unit preparation work, and the availability of an outage. A key factor in determining the installation schedule is the availability of LNB equipment. The limited number of qualified suppliers, and the sp ecial-purpose fabricati on techniques required, can extend fabrication and delivery times. Als o, there can be complications in the permitting process. At least one multi-state owner is an ticipating a lengthier schedule for installing LNB equipment, due to concerns that have arisen in the permitting of the installations, where local regulatory agencies are questio ning whether lower NOx emissions are inextricably linked to46 higher carbon monoxide emissions. section 4.2 of the Implementation Schedules Report presents schedule information concerning the low NO x burners installed at Salt River Project’s Coronado Unit 1 and Navajo Unit 3, and at units at Miss issippi Power Company’s Plant Daniel. This experience suggests project installations typically take a total of about 18 months -- far longer then the time between EPA’s projected date fo r final action on the PTR and EPA’s proposed compliance deadline of January 1, 2012.
E. Summary and Conclusions. Solid information from individual UARG me mbers and detailed information in the Implementation Schedules Report demonstrate that it now take s longer -- often much longer -- than 21 and 27 months to complete retrofits of SCR and FGD equipment, re spectively. There are many reasons why FGD and SCR installations take as long as they do, including the complicated physical constraints posed by the sites at which th e equipment will be inst alled (retrofits at any “simple” sites have likely already been done); the complexities of the overall permitting/authorization process that plant owners face today; and the high demand now for the skilled labor force needed to undertake these pr ojects. The extensive amount of information presented in these comments and in the attached re port, as well as information in comments from individual UARG members, refu te any EPA claim that FGD and SCR installations can generally be conducted and completed in a total of less than 30 months. There is also no basis for any suggestion th at electric generating companies could cut installation times by 30% to 50% if only they had the will to do so. Such a “field of dreams” approach (something akin to “demand it and it will happen”) does not apply to the construction of FGD and SCR systems. If electric generating companies could build such systems in less than 30 months, they would. For these companies, time is money, and the longer it takes to build a mandated project, the more it will cost. Elec tric generators may not -- and should not --47 undertake FGD and SCR retrofits un til it is clear that such inst allations are required and are prudent and consistent with fiduciary obligati ons to undertake. Once the companies commit to such projects, however, they are highly motivated to complete them quickly in order to minimize

costs. In summary, EPA has greatly underestimated the amount of time that it takes electric generating companies to design, permit, construct, and start up new FGD a nd SCR units. It will take longer than 30 months -- in many cases, considerably longer th an 30 months -- for companies to complete the retrofits of FGD and S CR units at existing EGUs. Thus, it will not be possible for affected EGUs to achieve all the SO 2 and NOx emission reductions that -- under the terms of the PTR -- must be achieved by EPA’s proposed January 2012 and January 2014 deadlines. In light of this, EPA either should decide not to call for the steep additional emission reductions demanded by the PTR -- because such reductions are not, for reasons discussed in these comments and in comments of individual UARG members, necessary to reduce significant regional contributions to downw ind nonattainment and interfer ence with maintenance -- or should extend the PTR’s compliance schedule by at least a two-year period beyond the proposed 2014 compliance date (plus an additional interval of time that reflects (i) any additional time that EPA takes to complete this rulemaking beyond mid-2011 and (ii) the reasonable period of time needed by states to implement emission budgets through SIP revisions af ter final promulgation of EPA’s rule).48 VI. EPA’s Analysis Significantly Understate s the Amount of Electric Generating Capacity that Would Have To Under go FGD and SCR Retrofits in the 2012-2014 Period and the Associated Demands on Resources; Constraints on Labor Resources Make Compliance With the PTR’s Timeline Impossible. As noted above, EPA states in the preamble to the PTR that it “ex pects about 14 GW of FGD and less than 1 GW of SCR capacity to be retrofit for Phase 2 of this rule [ i.e. , by January 1, 2014].” 75 Fed. Reg. at 45273/1. This projecti on omits the very substantial amounts of FGD and SCR retrofits that will be undertaken as part of the baseline when CAIR requirements are included in the baseline (as they should be, for reasons discussed elsewhere in these comments). In addition, because, as discussed in the pr eceding section of these comments, EPA has significantly underestimated the amount of time it takes to in stall these contro ls, a substantial number of retrofit projects that EPA assumes will be accomplished by the beginning of 2012 will in fact not be completed until the critical 2012-2 014 period (while, for the same reason, some of the retrofit projects EPA predicts will be comp leted after January 1, 2012, but before January 1, 2014, will in fact not be completed until after the latter date). According to estimates prepared by UARG’s consultants James Marchetti, J. Edward Cichanowicz, and Michael C. Hein, 28 a total of approximately 25 new GW of installed FGD capacity -- far higher than EPA’s assumed 14 GW -- would be needed to meet the PTR’s 2014 emission reduction requirements. In addition, thei r report projects that a total of about 8.2 new GW of installed SCR capacity would need to be installed by 2014. These numbers include emission control projects that will be needed under the 2014 base case, including CAIR. These 2014 numbers do not include re trofit capacity that would be installed by 2012.

28 J. Marchetti, E. Cichanowicz, and M. He in, “Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule” (Oct. 1, 2010). This report is attached hereto as Attachment II, and is incorporated by reference in these comments.49 Marchetti, et al. , evaluated the likely operational dates for new FGD and SCR projects during this period. They used owner-announced dates where available (as they were for a minority of the projects). For ot her projects, they used an assume d project-start date of the third quarter of 2011 to reflect EPA’s projected date of final promulgation of the PTR, and then assigned implementation schedules for the retrofit installations, applying information derived from the Implementation Schedules Report, as discussed in the previ ous section of these comments. The analysis shows that the majority of the projects could not be completed until well after January 2014; the larges t number of FGD and SCR proj ects are projected to become operational at various dates between early 2015 and mid-2016. This analysis then examined a key resource constraint considered by EPA in the CAIR proceeding, i.e. , the demand for boilermaker labor for re trofit installations. The analysis found that boilermaker demand for FGD and SCR installations can be accommodated if the realistic installation schedules applied from the Impl ementation Schedules Report are assumed. In contrast, if the retrofit projects were someho w otherwise able to be accomplished by 2014, as EPA assumes (a scenario that the Implementation Schedules Report shows is infeasible), then the resulting “logjam” of retrofit projects would requir e an amount of boilermak er hours that is far in excess of the boilermaker labor supply that wa s called on for EGU control retrofits in the 2008- 2010 period. Thus, even if EPA’s proposed comp liance schedule could otherwise be met (and it cannot), there is no basis for concluding that a sufficient supply of skilled labor would be available to do the work nece ssary to meet the schedule. Accordingly, EPA should recognize that under the PTR, the 2012-2014 period could be expected to involve far more FGD and SCR retr ofits than its statement in the PTR preamble would suggest. Given the demands that will be imposed on retrofit resources, such as50 boilermaker labor, due to the c ongestion of control project inst allations during this highly compressed period, requiring the PTR’s 2014 emissi on budgets to be met by accelerating retrofit projects that cannot realistically be projected to be completed by that year would both (1) be inconsistent with documented installation sc hedules (as described in the Implementation Schedules Report and in the previ ous section of these comments) and (2) be infeasible in any event in light of the available labor, and perh aps other resources, needed to accomplish these retrofits.
VII. Many of the Judgments and Policy Decisi ons Underlying the Structure of the Proposed Transport Rule Are Inappropriate and Unjustified. EPA made several important judgments and pol icy decisions in developing the Proposed Transport Rule without explaining adequately th e Agency’s rationale. As discussed below, many of these decisions are inappropriate and mu st be adjusted before EPA proceeds further with this rulemaking.
A. EPA’s Base Case Modeling Should Have Included CAIR. The Proposed Transport Rule fails to account properly for post-2005 emission reductions and air quality improvements resulting from CAIR. See 75 Fed. Reg. at 45233/3. EPA’s decision to assume that CAIR is not in effect for its analysis of the 2012 and 2014 base cases has the effect of greatly overestimating EGU emi ssions during those periods. EPA should have included CAIR in its base case because it re mains binding law pending the promulgation and effective date of a replacement rule. The D.C. Circuit granted EPA’s petition to remand CAIR without vacatur, holding that “notwithstanding the relative flaws of CA IR, allowing CAIR to remain in effect until it is replaced by a ru le consistent with ou r opinion would at least temporarily preserve the environmental values covered by CAIR.” 550 F.3d at 1178. By the terms of the court’s opinion on rehearing, CAIR will be in place until a replacement rule is51 implemented. Thus, there is no time during which neither CAIR nor a replacement rule will be effective. In the proposed rule’s preamble itself, EPA reco gnizes what it could hard ly dispute -- that CAIR has yielded substantial emission reductions. For example, according to the proposed rule, the most recent monitoring available (2006- 2008) “shows significant improvement[]” in PM 2.5 ambient air quality, and “EPA believes that a great deal of the improvement in PM 2.5 annual and 24-hour concentrations in the eastern U.S. can be attributed to EGU SO 2 reductions achieved due to the CAIR.” 75 Fed. Reg. at 45219/3; see also id. at 45220/1-3 (noting that “EPA believes that there would be substantially more nonattainme nt counties for both the annual and 24-hour standards if the CAIR were not in effect,” and crediting a va riety of programs with improved ozone air quality in the years since EPA publishe d CAIR). There can be no dispute that CAIR, together with other programs, has had signi ficant effects in reducing NAAQS design values. Additionally, in both the NOx SIP Call a nd CAIR rulemakings, EPA took account of other regulations in evaluating downwind air quality. See 63 Fed. Reg. at 57377/1 (NOx SIP Call) (EPA’s “analytical approach assumes that downwind areas implement all required controls and receive the benefit of reductions from Federal measures, and yet have a residual nonattainment problem.”); 69 Fed. Reg. at 4581/2- 3 (CAIR proposed rule) (“In modeling the 2010 and 2015 ‘base cases,’ we took into account adopted State and Federal regulations ( e.g. , mobile sources rules, the NOx SIP Call) as well as regulations that have been proposed and that we expect will be promulgated before [CAIR] is finalized.”) In the Proposed Transport Rule, EPA purportedly took into account all other federal rules prom ulgated as of December 2008,52 except for CAIR

. 29 75 Fed. Reg. at 45233/3. It is diffi cult to understand why EPA made the decision to ignore CAIR for purposes of the Proposed Transport Rule. EPA’s brief explanation of why it decided to ignore CAIR in modeling the base case for the proposed rule, which it characte rizes as “a unique situation,” id. at 45233/3, is baffling. EPA acknowledges that “EPA has been directed to replace the CAIR; yet the CAIR remains in place and has led to significant emissions reductions in many states.” Id. at 45233/3. Then, it says that “EPA cannot prejudge at this stage which states will be affected by the rule,” and goes on to note that sources in states that are regulated under CAIR but not under the Transport Rule may increase their emissions once CAIR expires. Id. at 45233/3. Yet there are very few of those states, and the existence of a minority of such stat es hardly justifies whol esale disregard of CAIR reductions. 30 Moreover, EPA has not shown that emi ssion increases in these few states are likely, or indeed that such increases would even be permitted under state law. In any event, many sources located in states that were re gulated under CAIR but are not proposed to be regulated under the Transport Rule have gone to gr eat expense to install c ontrols to comply with CAIR. They are very unlikely to dismantle them or to discontinue use of them to the point that their emissions return to pre-CAIR levels. Finally, PM 2.5 and ozone concentrations have declined substantially in recent years, due not onl y to CAIR but also to a combination of other

29 In addition, EPA has failed to include known local emission reductions in, for example, nonattainment areas. By ignoring the air quality benefits from those controls, EPA overestimates the number of downwind nonattainment and maintenance monitors an d inflates the design values of those monitor sites that are above the NAAQS , thereby overstating the emission transport problem that the Transport Rule is designed to resolve.

30 Compare 70 Fed. Reg. at 25167/1 with 75 Fed. Reg. at 45215/2. With respect to the annual PM 2.5 NAAQS, only Mississippi and Texas we re regulated under CAIR but are not proposed to be regulated under the Transport Ru le. With respect to the 8-hour ozone NAAQS, only Iowa, Massachusetts, Missouri, and Wiscons in were regulated under CAIR but are not proposed to be regulated under the Transport Rule.53 programs, and are expected to continue declining in the future. See EPA’s Trends Report at 1-2. While it may be conceivable that some limited in creases in emission levels could occur due to discontinuation of CAIR requirements in some states , it is far less realistic to assume that CAIR is no longer in effect than to assume that it remains in effect. EPA should recalculate the 2012 and 2014 base cases to take CAIR into account.
B. EPA Should Return to Its “Monitored-Plus-Modeled” Approach. EPA should not have abandoned use of the “m onitored-plus-modeled” approach that it used in CAIR and the NOx SIP Call rule to determine downwind nonattainment areas to be addressed. 31 EPA provides no justification in its pr oposal for its decision to jettison this approach. The monitored-plus-modeled approach is preferable to the approach used in the Proposed Transport Rule because the inclusion of monitored data helps provide a grounding in real-world air quality that is lost in EPA’s novel “modeling- only” approach that relies exclusively on IPM projections. It is by no means clear that IPM is even fit to be used in the manner in which EPA used it in developing the Pr oposed Transport Rule. IPM is a least-cost economic model that operates on a regional scale and is not desi gned to replicate real-world scenarios in specific locations. See section VIII infra for further discussion of IPM. Furthermore, LADCO specifically recommended thatEPA continue to use the “monitored-plusmodeled” approach. LADCO Letter, attachment at 2. Equally important, the use of monitored data for this purpose was never challenged or criticized in North Carolina v. EPA

. If EPA had considered current monitored data, it would have found that many of the areas that it projects, in the Proposed Transport Rule, to be downwind nonattainment areas in

31 See 62 Fed. Reg. 60318, 60324/3-60325/1; 63 Fed. Reg. at 57375/1-2 (explaining and adopting the “monitored-plus-modeled” appr oach in the NOx SIP Call); 69 Fed. Reg. 4566, 4581/1-2; 70 Fed. Reg. at 25174/2 (explaining and adopting for CAIR the “monitored-plusmodeled” approach used in the NOx SIP Call).54 fact currently have air quality that is in attainment of the ozone and/or PM 2.5 NAAQS. For example, nearly 60 percent of the monitoring sites that EPA projects to be in nonattainment areas for the 24-hour PM 2.5 NAAQS in 2012 in fact are in either currently designated attainment areas or areas that have air quality that is in attainment of that NAAQS, according to an EPA determination after notice- and-comment rulemaking. See Attachment III hereto at Table II for details. 32 Likewise, EPA has determined or proposed to determine that approximately 20 percent of the monitoring sites that EPA projects to be in nonattainment areas for the annual PM 2.5 NAAQS and approximately 10 percent of the site s that EPA projects to be in nonattainment areas for the 8-hour ozone NAAQS are in areas that currently have air quality that meets the relevant NAAQS. See id. at Tables I and III respectively for details. 33 Given the prevailing downward trend in ambient concentr ations, it is most unlikely that these areas should be viewed as downwind problem areas. EPA should return to its monitored-plus-mode led approach in this rulemaking, or at a minimum, should explain the basis for its depa rture from that approach, including how its

32 According to EPA’s Greenbook, http://www. epa.gov/oar/oaqps/greenbk/, of the 92 monitoring sites that EPA projects will be in nonattainment areas in 2012 for the 24-hour PM 2.5 NAAQS, 52 are in areas curren tly designated as attainment areas for that NAAQS, and EPA recently issued a final determination that an additional area (Jefferson County, Alabama) with two sites has air quality in attainment of that NAAQS.

33 With respect to the annual PM 2.5 NAAQS, EPA has issued eith er a proposed or final determination that 6 of the 32 sites that EPA pr ojects in the PTR will be in nonattainment areas in 2012 currently are in areas with air quality in atta inment of the NAAQS. With respect to the 8-hour ozone NAAQS, EPA has issued a final dete rmination that Baton Rouge, Louisiana, one of the 11 areas that EPA projects in the PT R will be nonattainment in 2012, currently has air quality in attainment of the NAAQS.55 reasoning has changed and why it believes that current monitored air quality data is not relevant to this rulemaking. 34
C. EPA’s Proposed Air Quality Contribution Threshold Is Flawed. EPA proposes to use an air quality cont ribution threshold base d on a percentage -- specifically, one percent -- of the NAAQS for annual PM 2.5 , 24-hour PM 2.5 , and 8-hour ozone to determine whether an upwind state should be in cluded in the Transport Rule program with respect to each of those NAAQS. See 75 Fed. Reg. at 45237/1-45238/1. EPA explains in the preamble to the proposed rule that it chose to de viate from the approach it used in CAIR with respect to PM 2.5 by using here a two-di git value rather than a single-digit value and “decoupl[ing] the precision of the air quality thresholds [from] the monitoring reporting requirements.” Id. at 45237/3. Although EPA properly proposes to avoid se tting a zero contribution threshold for the current 24-hour PM 2.5 NAAQS, see id. , and to avoid setting a precedent for a 0.1 μ /m 3
contribution threshold if the annual PM 2.5 NAAQS in the future is reduced to some value lower than the current NAAQS but higher than 10 μ /m 3 ( e.g. , 14 μ /m 3 ), see id. , EPA’s proposed approach ignores the limits of the capability of its air quality modeli ng techniques -- and of ambient monitoring -- to meaningfully detect and measure ambient-air contributions at the extremely low levels represented by one percen t of current or possible future NAAQS. For example, the numerical values that result from application of EPA’s one-percent contribution

34 EPA also must consider the results of air quality modeling and other analyses performed for the Midwest Ozone Group (“MOG”) and reported in MOG’s comments filed in this docket, dated October 1, 2010. MOG’s comm ents show, among other things, that existing controls, including CAIR, are projected to resolve most of the downwind PM 2.5 and ozone air quality problems in at least a large section of the PTR domain by no later than 2014. Moreover, MOG’s comments demonstrate that, much as is shown in UARG’s comments, there are substantially fewer existing nona ttainment problems in the PTR domain than EPA’s proposal suggests.56 threshold approach to the current NAAQS -- i.e. , 0.15 μ /m 3 for annual PM 2.5 , 0.35 μ/m 3 for 24- hour PM 2.5 , and 0.8 ppb for 8-hour ozone -- are so low th at they are likely below the detection capability of existing modeling and measurement tool s. For that reason, it is far from clear that these thresholds could be deemed to refl ect a “measurable cont ribution” to downwind nonattainment and maintenance problems, as required by the D.C. Circuit. Michigan v. EPA , 213 F.3d at 684 (“ . . . EPA must first establish that th ere is a measurable [air quality]
contribution. Interstate contributions cannot be assumed out of thin air. ”) (emphasis in original). At a minimum, EPA should provide, in a supplemental notice of proposed rulemaking, a technical justification for these very low threshol ds as representing meaningfully measurable air quality contributions. Equally troubling is EPA’s indication th at it may be planning to use this same percentage-based approach in any future version of the Transport Rule to address possible future NAAQS. See 75 Fed. Reg. at 45237/3 (noting that one of the considerations favoring the onepercent contribution threshold appro ach is that “the approach is r eadily applicable to any current and future NAAQS”). Application of this approa ch to potential future ambient standards that may be even lower than the current NAAQS woul d produce even less meaningful thresholds. It makes no sense for contribution thresholds to change based exclusively on changing NAAQS levels, irrespective of th e capabilities of m odeling and measurement technologies at the time the thresholds are established. Accordingly, UARG objects to EPA’s proposal to use its percenta ge-based air quality contribution threshold approach in the current ru lemaking -- or in any future interstate-transport rulemaking -- in the absence of a ro bust technical justification that the resulting thresholds reflect57 meaningful, and truly measurable, air quality cont ributions, consistent with the D.C. Circuit’s directive in Michigan v. EPA

. D. The Method EPA Used To Determine “Interference With Maintenance” in the Proposed Rule Overestimates Actual Future Design Values. The method that EPA used in the Proposed Transport Rule to identify downwind monitors to be included in its “interference wi th maintenance” analysis overstates actual future design values, probably by a substantial amount. EP A explains in the preamble to the proposed rule that it determined maintenance sites base d on the future-year maximum design values, and nonattainment sites based on future-year five-yea r weighted average annual design values. (Thus, all nonattainment sites we re, in effect, also maintena nce sites because the maximum design value is always greater than or equal to the five-year weighted average.) 75 Fed. Reg. at 45247/2-3, 45249/3, 45252/2-3. By using the future-year maximum PM 2.5 design values as the basis for the “interference with maintenance” anal ysis, EPA fails to take account of the strong nationwide trend toward decreasing design values and improving air quality, which the Agency has said it expects to continue. See EPA’s Trends Report at 1-2. One can only assume that EPA’s expectation is based on expected continui ng declines in emission levels and that the recent improving air quality has been largely dr iven by recent declines in emission levels resulting from controls. This approach had a major effect on the design of the proposed rule. For example, EPA proposed to require certain states (the “group 1 states ”) to meet additional SO 2 emission reduction requirements beginning in 2014, beyond th e reduction requirements for 2012, because of perceived maintenance problems at six spec ific downwind monitors. Southern Company, a58 UARG member, plotted the 98th percenti le design values for 24-hour PM 2.5 from 2003 to 2008 35
based on EPA’s 2006-2008 36 Design Value spreadsheet for 24-hour PM 2.5 , available at http://www.epa.gov/oaqps001/airtrends /pdfs/dv_pm25_2006_2008rev102809.xls. The downward trend in design values at these six monitors is clear:

It is easy to see that basing a determination of a maintenance problem at any one of these six monitors on the future-year maximum PM 2.5 design value would almost inevitably overstate the air quality design value at that monitor and, based on the strong dow nward trend in design values, would most likely result in a false determ ination. There is no reas on to believe that the trend that is apparent in the desi gn values at these six monitors is unusual. In fact, a similar trend

35 Although the three base periods us ed by EPA were 2003-2005, 2004-2006, and 2005- 2007, 75 Fed. Reg. at 45247/2, 45249/2, 45252/2, this plot includes data not only for those years but, for additional context, 2008 as well.

36 The spreadsheet contains design values from 1999-2001 through 2006-2008. See http://www.epa.gov/oaqps001/airtrends/values.html. 25 30 35 40 45 50 55 60 65 70

2003 2004 2005 2006 2007 200824‐HourPM2.5(μgm‐3) 

### 2003
‐ 2008 24
‐ hour PM 2.5 

### For the Six Monitors with EPA ‐ Projected Maintenance Issues in 2014

170311016 Cook IL 180890022 Lake IN 245100040 Baltimore City MD 261630016 Wayne MI 420030064 Allegheny PA 420030093 Allegheny PA59 is likely to exist at most of the downwind mon itors evaluated in the proposed rule. It is especially important for EPA to set forth a ju stifiable methodology for determining maintenance issues since EPA’s proposal in e ffect establishes elimination of all interference with maintenance as the driving factor for the PTR’s emission reduction requirements. Therefore, EPA should revisit its method for identifying downwind main tenance problems, justify its reasoning for choosing a particular method, and re vise its analysis to make it more representative of current and likely future air quality and to take acc ount of the downward trend in design values. One alternative approach that EPA could take to determine maintenance issues would be to remove the trend in the data where air quality is improving over the five-year period, prior to determining the maximum three-year design va lue. Briefly, this method would involve determining the linear fit to the five-year ( i.e. , the 2003-2007) air quality data, calculating the residual values from the difference between the linear fit and the observed values, and then adding the residual values to the av erage of all five years of data (2003-2007 values). The result would be an adjusted five-year time series with no trend, which would have the same average and the same five-year weighted mean design valu e as the original observations. This result would still capture the inter-annua l variability in air quality at sites with improving air quality without biasing the projected “maintenance” va lue upward for areas where emission reductions are already resulting in air quality improve ment, and would better identify sites where maintenance may genuinely be an issue. The plot below shows the effect of applying this methodology to the data at the six m onitors shown in the plot above. 37

37 This plot includes 2008 values for context -- they were not used for adjusting the data.60 As this plot depicts, the downw ard slope at all of these sites has been removed, but the interannual variability remains. Table VII-1 below shows the estimated effect of applying this methodology to the projected 2012 base case design va lues for these six sites. This approach provides a more reasonable estimate of the thres hold that may be necessary for maintenance of attaining air quality, in that it eliminates an inadvertent penalty for having made progressive improvements in air quality through emission re ductions. Furthermore, it provides a better estimate of inter-annual variabil ity that would be due to inte r-annual meteorological and/or emissions variability.61 Table VII-1 2012 Projected Values 5-Year (EPA Method) 5-Year Adjusted (Alternative Method) Receptor Monitor ID Receptor County Receptor State Wtd Mean DV Max DV Wtd Mean DV Max DV 170311016 Cook IL 41.0 44.1 41.0 41.6 180890022 Lake IN 37.3 42.1 37.3 38.4
245100040 Baltimore City MD 36.3 38.3 36.3 36.6 261630016 Wayne MI 40.6 43.0 40.6 41.2 420030064 Allegheny PA 58.8 62.3 58.8 59.0 420030093 Allegheny PA 41.1 46.2 41.1 41.3

E. The Process EPA Used To Classify C ertain States as “Group 1” States Is Inadequately Explained and Misguided. In the Proposed Transport Rule, EPA describes its process for classifying states as “group 1” and “group 2” states for PM 2.5 as follows: EPA used the air quality assessment tool to analyze the impact of requiring all states linked to the downw ind state site with an air quality problem, as well as the downwind stat e, to reduce emissions consistent with the levels discussed for 2012 . . . previously. The air quality assessment tool shows that those 2012 reductions will resolve the nonattainment and maintenance problems for all of the areas to which [certain] states [referred to as group 2 states] are linked . . . . EPA also assessed whether, in 2014, the combina tion of this level of reduction from the group 2 states and the remaining stat es (referred to as group 1 states) continued to result in all downw ind areas—except for Allegheny County, Pennsylvania—fully addressing their nonattainment [and/or] maintenance problems, and determined that it did. 75 Fed. Reg. at 45282/1-2. Conversations be tween UARG members and EPA staff have revealed that, while not untrue, this description is materially incomplete and potentially misleading, especially with respect to the analysis that led to classificatio n of the group 1 states. A representative of Southern Company cont acted EPA’s Clean Air Markets Division on September 3, 2010, and again on September 10, 2010, requesting clarifica tion regarding how62 EPA classified individual states as group 1 or group 2 states. A representative of the Clean Air Markets Division explained the process as follows. EPA first determined which downwind monitors were classified as nonattainment and/or maintenance for PM 2.5 based on the projected 2012 base cas e air quality, and then identified upwind states that were “linked” to these mon itors. This step in EPA’s methodology determined which states were included in the Transport Rule for PM 2.5 , at least as group 2 states, based on their significant contri bution to nonattainment or interferen ce with maintenance. Next, EPA used its air quality assessment tool and the em ission changes resulting from the 2014 cost curves to evaluate how air quality at the nonattainme nt and maintenance monitors would change in response to emission reductions from “linked” upwind states , assuming a linear relationship between reductions in the upwind states’ em issions and reductions in their respective contribution to projected ambient concentrations at the downwind monitors. EPA evaluated each monitor independently, considering only emission reductions from “linked” upwind states and the state in which the monitor is s ituated. EPA found that the 24-hour PM 2.5 NAAQS was controlling because most annual PM 2.5 problems were resolved at relatively low dollars-per-ton thresholds, while 24-hour PM 2.5 problems were more likely to pe rsist at higher cost thresholds. EPA focused on the maintenance monitors and di d not consider the nonattainment monitors separately because of the way that nonattain ment and maintenance sites were determined. 38 Using its air quality assessment tool, EP A determined that, in 2014, there were six monitors that still s howed maintenance problems at approx imately $300-$400 per ton that, with

38 As described above, EPA determined ma intenance sites based on the future-year maximum PM 2.5 design values, and nonattainment site s based on the future-year five-year weighted average annual PM 2.5 design values. Thus, all nonattainment sites were also maintenance sites. 75 Fed. Reg. at 45247/3. See section VII.D supra for comments regarding the manner in which EPA determined maintenance sites.63 the exception of one in Allegheny County, Pennsylva nia, could be eliminated at $2,400 per ton or less. EPA then decided that the states linke d to those six monitors that continued to have maintenance problems at higher dollar-per-ton levels should be required to make additional emission reductions, and EPA used the 2012 base case to determine which upwind states were “linked” to those six remaining monitors. EPA classified upwind states that, in the 2012 base case, were linked to those six monitors as group 1 states and classified upwind states not linked to those six monitors as group 2 states. It ap pears that this was th e sole determinant for classifying states as group 1. Strikingly, acco rding to EPA’s Clean Air Markets Division, in determining group 1 or group 2 status in 2014, EPA ignored the air quality benefits that would accrue in 2012 and 2013 from the emission reducti ons required by the Transport Rule during those years and from state rules, consent decr ees, and other requirements that will result in additional emission reductions by 2014

. This illogical decision not to consider th e results of reductions required beginning in 2012 in projecting remaining maintenance problems in 2014 demonstrates a complete disconnect in the Agency’s analysis. EPA characterizes its Proposed Transport Rule as having two “phases.” 75 Fed. Reg. at 45215/3. It makes no se nse to evaluate phase II of the proposal in isolation, ignoring the pr ojected effects of phase I (and ot her emission reduction requirements applicable in the period leadi ng up to 2014). EPA’s approach is made worse by the Agency’s decision to ignore the effects of CAIR and local controls for purposes of modeling. See section
VII.A supra and section VII.F infra . Had EPA considered the em ission reductions that would result from the 2012 compliance deadline and othe r controls, it is likel y that the supposed maintenance problems projected at most or all of these six monitors in 2014 would be shown not to exist, even if the Agency had continued to ignore the effects of CAIR. As these comments64 note above, air quality has been improving steadily in recent years, and, consistent with that nationwide trend, 24-hour PM 2.5 concentrations at all six of th e monitors at issue show a strong downward trend. See graph showing the 98th percenti le design values for 24-hour PM 2.5 at these six monitors from 2003-2008 at section VII.D supra . EPA should redo and publish for public comment its analysis of 2014 air quality by includ ing consideration of the emission reductions required in 2012 and 2013 under the proposed rule and other applicable requirements. A balanced analysis of this issue is likely to re move any justification for imposing more stringent
SO 2 requirements on certain states in phase II of the program.
F. EPA’s Determinations of “Significant Contribution” and “Interference with Maintenance” Improperly Presuppose Upwind-State EGU Emissions as the Primary Cause of Downwind Nonattainme nt Problems and Inappropriately Underestimate the Contribution of Local Sources from a Variety of Emission Sectors. 1. EPA’s Approach Places an Undue a nd Unlawful Burden on Sources in Upwind States To Reduce Emissions. EPA’s Proposed Transport Rule improperly pu ts all or most of the emission reduction burden on sources located outside the local nonattainment or ma intenance area. Indeed, EPA admits as much. In the preamble to the proposed rule, EPA explains that “EPA continues to believe that a strategy based on adopting cost effective controls on s ources of transported pollutants as a first step will produce a more reasonable, equitable, and optimal strategy than one beginning with local controls.” 75 Fed. Reg. at 45226/3. EPA recites se veral reasons for its decision to assign “substantial resp onsibility” to upwind states to decrease their emissions in an effort to decrease or eliminate nonattainment in downwind states, 75 Fed. Reg. at 45272/1, but none can justify EPA’s failure to adhe re to the terms of the CAA. Section 107(a) of the Act states that “[e]ach State shall have the primary responsibility for assuring air quality within the entire geographic area compri sing such State.” 42 U.S.C. §65 7407(a) (emphasis added). EPA’ s proposal instead would impose on upwind states the “primary responsibility” for assuring air quality in the dow nwind states that contain the nonattainment and maintenance sites, in direct c ontradiction to this fundamental principle of the CAA. EPA is bound by the terms of the Act to recognize that the primary responsibility for attaining and maintaining air quality standa rds in a given state is to be borne by that state. One consequence of this principle is that EPA was required to account for local controls in the first instance. EPA did not comply with this requirement. For example, EPA states that in the development of the future year emissi on scenarios, “[f]or nonEGU point and nonpoint stationary sources, any local co ntrol programs that may be necessary for areas to attain the annual PM 2.5 NAAQS and the ozone NAAQS are not in cluded in the future base case projections.” 75 Fed. Reg. at 45241/2. 39 Proper accounting for local controls may well have resulted in different emission budgets. EPA gave recognition to the terms of secti on 107(a) in the NOx SIP Call rule and CAIR, at least to a certain degree. Both the NOx SIP Call rule and CAIR were based on the concept of residual nonattainment -- that dow nwind states containing designa ted nonattainment areas would be unable to reach attainment in those areas through the use of local controls alone. See 63 Fed. Reg. at 57377/1-2 (“The fact that a nonattainme nt problem persists, notwithstanding fulfillment of CAA requirements by the downwind sources, is a factor suggesting that it is reasonable for the upwind sources to be part of the solution to the ongoing nonattainment problem.”); 70 Fed. Reg.

39 EPA stated in its technical support docume nt (“TSD”) on “Emissions Inventories” that “[t]his is because the nona ttainment 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 Inve ntories” TSD at 11. The unavaila bility of this information in 2005, however, does not explain why EPA has not take n it into account in the future base case projections.66 at 25184/3 (explaining that regional emission redu ctions are necessary because “it would be difficult if not impossible for many nonattainment areas to reach attainment through local measures alone”). In the final CAIR, for exam ple, EPA explained that it evaluated emission control options to determine the average emission reductions that were possible in nonattainment areas using local controls, and then determine d, based on this analysis , that reductions from sources in upwind states were necessary -- in addition to local controls -- in order for downwind states to reach attainment. 70 Fed. Reg. at 2519 4/1-2. As mentioned ab ove, this reasoning gives at least a degree of reco gnition to the requirement of section 107(a), discussed above, that states bear the primary responsibility for assuring air qual ity within their borders. EPA’s failure to do so here requires the Agency to revise and re issue the proposed rule based on a proper assessment of the role of local controls in NAAQS attainment strategies.
2. EPA’s Air Quality Assessment Improperly Overestimated the Marginal Benefit of Emission Reductions Above Relatively Low Dollar-Per-Ton Levels. EPA’s air quality assessment for the proposed rule did not properly consider the very limited nature of the reductions in the esti mated number of projected nonattainment and maintenance sites that result from increas ing the marginal cost per ton of EGU SO 2 controls above comparatively low levels such as $300 or $400 per ton. See Tables IV.D-3 and IV.D-4, 75 Fed. Reg. at 45280, which are reproduced below.67 EPA’s Table IV.D-3 indicates that , with respect to the annual PM 2.5 NAAQS, two nonattainment monitor sites would remain in 2014 at $200/ton and $300/ton and only one would remain at $400/ton, compared with 12 at $0/ ton. EPA projects that the one remaining nonattainment monitor would reach attainment onl y at $1,800/ton. Similarly, EPA projects that only three nonattainment and maintenance mon itors would remain in 2014 at $200/ton and $300/ton and two would remain at $400/ton, compared with 19 at $0/ton and six at $100/ton.68 Table IV.D-4 indicates that, w ith respect to the 24-hour PM 2.5 NAAQS, EPA projects that eight nonattainment and maintenance monitors would remain in 2014 at $300/ton and that six would remain at $400/ton, compared with 64 at $0 /ton. EPA projects that those six monitors would remain nonattainment or ma intenance until the $1,600/ton leve l, at which they would drop to five, and one would remain at $2,400/ton. Analysis of these cost curves is complicat ed by the fact that, in EPA’s analysis, few additional emission reductions are av ailable at each additional cost increment. This drives the analysis upward in pursuit of the modest be nefits available at each cost increment. Consideration of local cont rols would make this analysis far more realistic. 40 A proper analysis, particularly one conducted pursuan t to an iterative process, li kely would have produced very different and less stringent budgets. 41 EPA should conduct such an analysis and issue it for public comment in a supplemental notice of proposed rulemaking. Indeed, much of this work has already been done. Comments submitted by Southern Company include the results of an analysis condu cted by replicating EPA’s data and air quality assessment tool. That analysis shows that ke y indicators of air quali ty remain essentially unchanged under the Proposed Transport Rule de spite differences in aggregate and statewide

40 UARG also notes that, by basing 2012 unit allocations on each unit’s share of the lower of 2009 emissions or projected 2012 emissions for the state where the unit is located, 75 Fed. Reg. at 45309/3, EPA failed to take account of the additional overall cost of the program attributable to the de facto loss of the value of allowances that would have been generated as a result of early reductions under CAIR.

41 Although the cost per ton levels that EPA selected are unreasonably high, UARG supports EPA’s decisions not to select a NOx cost breakpoint above $500/ton and not to select an SO 2 cost breakpoint above $2,000/ton. 75 Fed. Reg. at 45281/1-3. Although UARG believes that these breakpoints are also unreasonably high, they are more reasonable than other breakpoints that EPA considered or may have considered. However, as discussed in this section of the comments, had EPA consid ered the effects of reducing SO 2 emissions before considering the effects of reducing NOx emissions, EPA w ould have concluded that annual NOx emission reduction obligations to address PM 2.5 should not have been included in the proposed rule at all.69 emission reduction amounts required under the propos ed rule compared to those required under CAIR. This analysis provides a basis for c oncluding that the Proposed Transport Rule will produce a level of air quality that is substantially the same as that which would be produced by continued implementation of CAIR. Table VI I-2 below, which was created by Southern Company, compares (i) the number of nonattainment and maintenance sites projected to remain after implementation of the emission reductions required beginning in 2012 under the PTR to (ii) the number of nonattainment and maintenance sites projected to remain after implementation of phase I of CAIR, and the number of nonattainment and maintenan ce areas projected to remain after implementation of the emission reductions required beginning in 2014 under the PTR to the number of nonattainment and maintenance areas projected to remain after implementation of phase II of CAIR.
Table VII-2 Number of Downwind Monitors NAAQS Scenario Nonattainment Maintenance 24-hr PM 2.5 2012 remedy 1 9 CAIR I 2 9 Annual PM 2.5 2012 remedy 1 2 CAIR I 1 1 8-hr ozone 2012 remedy 7 14 CAIR I 8 18
Number of Downwind Monitors NAAQS Scenario Nonattainment Maintenance 24-hr PM 2.5 2014 remedy 1 1 CAIR II 1 2 Annual PM 2.5 2014 remedy 0 1 CAIR II 0 1
In almost every comparison, there are very few differences in the numbers of nonattainment and maintenance sites projected to remain following implementation of the Proposed Transport Rule and following implementation of CAIR. This indi cates that no meaningful additional benefit is70 achieved by the emission reductions required und er the Proposed Transport Rule beyond those required under CAIR, despite th e increased cost and constrai nts that come along with the Proposed Transport Rule. Additionally, in developing the Proposed Tr ansport Rule, EPA assessed the effects of NOx emission reductions first, befo re considering the effects of SO 2 emission reductions, despite EPA’s acknowledgement that “SO 2 reductions are generally more effective than NOx reductions at reducing PM 2.5 .” 75 Fed. Reg. at 45281/1-2. This ar tificially inflates the projected contribution of NOx emissions to the formation of PM 2.5 . As EPA has acknowledged, for example, the contribution of NOx emissions to PM 2.5 formation in southeastern states is considerably smaller than the contribution of SO 2 emissions to PM 2.5 formation. See 75 Fed. Reg. at 45237/1. In fact, it is minimal. See comments of Southern Company on the PTR (explaining, among other things, th at particulate nitrate repres ents a very small fraction -- approximately five percent -- of PM 2.5 in southeastern states). 42 Had EPA taken a more logical approach and assessed SO 2 reductions first, it would have found that adding NOx reductions provides little additional improvement in key air quality indicators. Table VII-3 below, which was developed by Southern Company by repli cating EPA’s air quality assessment tool, illustrates the effect of assessing SO 2 reductions before NOx reductions.

42 Southern Company’s comments also explain, among other things, that although particulate nitrate can represen t an important fraction of PM 2.5 during the winter in northern states, EPA should not have required annual NOx reductions in the PTR because EPA does not include consideration of ammonia emissions in the PTR. The form ation of particulate nitrate is an inherently non-linear proce ss, is strongly thermodynamically driven, and is strongly associated with available ammonia. Thus , by excluding ammonia fr om consideration, EPA cannot properly assess the role of NOx versus a mmonia in particulate formation, especially using the linear assumptions in its air quality assessment tool.71 Table VII-3 24-hour PM 2.5 - 2014 Number of Downwind Monitors $/Ton SO 2 $/Ton NOx Nonattainment Maintenance 0 0 40 71 0 500 39 64 100 0 6 16 100 500 5 15 200 0 3 11 200 500 1 9 300 0 1 8 300 500 1 6 400 0 1 7 400 500 1 5

Annual PM 2.5 - 2014 Number of Downwind Monitors $/Ton SO 2 $/Ton NOx Nonattainment Maintenance 0 0 13 20 0 500 12 19 100 0 3 4 100 500 2 3 200 0 2 3 200 500 2 3 300 0 1 3 300 500 1 3 400 0 1 2 400 500 1 1

This indicates that for both the annual and 24-hour PM 2.5 NAAQS, the number of downwind nonattainment and maintenance monitors is driven primarily by reductions in SO 2 emissions. There are only very slight ch anges in the numbers of downwin d nonattainment and maintenance monitors when SO 2 emissions are not reduced and NOx emissions are reduced using EGU NOx controls available at $500 pe r ton. By contrast, when SO 2 emissions are reduced using EGU SO 2 controls available at $100 pe r ton, there are significantly fewer downwind nonattainment or maintenance sites, and reducing NOx emissions using EGU NOx controls available at $500 per ton yields only a very slight difference. This same pattern holds true when SO 2 emissions are reduced using EGU SO 2 controls available at $200 per ton, $300 per ton, and $400 per ton --72 although the additional incremental improvement even from the SO 2 reductions that are achieved at $300 and $400 per ton is minimal. In each case, the difference between reducing NOx emissions using EGU NOx controls availabl e at $500 per ton and not reducing EGU NOx emissions at all is very slight if there is any difference at all. The role of NOx in particulate matter formation is further complicated by recent research demonstrating that the producti on of biogenic secondary organi c aerosol (“SOA”) is heavily influenced by NOx levels. 43 Specifically, this research show s that biogenic SOA, particularly isoprene, is enhanced with lower NOx levels due to changes in the fate of peroxy radicals. Air quality models at present do not include this newly discovered ch emistry. In addition, the proper simulation of ammonium nitrat e and other nitrate aerosol ( e.g. , organic nitrates) has confounded air quality scientists for many years. Thus, th e representation of the impacts of NOx emission changes in particulate matter levels in these mode ls is incomplete, particularly when attempting to simulate relatively small signals such as inte rstate contributions to ambient particulate matter concentrations.

43 See, e.g. , Chan, M. N. et al. (2010), Character ization and quantification of isoprenederived epoxydiols in ambient aer osol in the southeastern Unite d States, Environmental Science & Technology, 44(12), 4590-6, doi:10.1021/es100596b; Su rratt, J. D., A. W. Chan, N. C. Eddingsaas, M. Chan, C. L. Loza, A. J. Kwan, S. P. Hersey, R. C. Flagan, P. O. Wennberg, and J. H. Seinfeld (2010), Reactive intermediates re vealed in secondary or ganic aerosol formation from isoprene, Proceedings of the National A cademy of Sciences of the United States of America, 107(15), 6640-5, doi:10.1073/pnas.0911114107; Paulot, F., J. D. Crounse, H. G. Kjaergaard, A. Kürten, J. M. St Clair, J. H. Seinfeld, and P. O. Wennberg (2009), Unexpected epoxide formation in the gas-phase photooxidati on of isoprene, Science (New York, N.Y.), 325(5941), 730-3, doi:10.1126/science.1172910; Paulot , F. (2009), Unexpected Epoxide Formation in the, Science, 730, doi:10.1126/scie nce.1172910; Hallquist, M. et al. (2009), The formation, properties and impact of secondary organic aerosol: current and emerging issues, Atmospheric Chemistry and Physics Di scussions, 9(1), 3555-3762, doi:10.5194/acpd-9-3555- 2009; Ng, N. L. et al. (2007), Effect of NOx le vel on secondary organic aerosol (SOA) formation from the photooxidation of terpenes, Atmospheri c Chemistry and Physics Discussions, 7(4), 10131-10177, doi:10.5194/acpd-7-10131- 2007; Surratt, J. D. et al. (2006), Chemical composition of secondary organic aerosol form ed from the photooxidation of isoprene, The journal of physical chemistry. A, 110(31), 9665-90, doi:10.1021/jp061734m.73 EPA should reevaluate the marginal air qua lity benefits that are projected from incremental increases in cost for EGU SO 2 controls above low levels, such as $300 to $400 per ton, and should reconsider the SO 2 cost breakpoint in that light. Additionally, because of the very minimal benefit that is achieved from reducing EGU NOx emissions in addition to SO 2 emissions, as well as the other issues discu ssed above, EPA should consider removing annual NOx reduction requirements from the proposed rule.

G. EPA Has Failed To Explain Why It Did Not Use 2008 Heat Input Data in Calculating SO 2 Emission Budgets. EPA proposes to set state emission budgets for annual and ozone season NOx and for
SO 2 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. 75 Fed. Reg. at 45290/2. In its TSD addressing st ate budgets, EPA explains that it calculated 2012 state budgets using a combination of emissions and heat input data reported to EPA as of
2009 44 and IPM projections for 2012, each adjusted to reflect emissions control equipment projected by EPA to be in place by 2012. 45 See State Budgets TSD at 3, 5.

44 According to EPA, it used the most r ecent non-null first, sec ond, third, and fourth quarter emissions and heat input data between th e first quarter of 2007 a nd the third quarter of 2009. Ozone season NOx emissions budgets were based on the most recent ozone season data reported between 2007 and 2009. EPA, “State B udgets, Unit Allocations, and Unit Emissions Rates” TSD, at 5 (July 2010), available at http://www.epa.gov/airquality/transport/ pdfs/TSD_StateBudgets_July152010.pdf (“State Budgets TSD”).

45 Many of the assumptions that EPA made in projecting the emissi ons control equipment that would be in place at indivi dual units by 2012 are incorrect. See section VIII.A infra for a discussion of this issue and examples. EPA represen tatives have requested that, to the extent that EPA’s projections are inaccurate, electric ge nerating companies submit comments correcting them and explaining why they are inaccurate . Individual UARG members are submitting comments correcting EPA’s projections to the exte nt that they contain inaccurate information regarding their units. However, to the extent th at some companies fail to correct inaccurate74 In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it “rebased” annual and ozone season NOx emi ssions for units reporting emission data to EPA by using 2008 rather than 2009 heat input. Id. at 9. According to EPA, this adjustment was made “to account for unusually low util ization [or heat input] in 2009.” Id. During a conference call on August 30, 2010, however, EPA staff offere d UARG members a different explanation for this adjustment. EPA staff indicated that the reason EPA used 2008 da ta was that the IPM projection of how sources would operate their NO x controls in 2012 did not align well with the 2009 data but aligned more clos ely with the 2008 data. Whatever the reason or reasons EPA used 2008 instead of 2009 heat input data for NOx, EPA did not make a similar adjustment for unit-reported SO 2 emissions. EPA does not provide any explanation for this differential treatment of the issue as between the two pollutants. EPA does, however, state repeatedly in the preambl e that it developed the state budgets based on projected emissions “in an average year.” See, e.g. , 75 Fed. Reg. at 45214/2 (“A state’s emissions budget is the quantity of emissions that would remain afte r elimination of the part of significant contribution a nd interference with maintenance the EPA has identified in an average year”); id. at 45271/2 (A state’s budget “r epresent[s] the remaining emissions for the state in an average year”); id. at 45292/1 (“EPA has . . . developed st ate budgets based on its projections of state emissions in an average year”). Both the explanation in the TSD and the explanation
projections regarding their units and the 2012 state budgets remain inadequate, all companies in the program will be affected. Requesting comments to correct a vast array of assumptions, especially in the short period of time that EPA has allowed for public comment on this lengthy and complicated proposed rule, is not adequate. EPA should have issued an advance notice of proposed rulemaking and communicated with electr ic generating companies to ensure that the information that it was using to develop the pr oposal was accurate. Having not done that, and seeing that these vital assumptions are inaccurate in many cases, EPA must either withdraw the proposed rule and begin the rulemaking anew or issue a comprehensive supplemental notice of proposed rulemaking for public comment.75 offered on the August 30 conference call seem to i ndicate that EPA believe s that 2009 heat input was not heat input for an average year, at least for NOx budget purposes. 46 It is far from apparent why, if 2009 heat input was not averag e for -- and therefore wa s not used for -- NOx budget purposes, there would be any basis to use it for SO 2 budget purposes. Before it proceeds further with this rulemaking, therefore, EPA w ill need to clarify and provide an adequate explanation for its decision to use 2009 heat input data for SO 2 . Prior to taking any final action to promulgate a rule, EPA should provide an opportunity for the public to comment on this important matter in light of an ad equate explanation by the Agency.
VIII. EPA’s Use of Inaccurate Inputs and A ssumptions for -- and Unrealistic Outputs from -- EPA’s Use of the Integrated Pla nning Model Makes the Proposed Transport Rule Inadequate for Public Comment. The principal analytical tool on which EPA relied in developing the unit allowance allocations and statewide emission budgets in the Proposed Transport Rule is IPM. The results of EPA’s numerous IPM runs provide the Agency w ith substantially all of the key data points to make its decisions on these critical elements of the PTR. As EPA explai ns in its TSD discussing its use of IPM, that model 47 provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeti ng electricity demand, environmental, transmission, dispatch, and reliability cons traints. IPM can be used to evaluate the cost and emissions impacts of proposed policies to limit emissions of sulfur dioxide (SO 2 ), nitrogen oxides (NOx), carbon dioxide (CO 2 ) and mercury (Hg)

46 UARG believes that EPA should have based state budgets on heat input in a higherthan-average year, at least for the first several years of the program, to allow for flexibility in the event that demand in those years requ ires higher-than-average generation.

47 EPA’s NODA, published on September 1, 2010, states, among other things, that the Agency had placed in the docket an updated ve rsion of IPM (v.4.10), along with a number of other documents and IPM runs. The present comments on the PTR are limited to IPM v.3.02 as used in developing the PTR and the runs produced by that version of the model. In its comments on the NODA, UARG will address issues concerning v.4.10 of IPM.76 from the electrical power sector and is used extensively by EPA to support regulatory activities. 48 A fundamental limitation on the accuracy of any model is the quality of the inputs to the model. Among the most critical inputs to IPM are the emission i nventory and unit-level characteristics and operating parameters. The pr imary source for unit-level emission information for IPM is the NEEDS database. The NEEDS data base is fraught with significant errors, as illustrated in section VIII.A below. In additi on, other inputs can be used for, and limitations placed on, IPM analyses to reflect particular, unique situations such as state-specific regulations of EGU emissions and NSR settlements that may limit those emissions. IPM refers to such inputs as “constraints.” Section VIII.A below also details various errors in the “constraints” EPA placed on the IPM model runs. Moreover, the outputs from EPA’s IPM runs, wh en compared to actual unit-specific data and individual companies’ plans, are inaccurate and unrealistic. The validity of a given set of outputs from an application of any modeling to ol is brought into question when the modeled results do not reflect real-world conditions. 49 The second subsection below provides specific examples of inconsistenc ies between EPA’s IPM projections a nd individual companies’ plans for their units. The following examples are an illust rative, but by no means an exhaustive, list of problems in the NEEDS database and EPA’s a pplication of IPM to support the Proposed Transport Rule.

48 Updates to EPA Base Case v3.02 EISA Usi ng the Integrated Planning Model, Docket ID No. EPA-HQ-OAR-2009-0491, at 3 (June 17, 2010), available at http://www.epa.gov/airquality /transport/tech.html.

49 Another problem with the outputs from IPM results from the fact that IPM does not perform a probabilistic analysis. IPM outputs give the illusion th at they are precise even though they are not. It would be more realistic for EPA to consider a range of projected data than to treat a single data point from IPM as a precise da ta point for purposes of calculating budgets and allowance allocations.77 A. Many of the IPM Inputs for Individual Units Are Inaccurate. Errors in the NEEDS database identified by UARG members generally fall into three categories: (1) emission cont rols that were assumed to exist currently but do not; (2) overestimated emission control efficiencies of existing control equipment; and (3) failure to account for emission controls or limits that do exist. Examples of pollution controls that were assumed to exist but do not include the following:

• NEEDS reports that PM scrubbe rs are already installed and operational at the Harrison power plant in West Virginia. PM sc rubbers do not exist at that plant.

• NEEDS reports that selective non-catalytic reduction (“SNCR”) is already installed and operational at two units at the Armstrong power plant in West Virg inia. SNCR does not exist at these two units.

• NEEDS reports that FGD is to be installed at unit 4 at the Scherer power plant in Georgia in 2011. The current target installation date is August 2012.

• NEEDS reports that SNCR is to be installed at units 4 and 5 at the Jack Watson power plant and units 1 and 2 at the Daniel power pl ant in Mississippi. No SNCRs exist or are planned for these units.

• NEEDS reports that a wet scrubber will be in stalled at unit 3 at the Brayton Point power plant in Massachusetts by 2012. Under a st ate-approved Emission Control Plan, a dry scrubber will be installed and will commence operation in 2014.

• NEEDS data indicate that an SCR on unit 3 at the E.W. Brown power plant in Kentucky is to be installed by the be ginning of 2012. An SCR is under construction at that unit but will not be completed until the end of 2012.

• NEEDS data indicate that an SCR exists on unit 2 at the Ghent power plant in Kentucky as of 2009. SCR neither exists nor is planned for this unit.
Examples of overestimation by NEEDS of remo val efficiency of controls that currently exist:78 • NEEDS reports the FGD control efficiency at the Mitchell power plant in West Virginia at 99.9% -- an impossible figure to achieve. The actual average removal efficiency is 97%.

• NEEDS reports the FGD control efficiency at the Pleasants power plant in West Virginia at 97%. The actual average removal efficiency is 95%.
Examples of emission controls that do exist but were not included:

• NEEDS fails to account for FGD systems at th e Harrison power plant in West Virginia.

• NEEDS fails to account for FGD systems at th ree units at the Hatfield’s Ferry power plant in West Virginia.

• NEEDS fails to account for FGD systems at two units at the Fort Martin power plant in West Virginia.

• NEEDS fails to account for a state SO 2 emission limitation on the Cumberland power plant in Tennessee of 0.5 lb/mmBtu and instead reports SO 2 emissions at that plant at a rate of 5.0 lb/MMBtu.

In addition, errors in IPM constraints and inputs appear to be re lated to inaccurate interpretation of state regulations and NSR settlements, and there are other errors as well. Examples include:

• IPM assumes (in the 2014 base cas e) that units 1 and 2 at th e Harllee Branch power plant in Georgia will each have an FGD and S CR in place by 2014 (presumably, January 1, 2014). The Georgia Multipollutant Rule instead requires that these be in place by December 31, 2014.

• IPM assumes (in the 2014 base case) that unit 4 at the Harl lee Branch power plant in Georgia will have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multipollutant Rule instead requ ires that these be in place by June 1, 2014.

• IPM assumes (in the 2014 base case) that units 6 and 7 at the Yates power plant in Georgia will each have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multipollutant Rule instead requires that these be in place by June 1, 2015.

• IPM assumes (in the 2014 base case) that unit 1 at the Sche rer power plant in Georgia will have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multipollutant Rule instead requi res that these be in place by December 31,79 2014.

• IPM assumes that FGD retrofits at the Kyge r Creek and Clifty Creek power plants in Ohio are complete and operational. These re trofits are not complete, and construction is currently suspended.

• IPM assumes that one of the primary units of the Cumberland power plant in Tennessee has an SO 2 emission rate of 5.0 lbs/mmBtu. The unit is currently regulated by and is complying with a state regulation that limits its SO 2 emissions to 0.5 lbs/mmBtu.

• IPM assumes that the Maryland Healthy Air Act allows for limited interstate trading and/or intrastate trading, depending on the proposed reme dy, and IPM appears to treat similar sources in Maryland very differen tly, judging from the IPM-based allowance allocations for units. The Maryland Healthy Air Act in fact only allows for intracompany trading of allowances and the unit- specific allowances established in the Maryland Healthy Air Act appear to have been ignored.
In addition to the NEEDS and IPM inputerrors, it appears EPA made downward adjustments to NOx emission rates in IPM that are unwarranted, unreasona ble, and inaccurately described in the State Budgets TSD. The State Budgets TSD indicates that “NOx controls were assumed not to control beyond a floor of 0.06 lb/mmBTU.” 50 The 0.06 lb/mmBTU rate would be more accurately described as a ceiling than a floor because of the adjustments EPA made to NOx emission rates. If a unit reported histor ical data that supported a NOx emission rate lower than 0.06 lb/mmBTU, EPA used that lower emission ra te. Yet if a unit reported historical data that demonstrated a NOx emission rate higher than 0.06 lb/mmBTU, EPA -- apparently arbitrarily -- made a downward adjustment of that rate to 0.06 lb/mmBTU. Such downward adjustments are unfair and unwarranted. Incentives exist in most cases to emit at the lowest reasonably achievable NOx emission rate, and if a given unit reports NOx emissions at rates above 0.06 lbs/mmBTU, it is likely th at that unit cannot physically a nd consistently operate at a lower rate. At a minimum, an across-the-boar d downward adjustment to 0.06 lb/mmBtu, without

50 State Budgets TSD at 6.80 consideration of case-by-case factors, cannot be justified. Under EPA’s proposed approach, where an existing unit cannot in fact meet the 0.06 lb/mmBTU rate, that unit may well be forced to upgrade its pollution control device or acquire allowances. EPA did not anticipate either of these options in the PTR and does not seem to ha ve accounted for the costs associated with these options in the PTR. EPA should abandon its ap proach of making across-the-board downward adjustments to 0.06 lb/mmBTU and should instea d use historical reported emission rates on a unit-by-unit basis.
B. EPA’s IPM Outcomes Do Not Reflect Actual Source Operations. UARG members have found many inconsis tencies between EPA’s IPM-projected operating scenarios for units in 2012 and 2014 and their own plans and projections. While EPA may argue that IPM accounts for the impact of th e proposed controls and th at generators are not capable of appreciating the influence of the pr oposed controls on their future operations, UARG members believe that their economic models, as well as their understandi ng of their operations, supply capabilities, and energy demand forecasts are more accurate than outputs of EPA’s proprietary IPM. IPM was not designed for this level of specificity -- it is a regional-scale model. IPM often does not reflect real-world operations with respect to a numb er of key factors, including unit availability. Ge nerators have years of experi ence with a greater level of specificity that allows them to understand the real-world constraints and demands on individual units and to better predict whic h units will run, how often they will run, and how long they will continue to run. The inaccurate IPM projections fall into four categories: (1) inaccurate assumptions of emission controls; (2) inaccurate estimates of emission control efficiencies; (3) inaccurate assumptions of early retirement of particular uni ts; and (4) inaccurate a ssumptions regarding fuel switching at particular units.81 Examples of inaccurate assumptions of em ission controls include the following:

• IPM projects FGD installati ons at the Armstrong power pl ant in Pennsylvania by 2014. No such installations ar e planned by the company.

• IPM projects FGD installation at the Willo w Island power plant in West Virginia by 2014. No such installation is planned by the company.

• IPM projects SCR installation at unit 2 at the J.H. Campbell power plant in Michigan by 2012. No such installation is planned by the company.

• IPM projects installation and operation of LN Bs with overfire air -- based on the listed emission rate -- at the J. R. Whiting power plan t (units 1-3) in Mich igan. The owner of the units does not believe such controls ar e viable options at these units due to operational and configuration constraints.

• IPM projects FGD installation and operati on at unit 2 at the Muskingum River power plant in Ohio by 2011. Although a preliminar y engineering study was conducted for unit 2, there is no ongoing construction and it would take at least three years to permit and build an FGD even if construction began immediately.

• IPM has not allocated NOx emission allowances to units 1 and 2 at the Salem Harbor power plant even through the IPM model for the 2012 base case predicts that these units will operate. This appears to be the result of erroneous adjustments made to projected IPM emissions to account for annual operation of each unit’s SNCR. No adjustment was necessary. Actual emissions already repr esent annual operation of SNCR -- both SNCRs have been operating on a year-round basis si nce October 2005 to co mply with a stationwide NOx limit in accordance with a state Administrative Consent Order.

Examples of inaccurate estimates of emissi on control efficiencies include the following:

• IPM projects an annual 35% NOx removal effi ciency for two units at the Fort Martin power plant in West Virginia and one unit at the Hatfield’s Ferry power plant in Pennsylvania. In fact, however, these units have only single-point injection controls capable of roughly 10% to 15% removal efficiency.

• IPM projects annual NOx emission rates at the Harrison power plan t and the Pleasants power plant in West Virginia from SCR as low as 0.04 to 0.05 lb/mmBtu. Such low rates were periodically achievable when the SCR wa s initially installed, but representative operation of the controls demonstrates that such rates are not sust ainable on a long-term basis and as the effectiveness of the SCR reduces as the catalyst ages.82 Examples of inaccurate assumptions of early retirement of particular units include the following:

• IPM projects early retirement of two units at the Rivesville power plant and one unit at the Willow Island power plant in West Virginia by 2014. No retirements by 2014 are planned by the company.

• IPM projects early retirement -- by 2014 -- of units 1 and 2 at the McManus power plant in Georgia, and of units 1 and 3 at the Wa tson power plant, and units 1 and 2 at the Sweatt power plant, both in Mississippi. Th ere are no plans by the company to retire these units by 2014.

• IPM projects early retirement of nine units in Michigan (B. C. Cobb units 1-3; D. E. Karn units 3 and 4; and Thetford units 1-4). Th ere are no plans by the company to retire these units by 2014.
Examples of inaccurate assumptions regardi ng fuel switching for particular units include the following:

• IPM projects fuel switching from coal to natu ral gas for three units at the Albright power plant in West Virginia and for two units at the R. Paul Smith power plant in Maryland. These fuel switches are not planned by the company.

• IPM projects fuel switching from coal to natural gas for the McManus power plant in Georgia. This fuel switching is not planned by the company.

• IPM projects fuel switching from higher sulf ur coal to 100% Powder River Basin coal by 2012 at units 4 and 5 at the B.C. Cobb power plant and units 1-3 at the J. R. Whiting power plant in Michigan. Such a fuel switch is not feasible due to the limited timeframe and outstanding coal, rail-line, and rail-car contracts.

• IPM projects fuel switching to low-sulfur Ea stern coals at units 1-4 of the Muskingum River power plant in Ohio. These units are wet bottom/cyclone-fired boilers that, historically, do not tolerate such coal because of its high ash-fusion temperatures.
In addition to these facility-specific erro rs, EPA’s application of IPM reveals certain systemic errors in the analysis supporting the PTR. Perhaps most notable is IPM’s treatment of dual-fuel units, i.e. , units capable of burning e ither natural gas or oil. Of the 493 dual-fuel units in the NEEDS database, IPM predicted in the 20 14 limited trading control strategy that 34 units83 would burn oil as the primary fuel. EPA proposes to allocate any SO 2 allowances to only 8 of those 34 units. This result ignores the reality th at many dual-fuel units do regularly burn oil for some part of the year, whether due to natural gas supply limitations, 51 price factors, or facilityspecific constraints. The mere fact that the IPM analysis may project that it will be more economical to run these units on na tural gas than on oil does not mean that the real-world factors that lead to combustion of oil at these units simply disappear. IPM projection errors of this sort appear to be a function of inhe rent limitations of IPM and/or EPA’s limited knowledge of certain local factors. IPM is a least-cost economic model designed to predict operations at a fairly broad regional level. In many instances, EPA lacks sufficient information about local issues such as transmission c onstraints, capacity commitments, fuel-contract commitments, and other cost-related considerations that have not been input to the IPM model. EPA’s insufficient information, coupl ed with the limitations of the regional IPM model, result, for example, in inaccurate projecti ons for oil-fired units and dual-fuel units. When IPM predicts natural gas is less expensive than oi l or that burning oil at an oil-fired unit is for some reason not “economical” within the terms of IPM’s protocol, no SO 2 emissions are projected from -- and thus no SO 2 allowances are allotte d to -- that unit. EPA must recognize the limitations of IPM and must consider lo cal issues and allow UARG members, other generators, and other me mbers of the public to comment on EPA’s adjustments to address those issues. For example, it should be self-evident that particular units

51 Natural gas markets and suppliers essentia lly “close” at 6 p.m. each day. Individual generating companies bargain before closing each day for their guaranteed supply of gas for the following day. If there is not enough gas in the pipeline to meet demand the following day, units may have to run on oil to meet demand. Additionally, many natural gas pipelines offer only “interruptible” service, in whic h gas supplies may be reduced or temporarily curtailed to meet higher-priority customers. When service is inte rrupted, units are forced to burn oil to meet demand. Many dual-fuel units are peaking units and may need to burn incremental volumes of oil in peak-demand periods.84 that have burned oil in the past, and that continue to burn oil, can be expe cted to burn oil in the future and should receive allowance allocations; the presumption should be in such cases that allowance allocations to those uni ts are appropriate in the absen ce of compelling reasons to the contrary. At a minimum, EPA s hould not blindly insist that IPM’ s projections for these types of units are accurate and should instead make adjust ments to the allocation determinations for these types of units, based on comments of co mpanies with interests in those units. Another systemic error invol ves the heat input rates list ed in the “BADetaileddata.xls” spreadsheet associated with th e proposed direct control altern ative remedy. Heat input is overstated by a factor of 10 in this spreadsheet. Because of the absolute tonnage cap in the direct control case, these artificially hi gh heat input levels are essentially meaningless in this context. Nonetheless, these types of errors draw into further question the accuracy and validity of the NEEDS database and IPM modeling runs. Accordingly, EPA should correct the errors in the NEEDS database and correct the erroneous and inaccurate IPM inputs and then rer un the critical IPM model runs, to the extent EPA continues to use IPM modeling as a basis to develop state budgets. Given the serious limitations in IPM’s capabilities as discussed above, EPA should develop for public review and comment alternative methods of calculating unit a llowance allocations (for example, alternative methods that use appropriate measurements of units ’ historical heat input, as EPA did in the NOx SIP Call rule and CAIR). EPA should then pub lish revised proposed budgets and allocations for public review and comment. Ho wever, any proposed allocations should at most be “model” allocations for consideration by the states; for the reasons discussed elsewhere in these comments, EPA has an obligation to allow each stat e to make -- and to give each state adequate85 time to make -- any emission control decisions for sources within the state and to incorporate those decisions in SIPs.
IX. Certain EPA Assumptions and Determinatio ns Do Not Account Adequately for the Interaction Between the Proposed Rule and Other CAA Programs. A. Contrary to EPA’s Assumption, Permitting Requirements Cannot Be Expected To Be Met in Time To Satisfy the Proposed Transport Rule’s Compliance Schedule. EPA asserts, based on an analysis 52 that it conducted following the D.C. Circuit’s decision in New York v. EPA , which vacated the PCP exclusion in EPA’s NSR regulations, that NSR permitting requirements “[will] not significantly impact the construction of controls that are installed to comply with the proposed transpor t rule.” 75 Fed. Reg. at 45343/3. EPA vastly underestimates the complexity of this issue in the proposed rule. As explained above in section V.A.2, although the operation of SCR and FGD un its will reduce emissions of NOx and SO 2 , in many cases operation of these controls may be t hought to result in an increase in emissions of other pollutants by more than insignificant amounts. Contrary to the assu mptions that EPA made in its 2005 analysis, experience has shown that NSR permitting requirements will significantly impact the construction of controls. See section V.A.2 supra (noting that NSR permitting can be expected to add many months to over a year to the process of adding FGD or SCR units). EPA must take a realistic view, based on real -world, practical expe rience, regarding the implications of NSR permitting requirements for the installation of controls required under the proposed rule, taking into account the effect that the court’s vacatur of the PCP exclusion has had on NSR permitting. Such a realistic view w ould reveal that the impact of NSR permitting

52 S ee “Impact on CAIR Analyses of D.C. Circuit Decision in New York v. EPA ” (Dec. 2005), available at http://epa.gov/cair/pdfs/0053-2263.pdf.86 requirements on the construction of controls required under the pr oposed rule is likely to be significant.
B. EPA Should Provide Justification for It s Unsupported Assertion that It Is “Very Unlikely” that Pollution Co ntrol Projects Would Cause GHG Emission Increases in Excess of th e PSD Emission Thresholds in the Agency’s June 2010 GHG Tailoring Rule. According to EPA, the analysis referred to above in section IX.A, conducted following the D.C. Circuit’s decision in New York v. EPA , indicated that the court’s decision on the PSP exclusion issue would not affect the assumptions underlying EPA’s determination that CAIR was cost-effective and feasible. EPA states simply th at it believes that the same is true for the Proposed Transport Rule. 75 Fed. Reg. at 45343/3. Although EPA’s CAIR analysis did not a ddress greenhouse gases (“GHGs”) because they were not regulated CAA pollutants at that time, EPA concludes in the Proposed Transport Rule that it is “very unlikely” that pollu tion control projects would cause GHG emission increases in excess of the NSR emission thre sholds in EPA’s June 2010 GHG Tailoring Rule. 75 Fed. Reg. at 45344/1. At least in part for th is reason, EPA concludes that NSR impacts are not likely with respect to emission control proj ects required to satisfy the Proposed Transport Rule. 75 Fed. Reg. at 45344/1. EPA provides no ju stification for this assumption. If EPA is wrong, the implications for NSR permitting -- and for the necessary compliance schedule for implementation of any rule such as the Proposed Transport Rule -- will be substantial. EPA must, at a minimum, provide an analysis and ex planation to support its as sertion and make that analysis and explanation available for public comment before it proceeds further with this rulemaking.87 X. EPA Should Amend the Proposed Transport Rule To Allow for Increased Flexibility in Complian ce and Allowance Trading. A. The Variability Limits and Assuran ce Provisions Proposed by EPA Are Unduly Stringent and Should Be Adjusted. 1. Variability Limits. EPA’s explanation in the preamble to the pr oposed rule, and in the TSD on Power Sector Variability 53 (“Variability TSD”), of its method for selecting the 10 percent uniform emission variability value is less than clear. At a minimum, it does not appear that EPA’s analysis precludes a conclusion that a hi gher uniform percentage is ju stified. EPA should carefully consider the basis for adop ting a higher percentage. The Variability TSD describes an analysis that EPA performed, using its air quality assessment tool, to evaluate the effect of variability in emissions in upwind states on air quality in downwind states. According to this TSD, EPA performed this analysis using two different approaches, each of which examined the effects of variations in SO 2 emissions from upwind states on 24-hour PM 2.5 concentrations at downwind nonattain ment and maintenance monitors. Variability TSD at 43. In the first approach -- intended to replicate “t ypical” variation -- EPA projected that SO 2 emissions in each upwind state in the proposed control region would vary randomly. Id. at 44. In the second approach -- intende d to replicate “worst case” variation -- EPA projected, on a monitor-by monitor basis, that SO 2 emissions in the upwind states with the largest air quality impacts per ton on the dow nwind monitor increased to the maximum amount (up to each state’s one-year variability limit) and that SO 2 emissions in all of the other upwind states decreased to compensate for the increased emissions from the high-impact states (so that the regionwide emissions in the proposed control region equaled the sum of all state budgets).

53 EPA, “Power Sector Va riability” TSD (July 2010), available at http://www.epa.gov/airquali ty/transport/tech.html.88 Id. at 47. EPA reported that “[f]or both approaches , the effects of the inherent variation in emissions on daily PM 2.5 concentrations were estimated to be small.” Id. at 44; see also id. at 46 (reporting that the results of the analysis using the first (“typi cal” variation) approach indicated that “the combined downwind air quality impacts were essentially neglig ible”), 47 (reporting that the results of the analysis using the second (“worst case” variation) approach indicated that “the resulting increases in air quality ar e small relative to other factors ( i.e. , weather)”). UARG commends EPA for conducting this analysis and agrees in broad terms that this analysis demonstrates that inte rstate trading can play a valuab le role in reducing emissions without decreasing downwind air quality. Howeve r, it is not apparent, and EPA does not explain, why it chose to perform th is analysis using only a variabili ty limit of 10 percent of the state budgets. EPA should perform the analysis usi ng higher variability limits , in the range of at least 20 to 30 percent of each stat e’s budget. If these analyses al so indicate that the impact of upwind emissions variability on do wnwind air quality remains small, higher variability limits would be justified. UARG strongly urges EPA to consider incr easing the variability limit. A higher variability limit would encourage emission tradi ng and increased emission reductions at sources where they are most cost-effective to achieve (t hus lowering the overall co st of compliance with the program), while still ensuring that substantia l emission control levels are maintained within each state. In fact, an analysis conducted by Southern Company and described in its comments on the Proposed Transport Rule indi cates that even unrestricted interstate emission trading could yield air quality that is substantially the same as if trading were not allowed under the proposal. 54

54 See Southern Company’s comments on the PTR (describing the results of an analysis comparing state budgets under CAIR and under th e PTR, which suggests that if unlimited89 2. Assurance Provisions. EPA requests comments on the proposed assu rance provisions. 75 Fed. Reg. at 45314/2. UARG believes that the allowance surrender re quirement associated with the assurance provisions should be less than one allowance per ton emitted, in addition to the standard allowance surrender. An additional allowance surrender requirement of one allowance per ton would be unnecessarily burdensome and overly punitive. EPA states in the proposed rule that it “believes the likelihood of triggering assurance provisions is low.” Id. at 45314/1. Indeed, the example that EPA provides of a circumstance that may lead to emissions “approaching the variability limit” -- “an extended nuc lear unit outage that causes a company to run its fossil units harder to meet demand” -- indicates that EPA an ticipates the assurance provisions would likely be triggered only in unusual condi tions and for a temporary peri od, due to forces largely beyond the unit owner’s control. Id. Any allowance surrender in ad dition to the standard allowance surrender of one allowance per t on -- perhaps, for example, an additional 1⁄2 allowance (rather than the additional one allowance) on top of th e standard one-allowance surrender requirement -- would provide an adequate incentive for unit owne rs to avoid exceeding their share of the state budget with variability limits. Additionally, for similar reasons, UARG strongly believes that such an exceedance should not be considered a violation of the CAA, subject to discretionary penalties. See 75 Fed. Reg. at 45314/2 (requesting comment on whether such exceedances should be considered a violation of the CAA and be s ubject to discretionar y penalties). As explained above, any

interstate trading were permitted under the PTR, air quality indicators could be very similar to the air quality indicators if no interstate trading were permitted).90 additional allowance surrender requirement w ould provide sufficient incentive to avoid triggering the assu rance provisions. 55
B. Units Should Be Permitted To Borrow Allowances From Future Year Allowance Accounts, at Least on a Limited Basis. EPA should allow units to “borrow” allowanc es from future-year accounts for use in compliance, at least on a limited basis. This w ould allow for increased flexibility, which will be particularly important in the ea rly years of the program, especial ly if EPA promulgates a final rule that includes the ambitious co mpliance schedule that it proposes. See sections III and V

supra for UARG’s comments on the compliance schedule. However, this feature would still result in units receiving and using a finite number of allowances ove r the years and, thus, produce no overall increase in emissions. 56
C. EPA Should Not Establish Any Government-Run Allowance Auctions. Although UARG does not support EPA’s Intras tate Trading Remedy Option, if EPA promulgates a final rule based on this op tion, EPA should not provide for government-run allowance auctions. As noted a bove in section II.C, governmental auctioning of allowances is contrary to the principle that regulated sour ces are permitted to emit up to their allowance allocation levels without bearing any obligation to pay for the right to emit up to those levels.

55 UARG does not believe that EPA’s proposed discretiona ry penalties for excess emissions, 75 Fed. Reg. at 45314/3, are appropriate. Those penalties could easily amount to millions of dollars for an inadvertent exceedance of allowance levels by even a few tons in one year. EPA should at a minimum clarify that in the allowance trad ing program that EPA proposes, an exceedance of one ton of emissions w ill be treated as a single violation over one year or ozone season, as the case may be, rather th an as a separate violation for each day in that year or ozone season. This change is partic ularly appropriate because any exceedances of allowance levels under the Transport Rule are almost certain to be inadvertent.

56 One potential approach that EPA could c onsider in developing a “borrowing” program could involve a requirement that borrowers pay a reasonable amount of “inter est” in future years in the form of additional allowance requirement s, reflecting the amounts borrowed and the term of the “loan.”91 EPA explains in the Proposed Transport Rule that revenues from the allowance auctions described in the section on the Intrastate Tr ading Remedy Option would be deposited into the U.S. Treasury. 75 Fed. Reg. at 45327/2. The effect of such auctions, besides providing revenue to the federal government, would be to force affect ed sources to pay not only for emissions that exceed their emission allowance allocation limits (by purchasing allowances on the market) but also for the right to emit below those limits. No legal basis exists for charging sources for emissions below their allocation levels, and prov iding revenue to the U.S. Treasury is not a legitimate purpose of section 110(a )(2)(D)(i)(I) of the CAA. Mo reover, as discussed above, EPA has not shown that any legal authority exists fo r EPA to auction allowances and thereby impose what amounts to a tax, with tax reve nue flowing to the federal government. In short, EPA should not promulgate a rule ba sed on the intrastate trading option, but if it does, it should remove government-run allowance auctions from the design of that option. Instead, to the extent EPA concludes it is necessary to make additional allowances available under that option to energy producers with lim ited market share, EPA should provide for adjustments in the distribution of allowance a llocations but without au ctioning the allowances.
XI. Requirements for Electronic Re porting of Quarterly Reports UARG has several objections to EPA’s proposed requirements for quarterly reporting.
A. Electronic Reporting Format First, UARG objects to EPA’s proposed require ment that source owners and operators submit electronic quarterly report s “in the format prescribed by the Administrator.” Proposed §§ 97.434(d)(1), 97.534(d)(2)(ii), 97.634(d)(1), and 97.734(d)(1). In the preamble, EPA describes this requirement as identical to that co ntained in 40 C.F.R. Part 75 (“Part 75”), which establishes monitoring, recordk eeping, and reporting requirement s for the Acid Rain Program (ARP), NO x Budget Program, and CAIR. 75 Fed. Reg. at 45325/2 - 45326/1. UARG is92 surprised that EPA did not acknowledge in that discussion that the Pa rt 75 requirement was challenged judicially (by UARG), and that the litigation has not yet been resolved. UARG objects to this requirement for the same reasons it objects to the requirement under Part 75. Under Part 75, reports must be submitted in a “format to be specified by the Administrator, including electronic submissi on of data” by “direct computer-to-computer electronic transfer via EPA-provided software, unl ess otherwise approved by the Administrator.” 40 C.F.R. § 75.64(d) and (f). UAR G challenged these provisions in part based on (1) concerns regarding the nature and content of EPA’s form at, which the Agency has changed with some frequency, (2) the EPA-provided software’s failure to ensure compliance with basic requirements of the ARP and the Cross-Media Elec tronic Reporting Rule (“CROMERR”), 57 and (3) the lack of appropriate procedures for submitting reports when a source is unable to gain access to EPA’s computer with the EPA-provided software, or conn ect to the internet in a secure environment. 58 See Appalachian Power Co., et al., v. EPA, No. 99-1302 (D.C. Cir., filed July 23, 1999); Utility Air Regulatory Group v. EPA, No. 02-1254 (D.C. Cir., filed A ugust 12, 2002). These cases have been held in abeyance pending discussions aimed at resolving these concerns. As UARG explained in the Part 75 rulema king, if EPA makes the format itself (as opposed to the requirement to submit the informa tion) a regulatory requ irement, EPA has an

57 For example, EPA’s software does not pr ovide a record of “submission” that is consistent with the requirements of §§ 75.62(a) , 75.63(a), 75.64(a) and the definition of “submit or serve” under § 72.2. EPA also has provided no documentation to assure that its software satisfies the requirements of CROMERR at 40 C.F.R. Part 3.10.

58 Currently, when a source cannot gain access to EPA’s reporting system in time to meet a reporting deadline, EPA handles the issue by “allowing” the de signated representative to submit the quarterly report by email. However, submission by email does not comply with the Agency’s requirements for electronic reporti ng under CROMERR, which imposes source owner and operator liability for elec tronic reporting to an “undesigna ted” EPA electronic receiving system or without a valid elec tronic signature as defined in CROMERR. Email does not meet the electronic signature requi rements of CROMERR.93 obligation to subject that format to notice-a nd-comment rulemaking and review by the Office of Management and Budget (“OMB”). The EPA elect ronic reporting formats specified to date by the Administrator have been sufficiently complex and substantive that it is not appropriate to totally exempt them from rulemaking. 59 To the extent some flexibility is needed to make adjustments to the format, that flex ibility can be provided by rule. ARP sources have spent years and hundreds of thousands (if not millions) of dollars attempting to comply with these EPA-specified formats. The formats and related instructions for the ARP are hundreds, if not thousands, of pages in length with few or no citations to the underlying rule requirements. In some cases, th e formats have included requirements to submit data that are not otherwise required to be re ported under the rules. Each time EPA makes a revision to the format, software, or instructions, sources are requi red to respond. In some cases, this response requires modifications to the sources’ own monitoring software at significant cost. Although EPA has responded to the electric gene rating industry’s concerns by informally soliciting comment on the formats and instructions, committing to reducing the number of revisions to the format, and, in the recent redesi gn of the format, holding stakeholder meetings and providing contractor “tech nical support” during business hour s, those efforts alone cannot cure what UARG believes is a legal defect in the rule. As implemented, EPA’s electronic formats are substantive requirements that can im pose significant burdens and impact sources’ compliance status.

59 Information on EPA’s current format and submission requirements, called the Emissions Collection and Monitoring Plan System (“ECMPS”), is available at http://www.epa.gov/airmarkets/business/ecmps/inde x.html and at EPA’s contractor’s technical support website at http://ecmps.pqa.com.94 B. Adjustments to Certified Information by the Administrator Second, UARG objects to EPA’s proposed langu age authorizing the Administrator to make adjustments to information personally cert ified by a designated representative (“DR”) (or alternate DR, or “ADR”). Specifically, in proposed §§ 97.428, 97.528, 97.628, and 97.728, EPA proposes to allow the Administrator to perform independent audits conc erning “any submission” and “make appropriate adjustments of the info rmation in the submission.” Under proposed §§ 97.414(a), 97.514(a), 97.614(a), and 97.714(a), DRs a nd ADRs are required to personally certify each submission as “true, accurate, and complete.” At a minimum, EPA must make clear that any adjustments the Agency might make to information in a certified submission have not been certified by the DR or ADR. Moreover, UARG objects to the Agency’s reservation to itself of the authority to unila terally override a DR’s or ADR’s cer tification, without any procedure or criteria for establishing that the existing information is incorrect, or that the adjustment is in fact appropriate. EPA should rem ove these provisions. C. Correction and Resubmission of Quarterly Reports Proposed §§ 97.434(d)(4), 97.534(d)(7), 97.634(d)(4), and 97.734(d)(4) are new provisions that do not exist in Part 75 that would authorize EPA to (1) conduct reviews and audits of DRs’ certified quarterly reports to dete rmine whether they “meet[ ] the requirements of this subpart and part 75,” (2) notif y the DR of any “determination” that the report “fails to meet those requirements,” and (3) specify in that notification “any corrections the Administrator believes are necessary to make th rough resubmission of the quarte rly report.” EPA proposes to require that the DR make the specified correctio ns, or provide “information demonstrating that a specified correction is not necessary because th e quarterly report alrea dy meets the requirements95 of this subpart and Part 75.” Id. 60 In the preamble, EPA character izes this provision as codifying a process that is “implicit under, and has b een in continuous use in, the Acid Rain, NO X Budget, and CAIR trading programs.” 75 Fed. Reg. at 45413/2-3. UARG disagrees that th is provision is consistent with current practice a nd objects to its inclusion in this rule. Each electronic repor t submitted under Part 75 is required to contain a certification by the DR or ADR that the inform ation in the report is “true, accurate, and complete,” and that the reported data were r ecorded in accordance with Part 75. 40 C.F.R. § 75.64(c). EPA proposes to include si milar provisions in this rule. See proposed §§ 97.414(a), 97.434(e), 97.514(a), 97.534(e), 97.614( a), 97.634(e), 97.714(a), 97.734(e). Under the current Part 75 program, disagreements between EP A and DRs or ADRs (particularly following adoption of a new rule, rule revision, or reportin g format change) about the accuracy of reports are not uncommon. Disagreements can arise for many reasons, including as a result of differences in rounding methodologi es, differences in interpreta tion, EPA’s use of the reporting “format” to collect information not otherwise re quired by rule to be submitted, and other errors or programming “bugs” in the electronic data qual ity assurance checks used by EPA to identify errors. Disagreements also occur as a result of the Agency’s attempt to develop and impose new (and often unsupported) rule inte rpretations through the use of automated checks built into the EPA-provided software. Although DRs and ADRs generally will engage in discussions with EPA when EPA’s report auditing software generate s an “error” message with which the DR or ADR disagrees, nothing in the current rule or process requires the DR or ADR to “demonstrate”

60 EPA also proposes to provide the Administra tor complete discretion to decide what “a reasonable time period” is for resubmission. UARG objects to this as well. If EPA can design an appropriate resubmission requirement, EPA also should propose and solicit comment on what would constitute a “reasonable time period.”96 the correctness of its position in order to certif y and submit a report or to avoid resubmission of a report. To the extent the Administrator believes that a Part 75 report does not in fact meet the requirements of this subpart, EPA (not the DR or ADR) bears the burden of establishing that failure. EPA cannot use its reporting “forma t” and auditing techni ques to establish a presumption of what constitutes compliance w ith Part 75, without subjecting its “reporting format” and software (including all of the audits contained in it) to rule making. EPA also cannot by rule shift the burden of proof with respect to establishing compliance to a source owner or operator’s DR or ADR, who already has met the cer tification requirements of the rule, or compel a DR or ADR to certify a resubmitted report that the DR or ADR does not believe is correct. EPA should remove this provision, or restructur e it to require resubmission only after the Administrator (not the source ow ner or operator) has established through an appropriate dispute resolution procedure that the report does not in fact m eet the rule’s requirement. 61
XII. As a Matter of CAA Procedural Requirem ents, the Proposed Rule’s Unfounded Assumptions, Errors, and Apparent Anomalies -- and EPA’s Failure To Explain Adequately Critical Aspects of the Pr oposal and To Include in the Docket Information that Would Enable Replication of EPA’s Process -- Make the Proposed Rule Inadequate for Public Comment. Even apart from the fundamental legal defi ciency in the Proposed Transport Rule -- i.e. , EPA’s use of a “FIP-first” approach that impr operly bypasses the SIP pr ocess, as described above -- and other flaws in EPA’ s proposal related to that defi ciency, such as an improperly

61 EPA recently proposed a report resubmission pr ovision in proposed revisions to its rule for Mandatory Reporting of Greenhouse Gase s at 40 C.F.R. Part 98, 75 Fed. Reg. 48744 (Aug. 11, 2010). See proposed § 98.3(h). This provision, which addresses resubmission in the context of “substantive errors,” does not require or pur port to allow EPA to unila terally resolve questions of compliance with Part 75 in the context of an audit of a quarterly report. It merely requires the source owner or operator to resubm it a report in the context of his/ her own determination that the report contained a “substantive e rror,” or to submit information to the Administrator explaining why the DR or ADR does not believe the re port contains a subs tantive error.97 accelerated compliance schedule, other elements of the proposed rule make it inadequate as a notice of proposed rulemaking for public comment. First, the unfounded assumptions, errors, and anomalies in the Proposed Transport Rule, as described in these comments, make EPA’s pr oposal inadequate for public comment. For example, the assumptions regarding individual units described in section VIII above affect the state budgets and allocations of allowances. These problems are serious, and some of them appear to be due to causes that are not readily discernible from EPA’s pr oposed rule and TSDs. Such problems might have been avoided had EPA issued an advance notice of proposed rulemaking as UARG requested in April 2009, 62 instead of developing th e proposed rule without any meaningful opportunity for preliminary public review and input. Similarly, EPA’s explanations of both its air quality assessment t ool and the budgets and unit allocations are inadequate. Without additional explanation from EPA, it is impossible to replicate or validate EPA’s significant contribution analysis and st ate budget and unit alloca tion calculations. See comments of Southern Company on the PTR (describi ng the lengths that it had to go to in order to try to replicate parts of EPA’s analyses). EPA must now revise the Proposed Transport Ru le to remove these errors and anomalies, correct its ill-founded assumptions and judgments, and provide the critical missing explanations, and must either withdraw the proposed rule and begin the rulemaking anew or issue a comprehensive supplemental notice of proposed rulemaking for public comment.

62 See Presentation to EPA on Behalf of UARG: CAIR Remand Issues: Principles that Should Guide EPA’s Upcoming Rulemaking; The Perspective of the Utility Air Regulatory Group, at slide 2 (Apr. 17, 2009).98 XIII. Conclusion. For the foregoing reasons, and reasons to be discussed in UARG’s comments on the NODA, although the Proposed Transport Rule do es contain some commendable elements, the proposed rule overall is seriously flawed on lega l, policy, and factual grounds. These flaws are so substantial that EPA should withdraw the pr oposed rule and replace it with a new proposed rule that remedies the specific defi ciencies identified by the court in North Carolina v. EPA , adopts a reasonable implementation and compliance schedule that allows adequate time for development of SIPs -- rather than impose FI Ps in the first instance -- and does not impose emission reduction obligations on affected states that are more demanding than those imposed by
CAIR.Attachment I Cichanowicz, J.E., “Implementation Schedules fo r Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Pro cess Equipment” (Oct. 1, 2010).IMPLEMENTATION SCHEDULES FOR SELECTIVE CATALYTIC REDUCTION (SCR) AND FLUE GAS DESULFURIZATION (FGD) PROCESS EQUIPMENT

October 1, 2010
Prepared by J. Edward Cichanowicz
Prepared for Utility Air Regulatory GroupImplementation Schedules for FGD and SCR Process Equipment

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### TABLE OF CONTENTS

SECTION 1 EXECUTIVE SUMMARY ................................ ................................ .. 1
- 1 SECTION 2 BACKGROUND ................................ ................................ ................... 2
- 1 2.1 PROCESS EQUIPMEN T REQUIRED 2

- 1 2.1.1 F LUE G AS D ESULFURIZATION (FGD) 2

- 1 2.1.2 S ELECTIVE C ATALYTIC R EDUCTION (SCR) 2

- 3 2.2 ELEMENTS OF A COMMERCIAL PROCUREMENT SPECIFICATION 2

- 4 2.2.1 C ONCEPTUAL D ESIGN /P REPARATION OF S PECIFICATION 2

- 4 2.2.2 I DENTIFICATION OF Q UALIFIED C ANDIDATE B IDDERS 2

- 6 2.2.3 S OLICITATION AND R EVIEW OF B IDS /S ELECTION OF C ONTRACTOR 2

- 6 2.2.4 N EGOTIATION OF C ONTRACT T ERMS /C ONTRACT I SSUANCE 2

- 7 2.2.5 S ECURING P ERMITS TO C ONSTRUCT AND O PERATE THE R ETROFITTED C ONTROL E QUIPMENT 2

- 7 2.2.6 F INALIZATION OF D ESIGN AND P REPARATION OF F ABRICATION D RAWINGS 2

- 10 2.2.7 M OBILIZATION OF THE W ORKFORCE TO S ITE 2

- 11 2.2.8 A CTUAL C ONSTRUCTION 2

- 11 2.2.9 P ROCESS E QUIPMENT T IE - I N 2

- 12 2.2.10 P ROCESS S TARTUP 2

- 12 SECTION 3 FLUE GAS DESULFURIZATION (FGD) SCHEDULES ............... 3
- 1 3.1 INSTALLATION OF A SINGLE FGD SYSTEM AT A SITE 3

- 2 3.2 INSTALLATION OF TWO FGD PROCESSES 3

- 3 3.3 INSTALLATION OF THREE OR MORE FGD PROCESS UNITS AT ONE SITE 3

- 4 3.3.1 A LABAMA P OWER G ORGAS U NITS 8

- 10 (61 M ONTHS ). 3

- 5 3.3.2 A LLEGHENY E NERGY H ATFIELD ’ S F ERRY U NITS 1

- 3 (45 M ONTHS ) 3

- 5 3.3.3 D UKE E NERGY A LLEN U NITS 1

- 5 (49 MONTHS FOR THE FIRST RETROFIT ; 1 EXTRA MONTH FOR THE OTHER ). 3

- 6 3.3.4 D UKE M ARSHALL U NITS 1

- 4 (46 MONTHS FOR THE FIRST RETROFIT ; 6 MORE MONTHS FOR THE OTHER THREE RETROFITS ). 3

- 6 3.3.5 F IRST E NERGY S AMMIS U NITS 1

- 7 (56 MONTHS ). 3

- 6 SECTION 4 SELECTIVE CATALYTIC R EDUCTION (SCR) AND LOW NO x BURNER SCHEDULES ................................ ................................ ............................... 4
- 1 4.1 SELECTIVE CATALYTIC REDUCTION (SCR) 4

- 2 4.1.1 I NSTALLATION OF A S INGLE SCR U NIT AT A S ITE 4

- 3Implementation Schedules for FGD and SCR Process Equipment

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- 4 4.2 LOW NO x BURNERS 4

- 5 SECTION 5 CRITIQUE OF EXAMPLES CITED BY EPA ................................ . 5
- 1 5.1 FGD INSTALLATIONS

– OVERVIEW 5

- 1 5.2 EPA EXAMPLES OF FGD INSTALLATIONS BEING COMPLETED IN A TOTAL OF LESS THAN 30 MONTHS 5

- 2 5.2.1 C ENTRALIA W ET FGD 5

- 2 5.2.2 T AMPA E LECTRIC B IG B E ND 5

- 3 5.3 EPA EXAMPLES OF SCR INSTALLATIONS BEING COMPLETED IN A TOTAL OF LESS THAN 30 MONTHS 5

- 4 5.4 OTHER FACTORS 5

- 4 SECTION 6 SUMMARY/CONCLUSIONS ................................ ............................ 6
- 1 6.1 DEMAND 6

- 2 6.2 LABOR PRODUCTIVITY 6

- 2 6.3 ENGINEERING 6

- 2 6.4 PERMITTING 6

- 2 SECTION 7 REFERENCES ................................ ................................ ..................... 7
- 1Implementation Schedules for FGD and SCR Process Equipment

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LIST OF FIGURES Figure 2

- 1. Typical Wet FGD Absorber Tower

................................ ................................ ....... 2

- 2 Figure 2

- 2. Perspective View of SCR Reactor for Coal

- Firing (Babcock & Wilcox product information: www.babcock.com/products/environmental_equipment/scr.html)

............................ 2

- 3 Figure 3

- 1. Timeline of FGD Activities

................................ ................................ ....................... 3

- 1 Figure 3

- 2. Sammis Site Layout

................................ ................................ ................................ .... 3

- 7 Figure 4

- 1. Timeline of NO x Control Projects

– SCR

................................ ............................. 4

- 1 Figure 4

- 2. Timeline of NO x Control Projects

– LNB

................................ ............................. 4

- 2 Figure 5

- 1: Timeline Showing Recent Installed FGD Capacity by Startup Date

........ 5

- 2

LIST OF T ABLES Table 2

- 1. Lead Time (Weeks) for Key FGD Components (after Katzberger, 2007)

................................ ................................ ................................ .................. 2

- 2 Table 6

- 1. Summary of Design, Fabrication, I nstallation Period

................................ ..... 6

- 1Implementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 1 EXECUTIVE SUMMARY This report evaluates the different factors that can affect how long it takes to design, permit and construct flue gas emissions control technologies that power plant owners m ay have to install on their electric generating units (EGUs) in order to meet the emission reduction requirements that will be included in the United States Environmental Protection Agency’s (EPA’s) final Transport Rule, which is now scheduled to be publis hed in mid 2011. The control technologies considered by this report as candidates to be used to meet the emission reduction requirements of the final Transport Rule are flue gas desulfurization (FGD) systems for the control of sulfur dioxide (SO 2 ) emission s; and Low NO x Burner s (LNB) and selective catalytic reduction (SCR) reactors for the control of nitrogen oxide (NO x ) emissions.
I n the preamble to its Proposed Transport Rule (published in the Federal Register on August 2, 2010) and in earlier studies up on which EPA now relies (EPA, 2005; EPA, 2002), EPA says that the Agency expects it will take 27 months of total effort for a n electric generating company to plan, engineer, install, and start up one FGD system at one unit at a plant site; and that the tot al effort to retrofit three FGD systems at one plant site might take 36 months. In addition, EPA says that it expects it will take 21 months of total effort for a n electric generating company to plan, engineer, install and start up one SCR system at one un it at a plant site; and that it might take about 35 months of total effort for a company to complete the retrofit of 7 SCR systems at a plant site. Also, in the preamble to its Proposed Transport Rule, EPA indicates that it believes it will take less than 6 months of total effort for a utility company to plan, engineer, install and start up a low NO x burner system at a plant site. This report includes a broad review of numerous FGD, SCR, and LNB retrofits that have been accomplished during the past ten y ears , describ ing each of the key steps that power plant owners must follow in order to be able to install and operate these control technology systems. In addition, this report presents more detailed information about the specific obstacles faced by the pl ant owners that have recently had to retrofit FGD and SCR systems on their plants, including some obstacles that were not faced by companies having to make such retrofits 5 to 10 years ago. Following the presentation of background information in Section 1 of this report, Section 2 describes the steps affected power plant owners must take in order to design, permit, and implement one or more SCR or FGD installation projects. Section 3 then presents information on specific FGD retrofits that have recentlyImplementation Schedules for FGD and SCR Process Equipment

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- 2 b een undertaken

– or are now in the process of being undertaken

– by electric generating companies. Section 4 then contains information about recent or ongoing projects for the installation of NO x controls: SCR and low NO x burners. The projects discussed i n Sections 3 and 4 provide examples of the obstacles that companies now face in undertaking such retrofits, including obstacles they (and others in the industry) may not have faced 10 years ago. Next, Section 5 addresses some of the retrofit cases that EPA cites in its much earlier reports (EPA, 2005; EPA, 2002). Finally, Section 6 summarizes observations and offers alternative, realistic schedules for equipment installation.Implementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 2 BACKGROUND This section presents background information, describing the type of equipment retrofit and the key activities involved in undertaking such equipment installations.
2.1 PROCESS EQUIPMENT RE QUIRED The type of process equipment required for a commercial FGD and SCR process is described, highlighting those aspects th at affect fabrication and installation.
2.1.1 F LUE G AS D ESULFURIZATION (FGD) The flue gas desulfurization (FGD) system is comprised of four key elements: (a) reagent receiving and preparation equipment, (b) SO 2 absorber tower, (c) byproduct dewatering an d management equipment, and (d) a wet stack (optional). The latter wet stack is considered optional particularly if an existing wet FGD process operates at the station, but is usually required for stations without FGD equipment and thus “dry” stacks.
The most visible element of the FGD process is the absorber tower, where flue gas SO 2 contacts finely prepared and dispersed alkali reagent. Figure 2

- 1 depicts a commercial absorber tower. Most absorber towers can be located near the stack, pending routing of ductwork. Installing or erecting absorber towers requires cranes to relocate material, boilermakers for special

- purpose welding, and other special trades and craft workers. Absorber towers are physically large and their installation has triggered construc tion delays, particularly where special exotic corrosion

- resistant alloys were required for liners. These delays, however, were generally not the project rate

determining step for the FGD equipment installed in 2008

- 2010. Rather, what typically caused pr oject schedules to be prolonged in the 2008 to 2010 timeframe was the lack of availability of heavy

- duty process equipment: reagent mills (pulverizers) and flue gas fans. In addition, projects were delayed by the limited number of stack erectors: reporte dly only 4

- 6 in the world with what some observers judge to be adequate experience. Katzberger (2007) describes the role of these items in more detail. Of particular note is the role of “ball mills” used to prepare limestone. The order

- to
- delivery time for this category of equipment escalated from 32 weeks in 2003, to 65 weeks (fall of 2005), 68 weeks (August 2006), 70 weeks (December 2006), and 75 weeks (April 2007).Implementation Schedules for FGD and SCR Process Equipment

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- 2 Figure 2
- 1 . Typical Wet FGD Absorbe r Tower http://www.babcockpower.com/index.php?option=products&task=viewproduct&coid=17&proid=11 ) AEP reports that its most recent (August 2010) attem pt to purchase a ball mill resulted in a 90 week delivery schedule from the vendor. Table 2

- 1 summarizes the escalation in delivery time of ball mills and other key process components.
Table 2
- 1 . Lead Time (Weeks) for Key FGD Components (after Katzberger, 2007)Implementation Schedules for FGD and SCR Process Equipment

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- 3 Transformers and switchgear can also be long

- lead items, with some companies reporting that it took more than 100 weeks to get delivery of such items. In addition, companies have reported extensive delays in the overall installation process caused by the need to get a broad array of permits and authorizations for SCR and FGD installations. As discussed more below, plant owners must have some of the needed permits and authorizations in hand before the y can begin most of the site work for FGD and SCR installations.
2.1.2 S ELECTIVE C ATALYTIC R EDUCTION (SCR) Unlike the case for FGD, SCR process reactors are installed within the “heart” of the plant layout

– extracting gas from the economizer exit and r eturning it to the air heater inlet. This location is necessarily constrained, as plant design did not envision access for such large equipment. Figure 2

- 2 depicts a typical SCR reactor. Finding space for and retrofitting such equipment is challenging at a ll sites.

Figure 2
- 2 . Perspective View of SCR Reactor for Coal
- Firing (Babcock & Wilcox product information: www.babcock.com/products/environmental_equipment/scr.html )Implementation Schedules for FGD and SCR Process Equipment

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- 4 2.2 ELEMENTS OF A COMMER CIAL PROCU REMENT SPECIFICATION This section addresses the steps in a project to design, procure, and install process control equipment such as SCR and FGD. It is convenient to consider the required activities as ten separate steps. Many of these steps can be conduc ted in parallel but some must be sequential. Each of these steps is described in the following text: Conceptual process design and preparation of specification Identification of qualified candidate bidders Solicitation and review of bids; selection of co ntractor Negotiation of contractual terms and conditions, and contract issuance Securing environmental permits and other needed authorizations and approvals Finalization of the process design and preparation of fabrication drawings Mobilization of the wor kforce to site Actual construction Process Equipment Tie

- in Process Startup Each of these key steps is further described in this section.
2.2.1 C ONCEPTUAL D ESIGN /P REPARATION OF S PECIFICATION As part of developing a conceptual design for FGD or SCR syst ems, it is necessary for the power plant owner to select the specific type of equipment to be applied, determine the feasible range of control efficiency, identify potential byproducts from operation of the new control equipment, and project the capital an d operating cost range. Also, as part of conceptual design, a power plant owner must identify any site characteristics or requirements that could make it more difficult

– or more expensive

– than is typical to install and operate the proposed new equipment . This step will require at least several months but typically takes 6

- 12 months, depending on site complexity. The owner of a large, multi

- state system reports that taking 9

- 12 months to complete this process is a prudent way to minimize risk and avoid co st overruns. Numerous other items can prolong this activity. These include the need to (a) undertake a thorough review and solicitation of available fuel suppliers, perhaps qualifying new fuel sources

– particularly for conventional wet limestone FGD, wh ich may allow the firing of coals with higher sulfur content not historically used at a station; (b) make a detailed characterization of site conditions, including soil characteristics, the presence of underground utilities, and available water for process make

- up; and (c) develop a detailed description of how the unit will operate over the future decades (which is not necessarily the same as historical operations).Implementation Schedules for FGD and SCR Process Equipment

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- 5 This and other preconstruction steps typically take over 12 months to complete. Some compan ies

– particularly those operating multiple EGUs at multiple sites

– may be able to take actions to reduce the time needed for engineering and for the procurement process (which is discussed below). Specifically, it may be possible for a plant owner to red uce engineering and procurement timelines to a year, or just under one year, by establishing a common

- design absorber and other process equipment. The best example of this is Duke Energy, which has used a common

- design absorber and auxiliary equipment in the retrofits of FGD systems at 12 individual units at 4 generating stations in North Carolina

– 4 units at Marshall, 2 at Belews Creek, 5 at Allen, and 1 at Cliffside (McCarthy, 2004). When Duke engaged Alstom to evaluate such an approach in 2003, it was at a point when none of the Duke units in North Carolina had yet deployed FGD. Because Alstom was working on such a relatively clean slate and because the fuel sources were relatively consistent, Alstom was able to develop for Duke’s North Carolina plants a system
- wide design for FGD absorbers and support equipment. A combination of these components was used in all applications in North Carolina, which reduced engineering and procurement actions. 1 As a result of this effort, completion of the engineering a nd procurement steps for FGD installations at each affected Duke plant in North Carolina generally took a year or just under one year. (Notably, McCarthy (2004) reports that each station underwent a two

- phase engineering analysis in order to ensure that t he work to be done was properly described. The first phase established the design basis (gas flow rate, gas composition, available reagent composition), optimized a standard absorber design, established balance

- of

- plant needs, and developed a layout and pr eliminary cost. The second phase addressed details of balance

- of

- plant and auxiliary equipment, and developed detailed contracts for fabrication and construction schedules by which to manage the work and hold subcontractors accountable. Each phase reported ly required 6 months. Such attention to detailed design is necessary, for either approach that emphasizes a system versus an optimized individual unit design. Before awarding contracts valued at several hundred million dollars, any less effort in the prese nt activist climate could invite prudency challenges.) Similarly, Southern Company employed common process designs developed by two suppliers

– Chyoda Corporation and AdvaTech LLC

– in assembling an FGD strategy for 12,000 MW of capacity (Wall, 2010).

1 After the system design strategy was conceived for Duke Energy’s Carolina units in 2003, Duke Energy merged with Cinergy in May of 2005

. It was not possible to use the “Carolina approach” for the former Cinergy plants , but Duke was able to use alternative design approaches for the former Cinergy plants, based on those plants’ considerable experience with higher sulfur fuels.Implementation Schedules for FGD and SCR Process Equipment

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- 6 T he use of a system

- wide engineering approach may not be applicable, or provide high payoff, to all owners. This approach may not be beneficial to small systems

– those with 1 or perhaps 2 units. Also, owners of large multi

- state systems

– that have in

- plac e “legacy” FGD equipment on existing units, and that have developed significant expertise and experience with coals native to their systems

– may not fully benefit from common design approaches.
2.2.2 I DENTIFICATION OF Q UALIFIED C ANDIDATE B IDDERS Once th e scope of the project is defined, owners can start to identify the candidate bidders for the project, i.e., vendors that are qualified to satisfactorily deliver and install the components of the project. To take advantage of competitive forces that can re duce the price of a project (and to avoid prudency challenges that can arise from seeking bids from only one provider), power plant owners typically want to receive bids from a broad list of candidates. Because of the high cost involved to prepare a bid in response to a request for proposal ( RFP ), and to review the bids, good business practice leads most power plant owners to solicit bids only from suppliers believed to be qualified. This step in the procurement process is also, however, intended to elim inate the possibility of limited or no bids, which can force plant owners to start the whole process over again. The possibility of this happening is very real. Katzberger (2007) noted that in 2007 some RFPs received one

– or in some cases no

– qualifying bids. This step typically requires at least 1 month. The most common delays are those resulting from potential bidders in submitting financial surety and market “backlog” data, which is important particularly in constrained (i.e., sellers) markets.
2.2. 3 S OLICITATION AND R EVIEW OF B IDS /S ELECTION OF C ONTRACTOR The process of deciding which suppliers to use is not based solely on cost. Many other factors must be taken into account in order to assure that the best long

- term solution is found, one which will assure approval by both management and, in the case of regulated companies, by PUC staff. This goal is factored into the process of soliciting and reviewing competitive bids. In particular, the bid solicitation process requires issuing a detailed proce ss specification, hosting a bidder meeting and site inspection, reviewing the submitted bids, and selecting the successful contractor. Generally, bidder meetings and site “walkdowns” are held within 2

- 3 weeks of issuing the specification, although this par t of the process can often take 4

- 6 weeks in the case of large, multi

- unit projects. A minimum of 30 days following the site inspection is required to prepare a bid. Review of bids will be conducted by power company staff or designated engineering firms. T he successful supplier is selected based on numerous factors, including relevant experience, ability to meet projected schedule, experience in containing cost, and historical performance on similar projects.Implementation Schedules for FGD and SCR Process Equipment

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- 7 This entire step typically requires 3

- 5 months but can take longer, depending on the need for follow

- up to clarify issues and proposed responses. For example, the development of an adequate bid in response to an engineering specification can take longer when demand on equipment and suppliers is high. 2 Also, the time for completing this part of the process can be extended when plant owners receive inadequate or partially responsive bids, need addendum or additional submittals from bidders, or must seek clarifications of the responses they get.
2.2.4 N E GOTIATION OF C ONTRACT T ERMS /C ONTRACT I SSUANCE Once the preferred contractor is selected, that contractor and the plant owner must agree to acceptable terms and conditions. The framework of acceptable terms and conditions is defined in the specification, an d bidders in their proposals can take exceptions to the proposed conditions. All these details cannot be resolved in the proposal process. After the preferred contractor has been selected, the time it will take to finalize contract terms will depend on se veral factors, including whether the plant owner and contractor have previously worked together and the nature of the contract terms. For example, it may take 1

- 2 months to negotiate standard terms and conditions where the plant owner is familiar with and has previously worked with the contractor. For larger projects where the plant owner and selected party have not previously worked together, it can take longer

– sometimes as long as 3

- 5 months. Also, the negotiation of non

- standard terms and conditions ca n add time to the overall process. One example is the financial surety details

– how much, if any, of a financial bond must be posted, or the damage provisions of a contract in the event of non

- performance. For projects that are conducted as an open book a lliance, the rate structure of relevant personnel and the financial incentives and penalties to reward or penalize performance can require lengthy financial and legal analysis.
2.2.5 S ECURING P ERMITS TO C ONSTRUCT AND O PERATE THE R ETROFITTED C ONTROL E QUIP MENT Securing all pre

- construction permits needed for the design and installation of pollution control projects can be a time

- consuming process

– but companies can incur legal liabilities and run other risks if they start installation before they have key permits in hand. Thus, the typical approach is for companies to finalize the conceptual design of equipment and to have in place the major contracts and then

– armed with detailed information

– they are in the best position to start the process of getting all needed permits and other regulatory authorizations.

2 Not surprisingly, a lmost without exception, it has been possible to accelerate project schedules only during times when demand on equipment and suppliers was low.Implementation Schedules for FGD and SCR Process Equipment

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- 8 As part of this step, plant owners will not only need to get permits governing the treatment of flue gas emitted from the retrofitted control equipment, but also to get other environmental permits (to cover other emissions of air pollutants, water discharges, and the treatment of waste water and the management of solids byproduct) and a broad array of other authorizations (for example, from zoning boards and public utility commissions). As just note d, although parts of the installation process can go forward in parallel with the permitting/authorization process, some permitting programs prohibit a company from going too far in the construction process without first getting specific pre

- construction a uthorizations. And getting all those authorizations has become much more time

- consuming and complicated during the past five years, thus making it a possible major bottleneck for the installation of FGD and SCR systems. This is especially the case for powe r plant stations at which FGD and SCR control systems have not previously been installed. There are many reasons that permitting has recently become more complicated and time

- consuming, including but not limited to the following. Increased Difficulties in Getting Preconstruction Permits Under the Clean Air Act

. The operation of SCR and FGD units will significantly reduce emissions of NO x and SO 2 , respectively, but operation of that control technology may result in a “collateral increase” in emissions of a byproduct species other than NO x or SO 2 . For example, the operation of wet FGD and SCR

– while reducing SO 2 and NO x emissions

– may increase sulfuric acid mist by more than insignificant amounts. Also, operating low NO x burners will reduce NO x emissions b ut under some conditions have been thought to increase carbon monoxide (CO) emissions. Concern for a possible increase in CO emissions may delay permit approval by some agencies. (Recent installations of LNBs, in conjunction with improved combustion contro ls, have not increased carbon monoxide emission rates.) The new source review preconstruction permitting program can be triggered by projects that will result in a significant net emissions increase of one or more regulated pollutants. Prior to late 200 5, projects that installed environmental control equipment did not trigger the time

- consuming new source review preconstruction permitting process because such projects were subject to the pollution control project exclusion (PCP exclusion) in EPA’s new so urce review (NSR) rules. In December 2005, a court decision vacated the PCP exclusion. As a result, the NSR permitting process may be triggered by a project to install an FGD, SCR or LNB system, if the operation of that control system may result in the inc rease of a pollutant other than the pollutant being controlled by the FGD, SCR or LNB unit. Having to obtain a new source review permit could delay installation of the new control system because of the elaborate procedures associated with NSR permitting. For example, the process of obtaining a new source review permit prior to the beginning of construction for FGD or SCR units, even if consisting of no more than a paper exercise, can add many months to the overall process. And if a full

- blown review is ne eded (perhaps to evaluate emissions of greenhouse gases once the NSRImplementation Schedules for FGD and SCR Process Equipment

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- 9 process is scheduled to start applying to greenhouse gas emissions in early 2011), that could add a year or more to the entire process. NSR provisions were not a problem faced by compa nies installing pollution control projects in the first part of the last decade. 3 Thus, the two key SCR examples cited by EPA

– those at the Kintigh and Keystone stations

– were retrofits that did not address the NSR implications of enhanced SO 3 emissions. Permits Governing Byproduct Management

. In addition to securing permits authorizing the release of air pollution associated with the operation of pollution control systems, power plant owners also must secure permits to address other environmental conse quences of operating such equipment, including permits for the treatment and/or storage of the byproducts of both wet and semi

- dry FGD systems. For a variety of reasons

– including public concerns over coal ash management that have prompted examination of the benign byproducts of both wet and semi

- dry FGD, such as gypsum

– addressing this issue can now take 4 to 5 years. Some of the specific examples presented in Sections 3 and 4 of this report demonstrate that securing a land use management permit for FG D byproducts can take longer than four years and can itself be an absolute impediment to the installation of a complete system in under 30 months. For example, AEP reports instances in which the time from preparing the permit application for a landfill to the first storage was 40

- 42 months. (As discussed in separate comments being filed by AEP, this was the case for the Cardinal and Mountaineer FGD projects). Also, Georgia Power Company reports that it took over 48 months to obtain a preconstruction permit for a byproduct management site and an additional 14 months to complete construction of that installation, a total of over 60 months. It can also take time to secure the necessary permits to authorize use of a separate byproduct management site not loca ted on plant property. AEP reports that the permitting process for a separate byproduct management site located remote from an existing site can add 10 to 20 months to a project schedule. Examples from Duke Energy in North Carolina also demonstrate this p oint. Duke staff report the timeline to secure a workable landfill on plant property in their possession has been 42

- 48 months (Hallman, 2010). This timeline includes locating and assessing the suitability of the site (18

- 22 months), securing the permit to construct (10

- 12 months), construction (12 months), and securing the operating permit (2 months).

3 Although a company may be able to avoid triggering the NSR permitting process by adding other controls to reduce emissions of collateral pollutants, that will not necessarily shorten the overall permitting process. Specifically, adding pollution control equipment to reduce emis sions of collateral pollutants means going through the above

- listed steps

– including engineering design, solicitation of bids, permitting, etc.

– before those additional pollution control systems can be constructed.Implementation Schedules for FGD and SCR Process Equipment

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- 10 Public Utility Commission (PUC) Approvals to Install Pollution Control Equipment

. Where PUC approvals are needed, the length of time it can take to seek a nd receive such approvals can vary widely, from 6 months to more than one year. For example, AEP reports that in one state in which it owns generating units (Kentucky), the PUC

– after receiving an application

– typically takes 9 months to act on that appl ication. Another example comes from Minnesota: the Minnesota PUC required 18 months to approve plans by Xcel Energy’s Northern States Power (NSP) subsidiary, for a series of environmental upgrades (Hansen, undated). These upgrades included applying SCR an d dry FGD with a new baghouse to NSP’s King Station, in addition to repowering smaller units with natural gas combustion turbines.
Other Authorizations

. Individual companies point to other, more site

- specific permitting issues that have arisen or are lik ely to arise when they seek permits to install FGD or SCR systems. For example, some companies report that the operation of pollution control equipment will result in discharges that will trigger the need for revisions to source Clean Water Act permits. Fo r discharges into some water bodies ( e.g., those that have stringent restrictions on discharges of any additional nutrients), that permitting process could be extremely difficult and time

- consuming. Other companies point to the increasing regulatory u ncert ainty surrounding effluent guideline regulations , noting that such uncertainty can hinder the decision

making process and make the process iterative if regulations require additional changes or alterations to the plant not anticipated in the original permi t applications . Yet other companies note the regulatory complications involved in locating, constructing, and operating pollution control equipment in urban areas, where they may face zoning challenges, restrictions on the truck traffic related to such ope rations, and even height restrictions if equipment is to be located near an airport. In summary, completion of this step will routinely take two years and can often take up to 4 years, making it a major impediment to the completion of FGD and SCR installa tions in less than 30 months.
2.2.6 F INALIZATION OF D ESIGN AND P REPARATION OF F ABRICATION D RAWINGS The engineering contractor will finalize design and fabrication drawings. These detailed drawings provide specific instructions as to what type of equipment to procure and install. Final design begins almost immediately after the engineering or supplier contractor is selected and will last for 15 to 45 months. Most delays in preparing the final design are due to identifying site limitations or constraints th at are not obvious at preliminary design

– such as the presence (or lack of ) underground utilities orImplementation Schedules for FGD and SCR Process Equipment

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- 11 other structures, or soil properties. Much of this process can be conducted in parallel with other equipment installation activities.
2.2.7 M OBILIZATIO N OF THE W ORKFORCE TO S ITE Securing the construction services of key trades and crafts staff must be executed promptly upon execution of construction contracts. When there are not a significant number of competing projects going on simultaneously, this can be accomplished in 1 to 3 months. It can take longer, however, when there are a significant number of similar projects underway and competing for the same skilled workforce. Significant regional differences in workforce availability or mobility can affect this element of construction.
2.2.8 A CTUAL C ONSTRUCTION Construction activities are initiated immediately following mobilization of the workforce to the site. Typically, progress is accomplished according to a rapidly accelerating rate, starting with pre paration of the site for laydown area, assembling necessary equipment, and initiating concrete and foundations work. Of course, construction cannot start until the necessary fabricated and raw materials can be delivered to the site. The extensive delays i n delivery of the key components defined in Table 2

- 1, as well as electrical and switchgear components, had a significant impact on FGD construction schedules in the 2008

- 2010 timeframe. The lack of availability of key components could also adversely affec t FGD and SCR installation schedules in a future 2012 to 2014 time frame. Although some fabrication work can take place off

- site, restrictions on the size of process equipment that can be transported limit the amount of off

- site fabrication. The physical size of the SO 2 absorber tower in Figure 2

- 1 and of the SCR reactor in Figure 2

- 2 indicates that most construction must occur on

- site. The length of time it will take to complete the construction process will vary from site to site depending upon several key factors: the complexity of the site and the presence of other in

- plant equipment, access to the site and limits on where the cranes required to install heavy equipment can be placed, the amount of existing equipment demolition or relocation, and site remediation. For example, as will be described in Section 4 of this report, the SCR reactors at First Energy’s Sammis facility could not be installed until contractors first removed from the site the original equipment ESPs, which had been abandoned “in

- p lace” when new particulate control equipment was installed. Also, the highly publicized retrofit of wet FGD to PSNH Merrimack required two years of site preparation, and one year of major construction (PSNH, 2010). Also, the productivity of construction l abor is key, and there can be significant differences in regional workforce productivity, which can affect installationImplementation Schedules for FGD and SCR Process Equipment

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- 12 schedule. Experience with the equipment retrofits in 2008

- 2010 showed a strong demand for the most experienced and productive staff. Con sequently, the skilled trade craft assigned to later

- in

- the

- pipeline projects

– often projects being undertaken by smaller companies, seeking to complete only 1 or 2 retrofits

– tended to be the less experienced and less productive staff. Finally, timely a ccess to equipment

– avoiding delays in delivery of equipment

– must be minimal.
Construction timelines under the best conditions have been about 25

- 30 months, with more complex sites requiring more than 40 months. For multiple units, the construction ti meline can extend for several years.
2.2.9 P ROCESS E QUIPMENT T IE - I N Following actual construction of the control equipment, a unit outage is necessary to tie in process ductwork to an existing unit. Companies usually try to conduct tie

- in activities duri ng or near planned outages, but such outages are typically not scheduled solely for the purpose of equipment tie

- in, and such outages are never scheduled during peak load periods. Also, in cases involving more complicated installations, the tie

- in process will likely extend beyond the time usually set aside for outages. In some cases, the equipment tie

- in process can be accomplished in as little as 3

- 4 weeks, but this process will require up to 3 months at sites where conditions are more challenging. For example, at TVA’s Bull Run Station, a 10

- week outage was required for tie

- in of the FGD process. This 10

- week period was due to the complex ductwork arrangement that prevented the use of conventional modular construction methods; also, the FGD retrofit req uired the company to make changes to the air heater and forced draft fans. Another example would be the retrofit of SCR at Georgia Power Scherer Unit 3. That effort required a 3 month outage due to the complexity of ductwork. Similarly, the tie

- in period r equired to install SCR at Unit 4 of Plant Hammond was 7 weeks

– simply due to the inability to get cranes close to the ductwork to be penetrated.
2.2.10 P ROCESS S TARTUP Once the equipment is installed and tied in, it generally takes at least 30 days and c an take up to 90 days of shakedown operations, testing, and process tuning before the power plant owner will take over unit operations. In some instances a process shutdown and re

- start is required to mitigate a performance issue. In summary, there are nu merous steps involved in the design permitting and construction of SCR or FGD process equipment, only a few of which can be conducted in parallel. And the overall period of time that it will take to complete the entire installation and design process will depend upon many factors including, for example, the size and configuration of the site at which equipment is being installed, whether (for FGD installations) the process equipment is located at a site whereImplementation Schedules for FGD and SCR Process Equipment

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- 13 FGD already exists, and whether the site has in place a permitted facility for byproduct management. As discussed in the following sections of this report, factors like this will lead to FGD and SCR installation schedules far in excess of the 30 months that EPA has cited.Implementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 3 FLUE GAS DESULFURIZA TION (FGD) SCHEDULES This section of the report discusses the installation schedules of several recent (or ongoing) FGD projects. The projects discussed demonstrate that the timetable for completing such installations can vary significantly, depending upon man y factors, including the nature of the site and whether the host is a single unit or one of multiple FGD processes to be installed at a station. Figure 3

- 1 presents a summary timeline for representative FGD projects, depicting when engineering and procur ement start, and construction begins. The stations represented in Figure 3

- 1 are from those FGD owners who could expeditiously provide the requested schedule information within the abbreviated time required for preparation of this report. Despite attempts to authentically reflect the distribution of the 1,500 generating stations in the U.S., it is not known if the stations in Figure 3

- 1 reflect a true statistically representative sample. Consequently, the trends between different categories of units will be approximate. Figure 3

- 1 shows a wide variety of project duration schedules.

Figure 3
- 1 . Timeline of FGD ActivitiesImplementation Schedules for FGD and SCR Process Equipment

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- 2 The following is a more detailed discussion of many of these FGD installation projects. The examples include what might be considered “best case” scenario installations of a single FGD process at one site. There are also examples of more challenging installations, including multiple FGD installations at a generating station with multiple uni ts. These examples also include stations that are contemporaneously retrofitting SCR and FGD systems.
3.1 INSTALLATION OF A SI NGLE FGD SYSTEM AT A SITE How long it will take to add a single FGD process at a site will depend on the specific details of the site. For example, retrofitting an FGD process to a site already equipped with one or more FGD units

– and where there is already a licensed byproduct management system at the site

– is likely to present a more straight

forward engineering and installa tion situation than will be faced when a company installs FGD at a site that is not already equipped with one or more FGD units. 4 However, other site

- specific factors can override any such advantage. Consequently, for the purposes of this discussion, stati ons with and without FGD are placed in the same category for discussion. As shown in Figure 3

- 1, examples in this category include the installation of the FGD unit at Alabama Power’s Barry Unit 5 (which took 53 months); the retrofit of an FGD system at G eorgia Power’s Hammond facility (which took 40 months); the retrofit of an FGD system at AEP’s Mountaineer facility (which took 42 months to complete); the retrofit of FGD at Georgia Power’s Bowen Unit 3 (which took 50 months); the FGD retrofit at Alabama Power Gaston Unit 5 (which took 64 months); and the installation of FGD at Salt River Project’s Coronado Unit 2 (which took 44 months even though the plant owner was willing to pay additional local agency fees and assign contactors to expedite the permitti ng process and accelerate review). The case of Georgia Power’s Plant Hammond installation is an example of a short

- to
average - time installation schedule. The single FGD module for four boilers at Hammond was implemented in the shortest schedule incurre d by this owner. Several factors enabled this abbreviated schedule. First, the process and absorber design developed for other sites was applied, shortening the period for procuring contracts. Second, certain design tasks were accelerated as they were leve raged on previous, similar applications. Third, as described in greater detail in comments being filed separately by Southern Company, ample and accessible space was available to allow simultaneous construction of equipment such as the absorber and reagent preparation facilities.

4 As will be noted in Section 5, one of the four reference units selected by EPA (Tampa Electric Big Bend) represents this case. There, the existence of reagent receiving, processing and handling systems for two other, FGD

- equipped units at the site supported expedited design and construction f or Units 1 and 2.Implementation Schedules for FGD and SCR Process Equipment

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- 3 In contrast, there was a 64

- month schedule for installation of FGD at Alabama Power’s Gaston Unit 5. This reflects the impact that a more complicated site can pose for a source owner trying to install control equipment.
Anoth er factor that should be considered is whether the plant owner operates a large fleet of plants or only a few units. Owners in the latter category

– without the market power of large, multi

- state operators

– will have less leverage over suppliers and can e xpect longer installation times. The relatively small market presence of Dairyland Power Cooperative is believed to contribute to the 50 month installation schedule for retrofit of semi

- dry FGD. As described by Katzberger (2007), it is not uncommon for sma ll operators to not receive the same degree of response as larger owners. In summary, during the past five years, the average time incurred to retrofit FGD on a single unit at a site has been 48 months, but it has recently taken some companies less time t o complete such a single retrofit (as little as 40 months) and it has taken other companies more than 60 months to complete a single retrofit. The difficulties faced by large companies are magnified for smaller companies.
3.2 INSTALLATION OF TWO FGD P ROCESSES Implementing two FGD units at a site can affect an overall FGD installation schedule. For example, by undertaking multiple installations, the per

- unit design timelines may be shorter, but the overall construction schedule may have to be extended due to the number and complexity of site activities. Usually the additional time is due to the availability

– or unavailability

– of space during construction. For example, in the ideal case, major equipment to be installed is temporarily stored in a “lay down” area adjacent to the final location, where final preparation can take place. The distance between the laydown area and installation site ideally is minimal, and a single installation can usually be supported. However, in many cases, an adequate laydo wn area for two units cannot be found adjacent to the site. As a result, there are longer transport distances and there may be a delay in the final preparation preceding installation. There are numerous examples of FGD retrofits that fall into this catego ry. These include Duke Energy’s Belews Creek Units 1 and 2 (which took a total of 49 months: 12 months of project work and 37 months of construction for the first unit to be operable) and Cayuga Units 1 and 2 (54 months: 9 months of project work and 45 m onths of construction); Allegheny Energy’s Ft. Martin Units 1 and 2 (40 months plus an additional 9 months to relocate existing byproduct settling lagoons); and AEP’s Cardinal Units 1 and 2 (52 months). Also being included in this category are the FGD p rojects at WE Energies Pleasant Prairie Units 1 and 2 and Progress Energy Crystal River Units 4 and 5 , where plant owners contemporaneously constructed FGD SO 2 control systems and SCR NO xImplementation Schedules for FGD and SCR Process Equipment

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- 4 control systems. This type of project can take more time than “singl e FGD system” retrofits due to size of the entire project

– a greater amount of concrete to be poured for foundations, electrical cable installed located for power and instrumentation and controls, fabricated steel vessels to be stored and prepared for ere ction in limited “laydown” space, cranes to be positioned for installation, and access and working space for hundreds of boilermaker and other skilled trades. Completion of the FGD installation at WE Energies’ Pleasant Prairie Units 1 and 2 took 56 months; and completion of work at Progress Energy’s Crystal River Units 4 and 5 took 44 months. One factor contributing to the fact that the design and engineering phases of Duke’s installations may, on average, have taken less time than those steps took at som e of the other above

- listed installations is that Duke

– by adopting a system

- wide FGD design

– was able to initiate construction sooner. Not all owners can adopt this approach, based on the variety of generating units and the presence of FGD on existing u nits. Site differences can also elongate a construction schedule. The case of Allegheny Fort Martin is instructive on this point

. The cited installation schedule of 40 months does not include an additional 9 months to relocate existing byproduct settlin g lagoons to accommodate the reagent storage and preparation, gypsum dewatering, and waste water t reatment facilities. In addition, the subsurface area beneath the former lagoons required caissons for support. This site was very congested and required a st ep - by

- step erection process instead of erecting multiple facilities simultaneously. For example, the stack shell was first erected, followed in sequence by the Unit 2 and Unit 1 absorber island. Site constraint s forced the absorber shell to be erected in “ rings” at the north end of the plant, transferred by barge to the south end of the plant, and welded section by section. The shared facilities such as reagent unloading, storage and processing, gypsum dewatering and storage, and waste water treatment were all separated from the absorber island. Consequently, significant pipe and electrical racks were necessary to connect all facilities

. In addition, finally, labor productivity was not optimal

– construction craft had to be bussed to the work site each day f rom a parking area that consumed valuable work time. In summary, t he average retrofit time for these installations was 47 months but

– as was the ca se with the previous category

– there was great variation, with some installations taking less time and o thers taking much more.
3.3 INSTALLATION OF THRE E OR MORE FGD PROCES S UNITS AT ONE SITE Implementing three or more FGD processes at a site can lead to even greater difficulties as the challenges for two units are extended. The limits of space and access f or manpower are greater.Implementation Schedules for FGD and SCR Process Equipment

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- 5 The following examples of this category of FGD retrofits are discussed below: Alabama Power Miller Units 1

- 4; Allegheny Hatfield’s Ferry Units 1

- 3; Duke Energy Allen Units 1

- 5; Duke Energy Marshall Units 1

- 4; First Energy Sammis Units 1

- 7; and Alabama Power Gorgas 8

- 10. TVA Kingston Units 6

- 9 are also reflected in Figure 3

- 1. As demonstrated by the following discussion, it took an average of 49 months for owners of these units to install three or more FGD systems at one site. T he least required time was 45 months; in two instances it took 56 months or more to complete installation of FGD at the first unit at the site, with subsequent units requiring additional time. The reasons why FGD installations at each of these took more than the 27 months that EPA suggests is standard is that there is nothing standard about most power plant sites.
3.3.1 A LABAMA P OWER G ORGAS U NITS 8

- 10 (6 1 M ONTHS ). The 61 month schedule for Gorgas was the longest incurred by this owner. There were severa l key reasons for this extended schedule. First, as the initial FGD project for this owner, the engineering required significant time as did negotiating contracts. Second, the site required extensive modifications

– literally moving a small mountain to cre ate the adequate space. The limit on space forced the new stack to be constructed sequentially, and not in parallel with other equipment. Further, significant improvements to the flue gas handling system

– including upgrade of fans

– were required.
3.3.2 A LLEGHENY E NERGY H ATFIELD ’ S F ERRY U NITS 1

- 3 (45 M ONTHS ) The Hatfield’s Ferry site is very hilly and required significant site earth movement to create “benches” to install the induced draft fan, absorber island, and the reagent process a nd material handli ng equipment. Each of these areas is located over an abandoned coal mine that required stabilization by injecting a flyash/concrete mixture. A caisson structure was also required to further provide structural support. Prior to construction, transmission li nes (500 KV) from the generating unit to the switchyard had to be relocated to provide clearance for cranes to erect the induced draft fan and absorber facilities. Due to lack of laydown space near the unit, the absorber vessel shells were built off site, shipped to the site and erected ring by ring. Finally, the shared facilities such as reagent unloading, storage and processing, gypsum dewatering and storage, and waste water treatment were all separated from the absorber island. Consequently, significant pipe and electrical racks were necessary to connect all facilities.Implementation Schedules for FGD and SCR Process Equipment

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- 6 3.3.3 D UKE E NERGY A LLEN U NITS 1

- 5 (4 9 MONTHS FOR THE FIRST RETROFIT ; 1 EXTRA MONTH FOR THE OTHER ). Two FGD units were installed to serve the five units at Duke Energy’s Allen Power Plant , where the units are relatively small and several boilers feed one of two FGD absorbers. It took a total of 4 9 months to bring on - line the first FGD unit and an additional month to bring the other FGD unit on line.
3.3.4 D UKE M ARSHALL U NITS 1

- 4 (4 6 MON THS FOR THE FIRST RE TROFIT ; 6 MORE MONTHS FOR THE OTHER THREE RETR OFITS ). Duke Energy installed 4 FGD units at its Marshall Power Plant. The first FGD installation to be completed was at Marshall Unit 4 , which took 4 6 months. It took an additional 4 months to complete work on the second retrofit and another two months to complete work on the remaining two retrofits.
3.3.5 F IRST E NERGY S AMMIS U NITS 1

- 7 (56 MONTHS )

. A notable case is that of Sammis Units 1

- 7. Figure 3

- 2 depicts the Sammis site layout, adjac ent to the Ohio River, with Ohio State Route 7 located below the ESPs and fabric filters built in the 1980s for these units, and three 800 MW FGD absorber towers. Flue gas from the entire station

– all 7 units

– is treated by these three absorber towers. ( SCR process equipment is located on Units 6 and 7.) Figure 3

- 2 shows the Sammis site is bounded by the Ohio River and a rail line

– which, among other factors, constrained construction activities and contributed to the extended installation time of 56 mont hs. Figure 3

- 2 also indicates where that two 600 MW SCR reactors were installed within the boilerhouse building. In summary, owners of major generating stations have required a total of between 45 and 66 months to retrofit 3 or more FGD systems at one si te. The length of time it took to complete FGD installations at the different sites varied depending upon site

specific factors. For example at Duke’s Marshall station, the first unit (Unit 4) became operational 46 month after start of engineering and perm itting, with the three remaining units coming on

- line over the next 6 months. At Alabama Power’s Miller station, three FGD units are on line and one is scheduled to come on

- line in 2011; the total installation time for each of the four retrofits ranges fro m 54 months to 66 months.
The common theme in these retrofits is the extensive number of activities to be conducted within a limited, confined space, which requires many activities to be conducted sequentially and not in parallel.Implementation Schedules for FGD and SCR Process Equipment

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- 7 Figure 3
- 2 . Sammis Site LayoutImplementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 4 SELECTIVE CATALYTIC REDUCTION (SCR) AND LOW NO X BURNER SCHEDULES

This section of the report reviews the schedule to retrofit SCR reactors and/or low NO x burners at 13 generating station s. A summary of the results for SCR is presented in Figure 4

- 1, and for low NO x burners in Figure 4

- 2. The stations represented in Figures 4

- 1 and 4

- 2 are those of plant owners that retrofit SCR and low NO x burners and that could expeditiously provide th e requested information within the time required for this report. As with the case for FGD experience summarized in Figure 3

- 1, it is not known if the stations in Figure 4

- 1 reflect a statistically representative sample. Consequently, the trends between di fferent categories of units will be approximate.

Figure 4
- 1 . Timeline of NO x Control Projects

– SCRImplementation Schedules for FGD and SCR Process Equipment

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- 2 Figure 4
- 2 . Timeline of NO x Control Projects

– LNB
4.1 SELECTIVE CATALYTIC REDUCTION (SCR) The design and installation of SCR is considered for single unit retrofit and multiple projects at one site. This section of the report also treats SCR installation projects conducted contemporaneously with FGD. U nlike the case for FGD, the use of a single, modular process design is not a widespread practice. This is because the location of the SCR process

– between the economizer outlet and air heater inlet

– requires a tailored, site

- specific treatment. Figure 4

- 1 presents a summary timeline for representative SCR projects, depicting the start of engineering and procurement, and construction. Figure 4

- 1 shows a variety of project durations. The data show that there is only a minor effect as to whether an SCR proc ess has been previously installed at a given station. This is because there is no central, shared facility of the magnitude of a reagent receiving and preparation system that can be expanded, or a byproduct management system, where an existing system can b e exploited. There may in some cases be a benefit of exploiting the existing ammonia

- based reagent preparation system, depending upon EPA’s eventual regulatory determination of how such materials are to be classified.Implementation Schedules for FGD and SCR Process Equipment

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- 3 4.1.1 I NSTALLATION OF A S INGLE SCR U NIT AT A S ITE Several owners retrofitted a single SCR reactor to a site. Examples of such retrofits include the work done at Alabama Power’s Barry Unit 5 (50 months) and Gaston Unit 5 (40 months), AEP’s Conesville Unit 4 (42 months), CPS’s J.T. Deeley Sta tion (36 months), Duke’s Marshall Unit 3 (46 months), Georgia Power’s Hammond Unit 4 (28 months), and Gulf Power’s Crist Unit 7 (42 months). Selected units are further described as follows. Georgia Power Plant Hammond (28 months ) . Georgia Power’s Plant H ammond Unit 4 represented the shortest schedule of any unit retrofit by this owner. Several reasons contributed to an installation schedule that was markedly shorter than others undertaken recently. First, Unit 4 is an end unit

– thus construction could pr oceed during routine operation, as access to the reactor was adequate. Also, the unit required minimal modifications to the gas handling system. These benefits to schedule did come at a price

– two cranes (rather than one) were required, and the tie

- in tim e due to extended ductwork was closer to 7 weeks and not the typical 4 weeks. Alabama Power Gaston Unit 5 (4 0 months ) . Alabama Gaston Unit 5 required 40 months, one of the longest project durations experienced by this owner. Most notably, major modificat ions to the gas handling system were necessary to accommodate the change in gas pressure drop; in addition to new fans both structural and electrical infrastructure had to be improved. The extremely congested site, adjacent to a river, minimized site acces s for construction, requiring mostly costly crane and protracted erection procedures. Ductwork location was complicated by coal conveyors, and the need for foundations in limited space. Finally, the altered ductwork arrangement required a new breach to the stack, imposing complexity. Duke Energy Marshall Unit 3 (4 6 months ) . It took approximately 12 months of upfront work at this site before the contractor was given authorization to proceed with detailed engineering. When the time for these efforts is adde d to the time needed for actual construction, the total time for this installation is 46 months. In summary, for cases involving the retrofit of a single SCR reactor at a site, the construction schedule will depend on the specific characteristics of the s ite, including technical details of the application, and the engineering prep work. Recent examples of the installation of a single SCR unit indicate that it takes between a total of 28 months and 50 months (an average of about 40 months) to complete such projects.Implementation Schedules for FGD and SCR Process Equipment

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- 4 4.1.2 M ULTIPLE SCR P ROCESSES AT O NE S ITE There are several examples of plant owners retrofitting multiple processes for the control of NO x at one site. Sites at which multiple SCR units have been installed include First Energy’s Sammis Plant ( retrofits on Units 6 and 7 required a total of 60

- 62 months); Alabama Power’s Miller Station (where retrofits on Units 1 and 2 each took a total of 42 months and retrofits on Units 3 and 4 each took a total of 34 months); AEP’s Kyger Creek Plant (where the re was a retrofit of 5 SCR units, with the first operable within 31 months); Progress Energy Crystal River Station (where SCR retrofits on Units 4 and 5 took 37 months); and Georgia Power’s Scherer station project (which includes work on SCR for Units 1 th rough 4, and where the SCR system closest to completion is that for Unit 3, which is scheduled to be completed in a total of 50 months). Also worth mentioning is Associated Electric Cooperative’s work to control NO x at its Thomas Hill Station (including th e addition of an SCR system and low NO x burners on Unit 3 and work on the Unit 2 SCR). The collective experience for this class of project suggests that it takes between 31 and 50 months (an average of approximately 44 months) to install the first of mult iple SCR systems at a site and subsequent units come on after varying intervals, depending upon site

- specific factors. It can, however, take much longer than the “average” time to complete SCR installations, as demonstrated by the experience at the Sammis site. Further details of selected stations are described as follows: First Energy Sammis Units 6 and 7

. Sammis 6 and 7 required approximately 60

- 62 months from the start of engineering to process startup. Section 3 discussed the difficulties encountered for FGD, and Figure 3

- 2 presented a pictorial view of the station. The SCR units were installed in an extremely congested environment. The retrofit of SCR to Units 6 and 7 required significant equipment demolition; the original equipment ESPs that had been decommissioned and abandoned in place (as new, upgraded particulate control equipment was installed) had to be removed. The ESPs occupied the space that was the only option for locating the SCR reactors. The constrained site as shown in Figure 3

- 2 illust rates that the significant demolition and equipment relocation are primary reasons why 60

- 62 months was incurred. Kyger Creek

. AEP retrofit five SCR reactors to the Kyger Creek Station in a period of approximately 31 months. The number of identical unit s and the generating capacity were key to achieving this abbreviated time: all five units are identical so engineering could be expedited, and the modest generating capacity (220 MW per unit) did not require large quantities of material to be installed or relocated. The use of cranes within the compact site, and small distances over which to transfer materials also contributed to expeditious installation. Although the plant site is constrained, the units are small

– and construction can be staged to addres s these in a serial manner. Consequently the 31 month period is not considered typical.Implementation Schedules for FGD and SCR Process Equipment

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- 5 Georgia Power Scherer Unit 3 . Unit 3

– the first unit to be operational at this site

- is planned to be completed within about 50 months, with engineering and permitt ing commencing 19 months prior to any startup activities. Other units at Scherer that will receive SCR

– Units 1, 2, and 4

– are schedu led for start up after Unit 3. The complexities of the site, and general congestion of executing these projects contempor aneously , extends the implementation schedule for these units. For example, Unit 4 is scheduled to be operable in early 2012, incurring a more than 60 month project schedule, about 10 months following Unit 3. Units 1 and 2 will be implemented after Unit 4 by a similar amount of time.
4.2 LOW NO X BURNERS The reduced complexity of an LNB system, compared to an SCR or FGD process, does not necessarily translate into abbreviated permit ting procedures. As with SCR, construction schedules for LNB installations will depend on conditions at the specific site, including details of the application, the engineering and unit preparation work, and the availability of an outage. Most notably, a key factor in determining the installation schedule is the availability of LNB equipment. The limited number of qualified suppliers, and the special

- purpose fabrication techniques required, can extend f abrication and delivery times. Also, there can be complications in the permitting process. At least one multi

- state owner is anti cipating a lengthier schedule for install i ng LNB equipment, due to concerns that have arisen in the permitting of the installations, where local regulatory agencies are questioning whether lower NO x emissions are inextricability linked to higher CO emissio ns. Regardless of whether or not there is any validity to the claim, that permitting process is anticipated to be time consuming. Figure 4

- 2 presents schedule information provided for low NO x burners at Salt River Project’s Coronado Unit 1 and Navajo Unit 3. Also included in Figure 4

- 2 is a schedule typical of LNB retrofits in the Southern Company System (based on recent LNB retrofits to generating units at Plants Daniel and Watson). This experience suggests project installations typically take a total of about 18 months

. Not included in Figure 4

- 2 is information on LNB installations for two 760 MW units (Units 4 and 5) at Progress Energy’s Crystal River facility. The LNB installations were part of a larger project that took many years to complete and th at included installation of an SCR unit, an FGD system, and an acid mist mitigation system (ammonia injection) and significant upgrades to the precipitator. If the low NO x burners had been installed on their own, company representatives estimate that permi tting and construction would have taken 18 to 24 months. The Crystal River installations are addressed here, though, because they are an example of a relatively straight

- forward LNB installation project. LNB retrofits can take less time than on average if (as Progress could do at Crystal River) companiesImplementation Schedules for FGD and SCR Process Equipment

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4

- 6 can use “plug

- in” burners that require minimal pressure

- part changes. In many cases, though, more significant modifications are required

– the burner “throat” may have to be expanded, to lower gas veloci ties and control mixing of fuel and air. Increasing the size of the penetration in the furnace wall to accommodate an enlarged burner throat will require high pressure part modifications. Further, the use of “overfire” or secondary air ports may be require d to promote burner performance

– these ports will also require pressure

- part modifications, and increase installation times. For these latter conditions, 18

- month project schedules are typical.Implementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 5 CRITIQUE OF EXAMPLES CITED BY EPA

This section of the report responds to

– and offers additional information on

– retrofit examples that EPA has cited in support of its idea that it is reasonable to expect a single FGD installation to be completed in a total of 27 months and a single SCR installation to be completed in a total of 21 months. As noted in the following sections of this report, the installations cited by EPA (EPA, 2005; EPA, 2002) in support of those shorter installation schedules occurred at the beginning of the last decade and are not repre sentative of recently completed FGD and SCR installations, or of FGD and SCR retrofits that are likely to be undertaken in the near future. There are many reasons for this, including the fact that first generation installations took place before owners and contractors knew all the pitfalls presented by these kinds of projects; now that the pitfalls are better known, plant owners typically require more up - front work on equipment design and engineering. They want to “get it right,” rather than just taking it on faith that contractors will know how to address the unique factors presented by each installation. Also, EPA’s handful of examples fails to capture the variety of conditions one can expect to find at all the sites now being evaluated for control equipm ent retrofits. The wide distribution of implementation schedules displayed in Figures 3

- 1 and 4

- 1 bears witness to the fact that each site is unique and each presents its own retrofit challenges. Finally, as discussed below, previous descriptions of the projects cited by EPA in support of its short installation deadlines may be incomplete. Additional information suggests that, in fact, some of the projects cited by EPA took longer to complete than suggested by EPA.
5.1 FGD INSTALLATIONS

– OVERVIEW Figur e 5

- 1 is a timeline showing the amount of FGD capacity that has been installed over the past decade and that is anticipated to be installed in the next two years. The figure shows that the demand for FGD equipment

– and although not shown, SCR equipment

– was low around the year 2000, the time when all four key references cited by EPA were implemented. This figure suggests the experiences of those undertaking FGD retrofits at the beginning of the past decade may not be representative of the experiences of t hose contemplating and conducting FGD retrofit at present. Further details concerning the EPA

- cited retrofits that were undertaken approximately 10 years ago are described in the following sections.Implementation Schedules for FGD and SCR Process Equipment

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- 2 Figure 5
- 1 : Timeline Showing Recent Installed FGD Capacity by Startup Date
5.2 EPA EXAMPLES OF FGD INSTALLATIONS BEING COMPLETED IN A TOTAL OF LESS THAN 3 0 MONTHS EPA cites two examples of FGD installations being completed in a total of less than 30 months: t hose at Centralia and Tampa Electric Company’s Big Bend Station. Further information on those installations is provided below.
5.2.1 C ENTRALIA W ET FGD The Centralia FGD project was completed in November 2001. EPA claims that it was completed in less than 30 months. In fact, the complete installation process appears to have taken longer than 30 months. Based on information in the public domain (Miller, 2004), it appears that Centralia owners first initiated engineering for wet FGD for their units in January of 1999, not in May 1999 (as was previously reported), that FGD performance tests for the first unit were conducted in November of 2001, and that the unit was declared commercial in December of 2001. Given that the installation of process equipment is not declared to be “substantially complete” until performance tests indicate the unit can be accepted for operation, this information indicates that it took a total of almost three years to do all the work to install the FGD system for Unit 1 at Centralia. In addition, the reported on

- line date for Unit 2 (December 2002), indicates that 48 months were required for completion of work on the second Centralia unit. In addition to the fact that the Centralia installation appears to have taken more than a total of 27 months to complete, there are reasons to believe that the CentraliaImplementation Schedules for FGD and SCR Process Equipment

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5

- 3 installation is atypical. As noted in comments being separately submitted by Southern Company, the contract for the engineering and construction work at Centralia was part of a unique “partnering” agreement between the owners of Centralia and the contractor. This type of relationship can speed subcontracting and procurement activities, but it can also require significant upfront negotiations and arrangements. As noted above, however, th ere can be pitfalls to any approach that does not set aside adequate time prior to the start of construction to ensure that the project design and engineering are done right. Also, because Centralia was an early generation installation, the plant owners may have had access to a larger number of experienced craftsmen to work on the project than would be available today, when so many retrofits are being implemented in the same time period. Moreover, as an early generation retrofit, Centralia may have faced fewer permitting obstacles than are faced by those now seeking to retrofit FGD units (see Section 2.2.5 of this report). Finally, it appears that the Centralia site was not as challenging a candidate for retrofits as some of the sites described in Sect ion 3 of this report. 5
5.2.2 T AMPA E LECTRIC B IG B END Tampa Electric Company’s installation of FGD systems on Big Bend Units 1 and 2 was also an early generation project. Starting with time to prepare a detailed FGD bid specification, it first appears (ba sed on reports in the technical literature) that this project was operational in about 28 months. (Smolenski, 1999.) However, further investigation reveals that the reported schedule does not take into account that Tampa Electric conducted preliminary cost assessments and prepared the FGD procurement specification 8 months earlier. Also, a further review of records shows that the permit application for the project was submitted in July of 1996. This all indicates that the total amount of time needed to desi gn, permit, and construct the FGD system was closer to a 42 month schedule than a 27

- or 28

- month schedule. In addition, there are several reasons for believing this project is not representative of the situations faced by many of the companies that wil l have to retrofit FGD units in the next five years. For example, it was possible for TECO to truncate the installation schedule at Big Bend by building upon the FGD installations that were already located at the site and in use at Big Bend Units 3 and 4. The reagent receiving and processing equipment and dewatering apparatus for the FGD equipment on Units 3 and 4 could

– with some limited modification

– be used in the new FGD installations at Units 1 and 2. Also, the land use permit for solid byproduct man agement already existed at Big Bend and likely received less scrutiny, which is

5 An indication of the fact that the Centralia retrofit may not have been a challenging one is that the reported FGD retrofit cost of the project ( approximately $100/kW on a 2001 dollar basis and $150/kW on a 2010 dollar basis) are a fact or of 2

- 3 less than more recent projects.Implementation Schedules for FGD and SCR Process Equipment

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- 4 very different from the situation faced today by those seeking permits for new, “greenfield” byproduct management sites. 6
5.3 EPA EXAMPLES OF SCR INSTALLATIONS BEING COMPLETE D IN A TOTAL OF LESS THAN 3 0 MONTHS EPA cites two examples of SCR installations being completed in a total of less than 24 months: those early 2000 installations at the AES Kintigh station in New York and Reliant Energy’s (now NRG’s) Keystone station in P ennsylvania. No information is available in the literature concerning the SCR project for Keystone, and very little information is available concerning the SCR project at the AES Kintigh station in New York. The available data do suggest, though, that th e Kintigh project

– from start to finish 9 months in duration, and one of the first SCR retrofit installations in the country

– is atypical in several respects. For example, the procurement process for the Kintigh project does not reflect what most plant o wners would have to follow today: there is no evidence this work was competitively bid; indeed, it is possible that B&W was the contractor selected because B&W provided the boiler and plant ancillary components. This “non

traditional” approach to selectin g a contractor

– perhaps not unreasonable for the time period

– bypassed the open, competitive bid process generally mandated for an investor

- owned utility or public agency. This procedure may not be available to investor owned or public agencies without p rudency challenges. Also, the non

- traditional Kintigh facility approach generally does not make sense for the much more complicated installations that companies now face. More complex projects require more effort to be taken up

- front in the planning proc ess – before actual construction begins

– in order to minimize problems on the back end. Further, as noted in Section 2, those involved in the Kintigh project faced far fewer regulatory obstacles 10 years ago than plant owners face today. For example, a de cade ago, companies did not have to deal with current requirements to predict and mitigate SO 3 emissions from SCR units.
5.4 OTHER FACTORS EPA also acknowledges (EPA, 2005; EPA, 2002) that the installation of multiple FGD and/or SCR units at one site will require more time than suggested in the proposed transport rule proceeding. While the overall conclusion is correct

– installing multiple control units at one site will take longer than installing just one control unit at the site

– EPA underestimates the complications in undertaking multiple installations simultaneously at a site. EPA assumes that many of the basic activities required

– conceptual system design, selecting the precise technology to be installed, developing technical specifications for the project, identifying bidders,

6 As was the case with the Centralia retrofit, a further indication that the Big Bend Unit 1 and 2 FGD retrofit may not have been a challenging one is that the reported FGD retrofit cost of the project was low: ap proximately $100/kW on a 2001 dollar basis

.Implementation Schedules for FGD and SCR Process Equipment

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- 5 procuring their bids, evaluating those bids, and awarding contracts

– are executed for not one but multiple units 7 . However, the rate

- limiting step in a multi

- project FGD or SCR retrofit is usually construction, and the impedi ments that retrofit activities for one unit can impose upon another. It is optimistic for EPA to assume that the incremental required time period for each additional retrofit would be just 4 months. In summary, there is not sufficient information to be a ble to determine the actual time it took to design, permit, and construct the projects upon which EPA relies in concluding that FGD and SCR retrofits can routinely be completed in a total of less than 30 months. There is, though, a long list of reasons why the FGD and SCR retrofits undertaken a decade ago may have taken less time to complete than those now being undertaken. It is generally believed the first generation of retrofits provided fewer challenges to those presently undertaking the work. For examp le, the simpler sites were logically chosen first. Also, in the present timeframe, there are difficulties in getting necessary preconstruction permits now that did not exist (or did not exist to the current extent) a decade ago. And finally, even EPA ackno wledges that multiple installations of FGD and SCR installations at a single site will take longer

– sometimes much longer

– than single retrofits. (Specifically, EPA concluded five years ago that it would then take 30 to 40 months to install multiple SCR and FGD equipment, respectively (EPA, 2005).) All of these factors undercut EPA’s current conclusion (set out in the preamble of the Proposed Transport Rule) that FGD and SCR retrofit installations can typically be completed in a total of less than 30 mont hs.

7 See Figures 1 and 2 of EPA, 2005.Implementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 6 SUMMARY/CONCLUSIONS

Significant evidence exists to show that the installation schedule proposed by EPA for SCR and FGD process equipment

– 21 and 27 months, respectively

– is unrealistic. Actual installation schedules that are reported in Sect ions 3 and 4 significantly exceed EPA’s projections.
Table 6

- 1 summarizes the observed total schedules for design and installation of flue gas desulfurization, selective catalytic reduction, and combustion controls (e.g., low NO x burners).
Table 6
- 1 . Summary of Design, Fabrication, Installation Period
Control Technology Site and Application Category Design, Fabrication, Installation (Months) Flue Gas Desulfurization Single Unit to Station: Large Owner 48

Single Unit to Small (e.g., Cooperative) Owner 50 Two Units to Site 51 Three or More Units to Site 54 Selective Catalytic Reduction Single Unit to Site 40

Multiple Units to Site 44 Combustion Controls Both single and multiple

installations 12

- 1 8 months, depending on the specific conditions As noted in both Sections 3 and 4, despite attempts to solicit schedule information from a representative sample of owners, it is not known if the results described in this report reflect a true statisticall y representative sample. As a consequence, although the estimates presented in Table 6

- 1 are believed valid, the trends between different categories should be viewed as approximate. However, it should also be noted that the number of example cases cited

– for FGD (23 projects at 21 stations), and for SCR (15 projects at 13 stations)

– well exceed the much smaller number of references cited by the EPA.Implementation Schedules for FGD and SCR Process Equipment

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- 2 The few cases cites by EPA provide no legitimate basis for challenging the reasonableness of the schedule s cited in Table 6

- 1. As noted in Section 5, the cases upon which EPA relies were done almost a decade ago and represent less than 5% of the present FGD and SCR inventory which has been installed. The evolution of the degree of sophistication of technology , permitting requirements, and market forces since that time has evolved as follows:
6.1 DEMAND The demand for competent process design and equipment suppliers will lengthen schedules. The reference cases were selected from a period when less than 5% of t he existing inventory was installed. Having such an abundant talent pool may have allowed construction schedules to be compressed during that timeframe. That is not possible now, when there is much greater demand for competent process design and equipment suppliers.
6.2 LABOR PRODUCTIVITY Demand affects labor productivity: with scores of projects underway simultaneously, there will be much more demand for the limited pool of skilled workers. As discussed in Section 2, this can have a disproportionately ad verse effect on later

- in

- the

- pipeline projects, which can frequently be projects for smaller utility systems. Construction schedules can be protracted as work schedules cannot be accomplished quickly with less experienced staff.
6.3 ENGINEERING McCarthy (2004) describes a typical effort required a two

- phase engineering approach, independent of whether a company adopts a system design or an individual optimized design. The first phase established the design basis (gas flow rate, gas composition, available reagent composition), optimized a standard absorber design, established balance

- of

- plant needs, and developed a layout and preliminary cost. The second phase addressed details of balance

- of

- plant and auxiliary equipment, and developed detailed contracts fo r fabrication and construction schedules by which to manage the work and hold subcontractors accountable. Each phase reportedly required 6 months. Such attention to detailed design is necessary, for either approach that emphasizes a system versus an optimi zed individual unit design. Before awarding contracts valued at several hundred million dollars, any less effort in the present activist climate could invite prudency challenges.
6.4 PERMITTING As discussed in Section 2.2.5 of this report, those retrofi tting SCR and FGD installations today face far more regulatory hurdles today than plant owners faced 10 years ago or even 5 years ago. For example, the court’s vacatur of the “pollution control project exclusion” provision means that projects to install SC R and FGD units can be subject to the rigors of the new source review preconstruction permittingImplementation Schedules for FGD and SCR Process Equipment

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6

- 3 program. Also, those retrofitting SCR units will need to conduct a detailed estimation and accounting of byproduct sulfuric acid emissions, with remedial means included in the design. These permitting issues were assuredly not part of the 9

- month SCR retrofit at the Kintigh facility. In addition, as also discussed in Section 2.2.5, those undertaking FGD retrofits will face myriad other requirements to get envir onmental permits (some of which could take 4 or more years to get) and other authorizations .Implementation Schedules for FGD and SCR Process Equipment

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- 1 SECTION 7 REFERENCES

Name, Date Citation EPA, 2005 Environmental Protection Agency, “Boilermaker Labor Analysis and

Installation Timing”, Technical Support Do cument for the Final Clean Air Interstate Rule, EPA Docket Number OAR

- 2003

- 0053, March 2005. EPA, 2002 Environmental Protection Agency, “Engineering and Economic Factors

Affecting the Installation of Control Technologies for Multipollutant Strategies,” E PA

- 600/R

- 02/073, October 2002. Hallman, 2010 Hallman, C., Personal communication with M. Stroben, August 20, 2010.

Hansen, undated Hansen, T., “Clearing The Air in the Twin Cities”, PennEnergy, Volume 111,

Issue 6. http://www.pennenergy.com/index/power/display/297417/articles/power

engineering/volume

- 111/issue

- 6/features/clearing

- the

- air

- in

- t he

- twin

cities.html Katzberger, 2007 Kathzberger, S., “Plant Economics: The Impact of Shortages on FGD Prices”,

Coal Power Magazine, September 1, 2007. http://www.coalpowermag.com/plant_design/Plant

- Economics

- The

- Impact

of

- Shortages

- on - FGD

- Prices_73.html McCarthy, 2004 McCarthy, J., et al., “Duke Power WFGD Retrofit Program: Achieving the

Lowest System

- Wide Cost of Compliance”, Proce edings of the 2004 Combined Power Plant Air Pollutant Control “Mega

- Symposium”, August 30

- September 2, 2004, Washington, D. C

. Miller, 2004 Miller, M., et al., “Centralia WFGD System: State

- of

- Art SO 2 Compliance”, Proceedings of the Combined Power Plant A ir Pollutant Control Mega

Symposium’, August 30

- September 2, 2004, Washington, D. C

. PSNH, 2010 PSNH, “Clean Air Project: Merrimack Station”, presentation to the NH Public

Utilities Commission, March 31, 2010, Docket 08

- 103 Informational Session.Implementation Schedules for FGD and SCR Process Equipment

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7

- 2 Smol enski, 1999 Smolenski, J., et al., ‘Tampa Electric Company Phase II FGD System Big Bend

Station Units 1 & 2 Advanced Design

– Low Cost”, Proceedings of the EPRI

DOE

- EPA Combined Utility Air Pollution Control Symposium: The Mega

Symposium, August 16

- 20, 199 9, Atlanta, GA. Wall, 2010 Wall, D., et al., “Implementation Strategies for Southern Company FGD

Projects”, proceedings of the 2010 Mega

- Symposium, August 30

- September 2, 2010, Baltimore, MD.

31531.420001 EMF_US 32738079v1Attachment II J. Marchetti, E. Cichanowicz, and M. Hein, “S chedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule” (Oct. 1, 2010).SCHEDULE OF CONTROL TECHNOLOGY RETROFIT TO MEET EPA’S PROPOSED TRANSPORT RULE

Final Prepared By James Marchetti J. Edward Cichanowicz Michael Hein

October 1, 2010Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010 

### TABLE OF CONTENTS

SECTION 1 INTRODUCTION 1-1 SECTION 2 EVALUATION METHODOLOGY 2-1 SECTION 3 REVIEW OF 2008-2010 CONTRO L TECHNOLOGY RETROFIT EXPERIENCE 3-1 3.1 GENERATING CAPACITY RETROFIT 3‐1 3.2 BOILERMAKER HOURS  3‐1 SECTION 4 CRITIQUE OF EPA’S APPROACH TO DETERMINING REQUIRED FGD AND SCR CAPACITY 4-1 SECTION 5 REVISED SCHEDULES AND MODELING RESULTS 5-1 5.1 SCHEDULE FOR INSTALLING FGD AND SCR  5‐1 5.2 DETERMINING THE SCHEDULE  5‐1

5.2.1 Owner

‐ Announced Project Dates 5

‐ 2 5.2.2 Modeled Project Start Dates 5

‐ 2 5.3 REQUIRED BOILERMAKER HOURS  5‐3 SECTION 6 OBSERVATIONS 6-1Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

LIST OF FIGURES Figure 3‐1.  FGD Capacity Installed: 2008-2010

............................................................... ......... 3‐2 Figure 3‐2.  SCR Capacity Installed:  2008‐2010 ................ ..................................................... 3‐2 Figure 3‐3 . Relationship between Required Boilermaker Hours for FGD and SCR Installation and Generating Capacity

............................................................... ................................ 3‐3 Figure 3‐4 . Calculated Boilermaker Demand for Both FGD and SCR: 3Q 2006 though 2Q 2010

............................................................... ............................................................... ........................ 3‐4 Figure 4‐1 . EPA New FGD Capacity – Ba se and Limited Trading Cases ........................ 4‐2 Figure 4‐2 . EPA New SCR Capacity – Ba se and Limited Trading Cases ........................ 4‐2 Figure 4‐3. EPA Estimate of the Number of FG D and SCR Projects Operational: 2011 to 2014

............................................................... ............................................................... .......................... 4‐3 Figure 5‐1 . Predicted FGD and SCR Operational Dates for Inventory of PTR-Affected Units

............................................................... ............................................................... .............................. 5‐3 Figure 5‐2 . Quarterly Demand for Boilermaker Hours: Predicted PTR Compliance (FGD and SCR)

............................................................... ............................................................... ......... 5‐4 Figure 5‐3.  Quarterly Demand fo r Boilermaker Hours:  EPA‐Assum ed Project Schedules (FGD and SCR) ........................................

............................................................... ........... 5‐5

LIST OF TABLES Table 5‐1 . Estimated Implementation Schedul e (Months) For FGD, SCR Projects ...... 5‐2Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

1‐1 SECTION 1 INTRODUCTION

The Environmental Protection Age ncy on August 2, 2010, publishe d the Proposed Transport Rule (PTR), the antici pated replacement of the Clean Air Interstate Rule (CAIR). The EPA in the August 2 announcement provided backgroun d support material, including analyses that assigned allocations of permi ssible levels of SO 2 and NO x emissions to owners of electric generating units (EGUs). EPA i n the background support material proj ected a total of 159 EGUs would retrofit a total of 185 control technology projects 1 , on a total generating ca pacity approximately 14 GW 2 , to meet this mandate. The EPA projected a two‐phase compliance schedule that purporte dly describes how industry will deploy control technology – by January 1, 201 2, and January 1, 2014. This compliance schedule wa s determined by EPA staff usin g IPM. The EPA‐ projected compliance schedule predicts that all 185 retrofit pr ojects proposed for the 14 GW of generating capacity will be operational by January 1, 2014. Consequently, EPA does not expect compliance delays. A key assumption inherent to EPA’ s results is that advanced con trol technologies – flue gas desulfurization (FGD) for SO 2 and selective catalytic reduction (SCR) for NO x – can be installed in timeframe s that, by recent industry expe rience, are abbreviated and unrealistic. Spe cifically, EPA assumes that SCR and FGD can be implemented in time spans of 21 to 27 months, respectively. EPA expects that, within these time spans, utilities will complete all project el ements – from project conception to successful commercia l operation. The adequacy of these 21‐ and 27‐ month periods has been challenged and is the subject of a compa nion report submitted with the comments of t he Utility Air Regulatory Group

. 3 In contrast to EPA’s projected periods of 21 an d 27 months, UARG submits docum ented experience that shows the reference cases selected by EPA from which to judge timeframes are not representativ e of present‐day utility experi ence. Actual implementation dates are much longer. This report projects a compliance schedule that is realistic an d based on actual industry experience. The results show the requisite generating capacity cannot be retrofit by the EPA‐required deadline. The inability to deploy the control

1 See EPA parsed files at http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html 2 75 Fed. Reg. at 45273 (Aug. 2, 2010). 3 Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment, Utility Air Regulatory Group, October 1, 2010.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

1‐2 technologies in a timely manner – due to a “logjam” of engineer ing, permitting, and construction activities – will compromise industry’s ability to meet PTR mandates. Section 2 presents an overview of the methodology used to proje ct the schedule. Section 3 presents an analysis of the recently completed and on ‐going activities to retrofit FGD and SCR beginning in 2008 and through this calenda r year. Section 4 critiques EPA’s approach to proj ecting the compliance schedule. Section 5 presents revised results using realistic schedule assumptions. Section 6 offers observations on the results of the analysis.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

2‐1 SECTION 2 EVALUATION METHODOLOGY

This section presents an overvie w of the methodology taken to c onduct this analysis. First, EPA predictions of the num ber of units required to retro fit control technology were reviewed. EPA identified specific units that would likely adopt control technology 4 . This “inventory” of control technology candidates as describe d in EPA’s “parsed” output files totals 185 projects, to be retrofit on 15 9 generating units. Specifically, EPA predicts that 106 units will retrofit FGD, 27 units will retrofit SCR. Of this inventory of units retro fitting control technology, a t otal of 26 units will retrofit both SCR and FGD. Second, a realistic schedule for project implementation based o n the companion report prepared for UARG’s comme nts was identified. Specificall y, an array of implementation schedules was identified based on the existing c ondition at the EGU (e.g., the unit’s size and whether it already has FGD or SCR on one or more sister units at the power plant), and t he number of units to be retrof it. Third, those EGU’s for which the unit owner or owners have an a nnounced intent to install either FGD or SCR, or bot h, and an operating date for t he control equipment, were identified. This pool of units was assigned the respective operating dates as identified by their owners. These units were treated differentl y than the inventory that EPA identified as candidates for control installation. Fourth, the inventory of units for which the owner did not assign specific operating dates was assumed to start insta llation in the third quarter of 2011. An EGU owner could not reasonably begin a pro ject earlier than this date, in light of EPA’s announced plan to complete this rulemaking in June 2011. (Even this third‐quarter 2011 date does not allow time for states to propose and make fi nal SIP revisions to implement the final rule and obt ain EPA’s approval of SIP revis ions.) Fifth, the project operating dat es were determined based on (1) the assumed start date and the applicable project i mplementation schedules or (2) the owner‐ announced operating date, in the case of those units with owner ‐announced operating dates.

4 EPA parsed files at http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.htmlSchedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

2‐2 Sixth, the boilermaker labor‐hour s demand for the projected 201 2 to 2014 PTR compliance was determined and compared to the historical demand for the 2008‐ 2010 FGD installation period (which is reviewed in Section 3 of this report). The boilermaker demand that would be necessary based on a realistic compliance schedule – with installations ex tending beyond EPA’s assumed Ja nuary 2014 operating date as necessary to reflect those realistic schedule s – was calculated and compared to the 2008‐2010 historical demand. The boilermaker de mand that would be necessary for the unrea listically accelerated deployme nt that would be required to meet EPA’s schedule – using an assumed January 2014 operating date (and ignoring the real‐world installation schedules described i n this report and the companion report) – was calculated and compared to the historic al 2008‐2010 value.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

3‐1 SECTION 3 REVIEW OF 2008-2010 CONTROL TECHNOLOGY RETROFIT EXPERIENCE

This section reviews the utilit y industry’s 2008‐2010 experienc e in retrofitting both FGD and SCR, and describes how t his experience is invoked to pr oject implementation schedules for 201 2 to 2014. Both the generating capacity retrofit and the demand on boilermaker hours are considered.
3.1 GENERATING CAPACITY RETROFIT Figures 3‐1 and 3‐2 illustrate t he FGD and SCR capacity that wa s installed during 2008 and through the end of 2010. 5 Figure 3‐1 shows that more than 20,000 MW of FGD capacity came on‐line in each of 2008 and 2009, and more th an 15,000 MW of capacity is anticipated to be operational in 2010. Figure 3‐2 presents the installe d generating capacity of SCR ov er the similar period. Figure 3‐2 shows that although t he generating capacity of SCR i nstalled is small compared to FGD, it is a signifi cant amount on an absolute basi s. 3.2 BOILERMAKER HOURS The inventory of FGD and SCR equ ipment installed in 2008 and 20 10 can be used to estimate boilermaker hours (i.e ., person‐hours of skilled boile rmaker labor) needed for each incremental megawatt ca pacity of FGD or SCR retrofit. The relationship between boilerm aker hours demand and generatin g capacity, for both FGD and SCR, is shown in Fi gure 3‐3. This relationship was developed based on discussions with suppliers, archi tect/engineering firms, and ow ners of EGU’s that have implemented control technologies. The relationship in Figure 3‐3 is important in generalizing the experience in 2008‐ 2010 and, based on that experienc e, projecting future boilermak er labor needs. Examining EPA’s parsed output fi les shows that compared to the generating capacity of the units retrofit in 2008‐2010, the generating cap acity of units anticipated to be retrofit with FGD and SCR in 2012 to 2014 is smaller.

5 These data were estimated using the Emissions Economic Modeling System Data Base, which contains detailed data related to the electric utility sector, in terms of unit design, fuel, unit operation and production costs, installed control equipment, emission control assumptions and costs, and unit specific emission rates for over 2,500 steam electric units and all opera ting combustion turbine and combine-cycle units.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

3‐2 Figure 3-1. FGD Capacity Installed: 2008-2010

Figure 3-2. SCR Capacity Installed: 2008-2010Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

3‐3 Figure 3-3. Relationship between Requi red Boilermaker Hours for FGD and SCR Installation and Generating Capacity The non‐linear relationship of b oilermaker hours required and g enerating capacity shown in Figure 3‐3 suggests more boilermaker hours and other c onstruction consumables will be needed for t he 2012 to 2014 retrofits, comp ared to the 2008 to 2010 retrofits, for an equivalent amount of generating capacity

. Figure 3‐3 describes the boilermaker demand total for the entir e project. The distribution of boilermaker hour s is not uniform over the const ruction period; specifically, early work such as clearing and preparing the sit e, concrete and foundation work, and general construction activities do not req uire boilermaker skills. Based on discussions with suppliers, architect/engineer ing firms, and owners of EGU’s, a relationship has been developed that presumes most boilermaker work is conducted over 5 quarters for FGD and 4 quarters for SCR, st aged according to a schedule that has this work conc luding one full quarter prior t o project completion. This schedule represents the average experience within the indu stry.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

3‐4 Figure 3‐4 presents the results of calculations of quarterly de mand of boilermaker hours, as experienced in 2008 through 2010, based on Figure 3‐3 . The bar chart in Figure 3‐4 shows that boilermake r‐hours demand, reported both o n a quarter total and a three‐quarter trailing average, peaked through the middle and towards the end of 2008. Using this analysis , it is estimated that a quarte rly maximum total exceeding 5.5 million boilermaker hours, and a three‐quarter tr ailing average exceeding 5.1 million boilermaker hours, were required.

Figure 3-4. Calculated Bo ilermaker Demand for Both FGD and SCR: 3Q 2006 though 2Q 2010 The consumption of boilermaker h ours in Figure 3‐4 is assumed a s a constraint on the construction of FGD and SC R in the 2012‐2014 timeframe.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

4‐1 SECTION 4 CRITIQUE OF EPA’S APPR OACH TO DETERMINING REQUIRED FGD AND SCR CAPACITY

The EPA analysis addressed two sc enarios:  (a) Base Case and (b ) State Budget – Limited Trading. These two scenarios were evaluated to determin e the number and generating capacity of FGD and S CR retrofits required for the y ears 2012 and 2014. It should be noted that Base Cas e compliance assumes compliance with other regulatory programs such as Title IV, NO x SIP Call, Consent Decrees and State Programs, but does not include any compliance with CAIR . In EPA’s preferred option ( State Budget

– Limited Trading ), PTR allows for unrestricte d intrastate trading and limited interstate trading among 32 states based upon state bud gets. EPA initially modeled the amount of “new” FGD and SCR capacity that would be required to meet the regulatory requirements of the Base Case i n both 2012 and 2014. This modeled capacity is then carried forward into the Li mited Trading Case, and is needed to meet the targets of the Limited Trading Case i n both 2012 and 2014. (Note that the Limited Trad ing Case in 2012 includes FGD and SCR retrofits that EPA projects will be compl eted by 2012 in order to comply with the TR. Many of these retrofits were modeled by EPA; however, a few retrofit s have been identified as retrofits that would have been installed to compl y with CAIR or consent decrees.) With this Base Case cap acity embedded, EPA then model s the additional/incremental FGD and S CR capacity that would be requi red to meet the PTR’s state budgets. Significant ly, it should be noted that the FGD and SCR capacity predicted by EPA for the State Budget

– Limited Trading scenario is incremental to that required for the Base Case capacity. Both Figures 4‐1 and 4‐2 illustrate the total amount of new FGD and SCR capaci ty, respectively, that will be required under the PTR by January 1, 2012, and Janua ry 1, 2014, including both the Base Case amounts (shown in blue) and the State Budget

– Limited Trading Case (designated as “LT Case”), shown in red. (Note th at the 2012 and 2014 amounts are not cumulative, i.e., the 2014 amounts do not include the 2012 amounts.) Therefore, EPA’s statement that the PTR will only result in 14 GW of additional FGD capacity by 2014 is misleading. A s shown above, EPA omitted fro m the discussion the 10 GW of FGD capacity that wi ll also be needed from the Bas e Case to achieve compliance under the Limited Trading Case by 2014. In reality, therefore, EPA has modeled, for completion after Ja nuary 1, 2012, but before Janua ry 1, 2014, a total of approximately 25 GW of new FGD ca pacity and 8.2 GW of new SCR c apacity in order to meet the PTR’s targets.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

4‐2 Figure 4-1. EPA New FGD Capacity – Base and Limited Trading Cases

Figure 4-2. EPA New SCR Capacity – Base and Limited Trading Cases Based upon EPA’s estimated capacity for both 2012 and 2014, we have projected the number of new FGD and SCR re trofit projects by quarter. Thi s identification of projects by quarter is displayed in Figure 4‐3. The data in Fig ure 4‐3 reflect EPA’s assumptions that a given amount of capacity and generating unit s can be retrofit by 2012 and 2014. This depiction also shows that some of the owner ‐announced FGD and SCR projects will be operati onal at various times in 2013. It should be emphasized that the schedule sho wn in Figure 4‐3, with the exce ption of the relatively modest number of proj ects (50) announced by EGU owne rs, is an assumption by EPA and not the re sult of a predictive analysis.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

4‐3 Figure 4-3. EPA Estimate of the Number of FGD and SCR Projects Operational: 2011 to 2014Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

5‐1 SECTION 5 REVISED SCHEDULES AN D MODELING RESULTS

This section presents a revised compliance schedule based on re alistic assumptions of project implementation. Resul ts presented in this section ad dress (a) schedule assumptions for constructing and installing FGD and SCR process equipment, (b) the projected compliance dates based on a start date of the third q uarter of 2011, and (c) the quarter‐by‐quarter boilermaker demand.
5.1 SCHEDULE FOR INST ALLING FGD AND SCR Section 1 noted a companion report being submitted by UARG with respect to the PTR, summarizing realistic sched ules for the retrofit of indivi dual FGD and SCR process equipment. This analysis uses results from that documen t to project the compliance schedule for the inve ntory of units affected by the PTR. Table 5‐1 recommends FGD and SCR project retrofit schedules bas ed on the UARG survey. The table summarizes the number of months required to i mplement an FGD or SCR retrofit project, startin g with preliminary engineering or permitting, through commercial operation. The schedule data is presented for variou s categories of generating stations and conditio ns at the site – for example, t he number of unit processes to be installed (i.e., the number of FGD modules or S CR reactors), and the existing equipment that is on‐si te. For both FGD and SCR, an ab breviated schedule is used for any unit for which an o perating date has been announce d by the owner. This special case presumes that EGU owners with announced opera ting dates have already initiated engineering, p ermitting, or other background activities. This assumption will not always be valid but is considered appropria te for these types of projects with owner‐announced schedules. These data were used to determine when a project would be opera tional, given a defined start date as described above. 5.2 DETERMINING THE SCHEDULE The schedule by which the EGUs a re predicted to have the contro l equipment installed and operational was de termined. The EGUs predicted by EPA to install FGD and/or SCR were partitioned into two categories, and treated as described as follows:Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

5‐2 Table 5-1. Estimated Implementation Sc hedule (Months) For FGD, SCR Projects
Control Technology Site and Application Category Design, Fabrication, Installation (Months) Flue Gas Desulfurization Single Unit at “Unscrubbed” Station: Large Owner 40 Single Unit at “Unscrubbed” Station: Small (e.g., co-operative) Owner 45 Single Unit at Site with Existing FGD Equipment 38 Two Units at “Unscrubbed” Site 40 for first unit; second unit, additional 3 months Three or More Units at “Unscrubbed” Site 44 for first unit; additional units, additional 3 months each. Selective Catalytic Reduction Single Unit at Site 36 Multiple Units at Site 39
5.2.1 Owner-Announced Project Dates The scheduled retrofit of either FGD or SCR equipment (or both) has been announced by unit owners for 50 projects. This analysis adopted those dates without question. EGU owners for these projects released specif ic dates when the technology is planned to be oper ational. Some dates populate 20 11; most are within the 2012‐2013 timeframe.
5.2.2 Modeled Project Start Dates All other units – i.e., all unit s besides the units with owner‐ announced dates – were considered to have start‐project dates in 3Q 2011; these dates are accepted as the earliest dates an EGU owner could initiate engineering or permi tting steps in light of EPA’s planned rulemaking complet ion date for the PTR and the li kelihood of changes to the PTR by the time EP A completes the rulemaking. Ea ch retrofit project (FGD or SCR) was assigned an impl ementation timeline, based on the applicable unit category (per Table 5‐1). This schedule, together with the assu med start date of 3Q 2011, defined the completion date for a given unit. Figure 5‐1 presents the project implementation as a function of time – defined by the quarter in which the FGD or SCR process becomes operational . Figure 5‐2 shows that a 3Q 2011 start‐project date , together with the applicable implementation timeline, results in a range of project completion dates under which only a fraction of projects can be operational b y the EPA‐proposed January 1, 2 012, and January 1, 2014, compliance dates – and thes e projects are only those for which unit ownersSchedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

5‐3 have announced a project complet ion date by January 1, 2012, or by January 1, 2014, respectively, and which this analysis assumes will meet t heir owner‐ announced completion dates. The largest number of FGD and SCR p rojects are projected to become operational (i.e., are completed) at variou s dates between early 2015 and mid 2016.

Figure 5-1. Predicted FGD and SCR Opera tional Dates for Inventory of PTRAffected Units The majority of units are projected to be unable to meet the EP A‐proposed compliance dates; specifically, 54 projects targeting the Janua ry 2012 date are “late,” while 81 projects targeting the January 2014 date are “late”. O nly about 27% of the targeted 185 retrofit projects are projected to meet the applic able EPA‐proposed date. 5.3 REQUIRED BOILERMAKER HOURS The project implementation sched ule in Figure 5‐1 can be used t o calculate the demand for boilermaker hours f or Transport Rule compliance. Figure 5‐2 presents the quarterl y demand for boilermakers to su pport the PTR – but with the compliance schedule adj usted to reflect the more reali stic control‐ implementation timetables as described and applied above. Under this scenario, the peak demand, for example, is pro jected to be somewhat more than 4,000,000 hours per quarter but less than the d emand for the 2008‐2010 FGD and SCR installation demand.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

5‐4 Figure 5-2. Quarterly Demand for Boilerm aker Hours: Predicted PTR Compliance (FGD and SCR) Separate from this analysis, the boilermaker demand was calculated to support the EPAassumed project implementation schedule of 21 and 27 months, respectively, for SCR and FGD implementation. Figure 5-3 presents the results of this analysis. Figure 5-3 shows that, to meet EPA’s proposed schedule, the estimated peak quarterly demand for boilermaker hours is approximately 8,000,000 hours and the estimated maximum threequarter average demand is approximately 7,000,000 hours. Consequent ly, even if the engineering and permitting tasks could be completed and the necessary process equipment and material could be fabricated a nd delivered to the site – all within the 21- and 27-month periods EPA assumes and by the compliance dates it proposes – there would be no basis for concluding that a su fficient number of boilermakers would be available to do the work necessary to ha ve the control equipment installed and operational within those periods.Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

5‐5 Figure 5-3. Quarterly Demand for Boil ermaker Hours: EPA-Assumed Project Schedules (FGD and SCR)Schedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

6‐1 SECTION 6 OBSERVATIONS

This report critically reviewed EPA assumptions regarding PTR i mplementation. These results show that, contrar y to EPA projections, there is inadequate time to deploy the necessary control tec hnology to meet the PTR mandate s. Specifically, of the 185 control technology retrofi t projects that EPA anticipat es, only 27% can be completed by the EPA‐proposed com pliance dates. (This 27% repre sents the fraction of the total retrofit projects for which unit owners a nnounced a completion date by January 1, 2012, or Janu ary 1, 2014, respectively, and which this analysis assumes will meet their owner‐announced completion dates.) A to tal of 54 retrofit projects are predicted to miss the January 1, 2012, deadline; a nd 81 such projects are predicted to miss the January 1, 2014, deadline. Project co mpletion dates persist well into 2016. A fundamental flaw in EPA’s evaluation is assuming the ability to deploy SCR and FGD in 21 and 27 months, respecti vely. Even if this unrealistic schedule could otherwise be met, it could not i n fact be met due to a limit in boilermaker hours, using the 2008‐2010 experience as a benchmark. The concentrated , simultaneous demands on equipment and service s, particularly as manifested b y the consumption of boilermaker hours, make compl iance with EPA’s proposed sched ule impossible. Moreover, this analysis does not take into consideration the ad ditional impacts of other rulemakings on the availab ility of labor and tradespeople as well as engineering contractors. Examples include the recent cement kil n MACT standards, which will require a large number of kilns to install wet FGD s ystems over the next three years, and the ICI boiler and process heat MACT standards , which are expected to require hundreds of w et FGD systems and other types of controls to be installed by 2014 if EPA makes th ose standards final by next ye ar. In addition, these rulemakings and the PTR itself will require, as part of any wet ‐FGD system installation, the construction of a new stack as a result of th e increase in water vapor in the flue gas and its effect on stack flow properties a s well as the construction or expansion of lan dfill capacity for byproducts o f FGD system operation. Limits on the availab ility of qualified tradespeople and engineering and construction contractors for stack construction will also have a significant adverse impact on the ability to meet the PTR’s compliance schedule. Co nsideration of theseSchedule of Control Technology Retrofit To Meet EPA’s Proposed Transport Rule October 1, 2010

6‐2 factors reinforces the conclusio n that it will not be possible for regulated electric generating companies to meet t he PTR’s compliance schedule.Attachment III Tables Regarding Current Air Quality at Site s Projected to be Nonattainment Sites in 20122 31531.420001 EMF_US 32433784v1 Current Air Quality at Sites Projecte d to be Nonattainment Sites in 2012
Table I : Annual PM 2.5 NAAQS (1997) Based on Table IV.C-7, 75 Fed. Reg. 45210, 45247 (Aug. 2, 2010). Monitor ID State County Current Air Quality Information 10730023 Alabama Jefferson 10732003 Alabama Jefferson 130210007 Georgia Bibb 130630091 Georgia Clayton 131210039 Georgia Fulton 170310052 Illinois Cook Final Rule -- determination of attainment -- 74 Fed. Reg. 62243 (Nov. 27, 2009) 171191007 Illinois Madison 171630010 Illinois Saint Clair 180190006 Indiana Clark Proposed Rule -- determination of attainment -- 75 Fed. Reg. 55727 (Sept. 14, 2010) 180372001 Indiana Dubois Final Rule -- determination of attainment -- 74 Fed. Reg. 62243 (Nov. 27, 2009) 180970078 Indiana Marion 180970081 Indiana Marion 180970083 Indiana Marion 211110043 Kentucky Jefferson Proposed Rule -- determination of attainment -- 75 Fed. Reg. 55727 (Sept. 14, 2010) 261630015 Michigan Wayne 261630033 Michigan Wayne 390170016 Ohio Butler 390350038 Ohio Cuyahoga 390350045 Ohio Cuyahoga 390350060 Ohio Cuyahoga 390610014 Ohio Hamilton 390610042 Ohio Hamilton 390610043 Ohio Hamilton 390617001 Ohio Hamilton 390618001 Ohio Hamilton 420030064 Pennsylvania Allegheny 420031301 Pennsylvania Allegheny 420070014 Pennsylvania Beaver 420710007 Pennsylvania Lancaster Final Rule -- determination of attainment -- 74 Fed. Reg. 48863 (Sept. 25, 2009)3 31531.420001 EMF_US 32433784v1 Monitor ID State County Current Air Quality Information 421330008 Pennsylvania York Final Rule -- determination of attainment -- 74 Fed. Reg. 48863 (Sept. 25, 2009) 540110006 West Virginia Cabell 540391005 West Virginia Kanawha
Table II: 24-hour PM 2.5 NAAQS (2006) Based on Table IV.C-9, 75 Fed. Reg. at 45249. Monitor ID State County Current Air Quality Information 10730023 Alabama Jefferson Final Rule -- determination of attainment -- 75 Fed. Reg. 57186 (Sept. 20, 2010) 10732003 Alabama Jefferson Final Rule -- determination of attainment -- 75 Fed. Reg. 57186 (Sept. 20, 2010) 90091123 Connecticut New Haven 170310052 Illinois Cook Not currently designated nonattainment 170310057 Illinois Cook Not currently designated nonattainment 170310076 Illinois Cook Not currently designated nonattainment 170311016 Illinois Cook Not currently designated nonattainment 170312001 Illinois Cook Not currently designated nonattainment 170313103 Illinois Cook Not currently designated nonattainment 170313301 Illinois Cook Not currently designated nonattainment 170316005 Illinois Cook Not currently designated nonattainment 171190023 Illinois Madison Not current ly designated nonattainment 171191007 Illinois Madison Not current ly designated nonattainment 171192009 Illinois Madison Not current ly designated nonattainment 171193007 Illinois Madison Not current ly designated nonattainment 180190006 Indiana Clark Not currently designated nonattainment 180372001 Indiana Dubois Not currently designated nonattainment 180830004 Indiana Knox Not currently designated nonattainment 180890022 Indiana Lake Not currently designated nonattainment 180890026 Indiana Lake Not currently designated nonattainment 180970042 Indiana Marion Not currently designated nonattainment 180970043 Indiana Marion Not currently designated nonattainment 180970066 Indiana Marion Not currently designated nonattainment 180970078 Indiana Marion Not currently designated nonattainment 180970079 Indiana Marion Not currently designated nonattainment 180970081 Indiana Marion Not currently designated nonattainment 180970083 Indiana Marion Not currently designated nonattainment 181570008 Indiana Tippecanoe Not currently designated nonattainment 191630019 Iowa Scott Not currently designated nonattainment 210590005 Kentucky Daviess Not current ly designated nonattainment4 31531.420001 EMF_US 32433784v1 Monitor ID State County Current Air Quality Information 211110043 Kentucky Jefferson Not currently designated nonattainment 211110044 Kentucky Jefferson Not currently designated nonattainment 211110048 Kentucky Jefferson Not currently designated nonattainment 245100040 Maryland Baltimore City Not currently designated nonattainment 245100049 Maryland Baltimore City Not currently designated nonattainment 261150005 Michigan Monroe 261250001 Michigan Oakland 261470005 Michigan St. Clair 261610008 Michigan Washtenaw 261630015 Michigan Wayne 261630016 Michigan Wayne 261630019 Michigan Wayne 261630033 Michigan Wayne 261630036 Michigan Wayne 290990012 Missouri Jefferson Not currently designated nonattainment 291831002 Missouri Saint Charles Not currently designated nonattainment 295100007 Missouri St. Louis City Not cu rrently designated nonattainment 295100087 Missouri St. Louis City Not cu rrently designated nonattainment 340171003 New Jersey Hudson 340172002 New Jersey Hudson 340390004 New Jersey Union 360050080 New York Bronx 360610056 New York New York 360610128 New York New York 390170003 Ohio Butler Not currently designated nonattainment 390170016 Ohio Butler Not currently designated nonattainment 390170017 Ohio Butler Not currently designated nonattainment 390171004 Ohio Butler Not currently designated nonattainment 390350038 Ohio Cuyahoga 390350045 Ohio Cuyahoga 390350060 Ohio Cuyahoga 390350065 Ohio Cuyahoga 390490024 Ohio Franklin Not currently designated nonattainment 390490025 Ohio Franklin Not currently designated nonattainment 390610006 Ohio Hamilton Not currently designated nonattainment 390610014 Ohio Hamilton Not currently designated nonattainment 390610040 Ohio Hamilton Not currently designated nonattainment 390610042 Ohio Hamilton Not currently designated nonattainment 390610043 Ohio Hamilton Not currently designated nonattainment 390617001 Ohio Hamilton Not currently designated nonattainment 390618001 Ohio Hamilton Not currently designated nonattainment 390811001 Ohio Jefferson5 31531.420001 EMF_US 32433784v1 Monitor ID State County Current Air Quality Information 391130032 Ohio Montgomery Not currently designated nonattainment 391530017 Ohio Summit 420030008 Pennsylvania Allegheny 420030064 Pennsylvania Allegheny 420030093 Pennsylvania Allegheny 420030116 Pennsylvania Allegheny 420031008 Pennsylvania Allegheny 420031301 Pennsylvania Allegheny 420070014 Pennsylvania Beaver 420110011 Pennsylvania Berks Not currently designated nonattainment 420210011 Pennsylvania Cambria 420430401 Pennsylvania Daupin 420710007 Pennsylvania Lancaster 421330008 Pennsylvania York 471251009 Tennessee Montgomery Not currently designated nonattainment 540090011 West Virginia Brooke 550790010 Wisconsin Milwaukee 550790026 Wisconsin Milwaukee 550790043 Wisconsin Milwaukee 550790099 Wisconsin Milwaukee Table III: 8-hour Ozone NAAQS (1997) Based on Table IV.C-11, 75 Fed. Reg. at 45252. Monitor ID State County Current Air Quality Information 220330003 Louisiana East Baton Rouge Final Rule -- determination of attainment -- 75 Fed. Reg. 54778 (Sept. 9, 2010) 361030002 New York Suffolk 361030009 New York Suffolk 421010024 Pennsylvania Philadelphia 480391004 Texas Brazoria 482010051 Texas Harris 482010055 Texas Harris 482010062 Texas Harris 482010066 Texas Harris 482011039 Texas Harris 484391002 Texas Tarrant