COMMENTS OF THE UTILITY AIR REGULATORY GROUP 

on the 

PROPOSED FEDERAL IMPLEMENTATION PLANS 

TO REDUCE INTERSTATE TRANSPORT OF FINE PARTICULATE 

MATTER AND OZONE 

(PROPOSED AIR POLLUTION TRANSPORT RULE) 

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, 2010
TABLE OF CONTENTS 

I. Introduction..........................................................................................................................4 

II. UARG Agrees with Certain Aspects 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 Not Include an Initial Compliance Deadline 

of 2012. ..............................................................................................................................11 

A. An Initial Compliance Deadline of 2012 Will Not Allow Enough Time for 

Sources To Make the Changes Necessary To Comply with the Transport 

Rule, or for States To Develop Implementation Plans. .........................................12 

B. A Compliance Deadline in 2012 Is Neither Necessary Nor Appropriate..............14 

IV. The Proposed Transport Rule Would Unlawfully 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 Direct Control Remedy Option -- Under 

Section 110(a)(2)(D)(i)(I). .....................................................................................27 

V. The January 2012 and January 2014 Compliance Deadlines Set Forth in the 

Proposed Transport Rule Are Unreasonable and Unrealistic. ...........................................27 

A. Background............................................................................................................31 

1. Step One Requires More Than Conducting 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. ..............................................................37 
ii 

B. EPA Relies Upon Incomplete and Outdated Information in Concluding 

that FGD and SCR Retrofits Can Be Installed in a Total of Less than 30 

Months. ..................................................................................................................38 

C. FGD Installations: Real-World Examples Demonstrate that EPA Has 

Substantially Underestimated How Long It Typically Takes To Retrofit 

FGD Systems at Power Plants. ..............................................................................41 

D. SCR Installations: Real-World Examples Demonstrate that EPA Has 

Substantially Underestimated How Long It Typically Takes To Retrofit 

SCR Systems at Power Plants................................................................................44 

E. Summary and Conclusions. ...................................................................................46 

VI. EPA’s Analysis Significantly Understates the Amount of Electric Generating 

Capacity that Would Have To Undergo 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 Decisions 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 “Monitored-Plus-Modeled” Approach.........................53 

C. EPA’s Proposed Air Quality Contribution 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 Certain States as “Group 1” States Is 

Inadequately Explained and Misguided.................................................................61 

F. EPA’s Determinations of “Significant Contribution” and “Interference 

with Maintenance” Improperly Presuppose Upwind-State EGU Emissions 

as the Primary Cause of Downwind Nonattainment Problems and 

Inappropriately Underestimate the Contribution 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. .......................................................64 
iii 

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 Assumptions 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 Determinations Do Not Account Adequately for 

the Interaction Between the Proposed Rule and Other CAA Programs. ...........................85 

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.............................................................................................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 the PSD Emission Thresholds in the 

Agency’s June 2010 GHG Tailoring Rule.............................................................86 

X. EPA Should Amend the Proposed Transport Rule To Allow for Increased 

Flexibility in Compliance and Allowance Trading............................................................87 

A. The Variability Limits and Assurance Provisions Proposed 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..................................................................................91 
iv 

B. Adjustments to Certified Information by the Administrator..................................94 

C. Correction and Resubmission of Quarterly Reports ..............................................94 

XII. As a Matter of CAA Procedural Requirements, the Proposed Rule’s Unfounded 

Assumptions, Errors, and Apparent Anomalies -- and EPA’s Failure To Explain 

Adequately Critical Aspects of the Proposal and To Include in the Docket 

Information that Would Enable Replication of EPA’s Process -- Make the 

Proposed Rule Inadequate for Public Comment................................................................96 

XIII. Conclusion. ........................................................................................................................98 
COMMENTS OF THE UTILITY AIR REGULATORY GROUP 

on the 

PROPOSED FEDERAL IMPLEMENTATION PLANS TO REDUCE 

INTERSTATE TRANSPORT OF FINE PARTICULATE MATTER AND OZONE 

75 Fed. Reg. 45210 (Aug. 2, 2010); Docket ID No. EPA-HQ-OAR-2009-0491 

October 1, 2010 

___________________________________________________________________________ 

On August 2, 2010, the U.S. Environmental Protection Agency (“EPA” or the “Agency”) 

published its Federal Implementation Plans To Reduce 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 voluntary, not-for-profit group of electric utilities, 

other electric generating companies, and national trade associations. UARG’s purpose is to 

participate on behalf of its members collectively in EPA rulemakings under the Clean Air Act 

(“CAA” or “Act”) and other proceedings that affect the interests of electric generators and in 

related litigation. Because the Proposed Transport Rule specifically -- and exclusively -- targets 

nitrogen oxide (“NOx”) and sulfur dioxide (“SO2”) 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 background of Agency decisions that has made 

participation in this proceeding exceedingly difficult. Specifically, on September 1, 2010, EPA 

published a separate Notice of Data Availability (“NODA”) for the Proposed Transport Rule. 75 

Fed. Reg. 53613. The NODA announces additional EPA 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 the 
2 

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 separate deadlines for public comments -- one on the 

Proposed Transport Rule and the information posted in the docket contemporaneously with it, 

and another for the information released pursuant to the NODA -- makes it extraordinarily 

challenging to provide comprehensive comments on EPA’s proposal. In addition, EPA on 

September 10, 2010, denied UARG’s August 19, 2010 request 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 proposed 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 the 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 promulgated in 2005 and the U.S. Court of 

Appeals for the D.C. Circuit found to be “fundamentally flawed,” initially vacated and remanded 

to the Agency in 2008, and then allowed to remain in place pending completion of EPA’s 

remand rulemaking. See North Carolina v. EPA, 531 F.3d 896, 929 (D.C. Cir. 2008), modified 

on petitions for rehearing, 550 F.3d 1176 (D.C. Cir. 2008). 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 and September 10, 2010 letters herein by 

reference. 
3 

110(a)(2)(D)(i)(I) of the Act, which requires, in relevant part, each state’s plan for attaining the 

national ambient air quality standards (“NAAQS”) to “contain adequate provisions . . . 

prohibiting . . . any source or other type of emissions activity within the State from emitting any 

air pollutant in amounts which will . . . contribute significantly to nonattainment 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 states. 75 Fed. Reg. at 45210/1. According to the 

proposal, EPA plans to promulgate a final rule in spring 2011,2 imposing an initial compliance 

date of January 1, 2012 (May 1, 2012 for the ozone season3 NOx program), and a further SO2

reduction requirement on January 1, 2014, for many states (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 additional comments on EPA’s September 1, 2010 

NODA and on any subsequently published EPA updates to support the final rulemaking. 

Because the information in the NODA is inextricably linked with information in the PTR, some 

 2

 Although the Proposed Transport Rule states only that EPA anticipates 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 Presentation 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 correspond to the ozone monitoring season for each 

state. 75 Fed. Reg. at 45292/1. UARG does not believe 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 consider 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 will 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 discussed in section II of these comments, UARG agrees with certain 

aspects of the proposal. For example, UARG supports EPA’s preferred option of permitting 

some degree of emission allowance trading (although, 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 misguided. 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 unlawful 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 for determining statewide emission reduction 

obligations and has required additional emission reductions even where they have not been 

shown to be needed to meet the air quality objectives that EPA asserts. And EPA in this 

proposed rule has arrogated to itself, in contravention of the law, the right and responsibility to 

determine how a state’s emission reduction requirements must be accomplished, thereby 

assuming an exceptionally heavy burden to show that it has applied its unit allowance allocation 

methodology accurately and consistently. Review of the PTR’s supporting information, 

however, reveals that EPA’s approach on this score is anything but accurate and consistent. 

Moreover, in many respects, EPA’s explanation of the elements of the PTR, and its information 
5 

and calculations offered in support of the PTR, are opaque to the point of incomprehensibility. 

These points are explained further below. 

 For these reasons, UARG believes that the PTR 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 replacement 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 sections 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 allowance trading, (ii) the proposal to permit 

allowance banking beginning in the first year of the 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 strengthen these elements of the proposed rule. 

A. EPA’s Proposal, in Its Preferred Remedy 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 interstate trading. UARG supports EPA’s proposal 

to permit at least some degree of allowance trading. Permitting interstate allowance trading 

would provide for increased flexibility and permit more cost-effective compliance options. 

Increased flexibility will be particularly important in the early years of the program, especially if 

 4

 As discussed below, UARG opposes the proposed allowance auction feature of the 

proposed Intrastate Trading Remedy Option (and indeed opposes that remedy option altogether). 
6 

EPA does not change the proposed rule’s unreasonably 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 interstate 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 unless it is promulgating a rule that achieves 

something measurable toward the goal of prohibiting sources ‘within the State’ from contributing 

to nonattainment or interfering with maintenance ‘in any other State,’” the court held that 

“EPA’s apportionment decisions have nothing to do with each state’s ‘significant 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 individual states to downwind nonattainment and 

maintenance problems. 

In developing the Proposed Transport 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 contribution to 

nonattainment and interference with maintenance based on the emissions that EPA projected 

could be eliminated from that state 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, although UARG disagrees with many aspects of 

the data and methodology that EPA used in this analysis, EPA’s methodology does, as a general 
7 

matter, attempt to address the EPA-projected contribution 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 should align with the court’s characterization of 

states’ section 110(a)(2)(D)(i)(I) duties.5 

In addition, if EPA retains its proposed 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 assurance provisions will not be necessary to 

limit interstate trading during the first two years of the program because during those years, 

“state-specific budgets are based on known air pollution controls and thus a high level of 

certainty exists about where reductions will occur.” 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 equipment that will be installed and operational 

by that time, there is no need for assurance provisions during this time period.7

 

B. Permitting Banking of Allowances Beginning in the First Year of the 

Program. 

The Proposed Transport Rule properly recognizes the important environmental and 

economic benefits of allowance banking, a feature 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 not 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 compliance 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 these comments, many of EPA’s assumptions 

regarding which controls will be installed and 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-effective early reductions are possible. Unfortunately, 

the nature and stringency of the proposed rule’s emission reduction requirements and its 

proposed compliance schedule would 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 states 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 supports approaches that would permit the use 

of banked CAIR NOx allowances for compliance with the Proposed Transport Rule. In the final 

rule, EPA should provide that it will transfer all CAIR NOx annual and ozone season allowances 

held in each source’s compliance accounts for the final compliance period of CAIR into that 

source’s compliance accounts for the new program (to the extent the 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 otherwise acquired from others) for compliance with 

the new program. 

EPA’s concern that some may view an approach that authorizes sources to use banked 

CAIR NOx allowances as unfairly permitting some sources a larger share of allowances due to 
9 

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 allowances, on a banked basis, in a new 

program. Moreover, if EPA disallows use of banked 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 use 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 identified by the court with respect to CAIR NOx 

allowances was the way EPA established NOx allowance 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 allowances in the new program -- have no value 

after the allowance transfer 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 banked 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 better ways to avoid that outcome 

than to invalidate the allowances in whole or in part. EPA should allow sources the full benefit 

of their banked CAIR NOx allowances. 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 first 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 set 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 Transport Rule as a seamless regulatory process to 

ensure that the mechanisms remain in place for continuous compliance and assurance of 

continued emission reductions. The D.C. Circuit, in its December 2008 decision, determined 

that CAIR could remain in place while EPA developed a replacement rule, specifically because 

of concerns that the emission reductions attributable to CAIR would not occur during the 

transition period if CAIR were vacated. Because the 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 possibility 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 current rulemaking and permit an adequate compliance 

schedule under the new rule, even while electric generating companies are 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 include 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 requirements. 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 allowance auctions. It 
11 

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 program. 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 such 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” denotes that a source is allowed to emit within the 

limits of its allowance allocations -- and providing 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 Include an Initial Compliance Deadline of 

2012. 

Many of the flaws in the Proposed Transport Rule, described in the sections that follow, 

could be resolved or at least somewhat ameliorated by deferring the initial 2012 compliance date 

and having CAIR’s allowance trading and enforcement mechanisms remain in effect pending 

implementation of the Transport Rule. It is unreasonable and unrealistic, for example, to expect 
12 

emission reductions required by the proposal to be achieved by January 1, 2012, barely six 

months after the date on which EPA expects to issue a final Transport Rule. 

A. An Initial Compliance Deadline of 2012 Will Not Allow Enough Time for 

Sources To Make the Changes Necessary To Comply with the Transport 

Rule, or for States To Develop Implementation Plans. 

An initial compliance deadline of January 1, 2012, will not allow sufficient time for 

sources to make the adjustments necessary to comply 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 burners (“LNBs”), and in many cases, would not 

allow sufficient time for sources to switch 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 withdraw the proposed rule and 

reinitiate rulemaking with a new proposal or issue 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 schedule that EPA proposes is in effect made even tighter by 

the fact that EPA is already changing 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 effect will result in substantial changes to 

the proposed rule and noting that further changes are to come. Among other things, the NODA 

 9

 As discussed in these comments, the NODA belies 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 base 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 rule 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 with the proposed rule, showing the initial IPM run, 

indicates that IPM projected about 23,723 MW of new coal generation 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/progsregs/epa-ipm/transport.html.11 By contrast, the updated 

parsed file that EPA added to the docket in connection with the NODA appears to indicate that 

IPM projected only about 2,001 MW of new coal generation 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 modified 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 summary 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, there 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 that it intends to propose additional interstate 

transport determinations in the future as EPA revises the NAAQS for PM2.5 and ozone, and that 

these proposals “could require greater emissions reductions from states covered by [the Proposed 

Transport Rule] and/or require reductions from states not covered” by the current proposal. 75 

Fed. Reg. at 45213/3. It would be very difficult for states and electric 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 allocations) 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 -- and 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 approval of SIPs before the program begins. See

section IV infra. 

B. A Compliance Deadline in 2012 Is Neither 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 EPA 
15 

representatives, the emission levels required in the 2012 phase for the most part reflect the 

emission reductions that would occur even in the absence of the Transport Rule. However, as 

noted above, in a number of cases, EPA has made 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 these assertions that the emission reductions required in 

2012 would occur even without the Proposed Transport Rule, EPA indicated in a presentation 

given in July 2010, when it announced the proposed rule, that it projects that the proposed rule 

would reduce SO2 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 publication in the Federal Register, EPA acknowledged 

that, according to the Agency’s projections, the 2012 state budgets in the Proposed Transport 

Rule would reduce SO2 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 existing controls are working to reduce emissions; the 

result is that concentrations of SO2 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/transport/actions.html and reproduced 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 reductions 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 for 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 (NO2) decreased by 27 percent between 2001 and 2008 and by 35 percent 

between 1990 and 2008, and that nationwide concentrations of SO2 decreased by 30 percent 

between 2001 and 2008 and by 59 percent between 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. Additionally, 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 annual and 24-hour concentrations of PM2.5 decreased 

by 17 and 19 percent, respectively, between 2001 and 2008. Id. at 1, 15, 20. 

14 The D.C. Circuit’s finding that the 2015 compliance deadline 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 their significant contribution with the attainment 

deadlines for downwind areas,” 531 F.3d at 912, does not mandate a 2012 compliance deadline. 

In the preamble to the proposed rule, EPA attempts to justify its proposed 2012 compliance 

deadline in part by asserting that it is coordinated with the 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 have 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 nonattainment areas “shall be the date by which 

attainment can be achieved as expeditiously as practicable” to justify 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 that 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 the 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 consistent with the requirement that states attain 

the NAAQS as expeditiously as practicable”). This requirement, that 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 dates to the extent proposed. 
17 

EPA should not adopt the 2012 compliance deadline in the Proposed Transport Rule and 

should not in any event consider any compliance date earlier than 2015.15 In any event, if EPA 

promulgates a Transport Rule that, like the proposed rule, includes requirements more stringent 

than CAIR, the compliance deadline must reflect the degree of stringency of those requirements. 

UARG is not alone in its concern regarding the initial compliance date. Last year, for 

example, the Lake Michigan Air Directors Consortium (“LADCO”) strongly recommended that 

any CAIR replacement rule include an initial compliance date no earlier than 2017 for any 

significant additional emission reduction requirements. See Letter from LADCO to 

Administrator Jackson (Sept. 10, 2009) (“LADCO Letter”) at 1. LADCO explained in its 

recommendations to EPA that it had conducted a state-by-state analysis that indicated that 

installation of significant new NOx and SO2 controls -- specifically, installation of selective 

catalytic reduction systems (“SCRs”) and flue gas desulfurization systems (“FGDs” or 

“scrubbers”) -- would not be possible 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 capital-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 construed as suggesting that a compliance date 

as early as 2015 is necessarily appropriate or could be justified. 

16 According to LADCO, a fundamental assumption for this state-by-state analysis was a 

July 2012 start date for the planning, engineering, and construction of any new NOx or SO2 

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. Thus, 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 submit them to EPA for approval. 
18 

interest rates, in the near term. In addition, electric generating companies have fiduciary 

obligations that prevent them from making commitments to capital 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 required 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 increased emissions. CAIR could remain in place 

and would continue to maintain a strong and effective program of emission reductions pending 

the initial compliance deadline for 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 implementation of the Transport Rule. 

UARG further notes that it would be possible for EPA to encourage early emission 

reductions beginning in 2012 under the proposed rule even if the initial binding compliance date 

under the rule was not until some years later. One possible approach would be to set “shadow” 

allowance allocations, using the best data available, for 2012 and each subsequent year until the 

new program begins. Then, during the period leading up to the new program’s initial 

compliance year, EPA (or, more properly, a state) could credit sources with additional 

allowances corresponding to the number of tons they emitted below their shadow allowance 

allocation levels in those years, with those allowances eligible to be banked and used beginning 

in the first compliance year. The ability to earn allowances -- usable once the new program 

begins -- for early reductions would give sources a meaningful 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 affording 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 such 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 Unlawfully 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 EPA proposes would make it 

nearly impossible for states to develop, submit, and receive EPA approval of SIPs in time to use 

them for implementation of the first phase of the 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 requirements,” 75 Fed. Reg. at 45342/2, misses the point. The 

opportunity to replace federal requirements 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 Transport Rule. EPA’s proposal would effectively 

bypass the states, at least with respect to the first phase of the program. This is unsupported by 

anything in the proposed rule and 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 and approval before implementation of a new or 

revised NAAQS. CAA § 110(a)(1). See also CAA § 101(a)(3) (“air pollution control at its 
20 

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 implementation 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 quality control region in such State”). The CAA 

provides that EPA may promulgate 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 Administrator has approved the SIP. CAA § 110(c)(1). 

With respect to interstate air pollution, section 110(a)(2) provides 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 interstate pollutant transport described in [section 

176A or section 184 of the Act], or to otherwise comply with any 

requirement of [the Act], the Administrator shall require the State to revise 

the plan as necessary to correct such inadequacies. The Administrator 

shall notify the State of the inadequacies, 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 implementation 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 national air quality goals,” as set 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, maintenance 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 provisions give states “authority to make the many sensitive technical 

and political choices that a pollution 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 the 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 state. EPA lacks the knowledge of state-specific 

conditions that state agencies can bring to bear 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 allowances, to assure not only environmental protection but also 

effective energy policies and electric reliability. 

 EPA may issue a FIP, “rescind[ing] state authority,” id., only after a state fails to develop 

and submit a complete SIP and receive Agency approval of it. CAA § 110(c)(1). The Act grants 

no authority to EPA to promulgate a FIP without first giving the states adequate time and a real 

opportunity to develop and submit SIPs that reflect each state’s “sensitive . . . 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 Agency 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 specific, 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 required to approve a state 

plan which provides for the timely attainment and subsequent maintenance 

of ambient air standards, and which also satisfies that section’s other 
22 

general requirements. The Act gives the Agency no authority to question 

the wisdom of a State’s choices of emission 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 effect of a State’s choice of emission 

limitations is compliance with the national standards for ambient air, the 

State is at liberty to adopt whatever mix of emission limitations it deems 

best suited to its particular 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 and other courts of appeals have 

recognized repeatedly and consistently the well-established relationship between the federal 

government and the states with respect to interstate pollution regulation -- and the limited scope 

of federal authority. As the D.C. Circuit explained, 

EPA determines the ends--the standards of air quality--but Congress has 

given the states the initiative and a broad responsibility regarding [the] 

means to achieve those ends through 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 affected 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 control 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 develop 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 determine exactly what states, and sources in the states, must do to comply with 

section 110(a)(2)(D)(i)(I). EPA explains that its proposal “identifies emission reduction 

responsibilities of upwind states, and also proposes enforceable FIPs to achieve the required 

emissions reductions in each state through cost-effective and flexible requirements for power 

plants,” and that “[e]ach state will 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 approach, the states and their sources would be 

required to comply with the FIP unless and until -- after the prolonged period needed for SIP 

development -- SIPs are in fact developed, submitted, and approved by EPA (if and when EPA 

decides to approve them). This scheme is plainly contrary to the terms of the Act and the statesfirst principle recognized and enforced by the courts. 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 right granted to states in section 110 of the Act. Congress 

gave the states the right to develop and submit 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 determining the mix of control measures needed to meet 

those standards and the sources that 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 Act and upsetting the balance that Congress struck between federal 

and state government. As the Supreme Court noted 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 standards 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 revealed 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’ implementation 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’ implementation of their section 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 justification in the proposed rule for 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 findings that CAIR states had failed to submit 

SIPs satisfying their section 110(a)(2)(D)(i)(I) obligations for the 1997 PM2.5 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) obligations . . . by complying with the CAIR requirements. 

Consequently, states within the CAIR region did not need to submit a 

separate SIP revision to satisfy the 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 explanation -- that the states are in default of their SIP obligations 

because the D.C. Circuit held that EPA’s promulgation of CAIR was unlawful -- is nonsensical. 

The states had no choice but to comply with CAIR 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 states have been prevented from meeting their 

statutory obligations due to the failure of EPA to comply with applicable CAA provisions, the 

deadline clock for states to submit 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 [regulatory decision] . . . . [W]e direct that the 

sanction clock for . . . SIPs start, if necessary, from the time of SIP disapproval in accordance 

 19 Some states may have already satisfied any obligation that they have under section 

110(a)(2)(D)(i)(I) for these NAAQS and the 2006 PM2.5 NAAQS. If a state were to have already 

implemented, under state law, the emission reductions necessary to satisfy the requirements of 

the Transport Rule, there would not even arguably 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 required to extend the deadline for compliance with 

automobile NOx emissions standards when EPA was 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 they enacted a four year 

leadtime requirement and we have no alternative but to enforce it, unless or until Congress 

decrees otherwise”). Thus, the three-year deadline for CAA section 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 PM2.5 NAAQS, it 

will finalize FIPs for states that have not submitted SIPs and those for which EPA finds the 

previously-submitted SIPs to be incomplete or inadequate, 75 Fed. Reg. at 45342/2,20 lacks merit 

and is contradicted by EPA’s own underlying justification for proposing the Transport Rule. In 

the proposed rule (as in CAIR), EPA plainly takes the position that it has the authority, if not the 

obligation, to set the overall terms for states’ implementation of section 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) obligation with respect to the 2006 24-hour PM2.5 NAAQS should be 

deemed to begin to run only upon EPA’s promulgation of a valid final rule setting guidelines (in 

the form of statewide emission 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 PM2.5 NAAQS). 
27 

B. EPA Lacks Authority To Impose Any Unit-Specific Emission Rate Limits -- 

Such as the Limits in the Direct Control Remedy Option -- Under Section 

110(a)(2)(D)(i)(I). 

With respect to EPA’s Direct Control Remedy Option, the second alternative option on 

which EPA requests comment in the Proposed Transport 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 performance standards go beyond the requirements of 

section 110 [of the Act] and the scope of the CAIR replacement rule.” LADCO Letter, 

attachment at 5. Indeed, all such matters are reserved to the states in the first instance. See, e.g.,

Michigan, 213 F.3d at 686 (“section 110 left to the states ‘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)) (alteration and emphases in original); Virginia, 108 F.3d at 

1408 (same). Consistent with those cases, EPA at most can determine what overall emission 

tonnage level a state must achieve; it may not impose 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 explain its Proposed Transport Rule,21 EPA made the following 

assumptions about how low SO2 and NOx emission levels from EGUs would be as a result of (a) 

the implementation of CAIR and other on-the-books 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/actions.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 

SO2 (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 been (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 sources very little time 

to achieve those additional reductions. 

Specifically, EPA assumes that affected EGUs will be able to reduce their SO2 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 PTR22) 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 will 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 requirements is when the Transport Rule is finalized. 

For example, at 75 Fed. Reg. at 45273/1, EPA makes “mid-2011 (when the Agency anticipates 

finalizing this rule)” the start of the time period in which source owners are to design and 

construct additional FGD and SCR systems at their plants. EPA is correct in taking this 

approach. It would be entirely inappropriate for EPA either to require affected source owners to 

initiate serious work on additional control systems, or to assume that source owners will 

voluntarily start such efforts, before the Transport Rule is final. Indeed, it would be imprudent 

for regulated sources, and inconsistent with fiduciary obligations for any affected electric 

generator, to start making in the near term any major investments in the design and construction 

of controls that may or may not be needed depending on the terms of the final Transport Rule 

and the terms of other emission control rules that 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 the outcome of the present rulemaking that EPA has 
29 

accomplished if affected companies (a) just complete the installations of FGD units that are 

already underway, and (b) supplement the emission reductions from those controls by switching 

some of their units to burning 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 stations 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 amounts by January 1, 2012, by completing alreadyin-the-pipeline projects to install SCR reactors 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 portions of these comments and in the comments 

being filed by individual UARG members, EPA has substantially overestimated the number of 

 

created by publishing the NODA and indicating that the emission 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/finaltech05.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 underestimated the number of FGD and SCR 

installations that affected utilities would have to undertake and complete between January 1. 

2012, and January 1, 2014, to meet the PTR’s requirements. Even worse than this, though, EPA 

has vastly underestimated the amount of time that it takes utilities to design, permit, construct, 

and start up new FGD and SCR units. It will take 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 SO2 and NOx emission reductions that -- under 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 call 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 regional contributions to downwind 

nonattainment and interference with maintenance. In the alternative, EPA should extend the 

PTR’s emission reduction deadlines 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 after final promulgation of EPA’s 

rule). The following subsections of this part of UARG’s comments provide more detailed 

information on the unreasonableness of the emission 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 with control equipment like FGD and SCR units. A 

more detailed discussion of these steps is provided in a separate report, which is attached hereto 
31 

as Attachment I, and is incorporated by reference herein: Cichanowicz, J.E., “Implementation 

Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process 

Equipment” (Oct. 1, 2010) (hereinafter “Implementation Schedules Report”). The 

Implementation Schedules Report was prepared by J. Edward Cichanowicz, who has been 

involved in -- and has first-hand knowledge of the challenges that can be posed by -- the design, 

permitting, and construction of FGD and SCR retrofits at many power plants throughout the 

United States. Next, section V.B of these comments 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 of 

FGD and SCR retrofits, respectively. These examples demonstrate the complexity and timeconsuming nature of the retrofit installation processes at most sites. EPA’s failure to understand 

this has led the Agency to systematically underestimate 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 activities into one of essentially three broad 

overlapping categories: (1) conducting an engineering review of the facility and awarding a 

procurement contract; (2) obtaining a construction permit; and (3) installing the control 

technology. EPA, “Engineering and Economic Factors Affecting the Installation of Control 

Technologies for Multipoint Strategies” (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 source 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 process of getting SCR and FGD equipment ready 

to operate. This step can in fact add many months to the timeline 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 design, 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 FGD 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 explained 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 preparation of detailed specifications concerning the 

actual control equipment to be installed, the equipment’s control efficiency, potential byproduct 

species, and project capital and operating costs; (2) identifying qualified control equipment 

vendors and qualified contractors for project construction; (3) soliciting and reviewing bids and 

then selecting vendors and contractors; and (4) negotiating contract terms and issuing the 

requisite contracts. 

There is no basis for EPA’s suggestion that all 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 for 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 limitations or related challenges at 

 25 The Implementation Schedules Report (in section 2.2.1) describes how several 

companies have used system engineering approaches to reduce their engineering timelines to a 

year or just under a year -- still 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 construction activities or physical features 

at the site that require more-extensive-than-normal activities to secure a place to put physically 

large structures like the SO2 absorber towers that are part of FGD systems); the possibility that a 

source owner could use new fuel sources (particularly 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 other unusual site conditions -- such as soil characteristics, the 

presence of underground utilities, and available water -- that will influence the selection of the 

precise equipment to be installed. Also worth 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 future regulatory programs requiring 

reductions in emissions of other pollutants (e.g., mercury, particulate matter, and acid mist). 

At a substantial percentage of affected sites -- including where FGD or SCR systems 

have not previously been installed because of site-specific complexities -- the need to consider 

and address these factors means that it will typically take 6 to 12 months to complete the 

engineering step of FGD and SCR installations. 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 then select the winning bids (a 

detailed process that, among other things, requires plant owners to host bidder meetings and site 
34 

inspections as well as to review all submittals in detail); and negotiate final contracts (which can 

take considerable time, particularly where a plant owner and contractor have not previously 

worked together or if there are to be non-standard terms in the contract). As set out in sections 

2.2.2 through 2.2.4 of the Implementation Schedules Report, it can take another 6 to 12 months 

to complete these steps. 

In short, it often takes a much more extensive effort to “conduct an engineering review” 

than the four months suggested in the 2002 EPA Report. Indeed, as discussed in more detail in 

the accompanying Implementation Schedules Report 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 complexity of its second step: obtaining a 

construction permit. Rather than merely getting a single “construction permit” -- which arguably 

may have been a relatively quick-and-easy process at the time of the writing of the 2002 EPA 

Report -- those retrofitting FGD and SCR systems today must apply for and obtain numerous 

authorizations before they can undertake construction or start operating those new systems, 

including authorizations and permits that were not 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 complexity involved in getting a CAA new source 

review (“NSR”) preconstruction permit to cover “increased emissions” from the installation of 
35 

FGD and SCR systems. Such a permit may be needed because even though the operation of FGD 

and SCR units will significantly reduce emissions of SO2 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 SO2 or NOx. Thus, the operation of wet scrubbers and SCR -- 

while reducing SO2 and NOx emissions -- may in some cases increase sulfuric acid mist by more 

than insignificant amounts. Also, operating low 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 triggered 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” exclusion) 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 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 increase of a 

pollutant other than the pollutant being controlled by the FGD, SCR, or LNB equipment. And an 

obligation to apply for and obtain an NSR permit, even if the permit itself does not require any 

additional emission controls, would 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 conjunction with advanced combustion controls such 

as overfire air, have not increased 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 process ultimately amounts to little more than a 

paper exercise, can add many months to the overall process. And 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 start applying to greenhouse gases 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 companies installing pollution control projects 

in the first part of the last decade (due to the existence of the PCP exclusion), it is a problem 

now. 

Also as noted in the Implementation Schedules Report, power plant owners must secure 

permits to address other environmental consequences of operating pollution 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 generating 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 locating, constructing, and operating plants (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 FGD or SCR systems unless and until they receive 

authorization from their public utility commissions 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 keep in mind: source owners may not be able 

to start actual on-site construction of FGD and SCR systems until they have at least some of the 

above-listed authorizations in hand. In particular, 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 owners 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 completed 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 SCR installations in less than 30 months. 

3. The Actual Construction of FGD and 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, those 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 projects are underway simultaneously -- such 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-specific complications 

that companies face at power stations. The earliest installations may have been at sites with 

sufficient space and access that construction could proceed in a straightforward way, without 

interfering with other plant operations. Today’s installations are typically more challenging: 

they are at sites that were not retrofit in the first or second rounds 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 closer 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 Outdated 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 the Implementation Schedules Report, the sole 

support for EPA’s belief that FGD and SCR installations 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 reflect 
39 

the variety of conditions one can expect to find at all the sites now being evaluated for control 

equipment retrofits. The implementation schedules 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 being 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. Additional 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 Centralia 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 took 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 the engineering and construction work at Centralia 

was part of a unique “partnering” agreement between the owners of Centralia and the contractor. 

As noted in the Implementation Schedules Report, this type of relationship can speed 

subcontracting and procurement activities, but it can also require significant upfront negotiations 

and arrangements, and there 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. 

 Similarly, the installation of Tampa Electric Company’s FGD systems on Big Bend Units 

1 and 2 -- also an early generation project -- appears to have taken more than 27 months to 
40 

complete. Information in the public domain indicates that the 27-month schedule cited by EPA 

does not take into account that Tampa Electric 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 specification. This all indicates 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 possible 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 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 management 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 concerning the SCR installations at Reliant 

Energy’s (now NRG’s) Keystone station in Pennsylvania and the AES Kintigh (previously 

Somerset) station in New York. These are the projects that EPA claims were completed in a 

total of approximately 21 months. Even if those projects did take less than 30 months to 

complete (and it is not clear that they did), there is nothing to suggest that they are typical of the 

construction challenges faced by those now undertaking SCR retrofits. For example, there is no 

evidence that the Kintigh project was competitively 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 utility or public agency. Also, the non-traditional 
41 

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 construction 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 fewer 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 Examples 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 described in section 3 of the Implementation 

Schedules Report. Specifically, the Implementation 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 months); 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 review); the retrofit of two FGD units at Duke 

Energy Company’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); the installation of 
42 

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 installation of three or more FGD systems at Allegheny 

Energy’s Hatfield’s Ferry facility (45 months), First Energy’s Sammis 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 complete an FGD installation, but that at the most 

challenging sites, it can take more than 60 months (i.e., five years). Typically, 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 installation is the example of a recent FGD 

installation that was completed in only 40 months. The single FGD 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 the process and absorber design developed for 

other sites, which shortened the period for procuring contracts. Second, certain design tasks 

were accelerated as they were leveraged 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. In contrast, the installation of a single FGD unit each at Alabama 

Power’s Barry Unit 5 and Gaston Unit 5 took a total of 53 months and 64 months, 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 electrostatic precipitators and fabric filters built 
43 

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.) The extremely tight site -- bounded by the Ohio River and a rail line – 

constrained construction activities and contributed to an installation time of 56 months. 

The retrofit of FGD at Alabama Power’s Gorgas Units 8-10 is another example of the 

hurdles faced by source owners trying to install FGD systems at existing plant sites. Several 

reasons contributed to the fact that it took over five years to complete the work at Gorgas. First, 

the Gorgas retrofit was the owner’s initial FGD project, which meant that significant time was 

required to do project engineering and to negotiate contracts. Second, the site required extensive 

modifications, including literally moving a small mountain to create 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 Gorgas site, it was necessary to make significant 

improvements to the plant’s flue gas handling system in conjunction with the control equipment 

retrofit. All these factors (and others) 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 schedules 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 Cooperative 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, confined space, which requires many phases of the process to be 
44 

conducted sequentially rather than in parallel. This produces FGD retrofit schedules of between 

40 months and over 60 months. 

D. SCR Installations: Real-World Examples 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 incomplete) 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, demonstrates that it takes an average of a total 

of 39-40 months to complete such retrofits, and can -- at the most challenging 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 retrofitted 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 months), 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 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 there was a retrofit of five SCR units, with the first operable within 31 

months); Progress Energy’s 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 

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 most important of which is the configuration of the 

plant site. For example, AEP was able to retrofit five SCR reactors at the Kyger Creek Station in 

a period of approximately 31 months because the units on which the SCR equipment was being 

retrofit were virtually identical to each other, allowing engineering to be expedited. Also, 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 it was possible to stage the construction in a serial manner. 

At the other end of the spectrum, however, are the 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 presents 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 FGD and SCR installations, the time it takes to 

complete an LNB installation 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. 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 fabrication and delivery times. Also, there can be complications in the permitting 

process. At least one multi-state owner is anticipating a lengthier schedule for installing LNB 

equipment, due to concerns that have arisen in the permitting of the installations, where local 

regulatory agencies are questioning whether lower NOx emissions are inextricably linked to 
46 

higher carbon monoxide emissions. section 4.2 of the Implementation Schedules Report presents 

schedule information concerning the low NOx burners installed at Salt River Project’s Coronado 

Unit 1 and Navajo Unit 3, and at units at Mississippi 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 for final action on the PTR and EPA’s proposed 

compliance deadline of January 1, 2012. 

E. Summary and Conclusions. 

Solid information from individual UARG members and detailed information in the 

Implementation Schedules Report demonstrate that it now takes longer -- often much longer -- 

than 21 and 27 months to complete retrofits of SCR and FGD equipment, respectively. 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 the equipment will be installed (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 projects. The extensive amount of information 

presented in these comments and in the attached report, as well as information in comments from 

individual UARG members, refute 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 that 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. Electric generators may not -- and should not -- 
47 

undertake FGD and SCR retrofits until it is clear that such installations are required and are 

prudent and consistent with fiduciary obligations 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 and SCR units. It will 

take longer than 30 months -- in many cases, considerably longer than 30 months -- for 

companies to complete the retrofits of FGD and SCR units at existing EGUs. Thus, it will not be 

possible for affected EGUs to achieve all the SO2 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 downwind nonattainment and interference 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 after final promulgation 

of EPA’s rule). 
48 

VI. EPA’s Analysis Significantly Understates the Amount of Electric Generating 

Capacity that Would Have To Undergo 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 “expects 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 projection 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 preceding section of these comments, EPA has 

significantly underestimated the amount of time it takes to install these controls, 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 2012-2014 period (while, for the same reason, some of 

the retrofit projects EPA predicts will be completed 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, their 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 retrofit capacity that would be installed by 2012. 

 28 J. Marchetti, E. Cichanowicz, and M. Hein, “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 other projects, they used an assumed 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 previous section of these 

comments. The analysis shows that the majority of the projects could not be completed until 

well after January 2014; the largest number of FGD and SCR projects 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 retrofit installations. The analysis found 

that boilermaker demand for FGD and SCR installations can be accommodated if the realistic 

installation schedules applied from the Implementation Schedules Report are assumed. In 

contrast, if the retrofit projects were somehow 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 require an amount of boilermaker hours that is far in 

excess of the boilermaker labor supply that was called on for EGU control retrofits in the 2008-

2010 period. Thus, even if EPA’s proposed compliance 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 necessary 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 retrofits than its statement in the PTR preamble 

would suggest. Given the demands that will be imposed on retrofit resources, such as 
50 

boilermaker labor, due to the congestion of control project installations during this highly 

compressed period, requiring the PTR’s 2014 emission 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 schedules (as described in the Implementation 

Schedules Report and in the previous section of these comments) and (2) be infeasible in any 

event in light of the available labor, and perhaps other resources, needed to accomplish these 

retrofits. 

VII. Many of the Judgments and Policy Decisions Underlying the Structure of the 

Proposed Transport Rule Are Inappropriate and Unjustified. 

EPA made several important judgments and policy decisions in developing the Proposed 

Transport Rule without explaining adequately the Agency’s rationale. As discussed below, 

many of these decisions are inappropriate and must 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 emissions during those periods. EPA should have 

included CAIR in its base case because it remains 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 CAIR, allowing CAIR to 

remain in effect until it is replaced by a rule consistent with our 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 is 
51 

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 recognizes what it could hardly 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 PM2.5

ambient air quality, and “EPA believes that a great deal of the improvement in PM2.5 annual and 

24-hour concentrations in the eastern U.S. can be attributed to EGU SO2 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 nonattainment counties for both the annual and 24-hour 

standards if the CAIR were not in effect,” and crediting a variety of programs with improved 

ozone air quality in the years since EPA published CAIR). There can be no dispute that CAIR, 

together with other programs, has had significant effects in reducing NAAQS design values. 

Additionally, in both the NOx SIP Call and 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 promulgated as of December 2008, 
52 

except for CAIR.

29 75 Fed. Reg. at 45233/3. It is difficult 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 characterizes 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 states hardly justifies wholesale disregard of CAIR 

reductions.30 Moreover, EPA has not shown that emission 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 regulated under CAIR but are not proposed to be 

regulated under the Transport Rule have gone to great expense to install controls 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, PM2.5 and ozone concentrations have 

declined substantially in recent years, due not only 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 and 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 PM2.5 NAAQS, only Mississippi and Texas were regulated under CAIR but are not 

proposed to be regulated under the Transport Rule. With respect to the 8-hour ozone NAAQS, 

only Iowa, Massachusetts, Missouri, and Wisconsin 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 increases 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 “monitored-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 proposal 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 Proposed Transport Rule. IPM is a least-cost 

economic model that operates on a regional scale and is not designed to replicate real-world 

scenarios in specific locations. See section VIII infra for further discussion of IPM. 

Furthermore, LADCO specifically recommended that EPA 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” approach 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 PM2.5 NAAQS. For 

example, nearly 60 percent of the monitoring sites that EPA projects to be in nonattainment areas 

for the 24-hour PM2.5 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 PM2.5

NAAQS and approximately 10 percent of the sites 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 concentrations, it is most unlikely that these areas should be viewed 

as downwind problem areas. 

 EPA should return to its monitored-plus-modeled approach in this rulemaking, or at a 

minimum, should explain the basis for its departure 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 PM2.5

NAAQS, 52 are in areas currently 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 PM2.5 NAAQS, EPA has issued either a proposed or final 

determination that 6 of the 32 sites that EPA projects in the PTR will be in nonattainment areas 

in 2012 currently are in areas with air quality in attainment of the NAAQS. With respect to the 

8-hour ozone NAAQS, EPA has issued a final determination that Baton Rouge, Louisiana, one 

of the 11 areas that EPA projects in the PTR 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 contribution threshold based on a percentage -- 

specifically, one percent -- of the NAAQS for annual PM2.5, 24-hour PM2.5, and 8-hour ozone to 

determine whether an upwind state should be included 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 deviate from the approach it used in CAIR with 

respect to PM2.5 by using here a two-digit 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 setting a zero contribution threshold for the 

current 24-hour PM2.5 NAAQS, see id., and to avoid setting a precedent for a 0.1 μ/m3

contribution threshold if the annual PM2.5 NAAQS in the future is reduced to some value lower 

than the current NAAQS but higher than 10 μ/m3 (e.g., 14 μ/m3), see id., EPA’s proposed 

approach ignores the limits of the capability of its air quality modeling techniques -- and of 

ambient monitoring -- to meaningfully detect and measure ambient-air contributions at the 

extremely low levels represented by one percent 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 comments show, among other things, that existing 

controls, including CAIR, are projected to resolve most of the downwind PM2.5 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 nonattainment problems in the PTR domain than EPA’s proposal 

suggests. 
56 

threshold approach to the current NAAQS -- i.e., 0.15 μ/m3

 for annual PM2.5, 0.35 μ/m3 for 24-

hour PM2.5, and 0.8 ppb for 8-hour ozone -- are so low that they are likely below the detection 

capability of existing modeling and measurement tools. For that reason, it is far from clear that 

these thresholds could be deemed to reflect a “measurable contribution” 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 there 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 thresholds as representing meaningfully measurable air 

quality contributions. 

 Equally troubling is EPA’s indication that 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 approach is that “the approach is readily applicable to any current 

and future NAAQS”). Application of this approach to potential future ambient standards that 

may be even lower than the current NAAQS would produce even less meaningful thresholds. It 

makes no sense for contribution thresholds to change based exclusively on changing 

NAAQS levels, irrespective of the capabilities of modeling and measurement technologies at the 

time the thresholds are established. 

 Accordingly, UARG objects to EPA’s proposal to use its percentage-based air quality 

contribution threshold approach in the current rulemaking -- or in any future interstate-transport 

rulemaking -- in the absence of a robust technical justification that the resulting thresholds reflect 
57 

meaningful, and truly measurable, air quality contributions, 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 with maintenance” analysis overstates actual future 

design values, probably by a substantial amount. EPA explains in the preamble to the proposed 

rule that it determined maintenance sites based on the future-year maximum design values, and 

nonattainment sites based on future-year five-year weighted average annual design values. 

(Thus, all nonattainment sites were, in effect, also maintenance 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 PM2.5 design values as the 

basis for the “interference with maintenance” analysis, 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 continuing declines in emission levels and that the 

recent improving air quality has been largely driven 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 SO2 emission 

reduction requirements beginning in 2014, beyond the reduction requirements for 2012, because 

of perceived maintenance problems at six specific downwind monitors. Southern Company, a 
58 

UARG member, plotted the 98th percentile design values for 24-hour PM2.5 from 2003 to 200835

based on EPA’s 2006-200836 Design Value spreadsheet for 24-hour PM2.5, 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 PM2.5 design value would almost inevitably overstate 

the air quality design value at that monitor and, based on the strong downward trend in design 

values, would most likely result in a false determination. There is no reason to believe that the 

trend that is apparent in the design values at these six monitors is unusual. In fact, a similar trend 

 35 Although the three base periods used 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 2008

24‐Hour PM2.5 (μg m‐3)

2003‐2008 24‐hour PM2.5

Forthe Six Monitors with EPA‐Projected Maintenance Issuesin 2014

170311016 Cook IL

180890022 Lake IN

245100040 Baltimore City MD

261630016 Wayne MI

420030064 Allegheny PA

420030093 Allegheny PA
59 

is likely to exist at most of the downwind monitors evaluated in the proposed rule. It is 

especially important for EPA to set forth a justifiable methodology for determining maintenance 

issues since EPA’s proposal in effect 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 maintenance problems, justify its reasoning for 

choosing a particular method, and revise its analysis to make it more representative of current 

and likely future air quality and to take account 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 value. 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 average 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 value as the original observations. This result 

would still capture the inter-annual variability in air quality at sites with improving air quality 

without biasing the projected “maintenance” value upward for areas where emission reductions 

are already resulting in air quality improvement, 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 monitors 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 downward 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 values for these six sites. This approach 

provides a more reasonable estimate of the threshold 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 reductions. Furthermore, it provides a better 

estimate of inter-annual variability that would be due to inter-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 Certain 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 PM2.5 as follows: 

EPA used the air quality assessment tool to analyze the impact of 

requiring all states linked to the downwind state site with an air quality 

problem, as well as the downwind state, 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 combination of this level of reduction from 

the group 2 states and the remaining states (referred to as group 1 states) 

continued to result in all downwind 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 between 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 classification of the group 1 states. 

A representative of Southern Company contacted EPA’s Clean Air Markets Division on 

September 3, 2010, and again on September 10, 2010, requesting clarification regarding how 
62 

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 PM2.5 based on the projected 2012 base case air quality, and then identified 

upwind states that were “linked” to these monitors. This step in EPA’s methodology determined 

which states were included in the Transport Rule for PM2.5, at least as group 2 states, based on 

their significant contribution to nonattainment or interference with maintenance. Next, EPA 

used its air quality assessment tool and the emission changes resulting from the 2014 cost curves 

to evaluate how air quality at the nonattainment and maintenance monitors would change in 

response to emission reductions from “linked” upwind states, assuming a linear relationship 

between reductions in the upwind states’ emissions 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 situated. EPA found that the 24-hour PM2.5 NAAQS was 

controlling because most annual PM2.5 problems were resolved at relatively low dollars-per-ton 

thresholds, while 24-hour PM2.5 problems were more likely to persist at higher cost thresholds. 

EPA focused on the maintenance monitors and did not consider the nonattainment monitors 

separately because of the way that nonattainment and maintenance sites were determined.38 

 Using its air quality assessment tool, EPA determined that, in 2014, there were six 

monitors that still showed maintenance problems at approximately $300-$400 per ton that, with 

 38 As described above, EPA determined maintenance sites based on the future-year 

maximum PM2.5 design values, and nonattainment sites based on the future-year five-year 

weighted average annual PM2.5 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, Pennsylvania, could be eliminated at $2,400 per ton 

or less. EPA then decided that the states linked 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 appears that this was the sole determinant for 

classifying states as group 1. Strikingly, according 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 reductions required by the Transport Rule during 

those years and from state rules, consent decrees, and other requirements that will result in 

additional emission reductions by 2014. 

This illogical decision not to consider the 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 sense to evaluate phase II of the proposal in 

isolation, ignoring the projected effects of phase I (and other emission reduction requirements 

applicable in the period leading 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 emission reductions that would 

result from the 2012 compliance deadline and other controls, it is likely 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 comments 
64 

note above, air quality has been improving steadily in recent years, and, consistent with that 

nationwide trend, 24-hour PM2.5 concentrations at all six of the monitors at issue show a strong 

downward trend. See graph showing the 98th percentile design values for 24-hour PM2.5 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 including 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 remove any justification for imposing more stringent 

SO2 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 Nonattainment Problems and Inappropriately 

Underestimate the Contribution of Local Sources from a Variety of Emission 

Sectors. 

1. EPA’s Approach Places an Undue and Unlawful Burden on Sources 

in Upwind States To Reduce Emissions. 

EPA’s Proposed Transport Rule improperly puts all or most of the emission reduction 

burden on sources located outside the local nonattainment or maintenance 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 sources 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 several reasons for its 

decision to assign “substantial responsibility” 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 adhere 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 comprising 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 downwind states that contain the nonattainment and 

maintenance sites, in direct contradiction 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 standards 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 emission scenarios, “[f]or nonEGU point and nonpoint 

stationary sources, any local control programs that may be necessary for areas to attain the 

annual PM2.5 NAAQS and the ozone NAAQS are not included 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 section 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 downwind states containing designated 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 nonattainment 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 document (“TSD”) on “Emissions Inventories” that 

“[t]his is because the nonattainment areas for the 1997 PM2.5 and ozone standards were not 

announced until 2004 and 2005 respectively, and the corresponding [SIPs] were not due until 

2007 and 2008, thereby preventing the inclusion of these local measures in the 2005 emissions 

inventory.” EPA, “Emissions Inventories” TSD at 11. The unavailability of this information in 

2005, however, does not explain why EPA has not taken it into account in the future base case 

projections. 
66 

at 25184/3 (explaining that regional emission reductions 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 example, 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 determined, 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 25194/1-2. As mentioned above, this reasoning gives 

at least a degree of recognition to the requirement of section 107(a), discussed above, that states 

bear the primary responsibility for assuring air quality within their borders. EPA’s failure to do 

so here requires the Agency to revise and reissue 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 estimated number of projected nonattainment and 

maintenance sites that result from increasing the marginal cost per ton of EGU SO2 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 PM2.5 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 only at $1,800/ton. Similarly, EPA projects that 

only three nonattainment and maintenance monitors 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, with respect to the 24-hour PM2.5 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 maintenance until the $1,600/ton level, at which they would drop 

to five, and one would remain at $2,400/ton. 

Analysis of these cost curves is complicated by the fact that, in EPA’s analysis, few 

additional emission reductions are available at each additional cost increment. This drives the 

analysis upward in pursuit of the modest benefits available at each cost increment. 

Consideration of local controls would make this analysis far more realistic.40 A proper analysis, 

particularly one conducted pursuant to an iterative process, likely 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 conducted by replicating EPA’s data and air quality 

assessment tool. That analysis shows that key indicators of air quality remain essentially 

unchanged under the Proposed Transport Rule despite 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 

SO2 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 considered the effects of reducing SO2 emissions before considering 

the effects of reducing NOx emissions, EPA would have concluded that annual NOx emission 

reduction obligations to address PM2.5 should not have been included in the proposed rule at all. 
69 

emission reduction amounts required under the proposed rule compared to those required under 

CAIR. This analysis provides a basis for concluding 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 VII-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 maintenance 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 PM2.5 2012 remedy 1 9 

 CAIR I 2 9 

Annual PM2.5 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 PM2.5 2014 remedy 1 1 

 CAIR II 1 2 

Annual PM2.5 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 indicates that no meaningful additional benefit is 
70 

achieved by the emission reductions required under the Proposed Transport Rule beyond those 

required under CAIR, despite the increased cost and constraints that come along with the 

Proposed Transport Rule. 

 Additionally, in developing the Proposed Transport Rule, EPA assessed the effects of 

NOx emission reductions first, before considering the effects of SO2 emission reductions, despite 

EPA’s acknowledgement that “SO2 reductions are generally more effective than NOx reductions 

at reducing PM2.5.” 75 Fed. Reg. at 45281/1-2. This artificially inflates the projected 

contribution of NOx emissions to the formation of PM2.5. As EPA has acknowledged, for 

example, the contribution of NOx emissions to PM2.5 formation in southeastern states is 

considerably smaller than the contribution of SO2 emissions to PM2.5 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, that particulate nitrate represents a very small fraction -- 

approximately five percent -- of PM2.5 in southeastern states).42 Had EPA taken a more logical 

approach and assessed SO2 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 replicating EPA’s air quality assessment tool, 

illustrates the effect of assessing SO2 reductions before NOx reductions. 

 42 Southern Company’s comments also explain, among other things, that although 

particulate nitrate can represent an important fraction of PM2.5 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 formation of particulate nitrate is 

an inherently non-linear process, is strongly thermodynamically driven, and is strongly 

associated with available ammonia. Thus, by excluding ammonia from consideration, EPA 

cannot properly assess the role of NOx versus ammonia in particulate formation, especially using 

the linear assumptions in its air quality assessment tool. 
71 

Table VII-3 

24-hour PM2.5 - 2014 Number of Downwind Monitors 

$/Ton SO2 $/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 PM2.5 - 2014 Number of Downwind Monitors 

$/Ton SO2 $/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 PM2.5 NAAQS, the number of downwind 

nonattainment and maintenance monitors is driven primarily by reductions in SO2 emissions. 

There are only very slight changes in the numbers of downwind nonattainment and maintenance 

monitors when SO2 emissions are not reduced and NOx emissions are reduced using EGU NOx 

controls available at $500 per ton. By contrast, when SO2 emissions are reduced using EGU SO2

controls available at $100 per 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 SO2 emissions are 

reduced using EGU SO2 controls available at $200 per ton, $300 per ton, and $400 per ton -- 
72 

although the additional incremental improvement even from the SO2 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 available 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 production of biogenic secondary organic aerosol (“SOA”) is heavily 

influenced by NOx levels.43 Specifically, this research shows 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 chemistry. In addition, the proper 

simulation of ammonium nitrate and other nitrate aerosol (e.g., organic nitrates) has confounded 

air quality scientists for many years. Thus, the representation of the impacts of NOx emission 

changes in particulate matter levels in these models is incomplete, particularly when attempting 

to simulate relatively small signals such as interstate contributions to ambient particulate matter 

concentrations. 

 43 See, e.g., Chan, M. N. et al. (2010), Characterization and quantification of isoprenederived epoxydiols in ambient aerosol in the southeastern United States, Environmental Science 

& Technology, 44(12), 4590-6, doi:10.1021/es100596b; Surratt, 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 revealed in secondary organic aerosol formation 

from isoprene, Proceedings of the National Academy 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 photooxidation 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/science.1172910; Hallquist, M. et al. (2009), The 

formation, properties and impact of secondary organic aerosol: current and emerging issues, 

Atmospheric Chemistry and Physics Discussions, 9(1), 3555-3762, doi:10.5194/acpd-9-3555-

2009; Ng, N. L. et al. (2007), Effect of NOx level on secondary organic aerosol (SOA) formation 

from the photooxidation of terpenes, Atmospheric 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 formed 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 quality benefits that are projected from 

incremental increases in cost for EGU SO2 controls above low levels, such as $300 to $400 per 

ton, and should reconsider the SO2 cost breakpoint in that light. Additionally, because of the 

very minimal benefit that is achieved from reducing EGU NOx emissions in addition to SO2

emissions, as well as the other issues discussed 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 SO2 Emission Budgets. 

EPA proposes to set state emission budgets for annual and ozone season NOx and for 

SO2 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 state budgets, EPA explains that it calculated 

2012 state budgets using a combination of emissions and heat input data reported to EPA as of 

200944 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 recent non-null first, second, third, and fourth 

quarter emissions and heat input data between the first quarter of 2007 and 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 Budgets, 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 emissions control equipment 

that would be in place at individual units by 2012 are incorrect. See section VIII.A infra for a 

discussion of this issue and examples. EPA representatives have requested that, to the extent that 

EPA’s projections are inaccurate, electric generating companies submit comments correcting 

them and explaining why they are inaccurate. Individual UARG members are submitting 

comments correcting EPA’s projections to the extent that they contain inaccurate information 

regarding their units. However, to the extent that some companies fail to correct inaccurate 
74 

In that TSD, EPA notes that in creating the state budgets for annual and ozone season 

NOx, it “rebased” annual and ozone season NOx emissions 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 utilization [or heat input] in 2009.” Id. During a conference 

call on August 30, 2010, however, EPA staff offered UARG members a different explanation for 

this adjustment. EPA staff indicated that the reason EPA used 2008 data was that the IPM 

projection of how sources would operate their NOx controls in 2012 did not align well with the 

2009 data but aligned more closely 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 SO2 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 preamble 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 after elimination of the part of 

significant contribution and interference with maintenance the EPA has identified in an average 

year”); id. at 45271/2 (A state’s budget “represent[s] the remaining emissions for the state in an 

average year”); id. at 45292/1 (“EPA has . . . developed state 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 electric generating companies to ensure that the 

information that it was using to develop the proposal 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 indicate that EPA believes 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 average for -- and therefore was not used for -- NOx 

budget purposes, there would be any basis to use it for SO2 budget purposes. Before it proceeds 

further with this rulemaking, therefore, EPA will need to clarify and provide an adequate 

explanation for its decision to use 2009 heat input data for SO2. 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 adequate explanation by the Agency. 

VIII. EPA’s Use of Inaccurate Inputs and Assumptions for -- and Unrealistic Outputs 

from -- EPA’s Use of the Integrated Planning 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 with substantially all of the key data points to 

make its decisions on these critical elements of the PTR. As EPA explains in its TSD discussing 

its use of IPM, that model47

provides forecasts of least-cost capacity expansion, electricity dispatch, and 

emission control strategies for meeting electricity demand, environmental, 

transmission, dispatch, and reliability constraints. IPM can be used to evaluate 

the cost and emissions impacts of proposed policies to limit emissions of sulfur 

dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) 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 requires 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 version 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 inventory and unit-level 

characteristics and operating parameters. The primary source for unit-level emission information 

for IPM is the NEEDS database. The NEEDS database is fraught with significant errors, as 

illustrated in section VIII.A below. In addition, 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, when 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 tool is brought into question when the modeled 

results do not reflect real-world conditions.49 The second subsection below provides specific 

examples of inconsistencies between EPA’s IPM projections and individual companies’ plans for 

their units. The following examples are an illustrative, but by no means an exhaustive, list of 

problems in the NEEDS database and EPA’s application of IPM to support the Proposed 

Transport Rule. 

 48 Updates to EPA Base Case v3.02 EISA Using 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 that 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 data 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 controls 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 scrubbers are already installed and operational at the Harrison 

power plant in West Virginia. PM scrubbers 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 Virginia. 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 plant in Mississippi. No SNCRs exist or are 

planned for these units. 

• NEEDS reports that a wet scrubber will be installed at unit 3 at the Brayton Point power 

plant in Massachusetts by 2012. Under a state-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 beginning 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 removal 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 the Harrison power plant in West Virginia. 

• NEEDS fails to account for FGD systems at three 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 SO2 emission limitation on the Cumberland power 

plant in Tennessee of 0.5 lb/mmBtu and instead reports SO2 emissions at that plant at a 

rate of 5.0 lb/MMBtu. 

 In addition, errors in IPM constraints and inputs appear to be related to inaccurate 

interpretation of state regulations and NSR settlements, and there are other errors as well. 

Examples include: 

• IPM assumes (in the 2014 base case) that units 1 and 2 at the Harllee Branch 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 

December 31, 2014. 

• IPM assumes (in the 2014 base case) that unit 4 at the Harllee Branch power plant in 

Georgia will 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, 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 Scherer power plant in Georgia 

will 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 December 31, 
79 

2014. 

• IPM assumes that FGD retrofits at the Kyger Creek and Clifty Creek power plants in 

Ohio are complete and operational. These retrofits 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 SO2 emission rate of 5.0 lbs/mmBtu. The unit is currently regulated by and is 

complying with a state regulation that limits its SO2 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 remedy, and IPM appears to treat 

similar sources in Maryland very differently, 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 input errors, it appears EPA made downward 

adjustments to NOx emission rates in IPM that are unwarranted, unreasonable, 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 historical data that supported a NOx emission rate lower

than 0.06 lb/mmBTU, EPA used that lower emission rate. 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 that that unit cannot physically and consistently operate at a 

lower rate. At a minimum, an across-the-board 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 have accounted for the costs associated with these 

options in the PTR. EPA should abandon its approach of making across-the-board downward 

adjustments to 0.06 lb/mmBTU and should instead 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 inconsistencies 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 the proposed controls and that generators are not 

capable of appreciating the influence of the proposed controls on their future operations, UARG 

members believe that their economic models, as well as their understanding 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 number of key factors, 

including unit availability. Generators have years of experience with a greater level of 

specificity that allows them to understand the real-world constraints and demands on individual 

units and to better predict which 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 units; and (4) inaccurate assumptions regarding fuel 

switching at particular units. 
81 

 Examples of inaccurate assumptions of emission controls include the following: 

• IPM projects FGD installations at the Armstrong power plant in Pennsylvania by 2014. 

No such installations are planned by the company. 

• IPM projects FGD installation at the Willow 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 LNBs with overfire air -- based on the listed 

emission rate -- at the J. R. Whiting power plant (units 1-3) in Michigan. The owner of 

the units does not believe such controls are viable options at these units due to 

operational and configuration constraints. 

• IPM projects FGD installation and operation at unit 2 at the Muskingum River power 

plant in Ohio by 2011. Although a preliminary 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 represent annual operation of SNCR -- both SNCRs 

have been operating on a year-round basis since October 2005 to comply with a stationwide NOx limit in accordance with a state Administrative Consent Order. 

 Examples of inaccurate estimates of emission control efficiencies include the following: 

• IPM projects an annual 35% NOx removal efficiency 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 plant 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 was initially installed, but representative 

operation of the controls demonstrates that such rates are not sustainable 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 Watson power plant, and units 1 and 2 at the 

Sweatt power plant, both in Mississippi. There 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). There are no plans by the company to retire these 

units by 2014. 

 Examples of inaccurate assumptions regarding fuel switching for particular units include 

the following: 

• IPM projects fuel switching from coal to natural 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 sulfur 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 Eastern 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 errors, 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 either natural gas or oil. Of the 493 dual-fuel units 

in the NEEDS database, IPM predicted in the 2014 limited trading control strategy that 34 units 
83 

would burn oil as the primary fuel. EPA proposes to allocate any SO2 allowances to only 8 of 

those 34 units. This result ignores the reality that 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 natural 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 inherent 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 constraints, capacity commitments, 

fuel-contract commitments, and other cost-related considerations that have not been input to the 

IPM model. EPA’s insufficient information, coupled with the limitations of the regional IPM 

model, result, for example, in inaccurate projections for oil-fired units and dual-fuel units. When 

IPM predicts natural gas is less expensive than oil or that burning oil at an oil-fired unit is for 

some reason not “economical” within the terms of IPM’s protocol, no SO2 emissions are 

projected from -- and thus no SO2 allowances are allotted to -- that unit. 

 EPA must recognize the limitations of IPM and must consider local issues and allow 

UARG members, other generators, and other members 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 essentially “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 which gas supplies may be reduced or temporarily curtailed to meet 

higher-priority customers. When service is interrupted, 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 expected to burn oil in the 

future and should receive allowance allocations; the presumption should be in such cases that 

allowance allocations to those units are appropriate in the absence of compelling reasons to the 

contrary. At a minimum, EPA should not blindly insist that IPM’s projections for these types of 

units are accurate and should instead make adjustments to the allocation determinations for these 

types of units, based on comments of companies with interests in those units. 

 Another systemic error involves the heat input rates listed in the “BADetaileddata.xls” 

spreadsheet associated with the proposed direct control alternative 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 high 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 rerun 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 allowance 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 publish revised proposed budgets and allocations for 

public review and comment. However, 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 state to make -- and to give each state adequate 
85 

time to make -- any emission control decisions for sources within the state and to incorporate 

those decisions in SIPs. 

IX. Certain EPA Assumptions and Determinations 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 analysis52 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 transport 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 units will reduce emissions of NOx and SO2, in 

many cases operation of these controls may be thought to result in an increase in emissions of 

other pollutants by more than insignificant amounts. Contrary to the assumptions 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 experience, 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 would reveal that the impact of NSR permitting 

 52 See “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 proposed rule is likely to be 

significant. 

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 the 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 that 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 address 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 pollution control projects would cause GHG emission 

increases in excess of the NSR emission thresholds in EPA’s June 2010 GHG Tailoring Rule. 

75 Fed. Reg. at 45344/1. At least in part for this reason, EPA concludes that NSR impacts are 

not likely with respect to emission control projects required to satisfy the Proposed Transport 

Rule. 75 Fed. Reg. at 45344/1. EPA provides no justification 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 explanation to support its assertion 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 Compliance and Allowance Trading. 

A. The Variability Limits and Assurance Provisions Proposed by EPA Are 

Unduly Stringent and Should Be Adjusted. 

1. Variability Limits. 

EPA’s explanation in the preamble to the proposed rule, and in the TSD on Power Sector 

Variability53 (“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 higher uniform percentage is justified. EPA should carefully 

consider the basis for adopting 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 SO2 emissions from upwind 

states on 24-hour PM2.5 concentrations at downwind nonattainment and maintenance monitors. 

Variability TSD at 43. In the first approach -- intended to replicate “typical” variation -- EPA 

projected that SO2 emissions in each upwind state in the proposed control region would vary 

randomly. Id. at 44. In the second approach -- intended to replicate “worst case” variation -- 

EPA projected, on a monitor-by monitor basis, that SO2 emissions in the upwind states with the 

largest air quality impacts per ton on the downwind monitor increased to the maximum amount 

(up to each state’s one-year variability limit) and that SO2 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 Variability” TSD (July 2010), available at

http://www.epa.gov/airquality/transport/tech.html. 
88 

Id. at 47. EPA reported that “[f]or both approaches, the effects of the inherent variation in 

emissions on daily PM2.5 concentrations were estimated to be small.” Id. at 44; see also id. at 46 

(reporting that the results of the analysis using the first (“typical” variation) approach indicated 

that “the combined downwind air quality impacts were essentially negligible”), 47 (reporting that 

the results of the analysis using the second (“worst case” variation) approach indicated that “the 

resulting increases in air quality are 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 interstate trading can play a valuable role in reducing emissions 

without decreasing downwind air quality. However, it is not apparent, and EPA does not 

explain, why it chose to perform this analysis using only a variability limit of 10 percent of the 

state budgets. EPA should perform the analysis using higher variability limits, in the range of at 

least 20 to 30 percent of each state’s budget. If these analyses also indicate that the impact of 

upwind emissions variability on downwind air quality remains small, higher variability limits 

would be justified. 

UARG strongly urges EPA to consider increasing the variability limit. A higher 

variability limit would encourage emission trading and increased emission reductions at sources 

where they are most cost-effective to achieve (thus lowering the overall cost of compliance with 

the program), while still ensuring that substantial 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 indicates 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 the PTR, which suggests that if unlimited 
89 

2. Assurance Provisions. 

EPA requests comments on the proposed assurance provisions. 75 Fed. Reg. at 45314/2. 

UARG believes that the allowance surrender requirement 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 nuclear unit outage that causes a company to run its fossil units 

harder to meet demand” -- indicates that EPA anticipates the assurance provisions would likely 

be triggered only in unusual conditions and for a temporary period, due to forces largely beyond 

the unit owner’s control. Id. Any allowance surrender in addition to the standard allowance 

surrender of one allowance per ton -- perhaps, for example, an additional 1⁄2 allowance (rather 

than the additional one allowance) on top of the standard one-allowance surrender requirement -- 

would provide an adequate incentive for unit owners 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 subject to discretionary 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 would provide sufficient incentive to avoid 

triggering the assurance 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” allowances from future-year accounts for use in 

compliance, at least on a limited basis. This would allow for increased flexibility, which will be 

particularly important in the early years of the program, especially if EPA promulgates a final 

rule that includes the ambitious compliance 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 over 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 Intrastate Trading Remedy Option, if EPA 

promulgates a final rule based on this option, EPA should not provide for government-run 

allowance auctions. As noted above in section II.C, governmental auctioning of allowances is 

contrary to the principle that regulated sources 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 discretionary 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 trading program that EPA 

proposes, an exceedance of one ton of emissions will be treated as a single violation over one 

year or ozone season, as the case may be, rather than as a separate violation for each day in that 

year or ozone season. This change is particularly appropriate because any exceedances of 

allowance levels under the Transport Rule are almost certain to be inadvertent. 

56 One potential approach that EPA could consider in developing a “borrowing” program 

could involve a requirement that borrowers pay a reasonable amount of “interest” in future years 

in the form of additional allowance requirements, 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 Trading 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 affected 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 providing revenue to the U.S. Treasury is not a 

legitimate purpose of section 110(a)(2)(D)(i)(I) of the CAA. Moreover, as discussed above, 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. 

In short, EPA should not promulgate a rule based 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 limited market share, EPA should provide for 

adjustments in the distribution of allowance allocations but without auctioning the allowances. 

XI. Requirements for Electronic Reporting 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 requirement that source owners and operators 

submit electronic quarterly reports “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 contained in 40 C.F.R. Part 75 (“Part 75”), which 

establishes monitoring, recordkeeping, and reporting requirements for the Acid Rain Program 

(ARP), NOx Budget Program, and CAIR. 75 Fed. Reg. at 45325/2 - 45326/1. UARG is 
92 

surprised that EPA did not acknowledge in that discussion that the Part 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 submission of data” by “direct computer-to-computer 

electronic transfer via EPA-provided software, unless otherwise approved by the Administrator.” 

40 C.F.R. § 75.64(d) and (f). UARG challenged these provisions in part based on (1) concerns 

regarding the nature and content of EPA’s format, 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 Electronic 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 connect 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 August 12, 2002). These cases have 

been held in abeyance pending discussions aimed at resolving these concerns. 

As UARG explained in the Part 75 rulemaking, if EPA makes the format itself (as 

opposed to the requirement to submit the information) a regulatory requirement, EPA has an 

 57 For example, EPA’s software does not provide 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 designated representative to 

submit the quarterly report by email. However, submission by email does not comply with the 

Agency’s requirements for electronic reporting under CROMERR, which imposes source owner 

and operator liability for electronic reporting to an “undesignated” EPA electronic receiving 

system or without a valid electronic signature as defined in CROMERR. Email does not meet 

the electronic signature requirements of CROMERR. 
93 

obligation to subject that format to notice-and-comment rulemaking and review by the Office of 

Management and Budget (“OMB”). The EPA electronic 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 flexibility 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, the formats have included requirements to submit 

data that are not otherwise required to be reported under the rules. Each time EPA makes a 

revision to the format, software, or instructions, sources are required 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 generating 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 redesign of the format, holding stakeholder meetings 

and providing contractor “technical support” during business hours, 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 impose 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/index.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 language authorizing the Administrator to 

make adjustments to information personally certified 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 concerning “any submission” 

and “make appropriate adjustments of the information in the submission.” Under proposed 

§§ 97.414(a), 97.514(a), 97.614(a), and 97.714(a), DRs and 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 unilaterally override a DR’s or ADR’s certification, without any procedure or 

criteria for establishing that the existing information is incorrect, or that the adjustment is in fact 

appropriate. EPA should remove 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 determine whether they “meet[ ] the requirements of 

this subpart and part 75,” (2) notify 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 through resubmission of the quarterly report.” EPA proposes to 

require that the DR make the specified corrections, or provide “information demonstrating that a 

specified correction is not necessary because the quarterly report already meets the requirements 
95 

of this subpart and Part 75.” Id.60 In the preamble, EPA characterizes this provision as codifying 

a process that is “implicit under, and has been in continuous use in, the Acid Rain, NOX Budget, 

and CAIR trading programs.” 75 Fed. Reg. at 45413/2-3. 

 UARG disagrees that this provision is consistent with current practice and objects to its 

inclusion in this rule. Each electronic report submitted under Part 75 is required to contain a 

certification by the DR or ADR that the information in the report is “true, accurate, and 

complete,” and that the reported data were recorded in accordance with Part 75. 40 C.F.R. 

§ 75.64(c). EPA proposes to include similar 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 EPA and DRs or ADRs (particularly following 

adoption of a new rule, rule revision, or reporting format change) about the accuracy of reports 

are not uncommon. Disagreements can arise for many reasons, including as a result of 

differences in rounding methodologies, differences in interpretation, EPA’s use of the reporting 

“format” to collect information not otherwise required by rule to be submitted, and other errors 

or programming “bugs” in the electronic data quality 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 interpretations 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 generates 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 Administrator 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 certify 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 “format” and auditing techniques to establish a 

presumption of what constitutes compliance with Part 75, without subjecting its “reporting 

format” and software (including all of the audits contained in it) to rulemaking. 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 certification 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 restructure it to require resubmission only after the 

Administrator (not the source owner or operator) has established through an appropriate dispute 

resolution procedure that the report does not in fact meet the rule’s requirement.61

XII. As a Matter of CAA Procedural Requirements, the Proposed Rule’s Unfounded 

Assumptions, Errors, and Apparent Anomalies -- and EPA’s Failure To Explain 

Adequately Critical Aspects of the Proposal 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 deficiency in the Proposed Transport Rule -- i.e., 

EPA’s use of a “FIP-first” approach that improperly bypasses the SIP process, as described 

above -- and other flaws in EPA’s proposal related to that deficiency, such as an improperly 

 61 EPA recently proposed a report resubmission provision in proposed revisions to its rule 

for Mandatory Reporting of Greenhouse Gases 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 purport to allow EPA to unilaterally 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 resubmit a report in the context of his/her own determination that the 

report contained a “substantive error,” or to submit information to the Administrator explaining 

why the DR or ADR does not believe the report contains a substantive 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 proposal 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 proposed 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 the proposed rule without 

any meaningful opportunity for preliminary public review and input. Similarly, EPA’s 

explanations of both its air quality assessment tool 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 state budget and unit allocation calculations. See

comments of Southern Company on the PTR (describing 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 Rule 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 does contain some commendable elements, the 

proposed rule overall is seriously flawed on legal, policy, and factual grounds. These flaws are 

so substantial that EPA should withdraw the proposed rule and replace it with a new proposed 

rule that remedies the specific deficiencies 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 FIPs 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 for Selective Catalytic Reduction (SCR) and Flue 

Gas Desulfurization (FGD) Process 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 Group
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

TABLE OF CONTENTS

SECTION 1 EXECUTIVE SUMMARY.................................................................. 1-1

SECTION 2 BACKGROUND................................................................................... 2-1

2.1 PROCESS EQUIPMENT REQUIRED 2-1

2.1.1 FLUE GAS DESULFURIZATION (FGD) 2-1

2.1.2 SELECTIVE CATALYTIC REDUCTION (SCR) 2-3

2.2 ELEMENTS OF A COMMERCIAL PROCUREMENT SPECIFICATION 2-4

2.2.1 CONCEPTUAL DESIGN/PREPARATION OF SPECIFICATION 2-4

2.2.2 IDENTIFICATION OF QUALIFIED CANDIDATE BIDDERS 2-6

2.2.3 SOLICITATION AND REVIEW OF BIDS/SELECTION OF CONTRACTOR 2-6

2.2.4 NEGOTIATION OF CONTRACT TERMS/CONTRACT ISSUANCE 2-7

2.2.5 SECURING PERMITS TO CONSTRUCT AND OPERATE THE RETROFITTED CONTROL 

EQUIPMENT 2-7

2.2.6 FINALIZATION OF DESIGN AND PREPARATION OF FABRICATION DRAWINGS 2-10

2.2.7 MOBILIZATION OF THE WORKFORCE TO SITE 2-11

2.2.8 ACTUAL CONSTRUCTION 2-11

2.2.9 PROCESS EQUIPMENT TIE-IN 2-12

2.2.10 PROCESS STARTUP 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 ALABAMA POWER GORGAS UNITS 8-10 (61 MONTHS). 3-5

3.3.2 ALLEGHENY ENERGY HATFIELD’S FERRY UNITS 1-3 (45 MONTHS) 3-5

3.3.3 DUKE ENERGY ALLEN UNITS 1-5 (49 MONTHS FOR THE FIRST RETROFIT; 1

EXTRA MONTH FOR THE OTHER). 3-6

3.3.4 DUKE MARSHALL UNITS 1-4 (46 MONTHS FOR THE FIRST RETROFIT; 6 MORE

MONTHS FOR THE OTHER THREE RETROFITS). 3-6

3.3.5 FIRST ENERGY SAMMIS UNITS 1-7 (56 MONTHS). 3-6

SECTION 4 SELECTIVE CATALYTIC REDUCTION (SCR) AND LOW NOx

BURNER SCHEDULES ............................................................................................... 4-1

4.1 SELECTIVE CATALYTIC REDUCTION (SCR) 4-2

4.1.1 INSTALLATION OF A SINGLE SCR UNIT AT A SITE 4-3
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October 1, 2010

4.1.2 MULTIPLE SCR PROCESSES AT ONE SITE 4-4

4.2 LOW NOx 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 CENTRALIA WET FGD 5-2

5.2.2 TAMPA ELECTRIC BIG BEND 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..................................................................................... 7-1
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FGD and SCR Process Equipment

October 1, 2010

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 NOx Control Projects – SCR .............................................................4-1

Figure 4-2. Timeline of NOx Control Projects – LNB.............................................................4-2

Figure 5-1: Timeline Showing Recent Installed FGD Capacity by Startup Date ........5-2

LIST OF TABLES

Table 2-1. Lead Time (Weeks) for Key FGD Components 

(after Katzberger, 2007)..................................................................................................................2-2

Table 6-1. Summary of Design, Fabrication, Installation Period.....................................6-1
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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 may 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 published 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 (SO2) emissions; and Low NOx Burners (LNB) and selective catalytic 

reduction (SCR) reactors for the control of nitrogen oxide (NOx) emissions.

In the preamble to its Proposed Transport Rule (published in the Federal Register 

on August 2, 2010) and in earlier studies upon which EPA now relies (EPA, 2005; 

EPA, 2002), EPA says that the Agency expects it will take 27 months of total effort 

for an electric generating company to plan, engineer, install, and start up one FGD 

system at one unit at a plant site; and that the total 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 an electric generating company to plan, 

engineer, install and start up one SCR system at one unit 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 NOx 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 years, describing 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 plant 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 recently 
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

1-2

been 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 NOx controls: SCR and low NOx burners. The projects 

discussed in 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. 
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FGD and SCR Process Equipment

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2-1

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 REQUIRED

The type of process equipment required for a commercial FGD and SCR process is 

described, highlighting those aspects that affect fabrication and installation.

2.1.1 FLUE GAS DESULFURIZATION (FGD)

The flue gas desulfurization (FGD) system is comprised of four key elements: 

(a) reagent receiving and preparation equipment, (b) SO2 absorber tower, 

(c) byproduct dewatering and 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 

SO2 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 

construction delays, particularly where special exotic corrosion-resistant alloys 

were required for liners. These delays, however, were generally not the project ratedetermining step for the FGD equipment installed in 2008-2010. 

Rather, what typically caused project 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: reportedly 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). 
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FGD and SCR Process Equipment

October 1, 2010

2-2

Figure 2-1. Typical Wet FGD Absorber Tower 

http://www.babcockpower.com/index.php?option=products&task=viewproduct&coid=17&proid=11)

AEP reports that its most recent (August 2010) attempt 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)
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October 1, 2010

2-3

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 they can begin most of the 

site work for FGD and SCR installations. 

2.1.2 SELECTIVE CATALYTIC REDUCTION (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 returning 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 all sites.

Figure 2-2. Perspective View of SCR Reactor for Coal-Firing (Babcock & Wilcox 

product information: 

www.babcock.com/products/environmental_equipment/scr.html)
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2.2 ELEMENTS OF A COMMERCIAL PROCUREMENT 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 conducted 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 contractor

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 workforce to site

Actual construction

Process Equipment Tie-in 

Process Startup

Each of these key steps is further described in this section. 

2.2.1 CONCEPTUAL DESIGN/PREPARATION OF SPECIFICATION

As part of developing a conceptual design for FGD or SCR systems, 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 and 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 cost 

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, 

which 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).
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October 1, 2010

2-5

This and other preconstruction steps typically take over 12 months to complete. 

Some companies – 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 reduce 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 and 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 the 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 preliminary 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 

reportedly 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 present 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.
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October 1, 2010

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The 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-place “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 IDENTIFICATION OF QUALIFIED CANDIDATE BIDDERS

Once the 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 reduce 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 eliminate 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 SOLICITATION AND REVIEW OF BIDS/SELECTION OF CONTRACTOR

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 process 

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 

part 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. The 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.
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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 NEGOTIATION OF CONTRACT TERMS/CONTRACT ISSUANCE

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, and 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 several 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 can 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 alliance, 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 SECURING PERMITS TO CONSTRUCT AND OPERATE THE RETROFITTED CONTROL 

EQUIPMENT

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, almost without exception, it has been possible to accelerate project schedules only 

during times when demand on equipment and suppliers was low.
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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 noted, 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 authorizations. 

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 power 

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 NOx and SO2, 

respectively, but operation of that control technology may result in a “collateral 

increase” in emissions of a byproduct species other than NOx or SO2. For example, 

the operation of wet FGD and SCR – while reducing SO2 and NOx emissions – may 

increase sulfuric acid mist by more than insignificant amounts. Also, operating low 

NOx burners will reduce NOx emissions but 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 controls, 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 2005, 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 source 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 increase 

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 needed (perhaps to evaluate emissions of greenhouse gases once the NSR 
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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 companies 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 SO3 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 consequences 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 FGD 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 located 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 point. 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 emissions 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.
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Public Utility Commission (PUC) Approvals to Install Pollution Control Equipment. 

Where PUC approvals are needed, the length of time it can take to seek and 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 

application. 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 and 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 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 source Clean Water Act permits. For 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 uncertainty surrounding 

effluent guideline regulations, noting that such uncertainty can hinder the decisionmaking process and make the process iterative if regulations require additional 

changes or alterations to the plant not anticipated in the original permit 

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 operations, 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 

installations in less than 30 months.

2.2.6 FINALIZATION OF DESIGN AND PREPARATION OF FABRICATION DRAWINGS

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 that are not obvious at 

preliminary design – such as the presence (or lack of ) underground utilities or 
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other structures, or soil properties. Much of this process can be conducted in 

parallel with other equipment installation activities. 

2.2.7 MOBILIZATION OF THE WORKFORCE TO SITE

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 ACTUAL CONSTRUCTION

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 preparation 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 in 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 affect 

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 SO2 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-place” 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 labor is key, and there can be significant 

differences in regional workforce productivity, which can affect installation 
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schedule. Experience with the equipment retrofits in 2008-2010 showed a strong 

demand for the most experienced and productive staff. Consequently, 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 access 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 timeline can extend for several years. 

2.2.9 PROCESS EQUIPMENT TIE-IN

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 during 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 required 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 required 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 PROCESS STARTUP

Once the equipment is installed and tied in, it generally takes at least 30 days and 

can 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 numerous 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 where 
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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. 
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SECTION 3

FLUE GAS DESULFURIZATION (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 many 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 procurement 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 Activities
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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 units. These examples also include stations that are 

contemporaneously retrofitting SCR and FGD systems. 

3.1 INSTALLATION OF A SINGLE 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 straightforward engineering and installation 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, stations 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 Georgia 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 permitting process and accelerate review). 

The case of Georgia Power’s Plant Hammond installation is an example of a short-toaverage-time installation schedule. The single FGD module for four boilers at 

Hammond was implemented in the shortest schedule incurred 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 leveraged 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 

for Units 1 and 2.
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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. 

Another 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 expect 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 small 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 to 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 PROCESSES 

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 “laydown” 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 laydown 

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 category. 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 

months 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 projects at WE Energies Pleasant 

Prairie Units 1 and 2 and Progress Energy Crystal River Units 4 and 5, where plant 

owners contemporaneously constructed FGD SO2 control systems and SCR NOx
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control systems. This type of project can take more time than “single 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 erection 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 some 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 units. 

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 settling 

lagoons to accommodate the reagent storage and preparation, gypsum dewatering, 

and waste water treatment facilities. In addition, the subsurface area beneath the 

former lagoons required caissons for support. This site was very congested and 

required a step-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 constraints 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 from a parking area that consumed valuable work 

time. 

In summary, the average retrofit time for these installations was 47 months but – as 

was the case with the previous category – there was great variation, with some 

installations taking less time and others taking much more.

3.3 INSTALLATION OF THREE OR MORE FGD PROCESS 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 for manpower are greater. 
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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. The 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 ALABAMA POWER GORGAS UNITS 8-10 (61 MONTHS).

The 61 month schedule for Gorgas was the longest incurred by this owner. There 

were several 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 create 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 ALLEGHENY ENERGY HATFIELD’S FERRY UNITS 1-3 (45 MONTHS)

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 and material handling 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 lines (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.
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3.3.3 DUKE ENERGY ALLEN UNITS 1-5 (49 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 49 months to bring on-line the first FGD unit and an 

additional month to bring the other FGD unit on line. 

3.3.4 DUKE MARSHALL UNITS 1-4 (46 MONTHS FOR THE FIRST RETROFIT; 6 MORE MONTHS FOR 

THE OTHER THREE RETROFITS).

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 46 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 FIRST ENERGY SAMMIS UNITS 1-7 (56 MONTHS).

A notable case is that of Sammis Units 1-7. Figure 3-2 depicts the Sammis site layout, 

adjacent 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 months.

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 site. The length of time it 

took to complete FGD installations at the different sites varied depending upon sitespecific factors. For example at Duke’s Marshall station, the first unit (Unit 4) 

became operational 46 month after start of engineering and permitting, 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 from 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.
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Figure 3-2. Sammis Site Layout
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SECTION 4

SELECTIVE CATALYTIC REDUCTION (SCR) 

AND LOW NOX BURNER SCHEDULES

This section of the report reviews the schedule to retrofit SCR reactors and/or low 

NOx burners at 13 generating stations. A summary of the results for SCR is 

presented in Figure 4-1, and for low NOx 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 NOx burners and that could expeditiously provide the 

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 

different categories of units will be approximate. 

Figure 4-1. Timeline of NOx Control Projects – SCR 
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Figure 4-2. Timeline of NOx 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. Unlike 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 process 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 be 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.
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4.1.1 INSTALLATION OF A SINGLE SCR UNIT AT A SITE

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 Station 

(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 Hammond 

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 

proceed 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 time due to extended ductwork was closer to 7 weeks and not the typical 

4 weeks.

Alabama Power Gaston Unit 5 (40 months). Alabama Gaston Unit 5 required 40 

months, one of the longest project durations experienced by this owner. Most 

notably, major modifications 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 access 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 (46 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 added 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 site, 

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

October 1, 2010

4-4

4.1.2 MULTIPLE SCR PROCESSES AT ONE SITE

There are several examples of plant owners retrofitting multiple processes for the 

control of NOx 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 there 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 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). Also worth mentioning is Associated Electric Cooperative’s 

work to control NOx at its Thomas Hill Station (including the addition of an SCR 

system and low NOx 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 

multiple 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 illustrates 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 units 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 address these in 

a serial manner. Consequently the 31 month period is not considered typical.
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

4-5

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 permitting 

commencing 19 months prior to any startup activities. Other units at Scherer that 

will receive SCR – Units 1, 2, and 4 – are scheduled for start up after Unit 3. The 

complexities of the site, and general congestion of executing these projects 

contemporaneously, 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 NOX BURNERS

The reduced complexity of an LNB system, compared to an SCR or FGD process, 

does not necessarily translate into abbreviated permitting 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 fabrication and delivery times. Also, there can be 

complications in the permitting process. At least one multi-state owner is 

anticipating a lengthier schedule for installing LNB equipment, due to concerns that 

have arisen in the permitting of the installations, where local regulatory agencies 

are questioning whether lower NOx emissions are inextricability linked to higher CO 

emissions. 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 NOx 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 that 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 NOx

burners had been installed on their own, company representatives estimate that 

permitting 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) companies 
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

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 velocities 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 required 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

October 1, 2010

5-1

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 representative 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 equipment 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

Figure 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 those 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

October 1, 2010

5-2

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 30 MONTHS

EPA cites two examples of FGD installations being completed in a total of less than 

30 months: those at Centralia and Tampa Electric Company’s Big Bend Station. 

Further information on those installations is provided below.

5.2.1 CENTRALIA WET 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 Centralia 
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

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, there 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 Section 3 of this report.5

5.2.2 TAMPA ELECTRIC BIG BEND

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 (based 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 design, 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 will 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 

management 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 factor of 2-3 less than more recent projects.
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

5-4

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 COMPLETED IN A 

TOTAL OF LESS THAN 30 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 Pennsylvania. 

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 the 

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 

owners 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 “nontraditional” approach to selecting 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 prudency 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 process – 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 

decade ago, companies did not have to deal with current requirements to predict 

and mitigate SO3 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: approximately $100/kW on a 2001 dollar basis.
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

5-5

procuring their bids, evaluating those bids, and awarding contracts – are executed 

for not one but multiple units7. However, the rate-limiting step in a multi-project 

FGD or SCR retrofit is usually construction, and the impediments 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 able 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 example, 

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 

acknowledges 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 months. 

 

7

See Figures 1 and 2 of EPA, 2005.
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FGD and SCR Process Equipment

October 1, 2010

6-1

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 Sections 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 NOx 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

12-18 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 statistically 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

October 1, 2010

6-2

The few cases cites by EPA provide no legitimate basis for challenging the 

reasonableness of the schedules 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 

the 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 adverse 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 for 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 

optimized 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 retrofitting 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 SCR and FGD units 

can be subject to the rigors of the new source review preconstruction permitting 
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

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 environmental permits (some of which could take 4 or more years to get) and 

other authorizations .
Implementation Schedules for 

FGD and SCR Process Equipment

October 1, 2010

7-1

SECTION 7

REFERENCES

Name, Date Citation

EPA, 2005 Environmental Protection Agency, “Boilermaker Labor Analysis and 

Installation Timing”, Technical Support Document 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,” EPA-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/powerengineering/volume-111/issue-6/features/clearing-the-air-in-the-twincities.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-Impactof-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”, Proceedings 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 SO2 Compliance”, 

Proceedings of the Combined Power Plant Air Pollutant Control MegaSymposium’, 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

October 1, 2010

7-2

Smolenski, 

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 EPRIDOE-EPA Combined Utility Air Pollution Control Symposium: The MegaSymposium, August 16-20, 1999, 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 32738079v1
Attachment II

J. Marchetti, E. Cichanowicz, and M. Hein, “Schedule 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, 2010 
Schedule 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 CONTROL 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 6-1
Schedule 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 – Base and Limited Trading Cases........................ 4‐2

Figure 4‐2. EPA New SCR Capacity – Base and Limited Trading Cases........................ 4‐2

Figure 4‐3.  EPA Estimate of the Number of FGD 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 for Boilermaker Hours:  EPA‐Assumed Project 

Schedules (FGD and SCR) .................................................................................................................. 5‐5

LIST OF TABLES

Table 5‐1. Estimated Implementation Schedule (Months) For FGD, SCR Projects...... 5‐2
Schedule of Control Technology Retrofit 

To Meet EPA’s Proposed Transport Rule 

October 1, 2010 

 

1‐1 

SECTION 1 

INTRODUCTION 

The Environmental Protection Agency on August 2, 2010, published the Proposed 

Transport Rule (PTR), the anticipated replacement of the Clean Air Interstate Rule 

(CAIR). The EPA in the August 2 announcement provided background support 

material, including analyses that assigned allocations of permissible levels of SO2

and NOx emissions to owners of electric generating units (EGUs). EPA in the 

background support material projected a total of 159 EGUs would retrofit a total of 

185 control technology projects1, on a total generating capacity approximately 14 

GW2, to meet this mandate. 

The EPA projected a two‐phase compliance schedule that purportedly describes 

how industry will deploy control technology – by January 1, 2012, and January 1, 

2014. This compliance schedule was determined by EPA staff using IPM. The EPA‐

projected compliance schedule predicts that all 185 retrofit projects 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 control technologies – 

flue gas desulfurization (FGD) for SO2 and selective catalytic reduction (SCR) for 

NOx – can be installed in timeframes that, by recent industry experience, are 

abbreviated and unrealistic. Specifically, 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 elements – from project 

conception to successful commercial operation. The adequacy of these 21‐ and 27‐

month periods has been challenged and is the subject of a companion report 

submitted with the comments of the Utility Air Regulatory Group.

3 In contrast to 

EPA’s projected periods of 21 and 27 months, UARG submits documented 

experience that shows the reference cases selected by EPA from which to judge 

timeframes are not representative of present‐day utility experience. Actual 

implementation dates are much longer.  

This report projects a compliance schedule that is realistic and 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 

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October 1, 2010 

 

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technologies in a timely manner – due to a “logjam” of engineering, permitting, and 

construction activities – will compromise industry’s ability to meet PTR mandates.   

Section 2 presents an overview of the methodology used to project 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 calendar year. Section 4 

critiques EPA’s approach to projecting the compliance schedule. Section 5 presents 

revised results using realistic schedule assumptions. Section 6 offers observations 

on the results of the analysis. 
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October 1, 2010 

 

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SECTION 2 

EVALUATION METHODOLOGY 

This section presents an overview of the methodology taken to conduct this 

analysis. 

First, EPA predictions of the number of units required to retrofit control technology 

were reviewed. EPA identified specific units that would likely adopt control 

technology4. This “inventory” of control technology candidates as described in EPA’s 

“parsed” output files totals 185 projects, to be retrofit on 159 generating units. 

Specifically, EPA predicts that 106 units will retrofit FGD, 27 units will retrofit SCR.  

Of this inventory of units retrofitting control technology, a total of 26 units will 

retrofit both SCR and FGD. 

Second, a realistic schedule for project implementation based on the companion 

report prepared for UARG’s comments was identified. Specifically, an array of 

implementation schedules was identified based on the existing condition 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 the number of units to be retrofit.  

Third, those EGU’s for which the unit owner or owners have an announced intent to 

install either FGD or SCR, or both, and an operating date for the control equipment, 

were identified. This pool of units was assigned the respective operating dates as 

identified by their owners. These units were treated differently 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 installation in the third quarter of 2011. An EGU owner 

could not reasonably begin a project 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 final SIP revisions to 

implement the final rule and obtain EPA’s approval of SIP revisions.)  

Fifth, the project operating dates were determined based on (1) the assumed start 

date and the applicable project implementation 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.html
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Sixth, the boilermaker labor‐hours demand for the projected 2012 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 extending beyond EPA’s assumed January 2014 

operating date as necessary to reflect those realistic schedules – was calculated and 

compared to the 2008‐2010 historical demand. The boilermaker demand that 

would be necessary for the unrealistically accelerated deployment that would be 

required to meet EPA’s schedule – using an assumed January 2014 operating date 

(and ignoring the real‐world installation schedules described in this report and the 

companion report) – was calculated and compared to the historical 2008‐2010 

value. 
Schedule of Control Technology Retrofit 

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October 1, 2010 

 

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SECTION 3 

REVIEW OF 2008-2010 

CONTROL TECHNOLOGY RETROFIT EXPERIENCE 

This section reviews the utility industry’s 2008‐2010 experience in retrofitting both 

FGD and SCR, and describes how this experience is invoked to project 

implementation schedules for 2012 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 the FGD and SCR capacity that was 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 than 15,000 MW of 

capacity is anticipated to be operational in 2010. 

Figure 3‐2 presents the installed generating capacity of SCR over the similar period. 

Figure 3‐2 shows that although the generating capacity of SCR installed is small 

compared to FGD, it is a significant amount on an absolute basis. 

3.2 BOILERMAKER HOURS 

The inventory of FGD and SCR equipment installed in 2008 and 2010 can be used to 

estimate boilermaker hours (i.e., person‐hours of skilled boilermaker labor) needed 

for each incremental megawatt capacity of FGD or SCR retrofit. 

The relationship between boilermaker hours demand and generating capacity, for 

both FGD and SCR, is shown in Figure 3‐3. This relationship was developed based on 

discussions with suppliers, architect/engineering firms, and owners 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 experience, projecting future boilermaker labor needs. 

Examining EPA’s parsed output files shows that compared to the generating 

capacity of the units retrofit in 2008‐2010, the generating capacity 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 operating combustion turbine and combine-cycle units. 
Schedule of Control Technology Retrofit 

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

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

Installation and Generating Capacity 

The non‐linear relationship of boilermaker hours required and generating capacity 

shown in Figure 3‐3 suggests more boilermaker hours and other construction 

consumables will be needed for the 2012 to 2014 retrofits, compared to the 2008 to 

2010 retrofits, for an equivalent amount of generating capacity. 

Figure 3‐3 describes the boilermaker demand total for the entire project. The 

distribution of boilermaker hours is not uniform over the construction period; 

specifically, early work such as clearing and preparing the site, concrete and 

foundation work, and general construction activities do not require boilermaker 

skills. Based on discussions with suppliers, architect/engineering 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, staged according to a 

schedule that has this work concluding one full quarter prior to project completion. 

This schedule represents the average experience within the industry. 
Schedule of Control Technology Retrofit 

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Figure 3‐4 presents the results of calculations of quarterly demand of boilermaker 

hours, as experienced in 2008 through 2010, based on Figure 3‐3. The bar chart in 

Figure 3‐4 shows that boilermaker‐hours demand, reported both on 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 quarterly maximum total 

exceeding 5.5 million boilermaker hours, and a three‐quarter trailing average 

exceeding 5.1 million boilermaker hours, were required. 

Figure 3-4. Calculated Boilermaker Demand for Both FGD and SCR: 3Q 2006 

though 2Q 2010 

The consumption of boilermaker hours in Figure 3‐4 is assumed as a constraint on 

the construction of FGD and SCR in the 2012‐2014 timeframe. 
Schedule of Control Technology Retrofit 

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October 1, 2010 

 

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SECTION 4 

CRITIQUE OF EPA’S APPROACH TO DETERMINING 

REQUIRED FGD AND SCR CAPACITY 

The EPA analysis addressed two scenarios:  (a) Base Case and (b) State Budget – 

Limited Trading. These two scenarios were evaluated to determine the number and 

generating capacity of FGD and SCR retrofits required for the years 2012 and 2014. 

It should be noted that Base Case compliance assumes compliance with other 

regulatory programs such as Title IV, NOx 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 unrestricted intrastate trading and 

limited interstate trading among 32 states based upon state budgets. 

EPA initially modeled the amount of “new” FGD and SCR capacity that would be 

required to meet the regulatory requirements of the Base Case in both 2012 and 

2014. This modeled capacity is then carried forward into the Limited Trading Case, 

and is needed to meet the targets of the Limited Trading Case in both 2012 and 

2014. (Note that the Limited Trading Case in 2012 includes FGD and SCR retrofits 

that EPA projects will be completed by 2012 in order to comply with the TR. Many 

of these retrofits were modeled by EPA; however, a few retrofits have been 

identified as retrofits that would have been installed to comply with CAIR or consent 

decrees.) With this Base Case capacity embedded, EPA then models the 

additional/incremental FGD and SCR capacity that would be required to meet the 

PTR’s state budgets. Significantly, 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 capacity, respectively, that will be required under the 

PTR by January 1, 2012, and January 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 that 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. As shown above, EPA omitted from the discussion 

the 10 GW of FGD capacity that will also be needed from the Base Case to achieve 

compliance under the Limited Trading Case by 2014. In reality, therefore, EPA has 

modeled, for completion after January 1, 2012, but before January 1, 2014, a total of 

approximately 25 GW of new FGD capacity and 8.2 GW of new SCR capacity in order 

to meet the PTR’s targets.   
Schedule of Control Technology Retrofit 

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October 1, 2010 

 

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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 retrofit projects by quarter. This identification of 

projects by quarter is displayed in Figure 4‐3. The data in Figure 4‐3 reflect EPA’s 

assumptions that a given amount of capacity and generating units can be retrofit by 

2012 and 2014. This depiction also shows that some of the owner‐announced FGD 

and SCR projects will be operational at various times in 2013. It should be 

emphasized that the schedule shown in Figure 4‐3, with the exception of the 

relatively modest number of projects (50) announced by EGU owners, is an 

assumption by EPA and not the result of a predictive analysis. 
Schedule of Control Technology Retrofit 

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October 1, 2010 

 

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Figure 4-3. EPA Estimate of the Number of FGD and SCR Projects Operational: 

2011 to 2014 
Schedule of Control Technology Retrofit 

To Meet EPA’s Proposed Transport Rule 

October 1, 2010 

 

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SECTION 5 

REVISED SCHEDULES AND MODELING RESULTS 

This section presents a revised compliance schedule based on realistic assumptions 

of project implementation. Results presented in this section address (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 quarter of 2011, and 

(c) the quarter‐by‐quarter boilermaker demand. 

5.1 SCHEDULE FOR INSTALLING FGD AND SCR 

Section 1 noted a companion report being submitted by UARG with respect to the 

PTR, summarizing realistic schedules for the retrofit of individual FGD and SCR 

process equipment. This analysis uses results from that document to project the 

compliance schedule for the inventory of units affected by the PTR.  

Table 5‐1 recommends FGD and SCR project retrofit schedules based on the UARG 

survey. The table summarizes the number of months required to implement an FGD 

or SCR retrofit project, starting with preliminary engineering or permitting, through 

commercial operation. The schedule data is presented for various categories of 

generating stations and conditions at the site – for example, the number of unit 

processes to be installed (i.e., the number of FGD modules or SCR reactors), and the 

existing equipment that is on‐site. For both FGD and SCR, an abbreviated schedule is 

used for any unit for which an operating date has been announced by the owner. 

This special case presumes that EGU owners with announced operating dates have 

already initiated engineering, permitting, or other background activities. This 

assumption will not always be valid but is considered appropriate for these types of 

projects with owner‐announced schedules.  

These data were used to determine when a project would be operational, given a 

defined start date as described above. 

5.2 DETERMINING THE SCHEDULE 

The schedule by which the EGUs are predicted to have the control equipment 

installed and operational was determined. The EGUs predicted by EPA to install FGD 

and/or SCR were partitioned into two categories, and treated as described as 

follows: 
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Table 5-1. Estimated Implementation Schedule (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 specific dates when the 

technology is planned to be operational. Some dates populate 2011; most are within 

the 2012‐2013 timeframe. 

5.2.2 Modeled Project Start Dates 

All other units – i.e., all units 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 permitting steps in light of 

EPA’s planned rulemaking completion date for the PTR and the likelihood of 

changes to the PTR by the time EPA completes the rulemaking. Each retrofit project 

(FGD or SCR) was assigned an implementation timeline, based on the applicable unit 

category (per Table 5‐1). This schedule, together with the assumed 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 by the EPA‐proposed January 1, 2012, and January 1, 

2014, compliance dates – and these projects are only those for which unit owners 
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October 1, 2010 

 

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have announced a project completion date by January 1, 2012, or by January 1, 

2014, respectively, and which this analysis assumes will meet their owner‐

announced completion dates. The largest number of FGD and SCR projects are 

projected to become operational (i.e., are completed) at various dates between early 

2015 and mid 2016.  

Figure 5-1. Predicted FGD and SCR Operational Dates for Inventory of PTRAffected Units 

The majority of units are projected to be unable to meet the EPA‐proposed 

compliance dates; specifically, 54 projects targeting the January 2012 date are “late,” 

while 81 projects targeting the January 2014 date are “late”. Only about 27% of the 

targeted 185 retrofit projects are projected to meet the applicable EPA‐proposed 

date.  

5.3 REQUIRED BOILERMAKER HOURS 

The project implementation schedule in Figure 5‐1 can be used to calculate the 

demand for boilermaker hours for Transport Rule compliance. 

Figure 5‐2 presents the quarterly demand for boilermakers to support the PTR – but 

with the compliance schedule adjusted to reflect the more realistic control‐

implementation timetables as described and applied above. Under this scenario, the 

peak demand, for example, is projected to be somewhat more than 4,000,000 hours 

per quarter but less than the demand for the 2008‐2010 FGD and SCR installation 

demand. 
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October 1, 2010 

 

5‐4 

Figure 5-2. Quarterly Demand for Boilermaker 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. Consequently, even if the 

engineering and permitting tasks could be completed and the necessary process 

equipment and material could be fabricated and 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 sufficient number of boilermakers would be 

available to do the work necessary to have the control equipment installed and 

operational within those periods. 
Schedule of Control Technology Retrofit 

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5‐5 

Figure 5-3. Quarterly Demand for Boilermaker 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 implementation. 

These results show that, contrary to EPA projections, there is inadequate time to 

deploy the necessary control technology to meet the PTR mandates. Specifically, of 

the 185 control technology retrofit projects that EPA anticipates, only 27% can be 

completed by the EPA‐proposed compliance dates. (This 27% represents the 

fraction of the total retrofit projects for which unit owners announced a completion 

date by January 1, 2012, or January 1, 2014, respectively, and which this analysis 

assumes will meet their owner‐announced completion dates.) A total of 54 retrofit 

projects are predicted to miss the January 1, 2012, deadline; and 81 such projects 

are predicted to miss the January 1, 2014, deadline. Project completion 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, respectively. Even if this unrealistic schedule could 

otherwise be met, it could not in 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 services, particularly as manifested by the consumption 

of boilermaker hours, make compliance with EPA’s proposed schedule impossible.   

Moreover, this analysis does not take into consideration the additional impacts of 

other rulemakings on the availability of labor and tradespeople as well as 

engineering contractors. Examples include the recent cement kiln MACT standards, 

which will require a large number of kilns to install wet FGD systems over the next 

three years, and the ICI boiler and process heat MACT standards, which are 

expected to require hundreds of wet FGD systems and other types of controls to be 

installed by 2014 if EPA makes those standards final by next year. 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 the increase in water 

vapor in the flue gas and its effect on stack flow properties as well as the 

construction or expansion of landfill capacity for byproducts of FGD system 

operation. Limits on the availability 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. Consideration of these 
Schedule of Control Technology Retrofit 

To Meet EPA’s Proposed Transport Rule 

October 1, 2010 

6‐2 

factors reinforces the conclusion that it will not be possible for regulated electric 

generating companies to meet the PTR’s compliance schedule. 
Attachment III

Tables Regarding Current Air Quality at Sites Projected to be Nonattainment Sites in 2012 
2 

31531.420001 EMF_US 32433784v1

Current Air Quality at Sites Projected to be Nonattainment Sites in 2012

Table I: Annual PM2.5 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 PM2.5 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 currently designated nonattainment 

171191007 Illinois Madison Not currently designated nonattainment 

171192009 Illinois Madison Not currently designated nonattainment 

171193007 Illinois Madison Not currently 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 currently designated nonattainment 
4 

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 currently designated nonattainment 

295100087 Missouri St. Louis City Not currently 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 Jefferson 
5 

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