COMMENTS OF THE UTILITY AIR REGULATORY GROUP 

on the 

NOTICE OF DATA AVAILABILITY SUPPORTING THE PROPOSED 

FEDERAL IMPLEMENTATION PLANS 

TO REDUCE INTERSTATE TRANSPORT OF FINE PARTICULATE 

MATTER AND OZONE 

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

 HUNTON & WILLIAMS LLP 

 Andrea Bear Field 

 Norman W. Fichthorn 

 James D. Elliott 

 E. Carter Chandler Clements 

 1900 K Street, N.W. 

 Washington, D.C. 20006 

 (202) 955-1500 

 Counsel for the Utility Air 

 Regulatory Group 

 October 15, 2010
i 

TABLE OF CONTENTS 

I. Introduction..........................................................................................................................1 

II. The Comment Period on the NODA Is Inadequate To Allow for Adequate 

Public Review of the Extensive Material Associated with It. .............................................4 

III. Despite the Quantity of New Information Added to the Docket Pursuant to 

the NODA, EPA Has Failed To Provide Data Necessary To Allow 

Meaningful Comment on That Information.........................................................................5 

IV. EPA’s Decision To Base 2014 SO2 Allowance Allocations for Units in 

Group 1 States on the Same State-Level Emission Caps Used in the PTR -

- Even Though Revised Data and an Updated Modeling Tool Were 

Available -- Is Arbitrary and Unjustified...........................................................................10 

V. Several of the Revisions to NEEDS and IPM that Are Reflected in the 

NODA Are Inappropriate or Inadequately Explained. ......................................................13 

A. EPA’s Upward Adjustment of Its Assumption Regarding FGD 

Maximum Removal Efficiency Is Unjustified and Inaccurate. .............................13 

B. Units with Generating Capacity Less than 100 MW Cannot 

Properly Be Assumed To Be Candidates for Installation of FGD or 

SCR........................................................................................................................15 

C. EPA May Well Be Understating SCR Capital Costs.............................................16 

D. EPA’s Revised NEEDS Database and IPM Platform Still Contain 

Numerous Errors and Have Introduced Additional Inaccurate 

Assumptions...........................................................................................................17 

VI. In Making the Changes Represented in the NODA, EPA Continues To 

Ignore the Effects of CAIR and Local Controls. ...............................................................21 

A. EPA Should Have Considered the Effects of CAIR..............................................22 

B. EPA Should Have Considered the Effects of Local Controls................................23 

VII. The Availability of NEEDS v.4.10 and IPM v.4.10 and the Central Role 

These Items Play in the Structure of EPA’s PTR Warrant a New or 

Supplemental Proposed Rule Based on the Results of the New Data and 

Modeling............................................................................................................................24 
1 

COMMENTS OF THE UTILITY AIR REGULATORY GROUP 

on the 

NOTICE OF DATA AVAILABILITY SUPPORTING THE PROPOSED 

FEDERAL IMPLEMENTATION PLANS TO REDUCE INTERSTATE TRANSPORT 

OF FINE PARTICULATE MATTER AND OZONE 

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

October 15, 2010 

______________________________________________________________________ 

I. Introduction 

On September 1, 2010, the U.S. Environmental Protection Agency (“EPA” or the 

“Agency”) published its Notice of Data Availability Supporting Federal Implementation Plans 

To Reduce Interstate Transport of Fine Particulate Matter and Ozone (“NODA”). 75 Fed. Reg. 

53613 (Sept. 1, 2010). The NODA supplements EPA’s Proposed Air Pollution Transport Rule 

(“Proposed Transport Rule” or “PTR”), published in the Federal Register on August 2, 2010, 

which was the subject of a 60-day public comment period that ended on October 1, 2010. 75 

Fed. Reg. 45210 (Aug. 2, 2010). The Proposed Transport Rule is intended to replace the Clean 

Air Interstate Rule (“CAIR”), which EPA promulgated in 2005 and the U.S. Court of Appeals 

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

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

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

petitions for rehearing, 550 F.3d 1176 (D.C. Cir. 2008). Like CAIR, the Proposed Transport 

Rule primarily addresses emissions from electric generating units (“EGUs”) and is based on 

EPA’s interpretation and application of section 110(a)(2)(D)(i)(I) of the Clean Air Act (“CAA” 

or “Act”), which requires, in relevant part, that each state’s plan for attaining the national 

ambient air quality standards (“NAAQS”) “contain adequate provisions . . . prohibiting . . . any 

source or other type of emissions activity within the State from emitting any air pollutant in 
2 

amounts which will . . . contribute significantly to nonattainment in, or interfere with 

maintenance by, any other State with respect to any [NAAQS].” 

The Utility Air Regulatory Group (“UARG”) submits the following comments on the 

NODA. UARG is a voluntary, not-for-profit group of electric utilities, 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 CAA 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 EGUs for regulation, UARG and its members have a compelling interest in the 

present proceeding. These comments supplement comments that UARG submitted on the PTR 

on October 1, 2010, Docket ID No. EPA-HQ-OAR-2009-0491-2756.1 (“UARG’s PTR 

Comments”), which are incorporated herein by reference. 

The NODA announces EPA’s placement in the docket of this rulemaking several new 

documents and computer runs that bear directly on the PTR. For example, the NODA announces 

the placement in the docket of information on a new version of the Integrated Planning Model 

(“IPM v4.10”) that EPA is now using in the rulemaking on the Transport Rule; modeling results 

from the use of that new version; new emission inventory information; and new information on 

key cost and other assumptions to be used in EPA’s rulemaking analyses. The new information 

adds hundreds of pages of documentation to the docket for this rulemaking. The NODA 

provides a 45-day comment period, until October 15, 2010, on the new information but states, 

without explanation, that EPA will not extend the comment period on the Proposed Transport 

Rule beyond the October 1, 2010 comment deadline. 
3 

UARG reiterates its objection, made in UARG’s comments on the PTR, that Agency 

decisions have made participation in this rulemaking unreasonably and unnecessarily difficult. 

The information released pursuant to the NODA amounts to a substantially revised set of new 

data that provides at least a potential basis for changing virtually every aspect of the PTR. As 

UARG explained in its comments on the PTR, the comment period on that lengthy and complex 

proposed rule was itself inadequate, and EPA’s decision to maintain two separate but largely 

overlapping periods for public comments -- one on the PTR and the information posted in the 

docket contemporaneously with it, and another, ending only two weeks after the PTR comment 

deadline, on the information released pursuant to the NODA -- has made it extraordinarily 

challenging to provide comprehensive comments on both the PTR and the NODA. On 

September 10, 2010, EPA denied UARG’s August 19, 2010 request for an extension of the 

comment period on the PTR, and on October 5, 2010, the Agency denied UARG’s September 

10, 2010 request for a comment deadline extension for the NODA as well as for the PTR itself.1

 

In light of the significant differences between the data on which EPA based (or says it based) the 

PTR and the data EPA released later pursuant to the NODA, EPA should withdraw the PTR, 

revise the PTR using the NODA data or whatever other data EPA may now deem most 

appropriate -- while addressing as well the many other deficiencies discussed in UARG’s 

comments on the PTR and the present comments -- and publish a complete, properly supported 

proposal for public comment with an adequate comment period. 

 1

 UARG incorporates its August 19, 2010 and September 10, 2010 letters herein by 

reference. 
4 

II. The Comment Period on the NODA Is Inadequate To Allow for Adequate Public 

Review of the Extensive Material Associated with It. 

As discussed above, EPA published the NODA midway through the inadequate public 

comment period on the PTR and denied UARG’s requests for extensions of the comment periods 

on the PTR and the NODA. The NODA represents the addition of an extensive amount of new 

material to the docket for this rulemaking. For example, the new “Documentation for EPA Base 

Case v.4.10 Using the Integrated Planning Model” (“Base Case v.4.10 Documentation”) alone is 

487 pages long and includes references to several new or revised databases. See EPA, 

“Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model” (Aug. 2010), 

Docket ID No. EPA-HQ-OAR-2009-0491-0309, available at

http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html. Despite this large 

quantity of new information, the NODA provides only an additional 14 days for public comment 

beyond the comment deadline that UARG and other members of the public were required to 

meet for the PTR. This does not allow enough time for a comprehensive review of the new 

material provided, much less enough time to analyze the material, determine its implications for 

the underlying rule, and develop and submit complete comments. 

The substantial impact of the NODA on the Proposed Transport Rule was apparent in 

recent comments by EPA representatives. During an EPA webinar held on September 22, 2010, 

in response to a question regarding which aspects of the PTR would be affected by the NODA, a 

representative of EPA’s Clean Air Markets Division indicated that the information contained in 

the NODA would affect, among other things, EPA’s “significant contribution” analysis, the 

creation and evaluation of the “cost curves” in EPA’s multi-factor analysis for determining 

emission reduction obligations under the PTR, and the cost-effectiveness “breakpoints” for 

emission controls that EPA will select based on the cost curves and the multi-factor analysis. 
5 

This EPA representative acknowledged that the NODA may result in changes in EPA’s 

determinations of which states are regulated under the Transport Rule, which states will be 

classified as group 1 rather than as group 2 states with respect to additional SO2 emission control 

obligations in the second phase of the program, the emission budgets to which regulated states 

will be subject, and unit-level allowance allocations. These matters are far from tangential to 

EPA’s development of the Transport Rule. To the contrary, they go to the very heart of the 

rulemaking. Yet, EPA provided only 14 days for public comment on the NODA beyond the 

comment period on the PTR. 

Equally important, as discussed below, EPA has unreasonably withheld information 

necessary to allow UARG, members of UARG, other members of the public, and states to 

develop and provide meaningful and comprehensive comments on the NODA and on the 

Proposed Transport Rule itself. The following sections of these comments address new and 

continuing inadequacies and omissions in the record that UARG urges EPA to correct before the 

Agency continues with this rulemaking. 

III. Despite the Quantity of New Information Added to the Docket Pursuant to the 

NODA, EPA Has Failed To Provide Data Necessary To Allow Meaningful Comment 

on That Information. 

The problems associated with the unreasonably abbreviated period EPA has provided for 

comment on the voluminous and complex information issued pursuant to the NODA are 

exacerbated by EPA’s failure to provide much of the information necessary to evaluate and 

meaningfully comment on the NODA. The docket omits much of the information that is 

necessary to properly evaluate the nature and extent of the changes that are likely to the PTR 

based on the addition to the docket of the data listed in the NODA. 

In support of the PTR, EPA provided in the docket the results of 48 IPM runs. These 

runs provided the public at least some basis for evaluating and commenting on the various steps 
6 

in EPA’s process of developing unit-specific allowance allocations. In contrast, in support of the 

NODA, EPA provided the results of only eight IPM runs. Of these eight runs, four relate to an 

entirely new alternative proposal based on the Energy Information Administration’s (“EIA”) 

Annual Energy Outlook 2010 natural gas resource assumptions -- leaving only four IPM runs 

that constitute a repeat of runs used to support the PTR. The paucity of IPM runs that EPA has 

provided with the NODA, using the revised National Electric Energy Data System (“NEEDS”) 

inventory and IPM v.4.10 frustrates the public’s ability to comment knowledgeably on the 

effects on the PTR of the updated NEEDS database and IPM platform. See section VII infra. 

Despite EPA’s limited use of the revised NEEDS inventory and IPM model in the allowance 

allocation step of its analysis,2 EPA still has not provided the IPM runs necessary for electric 

generating companies and others, including states, to understand and comment knowledgeably 

on the impact of the NODA on statewide emission budgets and unit-specific allocations. 

In addition to failing to provide many critical updated IPM runs using the NODA 

information, EPA has failed to provide key summary tables that it did provide in conjunction 

with the PTR. The key summary tables provided in support of the PTR include the “Allocation 

Table - Technical Support Document for the Transport Rule - State Budgets, Unit Allocations, 

and Unit Emission Rates” (EPA-HQ-OAR-2009-0491-0057.1) and the “Detailed Unit-Level 

Data for State-Budgets, Unit Allocations, and Unit Emission Rates” (EPA-HQ-OAR-2009-0491-

 2

 UARG notes that, as it states in its comments on the PTR, EPA lacks authority under 

the CAA to impose unit-specific allowance allocations because the CAA “left to the states ‘the 

power to [initially] determine which sources would be burdened by regulation and to what 

extent.’” Michigan v. EPA, 213 F.3d 663, 686 (D.C. Cir. 2001) (quoting Union Elec. Co. v. 

EPA, 427 U.S. 246, 269 (1976)) (alteration and emphases in original); see also Virginia v. EPA, 

108 F.3d 1397, 1408 (D.C. Cir. 1997) (same). See UARG’s PTR Comments at 19-27 

(discussing the ways in which the PTR upsets the statutorily established relationship between the 

federal government and the states with respect to development of plans to address interstate 

pollution control under the CAA). 
7 

0074.1). In the PTR, these tables provided important guidance regarding a unit’s allowance 

allocations under the PTR and provided electric generating companies at least some ability to 

evaluate the accuracy of EPA’s assumptions (or apparent assumptions) with respect to their 

individual units. For reasons that UARG explained in its comments on the PTR, EPA’s 

calculation of allowance allocations in the PTR was hardly a model of clarity. But EPA’s failure 

to provide with the NODA tables comparable to the above-described PTR tables leaves UARG 

members and other electric utilities and electric generating companies even further in the dark 

about what their unit allowance allocations will be, based on the outcome of EPA’s 2012 

allowance allocation determinations using the updated NEEDS database and the updated IPM 

platform. 

Perhaps the single most important file EPA did not provide with the NODA was a file 

comparable to the PTR “Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit 

Emission Rates” (EPA-HQ-OAR-2009-0491-0074.1) (an Excel spreadsheet entitled 

“BADetailedData.xls”). Without this file, electric generating companies cannot determine the 

impact of the NODA on their allowance allocations. Although EPA did provide a new “IPM 

Run – TR Base Case v.4.10 – 2012 Parsed File” and a new “IPM Run-TR SB Limited Trading 

v.4.10 – 2014 Parsed File,” without critically important additional information, electric 

generating companies cannot calculate the SO2 or NOx allowance allocations for their units for 

2012 or (where applicable) 2014. 

EPA made “adjustments” to the IPM-projected unit-specific emissions for 2012, and 

provided these adjustments in the BADetailedData.xls file for the PTR. See BADetailedData.xls 

at the “Adjustments” tab. In addition to providing these EPA adjustments to the IPM results, the 

BADetailedData.xls file provided the projected unit-specific operating parameters (e.g., heat 
8 

rates, emission rates, and controls) in one location, allowing electric generating companies to 

check EPA’s assumptions and better understand how EPA calculated each unit’s allocations. 

The BADetailedData.xls file also clarified whether a state’s annual 2012 NOx and SO2 unit 

allocations and seasonal NOx unit allocations were based on reported data or on the 2012 IPM 

projections. As described in EPA’s Technical Support Document (“TSD”) on “State Budgets, 

Unit Allocations, and Unit Emissions Rates” (“State Budgets TSD”),3 EPA based the 2012 

budgets (annual SO2 and NOx and seasonal NOx) on the lower of the recent actual emissions 

(essentially the 2009 reported emissions for existing units, aggregated by state) or the 2012 IPMprojected base case emissions at the state level. In the BADetailedData.xls file, EPA indicated 

which emission amount was lower for each state and, thus, whether the 2009 “reported” emission 

amount or the 2012 “projected” emission amount served as the basis for the allowance 

allocations in that state. Without the BADetailedData.xls file, it is not possible to determine 

from the NODA the statewide budgets and the unit allowance allocations for 2012.4

 EPA should 

not proceed further with this rulemaking until it has provided this critical information for public 

review and comment. 

In addition to not providing information needed to evaluate the effects of the NODA on 

state budgets and unit allowance allocations, EPA states in the NODA that it intends to change 

the NOx emission rates used in its calculations again before it takes final action in this 

rulemaking: 

 3

 EPA, “State Budgets, Unit Allocations, and Unit Emissions Rates” TSD (July 2010), 

Docket ID No. EPA-HQ-OAR-2009-0491-0057, available at

http://www.epa.gov/airquality/transport/pdfs/TSD_StateBudgets_July152010.pdf. 

4

 Counsel for UARG e-mailed EPA’s Clean Air Markets Division to request information 

regarding whether there was any way to calculate the 2012 statewide budgets from the 

information provided with the NODA, but EPA never responded to that request. 
9 

EPA intends to update the NOx rates for fossil-fuel fired units in the final 

rule to reflect the more recent 2009 data. IPM v.4.10 and the previous 

version of IPM used for the Proposed Transport Rule analysis relied on 

2007 unit level NOx rates. The updated NOx rates will more accurately 

portray the unit level control installations that have occurred at power 

plants during the past several years.5

These changes in the NOx rates will result in additional changes to the final unit-level allowance 

allocations. Electric generating companies will have no opportunity to review the new NOx 

rates assigned to their units and, thus, no opportunity to evaluate whether EPA made correct 

adjustments. Thus, EPA should also provide this information for public review and comment 

before proceeding to final action. 

 For the reasons discussed above and in UARG’s PTR Comments, the proposed NOx and 

SO2 allocations are likely to change due to a number of factors, including the many errors and illfounded assumptions contained in NEEDS and IPM and reflected in the NODA information. 

EPA will presumably make at least some of the corrections requested in comments on the PTR 

and NODA. Fluctuation of allowance allocations prevents electric generating companies from 

planning for the future, which further exacerbates the problems associated with the extremely 

compressed schedule under EPA’s proposal for installation of controls -- a matter discussed in 

detail in UARG’s PTR comments. 

In a stakeholder meeting held shortly after EPA issued the PTR but before its publication 

in the Federal Register, EPA requested that electric generating companies provide detailed 

comments correcting any inaccurate data or ill-founded assumptions that EPA made with respect 

to specific units. Publication of the NODA, which changes much of the information and many of 

the assumptions on which the PTR was based, has required electric generating companies to start 

over and to attempt, at considerable cost and with great difficulty, to repeat the same process -- 

 5

 75 Fed. Reg. at 53614/3 - 53615/1. 
10 

to the extent it is even possible to do so based on the limited and incomplete information 

provided by EPA. Yet EPA has, without explanation, failed to provide the information that 

would be necessary for companies to complete reviews similar to those that they undertook with 

respect to the PTR. Without the detailed information regarding key IPM runs and the 

assumptions associated with statewide budgets and unit-specific allocations discussed above, 

electric generating companies lack the information necessary to comment meaningfully on the 

impact of the NODA on the PTR. Thus, EPA has failed to provide an adequate opportunity for 

public review and comment on its proposal. 

IV. EPA’s Decision To Base 2014 SO2 Allowance Allocations for Units in Group 1 States 

on the Same State-Level Emission Caps Used in the PTR -- Even Though Revised 

Data and an Updated Modeling Tool Were Available -- Is Arbitrary and 

Unjustified. 

The primary purpose of the NODA was ostensibly to announce “an updated version of 

the power sector modeling platform that EPA proposes to use to support the final rule . . . 

consist[ing] of updated unit level input data ( [NEEDS v4.10]) and a set of model run results 

with the updated modeling platform ([IPM] v4.10).”6

 The “set” of model run results that EPA 

elected to provide pursuant to the NODA was, in fact, seriously deficient, for reasons discussed 

in these comments. With respect to UARG’s comments in section VII below, which urge EPA 

to redo its entire analysis using the updated NEEDS database and revised IPM platform, EPA’s 

decision not to provide an updated “TR SO2 2000” IPM run, using the revised database and 

modeling platform, to establish new proposed 2014 SO2 state budgets provides one of the 

clearest example of the flaws in EPA’s process. 

EPA stated in its State Budgets TSD that “[g]roup 1 state budgets are based on reductions 

projected to be cost-effective at $2000 per ton of SO2 . . . [based on] . . . the IPM run [i.e., TR 

 6

 75 Fed. Reg. at 53613/1 (emphasis added). 
11 

SO2 2000].”7

 EPA did not state directly in the NODA that this critically important run would be 

omitted from the new data “set,” but it got that point across nonetheless: 

These policy runs [i.e., the limited set of runs that EPA provided] include 

the same State-level caps that EPA modeled in the Proposed Transport 

Rule. The caps have not been modified to account for any changes that 

the new modeling might suggest; they are merely provided for 

informational purposes to allow commenters to understand the impact that 

changes in the model platform have on the projected impacts of the caps.

8

The “State-level caps” to which EPA apparently refers, i.e., the 2014 SO2 budgets for group 1 

states, are the results of the TR SO2 2000 IPM run. The results of that run are input to the IPM 

Run – TR SB Limited Trading – Summary Report run and the unit-level parsed file for 2014. 

The practical effect of holding the 2014 SO2 budgets for group 1 states constant and re-running 

the TR SB Limited Trading runs with the updated NEEDS database and IPM platform is that an 

individual unit’s percentage of the state budget changes but the state budget does not -- i.e., a 

unit’s share of the “pie” changes but the size of the pie (artificially) remains the same. It would 

be far more relevant and more useful for electric generating companies (and states) to have 

access not only to the information provided with the NODA but also to a model run that 

demonstrates the effects of the updated database and modeling platform on the size of the state 

budgets. EPA must have known that “new modeling” of state budgets based on the updated 

NEEDS and IPM platform would not merely “suggest” revised emission caps9

 -- that new 

modeling in fact would plainly result in establishment of new caps at levels different from those 

proposed under the PTR. EPA provides no justification for its decision not to provide a TR SO2 

2000 IPM run using the updated NEEDS database and IPM platform. In short, EPA’s decision 

 7

 State Budgets TSD at 10. 

8

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

9 Id.
12 

to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database 

and updated IPM platform while leaving state budgets the same -- based on the unrevised data 

and IPM platform used in the PTR -- is illogical and arbitrary. 

Although EPA’s failure to provide the updated 2014 SO2 budgets for group 1 states based 

on IPM v.4.10 undermines the public’s ability to understand the impact of the updated NEEDS 

database and IPM platform on the state-level caps for 2014, even a cursory comparison of the 

limited set of new IPM runs provided with the NODA demonstrates that the impact of the 

updated NEEDS database and updated IPM platform must be significant. Among the few IPM 

runs based on the updated NEEDS database and updated IPM platform that EPA did provide in 

the NODA are the TR SB Limited Trading Summary reports for 2012, 2015, 2020, and 2030. 

The following comparisons of these reports with reports based on the corresponding IPM run 

using the earlier versions of NEEDS and IPM illustrate the dramatic impacts of using the new 

information: 

• The total projected demand for power in 2015 is reduced by 230 GWh -- from 

4,333 GWh in the PTR to 4,103 GWh in the NODA. 

• The PTR projected 23.7 GW of new generation capacity from coal and 2.3 GW of 

new generation capacity from wind by 2015. The NODA projects only 2 GW of 

new generation capacity from coal and 22 GW of new generation capacity from 

wind by 2015 -- almost the exact inverse of EPA’s projection for these two energy 

sources in the PTR. 

• The PTR projected a total of 80.3 GW of flue gas desulfurization (“FGD”) unit 

retrofits by 2015, while the NODA projects a total of only 49 GW of FGD 

retrofits by 2015.10 

These very substantial changes in EPA’s projections of the demand for power, the projected mix 

of new generation capacity, and projected pollution control retrofits suggest that it would be 

 10 Compare “IPM Run – TR SB Limited Trading – Summary Report” (EPA-HQ-OAR2009-0491-0088) with “IPM Run – TR SB Limited Trading v.4.10 – Summary Report” (EPAHQ-OAR-2009-0491-0305). 
13 

reasonable to expect significant changes in the 2014 SO2 budgets for group 1 states (as well as 

the 2012 SO2 and NOx budgets) if those budgets are based on the revised versions of NEEDS 

and IPM. EPA thus should promptly provide the results of a re-run TR SO2 2000 using the new 

NEEDS and IPM versions. 

V. Several of the Revisions to NEEDS and IPM that Are Reflected in the NODA Are 

Inappropriate or Inadequately Explained. 

A. EPA’s Upward Adjustment of Its Assumption Regarding FGD Maximum 

Removal Efficiency Is Unjustified and Inaccurate. 

EPA states in its IPM v.4.10 Documentation that it assumes a maximum SO2 emission 

removal efficiency for wet FGDs of 98%, representing an increase of three percentage points 

over the maximum percentage removal assumption used in the version of IPM on which EPA 

relied in developing the PTR. Compare IPM v.4.10 Documentation at 5-2 with EPA, “Updates 

to EPA Base Case v.3.02 EISA Using the Integrated Planning Model” (“Base Case v.3.02 TSD”) 

at 8 n.3 (July 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0052, available at

http://www.epa.gov/airquality/transport/tech.html. EPA does not provide an explanation or any 

justification for this upward revision in assumed wet FGD removal efficiency, other than to say 

that, in transferring data from the EIA’s Form 767 for use in IPM v.4.10, “changes were made.” 

Base Case v.4.10 Documentation at 5-2. EPA states further that, in modeling the effects of 

installing wet FGDs, EPA assumed that the new scrubbers would operate at maximum 

efficiency. Id. (“existing units that are selected to be retrofitted by the model with [wet] 

scrubbers are given the maximum removal efficienc[y] of 98% . . . . Potential (new) coal-fired 

units built by the model are also assumed with a [wet] scrubber achieving a removal efficiency of 

98% . . . .”). In the absence of a more explicit explanation by EPA, commenters can only 

presume that this is an assumption of continuous control efficiency of 98%. It is unreasonable 

for EPA to assume that new FGDs will always operate at maximum efficiency, regardless of the 
14 

percentage of SO2 that is estimated to be removed at maximum efficiency. Equally important, 

the level at which EPA assumes wet FGDs will operate -- 98% -- is unrealistic. 

A recent study of the best-performing FGD equipment -- evaluating the removal 

performance of the ten lowest SO2 emitting units nationwide -- concluded that “none of these 

‘top performing’ wet FGD systems was able to achieve a removal efficiency of 98% or greater in 

every month of the year.” See Cichanowicz, J.E., “Overview of Information on Projected 

Control Technology Costs and Performance as Developed for EPA’s Integrated Planning Model 

(IPM),” at 4 (Oct. 15, 2010) (hereinafter “Cichanowicz Report”)11 (quoting Weilert, C.V., et al., 

“Emissions Control Performance Achieved in Practice by Electric Utility FGD Systems in the 

United States,” at 12, proceedings of the 2010 Power Plant Air Pollutant Control MEGA 

Symposium (Aug. 30-Sept. 2, 2010, Baltimore, Maryland)). In fact, the available data suggest 

that even top-performing wet FGD units are unable to achieve consistent, annual average 

reduction levels of more than perhaps 95% to 96% SO2 removal. Id. 

EPA’s assumption that the “new” scrubbers that IPM projects will be installed in the 

coming years will operate continuously and consistently at 98% efficiency -- a level perhaps 2 to 

3 percentage points above the efficiency level that they may be likely to actually achieve on an 

annual average -- will result in an insufficient number of allowances being allocated to units 

projected to add new FGD. Thus, based on EPA’s proposal, units projected to be retrofit with 

wet scrubbers will have insufficient allowances at the start of each control year and will be 

forced to purchase allowances to make up the difference. 

This effect of EPA’s unrealistic assumption regarding the removal efficiency of new wet 

FGDs is exacerbated by the fact that EPA proposes to reduce allowance allocations by 3% to 

 11 The Cichanowicz Report was prepared to support these comments. It is attached and is 

incorporated herein by reference. 
15 

create an allowance set-aside for new units before distributing allowances to existing units. See

75 Fed. Reg. at 45309/1. Given that EPA plans to set aside 3% of each state’s allowance budget 

for new units and distribute the remaining 97% among existing units, the Agency should be all 

the more careful to avoid making unrealistically aggressive assumptions regarding removal 

efficiency.12 

EPA should adjust its assumption regarding the control efficiency at which new scrubbers 

will operate to reflect a more realistic annual-average maximum-removal assumption of 95% to 

96% and recalculate state budgets and unit-level allocations accordingly. 

B. Units with Generating Capacity Less than 100 MW Cannot Properly Be 

Assumed To Be Candidates for Installation of FGD or SCR. 

EPA explains in its Base Case v.4.10 Documentation that IPM v.4.10 assumes that units 

with generating capacities between 25 MW and 100 MW are candidates for installation of FGD 

and selective catalytic reduction (“SCR”).13 However, in the base case for the PTR, EPA 

assumed that “coal-fired EGUs under 100 MW capacity [did] not have the option of retrofitting 

FGD or SCR.” Base Case v.3.02 TSD at 20 (emphasis added). EPA fails to provide any 

plausible explanation for changing this assumption. 

In fact, EPA’s new assumption that units with capacities between 25 MW and 100 MW 

can be retrofit with FGD and SCR is unrealistic. In many cases, it is impossible to retrofit units 

 12 The same point applies to assumptions regarding other emission controls, including 

NOx controls. 

13 Base Case v.4.10 Documentation at 5-13. For modeling purposes, IPM v.4.10 

effectively assumes that the cost of adding emission controls to units in this MW range is 

equivalent to the cost of adding controls to a 100 MW unit. This assumption is based on the 

notion that several small units are likely to be ducted to share a common control, and that single 

units that are not ducted are likely to have the option of installing hybrid multi-pollutant controls, 

which are currently under development. Id. at 5-13 to 5-14; see also Cichanowicz Report at 10-

11 (discussing treatment of smaller units in control-cost analysis). 
16 

with capacity below 100 MW with FGD and SCR. And in cases where it is technically possible 

to do so, it would rarely, if ever, be cost-effective. EPA acknowledged in its Base Case v.3.02 

TSD that “FGD and SCR retrofits to such small units are very costly in any case.” Id. The 

emission reduction (and air quality improvement) benefits to be gained from such a large 

expense are quite limited due to the low emission amounts from “such small units.” Thus, even 

in cases where below-100 MW units theoretically could be retrofit with FGD or SCR, it would 

not be an economic choice to do so, at least in the great majority of cases. 

EPA should recalculate its base case emission inventories to remove the assumption that 

small units, with capacities between 25 MW and 100 MW, can be retrofit with FGD and SCR. 

At a minimum, EPA should explain its reasoning for changing its assumption regarding small 

unit retrofits in the NODA. 

C. EPA May Well Be Understating SCR Capital Costs. 

UARG supports EPA’s decision to retain Sargent & Lundy (“S&L”) to estimate control 

technology costs for the Proposed Transport Rule based on S&L’s database of component costs 

and installation charges. Using a firm that specializes in determining the average costs of 

installation, operation, and maintenance of electric power generation and emission control 

equipment is likely to produce data that is more accurate than if EPA had pursued certain other 

cost-estimation approaches. See Cichanowicz Report at 1. 

Although UARG believes that many of S&L’s cost estimates are reasonable and likely to 

be accurate, or close to accurate, see generally id., S&L’s projected capital cost of adding SCR 

appears likely to be an underestimate. See id. at 7-9 (describing differences between S&L’s 

estimates and those provided as a result of a recent UARG survey and discussing possible 

reasons for those differences). 
17 

This apparent underestimate of SCR costs can affect the calculations and assumptions on 

which EPA relies in the Proposed Transport Rule, including the creation and evaluation of cost 

curves in EPA’s multi-factor analysis for determining emission reduction obligations under the 

PTR and the selection of “breakpoints” for emission controls, based on the cost curves. 

Furthermore, the S&L estimates reflected in the NODA differ from the control cost estimates 

that EPA used for its analyses in the PTR. EPA’s use of these different cost estimates will affect 

EPA’s analyses, regardless of whether the new cost estimates are more or less accurate than the 

estimates used for the PTR. See also section VII infra. EPA should therefore revise its analyses 

using appropriate control cost estimates and allow for public comment on the results. 

D. EPA’s Revised NEEDS Database and IPM Platform Still Contain Numerous 

Errors and Have Introduced Additional Inaccurate Assumptions. 

As discussed in section VIII of UARG’s comments on the PTR, NEEDS v.3.02 and IPM 

v.3.02 contained many inaccurate inputs, in the form of errors in NEEDS, inaccurate IPM 

constraints, and inaccurate outputs. Despite the limited time provided for UARG members to 

check the accuracy of the “updated” NEEDS v.4.10 and IPM v.4.10, UARG and its members 

have discovered that it appears that EPA has introduced additional errors and inaccurate 

assumptions in the updated versions, while leaving many earlier problems uncorrected. As 

illustrated by the discussion in section V.A supra, certain systemic adjustments to EPA’s 

assumptions regarding new FGD control efficiencies are inconsistent with real-world experience 

and would result in inadequate allowance allocations. Moreover, unit-specific examples of 

changed assumptions are provided below. In addition to the same categories of errors and 

assumptions catalogued in UARG’s comments on the PTR, new assumptions in IPM v.4.10 

regarding fuel prices and the cost of control technologies appear to have resulted in a new 
18 

category of errors -- errors related to, for example, the retirement of coal-fired units and the 

controls that existing units are projected to install.14 

Examples of errors and incorrect assumptions in NEEDS v.4.10 include: 

• NEEDS v.4.10 reports that Units 1-3 at the Baldwin Energy Complex in Illinois are 

currently equipped with wet FGD systems. That is incorrect. As a result of a consent 

decree, Unit 1 is required to install a dry FGD system by the end of 2011, Unit 2 is 

required to install a dry FGD system by the end of 2012, and Unit 3 is required to install a 

dry FGD system by the end of 2013. NEEDS also assumes a 98% removal efficiency for 

wet FGD, which, for reasons set forth above, could not be assumed to be achievable on 

an annual basis even if these units were to install wet rather than dry FGD. 

• NEEDS v.4.10 reports that Units 1-3 at the Baldwin Energy Complex in Illinois are 

currently equipped with cold-side electrostatic precipitators (“ESPs”) and baghouses. 

This is incorrect. Although these units are currently equipped with ESPs, Unit 1, Unit 2, 

and Unit 3 are not required to construct baghouses until the end of 2011, 2012 and 2013, 

respectively. 

• NEEDS v.4.10 reports that Units 1 and 2 at the Baldwin Energy Complex in Illinois have 

an uncontrolled NOx rate of 0.0723 lb/mmBtu. Based on continuous emission 

monitoring system (“CEMS”) data previously reported to EPA, the uncontrolled rate of 

these units is 0.61 lb/mmBtu. 

• NEEDS v.4.10 reports that Unit 9 at the Havana Station in Illinois has an uncontrolled 

NOx rate of 0.0723 lb/mmBtu. Based on CEMS data previously reported to EPA, the 

uncontrolled rate of this unit is 0.61 lb/mmBtu. 

• NEEDS v.4.10 reports that Unit 2 at the Ghent facility in Kentucky had an SCR installed 

as of 2009. That unit does not have an SCR, and installation of SCR is not planned at 

that unit. 

• NEEDS v.4.10 reports that two units at the Armstrong power station in Pennsylvania 

have installed selective noncatalytic reduction (“SNCR”). A Mobotech Rotamix system 

was installed in 2003 in an effort to reduce NOx, but the equipment was ineffective and 

was removed. 

• NEEDS v.4.10 reports FGD removal efficiency at the Mitchell power station in 

Pennsylvania as 99.9% and at the Pleasants power station in West Virginia as 97%. 

These removal efficiencies are incorrect. Actual removal efficiency at the Mitchell 

 14 For additional discussion of issues associated with retirement of coal-fired generation 

and erroneous control assumptions for coal-fired generation, see Comments of the Midwest 

Ozone Group on the NODA. 
19 

power station averages 97% and actual removal efficiency at the Pleasants power station 

averages 95%. 

Examples of errors in IPM outputs and erroneous IPM inputs include: 

• IPM v.4.10 reports in both the TR_SB_Limited_Trading parsed files that the primary fuel 

for Units 1 and 2 at the Danskammer power station in New York is natural gas. The 

primary fuel for both units is oil. 

• IPM v.4.10 reports in both the TR_SB_Limited_Trading parsed files that the primary fuel 

for Units 1 and 2 at the Roseton power station in New York is natural gas. The primary 

fuel for both units is oil. 

• IPM v.4.10 reports NOx controls for Unit 4 at the Scherer power station in Georgia 

consisting of low NOx burners and separated overfire air. This is inaccurate -- only 

overfire air is installed at that unit. 

• IPM v.4.10 reports in the 2014 TR_SB_Limited_Trading parsed file that the coal-fired 

Unit 3 at the Sibley power station in Missouri will retire early. SCR was installed in 

2009, making it highly unlikely that the unit will retire in or by 2014. 

• IPM v.4.10 reports in the 2014 TR_SB_Limited_Trading parsed file that the coal-fired 

Mount Tom power station in Massachusetts will retire early. Dry FGD was installed in 

2009, making it highly unlikely that that facility will retire in or by 2014. 

• IPM v.4.10 reports in the 2014 TR_SB_Limited_Trading parsed file that the coal-fired 

Unit 4 at the Indian River power station in Delaware will retire early. Installation of dry 

FGD is planned for 2012, making it unlikely that the unit will retire in or by 2014. 

The specific errors cited above are provided as examples of the types of mistakes found 

in the updated NEEDS and IPM modeling -- they represent a mere sampling of the problems 

found by electric generating companies. In order to provide an adequate opportunity to comment 

on proposed unit-level allowance allocations, EPA should correct these errors and publish a 

revised allocation table for comment. 

In addition to the flawed IPM outputs for specific units, other outputs provided on a 

regional scale in the IPM Run – TR SB Limited Trading v.4.10 – Summary Report do not seem 

plausible and call into question the accuracy and validity of the modeling results. Two examples 
20 

are (1) IPM’s forecast for additional wind generation by 2015 and (2) IPM’s projected SO2

allowance price. 

As mentioned above, the IPM Run – TR SB Limited Trading – Summary Report 

projected 23.7 GW of new generation capacity from coal and 2.3 GW of new generation capacity 

from wind in 2015. The IPM Run – TR SB Limited Trading v.4.10 – Summary Report projects 

only 2 GW of new generation capacity from coal and 22 GW of new generation capacity from 

wind in 2015. The magnitude of the projected increase in predicted new wind generation 

between successive versions of the model calls into question the validity of the model results. In 

any event, even if there is some “logical” justification for IPM’s projection of 22 GW of new 

wind generation, there are certain practicalities that make that projection doubtful. As of January 

1, 2010, the total installed wind generation capacity in the United States stood at 35 GW.15 IPM 

predicts that 21 of the 22 GW of projected new wind generation will be online by 2012. Thus, 

the additional wind generation that EPA projects would constitute a 60% increase in the United 

States capacity in approximately three years.16 Considering that the average-sized wind farm in 

2009 had generation capacity of 91 MW,17 that would mean that approximately 231 averagesized wind farms would have to be permitted and built by 2012. According to the American 

Wind Energy Association, it takes approximately 18 months to two years to permit and build 

 15 U.S. Department of Energy, “2009 Wind Technologies Market Report” at iii (Aug. 

2010) (“2009 Wind Report”), available at http://www1.eere.energy.gov/windandhydro/. 

16 IPM results provide no indication of where this additional wind generation will be 

located. Thus, there is no way to determine whether it will be located within the states regulated 

by the PTR. 

17 2009 Wind Report at v. 
21 

even relatively small (50 MW) wind farms.18 The dramatic change in generation mix between 

successive versions of IPM and practical considerations of actually permitting and building that 

many new wind farms in a very short period call for explanation and additional justification by 

EPA of this very substantial change in its projections. 

Finally, the IPM Run – TR SB Limited Trading v.4.10 – Summary Report provides 

estimates of SO2 allowance prices for group 1 and group 2 states at $313 and $184, 

respectively.19 Although it is not possible to compare these prices to projections from the IPM 

Run – TR SB Limited Trading – Summary Report because allowance price projections were not 

provided in that report, a report by James Marchetti for the Midwest Ozone Group (“MOG”) and 

submitted with MOG’s comments on the NODA notes that the cost in 2015 of SO2 allowances in 

a group 1 state under an intra-state-only trading regime was estimated at approximately $1,900 

per allowance.20 At best, this analysis demonstrates that the IPM projection of 2015 SO2

allowance prices is considerably underestimated. At worst, this analysis suggest a flaw in IPM’s 

methodology. 

VI. In Making the Changes Represented in the NODA, EPA Continues To Ignore the 

Effects of CAIR and Local Controls. 

EPA indicates that IPM v.4.10 takes into account all existing federal and state air 

emission regulations (except for CAIR), as well as new source review (“NSR”) and other 

settlements, that were in effect or were final as of August 2010. Base Case v.4.10 

 18 See “Wind Energy Basics” from the American Wind Energy Association, available at

http://www.awea.org/faq/wwt_basics.html. 

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

20 See Marchetti, J., “Final Report: MOG Comments on the NODA,” at 9-10 (Oct. 15, 

2010), submitted to the docket for this rulemaking as an attachment to MOG’s comments on the 

NODA. 
22 

Documentation at 1-1.21 By contrast, the previous version of IPM, used to model the PTR, took 

into account these same factors effective as of February 3, 2009. 75 Fed. Reg. at 45243/2. 

Despite this updating by about 18 months with respect to EGU emission limitations, EPA in the 

NODA improperly continues to ignore the effects of CAIR and local emission controls, 

including controls affecting emissions from non-EGU point sources and nonpoint stationary 

sources. 

A. EPA Should Have Considered the Effects of CAIR. 

As UARG explained in its comments on the PTR, EPA should have included CAIR in its 

base case modeling because it remains binding law until it is replaced by a valid rule. See

UARG’s PTR Comments at 50-53. According to the terms of the D.C. Circuit’s December 2008 

opinion on rehearing in North Carolina v. EPA, CAIR will remain binding law until a new rule is 

in place. Thus, it is appropriate for EPA to conclude in this rulemaking that there will be no time 

when neither CAIR nor a CAIR replacement rule will be in effect. See id. at 50-51. 

Additionally, EPA has not demonstrated that EGUs in the few states that were regulated under 

CAIR but may not be regulated under the Transport Rule, as proposed, are likely to increase their 

emissions when CAIR expires, or that such increases would be permitted under state law. In 

reality, these EGUs have already made reductions pursuant to CAIR and it is very unlikely that 

they will increase their emissions to pre-CAIR levels once CAIR expires. Based on these 

factors, as well as the downward trend that EPA has acknowledged in PM2.5 and ozone 

 21 See also Base Case v.4.10 Documentation at Appendix 3-2 (“State Power Sector 

Regulations [I]ncluded in EPA Base Case v.4.10”), Appendix 3-3 (“[NSR] Settlements in EPA 

Base Case v.4.10”), Appendix 3-4 (“State Settlements in EPA Base Case v.4.10”), Appendix 3-5 

(“Citizen Settlements in EPA Base Case v.4.10”), Appendix 3-6 (“Renewable Portfolio 

Standards in EPA Base Case v. 4.10”). 
23 

concentrations nationwide,22 it is far more realistic to assume that CAIR applies than it is to 

assume that it does not. See UARG’s PTR Comments at 52-53. 

B. EPA Should Have Considered the Effects of Local Controls. 

UARG also explained in its comments on the PTR that EPA’s proposal improperly failed 

to account for local emission controls. Section 107(a) of the CAA 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. § 7407(a). See UARG’s PTR Comments at 64-66. Thus, 

EPA’s proposal to promulgate and implement a rule that regulates sources of transported 

pollutants without considering the effects of local controls, see 75 Fed. Reg. at 45226/3, is 

contrary to the Act. EPA attempted to explain its failure to account for local controls in the PTR 

by asserting that “nonattainment areas for the 1997 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 (“Emissions TSD”) at 11 (June 2010), Docket 

ID No. EPA-HQ-OAR-2009-0491-0050, available at

http://www.epa.gov/airquality/transport/tech.html. As UARG noted in its comments on the PTR, 

however, the unavailability of this information in 2005 does not explain EPA’s failure to account 

for it in its future base case projections. See UARG’s PTR Comments at 65 n.39. Again, despite 

the many updates reflected in the NODA, EPA fails to account for local controls. EPA must 

consider the effects of local controls on its modeling and on air quality and attainment and 

interference with maintenance of the NAAQS. 

 22 See EPA, “Our Nation’s Air Status and Trends Through 2008,” 1-2 (Feb. 2010), 

available at http://www.epa.gov/airtrends/2010/index.html. 
24 

 Moreover, even if one were to accept that EPA had insufficient time to account for local 

controls in the entire proposed control region before issuing the PTR, EPA could and should 

have at least considered the effects of local controls on the areas surrounding the six monitors 

with perceived maintenance problems that led to EPA’s proposed designation of the group 1 

states that are subject to additional SO2 reduction requirements in 2014. See UARG’s PTR 

Comments at 61-64 (discussing EPA’s classification of group 1 states based on six monitors with 

perceived maintenance problems). EPA certainly has the resources to consider the effects of 

local controls in the areas surrounding these six monitors.23 Such consideration of local controls 

may have eliminated the need (as determined by EPA) for additional SO2 reduction requirements 

in 2014, or at least may have reduced the number of group 1 states. 

VII. The Availability of NEEDS v.4.10 and IPM v.4.10 and the Central Role These Items 

Play in the Structure of EPA’s PTR Warrant a New or Supplemental Proposed Rule 

Based on the Results of the New Data and Modeling. 

EPA’s PTR depends in substantial measure on the validity, reliability, and accuracy of 

IPM. No other tool has as great an influence on key elements of the PTR. Indeed, the results of 

IPM runs have a direct or indirect effect on every major step in EPA’s PTR methodology. In the 

NODA, EPA acknowledged as much by stating: 

Changes from the projections relied on in the proposed rule, from using an 

updated model, could impact the final rulemaking in a number of ways 

including, but not limited to: 

 1. Changing emission projections that were used to determine 

which downwind areas have air quality concerns (i.e., non-attainment or 

maintenance) absent this rulemaking and to determine which States 

contribute to those problems. 

 2. Changing cost and emission projections used in the multi-factor 

[e.g., cost curve] test to determine the amount of emissions that represent 

significant contribution. 

 23 In fact, UARG notes that two of the six monitors are located in Allegheny County, 

Pennsylvania. Thus, EPA would have had to consider local controls in only five local areas. 
25 

75 Fed. Reg. at 53614/3. If anything, EPA understates the potential impact of the updated 

database and platform. The NEEDS inventory and the output of IPM substantially influence the 

fundamental components of the PTR: the analyses of air quality; the linkages of upwind states to 

downwind problem areas; the definition of significant contribution to nonattainment and 

interference with maintenance; and the establishment of statewide budgets and unit-specific 

allocations. 

 Despite the central role of IPM in each of these components, EPA elected to provide a 

very limited number of runs using the updated NEEDS database and revised IPM platform and 

then further qualified the import of the runs by stating that “they are merely provided for 

informational purposes to allow commenters to understand the impact that changes in the model 

platform have on the projected impacts of the caps.”24 It is unclear why EPA tries to downplay 

the potential impact of the updated NEEDS database and IPM platform when EPA clearly 

“proposes to use this version of the IPM model [IPM v.4.10] in the final Transport Rule.”25 As 

discussed in section IV above, a cursory comparison of the NODA IPM runs with the PTR IPM 

runs demonstrates that changing the NEEDS emission inventory and using an updated IPM 

version result in significantly different outcomes. 

 UARG appreciates that entirely redoing EPA’s analysis using the updated NEEDS 

database and IPM platform takes significant time and resources. EPA should, however, conduct 

its analysis using the most current model and information at its disposal, and then should make 

all the results available to the public and allow an adequate time for public review and comment 

before taking any final action in this rulemaking. 

 24 75 Fed. Reg. 53614/3. 

25 Id. 
26 

In all its complexity, EPA’s PTR methodology can be broken down into approximately 

eight major steps. In each of these steps, IPM provides information critical to the accuracy and 

validity of EPA’s analysis. The purpose of reviewing each of these steps is to demonstrate 

EPA’s thoroughgoing reliance in this rulemaking on IPM and the importance of EPA 

undertaking a full analysis with the revised modeling tool and data, and allowing a full 

opportunity for public comment on the methodology and results of that analysis. 

The following paragraphs describe the eight major steps in EPA’s methodology, as 

reflected in the PTR, and discuss why these steps depend on IPM results: 

1. EPA created four emission inventory cases to support air quality modeling. 

EPA created four “complete” emissions cases to support its air quality 

modeling and analysis. The principal input to the Comprehensive Air Quality 

Model with Extensions (“CAMx”), which EPA used for its air quality 

modeling, is the emission inventory for each source sector. EPA refers to its 

four inventory cases as the 2005 base case, the 2012 base case, the 2014 base 

case, and the 2014 control/policy case.26 These emissions cases are complete 

in that they contain estimates of emissions for each of the main source sectors: 

EGUs, non-EGU point sources, nonpoint (area) stationary sources, onroad 

mobile sources, nonroad mobile sources, and fires. The EGU portion of the 

SO2 emissions constitutes a majority of the total SO2 emissions for 2005 (e.g., 

for the 2005 base case in the PTR, 10,019,774 tons of the total 13,380,267 

tons of SO2 emissions).27 The EGU portion of the NOx emissions represents 

about a fifth of the overall NOx emissions for 2005 (3,223,184 tons of the 

total 15,943,047 tons of NOx emissions for the base case).28 For the three 

future emissions cases (the 2012 base case, the 2014 base case, and the 2014 

control/policy case), EPA relied on IPM to project the EGU portion of the 

complete emission inventory.29 Thus, IPM is the source of the emission 

 26 Emissions TSD at 6. 

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

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

29 Emissions TSD at 11, 37. 
27 

estimates for two of the most significant precursors to PM2.5 and ozone 

formation in the CAMx atmospheric modeling.30 

2. The IPM-dependent CAMx modeling was used to project future downwind 

PM2.5 and ozone nonattainment and maintenance problems. A critical first 

step in predicting future nonattainment and maintenance problem monitors for 

the annual PM2.5, 24-hour PM2.5, and 8-hour ozone NAAQS involved 

calculating the relative changes from the 2005 base case modeling results 

from CAMx to the 2012 base case model run results.31 The CAMx 

atmospheric modeling runs depend in considerable part on the IPM emission 

projections for 2005 and 2012 because those are among the most influential 

inputs to the modeling, and changes to the 2012 base case model run results 

due to changes in IPM will affect the results of this step of the analysis. 

3. EPA used IPM-dependent CAMx modeling to assess interstate contributions 

to nonattainment and maintenance. After EPA used CAMx to model future 

nonattainment and maintenance problems at downwind monitors, EPA used 

the photochemical source apportionment feature of CAMx to “quantify the 

impact of emissions in specific upwind states on air quality concentrations in 

projected downwind nonattainment and maintenance locations.”32 As 

discussed in step 1, EGU emissions make up the large majority of SO2

emissions and approximately one-fifth of NOx emissions. Consequently, one 

of the most influential emission source categories in shaping the results of the 

CAMx source apportionment modeling is the EGU source sector, whose 

estimated emissions depend on IPM projections. 

4. After establishing state linkages to downwind nonattainment and maintenance 

sites, EPA’s first step to quantify significant contribution -- i.e., creation of 

emission reduction cost curves -- depends entirely on IPM modeling results. 

EPA’s first step in “determining the quantity of emissions that represents each 

state’s significant contribution is to identify reductions available at different 

costs.”33 EPA developed “cost curves” that are intended to show the available 

emission reductions from EGUs at various dollar-per-ton cost increments. 

EPA derived the amount of emission reductions available at each cost 

 30 For this and the subsequent steps described in this section of UARG’s comments on the 

NODA, UARG recognizes that it is conceivable that EPA has used this new, updated 

information in its analyses -- but, critically, if EPA has done so, it has not disclosed that fact in 

the NODA information and has not provided the results to the public for review and comment. 

31 75 Fed. Reg. at 45246/3 - 45247/3 (annual PM2.5 methodology); id. at 45248/1 - 

45249/3 (24-hour PM2.5 methodology); id. at 45252/1-3 (8-hour ozone methodology). 

32 Id. at 45253/1. 

33 Id. at 45272/2. 
28 

increment from IPM; the cost curves are a direct output of IPM.34 The 

relevance and accuracy of the cost curves thus depend on IPM. 

5. EPA used its air quality assessment tool (“AQAT”) to estimate the air quality 

benefits of upwind emission reductions on downwind ambient concentrations 

of PM2.5 and ozone. Instead of using CAMx as a primary tool to evaluate the 

downwind benefit of upwind emission reductions, EPA created its AQAT. 

Unlike CAMx, AQAT is not a dynamic air quality model but is essentially an 

Excel spreadsheet that generates estimates of downwind ambient pollutant 

concentrations based on the amounts of emissions from an upwind state. “For 

each downwind area with a nonattainment and/or maintenance problem, it 

shows the total improvement in air quality for each cost level and associated 

pollutant reduction . . . .”35 The amount of the pollutant reduction that is 

available at each cost level is a direct output of the IPM model runs. In 

addition to the updates to the NEEDS emission inventory that is input to IPM, 

one of the changes from IPM v.3.02 to IPM v.4.10 was a “major update of 

emission control technology assumptions[],” which in turn involved changes 

to the estimates of costs associated with NOx and SO2 emission controls.36 

Consequently, in this step perhaps more than in any other, the updates 

reflected in the latest version of IPM would have produced different results. 

6. EPA evaluated the results of the IPM-dependent AQAT to establish control 

cost thresholds, or “breakpoints.” EPA evaluated the air quality benefits 

predicted by AQAT at the various cost levels on the cost curves and identified 

“breakpoints” -- “places where there is a noticeable change on one of the cost 

curves, such as a point where a large reduction occurs because a certain type 

of emissions control becomes cost-effective.”37 EPA selected a breakpoint of 

$2,000/ton for SO2 and a breakpoint of $500/ton for NOx.38 The cost curves 

and results of the AQAT would be different if EPA had used the latest version 

of IPM. When the assumed costs of control technologies change, as they did 

pursuant to the NODA information, there is every reason to believe that the 

“breakpoints,” where large emission reductions become available because a 

technology becomes cost-effective, also would change. 

7. EPA established SO2 emission budgets for group 1 states based on an IPM 

run; IPM runs also influenced 2012 state budgets for both SO2 and NOx. 

Using its cost-curve breakpoint for SO2, EPA set the group 1 statewide 2014 

 34 Id. 

35 Id. at 45273/3. 

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

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

38 Id. at 45281/2-3 (SO2); id. at 45288/2 (NOx). 
29 

SO2 emission budgets based on the emission reductions projected to be costeffective at $2,000 per ton of SO2. The state budgets were a direct output 

from a single IPM run, referred to as “TR SO2 2000.”39 The 2012 SO2 and 

NOx budgets are also influenced by the NEEDS inventory and IPM because 

EPA calculated budgets based on the operation of existing controls, controls 

that EPA projects to be operational by 2012, and EPA-projected switches to 

lower-sulfur coal.40 The calculation of these budgets is dependent on the 

accuracy of both the NEEDS emissions inventory and the IPM assumptions 

regarding when installation or use of various controls is economical and the 

level of emission reductions that can be achieved by those controls. 

8. EPA established unit-specific NOx and SO2 allowance allocations. For units 

in group 1 states, EPA established 2014 unit-specific SO2 allocations as “a 

proportional share of the state’s budget based on projected SO2 emissions 

from fossil-fired greater than 25 MW capacity units in the [2014] TR SB 

Limited Trading IPM run, as apportioned to the unit level in the 2014 parsed 

file” (minus 3% of the emissions that EPA allocated to establish the new unit 

set-asides).41 EPA based the 2012 unit-specific allocations for annual SO2

emissions, annual NOx emissions, and seasonal NOx emission on the lower of 

either the most recent actual reported cumulative emissions from all affected 

EGUs within a state or the cumulative 2012 IPM base case projection for each 

state. “The proposed unit-level allocations are calculated analogous[ly] with 

the way each state budget is calculated -- each unit receives a proportional 

share of its state budget based on that unit’s share of state emissions assumed 

in developing the budget [minus 3% to establish the new unit set-aside].”42 If 

a state’s 2012 budget was based on the IPM 2012 projection (because the 

state’s 2012 projected emissions were lower than its actual reported 

emissions), then the individual allocations for units in that state were based on 

the projected emissions for units in the same IPM Run-Parsed File SB Limited 

Trading run that contained the 2012 unit-level emissions. Yet, without 

offering any particular explanation as to why it replicated certain portions of 

this step using the new IPM version even though it did not do so for earlier 

steps, EPA recalculated the 2014 unit-level SO2 emissions for units in group 1 

states in a new “SB Limited Trading v.4.10 – 2014 Parsed File”43 -- but 

 39 State Budgets TSD at 10. 

40 75 Fed. Reg. at 45290/3. The State Budgets TSD clarifies that the 2012 NOx and SO2

“budgets are the lower of the recent actual emissions [approximately 2009] or projected base 

emissions, at the state level.” State Budgets TSD at 9. 

41 State Budgets TSD at 12. 

42 Id. at 11. 

43 IPM Run – TR SB Limited Trading v.4.10 – 2014 Parsed File (EPA-HQ-OAR-2009-

0491-0312). 
30 

apparently limited by the original proposed state emission budgets derived 

from the PTR IPM-based TR_2000_SO2. Without explanation, EPA elected 

not to provide for public review and comment the parsed results for 2012 unitspecific emissions based on the updated NEEDS database and IPM platform. 

As the discussion above indicates, at every major step in EPA’s methodology -- e.g., 

creating emission inventory cases as inputs to CAMx modeling, projecting future nonattainment 

and maintenance problem areas, establishing linkages of upwind states to downwind 

nonattainment and maintenance problem areas, defining significant contribution to 

nonattainment and interference with maintenance, and establishing unit-specific allocations -- 

IPM played an indisputably critical role in ultimately determining unit-specific allowance 

allocations. 

Although EPA states in the NODA that it proposes to use IPM v.4.10 (along with 

NEEDS v.4.10) “in the final Transport Rule,”44 the NODA is unclear as to exactly where and 

how EPA intends to use it. EPA should clarify these issues for the public and should revisit the 

basis for its proposal if it intends to proceed with this rulemaking and to continue to use its 

proposed approach to implementing section 110(a)(2)(D)(i)(I) of the Act. In doing so, EPA 

should redo each step of its methodology as described above using the updated NEEDS 

inventory and IPM platform. EPA then should issue the results of its new analysis for public 

review and comment, providing an adequate comment period. 

 44 75 Fed. Reg. at 53614/3. 
OVERVIEW OF INFORMATION ON PROJECTED CONTROL TECHNOLOGY  

COSTS AND PERFORMANCE  

AS DEVELOPED FOR EPA’S INTEGRATED PLANNING MODEL (IPM) 

October 15, 2010 

Prepared by 

J. Edward Cichanowicz 

Prepared for the 

Utility Air Regulatory Group 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

1 

OVERVIEW OF INFORMATION ON PROJECTED CONTROL TECHNOLOGY  

COSTS AND PERFORMANCE  

AS DEVELOPED FOR EPA’S INTEGRATED PLANNING MODEL 

INTRODUCTION 

This document reviews and responds to information on projected SO2 and NOx 

control technology costs as developed by Sargent & Lundy Engineers (S&L) for the 

Environmental Protection Agency (EPA), for use in a new version (v.4.10) of the 

Integrated Planning Model (IPM), and as reported by EPA (EPA, 2010a).  S&L’s 

information on costs and performance is reviewed and compared to other recent 

data derived for similar control technologies.  For example, S&L’s cost data are 

compared to cost data developed in a 2009 survey of utility industry operators and 

reported by the Utility Air Regulatory Group (UARG, 2010).  S&L’s information on 

the performance of control technologies is evaluated and compared to other recent 

data, including data from a recent study of the best‐performing wet and dry FGD 

equipment (Weilert, 2010).   

The control technologies addressed are wet and dry flue gas desulfurization (FGD) 

for control of SO2; and selective catalytic reduction (SCR), selective non‐catalytic 

reduction (SNCR), and combustion controls for control of NOx.  (The referenced EPA 

report also address costs for control of mercury (Hg), but the cost of equipment for 

reducing Hg emissions is not reviewed in this analysis.) 

APPROACH 

EPA’s approach to acquiring cost data for use in v. 4.10 of IPM is very different from 

the approach the Agency took in conducting past studies to develop the same 

information.  In the present case, EPA engaged S&L to develop such inputs.  

Historically, EPA either derived such costs with internal staff, after discussions with 

control equipment suppliers, or employed contractors that had limited access to 

information on equipment cost and performance.  By engaging an 

architectural/engineering firm with broad experience working with electric 

generating companies, EPA accessed an authentic database of component and 

installed costs.  

S&L applied their in‐house database of control technology component costs and 

their knowledge of installation requirements and maintenance duties to project 

realistic cost estimates.  S&L then used this database to estimate fixed and variable 

O&M costs for the different categories of control technology.  Once the size of the 

control equipment was determined, and the coal composition was considered, S&L 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

2 

applied conventional cost indices for installation of delivered equipment to 

determine final costs.  This approach replicates the steps in a commercial project. 

Table 5‐3 in the S&L report lists the factors considered in the cost evaluation.  This 

table comprises a representative and comprehensive list. 

S&L note that by adopting these most recent cost estimates into the IPM, EPA is 

apparently accepting that the escalation in capital costs for control equipment that 

was experienced in 2009 is permanent, with costs not expected to revert to levels 

preceding the 2009 installation window.  Such an approach (EPA’s adoption of the 

S&L projected costs into the IPM) is consistent with UARG’s projection of FGD and 

SCR capital costs (UARG, 2010). 

The following sections describe and evaluate S&L’s data concerning the cost and 

performance of control technology for removing sulfur dioxide (SO2) and nitrogen 

oxide (NOx) emissions from power plants.   

FLUE GAS DESULFURIZATION (SO2 CONTROL) PROCESS EQUIPMENT 

Both conventional wet and dry flue gas desulfurization (FGD) are addressed.  The 

specifics of the cost evaluation for wet FGD and dry FGD are described in companion 

documents prepared by S&L (EPA, 2010b, and EPA, 2010c). 

  

Wet FGD 

Estimated Costs. The capital cost for wet FGD process equipment as projected by 

S&L is shown in Figure 1, depicting capital cost ($/kW) as a function of generating 

capacity.  Figure 1 presents data sets or curve‐fits of data sets for three sources of 

wet FGD costs.  S&L’s projected capital costs are described by the blue line that is 

curve‐fit through square data points, which reflect the 2010 IPM update costs 

described by EPA (2010b).  This curve is labeled “2010 EPA IPM Projections”. The 

red curve‐fit through the locus of red triangle points represents capital costs for 

analogous wet FGD equipment, as reported in the 2010 UARG survey.  This curve is 

labeled “2008‐2010 Operating Units” and describes cost data that represent units at 

which the controls began commercial operation in that timeframe. Finally, the light 

blue curve reflects EPA’s 2006 projected capital costs for wet FGD; these costs were 

used in EPA’s previous IPM analysis (EPA, 2006). The cost data in Figure 1 for the 

EPA 2006 study case have been adjusted to a 2008 dollar basis. 

Figure 1 shows that the wet FGD capital costs projected by S&L exceed by 

approximately 20‐25% an average of the capital costs reported to UARG by plant 

owners.   However, the curve‐fit for S&L’s projected costs resides within a portion of 

the UARG‐reported cost data points for approximately 20 individual installations.  

Consequently, the difference in cost as reflected by the UARG and S&L curves – 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

3 

although notable – is not considered significant.  Given the paucity of data, either 

curve could be correct.   

The capital costs in the two upper lines ‐‐ the 2010 EPA IPM Projections and 

Operating Units:  2008‐2010 (i.e., the costs reported for units at which the controls 

began commercial operation in 2008‐2010) ‐‐ are significantly higher than the 

capital costs used in the 2006 EPA IPM analysis. 

Figure 1. EPA‐IPM Input for Wet FGD Capital Cost vs. UARG Survey Data  

Fixed operating and variable operating costs for wet FGD equipment were also 

projected by S&L.  For the range of generating capacity evaluated by S&L, the fixed 

operating costs projected by S&L are identical to UARG’s estimates of fixed 

operating costs. S&L estimated variable operating costs only for one specific coal (3 

lbs SO2/MBtu); this cost of 2.03 mills/kWh is within 10% of the projected cost in 

the UARG evaluation (2.2 mills/kWh).  

SO2 Removal Assumption.  The S&L analysis assumes 98% SO2 removal by wet FGD 

equipment, based on an annual average, with a minimum “floor” SO2 emission rate 

of 0.06 lbs/MBtu.  Although present‐generation wet FGD equipment can be capable 

of such high removal rates for abbreviated periods of time, the available data 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

4 

suggest that such a level of performance cannot be achieved for each month of the 

year, for all coals.   

A recent study of the best–performing wet FGD equipment suggests that 98% 

removal cannot be widely achieved on lower sulfur coals (Weilert, 2010).  

Specifically, Weilert evaluated the removal performance of the ten lowest SO2 

emitting generating units in the U.S.  Using the EPA Clean Air Markets Division 

database, the investigators calculated rolling SO2 outlet averages for periods of 3 

hours, 24 hours, and 30 days.  These averages excluded periods of startup or 

shutdown. These data were used in conjunction with monthly fuel use reported to 

the Energy Information Agency (EIA) of the Department of Energy (DOE), allowing 

investigators to calculate the monthly average of SO2 removal efficiency for wet FGD 

equipment.  This exercise was repeated for dry FGD process equipment and is 

discussed in a subsequent section of this report.  The authors offer the following 

observation:  

“......none of these ‘top performing’ wet FGD systems was able to achieve a removal

efficiency of 98% or greater in every month of the year.”

The authors note some of the inability to achieve 98% removal was due to the 

predominant use of low sulfur coal by the ten lowest SO2 emitting units and the 

process challenges presented by low inlet SO2 content.  The “floor” of 0.06 lbs/MBtu 

recognizes the difficulties inherent in attaining high SO2 removal percentages for 

coals of lower sulfur content.  However, the units considered are the top ten 

performing units in the U.S. – not a random sample.   This data set demonstrates that 

the ten best performing units could not achieve 98% SO2 removal in each month of 

a year.   And because the data set described by Weilert indicates that the best‐

performing wet FGD units are unable to achieve annual average reduction levels of 

more than perhaps 95 or 96% SO2 removal, then all wet FGD units (including those 

at plants burning higher sulfur coals) may be unlikely to be able to achieve monthly 

or annual removal levels of more than approximately 95%. 

Evaluated Per Ton Removal Cost.  Cost assumptions play a significant role in the IPM 

modeling done by EPA.  One measure of the influence of cost assumptions can be 

deduced from comparing SO2 removal cost per ton ($/ton) using both the S&L‐

derived and UARG cost premises.  To do this, one can determine the SO2 removal 

cost for a range of reference units that were described in the S&L study.  For 

example, one can evaluate the SO2 removal costs for a (a) 500 MW unit, with plant 

heat rate of 10,000 Btu/kWh, and coal sulfur content of 3 lbs (as SO2) /MBtu; (b) 

100 MW unit operating at a lower capacity factor more typical of smaller, perhaps 

higher heat rate units; and (c) 500 MW unit firing low sulfur (e.g., Powder River 

Basin (PRB)) coal. Calculations were conducted for a process capital recovery factor 

of 11.3% and SO2 removal of 95‐98%.  For a 500 MW unit operating at an 80% 

capacity factor and 98% SO2 removal, the SO2 removal costs derived with the S&L 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

5 

premises would be $715/ton; the costs derived with the UARG premises would be 

$645/ton, a difference of approximately 10%.   For a 100 MW unit operating at a 

60% capacity factor and 98% SO2 removal, the SO2 removal costs are 

approximately $1,450‐1,575/ton, again with S&L premises deriving 10% higher 

costs.  For a 500 MW plant operating at an 80% capacity factor and 95% SO2 

removal, and firing PRB of 1.2 lbs SO2/MBtu, the removal cost is approximately 

$1,750‐1,950/ton, with S&L premises deriving 10% higher costs.  These projected 

costs would be about 20% higher if a capital recovery factor reflecting the typical 

15‐20 year life for retrofit equipment were used, instead of the EPA‐proposed value  

(0.113) that is appropriate for new generation.  

In summary, the S&L projected capital costs somewhat exceed those costs recently 

projected by UARG, but both the S&L projected fixed and the S&L projected variable 

operating costs are similar to UARG estimates.  The net influence on calculated SO2 

removal costs per ton – for the same reference unit, operating conditions, and 

financial premises – is that the S&L estimates are approximately 10% higher than 

the UARG estimates.   

Dry FGD 

Estimated Cost. The projected capital cost for dry FGD process equipment, including 

a fabric filter for particulate matter removal, is shown in Figure 2, depicting capital 

cost ($/kW) as a function of generating capacity.  The S&L projected costs – depicted 

as the blue line through square calculated data points ‐ are compared to capital costs 

for similar equipment reported in the 2010 UARG survey.  Figure 2 shows a red 

curve‐fit through a locus of cost data that represent both (a) actual costs incurred 

for units operating or under construction (triangle green points), or (b) estimates of 

costs based on detailed engineering studies (diamond blue points).  Figure 2 shows 

S&L projected dry FGD capital costs that exceed the costs reported to UARG by plant 

owners by approximately 20% for smaller and 40% for larger units.  

Typically the maximum processing capacity of dry FGD equipment installed to date 

– and that expected for dry FGD equipment in most future applications – is 

approximately 400 MW.  It is not clear why S&L and reported UARG costs diverge at 

generating capacities larger than about 400 MW.  The data can be interpreted in two 

ways.  First, either there is an economy‐of‐scale with larger generating capacities 

that S&L estimates do not recognize; or second, there are design complications at 

larger capacities that UARG data do not recognize.  Although this point is not overtly 

stated in the background documents, S&L may have developed the dry FGD process 

design for units of 500 MW capacity and greater by utilizing two spray dryer 

absorbers in parallel.  This process design would decrease economies of scale and 

elevate capital cost at higher capacities. 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

6 

Figure 2. EPA‐IPM Input for Dry FGD Capital Cost vs. UARG Survey Data 

It should be noted Figure 2 contains actual incurred costs for only three units; the 

remainder are projections. 

Fixed and variable operating costs for dry FGD process equipment were also 

projected by S&L.  The fixed operating costs are essentially identical to UARG 

estimates. S&L projected variable operating costs for a specific coal (2 lbs 

SO2/MBtu); this variable cost of 2.60 mills/kWh is a factor of two higher than the 

1.1 mills/kWh cost determined in the UARG study for PRB coal.  One contributor to 

the difference in cost estimated by S&L are assumptions of cost for lime reagent and 

for solid byproduct disposal.  S&L’s estimate of the delivered cost for lime appears 

higher than historical values ($95/ton compared to historical values of $60/ton) but 

could be representative of lime reagent costs in the future.  Given the uncertainty in 

solid byproduct disposal costs and challenges in siting a landfill, it is possible that 

S&L’s estimate of byproduct management costs could be realized.   

In summary, the S&L projected capital costs for dry FGD exceed those recently 

projected by UARG, and S&L’s fixed and variable operating cost estimates are 

notably higher than UARG’s estimates. This will elevate the calculated cost per ton of 

SO2 removed for dry FGD, and perhaps reduce its role as an alternative to wet FGD. 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

7 

SO2 Removal Assumption. The S&L analysis assumes 95% SO2 removal by dry FGD 

equipment, based on an annual average, with a minimum “floor” SO2 emission rate 

of 0.08 lbs/MBtu.  Weilert (2010) evaluated the SO2 performance capabilities of dry 

FGD using an approach similar to that used to evaluate wet FGD process equipment. 

Weilert identified the lowest ten SO2 emitting units equipped with dry FGD and 

calculated rolling averages of SO2 outlet emissions on a 3‐hour, 24‐hour, and 30‐day 

basis.   These SO2 data were used in conjunction with fuel input data reported to the 

EIA to calculate SO2 removal on a percentage basis.   Weilert concludes the data set 

does not support a 95% SO2 removal efficiency in each month of the year, based on 

the coals used in the ten units examined.  Although this point is not explicitly 

addressed, the data from the plants evaluated by Weilert suggest it may be possible 

to achieve a 93% SO2 removal efficiency on an annual basis. Similar to the case of 

wet FGD, however, the data set evaluated by Weilert is not representative of 

industry practice.  The units represent only the top ten performing units in this 

category, i.e., those units that are already achieving low outlet values of SO2.  Thus, 

many dry FGD units are unlikely to be able to achieve monthly or annual removal 

levels of as much as 93%. 

CONTROL EQUIPMENT FOR NOx 

NOx control process equipment ‐‐ selective catalytic reduction (SCR), selective non‐

catalytic reduction (SNCR), and combustion controls ‐‐ are addressed in these 

analyses. 

Selective Catalytic Reduction (SCR) 

Estimated Cost. The specifics of the cost evaluation for SCR are described in a 

document prepared by S&L (EPA, 2010d). 

The capital costs for SCR process equipment as projected by S&L are shown in 

Figure 3, depicting capital costs ($/kW) as a function of generating capacity.  Figure 

3 presents data sets or curve‐fits of data sets for three sources of SCR costs.  S&L’s 

projected capital costs are described by the blue line that is curve‐fit through blue 

square data points, which reflect the 2010 IPM update described by EPA (2010d).  

This curve is labeled “2010 EPA IPM Projections”. The red curve‐fit through the 

locus of red square points represents capital costs for SCR process equipment as 

reported in the 2010 UARG survey.  This curve is labeled “2008‐2010 Operating 

Units”, noting all cost data representing units at which the SCR became 

commercially operational in that timeframe. Finally, the gray curve reflects SCR 

costs projected by EPA in 2004 (Khan, 2004). This curve was derived in 2004, but 

used in the 2006 IPM analyses, and is thus labeled “2006 EPA IPM Projections”. 

It is not clear why the S&L SCR capital cost estimates are 20‐25% lower than recent 

UARG‐derived costs.  Perhaps part of the reason for the difference is that S&L 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

8 

determined installed capital cost by applying a cost multiplier, with a subjective 

degree of retrofit difficulty, to estimated process capital. The approach of using 

retrofit difficulty factors to assess installed cost, although widely used, is known to 

provide faulty cost estimates, particularly for SCR.  SCR cost estimates using retrofit 

difficulty factors are particularly prone to error as such factors frequently do not 

capture the true complexity of a site, or the limitations on productivity of 

installation labor in a constrained (e.g., sellers’) market.  S&L also stated that actual 

incurred SCR costs were used in the analysis reported by the Midwest Ozone Group 

in a document submitted to the Lake Michigan Air Directors Consortium (Marchetti, 

2007).  The SCR capital costs contained in that referenced document, however, 

reflect installations prior to 2006, and not the most recent installation window.  

Thus, S&L costs may be influenced by 2006‐vintage experience. 

Figure 3. EPA‐IPM Input for SCR Capital Cost vs. UARG Survey Data 

S&L estimates of fixed O&M costs are similar to those in the UARG analysis.  The S&L 

analysis projects SCR fixed O&M costs to be $2.5/kW‐yr for a 500 MW unit; UARG’s 

estimate of 0.75% of process capital for a 500 MW unit (requiring a capital cost of 

$265/kW) translates into an equivalent cost of about $2.1/kW‐yr.   

Variable O&M costs projected by S&L for SCR are 1.1‐1.3 mills/kWh. The UARG 

analysis estimates the variable O&M costs to be 0.67‐1.3 mills/kWh; however, the 

variable O&M costs in the UARG estimates that are most relevant to the coal and 

boiler NOx emissions used for the S&L reference case are in the range of 0.77‐0.90 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

9 

mills/kWh.  The differences in these operating costs – at most about 10% ‐ are likely 

due to the delivered price of both reagent and replacement catalyst, and the 

frequency of catalyst exchange.  

NOx Control Performance. Recognizing that there is a limit to the lowest NOx 

emission rate that can be achieved with SCR, the S&L analysis recommends the 

establishment of NOx emission rate “floors” with use of SCR.  S&L assumed NOx 

outlet emissions cannot be less than 0.05 and 0.07 lbs/MBtu, respectively, for sub‐

bituminous and bituminous coals. It is possible that these “floors” may represent 

minimum emission rates that are achievable over short‐term averaging periods for 

high‐performing SCRs at certain units, although SCRs at other units may not be 

capable of achieving rates that low.  

Evaluated Per Ton Removal Cost.  One measure of the influence of cost assumptions 

is to compare the NOx removal cost per ton ($/ton) using both the S&L‐derived and 

UARG cost premises.  The NOx removal cost was determined for a reference unit 

described in the S&L study documentation:  a 500 MW unit, with a plant heat rate of 

10,000 Btu/kWh, and a boiler NOx emission rate of 0.40 lbs/MBtu (typifying NOx 

emissions from burning bituminous coal).   Calculations were conducted for an 80% 

capacity factor, a process capital recovery factor of 11.3%, and NOx control to 0.07 

lbs/MBtu (83% NOx removal). The NOx removal costs derived with the S&L 

premises ($2,552/ton) are about 18% less than those derived with UARG premises 

($3,117/ton). The most significant source of the differences in evaluated cost using 

S&L versus UARG‐reported premises is the difference in capital requirement.  

Similar to the case with wet FGD, projected costs for SCR installations would be 

approximately 20% higher if one used a capital recovery factor reflecting the typical 

15‐20 year life for retrofits to existing units, instead of the value proposed by EPA 

(0.113) that is appropriate for new generation. 

In summary, the S&L‐projected capital costs for SCR are notably less than those 

recently projected by UARG.  S&L and UARG fixed O&M costs are similar, but S&L’s 

variable O&M costs are higher than those UARG derived from discussions with plant 

owners.  Based on these differences in cost estimates, using the S&L SCR cost 

premises generates a calculated NOx removal cost per ton that is about 18% below 

that derived with UARG premises, for the same reference unit, operating conditions, 

and financial premises. 

SNCR 

S&L estimate that the SNCR capital cost for units less than 300 MW will be $45/kW.  

This number is consistent with, although generally somewhat higher than, the cost 

derived by UARG of $20‐45/kW for units less than 300 MW. Variable O&M costs of 

about 1 mills/kWh are projected by S&L.  These costs are similar to UARG’s 

estimates of variable O&M costs, which ‐‐ depending on unit size and initial NOx 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

10 

emission rate ‐‐ are 0.5‐1 mills/kWh.  For most applications the variable O&M costs 

are anticipated to be near the higher end of the UARG estimated range.  Fixed O&M 

costs for SNCR are negligible. 

S&L assume SNCR control efficiency to be 25%, similar to UARG projections.  S&L 

also limit the application of SNCR to 100‐300 MW at this NOx removal capability.  

(UARG’s projections permit applying SNCR to larger units, but estimate that NOx 

removal at those units would be restricted to less than 25%.)  

Combustion Controls (Low NOx Burners) 

S&L estimates the capital cost of low NOx burners (LNB) to be $24‐45/kW, 

depending on the generating capacity of the boiler to which the LNB is retrofit.  

These estimates are accepted as reflecting recent industry experience. UARG‐

derived estimates of LNB costs average $20/kW; for a 300 MW unit, the UARG 

$20/kW estimate approximates S&L’s $24/kW estimate. S&L also assign a small 

fixed cost and variable cost to the operation of this equipment.  

ROLE OF SMALL UNITS 

EPA predicts generating units that are less than about 200 MW in size will install 

SO2 and NOx controls.  Specifically, EPA projects that 15 units of less than 225 MW 

will install FGD, and that 6 units of less than 220 MW will choose to install SCR.  To 

date, the number of generating units in the U.S. of this capacity that have deployed 

either conventional FGD or SCR is small.  The smallest generating units with SCR are 

the 80 MW Dahlman units at City of Springfield Power & Light. The smallest with 

FGD are the dry‐FGD‐equipped 57 MW Cogentrix units.  These units were retrofit 

with control technology at a time when demand for such systems was low – i.e., a 

buyers’ market.  The reported costs for these units – such as $175/kW for the 80 

MW Dahlman units – are unlikely to be replicated in the anticipated market for 2012 

and 2014 compliance.  

S&L recognize that retrofitting SCR and FGD to units less than about 200 MW 

capacity would be prohibitively costly.  S&L suggest that in light of this cost penalty, 

the owners of such units would choose to retrofit an alternative control option such 

as that recently tested in a DOE‐funded demonstration (Connell, 2009).  S&L 

propose the cost for this alternative option to be lower than the cost associated with 

retrofitting SCR or FGD.  S&L do not have data to derive a cost algorithm for this 

alternative control technology, but propose a means to approximate such costs. 

Specifically, S&L propose to use the cost algorithm developed for FGD and SCR; 

however, S&L use a higher capacity to assign the cost per unit ($/kW) generating 

capacity. S&L state that the absolute magnitude of capital cost ($M) for SCR and FGD 

for a 100 MW unit – when using a 200 MW basis to derive unit cost ($/kW), and 

using 100 MW to calculate the actual cost magnitude ($M) – by coincidence provides 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

11 

about the right cost estimate for this scenario.  Although this approach is imperfect, 

S&L submit that the approach permits a reasonable cost number to be used in IPM 

while still recognizing that SCR and FGD will likely not be applied to 100 MW units.  

S&L are correct in recognizing that the cost to retrofit SCR and FGD on small units is 

prohibitive and thus that owners of smaller units might well choose to retire units 

rather than retrofit them with any additional controls. This is particularly the case 

as long as alternative NOx and SO2 control options are few and are offered by only 

one or two suppliers (and those suppliers have little experience in installing the 

alternative technologies).  Such options might be applied in isolated cases but broad 

deployment within the mandated time frame is unlikely.  

SUMMARY 

EPA has revised the cost inputs for IPM based on information prepared by a 

knowledgeable architect/engineering company:  Sargent & Lundy Engineers (S&L).   

EPA has also derived control technology costs based on an S&L database of 

component costs and installation charges.  This report has compared the capital and 

operating costs derived from the newly‐compiled work by S&L with the capital and 

operating costs summarized by UARG in a recent survey of costs incurred by power 

plant owners that have installed similar control technologies (UARG, 2010).  This 

report also has evaluated information presented by S&L concerning the 

performance of various control technologies for reducing SO2 and NOx.   The 

following is a summary of this report’s findings.   

The S&L‐projected capital costs associated with installing wet FGD systems can be 

20‐25% higher than the capital costs for FGD installations as estimated by UARG.  

S&L’s estimates of fixed and variable operating and maintenance costs are generally 

similar to those summarized by UARG.  The S&L analysis assumes wet FGD systems 

can achieve an annual average SO2 removal capacity of 98%, with a “floor” of 0.06 

lbs/MBtu.  A detailed statistical study by Weilert (2010), however, suggests that, at 

least when burning lower sulfur coals, even the best‐performing units cannot 

achieve 98% SO2 removal over long averaging times (e.g., months or a full year).  

The data were not evaluated to determine the annual average; but for the units 

addressed it is possible the annual SO2 reduction would be limited to 95 or 96%.  

For dry FGD, the S&L‐derived capital and operating costs are both higher than 

UARG’s estimated costs, with the former most divergent for large generating 

capacity.   S&L propose a dry FGD annual SO2 removal target of 95% with a “floor” 

of 0.08 lbs/MBtu.  The recent analysis of the SO2 emissions control performance 

data from dry FGD operating at the ten lowest SO2‐emitting units in the U.S. 

(Weilert, 2010) shows that 95% removal efficiency could not be achieved. The data 

were not evaluated to determine the annual average; but for the units addressed it 

is possible the annual SO2 reduction would be limited to about 93%. 
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

12 

The S&L estimates of the evaluated cost of SCR NOx control – on a $/ton basis of 

NOx removed – are approximately 20% less than the evaluated cost reported to 

UARG by owners that installed SCR systems in the past three years.  Most of this 

difference is due to lower estimates of capital cost, which can be 20‐25% less than 

costs reported by owners.  The S&L‐estimated operating costs for SCR systems 

exceed those estimated by UARG by not more than 10%.  As far as SCR performance 

is concerned, the S&L analysis recognizes that there is a limit to the lowest NOx 

emission rate that can be achieved with SCR.  S&L assumed NOx outlet emissions 

cannot be less than 0.05 and 0.07 lbs/MBtu, respectively, for sub‐bituminous and 

bituminous coals.  These performance levels may represent minimum emission 

rates over short‐term averaging periods for certain high‐performing SCRs, but SCRs 

at other units may not be capable of achieving rates that low, particularly over 

longer averaging times.   
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

13 

Author, Date Reference

Connell, 2009  Connell, D., et al., “Greenidge Multi‐Pollutant Control 

Project: Final Public Design Report”, Prepared for U.S. 

Department of Energy, Cooperative Agreement DE‐FC26‐

06NT41426, January, 2009.  

EPA, 2006  EPA, “Documentation for EPA Base Case 2006 (v.3.0) Using 

the Integrated Planning Model”, Prepared by the Air & 

Radiation Division, November, 2006. 

EPA, 2010a  EPA, “Documentation for EPA Base Case v.4.10 Using the 

Integrated Planning Model”, Prepared by the Air & 

Radiation Division, August, 2010. 

EPA, 2010b  EPA, “IPM Model – Revisions to Cost and Performance for 

APC Technologies: Wet FGD Cost Development 

Methodology”, Final Report for Project 12301‐007, 

prepared by Sargent & Lundy, August, 2010. 

EPA, 2010c  EPA, “IPM Model – Revisions to Cost and Performance for 

APC Technologies: Dry FGD Cost Development 

Methodology”, Final Report for Project 12301‐007, 

prepared by Sargent & Lundy, August, 2010. 

EPA, 2010d  EPA, “IPM Model – Revisions to Cost and Performance for 

APC Technologies: SCR Cost Development Methodology”, 

Final Report for Project 12301‐007, prepared by Sargent & 

Lundy, August, 2010. 

Khan, 2004  Khan, S. et. al., “Updating Performance and Cost of NOx 

Control Models in the IPM Model,” paper presented to the 

2004 Combined Power Plant Air Pollutant Control “Mega” 

Symposium”, August 30‐September 2, 2004, Baltimore, MD.
Overview of Projected Cost for  

Control Technology for EPA’s IPM

October 15, 2010  

14 

Author, Date Reference

Marchetti, 2007  Marchetti, J. et. al., “Analysis of MOG and LADCO’s FGD and 

SCR Capacity and Cost Assumptions in the Evaluation of 

Proposed EGU 1 and EGU 2 Emission Controls”, paper 

prepared for the Midwest Ozone Group, January, 2007. 

UARG, 2010  UARG, “Current Cost and Cost Effectiveness of Power Plant 

Emissions Control Technology”, prepared by J.E. 

Cichanowicz for the Utility Air Regulatory Group, January, 

2010. 

Weilert, 2010  Weilert, C.V. et. al., “Emissions Control Performance 

Achieved in Practice by Electric Utility FGD Systems in the 

United States”, proceedings of the 2010 Mega‐Symposium, 

August 30‐September 2, 2010, Baltimore, MD.