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Best Available Control Technologies for the Baldwin Generating Station, Baldwin, Illinois

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__ .J 

### / Matt Haber

Prepared for the United States in connection with: United States v. Illinois Power Company And Dynegy Midwest Generation, Inc.,

. Civil Action No. 99-833-MJR in the U.S. District Court for the Southern District ofIllinois

APRIL 2002

Pet. EX 28-1

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• TABLE OF CONTENTS Paee LIST OF TABLES , iv I. Introduction and Overview 1 A. Infonnation Required forthe Expert Report 1 B. Purpose ofReport 1 II. Summary ofConclusions 2 III. Qualifications 3 IV. What is BACT? : 5 V. The Typical BACT Determination Process 6 VI. Baldwin Station: Background 11 VII. BACT Determinations for the Baldwin Station 13 A. BACT Determination for Baldwin Unit 3: 1982 ; 13 

### 1. SulfUrDioxide 13 

### 2. Nitrogen Oxides 17 

### 3. ParticulateMatter 22 B. BACT Determination ForBaldwin Unit 1: 1985 23 

### 1. SulfurDioxide 23 

### 2. Nitrogen Oxides 26 

### 3. ParticulateMatter 30 C. BACT Determination for Baldwin Unit 2: 1988 33 

### 1. SOl Control 33

11

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• 2. NO x Control 35 3. Particulate Matter 38 D. BACT Detenninations for Baldwin Station: 2001 40 1. BACTDetermination atBaldwin Units 1 and2 40
a. S02 Control 40 b. NO. Control 40
c. Particulate Matter 44 2. BACTDeterminationforBaldwin Unit 

### 3 46
a. S02 Control (applicableto Units 

### 1,2 and 3) 46 b. NO. Control 48
c. Particulate Matter 52 Appendix A: Tables..
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - I Appendix B: Data and Infonnation Considered B-1 Appendix C: Papers Authored in the Last Ten Years C - 1 Appendix D: Resume.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. D - 1 Attachment 1: Report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02 , NO. and PM Control Devices at illinois Power's Baldwin Station," developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc. Attachment 2: Report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DvnegyMidwest Generation, Inc
.

111

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• Table I: Table 2:
Table 3a:
Table 3b:
Table 3c:
Table 3d:
Table 3e:
Table4a:
Table 4b:
Table 4c:
Table4d:
Table 4e:
Table 5: Table 6: Table 7: 

### LIST OFTABLES
NOx Emissions Rates for Permits Issued up to 1982 "
.. A - 3 Cost Effectiveness of

### S02 for Permits Issued 1979-1999, Converted to 1982,1985, 1988, and 2001 A - 4 NOxEmission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982 

### A - 5 NOx Emission Calculations and Cost Effectiveness for Baldwin Unit 1, 1985 A - 6 NOx Emission Calculations and Cost Effectiveness for Baldwin Uilit 2, 1988 A - 7 NOx Emission Calculations and Cost Effectiveness for Baldwin Unit 1 & 2, 2001 A - 8 NOx Emissions Calculations and Cost Effectiveness for Baldwin Unit 3, 2001 A - 9 Particulate MatterEmissions Calculations for Baldwin Unit 3, 1982 A - 10 Emission Calculations for Particulate Matter, Baldwin Unit 1, 1985 A-II Emissions Calculations for Particulate Matter, Baldwin Unit 2, 1988 A - 12 Emissions Calculations forParticulate Matter, Baldwin Unit 1 & 2,2001 A - 13 Emissions Calculations forParticulate Matter, Baldwin Unit 3,2001 , . . . . . . . . . . . . . . . . . . . . . . . . .. A - 14 RACTIBACTILAER Summary: 1982 Timeframe A - 15 Summary**ofPo~erplants** with High 

### S02Removal: 1985 timeframe
..... A - 16 Derivation ofParticulate Removal Efficiency A - 17

IV

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• Table 8a:
Table 8b:
Table 8c:
Table 8d:
Table 8e:
Table 9:
Table 10: Table 11: 

### S02Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982 " A - 18 

### S02Emission Calculations and Cost Effectiveness for Baldwin Unit 1, 1985 " " A - 19 

### S02Emission Calculations and Cost Effectiveness for Baldwin Unit 2, 1988
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A

- 20 

### S02Emission Calculations and Cost Effectiveness for Baldwin Unit 1 & 2, 2001 A- 21 

### S02Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 2001
.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - 22 General Information About Baldwin

- Baldwin Unit 1 Design Data.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A

- 23 Cost Effectiveness ofBACT Determinations for NOx •••••••••••••••• A - 26 BACT CostEffectiveness for 

### S02 Controls A - 27

v• I. INTRODUCTION AND OVERVIEW A. Information Required for· the Expert Report The following is a listing ofthe items required bythe Federal Rules ofCivil Procedures provided with this report: (I) This report contains my opinions, conclusions and the reasons therefor. (2) Exhibits and tables in summaryof, or in support of, these opinions are included with this report in Appendix A. (3) The body ofthe report and Appendix B list the data and otherinformation considered in forming these opinions. (4) Appendix C includes a listing ofpublications authored during the past ten years. (5) Section III presents a statement ofmy qualifications; my resume is attached as Appendix D. (6) lam being compensated for the preparation ofthis report and my testimony as a normal part ofmy compensation as an employee ofthe US EPA
. 

# •• (7) I have not provided previous testimonywithin thepreceding four years as an expert attrial orby deposition.



# • B. Purpose ofReport This report is written pursuant to a request from the Department ofJustice for an analysis ofwhat controls should have been installed at the Baldwin Station when the Prevention ofSignificant Deterioration (PSD) regulations were triggered ateach unit, as alleged in the United States' Amended Complaint. Under § 165 ofthe Clean 

### Air Act ("C.A.A.") (42 U.S.C. § 7475), the permitting requirements triggered by the majormodifications undertaken atthe Baldwin Units would have included a requirement that Illinois Power Company (IPC) install the "Best Available Control Technology" (BACT). This report explains what BACT would have been-- for sulfur dioxide (S02)' nitrogen oxides (N0J andparticulate matter (PM)

-- at Unit I in 1985, Unit 2 in 1988, and Unit 3 in 1982, when PSD was allegedly triggered. In addition, it is EPA's policythat a source that is in violation because itconstructed ormodified without aproper preconstruction permit must install controls that constitute BACT when the properpermit is finally issued
..!J Therefore, this report also makes adetermination ofBACT for all units as if
11 Office ofAir QualityPlanning and Standards, U.S. EPA, NewSource Review Workshop Manual: Prevention of SignificantDeterioration andNonattainmentArea Permitting (Draft Oct.• pennits were being issued as ofthe date this report is submitted. 

### II. Summary of

### Conclusions In summary, and for the reasons described herein, I have concluded that the following emission rates and technologies would have been BACT for the pollutants at issue, and the Baldwin Station Units at issue, in the time frames specified below.



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• 8°2 NO. PM 1982 (Unit 3) 0.30 pounds per 0.40 pounds per 0.036 pounds per million BTU, based on million BTU, based on mi11ion BTU, 99.4% 95% scrubbing and use ofLow NO. control, based on use assuming coal with a 3- Burners. of(then existing) ESP' 3.5% sulfurcontent, Averaging time: Averaging time: and use ofa wet 3 hour 3 hour limestone scrubber Monitored via CEMS Monitored via EPA



## - Averaging time: method**5~,** opacity 30 day rolling monitor Monitored via**CEMS~** 1985 (Unit 1) 0.30 pounds per 0.90 pounds per 0.003 pounds per million BTU, based on million BTU, based on million BTU, based on 95% scrubbing and use ofselective use ofa baghouse assuming coal with a 3- catalytic reduction Averaging time: 3.5% sulfur content, Averaging time: 3 hour and use ofa wet 3 hour Monitored via EPA limestone scrubber Monitored via CEMS method 5, opacity Averaging time: monitor 30 day roIling Monitored via CEMS

1990), page 

### B.5S: "the BACT emission limit in a new source pennit is not set until the final pennit is issued." Y Continuous Emissions Monitoring System }j See 40 C.F.R 60 Appendix A 2

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• 1988 (Unit 2) 0.30 pounds per 0.36 pounds per 0.003 pounds per million BTU, based on minion BTU, based on million BTU, based on 95% scrubbing and use ofselective use ofabaghouse assuming coal with a 3- catalytic reduction Averaging time: 3.5% sulfur content, Averagingtime: 3 hour and use ofa wet 3 hour Monitored via EPA limestone scrubber Monitored via CEMS method 5, opacity Averaging time: monitor 30 day rolling Monitored via CEMS 2002 (Units 1 & 2) 0.095 pounds per 0.14 pounds per 0.006 pounds per million BTU, based on million BTU, based on million BTU, based on 95% scrubbing, and use ofoverfire air, use ofa baghouse assuming use ofcoal selective catalytic Averaging time: with 0.6% sulfur reduction, and an 3 hour content optimization system Monitored via EPA Averaging time: Averaging time: method 5, triboelectric 30 day rolling 3 hour broken bag monitors Monitored via CEMS Monitored via CEMS 2002 (Unit 3) 0.095 pounds per 0.020 pounds per 0.015 pounds per million BTU, based on million BTU, based on million BTU, based on 95% scrubbing, and use oflow-NO. use ofa ESP.

, assuming use ofcoal burners, selective Averaging time: with 0.6% sulfur catalytic reduction, and 3 hour content an optimization system. Monitored via EPA Averaging time: Limit may be adjusted method 5, PM**CEMS~** 30 day rolling as high as 0.040 '-r;'- Monitored via·CEMS pounds per million B111 iflower limitis demonstrated to be unachievable. Averagingtime: 3 hour Monitored via CEMS
III. Qualifications I have been involved in BACT decisions in avariety ofcapacities at EPA's Region 9 for over twenty one years. I began work for EPA Region 9 in 1980 as a staffengineer in the New Source Section ofwhat was then called the Enforcement Division. The primary function ofthis section
See http://www.epa.gov/ttnJemc/propperfi'ps-ll&fmotice.pdf, proposed Performance Specification for Continuous PM Monitoring Systems
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• was to perform analyses, including control technology (i.e. BACT) analyses necessary for the issuance ofPSD permits, and tooversee the issuance ofPSD and nonattainment NSR permits by State and local agencies I conducted technical analyses on a variety ofPSD sources, including powerplants, cement plants, and waste-to-energyplants. I also reviewed BACT and Lowest Achievable Emission Rate (LAER) analyses conducted by state and local agencies in Region 9 (these include agencies in California, Nevada, Arizona and Hawaii). In 1987, Ico-authored Region 9's BestAvailable Control Technology Guidance Document. which laid out a methodology for use primarilyby permit applicants, their consultants, and state and local permitting authorities for conducting a BACT deterrnimition. Beginning in about 1987, I spent approximately one year in our enforcement office, focusing on two cases involving coal-fired powerplants in Arizona and Nevada: NevadaPower-Reid Gardner and Arizona Public Service-Cholla. 

### In 1989, 1became the managerofthe New Source Section. I managed the Region's work in permitting new and modified airpollution sources, as well as overseeing the permit issuance work ofour state and local agencies. 

### In addition, my group had the responsibility for review and action on permitrules submitted to EPA for inclusion in the State Implementation Plan, as well as reviews ofstate programs to determine-afterthe fact-the efficacy oftheir permitting programs, including theirBACT reviews. 

### In 2000, I began a one-year assignment as Associate Directorofthe AirDivision. One ofmy responsibilities was managing the Region's**~esponse** to the western energy shortage, a responsibility I continued when I became the Region's SeniorEnergy.Advisor, the position I currentlyhold. One responsibility ofmy current position is to advise staffin the Permits Office on decisions related to powerplants, including BACT decisions
. I speak frequently on Clean Air Act issues. During the past ten years, I have spoken to groups such as the environmental section ofthe ArizonaBarAssociation, the annual environmental section conference ofthe CaliforniaBarAssociation, and numerous industry conferences, such as several sessions of the SummerIssues Seminar ofthe California Council for Environmental and Economic Balance, a company-wide conference ofGranite Construction, the 2000 CADER Distributed Generation Conference, the 1999 Utility Environmental Conference, and others. Most ofmytalks were solely orprimarily about New Source Review and the control technology requirement (BACT and LAER) underthe NSRregulations. Ihave also created and presented New Source Review training courses for several audiences. In about 1991, staffunder my direction and I created and presented a comprehensive (2-3 day) New Source Review training for Region 9's 44 state and local permitting authorities. About 150people attended four training sessions. That training was followed by internal training ofabout 50 EPA Region 9 staff. Between about 1994 and 1997, Ipresented several short (several-hour) new source review training modules as part ofa largerUniversity ofCalifornia extension course about the Clean Air Act. Most recently (March 200I), Iwas invited to present a paperto the second conference ofthe European Union nations on NOxand N20 control ("NOxCONF 2001 "). My paperwas titled

### NOr Emissions Controls atRefineries: USRegulatoryDrivers andResults
.

4• IV. What is BACT? When anew major source ofair pollution is proposed to be constructed, orwhen an existing major source is modified in such a manner that its emissions will be increased by a significant amount, apermit is required from EPA or a**Stat~** authorized under the New Source Review ("NSR") program. Because the Baldwin plant is located in an area that is in attainment ofthe National Ambient Air Quality Standards for the pollutants at issue here, NSR regulations for attainment areas, known as the Prevention ofSignificant Deterioration ("PSD") regulations apply.§' State-of-the-art-emissions controls, known as Best Available Control Technology ("BACT") are one ofthe keyrequirements ofthe PSD permit. BACT is defined as:



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• "an emissions limitation (including a visible emission standard) based on the maximum degree ofreduction for each pollutant subjectto regulation under [the Clean Air Act] which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification thrqugh application ofproduction processes oravailable methods, systems, and techniques, including fuel cleaning or treatment orinnovative fuel combustion techniques for control of such pollutant. In no event shall application ofbest available control technologyresult in emissions ofany pollutant which would exceed the emissions allowed by any applicable standard under40 CFR Parts 6()?! and 61. Ifthe Administrator determines that technological or economic limitations on the application ofmeasurement methodology to aparticular emissions unit would make the imposition ofan emissions standard infeasible, a design, equipment, work practice, operational standard, orcombination thereof, may be prescribed instead to satisfy the requirement for the application ofbest available control technology. Such standard shall, to the degree possible, setforth the emissions reduction achievable by implementation ofsuch design, equipment, work practice or operation, and shall provide for

In this context, "state" may mean a state agency, or a local agency authorized under state law and federal regulations to carry out airpollution control functions. §' These regulations are codified at 40 C.F.R. 

### § 52.21, and are incorporated into the Illinois PSD program. Definitions ofthe terms "majorsource," "majormodification," and "significant" can be found in these regulations. ?1 40 C.F.R. Part 60 is generally known as New Source Performance Standards. This section requires aminimum, uniform level ofcontrol technology for new or modified construction of categories ofsources ofair pollution, such as coal fired powerplants, petroleum refineries, pulp mills and the like
. 5

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• compliance by means which achieve equivalent results."!!! In a typical BACT process, the applicant performs an analysis that is then submitted to a permitting authority, typically a state or local air pollution control agency. The applicant must submit information supporting its proposal, including information specific to its proposed plant, as well as information about other facilities and otherBACT determinations it believes are relevant. That agency reviews the proposal, asks for clarifying information from the applicant, gathers information independently, and then proposes apermit that contains its own independent review, analysis and proposed BACT decision. The public, including the applicant, the public at large, and EPA then have an opportunity to review and comment on the proposed decision bythe permitting authority. After the close ofthe comment period, the permitting authority reviews all comments, modifies the proposed decision (where appropriate) based on its analysis ofthe comments, and issues a pennit containing emission limits and control technologies that reflect its BACT decision. Thepermit should also contain monitoring and testing requirements to ensure that the BACT limit is attained on an ongoing basis. The BACT analyses contained in this report are, by necessity, different from most in several respects. A typical BACT analysis is conducted before construction ofanew source or modification has begun; because Illinois Powerfailed to obtain timely PSD permits priorto its construction ofchanges that triggered BACT, this analysis is being conducted afterthe modifications at the Baldwin powerplanthave been completed. Also, my analysis is based largely on my own research, because Illinois Powerhas not, to date, submitted aBACT analysis to**review.~** V. The Typical BACT Determination Process Overthe years, EPAhas issuedpolicy guidance on the BACT process several times. Most notably, EPA published in 1980 the Prevention of SignificantDeterioration Workshop Manual.!1'

§' 40 C.F.R. 

### § 52.2I(b)(12).
'}j 

### In addition to my own research, I cite below to the work ofEllison Consultants, who have performed areview ofthe historical installation oftechnologies, and to the work ofstaffin EPA's Office ofAir Quality Planning and Standards, who have perfonned a review ofthe costeffectiveness ofcertain technologies, at myrequest. See Attachments 1 and 2. The information contained in these reports, which I have reviewed and agree with, is among the types of informationthat might be submitted by an applicant, orpresented by anotherpermitting authority. Just as in a traditional BACT analysis, Ihave utilized this datain reaching the BACT determinations described herein
. .ill' Leigh Hayes, et ai, TRW Incorporated, Prevention of SignificantDeterioration Workshop Manual (Oct. 1980) EPA 450/2-80-081
. 6

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• and in 1990 published theNew SourceReview Workshop Manual (draft),l!! accompanied by the "Top-Down"BestAvailable Control Technology Guidance Document.J1I Also, EPA's Region 9 office published, in about 1987, its BACTGuidance Document.J JiThe following description reflects the process generallyused to perform a BACT analysis today. During each BACT analysis, which is done on acase-by-case basis, the reviewing authority evaluates the energy, environmental, economic and othercosts associated with each alternative technology, and the benefit ofreduced emissions that the technology would bring. The reviewing authority then specifies an emissions limitation for the source that reflects the maximum degree ofreduction achievable for each pollutantregulated underthe Act. In no event can a technologybe selected which would not meet any applicable standard ofperformance under40 C.F.R. Parts 60 (New Source Performance Standards) and 61 (National Emission Standards for Hazardous AirPollutants). In brief, the process provides that all available control technologies be ranked in descending order ofcontrol effectiveness. The PSD applicant first examines the most stringent--or "top"--altemative. That alternative is established as BACT unless the applicant demonstrates, and the permitting authority in its informedjudgmentagrees, that technical considerations, or energy, environmental, or economic impactsjustify a conclusionthat the most stringent technology is not "achievable" in that case. Ifthe most stringenttechnology is eliminated in this fashion, then the next most stringent alternative is considered, and so on. This**i~** known as the "top-down" process. The first step in a "top-down" analysis is to identify, for the emissions unit in'question, all "available" control options. Available control options are those airpollution control technologies or techniques with apractical potential for application to the emissions unit and the regulated pollutant under evaluation. Airpollution control technologies and techniques include the application ofproductionprocess or available methods, systems, and techniques, including clean fuels, fuel cleaning or treatmentor innovative fuel combustion techniques for control ofthe affected pollutant. This analysis includes a review oftechnologies employed bothwithin and

l!! Office ofAir QualityPlanning and Standards, U.S. EPA, New SourceReview Workshop Manual: Prevention of SignificantDeterioration andNonattainmentArea Permitting (Draft Oct. 1990)
.

.ill Office ofAir QualityPlanning and Standards, U.S. EPA, "Top-Down"BestAvailable Control Technology GuidanceDocument (Mar. 15,1990). This document was shared with other EPA Regions and States, who would have considered it in theirown BACT analyses
. .!)J Matt Haber et ai., U.S. EPA Region 9, BestAvailable Control Technology Guidance Document
. 7

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• outside ofthe United States.H' As discussed later, in some circumstances, inherently lower-polluting processes are appropriate for consideration as available control alternatives. The control alternatives evaluated should include not onlyexisting controls for the source categoryin question, but also (through technology transfer) controls applied to similarsource categories and gas streams, and innovative control technologies. In addition, the technology that will achieve the greatest emission reductiori technically possible (which is requiredin areas not attaining the National Ambient Air Quality Standards, and known as lowest achievable emission rate (LAER).!.?J) is considered available for BACT purposes, must also be included as a control alternative and usually represent the "top" alternative
..!9' In the course ofthe BACT analysis, one or more ofthe options may be eliminated from consideration because they are demonstrated to be technically infeasible orhave unacceptable energy, economic, and environmental impacts on a case-by-case (or site-specific) basis. However, at the outset, applicants should initially identify all control options with potential application to the emissions unit underreview..!?! Next, the technical feasibility ofthe control options identified in step one is evaluated with respect to the source-specific (or emissions unit-specific) factors. Any demonstration oftechnical infeasibility must be clearly documented in the analysis to show, based onphysical, chemical, or engineering principles, that technical difficulties would preclude the successful use ofthe control option on the emissions unit under review. Technically infeasible control options are then eliminated from further consideration in the BACT**analysis.~** For example, in cases where the level ofcontrol in a permit is not.expected to be achieved in practice (e.g., a source has received a permitbut the projectwas canceled, orevery operating source at that permitted level has been physicallyunable to achieve compliance with the limit), and supporting documentation showing why such limits are not technically feasible is provided, the level ofcontrol (butnotnecessarily the technology) maybe eliminated from further
H' Office ofAir Quality Planning and Standards, U.S. EPA, "Top-Down"BestAvailable Control Technology GuidanceDocument (Mar. 15, 1990), page B.l1. "Also, technologies in application outside the United States to the extentthe technologies have been successfully demonstrated in practice on full scale operations [should be considered]." .!J LAER is defined as the lowest emission rate achieved in practice, orin a SIP, for that class or category ofsource (C.A.A. 

### § 171)
. .!3' Office ofAir Quality Planning and Standards, U.S. EPA, 'Top-Down"BestAvailable Control Technology Guidance Document (Mar. 15, 1990). J1J Ibid. Ibid. 8

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• consideration. However, a permit from another facility requiring the application ofacertain technology or emission limit to be achieved for such technology usually is sufficientjustification to assume the technical feasibility ofthat technology or emission**limit.~** All remaining control alternatives not eliminated above are listed in rank orderofoverall control effectiveness for the pollutant underreview, with the most effective control alternative at the top. A list should be prepared for each pollutant and for each emissions unit (or grouping ofsimilar units) subject to aBACT analysis. The list should present the array ofcontrol technology alternatives and should include the following types**ofinformation:~**

• control efficieiicies (percentpollutantremoved, where**appropriate)~**

• expected emission rate (concentration ormass perunit production);

• economic impacts (cost effectiveness);

• environmental impacts (includes any significantor unusual othermedia impacts (e.g., water or solid waste), and, at a minimum, the impact ofeach control alternative on emissions oftoxic orhazardous aircontaminants); and

• energy impacts (to the extent not already included in the economic impacts)
. After the identification ofavailable and technically feasible control technology options, the energy, environmental, and economic impacts should be considered to anive at the final level of control. For each option, the applicant is responsible forpresentingan objective evaluation of each impact. Beneficial and adverse impacts are discussed and, where possible, quantified. In general, the BACT analysis focuses on the direct impactofthe control alternative. Indirect impacts, such as the environmental impact from the generation ofelectricityneeded to run fans· for an airpollution control device, are not included in the BACT analysis. However, an applicantproposing the top control alternative need not provide cost and other detailed information in regard to other control options. In such cases the applicant should document that the control option chosen is, indeed, the top, and review that option only for collateral environmental impacts.lli Economic impacts are considered in terms ofdollars perton ofpollutantremoved. This factor is
J.2r Ibid. Ibid. lli Ibid. 

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• known as "cost effectiveness." Using this common unit ofmeasurement facilitates a comparison ofsimilar data across technology options. Othermeasures, such as dollars invested in control equipment compared to fraction oftotal capital investment, or dollars perunit ofproduct, should not be used in BACT determinations. Cost effectiveness for the purpose ofa BACT analysis is always measured as total cost effectiveness and, sometimes, by incremental cost effectiveness. Total cost effectiveness is the cost, in dollars perton ofpollutant removed, ofall emissions removed compared to a baseline emissions level. Thatbaseline is usuallythe legal limit that would existbut for the BACT determination. In manycases, that limit is equal to uncontrolled emissions, since no legal orpractical limit may exist for a particularpollutant. Incremental cost effectiveness is defined as the cost, in dollars perton ofpollutant removed, ofadditional emissions removed compared to the next less effective control option. When comparing a particularcalculated cost effectiveness with apotential cost benchmark, it is essential to ascertain whether the values are total or incremental cost effectiveness, as incremental cost effectiveness is always much larger than total cost effectiveness. EPA does not set a bright line for acceptable costs for BACT. The cost expectations for aparticularindustry and across all industrial sectors are expected to evolve over time, and may vary from area to area and from permitting authority to permitting authority. The focus ofthe economic cost portion ofthe BACT analysis is to ensure that a permit applicant may propose elimination ofa control option ifits costs for that option are disproportionately high compared to other sources using that control option, orthe cost for that control alternative is significantly higher than the range ofcosts associated with BACT costs for that type offacility or BACT in general. lfthe applicant accepts the topaltemative in the listing as BACT, the applicant proceeds to considerwhetherimpacts ofunregulated airpollutants orimpacts in other mediawouldjustify selection ofan alternative control option. Ifthere are no outstanding issues regarding collateral environmental impacts, the analysis is ended and the results are proposed as BACT. In the event that the top candidate is shownto be inappropriate, due to energy, environmental, oreconomic impacts, the rationale for this finding shouldbe documentedby the permitting authority forthe public record. Then the next most stringent alternative in the listing becomes the new control candidate and is similarly evaluated. This process continues until the technologyunder consideration cannotbe eliminated by any source-specific environmental, energy, oreconomic impacts which demonstrate that alternative to beinappropriate as BACT.llI
1lI Prior to the formalization ofthe "top-down"BACTprocess described above, the BACT process did not require that the applicantbegin with an analysis ofthe most stringenttechnology option; however, the otherkey elements are verymuch the same. The process I describe has been formally in place since 1987, when EPA headquarters issued guidance ("Pottermemo") for the improvement ofthe BACT determination process, after a series ofevaluations ofstate and local permitting programs gave rise to concern at EPA that control technology (BACT) determinations defaulted too often to the minimum floor for emissions controls. After EPA headquarters issued its Potter memo, EPA's expectation was that permitting authorities would use that guidance in preparing their BACT determinations. My analysis for the 1988 and later timeframes largely conforms to the methodologyofthe Pottermemo and later guidance
. 10• VI. Baldwin Station: Back2round Baldwin Station consists ofthree coal-fired steam electric generation units, each with a capacity ofapproximately 585 megawatts (MW). The Baldwin plant combusted local Illinois coal with a heating value ofapproximately 10,400 to 10,800 BritishThermal Units (BTU) perpound, a sulfurcontent ofapproximately 3% by weight, and an ash content ofapproximately 10% to II% by weightDl until 1999, when the facility began use ofPowderRiverBasin (PRB) coal with a heating value of8600-8800 BTUllb, a sulfur content of0.25%, and an ash content of**4.6-4.8%.~** Unit I began operation in 1970, and operates a cyclone fired**boiler.~** Unit 1 has a gross output of584 megawatts (MW).±9' Its airpollution equipment includes ofan electrostatic precipitator (ESP) initially designed to remove 99% ofthe particulate matter (PM) contained in the boiler exhaust gas. The ESP was upgraded inI999.1lIThe upgraded ESP was expected to remove 99.4% ofparticulate**matter.~** For NOx control, an over-fire air system was installed in**1999,~** as was the infrastructure for selective catalytic reduction (SCR).;ill' However, at least as ofNovember 

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• However, the only substantive difference between the current (1987 and later) and earlier (1980) guidance is that the current guidance recommends that the top (i.e. most effective at controlling pollution) technology be listed first, and then rejected only ifcompelling reasons, consistentwith the law, are found, In contrast, the earlierguidance recommend assessment ofeach control technology, and selection ofthe "best" technologybased on the statutorycriteria. My analysis in the 1982 and 1985 timeframes is consistent with the 1980 publication. While the processes laid out in the 1980 document and the 1987 Pottermemo (and laterguidance) were different, the results should have been the same. DI Department ofEnergy, Energy InformationAdministration (Form EIA-767) for 1985. Department ofEnergy, Energy Information Administration (Form EIA-767) for 2000. Ibid. ±9' Sargent & Lundy Engineers Engineering Data, Unit 1 Baldwin Power Station. IPPRO0085676-744. llJ IP Permit Application dated March 30, 1998. IPPRO-OOI9396. ¥i Ibid. IP Permit Application dated September 8, 1999. IPPRO-0028775. ;ill' IEPA Construction Permit. EPA 5775
. II

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• 2000, the SCR system does hot contain catalyst, and is not currentlyoperating.ll! There are no S02 controls in place at Baldwin Unit I. Unit 2 also employs a cyclone fired boiler and has a gross capacity of586 MW
..!Y Unit 2 began· operation in 1

### 973.J1IThe Unit 2 ESP was initiallydesigned to remove 99% ofthe exhaust gas**PM.~** Although the ESP was modified in 1999 by adding additional collection fields,J,Y and installation ofa flue gas conditioning system,J.9' no information has been provided regarding the new removal efficiencyoremission rate. With respect to NOx, an over-fire air system was installed in 1999,TI' as was an SCR system infrastructure. However, at least as ofNovember 2000 no catalyst was installed, and the SCR system is not currently**operating.~** There are no S02 controls in place at Baldwin Unit 2. Unit 3 is a tangentially fired unit with a gross output of586**MW,~** and began operation in**1975.~** Its airpollution controls include an ESP initiallydesigned to remove 99.5% ofexhaust gas PM.±!J Although the ESP was upgraded in 

### 20aO,£' no information has been provided regarding the new performance level in terms ofPM-removal efficiency or emission rate. With

l!I Deposition testimony ofAric Diericx, November 10, 2000
. .!Y Ratings ofIllinois PowerCompanyFossil Fuel Fired Generating Units; ReportbyPower Technologies, Inc. December, 1987 -IPPRO-00151120 J1I Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985. Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1985. IP Permit Application dated November25, 1998. IPPRO-0019250. J!i IP PermitApplication dated December20, 1999. IPPRO-0028865 TI' IP Permit Application dated September 8, 1999. IPPRO-0028775. Deposition testimony ofAric Diericx, November 10, 2000. 12t Sargent & Lundy Engineers Engineering Data, Unit 3 Baldwin Power Station. IPPRO0085900. Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985. iY Ibid. IP Permit Application datedNovember25, 1998. IPPRO-OOI9250
. 12

# •
'.

• respect to NO•• in 1994, low NO. burners, with an overfire air system were**installed.~** There are no S02 controls inplace at Baldwin Unit 3. VII. BACT Determinations for the Baldwin Station A. BACT Determination for Baldwin Unit 3: 1982 Unit 3 is a tangentially fired unit with a gross output of586 MW, and began operation in**1975.~** It was designed to fire up to 294 tons per**hour~** ofcoal with aheating value of10,460 BTU per**pound.~** 1. SulfurDioxide As of 1982, Baldwin Unit 3 was uncontrolled for emissions ofS02' and was burning coal with a sulfur content of3%-3.5%.B Actual emissions for the unit were about 85,000 tons peryear (TPY) of**S02'~** a. Technical Feasibility Two S02 emissions control options were potentiallyavailable in 1982. I analyzed the following options to determine technical feasibility, availability and cost effectiveness for S02 control: 1. Wet Limestone Scrubber 2. Wet Lime scrubbingbuffered byMagnesium Oxide All wet scrubbing type sulfurremoval controls employabsorption bypassing the flue gasses

IP Pennit Application dated January 19, 1993. IPPRO-0032541. Ibid. Ibid. Sargent & LundyEngineers Engineering Data, Unit 3 Baldwin PowerStation. IPPRO0085900 9 Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985. See Expert Report ofRanajit (Ron) Sahu, April, 2002, compiling CEMS data submitted by Illinois PowerCompanyto U.S. EPA
. 13

# •

•

• through an injected mist ofreagent
- generally limestone or lime.12' The reagent is crushed into a fine powder, hydrated into awet slurry, and then injected into the flue gas stream via specialized high pressure pumps and nozzles.The airborne slurrymist absorbs the sulfur and precipitates out ofthe injection chamberwhere it is de-watered and neutralized for landfill. In many cases, the by-product material is ofsufficient quality it can be sold as wallboard-quality gypsum. The use of magnesium oxide as a buffering agent may increase the effectiveness ofSOzremoval. Both ofthe technologies under consideration were technically feasible and available, as both wet scrubbing technologies had been in widespread use by 1982. For example, in the U.S., at least eight other facilities were operating using wet limestone systems bythe end of 1982, and twelve facilities were using magnesium oxide (MgO) enhanced lime. Design removal efficiencies for these facilities ranged from 80 to**95%.~** Wet scrubbers were put in place at the above facilities for a variety ofreasons, but by 1982 there were atleast two Federal requirements for the use of scrubbers for 

### SOz control. The first ofthese federal requirements is the New Source Performance Standards (NSPS) for coal fired powerplants. The NSPS had been amended in 1979, and applies to. powerplants constructed or modified after 1978.lli Those standards require removal ofup to 90% offlue gas S02 (depending on the sulfur content ofthe coal). NSPS is set at level that is technically feasible, and cost effective.S' The second requirement is the BACT requirement ofthe PSD regulations, which, in 1982, had been in effect for almost four**years.~** At least seven coal fired powerplants were issued PSD permits between 1978 and 1983 with the requirement for between 80 and 95% control.3' For

!If"Estimating Costs ofAirPollution Control," 1990, Vatavuk, W.M., Lewis Publishers, Chelsea, MI., pp. 194-199. See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. W See 40 C.F.R. § 60.40a (1979), "Standards ofPerformance for Electric Utility Steam Generating Units for Which Construction is commenced after September 18, 1978." ?1J See C.A.A.§ 111(a)(I). In 1978, EPA revised its regulations pursuantto the 1977 Clean Air Act Amendments. Prior to that date, BACT was defined to be equal to NSPS, where an NSPS existed. The 1978 regulation conformed the regulations to the new statutory language, and provided that the permit applications that were "complete" priorto the new regulation would be processed underthe old regulations. 3' See Appendix A, Table 5: RACTIBACTILAER summary: 1982 timeframe
. 14

# •

•

• example, Nevada Power's Harry Allen Station was issued a pennit in early 1981 with a 95% removal requirement and an emission rate of0.1 pound/million BTU. In 1980, the Platte River Power Authority, Rawhide Station was issued a permit with an 80% removal requirement and an emission rate limit of0.13 pound/million**BTU.~** In addition, in 1982, the Allegheny Power, Mitchell 33 Unit, a powerplant firing up to 2.9% sulfur coal, began operation ofa scrubber removing 95% ofthe stack gas.iY Taken together, it is clear that by 1982, scrubbingtechnologies to remove SOl were required of many powerplants and in place at many others. Both wet limestone scrubbers and wet lime scrubbers with magnesium buffering had been used and had demonstrated removal efficiencies of up to 95%. These two wet scrubbing technologies, with efficiencies ofup to 95%, were therefore both technologically feasible and well demonstrated in practice. b. Cost Analysis Both ofthe available wet scrubbing options were analyzed to detennine their cost effectiveness. Both scrubbing options were analyzed at the 95% efficiency level. The cost for scrubbers capable ofremoving 95% offlue gas SOl were analyzed based on a study conducted by Illinois Power in 1991 to install flue gas desulfurization systems on Unit**l.~** Most ofthe methodology used in 1991 would also apply in**1982.~** Based on this analysis, the capital costs for the limestone system, would be approximately $176 million (in 1982 dollars). Operating costs would range from $3.3 million to 4.7 million, depending on whether waste from the

Ibid. Ibid. iY See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx BurnerInstallations", developed in connection with United States v. Illinois Power and Dvnegy Midwest Generation, Inc. Babcock and Wilcox, Contract Research Division and Environmental Equipment Division, Volumes I-IV ofProposal for Full-Scale Demonstration ofIntegrated Flue Gas Desulfurization System with Reburning NOx Control, B&W Proposal #90-071 (May 1991). IPPRO-0128923- 0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-0127567-0127848. Seereport ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Powerand Dynegy Midwest Generation, Inc. The cost data adjustment was based on infonnation found at website address http://www.enr.comlcost/costcci.asp
. 15

# •

•

• scrubber system would have been sold. When these costs are converted to annualized**costs~,** the annual cost would have been between $22.0 and 23.4 million.§Jj Based on 95% control ofS02 emissions, a wet limestone scrubber system installed on Baldwin's Unit 3 would remove 106,600 tons peryear ofS02' Its cost effectiveness in 1982 would have been approximately $220/ton.2Y The wet lime scrubberwith magnesium buffering would have had both higher capital and operating costs than the wet limestone scrubber.§' Therefore, unless the wet limestone scrubber were to be rejected on other grounds (such as lesser other environmental impacts), it would no longer need to be considered. In order to ensure that the costs estimated for the scrubber are not excessive, Ireviewed other BACT determinations and EPA policy**documents.~** Ireviewed the cost effectiveness of eighteen powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. Ofthose where a dollarperton cost effectiveness was listed, the range (once converted to 1982 dollars) was $145 to 4405/ton.@ Also, in 2001, EPA issued guidance related to presumptive BACT for NOx at refineries being modified to meet EPA mandates for making cleanerburning Annualizing a cost is method to determine the annual equivalent value ofthe initial investment over its life. §Jj Ibid.; the cost data adjustment was based on information found at website address http://www.enr.com/cost/costcci.asp
. §lI See Table 8a: S02 Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982. §}j See report ofDan Mussatti and Larry Sorrels, Estimated Costs for the Installation ofS02' NOx and PM Control Devices at Illinois Power's Baldwin Station, developed in connection with 'United States v. Illinois Powerand DynegyMidwest Generation, Inc. Specifically, as part ofthe economic analysis here and throughout the report, I compared the cost effectiveness ofavailable control options to a variety ofotherbenchmarks. This comparison assisted in determining whethera particular scenario's cost effectiveness should be deemed unreasonable. Forexample;to the extent available, I looked at contemporaneously issued PSD permits, as well as PSD permits issued later. In addition, I considered more generalized data applicable to source types orregulatory schemes that are expected to use a lowercost effectiveness. Forexample, Ihave compared potential control costs at the Baldwin station to costs calculated for control measures imposed to attain the National Ambient Air Quality Standards. These control measures are usuallyknown as Reasonably Available Control Technology (RACT). RACT level emissions controls·are considered to be a less stringent control technology requirement than BACT, and therefore are less expensive. Therefore, the use of RACT level controls should yield a conservative (i.e. lower cost) measure against which to compare potential BACT options. @See Table 11, Cost Effectiveness ofBACT Determinations for S02' 16

# •

•

•**gasoline.~** That guidance used $1 O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is converted to 1982 dollars it becomes $6,148/ton. The estimated costs for wet limestone scrubbing at Baldwin Unit 3 in 1982 is at the low end ofthe range ofthese permits and EPA guidance. The cost is therefore not unreasonable.
c. OtherEnvironmental Impacts Wet scrubbers produce a sludge that may. have economic use. Ifnot used, it must be disposed in a landfill. This sludge is not considered hazardous waste. No other significant environmental effect occurdue to the use ofscrubbers. d. Conclusion Based on the above data, I conclude that BACT at Baldwin Unit 3 in 1982 would have been an emission rate of0.3 pound/million BTU,2.?J 30 day rolling average, based on the use of 

### a wet limestone scrubberremoving 95% ofthe S02 from coal having a sulfurcontent of3-3.5%. Compliance with the limit would have been monitored by use ofa Continuous Emissions Monitoring System (CEMS).@ 2. Nitrogen Oxides In 1982, Unit 3, based limited data available, had uncontrolled NOx emission rates that appearto average about 0.47 pound/million BTU, and range as high as 0.75 pound/million**BTU.~** Several emissions control options were potentially available in 1982. I analyzed the following options to determine technical feasibility, availability and cost effectiveness for NOx control:1. Low NOxBurners ("LNB") 2. Overfire Air ("OFA")

¥1 See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline Refinery Projects, dated January 19, 2001. This information can be found at website address: http://www.epa.gov/rgytgmj/programs/artd/air/nsr/nsrmemos/t2bact.pdf 2.?J The limit of0.3 pounds permillion BTU is derived from 95% removal ofcoal with 3.5% sulfurand 10,900 BTU/pound. SeeTable 8a, S02 Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982 §' See 40 C.F.R Part 60, Appendix B, Performance Specification 2. See Compilation ofCEMS Data for the Baldwin Station, submitted by Illinois Power Companyto U.S. EPA. 17

# •

a. 3. Selective Catalytic Reduction ("SCR") 4. Flue Gas Recirculation ("FGR") Technical Feasibility



# •

• Low NOxburners limit NOx formation by controllingboth the stoichiometric and temperature profiles of the combustion process in each burner flame zone. This control is achieved with mechanical designs that regulate the aerodynamic distribution and mixing ofthe fuel and air which results in reduced oxygen concentration in the primary combustion zone, reduced flame temperature, or reduced residence time at the peak NOx formation temperature. There are many types ofLow-NOx burners for use on many types ofboilers (except cyclone**boilers.~** LNBs were installed in numerous facilities by 1982. At least seven plants were operating with LNBs worldwide by 

### 1982.211 At least one burnermanufacturerhad developed a burner capable of reaching levels ofless than 0.4 pound NOx/million BTU. That burner was installed at Utah Power and Light's Hunter Unit 2 and started operation in 1981.llI.2.JfAt least two other powerplants were permitted by 1982 with emission rates near 0.4 pound NOx/million BTU-Nevada Power's Harry Allen Station, and Tucson Electric Power's (TEP) Springerville Unit 3.11' Units 1 and 2 at TEP's Springerville, permitted in 1978, have achieved levels of approximately 0.4 pounds permillion BTU.12 All ofthe foregoing powerplants were designed as tangentially**fin~d** boilers
.

JSj Babcock & Wilcox, Steam/its generation anduse (39th ed. 1978). ?1J See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOxBurner Installations," developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc.

q •• III See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOxBurner Installations," developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc. 2.Jf Conversion from parts permillion to pounds permillion BTU based onEmissions standards handbook: airpollutantstandardsfor coal-firedpowerplants, Appendix, Hermine N. Soud, IEA Coal Research, December 1991. 11' See Appendix A, Table 1. 12 See U.S. EPA, Clean AirMarkets Division, "Emissions Scorecard." This information can be found at website address: http://www.epa:.gov/airmarkets/emissions/scoreOO/index.html. TEP's emission rate for 2000 was reportedto have been 0.39 poundslMMBTU. TEP has presumably maintained the same burners since the boilers were built. 18

# •

•

• The relevant NSPS requirement was an emission rate of0.6 pound/million BTU for coal fired powerplants burning bituminous coal, which is the coal that Illinois Power was burning in 1982. In 1982, several plants were in operationl9' orwere permitted for lower levels using LNBsP These installations demonstrate that, using LNBs, facilities would be capable ofreaching lower emission rates than the NSPS requires. Overfire air is a combustion control technique where a percentage**(~5** - 20%) ofthe total combustion air is diverted from the burners and injected through ports about the top burnerlevel. The zone where the coal is injected is slightly oxygen deficient (sub-stoichiometric) thereby suppressing production ofNOx' Combustion is completed in the over-fire air zone. Overfire air is sometimes called air staging. Overfire air limits NOx emissions by two mechanisms: (l) thermal NOx formation is delayed and suppressed because ofthe lower flame temperature and extended combustion zone, and (2) fuel NOx formation is suppressed because ofthe lower oxygen concentration in the lower furnace and the lower**temperature.~** Overfire air was installed in numerous facilities by 1982. By 1982, at least five plants were operating worldwide using OFA. However,OFA installations in the 1892 time frame in tangentially fired boilers appearto be an integral part ofLNB designs, and also appeardesigned to meet a limit of0.7 pound per million BTU. JJJ Selective Catalytic Reduction involves injecting ammonia into the flue gas before the gas reaches a catalyst, at a specific temperature. The catalyst lowers the energyrequired to complete the reaction ofthe ammonia with the NOxto form nitrogen and water, therefore the catalyst can be placed in a lowertemperature zone ofthe boiler. The most common catalysts are a vanadium/titanium composition, with vanadium pentoxide (V205) as the active catalyst and a titanium support, and operate at about 750F in hot side SCR systems. Zeolite catalysts are crystalline aluminosilicate compounds and can operate at a lowertemperature, typically found

19' See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations," developed in connection with United States v. Illinois Powerand Dvnegy Midwest Generation, Inc. ]]j See Appendix A, Table 1. 7Ji See U.S. EPA, Office ofAir and Radiation, Office ofAirQualityPlanning and Standards, "Alternative Control Technologies Document NOxEmissions from Utility Boilers" March 1994. This information can be found atwebsite address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. JJJ See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx BurnerInstallations," developed in connection with United States v. Illinois Power and Dvnegy Midwest Generation, Inc
. 19• after the preheater. Zeolite catalysts would be used in cold side SCR

## systems.~ Selective Catalytic Reduction was in use by 1982 on at least five coal fired powerplants woridwide.!!J·B' It therefore must be considered technicallyfeasible, an important consideration in the BACT analysis. However, the largest boiler with SCR installed at this time was 350 MW, which is much smallerthan Baldwin Unit 3, at almost 600 MW. In addition, in 1982, there were roughly two years ofworld-wide experience with SCR systems. To be most conservative in this retrospective analysis, Iwould conclude that the uncertainty associated with the newness ofthe technology and scale-up would mean that the technology was not available for use on Baldwin's Unit 3, and therefore was not a candidate for further BACT evaluation. Flue gas recirculation involves reintroducing flue gas from the economizer or airheaterinto the furnace for NOx control using ductwork and an additional fan. The method was originally developed for controlling superheater and reheater steam temperatures. NOx is reduced by lowering the temperature in combustion zone and therefore suppressing NOx fonnation. 

# •

• By 1982, flue gas recirculation was in use at a large number ofcombustion processes.!JI All of these installations appear to be designed to meet an emissions limit of0.7 poundsIMMBTU.§1' However, little data are available suggesting use and effectiveness ofFGR for NOx control at coal fired boilers. For that reason, I have excluded FGR from further analysis as a BACT option. b.
. Cost Analysis This section presents costs for the installation ofLNBs at Baldwin Unit**3.~** A state-of-the-art
See U.S. EPA, Office ofAir and Radiation, Office ofAir Quality Planning and Standards, "Alternative Control Technologies DocumentNOxEmissions from Utility Boilers" March 1994. This infonnation can be found at website address: http://www.epa.gov/ttn/catc/dirllutboiler.pdf. !!J See report ofWilliam Ellison, PE, Ellison Consultants, "Table 

### 2, SCR Installations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. B' See Ando, Jumpei, "S02 and NOx Removal for Coal Fired Boilers in Japan," presented at the Seventh Symposium on Flue Gas Desulfurization, May, 1982. See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. Ibid. OFA was excluded from further analysis because installations using OFA, in 1982, were emitting at about the same rate as Baldwin Unit 3 was, i.e. 0.7 pound/MMBTU. 20

# •

•

• LNB in 1982 would have been capable ofreducing emissions to less than 0.4 pound/million BTU. The annualized cost ofa LNB would have been $3.19 million, yielding acost effectiveness of$589/ ton ofNO. reduced.!§' These costs compare favorably to relevant, historical, PSD permits and cost analyses performed for air qualityplanning needs. For example, the New Jersey Department ofEnvironmental Protection issued permits in 1990 and 1991 that were based on a cost effectiveness of $13,200/ton.B' When converted to 1982 dollars, the New Jersey permits would require controls at a cost effectiveness**of$1O,600/ton.~** Also, in 1982 the South Coast AQMD (SCAQMD) adopted a revision to its air qualitymanagement**plan.~** That plan adopted control measures in' order for the area to meet the National Ambient Air Quality Standards (NAAQS) for nitrogen· dioxide (N02). Control measures for areas violating the NAAQS apply to a broad range of source categories, and are almost always retrofit measures. Consequently, the costs ofthese measures are generally less than BACT costs. The Los Angeles area, which is part ofthe jurisdiction ofthe SCAQMD, was the only area in the country not attaining the NAAQS for N02. The plan shows a number ofcontrol measures, some ofwhich would be implemented immediately, and some overtime. Forrules projected to be adopted between 1983 and 1986, the cost effectiveness was between $700/ton and $7,600/ton in 1987 dollars. When those values are adjusted to 1982 dollars, the range becomes $617 to $6700/ton. Lastly, in 2001 EPA issued guidance related to presumptive BACT for NO. at refineries being modified to meet EPA mandates for making cleanerburning gasoline.29' That guidance used $1 O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is converted to 1982 dollars it becomes $6,148/ton. The average cost per ton for NO. reductions at Baldwin Unit 3 in 1982 using LNBs is substantially lower than the acceptable high end for costs usedbyNJDEP and EPA in the two
.!lli See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NO. and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Power and DynegyMidwest Generation. Inc. 'f!J See Keystone Cogeneration FacilityBACT forNitrogen Oxides Addendum, June 1990, ENSR Consulting and Engineering. See http://www.enr.comlcost/costcci/asp for cost adjustments. Final Air Quality Management Plan, 1982 Revision, South Coast Air QualityManagement District and Southern CaliforniaAssociation ofGovernments, October 1982. 29' See memorandum from John 

### S. Seitz, Director, OAQPS, to AirDivision Directors regarding BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline Refinery Projects, dated January 19,2001. This information can be found at website address: http://www.epa.gov/rgytgrnj/programs/artdlair/nsr/nsrrnemos/t2bact.pdf 21

# • examples above, and similar to or less than the costs for most ofthe control measures in the SCAQMD plan. Therefore, the costs for LNBs at Baldwin Unit 3 in 1982 are not unreasonable.
c. Other Environmental Impacts No significant environmental impacts would have occurred as a result ofusing LNBs. d. Conclusion In summary, I conclude that 

### an emission rate of0.40 pounds permillion BTU (three hour average) based on the use ofLNBs was BACT for NOx at Baldwin #3 in 1982. Compliance with the limit would be monitored by use ofa Continuous Emissions Monitoring System (CEMS). 3. Particulate Matter As of 1982, Baldwin Unit 3 was equipped with an electrostatic precipitator. Data reported by Illinois Powershow that it was achieving a removal efficiencyofabout 99.4-99.5%.2.!I The following emissions control options were available for consideration in 1982. 1. Electrostatic Precipitator (ESP) 

# •
a. 2. Baghouse Technical Feasibility



# • An ESP was in use on BaldwinUnit 3 

### in 1982. It was therefore, technil;aUy feasible and available. A baghouse is also a feasible option. Several facilities were reported to be using baghouses in '1982, and achieving limits as low as .005 gr/ACF.2Y (This equates to 99.7% control at Baldwin Unit

# 3.PBaghouses were therefore also technically feasible and available. The removal efficiencythat Baldwin Unit 3 was achieving in 1982 compares favorably with the

2.!1 Department ofEnergy, Energy Information Administration (Form EIA-767) for 1982. IPPRO-Ol04439-0104464. 2Y See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 2JI See Table 7 for derivation ofcontrol level. 22

# •

•

• baghouses in 1982, and achieving limits as low as .005 gr/ACF.'l1J(This equates to 99.7% control at Baldwin Unit

## 3.p Baghouses were therefore also technically feasible and available. The removal efficiency that Baldwin Unit 3 was achieving in 1982 compares favorably with the permitted emission rate for the Harry Allen Station (where a particulate matter emission rate of 0.015 pound/MMBTU was required, based on aremoval rate of99.76%). Although that permit assumed that abaghousewould be required to meet the removal rate, it also allowed the applicant to use an ESP ifdata were submitted demonstrating that the ESP was likely to be able to achieve that rate. Baldwin Unit 3's ESP was controlling emissions to about 99.4% in 1982.2JI IfIllinois Powerhad been required to add controls (likely to be an additional baghouse or anotherfield in its ESP) to control its emissions to the then state ofthe art (i.e. to about 99.7% control), the costs would likely have been substantial. b. Conclusion Ihave concluded that BACT for PM at Baldwin unit 3 in 1982 would have been an emission rate of0.036 pounds per million BTU, based on 99.4% removal and the emissions controls already in place at Baldwin Unit 3 in 1982. Compliance would have been monitored using EPA method 5 and an opacity monitor. B. BACT Determination For Baldwin Unit I: 1985 Unit 1 is acyclone fired boilerwith a gross output rating of584 megawatts (MW)29' and began operation in I 970.'!1JIt is designed to fire 267 tons perhour ofcoal2!' with a heating value of

'l1J See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and Dynegy Midwest Generation. Inc. 2]j See Table 7 for derivation ofcontrol·level. 2.*' See EPA permit for

### Harry Allen Station, 

### NY-77-Oland associated National AmbientAir Quality Impact Report. 2JI Department ofEnergy, Energy Information Administration, (Form EIA.-767) for year 1982. '1!i Sargent & Lundy Engineers Engineering Data, 

### Unit 1 BaldwinPower Station. IPPRO0085676-744. '!1J Ibid. Department ofEnergy, Energy Information Administration, (Form EIA-767) for year 1985
. 23• I985
..!.Q9' The available control technologies are the same as those that were potentiallyapplicable to Unit 3 in 1982.
a. Technical Feasibility By 1985, at least thirty-five additional (compared to 1982) coal fired powerplants were in operation with scrubbers to remove S02 from their exhaustgas. Most ofthese scrubbers were wet limestone orwet lime buffered with magnesium oxide.!illJ·!Q5' These two types ofscrubbers were technically feasible in 1985. b. Cost Analysis


# •

• The cost in 1985 ofscrubbers capable ofremoving 95% offlue gas S02 was analyzed based on 

### a studyconducted by Illinois Power in 1991 to install flue gas desulfurization systems on Unit 1.!Q}f Most ofthe methodology used in 1991 would also apply to Unit 1 in 1985. According to that study, capital costs for the wet limestone scrubberare estimated to have been approximately $189 million
..!Q1' Operating costs would have ranged from $3.53 million to 5.04 million, depending on whetherwaste from the scrubber system would have been sold
.. When these costs are converted to annualized costs, the annual costwould have been between $23.5 and 25.0 million. Analysis ofwet lime scrubberbuffed with magnesium oxide shows it to be more

.!.Q9' See Expert Report ofRanajit (Ron) Sahu, April 2002, compiling CEMS data submitted by Illinois PowerCompany to U.S. EPA
. .!Q!I See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCR Installations," developed in connection with United States v. Illinois Power and Dynegy Midwest Generation. Inc. !.Q2{ See "Table 30: Flue Gas Desulfurization (FGD) Capacity in Operation at U.S. Electric Utility Plants as ofDecember 1999." This information can be found at website address: http://www.eia.doe.gov/cneaf/electricity/epav2/html_tables/epav2t30pl.html and following pages .!Qat Babcock and Wilcox, Contract Research Division and Environmental EquipmentDivision, Volumes 

### I-IV ofProposal for Full-Scale Demonstration ofIntegrated Flue Gas Desulfurization System with Rebuming NOx Control, B&W Proposal #90-071 (May 1991), IPPRO-0128923- 0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-OI27567-0127848
. .!Q1' See report ofDan Mussatti and 

### Lany Sorrels, "Estimated Costs for the Installation ofS02' NO and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with x . United States v. Illinois Powerand Dynegy Midwest Generation. Inc
. 24

# •

•

• expensive for the same level ofcontrol as the wet limestone scrubber, therefore onlythe wet limestone option received further consideration.

### w The wet limestone scrubberwould remove 96,800 tons per yearofS02' Therefore, the cost effectiveness ofa limestone FGD system would have been approximately $258/ton in 1985
..!Q9' In order to ensure that the costs estimated for the scrubber are not excessive, Ireviewed other BACT determinations and EPA policy documents. I reviewed the cost effectiveness ofeighteen powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. Ofthose where a dollarper ton cost effectiveness was listed, the range (once converted to 1985 dollars) is $155 to 4715/ton
..!Q]jAlso, in 2001, EPA issued guidance related to presumptive BACT for NOx at refineries being modified to meet EPA mandates for making cleanerburning gasoline
..!.Q.§' That guidance used $1 O,OOO/ton as an upperbound for BACT cost effectiveness. When that value is converted to 1985 dollars it becomes $6,581/ton. The estimated costs for wet limestone scrubbing at Baldwin Unit 1 in 1985 is at the low end ofthe range ofthese permits and EPA guidance. The cost is therefore not unreasonable.
c. OtherEnvironmental Impacts Wet scrubbers produce a sludge that mayhave economic use. Ifnot used, it must be disposed in a landfill. This sludge is not considered hazardous waste. No other significant environmental effect occurdue to the use ofscrubbers. d. Conclusion Based on the above data, I conclude that BACT for S02 atBaldwinUnit I in 1985 would have been an emission rate of0.30 pound/million**BTU,~** 30 dayrolling average, based on the use of a wet limestone scrubberremoving 95% ofthe S02 from coal having a sulfurcontent of3-3.5%. Compliance with the limit wouldhave been monitored by use ofa Continuous Emissions Monitoring System (CEMS)
..!.!9' Ibid; also see http://www.enr.com/cost/costcci.asp for cost adjustments
. .!Q9' See Table 8b for calculations
. .!Q7I See Table 11, Cost Effectiveness ofBACT Determinations for S02' .!.Q.§' See memorandum from John S. Seitz, Director, OAQPS, to AirDivision Directors regarding BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline RefineryProjects, dated January 19,2001. This information can be found at website address: http://www.epa.gov/rgytgmj/programs/artd/air/nsr/nsrmemos/t2bact.pdf !Q2' See Table 8b for calculations. ill' See 40 C.F.R Part 60, Appendix B, Performance Specification 2. 25

# • 2. Nitrogen Oxides



# •

• As of 1985, Baldwin Unit 1 had no controls in place for NO. emissions
..!..!JI Unit I's NO. emissions are estimated to have been approximately 1.8 pounds per million BTU
..!..!1I The relevant NSPS requirement was an emission rate of0.6 pound/million BTU for coal fired powerplants burning bituminous coal, which is the coal that Illinois Power was burning in 1985.
a. Technical Feasibility For Unit 1, in 1985, I considered the feasibility ofLNBs, OFA, SCR and SNCR. LNBs were not technically feasible because they simplyhave notbeen developed for use on cyclone fired boilers. As to OFA, from the vantage point of2001, for cyclone fired boilers, OFA would appear to have been technically feasible, but no installations on cyclone boilers appear to have been in place by 1985.ill Therefore, in myjudgement, given the technical difficulty ofengineering an overfire air system for a cyclone fired boiler, I would considerthat technology also to be unavailable for use on Unit 1 in 1985. However, in contrast to1982, by 1985, SCR had been used for coal fired boilers for at least five years. For example, by 1985, at least three Japanese facilities (i.e., Shiminoseki, Shin Ube and Tomatoatsuma) had operated five years.lli' In addition, at least sixteen SCR systems on coal fired powerplantboilers in Japan were in operation orunder construction by this time, including both new and retrofit facilities. These powerplantboilers ranged in size from 125 to 700 megawatts in size.illJ Planned reduction rates are not available for all ofthese facilities, but for a subset in operation by 1984, reduction ranged from 57 to 81 %.lli' Operational problems experienced in the

.!..!JI Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985
. .!..!11 See Expert Report ofRanajit (Ron) Sahu, April, 2002, compiling CEMS data submitted by Illinois PowerCompanyto U.S. EPA. ill Seereport ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. No instance ofOFA were located in the relevant timeframe. ill' See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Powerand Dynegy Midwest Generation, Inc. illJ See Ando, Jumpei, "S02 andNO xRemovalFor Coal-FiredBoilers in Japan," presented to the Seventh Symposium on Flue Gas Desulfurization, May, 1982. ill' See U.S. EPA, Air and EnergyEngineering Research Laboratory, Office ofEnvironmental Engineering and Technology, "RecentDevelopments in S02 and NO. Abatement Technology," September 1985
. 26

# •

•

• early stages ofSCR development had been solved by this time.ill Two German facilities that would begin operation in 1986 were likely underconstruction.ill' Also, by 1985, SCR had begun to be used in the United States. For example, use ofSCR, by 1984, resulted in a Lowest Achievable Emission Rate (LAER) emission rate for combined cycle gas turbines.!.!2t,.Jl!)' An additional technology that would have been considered in 1985 is Selective Non-Catalytic Reduction (SNCR). This process involves injection ofammonia into the combustion chamber at a point where the temperature is in aprecise range:illJ SNCRsystems have lower capital costs than SCR, but typicallyhave higher ammonia emissions levels compared to SCR, i.e. 30 to 40 parts permillion (ppm) compared to as little as 1 ppm for SCR systems.ill Beginning in about 1985, many coal fired powerplants were permitted using SNCR
..ill' However, none ofthese were cyclone fired boi1ers
..!11'Therefore, I would conclude that SNCR was not available in 1985 for

ill Ibid, page 5-2. ill' See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2,'SCR Installations," developed in connection with United States v. Illinois Powerand Dynegy Midwest Generatiori, Inc. !.!2t Personal conversation with Robert Pease, Air Quality Analysis/Compliance Supervisor, South Coast AQMD, September 19, 2001. Mr. Pease visited Japan in June 1984 to observe the operation ofSCRon a large gas turbine. In July 1984, Mr. Pease prepared a report for the AQMD about its operation, and shortlythereafterbegan to require combined gas turbines to meet a 9 ppm NOx limit. ll9' LAER is generallythe most effective emission limit that has been achieved for a source category. Consequently, the LAER emission rate, and the technology on which it is based, would generally be the most effective emission control option in a BACT analysis, and mustbe considered. ill! See U.S. EPA, Office ofAir and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies DocumentNOx Emissions from Utility Boilers" March 1994. This information can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. ill See U.S. EPA, Office ofAir and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies DocumentNOxEmissions from Utility Boilers" March 1994. This information can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. ill{ References: PSD permit #s SE 85-01, 85-05, SJ 85-06, SJ 85-07, SJ SE 86-04, SJ 86-08,86- 09. ill' See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. See also U.S. EPA, Office ofAir 27• use on cyclone fired boilers. In summary, SCR was the sole NOx control technology available for cyclone fired boilers in 1985. Moreover, a 55% reduction in emissions was well demonstrated for SCR based on the technical feasibility above. However, there is little infonnation in the literature as to the effectiveness ofSCR as the boilerundergoes changes in load. Current day control systems are able to react and adjust operation ofthe SCR to maintain a given level ofcontrol; systems in the mid '80s were less capable. 

### In orderto account for this lesser level ofeffectiveness ofthe SCR system during load changes, I assigned slightly less efficiency, 50%, to the SCR system, which could have been easily achieved on Baldwin's Unit 1 in 1985. A 50% reduction applied to uncontrolled emissions of 

### 1.8 pound/million BTU yields an emission rate of0.90 pounds per million BTU. b. Cost Analysis


# •

• The estimated cost ofan SCR system at Baldwin Unit 1 in 1985 was based on Illinois Power's study for installation SCR at Units 1 and 2. illISince that study was conducted in 1990, the costs were adjusted to reflect 1985 dollars
..The capital cost ofSCR in1985 is estimated to be $88.6 million, and annual operating costs are estimated to be $3.43 million. The annualized cost would be $20.2 million
..!l9' This yields a cost effectiveness of$1368/ton reduced.

### m .@ These costs are likely to be conservative. For example, the 1990 studywas for an installation that would remove
and Radiation, Office ofAir QualityPlanning and Standards, "Alternative ControlTechnologies Document NOx Emissions from UtilityBoilers" March 1994, page 49. This information can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. ill! See report ofDan Mussatti and Lany Sorrels, "Estimated Costs for the Installation ofSOz , NOxand PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States 

### v. Illinois Powerand Dynegy Midwest Generation, Inc
. .!l9' Ibid. gy See Table 3b for calculations.
@ This cost estimate assumes that the catalyst would be replaced every three years. That assumption maybe veryconservative. At least one earlySCR installation, at Knepper Unit C in Gennany, went into service in 1986, and, as of1998, was operating with 56% ofits original catalyst. Anotherplant, Velthiem, began operation in 1989, and as of1998, was operating with all ofits original catalyst, together with an additional amount ofcatalyst added after two to three years ofoperation. See "Development and Commercial Operating Experience ofSCRdeNOx Catalysts for Wet-Bottom Coal-Fired Boilers," Isato MoritaetaI, Presented to Power-Gen International '98, December 1998. This document maybe found at website address http://www.babcock.com/pggltt/pdfIBR-1665.pdf
. 28

# •

•

• 85% ofNO" from the exhaust stream. 

### In contrast, a 55% reduction ofNO" was used for this analysis. The lowerremoval rate should reduce costs in two ways. First, less catalyst would be required, reducing capital cost, and secondly, less ammonia would need to be injected into the SCR system, reducing operating cost. Lastly, because less catalyst would initially be used, less catalyst would need to be periodicallyreplaced. In spite ofthese likelycost reductions, ourcost estimate did not take the lowerremoval rate into account. Therefore, these cost estimates are likely to be quite conservative. This cost compares favorably to some ofthe same relevant benchmarks mentioned above. For example, the New JerseyDepartment ofEnvironmental Protection issued permits in 1990 and 1991 that were based on a cost effectiveness of$13,200/ton. When converted to 1985 dollars, the New Jerseypermits would require controls at acost effectiveness of$11 ,700.!l2JAlso, in 1982 the South Coast AQMD (SCAQMD) adopted a revision to its air qualitymanagement plan.1ill' That plan adopted control measures in order for the area to meet the National Ambient Air Quality Standards (NAAQS) for nitrogen dioxide (N02). Control measures for areas violating the NAAQS applyto abroad range ofsourcecategories, and are almost always retrofit measures. Consequently, the costs ofthese measures are generally less than BACT costs. The Los Angeles area, which is part ofthejurisdiction ofthe SCAQMD, was the only area in the country not attaining the NAAQS for N02. The plan shows anumberofcontrol measures, some ofwhich wouldbe implemented immediately, and some overtime. Forrules projected to be adopted between 1983 and 1986, the cost effectiveness was between $700/ton and $7,600/ton in 1987 dollars. When those values are adjusted to 1985 dollars, the range becomes $660 to $7180/ton. Lastly, in 2001 EPA issued guidance related to presumptive BACT for NO" at refineries being modified to meet EPA mandates for making cleaner burning gasoline.1l!JThat guidance used $10,000/ton as an upperbound for BACT cost effectiveness. When that value is converted to1985 dollars it becomes $6,620/ton. The average cost perton for NO" reductions usingSCR at Baldwin Unit 1 in 1985 is substantially lower than the acceptable high end for costs used by NJDEP and EPA in the two examples above, and similarto orless than the costs for most ofthe control measures in the SCAQMD plan. Therefore, the costs for LNBs at Baldwin Unit I in 1985 are not unreasonable.
c. OtherEnvironmental Impacts
ill! See http://www.enr.com/cost/costccilasp for cost adjustments. 119' Final Air QualityManagement Plan, 1982 Revision, South Coast Air QualityManagement District and Southern California Association ofGovemments, October 1982. ill See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline RefineryProjects, dated January 19, 2001. This information can be found at website address: http://www.epa.gov/rgytgrnj/programs/artdJair/nsr/nsrmemos/t2bact.pdf 29

# • SCR and SNCR use ammonia, which could cause environmental effects ifemitted in large amounts. However, ammonia slip (unreacted ammonia emitted to the atmosphere) is limited by design in SCR systems to about 3 ppm, so effects would not be likelyto occur. SNCR typically has a higher ammonia slip; as high as 30 ppm. Because ofthe higher ammonia slip rate for SNCR, SCR would usually be preferred because ofits lower other environmental impacts. d. Conclusion I conclude that an emission rate of0.90 pound/million BTU (3 hour average) based on the use of SCR was BACT for Baldwin Unit 1 in 1985. Compliance with the limit would have been monitored by use ofa Continuous Emissions Monitoring System (CEMS).ill' 3. Particulate Matter In 1985, Baldwin Unit 1 was operating with an ESP to control particulate emissions. Based on Illinois Power's reported efficiency, which started at 96% in 1982 and decreased overtime to 90% in I985,illJit appears that the ESP was in need ofsignificant maintenance or repair. Illinois Power also performed periodic tests ofthe ESP. Based on the 1984 tests, I estimate emissions to have been approximately 580 pounds perhourlli' but, based on other tests performed before and afterthat date, showing that emissions were highly variable, I concludelhat emissions could have been as high as 879 pounds per hour in 1985
. 

# • a. Technical Feasibility



# • In order to reduce emissions further, one ofthe following actions would need to be taken at Baldwin Unit 1:

- Replacement ofcurrent ESP with new ESP orbaghouse,

- Upgrade ofESP.

ill' See 40 C.F.R Part 60, Appendix B, Performance Specification 2. illJ See EIA Reports numbered IPPRO-OI04246; IPPRO-0104275; IPPRO-OI04304; IPPRO0104333; IPPRO-OI04370; IPPRO-OI04404; IPPRO-OI04456; IPPRO-0104457; IPPRO0104480; IPPRO-O104481; IPPRO-O104503 and IPPRO-O 104504. lli See Summary ofStack Test Data (0.1 poundIMMBTU); 5,824 MMBTU/hrderived from document number B&W02758. IPPRO-0021437; IPPRO-0016781; IPPRO-0020203; EPA6427; IPPRO-0049695; IPPRO-0057472; IPPRO-0020445; IPPRO-0016913; IPPRO-0017018; IPPRO-0018463; IPPRO-0002372; IPPRO-0020345; IPPRO-0071136; IPPRO-OOI8582; IPPRO-OOI6835; IPPRO-0021387; IPPRO-0070999
. 30

# •

•

• Forthis analysis, I have assessed only the option ofreplacing the ESP with either a new ESP ora baghollse. In 1991, Illinois Power analyzed the options to increase particulate control at Units I and 2.illIThey concluded that a replacement ESP would be more cost effective than an upgrade ofthe existing ESP. Illinois Powerdid not analyze the cost ofreplacing the ESP with abaghouse. Among the conclusions ofthat study was that the existing ESP was in "poor condition," and that a "majorupgrade and refurbishment ofthe existing ESP will be required in orderto obtain another 30 years ofservice."ilii' Since this studywas conducted only about five years after 1985, I believe its conclusions would generally have applied in 1985, i.e., that the existing ESP was near the end ofits useful life and that a new orrefurbished control device would be soon be needed.
1. Baghouse In 1985, it would have been technically feasible for Illinois Power to substantially improve its particulate control with a baghouse. By 1985, at least 29 coal fired powerplants had installed baghouses designed to achieve levels ofPM less than 0.01 grain/ACF (actual cubic foot).ill Of those 29, many were designed to achieve levels ofbetween 0.001 and 0.005 gr/ACF.ill' This level is approximately equal to a 98.3 to 99.6% reduction ofuncontrolled emissions at Baldwin Unit l.lli' An emission rate of.003 gr/ ACF is equivalent to 99.7% control at Baldwin Unit l.lli'
11. ESP As of 1982, Illinois Power operated an ESP on Unit 3 with a removal efficiency ofapproximately 99.4% (see 1982 analysis, above). This alone demonstrates the technical feasibility ofan ESP at Baldwin at that removal efficiency.
a. Cost Analysis

ill! See Bums and McDonnell report, "Baldwin Unit 1 Electrostatic Precipitator Study" (1991). IPPRO-0058084 through JPPRO-0058136. lli' Ibid., page II-I. IPPRO-0058092. ill See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc. ill' See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc. ill' See Appendix A, Table 4b: Emissions Calculations and Cost Effectiveness for Particulate Matter in 1985. See Table 4c for calculations. 31

# •

•

• Based on a design to remove 99.6% ofparticulatematter (based on the capability ofabaghouse, as discussed in the 1982 analysis, above), an ESP is estimated to have an annualized cost of about $19 million (and acapital cost of$105 million)
..!i1IA baghouse with similarcapabilities would have an annualized cost of $10.9 million (and a capital cost of$55 million).ill' Since the baghouse would be less expensive for the same level ofemissions reduction, that is the option that Iconsidered for further analysis. The total cost effectiveness ofthe baghouse would be $81l/ton. Comparable cost effectiveness values are not available for cyclone fired boilers (which have much lower inlet PM loadings than tangentiallyfired boilers). However, construction cost data are available for powerplants constructed in the 1985 timeframe. These data show that the estimated construction cost for abaghouse is similarto that ofothercontemporaneous sources. Forexample, ArizonaPublic Service's Four Comers Unit 4 (818 MW), built in 1982, reported a capital cost of$90 million for its baghouse removing 99.8% ofPM. TampaElectric's Big Bend Unit 4 (445 MW), built in 1985, reported a capital cost of$76.8 million for its ESP removing 99.7% ofPM. Paradise Unit I (704 MW), built in 1983, reported a capital cost of$210 million for its ESP removing 99.9% ofPM. The estimated costs for abaghouse at Baldwin Unit 1 in 1985 are within the range ofcosts for similarfacilities at that time, and are therefore not unreasonable.ill b. OtherEnvironmental Impacts No significant environmental impacts would occur from the use ofa baghouse. Collected ash from the baghouse would need to be disposed of, but is not considered hazardous waste.
c. Conclusion I have determined that BACT for particulate matter for Unit I in 1985 wouldhave been an emission limit of0.003 pound/million BTU and the use ofabaghouse and 99.6% removal.lli' Compliance would have been monitored using EPA method 5 and an opacityCEMS
.

.!1!J See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NO, and PM Control Devices atIllinois Power's Baldwin Station," developed in connection with United States v. Illinois Power and Dvnegy Midwest Generation, Inc. ill' Ibid. ill! Department ofEnergy, EnergyInfonnation Administration (Form EIA-767) for 2000. lli' See Table4b for calculations
. 32• C. BACT Determination for Baldwin Unit 2: 1988 Unit 2 is a a cyclone fired boiler and has a gross capacity of587 MW.illI Unit 2 began operation in 1973
..!i9' It was designed to fire up to 267 tons per hourill ofcoal with a heating value of 10,460 BTU perpound.ill' 1. SOl Control As of1988, Baldwin Unit 2 was uncontrolled for emissions ofS02 , and was burning coal with a sulfurcontent of3%.H2I
a. Technical Feasibility



# •

• Control options for S02 control in 1988 were similar to the options available in 1985, as I discussed previously (see Baldwin Unit 2, 1985, above). However, by 1988, powerplant owners had more experience with all the scrubber options. 

### In addition, many new facilities had come on line by 1988 utilizing scrubbers to remove S02. Over 148 coal fired powerplants with scrubbers were in operation in the U.S. bythe end of1988. Most ofthese scrubbers were operating at a removal efficiency of80 to 95%
..ll!YOutside the U.S. similarincreases in scrubbercapacity occurred. Most significant is the Preussen Electric Borken 2 and 3 facilities, which started operation in 1988, and which employed scrubbers with a design removal efficiency of97% of S02·.wJ Since there was only one powerplant operating at 97%, I continued to analyze scrubber

ill! Ratings ofIllinois Power Company Fossil Fuel Fired Generating Units; ReportbyPower Technologies, Inc. December, 1987. IPPRO-00151120 ill' Department ofEnergy, Energy Infonnation Administration (Form EIA-767) for 1985. ill Ibid. Sargent & Lundy Engineers Engineering Data, Unit 3 Baldwin PowerStation. IPPRO0085900 H2I Department ofEnergy, Energy Information Administration (Form EIA-767) for 1988
. .ll!Y See "Table 30: Flue Gas Desulfurization (FGD) Capacity in Operation at U.S. Electric Utility Plants as ofDecember 1999." This information can be found at website address: http://www.eia.doe.gov/cneaf/electricity/epav2/html_tables/epav2t30pl.html and following pages .wJ See report ofWilliam Ellison, PE, Ellison Consultants, "Table 1, FGD Installations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc
. 33• options based on 95% control. By 1988, scrubber technologies were mature. Both scrubbers previously analyzed (i.e. wet limestone and wet lime buffered by magnesium oxide) had been well demonstrated. b. Cost Analysis Capital and operating costs for wet limestone and wet lime with magnesium buffering were analyzed for the 1985 scenario. That analysis (see analysis for Unit 1, 1985) showed that wet limestone scrubbing was the less expensive option. The least cost option continues to be wet limestone scrubbing in 1988. Capital costs for the limestone system would beapproximately $204 million (1988 dollars). Operating costs would range from $3.8 million and 5.4 million, depending on whether waste from the scrubber system would have been sold or not. When these costs are converted to annualized costs, the annual cost would be approximately $27.1 million. The scrubber system would remove approximately 96,800 tons peryear ofS02' Therefore, the cost effectiveness the limestone FGD system would have been approximately $280/ton.illI 

# •

• As with the analysis ofscrubbers in 1985, this cost compares very favorably to the cost effectiveness ofeighteen powerplants peITIlittedbetween 1979 and 1999 with BACT requirements for scrubbers. Ofthose where a dollarper ton cost effectiveness was listed, the range (once converted to 1988 dollars) is $167 to 5092/ton.ill As also noted above, EPA's 2001 guidance related to presumptive BACT for NOx at refineries cited $1 O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is converted tol988 dollars itbecomes $7,149/ton. The estimated costs for wet limestone scrubbing at Baldwin Unit 2 in 1988 is at the low end of the range ofthese permits and EPA guidance. The cost is therefore not unreasonable.
c. Other Environmental Impacts Wet scrubbers produce a sludge that mayhave economic use. Ifnot used, itmust be disposed in a landfill. This sludge is not consideredhazardous waste. No other significant environmental effect occur due to the use ofscrubbers. d. Conclusion Based on the above data, I conclude that BACT at Baldwin Unit 2 in 1988 would havebeen an

ill' See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NO. and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc.; cost data adjusted based on http://www.enr.com/cost/costccLasp. ill! See Table 11, Cost Effectiveness ofBACT Determinations for S02' 34

# •

•

• emission rate of0.30 pound/million**BTU,!~** 30 dayrolling average, based on the use ofa wet limestone scrubber removing 95% ofthe S02 from coal having a sulfur contentof3-3.5%. Compliance with the limit would have been monitored by use ofa Continuous Emissions Monitoring System (CEMS).illI 2. NOr Control Like Unit 1, as of 1988, Baldwin Unit 2 had no controls for NOx emissions.lli'
a. Technical Feasibility ForUnit 2 in 1988, I again considered the feasibility ofLNBs, OFA, SNCR and SCR. Ofthese options, LNBs were not technically feasible in 1988, because they have not today been developed for cyclone fired boilers. OFA was also not technically feasible by 1988. While OFA had been used on othertypes ofcoal combustion, it had not been used on cyclone fired boilers.ill SNCR had been demonstrated by 1988 on a number offacilities overseas firing high sulfurcoal, as well as manyfluidized bed coal fired boilers permitted and underconstruction in the U.S. using low sulfur coal. By 1988, at least seven coal fired powerplants in the U.S. were required to use SNCR to control NOx'.!.3' Emissions reductions ofapproximately 50% were expected at these facilities, and the permits included emissions limits in the range of0.09-0.15 pounds/million BTU.illI
..lliY With respect to SCR, by 1988, significant additional experience had been gained worldwide in the application ofthis technology to coal fired boilers. SCRhad been installed on at least two

ill' See Table 8c for calculations. illI See 40 C.F.RPart 60, Appendix 

### B, Performance Specification 

### 2. lli' Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1988. ill See report ofWilliam Ellison, PE, Ellison Consultants, "Table I, FGD Installations," developed in connection with United States v. Illinois Power and Dynegy Midwest Generation. Inc. ill' See PSD permit#s SE**85~01, 85~05,**  SJ 85-06, SJ 85-07, SJ SE 86-04, SJ 86-08, 86-09. illJ Ibid
. .lliY See Kern County AirPollution Control District, Engineering Analysis ofMt.PosolPyropower Cogeneration Facility, November 1986, page 67. "
...an emission rate of

### 0.092 pound NO/MMBTU satisfies NOx LAERrequirement." 35

# •

•

• cyclone, (or "wet bottom") boilers, as well as many other coal fired powerplants.ill By 1988, twenty-five coal fired boilers in Japan, six in Germany and two in Austria had begun commercial operation ofSCR systems for NOx control.illI These installations were across a wide range ofboiler size. For example, the Gennan boilers vary in capacity from 153 MWe (Walheim, wet bottom boiler) to 770 MWe (Ibbenbuehren), and bum coal with sulfurcontents up to 1.3%
..!§' The use of SCR at these boilers achieved NOx control efficiencies ranging from 67 to 92 percent. Six other facilities were underconstruction overseas and would begin operationby 1992. 1M' Because all but one ofthese Gennan facilities had SCR with design NOx reduction levels of approximately 80% orgreater,ill! I have detennined that level ofreduction was technically feasible in 1988. b. Cost Analysis SCR was the top, ormost effective, option for available in 1988. Unless it were to be rejected on the grounds ofunacceptable environmental or economic cost, SCRwould be chosen as BACT. As in the 1985 analysis above, the cost for SCRwas estimated using Illinois Power's study!§.§' for installing SCR onunits 1 and 2 in 1990. The costs were then adjusted to 1988 values.ill These adjustments yield an annualized cost of$22.6 million. SCR would reduce Unit 1 emissions by about 23,604 tons/year, based on a 1.8 pound NO/MMBTU inlet concentration and a 66.7

ill' Ibid. ill;' See ENSR Consulting and Engineering, "Keystone CogenerationFacility BACT for Nitrogen Oxides, Addendum," June 1990. ill' See report ofWilliam Ellison, PE, Ellison Consultants, '·Table 2, SCR Installations," developed in connection with United States v. Illinois Powerand DynegyMidwest Generation, Inc.**~Ibid.** ill! See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCRInstallations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. lliJ' See SCR Cost Evaluation for Illinois Power, Baldwin Units 1 & 2, May 17, 1990. Prepared byBums & McDonnell, Kansas City, MO. J!ilJ See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NO and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with x United States v. Illinois Powerand DynegyMidwest Generation, Inc
. 36

# •

•

• percent capacity factor, and an SCR system that removes 80% ofthe inlet NO•.@The annualized cost ofan SCR system is estimated to have been approximately $22.6 million. This results in a cost effectiveness of$959/ton. As in 1985, this cost perton compares very favorably with relevant PSD permits and cost analysis perfoffi1ed for air quality planningpurposes. As noted above, the New Jersey Department ofEnvironmental Protection issued permits in 1990 and 1991 that were based on a cost effectiveness of$13,200/ton. When converted to1988 dollars, the New Jersey peffi1its would require controls at a cost effectiveness of$12,640.W Also, as noted above, in 1982 the SCAQMD adopted an air quality management plan..!1!¥establishing control measures to help bring the area into compliance with the NAAQS. For rules projected to be adopted between 1983 and 1986, the cost effectiveness was between $7001ton and $7,600/ton in 1987 dollars. When those values are adjusted to 1988 dollars, the range becomes $713 to $7,750/ton. Lastly, in 2001 EPA issued guidance related to presumptive BACT for NO. at refineries being modified to meet EPA mandates for making cleanerburning gasoline
..!2!IThat guidance used $1O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is converted to1988 dollars it becomes $7, 150/ton. The estimated costs for SCR at Baldwin Unit 2 in 1988 is at the low end ofthe range ofthese peffi1its and EPA guidance. The cost is therefore not unreasonable.
c. OtherEnvironmental Impacts SCR and SNCR use ammonia, which could cause environmental effects ifemitted in large amounts. However, ammonia slip (unreacted ammonia emitted to the atmosphere) is limited by design in SCR systems to about 3 ppm, so effects would notbe likelyto occur. SNCR typically has a higher ammonia slip; as high as 30 ppm. Because ofthe higher ammonia slip rate for SNCR, SCR would usuallybepreferred because ofits lower other environmental impacts. d. Conclusion Based on the analysis above, I conclude that an emission limit of0.36 poundslMMBTU, 3 hour average based on the use ofSCRwith 80% removal was BACT for Unit 2 in 1988. Compliance

.!§' Ibid. illI See http://www.enr.com/cost/costcci/asp for cost adjustments
. .!l9' Final Air Quality Management Plan, 1982 Revision, South Coast Air Quality Management District and Southern California Association ofGovernments, October 1982. ill See memorandum from John S. Seitz, Director, OAQPS, to AirDivision Directors regarding BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline Refinery Projects, dated January 19, 2001. This information can be found at website address: http://www.epa.gov/rgytgrnj/programs/artd/air/nsr:Lnsffi1emos/t2bacLpdf 37• with the limit would have been monitored with aCEMS. 3. Particulate Matter As of 1988, Baldwin Unit 2 was operating with an ESP that had demonstrated efficiencies ranging from 93 to 97%, with an apparent downward trend in efficiency.1B' In order to reduce emissions further, one ofthe following actions would need to be taken at Baldwin Unit 2:

- Replacement ofcurrent ESP with new ESP orbaghouse,

- Upgrade ofESP.
a. Technical feasibility


# •

• Forthis analysis, Ihave again assessed onlythe option ofreplacing the ESP at Baldwin with eithera new, more efficient ESP or a baghouse. The ESP for Unit 2 was designed for 99% removal efficiency, but had performed at significantly lowerremoval efficiencies,.!DI suggesting that the unit would need significant repair orupgrade. As noted above, Illinois Power's studyof PM controls for Unit 1, which is very similarto Unit 2, showed that the least cost option would be replacement; rather than upgrade, ofthe existing ESP (Illinois Powerdid not analyze the option ofreplacing the ESP with abaghouse).lli' Those conclusions should be equally applicable to Unit 2.
1. Baghouse 

### In 1985, it would have been technically feasible for Illinois Powerto substantially improve its particulate control with a baghouse. As of1988, at least 32 coal fired powerplants had installed baghouses designed to achieve levels ofPM less than 0.01 grain/ACF (actual cubic foot).ill' Of



### m See EIA Reports numbered IPPRO-OI04246; IPPRO-0104275; IPPRO-OI04304; IPPRO0104333; IPPRO-OI04370; IPPRO-OI04404; IPPRO-0104456; IPPRO-0104457; IPPRO0104480; IPPRO-0104481; IPPRO-OI04503 and IPPRO-OI04504. ill' Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1988. ill' See Bums and McDonnell report, "Baldwin Unit I Electrostatic Precipitator Study" (1991). IPPRO-0058084 through IPPRO-0058136. ill' See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and Dvnegy Midwest Generation, Inc
. 38

# •

•

• those 32, many were designed to achieve levels ofbetween 0.001 and 0.005 gr/ACF.1.Th' An emission rate of.003 gr/ACF is equivalent to 99.7% control at Baldwin Unit l.

## m ii. ESP As of1982, Illinois Power operated an ESP on Unit 3 with aremoval efficiency ofapproximately 99.4% (see 1982 analysis, above). This alone demonstrates the technical feasibility ofan ESP at Baldwin at that removal efficiency.
a. Cost Analysis Based on a design to remove 99.7% ofparticulate matter, the annualized cost ofinstalling anew ESP at Baldwin Unit 1 in 1988 is estimated to have been about $20.2 million ($113 million capital cost)
..!l!¥ Abaghouse with similarcapabilities would have had an annualized costof $11.6 million ($55 million capital cost)
..!221 Since the baghouse would have been vastly less expensive for the same level ofemissions reduction, that is the option that I considered for further analysis. The total cost effectiveness ofthebaghouse would have been $857/ton. Comparable cost effectiveness values are not available for cyclone fired boilers (which have much lower inlet PM loadings than tangentially fired boilers). However, construction cost data are available for powerplants constructed in the 1988 timeframe. These data showthat the estimated construction cost for a baghouse is similarto that ofothercontemporaneous sources. For example, Northern States Power's SherburnCountyUnit 3 (809 MW), built in 1987, reported a capital cost of$73.1 million for its baghouseremoving 99.9% ofPM. Tampa Electric's Big Bend Plant (445 MW), referenced in my 1985 analysis, is also relevant in 1988. Its capital cost was 76.8 million
..!!9' The costs for abaghouse at Baldwin Unit 1 in 1988 are therefore note unreasonable.

illf Seereport ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc. ill SeeTable 4c for calculations
. .!l!¥ See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02, NOxand PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Power and DvnegyMidwest Generation, Inc. ill Ibid
. .® Department ofEnergy, Energy Information Administration (Form EIA-767) for 2000
. 39

# • b. OtherEnvironmental Impacts



# •

• No significant environmental impacts would occurfrom the use ofa baghouse. Collected ash from the baghouse would need to be disposed of, but is not considered hazardous waste.
c. Conclusion I conclude that an emission limit of0.003 pound/million BTU based on the use ofthe use ofa baghouse removing 99.7% ofPM represented BACT at Baldwin Unit 1 in 1988. Compliance would have been monitored with EPA method 5 and use ofan opacity CEMS. 

### D. BACT Determinations for Baldwin Station: 2002 I. BACTDetermination atBaldwin Units I and2 I am analyzing these two units togetherbecause they have designs that are virtuallyidentical for thepurposesofthis analysis. These two units are currently burning coal from the Powder River Basin with a sulfur content ofapproximately 0.25%. They both also have overfire air installed, as well as infrastructure for SCR, although no catalyst is installed. Units 1 and 2 underwent upgrades to theirESPs in 1999. Although none ofthe results ofthese upgrades and changes are enforceable as permit conditions,.!!!! the S02 andNOx controls IP has employed to date are presumablythe result ofIllinois Power's need to comply with acid rain (Title IV) provisions of the Clean Air Act.
a. S02 Control To be analyzed together with Unit 3, below. b. NO. Control The available control options are: 1. SCR 

### 2. OFA 3. SNCR 4. Coal or Gas Rebuming 5. Optimization system
.!!!! Joint Construction and Operating Permit issued February 19, 1999 (EPA 5776); Operating Permit issued January 5, 1996 (IPPRO-OOI9014); Operating Pennit issued December4, 1998 (IPPRO-OOl9233); Operating Pennit issued June 20, 1996 (IPPRO-0018725); Construction Permit issued April 14, 1998 (EPA 5775); Operating Pennit issued June 26, 1997 (IPPRO0019094)
. 40

# • I. Technical Feasibility



# •

• SCR systems are now in wide use in the U.S. and worldwide, and have been applied to meet BACT emission limits for coal fired powerplants since I990.ill' Reported reduction efficiencies are up to 90%. At least 229 units at coal fired powerplants worldwide, including at least thirteen in the U.S., are now using SCR to control NOx**emissions.~rn** OFA has also become a verywidely used technology. In fact, Illinois Power installed OFA at Baldwin Units 

### I and 

### 2 in approximately 

### I999.ill! OFA can reduce emissions by as much as 50% in cyclone fired boilers. Illinois Power achieved reductions ofabout 62 % with its OFA installations
..!§' Reburn is a NOx control technology that involves diverting a portion ofthe fuel from the burners to a second combustion area (reburn zone) above the main combustion zone. Additional air is then added above the rebum zone to complete fuel burnout. The reburn fuel can be eithernatural gas, oil, orpulverized coal; however, most experience to date is with natural gas reburning. There are many technical issues in applying reburn, such as maintaining acceptable boilerperformance when alarge amount ofheat input is moved from the main combustion zoneto adifferent area of the furnace. Utilizing all the carbon in the fuel has been a problem in the past when pulverized coal is the reburn fue1.illI Notwithstanding these concerns, at least one demonstration project on a cyclone firedboiler showed reburn technology achieving a NOxreduction of50%, with minimal

ill' See, e.g. New JerseyDepartment ofEnvironmental Protection, permitnumber01-89-3086, issued on December26, 1990 to Chambers Cogeneration Limited Partnership. See "Performance ofSelective Catalytic Reduction on Coal-Fired Steam Generating Units," USEPA, June, 1997. This document may be found at website address: http://www.epa.gov/airmarkt/arp/nox/scrfinal.pdf. ill' See SCR Installations Spreadsheet, EPA Clean AirMarkets Division, 2001. ill! Deposition testimony ofAric Diericx, November 10, 2000
. .!§' See "Appendix B-1: Compliance Results for All NOx Affected Units in 2000". This document maybe found at website address http://www.epa.gov/airmarkets/cmprpt/arpOO/appendixbI200.pdf. The reported emission rate for Baldwin Units I and 2 are 0.66 and 0.70 poundpermillion BTU, respectively. This is more than a 50% reduction compared to the uncontrolled rate of1.8 pourids&:1MBTU. ill' See U.S. EPA, Office ofAir and Radiation, Office ofAir Quality Planning and Standards, "Alternative Control Technologies Document NOx Emissions from UtilityBoilers" March 1994. This information can be found at website address: http://www.epa.gov/ttnlcatc/dirl/utboiler.pdf. 41• operational problems.@ SNCR has been described earlier. Emissions reductions ofup to 80% ofNOxhave been demonstrated using SNCR on coal fired boilers.

### rn Optimization systems are new technologies that Ihave not described previously. Although these systems are often known generically as "neural nets," different manufacturers use various software and hardware. Optimization systems attempt to reduce NOx and improve boiler efficiency by monitoring a number ofparameters, and then providing information to a plant's distributed control system. More than 200 boilers, most ofthem coal fired, are using an optimization technology. Reductions ofas much as 40% are possible with optimization systems..!2.!¥



# •

• Some ofthe above technologies maybe used effectively in conjunction with one another, and feasible combinations therefore should be considered. Specificallyeither SCR or SNCR may follow almost any otherNOx emissions control technology. For example, use ofOFA may be followed by an SCR system. OFA and rebuming (both coal and gas) are considered to modifythe combustion process, while SCR and SNCR are post-combustionprocesses. Emissions reductions achieved through use ofcombustion modification followed by SCR orSNCR are multiplicative. In otherwords, an emission reduction of50% from an LNB followed by 80% control via SNCR will yield an overall reduction of 90% reduction. One exception to this rule is optimization systems, which operate on the combustion process. Little information is available as to the effect ofoptimization systems in conjunction with other emissions reductions retrofits
. Because ofthe high NOxemission rate ofan uncontrolled cyclone fired boiler(compared with tangentially fired boilers), effective NOx emissions control requires both combustion control as well as post combustion control. Illinois Powerevaluated the options for controls at units 1 and 2 in the early 90s and concluded that OFA would be a more cost effective option than rebuming;..® for that reason I did not analyze rebuming further. Therefore, the options available are SCR or SNCR and OFA together, or OFA alone (i.e with no additional control). AIl three options are
ill' See "Demonstration ofCoal Rebuming for Cyclone BoilerNOxControl," McDermott International Inc, 2001. This information can be found at website address: http://www.mtiresearch.com/expemce.html#Demonstration ofCoal Reburn. See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCR InstaIlations," developed in connection with United States v. Illinois Powerand Dynegy Midwest Generation, Inc
. .!2!¥ See "What's New in the PowerIndustry," World Bank, 2001, found at website address http://www.worldbank.orglhtml/fpd/emJpower_industryIO.htm. !2.Y See Illinois Power "Gas at Baldwin" report, dated May 1990 (IPPRO

- 0003712). 42• amenable to the use ofan optimization system. The next step is to detennine an appropriate emission limit. 

### In order to detennine the emission limit, Iconsidered both the effectiveness ofthe controls as well as the fact that this would be a retrofit to a thirty year old powerplant..!2Y Based on I1linois Power's experience to date on Units I and 2, I determined that the OFA system, operating together with the optimization system, would easily achieve a 50% reduction. An SCR system is capable ofcontrolling an additional 90%, and perhaps as high as 95% ofNOx: 

### In determining the appropriate emission limit, I considered the potential emissions reductions achievable with each technology and the fact that this would be a retrofit, ratherthan a new installation.



# ••

• Ialso reviewed the proposed emission rates and permitted emission rates for recently announced orpermitted coal fired powerplants
..ill! Most ofthese powerplants are subject to the BACT requirement under PSD. All ofthese plants would emit less than 0.15 pound/million BTU, because that is the maximum allowed underthe**NSPS.~** However, cyclone fired boilers without controls emit far more NOxthan othercoal burning technologies, and ofthe currentlyproposed plants would be cyclone fired boilers. Therefore, it is difficult to make a direct comparison between recent BACT levels and the appropriate level for Baldwin Units 1 and 2. It is, instead, necessaryto derive aBACT emission limit for Baldwin Units 1 and 2 based on the.perfonnance ofdemonstrated NOx control technologies. Based on the performance ofthe technologies discussed above, and the reductions achievable from these technologies, the "top" option for NOxcontrol forUnits 1 and 2 would be the combined use ofoverfire air, an optimization system, and SCR, as this combination would provide the greatest control efficiency. The overfire airsystem would reduce emissionby at least 50%, and SCR could reduce emissions by a further 90%. Iassumed a combinedremoval
. effectiveness ofapproximately 92% from use ofOFA and SCR. This rate assumes that OFAwill reduce emissions between 60 and 70%, and SCRbetween 80 and 90%. As I discussed above, I did not assign a specific amountofemission reduction to the optimization system. Rather, the optimization system should improve the overall performance and cost effectiveness ofNOx control. On the basis ofIP's uncontrolled emissionrate of1.8 pound/millionBTU, this combination ofcontrols couldresult in removal of92% ofemissions, resulting in a controlled emission rate of0.14 pound/million BTU. This combination, i.e. OFA, SCR and optimization system, is the most effective control option available forNOx emissions control at Baldwin Units 1 and 2 today
. .!2Y See PSD Appeal No. 94-1 (Masonite Corporation), 5 EAD 551, page 10. This document may be found at website address http://www.epa.gov/eab/eabpsd.htm
. .ill! See National Coal-Fired UtilityProjects Spreadsheet, EPA Region 7, March 1,2002. See 40 C.F.R. § 60.40a (1979), "Standards ofPerformance for Electric Utility Steam Generating Units for Which Construction is commenced after September 18, 1978." 43

# • II. Other Environmental Effects**~:** .'
Most ofthe options for NO. emissions control would have no significant other environmental effects. SCR and SNCR use ammonia, which could cause environmental effects ifemitted in large amounts. However, ammonia slip is limited by design to about 3 ppm, so effects would not be likely to occur. iii Cost Effectiveness The annual cost for SCR, OFA and an optimization system would be approximately $8.4 million for Unit 1 and $8.7 million for Unit 2.illJBased on a controlled rate of0.14 pounds/MMBTU (controlling approximately 10,000 TPY ofNO.), the cost effectiveness ofthese controls would be $877 and 842/ton for Units 1 and 2, respectively.!2§' The costs associated with the combination ofcontrols is conservative because I included the cost ofinstalling OFA systems at Units 1 and 2, even though both already have OFA installed. This compares very favorably to the cost points I have used throughout the report. For example, as noted above, the New Jersey Department ofEnvironmental Protection based on a cost effectiveness of$13,200/ton (in 1990/91 dollars). EPA's guidance related to presumptive BACT forNO. at refineries used $1 O,OOO/ton as an upperbound for BACT cost effectiveness. In comparison to these benchmarks, the cost ofSCR, OFA and an optimization system is not unreasonabIe
. 

# •• iv. Conclusion



# • Based on all ofthe above factors, I have detennined that an emission limit of0.14 pound/million BTU, 30 day rolling average,. based on use ofthe combination ofOFA, SCR capable of90% control, and 

### an optimization system, represents current day BACT for emissions ofNO. at Baldwin Units I and 2. Compliance with this limit would be monitored via use ofa CEMS.
c. Particulate Matter
1. Technical Feasibility Control technologies available forparticulate control are essentiallythe same as those discussed earlier: ESPs and baghouses. Two kinds ofbaghouses are currently available for consideration for coal fired powerplants: pulse-jetbaghouses and reverse airbaghouses. The difference
ill! See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02, NO. and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Powerand Dynegy Midwest Generation, Inc. !29' See Table 3d for calculations. 44

# •

••

• between the two technologies relates to the way in which captured particles are removed from the bags afterthe bags collect the particles. Emission rates for new facilities controlled by ESPs and baghouses range from about 0.015 to 0.020 poundlMMBTU. These emission rates reflect Control ofapproximately 99.7% (see also PM analyses, 1985 and 1988).!2.9

11. Other Environmental Impacts Neitherbaghouses nor ESPs would have any significant other environmental effects. The material collected in baghouses and ESPs is not considered hazardous, and may be disposed ofin accordance with regulations for non-hazardous waste.
111. Cost Analysis I analyzed the cost ofcomplying with the lowest limit currently proposed for new powerplants: 0.015 pound/million BTU. As discussed in the earliertimeframes, (see 1985 and 1988 analyses above), abaghouse was the least expensive option. The same conclusion was reached for the present day. Therefore, only options for using abaghouse to control emissions were analyzed. Of the two baghouse options, the pulsejet design is less expensive, with a initial capital investment of$46.1 million, and annual operating costs ofapproximately $1.1 million. The total annualized cost for a pulse-jetbaghouse would be $8.3**million.~** I estimate that the total cost effectiveness wouldbe $302/ton ofparticulate removed (assuming that the baghouse would replace the current ESP)
. As I have noted earlier, comparable cost effectiveness values are not available for cyclone fired boilers (which have much lower inlet PM loadings than tangentially fired boilers). However, construction cost data are available for powerplants constructed in the 2002 timeframe. These data show that the estimated construction cost for a baghouse is similarto that ofother contemporaneous sources. For example, Public Service Electric & Gas Company's MercerUnit (326 MW, about halfthe size ofthe Baldwin units), built in 1994, reported a capital cost of$38.9 million for its ESP removing 99.8%**ofPM.~** Data reported from powerplants constructed earlier, discussed in the 1985 and 1988 timeframes, also show that the capital cost estimated for a new pulse-jetbaghouse at Baldwin Units 1 and 2 is at the low end compared to these other powerplants. The cost is therefore not unreasonable.

illJ See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1, 2002. ill' See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc. 

## m Department ofEnergy, Energy Information Administration (Form EIA-767) for 2000. 45

# • lV. Conclusion I therefore conclude that an emission rate of0.006 pounds permillion BTUlilli' based on use ofa 99.6% efficientpulsejet baghouse is-BACT forparticulate matterat Baldwin Units 1 and 2
.. Monitoring would be via EPA method 5, and triboelectric broken bag monitors. 2. BACTDeterminationfor Baldwin Unit 3 Unit 3 is also currentlyburning coal from the Powder River Basin with a sulfurcontent of approximately 0.25%. Unit 3 was retrofitted with a low 

### NOxburnerin**1994.~** The ESP was upgraded in 2000.ill' Although none ofthe results ofthese upgrades and changes are enforceable as permit**conditions,~** the S02 and 

### NOx controls IP has employed to date are presumably the result ofIllinois Power's need to comply with acid rain (Title IV) provisions ofthe Clean Air Act.
a. S02 Control (applicable to Units 1, 2 and 3) The following options are available for S02 control: b. Wet Limestone Scrubbing c. Wet Lime scrubbing buffered by Magnesium Oxide d. Dry Scrubbing
. 

# • 1. Technical Feasibility



# • I have previously addressed the technical feasibility ofthe two wet scrubbing options. To summarize, both wet scrubbing options are currently available, and demonstrated with removal efficiencies ofup to 97%. In the dry scrubbing process, flue gas is sentto aspray dryer absorber (SDA). In the SDA, a fine mist oflime slurry is sprayed into the flue gas. Heat from the flue gas evaporates the moisture in the slurry cloud while the alkaline slurry simultaneously absorbs the S02in the flue gas. The result is the conversion ofthe calcium hydroxide componentofthe slurry into a fine powderof calcium/sulfurcompounds, and lowering ofthe flue gas temperature. Removal efficiencies ofup

See Table 4d for calculations. IP Permit Application dated January 19,1993. IPPRO-0032541. Operating Permit issued June 26, 1997. IPPRO-0019094. Wi Ibid., and IP Permit Application dated January 19, 1993. IPPRO-0032541
. 46• to 90% with PRB coal have been demonstrated.lli' Illinois Power has now been using PRB coal since 1999, which, for the purpose ofthis analysis, has a sulfur content ofapproximately 0.6%.A large number offacilities are burning western coal and scrubbing 90% or greater, using one ofthe above technologies. Several plants using coal with less than I% sulfur coal are removing 95% ofthe S02 from the flue gas. For example, Bonanza Unit 1-1 (owned by Deseret Generation and Transmission Co-op) is using coal with a 0.5% sulfur, and removing 95% ofthe emitted S02 with a wet limestone**scrubber.~** All three scrubbing technologies are technically feasible and available. Both wet scrubbing technologies have been demonstrated to remove over 95% ofS02 from western coal, and up to 97% ofS02 from eastern, high sulfurcoals. Dry scrubbing has been demonstrated to remove up to 90% ofS02from western coal. Wet scrubbing is therefore the "top," ormost effective option.
n. Other Environmental Impacts 

# •

• Wet scrubbers produce a sludge that requires may have economic use. Ifnot used, it must be disposed in a landfill. This sludge is not considered hazardous waste. Dry scrubbers produce a powder that may also be disposed in a landfill, and is also not considered hazardous waste. No other significant environmental effect occurdue to the use ofscrubbers. iii. Cost Effectiveness The capital cost to install a wet limestone**scrubbe~** today would be $71.4 million at each of Baldwin units. Annual_operating costs for Units 1 and 2 would be $8.0 to 8.3 million per unit; annual operating costs for Unit 3 would be $8.4 to 8.7 million (the-difference reflects the higher assumed capacity factor for Unit 3). Total annualized costwould be approximately $15.9 million perunit for Units 1 and 2, and $16.3 million for Unit 3.

### m Assuming a removal efficiency of

lli' See "Retrofitting Lime Spray Dryers at Public Service Company ofColorado," R. Telesz et. aI., Presented to Power-Gen International 2000, November200. This document maybe found at website address: http://www.babcock.com/pgglttlpdflBR-1707.pdf "WI See "Table 30: Flue Gas Desulfurization (FGD) Capacity in Operation at U.S. Electric Utility Plants as ofDecember 1999." This information can be found at website address: http://www.eia.doe.gov/cneafJelectricity/epav2/htmI_ tables/epav2t30p1.html and following pages. ?2!i Prioranalyses (see e.g. 1982 analysis) offered in this report establish this technology as the lowercost wet scrubbing option, compared to wet lime scrubbingbuffered magnesium oxide. 

### m See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02 , NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with 47

# • 95%, the cost effectiveness, therefore, would be approximately $652/ton for Units 1 and 2, and $570/ton for Unit 3.£Q!Y In order to ensure that the costs estimated for the scrubber are not excessive, I reviewed other BACT determinations and EPA policy documents. I reviewed the cost effectiveness of eighteen powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. Ofthose where a dollar perton cost effectiveness was listed, the range (once converted to 2001 dollars) is $234 to 7129/ton.W! Also, as noted, EPA's guidance related to presumptive BACT for NOx at refineries used $1 O,OOO/ton as an upperbound for BACT cost effectiveness. The estimated costs for wet limestone scrubbing at the Baldwin powerplant today is toward the low end ofthe range ofthese permits and EPA guidance. The cost is therefore not unreasonable.ill
IV. Conclusion Based on the above information, I have determined that BACT for S02 at Baldwin station today is an emission rate of0.095 pounds permillion BTU based on 95% scrubbing and assuming use ofcoal with 0.6% sulfur.ill Compliancewith this limit would be monitored with a CEMS. b. NOx Control The available control options are: 

# • 1. 2. 3. 3. 

### 4. 5. 

### LNB SCR OFA SNCR Coal or Gas Rebuming Optimization system



# • United States v. Illinois Power and DynegyMidwest Generation, Inc. See Table 8d and 8e for calculations. M!Jf See Table 11, Cost Effectiveness ofBACT Determinations for S02' Most ofthe higher cost effectiveness values attach to facilities burning lower sulfur coal, while lowercost effectiveness correlates to facilities burning higher sulfurcoal. The cost estimate presented here may, in fact, be conservative. Some literature suggests that S02 scrubber costs have recently gone down. See "Cost ofS02 Scrubbers Down to $1 OOIKW, Douglas Smith, SeniorEditor, PowerEngineering, September, 2001. ill Calculated by using a controlled emission rate of533 poundlhr and 5587 million BTUIhr
. 48

# • I. Technical Feasibility



# •

• As with Units I and 2, several NOx control options may be used singly or in combination at Baldwin Unit 3. The same options discussed above as currently feasible for NOx control on Units 

### I and 2 are technically feasible and demonstrated for use on Unit 

### 3. In addition, as I discussed in the 1982 time frame, low NO. burners are also technically feasible and available for tangentially fired boilers such as Baldwin's Unit 3. In fact, Illinois Power installed a low-NO. burner in Unit 3 in 1994. Emission rates from IP's 1994 installation were about 0.3 pound/million**BTU~.** Emission rates from LNBs have improved dramatically since the 1994 installation. At least three manufacturers have demonstrated LNBs that attain NO. emission rates around 0.15 pound/million BTU.illf.6.!.1.ill! OFA is often an integral part ofthe design ofnewer LNBs (in fact, the currently installed LNBs at Unit 3 include integral OFAlli'), or maybe added in alocation near the burner in the boiler.ill 

### In addition to LNBs, SCRorSNCRmaybe used as 

### apostcombustion control. Most new coal fired powerplants that are permitted with SCR also use· combustion controls such as LNBs.ill They may also use optimizations systems to enhance boiler efficiency and reduce NOx '

See "Emissions Data and Compliance Reports," USEPA. These data maybe found at website address: http://www.epa.gov/airmarkets/emissions/index.html ill Tangential Low NOx System at Reliant Energy's Limestone Unit 2 Cuts Texas Lignite, PRB and Pet Coke NO., Ron Pearce, Reliant Energy and John Grusha, FosterWheeler Energy Corporation, May 30,2001.' ill' Maximize PRB Coal Usage in Conjunction with In-Furnace NOx Solutions to Minimize Cost ofNOx Compliance, James Topper, Herb Blue, Jim Pomaranski, Consumers Energy, Ed Rebula, Robert Lewis, ALSTOM Power, undated. ill! "4 X 550 MWe BoilerOperating Experience at 0.15 lb/MMBTU NOxEmissionLevel Firing aBroad Range ofCoals," A.D. LaRue et. al., Presented at EPRI-DOE-EPA Combined Utility AirPollutant Control Symposium, August 1999. This document can be found at website address:http://www.babcock.comlpgglttlpdf7BR-1682.pdf. lli' Deposition testimony ofAric Diericx, November 10, 2000. ill See "B&W's Experience Reducing NO. Emissions in Tangentially;;,Fired Boilers-2001 update," A. Kokkinos et. al., Presented to Power-Gen International 2001, December 2001. This document may be found at website location: http://www.babcock.com/pgglttlpdf7BR-I726.pdf. ill' See, eg, "PREVENTION OF SIGNIFICANT DETERIORATION CONSTRUCTION PERMIT 888 REVIEW DOCUMENT," issued to Kansas City Power and Light for the Hawthorn Generating Station
. 49

# • Just as with Units I and 2, some ofthe above technologies may be used effectively in conjuncti.on with one another, and feasible combinations therefore should be considered. Specifically either SCR or SNCR may follow almost any otherNOx emissions control technology. Several powerplants have recently been built or modified with a combination ofLNBs andSCR. Forexample, the Chambers Cogeneration facility, an new plantpermitted in 1990, has both LNBs and SCR,ll?! as does the Hawthorn facility, anew plant permitted in 2001.ll9' The currently installed LNB at Unit 3 achieves levels ofabout 0.3 pound/million BTU NOx• With the additional use ofan SCR system removing 90% ofthe NOx exiting the burner, emissions of0.04 pound/million BTU are readily achievable using the current LNB. Replacement ofthe current LNB with a state-of-the-art LNB would, togetherwith the use of SCR, allow Unit 3 to reach an emissions level of0.015 poundslMMBTU NOx•However, since this is a retrofit, ratherthan a new powerplant, it maybe difficult to achieve the lowest levels reached by new plants. Therefore, I would conclude that an emission rate of 0.02 pounds/MMBTU would represent the most effective level ofNOx' control currently achievable at Baldwin Unit 3. A limit of0.02 pound/million BTU appears to be somewhat lower than limits in recently issued PSD permits for coal fired powerplants.llitHowever, as I have shown above, it is readily achievable using currently available controls (i.e. SCR, LNB and optimization). For example, the AES Somersetplant in New York, a 675 MWboiler, has reduced its emissions to 0.05 pounds permillion BTU, a 90% reduction using only SCR..ill' 

# • 11. OtherEnvironmental Effects



# • Most ofthe options for NOx emissions control would have no significant otherenvironmental effects. SCR and SNCR use ammonia, which could cause environmental effects ifemitted in

ll?! See New JerseyDepartmentofEnvironmental Protection, permit number01-89-3086, issued on December26, 1990 to Chambers Cogeneration Limited Partnership. ll9' See "PREVENTION OF SIGNIFICANT DETERIORATION CONSTRUCTION PERMIT 888 REVIEW DOCUMENT," issuedto Kansas CityPowerand Light for the Hawthorn Generating Station.
llit SeeNational Coal-Fired UtilityProjects Spreadsheet, EPA Region 7, March 1,2002. 

### m See Selective Catalytic Reduction Retrofit ofa 675 MW BoileratAES Somerset and Update ofSCR Retrofit on a 675MW Boiler at AES Somerset, Nischt et aI, Presented to ICAC NOx Forum, March 2000, and to ASMEJoint PowerGeneration Conference, July 2000. These documents can be found at web site addresses http://www.babcock.com/pggltt/pdf/BR-1698.pdf

. http://www.babcock.comlpggltt/pdf/BR-1703.pdf. 50

# •

•

• large amounts. However, ammonia slip is limited by design to about 3 ppm, so effects would not be likely to occur.
111. Cost Effectiveness The top BACT option be the use ofLNBs, SCR, and an optimization system. The annualized cost ofan SCR system at Baldwin Unit 

### 3 today would be $8.3 million.ill This cost is higher than the estimated cost for an SCR system at Units 

### I and 

### 2 because those two units already have significant portions ofthe necessary SCR infrastructure installed, while Unit 3 does not.lli'·lli' The annualized cost ofnew LNBs would be $1.5 million, and the annualized cost ofan optimization system would be $18,000.ill'·ill! The total annualized cost would be $9.8 million, and would reduce approximately 3,900 TPY (this reduction is substantially smallerthan potential reductions at Units 

### I and 

### 2 because Units 1 and 

### 2have a substantially largeruncontrolled NOx emission rate). The cost effectiveness ofthis combined option would be $2539/ton.ill' The costs ofachieving 0.02 poundIMMBTU are well within the range ofcosts estimated in recent PSD permits for coal fired powerplants. Forexample, coal fired powerplants permitted since 1990 have been required to install controls with predicted cost effectiveness that ranges from $1690 (in 1999) to $13,196/ton (in 1990).m

ill See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02' NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. lllinois Powerand DynegyMidwest Generation, Inc. ill' Ibid. ll2J Deposition testimony ofAric Diericx, November 10,2000. ill' See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02 , NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with United States v. Illinois Powerand DynegyMidwest Generation. Inc. ill Information from manufacturers ofthese systems show that these systems often yieldboth net cost savings and NOx emissionreductions. See "Full Scale ImplementationResults for GNOCIS (tm) Plus," George Warriner, DRS Corporation, Steve Logan, Southern Company Services, Steve Pascoe, Powergen. James Noblett. Presented at theUSDOE-EPRI combined PowerPlant Air Pollution Control Symposium, August, 2001. "At some plants, lowering NOx canbe done simultaneouslywith increasing efficiency." ill' See Table 3e for calculations. lliJ See Table 10, BACT CostEffectiveness for NOx Controls
. 51

# • IV. Conclusion



# •

• Ihave determined that BACT for NOx emissions at Baldwin Unit 3 today is an emission limit of 0.020 pound/million BTU and use ofLNBs, an optimization system, and the use ofSCR. Illinois Power would be able to request that this limit be raised as high as 0.04 poundslMMBTU ifthey could demonstrate that 0.020 is not achievable. I would provide this flexibility because this is a retrofit, and therefore more difficult. Compliance with this limit would be monitored with a CEMS.
c. Particulate Matter Control technologies available for particulate control are the same 

### as those discussed earlier, with improvements in efficiency and reliability. Emission rates for new facilities controlled byESPs and baghouses range from about 0.015 to 0.02 pound/MMBTU.ru¥Illinois Power upgraded its ESP in 1999 

### as part ofits preparation to begin burning PRB coal.ill As I discussed in the 1982 case above, the original perfonnance ofUnit 3 was far betterthan the performance ofUnits 1 and 2. Although we currently have no data about the currentperformance ofUnit 3's ESP, it appears that the original design, together with the upgrade, maybe capable ofmeeting a limit of0.0IS, the lowest limit currently set for BACT. However, I evaluated the cost ofa replacement PM control device, in order to determine what the cost might be ifthe Unit 

### 3 ESP cannotperfonn at the necessary level to meet BACT. Assuming an emissionrate of0.015 poundIMMBTU, the capital cost ofa new baghouse at Baldwin Unit 3 would be $43.8 million, and the annualized cost would be approximately $10 million. The cost effectiveness ofthat baghouse would be $69/too. This is similarto other recentlypermitted powerplants. Forexample, the cost estimated forthe Chambers Works Cogeneration Project for PM control (to 0.3 pound/MMBTU) in 1989 was $78/ton.lli' More recently, the KCP&L Hawthorn Unit 5 permit application proposed use ofa baghouse with a cost effectiveness of $82/ton.ill' However it is unlikely that Illinois Power would be required to incur these costs, in that Illinois Powercould improve the performance ofthe ESP by adding a field or a "polishing" baghouse, likely at a substantially lowercost than a new device.

ll9' See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1, 2002. ill Deposition testimonyofAric Diericx, November 10,2000. 

## m See BestAvailable Control TechnologyAnalysis for Keystone Cogeneration Facility, Bechtel Power Corporation, October, 1989. ill' See Prevention ofSignificant Deterioration Construction Permit Application: Replacement of Unit 5 at the Hawthorn Generating Station, Bums and McDonnell, May 1999
. 52• Conclusion Itherefore have detennined that BACT for PM at Baldwin Unit 3 is an emission limit of0.015 pound/million BTU, based on use ofan ESP orbaghouse. Compliance would be monitored with aCEMS
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