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

# --r&::L~~_x_p_e_rt_R==ep=o=r=t=o=f==::::::: __

# ==-_-----,,,---~.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 2002TABLE OF CONTENTS Pal:e LIST OF TABLES
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv I. Introduction and Overview
.................................................... 1 A. Infonnation Required for the Expert Report
................................ 1 B. Purpose ofReport
..................................................... 1 II. Summary ofConclusions
..................................................... 2 III. Qualifications
............................................................. 3 IV. What is BACT?
............................................................ 5 V. The Typical BACT DetenninationProcess
...................................... 6 VI. Baldwin Station: Background
................................................ 11 VII. BACT Detenninations for the Baldwin Station
.................................. 13 A. BACTDetennination for BaldwinUnit 3: 1982
... ; ........................ 13 

### 1. SulfurDioxide
................................................. 13 

### 2. Nitrogen Oxides
............................................... 17 

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

### 1. SulfurDioxide
................................................. 23 

### 2. Nitrogen Oxides
...............................................26 

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

### 1. SOl Control
. .................................................. 33

11

### 2. NO x 

### Control
. .................................................. 35 

### 3. ParticulateMatter
. ............................................. 38 D. BACT Determinations for Baldwin Station: 2001
...........................40 

### 1. BACTDetermination atBaldwin Units 1 and2
....................... 40
a. S02 Control
............................................. 40 b. NOx Control
............................................ 40
c. Particulate Matter
........................................ 44 

### 2. BACTDetermination/orBaldwin Unit 3
............................ 46
a. S02 Control (applicable to Units 1,2 and 3)
.................... 46 b. NOx Control
............................................48
c. Particulate Matter
........................................ 52 Appendix A: Tables
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A-I Appendix B: Data and Information Considered
................................... B-1 Appendix C: Papers Authored in the Last Ten Years
............................... C - 1 Appendix D: Resume
....................................................... D - 1 Attachment 1: Report ofDanMussatti 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 DynegyMidwest Generation, Inc. Attachment 2: Report ofWilliam Ellison, PE, Ellison Consultants, developed inconnection with United States v. Illinois Power and DynegyMidwest Generation, Inc.

IIILIST OFTABLES
Table 1: NOx Emissions Rates for Permits Issued up to 1982
. . . . . . . . . . . . . . . . . .. A - 3 Table 2: Cost Effectiveness ofS02 for Permits Issued 1979-1999, Converted to 1982,1985, 1988, and 2001
........................... A - 4 Table 3a: NOx Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982
.......................................... A - 5 Table 3b: NOx Emission Calculations and Cost Effectiveness for Baldwin Unit 1, 1985
.......................................... A - 6 Table 3c: NOxEmission Calculations and Cost Effectiveness for Baldwin Unit 2, 1988
.......................................... A - 7 Table 3d: NOx Emission Calculations and Cost Effectiveness for Baldwin Unit 1 & 2, 2001
....................................... A - 8 Table 3e: NOx Emissions Calculations and Cost Effectiveness for Baldwin Unit 3, 2001
.......................................... A - 9 Table 4a: Particulate MatterEmissions Calculations for Baldwin Unit 3, 1982
................................................. A - 10 Table 4b: Emission Calculations for Particulate Matter, Baldwin Unit 1, 1985
................................................ 

### A-II Table 4c: Emissions Calculations for Particulate Matter, Baldwin Unit 2, 1988
................................................. A - 12 Table 4d: Emissions Calculations for Particulate Matter, Baldwin Unit 1 & 2, 2001
............................................. A - 13 Table 4e: Emissions Calculations for Particulate Matter, Baldwin Unit 3, 2001
................................................. A - 14 Table 5: RACTIBACT/LAER Summary: 1982 Timeframe
................... A - 15 Table 6: SummaryofPowerplants with High S02Removal: 1985 timeframe
..... A - 16 Table 7: Derivation ofParticulate Removal Efficiency.
. . . . . . . . . . . . . . . . . . . . .. A - 17

IVTable 8a: S02Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - 18 Table 8b: S02Emission Calculations and Cost Effectiveness for Baldwin Unit 1, 1985
.......................................... A - 19 Table 8c: S02Emission Calculations and Cost Effectiveness for Baldwin Unit 2, 1988
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - 20 Table 8d: S02Emission Calculations and Cost Effectiveness for Baldwin Unit 1 & 2, 2001
....................................... A- 21 Table 8e: S02Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 2001
.......................................... A - 22 Table 9: General Information About Baldwin

- Baldwin Unit 1Design Data
............................................ A - 23 Table 10: Cost Effectiveness ofBACT Determinations for NOx •••••••••••••••• A - 26 Table 11: BACT CostEffectiveness for S02 Controls
........................ A - 27

vI. 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: (1) This report contains myopinions, 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) Thebodyofthe report and Appendix B list the data and other information 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; myresume is attached as Appendix D. (6) I am being compensated for thepreparation ofthis report and mytestimony as a normal part ofmycompensation as an employee ofthe US EPA. (7) I have not provided previous testimonywithin thepreceding four years as an expert at trial orbydeposition. B. Purpose ofReport This report is written pursuant to a request from the Department ofJustice for an analysis ofwhat controls should havebeen installed at the Baldwin Stationwhen the Prevention ofSignificant Deterioration (PSD) regulations were triggered at each unit, as alleged in the United States' Amended Complaint. Under 

### § 165 ofthe CleanAirAct ("C.A.A.") (42 U.S.C. 

### § 7475), the permittingrequirements triggered bythe majormodifications undertaken at the BaldwinUnits would have included a requirement that Illinois Power Company (lPC) install the "Best Available Control Technology" (BACT). This report explains what BACTwould have been-- for sulfur dioxide (S02)' nitrogen oxides (NOx) and particulate matter (PM)

-- at Unit 1 in 1985, Unit 2 in 1988, and Unit 3 in 1982, when PSD was allegedlytriggered. In addition, it is EPA's policythat a source that is in violation because itconstructed ormodified without a proper preconstruction permit must install controls that constitute BACT when the properpermit is finally issued
. .!! Therefore, this report also makes a determination ofBACT for all units as if

.!! Office ofAir QualityPlanning and Standards, U.S. EPA,

### New SourceReview Workshop Manual: Prevention of SignificantDeterioration andNonattainmentArea Permitting (Draft Oct. 1permits were being issued as ofthe date this report is submitted. 

### II. Summary ofConclusions 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.
80,_ 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 million 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% sulfur content, 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 I} 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% sulfurcontent, 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 rolling Monitored via CEMS

1990), page B.55: "the BACT emission limit in a new source permit is not set until the final permit is issued." Y Continuous Emissions Monitoring System JJ See 40 C.F.R 60 Appendix A 21988 (Unit 2} 0.30 pounds per 0.36 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 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 dayrolling 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. assuminguse 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 Monitored viaCEMS pounds permillion BTU iflower limit is demonstrated to be unachievable. Averaging time: 3 hour Monitored via CEMS
III. Qualifications I have been involved in BACT decisions in a variety ofcapacities at EPA's Region 9 for over twenty one years. I began work for EPARegion 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/ttniemc/propperfips-ll&frnotice.pdf, proposed Performance Specification for Continuous PM Monitoring Systems. 3was to perfonn analyses, including control technology (i.e. BACT) analyses necessary for the issuance ofPSD pennits, and to oversee the issuance ofPSD and nonattainment NSRpennits 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, I co-authored Region 9's BestAvailable Control Technology GuidanceDocument, which laid out a methodology for use primarilybypennit applicants, their consultants, and state and local pennitting authorities for conducting a BACT detennination. 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: Nevada Power-Reid Gardner and Arizona Public Service-Cholla. In 1989, I became the manager ofthe New Source Section. I managed the Region's work in pennitting new and modified airpollution sources, as well as overseeing the pennit issuance work ofour state and local agencies. In addition, my group had the responsibility for review and action onpennitrules submitted to EPA for inclusion in the State Implementation Plan, as well as reviews ofstate programs to detennine-afterthe fact-the efficacy oftheir pennittingprograms, including their BACTreviews. In 2000, I began a one-year assignment as Associate Directorofthe Air Division. One ofmyresponsibilities was managing the Region's response to the western energy shortage, a responsibility I continued when I became the Region's SeniorEnergy Advisor, the position I currentlyhold. Oneresponsibility ofmycurrent position is to advise staffin the Pennits Office ondecisions related to powerplants, including BACT decisions. I speak frequently on Clean Air Act issues. During the pastten 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 UtilityEnvironmental Conference, and others. Most ofmytalks were solelyorprimarily about New Source Review and the control technology requirement (BACT and LAER) underthe NSRregulations. I have 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 pennitting authorities. About 150 people attended four training sessions. That training was followed byinternal training ofabout 50 EPARegion 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 2001), I was invited to present a paperto the second conference ofthe European Union nations on NOxand N2

### 0 control ("NOxCONF 2001 "). Mypaperwas titled

### NOr Emissions Controls atRefineries: USRegulatoryDrivers andResults.

4

### IV. What is BACT? When a new 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, a permit is required from EPA or a State2i 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: "an emissions limitation (including a visible emission standard) based on the maximum degree ofreduction for each pollutant subject to 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 through application ofproduction processes or available methods, systems, and techniques, including fuel cleaning ortreatment or innovative 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 under 40 CFR Parts 6()11 and 61. Ifthe Administrator determines that technological or economic limitations on the application ofmeasurement methodologyto a particular emissions unit would make the imposition ofan emissions standard infeasible, a design, equipment, work practice, operational standard, orcombination thereof, maybe prescribed instead to satisfythe requirement for the application ofbest available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation ofsuch design, equipment, work practice oroperation, and shall provide for

?i In this context, "state" maymean a state agency, ora local agency authorized under state law and federal regulations to carryout 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 "major source," "majormodification," and "significant" can be found in these regulations. ?J 40 C.F.R. Part 60 is generallyknown as New Source Performance Standards. This section requires a minimum, uniform level ofcontrol technology for new ormodified construction of categories ofsources ofair pollution, such as coal fired powerplants, petroleum refineries, pulp mills and the like. 5compliance bymeans which achieve equivalent results.flv In a typical BACTprocess, 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 other BACT determinations it believes are relevant. That agency reviews the proposal, asks for clarifying information from the applicant, gathers information independently, and then proposes a permit 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 permit containing emission limits and control technologies that reflect its BACT decision. The permit 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, bynecessity, different from most in several respects. A typical BACT analysis is conducted before construction ofa new source or modification has begun; because Illinois Power failed to obtaintimelyPSD permits prior to its construction ofchanges that triggered BACT, this analysis is being conducted afterthe modifications at the Baldwin powerplant havebeen completed. Also, my analysis is based largely on my own research, because Illinois Powerhas not, to date, submitted a BACT analysis to**review.~** 

## v. The Typical BACT Determination Process Overthe years, EPAhas issued policy guidance on the BACTprocess several times. Most notably, EPApublished in 1980 the Prevention of SignificantDeterioration Workshop Manual,l!l'

§' 40 C.F.R. § 52.21(b){l2).**~** In addition to my own research, I cite below to the work ofEllison Consultants, who have performed a review ofthe historical installation oftechnologies, and to the work ofstaffin EPA's Office ofAir QualityPlanning and Standards, who have performed 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 information that might be submittedby an applicant, orpresented by anotherpermitting authority. Just as in a traditional BACT analysis, I have utilized this data inreaching the BACT determinations described herein
. .ill Leigh Hayes, et aI, TRW Incorporated, Prevention a/SignificantDeterioration Workshop Manual (Oct. 1980) EPA 450/2-80-081. 6and in 1990 published the 

### New Source Review Workshop Manual (draft),lY accompanied bythe 

### "Top-Down" BestAvailable Control Technology Guidance Document. 11I Also, EPA's Region 9 office published, in about 1987, its 

### BACTGuidance DocumentPThe following description reflects the process generallyused to perform a BACT analysis today. During each BACT analysis, which is done on a case-by-case basis, the reviewing authority evaluates the energy, environmental, economic and other costs 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 pollutant regulated under the 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 Air Pollutants). 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"--alternative. That alternative is established as BACT unless the applicant demonstrates, and the permitting authority in its informedjudgment agrees, that technical considerations, or energy, environmental, or economic impactsjustifya conclusion that the most stringent technology is not "achievable" in that case. Ifthe most stringent technology is eliminated in this fashion, then the next most stringent alternative is considered, and so on. This is 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 ortechniques with a practical potential for application to the emissions unit and the regulated pollutant under evaluation. Airpollution control technologies and techniques include the application ofproductionprocess oravailable methods, systems, and techniques, including clean fuels, fuel cleaning ortreatment or innovative fuel combustion techniques for control ofthe affected pollutant. This analysis includes a review oftechnologies employed both within and

lY Office ofAir QualityPlanning and Standards, U.S. EPA, 

### New Source Review Workshop Manual: Prevention of SignificantDeterioration andNonattainmentArea Permitting (Draft Oct. 1990). 111 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 their own BACT analyses. DI Matt Haber et aI., U.S. EPA Region 9, 

### BestAvailable Control Technology Guidance Document. 7outside ofthe United States
. .!1' 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 only existing controls for the source categoryin question, but also (through technology transfer) controls applied to similar source categories and gas streams, and innovative control technologies. In addition, the technology that will achieve the greatest emission reduction technically possible (which is required in areas not attaining the National Ambient Air Quality Standards, and known as lowest achievable emission rate (LAER).!.?i) is considered available for BACT purposes, must also be included as a control alternative and usually represent the "top" alternative.!§' In the course ofthe BACT analysis, one ormore ofthe options maybe 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.!1! 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.lli 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 theprojectwas canceled, oreveryoperating source at that permitted level has beenphysically unable to achieve compliance with the limit), and supporting documentation showing why such limits are not technicallyfeasible is provided, the level ofcontrol (but not necessarilythe technology) maybe eliminated from further

.!1' Office ofAir QualityPlanning and Standards, U.S. EPA, "Top-Down"BestAvailable Control Technology GuidanceDocument (Mar. 15, 1990), page B.11. "Also, technologies in application outsidethe United States to the extentthe technologies have been successfully demonstrated in practice on full scale operations [should be considered]." .!.?i LAER is defined as the lowest emission rate achieved in practice, orin a SIP, for that class or category ofsource (C.A.A. § 171). !§' Office ofAir Quality Planning and Standards, U.S. EPA, "Top-Down"BestAvailable Control Technology GuidanceDocument (Mar. 15, 1990). )]j Ibid. lli Ibid. 8consideration. However, a permit from another facility requiring the application ofa certain technology oremission limit to be achieved for such technology usually is sufficientjustification to assume the technical feasibility ofthat technology or emission limit.r8 All remaining control alternatives not eliminated above are listed in rank orderofoverall control effectiveness for the pollutant under review, 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 a BACT analysis. The list should present the array ofcontrol technology alternatives and should include the following types ofinformation:£!}

• control efficiencies (percent pollutant removed, where appropriate);
• expected emission rate (concentration ormass perunit production);
• economic impacts (cost effectiveness);
• environmental impacts (includes any significant or unusual othermedia impacts (e.g., water or solid waste), and, at a minimum, the impact ofeach control alternative on emissions oftoxic orhazardous air contaminants); 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 shouldbeconsidered to arrive at the final level of control. Foreach option, the applicant is responsible for presenting an objective evaluation of each impact. Beneficial and adverse impacts are discussed and, where possible, quantified. In general, the BACT analysis focuses on the direct impact ofthe control alternative. Indirect impacts, such as the environmental impact from the generation ofelectricityneeded to run fans for an air pollution control device, are not included in the BACT analysis. However, an applicant proposing 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 onlyfor collateral environmental impacts.lli Economic impacts are considered in terms ofdollars perton ofpollutantremoved. This factor is

r8 Ibid. £!} Ibid. lli Ibid. 9known 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 per ton ofpollutant removed, ofall emissions removed compared to a baseline emissions level. That baseline is usuallythe legal limit that would exist but for the BACT determination. In manycases, that limit is equal to uncontrolled emissions, since no legal or practical 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 a potential cost benchmark, it is essential to ascertain whether the values are total orincremental 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 a particular industry 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 maypropose 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. Ifthe applicant accepts the top alternative in the listing as BACT, the applicant proceeds to considerwhether impacts ofunregulated airpollutants orimpacts in othermediawouldjustify selection ofan alternative control option. Ifthere are no outstanding issues regarding collateral environmental impacts, the analysis is ended and theresults are proposed as BACT. In the event that the top candidate is shown to be inappropriate, due to energy, environmental, oreconomic impacts, the rationale for this finding should be documented bythe permitting authority for the 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 cannot be eliminated by any source-specific environmental, energy, oreconomic impacts which demonstrate that alternative to be inappropriate as**BACT.~ ~**  Prior to the formalization ofthe "top-down"BACTprocess described above, the BACT process did not require that the applicant begin with an analysis ofthe most stringent technology option; however, the otherkey elements are verymuch the same. Theprocess 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 theirBACT determinations. My analysis for the 1988 and later timeframes largely conforms to the methodology ofthe Pottermemo and later guidance. 10VI. Baldwin Station: Background 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 British Thermal Units (BTU) per pound, a sulfurcontent ofapproximately 3% byweight, and an ash content ofapproximately 10% to 11% by weightnt until 1999, when the facility began use ofPowderRiverBasin (PRB) coal with a heating value of8600-8800 BTU/lb, a sulfur content of0.25%, and an ash content of4.6-4.8%.f1' Unit 1began operation in 1970, and operates a cyclone fired boiler.£?! Unit 1has a gross output of584 megawatts (MW).l9' Its air pollution 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.£.Y The 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).l!¥ However, at least as ofNovember

However, the only substantive differencebetween 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) technologybe listed first, and then rejected onlyifcompellingreasons, consistent with the law, are found. In contrast, the earlierguidance recommend assessment ofeach control technology, and selection ofthe "best"technologybased on the statutorycriteria. Myanalysis 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 later guidance) were different, the results should have been the same. nt Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1985. f1' Department ofEnergy, Energy Information Administration (Form EIA-767) for 2000. £?! Ibid. 19' Sargent & LundyEngineers Engineering Data, Unit 1 Baldwin Power Station. IPPRO0085676-744. £.Y IP Permit Application dated March 30, 1998. IPPRO-0019396.**~** Ibid.**~** IP Permit Application dated September 8, 1999. IPPRO-0028775. l!¥ IEPA Construction Permit. EPA 5775. 112000, the SCR system does hot contain catalyst, and is not currentlyoperating}..!! There are no S02 controls in place at Baldwin Unit I. Unit 2 also employs a cyclone fired boiler and has a gross capacityof586 MW.BI Unit 2 began operation in 1973.J)jThe Unit 2 ESP was initiallydesigned to remove 99% ofthe exhaust gas PM.J1' Although the ESP was modified in 1999 byadding additional collection**fields,~** and installation ofa flue gas conditioning system,2§' no information has been provided regarding the new removal efficiencyoremission rate. With respect to NOx, an over-fire air system was installed in 1999,1lJ as was an SCR system infrastructure. However, at least as ofNovember 2000 no catalyst was installed, and the SCR system is not currentlyoperating.2.§' There are no S02 controls in place at Baldwin Unit 2. Unit 3 is a tangentially fired unit with a gross output of586 MW,J2! and began operation in 1

975.5S1 Its air pollution controls include an ESP initiallydesigned to remove 99.5% ofexhaust gas PM.±!! Although the ESP was upgraded in 2000,1Y no information has been provided regarding the new performance level in terms ofPM removal efficiencyor emission rate. With

l.!! Deposition testimonyofAric Diericx, November 10,2000. BI Ratings ofIllinois Power CompanyFossil Fuel Fired GeneratingUnits; ReportbyPower Technologies, Inc. December, 1987

- IPPRO-00151120 J)j Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1985. J1' Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1985.**~** IP Permit Application dated November25, 1998. IPPRO-0019250. 2§' IP Permit Applicationdated December20, 1999. IPPRO-0028865 1lJ IP Permit Application dated September 8, 1999. IPPRO-0028775. l§' Deposition testimony ofAric Diericx, November 10, 2000. J2! Sargent & Lundy Engineers EngineeringData, Unit 3 Baldwin Power Station. IPPRO0085900. 5S1 Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985. ±!! Ibid. 1Y IP Permit Application dated November25, 1998. IPPRO-0019250. 12respect to NOx, in 1994, low NOx burners, with an overfire air system were installed.iJ/ There are no S02 controls in place 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.±Y 

### It was designed to fire up to 294 tons per**hour~** ofcoal with a heating value of 10,460 BTU per**pound.~** 

### 1. SulfurDioxide As of 1982, BaldwinUnit 3 was uncontrolled for emissions ofS02' and was burning coal with a sulfur content of**3%-3.5%.~** Actual emissions for the unit were about 85,000 tons peryear (TPY) of**S02.~** a. Technical Feasibility Two S02 emissions control options were potentially available 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 employ absorption bypassing the flue gasses

iJ/ IP Permit Application dated January 19, 1993. IPPRO-0032541. ±Y Ibid.**~** Ibid.**~** Sargent & LundyEngineers Engineering Data, Unit 3 Baldwin Power Station. IPPRO0085900**~** Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985.**~** See Expert Report ofRanajit (Ron) Sahu, April, 2002, compiling CEMS data submittedby Illinois Power Companyto U.S. EPA. 13

### through an injected mist ofreagent
- generally limestone or**lime.~** 

### Thereagent is crushed into a fine powder, hydrated into a wet 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 ofS02 removal. 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 operatingusing 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 at least two Federal requirements for the use of scrubbers for S02 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 1978.1Y

### 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.2I 

### The second requirement is the BACT requirement ofthe PSD regulations, which, in 1982, had been in effect for almost four years.2J/ At least seven coal fired powerplants were issued PSD permits between 1978 and 1983 with the requirement for between 80 and 95% control.i1' For**~** 

### "EstimatingCosts 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. 1Y 

### 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." 21 

### See C.A.A.§ 111(a)(I). f1I 

### In 1978, EPA revised its regulations pursuant to the 1977 Clean Air Act Amendments. Prior to that date, BACTwas 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 under the old regulations. i1' See Appendix A, Table 5: RACTIBACTILAER summary: 1982 timeframe. 14example, Nevada Power's Harry Allen Station was issued a permit in early 1981 with a 95% removal requirement and an emission rate of0.1 pound/million BTU.?2i 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.i9' 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.TIt Taken together, it is clear that by 1982, scrubbing technologies to remove S02 were required of manypowerplants 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 determine their cost effectiveness. Both scrubbing options were analyzed at the 95% efficiency level. The cost for scrubbers capable ofremoving 95% offlue gas S02 were analyzed based on a study conducted by Illinois Power in 1991 to install flue gas desulfurization systems on Unit**l.~** Most ofthe methodologyused in 1991 would also apply in 

### 1982.221 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 onwhetherwaste from the

?2i Ibid. i9' Ibid. TIt 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 DynegyMidwest 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 Rebuming NOx Control, B&WProposal #90-071 (May 1991). IPPRO-0128923- 0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-0127567-0127848. 

### 221 See report ofDanMussatti 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 information found at website address http://www.enr.com/cost/costcci.asp. 15scrubber system would have been sold. When these costs are converted to annualized**costs~,** the annual cost would have been between $22.0 and 23.4million.Q.!J 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 $220Iton.@ 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 orderto ensure that the costs estimated for the scrubber are not excessive, I reviewed other BACT determinations and EPApolicydocuments.M' 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 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. Q.!J Ibid.; the cost data adjustment was based on information found at website address http://www.enr.com/cost/costcci.asp.
@ SeeTable 8a: S02 Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982.**~** See report ofDan Mussatti and Larry Sorrels, Estimated Costs for the Installation ofS02' NOx andPM Control Devices at Illinois Power's Baldwin Station, developed in connection with United States v. Illinois Powerand DynegyMidwest Generation, Inc. M' 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 whether a particular scenario's cost effectiveness should be deemed unreasonable. Forexample, to the extent available, I looked at contemporaneouslyissued 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, I have 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. lowercost) measure against which to comparepotential BACT options.
@ SeeTable 11, Cost Effectiveness ofBACT Determinations for S02. 16**gasoline.~** 

### That guidance used $1O,OOO/ton as an upperbound 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. Other Environmental 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 occur due 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 BTUP 30 dayrolling average, based on the use of a wet limestone scrubberremoving 95% ofthe S02 from coal having a sulfur content of3-3.5%. Compliance with the limit would have been monitored byuse 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 NOx 

### Burners ("LNB") 2. Overfire Air ("OFA")**~** 

### 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.govIrgytgmj/programsl 

### artd/air/nsr/nsrmemos/t2bact.pdf §]j 

### The limit of0.3 pounds permillion BTU is derived from 95% removal ofcoal with 3.5% sulfur and 10,900 BTU/pound. See Table 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 byIllinois Power Companyto U.S. EPA. 17

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

### burners limit NOx 

### fonnation by controlling both 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 

### fonnation temperature. There are many types ofLow-NOx 

### burners for use on many types ofboilers (except cyclone boilers.):ill' LNBs were installed in numerous facilities by 1982. At least seven plants were operating with LNBs worldwide by 1982.l!i

### At least one burnermanufacturer had 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 1981.2.?I,D!

### At least two other powerplants were pennitted by 1982 with emission rates near 0.4 pound NOx/million BTU-NevadaPower's Harry Allen Station, and Tucson Electric Power's (TEP) Springerville Unit 3.Z1'

### Units 1and 2 at TEP's Springerville, pennitted in 1978, have achieved levels of approximately 0.4 pounds permillion BTU.TII 

### All ofthe foregoing powerplants were designed as tangentially fired boilers.

:ill' Babcock & 

### Wilcox, Steam/its generation anduse 

### (39th ed. 1978). l!i 

### See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx 

### Burner Installations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 2.?1 

### See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx

### BurnerInstallations," developed in connection with United States v. Illinois Powerand DynegyMidwest Generation, Inc. D! 

### Conversion from parts permillion to pounds permillion BTU based onEmissions standards handbook: airpollutantstandards for coal-firedpowerplants, 

### Appendix, Hennine N. Soud, IEA Coal Research, December 1991. Z1' 

### See Appendix A, Table 1. TIl 

### See U.S. EPA, Clean AirMarkets Division, "Emissions Scorecard." This infonnation can be found at website address: http://www.epa.gov/ainnarkets/emissions/scoreOO/index.html. TEP's emission rate for 2000 was reported to have been 0.39 poundslMMBTU. TEP has presumably maintained the sameburners since the boilers were built. 18The 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 operationI§' orwere permitted for lower levels using LNBs.lZ' 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 burner level. 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 bytwo mechanisms: (1) 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 appear to be an integral part ofLNB designs, and also appeardesigned to meet a limit of0.7 pound per million BTU. 7JJ Selective Catalytic Reduction involves injecting ammonia into the flue gas before the gas reaches a catalyst, at a specific temperature. The catalyst lowers the energy required to complete the reaction ofthe ammonia with the NOx to 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 lower temperature, typically found

I§' See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx BurnerInstallations," developed in connection with United States v. Illinois Powerand Dynegy Midwest Generation, Inc. lZ' See Appendix A, Table 1.**~** See U.S. EPA, Office ofAir and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies Document NOx Emissions from UtilityBoilers"March 1994. This information can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. 7JJ See report ofWilliam Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 19after the preheater. Zeolite catalysts would be used in cold side SCR systems.ffi' Selective Catalytic Reduction was in use by 1982 on at least five coal fired powerplants**worldwide.~'go-** It therefore must be considered technically feasible, 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, I would 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 airheater into the furnace for NOx control using ductwork and an additional fan. The method was originally developed for controlling superheater and reheater steam temperatures. NOxis reduced by lowering the temperature in combustion zone and therefore suppressingNOx fonnation. By 1982, flue gas recirculation was in use at a large number ofcombustionprocesses.

## nr All of these installations appearto 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. Forthat 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.'§2jA state-of-the-art
ffi' See U.S. EPA, Office ofAir and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies DocumentNOxEmissions from UtilityBoilers"March 1994. This infonnation can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf.**~** See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCRInstallations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. go- 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. '§2j OFA was excluded from further analysis because installations using OF A, in 1982, were emitting at about the same rate as Baldwin Unit 3 was, i.e. 0.7 poundlMMBTU. 

### 20LNB 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 a cost effectiveness of$589/ton ofNOx**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$10,600/ton.~** Also, in 1982 the South Coast AQMD (SCAQMD) adopted a revision to its air quality management 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 violatingthe NAAQS applyto abroad 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 countrynot 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 $1O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is converted to1982 dollars it becomes $6,148/ton. The average cost per ton for NO, reductions at BaldwinUnit 3 in 1982 using LNBs is substantially lower than the acceptable high end for costs used byNJDEP and EPA in the two**~** 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 DynegyMidwest Generation, Inc. B' See Keystone Cogeneration FacilityBACT for Nitrogen Oxides Addendum, June 1990, ENSR Consulting and Engineering.**~** See http://www.enr.com/cost/costcci/asp for cost adjustments. @ Final Air Quality Management Plan, 1982 Revision, South Coast Air QualityManagement District and Southern California Association 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/artdiair/nsr/nsrmemos/t2bact.pdf 21examples above, and similarto 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. OtherEnvironmental Impacts No significant environmental impacts would have occurred as a result ofusing LNBs. d. Conclusion In summary, Iconclude 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 byuse ofa Continuous Emissions Monitoring System (CEMS). 3. ParticulateMatter As of 1982, Baldwin Unit 3 was equipped with an electrostatic precipitator. Data reported by Illinois Power show that it was achieving a removal efficiencyofabout 99.4-99.5%.2.!! The following emissions control options were available for consideration in 1982. 1. Electrostatic Precipitator (ESP) 2. Baghouse
a. Technical Feasibility An ESP was in use on Baldwin Unit 3 in 1982. Itwas therefore, technically 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.)'!liBaghouses were therefore also technicallyfeasible and available. The removal efficiencythat BaldwinUnit 3 was achieving in 1982 compares favorably with the

2.!! Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1982. IPPRO-0104439-0104464. 2Y See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. '!li See Table 7 for derivation ofcontrol level. 22baghouses in 1982, and achieving limits as low as .005 

### grlACF.2Y (This equates to 99.7% control at Baldwin Unit 3.)211 Baghouses were therefore also technically feasible and available. The removal efficiency that Baldwin Unit 3 was achieving in 1982 compares favorably with the permitted emissionrate for the Harry Allen Station**~** (where a particulate matter emission rate of 0.015 poundfMMBTU was required, based on a removal rate of99.76%). Although that permit assumed that a baghousewouldbe 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. BaldwinUnit 3's ESP was controlling emissions to about 99.4% in**1982.~** IfIllinois Powerhad been required to add controls (likelyto be an additional baghouse or another field 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 I have 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 ForBaldwin Unit 1: 1985 Unit I is a cyclone fired boilerwith a gross output rating of584 megawatts (MW)29' and began operation in 1970.'l1I Itis designed to fire 267 tons perhour of**coal~** with a heating value of

2Y See report ofWilliam Ellison, PE, Ellison Consultants, developed inconnection with United States v. Illinois Powerand DynegyMidwest Generation, Inc. 211 See Table 7 for derivation ofcontrol level.**~** See EPApermit for Harry Allen Station, NV-77-01 and associated National AmbientAir Quality Impact Report.**~** Department ofEnergy, Energy Information Administration, (Form EIA-767) for year 1982. 29' Sargent & Lundy Engineers Engineering Data, Unit 1 BaldwinPower Station. IPPRO0085676-744. 'l1I Ibid.**~** Department ofEnergy, Energy Information Administration, (Form EIA-767) for year 1985. 23I985.®' The available control technologies are the same as those that were potentially applicable 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 exhaust gas. Most ofthese scrubbers were wet limestone orwet lime buffered with magnesium oxide
. .!QY·lQ!I 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 I
. .!§! Most ofthe methodologyused in 1991 would also apply to Unit 1 in 1985. According to that study, capital costs for the wet limestone scrubber are estimated to have been approximately $189**million.~** Operating costs would have ranged from $3.53 million to 5.04 million, depending on whether waste from the scrubber system would have been sold
.. When these costs are converted to annualized costs, the annual cost would have beenbetween $23.5 and 25.0 million. Analysis ofwet lime scrubberbuffed with magnesium oxide shows it to bemore

.®' See Expert Report ofRanajit (Ron) Sahu, April 2002, compiling CEMS data submittedby Illinois Power Companyto U.S. EPA. .!QY See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCRInstallations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc
. .!.Q2{ See "Table 30: Flue Gas Desulfurization (FGD) Capacityin Operation at U.S. Electric Utility Plants as ofDecember 1999." This information can be found at website address: http://www.eia.doe.gov/cneafielectricity/epav2lhtml_ tables/epav2t30pl.html and following pages .!§! Babcock and Wilcox, Contract Research Division and Environmental Equipment Division, Volumes 

### I-IV ofProposal for Full-Scale Demonstration ofIntegrated Flue Gas Desulfurization System with RebumingNOx Control, B&W Proposal #90-071 (May 1991), IPPRO-0128923- 0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-0127567-0127848.**~** 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 DynegyMidwest Generation, Inc. 24expensive for the same level ofcontrol as the wet limestone scrubber, therefore onlythe wet limestone option received further consideration
. .ill2 The wet limestone scrubber would remove 96,800 tons peryear ofS02. 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, I reviewed other BACT determinations and EPA policydocuments. I reviewed the cost effectiveness ofeighteen powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. Ofthose where a dollarperton cost effectiveness was listed, the range (once converted to 1985 dollars) is $155 to 4715/ton
. .!Q7J Also, in 2001, EPA issued guidance related to presumptive BACT for NOx at refineries being modified to meet EPA mandates for making cleanerburning gasoline
. .!.QJY That guidance used $10,000Iton as an upperbound for BACT cost effectiveness. When that value is converted to 1985 dollars it becomes $6,5811ton. The estimated costs for wet limestone scrubbing at Baldwin Unit 1 in 1985 is at the low end ofthe range ofthesepermits and EPA guidance. The cost is therefore not unreasonable.
c. OtherEnvironmental Impacts Wet scrubbers produce a sludge that mayhave economic use. Ifnot used, it mustbe disposed in a landfill. This sludge is not considered hazardous waste. No other significant environmental effect occur due to the use ofscrubbers. d. Conclusion Based on the above data, I conclude that BACT for S02 at BaldwinUnit 1 in 1985 would have been an emissionrate of0.30 pound/million BTU,.!Q2r 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 would have been monitored byuse ofa Continuous Emissions Monitoring System (CEMS).!!!¥

.ill2 Ibid; also see http://www.enr.com/cost/costcci.asp for cost adjustments
. .!Q9' See Table 8b for calculations
. .!Q7J See Table 11, Cost Effectiveness ofBACT Determinations for S02
. .!.QJY 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 canbe found at website address: http://www.epa.gov/rgytgrnj/programs/artd/air/nsr/nsrmemos/t2bact.pdf .!Q2r See Table 8b for calculations. !!!¥ See 40 C.F.R Part 60, Appendix B, Performance Specification 2. 25

### 2. Nitrogen Oxides As of 1985, Baldwin Unit 1had no controls inplace for NOx emissions.!.!.!i Unit 1's NOx emissions are estimated to have been approximately 1.8 pounds per million BTU.ill' 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 ForUnit 1, in 1985, I considered the feasibility ofLNBs, OFA, SCR and SNCR. LNBs were not technically feasible because they simplyhave not been 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.illTherefore, in myjudgement, given the technical difficulty ofengineering an overfire air system for a cyclone fired boiler, I would consider that technology also to be unavailable for use on Unit 1in 1985. However, in contrast to1982, by 1985, SCRhad 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.ill! In addition, at least sixteen SCR systems on coal fired powerplant boilers in Japan were in operation orunderconstruction bythis time, including both new and retrofit facilities. These powerplantboilers ranged in size from 125 to 700 megawatts in size.illPlanned reduction rates are not available for all ofthese facilities, but for a subset in operation by 1984, reduction ranged from 57 to 81%.ill'Operational problems experienced in the
!.!.!i Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1985. ill' See Expert Report ofRanajit (Ron) Sahu, April, 2002, compiling CEMS data submitted by Illinois Power Companyto 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 withUnited States v. Illinois Power and DynegyMidwest Generation, Inc. ill See Ando, Jumpei, 

### "SOl andNOx 

### RemovalFor 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 bythis time. ill

### Two Gennan facilities that would begin operation in 1986 were likely under**construction.~** 

### 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.!!2',1N' 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 a precise range.Q!/ SNCR systems have lower capital costs than SCR, but typically have higher ammonia emissions levels compared to SCR, i.e. 30 to 40 parts permillion (ppm) compared to as little as 1ppm for SCR systems.ill! Beginning in about 1985, many coal fired powerplants were pennitted using SNCR.ill! However, none ofthese were cyclone fired boilers.MTherefore, I would conclude that SNCR was not available in 1985 for

ill 

### Ibid, page 5-2.**~** 

### 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. !.!Ji 

### 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 ppmNOx 

### limit. 1N' LAER is generallythe most effective emission limit that has been achieved for a source category. Consequently, the LAER emissionrate, and the technology on which it is based, would generallybe the most effective emission control option in a BACT analysis, and must be considered. Q!/ See U.S. EPA, Office ofAir and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies DocumentNOx

### Emissions from Utility Boilers" March 1994. This infonnation can be found at website address: http://www.epa.gov/ttnlcatcldirl/utboiler.pdf. ill! See U.S. EPA, Office ofAir and Radiation, Office ofAir Quality Planning and Standards, "Alternative Control Technologies DocumentNOx

### Emissions from Utility Boilers" March 1994. This infonnation can be found at website address: http://www.epa.gov/ttnlcatc/dirllutboiler.pdf. ill! References: PSD pennit #s SE 85-01, 85-05, SJ 85-06, SJ 85-07, SJ SE 86-04, SJ 86-08, 86- 09. M 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 information in the literature as to the effectiveness ofSCR as the boiler undergoes 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 order to 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 1and 2.ill! 

### Since 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 $20.2 million.illY This yields a cost effectiveness of$ 1368/ton 

### reduced.ill'·@ These costs are likelyto be conservative. For example, the 1990 studywas for an installation that would remove
and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies Document NOx 

### Emissions from UtilityBoilers" March 1994, page 49. This information can be found at website address: http://www.epa.gov/ttn/catc/dirllutboiler.pdf. 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 DynegyMidwest Generation, Inc. illY Ibid. ill' See Table 3b for calculations.
@ 

### This cost estimate assumes that the catalyst would bereplaced every three years. That assumption maybe very conservative. At least one early SCRinstallation, at Knepper Unit C in Germany, went into service in 1986, and, as of 1998, was operating with 56% ofits original catalyst. Anotherplant, Velthiem, began operation in 1989, and as of 1998, 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/pgglttlpdfIBR 

### -1665.pdf. 2885% ofNOx from the exhaust stream. In contrast, a 55% reduction ofNOx was used for this analysis. The lower removal 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 initiallybe used, less catalyst would need to be periodicallyreplaced. In spite ofthese likely cost reductions, our cost estimate did not take the lower removal 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$13,200/ton. When converted to1985 dollars, the New Jerseypermits would require controls at a cost effectiveness of$II,700. ll2i Also, in 1982 the South Coast AQMD (SCAQMD) adopted a revision to its air quality management plan
..!.l9' 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 ofsource categories, and are almost always retrofit measures. Consequently, the costs ofthesemeasures are generally less than BACT costs. The Los Angeles area, which is part ofthejurisdiction ofthe SCAQMD, was the only area in the countrynot 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 1985 dollars, the range becomes $660 to $7180/ton. Lastly, in 2001 EPA issued guidance related to presumptive BACT for NOx at refineries being modified to meet EPA mandates for making cleanerburning gasoline.illThat guidance used $10,000Iton as an upper bound for BACT cost effectiveness. When that value is converted to1985 dollars it becomes $6,620Iton. The average cost perton for NOx reductions using SCR at Baldwin Unit 1in 1985 is substantially lower than the acceptable high end for costs used byNJDEP and EPA in the two 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 1 in 1985 are not unreasonable.
c. OtherEnvironmental Impacts

ill! See http://www.enr.com/cost/costcci/asp for cost adjustments
. .IN' Final Air QualityManagement Plan, 1982 Revision, South Coast Air QualityManagement District and Southern California Association ofGovernments, 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 Refinery Projects, dated January 19, 2001. This information can be found at website address: http://www.epa.gov/rgytgmj/programs/artdiair/nsr/nsrmemos/t2bact.pdf 29SCR and SNCR use ammonia, which could cause environmental effects ifemitted in large amounts. However, ammonia slip (umeacted ammonia emitted to the atmosphere) is limited by design in SCR systems to about 3 ppm, so effects would not be likely to 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 1in 1985. Compliance with the limit would have been monitored byuse ofa Continuous Emissions Monitoring System (CEMS).ill' 3. ParticulateMatter 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 

### 1985,ill! it appears that the ESP was in need ofsignificant maintenance orrepair. Illinois Power also performed periodic tests ofthe ESP. Based on the 1984 tests, I estimate emissions to have been approximately 580 pounds per hour.!l1' but, based on other tests performed before and afterthat date, showing that emissions were highly variable, I conclude that emissions could have been as high as 879 pounds perhour 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. ill! See EIA Reports numbered IPPRO-0104246; IPPRO-OI04275; IPPRO-0104304; IPPRO0104333; IPPRO-OI04370; IPPRO-OI04404; IPPRO-OI04456; IPPRO-OI04457; IPPRO0104480; IPPRO-OI04481; IPPRO-OI04503 and IPPRO-OI04504
. .!l1' See Summary ofStack Test Data (0.1 poundfMMBTU); 5,824 MMBTUIhr derived 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-0018582; IPPRO-0016835; IPPRO-0021387; IPPRO-0070999. 30For this analysis, I have assessed only the option ofreplacing the ESP with either a new ESP or a baghouse. In 1991, Illinois Power analyzed the options to increase particulate control at Units 1 and 2.ill! Theyconcluded that a replacement ESP would be more cost effective than an upgrade ofthe existing ESP. Illinois Power did not analyze the cost ofreplacing the ESP with a baghouse. Among the conclusions ofthat study was that the existing ESP was in "poorcondition," and that a "majorupgrade and refurbishment ofthe existing ESP will be required in order to obtain another 30 years ofservice."11§' Since this study was conducted only about five years after 1985, I believe its conclusions would generallyhave applied in 1985, i.e., that the existing ESP was near the end ofits useful life and that a new or refurbished 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 grainlACF (actual cubic foot).ill! Of those 29, manywere 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 1 . .!l2t An emission rate of.003 gr/ACF is equivalent to 99.7% control at Baldwin Unit l . .!±!.¥
11. ESP As of 1982, Illinois Power operated an ESP on Unit 3 with a removal efficiencyofapproximately 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 1Electrostatic Precipitator Study" (1991). IPPRO-0058084 through IPPRO-0058136. 11§' Ibid., page 11-1. IPPRO-0058092. ill! See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. ill' See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, Inc
. .!l2t See Appendix A, Table 4b: Emissions Calculations and Cost Effectiveness for Particulate Matter in 1985
. .!±!.¥ See Table 4c for calculations. 31Based on a design to remove 99.6% ofparticulate matter (based on the capability ofa baghouse, as discussed in the 1982 analysis, above), an ESP is estimated to have an annualized cost of about $19 million (and a capital cost of$105 million).li!t A baghouse with similar capabilities 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 I considered for further analysis. The total cost effectiveness ofthe baghouse would be $8111ton. 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 1985 timeframe. These data show that the estimated construction cost for a baghouse is similar to that ofother contemporaneous sources. Forexample, Arizona Public 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 1 (704 MW), built in 1983, reported a capital cost of$210million for its ESP removing 99.9% ofPM. The estimated costs for a baghouse 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 consideredhazardous waste.
c. Conclusion I have determined that BACT for particulate matter for Unit 1 in 1985 wouldhave been an emission limit of0.003 pound/million BTU and the use ofabaghouse and 99.6% removal.ill' Compliance would have been monitored using EPA method 5 and an opacityCEMS.

li!t 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 Power and DynegyMidwest Generation, Inc. ill' Ibid. ill! Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 2000.**~** See Table 4b 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.ill! Unit 2 began operation in 1973
..!§ It was designed to fire up to 267 tons per hour.!£! ofcoal with a heating value of 10,460 BTU per pound
. .!.i§t 1. SOl Control As of 1988, Baldwin Unit 2 was uncontrolled for emissions ofSOl' and was burningcoal with a sulfur content of3%.illt

a. Technical Feasibility Control options for SOl 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, manynew 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 of80to 95%.lli' Outside the U.S. similar increases in scrubber capacity 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.ill Since there was onlyonepowerplant operating at 97%, I continued to analyze scrubber
ill! Ratings ofIllinois Power CompanyFossil Fuel Fired Generating Units; Report byPower Technologies, Inc. December, 1987. IPPRO-00151120 .!§ Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1985
. .!£! Ibid
. .!.i§t Sargent & Lundy Engineers EngineeringData, Unit 3 Baldwin Power Station. IPPRO0085900 illt Department ofEnergy, Energy Information Administration (Form EIA-767) for 1988. lli' See "Table 30: Flue Gas Desulfurization (FGD) Capacityin 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/epav2lhtml_tables/epav2t30pl.html and following pages ill See report ofWilliam Ellison, PE, Ellison Consultants, "Table 1, FGD Installations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 33options 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 be approximately $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 ornot. When these costs are converted to annualized costs, the annual costwould be approximately $27.1 million. The scrubber system would remove approximately96,800 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 permittedbetween 1979 and 1999 with BACT requirements for scrubbers. Ofthose where a dollarperton 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 $10,000/ton as an upperbound for BACT cost effectiveness. When that value is converted to1988 dollars it becomes $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, it must be disposed in a landfill. This sludge is not considered hazardous 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

illI 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 DynegyMidwest Generation, Inc.; cost data adjusted based on http://www.enr.com/cost/costcci.asp. ill! See Table 11, Cost Effectiveness ofBACT Determinations for S02. 34emission rate of0.30 pound/million BTU,ll1' 30 dayrolling average, based on the use ofa wet limestone scrubber removing 95% ofthe S02 from coal having a sulfur content of3-3.5%. Compliance with the limit would have been monitored byuse ofa Continuous Emissions Monitoring System (CEMS)
. .illJ 

### 2. NO f 

### Control Like Unit I, as of 1988, Baldwin Unit 2 had no controls for NOx emissions.J19'

a. Technical Feasibility For Unit 2 in 1988, I again considered the feasibilityofLNBs, OFA, SNCR and SCR. Ofthese options, LNBs were not technically feasible in 1988, because theyhave not today been developed for cyclone fired boilers. OFA was also not technically feasible by 1988. While OFA had been used on other types ofcoal combustion, it had not been used oncyclone fired boilers.ill SNCR had been demonstrated by 1988 on a number offacilities overseas firing high sulfur coal, as well as manyfluidized bed coal fired boilers permitted and under construction 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**NOJ~§'** 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.ill!·~** With respect to SCR,by 1988, significant additional experiencehadbeen gained worldwide in the application ofthis technology to coal fired boilers. SCRhad been installed on at least two

lli' See Table 8c for calculations
. .illJ See 40 C.F.RPart 60, Appendix B, Performance Specification 2. J19' Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1988. ill' See report ofWilliam Ellison, PE, Ellison Consultants, "Table 1, FGD Installations," developed in connection with United States v. Illinois Power and DynegyMidwest 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. ill! Ibid.**~** See Kern CountyAir Pollution Control District, EngineeringAnalysis ofMt.PosolPyropower Cogeneration Facility, November 1986, page 67. "
...an emissionrate of0.092 pound NOJMMBTU satisfies NOx LAER requirement." 35cyclone, (or "wet bottom") boilers, as well as many othercoal fired powerplants.illBy 1988, twenty-five coal fired boilers in Japan, six in Gennany and two in Austria had begun commercial operation ofSCR systems for NOx control..!EI 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 sulfur contents up to 1.3%.ill!The use of SCR at these boilers achieved NOx control efficiencies ranging from 67 to 92 percent. Six other facilities were under construction overseas and would begin operation by 1992.lli' Because all but one ofthese Gennan facilities had SCR with design NOx reduction levels of approximately 80% orgreater,.!.@ I have detennined that level ofreduction was technically feasible in 1988. b. Cost Analysis SCRwas the top, ormost effective, option for available in 1988. Unless it were to be rejected on the grounds ofunacceptable environmental or economic cost, SCRwould bechosen as BACT. As in the 1985 analysis above, the cost for SCRwas estimated using Illinois Power's studyW for installing SCRonunits 1 and 2 in 1990. The costs were then adjusted to 1988 values.ill' These adjustments yield an annualized cost of$22.6 million. SCRwould 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
. .!EI See ENSR Consulting and Engineering, "Keystone Cogeneration FacilityBACT for Nitrogen Oxides, Addendum," June 1990. ill! See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCRInstallations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. lli'Ibid
. .!.@ See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCRInstallations," developed in connection with United States v. Illinois Powerand DynegyMidwest Generation, Inc. W See SCR Cost Evaluation for Illinois Power, BaldwinUnits 1 & 2, May 17, 1990. Prepared byBums & McDonnell, Kansas City, MO. ill' See report ofDanMussatti 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 DynegyMidwest Generation, Inc. 36percent capacity factor, and an SCR system that removes 80% ofthe inlet NOJ@ 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 per ton compares very favorably with relevant PSD permits and cost analysis performed 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 Jerseypermits would require controls at a cost effectiveness of$12,640
. .!§' Also, as noted above, in 1982 the SCAQMD adopted an air quality management planlEY establishing control measures to help bring the area into compliance with the NAAQS. 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 1988 dollars, the range becomes $713 to $7,750/ton. Lastly, in 2001 EPA issued guidance related to presumptive BACT for NOx at refineries being modified to meet EPA mandates for making cleanerburning gasoline
. .!2Y That guidance used $1O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is converted to 1988 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 permits and EPA guidance. The cost is therefore not unreasonable.
c. OtherEnvironmental Impacts SCR and SNCRuse 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. SNCRtypically has a higher ammonia slip; as high as 30 ppm. Because ofthe higher ammonia slip rate for SNCR, SCRwould usuallybe preferredbecause 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 onthe use ofSCRwith 80% removal was BACT for Unit 2 in 1988. Compliance

!§' Ibid
. .!§' See http://www.enr.com/cost/costcci/asp for cost adjustments. lEY Final Air QualityManagement Plan, 1982 Revision, South Coast Air QualityManagement District and Southern California Association ofGovernments, October 1982
. .!2Y 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/rgytgmj/programs/artdlair/nsr/nsrmemos/t2bact.pdf 37with the limit would have been monitored with a CEMS. 3. ParticulateMatter 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
..ill' 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, I have again assessed onlythe option ofreplacing the ESP at Baldwin with either a 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,ill! 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 bereplacement, rather than upgrade, ofthe existing ESP (Illinois Powerdid not analyze the option ofreplacing the ESP with a baghouse).ill' Those conclusions shouldbe equally applicable to Unit 2.
1. Baghouse In 1985, it would have been technically feasible for Illinois Power to substantiallyimprove its particulate control with a baghouse. As of 1988, at least 32 coal fired powerplants had installed baghouses designed to achieve levels ofPM less than 0.01 grainlACF (actual cubic foot).illi Of

.ill' See EIA Reports numbered IPPRO-OI04246; IPPRO-0104275; IPPRO-OI04304; IPPRO0104333; IPPRO-0104370; IPPRO-0104404; IPPRO-0104456; IPPRO-OI04457; IPPRO0104480; IPPRO-0104481; IPPRO-OI04503 and IPPRO-OI04504. ill! Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 1988. ill' See Bums and McDonnell report, "BaldwinUnit 1Electrostatic Precipitator Study" (1991). IPPRO-0058084 through IPPRO-0058136. illi See report ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 38those 32, manywere designed to achieve levels ofbetween 0.001 and 0.005 

### gr/ACF.ill' 

### An emission rate of.003 

### grlACF is equivalent to 99.7% control at Baldwin Unit 

### I,1JJi

n. ESP As of 1982, Illinois Power operated an ESP on Unit 3 with a removal efficiencyofapproximately 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 a new ESP at Baldwin Unit 1in 1988 is estimated to have been about $20.2 million ($113 million capital cost)
. .!2!Y' A baghouse with similarcapabilities would have had an annualized cost of $11.6 million ($55 million capital 

### cost)
. .J12t 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 ofthe baghouse 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 show that the estimated construction cost for a baghouse is similarto that ofothercontemporaneous sources. Forexample, Northern States Power's Sherburn CountyUnit 3 (809 MW), built in 1987, reported a capital cost of$73.1 million for its baghouse removing 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
. .@'The costs for a baghouse at BaldwinUnit 1in 1988 are therefore note unreasonable.

ill' Seereport ofWilliam Ellison, PE, Ellison Consultants, developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. ill See Table 4c for calculations
. .!2!Y' 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 DynegyMidwest Generation, Inc
. .J12t Ibid
. .@' Department ofEnergy, EnergyInformation Administration (Form EIA-767) for 2000. 39b. Other Environmental 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 conclude that an emission limit of0.003 pound/million BTUbased on the use ofthe use ofa baghouse removing 99.7% ofPM represented BACT at Baldwin Unit 1in 1988. Compliance would have been monitored with EPA method 5 and use ofan opacity CEMS. D. BACT Determinations for Baldwin Station: 2002 

### 1. BACTDetermination atBaldwin Units 1

### and2 I am analyzing these two units togetherbecause they have designs that are virtually identical for thepurposes ofthis analysis. These two units are currentlyburning coal from the Powder River Basin with a sulfurcontent ofapproximately 0.25%. Theyboth also have overfire air installed, as well as infrastructure for SCR, although no catalyst is installed. Units 1 and 2 underwent upgrades to their ESPs in 1999. Although none ofthe results ofthese upgrades and changes are enforceable as permit conditions,illthe S02 and NOx controls IP has employed to date are presumablythe result ofIllinois Power's need to complywith acid rain (Title IV)provisions of the Clean AirAct.
a. S02 Control To be analyzed together with Unit 3, below. b. NOx Control The available control options are: 1. SCR 2. OFA 3. SNCR 4. Coal or Gas Reburning 5. Optimization system
ill Joint Construction and Operating Permit issued February 19, 1999 (EPA 5776); Operating Permit issued January 5, 1996 (IPPRO-0019014); Operating Permit issued December4, 1998 (IPPRO-0019233); Operating Permit issued June 20, 1996 (IPPRO-0018725); Construction Permit issued April 14, 1998 (EPA 5775); Operating Permit issued June 26, 1997 (IPPRO0019094). 401. 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 1990.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 SCRto control NOx**emissions.ill~** OFA has also become a verywidely used technology. In fact, Illinois Powerinstalled OFA at Baldwin Units 1 and 2 in approximately 1999.illOFA 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 reburn 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 manytechnical issues in applying reburn, such as maintaining acceptable boiler performance when a large amount ofheat input is moved from the main combustion zone to a different area of the furnace. Utilizing all the carbon in the fuel has been a problem in the past when pulverized coal is the reburn fuel.ill! Notwithstanding these concerns, at least one demonstration project on a cyclone fired boiler showed reburn technology achieving a NOxreduction of50%, with minimal

ill' See, e.g. New JerseyDepartment ofEnvironmental Protection, permit number01-89-3086, issued onDecember 26, 1990to Chambers Cogeneration Limited Partnership. ill See "Performance ofSelective Catalytic Reduction on Coal-Fired Steam GeneratingUnits," USEPA, June, 1997. This document maybe found at website address: http://www.epa.govIairmarktlarp/nox/scrfinal.pdf.**~** See SCRInstallations 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/cmprptlarpOO/appendixbI200.pdf. The reported emissionrate for Baldwin Units 1 and 2 are 0.66 and 0.70 pound permillion BTU, respectively. This is more than a 50% reduction compared to the uncontrolled rate of 1.8 poundslMMBTU. ill! See U.S. EPA, Office ofAir and Radiation, Office ofAir QualityPlanning and Standards, "Alternative Control Technologies Document NOx Emissions from UtilityBoilers" March 1994. This information can be found at website address: http://www.epa.gov/ttn/catc/dirllutboiler.pdf. 41operational**problems.~** SNCR has been described earlier. Emissions reductions ofup to 80% ofNOx have been demonstrated using SNCR on coal fired boilers.m Optimization systems are new technologies that I have 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 NOxand improve boiler efficiencybymonitoring a number ofparameters, and then providing infonnation 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.

### m Some ofthe above technologies maybe used effectively in conjunction with one another, and feasible combinations therefore should be considered. Specifically either SCRor SNCR may follow almost any otherNOx emissions control technology. For example, use ofOFA maybe followed by an SCR system. OFA and reburning (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 bySCR or SNCR 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 infonnation is available as to the effect ofoptimization systems in conjunction with other emissions reductions retrofits. Because ofthe high NOx emission 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 optionthan reburning;.!2.!! for that reason I did not analyze reburning further. Therefore, the options available are SCRor SNCR and OFA together, orOFA alone (i.e with no additional control). All three options are**~** See "Demonstration ofCoal Reburning for Cyclone BoilerNOx Control," McDennott International Inc, 2001. This infonnation canbefound at website address: http://www.mtiresearch.com/expernce.html#Demonstration ofCoal Reburn.
m See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCRInstallations," developed in connection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 

## m See "What'sNew in the Power Industry," World Bank, 2001, found at website address http://www.worldbank.org/html/fpd/ern/power_industryl0.htm
. .!2.!! See Illinois Power "Gas at Baldwin" report, dated May 1990 (IPPRO

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

### In order to determine the emission limit, I considered both the effectiveness ofthe controls as well as the fact that this would be a retrofit to a thirty year old powerplant..!2?I Based on Illinois 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, rather than a new installation. I also 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 oftheseplants would emit less than 0.15 pound/million BTU, because that is the maximum allowed under the NSPS.lli' However, cyclone fired boilers without controls emit far more NOxthan othercoal burning technologies, and ofthe currently proposed plants would be cyclone fired boilers. Therefore, it is difficult to make a direct comparison betweenrecent BACT levels and the appropriate level for Baldwin Units 1 and 2. 

### It is, instead, necessary to derive a BACT emission limit for Baldwin Units 1 and 2 based on the performance ofdemonstrated NOx control technologies. Based onthe performance ofthe technologies discussed above, and the reductions achievable from these technologies, the "top"option for NOx control for Units 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 air system would reduce emissionbyat least 50%, and SCR couldreduce emissions bya further 90%. I assumed a combined removal effectiveness ofapproximately 92% from use ofOFA and SCR. This rate assumes that OF A will reduce emissions between 60 and 70%, and SCRbetween 80 and 90%. As I discussed above, I did not assign a specific amount ofemission 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 emission rate of 1.8 pound/million BTU, this combination ofcontrols could result 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 for NOx emissions control at Baldwin Units 1 and 2 today
.
.!2?1 See PSD Appeal No. 94-1 (Masonite Corporation), 5 EAD 551, page 10. This document maybe found at website address http://www.epa.gov/eab/eabpsd.htm. ill! See National Coal-Fired UtilityProjects Spreadsheet, EPA Region 7, March 1,2002. lli' 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." 43II. 

### Other Environmental Effects Most ofthe options for NOx 

### 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 1and $8.7 million for Unit 2.ill! 

### Based on a controlled rate of0.14 poundslMMBTU (controlling approximately 10,000 TPY ofNOx), 

### the cost effectiveness ofthese controls would be $877 and 842/ton for Units 1 

### and 2,**respectively.~** 

### 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 for NOx 

### at refineries used $10,000Iton 

### as an upperbound for BACT cost effectiveness. In comparison to these benchmarks, the cost ofSCR, OFA and an optimization system is not unreasonable.
IV. 

### Conclusion Based on all ofthe above factors, I 

### have determined that an emission limit of0.14 pound/million BTU, 30 dayrolling average, based onuse ofthe combination ofOFA, SCR capable of90% control, and an optimization system, represents current day BACT for emissions ofNOx 

### at Baldwin Units 1 

### and 2. Compliance with this limit would be monitored via use ofa CEMS.
c. Particulate Matter
1. 

### Technical Feasibility Control technologies available for particulate control are essentially the same as those discussed earlier: ESPs and baghouses. Two kinds ofbaghouses are currently available for consideration for coal fired powerplants: pUlse-jetbaghouses and reverse air baghouses. The difference

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 DynegyMidwest Generation, Inc.**~** 

### See Table 3d for calculations. 44between the two technologies relates to the wayin which captured particles are removed from the bags after the bags collect the particles. Emission rates for new facilities controlled byESPs and baghouses range from about 0.015 to 0.020 pound/MMBTU. These emission rates reflect control ofapproximately 99.7% (see also PM analyses, 1985 and 1988)

. .!27J
H. Other Environmental Impacts Neither baghouses nor ESPs would have any significant other environmental effects. The material collected in baghouses and ESPs is not considered hazardous, and maybe disposed ofin accordance with regulations for non-hazardous waste.
HI. Cost Analysis I analyzed the cost ofcomplying with the lowest limit currentlyproposed for new powerplants: 0.015 pound/million BTU. As discussed in the earliertimeframes, (see 1985 and 1988 analyses above), a baghouse was the least expensive option. The same conclusion was reached for the present day. Therefore, only options for using a baghouse to control emissions were analyzed. Of the two baghouse options, the pulsejetdesign 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
. .!2§' I estimate that the total cost effectiveness would be $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.112' Datareported from powerplants constructed earlier, discussed in the 1985 and 1988 timeframes, also show that the capital cost estimated for a new pUlse-jet baghouse at Baldwin Units 1 and 2 is at the low end compared to these other powerplants. The cost is therefore not unreasonable
.

.!27J SeeNational Coal-Fired UtilityProjects Spreadsheet, EPA Region 7, March 1,2002
. .!2§' 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. 112' Department ofEnergy, Energy Information Administration (Form EIA-767) for 2000. 45IV. Conclusion I therefore conclude that an emission rate of0.006 poundspermillion**BTU~** based on use ofa 99.6% efficient pulsejet baghouse is BACT for particulate matter at 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 PowderRiver Basin with a sulfur content of approximately 0.25%. Unit 3 was retrofitted with a low NOxburner in 1994.N!IThe ESP was upgraded in**2000.~** Although none ofthe results ofthese upgrades and changes are enforceable as permit conditions,ill!the S02 and NOx controls IP has employed to date are presumably the result ofIllinois Power's need to complywith 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 scrubbingbuffered byMagnesium Oxide d. Dry Scrubbing.
1. Technical Feasibility I have previously addressed the technical feasibility ofthetwo 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 sent to a spraydryer absorber (SDA). In the SDA, a fine mist oflime slurryis sprayed into the flue gas. Heat from the flue gas evaporates the moisture in the slurry cloud while the alkaline slurry simultaneously absorbs the S02inthe flue gas. The result is the conversion ofthe calcium hydroxide component ofthe slurryinto a fine powderof calcium/sulfur compounds, and lowering ofthe flue gas temperature. Removal efficiencies ofup**~** See Table 4d for calculations. N!I IP Permit Application dated January 19, 1993. IPPRO-0032541.**~** Operating Permit issued June 26, 1997. IPPRO-0019094. ill! Ibid., and IP Permit Application dated January 19, 1993. IPPRO-0032541. 46to 90% with PRB coal have been**demonstrated.~** Illinois Powerhas 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% orgreater, using one ofthe above technologies. Several plants using coal with less than 1 % 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 sulfur coals. Dry scrubbing has been demonstrated to remove up to 90% ofS02 from western coal. Wet scrubbing is therefore the "top," ormost effective option.
11. Other Environmental Impacts Wet scrubbers produce a sludge that requires mayhave economic use. Ifnot used, it must be disposed in a landfill. This sludge is not considered hazardous waste. Dry scrubbers produce a powder that mayalso be disposed in a landfill, and is also not considered hazardous waste. No other significant environmental effect occur due to the use ofscrubbers.
lll. Cost Effectiveness The capital cost to install a wet limestone scrubber....Q9' today would be $71.4 million at each of Baldwin units. Annual operating costs for Units 1and 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 cost would be approximately $15.9 million perunit for Units 1 and 2, and $16.3 million for Unit 3.

## m Assuming a removal efficiencyof**~** See "RetrofittingLime Spray Dryers at Public Service CompanyofColorado," R. Telesz et. aI., Presented to Power-Gen International 2000, November200. This document maybe found at website address: http://www.babcock.com/pgg/tt/pdflBR-1707.pdf.**~** See "Table 30: Flue Gas Desulfurization (FGD) Capacityin Operation at U.S. Electric Utility Plants as ofDecember 1999." This information can be found at website address: http://www.eia.doe.gov/cneafielectricity/epav2Ihtml_ tables/epav2t30pl.html and following pages. l:2!!f Prior analyses (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 4795%, the cost effectiveness, therefore, would be approximately 

### $652/ton for Units 1 and 2, and 

### $570/ton for Unit**3.~** In order to ensure that the costs estimated for the scrubber are not excessive, I reviewed other BACT determinations and EPA policydocuments. I reviewed 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 2001 dollars) is $234 to 

### 7129/ton.M Also, as noted, EPA's guidance related to presumptive BACT for NOx at refineries used $1

### O,OOO/ton as an upper bound 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.lli¥
IV. Conclusion Based on the above information, I have determined that BACT for S02 at Baldwin station today is an emissionrate of0.095 pounds permillion BTUbased on 95% scrubbing and assuming use ofcoal with 0.6% sulfur.illCompliance with this limit would be monitored with a CEMS. b. NOx Control The available control options are: 1. LNB 2. SCR 3. OFA 3. SNCR 4. Coal orGas Reburning 5. Optimization system

United States v. Illinois Power and DynegyMidwest Generation, Inc. lQ§' See Table 8d and 8e for calculations. M See Table 11, CostEffectiveness ofBACTDeterminations for S02. Most ofthe highercost effectiveness values attach to facilities burning lower sulfur coal, while lowercost effectiveness correlates to facilities burning higher sulfur coal. lli¥ The cost estimate presented here may, in fact, beconservative. Some literature suggests that S02 scrubber costs have recently gone down. See "Cost ofS02 Scrubbers Down to 

### $100IKW, Douglas Smith, SeniorEditor, PowerEngineering, September, 2001. ill Calculated byusing a controlled emission rate of533 poundlhr and 5587 million BTUIhr. 481. Technical Feasibility As with Units 1 and 2, several NOx control options maybe 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 NOxburners are also technically feasible and available for tangentially fired boilers such as Baldwin's Unit 3. In fact, Illinois Power installed a 10w-NOx burner in Unit 3 in 1994. Emission rates from IP's 1994 installation were about 0.3 pound/million BTUill'. Emission rates from LNBs have improved dramatically since the 1994 installation. At least three manufacturers have demonstrated LNBs that attain NOx emission rates around 0.15 pound/million BTU.ill.ill!.ill! OFA is often an integral part ofthe design ofnewer LNBs (in fact, the currently installed LNBs at Unit 3 include integral OFAill'), or maybe added in a location near the burner in the boiler.illIn addition to LNBs, SCRor SNCRmaybe used as a postcombustion control. Most new coal fired powerplants that are permitted with SCR also use combustion controls such as LNBs.@ Theymay also use optimizations systems to enhance boiler efficiency and reduce NOx '

211, See "Emissions Data and Compliance Reports," USEPA. These data maybe found at website address: http://www.epa.gov/airmarkets/emissions/index.html ill Tangential LowNOx System at Reliant Energy's Limestone Unit 2 Cuts Texas Lignite, PRB and Pet Coke NOx, 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 MWeBoilerOperating Experience at 0.15 IblMMBTU NOx EmissionLevel Firing a Broad Range ofCoals," A.D. LaRue et. aI., Presented at EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, August 1999. This document can be found at website address:http://www.babcock.com/pgg/tt/pdflBR-1682.pdf. ill' Deposition testimony ofAric Diericx, November 10, 2000. ill See "B&W'sExperience Reducing NOx Emissions in Tangentially-Fired Boilers-2001 update," A. Kokkinos et. aI., Presented to Power-Gen International 2001, December 2001. This document maybe found at website location: http://www.babcock.com/pgg/tt/pdflBR-1726.pdf. @ See, eg, "PREVENTION OF SIGNIFICANT DETERIORATION CONSTRUCTION PERMIT 888 REVIEW DOCUMENT," issued to Kansas CityPower and Light for the Hawthorn Generating Station. 49Just as with Units 1 and 2, some ofthe above technologies maybe used effectively in conjunction 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 recentlybeen built ormodified with a combination ofLNBs and SCR. Forexample, the Chambers Cogeneration facility, an new plant permitted in 1990, has both LNBs and SCR,ill as does the Hawthorn facility, a new plant permitted in 2001.m¥ 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 bynew plants. Therefore, I would conclude that an emissionrate of 0.02 poundslMMBTU 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.ill! However, as I have shown above, it is readily achievable using currently available controls (i.e. SCR, LNB and optimization). For example, the AES Somerset plant inNew York, a 675 MWboiler, has reduced its emissions to 0.05 pounds permillion BTU, a 90%reduction using only SCR.ill'
n. OtherEnvironmental Effects Most ofthe options for NOx emissions control would have no significant otherenvironmental effects. SCRand SNCRuse ammonia, which could cause environmental effects ifemitted in
ill See New JerseyDepartment ofEnvironmental Protection, permit number 01-89-3086, issued onDecember 26, 1990 to Chambers Cogeneration Limited Partnership. m¥ See "PREVENTION OF SIGNIFICANT DETERIORATIONCONSTRUCTION PERMIT 888 REVIEW DOCUMENT," issued to Kansas CityPower and Light for the Hawthorn Generating Station.
ill! See National Coal-Fired UtilityProjects Spreadsheet, EPA Region 7, March 1, 2002. ill' See Selective Catalytic Reduction Retrofit ofa 675 MW Boiler at AES Somerset and Update ofSCR Retrofit on a 675MW Boiler at AES Somerset, Nischt et aI, Presented to ICAC NOx Forum, March 2000, and to ASME Joint PowerGeneration Conference, July 2000. These documents can be found at web site addresses http://www.babcock.com/pgg/ttlpdfIBR-1698.pdf

.http://www.babcock.comJpgg/tt/pdfIBR-1703.pdf. 50large amounts. However, ammonia slip is limited bydesign to about 3 ppm, so effects would not be likely to occur.
Ill. 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.ill!·W1 The annualized cost ofnew LNBs would be $1.5 million, and the annualized cost ofan optimization system would be $18,000.lli'·mThe total annualized cost would be $9.8 million, and would reduce approximately 3,900 TPY (this reduction is substantially smaller than potential reductions at Units 1 and 2 because Units I and 2 have a substantially larger uncontrolled NOx emission rate). The cost effectiveness ofthis combined option would be**$2539/ton.~** The costs ofachieving 0.02 poundlMMBTU are well within the range ofcosts estimated in recent PSD permits for coal fired powerplants. Forexample, coal fired powerplantspermitted since 1990 have been required to install controls with predicted cost effectiveness that ranges from $1690 (in 1999) to $13,196/ton (in 1990).llii

ill See report ofDanMussatti 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 DynegyMidwest Generation, Inc. ill! Ibid. WI Deposition testimony ofAric Diericx, November 10, 2000. lli' 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 inconnection with United States v. Illinois Power and DynegyMidwest Generation, Inc. 

## m Information from manufacturers ofthese systems show that these systems often yield bothnet cost savings and NOx emissionreductions. See "Full Scale ImplementationResults for GNOCIS (tm) Plus," George Warriner, URS Corporation, Steve Logan, Southern Company Services, Steve Pascoe, Powergen, James Noblett. Presented at theUSDOE-EPRI combined PowerPlant Air Pollution Control Symposium, August, 2001. "At someplants, lowering NOx canbe done simultaneouslywith increasing efficiency."**~** See Table 3e for calculations. llii See Table 10, BACT Cost Effectiveness for NOx Controls. 51IV. Conclusion I have 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 poundlMMBTU.

## m Illinois Power upgraded its ESP in 1999 as part ofits preparation to begin burning PRB coal.illAs I discussed in the 1982 case above, the original performance ofUnit 3 was far betterthan the performance ofUnits 1 and 2. Although we currently have no data about the current performance ofUnit 3's ESP, it appears that the original design, together with the upgrade, maybe capable ofmeeting a limit of0.015, 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 cannotperform at the necessarylevel to meet BACT. Assuming an emission rate of0.015 poundlMMBTU, the capital cost ofanew 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/ton. This is similarto other recently permitted powerplants. Forexample, the cost estimated for the Chambers Works Cogeneration Project for PM control (to 0.3 poundlMMBTU) in 1989 was $78/ton.ill'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 unlikelythat Illinois Power would berequired 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.



## m See National Coal-Fired UtilityProjects Spreadsheet, EPARegion 7, March 1, 2002. illDeposition testimonyofAric Diericx, November 10, 2000. ill' See Best Available Control TechnologyAnalysis for Keystone Cogeneration Facility, Bechtel Power Corporation, October, 1989. illSee Prevention ofSignificant Deterioration Construction Permit Application: Replacement of Unit 5 at the Hawthorn Generating Station, Bums and McDonnell, May 1999. 52Conclusion I therefore have determined 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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