\ 

REDACTED 

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 of Illinois 

APRIL 2002 

018984
TABLE OF CONTENTS 

Pal:e 

LIST OF TABLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv 

I. Introduction and Overview .................................................... 1 

A. Infonnation Required for the Expert Report ................................ 1 

B. Purpose of Report ..................................................... 1 

II. Summary of Conclusions ..................................................... 2 

III. Qualifications ............................................................. 3 

IV. What is BACT? ............................................................ 5 

V. The Typical BACT Detennination Process ...................................... 6 

VI. Baldwin Station: Background ................................................ 11 

VII. BACT Detenninations for the Baldwin Station .................................. 13 

A. BACT Detennination for Baldwin Unit 3: 1982 ... ; ........................ 13 

1. Sulfur Dioxide ................................................. 13 

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

3. Particulate Matter . ............................................. 22 

B. BACT Detennination For Baldwin Unit 1: 1985 ............................ 23 

1. Sulfur Dioxide ................................................. 23 

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

3. Particulate Matter . ............................................. 30 

C. BACT Detennination for Baldwin Unit 2: 1988 ............................ 33 

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

11 

018985
2. NOx Control . .................................................. 35 

3. Particulate Matter . ............................................. 38 

D. BACT Determinations for Baldwin Station: 2001 ........................... 40 

1. BACT Determination at Baldwin Units 1 and 2 ....................... 40 

a. S02 Control ............................................. 40 

b. NOx Control ............................................ 40 

c. Particulate Matter ........................................ 44 

2. BACT Determination/or Baldwin 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 of Dan 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. 

Attachment 2: 

Report of William Ellison, PE, Ellison Consultants, developed in connection with United States 

v. Illinois Power and Dynegy Midwest Generation, Inc. 

III 

018986
LIST OF TABLES 

Table 1: NOx Emissions Rates for Permits Issued up to 1982 . . . . . . . . . . . . . . . . . .. A - 3 

Table 2: Cost Effectiveness of S02 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: NOx Emission 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 Matter Emissions 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: Summary ofPowerplants with High S02 Removal: 1985 timeframe ..... A - 16 

Table 7: Derivation of Particulate Removal Efficiency. . . . . . . . . . . . . . . . . . . . . .. A - 17 

IV 

018987
Table 8a: S02 Emission Calculations and Cost Effectiveness for 

Baldwin Unit 3, 1982 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - 18 

Table 8b: S02 Emission Calculations and Cost Effectiveness for 

Baldwin Unit 1, 1985 .......................................... A - 19 

Table 8c: S02 Emission Calculations and Cost Effectiveness for 

Baldwin Unit 2, 1988 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - 20 

Table 8d: S02 Emission Calculations and Cost Effectiveness for 

Baldwin Unit 1 & 2, 2001 ....................................... A- 21 

Table 8e: S02 Emission Calculations and Cost Effectiveness for 

Baldwin Unit 3, 2001 .......................................... A - 22 

Table 9: General Information About Baldwin - Baldwin 

Unit 1 Design Data ............................................ A - 23 

Table 10: Cost Effectiveness of BACT Determinations for NOx •••••••••••••••• A - 26 

Table 11: BACT Cost Effectiveness for S02 Controls ........................ A - 27 

v 

018988
I. INTRODUCTION AND OVERVIEW 

A. Information Required for the Expert Report 

The following is a listing of the items required by the Federal Rules of Civil Procedures provided 

with this report: 

(1) This report contains my opinions, conclusions and the reasons therefor. 

(2) Exhibits and tables in summary of, or in support of, these opinions are included 

with this report in Appendix A. 

(3) The body of the report and Appendix B list the data and other information 

considered in forming these opinions. 

(4) Appendix C includes a listing of pUblications authored during the past ten years. 

(5) Section III presents a statement of my qualifications; my resume is attached as 

Appendix D. 

(6) I am being compensated for the preparation of this report and my testimony as a 

normal part of my compensation as an employee of the US EPA. 

(7) I have not provided previous testimony within the preceding four years as an 

expert at trial or by deposition. 

B. Purpose of Report 

This report is written pursuant to a request from the Department of Justice for an analysis of what 

controls should have been installed at the Baldwin Station when the Prevention of Significant 

Deterioration (PSD) regulations were triggered at each unit, as alleged in the United States' 

Amended Complaint. Under § 165 of the Clean Air Act ("C.A.A.") (42 U.S.C. § 7475), the 

permitting requirements triggered by the major modifications undertaken at the Baldwin Units 

would have included a requirement that Illinois Power Company (lPC) install the "Best 

Available Control Technology" (BACT). This report explains what BACT would 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 allegedly triggered. In addition, it is EPA's 

policy that a source that is in violation because it constructed or modified without a proper 

preconstruct ion permit must install controls that constitute BACT when the proper permit is 

finally issued . .!! Therefore, this report also makes a determination of BACT for all units as if 

.!! Office of Air Quality Planning and Standards, U.S. EPA, New Source Review Workshop 

Manual: Prevention of Significant Deterioration and Nonattainment Area Permitting (Draft Oct. 

1 

018989
permits were being issued as of the date this report is submitted. 

II. Summary of Conclusions 

In summary, and for the reasons described herein, I have concluded that the following emission 

rates and technologies would have been BACT for the pollutants at issue, and the Baldwin 

Station Units at issue, in the time frames specified below. 

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 of Low NO, control, based on use 

assuming coal with a 3- Burners. of (then existing) ESP 

3.5% sulfur content, Averaging time: A veraging time: 

and use of a 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 of selective use of a baghouse 

assuming coal with a 3- catalytic reduction Averaging time: 

3.5% sulfur content, Averaging time: 3 hour 

and use of a 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 

2 

018990
1988 (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 of selective use of a baghouse 

assuming coal with a 3- catalytic reduction A veraging time: 

3.5% sulfur content, Averaging time: 3 hour 

and use of a wet 3 hour Monitored via EPA 

limestone scrubber Monitored via CEMS method 5, opacity 

A veraging 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 of overfire air, use of a baghouse 

assuming use of coal selective catalytic A veraging time: 

with 0.6% sulfur reduction, and an 3 hour 

content optimization system Monitored via EPA 

Averaging time: Averaging time: method 5, triboelectric 

30 day rolling 3 hour broken bag monitors 

Monitored via CEMS Monitored via CEMS 

2002 (Unit 3} 0.095 pounds per 0.020 pounds per 0.015 pounds per 

million BTU, based on million BTU, based on million BTU, based on 

95% scrubbing, and use of low-NO, use ofa ESP. 

assuming use of coal 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 per million 

BTU if lower 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 of capacities at EPA's Region 9 for over 

twenty one years. I began work for EPA Region 9 in 1980 as a staff engineer in the New Source 

Section of what was then called the Enforcement Division. The primary function of this section 

~ See http://www.epa.gov/ttniemc/propperfips-ll&frnotice.pdf, proposed Performance 

Specification for Continuous PM Monitoring Systems. 

3 

018991
was to perfonn analyses, including control technology (i.e. BACT) analyses necessary for the 

issuance ofPSD pennits, and to oversee the issuance ofPSD and nonattainment NSR penn its by 

State and local agencies I conducted technical analyses on a variety of PSD sources, including 

powerplants, cement plants, and waste-to-energy plants. 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 Best Available Control Technology Guidance Document, which laid out a 

methodology for use primarily by pennit 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 of the New Source Section. I managed the 

Region's work in pennitting new and modified air pollution sources, as well as overseeing the 

pennit issuance work of our state and local agencies. In addition, my group had the responsibility 

for review and action on pennit rules submitted to EPA for inclusion in the State Implementation 

Plan, as well as reviews of state programs to detennine-after the fact-the efficacy of their 

pennitting programs, including their BACT reviews. In 2000, I began a one-year assignment as 

Associate Director of the Air Division. One of my responsibilities was managing the Region's 

response to the western energy shortage, a responsibility I continued when I became the Region's 

Senior Energy Advisor, the position I currently hold. One responsibility of my current position is 

to advise staff in the Pennits Office on decisions related to powerplants, including BACT 

decisions. 

I speak frequently on Clean Air Act issues. During the past ten years, I have spoken to groups 

such as the environmental section of the Arizona Bar Association, the annual environmental 

section conference of the California Bar Association, and numerous industry conferences, such as 

several sessions of the Summer Issues Seminar of the California Council for Environmental and 

Economic Balance, a company-wide conference of Granite Construction, the 2000 CADER 

Distributed Generation Conference, the 1999 Utility Environmental Conference, and others. 

Most of my talks were solely or primarily about New Source Review and the control technology 

requirement (BACT and LAER) under the NSR regulations. I have also created and presented 

New Source Review training courses for several audiences. In about 1991, staff under 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 by internal training of about 50 EPA Region 9 staff. 

Between about 1994 and 1997, I presented several short (several-hour) new source review 

training modules as part of a larger University of California extension course about the Clean Air 

Act. Most recently (March 2001), I was invited to present a paper to the second conference of the 

European Union nations on NOx and N20 control ("NOxCONF 2001 "). My paper was titled NOr 

Emissions Controls at Refineries: US Regulatory Drivers and Results. 

4 

018992
IV. What is BACT? 

When a new major source of air pollution is proposed to be constructed, or when 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 of the 

National Ambient Air Quality Standards for the pollutants at issue here, NSR regulations for 

attainment areas, known as the Prevention of Significant Deterioration ("PSD") regulations 

apply.§' State-of-the-art-emissions controls, known as Best Available Control Technology 

("BACT") are one of the key requirements of the PSD permit. 

BACT is defined as: 

"an emissions limitation (including a visible emission standard) based on the maximum 

degree of reduction 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 of production processes or available methods, systems, and techniques, 

including fuel cleaning or treatment or innovative fuel combustion techniques for control of 

such pollutant. In no event shall application of best available control technology result in 

emissions of any pollutant which would exceed the emissions allowed by any applicable 

standard under 40 CFR Parts 6()11 and 61. If the Administrator determines that technological 

or economic limitations on the application of measurement methodology to a particular 

emissions unit would make the imposition of an emissions standard infeasible, a design, 

equipment, work practice, operational standard, or combination thereof, may be prescribed 

instead to satisfy the requirement for the application of best available control technology. 

Such standard shall, to the degree possible, set forth the emissions reduction achievable by 

implementation of such design, equipment, work practice or operation, and shall provide for 

?i In this context, "state" may mean a state agency, or a local agency authorized under state law 

and federal regulations to carry out air pollution control functions. 

§' These regulations are codified at 40 C.F.R. § 52.21, and are incorporated into the Illinois PSD 

program. Definitions of the terms "major source," "major modification," and "significant" can 

be found in these regulations. 

?J 40 C.F.R. Part 60 is generally known as New Source Performance Standards. This section 

requires a minimum, uniform level of control technology for new or modified construction of 

categories of sources of air pollution, such as coal fired powerplants, petroleum refineries, pulp 

mills and the like. 

5 

018993
compliance by means which achieve equivalent results.flv 

In a typical BACT process, the applicant performs an analysis that is then submitted to a 

permitting authority, typically a state or local air pollution control agency. The applicant must 

submit information supporting its proposal, including information specific to its proposed plant, 

as well as information about other facilities and 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 by the 

permitting authority. After the close of the comment period, the permitting authority reviews all 

comments, modifies the proposed decision (where appropriate) based on its analysis of the 

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, by necessity, different from most in several 

respects. A typical BACT analysis is conducted before construction of a new source or 

modification has begun; because Illinois Power failed to obtain timely PSD permits prior to its 

construction of changes that triggered BACT, this analysis is being conducted after the 

modifications at the Baldwin powerplant have been completed. Also, my analysis is based largely 

on my own research, because Illinois Power has not, to date, submitted a BACT analysis to 

review.~ 

v. The Typical BACT Determination Process 

Over the years, EPA has issued policy guidance on the BACT process several times. Most 

notably, EPA published in 1980 the Prevention of Significant Deterioration Workshop Manual,l!l' 

§' 40 C.F.R. § 52.21(b){l2). 

~ In addition to my own research, I cite below to the work of Ellison Consultants, who have 

performed a review of the historical installation of technologies, and to the work of staff in 

EPA's Office of Air Quality Planning and Standards, who have performed a review of the costeffectiveness of certain technologies, at my request. 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 submitted by an applicant, or presented by another permitting 

authority. Just as in a traditional BACT analysis, I have utilized this data in reaching the BACT 

determinations described herein . 

.ill Leigh Hayes, et aI, TRW Incorporated, Prevention a/Significant Deterioration Workshop 

Manual (Oct. 1980) EPA 450/2-80-081. 

6 

018994
and in 1990 published the New Source Review Workshop Manual (draft),lY accompanied by the 

"Top-Down" Best Available Control Technology Guidance Document.11I Also, EPA's Region 9 

office published, in about 1987, its BACT Guidance DocumentP The following description 

reflects the process generally used 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 of reduced emissions that the technology would bring. The 

reviewing authority then specifies an emissions limitation for the source that reflects the 

maximum degree of reduction achievable for each pollutant regulated under the Act. In no event 

can a technology be selected which would not meet any applicable standard of performance 

under 40 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 of control 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 informed judgment agrees, that technical considerations, or 

energy, environmental, or economic impacts justify a conclusion that the most stringent 

technology is not "achievable" in that case. If the 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 air pollution control technologies 

or techniques with a practical potential for application to the emissions unit and the regulated 

pollutant under evaluation. Air pollution control technologies and techniques include the 

application of production process or available methods, systems, and techniques, including clean 

fuels, fuel cleaning or treatment or innovative fuel combustion techniques for control ofthe 

affected pollutant. This analysis includes a review of technologies employed both within and 

lY Office of Air Quality Planning and Standards, U.S. EPA, New Source Review Workshop 

Manual: Prevention of Significant Deterioration and Nonattainment Area Permitting (Draft Oct. 

1990). 

111 Office of Air Quality Planning and Standards, U.S. EPA, "Top-Down" Best Available 

Control Technology Guidance Document (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, Best Available Control Technology Guidance 

Document. 

7 

018995
outside of the 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 category in 

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 of the BACT analysis, one or more of the options may be eliminated from 

consideration because they are demonstrated to be technically infeasible or have 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 under review.!1! 

Next, the technical feasibility of the control options identified in step one is evaluated with 

respect to the source-specific (or emissions unit-specific) factors. Any demonstration of technical 

infeasibility must be clearly documented in the analysis to show, based on physical, chemical, or 

engineering principles, that technical difficulties would preclude the successful use of the 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 of control in a permit is not expected to be achieved in 

practice (e.g., a source has received a permit but the project was canceled, or every operating 

source at that permitted level has been physically unable to achieve compliance with the limit), 

and supporting documentation showing why such limits are not technically feasible is provided, 

the level of control (but not necessarily the technology) may be eliminated from further 

.!1' Office of Air Quality Planning and Standards, U.S. EPA, "Top-Down" Best Available 

Control Technology Guidance Document (Mar. 15, 1990), page B.11. "Also, technologies in 

application outside the United States to the extent the 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, or in a SIP, for that class or 

category of source (C.A.A. § 171). 

!§' Office of Air Quality Planning and Standards, U.S. EPA, "Top-Down" Best Available 

Control Technology Guidance Document (Mar. 15, 1990). 

)]j Ibid. 

lli Ibid. 

8 

018996
consideration. However, a permit from another facility requiring the application of a certain 

technology or emission limit to be achieved for such technology usually is sufficient justification 

to assume the technical feasibility of that technology or emission limit.r8 

All remaining control alternatives not eliminated above are listed in rank order of overall 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 of similar 

units) subject to a BACT analysis. The list should present the array of control technology 

alternatives and should include the following types of information:£!} 

• control efficiencies (percent pollutant removed, where appropriate); 

• expected emission rate (concentration or mass per unit production); 

• economic impacts (cost effectiveness); 

• environmental impacts (includes any significant or unusual other media impacts (e.g., 

water or solid waste), and, at a minimum, the impact of each control alternative on 

emissions of toxic or hazardous air contaminants); and 

• energy impacts (to the extent not already included in the economic impacts). 

After the identification of available and technically feasible control technology options, the 

energy, environmental, and economic impacts should be considered to arrive at the final level of 

control. For each 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 of the control alternative. Indirect 

impacts, such as the environmental impact from the generation of electricity needed 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 only for 

collateral environmental impacts.lli 

Economic impacts are considered in terms of dollars per ton of pollutant removed. This factor is 

r8 Ibid. 

£!} Ibid. 

lli Ibid. 

9 

018997
known as "cost effectiveness." Using this common unit of measurement facilitates a comparison 

of similar data across technology options. Other measures, such as dollars invested in control 

equipment compared to fraction of total capital investment, or dollars per unit of product, should 

not be used in BACT determinations. Cost effectiveness for the purpose of a 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 of pollutant removed, of all emissions 

removed compared to a baseline emissions level. That baseline is usually the legal limit that 

would exist but for the BACT determination. In many cases, that limit is equal to uncontrolled 

emissions, since no legal or practical limit may exist for a particular pollutant. Incremental cost 

effectiveness is defined as the cost, in dollars per ton of pollutant removed, of additional 

emissions removed compared to the next less effective control option. When comparing a 

particular calculated cost effectiveness with a potential cost benchmark, it is essential to ascertain 

whether the values are total or incremental cost effectiveness, as incremental cost effectiveness is 

always much larger than total cost effectiveness. EPA does not set a bright line for acceptable 

costs for BACT. The cost expectations for 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 of the BACT analysis is to ensure 

that a permit applicant may propose elimination of a control option if its costs for that option are 

disproportionately high compared to other sources using that control option, or the cost for that 

control alternative is significantly higher than the range of costs associated with BACT costs for 

that type of facility or BACT in general. 

If the applicant accepts the top alternative in the listing as BACT, the applicant proceeds to 

consider whether impacts of unregulated air pollutants or impacts in other media would justify 

selection of an alternative control option. If there are no outstanding issues regarding collateral 

environmental impacts, the analysis is ended and the results are proposed as BACT. In the event 

that the top candidate is shown to be inappropriate, due to energy, environmental, or economic 

impacts, the rationale for this finding should be documented by the 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 technology under 

consideration cannot be eliminated by any source-specific environmental, energy, or economic 

impacts which demonstrate that alternative to be inappropriate as BACT.~ 

~ Prior to the formalization ofthe "top-down"BACT process described above, the BACT 

process did not require that the applicant begin with an analysis of the most stringent technology 

option; however, the other key elements are very much the same. The process I describe has 

been formally in place since 1987, when EPA headquarters issued guidance ("Potter memo") for 

the improvement of the BACT determination process, after a series of evaluations of state and 

local permitting programs gave rise to concern at EPA that control technology (BACT) 

determinations defaulted too often to the minimum floor for emissions controls. After EPA 

headquarters issued its Potter memo, EPA's expectation was that permitting authorities would 

use that guidance in preparing their BACT determinations. My analysis for the 1988 and later 

timeframes largely conforms to the methodology of the Potter memo and later guidance. 

10 

018998
VI. Baldwin Station: Background 

Baldwin Station consists of three coal-fired steam electric generation units, each with a capacity 

of approximately 585 megawatts (MW). The Baldwin plant combusted local Illinois coal with a 

heating value of approximately 10,400 to 10,800 British Thermal Units (BTU) per pound, a 

sulfur content of approximately 3% by weight, and an ash content of approximately 10% to 11 % 

by weightnt until 1999, when the facility began use of Powder River Basin (PRB) coal with a 

heating value of 8600-8800 BTU/lb, a sulfur content of 0.25%, and an ash content of 4.6-4.8%.f1' 

Unit 1 began operation in 1970, and operates a cyclone fired boiler.£?! Unit 1 has a gross output 

of 584 megawatts (MW).l9' Its air pollution equipment includes of an electrostatic precipitator 

(ESP) initially designed to remove 99% of the particulate matter (PM) contained in the boiler 

exhaust gas. The ESP was upgraded inI999.£.Y The upgraded ESP was expected to remove 99.4% 

of particulate 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 of November 

However, the only substantive difference between the current (1987 and later) and earlier (1980) 

guidance is that the current guidance recommends that the top (i.e. most effective at controlling 

pollution) technology be listed first, and then rejected only if compelling reasons, consistent with 

the law, are found. In contrast, the earlier guidance recommend assessment of each control 

technology, and selection of the "best" technology based on the statutory criteria. My analysis in 

the 1982 and 1985 timeframes is consistent with the 1980 pUblication. While the processes laid 

out in the 1980 document and the 1987 Potter memo (and later guidance) were different, the 

results should have been the same. 

nt Department of Energy, Energy Information Administration (Form EIA-767) for 1985. 

f1' Department of Energy, Energy Information Administration (Form EIA-767) for 2000. 

£?! Ibid. 

19' Sargent & Lundy Engineers 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. 

11 

018999
2000, the SCR system does hot contain catalyst, and is not currently operating}..!! There are no 

S02 controls in place at Baldwin Unit I. 

Unit 2 also employs a cyclone fired boiler and has a gross capacity of 586 MW.BI Unit 2 began 

operation in 1 973.J)j The Unit 2 ESP was initially designed to remove 99% of the exhaust gas 

PM.J1' Although the ESP was modified in 1999 by adding additional collection fields,~ and 

installation of a flue gas conditioning system,2§' no information has been provided regarding the 

new removal efficiency or emission rate. With respect to NOx, an over-fire air system was 

installed in 1 999,1lJ as was an SCR system infrastructure. However, at least as of November 2000 

no catalyst was installed, and the SCR system is not currently operating.2.§' There are no S02 

controls in place at Baldwin Unit 2. 

Unit 3 is a tangentially fired unit with a gross output of 586 MW,J2! and began operation in 

1 975.5S1 Its air pollution controls include an ESP initially designed to remove 99.5% of exhaust 

gas PM.±!! Although the ESP was upgraded in 2000,1Y no information has been provided 

regarding the new performance level in terms of PM removal efficiency or emission rate. With 

l.!! Deposition testimony of Aric Diericx, November 10,2000. 

BI Ratings of Illinois Power Company Fossil Fuel Fired Generating Units; Report by Power 

Technologies, Inc. December, 1987 - IPPRO-00151120 

J)j Department of Energy, Energy Information Administration (Form EIA-767) for 1985. 

J1' Department of Energy, Energy Information Administration (Form EIA-767) for 1985. 

~ IP Permit Application dated November 25, 1998. IPPRO-0019250. 

2§' IP Permit Application dated December 20, 1999. IPPRO-0028865 

1lJ IP Permit Application dated September 8, 1999. IPPRO-0028775. 

l§' Deposition testimony of Aric Diericx, November 10, 2000. 

J2! Sargent & Lundy Engineers Engineering Data, Unit 3 Baldwin Power Station. IPPRO0085900. 

5S1 Department of Energy, Energy Information Administration (Form EIA-767) for 1985. 

±!! Ibid. 

1Y IP Permit Application dated November 25, 1998. IPPRO-0019250. 

12 

019000
respect 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 of 586 MW, and began operation in 1975.±Y 

It was designed to fire up to 294 tons per hour~ of coal with a heating value of 10,460 BTU per 

pound.~ 

1. Sulfur Dioxide 

As of 1982, Baldwin Unit 3 was uncontrolled for emissions of S02' and was burning coal with a 

sulfur content of 3%-3.5%.~ Actual emissions for the unit were about 85,000 tons per year 

(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 scrubbing buffered by Magnesium Oxide 

All wet scrubbing type sulfur removal controls employ absorption by passing the flue gasses 

iJ/ IP Permit Application dated January 19, 1993. IPPRO-0032541. 

±Y Ibid. 

~ Ibid. 

~ Sargent & Lundy Engineers Engineering Data, Unit 3 Baldwin Power Station. IPPRO0085900 

~ Department of Energy, Energy Information Administration (Form EIA-767) for 1985. 

~ See Expert Report of Ranajit (Ron) Sahu, April, 2002, compiling CEMS data submitted by 

Illinois Power Company to U.S. EPA. 

13 

019001
through an injected mist of reagent - generally limestone or lime.~ The reagent 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 slurry mist absorbs the sulfur and precipitates out 

of the injection chamber where it is de-watered and neutralized for landfill. In many cases, the 

by-product material is of sufficient quality it can be sold as wallboard-quality gypsum. The use of 

magnesium oxide as a buffering agent may increase the effectiveness of S02 removal. 

Both of the technologies under consideration were technically feasible and available, as both wet 

scrubbing technologies had been in widespread use by 1982. For example, in the U.S., at least 

eight other facilities were operating using wet limestone systems by the 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 of reasons, but by 1982 there were at least two Federal requirements for the use of 

scrubbers for S02 control. 

The first of these 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 of up to 90% of flue gas S02 

(depending on the sulfur content of the coal). NSPS is set at level that is technically feasible, and 

cost effective.2I 

The second requirement is the BACT requirement of the 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 

~ "Estimating Costs of Air Pollution Control," 1990, Vatavuk, W.M., Lewis Publishers, 

Chelsea, MI., pp. 194-199. 

~ See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

1Y See 40 C.F.R. § 60.40a (1979), "Standards of Performance 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, BACT was defined to be equal to NSPS, where an NSPS existed. The 1978 

regulation conformed the regulations to the new statutory language, and provided that the permit 

applications that were "complete" prior to the new regulation would be processed under the old 

regulations. 

i1' See Appendix A, Table 5: RACTIBACTILAER summary: 1982 timeframe. 

14 

019002
example, Nevada Power's Harry Allen Station was issued a permit in early 1981 with a 95% 

removal requirement and an emission rate of 0.1 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 of 0.13 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 of a 

scrubber removing 95% of the stack gas.TIt 

Taken together, it is clear that by 1982, scrubbing technologies to remove S02 were required of 

many powerplants and in place at many others. Both wet limestone scrubbers and wet lime 

scrubbers with magnesium buffering had been used and had demonstrated removal efficiencies of 

up to 95%. These two wet scrubbing technologies, with efficiencies of up to 95%, were therefore 

both technologically feasible and well demonstrated in practice. 

b. Cost Analysis 

Both of the 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 of removing 95% of flue gas S02 were analyzed based on a study 

conducted by Illinois Power in 1991 to install flue gas desulfurization systems on Unit l.~ Most 

of the methodology used 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 on whether waste from the 

?2i Ibid. 

i9' Ibid. 

TIt See report of William Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations", developed in connection with United States v. Illinois 

Power and Dynegy Midwest Generation, Inc. 

~ Babcock and Wilcox, Contract Research Division and Environmental Equipment Division, 

Volumes I-IV of Proposal for Full-Scale Demonstration of Integrated Flue Gas Desulfurization 

System with Rebuming NOx Control, B&W Proposal #90-071 (May 1991). IPPRO-0128923-

0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-0127567-0127848. 

221 See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

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. The cost data adjustment 

was based on information found at website address http://www.enr.com/cost/costcci.asp. 

15 

019003
scrubber system would have been sold. When these costs are converted to annualized costs~, the 

annual cost would have been between $22.0 and 23.4 million.Q.!J Based on 95% control of S02 

emissions, a wet limestone scrubber system installed on Baldwin's Unit 3 would remove 106,600 

tons per year of S02. Its cost effectiveness in 1982 would have been approximately $220Iton.@ 

The wet lime scrubber with magnesium buffering would have had both higher capital and 

operating costs than the wet limestone scrubber.~ Therefore, unless the wet limestone scrubber 

were to be rejected on other grounds (such as lesser other environmental impacts), it would no 

longer need to be considered. 

In order to ensure that the costs estimated for the scrubber are not excessive, I reviewed other 

BACT determinations and EPA policy documents.M' I reviewed the cost effectiveness of 

eighteen powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. 

Of those where a dollar per ton 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 cleaner burning 

~ Annualizing a cost is method to determine the annual equivalent value of the 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. 

@ See Table 8a: S02 Emission Calculations and Cost Effectiveness for Baldwin Unit 3, 1982. 

~ See report of Dan Mussatti and Larry Sorrels, Estimated Costs for the Installation of S02' NOx 

and PM Control Devices at Illinois Power's Baldwin Station, developed in connection with 

United States v. Illinois Power and Dynegy Midwest Generation, Inc. 

M' Specifically, as part of the economic analysis here and throughout the report, I compared the 

cost effectiveness of available control options to a variety of other benchmarks. This comparison 

assisted in determining whether a particular scenario's cost effectiveness should be deemed 

unreasonable. For example, to the extent available, I looked at contemporaneously issued PSD 

permits, as well as PSD permits issued later. In addition, I considered more generalized data 

applicable to source types or regulatory schemes that are expected to use a lower cost 

effectiveness. For example, 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 usually known as Reasonably Available Control 

Technology (RACT). RACT level emissions controls· are considered to be a less stringent control 

technology requirement than BACT, and therefore are less expensive. Therefore, the use of 

RACT level controls should yield a conservative (i.e. lower cost) measure against which to 

compare potential BACT options. 

@ See Table 11, Cost Effectiveness of BACT Determinations for S02. 

16 

019004
gasoline.~ That guidance used $1 O,OOO/ton as an upper bound for BACT cost effectiveness. 

When that value is converted to 1982 dollars it becomes $6,148/ton. The estimated costs for wet 

limestone scrubbing at Baldwin Unit 3 in 1982 is at the low end of the range of these 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 of scrubbers. 

d. Conclusion 

Based on the above data, I conclude that BACT at Baldwin Unit 3 in 1982 would have been an 

emission rate of 0.3 pound/million BTUP 30 day rolling average, based on the use of a wet 

limestone scrubber removing 95% of the S02 from coal having a sulfur content of 3-3.5%. 

Compliance with the limit would have been monitored by use of a Continuous Emissions 

Monitoring System (CEMS).~ 

2. Nitrogen Oxides 

In 1982, Unit 3, based limited data available, had uncontrolled NOx emission rates that 

appear to 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 ("OF A") 

~ See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding 

BACT and LAER for Emissions of Nitrogen 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 Irgytgmj/programsl artd/ air/nsr/nsrmemos/t2bact. pdf 

§]j The limit of 0.3 pounds per million BTU is derived from 95% removal of coal 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 of CEMS Data for the Baldwin Station, submitted by Illinois Power 

Company to U.S. EPA. 

17 

019005
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 of the 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 of Low-NOx burners for use on many types of boilers (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 burner manufacturer 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-Nevada Power's Harry Allen Station, and Tucson Electric Power's (TEP) Springerville 

Unit 3.Z1' Units 1 and 2 at TEP's Springerville, pennitted in 1978, have achieved levels of 

approximately 0.4 pounds per million BTU.TII All of the foregoing powerplants were designed as 

tangentially fired boilers. 

:ill' Babcock & Wilcox, Steam/its generation and use (39th ed. 1978). 

l!i See report of William Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations," developed in connection with United States v. Illinois 

Power and Dynegy Midwest Generation, Inc. 

2.?1 See report of William Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations," developed in connection with United States v. Illinois 

Power and Dynegy Midwest Generation, Inc. 

D! Conversion from parts per million to pounds per million BTU based on Emissions standards 

handbook: air pollutant standards for coal-fired power plants, Appendix, Hennine N. Soud, 

IEA Coal Research, December 1991. 

Z1' See Appendix A, Table 1. 

TIl See U.S. EPA, Clean Air Markets 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 same burners since the boilers were built. 

18 

019006
The relevant NSPS requirement was an emission rate of 0.6 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§' or were 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%) of the 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 by two mechanisms: (1) 

thermal NOx formation is delayed and suppressed because of the lower flame temperature and 

extended combustion zone, and (2) fuel NOx formation is suppressed because of the 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 

OF A. However, OF A installations in the 1892 time frame in tangentially fired boilers appear to 

be an integral part ofLNB designs, and also appear designed to meet a limit of 0.7 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 of the ammonia with the NOx to form nitrogen and water, therefore the catalyst can be 

placed in a lower temperature zone of the 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 of William Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations," developed in connection with United States v. Illinois 

Power and Dynegy Midwest Generation, Inc. 

lZ' See Appendix A, Table 1. 

~ See U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, 

"Alternative Control Technologies Document NOx Emissions from Utility Boilers" March 1994. 

This information can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. 

7JJ See report of William Ellison, PE, Ellison Consultants, "Table 5, Pre-1983, TangentiallyFired, Low NOx Burner Installations," developed in connection with United States v. Illinois 

Power and Dynegy Midwest Generation, Inc. 

19 

019007
after 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 smaller than Baldwin Unit 3, at almost 600 MW. In addition, in 1982, there were 

roughly two years of world-wide experience with SCR systems. To be most conservative in this 

retrospective analysis, I would conclude that the uncertainty associated with the newness of the 

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 air heater into the 

furnace for NOx control using ductwork and an additional fan. The method was originally 

developed for controlling superheater and reheater steam temperatures. NOx is reduced by 

lowering the temperature in combustion zone and therefore suppressing NOx fonnation. 

By 1982, flue gas recirculation was in use at a large number of combustion processes.nr All of 

these installations appear to be designed to meet an emissions limit of 0.7 poundsIMMBTU.§1 

However, little data are available suggesting use and effectiveness ofFGR for NOx control at 

coal fired boilers. For that reason, I have excluded FGR from further analysis as a BACT option. 

b. Cost Analysis 

This section presents costs for the installation ofLNBs at Baldwin Unit 3.'§2j A state-of-the-art 

ffi' See U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, 

"Alternative Control Technologies Document NOx Emissions from Utility Boilers" March 1994. 

This infonnation can be found at website address: http://www.epa.gov/ttn/catc/dirl/utboiler.pdf. 

~ See report of William Ellison, PE, Ellison Consultants, "Table 2, SCR Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest 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 of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

~ Ibid. 

'§2j OF A 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. 

20 

019008
LNB in 1982 would have been capable of reducing emissions to less than 0.4 pound/million 

BTU. The annualized cost of a LNB would have been $3.19 million, yielding a cost effectiveness 

of$589/ ton of NO x reduced.~ 

These costs compare favorably to relevant, historical, PSD permits and cost analyses performed 

for air quality planning needs. For example, the New Jersey Department of Environmental 

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 violating the NAAQS apply to a broad range of 

source categories, and are almost always retrofit measures. Consequently, the costs of these 

measures are generally less than BACT costs. The Los Angeles area, which is part of the 

jurisdiction of the SCAQMD, was the only area in the country not attaining the NAAQS for 

N02. The plan shows a number of control measures, some of which would be implemented 

immediately, and some over time. For rules 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 cleaner burning gasoline.29' That guidance used $1 O,OOO/ton as an upper 

bound for BACT cost effectiveness. When that value is converted to 1982 dollars it becomes 

$6,148/ton. 

The average cost per ton for NO, reductions at Baldwin Unit 3 in 1982 using LNBs is 

substantially lower than the acceptable high end for costs used by NJDEP and EPA in the two 

~ See report of Dan 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. 

B' See Keystone Cogeneration Facility BACT 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 Quality Management 

District and Southern California Association of Governments, October 1982. 

29' See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding 

BACT and LAER for Emissions of Nitrogen 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 

21 

019009
examples above, and similar to or less than the costs for most of the control measures in the 

SCAQMD plan. Therefore, the costs for LNBs at Baldwin Unit 3 in 1982 are not unreasonable. 

c. Other Environmental Impacts 

No significant environmental impacts would have occurred as a result of using LNBs. 

d. Conclusion 

In summary, I conclude that an emission rate of 0.40 pounds per million BTU (three hour 

average) based on the use ofLNBs was BACT for NOx at Baldwin #3 in 1982. Compliance with 

the limit would be monitored by use of a Continuous Emissions Monitoring System (CEMS). 

3. Particulate Matter 

As of 1982, Baldwin Unit 3 was equipped with an electrostatic precipitator. Data reported by 

Illinois Power show that it was achieving a removal efficiency of about 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. It was 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.)'!li Baghouses were therefore also technically feasible and available. 

The removal efficiency that Baldwin Unit 3 was achieving in 1982 compares favorably with the 

2.!! Department of Energy, Energy Information Administration (Form EIA-767) for 1982. 

IPPRO-0104439-0104464. 

2Y See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

'!li See Table 7 for derivation of control level. 

22 

019010
baghouses in 1982, and achieving limits as low as .005 grl ACF.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 emission rate 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 baghouse would be required to meet the removal rate, it also allowed the 

applicant to use an ESP if data were submitted demonstrating that the ESP was likely to be able 

to achieve that rate. Baldwin Unit 3's ESP was controlling emissions to about 99.4% in 

1982.~ If Illinois Power had been required to add controls (likely to be an additional baghouse or 

another field in its ESP) to control its emissions to the then state of the 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 

of 0.036 pounds per million BTU, based on 99.4% removal and the emissions controls already in 

place at Baldwin Unit 3 in 1982. Compliance would have been monitored using EPA method 5 

and an opacity monitor. 

B. BACT Determination For Baldwin Unit 1: 1985 

Unit I is a cyclone fired boiler with a gross output rating of 584 megawatts (MW)29' and began 

operation in 1970.'l1I It is designed to fire 267 tons per hour of coal~ with a heating value of 

2Y See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

211 See Table 7 for derivation of control level. 

~ See EPA permit for Harry Allen Station, NV-77-01 and associated National Ambient Air 

Quality Impact Report. 

~ Department of Energy, Energy Information Administration, (Form EIA-767) for year 1982. 

29' Sargent & Lundy Engineers Engineering Data, Unit 1 Baldwin Power Station. IPPRO0085676-744. 

'l1I Ibid. 

~ Department of Energy, Energy Information Administration, (Form EIA-767) for year 1985. 

23 

019011
I 985.®' 

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 of these scrubbers were 

wet limestone or wet lime buffered with magnesium oxide . .!QY·lQ!I These two types of scrubbers 

were technically feasible in 1985. 

b. Cost Analysis 

The cost in 1985 of scrubbers capable of removing 95% of flue gas S02 was analyzed based on a 

study conducted by Illinois Power in 1991 to install flue gas desulfurization systems on Unit I . .!§! 

Most of the methodology used 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 been between $23.5 and 25.0 

million. Analysis of wet lime scrubber buffed with magnesium oxide shows it to be more 

.®' See Expert Report ofRanajit (Ron) Sahu, April 2002, compiling CEMS data submitted by 

Illinois Power Company to U.S. EPA. 

.!QY See report of William Ellison, PE, Ellison Consultants, "Table 2, SCR Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, 

Inc . 

.!.Q2{ See "Table 30: Flue Gas Desulfurization (FGD) Capacity in Operation at U.S. Electric Utility 

Plants as of December 1999." This information can be found at website address: 

http://www.eia.doe.gov/cneafielectricity/epav2lhtml_ tables/epav2t30p l.html and following 

pages 

.!§! Babcock and Wilcox, Contract Research Division and Environmental Equipment Division, 

Volumes I-IV of Proposal for Full-Scale Demonstration of Integrated Flue Gas Desulfurization 

System with Rebuming NOx Control, B&W Proposal #90-071 (May 1991), IPPRO-0128923-

0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-0127567-0127848. 

~ See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

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. 

24 

019012
expensive for the same level of control as the wet limestone scrubber, therefore only the wet 

limestone option received further consideration . .ill2 The wet limestone scrubber would remove 

96,800 tons per year of S02. Therefore, the cost effectiveness of a 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 policy documents. I reviewed the cost effectiveness of eighteen 

powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. Of those 

where a dollar per ton 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 cleaner burning gasoline . .!.QJY That 

guidance used $10,000Iton as an upper bound 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 of the range of these permits and EPA guidance. The 

cost is therefore not unreasonable. 

c. Other Environmental Impacts 

Wet scrubbers produce a sludge that may have economic use. If not 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 of scrubbers. 

d. Conclusion 

Based on the above data, I conclude that BACT for S02 at Baldwin Unit 1 in 1985 would have 

been an emission rate of 0.30 pound/million BTU,.!Q2r 30 day rolling average, based on the use of 

a wet limestone scrubber removing 95% of the S02 from coal having a sulfur content of 3-3.5%. 

Compliance with the limit would have been monitored by use of a 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 of BACT Determinations for S02 . 

.!.QJY See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding 

BACT and LAER for Emissions of Nitrogen Oxides and Volatile Organic Compounds at Tier 

2/Gasoline Refinery Projects, dated January 19,2001. This information can be found at website 

address: http://www.epa.gov/rgytgrnj/programs/artd/air/nsr/nsrmemos/t2bact.pdf 

.!Q2r See Table 8b for calculations. 

!!!¥ See 40 C.F.R Part 60, Appendix B, Performance Specification 2. 

25 

019013
2. Nitrogen Oxides 

As of 1985, Baldwin Unit 1 had no controls in place 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 of 0.6 pound/million BTU for coal fired powerplants 

burning bituminous coal, which is the coal that Illinois Power was burning in 1985. 

a. Technical Feasibility 

For Unit 1, in 1985, I considered the feasibility of LNBs, OF A, SCR and SNCR. LNBs were not 

technically feasible because they simply have not been developed for use on cyclone fired 

boilers. As to OF A, from the vantage point of 200 1, for cyclone fired boilers, OF A would appear 

to have been technically feasible, but no installations on cyclone boilers appear to have been in 

place by 1985.ill Therefore, in my judgement, given the technical difficulty of engineering an 

overfire air system for a cyclone fired boiler, I would consider that technology also to be 

unavailable for use on Unit 1 in 1985. 

However, in contrast to 1982, by 1985, SCR had been used for coal fired boilers for at least five 

years. For example, by 1985, at least three Japanese facilities (i.e., Shiminoseki, Shin Ube and 

Tomatoatsuma) had operated five years.ill! In addition, at least sixteen SCR systems on coal fired 

powerplant boilers in Japan were in operation or under construction by this time, including both 

new and retrofit facilities. These powerplant boilers ranged in size from 125 to 700 megawatts in 

size.ill Planned reduction rates are not available for all of these facilities, but for a subset in 

operation by 1984, reduction ranged from 57 to 81 %.ill' Operational problems experienced in the 

!.!.!i Department of Energy, Energy Information Administration (Form EIA-767) for 1985. 

ill' See Expert Report of Ranajit (Ron) Sahu, April, 2002, compiling CEMS data submitted by 

Illinois Power Company to U.S. EPA. 

ill See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. No instance of OF A were located 

in the relevant timeframe. 

ill! See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

ill See Ando, Jumpei, "SOl and NOx Removal For Coal-Fired Boilers in Japan," presented to 

the Seventh Symposium on Flue Gas Desulfurization, May, 1982. 

ill' See U.S. EPA, Air and Energy Engineering Research Laboratory, Office of Environmental 

Engineering and Technology, "Recent Developments in S02 and NO, Abatement Technology," 

September 1985. 

26 

019014
early stages of SCR development had been solved by this 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 of SCR, 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 of ammonia 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 per million (ppm) compared to as little as 1 ppm for SCR systems.ill! Beginning in about 

1985, many coal fired powerplants were pennitted using SNCR.ill! However, none of these were 

cyclone fired boilers.M Therefore, I would conclude that SNCR was not available in 1985 for 

ill Ibid, page 5-2. 

~ See report of William 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 of SCR on a large gas turbine. In July 1984, Mr. Pease prepared a report for the 

AQMD about its operation, and shortly thereafter began to require combined gas turbines to meet 

a 9 ppm NOx limit. 

1N' LAER is generally the most effective emission limit that has been achieved for a source 

category. Consequently, the LAER emission rate, and the technology on which it is based, would 

generally be the most effective emission control option in a BACT analysis, and must be 

considered. 

Q!/ See U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, 

"Alternative Control Technologies Document NOx 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 of Air and Radiation, Office of Air Quality Planning and Standards, 

"Alternative Control Technologies Document NOx 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 of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. See also U.S. EPA, Office of Air 

27 

019015
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 of SCR as the boiler undergoes changes in load. Current day control systems are 

able to react and adjust operation of the SCR to maintain a given level of control; systems in the 

mid '80s were less capable. In order to account for this lesser level of effectiveness of the 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 of 0.90 pounds per 

million BTU. 

b. Cost Analysis 

The estimated cost of an SCR system at Baldwin Unit 1 in 1985 was based on Illinois Power's 

study for installation SCR at Units 1 and 2.ill! Since that study was conducted in 1990, the costs 

were adjusted to reflect 1985 dollars. The capital cost of SCR in 1985 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 

likely to be conservative. For example, the 1990 study was for an installation that would remove 

and Radiation, Office of Air Quality Planning and Standards, "Alternative Control Technologies 

Document NOx Emissions from Utility Boilers" March 1994, page 49. This information can be 

found at website address: http://www.epa.gov/ttn/catc/dirllutboiler.pdf. 

ill! See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

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. 

illY Ibid. 

ill' See Table 3b for calculations. 

@ This cost estimate assumes that the catalyst would be replaced every three years. That 

assumption may be very conservative. At least one early SCR installation, at Knepper Unit C in 

Germany, went into service in 1986, and, as of 1998, was operating with 56% of its original 

catalyst. Another plant, Velthiem, began operation in 1989, and as of 1998, was operating with 

all of its original catalyst, together with an additional amount of catalyst added after two to three 

years of operation. See "Development and Commercial Operating Experience of SCR deNOx 

Catalysts for Wet-Bottom Coal-Fired Boilers," Isato Morita et aI, Presented to Power-Gen 

International '98, December 1998. This document may be found at website address 

http://www.babcock.com/pgglttlpdfIBR -1665. pdf. 

28 

019016
85% of NO x from the exhaust stream. In contrast, a 55% reduction of NO x 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 initially be used, less 

catalyst would need to be periodically replaced. In spite of these 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 of the same relevant benchmarks mentioned above. For 

example, the New Jersey Department of Environmental Protection issued permits in 1990 and 

1991 that were based on a cost effectiveness of $13,200/ton. When converted to1985 dollars, the 

New Jersey permits 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 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 of the jurisdiction of the SCAQMD, was the only area in the country not 

attaining the NAAQS for N02. The plan shows a number of control measures, some of which 

would be implemented immediately, and some over time. For rules 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 cleaner burning gasoline.ill That guidance used 

$10,000Iton as an upper bound for BACT cost effectiveness. When that value is converted 

to 1985 dollars it becomes $6,620Iton. 

The average cost per ton for NOx reductions using SCR at Baldwin Unit 1 in 1985 is 

substantially lower than the acceptable high end for costs used by NJDEP and EPA in the two 

examples above, and similar to or less than the costs for most of the control measures in the 

SCAQMD plan. Therefore, the costs for LNBs at Baldwin Unit 1 in 1985 are not unreasonable. 

c. Other Environmental Impacts 

ill! See http://www.enr.com/cost/costcci/asp for cost adjustments . 

.IN' Final Air Quality Management Plan, 1982 Revision, South Coast Air Quality Management 

District and Southern California Association of Governments, October 1982. 

ill See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding 

BACT and LAER for Emissions of Nitrogen 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 

29 

019017
SCR and SNCR use ammonia, which could cause environmental effects if emitted 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 of the higher ammonia slip rate for 

SNCR, SCR would usually be preferred because of its lower other environmental impacts. 

d. Conclusion 

I conclude that an emission rate of 0.90 pound/million BTU (3 hour average) based on the use of 

SCR was BACT for Baldwin Unit 1 in 1985. Compliance with the limit would have been 

monitored by use of a Continuous Emissions Monitoring System (CEMS).ill' 

3. Particulate Matter 

In 1985, Baldwin Unit 1 was operating with an ESP to control particulate emissions. Based on 

Illinois Power's reported efficiency, which started at 96% in 1982 and decreased over time to 

90% in 1985,ill! it appears that the ESP was in need of significant maintenance or repair. Illinois 

Power also performed periodic tests of the 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 

after that date, showing that emissions were highly variable, I conclude that emissions could have 

been as high as 879 pounds per hour in 1985. 

a. Technical Feasibility 

In order to reduce emissions further, one of the following actions would need to be taken at 

Baldwin Unit 1: 

- Replacement of current ESP with new ESP or baghouse, 

- Upgrade of ESP. 

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 of Stack 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. 

30 

019018
For this analysis, I have assessed only the option of replacing 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! They concluded that a replacement ESP would be more cost effective than an upgrade 

of the existing ESP. Illinois Power did not analyze the cost of replacing the ESP with a baghouse. 

Among the conclusions of that study was that the existing ESP was in "poor condition," and that 

a "major upgrade and refurbishment of the existing ESP will be required in order to obtain 

another 30 years of service."11§' Since this study was conducted only about five years after 1985, 

I believe its conclusions would generally have applied in 1985, i.e., that the existing ESP was 

near the end of its 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 of PM less than 0.01 grainlACF (actual cubic foot).ill! Of 

those 29, many were designed to achieve levels of between 0.001 and 0.005 gr/ACF.ill' This 

level is approximately equal to a 98.3 to 99.6% reduction of uncontrolled 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 efficiency of approximately 

99.4 % (see 1982 analysis, above). This alone demonstrates the technical feasibility of an ESP at 

Baldwin at that removal efficiency. 

a. Cost Analysis 

ill! See Bums and McDonnell report, "Baldwin Unit 1 Electrostatic Precipitator Study" (1991). 

IPPRO-0058084 through IPPRO-0058136. 

11§' Ibid., page 11-1. IPPRO-0058092. 

ill! See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

ill' See report of William 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. 

31 

019019
Based on a design to remove 99.6% of particulate matter (based on the capability of a 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 $1 05 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 of emissions reduction, that is the option 

that I considered for further analysis. The total cost effectiveness of the 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 of other contemporaneous sources. 

For example, 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% of PM. Tampa Electric's Big Bend 

Unit 4 (445 MW), built in 1985, reported a capital cost of$76.8 million for its ESP removing 

99.7% of PM. Paradise Unit 1 (704 MW), built in 1983, reported a capital cost of$210 million 

for its ESP removing 99.9% of PM. The estimated costs for a baghouse at Baldwin Unit 1 in 

1985 are within the range of costs for similar facilities at that time, and are therefore not 

unreasonable.ill! 

b. Other Environmental Impacts 

No significant environmental impacts would occur from the use of a baghouse. Collected ash 

from the baghouse would need to be disposed of, but is not considered hazardous waste. 

c. Conclusion 

I have determined that BACT for particulate matter for Unit 1 in 1985 would have been an 

emission limit of 0.003 pound/million BTU and the use ofa baghouse and 99.6% removal.ill' 

Compliance would have been monitored using EPA method 5 and an opacity CEMS. 

li!t See report of Dan 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. 

ill' Ibid. 

ill! Department of Energy, Energy Information Administration (Form EIA-767) for 2000. 

~ See Table 4b for calculations. 

32 

019020
C. BACT Determination for Baldwin Unit 2: 1988 

Unit 2 is a a cyclone fired boiler and has a gross capacity of 587 MW.ill! Unit 2 began operation 

in 1973 . .!§ It was designed to fire up to 267 tons per hour.!£! of coal 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 of SOl' and was burning coal with a 

sulfur content of 3%.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, many new facilities had come on 

line by 1988 utilizing scrubbers to remove S02. Over 148 coal fired powerplants with scrubbers 

were in operation in the U.S. by the end of1988. Most of these scrubbers were operating at a 

removal efficiency of80 to 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 of 97% of 

S02.ill Since there was only one powerplant operating at 97%, I continued to analyze scrubber 

ill! Ratings of Illinois Power Company Fossil Fuel Fired Generating Units; Report by Power 

Technologies, Inc. December, 1987. IPPRO-00151120 

.!§ Department of Energy, Energy Information Administration (Form EIA-767) for 1985 . 

.!£! Ibid . 

.!.i§t Sargent & Lundy Engineers Engineering Data, Unit 3 Baldwin Power Station. IPPRO0085900 

illt Department of Energy, Energy Information Administration (Form EIA-767) for 1988. 

lli' See "Table 30: Flue Gas Desulfurization (FGD) Capacity in Operation at U.S. Electric Utility 

Plants as of December 1999." This information can be found at website address: 

http://www .eia.doe.gov/cneaf/electricity/epav2lhtml_tables/epav2t30p l.html and following 

pages 

ill See report of William Ellison, PE, Ellison Consultants, "Table 1, FGD Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, 

Inc. 

33 

019021
options based on 95% control. 

By 1988, scrubber technologies were mature. Both scrubbers previously analyzed (i.e. wet 

limestone and wet lime buffered by magnesium oxide) had been well demonstrated. 

b. Cost Analysis 

Capital and operating costs for wet limestone and wet lime with magnesium buffering were 

analyzed for the 1985 scenario. That analysis (see analysis for Unit 1, 1985) showed that wet 

limestone scrubbing was the less expensive option. The least cost option continues to be wet 

limestone scrubbing in 1988. Capital costs for the limestone system would 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 or not. When these 

costs are converted to annualized costs, the annual cost would be approximately $27.1 million. 

The scrubber system would remove approximately 96,800 tons per year of S02. Therefore, the 

cost effectiveness the limestone FGD system would have been approximately $280/ton.illI 

As with the analysis of scrubbers in 1985, this cost compares very favorably to the cost 

effectiveness of eighteen powerplants permitted between 1979 and 1999 with BACT 

requirements for scrubbers. Of those where a dollar per ton cost effectiveness was listed, the 

range (once converted to 1988 dollars) is $167 to 5092/ton.ill! As also noted above, EPA's 2001 

guidance related to presumptive BACT for NOx at refineries cited $10,000/ton as an upper bound 

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 of these permits and EPA guidance. The cost is therefore not unreasonable. 

c. Other Environmental Impacts 

Wet scrubbers produce a sludge that may have economic use. If not 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 of scrubbers. 

d. Conclusion 

Based on the above data, I conclude that BACT at Baldwin Unit 2 in 1988 would have been an 

illI See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

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.; cost data adjusted based 

on http://www.enr.com/cost/costcci.asp. 

ill! See Table 11, Cost Effectiveness of BACT Determinations for S02. 

34 

019022
emission rate of 0.30 pound/million BTU,ll1' 30 day rolling average, based on the use of a wet 

limestone scrubber removing 95% of the S02 from coal having a sulfur content of3-3.5%. 

Compliance with the limit would have been monitored by use of a 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. Of these 

options, LNBs were not technically feasible in 1988, because they have not today been developed 

for cyclone fired boilers. OF A was also not technically feasible by 1988. While OF A had been 

used on other types of coal combustion, it had not been used on cyclone fired boilers.ill SNCR 

had been demonstrated by 1988 on a number of facilities overseas firing high sulfur coal, as well 

as many fluidized bed coal fired boilers permitted and under construction in the U.S. using low 

sulfur coal. By 1988, at least seven coal fired power plants in the U.S. were required to use 

SNCR to control NOJ~§' Emissions reductions of approximately 50% were expected at these 

facilities, and the permits included emissions limits in the range of 0.09-0.15 pounds/million 

BTU.ill!·~ 

With respect to SCR, by 1988, significant additional experience had been gained worldwide in 

the application of this technology to coal fired boilers. SCR had been installed on at least two 

lli' See Table 8c for calculations . 

.illJ See 40 C.F.R Part 60, Appendix B, Performance Specification 2. 

J19' Department of Energy, Energy Information Administration (Form EIA-767) for 1988. 

ill' See report of William Ellison, PE, Ellison Consultants, "Table 1, FGD Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, 

Inc . 

.ill' See PSD permit #s SE 85-01, 85-05, SJ 85-06, SJ 85-07, SJ SE 86-04, SJ 86-08, 86-09. 

ill! Ibid. 

~ See Kern County Air Pollution Control District, Engineering Analysis of Mt.PosolPyropower 

Cogeneration Facility, November 1986, page 67. " ... an emission rate of 0.092 pound 

NOJMMBTU satisfies NOx LAER requirement." 

35 

019023
cyclone, (or "wet bottom") boilers, as well as many other coal fired powerplants.ill By 1988, 

twenty-five coal fired boilers in Japan, six in Gennany and two in Austria had begun 

commercial operation of SCR systems for NOx control..!EI These installations were across a 

wide range of boiler 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 of these Gennan facilities had SCR with design NOx reduction levels of 

approximately 80% or greater,.!.@ I have detennined that level of reduction was technically 

feasible in 1988. 

b. Cost Analysis 

SCR was the top, or most effective, option for available in 1988. Unless it were to be rejected on 

the grounds of unacceptable environmental or economic cost, SCR would be chosen as BACT. 

As in the 1985 analysis above, the cost for SCR was estimated using Illinois Power's studyW for 

installing SCR on units 1 and 2 in 1990. The costs were then adjusted to 1988 values.ill' These 

adjustments yield an annualized cost of$22.6 million. SCR would reduce Unit 1 emissions by 

about 23,604 tons/year, based on a 1.8 pound NO/MMBTU inlet concentration and a 66.7 

ill Ibid . 

.!EI See ENSR Consulting and Engineering, "Keystone Cogeneration Facility BACT for Nitrogen 

Oxides, Addendum," June 1990. 

ill! See report of William Ellison, PE, Ellison Consultants, "Table 2, SCR Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, 

Inc. 

lli'Ibid . 

.!.@ See report of William Ellison, PE, Ellison Consultants, "Table 2, SCR Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, 

Inc. 

W See SCR Cost Evaluation for Illinois Power, Baldwin Units 1 & 2, May 17, 1990. Prepared 

by Bums & McDonnell, Kansas City, MO. 

ill' See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

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. 

36 

019024
percent capacity factor, and an SCR system that removes 80% of the inlet NOJ@ The annualized 

cost of an 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 planning purposes. As noted above, the New Jersey 

Department of Environmental Protection issued permits in 1990 and 1991 that were based on a 

cost effectiveness of $ 13,200/ton. When converted to 1988 dollars, the New Jersey permits 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. For rules 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 cleaner burning gasoline . .!2Y That guidance used $1 O,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 of the range 

of these permits and EPA guidance. The cost is therefore not unreasonable. 

c. Other Environmental Impacts 

SCR and SNCR use ammonia, which could cause environmental effects if emitted 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 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 of its lower other environmental impacts. 

d. Conclusion 

Based on the analysis above, I conclude that an emission limit of 0.36 poundslMMBTU, 3 hour 

average based on the use of SCR with 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 Quality Management Plan, 1982 Revision, South Coast Air Quality Management 

District and Southern California Association of Governments, October 1982 . 

.!2Y See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding 

BACT and LAER for Emissions of Nitrogen 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/artdlair/nsr/nsrmemos/t2bact.pdf 

37 

019025
with the limit would have been monitored with a CEMS. 

3. Particulate Matter 

As of 1988, Baldwin Unit 2 was operating with an ESP that had demonstrated efficiencies 

ranging from 93 to 97%, with an apparent downward trend in efficiency . .ill' 

In order to reduce emissions further, one of the following actions would need to be taken at 

Baldwin Unit 2: 

- Replacement of current ESP with new ESP or baghouse, 

- Upgrade of ESP. 

a. Technical feasibility 

For this analysis, I have again assessed only the option of replacing 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 lower removal efficiencies,ill! suggesting 

that the unit would need significant repair or upgrade. As noted above, Illinois Power's study of 

PM controls for Unit 1, which is very similar to Unit 2, showed that the least cost option would 

be replacement, rather than upgrade, of the existing ESP (Illinois Power did not analyze the 

option of replacing the ESP with a baghouse).ill' Those conclusions should be equally applicable 

to Unit 2. 

1. Baghouse 

In 1985, it would have been technically feasible for Illinois Power to substantially improve its 

particulate control with a baghouse. As of 1988, at least 32 coal fired powerplants had installed 

baghouses designed to achieve levels of PM 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 of Energy, Energy Information Administration (Form EIA-767) for 1988. 

ill' See Bums and McDonnell report, "Baldwin Unit 1 Electrostatic Precipitator Study" (1991). 

IPPRO-0058084 through IPPRO-0058136. 

illi See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

38 

019026
those 32, many were designed to achieve levels of between 0.001 and 0.005 gr/ACF.ill' An 

emission rate of .003 grl ACF 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 efficiency of approximately 

99.4% (see 1982 analysis, above). This alone demonstrates the technical feasibility of an ESP at 

Baldwin at that removal efficiency. 

a. Cost Analysis 

Based on a design to remove 99.7% of particulate matter, the annualized cost of installing a new 

ESP at Baldwin Unit 1 in 1988 is estimated to have been about $20.2 million ($113 million 

capital cost) . .!2!Y' A baghouse with similar capabilities 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 of emissions reduction, that is the option that I considered for further analysis. 

The total cost effectiveness of the 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 similar to that of other contemporaneous sources. 

For example, Northern States Power's Sherburn County Unit 3 (809 MW), built in 1987, 

reported a capital cost of$73.1 million for its baghouse removing 99.9% of PM. 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 Baldwin Unit 1 in 1988 are therefore 

note unreasonable. 

ill' See report of William Ellison, PE, Ellison Consultants, developed in connection with United 

States v. Illinois Power and Dynegy Midwest Generation, Inc. 

ill See Table 4c for calculations . 

.!2!Y' See report of Dan 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 . 

.J12t Ibid . 

.@' Department of Energy, Energy Information Administration (Form EIA-767) for 2000. 

39 

019027
b. Other Environmental Impacts 

No significant environmental impacts would occur from the use of a 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 of 0.003 pound/million BTU based on the use of the use of a 

baghouse removing 99.7% of PM represented BACT at Baldwin Unit 1 in 1988. Compliance 

would have been monitored with EPA method 5 and use of an opacity CEMS. 

D. BACT Determinations for Baldwin Station: 2002 

1. BA CT Determination at Baldwin Units 1 and 2 

I am analyzing these two units together because they have designs that are virtually identical for 

the purposes of this analysis. These two units are currently burning coal from the Powder River 

Basin with a sulfur content of approximately 0.25%. They both also have overfire air installed, as 

well as infrastructure for SCR, although no catalyst is installed. Units 1 and 2 underwent 

upgrades to their ESPs in 1999. Although none of the results of these upgrades and changes are 

enforceable as permit conditions,ill the S02 and NOx controls IP has employed to date are 

presumably the result of Illinois Power's need to comply with acid rain (Title IV) provisions of 

the Clean Air Act. 

a. S02 Control 

To be analyzed together with Unit 3, below. 

b. 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 December 4, 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). 

40 

019028
1. 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 SCR to control NOx emissions.ill~ 

OF A has also become a very widely used technology. In fact, Illinois Power installed OF A at 

Baldwin Units 1 and 2 in approximately 1999.ill OF A can reduce emissions by as much as 50% 

in cyclone fired boilers. Illinois Power achieved reductions of about 62 % with its OF A 

installations.~ 

Reburn is a NOx control technology that involves diverting a portion of the fuel from the burners 

to a second combustion area (reburn zone) above the main combustion zone. Additional air is 

then added above the reb urn zone to complete fuel burnout. The reb urn fuel can be either natural 

gas, oil, or pulverized coal; however, most experience to date is with natural gas reburning. There 

are many technical issues in applying reburn, such as maintaining acceptable boiler performance 

when a large amount of heat 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 reb urn fuel.ill! Notwithstanding these concerns, at least one demonstration project on a 

cyclone fired boiler showed reburn technology achieving a NOx reduction of 50%, with minimal 

ill' See, e.g. New Jersey Department of Environmental Protection, permit number 01-89-3086, 

issued on December 26, 1990 to Chambers Cogeneration Limited Partnership. 

ill See "Performance of Selective Catalytic Reduction on Coal-Fired Steam Generating Units," 

USEP A, June, 1997. This document may be found at website address: 

http://www .epa.gov I airmarktl arp/nox/scrfinal. pdf. 

~ See SCR Installations Spreadsheet, EPA Clean Air Markets Division, 2001. 

ill Deposition testimony of Aric Diericx, November 10, 2000. 

@ See "Appendix B-1: Compliance Results for All NOx Affected Units in 2000". This 

document may be found at website address 

http://www.epa.gov/airmarkets/cmprptlarpOO/appendixbI200.pdf. The reported emission rate for 

Baldwin Units 1 and 2 are 0.66 and 0.70 pound per million BTU, respectively. This is more than 

a 50% reduction compared to the uncontrolled rate of 1.8 poundslMMBTU. 

ill! See U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, 

"Alternative Control Technologies Document NOx Emissions from Utility Boilers" March 1994. 

This information can be found at website address: http://www.epa.gov/ttn/catc/dirllutboiler.pdf. 

41 

019029
operational problems.~ 

SNCR has been described earlier. Emissions reductions of up to 80% of NO x 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 NOx and improve boiler 

efficiency by monitoring a number of parameters, and then providing infonnation to a plant's 

distributed control system. More than 200 boilers, most of them coal fired, are using an 

optimization technology. Reductions of as much as 40% are possible with optimization 

systems.m 

Some of the above technologies may be used effectively in conjunction with one another, and 

feasible combinations therefore should be considered. Specifically either SCR or SNCR may 

follow almost any other NOx emissions control technology. For example, use of OF A may be 

followed by an SCR system. OFA and reburning (both coal and gas) are considered to modify the 

combustion process, while SCR and SNCR are post-combustion processes. Emissions reductions 

achieved through use of combustion modification followed by SCR or SNCR are mUltiplicative. 

In other words, an emission reduction of 50% 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 

of optimization systems in conjunction with other emissions reductions retrofits. 

Because of the high NOx emission rate of an uncontrolled cyclone fired boiler (compared with 

tangentially fired boilers), effective NOx emissions control requires both combustion control as 

well as post combustion control. Illinois Power evaluated the options for controls at units 1 and 2 

in the early 90s and concluded that OF A would be a more cost effective option than reburning;.!2.!! 

for that reason I did not analyze reburning further. Therefore, the options available are SCR or 

SNCR and OFA together, or OFA alone (i.e with no additional control). All three options are 

~ See "Demonstration of Coal Reburning for Cyclone Boiler NOx Control," McDennott 

International Inc, 2001. This infonnation can be found at website address: 

http://www.mtiresearch.com/expernce.html#Demonstration of Coal Reburn. 

m See report of William Ellison, PE, Ellison Consultants, "Table 2, SCR Installations," 

developed in connection with United States v. Illinois Power and Dynegy Midwest Generation, 

Inc. 

m See "What's New 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). 

42 

019030
amenable to the use of an optimization system. 

The next step is to determine an appropriate emission limit. In order to determine the emission 

limit, I considered both the effectiveness of the 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 OF A system, operating together with the optimization system, 

would easily achieve a 50% reduction. An SCR system is capable of controlling 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 

or permitted coal fired powerplants.ill! Most of these powerplants are subject to the BACT 

requirement under PSD. All ofthese plants would emit less than 0.15 pound/million BTU, 

because that is the maximum allowed under the NSPS.lli' However, cyclone fired boilers without 

controls emit far more NOx than other coal burning technologies, and of the currently proposed 

plants would be cyclone fired boilers. Therefore, it is difficult to make a direct comparison 

between recent BACT levels and the appropriate level for Baldwin Units 1 and 2. It is, instead, 

necessary to derive a BACT emission limit for Baldwin Units 1 and 2 based on the performance 

of demonstrated NOx control technologies. 

Based on the performance of the 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 of overfire air, an optimization system, and SCR, as this combination would 

provide the greatest control efficiency. The overfire air system would reduce emission by at least 

50%, and SCR could reduce emissions by a further 90%. I assumed a combined removal 

effectiveness of approximately 92% from use of OF A and SCR. This rate assumes that OF A will 

reduce emissions between 60 and 70%, and SCR between 80 and 90%. As I discussed above, I 

did not assign a specific amount of emission reduction to the optimization system. Rather, the 

optimization system should improve the overall performance and cost effectiveness of NO x 

control. On the basis ofIP's uncontrolled emission rate of 1.8 pound/million BTU, this 

combination of controls could result in removal of 92% of emissions, resulting in a controlled 

emission rate of 0.14 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 

may be found at website address http://www.epa.gov/eab/eabpsd.htm. 

ill! See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1,2002. 

lli' See 40 C.F.R. § 60.40a (1979), "Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is commenced after September 18, 1978." 

43 

019031
II. Other Environmental Effects 

Most of the options for NOx emissions control would have no significant other environmental 

effects. SCR and SNCR use ammonia, which could cause environmental effects if emitted 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, OF A and an optimization system would be approximately $8.4 million 

for Unit 1 and $8.7 million for Unit 2.ill! Based on a controlled rate of 0.14 poundslMMBTU 

(controlling approximately 10,000 TPY of NO x), the cost effectiveness of these controls would 

be $877 and 842/ton for Units 1 and 2, respectively.~ The costs associated with the combination 

of controls is conservative because I included the cost of installing OF A systems at Units 1 and 2, 

even though both already have OF A installed. 

This compares very favorably to the cost points I have used throughout the report. For example, 

as noted above, the New Jersey Department of Environmental 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 upper bound for BACT cost effectiveness. In 

comparison to these benchmarks, the cost of SCR, OF A and an optimization system is not 

unreasonable. 

IV. Conclusion 

Based on all of the above factors, I have determined that an emission limit of 0.14 pound/million 

BTU, 30 day rolling average, based on use ofthe combination of OF A, SCR capable of90% 

control, and an optimization system, represents current day BACT for emissions of NO x at 

Baldwin Units 1 and 2. Compliance with this limit would be monitored via use of a 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-jet baghouses and reverse air baghouses. The difference 

ill! See report of Dan 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. 

~ See Table 3d for calculations. 

44 

019032
between the two technologies relates to the way in which captured particles are removed from 

the bags after the bags collect the particles. Emission rates for new facilities controlled by ESPs 

and baghouses range from about 0.015 to 0.020 pound/MMBTU. These emission rates reflect 

control of approximately 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 may be disposed of in 

accordance with regulations for non-hazardous waste. 

HI. Cost Analysis 

I analyzed the cost of complying with the lowest limit currently proposed for new powerplants: 

0.015 pound/million BTU. As discussed in the earlier timeframes, (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 pulse jet design is less expensive, with a initial capital investment 

of $46.1 million, and annual operating costs of approximately $1.1 million. The total annualized 

cost for a pulse-jet baghouse would be $8.3 million . .!2§' 

I estimate that the total cost effectiveness would be $302/ton of particulate 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 similar to that of other 

contemporaneous sources. For example, Public Service Electric & Gas Company's Mercer Unit 

(326 MW, about half the size of the Baldwin units), built in 1994, reported a capital cost of$38.9 

million for its ESP removing 99.8% ofPM.112' Data reported 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 See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1,2002 . 

.!2§' See report of Dan 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 of Energy, Energy Information Administration (Form EIA-767) for 2000. 

45 

019033
IV. Conclusion 

I therefore conclude that an emission rate of 0.006 pounds per million BTU~ based on use of a 

99.6% efficient pulse jet 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. BA CT Determination for Baldwin Unit 3 

Unit 3 is also currently burning coal from the Powder River Basin with a sulfur content of 

approximately 0.25%. Unit 3 was retrofitted with a low NOx burner in 1994.N!I The ESP was 

upgraded in 2000.~ Although none of the results of these upgrades and changes are enforceable 

as permit conditions,ill! the S02 and NOx controls IP has employed to date are presumably the 

result of Illinois Power's need to comply with acid rain (Title IV) provisions of the Clean Air 

Act. 

a. S02 Control (applicable to Units 1, 2 and 3) 

The following options are available for S02 control: 

b. Wet Limestone Scrubbing 

c. Wet Lime scrubbing buffered by Magnesium Oxide 

d. Dry Scrubbing. 

1. Technical Feasibility 

I have previously addressed the technical feasibility ofthe two wet scrubbing options. To 

summarize, both wet scrubbing options are currently available, and demonstrated with removal 

efficiencies of up to 97%. 

In the dry scrubbing process, flue gas is sent to a spray dryer absorber (SDA). In the SDA, a fine 

mist of lime slurry is sprayed into the flue gas. Heat from the flue gas evaporates the moisture in 

the slurry cloud while the alkaline slurry simultaneously absorbs the S02in the flue gas. The 

result is the conversion ofthe calcium hydroxide component of the slurry into a fine powder of 

calcium/sulfur compounds, and lowering of the flue gas temperature. Removal efficiencies of up 

~ 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. 

46 

019034
to 90% with PRB coal have been demonstrated.~ 

Illinois Power has now been using PRB coal since 1999, which, for the purpose of this analysis, 

has a sulfur content of approximately 0.6%.A large number of facilities are burning western coal 

and scrubbing 90% or greater, using one of the above technologies. Several plants using coal 

with less than 1 % sulfur coal are removing 95% of the 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% of S02 from western coal, and up to 

97% of S02 from eastern, high sulfur coals. Dry scrubbing has been demonstrated to remove up 

to 90% of S02 from western coal. Wet scrubbing is therefore the "top," or most effective option. 

11. Other Environmental Impacts 

Wet scrubbers produce a sludge that requires may have economic use. If not used, it must be 

disposed in a landfill. This sludge is not considered hazardous waste. Dry scrubbers produce a 

powder that may also be disposed in a landfill, and is also not considered hazardous waste. No 

other significant environmental effect occur due to the use of scrubbers. 

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 1 and 2 would be $8.0 to 8.3 million per unit; 

annual operating costs for Unit 3 would be $8.4 to 8.7 million (the difference reflects the higher 

assumed capacity factor for Unit 3). Total annualized cost would be approximately $15.9 million 

per unit for Units 1 and 2, and $16.3 million for Unit 3.m Assuming a removal efficiency of 

~ See "Retrofitting Lime Spray Dryers at Public Service Company of Colorado," R. Telesz et. 

aI., Presented to Power-Gen International 2000, November 200. This document may be found at 

website address: http://www.babcock.com/pgg/tt/pdflBR-1707.pdf. 

~ See "Table 30: Flue Gas Desulfurization (FGD) Capacity in Operation at U.S. Electric Utility 

Plants as of December 1999." This information can be found at website address: 

http://www .eia.doe.gov/cneafielectricity/epav2Ihtml_ tables/epav2t30p l.html and following 

pages. 

l:2!!f Prior analyses (see e.g. 1982 analysis) offered in this report establish this technology as the 

lower cost wet scrubbing option, compared to wet lime scrubbing buffered magnesium oxide. 

m See report of Dan M ussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with 

47 

019035
95%, 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 policy documents. I reviewed the cost effectiveness of 

eighteen powerplants permitted between 1979 and 1999 with BACT requirements for scrubbers. 

Of those where a dollar per ton 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 of the range of these 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 emission rate of 0.095 pounds per million BTU based on 95% scrubbing and assuming use 

of coal with 0.6% sulfur.ill Compliance 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 or Gas Reburning 

5. Optimization system 

United States v. Illinois Power and Dynegy Midwest Generation, Inc. 

lQ§' See Table 8d and 8e for calculations. 

M See Table 11, Cost Effectiveness of BACT Determinations for S02. Most of the higher cost 

effectiveness values attach to facilities burning lower sulfur coal, while lower cost effectiveness 

correlates to facilities burning higher sulfur coal. 

lli¥ The cost estimate presented here may, in fact, be conservative. Some literature suggests that 

S02 scrubber costs have recently gone down. See "Cost of S02 Scrubbers Down to $100IKW, 

Douglas Smith, Senior Editor, Power Engineering, September, 2001. 

ill Calculated by using a controlled emission rate of 533 poundlhr and 5587 million BTUIhr. 

48 

019036
1. Technical Feasibility 

As with Units 1 and 2, several NOx control options may be used singly or in combination at 

Baldwin Unit 3. The same options discussed above as currently feasible for NOx control on Units 

I and 2 are technically feasible and demonstrated for use on Unit 3. In addition, as I discussed in 

the 1982 time frame, low NOx burners 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 of the design of newer LNBs (in fact, 

the currently installed LNBs at Unit 3 include integral OF Aill'), or may be added in a location 

near the burner in the boiler.ill In addition to LNBs, SCR or SNCR may be used as a postcombustion control. Most new coal fired powerplants that are permitted with SCR also use 

combustion controls such as LNBs.@ They may also use optimizations systems to enhance 

boiler efficiency and reduce NOx ' 

211, See "Emissions Data and Compliance Reports," USEP A. These data may be found at website 

address: http://www.epa.gov/airmarkets/emissions/index.html 

ill Tangential Low NOx System at Reliant Energy's Limestone Unit 2 Cuts Texas Lignite, PRB 

and Pet Coke NOx, Ron Pearce, Reliant Energy and John Grusha, Foster Wheeler Energy 

Corporation, May 30, 2001. 

ill! Maximize PRB Coal Usage in Conjunction with In-Furnace NOx Solutions to Minimize Cost 

of NO x Compliance, James Topper, Herb Blue, Jim Pomaranski, Consumers Energy, Ed Rebula, 

Robert Lewis, ALSTOM Power, undated. 

ill! "4 X 550 MWe Boiler Operating Experience at 0.15 IblMMBTU NOx Emission Level Firing 

a Broad Range of Coals," A.D. La Rue 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 of Aric Diericx, November 10, 2000. 

ill See "B&W's Experience Reducing NOx Emissions in Tangentially-Fired Boilers-2001 

update," A. Kokkinos et. aI., Presented to Power-Gen International 2001, December 2001. This 

document may be 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 City Power and Light for the Hawthorn 

Generating Station. 

49 

019037
Just as with Units 1 and 2, some of the above technologies may be used effectively in 

conjunction with one another, and feasible combinations therefore should be considered. 

Specifically either SCR or SNCR may follow almost any other NOx emissions control 

technology. 

Several powerplants have recently been built or modified with a combination of LNBs and SCR. 

For example, 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 of about 0.3 pound/million BTU NOx' 

With the additional use of an SCR system removing 90% of the NOx exiting the burner, 

emissions of 0.04 pound/million BTU are readily achievable using the current LNB. 

Replacement of the current LNB with a state-of-the-art LNB would, together with the use of 

SCR, allow Unit 3 to reach an emissions level of 0.015 poundslMMBTU NOx' However, since 

this is a retrofit, rather than a new powerplant, it may be difficult to achieve the lowest levels 

reached by new plants. Therefore, I would conclude that an emission rate of 0.02 

poundslMMBTU would represent the most effective level ofNOx ' control currently achievable at 

Baldwin Unit 3. A limit of 0.02 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 in New York, a 675 MW boiler, has reduced its emissions to 

0.05 pounds per million BTU, a 90% reduction using only SCR.ill' 

n. 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 if emitted in 

ill See New Jersey Department of Environmental Protection, permit number 01-89-3086, issued 

on December 26, 1990 to Chambers Cogeneration Limited Partnership. 

m¥ See "PREVENTION OF SIGNIFICANT DETERIORATION CONSTRUCTION PERMIT 

888 REVIEW DOCUMENT," issued to Kansas City Power and Light for the Hawthorn 

Generating Station. 

ill! See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1, 2002. 

ill' See Selective Catalytic Reduction Retrofit of a 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 Power Generation 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. 

50 

019038
large amounts. However, ammonia slip is limited by design to about 3 ppm, so effects would not 

be likely to occur. 

Ill. Cost Effectiveness 

The top BACT option be the use of LNBs, SCR, and an optimization system. The annualized 

cost of an 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 of new LNBs would be $1.5 million, and the annualized cost of an 

optimization system would be $18,000.lli'·m The 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 of this combined option would be $2539/ton.~ 

The costs of achieving 0.02 poundlMMBTU are well within the range of costs estimated in 

recent PSD permits for coal fired powerplants. For example, coal fired powerplants permitted 

since 1990 have been required to install controls with predicted cost effectiveness that ranges 

from $1690 (in 1999) to $13,196/ton (in 1990).llii 

ill See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation of S02' 

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. 

ill! Ibid. 

WI Deposition testimony of Aric Diericx, November 10, 2000. 

lli' See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02, 

NOx and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with 

United States v. Illinois Power and Dynegy Midwest Generation, Inc. 

m Information from manufacturers of these systems show that these systems often yield both net 

cost savings and NOx emission reductions. See "Full Scale Implementation Results for GNOCIS 

(tm) Plus," George Warriner, URS Corporation, Steve Logan, Southern Company Services, Steve 

Pascoe, Powergen, James Noblett. Presented at the USDOE-EPRI combined Power Plant Air 

Pollution Control Symposium, August, 2001. "At some plants, lowering NOx can be done 

simultaneously with increasing efficiency." 

~ See Table 3e for calculations. 

llii See Table 10, BACT Cost Effectiveness for NOx Controls. 

51 

019039
IV. 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 if they 

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 by ESPs 

and baghouses range from about 0.015 to 0.02 poundlMMBTU.m Illinois Power upgraded its 

ESP in 1999 as part of its preparation to begin burning PRB coal.ill As I discussed in the 1982 

case above, the original performance of Unit 3 was far better than the performance of Units 1 and 

2. Although we currently have no data about the current performance of Unit 3's ESP, it appears 

that the original design, together with the upgrade, may be capable of meeting a limit of 0.0 15, 

the lowest limit currently set for BACT. 

However, I evaluated the cost of a replacement PM control device, in order to determine what the 

cost might be if the Unit 3 ESP cannot perform at the necessary level to meet BACT. Assuming 

an emission rate of 0.015 poundlMMBTU, the capital cost ofa new baghouse at Baldwin Unit 3 

would be $43.8 million, and the annualized cost would be approximately $10 million. The cost 

effectiveness of that baghouse would be $69/ton. This is similar to other recently permitted 

powerplants. For example, 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 of a baghouse with a cost effectiveness of 

$82/ton.ill However it is unlikely that Illinois Power would be required to incur these costs, in 

that Illinois Power could improve the performance of the ESP by adding a field or a "polishing" 

baghouse, likely at a substantially lower cost than a new device. 

m See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1, 2002. 

ill Deposition testimony of Aric Diericx, November 10, 2000. 

ill' See Best Available Control Technology Analysis for Keystone Cogeneration Facility, Bechtel 

Power Corporation, October, 1989. 

ill See Prevention of Significant Deterioration Construction Permit Application: Replacement of 

Unit 5 at the Hawthorn Generating Station, Bums and McDonnell, May 1999. 

52 

019040
Conclusion 

I therefore have determined that BACT for PM at Baldwin Unit 3 is an emission limit of 0.015 

pound/million BTU, based on use of an ESP or baghouse. Compliance would be monitored with 

aCEMS. 

53 

019041