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REDACTED

Best Available Control Technologies

for the Baldwin Generating Station, Baldwin, Illinois

7~L-kC-_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

Pet. EX 28-1
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TABLE OF CONTENTS

Paee

LIST OF TABLES , iv

I. Introduction and Overview 1

A. Infonnation Required for the Expert Report 1

B. Purpose ofReport 1

II. Summary ofConclusions 2

III. Qualifications 3

IV. What is BACT? : 5

V. The Typical BACT Determination Process 6

VI. Baldwin Station: Background 11

VII. BACT Determinations for the Baldwin Station 13

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

1. SulfUr Dioxide 13

2. Nitrogen Oxides 17

3. Particulate Matter 22

B. BACT Determination For Baldwin Unit 1: 1985 23

1. Sulfur Dioxide 23

2. Nitrogen Oxides 26

3. Particulate Matter 30

C. BACT Determination for Baldwin Unit 2: 1988 33

1. SOl Control 33

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2. NOx Control 35

3. Particulate Matter 38

D. BACT Detenninations for Baldwin Station: 2001 40

1. BACTDetermination at Baldwin Units 1 and 2 40

a. S02 Control 40

b. NO. Control 40

c. Particulate Matter 44

2. BACTDetermination for Baldwin Unit 3 46

a. S02 Control (applicable to Units 1,2 and 3) 46

b. NO. Control 48

c. Particulate Matter 52

Appendix A: Tables.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. A - I

Appendix B: Data and Infonnation Considered B-1

Appendix C: Papers Authored in the Last Ten Years C - 1

Appendix D: Resume. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. D - 1

Attachment 1:

Report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02, NO. and

PM Control Devices at illinois Power's Baldwin Station," developed in connection with United

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

Attachment 2:

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

v. Illinois Power and Dvnegy Midwest Generation, Inc.

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Table I:

Table 2:

Table 3a:

Table 3b:

Table 3c:

Table 3d:

Table 3e:

Table4a:

Table 4b:

Table 4c:

Table4d:

Table 4e:

Table 5:

Table 6:

Table 7:

LIST OF TABLES

NOx Emissions Rates for Permits Issued up to 1982 " .. A - 3

Cost Effectiveness ofS02 for Permits Issued 1979-1999,

Converted to 1982,1985, 1988, and 2001 A - 4

NOx Emission Calculations and Cost Effectiveness for

Baldwin Unit 3, 1982 A - 5

NOx Emission Calculations and Cost Effectiveness for

Baldwin Unit 1, 1985 A - 6

NOx Emission Calculations and Cost Effectiveness for

Baldwin Uilit 2, 1988 A - 7

NOx Emission Calculations and Cost Effectiveness for

Baldwin Unit 1 & 2, 2001 A - 8

NOx Emissions Calculations and Cost Effectiveness for

Baldwin Unit 3, 2001 A - 9

Particulate Matter Emissions Calculations for Baldwin

Unit 3, 1982 A - 10

Emission Calculations for Particulate Matter, Baldwin

Unit 1, 1985 A-II

Emissions Calculations for Particulate Matter, Baldwin

Unit 2, 1988 A - 12

Emissions Calculations for Particulate Matter, Baldwin

Unit 1 & 2,2001 A - 13

Emissions Calculations for Particulate Matter, Baldwin

Unit 3,2001 , . . . . . . . . . . . . . . . . . . . . . . . . .. A - 14

RACTIBACTILAER Summary: 1982 Timeframe A - 15

Summary ofPo~erplantswith High S02 Removal: 1985 timeframe ..... A - 16

Derivation ofParticulate Removal Efficiency A - 17

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Table 8a:

Table 8b:

Table 8c:

Table 8d:

Table 8e:

Table 9:

Table 10:

Table 11:

S02 Emission Calculations and Cost Effectiveness for

Baldwin Unit 3, 1982 " A - 18

S02 Emission Calculations and Cost Effectiveness for

Baldwin Unit 1, 1985 " " A - 19

S02 Emission Calculations and Cost Effectiveness for

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

S02 Emission Calculations and Cost Effectiveness for

Baldwin Unit 1 & 2, 2001 A- 21

S02 Emission Calculations and Cost Effectiveness for

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

General Information About Baldwin - Baldwin

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

Cost Effectiveness ofBACT Determinations for NOx •••••••••••••••• A - 26

BACT Cost Effectiveness for S02 Controls A - 27

v
• I. INTRODUCTION AND OVERVIEW

A. Information Required for· the Expert Report

The following is a listing ofthe items required by the Federal Rules ofCivil Procedures provided

with this report:

(I) 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 ofthe report and Appendix B list the data and other information

considered in forming these opinions.

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

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

Appendix D.

(6) lam being compensated for the preparation ofthis report and my testimony as a

normal part ofmy compensation as an employee ofthe US EPA.

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

expert at trial or by deposition.

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B. Purpose of Report

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

controls should have been installed at the Baldwin Station when the Prevention ofSignificant

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

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

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

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

Available Control Technology" (BACT). This report explains what BACT would have been--

for sulfur dioxide (S02)' nitrogen oxides (N0J and particulate matter (PM) -- at Unit I in 1985,

Unit 2 in 1988, and Unit 3 in 1982, when PSD was allegedly triggered. In addition, it is EPA's

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

preconstruction permit must install controls that constitute BACT when the proper permit is

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

11 Office ofAir Quality Planning and Standards, U.S. EPA, New Source Review Workshop

Manual: Prevention ofSignificant Deterioration and Nonattainment Area Permitting (Draft Oct.
• pennits were being issued as ofthe date this report is submitted.

II. Summary of Conclusions

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

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

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

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8°2 NO. PM

1982 (Unit 3) 0.30 pounds per 0.40 pounds per 0.036 pounds per

million BTU, based on million BTU, based on mi11ion BTU, 99.4%

95% scrubbing and use of Low NO. control, based on use

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

3.5% sulfur content, Averaging time: Averaging time:

and use 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 1) 0.30 pounds per 0.90 pounds per 0.003 pounds per

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

95% scrubbing and use ofselective use 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 roIling

Monitored via CEMS

1990), page B.5S: "the BACT emission limit in a new source pennit is not set until the final

pennit is issued."

Y Continuous Emissions Monitoring System

}j See 40 C.F.R 60 Appendix A

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1988 (Unit 2) 0.30 pounds per 0.36 pounds per 0.003 pounds per

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

95% scrubbing and use ofselective use 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

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 Averaging time:

with 0.6% sulfur reduction, and an 3 hour

content optimization system Monitored via EPA

Averaging time: Averaging time: method 5, triboelectric

30 day rolling 3 hour broken bag monitors

Monitored via CEMS Monitored via CEMS

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

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

95% scrubbing, and use oflow-NO. use ofa ESP. , assuming use 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 '-r;'-

Monitored via ·CEMS pounds per million

B111 iflower limit is

demonstrated to be

unachievable.

Averaging time:

3 hour

Monitored via CEMS

III. Qualifications

I have been involved in BACT decisions in a variety 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 ofthis section

See http://www.epa.gov/ttnJemc/propperfi'ps-ll&fmotice.pdf, proposed Performance

Specification for Continuous PM Monitoring Systems.

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

issuance ofPSD permits, and to oversee the issuance ofPSD and nonattainment NSR permits by

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

powerplants, cement plants, and waste-to-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 permit applicants, their consultants, and state and local

permitting authorities for conducting a BACT deterrnimition. Beginning in about 1987, I spent

approximately one year in our enforcement office, focusing on two cases involving coal-fired

powerplants in Arizona and Nevada: Nevada Power-Reid Gardner and Arizona Public

Service-Cholla. In 1989, 1became the manager ofthe New Source Section. I managed the

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

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

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

Plan, as well as reviews ofstate programs to determine-after the fact-the efficacy oftheir

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

Associate Director ofthe Air Division. One ofmy responsibilities was managing the Region's

~esponse 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 Permits Office on decisions related to powerplants, including BACT

decisions.

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

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

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

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

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

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

Most ofmy 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 permitting 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 ofCalifornia extension course about the Clean Air

Act. Most recently (March 200 I), I was invited to present a paper to the second conference ofthe

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

Emissions Controls at Refineries: US Regulatory Drivers and Results.

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• 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 Stat~ authorized under the New Source Review

("NSR") program. Because the Baldwin plant is located in an area that is in attainment ofthe

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

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

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

("BACT") are one ofthe key requirements ofthe PSD permit.

BACT is defined as:

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

degree ofreduction for each pollutant 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

thrqugh 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 ofbest available control technology result in

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

standard under 40 CFR Parts 6()?! and 61. Ifthe Administrator determines that technological

or economic limitations on the application ofmeasurement 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 ofsuch design, equipment, work practice or operation, and shall provide for

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

and federal regulations to carry out air pollution control functions.

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

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

be found in these regulations.

?1 40 C.F.R. Part 60 is generally known as New Source Performance Standards. This section

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

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

mills and the like.

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compliance by means which achieve equivalent results."!!!

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

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

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

as well as information about other facilities and 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 ofthe comment period, the permitting authority reviews all

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

comments, and issues a pennit 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 ofSignificant Deterioration Workshop Manual.!1'

§' 40 C.F.R. § 52.2I(b)(12).

'}j In addition to my own research, I cite below to the work ofEllison Consultants, who have

performed a review ofthe historical installation oftechnologies, and to the work ofstaffin

EPA's Office ofAir Quality Planning and Standards, who have perfonned a review ofthe 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 ofSignificant Deterioration Workshop

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

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

"Top-Down" Best Available Control Technology Guidance Document.J1I Also, EPA's Region 9

office published, in about 1987, its BACT Guidance Document.JJi 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 ofreduced emissions that the technology would bring. The

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

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

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

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"--altemative. 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. Ifthe most stringent technology is eliminated in this

fashion, then the next most stringent alternative is considered, and so on. This i~ known as the

"top-down" process.

The first step in a "top-down" analysis is to identify, for the emissions unit in'question, all

"available" control options. Available control options are those 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 ofproduction 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 oftechnologies employed both within and

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

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

1990).

.ill Office ofAir 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.

.!)J Matt Haber et ai., U.S. EPA Region 9, Best Available Control Technology Guidance

Document.

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outside ofthe United States.H' As discussed later, in some circumstances, inherently

lower-polluting processes are appropriate for consideration as available control alternatives. The

control alternatives evaluated should include not 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 reductiori technically possible (which is required in areas not attaining the

National Ambient Air Quality Standards, and known as lowest achievable emission rate

(LAER).!.?J) is considered available for BACT purposes, must also be included as a control

alternative and usually represent the "top" alternative..!9'

In the course ofthe BACT analysis, one or more 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..!?!

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

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

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

engineering principles, that technical difficulties would preclude the successful use ofthe control

option on the emissions unit under review. Technically infeasible control options are then

eliminated from further consideration in the BACT analysis.~

For example, in cases where the level 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

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

Control Technology Guidance Document (Mar. 15, 1990), page B.l1. "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]."

.!J LAER is defined as the lowest emission rate achieved in practice, or in a SIP, for that class or

category ofsource (C.A.A. § 171).

.!3' Office ofAir Quality Planning and Standards, U.S. EPA, 'Top-Down" Best Available

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

J1J Ibid.

Ibid.

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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.~

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 ofsimilar

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

alternatives and should include the following types ofinformation:~

• control efficieiicies (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 oftoxic 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 anive 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 ofthe 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

J.2r Ibid.

Ibid.

lli Ibid.

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known as "cost effectiveness." Using this common unit ofmeasurement facilitates a comparison

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

equipment compared to fraction oftotal 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 ofpollutant 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 ofthe BACT analysis is to ensure

that a permit applicant may propose elimination of a control option ifits 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 offacility or BACT in general.

lfthe applicant accepts the topaltemative 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. Ifthere are no outstanding issues regarding collateral

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

that the top candidate is 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.llI

1lI Prior to the formalization ofthe "top-down"BACT process described above, the BACT

process did not require that the applicant begin with an analysis ofthe 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 ofthe BACT determination process, after a series of evaluations ofstate and

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

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

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

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

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

10
• VI. Baldwin Station: Back2round

Baldwin Station consists ofthree 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 II %

by weightDl until 1999, when the facility began use ofPowder River Basin (PRB) coal with a

heating value of 8600-8800 BTUllb, a sulfur content of 0.25%, and an ash content of 4.6-4.8%.~

Unit I began operation in 1970, and operates a cyclone fired boiler.~ Unit 1 has a gross output

of 584 megawatts (MW).±9' Its air pollution equipment includes of an electrostatic precipitator

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

exhaust gas. The ESP was upgraded in I999.1lI 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).;ill' However, at least as ofNovember

•

•

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 ofthe "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.

DI Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985.

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

Ibid.

±9' Sargent & Lundy Engineers Engineering Data, Unit 1 Baldwin Power Station. IPPRO0085676-744.

llJ IP Permit Application dated March 30, 1998. IPPRO-OOI9396.

¥i Ibid.

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

;ill' IEPA Construction Permit. EPA 5775.

II
•

•

•

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

S02 controls in place at Baldwin Unit I.

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

operation in 1973.J1I The Unit 2 ESP was initially designed to remove 99% ofthe exhaust gas

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

installation of a flue gas conditioning system,J.9' 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 1999,TI' as was an SCR system infrastructure. However, at least as ofNovember 2000

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

controls in place at Baldwin Unit 2.

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

1975.~ Its air pollution controls include an ESP initially designed to remove 99.5% of exhaust

gas PM.±!J Although the ESP was upgraded in 20aO,£' no information has been provided

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

l!I Deposition testimony ofAric Diericx, November 10, 2000.

.!Y Ratings ofIllinois Power Company Fossil Fuel Fired Generating Units; Report by Power

Technologies, Inc. December, 1987 -IPPRO-00151120

J1I Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985.

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

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

J!i IP Permit Application dated December 20, 1999. IPPRO-0028865

TI' IP Permit Application dated September 8, 1999. IPPRO-0028775.

Deposition testimony of Aric Diericx, November 10, 2000.

12t Sargent & Lundy Engineers Engineering Data, Unit 3 Baldwin Power Station. IPPRO0085900.

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

iY Ibid.

IP Permit Application dated November 25, 1998. IPPRO-OOI9250.

12
•

'.

•

respect to NO•• in 1994, low NO. burners, with an overfire air system were installed.~ 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.~

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 of3%-3.5%.B 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

IP Pennit Application dated January 19, 1993. IPPRO-0032541.

Ibid.

Ibid.

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

9 Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985.

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

Illinois Power Company to U.S. EPA.

13
•

•

•

through an injected mist ofreagent - generally limestone or lime.12' 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

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

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

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

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

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

eight other facilities were 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 ofreasons, but by 1982 there were at least two Federal requirements for the use of

scrubbers for SOz control.

The first ofthese federal requirements is the New Source Performance Standards (NSPS) for coal

fired powerplants. The NSPS had been amended in 1979, and applies to. powerplants constructed

or modified after 1978.lli Those standards require removal of up to 90% of flue gas S02

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

cost effective.S'

The second requirement is the BACT requirement ofthe PSD regulations, which, in 1982, had

been in effect for almost four years.~ At least seven coal fired powerplants were issued PSD

permits between 1978 and 1983 with the requirement for between 80 and 95% control.3' For

!If "Estimating Costs 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.

W See 40 C.F.R. § 60.40a (1979), "Standards ofPerformance for Electric Utility Steam

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

?1J See C.A.A.§ 111(a)(I).

In 1978, EPA revised its regulations 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.

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

14
•

•

•

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

removal requirement and an emission rate of 0.1 pound/million BTU. In 1980, the Platte

River Power Authority, Rawhide Station was issued a permit with an 80% removal requirement

and an emission rate limit of 0.13 pound/million BTU.~ In addition, in 1982, the Allegheny

Power, Mitchell 33 Unit, a powerplant firing up to 2.9% sulfur coal, began operation of a

scrubber removing 95% ofthe stack gas.iY

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

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

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

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

both technologically feasible and well demonstrated in practice.

b. Cost Analysis

Both ofthe available wet scrubbing options were analyzed to detennine their cost effectiveness.

Both scrubbing options were analyzed at the 95% efficiency level.

The cost for scrubbers capable ofremoving 95% offlue gas SOl were analyzed based on a study

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

ofthe methodology used in 1991 would also apply in 1982.~ Based on this analysis, the capital

costs for the limestone system, would be approximately $176 million (in 1982 dollars). Operating

costs would range from $3.3 million to 4.7 million, depending on whether waste from the

Ibid.

Ibid.

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

Power and Dvnegy Midwest Generation, Inc.

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

Volumes I-IV ofProposal for Full-Scale Demonstration ofIntegrated Flue Gas Desulfurization

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

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

See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02'

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

United States v. Illinois Power and Dynegy Midwest Generation, Inc. The cost data adjustment

was based on infonnation found at website address http://www.enr.comlcost/costcci.asp.

15
•

•

•

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

annual cost would have been between $22.0 and 23.4 million.§Jj Based on 95% control ofS02

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

tons per year of S02' Its cost effectiveness in 1982 would have been approximately $220/ton.2Y

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.~ I reviewed the cost effectiveness of

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

Ofthose 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 ofthe initial

investment over its life.

§Jj Ibid.; the cost data adjustment was based on information found at website address

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

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

§}j See report ofDan Mussatti and Larry Sorrels, Estimated Costs for the Installation 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.

Specifically, as part ofthe 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 ofBACT Determinations for S02'

16
•

•

•

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

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

limestone scrubbing at Baldwin Unit 3 in 1982 is at the low end ofthe range ofthese permits and

EPA guidance. The cost is therefore not unreasonable.

c. Other Environmental Impacts

Wet scrubbers produce a sludge that may. have economic use. Ifnot used, it must be disposed in a

landfill. This sludge is not considered hazardous waste. No other significant environmental effect

occur due to the use ofscrubbers.

d. Conclusion

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

emission rate of0.3 pound/million BTU,2.?J 30 day rolling average, based on the use of a wet

limestone scrubber removing 95% ofthe 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).@

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 ("OFA")

¥1 See memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding

BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier

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

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

2.?J The limit of0.3 pounds 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 ofCEMS Data for the Baldwin Station, submitted by Illinois Power

Company to U.S. EPA.

17
•

a.

3. Selective Catalytic Reduction ("SCR")

4. Flue Gas Recirculation ("FGR")

Technical Feasibility

•

•

Low NOx burners limit NOx formation by controlling both the stoichiometric and temperature

profiles of the combustion process in each burner flame zone. This control is achieved with

mechanical designs that regulate the aerodynamic distribution and mixing ofthe fuel and air

which results in reduced oxygen concentration in the primary combustion zone, reduced flame

temperature, or reduced residence time at the peak NOx formation temperature. There are many

types of Low-NOx burners for use on many types of boilers (except cyclone boilers.~

LNBs were installed in numerous facilities by 1982. At least seven plants were operating with

LNBs worldwide by 1982.211 At least one 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.llI.2.Jf At least two other

powerplants were permitted by 1982 with emission rates near 0.4 pound NOx/million

BTU-Nevada Power's Harry Allen Station, and Tucson Electric Power's (TEP) Springerville

Unit 3.11' Units 1 and 2 at TEP's Springerville, permitted in 1978, have achieved levels of

approximately 0.4 pounds per million BTU.12 All ofthe foregoing powerplants were designed as

tangentially fin~d boilers.

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

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

Power and Dynegy Midwest Generation, Inc. q••

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

Power and Dynegy Midwest Generation, Inc.

2.Jf Conversion from parts per million to pounds per million BTU based on Emissions standards

handbook: air pollutant standardsfor coal-fired power plants, Appendix, Hermine N. Soud,

IEA Coal Research, December 1991.

11' See Appendix A, Table 1.

12 See U.S. EPA, Clean Air Markets Division, "Emissions Scorecard." This information can be

found at website address: http://www.epa:.gov/airmarkets/emissions/scoreOO/index.html. TEP's

emission rate for 2000 was reported to have been 0.39 poundslMMBTU. TEP has presumably

maintained the same burners since the boilers were built.

18
•

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•

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 operationl9' or were permitted for lower levels using LNBsP

These installations demonstrate that, using LNBs, facilities would be capable ofreaching lower

emission rates than the NSPS requires.

Overfire air is a combustion control technique where a percentage (~5 - 20%) ofthe total

combustion air is diverted from the burners and injected through ports about the top 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: (l)

thermal NOx formation is delayed and suppressed because ofthe lower flame temperature and

extended combustion zone, and (2) fuel NOx formation is suppressed because ofthe lower

oxygen concentration in the lower furnace and the lower temperature.~ Overfire air was installed

in numerous facilities by 1982. By 1982, at least five plants were operating worldwide using

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

be an integral part ofLNB designs, and also appear designed to meet a limit of0.7 pound per

million BTU. JJJ

Selective Catalytic Reduction involves injecting ammonia into the flue gas before the gas reaches

a catalyst, at a specific temperature. The catalyst lowers the energy required to complete the

reaction ofthe ammonia with the NOx to form nitrogen and water, therefore the catalyst can be

placed in a lower temperature zone ofthe boiler. The most common catalysts are a

vanadium/titanium composition, with vanadium pentoxide (V205) as the active catalyst and a

titanium support, and operate at about 750F in hot side SCR systems. Zeolite catalysts are

crystalline aluminosilicate compounds and can operate at a lower temperature, typically found

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

Power and Dvnegy Midwest Generation, Inc.

]]j See Appendix A, Table 1.

7Ji See U.S. EPA, Office of Air and Radiation, Office ofAir 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.

JJJ 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 Dvnegy Midwest Generation, Inc.

19
• after the preheater. Zeolite catalysts would be used in cold side SCR systems.~

Selective Catalytic Reduction was in use by 1982 on at least five coal fired powerplants

woridwide.!!J·B' It therefore must be considered 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 ofthe

technology and scale-up would mean that the technology was not available for use on Baldwin's

Unit 3, and therefore was not a candidate for further BACT evaluation.

Flue gas recirculation involves reintroducing flue gas from the economizer or 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.!JI All of

these installations appear to be designed to meet an emissions limit of0.7 poundsIMMBTU.§1'

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

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

b. . Cost Analysis

This section presents costs for the installation ofLNBs at Baldwin Unit 3.~ A state-of-the-art

See U.S. EPA, Office ofAir and Radiation, Office 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/dirllutboiler.pdf.

!!J 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.

B' See Ando, Jumpei, "S02 and NOx Removal for Coal Fired Boilers in Japan," presented at the

Seventh Symposium on Flue Gas Desulfurization, May, 1982.

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

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

Ibid.

OFA was excluded from further analysis because installations using OFA, in 1982, were

emitting at about the same rate as Baldwin Unit 3 was, i.e. 0.7 pound/MMBTU.

20
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•

LNB in 1982 would have been capable ofreducing 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 ofNO. 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 ofEnvironmental

Protection issued permits in 1990 and 1991 that were based on a cost effectiveness of

$13,200/ton.B' When converted to 1982 dollars, the New Jersey permits would require controls at

a cost effectiveness of$1O,600/ton.~ Also, in 1982 the South Coast AQMD (SCAQMD)

adopted a revision to its air 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 ofthese

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

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

N02. The plan shows a number of control measures, some ofwhich 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

.!lli See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02'

NO. and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with

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

'f!J See Keystone Cogeneration Facility BACT for Nitrogen Oxides Addendum, June 1990,

ENSR Consulting and Engineering.

See http://www.enr.comlcost/costcci/asp for cost adjustments.

Final Air Quality Management Plan, 1982 Revision, South Coast Air Quality Management

District and Southern California Association ofGovernments, October 1982.

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

BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier

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

address: http://www.epa.gov/rgytgrnj/programs/artdlair/nsr/nsrrnemos/t2bact.pdf

21
• examples above, and similar to or less than the costs for most ofthe control measures in the

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

c. Other Environmental Impacts

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

d. Conclusion

In summary, I conclude that an emission rate of0.40 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.!I

The following emissions control options were available for consideration in 1982.

1. Electrostatic Precipitator (ESP)

•

a.

2. Baghouse

Technical Feasibility

•

An ESP was in use on Baldwin Unit 3 in 1982. It was therefore, technil;aUy feasible and

available. A baghouse is also a feasible option. Several facilities were reported to be using

baghouses in '1982, and achieving limits as low as .005 gr/ACF.2Y (This equates to 99.7% control

at Baldwin Unit 3.P Baghouses were therefore also technically feasible and available.

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

2.!1 Department ofEnergy, Energy Information Administration (Form EIA-767) for 1982.

IPPRO-Ol 04439-0104464.

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

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

2JI See Table 7 for derivation of control level.

22
•

•

•

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

at Baldwin Unit 3.p Baghouses were therefore also technically feasible and available.

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

permitted emission rate for the Harry Allen Station (where a particulate matter emission rate of

0.015 pound/MMBTU was required, based on 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 ifdata were submitted demonstrating that the ESP was likely to be able

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

1982.2JI IfIllinois 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 ofthe art (i.e. to about 99.7%

control), the costs would likely have been substantial.

b. Conclusion

I have concluded that BACT for PM at Baldwin unit 3 in 1982 would have been an emission rate

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 I: 1985

Unit 1 is a cyclone fired boiler with a gross output rating of 584 megawatts (MW)29' and began

operation in I 970.'!1J It is designed to fire 267 tons per hour of coal2!' with a heating value of

'l1J See report of William Ellison, PE, Ellison Consultants, developed in connection with United

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

2]j See Table 7 for derivation of control· level.

2.*' See EPA permit for Harry Allen Station, NY-77-Oland associated National Ambient Air

Quality Impact Report.

2JI Department ofEnergy, Energy Information Administration, (Form EIA.-767) for year 1982.

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

'!1J Ibid.

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

23
• I985 ..!.Q9'

The available control technologies are the same as those that were potentially applicable to Unit

3 in 1982.

a. Technical Feasibility

By 1985, at least thirty-five additional (compared to 1982) coal fired powerplants were in

operation with scrubbers to remove S02 from their exhaust gas. Most ofthese scrubbers were

wet limestone or wet lime buffered with magnesium oxide.!illJ·!Q5' These two types ofscrubbers

were technically feasible in 1985.

b. Cost Analysis

•

•

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

study conducted by Illinois Power in 1991 to install flue gas desulfurization systems on Unit 1.!Q}f

Most ofthe methodology used in 1991 would also apply to Unit 1 in 1985. According to that

study, capital costs for the wet limestone scrubber are estimated to have been approximately

$189 million..!Q1' 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 ofwet lime scrubber buffed with magnesium oxide shows it to be more

.!.Q9' See Expert Report ofRanajit (Ron) Sahu, April 2002, compiling CEMS data submitted by

Illinois Power Company to U.S. EPA.

.!Q!I See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCR Installations,"

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

Inc.

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

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

http://www.eia.doe.gov/cneaf/electricity/epav2/html_tables/epav2t30pl.html and following

pages

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

Volumes I-IV ofProposal for Full-Scale Demonstration ofIntegrated Flue Gas Desulfurization

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

0129035, IPPRO-0128096-0128265, IPPRO-0127849-0128091, IPPRO-OI27567-0127848.

.!Q1' See report ofDan Mussatti and Lany Sorrels, "Estimated Costs for the Installation ofS02'

NO and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with x .

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

24
•

•

•

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

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

96,800 tons per year ofS02' 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. Ofthose

where a dollar per ton cost effectiveness was listed, the range (once converted to 1985 dollars) is

$155 to 4715/ton..!Q]j 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..!.Q.§' That

guidance used $1 O,OOO/ton as an upper bound for BACT cost effectiveness. When that value is

converted to 1985 dollars it becomes $6,581/ton. The estimated costs for wet limestone scrubbing

at Baldwin Unit 1 in 1985 is at the low end ofthe range ofthese permits and EPA guidance. The

cost is therefore not unreasonable.

c. 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 ofscrubbers.

d. Conclusion

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

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

a wet limestone scrubber removing 95% ofthe 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)..!.!9'

Ibid; also see http://www.enr.com/cost/costcci.asp for cost adjustments.

.!Q9' See Table 8b for calculations.

.!Q7I See Table 11, Cost Effectiveness ofBACT Determinations for S02'

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

BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier

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

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

!Q2' See Table 8b for calculations.

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

25
• 2. Nitrogen Oxides

•

•

As of 1985, Baldwin Unit 1 had no controls in place for NO. emissions..!..!JI Unit I's NO.

emissions are estimated to have been approximately 1.8 pounds per million BTU..!..!1I The relevant

NSPS requirement was an emission rate 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 ofLNBs, OFA, SCR and SNCR. LNBs were not

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

boilers. As to OFA, from the vantage point of2001, for cyclone fired boilers, OFA would appear

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

place by 1985.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 to1982, by 1985, SCR had been used for coal fired boilers for at least five

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

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

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.illJ Planned reduction rates are not available for all ofthese facilities, but for a subset in

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

.!..!JI Department ofEnergy, Energy Information Administration (Form EIA-767) for 1985.

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

Illinois Power Company to U.S. EPA.

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

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

in the relevant timeframe.

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

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

illJ See Ando, Jumpei, "S02 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 ofEnvironmental

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

September 1985.

26
•

•

•

early stages of SCR development had been solved by this time.ill Two German facilities that

would begin operation in 1986 were likely under construction.ill' Also, by 1985, SCR had begun

to be used in the United States. For example, use ofSCR, by 1984, resulted in a Lowest

Achievable Emission Rate (LAER) emission rate for combined cycle gas turbines.!.!2t,.Jl!)'

An additional technology that would have been considered in 1985 is Selective Non-Catalytic

Reduction (SNCR). This process involves injection of ammonia into the combustion chamber at

a point where the temperature is in a precise range:illJ SNCRsystems 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 permitted using SNCR..ill' However, none ofthese were

cyclone fired boi1ers..!11' Therefore, I would conclude that SNCR was not available in 1985 for

ill Ibid, page 5-2.

ill' See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2,'SCR Installations,"

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

Inc.

!.!2t Personal conversation with Robert Pease, Air Quality Analysis/Compliance Supervisor,

South Coast AQMD, September 19, 2001. Mr. Pease visited Japan in June 1984 to observe the

operation ofSCR 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.

ll9' 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.

ill! See U.S. EPA, Office ofAir 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.

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/dirl/utboiler.pdf.

ill{ References: PSD permit #s SE 85-01, 85-05, SJ 85-06, SJ 85-07, SJ SE 86-04, SJ 86-08,86-

09.

ill' See report 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
• use on cyclone fired boilers.

In summary, SCR was the sole NOx control technology available for cyclone fired boilers in

1985. Moreover, a 55% reduction in emissions was well demonstrated for SCR based on the

technical feasibility above. However, there is little infonnation in the literature as to the

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

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

mid '80s were less capable. In order to account for this lesser level of effectiveness ofthe SCR

system during load changes, I assigned slightly less efficiency, 50%, to the SCR system, which

could have been easily achieved on Baldwin's Unit 1 in 1985. A 50% reduction applied to

uncontrolled emissions of 1.8 pound/million BTU yields an emission rate 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.illI Since that study was conducted in 1990, the costs

were adjusted to reflect 1985 dollars..The capital cost ofSCR in1985 is estimated to be $88.6

million, and annual operating costs are estimated to be $3.43 million. The annualized cost would

be $20.2 million..!l9' This yields a cost effectiveness of $1368/ton reduced.m.@ 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 ControlTechnologies

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

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

ill! See report of Dan Mussatti and Lany Sorrels, "Estimated Costs for the Installation ofSOz,

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.

.!l9' Ibid.

gy 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

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

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

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

years ofoperation. See "Development and Commercial Operating Experience ofSCR 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/pggltt/pdfIBR-1665.pdf.

28
•

•

•

85% ofNO" from the exhaust stream. In contrast, a 55% reduction ofNO" 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 ofthese likely cost reductions, our cost

estimate did not take the lower removal rate into account. Therefore, these cost estimates are

likely to be quite conservative.

This cost compares favorably to some of the same relevant benchmarks mentioned above. For

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

1991 that were based on a cost effectiveness of $13,200/ton. When converted to 1985 dollars, the

New Jersey permits would require controls at a cost effectiveness of $11 ,700.!l2J Also, in 1982

the South Coast AQMD (SCAQMD) adopted a revision to its air quality management plan.1ill'

That plan adopted control measures in order for the area to meet the National Ambient Air

Quality Standards (NAAQS) for nitrogen dioxide (N02). Control measures for areas violating

the NAAQS apply to a broad range ofsource categories, and are almost always retrofit measures.

Consequently, the costs ofthese measures are generally less than BACT costs. The Los Angeles

area, which is part ofthe jurisdiction 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 NO" at refineries being

modified to meet EPA mandates for making cleaner burning gasoline.1l!J That guidance used

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

to1985 dollars it becomes $6,620/ton.

The average cost per ton for NO" reductions usingSCR at Baldwin Unit 1 in 1985 is

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

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

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

c. Other Environmental Impacts

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

119' Final Air Quality Management Plan, 1982 Revision, South Coast Air Quality Management

District and Southern California Association ofGovemments, October 1982.

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

BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier

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

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

29
• SCR and SNCR use ammonia, which could cause environmental effects 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

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 I985,illJ it appears that the ESP was in need ofsignificant maintenance or repair. Illinois

Power also performed periodic tests ofthe ESP. Based on the 1984 tests, I estimate emissions to

have been approximately 580 pounds per hourlli' but, based on other tests performed before and

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

been as high as 879 pounds per hour in 1985.

• a. Technical Feasibility

•

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

Baldwin Unit 1:

- Replacement of current ESP with new ESP or baghouse,

- Upgrade ofESP.

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

illJ See EIA Reports numbered IPPRO-OI04246; IPPRO-0104275; IPPRO-OI04304; IPPRO0104333; IPPRO-OI04370; IPPRO-OI04404; IPPRO-OI04456; IPPRO-0104457; IPPRO0104480; IPPRO-O104481; IPPRO-O104503 and IPPRO-O 104504.

lli See Summary of Stack Test Data (0.1 poundIMMBTU); 5,824 MMBTU/hr 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-OOI8582;

IPPRO-OOI6835; IPPRO-0021387; IPPRO-0070999.

30
•

•

•

For this analysis, I have assessed only the option ofreplacing the ESP with either a new ESP or a

baghollse. In 1991, Illinois Power analyzed the options to increase particulate control at Units I

and 2.illI They concluded that a replacement ESP would be more cost effective than an upgrade

ofthe existing ESP. Illinois Power did not analyze the cost ofreplacing the ESP with a baghouse.

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

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

another 30 years ofservice."ilii' 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 ofits useful life and that a new or refurbished control device would be soon be

needed.

1. Baghouse

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

particulate control with a baghouse. By 1985, at least 29 coal fired powerplants had installed

baghouses designed to achieve levels ofPM less than 0.01 grain/ACF (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 l.lli' An emission rate of.003 gr/ACF is equivalent to 99.7% control at Baldwin Unit l.lli'

11. ESP

As of 1982, Illinois Power operated an ESP on Unit 3 with a removal efficiency 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 JPPRO-0058136.

lli' Ibid., page II-I. IPPRO-0058092.

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

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

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

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

ill' See Appendix A, Table 4b: Emissions Calculations and Cost Effectiveness for Particulate

Matter in 1985.

See Table 4c for calculations.

31
•

•

•

Based on a design to remove 99.6% ofparticulate matter (based on the capability ofa baghouse,

as discussed in the 1982 analysis, above), an ESP is estimated to have an annualized cost of

about $19 million (and a capital cost of$105 million)..!i1I 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 ofthe baghouse would be

$81l/ton.

Comparable cost effectiveness values are not available for cyclone fired boilers (which have

much lower inlet PM loadings than 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% ofPM. 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 I (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 I in 1985 would have been an

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

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

.!1!J See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02'

NO, and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with

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

ill' Ibid.

ill! Department ofEnergy, Energy Infonnation Administration (Form EIA-767) for 2000.

lli' See Table 4b for calculations.

32
• C. BACT Determination for Baldwin Unit 2: 1988

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

in 1973..!i9' It was designed to fire up to 267 tons per hourill of coal with a heating value of

10,460 BTU per pound.ill'

1. SOl Control

As of 1988, Baldwin Unit 2 was uncontrolled for emissions ofS02, and was burning coal with a

sulfur content of 3%.H2I

a. Technical Feasibility

•

•

Control options for S02 control in 1988 were similar to the options available in 1985, as I

discussed previously (see Baldwin Unit 2, 1985, above). However, by 1988, powerplant owners

had more experience with all the scrubber options. In addition, many new facilities had come on

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

were in operation in the U.S. by the end of 1988. Most ofthese scrubbers were operating at a

removal efficiency of 80 to 95%..ll!Y 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·.wJ Since there was only one powerplant operating at 97%, I continued to analyze scrubber

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

Technologies, Inc. December, 1987. IPPRO-00151120

ill' Department ofEnergy, Energy Infonnation Administration (Form EIA-767) for 1985.

ill Ibid.

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

H2I Department ofEnergy, Energy Information Administration (Form EIA-767) for 1988.

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

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

http://www.eia.doe.gov/cneaf/electricity/epav2/html_tables/epav2t30pl.html and following

pages

.wJ See report ofWilliam Ellison, PE, Ellison Consultants, "Table 1, FGD Installations,"

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

Inc.

33
• options based on 95% control.

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

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

b. Cost Analysis

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

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

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

limestone scrubbing in 1988. Capital costs for the limestone system would beapproximately

$204 million (1988 dollars). Operating costs would range from $3.8 million and 5.4 million,

depending on whether waste from the scrubber system would have been sold or not. When these

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

The scrubber system would remove approximately 96,800 tons per year ofS02' Therefore, the

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

•

•

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

effectiveness of eighteen powerplants peITIlitted between 1979 and 1999 with BACT

requirements for scrubbers. Ofthose 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 $1 O,OOO/ton as an upper bound

for BACT cost effectiveness. When that value is converted tol988 dollars it becomes $7,149/ton.

The estimated costs for wet limestone scrubbing at Baldwin Unit 2 in 1988 is at the low end of

the range ofthese permits and EPA guidance. The cost is therefore not unreasonable.

c. Other Environmental Impacts

Wet scrubbers produce a sludge that 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 ofscrubbers.

d. Conclusion

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

ill' See report of Dan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02'

NO. and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with

United States v. Illinois Power and Dynegy Midwest Generation, Inc.; cost data adjusted based

on http://www.enr.com/cost/costccLasp.

ill! See Table 11, Cost Effectiveness ofBACT Determinations for S02'

34
•

•

•

emission rate of0.30 pound/million BTU,!~ 30 day rolling average, based on the use of a wet

limestone scrubber removing 95% ofthe 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).illI

2. NOr Control

Like Unit 1, as of 1988, Baldwin Unit 2 had no controls for NOx emissions.lli'

a. Technical Feasibility

For Unit 2 in 1988, I again considered the feasibility ofLNBs, OFA, SNCR and SCR. Ofthese

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

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

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

had been demonstrated by 1988 on a number offacilities 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 NOx'.!.3' Emissions reductions of approximately 50% were expected at these

facilities, and the permits included emissions limits in the range of0.09-0.15 pounds/million

BTU.illI..lliY

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

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

ill' See Table 8c for calculations.

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

lli' Department ofEnergy, Energy Information Administration (Form EIA-767) for 1988.

ill See report ofWilliam Ellison, PE, Ellison Consultants, "Table I, FGD Installations,"

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

Inc.

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

illJ Ibid.

.lliY See Kern County Air Pollution Control District, Engineering Analysis ofMt.PosolPyropower

Cogeneration Facility, November 1986, page 67. "...an emission rate of0.092 pound

NO/MMBTU satisfies NOx LAER requirement."

35
•

•

•

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

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

commercial operation ofSCR systems for NOx control.illI These installations were across a

wide range 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%..!§' 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. 1M'

Because all but one ofthese Gennan facilities had SCR with design NOx reduction levels of

approximately 80% or greater,ill! I have detennined that level ofreduction 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 study!§.§' 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.

ill;' See ENSR Consulting and Engineering, "Keystone Cogeneration Facility BACT for Nitrogen

Oxides, Addendum," June 1990.

ill' See report ofWilliam Ellison, PE, Ellison Consultants, '·Table 2, SCR Installations,"

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

Inc.

~Ibid.

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

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

Inc.

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

by Bums & McDonnell, Kansas City, MO.

J!ilJ See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02'

NO and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with x

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

36
•

•

•

percent capacity factor, and an SCR system that removes 80% ofthe inlet NO•.@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 perfoffi1ed 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 to1988 dollars, the New Jersey peffi1its would

require controls at a cost effectiveness of$12,640.W Also, as noted above, in 1982 the

SCAQMD adopted an air quality management plan..!1!¥ establishing control measures to help bring

the area into compliance with the NAAQS. For rules projected to be adopted between 1983 and

1986, the cost effectiveness was between $7001ton and $7,600/ton in 1987 dollars. When those

values are adjusted to 1988 dollars, the range becomes $713 to $7,750/ton. Lastly, in 2001 EPA

issued guidance related to presumptive BACT for NO. at refineries being modified to meet EPA

mandates for making cleaner burning gasoline..!2!I That guidance used $1O,OOO/ton as an upper

bound for BACT cost effectiveness. When that value is converted to1988 dollars it becomes

$7, 150/ton. The estimated costs for SCR at Baldwin Unit 2 in 1988 is at the low end ofthe range

ofthese peffi1its and EPA guidance. The cost is therefore not unreasonable.

c. 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 ofits lower other environmental impacts.

d. Conclusion

Based on the analysis above, I conclude that an emission limit of0.36 poundslMMBTU, 3 hour

average based on the use ofSCR with 80% removal was BACT for Unit 2 in 1988. Compliance

.!§' Ibid.

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

.!l9' Final Air Quality Management Plan, 1982 Revision, South Coast Air Quality Management

District and Southern California Association ofGovernments, October 1982.

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

BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier

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

address: http://www.epa.gov/rgytgrnj/programs/artd/air/nsr:Lnsffi1emos/t2bacLpdf

37
• 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.1B'

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

Baldwin Unit 2:

- Replacement of current ESP with new ESP orbaghouse,

- Upgrade ofESP.

a. Technical feasibility

•

•

For this analysis, I have again assessed only the option ofreplacing the ESP at Baldwin with

either a new, more efficient ESP or a baghouse. The ESP for Unit 2 was designed for 99%

removal efficiency, but had performed at significantly lower removal efficiencies,.!DI 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, ofthe existing ESP (Illinois Power did not analyze the

option ofreplacing the ESP with a baghouse).lli' 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 ofPM less than 0.01 grain/ACF (actual cubic foot).ill' Of

m See EIA Reports numbered IPPRO-OI04246; IPPRO-0104275; IPPRO-OI04304; IPPRO0104333; IPPRO-OI04370; IPPRO-OI04404; IPPRO-0104456; IPPRO-0104457; IPPRO0104480; IPPRO-0104481; IPPRO-OI04503 and IPPRO-OI04504.

ill' Department ofEnergy, Energy Information Administration (Form EIA-767) for 1988.

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

IPPRO-0058084 through IPPRO-0058136.

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

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

38
•

•

•

those 32, many were designed to achieve levels of between 0.001 and 0.005 gr/ACF.1.Th' An

emission rate of.003 gr/ACF is equivalent to 99.7% control at Baldwin Unit l.m

ii. ESP

As 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 ofinstalling a new

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

capital cost)..!l!¥ A baghouse with similar capabilities would have had an annualized cost of $11.6

million ($55 million capital cost)..!221 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 ofthe baghouse would have been $857/ton.

Comparable cost effectiveness values are not available for cyclone fired boilers (which have

much lower inlet PM loadings than tangentially fired boilers). However, construction cost data

are available for powerplants constructed in the 1988 timeframe. These data show that the

estimated construction cost for a baghouse is similar to that ofother 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% ofPM. Tampa

Electric's Big Bend Plant (445 MW), referenced in my 1985 analysis, is also relevant in 1988. Its

capital cost was 76.8 million..!!9' The costs for a baghouse at Baldwin Unit 1 in 1988 are therefore

note unreasonable.

illf 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.

.!l!¥ See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02,

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

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

ill Ibid.

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

39
• 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 of0.003 pound/million BTU based on the use ofthe use ofa

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

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

D. BACT Determinations for Baldwin Station: 2002

I. BACT Determination at Baldwin Units I and 2

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

the purposesofthis 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 ofthe results ofthese upgrades and changes are

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

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

the Clean Air Act.

a. S02 Control

To be analyzed together with Unit 3, below.

b. NO. Control

The available control options are:

1. SCR

2. OFA

3. SNCR

4. Coal or Gas Rebuming

5. Optimization system

.!!!! Joint Construction and Operating Permit issued February 19, 1999 (EPA 5776); Operating

Permit issued January 5, 1996 (IPPRO-OOI9014); Operating Pennit issued December 4, 1998

(IPPRO-OOl9233); Operating Pennit issued June 20, 1996 (IPPRO-0018725); Construction

Permit issued April 14, 1998 (EPA 5775); Operating Pennit issued June 26, 1997 (IPPRO0019094).

40
• I. Technical Feasibility

•

•

SCR systems are now in wide use in the U.S. and worldwide, and have been applied to meet

BACT emission limits for coal fired powerplants since I990.ill' Reported reduction efficiencies

are up to 90%. At least 229 units at coal fired powerplants worldwide, including at least thirteen

in the U.S., are now using SCR to control NOx emissions.~rn

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

Baldwin Units I and 2 in approximately I999.ill! OFA can reduce emissions by as much as 50%

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

installations..!§'

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

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

then added above the rebum zone to complete fuel burnout. The reburn fuel can be 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 zoneto a different area of

the furnace. Utilizing all the carbon in the fuel has been a problem in the past when pulverized

coal is the reburn fue1.illI 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 ofEnvironmental Protection, permit number 01-89-3086,

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

See "Performance ofSelective Catalytic Reduction on Coal-Fired Steam Generating Units,"

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

http://www.epa.gov/airmarkt/arp/nox/scrfinal.pdf.

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

ill! Deposition testimony ofAric Diericx, November 10, 2000.

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

document may be found at website address

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

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

a 50% reduction compared to the uncontrolled rate of 1.8 pourids&:1MBTU.

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/ttnlcatc/dirl/utboiler.pdf.

41
• operational problems.@

SNCR has been described earlier. Emissions reductions of up to 80% of NOx have been

demonstrated using SNCR on coal fired boilers.rn

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 information to a plant's

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

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

systems..!2.!¥

•

•

Some ofthe 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 OFA may be

followed by an SCR system. OFA and rebuming (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 information is available as to the effect

ofoptimization systems in conjunction with other emissions reductions retrofits.

Because ofthe 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 OFA would be a more cost effective option than rebuming;..®

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

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

ill' See "Demonstration ofCoal Rebuming for Cyclone Boiler NOx Control," McDermott

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

http://www.mtiresearch.com/expemce.html#Demonstration ofCoal Reburn.

See report ofWilliam Ellison, PE, Ellison Consultants, "Table 2, SCR InstaIlations,"

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

Inc.

.!2!¥ See "What's New in the Power Industry," World Bank, 2001, found at website address

http://www.worldbank.orglhtml/fpd/emJpower_industryIO.htm.

!2.Y See Illinois Power "Gas at Baldwin" report, dated May 1990 (IPPRO - 0003712).

42
• amenable to the use of an optimization system.

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

limit, I considered both the effectiveness ofthe controls as well as the fact that this would be a

retrofit to a thirty year old powerplant..!2Y Based on I1linois Power's experience to date on Units

I and 2, I determined that the OFA system, operating together with the optimization system,

would easily achieve a 50% reduction. An SCR system is capable 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 ofthese powerplants are subject to the BACT

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

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

controls emit far more NOx than other coal burning technologies, and ofthe 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.perfonnance

of demonstrated NOx control technologies.

Based on the performance ofthe technologies discussed above, and the reductions achievable

from these technologies, the "top" option for NOx control for Units 1 and 2 would be the

combined use 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 ofOFA and SCR. This rate assumes that OFA 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 ofNOx

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

combination ofcontrols could result in removal of92% 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.

.!2Y See PSD Appeal No. 94-1 (Masonite Corporation), 5 EAD 551, page 10. This document

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

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

See 40 C.F.R. § 60.40a (1979), "Standards ofPerformance for Electric Utility Steam

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

43
• II. Other Environmental Effects

~: .'

Most ofthe options for NO. emissions control would have no significant other environmental

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

for Unit 1 and $8.7 million for Unit 2.illJ Based on a controlled rate of 0.14 pounds/MMBTU

(controlling approximately 10,000 TPY ofNO.), the cost effectiveness ofthese controls would

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

of controls is conservative because I included the cost ofinstalling OFA systems at Units 1 and 2,

even though both already have OFA installed.

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

as noted above, the New Jersey Department ofEnvironmental Protection based on a cost

effectiveness of$13,200/ton (in 1990/91 dollars). EPA's guidance related to presumptive BACT

for NO. at refineries used $1 O,OOO/ton as an upper bound for BACT cost effectiveness. In

comparison to these benchmarks, the cost ofSCR, OFA and an optimization system is not

unreasonabIe.

•• iv. Conclusion

•

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

BTU, 30 day rolling average,. based on use ofthe combination ofOFA, SCR capable of90%

control, and an optimization system, represents current day BACT for emissions ofNO. at

Baldwin Units I and 2. Compliance with this limit would be monitored via use 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,

NO. and PM Control Devices at Illinois Power's Baldwin Station," developed in connection with

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

!29' See Table 3d for calculations.

44
•

••

•

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 poundlMMBTU. These emission rates reflect

Control of approximately 99.7% (see also PM analyses, 1985 and 1988).!2.9

11. 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 ofin

accordance with regulations for non-hazardous waste.

111. 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 earliertimeframes, (see 1985 and 1988 analyses

above), a baghouse was the least expensive option. The same conclusion was reached for the

present day. Therefore, only options for using a baghouse to control emissions were analyzed. Of

the two baghouse options, the 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.~

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 halfthe size ofthe Baldwin units), built in 1994, reported a capital cost of$38.9

million for its ESP removing 99.8% ofPM.~ Data reported from powerplants constructed

earlier, discussed in the 1985 and 1988 timeframes, also show that the capital cost estimated for a

new pulse-jet baghouse at Baldwin Units 1 and 2 is at the low end compared to these other

powerplants. The cost is therefore not unreasonable.

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

ill' See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation 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 Department ofEnergy, Energy Information Administration (Form EIA-767) for 2000.

45
• lV. Conclusion

I therefore conclude that an emission rate of 0.006 pounds per million BTUlilli' 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. BACT 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.~ The ESP was

upgraded in 2000.ill' Although none ofthe results ofthese upgrades and changes are enforceable

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

result ofIllinois Power's need to comply with acid rain (Title IV) provisions ofthe Clean Air

Act.

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

The following options are available for S02 control:

b. Wet Limestone Scrubbing

c. Wet Lime scrubbing buffered by Magnesium Oxide

d. Dry Scrubbing.

• 1. Technical Feasibility

•

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

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

efficiencies 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 oflime slurry is sprayed into the flue gas. Heat from the flue gas evaporates the moisture in

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

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

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

See Table 4d for calculations.

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

Operating Permit issued June 26, 1997. IPPRO-0019094.

Wi Ibid., and IP Permit Application dated January 19, 1993. IPPRO-0032541 .

46
• to 90% with PRB coal have been demonstrated.lli'

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

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

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

with less than I% sulfur coal are removing 95% ofthe S02 from the flue gas. For example,

Bonanza Unit 1-1 (owned by Deseret Generation and Transmission Co-op) is using coal with a

0.5% sulfur, and removing 95% ofthe emitted S02 with a wet limestone scrubber.~

All three scrubbing technologies are technically feasible and available. Both wet scrubbing

technologies have been demonstrated to remove over 95% ofS02 from western coal, and up to

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

to 90% ofS02 from western coal. Wet scrubbing is therefore the "top," or most effective option.

n. 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 ofscrubbers.

iii. Cost Effectiveness

The capital cost to install a wet limestone scrubbe~ today would be $71.4 million at each of

Baldwin units. Annual_operating costs for Units 1 and 2 would be $8.0 to 8.3 million per unit;

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

assumed capacity factor for Unit 3). Total annualized 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

lli' See "Retrofitting Lime Spray Dryers at Public Service Company ofColorado," R. Telesz et.

aI., Presented to Power-Gen International 2000, November 200. This document may be found at

website address: http://www.babcock.com/pgglttlpdflBR-1707.pdf

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

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

http://www.eia.doe.gov/cneafJelectricity/epav2/htmI_tables/epav2t30p1.html and following

pages.

?2!i 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 Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02,

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

47
• 95%, the cost effectiveness, therefore, would be approximately $652/ton for Units 1 and 2, and

$570/ton for Unit 3.£Q!Y

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

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

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

Of those where a dollar per ton cost effectiveness was listed, the range (once converted to 2001

dollars) is $234 to 7129/ton.W! Also, as noted, EPA's guidance related to presumptive BACT for

NOx at refineries used $1 O,OOO/ton as an 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 ofthese permits and EPA guidance. The cost is therefore not unreasonable.ill

IV. Conclusion

Based on the above information, I have determined that BACT for S02 at Baldwin station today

is an emission rate of 0.095 pounds per million BTU based on 95% scrubbing and assuming use

of coal with 0.6% sulfur.ill Compliancewith this limit would be monitored with a CEMS.

b. NOx Control

The available control options are:

• 1.

2.

3.

3.

4.

5.

LNB

SCR

OFA

SNCR

Coal or Gas Rebuming

Optimization system

•

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

See Table 8d and 8e for calculations.

M!Jf See Table 11, Cost Effectiveness ofBACT Determinations for S02' Most ofthe higher cost

effectiveness values attach to facilities burning lower sulfur coal, while lower cost effectiveness

correlates to facilities burning higher sulfur coal.

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 $1 OOIKW,

Douglas Smith, Senior Editor, Power Engineering, September, 2001.

ill Calculated by using a controlled emission rate of 533 poundlhr and 5587 million BTUIhr.

48
• I. Technical Feasibility

•

•

As with Units I and 2, several NOx control options may be used singly or in combination at

Baldwin Unit 3. The same options discussed above as currently feasible for NOx control on Units

I and 2 are technically feasible and demonstrated for use on Unit 3. In addition, as I discussed in

the 1982 time frame, low NO. burners are also technically feasible and available for tangentially

fired boilers such as Baldwin's Unit 3. In fact, Illinois Power installed a low-NO. burner in Unit

3 in 1994. Emission rates from IP's 1994 installation were about 0.3 pound/million BTU~.

Emission rates from LNBs have improved dramatically since the 1994 installation. At least three

manufacturers have demonstrated LNBs that attain NO. emission rates around 0.15

pound/million BTU.illf.6.!.1.ill! OFA is often an integral part ofthe design of newer LNBs (in fact,

the currently installed LNBs at Unit 3 include integral OFAlli'), or maybe 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.ill They may also use optimizations systems to enhance

boiler efficiency and reduce NOx '

See "Emissions Data and Compliance Reports," USEPA. 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 NO., 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

ofNOx 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 lb/MMBTU NOx Emission Level Firing

a Broad Range ofCoals," A.D. La Rue et. al., Presented at EPRI-DOE-EPA Combined Utility

Air Pollutant Control Symposium, August 1999. This document can be found at website

address:http://www.babcock.comlpgglttlpdf7BR-1682.pdf.

lli' Deposition testimony ofAric Diericx, November 10, 2000.

ill See "B&W's Experience Reducing NO. Emissions in Tangentially;;,Fired Boilers-2001

update," A. Kokkinos et. al., Presented to Power-Gen International 2001, December 2001. This

document may be found at website location: http://www.babcock.com/pgglttlpdf7BR-I726.pdf.

ill' See, eg, "PREVENTION OF SIGNIFICANT DETERIORATION CONSTRUCTION

PERMIT 888 REVIEW DOCUMENT," issued to Kansas City Power and Light for the Hawthorn

Generating Station.

49
• Just as with Units I and 2, some ofthe above technologies may be used effectively in

conjuncti.on with one another, and feasible combinations therefore should be considered.

Specifically either SCR or SNCR may follow almost any other NOx emissions control

technology.

Several powerplants have recently been built or modified with a combination ofLNBs andSCR.

For example, the Chambers Cogeneration facility, an new plant permitted in 1990, has both

LNBs and SCR,ll?! as does the Hawthorn facility, a new plant permitted in 2001.ll9'

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% ofthe NOx exiting the burner,

emissions of 0.04 pound/million BTU are readily achievable using the current LNB.

Replacement ofthe current LNB with a state-of-the-art LNB would, together with the use of

SCR, allow Unit 3 to reach an emissions level of0.015 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

pounds/MMBTU 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.llit 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'

• 11. 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

ll?! See New Jersey Department ofEnvironmental Protection, permit number 01-89-3086, issued

on December 26, 1990 to Chambers Cogeneration Limited Partnership.

ll9' See "PREVENTION OF SIGNIFICANT DETERIORATION CONSTRUCTION PERMIT

888 REVIEW DOCUMENT," issued to Kansas City Power and Light for the Hawthorn

Generating Station.

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

m 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/pggltt/pdf/BR-1698.pdf

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

50
•

•

•

large amounts. However, ammonia slip is limited by design to about 3 ppm, so effects would not

be likely to occur.

111. Cost Effectiveness

The top BACT option be the use ofLNBs, SCR, and an optimization system. The annualized

cost 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.lli'·lli'

The annualized cost of new LNBs would be $1.5 million, and the annualized cost of an

optimization system would be $18,000.ill'·ill! The total annualized cost would be $9.8 million,

and would reduce approximately 3,900 TPY (this reduction is substantially smaller than potential

reductions at Units I and 2 because Units 1 and 2 have a substantially larger uncontrolled NOx

emission rate). The cost effectiveness ofthis combined option would be $2539/ton.ill'

The costs of achieving 0.02 poundIMMBTU 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).m

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. lllinois Power and Dynegy Midwest Generation, Inc.

ill' Ibid.

ll2J Deposition testimony of Aric Diericx, November 10,2000.

ill' See report ofDan Mussatti and Larry Sorrels, "Estimated Costs for the Installation ofS02,

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

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

ill Information from manufacturers ofthese 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, DRS 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."

ill' See Table 3e for calculations.

lliJ See Table 10, BACT Cost Effectiveness for NOx Controls.

51
• 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 ifthey

could demonstrate that 0.020 is not achievable. I would provide this flexibility because this is a

retrofit, and therefore more difficult. Compliance with this limit would be monitored with a

CEMS.

c. Particulate Matter

Control technologies available for particulate control are the same as those discussed earlier, with

improvements in efficiency and reliability. Emission rates for new facilities controlled by ESPs

and baghouses range from about 0.015 to 0.02 pound/MMBTU.ru¥ Illinois Power upgraded its

ESP in 1999 as part ofits preparation to begin burning PRB coal.ill As I discussed in the 1982

case above, the original perfonnance ofUnit 3 was far better than the performance ofUnits 1 and

2. Although we currently have no data about the current performance ofUnit 3's ESP, it appears

that the original design, together with the upgrade, may be capable ofmeeting a limit of0.0 IS,

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 ifthe Unit 3 ESP cannot perfonn at the necessary level to meet BACT. Assuming

an emission rate of 0.015 poundIMMBTU, the capital cost of a new baghouse at Baldwin Unit 3

would be $43.8 million, and the annualized cost would be approximately $10 million. The cost

effectiveness ofthat baghouse would be $69/too. This is similar to other recently permitted

powerplants. For example, the cost estimated for the Chambers Works Cogeneration Project for

PM control (to 0.3 pound/MMBTU) in 1989 was $78/ton.lli' More recently, the KCP&L

Hawthorn Unit 5 permit application proposed use 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 ofthe ESP by adding a field or a "polishing"

baghouse, likely at a substantially lower cost than a new device.

ll9' See National Coal-Fired Utility Projects Spreadsheet, EPA Region 7, March 1, 2002.

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

m See Best Available Control Technology Analysis for Keystone Cogeneration Facility, Bechtel

Power Corporation, October, 1989.

ill' See Prevention ofSignificant Deterioration Construction Permit Application: Replacement of

Unit 5 at the Hawthorn Generating Station, Bums and McDonnell, May 1999.

52
• Conclusion

I therefore have detennined 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