DOE/EIA-0582

Distribution Category UC-98

Electric Utility Phase I Acid Rain Compliance

Strategies for the Clean Air Act Amendments of 1990

March 1994

Energy Information Administration

Office of Coal, Nuclear, Electric and Alternate Fuels

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the Energy Information Administration, the independent statistical and

analytical agency within the Department of Energy. The information contained herein should not be

construed as advocating or reflecting any policy position of the Department of Energy or of any other

organization.
Contacts

This report was prepared by the staff of the Supply

Analysis Branch, Analysis and Systems Division, Office

of Coal, Nuclear, Electric and Alternate Fuels. General

information regarding this publication may be obtained

from Robert M. Schnapp, Director, Analysis and

Systems Division (202/254-5392), or Betsy O’Brien,

Chief, Supply Analysis Branch (202/254-5490). Specific

questions regarding the preparation and content of the

report should be directed to Art Fuldner, coordinator of

the publication (202/254-5321), or contributing authors,

Ronald Hankey (202/254-5333), Thelda McMillian

(202/254-5414), Rebecca McNerney (202/254-5469),

Robert Mumper (202/254-5628), Robin Reichenbach

(202/254-5353), and Larry Spancake (202/254-5344).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

ii Clean Air Act Amendments of 1990
Preface

Section 205(a)(2) of the Department of Energy Organization Act of 1977 (Public Law 95-91) requires the Administrator of the Energy Information Administration (EIA)

to carry out a central, comprehensive, and unified

energy data information program that will collect, evaluate, assemble, analyze, and disseminate data and

information relevant to energy resources, reserves, production, demand, technology, and related economic and

statistical information. To assist in meeting these responsibilities in the area of electric power, EIA has

prepared this report, Electric Utility Phase I Acid Rain

Compliance Strategies for the Clean Air Act Amendments of

1990. The purpose of this report is to provide information on strategies utilities are using to comply with

Phase I of the Clean Air Act Amendments of 1990 and

estimates of the costs of selected utilities for compliance. Compliance strategies are discussed including

technological considerations and costs for the six main

strategies: (1) fuel switching and/or blending, (2)

obtaining additional allowances, (3) installing flue gas

desulfurization equipment (scrubbers), (4) using previously implemented controls, (5) retiring facilities, and

(6) boiler repowering. Impacts on coal demand and

supply are also examined.

The legislation that created the EIA vested the organization with an element of statutory independence. The

EIA does not take positions on policy questions. The

EIA’s responsibility is to provide timely, high-quality

information and to perform objective, credible analyses

in support of deliberations by both public and private

decisionmakers, as well as academia, the Congress, and

the general public. Accordingly, this report does not

purport to represent the policy positions of the U.S.

Department of Energy or the Administration.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 iii
Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

1. Introduction ........................................................................ 1

Units Affected by Phase I ............................................................. 1

Sulfur Dioxide Compliance Strategies .................................................... 1

Contents of the Report ............................................................... 5

2. The Acid Rain Provisions of the Clean Air Act Amendments of 1990 and Their Antecedents ......... 7

The Clean Air Act Before 1990 ......................................................... 7

The Acid Rain Program of the Clean Air Act Amendments of 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

3. Compliance Strategies for Control of Sulfur Dioxide Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Fuel Switching/Blending . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Obtaining Additional Allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Flue Gas Desulfurization Retrofits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Previously Implemented Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Retiring Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Boiler Repowering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Additional Compliance Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Phase I Permit Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

4. Individual Utility Compliance Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Large Plant Compliance Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Specific Utility Compliance Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Appendices

A. Phase I Affected Units of the Clean Air Act Amendments of 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

B. Engineering Characteristics of Retrofitted Flue Gas Desulfurization Units . . . . . . . . . . . . . . . . . . . . . 71

C. Econometric Estimates of Scrubber Retrofit Costs Based on Historical Costs . . . . . . . . . . . . . . . . . . . . 81

D. Current Engineering Estimates of Scrubber Retrofit Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

E. Nitrogen Oxide Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

F. Continuous Emission Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

G. Selection Process and Data Collection for Individual Utility Compliance Costs and Effects for

CAAA90 Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 v
Tables Page

1. Emissions from Fossil-Fueled Steam-Electric Generating Units at Electric Utilities by Census Division

and State, 1992 .................................................................... 2

2. Phase I Affected Coal-Fired Nameplate Capacity and Total Nameplate Capacity by State, 1992 ....... 3

3. Profile of Phase I Compliance Methods ................................................. 6

4. Scrubber Retrofits for Compliance with Phase I ........................................... 6

5. Chronology of Historic Federal Legislation to Control Air Pollution ............................ 8

6. Comparison of Typical Coal Characteristics and Ash Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

7. Impact of Coal Characteristics on Coal Switching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

8. Capital Expenditures for Modifications Associated with Switching to Low-Sulfur Eastern and

Western Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

9. Coal Receipts at Electric Utility Plants by Supply Region and Sulfur Dioxide Level, 1989 and 1992 . . . . 23

10. 1995 SO2 Emission Allowance (Spot Market) Bids at the EPA Auction, March 29, 1993 . . . . . . . . . . . . . . 27

11. 2000 SO2 Emission Allowance (Advance Market) Bids at the EPA Auction, March 29, 1993 . . . . . . . . . . 28

12. 1995 SO2 Emission Allowance (Spot Market) Offers at the EPA Auction, March 29, 1993 . . . . . . . . . . . . 29

13. 2000 SO2 Emission Allowance (Advance Market) Offers at the EPA Auction, March 29, 1993 . . . . . . . . . 29

14. Plants with More Than 1,500 Megawatts of Phase I Affected Capacity, 1992 . . . . . . . . . . . . . . . . . . . . . . 41

15. Characteristics of Selected Phase I Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

16. Costs of Phase I Compliance of Selected Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

17. Effects of Phase I Compliance on Selected Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

A1. Profile of the 261 Generators Affected by Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet Compliance with

Phase I, 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

B1. Number of Retrofit Scrubbers in Sample by State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

C1. Retrofit Scrubber Installed Capital Cost Model Parameter Estimates and Model Performance Statistics . 85

C2. Retrofit Scrubber Installed Capital Costs by Design Sulfur Removal Efficiency . . . . . . . . . . . . . . . . . . . . 85

C3. Retrofit Scrubber Operations and Maintenance Costs by Coal Sulfur Content and Technology Type . . . 86

C4. Pooled Retrofit Scrubber Operations and Maintenance Model Parameter Estimates . . . . . . . . . . . . . . . . 86

D1. Operations and Maintenance Costs for a Scrubber Retrofitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

E1. Typical Nitrogen Content of Selected Fuels from the United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

E2. Comparison of Low-NOx Burner Retrofit Cost Estimates for a 300-Megawatt Unit . . . . . . . . . . . . . . . . . 100

F1. Continuous Emission Monitoring Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

F2. Continuous Emission Monitoring Measurement Techniques by Gas Constituent . . . . . . . . . . . . . . . . . . 104

F3. Continuous Emission Monitoring Components Required for Acid Rain Regulations . . . . . . . . . . . . . . . . 106

G1. Characteristics of Selected Phase I Affected Units by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

G2. Costs and Effects of Phase I Compliance for Selected Affected Units by Utility . . . . . . . . . . . . . . . . . . . 114

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

vi Clean Air Act Amendments of 1990
Figures Page

1. Percentage of Nameplate Capacity Affected by Phase I by State, 1992 .......................... 4

2. Phase I Affected Nameplate Capacity, Coal-Fired Nameplate Capacity, and Total Nameplate Capacity

for States with More than 5 Gigawatts of Affected Capacity by State, 1992 ....................... 5

3. Average Sulfur Content of Coal Shipped to U.S. Power Plants by State of Origin, 1992 . . . . . . . . . . . . . 15

4. Coal-Fired Utility Steam Generator Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

5. 1995 SO2 Emission Allowance (Spot Market) Supply and Demand at the EPA Auction, March 29, 1993 25

6. 2000 SO2 Emission Allowance (Advance Market) Supply and Demand at the EPA Auction,

March 29, 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

B1. Packed-Type Scrubber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

B2. Tray-Type Scrubber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

B3. Spray-Type Scrubber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

B4. Venturi-Type Scrubber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

B5. Number of Retrofit Scrubbers in Sample by Year In-Service, 1972-1990 . . . . . . . . . . . . . . . . . . . . . . . . . . 76

B6. Number of Scrubbers by Type of Technology, 1985 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

B7. Number of Scrubbers by Type of Sorbent, 1985 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

B8. Weighted Average Design Removal Efficiency and Weighted Average Actual Removal Efficiency

by Year, 1985-1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

B9. Weighted Average Availability of Scrubbers by Year, 1985-1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

B10. Average Number of Modules and Average Number of Modules Used at 100 Percent Load by Year

In-Service, 1971-1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

B11. Average Amount of Sorbent Used by Year, 1985-1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

B12. Weighted Average Percent of Plant Generation Used by Retrofit Scrubbers, 1985-1991 . . . . . . . . . . . . . . 79

D1. Conventional Limestone Wet Scrubbing Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

E1. Air Staging in the Burner and the Furnace . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

E2. Principle of Fuel Staging (Reburning) in a Furnace . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

E3. Options for Burner Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

F1. Conceptual Extractive Continuous Emission Monitoring System Design . . . . . . . . . . . . . . . . . . . . . . . . . 104

F2. Conceptual In Situ Continuous Emission Monitoring System Design . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 vii
Executive Summary

The Clean Air Act Amendments of 1990 (CAAA90)—

Public Law 101-549—are the latest revisions to the

Clean Air Act. Among the numerous provisions of the

CAAA90 is Title IV, which requires the U.S. Environmental Protection Agency (EPA) to establish the Acid

Rain Program to reduce the adverse effects of acidic

deposition (acid rain). Acid rain is formed largely from

emissions of sulfur dioxide (SO2) and nitrogen oxides

(NOx) which are emitted primarily by fossil-fueled

electric power plants, other industrial sources, and

transportation sources. The SO2 reduction provisions of

CAAA90 are noteworthy and controversial, because

they represent the first large-scale attempt to set overall

emissions levels using marketable licenses (allowances)

to control emissions, as opposed to regulations that

specify what actions must be undertaken by those

affected (command and control). An allowance permits

the emission of one ton of SO2. The use of allowances

leaves electric utilities with several options for compliance strategies and, thus, introduces flexibility into

compliance plans. Many utilities, because they have

several compliance options, have alternative plans that

can be used to comply with Phase I, depending on the

circumstances.

The Acid Rain Program is divided into two time

periods; Phase I, from 1995 through 1999, and Phase II,

starting in 2000. Phase I mostly affects power plants

that are the largest sources of SO2 and NOx. Phase II

affects virtually all electric power producers, including

utilities and nonutilities. This report is a study of the

effects of compliance with Phase I regulations on the

costs and operations of electric utilities, but does not

address any Phase II impacts.

The CAAA90 specifies 261 generating units1 (mostly

coal-burning) at 110 utility plants that are affected by

Phase I. These units, located in 21 eastern and midwestern States, are high emitters of SO2 and NOx.

However, because of provisions in the CAAA90 that

allow utilities to use other units to substitute or

compensate for those originally specified, additional

In the CAAA90, 261 units were targeted for emissions reductions before 1995, including 4 units at the 953-megawatt Hammond

facility operated by Georgia Power.

1

Table A of the CAAA90 specified 261 electric power generators that were affected by Phase I. These generators are attached to 263

boilers at 261 boiler/generator units. See Appendix A for an individual listing of the 261 generators.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 ix
generator units may be affected by Phase I.2 This

report focuses on the original 261 Phase I affected units

specified in Table A of the CAAA90. During Phase I,

those 261 units will receive an annual allocation of

allowances for SO2 emissions equal to approximately

2.5 pounds of SO2 per million Btu of heat input during

the historic baseline period (the average for 1985

through 1987). For most of the units, the allowances are

lower than historical emission levels. Phase I also

specifies maximum levels of NOx emissions that affected units may emit.

Options to comply with the SO2 limitations of Phase I

are grouped into six categories: (1) fuel switching

and/or blending, (2) obtaining additional allowances,

(3) installing flue gas desulfurization equipment (scrubbers), (4) using previously implemented controls, (5)

retiring facilities, and (6) boiler repowering (Table ES1).

Fuel switching consists of either switching to lower

sulfur coal, blending lower sulfur coal with higher

sulfur coal, or co-firing with another fuel, usually

natural gas. Obtaining additional allowances entails

obtaining a sufficient number of allowances in addition

to the initial allocation so that no other action needs to

be taken.3 The use of scrubbers involves installing

equipment that removes sulfur dioxide from the boiler

flue gas. Previously implemented controls are actions

already taken, usually because of State requirements,

that have already reduced emissions. Boiler repowering

involves replacing an existing boiler with one using a

different fuel or technology that may emit less SO2.

Permanently retiring a facility is also an option. Several

additional strategies are available: energy conservation

(including supply-side and demand-side management),

reduced utilization, and substitution of units. Most

Phase I affected utilities are using one or more of these

in conjunction with their main method of compliance.

The main strategy planned for compliance with the SO2

requirements of Phase I is fuel switching. Utilities

currently plan to change fuels at more than half (about

62 percent) of the affected units. Fuel switching is

Table ES1. Compliance Methods for the 261 Generators Affected by Phase I of the CAAA90

Compliance Methoda

Number

of Generatorsb

Affected

Nameplate

Capacity

(megawatts)

Allowancesc

(per year)

1985 SO2

Emissions

(tons)

Total Phase I

Extension

Allowancesd

Fuel Switching and/or Blending . . . . . . . . . . . 162 53,203 3,315,554 5,455,734 499,202

Obtaining Additional Allowances . . . . . . . . . . 39 14,137 917,573 1,496,406 817,023

Installing Flue Gas Desulfurization

Equipment (Scrubbers) . . . . . . . . . . . . . . . 27 14,101 923,467 1,637,783 2,178,324

Using Previously Implemented Controlse . . . . 25 6,092 333,061 584,307 0

Retiring Facilities ..................... 7 1,342 56,781 121,039 0

Boiler Repowering . . . . . . . . . . . . . . . . . . . . 1 113 4,385 6,713 5,451

Total .............................. 261 88,989 5,550,821 9,301,982 3,500,000

a

These compliance methods are based on information obtained in late 1993.

b

Cincinnati Gas & Electric’s Miami Fort generator 5 has two boilers as does Ohio Edison’s R.E. Burger generator 3. Therefore, the total number

of affected boilers is 263 and the number of affected generators is 261. c

One SO2 allowance permits one ton of SO2 emissions. d

Phase I extension allowances were awarded to (1) control units that install a technology that removes 90 percent or more of their SO2 emissions

or (2) control units and other units that use a different compliance strategy but are associated with the control unit in the extension allowance

application. Extension allowances were awarded for 1995 through 1999. e

Using previously implemented controls includes facilities that have already met required reductions due to existing State regulations or other

reasons.

CAAA90 = Clean Air Act Amendments of 1990. SO2 = Sulfur dioxide.

Source: Compliance Method: U.S. Environmental Protection Agency, Coal Week, Compliance Strategies Review, Georgia Public Utility

Commission, Utility Environment Report, and McIlvaine Utility Forecast. List of Affected Units: Federal Register, Vol. 58, No. 6 (January 11,

1993), pp. 3687-3691. Capacity: Energy Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC, October

1993). 1985 Emissions: U.S. Environmental Protection Agency, National Allowance Data Base, Versions 2.11 (January 1993). Phase I Extension

Allowances: Facsimile from the U.S. Environmental Protection Agency (February 7, 1994).

2

The number of additional units affected by Phase I is not clear for two reasons: (1) on March 12, 1993, petitions for review of the EPA

rules covering substitution and compensating units were filed in the U.S. Court of Appeals; and (2) EPA currently is proposing to revise

these rules for the years 1996 through 1999. 3

Publicly announced Phase I allowance transaction prices have ranged from $178 to $276. “Publicly Announced Phase I Allowance

Transactions,” Compliance Strategies Review 4, 24 (December 20, 1993), p. 4.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

x Clean Air Act Amendments of 1990
favored not only because of the low cost of low-sulfur

coal but also because its usually smaller capital

expenditures make it a more cost-effective compliance

method given the uncertainty associated with compliance costs. The second most frequently chosen

strategy is allowance acquisition. For about 15 percent

of the affected units, the operating utilities plan to

comply by acquiring enough SO2 allowances, largely

from other utilities that have reduced their allowance

requirements below their annual allocation of allowances, to cover their emissions. About 10 percent of the

affected units will install scrubbers to reduce emissions.

While this percentage is small compared to the percentage of utilities switching fuels or acquiring additional

allowances, it should be noted that scrubbers will

account for a large share of the required SO2 emissions

reduction in Phase I. At another 10 percent of the

affected units, emissions have already been reduced

below the number of allowances that have been allotted. Phase I affected utilities plan to repower only one

unit.

Utilities switching to low-sulfur coal are expected to

obtain two-thirds of the low-sulfur coal (approximately

24 million tons) from central Appalachia, located in

eastern Kentucky, western Virginia, and southern West

Virginia and the remainder (approximately 12 million

tons) from the Powder River Basin, located in southwestern Montana and northwestern Wyoming. An

electric utility that switches to burning a subbituminous

western low-sulfur coal may need to modify its plant,

including the coal handling system, fuel preparation

and firing system, steam generator, particulate removal

system, ash and waste disposal system, and building

structures. These modifications are necessary because of

the higher moisture content and different ash properties

of western coal, and may cost between $25 and $119

per kilowatt (1992 dollars).4

The responses of electric utilities to Phase I SO2 emissions limits, however, have been evolving since the

CAAA90 was enacted. Two trends in this development

are evident. One is that an increasing number of utilities are purchasing allowances from others who own

them. Prices for allowances have been lower than many

expected. As a result, fewer scrubbers are being installed at affected plants than originally planned. For

example, Illinois Power originally began installing

scrubbers at its Baldwin plant, but has since stopped

construction and announced that it will buy allowances

to comply with Phase I. The other trend is that the

price of low-sulfur coal has not risen as much as

expected, resulting in lower costs to switch to lowsulfur coal. Several utilities report that they are not

paying any premium for low-sulfur coal. Both trends

have reduced the expected cost of compliance with

Phase I for many utilities.

There are two other basic requirements of Phase I: NOx

emission performance standards for certain types of

boilers, and installation of continuous emission monitors (CEMs).5 The NOx performance standards limit

each affected unit to specific maximum emission rates.

CEMs measure emissions in the flue gas from a boiler.

Although these requirements are more straightforward

than the SO2 requirements, NOx control and CEM

requirements will be costly to Phase I affected utilities

in part because of their less flexible compliance options.

The costs of complying with Phase I of the Acid Rain

Program, while relatively small, vary substantially

among utilities. For a small sample of six utilities, total

capital costs for SO2 and NOx controls and CEMs range

from $10 to $216 per kilowatt (1993 dollars) of affected

capacity (Table ES2). Annual operation and maintenance and fuel expenses range up to over $14 per

kilowatt per year. Depreciating Phase I capital expenditures over 15 years results in annual total costs ranging

from less than $1 to more than $14 per kilowatt. The

effect of these costs on electricity rates is small, ranging

from 0.3 to 1.9 mills per kilowatthour; the additional

electricity sales revenue requirements range between 0.4

and 3.8 percent for an entire utility.

Table ES2. Utility Costs for Complying with

Phase I of the Acid Rain Program

Range of Cost Lowest Highest

Total Capital (1993 dollars per kilowatt) 10.5 216.4

Annual Capital (1993 dollars per kilowatt) 0.7 14.4

Annual Operations & Maintenance

(1993 dollars per kilowatt) . . . . . . . . . 0.2 14.1

Annual Fuel (1993 dollars per kilowatt) 0.0 3.8

Annual Total (1993 dollars per kilowatt) 2.6 17.2

Required Rate Increase

(1993 mills per kilowatthour) . . . . . . . 0.3 1.9

Required Rate Increase (percent) .... 0.4 3.8

Source: Energy Information Administration, Office of Coal,

Nuclear, Electric and Alternate Fuels (November 1993 through

March 1994).

4

Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur to Low-Sulfur Coal,” Sargent and Lundy,

paper presented at the 1992 International Joint Power Generation Conference and Exposition (Atlanta, GA, October 18-22, 1992). 5

Any alternative to CEMs must be explicitly approved by EPA.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 xi
1. Introduction

Title IV of the Clean Air Act Amendments of 1990

(CAAA90) requires the Environmental Protection

Agency (EPA) to establish the Acid Rain Program

which in turn requires electric utilities to substantially

reduce their emissions of sulfur dioxide (SO2) and

nitrogen oxides (NOx), the primary air pollutants that

contribute to acid rain. Fossil-fired electric utility plants

are the main source of SO2 emissions and a major

source of NOx emissions in the United States. Because

NOx reductions rely on more traditional controls, this

report places special emphasis on the unique, marketbased approach to SO2 reduction strategies. The Acid

Rain Program for both pollutants is split into two

periods—Phase I, which runs from 1995 through 1999,

and Phase II, which starts in 2000. In complying with

Phase I, affected utilities have considerable flexibility in

deciding how to reduce their SO2 emissions and can

design a compliance plan utilizing one or more strategies best suited to their individual needs.

Units Affected by Phase I

SO2 and, to a lesser extent, NOx emissions from fossilfired facilities are concentrated in the eastern and

midwestern portions of the United States (Table 1).

Many of the utility coal-fired power plants in those

regions emit more SO2 per million British thermal units

(Btu) than the standards set by EPA in 1971 because

they were constructed prior to the issuance of those

standards. They are also located in States that have coal

deposits with higher sulfur content and frequently use

such coal. These areas therefore account for the largest

emissions reductions and have the most generating

capacity affected by Phase I.

Table A of the CAAA90 specifies 261 generating units,

associated with 261 generators and 263 boilers,1 located

in 110 plants in 21 States, that are affected by the SO2

requirements of Phase I.2 All 110 plants are located in

the eastern and midwestern parts of the United States

(Table 2). Of the 21 States in which affected units are

located, 3 States have more than 40 percent of their

total nameplate capacity affected by Phase I: Ohio,

Indiana, and West Virginia. Another three States—

Georgia, Missouri, and Tennessee—have at least onethird of their total nameplate generating capacity

affected by Phase I (Figure 1). In absolute terms, 8 of

the 21 States have more than 5 gigawatts of capacity

affected by Phase I (Figure 2). Ohio has the largest

amount of Phase I affected capacity with 14.3 gigawatts

representing 48.7 percent of its total capacity and 57.3

percent of its coal-fired capacity.

Sulfur Dioxide Compliance

Strategies

The CAAA90 allows affected units to choose their SO2

compliance strategies, allowing several options for utilities. To meet CAAA90 requirements, all Phase I utilities

must have allowances to cover their SO2 emissions—

each allowance permits the utility to emit one ton of

SO2. Each of the 261 Phase I units initially receive

annual allowances for emissions of approximately 2.5

pounds of SO2 per million Btu of heat input during the

baseline period (the average for 1985 through 1987).

Beginning in the year 2000, the act places a cap on the

number of allowances issued to all utility generating

units, 25 megawatts and larger, each year at 8.95

million. This effectively permanently caps emissions

and ensures that the mandated emissions reductions

will be maintained over time. Each utility generally has

chosen a specific strategy in addition to the use of

allowances for compliance with Phase I. These specific

strategies can be grouped into six categories (Table 3):

• Fuel switching and/or blending

• Obtaining additional allowances

• Installing flue gas desulfurization equipment

(scrubbers)

• Using previously implemented controls

• Retiring facilities

• Boiler repowering.

1

Table A of the CAAA90 specified 261 electric power generators that were affected by Phase I. These generators are attached to 263

boilers at 261 boiler/generator units. See Appendix A for an individual listing of the 261 generators. 2

All coal-fired boilers in this group also must meet NOx emissions limits. Dry bottom wall-fired and tangentially-fired boilers must

meet NOx standards by January 1, 1995, while all other Phase I coal-fired boilers must meet NOx standards by January 1, 1997.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 1
Table 1. Emissions from Fossil-Fueled SteamElectric Generating Units at Utilities by

Census Division and State, 1992

(Thousand Short Tons)

Census Division

State

Sulfur

Dioxide

Nitrogen

Oxides

New England .................. 302 117

Connecticut . . . . . . . . . . . . . . . . . . 34 16

Maine ...................... 7 3

Massachusetts . . . . . . . . . . . . . . . . 203 75

New Hampshire . . . . . . . . . . . . . . . 57 23

Rhode Island ................. * *

Vermont ..................... * *

Middle Atlantic ................ 1,599 558

New Jersey . . . . . . . . . . . . . . . . . . 61 45

New York . . . . . . . . . . . . . . . . . . . . 342 154

Pennsylvania ................. 1,197 358

East North Central ............. 4,869 1,868

Illinois . . . . . . . . . . . . . . . . . . . . . . 842 306

Indiana ...................... 1,182 539

Michigan . . . . . . . . . . . . . . . . . . . . 353 313

Ohio ....................... 2,228 552

Wisconsin . . . . . . . . . . . . . . . . . . . 264 158

West North Central ............. 1,215 913

Iowa . . . . . . . . . . . . . . . . . . . . . . . 175 155

Kansas . . . . . . . . . . . . . . . . . . . . . 67 129

Minnesota . . . . . . . . . . . . . . . . . . . 78 151

Missouri . . . . . . . . . . . . . . . . . . . . . 681 284

Nebraska . . . . . . . . . . . . . . . . . . . . 52 82

North Dakota . . . . . . . . . . . . . . . . . 130 94

South Dakota . . . . . . . . . . . . . . . . . 32 18

South Atlantic ................. 3,456 1,345

Delaware . . . . . . . . . . . . . . . . . . . . 40 19

District of Columbia ............. 1 *

Florida . . . . . . . . . . . . . . . . . . . . . . 745 394

Georgia . . . . . . . . . . . . . . . . . . . . . 787 194

Maryland . . . . . . . . . . . . . . . . . . . . 259 96

North Carolina . . . . . . . . . . . . . . . . 378 195

South Carolina . . . . . . . . . . . . . . . . 154 80

Virginia . . . . . . . . . . . . . . . . . . . . . 177 72

West Virginia . . . . . . . . . . . . . . . . . 916 295

East South Central ............. 2,210 820

Alabama . . . . . . . . . . . . . . . . . . . . 537 229

Kentucky . . . . . . . . . . . . . . . . . . . . 767 358

Mississippi . . . . . . . . . . . . . . . . . . . 102 42

Tennessee . . . . . . . . . . . . . . . . . . . 803 192

West South Central ............. 756 1,264

Arkansas . . . . . . . . . . . . . . . . . . . . 66 102

Louisiana . . . . . . . . . . . . . . . . . . . . 110 189

Oklahoma . . . . . . . . . . . . . . . . . . . 108 168

Texas . . . . . . . . . . . . . . . . . . . . . . 473 804

Mountain ..................... 464 786

Arizona . . . . . . . . . . . . . . . . . . . . . 128 144

Colorado . . . . . . . . . . . . . . . . . . . . 87 136

Idaho . . . . . . . . . . . . . . . . . . . . . . . -- --

Montana . . . . . . . . . . . . . . . . . . . . . 22 80

Nevada . . . . . . . . . . . . . . . . . . . . . 59 71

New Mexico . . . . . . . . . . . . . . . . . . 59 152

Utah . . . . . . . . . . . . . . . . . . . . . . . 31 77

Wyoming . . . . . . . . . . . . . . . . . . . . 78 126

Pacific Contiguous ............. 85 205

California . . . . . . . . . . . . . . . . . . . . 1 137

Oregon . . . . . . . . . . . . . . . . . . . . . 14 21

Washington . . . . . . . . . . . . . . . . . . 70 47

Pacific Noncontiguous .......... 23 12

Alaska ...................... 1 *

Hawaii . . . . . . . . . . . . . . . . . . . . . . 23 12

U.S. Total .................... 14,981 7,889

*Value less than 0.5.

Notes: • Total may not equal sum of components because of independent

rounding. • These data are estimates derived from Form EIA-767, “SteamElectric Plant Operation and Design Report.” • Data include facilities of 10

megawatts or greater capacity. • Data are preliminary.

Source: Energy Information Administration, Electric Power Annual 1992,

DOE/EIA-0348(92) (Washington, DC, January 1994), p. 73.

Kentucky Utilities is installing flue gas desulfurization

equipment (top) at its 557-megawatt Ghent unit 1 (bottom)

to meet compliance with Phase I, which will yield excess

allowances at Ghent that can be distributed to the utility’s

other affected facilities.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

2 Clean Air Act Amendments of 1990
Table 2. Phase I Affected Coal-Fired Nameplate Capacity and Total Nameplate Capacity by State, 1992

State

Nameplate

Capacity

Affected by

Phase I

(gigawatts)

Number

of

Generators

Total

Nameplate

Capacity

(gigawatts)

Percentage

of Total

Nameplate

Capacity

Affected by

Phase I

Coal-Fired

Nameplate

Capacity

(gigawatts)

Percentage

of CoalFired

Nameplate

Capacity

Affected

by Phase I

Percentage

of Coal-Fired

Nameplate

Capacity

Alabama . . . . . . . . . 3.4 10 21.4 15.7 12.6 26.6 59.1

Florida . . . . . . . . . . . 2.3 5 36.9 6.2 10.9 21.1 29.4

Georgia . . . . . . . . . . 8.4 19 23.2 36.4 14.5 58.0 62.7

Illinois . . . . . . . . . . . 6.0 17 36.9 16.3 17.2 34.9 46.7

Indiana ........... 11.2 37 23.1 48.4 21.6 51.8 93.5

Iowa . . . . . . . . . . . . 1.0 6 8.8 11.2 6.3 15.6 71.4

Kansas . . . . . . . . . . 0.2 1 10.6 1.5 5.6 2.8 53.3

Kentucky . . . . . . . . . 4.7 17 17.4 26.8 16.1 28.9 92.8

Maryland . . . . . . . . . 2.4 6 11.8 20.2 4.9 48.1 42.0

Michigan . . . . . . . . . 0.7 2 24.0 2.7 12.9 5.0 53.8

Minnesota . . . . . . . . 0.2 1 9.3 1.8 5.8 2.8 63.0

Mississippi . . . . . . . . 0.8 2 7.2 10.4 2.2 34.9 29.9

Missouri . . . . . . . . . . 6.5 16 16.8 38.4 11.7 55.3 69.4

New Hampshire . . . . 0.5 2 2.6 17.6 0.6 75.4 23.4

New Jersey . . . . . . . 0.3 2 14.6 2.1 1.7 17.3 11.9

New York . . . . . . . . . 2.4 10 33.4 7.2 4.1 59.1 12.2

Ohio ............ 14.3 41 29.3 48.7 24.9 57.3 85.0

Pennsylvania . . . . . . 7.7 21 36.9 20.8 19.3 39.8 52.2

Tennessee . . . . . . . . 6.3 19 18.2 34.7 10.0 63.2 55.0

West Virginia . . . . . . 7.4 14 15.1 48.8 15.0 49.1 99.2

Wisconsin . . . . . . . . 2.7 13 10.9 24.8 7.3 37.0 67.0

Total United States . 89.0 261 741.7 12.0 325.1 27.4 43.8

Source: Capacity: Energy Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC, October 1993).

List of Affected Units: Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691.

Over half of the compliance strategies involve fuel

switching and/or blending (including cofiring). Fuel

switching and/or blending is not capital intensive, and

as such is a low fixed-cost strategy that allows utilities

to comply with the CAAA90 for a few years at relatively low cost. Therefore, utility planners have additional

time for resolving uncertainties in strategy costs. Kovy

A. Bailey, an economist with the Technology and

Environmental Policy Section of Argonne National Laboratory, states that, “Maintaining flexibility is probably

the most important thing utilities can do right now in

terms of environmental air-emission compliance. The

view seems to be, when in doubt, fuel switch.”3

Currently 162 Phase-I affected units are planning to

switch fuels. The use of lower sulfur coal, as well as a

complete switching and blending, are the two major

types of fuel switching being utilized. Other options are

mixing in-State coal with various low-sulfur coals and

switching or blending fuels, as well as some other

temporary fuel change, such as a seasonal switch to gas

or cofiring with gas. A few units have also indicated

that they will blend coal with another energy source,

such as tires.

Another 39 units will comply by obtaining emission

allowances from other units as their main strategy. For

example, Illinois Power will buy approximately 550,000

allowances for its Baldwin, Hennepin, and Vermilion

plants to comply with Phase I.4 Illinois Power

considered fuel blending and scrubbers for Baldwin,

but announced in mid-1993 that it would use allowances to comply. The lower-than-expected allowance

prices may have played a significant role in Illinois

Power’s decision.

3

“Phase I Compliance Plans Emphasize Flexibility,” Electric Light and Power (August 1993), p. 8. 4

“Illinois Power Fishes for Credits,” Coal Outlook (October 11, 1993), p. 3.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 3
0.01% - 10.00%

10.01% - 20.00%

20.01% - 30.00%

30.01% - 40.00%

40.01% - 50.00%

WI

IA

PA

NY

NJ

MD

WV

OH

NH

MI

IL IN

MN

KS MO

KY

TN

MS AL GA

FL

Figure 1. Percentage of Nameplate Capacity Affected by Phase I by State, 1992

Source: Capacity: Energy Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC,

October 1993). List of Affected Units: Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691.

Allowances also may be obtained from other units

within the same utility system. For example, Kentucky

Utilities will scrub the flue gas of its Phase I unit at

Ghent, resulting in Ghent needing fewer allowances

than the EPA allotted to it. This allows Kentucky

Utilities to transfer allowances from Ghent to its other

Phase I plants, Brown and Green River, to bring them

into compliance.

Scrubber equipment (primarily wet-limestone or wetlime) will be installed or retrofitted on flue stacks

associated with 27 units, principally in Indiana, Kentucky, and West Virginia (Table 4). Some have chosen

to scrub in order to receive additional allowances from

EPA which were set aside for utilities that would be

installing scrubbers. The number of generating units

estimated to install scrubbers has fallen since early

1993. This can be attributed to allowance prices that are

lower than had been expected.

A number of Phase I affected units are already in

compliance so their owners do not have to take action.

Some plants have already undertaken steps that will

ensure that, by continuing their current generation

practices, they will have sufficient allowances from the

initial allowance distribution. Often these reductions in

emissions have resulted from State regulations. In

Wisconsin, excluding four units that have already been

retired, all affected units already meet Phase I requirements. Currently, 25 units fall into the category of using

previously implemented controls.

One unit, Wabash River unit 1, owned and operated by

PSI Energy, will comply through boiler repowering.

This utility will replace its Phase I coal-fired generating

unit with a coal-gasification/combined-cycle unit. The

remaining seven Phase I units will meet compliance by

being retired.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

4 Clean Air Act Amendments of 1990
Gigawatts

Georgia

Illinois

Indiana

Missouri

Ohio

Pennsylvania

Tennessee

West Virginia

0 10 20 30 40

Phase I Coal-Fired Total

Figure 2. Phase I Affected Nameplate Capacity, Coal-Fired Nameplate Capacity, and Total Nameplate

Capacity for States with More than 5 Gigawatts of Affected Capacity by State, 1992

Source: Capacity: Energy Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC,

October 1993). List of Affected Units: Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691.

Contents of the Report

The remaining chapters of this report provide analyses

of the effects of compliance strategies for Phase I of the

Acid Rain Program on electric utilities. Chapter 2 provides detailed information about the CAAA90 and their

antecedents. Chapter 3 gives detailed descriptions,

including engineering considerations and cost estimates,

of the six specific strategies utilities are using to meet

compliance with the Acid Rain Program. Chapter 4 discusses the effects of the Acid Rain Program on the

largest affected plants, and also looks at the effects of

the amendments on six individual utilities, including

cost estimates for the compliance method being followed, plus the conclusion of this study.

Following the analyses in the chapters, several appendices are provided that include data, methodologies,

and more extensive background information. Appendix

A presents the list of 261 generators that are affected by

Phase I, along with data about the individual units.

Appendix B includes a technical description of the

characteristics of scrubbers reported since 1985. An

econometric analysis of costs and operating characteristics is presented in Appendix C for the 32 retrofitted

scrubbers. The capital and operations and maintenance

costs for the current scrubber technology for new units

along with a technical description of the technology are

presented in Appendix D. Appendices E and F present

cost analyses for the installation of NOx controls and

continuous emission monitors. These appendices also

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 5
include descriptions of the technical aspects of the

equipment. Appendix G presents the methodology used

for cost estimates of the six utilities presented in

the latter part of Chapter 4. Finally, a glossary of technical terms is included.

Table 3. Profile of Phase I Compliance Methods

Compliance Methoda

Number

of

Generatorsb

Average

Agec

(years)

Affected

Nameplate

Capacity

(megawatts)

Average

Nameplate

Capacity

(megawatts)

Allowancesd

(per year)

1985 SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancese

Fuel Switching and/or Blending . . . . . 162 29 53,203 328 3,315,554 5,455,734 499,202

Obtaining Additional Allowances . . . . 39 30 14,137 362 917,573 1,496,406 817,023

Installing Flue Gas Desulfurization

Equipment (Scrubbers) . . . . . . . . . 27 24 14,101 522 923,467 1,637,783 2,178,324

Using Previously Implemented

Controlsf . . . . . . . . . . . . . . . . . . . . 25 28 6,092 244 333,061 584,307 0

Retiring Facilities . . . . . . . . . . . . . . . 7 35 1,342 192 56,781 121,039 0

Boiler Repowering . . . . . . . . . . . . . . 1 39 113 113 4,385 6,713 5,451

Total ........................ 261 29 88,989 340 5,550,821 9,301,982 3,500,000

a

These compliance methods are based on information obtained in late 1993.

b

Cincinnati Gas & Electric’s Miami Fort generator 5 has two boilers as does Ohio Edison’s R.E. Burger generator 3. Therefore, the total number

of affected boilers is 263 and the number of affected generators is 261. c

Base year of 1992 was used to calculate average age.

d

One SO2 allowance permits one ton of SO2 emissions. e

Phase I extension allowances were awarded to (1) control units that install a technology that removes 90 percent or more of their SO2 emissions

or (2) control units and other units that use a different compliance strategy but are associated with the control unit in the extension allowance

application. Extension allowances were awarded for 1995 through 1999. f

Using previously implemented controls includes facilities that have already met required reductions due to existing State regulations or other

reasons.

SO2 = Sulfur dioxide.

Source: Compliance Method: U.S. Environmental Protection Agency, Coal Week, Compliance Strategies Review, Georgia Public Utility

Commission, Utility Environment Report, and McIlvaine Utility Forecast. List of Affected Units: Federal Register, Vol. 58, No. 6 (January 11,

1993), pp. 3687-3691. Age and Capacity: Energy Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington,

DC, October 1993). 1985 Emissions: U.S. Environmental Protection Agency, National Allowance Data Base, Versions 2.11 (January 1993).

Phase I Extension Allowances: Facsimile from U.S. Environmental Protection Agency (February 7, 1994).

Table 4. Scrubber Retrofits for Compliance with Phase I

Year State Units Plant Utility

1993 ................ Georgia Y1BR Yates Georgia Power

Indiana 7,8 Bailly Northern Indiana Public Service

1995 ................ Indiana 2,3 F.B. Cully Southern Indiana Gas & Electric

Indiana 4 Gibson PSI Energy

Kentucky 1,2 Elmer Smith City of Owensboro

Kentucky 1 Ghent Kentucky Utilities

New York 1,2 Milliken New York State Gas & Electric

Pennsylvania 1 Conemaugh Pennsylvania Electric Company

Tennessee 1,2 Cumberland Tennessee Valley Authority

West Virginia 1,2,3 Harrison Monongahela Power Company

West Virginia 3 Mt. Storm Virginia Electric & Power Company

1996 ................ Ohio 1,2 General J.M. Gavin Ohio Power

Pennsylvania 2 Conemaugh Pennsylvania Electric Company

Indiana 1,2 Petersburg Indianapolis Power & Light

1997 ................ Kentucky H1,H2 Henderson MP&L Station Big Rivers Electric

New Jersey 2 B.L. England Atlantic City Electric Company

Note: The scrubbing retrofits should go up substantially in the year 2000 and after due to Phase II requirements of the Acid Rain Program.

Source: U.S. Environmental Protection Agency, Applications for Acid Rain Program Phase I Bonus and Extension SO2 Emission Allowances

(March 31, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

6 Clean Air Act Amendments of 1990
2. The Acid Rain Provisions of the Clean Air Act

Amendments of 1990 and Their Antecedents

The Clean Air Act Amendments of 1990 (CAAA90)—

Public Law 101-549—are the most recent in a progression of legislative measures to control air pollution.

The CAAA90 were preceded by An Act to Provide Research and Technical Assistance Relating to Air

Pollution Control (Public Law 84-159) (the original

clean air legislation), the Clean Air Act of 1963 (Public

Law 88-206), the Air Quality Act of 1967 (Public Law

90-148), the Clean Air Amendments of 1970 (Public Law

91-604), and the Clean Air Act Amendments of

1977—Public Law 95-95—(Table 5).

The Clean Air Act Before 19905

An Act to Provide Research and

Technical Assistance Relating to Air

Pollution Control

An Act to Provide Research and Technical Assistance

Relating to Air Pollution Control was passed in 1955

partially in response to the growing concentration of

the U.S. population in urban areas. Many urban areas

were spread over more than one State (e.g., New York,

Chicago, and Washington, DC). Congress found that

“the growth in the amount and complexity of air pollution brought about by urbanization, industrial

development, and the increasing use of motor vehicles,

had resulted in mounting dangers to the public’s health

and welfare, including injury to agricultural crops and

livestock, damage to and the deterioration of property,

and hazards to air and ground transportation.”6

The 1955 act sought to remedy the growing air pollution problem by supporting research and providing

information and financial aid to the States. The act

expressly acknowledged the primary responsibilities

and rights of State and local governments to control air

pollution. There was no direct regulatory role for the

Federal Government.

The Clean Air Act of 1963

The Clean Air Act of 1963 began to expand the role of

the Federal Government in curbing air pollution by

including direct regulation. Air pollution which “endanger[ed] the health or welfare of any persons” was

made “subject to abatement” under certain circumstances. The law provided two additional tools for use

in the fight against air pollution. Federal funds were to

be made available to State and local pollution-control

agencies, and, since the effects of air pollution often

crossed State boundaries, the negotiation of interstate

compacts establishing joint control agencies was authorized.

The Air Quality Act of 1967

The Air Quality Act of 1967 further extended the role

of the Federal Government into air pollution standards.

It authorized the Secretary of Health, Education and

Welfare to create air quality regions and establish criteria for setting air quality levels that would protect

public health. The States were required to adopt

ambient air quality standards that were consistent with

these criteria.

The Clean Air Act Amendments of 1970

The Clean Air Act Amendments of 1970 substantially

enlarged the Federal role in air pollution control.

Because only a limited amount of action had been taken

by State and local governments (with the exception of

California) to control air pollution, Congress decided

5

The following discussion of the 1955 Act and the 1963 Act is based on David P. Currie, Air Pollution, Federal Law and Analysis (Wilmette,

IL: Callaghan and Company, 1981), pp. 1-10. The remaining discussion of the progression of the Clean Air Act is based on Energy

Information Administration, Impacts of the Proposed Clean Air Act Amendments of 1982 on the Coal and Electric Utility Industries, DOE/EIA0407 (Washington, DC, June 1983), pp. 3-4, Lester B. Lave and Gilbert S. Omenn, Clearing the Air: Reforming the Clean Air Act (Washington,

DC: Brookings Institution, 1981), pp. 7-9, and 40 CFR Part 60. 6

The Clean Air Act (42 U.S.C. 7401-7626), consisting of Public Law 159 (July 14, 1955; 69 Stat. 322) and the amendments made by

subsequent enactments.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 7
Table 5. Chronology of Historic Federal Legislation to Control Air Pollution

Legislation and Date Federal Role State Role

An act to provide research and technical

assistance relating to air pollution control

(1955)

Research, technical and financial aid to

States

All responsibility for control

Clean Air Act of 1963 Mediate among States, if requested Form regional commissions

Air Quality Act of 1967 Create air quality control regions; establish

criteria for health protection; recommend

control techniques; set national emissions

standards for vehicles

Must adopt ambient air quality standards

(Federal review and approval)

Clean Air Amendments of 1970 Set national primary and secondary air

quality standards; review and approve State

implementation plans; assess hazards from

additional named pollutants; set national

emissions standards for stationary sources;

set statutory reductions and timetable for

vehicle emissions; regulate fuels, fuel

additives, aircraft emissions, noise

Design State implementation plans and

enforce, if approved by EPA; right to impose

more stringent standards

Amendments and extensions of Clean Air

Act (1971, 1973, 1974, 1976)

Waivers and extensions of motor vehicle

emissions standards

Clean Air Act Amendments of 1977 Classification of air quality control regions

as attainment or nonattainment; program for

prevention of significant deterioration;

special treatment for eastern coal; new

source performance standards and

hazardous pollutant sections strengthened;

motor vehicle emissions standards tightened

further

Modification of State implementation plans

for nonattainment areas, to avoid major

sanctions; cost-benefit analysis and offset

policy for new sources

Source: Lester B. Lave and Gilbert S. Omenn, Clearing the Air: Reforming the Clean Air Act (Washington, DC: Brookings Institution,

1981), p. 6.

that National Ambient Air Quality Standards (NAAQS)

were the appropriate criteria for protecting public

health, and it dismissed the relevance of abatement cost

in setting the standards. The newly created Environmental Protection Agency (EPA) was given

responsibility for setting the standards. The States

implemented the program by designing, seeking EPA

approval for, and then enforcing State Implementation

Plans that would ensure attainment of the NAAQS by

1975. Standards were promulgated for six criteria

pollutants: particulate matter, sulfur oxides, carbon

monoxide, nitrogen dioxide, ozone,7 and nonmethane

hydrocarbons. A standard for lead was added in 1978

and the standard for ozone was revised in 1979. All of

these standards are still in place.

For enforcement purposes, the United States was

divided into 274 air quality control regions. NAAQS

limits were required to be met in each region. Control

regions within State boundaries where the ambient

pollutant concentrations were below or met the NAAQS

were designated as “attainment areas” by the 1970

amendments. Conversely, areas where the ambient

pollutant concentrations did not meet NAAQS were

labeled “nonattainment areas.” In nonattainment areas,

the 1970 amendments mandated that States establish

State Implementation Plans to ensure that the minimum

standards set by EPA would be met and maintained.

Accordingly, new and modified sources within nonattainment areas were required to attain the “lowest

achievable emission reduction.” Consistent with

Congress’ directive concerning setting the standards for

NAAQS, cost was again not to be considered in

achieving this reduction.

Distinct from ambient standards, the 1970 amendments

also introduced national emissions standards for new

stationary sources of air pollution, limiting the amounts

7

Ozone at lower levels in the atmosphere is a pollutant; at higher levels, it forms a layer that protects the earth from ultraviolet

radiation.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

8 Clean Air Act Amendments of 1990
Some Phase I affected facilities have been around longer than much of the clean air legislation, including five of Yates’ seven

affected units that were built prior to the original Clean Air Act of 1963.

of sulfur dioxide (SO2), nitrogen oxides (NOX), and

particulates that coal-fired boilers of certain classes

could emit. In general, these technology-based standards called for the application of the “best available

control technology,” under which Congress did allow

some consideration of the cost of the abatement.

However, Congress imposed stringent deadlines for

achieving national standards.

The 1971 New Source Performance Standards issued by

EPA under the authority of the 1970 amendments

required that utility coal-fired boilers of 73-megawatt

output or greater, on which construction or modification had begun after August 17, 1971, could not emit

more than 1.2 pounds of SO2 per million British thermal

units (Btu) of heat input. Plant operators were required

to use “continuous emission monitoring” to measure

the SO2 emission levels in the flue gas outlets of coalfired boilers. If the average emission level exceeded the

new standard for more than 3 hours, the plant could be

cited for violation.8

The 1971 New Source Performance Standards also

issued requirements for NOx and particulate emissions.

NOx emissions from bituminous coal-fired units were

limited to 0.7 pounds per million Btu; subbituminousfired units and lignite-fired units were limited to 0.6

pounds per million Btu; except for those units fired by

lignite mined in North Dakota, South Dakota, or Montana which were limited to 0.8 pounds per million Btu.

Particulate emissions were limited to 0.1 pounds per

million Btu. Additionally, plants were prohibited from

producing emissions that exhibited greater than 20

percent opacity except for one 6-minute period per

hour of not more than 27 percent opacity.9

The Clean Air Act Amendments of 1977

The Clean Air Act Amendments of 1977 further emphasized the classification of air quality control regions as

attainment or nonattainment areas with regard to all

established ambient air standards. Sanctions and special

implementation strategies were introduced for nonattainment areas. The amendments stipulated that

sources in nonattainment areas must use “reasonably

available pollution control technologies,” taking into

consideration both cost and technological feasibility.

Whereas, sources in attainment areas were directed to

use the “best available control technology” in order to

8

The continuous emission monitoring (CEM) equipment required in the CAAA90 acid rain regulations is more accurate than that

required in the New Source Performance Standards of 1971. The standards required plants to emit below a certain level, so older CEMs

only needed to accurately measure emissions up to that level. For the CAAA90 rules, the CEM equipment must be able to accumulate

total emissions over a given period of time. Thus the new CEMs need to be accurate for any level of emissions that an electric power

generating plant may produce. 9

Opacity is the percentage of incident light that does not pass through the flue gas, and gives an indication of the amount of particulate

matter being emitted.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 9
“prevent significant deterioration” of the clean air

within the control region.

In 1979, EPA issued Revised New Source Performance

Standards. These standards were more stringent than

the original standards and applied to all coal-fired

utility plants capable of producing more than 73

megawatts of generating capacity, and on which construction or modification began after September 12,

1978. The new standards retained the 1971 standard of

1.2 pounds of SO2 per million Btu of energy input as a

ceiling for emissions, but additionally required that SO2

emissions from all new or modified boilers be reduced

on a sliding scale of percentages based on the sulfur

content of the coal burned. All coal burned was

required to have at least 90 percent of the SO2 removed

from its emissions, unless 90-percent removal reduced

emissions to less than 0.6 pounds per million Btu, in

which case reductions between 70 and 90 percent were

permitted, depending on the sulfur content of the coal.

Utilities were required to monitor SO2 emissions from

these new sources continuously, both at the flue gas

inlet and at the outlet, to determine whether the

required removal was attained on a 24-hour rolling

average.

The Revised New Source Performance Standards also

included new requirements for NOx and particulate

emissions that were sometimes more stringent than the

requirements of the 1971 standards. NOx emissions

from bituminous coal-fired units were lowered to 0.6

pounds per million Btu, subbituminous-fired units were

lowered to 0.5 pounds per million Btu, and the limit for

units fired by lignite mined in North Dakota, South

Dakota, or Montana remained at 0.8 pounds per million

Btu. The limit for other lignite-fired plants remained at

0.6 pounds per million Btu. Particulate emissions were

limited to 0.03 pounds per million Btu. The prohibition

against emissions exhibiting greater than 20 percent

opacity was retained under the revised standards, but

there was no mention of the 6-minute period per hour

of not more than 27 percent opacity.

The Acid Rain Program of the Clean

Air Act Amendments of 199010

Title IV of the CAAA90 established the Acid Rain Program, which is designed to reduce the adverse effects

of acid deposition. This will be achieved primarily

through domestic reductions of SO2 and NOx emissions by electricity producers, while concurrently

encouraging energy conservation and the use of renewable and clean alternative technologies in electricity

production. The primary goal of Title IV is the reduction of annual SO2 emissions from electric utilities by 10

million tons below their 1980 level by the year 2010.

The legislation also calls for a reduction of 2 million

tons in NOx emissions from utility boilers. Utilities will

apply low-NOx burner technologies to meet regulations

that become effective on the date the unit must meet

the SO2 standard, i.e., January 1, 1995, for Phase I units;

January 1, 1997, for Phase I units employing scrubber

technology; and January 1, 2000, for all Phase II units.

NOx limits for wall dry-fired and tangential-fired

boilers affected in Phase I have been selected as 0.50

and 0.45 pounds per million Btu, respectively. Regarding Phase II compliance, NOx limits must be established

by no later than January 1, 1997, for two categories of

boilers exempted from Phase I—cell- and cyclone-fired

units. Also by that date, the limits for wall- and

tangential-fired boilers can be revised, if allowed by

improved technology. An emissions averaging provision allows individual utilities to average NOx over

multiple units, if the same or lower emissions result.

To achieve these reductions, the law requires a twophase tightening of the restrictions placed on fossil-fuelfired utility power plants. Phase I begins in 1995 with

specified limitations for 110 mostly coal-burning electric

utility plants located in 21 eastern and midwestern

States. Phase II, which begins in the year 2000, tightens

the total annual emissions limits imposed on these

large, higher emitting plants and also sets restrictions

on smaller and cleaner plants fired by coal, oil, and gas.

Approximately 2,500 boiler units within approximately

1,000 utility plants will be affected in Phase II. New

nonutility boilers that produce electricity for sale to end

users will also be affected in Phase II.

Emission Allowances

The Acid Rain Program represents a legislative breakthrough in environmental protection. The approach to

controlling SO2 embodied in the new provisions represents a radical departure from the traditional

“command-and-control” approach to environmental

regulation. Instead, it introduces an innovative allowance system that harnesses the incentives of the free

market to reduce pollution. The acid rain provisions

10The discussion in this summary is based primarily on the series of documents regarding the Acid Rain Program published by the U.S.

Environmental Protection Agency, Office of Air and Radiation, beginning in 1991.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

10 Clean Air Act Amendments of 1990
of the CAAA90 may become the prototype for tackling

emerging environmental issues in a more cost-effective

manner.

An “allowance” is defined in the CAAA90 as the authorization, allocated to an electricity producer, to emit 1

ton of SO2 during or after a specified calendar year.11

The EPA, which will maintain the system for issuing,

recording, and tracking allowances, will allocate allowances to affected utilities each calendar year during

Phase I based on a standard formula: the product of a

2.5 pound sulfur dioxide per million Btu emission rate

multiplied by the unit’s average fuel consumption for

1985 through 1987. In Phase II, all Phase I plants, as

well as all remaining utility generating units greater

than 25 megawatts in size, must constrain annual emissions to a permanent cap totaling 8.95 million tons of

SO2.

12 Included in the basic allocation of 8.95 million

allowances are three reserves: (1) 50,000 allowances for

the use of clean coal technologies, (2) 50,000 allowances

for conservation and renewable energy initiatives, and

(3) 250,000 allowances for auctions and sales. In addition, there will be 500,000 bonus allowances and 50,000

allowances allocated to utilities in certain midwestern

States.

The primary requirement for electric power generators

to be in compliance with the law is that a generator

may not emit more sulfur dioxide than it holds allowances for; therefore, electricity producers will have to

either reduce emissions to the level of allowances given

to them or obtain additional allowances to cover their

emissions above their initial allocation. Sources whose

emissions exceed allowances held will be required to

pay $2,000 per excess ton, and will be required to offset

excess emissions with allowances the following year.

Allowances may not be used prior to the calendar year

for which they are allocated.

Electric power producers that reduce their emissions

below the number of allowances they hold may elect to

trade allowances within their systems, bank allowances

for future use, or sell them to other utilities. This flexibility provides an incentive for power producers to

achieve total emissions limits as cheaply as possible.

Anyone may hold allowances—including brokers, environmental groups, and private citizens—and trading

will be conducted nationwide. However, regardless of

the number of allowances a source holds, it may not

emit at levels that would violate Federal or State limits

set under Title I or other provisions of the act and its

previous amendments to protect public health.

Electricity generating units that began operating after

November 15, 1990, will not receive any allowances.

Instead, they will have to purchase allowances that

were initially allocated to other units, which will limit

emissions even more as plants are built and the combustion of fossil fuels to generate electricity increases.

In addition to the initial allocation, allowances are

available in three different reserves. In Phase I, units

can apply for and receive additional allowances by: (1)

installing a qualifying Phase I technology (a technology

that can be demonstrated to remove at least 90 percent

of the unit’s SO2 emissions), (2) by reassigning their

reduction requirements among other units employing

such a technology, or (3) by replacing boilers with new,

cleaner and more efficient technologies. EPA has

created 3.5 million allowances to stock this reserve. A

second reserve provides allowances as incentives for

units achieving SO2 emissions reductions through

customer-oriented conservation measures or renewable

energy generation.

For the third reserve, EPA has set aside allowances for

auctions and direct sales in a Special Allowance Reserve, which is approximately 2.8 percent of the total

On November 15, 1990, President George Bush signed the

new Clean Air Act Amendments into law.

11U.S. Environmental Protection Agency, “Acid Rain Program Allowance System,” EPA 430/F-92/018 (December 1992), p. 2.

12This annual limit averages out to approximately 1.2 pounds per million Btu for all units existing before 1990.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 11
annual allowances allocated to all units. The auctions,

the first of which has already occurred, are intended to

send the market an allowance price signal along with

furnishing affected units and others with an additional

source for purchasing allowances. Auction results will

be made public by EPA. The sales offer allowances at

a fixed price of $1,500. Anyone can buy allowances in

the direct sale, but independent power producers can

obtain written guarantees from EPA stating that they

will have first priority. These guarantees, which are

awarded on a first-come, first-served basis, secure the

option for qualified independent power producers to

purchase a yearly amount of allowances over a 30-year

span, and enables them to assure lenders that they will

have access to the allowances they need to operate new

generating units.

Operating Permits

The Acid Rain Program is implemented through operating permits. Each plant that houses an affected unit

must submit a standard permit application form when

applying for an Acid Rain Permit. The form must

include general plant information, information about

the Designated Representative, specific unit information, and a compliance plan for each affected unit. The

plan must describe the actions taken to ensure compliance with the Acid Rain Program and must indicate

that the unit will hold enough allowances to cover its

annual SO2 emissions and will be operated in compliance with the applicable NOx emissions limitations.

The plan may comprise one or more of the following

options: (1) hold allowances, (2) substitution plan, (3)

extension plan, and (4) reduced utilization plan. Each of

these options and the permitting process are discussed

in more detail in Chapter 3. Applications are submitted

for approval to EPA in Phase I and to an EPAapproved State or local permitting authority in Phase II.

Those States that do not have EPA approval permit

programs by July 1, 1996, will have their sources’ Phase

II permits processed by EPA.

Continuous Emission Monitoring

Affected units also are required to install systems that

continuously monitor emissions of pollutants discharged into the atmosphere in exhaust gases. This

“continuous emission monitoring” (CEM) is required to

ensure that the mandated reductions of pollutants are

achieved. EPA has established requirements for the

continuous monitoring of SO2, NOx, volumetric flow,

opacity, and diluent gas (carbon dioxide (CO2) or

oxygen) for units regulated under Phase I and Phase II.

In addition, if a utility uses a CEM system to monitor

emissions, a CO2 diluent monitor plus a flow monitor

would be used to compute emissions. The rule also

contains requirements for equipment performance specifications, certification procedures, and recordkeeping

and reporting, which plants must do on a quarterly

basis to EPA. All required CEM equipment must be installed, certified, and operational by November 15,

1993, for Phase I units, and by January 1, 1995, for

Phase II units (Appendix F). A new unit (a unit that

begins commercial operation on or after November 15,

1990) must meet all requirements no later than 90 days

after commencing commercial operation.

Phase I Implementation Issues

Two substantial issues have arisen in the implementation of Phase I of the CAAA90. EPA has approved

some of the Phase I permits for only 1 year, although

it had initially planned to approve them for the entire

5 years of Phase I. EPA estimates that some substitution

compliance plans and reduced utilization compliance

plans specified by utilities under the initial EPA rules

will generate approximately 1 million more allowances

for Phase I than they expected. As a result, EPA has

proposed that it revise the Phase I rules for substitution

plans and reduced utilization plans, and that it issue

permits for these two plans for 1995 only under the old

compliance rules. Permits for 1996 through 1999 for

these units will be subject to the revised rules, which

are expected to be promulgated in early 1994.

Previous to the proposal to only partially approve some

permits, several environmental advocate groups and the

State of New York petitioned the U.S. Court of Appeals

for review of the initial compliance rules. These petitions are currently being considered by the court.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

12 Clean Air Act Amendments of 1990
3. Compliance Strategies for Control of

Sulfur Dioxide Emissions

Most utilities affected by Phase I of the Acid Rain

Program need to take some action to meet sulfur

dioxide (SO2) emissions limitations. The majority will

switch or blend fuels, obtain additional allowances, or

install flue gas desulfurization equipment (scrubbers).

Some affected units will not need to take any action

because previously implemented controls will enable

them to meet compliance using their basic allotment of

allowances. Others will retire affected units, and one

unit will use boiler repowering. In addition to the six

main methods of compliance discussed in this report,

there are further strategies available which most utilities plan to use in conjunction with their main method.

They include energy conservation (including supplyside and demand-side management), reduced utilization plans, and substitution plans. Chapter 3 discusses

each of these strategies and several other directly

related issues.

Fuel Switching/Blending

More than half of the compliance methods chosen for

Phase I affected units involve fuel switching, blending,

or cofiring.11 Fuel switching usually involves changing

to a coal with a lower sulfur content, although it may

include switching to another type of fuel entirely. Fuel

blending is the blending of high- and low-sulfur coals

to reduce SO2 emissions, while cofiring usually involves

combining another type of fuel, commonly natural gas,

with coal in the boiler to reduce emissions. Of the 110

Phase I targeted plants, with a total of 261 affected

generating units, more than 60 plants housing 162

affected units have chosen fuel switching, blending, or

cofiring. About 40 of those 162 units, primarily in

Illinois, Pennsylvania, and Indiana, are planning to

blend in-State coal with coals of lower sulfur content.

Another four to six plants have submitted plans to

cofire with, or switch to, natural gas.

While some utilities have stated where they intend to

purchase low-sulfur coal for compliance with Phase I,

relatively few utilities have signed contracts confirming

these intentions. However, the Central Appalachian

Region is mentioned most often as a possible source for

low-sulfur coal, followed by the Powder River Basin.

Switching to Low-Sulfur Coal

Compared to scrubbing and repowering, the fuel

switching/blending method has lower capital costs,

which will result in lower sunk costs in case a different

compliance method later becomes preferred. Coal

switching also offers the utility more time to look at the

issues involved, including coal quality in total switching versus blending, transportation and fuel costs, and

boiler performance, because switching may require less

lead time to implement. This is particularly important

for Phase I, since the amendments were passed in

November 1990 and will take effect January 1995. However, switching to a low-sulfur coal carries with it a

different set of costs and requirements to assess the

characteristics of the low-sulfur coal and its impacts on

the operation of existing power plants and the performance of boiler units and related components.

It has been estimated that potentially up to 60 percent

of unscheduled outages at a power plant are associated

with equipment that contacts either coal or coal

combustion products.12 In general, power plants are

designed for a particular type of coal, with which initial

performance guarantees are met. Plants also have an

allowable range for the most important coal properties,

within which it is expected that a full load may be

produced, although possibly at reduced efficiencies.

Deviations in one or more of the properties beyond the

allowable range may result in impaired plant performance or even serious operating and maintenance

11Phase I units may use coal of any sulfur content that will meet their allowances to emit no more than 2.5 pounds of SO2 per million

Btu. SO2 emissions are expressed as a function of the heating content of the coal and the sulfur content of the coal. 12IEA Coal Research, Coal Specifications—Impact on Power Station Performance, IEACR/52 (London, England, January 1993), p. 13.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 13
Around 62 percent of the affected units will meet compliance

by fuel switching and/or blending, including Ohio Edison’s

Edgewater facility.

problems.13 Thus, a good coal switching plan requires

significant cost analysis and could take as long as 2

years to implement, allowing time for study and design, test burns, equipment procurement and delivery,

construction, and outages during construction.14

Low-Sulfur Coal Characteristics

There are an estimated 100 billion short tons of lowsulfur recoverable reserves in the United States. About

12 percent of those reserves are in the Appalachian

Region, which includes Alabama, Georgia, eastern Kentucky, Maryland, North Carolina, Ohio, Pennsylvania,

Tennessee, Virginia, and West Virginia. Eighty-seven

percent are in the West, which includes Alaska,

Arizona, Colorado, Idaho, Montana, New Mexico,

North Dakota, South Dakota, Wyoming, Oregon, and

Washington. Less than 1 percent are in the Interior

Region which includes Oklahoma, Texas, Arkansas,

Louisiana, Missouri, western Kentucky, Iowa, Kansas,

Indiana, and Illinois.15

Low-sulfur coals in the West are found mostly in the

Powder River Basin (Wyoming and Montana), Colorado, Utah, Arizona, and Washington (Figure 3). In the

East, low-sulfur coals are found in the Central Appalachian Region, primarily in southern West Virginia,

eastern Kentucky, and western Virginia. Low-sulfur

coal from the East generally has a higher heating value

and lower moisture content than low-sulfur coal from

the West. These differences can greatly affect plant

operation, from coal handling, storage, and pulverization to boiler design and ash handling.

Eastern Low-Sulfur Coal

The Effects of Eastern Low-Sulfur Coal on

Boiler Performance

A typical eastern low-sulfur coal has a heating value of

13,000 British thermal units (Btu) per pound, moisture

content of 6.9 percent, ash content of 4.5 percent, Hardgrove Grindability Index (HGI) of 45 to 55, and sulfur

content of 0.7 percent by weight (Table 6).16

Little has been written about burning eastern low-sulfur

coals, probably because of the relatively small impact of

eastern low-sulfur coal on boiler performance or

because of the economic attractiveness of low-sulfur

coal from the Powder River Basin. It may be that central Appalachian low-sulfur coals will have little impact

on boiler performance because most plants in Illinois

and Ohio, where much switching will occur, can easily

accommodate eastern low-sulfur coals with its high ash

fusion temperatures.17 The transition from bituminous

high-sulfur coal to bituminous low-sulfur coal has few

equipment impacts. The grindability of eastern lowsulfur coals from southern West Virginia is usually

around 55, a favorable HGI for pulverizers. (The lower

the HGI, the more difficult the coal is to grind.)

In a study of one plant switching to low-sulfur eastern

coal, the low-sulfur eastern coal that was tested

produced more favorable results in some equipment

13IEA Coal Research, Coal Specifications—Impact on Power Station Performance, IEACR/52 (London, England, January 1993), p. 13. 14Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992). 15Energy Information Administration, U.S.Coal Reserves: An Update by Heat and Sulfur Content, DOE/EIA-0529(92) (Washington, DC,

February 1993), p. ix. 16Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992). 17Verbal communication with Edward T. McHale, Science Applications International Corporation.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

14 Clean Air Act Amendments of 1990
Figure 3. Average Sulfur Content of Coal Shipped to U.S. Power Plants by State of Origin, 1992

(Pounds of Sulfur per Million Btu)

Source: Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants 1992, DOE/EIA-0191(92)

(Washington, DC, August 1993), p. 30.

Table 6. Comparison of Typical Coal Characteristics and Ash Properties

High-Sulfur

Coal

Eastern LowSulfur CoalWestern LowSulfur Coal

Heating Value (Btus per pound) ................ 10,500 13,000 8,000

Moisture Content (percent) ................... 11.7 6.9 30.4

Ash Content (percent) ....................... 11.8 4.5 6.4

Hardgrove Grindability Index (HGI) . . . . . . . . . . . . . 55 45-55 40-65

Sulfur Content (percent) . . . . . . . . . . . . . . . . . . . . . 3.2 0.7 0.5

Ash Properties

Sodium Content (percent) . . . . . . . . . . . . . . . . . . 0.5 0.8 1.6

Calcium Content (percent) . . . . . . . . . . . . . . . . . . 4.8 1.0 21.8

Slag Temperature (T250 in °F)a ............... 2,400 2,900 2,900

a

T250 is the maximum temperature for which molten ash or slag will flow easily, and is characteristic of the slag

constituents. The notation 250 refers to a measure of the viscosity of the slag (specifically, at temperature T250, the slag

will have a viscosity of 250 poise).

Note: All values are typical of “as-received” coal.

Source: Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low Sulfur

Coal,” Sargent & Lundy, presented at the 1992 International Joint Power Generation Conference and Exposition (Atlanta,

GA, October 18-22, 1992).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 15
performance areas than the higher-sulfur coal that the

boiler was designed to burn. Boiler efficiency was

expected to increase by 2 percent, primarily because of

lower moisture content. The higher heating value of the

eastern low sulfur coal improved boiler efficiency and

resulted in 26 percent less pulverizer capacity required.

The higher HGI and the lower moisture content also

contributed to an increase in available pulverizer capacity. However, installation of a flue gas conditioning

system was required to improve precipitator performance. No change was required for the forced draft fans

or for the fly ash handling system. The estimated cost

for these plant modifications amounted to $25.5 per

kilowatt of plant capacity (1992 dollars).18

Production and Distribution in Central

Appalachia

Since the Central Appalachian Region has been chosen

as a new source of coal by more of the plants switching

to a lower sulfur coal, the present production and end

use of coal from this region may be affected when

plants make the final implementation of their compliance plans.

Production in the Central Appalachian Region in 1992

was 273.6 million short tons; 118.7 million short tons

from eastern Kentucky, 112.0 million short tons from

southern West Virginia, and 42.9 million short tons

from Virginia.19 The eastern Kentucky coalfield covers

10,500 square miles, with more than 80 named coal

seams and eight widespread, relatively thick beds of

low-sulfur coal.20 In 1992, 69 percent of eastern Kentucky coal distributed was used by electric utilities; 18

percent was used by coke plants and industrial, residential, and commercial users; and 12 percent was

exported.21

The southern coalfield of West Virginia is more homogeneous than its northern counterpart, with 43 minable

seams and many high-quality (low-sulfur, low-ash, and

high-Btu) coals. The average sulfur content is consistently below 1.5 percent. In 1992, southern West

Virginia coal was distributed as follows: 43 percent

went to electric utilities, 39 percent was exported, and

17 percent went to coke plants and industrial, residential and commercial users.

All of Virginia’s 1992 coal production, totaling 42.9

million short tons, came from the Southwest Virginia

coalfield in the western part of Virginia. The coals vary

from high to low volatile bituminous in rank and are

typically low sulfur (less than 1 percent). Thirty-eight

percent of the coal distributed from this coalfield was

exported, 33 percent went to electric utilities, and 27

percent went to coke plants, industrial, residential, and

commercial users.

Powder River Basin Coal

As previously mentioned, of the estimated U.S. total of

100 billion short tons of low-sulfur recoverable coal

reserves, 87 percent is in the West.22 Western coals

have several characteristics that differentiate them from

eastern coals and will have an impact on plant operations (Table 7):

• They are more brittle, which means that they are

very dusty. The brittleness of Powder River Basin

coals is caused by the presence of intact plant

materials (vitrain bands). This characteristic

requires more aggressive dust suppression and

dust collection procedures and more diligent

housekeeping in coal handling areas.23

• They have a higher tendency for spontaneous

combustion than eastern coals, creating a fire and

explosion hazard and requiring more extensive

fire protection equipment and procedures. The

risk of fire is greater for cyclone boilers than for

pulverized coal boilers because the coal for

cyclone boilers is crushed in the coal handling

areas. This means that the crushed coal receives

an increased amount of handling in a more ignitable form as it is brought over an extended

distance by a conveyor system to coal bunkers

18Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992). 19Energy Information Administration, Coal Production 1992, DOE/EIA-0118(92) (Washington, DC, November 1993), Table 3. 201992 Keystone Coal Industry Manual, Maclean Hunter Publishing Company (Chicago, Illinois, 1992). 21Energy Information Administration, Quarterly Coal Report, DOE/EIA-0121(92/4Q) (Washington, DC, May 1993), pp. 20-22. 22Energy Information Administration, U.S. Coal Reserves: An Update by Heat and Sulfur Content, DOE/EIA-0529(92) (Washington, DC,

February 1993), p. ix. The West includes Alaska, Arizona, Colorado, Idaho, Montana, New Mexico, North Dakota, Oregon, South Dakota,

Utah, Washington, and Wyoming. 23Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

16 Clean Air Act Amendments of 1990
Table 7. Impact of Coal Characteristics on Coal Switching

Change in Coal

Characteristics Resulting Potential Operating Problems Possible Solutions

Lower heating value Insufficient coal-handling capacity

Unable to achieve design steam output

Enlarge coal-handling equipment

Derate capacity

Higher moisture Longer/cooler flames

Lower furnace exit temperature

Higher gas flow

Derate capacity

Increase/modify boiler heat

transfer surface area

Increase fan capacity

Higher ash Increased particulate in flue gas

Increased solid waste

Increase soot blowing

Modify boiler convective section

heat transfer area

Increase electrostatic precipitator plate area

Modify ash-handling and disposal systems

Lower sulfur Lower particulate collection efficiency Increase electrostatic precipitator plate area

Install flue gas conditioning

Higher ash fusion Incompatible with cyclone and wet-bottom

furnaces

Use different coal

Higher sodium and

iron content in ash

Increased slagging and fouling Increase soot blowing

Use ash additives

Accept higher forced-outage rates

Higher volatility Changed heat transfer characteristics

Heating and potential fires in

coal-handling equipment

Change boiler tube distribution in furnace

and convective sections

Modify pulverizers, silos, and other

coal-handling equipment

Harder grindability Insufficient pulverizer capacity Increase pulverizer capacity

Derate boiler capacity

Source: Radian Corporation, “Analysis of Low NOx Burners Technology Costs,” unpublished draft report prepared for the U.S. Environmental

Protection Agency (Research Triangle Park, NC, November 1992).

and silos. Pulverizers for low-sulfur coals may

require enclosed conveyors and explosion venting

and procedures to remove hot coals from bunkers

and silos.24

• They generally have a lower heat value, requiring

a higher firing rate to produce the same heat rate.

Lower heat values force the utility to decide

between derating the capacity of the boiler and

increasing the size of the boiler combustion zone.

• Some Powder River Basin coals have a higher

moisture content than high-sulfur coals. A higher

moisture content increases the drying requirements in the pulverization process,25 and may

decrease boiler efficiency because combustion heat

must be used to evaporate the water in the coal.

• They are more difficult to pulverize, with HGI in

the range of 40 to 50. Utilities are using a variety

of measures to maintain pulverizer capacity and

performance when firing blends of western coal

with eastern coal. A recent survey reports that 5

of 11 pulverizer units blending eastern and western coals reported lowering the pulverizer exit

temperature control point to reduce the incidence

24Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992). 25These results were obtained from a pulverization pilot plant program to determine the effect of moisture differences on mill

performance, using a blend of 40/60 Illinois low-sulfur with Powder River Basin coal containing 21.7 percent moisture by weight. R.E.

Douglas and C.L. Krcil, “The Effect of HGI and Coal Moisture Differences on Mill Performance for Coals and Coal Blends,” paper

presented at the Engineering Foundation Conference on Coal Blending and Switching of Western Low-Sulfur Coals (Salt Lake City, UT,

September 26, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 17
Amax Coal, owned by Amax Incorporated who recently merged with the Cyprus Minerals Company, has been producing low-sulfur

coal in Wyoming for a number of years, and demand for low-sulfur coal is expected to rise due to the passage of the CAAA90.

of mill “puffs” or pyrite trap fires. Four of the

units added mill inerting or flooding capabilities,

while two of the same units altered startup and

shutdown procedures to promote safe operation.

Two units reported efforts to improve pulverizer

maintenance, and two units added pulverizer air

flow and/or temperature instrumentation where

none had existed before.26

In addition, the different ash properties of western lowsulfur coal have a significant effect on the components

of a steam generator. Ash resulting from the combustion of coal can occur in several forms in the furnace: as

solid fly ash passing through the furnace, as molten ash

particles in the gas stream, or as an accumulation of

very hot, but not molten, ash in the convective passes

of the superheater. Each of these leads to different

problems: decreased effectiveness of the electrostatic

precipitator,27 a lower heat transfer rate because of the

formation of slag deposits on the water wall tubes, and

less efficient heat transfer because ash builds up and

plugs convection passes (fouling). While theories vary

as to which constituents of western coal are related to

ash problems, there is general agreement that the tendency to foul and slag increases with western coals.

These ash problems may require upgrades or modifications to boiler components, including additional soot

blowers, mechanisms to control steam temperature,

conversion or replacement of fans, adjustments to air

heaters, and modifications or upgrades to electrostatic

precipitators.

Equipment Problems Resulting from Fuel

Switching

The extent of the impact of fuel switching on plant

operation depends on the original plant design and the

specific coal considered for the fuel switch. Although

potential equipment problems vary on a case-by-case

basis, there are several common problems for a typical

unit switching to a subbituminous western coal. The

following discussion identifies some of the major

problems and the methods for addressing them.

Coal Handling System: Depending on the origin and

delivery route of the western coal, it could arrive

frozen, causing problems during coal unloading.

Unloading facilities may have to be modified if the

current system is not capable of handling frozen coal.

These modifications could range from the addition of

coal car rappers to the construction of a coal car

preheating facility.

26J.R. Gunderson, S.J. Selle, and N.S. Harding, “Utility Experience Blending Western and Eastern Coals—Survey Results,” paper

presented at the Engineering Foundation Conference on Coal Switching and Blending of Western Low Sulfur Coals (Salt Lake City, UT,

September 26, 1993). 27This occurs because the reduction in sulfur content lowers the sulfur oxidation process in which sulfuric acid is formed and condenses

on the fly ash particles and produces an electrically conducive film that makes the electrostatic precipitator process effective.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

18 Clean Air Act Amendments of 1990
Western coal brittleness and dust-forming characteristics require additional dust suppression equipment to

reduce the potential of explosions. Higher coal volatility, accumulation of coal dust on surfaces, and

exposure of coal dust to electrical contacts increases the

possibility of fire. It may be necessary to reduce conveyor speeds to control coal spillage and coal dust

release to surrounding areas. Transfer points, bins, and

bunkers may need to be enclosed or equipped with additional skirting structures and belt wipers. Also a

fabric filter collecting the dry particulate matter as the

cooled flue-gas passes through or wet dust suppression

system may be required.

The lower Btu content of the coal will require greater

volumes of fuel and will affect long-term and shortterm storage requirements. The high moisture content

and increased fineness reduce movement on the conveyor and may require additional conveyor capacity.

Western coals also become more cohesive when wet,

causing plugging in crushers, feeders, chutes, and coal

silos. Required modifications can include replacement

of or lining existing equipment.

Fuel Preparation and Firing System: The lower HGI,

higher moisture content, and increased inlet feed size

typical of western coal increase time requirements in

the fuel preparation stage, thereby decreasing coal

throughput capacity. High-moisture western coals

require more drying than low-moisture bituminous

coals. This may be offset to a slight degree by a reduction in the required fineness. Reduced throughput may

necessitate bringing an additional mill into service,

installing an additional mill, or replacing all mills.

Western coal brittleness and dust-forming characteristics, coupled with the higher inlet temperatures

required for drying the coal, increase the chance of mill

explosions. Inerting systems, explosion venting, and

additional water hoses and fire extinguishers may be

required.

Primary Air System: The high moisture and increased

fuel burn rate of western coals require larger volume

and higher temperature primary air, increasing the

requirements on primary air fans and air heaters. If

primary air flow is insufficient to convey and dry the

coal, modifications to primary air fan blades, wheels, or

motors may be needed, or fan replacement may be required. If temperatures cannot be maintained at higher

flows, air heater performance can be upgraded by

replacing existing air heater baskets with high-density

baskets or adding in-duct air heaters (Figure 4).

Steam Generator: Western coals typically have a

higher propensity to slag and foul, increasing the

difficulty of removing deposits on water wall surfaces.

If tube cleanliness cannot be maintained because of ash

deposits that are difficult to remove, heat transfer to the

walls decreases, increasing heat input requirements and

thereby decreasing boiler efficiency. Higher furnace

temperatures may lead to further slagging or fouling

problems. Increased fouling may reduce heat transfer to

the convective surfaces, thereby increasing the economizer (a counterflow heat exchanger for recovering

energy from the flue gas) gas outlet temperature and

decreasing boiler efficiency.

Ash deposits caused by western coals may also increase

the difficulty of removing the slag or foul deposits.

Additional steam or air soot blowers and water cleaning may maintain cleanliness; however, tube erosion

problems resulting from additional soot blowing or

cleaning will also increase. Boiler unit availability will

be reduced if unit load must be decreased for slag shed

or if additional tube failures cause more outages.

Higher gas volumes and temperatures entering the convective pass (the horizontal and vertical downflow

sections of the boiler enclosure) may also reduce net

turbine efficiency. Higher moisture content increases

latent heat losses, decreasing boiler efficiency. Higher

fuel burn rate due to larger volume causes higher duty

requirements in several systems and increases auxiliary

power requirements. Increased spray treatment may

increase net turbine heat rate. These all decrease the

efficiency of the power plant.

Particulate Removal System: Sodium, an essential

chemical for charging particulate matter for capture by

the electrostatic precipitator is more easily depleted

from western coals. A layer of ash, resistant to being

charged, accumulates on the precipitator causing the

degrading of the performance and necessitating manual

cleaning. Sodium treatment of the particulate material

can be used to reduce ash resistivity and improve the

precipitator performance.

Ash and Waste Disposal: The low ash content typical

of western coal will have little impact on the typical ash

and waste disposal system; however, the high calcium

oxide content of some western coals can cause ash to

harden when wet. Avoiding these buildups may

require conversion from a wet to a dry ash disposal

system.

Building and Structural Support: The brittleness and

dust-forming characteristics of western coals may

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 19
Boiler

Burners

Coal pulverization Coal supply

Stack

Induced

draft fan

SO2

scrubber

Particulate

collector

Water from

heaters

Combustion air

Steam to Turbine-Generator

to Produce Electricity

Fuel

Primary

air fan Forced

draft

fan

Air Heater

Air

Figure 4. Coal-Fired Utility Steam Generator Schematic

Source: Steven C. Stultz and John B. Kito, eds., Steam: Its Generation and Use, 40th ed. (Barberton, OH: Babcock and Wilcox

Co., 1992), p. 1-4.

require modifications to the boiler building, as well as

to coal handling and other coal contact areas and

structures, to prevent dust buildup and reduce explosion potential. Since dust collects on horizontal surfaces,

exterior wall panels may have to be moved inside the

supporting structure to prevent coal dust from accumulating on the structural beams. Additional ventilation

may be necessary to supply makeup air, especially if a

dry dust bag house collection system is installed. Some

areas may need to be pressurized to prevent infiltration

of coal dust. Electrical systems such as junction boxes,

conduits, and plug receptacles may require modification to be dust ignition-proof. Cable trays may need to

be moved or covered, and motors and control systems

may need to be upgraded or enclosed. Expansion of the

existing fire protection system may also be necessary.

Plant Cleanup and Maintenance: Proper plant cleanup

schedules reduce the presence of stray coal, which

reduces the chance of fires and explosions. Necessary

equipment upgrades for cleanup could include the

addition of water hoses and runoff drains or the installation of a vacuum system. In addition to good

housekeeping practices, maintenance procedures may

need modification to ensure a safe working environment.28

The Effects of Fuel Switching on Power

Plant Costs, Coal Distribution, and

Production

A wide range of capital costs can be incurred in converting a power plant from high-sulfur to low-sulfur

28John H. Pavlish, April Anderson, and Neil C. Craig, “Using the CQIM to Evaluate Switching to Western Low-Sulfur Coals,” Black

& Veatch, paper presented at the Engineering Foundation Conference on Coal Switching and Blending of Western Low Sulfur Coals (Salt

Lake City, UT, September 26, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

20 Clean Air Act Amendments of 1990
Compliance with Phase I may result in changes in coal

distribution patterns and transportation rates; however,

because of the variety of compliance strategies, the impacts of

the law on coal and coal transportation markets are highly

uncertain.

coals. Information compiled from eight case studies to

assess the potential effects of coal switching indicates

that the costs may vary from $25 to $119 per kilowatt

of capacity (Table 8).29 The studies included two

conversions to eastern low-sulfur coal and six to

western low-sulfur coal. The two plants changing to

eastern coals had capital costs of $25 and $31 per

kilowatt, both for electrostatic precipitators. All six

western coal cases had higher costs, and only western

coal cases required modifications to reduce fire and

explosion hazards. Dust control capital costs ranged

from $6 to $28 per kilowatt. The capital costs for modifications for fire protection ranged from $12 to $33 per

kilowatt. The capital costs for modifications to reduce

or eliminate facility and performance shortcomings

such as modifications to pulverizers and electrostatic

precipitators ranged from $18 to $86 per kilowatt. The

highest capital costs to modify plants changing to

western coal were also for modifications to electrostatic

precipitators.

Another study has reviewed the capital costs of the coal

handling system modifications required to switch to

low-sulfur blends for three electric utilities in the

Midwest.30 One plant made several modifications to

the conveyor system and added ventilation fans, dust

suppression systems at conveyors, and some housekeeping equipment. The installation was completed

over an 11-month period and cost $8 per kilowatt.

Another plant installed a new blending system, requiring 18 months for the modification and costing $14

per kilowatt. A third plant made extensive modifications to the reclaim belt conveyor system, including

new electronically controlled belt feeders, new dust

suppression and collection systems, and a new

programmable logic control system for the entire coalhandling process at a cost of $30 per kilowatt.31

Fuel costs may change when a plant switches to lowsulfur coal. In 1992, the coal receipts of the plants

planning to switch to low-sulfur coal totaled 133.2

million short tons. The five States from which the

largest amounts of coal originated were Illinois,

Kentucky, West Virginia, Ohio, and Pennsylvania.

Other States from which coal originated were Alabama,

Colorado, Indiana, Iowa, Maryland, Missouri, Tennessee, Utah, Virginia, and Wyoming. (Appendix A

contains a listing of the origin of the coal received in

1992 at plants planning to switch or blend). Their

average Btu content was 11,739 Btu per pound, average

sulfur content was 2.22 percent by weight and average

delivered coal cost was $35 per short ton.

The average fuel costs of all plants planning to switch

to a low-sulfur coal are not expected to increase

significantly because of two factors:

• The potential excess productive capacity of the

regions selected as new sources of coal

• It is expected that fuel costs for some plants may

increase and others decrease as plants switch to

coal from the Central Appalachian Region and the

Powder River Basin.

Fuel switching will have some effects on production

and distribution of low-sulfur coal. Over the last 3

years (from 1989 to 1992), receipts of low-sulfur coal

29Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992). 30Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low-Sulfur Coal,” Sargent and

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Altanta, GA, October 18-22, 1992). 31Some of these costs were for new electrical work that was not related to coal blending.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 21
Table 8. Capital Expenditures for Modifications Associated with Switching to Low-Sulfur Eastern and

Western Coal

(1992 Dollars per Kilowatt)

Issues

Case Studya

Eastern

Coal Region

Western

Coal Region

1 2 3 4 5 6 7 8

Fire and Explosion Issues

Dust Control

Dust Suppression . . . . . . . . . . . . . . . . 0.0 0.0 0.2 2.1 2.5 1.9 2.1 1.4

Dust Collection . . . . . . . . . . . . . . . . . . 0.0 0.0 1.1 3.0 4.5 9.3 3.4 3.3

Ventilation . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.7 1.2 3.2 3.6 5.7 4.1

Housekeeping . . . . . . . . . . . . . . . . . . . 0.0 0.0 3.3 0.6 3.1 0.9 0.6 0.9

Electrical Component Replacement or

Relocation . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.2 2.6 0.0 12.3 2.5 3.4

Subtotal . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 5.5 9.5 13.3 28.0 14.3 13.1

Fire Protection

Additional Coverage . . . . . . . . . . . . . . 0.0 0.0 5.4 0.6 4.9 0.9 3.0 2.8

Explosion Venting . . . . . . . . . . . . . . . . 0.0 0.0 0.0 0.6 0.0 1.0 0.8 0.8

Bunker/Silo/Pulverizer Inerting . . . . . . . 0.0 0.0 1.1 0.6 3.1 1.7 2.0 0.9

Emergency Bunker/Silo Unloading . . . . 0.0 0.0 1.1 0.4 1.4 0.8 2.2 1.2

Conveyor Modifications . . . . . . . . . . . . 0.0 0.0 0.2 0.0 0.0 0.0 0.4 0.0

Subtotal . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 7.8 2.2 9.4 4.4 8.4 5.7

Total Fire and Explosion . . . . . . . . . 0.0 0.0 13.3 11.7 22.7 32.4 22.7 18.8

Facilities and Performance Issues

Steam Generator . . . . . . . . . . . . . . . . . 0.0 0.0 10.1 0.0 0.0 0.0 0.0 10.3

Pulverizers . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 2.2 0.0 0.0 0.0 10.7 0.5

Sootblowers . . . . . . . . . . . . . . . . . . . . 0.0 0.0 3.2 0.0 2.1 0.0 0.0 0.0

Fans . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 1.3 0.0 0.0 0.0 5.4 0.0

Precipitators .................... 24.9 31.0 0.0 46.4 24.9 74.4 12.8 5.3

Coal Handling . . . . . . . . . . . . . . . . . . . 0.0 0.0 1.5 2.0 3.7 1.9 9.7 11.2

Ash Handling . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 7.8 0.0 9.9 8.3 5.7

Auxiliary Power . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 1.0 0.9 0.0 2.4 1.5

Total Facilities and Performance . . . 24.9 31.0 18.3 57.2 31.6 86.2 49.3 34.5

Grand Total ...................... 24.9 31.0 31.6 68.9 54.3 118.6 72.0 53.3

Derating (percent) ................. 0.0 0.0 15.0 0.0 7.5 0.0 0.0 0.0

a

Eight case studies were presented in the report considering eight unnamed plants.

Note: Costs include equipment, material, labor, and contingency.

Source: Romas L. Rupinskas and Paul A. Hiller, “Considerations for Switching from High-Sulfur Coal to Low Sulfur Coal,” Sargent &

Lundy, paper presented at the 1992 International Joint Power Generation Conference and Exposition (Atlanta, GA, October 18-22, 1992).

show slight regional increases in anticipation of acid

rain legislation as indicated by receipts at U.S. electric

utilities from the Central Appalachian Region in 1989 of

131.9 million short tons of low-to-medium sulfur coal,

compared with 135.9 million short tons of low-tomedium sulfur coal from the Central Appalachian

Region in 1992. Likewise, U.S. electric utilities received

215.8 million short tons of low-to-medium sulfur coal

from Wyoming, Montana, and Colorado in 1989 and

235.2 million short tons of low-to-medium sulfur coal

from this region in 1992 (Table 9).

About 34 of the plants planning to switch to low-sulfur

coal have already decided where they will obtain the

low-sulfur coal. Thus far, two-thirds have chosen the

Central Appalachian Region and one-third have chosen

the Powder River Basin as the new source of coal. It is

estimated that these plants will require about 24 million

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

22 Clean Air Act Amendments of 1990
Table 9. Coal Receipts at Electric Utility Plants by Supply Region and Sulfur Dioxide Level,

1989 and 1992

(Thousand short tons)

Supply Region

1989 1992

Low to

Medium

SO2

a

High

SO2

b Total

Low to

Medium

SO2

a

High

SO2

b Total

Central Appalachia .............. 131,889 12,213 144,102 135,853 4,349 140,202

Eastern Kentucky ............. 76,031 9,451 85,482 74,521 2,321 76,842

Virginia ..................... 16,192 1,807 17,999 15,178 1,370 16,548

Southern West Virginia ......... 39,666 955 40,621 46,154 658 46,812

Mountain ..................... 215,835 27 215,862 235,182 184 235,366

Wyoming ................... 165,633 -- 165,633 181,368 184 181,552

Montana .................... 36,063 18 36,081 37,309 -- 37,309

Colorado .................... 14,139 9 14,148 16,505 -- 16,505

Illinois Basin ................... 9,478 106,462 115,940 7,136 112,870 120,006

Illinois ...................... 7,598 46,220 53,818 4,236 50,268 54,504

Indiana ..................... 1,734 25,431 27,165 2,454 22,472 24,926

Western Kentucky . . . . . . . . . . . . . 146 34,811 34,957 446 40,130 40,576

a

Low to Medium SO2 level is less than or equal to 2.5 pounds of sulfur dioxide per million Btu. b

High SO2 level is greater than 2.5 pounds of sulfur dioxide per million Btu.

SO2 = Sulfur dioxide.

Source: Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants, DOE/EIA-0191 (Washington, DC, 1989

and 1992).

tons of coal from the Central Appalachian Region in

order to reach the Phase I emission level goal of 2.5

pounds SO2 per million Btu in 1995 and about 12 million tons from the Powder River Basin.32

Both the Central Appalachian Region and the Powder

River Basin potentially have the productive capacity to

meet the demands of complying with the Clean Air Act

Amendments of 1990 (CAAA90). In 1992, mines east of

the Mississippi River operated with an excess capacity

of about 20 percent, implying that southern West Virginia, Virginia and the eastern Kentucky region could

produce an additional 65 million tons of coal without

a significant increase in mine cost or minemouth price.

In the West, mines in the Powder River Basin operated

with an excess capacity of about 22 percent in 1992,

implying that the States of Montana and Wyoming

could produce an additional 78 million tons of coal

without significant increases in mine cost or minemouth

price.33

Obtaining Additional Allowances

Another option for complying with the CAAA90 is for

an affected unit to acquire additional SO2 allowances

that will cover its emissions. Every Phase I affected

unit, as well as Phase II affected units in the year 2000,

must possess a number of allowances equal to its emissions. Thus, every affected unit must use allowances to

comply with the Acid Rain Program. Units are given an

initial quantity of allowances, based on their average

fuel consumption in 1985 through 1987 times a 2.5

pound SO2 per million Btu emission rate for Phase I. In

most cases, this initial distribution is not sufficient to

meet the amount of SO2 that the unit is expected to

emit starting in 1995.

For each individual unit, a sufficient strategy to meet

the clean air requirements is to acquire enough additional allowances to cover their expected emissions.

32See Appendix A for the methodology used to calculate these estimates.

33Energy Information Administration, Coal Production 1992, DOE/EIA-0118(92) (Washington, DC, November 1993), p. 68.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 23
Ohio Edison’s Niles facility will use allowances for compliance

on unit 1 and a flue gas desulfurization technology on unit 2.

Notwithstanding the small number of supplemental

allowances allocated by the EPA, utilities must obtain

additional allowances from other utilities that have

reduced their emissions below their annual allocation.

Because the total number of allowances for any one

year is fixed, and is less than the emissions expected to

be produced by all of the affected units, not all utilities

may choose the strategy of acquiring additional allowances. Thus, there are not enough allowances for every

unit to purchase allowances to cover its expected

emissions.

One way for utilities to acquire additional emission

allowances is to purchase them from a current allowance owner. This process constitutes the private

allowance market. In addition, there are two institutions

specified by the CAAA90 to foster the exchange of

allowances—an allowance auction and an allowance

sale.

Private Allowance Market

As of December 20, 1993, nine private market Phase I

allowance sales have been announced. This number

includes only firm purchases; there have also been

several options to purchase allowances and to barter

allowances between utilities. These sales in 1992 and

1993 have exchanged more than 350,000 allowances; for

those where the cost was reported, the average amount

paid for each allowance was between $178 and $276

(current dollars).34

Many observers have been disappointed in the small

number of private sales that have been announced.

Several factors may be restricting the private allowance

market. One may be the adverse publicity surrounding

one of the early sales of allowances. Wisconsin Power

and Light was criticized for limiting future economic

growth in the State of Wisconsin due to its sale of

allowances to the Tennessee Valley Authority, while the

Tennessee Valley Authority was criticized for importing

pollution into its service area. These problems for both

sides of the sale have decreased the enthusiasm of other

utilities to trade allowances.

Another inhibiting factor may be the uncertainty associated with a sale or purchase of allowances. Utilities are

often unsure how a sale of allowances would be treated

by the State Public Utility Commissions, because many

State commissions have not specified how they will

treat allowance sales and purchases. Of course, not

selling or purchasing allowances could also be received

unfavorably by a State commission; apparently, omitted

actions are considered less risky by many utilities than

committed actions. Another uncertainty rests with how

much of the savings that a utility gains by trading

allowances will the State commissions allow the utility

to keep and how much must be returned to share

holders.

The novelty of emissions allowance markets may be

inhibiting utilities from trading. The allowance market

system specified by CAAA90 has not been used before

on such a wide scale and may be unfamiliar to many

utilities; they have become comfortable with the

command and control systems specified by earlier clean

air legislation.

Finally, individual utilities may be trading allowances

among their own plants, but not with another utility.

This would occur if individual utilities had a broad

range of compliance costs among their plants, so that

efficient trading could occur within individual utilities.

These intra-utility trades may not have been announced

yet. In fact, even some inter-utility trades that have

been negotiated may not have been announced.

34“Publicly Announced Phase I Allowance Transactions,” Compliance Strategies Review 4, 24 (December 20, 1993), p. 4.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

24 Clean Air Act Amendments of 1990
Sulfur Dioxide Allowance Auctions and

Sales

The EPA was required by the CAAA90 to hold annual

emission allowance auctions and sales for a small portion of the total allowances distributed each year. The

auctions and sales are intended to provide a limited

source of additional allowances for affected units,

including independent power producers in Phase II.

The auctions also are expected to provide some information to market participants about allowance prices,

although this purpose has to some extent been

thwarted by the design of the auction.

The EPA offered 150,000 allowances for sale at the first

auction, conducted by the Chicago Board of Trade for

the EPA on March 29, 1993, and will do so again in

1994 and 1995; it will offer 250,000 allowances annually

from 1996 through 1999 and 200,000 annually starting

in 2000 from a special reserve of allowances that otherwise would have been allocated to affected units. The

revenue raised at these auctions is returned to the

affected units on a pro-rata basis. The auctions use

sealed bids and award allowances to the highest bidders at their bid price. Allowances also can be offered

for sale by private (non-EPA) holders at an EPA

auction; they are traded after the allowances from EPA

are sold, in order, from lowest to highest. Each auction

is separated into two markets, spot and advance. The

spot market trades allowances that can be used in the

same year (for 1993 and 1994, the “same” year is 1995)

as the auction, and the advance market trades

Quantity (Thousands)

Price (Dollars)

0 50 100 150 200 250 300 350 0

0

500

1,000

1,500

EPA

Supply

Private

Supply

Demand

Figure 5. 1995 SO2 Emission Allowance (Spot Market) Supply and Demand at the EPA Auction,

March 29, 1993

SO2 = Sulfur dioxide.

EPA = U.S. Environmental Protection Agency.

Source: U.S. Environmental Protection Agency, Information Package on First Acid Rain Allowance Auctions (April 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 25
allowances that cannot be used until 7 years after the

auction.

In the March 1993 spot market, for allowances usable

beginning in 1995, 50,000 allowances were sold by EPA,

with successful bids ranging from $450 to $131. In

addition, 10 allowances offered by a private holder

were sold for $131. For the 100,000 allowances offered

by EPA in the advance market, for allowances usable

beginning in 2000, successful bids ranged from $310 to

$122; no privately-held allowances were traded in this

market.

Carolina Power and Light purchased the majority of the

allowances—85,103 in both markets—for a total of $11.5

million or a price that averaged $135 each. Brokerage

firms, businesses, public interest groups, and private

investors made up a small portion of the bidders. The

largest number of allowances purchased by a bidder

that was not an electric utility—Cantor Fitzgerald, a

New York broker—was 2,572.

The winning price ranges show only a fraction of the

bids and offers. Many more bids were submitted at

lower prices, and most offers were submitted at higher

prices; because most of these bids and offers did not

match, they were not executed. The full range of

activity in the markets included bids for more than

321,000 allowances for 1995 (Figure 5), and more than

283,000 allowances for 2000 (Figure 6). Because the

auction rules specify that the EPA-offered allowances

are to be sold first, the supply of allowances offered by

private sources is shown added to the right of the EPA

supply, which is a vertical line (perfectly inelastic)

because there is no reserve price for them.

Quantity (Thousands)

Price (Dollars)

0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 0

0

50

100

150

200

250

300

350

400

450

EPA

Supply

Private

Supply

Demand

Figure 6. 2000 SO2 Emission Allowance (Advance Market) Supply and Demand at the EPA Auction,

March 29, 1993

SO2 = Sulfur dioxide.

EPA = U.S. Environmental Protection Agency.

Source: U.S. Environmental Protection Agency, Information Package on First Acid Rain Allowance Auctions (April 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

26 Clean Air Act Amendments of 1990
Table 10. 1995 SO2 Emission Allowance (Spot Market) Bids at the EPA Auction, March 29, 1993

Bid

Price

Bid

Quantity

Bid

Price

Bid

Quantity

Bid

Price

Bid

Quantity

Bid

Price

Bid

Quantity

450 1 150 1 100 20,000 51 80

369 1 150 69 96 142 51 133

350 1 150 500 92 35,400 50 1

280 1 150 10,000 90 3 50 100

251 1 142 2,914 88 2,750 50 2,000

234 1 141 48 85 851 50 4,000

225 1 138 972 81 20 50 5,000

208 2 132 1,567 80 500 50 11,750

201 1,000 131 3,800 78 5 50 25,000

200 1 130 1 77 2,500 38 50

200 1 130 10,000 77 2,500 26 10

200 1 128 3 77 2,500 11 100

200 500 128 729 77 2,500 11 2,272

176 3,000 126 81 77 2,500 10 1,000

175 1 122 848 77 2,500 10 1,000

175 5,000 122 27,709 76 134 6 1,000

173 70 120 100 76 1,000 5 50,000

171 604 108 3 66 103 3 300

170 2,572 106 128 65 4 2.6 100

162 1,277 101 1,000 60 1,400 2 200

158 3 101 5,000 58 10 2 5,000

157 2,636 100 2 52 2,665 1 250

156 446 100 10 52 2,665 1 7,000

152 45 100 50 52 2,665 1 10,000

152 4,085 100 200 52 2,665 0.26 1,000

151 3,300 100 500 52 2,665

151 8,900 100 1,000 52 2,675

SO2 = Sulfur dioxide.

EPA = U.S. Environmental Protection Agency.

Note: Bids outlined with thick lines were winning bids; the lowest winning bid was only partially filled.

Source: U.S. Environmental Protection Agency, Information Package on First Acid Rain Allowance Auctions (April 1993).

In the auction for 1995 allowances, bids for more than

242,000 allowances were submitted at $50 or more, but

bids for only 1,512 allowances were submitted at $200

or more (Tables 10 through 13). Of the more than

91,000 private offers at $600 and below, only 10 allowances were offered at $200 and below. Similarly, in the

auction for 2000 allowances, bids for more than 145,000

allowances were submitted at $50 or more, but bids for

only 106 allowances were submitted at $200 or more.

Of the 30,500 private offers at $449 and below, no

allowances were offered at prices below $200, although

12,000 were offered at $200. Many of the offers in both

auctions were part of an ordered series, suggesting that

there may have been only a few private suppliers

making many of the offers in the two auctions. Without

the supply of allowances offered by EPA, only 10 of the

1995 allowances would have been traded, with a

market-clearing price of $201, and only 106 of the 2000

allowances would have been traded, with a marketclearing price of $200.

There are two complications to interpreting the results

of the EPA auction. One is the price discrimination

(exchange of different units of the same good at price

differentials not related to differences in their cost of

supply) that was specified in CAAA90.35 The lowest

winning bids in each market, $131 for 1995 allowances

and $122 for 2000 allowances, are the market-clearing

prices. If there had been no price discrimination in the

auctions so that a single price was determined for each

market, these two prices, $131 and $122, would have

equilibrated demand and supply. The price discrimination that did occur in the auctions did not affect the

quantity of allowances exchanged. It did increase the

prices paid by those buyers willing to pay more than

the market-clearing price. In doing so it redistributed

35For an analysis of price discriminating auctions, see James C. Cox, Vernon L. Smith, and James M. Walker, “Theory and Behavior of

Multiple-unit Discriminative Auctions,” Journal of Finance 39,4 (September 1984), pp. 983-1010.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 27
Table 11. 2000 SO2 Emission Allowance (Advance Market) Bids at the EPA Auction, March 29, 1993

Bid

Price

Bid

Quantity

Bid

Price

Bid

Quantity

Bid

Price

Bid

Quantity

310 1 136 87 43 10

275 1 132 3,135 41 117

251 1 131 100 41 8,000

240 100 128 1,234 40 25,000

207 1 126 114 31 5,000

200 1 125 1 26 138

200 1 122 1,696 23 50

171 24 122 55,416 20 1

171 1,209 117 41 11 100

166 30 101 500 11 2,272

162 2,554 101 2,500 6 830

161 37 85 2,282 6 1,000

157 5,272 82 58 5 75,000

156 45 78 5 3 500

152 8,170 76 10,000 3 1,000

151 54 62 5,000 2 5,000

151 300 61 5,000 1 250

147 25,000 56 128 1 250

146 64 52 7,000 1 1,010

142 5,830 51 100 1 7,000

141 75 50 2,000 0.01 5,000

141 709 45 2

SO2 = Sulfur dioxide.

EPA = U.S. Environmental Protection Agency.

Note: Bids outlined with thick lines were winning bids; the lowest winning bid was only partially filled.

Source: U.S. Environmental Protection Agency, Information Package on First Acid Rain Allowance Auctions (April 1993).

more money from buyers to sellers than a single-price

auction would have.

More importantly, discriminatory pricing schemes encourage strategic bidding behavior (not revealing their

true demand for allowances) by market participants,

because the bid prices and not the market-clearing price

become the prices at which allowances are exchanged.

Strategic behavior by participants may, in general,

distort the results and efficiency of a market. In particular, since bidders knew they would pay their bid

price and not the market clearing price, they would be

expected to “under-reveal” their “true” demand for

allowances by bidding less than they would have had

the price discrimination not occurred.36 Concurrently,

since sellers knew that private allowance offers were to

be executed in order, from lowest to highest, they

would be expected to price their offers strategically and

not correctly reveal their “true” supply of allowances.

An extreme manifestation of strategic behavior may

have been the offer of 10 allowances in the 1995 auction

at $10 each. The auction rules, stipulated by Congress,

require that privately offered allowances be exchanged

at the bid price (not the offer price) and sold in

ascending order, starting with the allowances which

have the lowest minimum price requirements. Given

these rules, this lowest minimum price offer may have

been a strategic one to ensure that the corresponding

allowances would be the first, and therefore the

highest-priced, privately held allowances sold at the

auction. No other allowances were offered at either

auction by private holders for less than $200.

One less ambiguous result of the auction was the confirmation that allowances will be more valuable in 2000

(Phase II) than in 1995. When viewed solely as financial

instruments, with everything else held constant, the

prices of the 1995 and 2000 allowances should be quite

different because of the time value of money. If 1995

and 2000 allowances are viewed as providing the same

stream of benefits (avoiding the same stream of costs),

then the 1995 allowances are more valuable than the

2000 allowances, because they potentially begin

36For a general analysis of auctions, see Paul Milgram and Robert Weber, “A Theory of Auctions and Competition Bidding,” Econometrica

50, 5 (September 1992), pp. 1089-1122.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

28 Clean Air Act Amendments of 1990
Table 12. 1995 SO2 Emission Allowance

(Spot Market) Offers at the EPA

Auction, March 29, 1993

Offer

Price

Offer

Quantity

Offer

Price

Offer

Quantity

10 10 250 2,500

210 5,000 255 2,500

210 5,000 361 1,000

225 5,000 375 10,000

230 2,500 400 5,000

235 2,500 600 45,000

240 2,500 1,900 1,900

245 2,500 1,900 2,100

SO2 = Sulfur dioxide.

EPA = U.S. Environmental Protection Agency.

Note: Offer outlined with thick lines was only accepted offer.

Source: U.S. Environmental Protection Agency, Information

Package on First Acid Rain Allowance Auctions (April 1993).

providing benefits 5 years earlier than 2000 allowances.

In present value terms, assuming a discount rate of 15

percent,37 a stream of benefits beginning in 2000 is

worth only about 50 percent of the same benefits beginning in 1995. This calculation suggests that, if 1995 and

2000 allowances were equally valuable to their holder

at the time each could first be used, 1995 allowances

would have twice the market value of 2000 allowances

in 1993. However, in the auctions, 2000 allowances had

a market-clearing price only 7 percent below 1995

allowances. Therefore, given the time value of money,

the auctions valued an allowance useable in 2000 more

highly than one useable in 1995. An alternative way to

reach a similar conclusion is to calculate the future

value of 2000 allowances in the year 2000 and the

future value of 1995 allowances in the year 1995, assuming a particular rate of return and the 1993 auction

relative prices. Using a (riskless) rate of return of 3

percent, 2000 allowances in 2000 were valued at 25 percent more than 1995 allowances in 1995 by the auction.

Using a rate of return of 10.8 percent,38 2000 allowances are valued at 80 percent more than 1995

allowances, and, using a rate of return of 15 percent,

2000 allowances are valued at 116 percent more than

1995 allowances. Of course, 2000 is the year when the

more stringent and extensive limits of Phase II of

CAAA90 take effect.

Table 13. 2000 SO2 Emission Allowance

(Advance Market) Offers at the

EPA Auction, March 29, 1993

Offer

Price

Offer

Quantity

Offer

Price

Offer

Quantity

200 2,000 340 100

200 10,000 345 105

280 40 350 110

282 1,500 355 115

285 45 360 120

290 50 365 125

295 55 370 130

297 5,000 375 135

300 60 377 1,000

300 2,000 380 140

305 65 385 145

307 5,000 390 150

310 70 395 155

315 75 400 160

320 80 400 1,000

325 85 449 250

330 90 449 250

335 95

SO2 = Sulfur dioxide.

EPA = U.S. Environmental Protection Agency.

Note: No offers were accepted.

Source: U.S. Environmental Protection Agency, Information

Package on First Acid Rain Allowance Auctions (April 1993).

Flue Gas Desulfurization Retrofits

Installing flue gas desulfurization equipment (scrubbers) is a capital-intensive strategy for complying with

Phase I SO2 limitations. As such, the initial cost of this

strategy is greater than the initial cost for other

responses, although the operating costs may be less. In

addition, the utility industry has had substantial experience with scrubbers, which were required on some

electric power generating plants by earlier environmental regulations and have been installed on some

utility boilers for several decades. It is estimated that

scrubbers will account for a large share of the required

SO2 emissions reduction in Phase I of the CAAA90.

The initial cost of retrofitting a plant with a scrubber

varies dramatically, depending on the characteristics of

37Discount rates used by businesses are often much higher than their cost of capital. Fifteen percent was the median discount rate found

in a recent study. See Lawrence H. Summers, “Investment Incentives and the Discounting of Depreciation Allowances,” in Martin

Feldstein, ed., The Effects of Taxation on Capital Accumulation (University of Chicago Press, Chicago, IL, 1987), p. 300. For a possible

explanation of this high discount rate, see Avinash Dixit, “Investment and Hysteresis,” Journal of Economic Perspectives 6, 1 (Winter 1992),

pp. 107-132. 38For an estimate of the investor-owned electric utility cost of capital, see Energy Information Administration, Assumptions for the Annual

Energy Outlook 1993, DOE/EIA-0527(93) (Washington, DC, January 1993), p. 94.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 29
the electricity generating plant where they are installed

as well as the characteristics of the scrubbers themselves. This report presents two methods to estimate

these costs which were developed in two separate

studies sponsored by the Energy Information Administration (EIA).39 One is based on historical accounting

records of costs. The historical cost approach uses

econometric techniques to analyze the recorded costs

and their statistical relationship to other scrubber

characteristics. For example, these techniques estimate

how much the cost of a scrubber increases as the size

of the electricity generator associated with it increases.

The other method used in this report is based on recent

engineering design and cost estimates. Expert engineers

use currently available technology to design a scrubber

and estimate its cost based on the components of the

design.

These two estimating methodologies offer distinct

advantages and disadvantages. The most important

distinction is that historical cost estimates are based on

actual recorded costs, while engineering costs are

estimated by the expert engineer. Engineering cost

estimates may differ from the actual costs that would

be incurred if the designed scrubber were built. However, engineering cost estimates use currently available

technology, which would be available to future builders, for their design. Historical cost estimates are based

on the technology existing at the time they were built;

they do not take into account current design technologies or current costs.

Estimates Based on Historic Costs

The historical cost estimating methodology uses econometric techniques to analyze data regarding scrubbers

that are collected by EIA on Form EIA-767, “SteamElectric Plant Operation and Design Report.” This form

has been used to collect plant operations and equipment design information on all fossil-fueled steamelectric generating plants in the United States with a

nameplate capacity of 10 or more megawatts since 1986.

The form pays particular attention to the scrubber units

at those plants.

Sample Characteristics

This sample contains 32 flue gas desulfurization units

that have been installed for normal production use after

the boilers were initially built (retrofit) and were

operating between 1985 and 1991. These units have 12

gigawatts of electricity generating nameplate capacity.

Extension Allowances for Units Installing High-Efficiency Control Technologies

An additional incentive to install high-efficiency control technologies has resulted from the creation of extension allowances.

The CAAA90 specify that a pool of 3.5 million allowances, called “Phase I extension allowances,” be made available to (1)

control units that install a technology that removes 90 percent or more of their SO2 emissions and begin operation by

January 1, 1997, or (2) control units and other units that use a different compliance strategy but are associated with the

control unit in the extension allowance application. The extension allowances do not extend the dates by which qualifying

units must acquire allowances for their emissions. They do allocate, at no charge, additional allowances to utilities so that

they may emit SO2 above their annual allocation of allowances.

Seventeen utilities submitted final requests for extension allowances. Since the total number of requests was for more than

4 million allowances, EPA used a lottery to distribute the extension allowances. The number of allowances awarded to the

winning applicants becomes final when EPA issues an Acid Rain Permit to the utility.

However, all utilities in the lottery, except for Potomac Electric Power, voluntarily joined a pool that agreed to share any

extension allowances received by its members. Potomac Electric Power was ranked third in the lottery, but its request for

allowances was denied by the EPA. That leaves the entire 3.5 million extension allowances for the 16 utilities in the pool,

which agreed to share them on a pro-rata basis, with those that won in the lottery receiving a slightly higher pro-rata share

than those that lost. Based on the 88 percent pro-rata share, the largest recipients of extension allowances, conditional on

EPA approval, are American Electric Power, with approximately 750,000 allowances, and the Tennessee Valley Authority,

with approximately 710,000.

39United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired

Power Plant, UE&C/EIA: 921005 (Philadelphia, PA, October 1992) and Decision Analysis Corporation of Virginia, “Regression Models

for Analysis of Retrofit Flue Gas Desulfurization Unit Cost and Performance” (Vienna, VA, May 28, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

30 Clean Air Act Amendments of 1990
This capacity represents 17 percent of all generators

associated with scrubbers in service at electric utilities

in 1991. The average size of the generators which have

retrofit scrubbers is 365 megawatts; they range from 114

to 818 megawatts. Because some of the observations

contained problematic information, fewer units remain

in the cost estimating sample.40 Only retrofit scrubbers

are included in the sample because they are

substantially more expensive than scrubbers designed

and built with the plant, and because all the plants

installing scrubbers to comply with Phase I will be

retrofitting scrubbers. Retrofit scrubbers are more

expensive to install than original equipment scrubbers

because the plant was not designed to include them,

and therefore they may present difficult design and

construction problems (for example, a lack of physical

space for building the scrubber). It is also important

that the units in the sample be designed for normal

production use. Experimental or prototype units may

have anomalous costs.

On average, the scrubbers in the sample were installed

13 years after the boilers to which they are connected

were built, with 28 years as the longest gap between

boiler and scrubber installation. Retrofit scrubbers in

the sample were installed beginning in the early 1970’s.

The retrofit scrubber units in the sample are located in

8 States, with 5 or more units in each of 4 States,

Kentucky, New Mexico, Pennsylvania, and Wyoming.

Many of the western scrubbers were installed to meet

previous Clean Air Act requirements for “prevention of

signification deterioration” in air quality.

Design Characteristics

Scrubber designs can be characterized by the method

that they bring into contact the flue gas containing the

SO2 and the absorbent (which absorbs the SO2 from the

flue gas). Some absorbers spray the absorbent into the

flue gas, while others pass the gas over or through a

bed of the absorbent. In some, the waste from the

process is a dry solid; in others, a liquid. The most

common absorbent in the sample is limestone; lime is

second.

The sulfur dioxide removal efficiency is another important design parameter for describing a scrubber. It

specifies the proportion of sulfur dioxide removed from

the flue gas. Most of the current generation of scrubbers

are designed to remove 85 to 95 percent of the SO2. The

average removal efficiency for the sample studied was

83 percent; however, efficiencies ranged down to only

26 percent.

Scrubbers also are characterized by their energy

requirements. Electricity is needed to power the fans

that force the flue gas through the scrubber and to

power other electromechanical equipment. The design

electricity requirements for the sample of retrofit

scrubbers averaged 7 megawatts, with a range from 0.4

to 18 megawatts. In addition, thermal energy is sometimes needed to reheat the flue gas as it leaves the

absorber so it will be less corrosive.

Performance Characteristics

One of the most important performance characteristics

for a scrubber is its actual SO2 removal efficiency—that

is, the actual percentage of SO2 removed from the flue

gas during operation. The actual removal rate often

differs from the design removal rate. For the average

scrubber, the actual removal rate has been about 2 percent less than the design removal rate. However, many

scrubbers in the sample perform above their design

One method of compliance is scrubber installation, such

as the one being installed at Conemaugh. The average

scrubber can remove up to 95 percent of the SO2 in the

flue gas.

40There were several estimating samples, depending on the information necessary for the estimation being performed. For a more

extensive discussion of the data and editing procedures, see Appendix C.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 31
efficiency. There are several possible explanations for

design efficiency to exceed actual efficiency: the design

rate of SO2 removal may be greater than the rate that is

actually required; the scrubber may be more costly to

operate at its design efficiency than at a lower rate; or

the potential efficiency of the scrubber may decline over

time.

Costs of Scrubbers

Costs are generally broken down into two categories:

(1) capital costs, the total cost of installing the physical

equipment, and (2) operation and maintenance costs

(operating costs), the annual cost of running the scrubber.41 In general, the most important factors affecting

retrofit scrubber capital costs are size, efficiency, type,

and the difficulty of incorporating the scrubber into the

existing structure of the generating plant.

The statistical analysis of the sample of retrofit scrubbers identified four characteristics that were important

in estimating capital costs:

• Capacity of the associated electric generators

• Number of absorber modules in the scrubber

• Design efficiency of the scrubber (percentage of

SO2 it was designed to remove)

• Type of absorber technology.

The capital cost estimated by an econometric model

from the sample of retrofit scrubbers was $227 per

kilowatt of installed generating capacity (1992

dollars).42 There is some ambiguity as to whether the

installed capital costs include overhead costs. The

Accounting and Reporting Requirements for Public Utilities

and Licensees require that overhead construction costs be

included in the capital costs of each unit as reported to

the Federal Energy Regulatory Commission (FERC).43

However, these requirements do not specifically apply

to Form EIA-767, and some utilities reporting on the

form do not report information to FERC. An informal

survey of several reporting utilities found that some

may not include overhead costs in capital costs for

scrubbers. Excluding overhead costs understates total

capital costs. One engineering estimate of the overhead

costs for scrubbers is 21 percent of their total installed

capital costs.44

The largest cost in operating a scrubber is the cost of

the absorbent.45 For the sample of retrofit scrubbers

examined, operation and maintenance costs averaged

4.2 mills per kilowatthour, excluding the electricity

used by the scrubber.

Estimates Based on Engineering

Studies

The current engineering cost estimate for scrubbers is

based on a 488-megawatt (net) high-sulfur pulverized

coal-fired power generating station. The cost estimate

reflects the best available control technology that is

being applied in currently built plants, with an adjustment for the additional retrofit costs.46

Description of Scrubber

The scrubber system is designed to remove SO2 from

the essentially particulate-free flue gas exiting the

electrostatic precipitator from a coal-fired plant and

produce a co-mixed fly ash waste product suitable for

landfill disposal. The system design is a nonrecovery

forced-oxidation wet limestone process consisting of a

limestone unloading and storage facility; a limestone

slurry preparation system; an SO2 absorber system; a

waste slurry thickening system; a scrubber waste

product system; and a water distribution system. The

performance criterion for this design is 95 percent SO2

41The operating expenses recorded on the Energy Information Administration, Form EIA-767, “Steam-Electric Plant Operation and

Design Report,” do not include the cost of the electricity consumed by the scrubber; the physical quantity of electricity consumed is

recorded separately on the form. Scrubber operating costs on the form are broken down into feed materials and chemicals, labor and

supervision, waste disposal, and other costs. 42This cost is calculated by evaluating the regression estimating equation at the sample means of the independent variables.

Heteroscedasticity was encountered in estimating the econometric model. Remedial measures were attempted to eliminate it, but they

were unsuccessful. 43Federal Energy Regulatory Commission, FERC-0114, (Washington, DC, January 17, 1989), ¶15,054. Installed capital costs do include

the cost of major modifications, which are defined as physical changes which result in a change in the amount of pollutants emitted. They

are broken down into structures and equipment, sludge transportation and disposal system, and other capital costs. 44United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired

Power Plant, UE&C/EIA: 921005 (Philadelphia, PA, October 1992). 45Oak Ridge National Laboratory, “Nonfuel Operation and Maintenance Costs for Large Steam-Electric Power Plants—1982,”

ORNL/TM-8324 (Oak Ridge, TN, September 1982). 46United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired

Power Plant, UE&C/EIA: 921005 (Philadelphia, PA, October 1992).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

32 Clean Air Act Amendments of 1990
removal efficiency for 3.2 percent sulfur coal. This

system design provides a zero liquid discharge capability and the latest reliability features. The SO2

absorber system brings the flue gas into direct contact

with a recirculating slurry within an absorber vessel in

order to remove SO2 from the flue gas stream. The SO2

absorber system is sized to treat 100 percent of the flue

gas flow at valves wide open, 5 percent overpressure

turbine operation.

The major components of the SO2 absorber system

include spray tower type absorber modules fabricated

of rubber-lined carbon steel, recirculation pumps, mist

eliminator wash pumps and blend tank, limestone

slurry feed pumps and storage tank, dampers, agitators,

piping, valves, instrumentation, and controls. The

absorber system waste products are discharged via a

bleed stream from the recirculating slurry. The waste

slurry thickening system dewaters the bleed slurry

from the absorber module to produce a concentrated

underflow slurry and a high-quality (low suspended

solids) overflow. The underflow slurry, which contains

a minimum of 45 percent solids by weight, is pumped

to the waste product system for treatment prior to

disposal.

Costs of Scrubber

The capital costs, including direct and indirect costs, for

retrofitting scrubber structures and equipment to an

existing coal-fired plant with no spare module is

estimated to be $266 per kilowatt (1992 dollars),

including a scrubber retrofit multiplier of 1.25. The

design criteria for this scrubber is 95 percent SO2

removal efficiency which is higher than the historical

sample for scrubbers. The amount of space available to

install scrubbers is the main constraint.47

The additional nonfuel operation and maintenance

(O&M) costs for a plant retrofitting a scrubber were

determined by comparing a coal plant using bituminous 3.2 percent sulfur coal with and without a wet

limestone scrubber.48

The additional nonfuel O&M costs for retrofitting a

scrubber is $9.2 per kilowatt per year for fixed costs

and 1.6 mills per kilowatthour for variable costs. The

largest increase is in supplies and expenses (including

fixed and variable costs of $4.5 million). The variable

cost for limestone of $2.7 million and waste disposal of

$1.3 million are the two major items. The additional

onsite staff of 34 personnel is required to maintain and

monitor the scrubbers, at a cost of $1.3 million.

Previously Implemented Controls

A number of plants have already taken steps to ensure

that, by continuing their current generation practices

they will have sufficient allowances from the initial

allowance distribution to cover their emissions in Phase

I. In most cases, States had already required emissions

reductions for these Phase I plants. The States that had

such regulations were Kansas, Michigan, New Hampshire, New York, and Wisconsin.

In most cases, the State-mandated actions were required

either during or after the Phase I baseline period of

1985 through 1987. This overlap allowed the plants to

have their higher emissions calculated into the Phase I

allowance allocation equation.

In Kansas, the City of Kansas City’s Quindaro plant has

taken steps to meet State regulations that will put it in

compliance with Phase I. Although the regulations

addressed ambient air quality standards, and not just

SO2 emissions, they permitted reductions in SO2 as one

means of meeting the air quality regulations. Therefore,

in 1989, Quindaro began blending the Southern Illinois

coal that it had been using exclusively with a lower

sulfur Hanna Basin coal.49

Consumers Power’s J.H. Campbell plant was required

to convert to 1 percent sulfur coal from 2 to 3 percent

sulfur coal by the Emissions Limitations and Prohibitions—Sulfur-Bearing Compounds regulations as

issued by the Michigan Air Pollution Control Commission. Campbell underwent this conversion at the end of

1987. The plant had been operating under extensions of

the fuel sulfur limit compliance date (originally January

18, 1980). The mechanism for the extension was a

consent order issued by the Air Pollution Control

Commission. This explains why Campbell’s baseline

was higher than other Michigan plants.50

47United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired

Power Plant, UE&C/EIA: 921005 (Philadelphia, PA, October 1992), Table 3, pp. 1-3. 48Oak Ridge National Laboratory, Nonfuel Operation and Maintenance Costs for Large Steam-Electric Power Plants - 1982, NUREG/CR2844, ORNL/TM-8324 (Oak Ridge, Tennessee, September, 1982). This model was updated in 1987. 49Verbal communication with the Kansas City, Kansas Board of Public Utilities (October 6, 1993).

50Michigan Air Pollution Control Commission, General Rules, as amended April 20, 1989, Part 4, Emission Limitations and Prohibitions -

Sulfur-Bearing Compounds.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 33
The New Hampshire Acid Deposition Control Program

required Public Service of New Hampshire’s Merrimack

plant to reduce its emissions to a level that has coincidentally placed the plant in compliance with Phase I

of CAAA90. The effective date of this program was January 1, 1991. The program mandated large plants to

reduce their emissions by 40 percent from a baseline

established from 1979 through 1982.51

The New York State Acid Rain Deposition Control Act

ensured that the Long Island Lighting Company’s

Northport and Port Jefferson plants (both oil-fired)

would be in compliance with Phase I of CAAA90. The

Act required both plants to reduce the sulfur content of

the oil they burned from 2.8 percent to 1 percent. The

act allowed a two-year phase-in period from 1986 until

January 1, 1988.52

Wisconsin also required its plants to reduce their sulfur

emissions prior to CAAA90 and has a number of plants

that will find themselves in compliance with Phase I

requirements simply by adhering to State regulations.

These Phase I plants are South Oak Creek, operated by

Wisconsin Electric Power; Genoa, operated by Dairyland Power Cooperative; Nelson Dewey and Edgewater, operated by Wisconsin Power and Light; and

Pulliam, operated by Wisconsin Public Service.

According to the Wisconsin Department of Natural

Resources, Bureau of Air Management, Statute 144.386,

paragraph 2, passed in 1989, lays out the requirements.

The legislation requires that major utilities (those

emitting more than 5,000 tons of SO2 systemwide in any

year after 1979) limit the average number of pounds of

SO2 emissions per million Btu of heat input from all

boilers under their ownership or control to 1.2.

There is, however, a trading mechanism, whereby two

major utilities may enter into an agreement for trading

emissions unless the sum of the proposed traded emissions and the projected annual emissions of the grantor

major utility for the year to which the agreement will

apply would exceed the actual annual emissions of the

grantor major utility in 1985. To determine whether the

major utility that is the grantor in an agreement is in

compliance, the Wisconsin Department of Natural

Resources adds the traded emissions and the grantor’s

annual emissions and divides the sum by the annual

heat input of the grantor.53 (Note that this does not

permit the same level of flexibility as CAAA90, where

total emissions, regardless of heat input, are the only

compliance issue.)

In addition to the plants that were required to reduce

their emissions by State legislation, there are a number

of plants that took action based on other factors. These

plants are located in Minnesota, Iowa, and Missouri,

which are three of the four westernmost States affected

by Phase I of CAAA90.

In Minnesota, Northern States Power’s High Bridge

plant switched from bituminous to a western subbituminous fuel. The switch was completed in 1987. The

utility gave three reasons for the switch: environmental

benefits; economic considerations;54 and the fact that

stricter environmental legislation seemed imminent.

In Missouri, two plants, Empire District’s Asbury55

and Kansas City Power and Light’s Montrose,56 fuel

switched after and during the CAAA90 baseline period,

respectively. In both cases, low-sulfur western coal was

chosen as the new fuel. Economic analyses led to the

conclusion that western coal was cheaper than local

Missouri coal, even though both plants are minemouth

plants. In the case of the Montrose plant, one of the

local supply mines had played out as well.

In Iowa, boiler 1 at Midwest Power’s George Neal plant

switched fuel for economic reasons. The plant had been

burning both Hanna Basin coal and gas during the

baseline period, when it was used predominantly as a

peaking unit, and switched to a much lower sulfur

Powder River Basin coal in 1989. The plant will need to

take no further action to comply with Phase I requirements.57

In summary, 10 Phase I plants, by complying with relatively strict State regulations, will, in essence, find

themselves in compliance with the requirements of

Phase I. Additionally, four plants have taken action for

other reasons that have also reduced their sulfur

dioxide emissions to a level that will meet the requirements of Phase I.

51Verbal communication with the New Hampshire Air Resources Division (September 28, 1993).

52Verbal communication with the Long Island Lighting Company (September 29, 1993).

5391-92 Wisconsin Statutes, 144.386, Sulfur dioxide emission rates after 1992; major utilities, Section 2, paragraphs (a) and (b).

54Verbal communication with Patty Boyce of Northern States Power (October 1, 1993).

55Verbal communication with Bob Bromley of the Empire District Electric Company (October 4, 1993).

56Verbal communication with Jerry Bennett of Kansas City Power and Light (October 5, 1993).

57Verbal communication with Dave Dooley of Midwest Power (October 6, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

34 Clean Air Act Amendments of 1990
Retiring Facilities

Retirement is also an available option for compliance

with Phase I. There are seven units that have indicated

that they will use retirement. Five of the seven units,

Wisconsin Electric Power’s North Oak Creek units 1

through 4 and Cleveland Electric Illuminating’s Avon

Lake unit 8, retired prior to the passage of the law. Two

other units, Indiana Michigan Power’s Breed unit 1 and

Iowa Power’s Des Moines unit 7 will retire in time to

meet compliance with Phase I. These units will be

required to show compensating generation elsewhere in

their system or surrender the units’ allowance allocation.

Boiler Repowering

Repowering is the integration of modern technology

into an existing power plant site, thereby increasing the

available capacity at the site by as much as 200 percent;

improving efficiency; and lowering the plant’s air emissions profile. Repowering typically involves a partial or

complete replacement of the existing steam supply

system and a more or less complete retention and

refurbishment of the turbine-generator system. Refurbishment and reuse of the turbine-generator is the

major area of cost savings over new construction. Other

components and systems, including the fuel supply and

storage (if the same fuel is used), roads and utilities,

cooling towers, and nongeneration buildings, are almost

always refurbished and used.

Repowering assumes the existence of a utility steam

plant which through age or technological obsolescence

is no longer viable. The ability to use the existing site

and the extent to which existing equipment can be

reused are important repowering considerations. These

present the opportunity to save up to half the cost of a

comparable new plant. Repowering represents the leastcost option for the utility in some cases.58

Many of these aging plants are without air pollution

controls and are candidates for repowering including

integrated gasification combined-cycle technology.

Repowering technologies are still under development;

however, it represents a potential for development,

particularly after the year 2000 when more of the

repowering technologies will be ready for commercial

implementation.

Coal and Oil and Gas Repowering

Repowering options for coal include partial repowering

and station repowering. Several different systems can

be introduced in each of these groups. “Coal-for-coal

boiler repowering” is partial repowering of the unit by

replacing the bottom half of the existing boiler with

bubbling bed atmospheric fluidized bed combustion.

“Coal-for-coal station repowering” is complete repowering of the unit by replacing the entire boiler (and

possibly the nonsteam supply systems as well) with

any fluidized bed boiler (atmospheric, circulating, or

pressurized), integrated gasification combined cycle

coal, or some other clean coal technology.

Steam units can be repowered to fire partly or completely on oil or gas using combustion turbines and

heat recovery steam generators. Several options are

commercially proven, including combustion turbine

repowering, gas-firing in addition to existing boiler

firing (addition of a gas-fired combustion turbine to an

existing gas-, oil-, or coal-fired boiler with the

combustion turbine exhaust used for air or water preheating and retention of the existing boiler method and

fuel); and heat recovery steam generator repowering

(addition of a heat recovery steam generator with or

without replacement of the existing boiler and without

replacement of the steam turbine-generator).

Wabash River Coal Gasification

Repowering Project

PSI Energy is repowering unit 1 of the Wabash River

Generating Station in Vigo County, Indiana, for

CAAA90 Phase I.59 This is a 112.5-megawatt steam

turbine-boiler generating station that burns bituminous

coal. It was completed in 1953. The unit is being

repowered with integrated gasification combined-cycle

using a two-stage, entrained-flow gasification system.

The plant capacity after repowering will be 268

megawatts (net), and the total project cost $396 million.

With the new technology to be used at the Wabash station, coal is ground, slurried with water, and gasified

in a pressurized, two-stage (entrained-flow slagging

first stage and non-slagging second stage), oxygenblown, entrained-flow gasifier. The product gas is

cooled through heat exchangers and passed through a

conventional cold gas cleanup system that removes

58Energy Information Administration, “Performance Optimization and Repowering of Generating Units,” Electric Power Monthly,

DOE/EIA-0226(92/08) (Washington, DC, August 1992). 59U.S. Environmental Protection Agency, SO2 Phase 1 and 2 Boiler Compliance Methods (July 12, 1993), p. 13.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 35
particulates, ammonia, and sulfur. The clean, mediumBtu gas is then reheated and burned in an advanced

192-megawatt gas turbine. Hot exhaust from the gas

turbine is passed through a heat recovery steam generator to produce high-pressure steam. High-pressure

steam is also produced from the gasification plant and

superheated in the heat recovery steam generator. The

combined high-pressure steam flow is supplied to an

existing 110-megawatt steam turbine.

The repowered unit will use 2,544 tons of high-sulfur,

Illinois Basin bituminous coal per day. The anticipated

heat rate for the repowered unit is 8,974 Btu per kilowatthour (38 percent efficiency). Using high-sulfur

bituminous coal, SO2 emissions are expected to be less

than 0.2 pound per million Btu (98 percent reduction).

Nitrogen oxide (NOx) emissions are expected to be less

than 0.1 pound per million Btu (90 percent reduction).

Upon completion in 1995, the project, partially sponsored by the Department of Energy, will represent the

largest single-train integrated gasification combinedcycle plant in operation in the United States.60

Additional Compliance Strategies

Many plants intend to supplement their main method

of compliance with one or more of the additional

strategies available: energy conservation, reduced utilization, and substitution of units. Each of these, along

with issues that are directly related, are addressed in

the following sections.61

Energy Conservation

Title IV of the CAAA90 required EPA to establish rules

for the use of energy conservation as a compliance

strategy. The allowance trading system contains an

inherent incentive for utilities to conserve energy, since

for each ton of SO2 that a utility avoids emitting, one

fewer allowance must be held at year end. There are

also two explicit conservation incentives in the Acid

Rain Program: (1) the Conservation and Renewable

Energy Reserve, and (2) the reduced utilization provision.

The Conservation and Renewable Energy Reserve is a

pool of 300,000 allowances that will be awarded to

utilities for implementing demand-side conservation

measures (actions taken to encourage a customer to

modify the amount or timing of electricity use) or for

using renewable energy sources (such as biomass, solar,

geothermal, or wind). According to EPA, in order for

an electric utility to qualify for the reserve, it must:

• Own or partly own an affected unit

• Pay or partially pay for the measure

• Implement least cost planning

• Have net income neutrality (if investor-owned).62

The reserve was established by reducing Phase II

allowances by 30,000 annually over a 10-year period

from 2000 to 2009. Twenty percent (or 60,000 allowances) of the reserve is set aside for renewables, with a

maximum of 30,000 allowances for each renewable technology. The allowances will be granted to utilities on a

first-come, first-served basis starting in 1995 for

demand-side conservation activities initiated after 1992.

The Department of Energy is responsible for certifying

that States have net-income neutrality policies before a

company can receive bonus allowances.

On November 17, 1993, EPA awarded the first 532

reserve bonus allowances to 6 non-Phase I affected

companies during the annual meeting of the National

Association of Regulatory Utility Commissioners in

New York City. Puget Sound Power & Light received

the largest award of the group, 245 allowances, for

residential, commercial, and industrial conservation

programs, followed by ESI Energy, the Florida Power

& Light subsidiary, with 109 allowances attributable to

geothermal generation, and 2 New England Electric

System companies, which received a total of 103 allowances for conservation programs and a landfill gas

project. In addition, Portland General Electric received

57 and the City of Austin, Texas, got 18 allowances,

both for conservation projects.63

Demand-Side Management

While the Acid Rain Program provides incentives for

utilities owning Phase I and/or Phase II plants to

60U.S. Department of Energy, Assistant Secretary for Fossil Energy, Clean Coal Technology Demonstration Program: Program Update 1992

(As of December 31, 1992), DOE/FE-0272 (Washington, DC, February 1993), pp. 7-96, 7-97. 61The discussion in this section is based primarily on the series of documents regarding the Acid Rain Program published by the U.S.

Environmental Protection Agency, Office of Air and Radiation, beginning in 1991. 62Net income neutrality occurs when the State regulatory authority establishes rates and charges that are expected to keep the net

income earned by the utility constant as it adopts conservation programs. 63“Six companies Earn Bonus Allowances from Conservation/Renewable Reserve,” Utility Environment Report (November 26, 1993), pp.

1-2.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

36 Clean Air Act Amendments of 1990
develop demand-side management (DSM) programs,

nearly half of the Nation’s utilities are electively

establishing DSM programs, and interest in them

continues to grow. DSM is the process, employed by

utilities, of influencing customers directly or indirectly

to modify and/or reduce energy consumption. DSM

has entered the mainstream of utility planning options,

and utility management has come to view DSM as a

viable business strategy. Its popularity stems from three

major factors: (1) DSM programs can provide costeffective energy and capacity resources that can reduce

the need to build new power plants and transmission

lines; (2) they are strongly favored by public opinion

over construction of new plants; and (3) they offer

substantial environmental benefits over traditional

utility supply resources. By emphasizing the various

applications of energy efficiency, DSM programs can

lead customers to use less electricity, alter the time

when they use it, or substitute more efficient technologies for less efficient applications.

From 1989 through 1991, total energy savings attributable to DSM programs increased from 16,268 million

kilowatthours to 23,343 million kilowatthours. By 1996,

DSM energy savings are estimated to increase to 57,011

million kilowatthours, representing an average annual

increase of nearly 20 percent for the period from 1991

through 1996. Most of the energy savings result from

conservation programs that promote high-efficiency

end-use equipment. Investor-owned utilities accounted

for the major share of the DSM energy savings, with

nearly 60 percent of the total in 1991. Total DSM energy

savings represented nearly 1 percent of the 2,762 billion

kilowatthours of total sales to ultimate customers.64

Utilities are obligated to meet the needs of their

customers. Historically, the fundamental strategy used

to meet increasing electricity needs has been to build

more power plants. During the past several years,

however, DSM has become one of the primary vehicles

used to satisfy the Nation’s increasing energy requirements.

EPA Conservation Verification Protocols

Conservation measures that are used to qualify for the

300,000 Conservation and Renewable Energy Reserve

bonus allowances or to contribute to the reduced

utilization provision enable electric utilities to earn or

save allowances, which can be banked for future use or

sold. It is, therefore, essential to the credibility of the

market approach for there to be procedures to verify

and quantify energy savings. Accordingly, EPA set

forth the Conservation Verification Protocols, which

will be used primarily by public power utilities, while

investor-owned utilities’ energy savings will be verified

by procedures specified by their State Public Utility

Commissions. Due to the diversity of conservation

technologies, programs, and activities, the Protocols

give general guidelines, rather than specific requirements, for verifying energy savings. The Protocols are

designed to ensure the cost effectiveness of conservation programs and SO2 emission reduction measures, as

well as the reliability of actual energy savings from

these programs.65

Reduced Utilization

The second conservation incentive is contained in the

reduced utilization provision where a utility can use

conservation, both on the demand side and on the supply side (i.e., power generation, transmission, or

distribution efficiency) to reduce utilization in Phase I

without surrendering allowances.

To account for possible shifts in electricity generation

from Phase I units to Phase II units, the CAAA90 specify that a Phase I unit that meets its emissions reduction

requirements by decreasing electricity generation must

either surrender allowances or account for the reduced

generation in one of several ways: (1) by adopting verifiable energy conservation or improved unit efficiency

measures, (2) by designating sulfur-free generators to

provide generation, or (3) by designating one or more

non Phase I SO2-emitting unit or units (called compensating units) to increase generation. Compensating units

are granted allowances based on 1985 SO2 emissions

rates and average annual fuel use from 1985 through

1987. Allowances may be transferred from the original

unit to the compensating units in order to cover

emissions beyond their granted allowances.

Substitution Units

EPA designed a plan that would allow a Phase I unit to

reassign all or some of its Phase I SO2 emissions

reductions requirements to one or more existing units

64Energy Information Administration, Form EIA-861, “Annual Electric Utility Report.”

65U.S. Environmental Protection Agency, “Conservation Verification Protocols: A Guidance Document for Electric Utilities Affected by

the Acid Rain Program of the Clean Air Act Amendments of 1990,” EPA 430/8/B-92-002 (March 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 37
(referred to as substitution units) that would otherwise

not be regulated until Phase II, if these units met the

Phase I unit’s requirements. This plan was designed to

allow Phase I units to cost-effectively reduce emissions

at another plant, achieving the same overall emissions

reductions that would have occurred without the plan.

EPA Revisions to Reduced Utilization

and Substitution Rules

In the case of both the reduced utilization provision

and the substitution provision, the original intent was

that emissions would be no higher with the option than

without. However, some substitution plans and reduced utilization plans rely on emissions reductions at

Phase II units that—after 1985, but prior to passage of

the CAAA90—had already reduced their emissions, or

were required to reduce their emissions in response to

State laws. Again, relying on these reductions does not

achieve new emissions reductions in response to the

CAAA90. In each case, new authorizations to emit sulfur dioxide were created, thereby making projected

total emissions higher with such plans (including the

allocated allowances) than without. As a result, EPA is

taking two actions to address this issue: (1) revisions

of the rules promulgated for substitution and reduced

utilization plans, and (2) issuance of draft Phase I

permits containing partial approval of such compliance

plans. EPA has proposed revisions to the rules for substitution and reduced utilization in the fall of 1993, and

expects final revisions to be promulgated in early 1994.

Using its discretionary authority to approve compliance

plans, EPA is proposing to approve most Phase I permits with substitution or reduced utilization plans for

1995 only, and to defer action for the remainder of

Phase I until the rulemaking on the revised rules is

complete. This action will allow Phase I utilities to

count on their current plans for the first year of

compliance and, where appropriate, provide time to

revise plans. Compliance plans submitted after this

action will be considered under the amended rules to

be issued in 1994.66

Phase I Permit Applications

All Phase I plants must submit to the EPA a “Phase I

Permit Application” specifying, by boiler, which compliance plan is intended for each unit. The choices

listed on the application are as follows:

• Hold allowances

• Substitution plan

• Reduced utilization plan

• Phase I extension plan.

A plant which plans to comply by purchasing additional allowances or by switching, blending, or cofiring

falls into the category of “holding allowances” because

it intends to meet emissions limitations without

substituting units, reducing utilization, or installing

scrubber equipment. In this case, EPA takes into consideration that there are actions plants can take in order

to comply by holding allowances (e.g., switching fuels),

but it is left entirely up to the plant to decide which is

the most feasible and cost-effective action.

Plant operators may choose one or more options. Many

have applied to use a substitution plan and a reduced

utilization plan designating the same non-Phase I unit

or units as substitution and compensating units. After

the review process, if all criteria are met, EPA will give

a “conditional” approval to both, along with any

appropriate allowance allocations for both, and the

plant operators will decide at a later date which plan to

activate. If the approval is for the year 1995, plant

officials have until December 31, 1995, to notify EPA, in

writing, which plan has been implemented.

Phase I unit operators who plan to comply by installing

a scrubber or repowering would submit a Phase I

extension plan. The time for compliance would then

effectively be extended until 1997 because EPA would

provide additional allowances for the unit.

Sample Compliance Plans

To demonstrate the variety and flexibility of Phase I

compliance plans, it will be helpful to cite the following

examples of permits which have received draft approval.

On August 9, 1993, EPA issued a Draft Phase I Acid

Rain Permit to Ashtabula boiler unit 7 (generating unit

5) operated by Cleveland Electric Illuminating Company, approving 14 conditional substitution plans

66U.S. Environmental Protection Agency, “Acid Rain Program: EPA’s Proposed Response to Substitution and Reduced Utilization

Compliance Plan Litigation” (July 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

38 Clean Air Act Amendments of 1990
for 1995.67 Each plan designates the following 14

substitution units individually:

• Ashtabula boiler units 8, 9, 10, and 11

• Bay Shore boiler units 1, 2, 3 and 4

• Acme boiler unit 16

• Lake Shore boiler units 18, 91, 92, 93, and 94.

EPA also gave draft approval for five active substitution plans, designating Acme boiler units 13, 14, 15,

91, and 92 individually as substitution units for

calendar year 1995. Action on the conditional and active

substitution plans for 1996 through 1999 was deferred

pending the aforementioned revisions to the substitution and reduced utilization rules.

A reduced utilization plan was also given draft

approval; the plan will result in the shift of generation

from Ashtabula boiler unit 7 to the following nuclear

(sulfur-free) generators:

• Perry unit 1

• David Besse unit 1

• Beaver Valley unit 2.

This reduced utilization plan will also result in the use

of energy conservation and improved unit efficiency

measures to account for underutilization of this unit.

There is no allowance allocation for the use of these

conservation compliance measures, nor is there an

allocation for the use of sulfur-free generators.

Ashtabula boiler unit 7 also applied for an extension

plan naming an Elmer Smith coal-fired unit as a

transfer unit. It was not approved because unallocated

allow-ances did not remain in the Phase I Extension

Reserve at the time EPA acted on this plan. However,

if Phase I extension reserve allowances become

available in the future, the application will be eligible

to receive 7,279 allowances.

Included in the same application were the plans for

Ashtabula boiler units 8, 9, 10, and 11 to be substitution

units for Ashtabula boiler unit 7. All four units received

draft approval for a conditional substitution plan for

1995 in which they were designated as substitution

units for Ashtabula boiler unit 7. If the plans are

activated, they will receive the following allowance

allocations for 1995:

• Ashtabula unit 8: 10,753 allowances

• Ashtabula unit 9: 9,173 allowances

• Ashtabula unit 10: 8,275 allowances

• Ashtabula unit 11: 8,706 allowances.

All four also received draft approval for a conditional

reduced utilization plan, shifting generation to sulfurfree generators and resulting in the use of energy

conservation and improved unit efficiency measures.

Activation of the reduced utilization plan is contingent

upon the activation of the substitution plans for these

four units.

On August 11, 1993, EPA issued a Draft Phase I Acid

Rain Permit to the Potomac River Plant operated by the

Potomac Electric Power Company. It states that EPA

gave draft approval for conditional substitution plans

for Potomac River units 1, 2, 3, 4, and 5 in which they

are designated as substitution units for Chalk Point

units 1 and 2, and for Morgantown units 1 and 2 in

1995. It also states that Potomac units 1, 2, 3, 4, and 5

are approved for a conditional reduced utilization plan

in which they are designated as compensating units for

Chalk Point units 1 and 2, and for Morgantown units 1

and 2 in 1995. Although the Potomac River plants were

not originally targeted as Phase I plants, they became

Phase I plants and were allocated allowances at the

time they were given draft approval as either substitution or compensating units.

These conditional plans can be activated only to the

extent that none of the five Potomac River units is both

a substitution unit and a compensating unit for the

same year and that none is a substitution unit under

more than one substitution plan for the same year.

Because these plans were conditionally approved for

the year 1995, EPA must be advised by December 31,

1995, as to which plans were activated.

67Where a generator and boiler do not have the same identification number, as in the case of the Ashtabula plant, the unit number is

specified as either the boiler or the generator.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 39
4. Individual Utility Compliance Plans

While the previous chapter presented an overview of

the different types of possible responses to Phase I of

the Clean Air Act Amendments of 1990 (CAAA90), this

chapter discusses the responses of individual utilities.

The specific responses, and their costs, of individual

utilities affected by Phase I of the CAAA90 vary

substantially. One way to appreciate this variation is to

consider the individual compliance strategies. First, this

chapter presents the compliance plans of the large

plants that are affected by Phase I; then the more

detailed plans, including their costs, of six separate

utilities are discussed.

Large Plant Compliance Plans

Of 110 plants affected by Phase I, some are very large

coal-fired facilities. There are 16 plants with more than

1,500 megawatts of nameplate capacity affected by the

law, and 7 plants with more than 2,000 megawatts of

capacity affected (Table 14). These plants are located in

various States throughout the affected area. The largest

is Georgia Power’s Bowen facility. Of its 3,541 megawatts, 3,499 megawatts (98.8 percent) of its capacity

(generators 1, 2, 3, and 4) are affected by Phase I. The

remaining portion of the Bowen facility is a small

petroleum-fired unit.

To comply with Phase I, Bowen plans to switch to lowsulfur coal or blend its current fuel with a low-sulfur

coal. In October 1992, Georgia Power signed contracts

with Transco Coal Company to receive low-sulfur coal

primarily for its Bowen units,68 and more contracts are

expected to meet demand at the facility.

PSI Energy’s Gibson plant in Indiana has 2,672

megawatts of affected capacity at generators 1, 2, 3, and

4. The main compliance strategy at Gibson is the

Table 14. Plants with More Than 1,500 Megawatts of Phase I Affected Capacity, 1992

Plant

Operating

Utility State

Affected

Nameplate

Capacity

(megawatts) Allowancesa

1985 SO2

Emissions

(tons)

Bowen ............. Georgia Power Georgia 3,499 247,881 305,302

Gibson . . . . . . . . . . . . . PSI Energy Indiana 2,672 178,477 294,669

Cumberland ......... Tennessee Valley Authority Tennessee 2,600 176,763 344,153

General J.M. Gavin .... Ohio Power Ohio 2,600 175,002 363,249

Labadie ............ Union Missouri 2,390 150,016 269,642

Harrison ............ Monongahela Power West Virginia 2,052 132,685 234,693

E.C. Gaston ......... Alabama Power Alabama 2,013 130,542 159,288

Wansley ............ Georgia Power Georgia 1,904 132,616 248,651

Baldwin ............ Illinois Power Illinois 1,892 141,391 264,594

Conemaugh ......... Pennsylvania Electric Pennsylvania 1,872 122,918 181,892

Hatfield’s Ferry ....... West Pennsylvania Power Pennsylvania 1,728 112,383 161,081

W.H. Sammis ........ Ohio Edison Ohio 1,694 117,649 150,580

Mt. Storm ........... Virginia Electric & Power West Virginia 1,662 118,528 128,310

Mitchell ............ Ohio Power West Virginia 1,633 87,135 103,326

Brunner Island ....... Pennsylvania Power & Light Pennsylvania 1,559 109,716 124,956

Muskingum River ..... Ohio Power Ohio 1,530 104,416 253,435

a

One SO2 allowance permits one ton of SO2 emissions.

SO2 = Sulfur dioxide.

Source: Capacity: Energy Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC, October

1993). Number of Allowances: Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691. 1985 Emissions: U.S. Environmental

Protection Agency, National Allowance Data Base, Version 2.11 (January 1993).

68Feildston Company, Inc., Compliance Strategies Review: Guide to Phase I Units, 3rd edition (Washington, DC, October 1992), p. 23.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 41
Union’s Labadie plant is one of the largest Phase I affected facilities at 2,390 megawatts.

installation of a scrubber on unit 4. The other three

units will blend low-sulfur eastern and Illinois Basin

coals. PSI Energy has purchased five elemental coal

analyzers for use at Gibson to assist in blending the

coal.69

The Tennessee Valley Authority’s (TVA) Cumberland

facility and Ohio Power’s General J.M. Gavin facility

both have 2,600 megawatts of Phase I affected capacity,

and both are planning to install scrubbers in order to

comply with Phase I. For the Cumberland plant, the

installation of scrubbers on its two affected units, 1 and

2, will allow the facility to continue burning Kentucky

coal. The plant has historically received the majority of

its coal from Kentucky mines. The scrubbers will also

aid the other affected TVA units, since excess allowances from the Cumberland plant can be reallocated to

other plants so that all of TVA’s Phase I affected

capacity can have a sufficient number of allowances.70

Similarly, the centerpiece of Ohio Power’s compliance

strategy is the installation of scrubbers at Gavin 1 and

2. Some opposition to this plan was raised on the basis

that scrubber installation was not the least-cost option.

American Electric Power, the holding company for

Ohio Power, supported the scrubber installations,

saying that the long-run cost of scrubbers would be less

than that of fuel switching.71 It has since been decided

that Gavin 1 and 2 will scrub in order to meet Phase I

compliance.

Three other large facilities—Monongahela Power’s

Harrison plant, Pennsylvania Electric’s Conemaugh

plant, and Virginia Electric & Power’s Mt. Storm

plant—also plan to install scrubbers as part of their

Phase I compliance strategies.

Like Georgia Power’s Bowen facility, Union’s Labadie

facility and Alabama Power’s E.C. Gaston are planning

to switch and/or blend fuels in order to comply. Both

plants are currently looking at existing contracts and

negotiating new contracts in order to meet coal demand

at the facilities.

The majority of the other large plants affected by Phase

I are also complying by switching or blending fuels,

including Georgia Power’s Wansley facility, Ohio

Edison’s W.H. Sammis facility, Pennsylvania Power &

Light’s Brunner Island facility, and Ohio Power’s

Mitchell and Muskingum River unit 5 facilities.

69Fieldston Company, Inc., Compliance Strategies Review: Guide to Phase I Units, 3rd edition (Washington, DC, October 1992), pp. 73-74. 70Fieldston Company, Inc., Compliance Strategies Review: Guide to Phase I Units, 3rd edition (Washington, DC, October 1992), p. 83. 71Fieldston Company, Inc., Compliance Strategies Review: Guide to Phase I Units, 3rd edition (Washington, DC, October 1992), p. 61.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

42 Clean Air Act Amendments of 1990
The two remaining plants with more than 1,500 megawatts of affected capacity are West Penn Power’s

Hatfield’s Ferry facility and Illinois Power’s Baldwin

facility. Plans at both of these plants are to use

allowances in order to meet their reduction requirements for Phase I. West Penn Power is a subsidiary of

Allegheny Power System and a joint owner of

Monongahela Power Company. Allowances from Monongahela Power’s Harrison plant, which is installing

scrubbers on its three affected units, 1, 2, and 3, will be

available for Hatfield’s Ferry.72 For Baldwin, allowances are being purchased from other owners.

Specific Utility Compliance Plans

To provide a more intensive look at the compliance

plans of some utilities, this section discusses the plans

to comply with Phase I of the CAAA90 for six utilities.

These six include three of the utilities with large plants

discussed above and three other affected utilities. This

discussion provides some examples of the differences

and similarities among utility compliance plans and the

effects of these plans. To comply with the sulfur

dioxide (SO2) control requirements, only one utility will

use a single compliance strategy; the others will use a

combination of strategies.

Illinois Power: Illinois Power owns 5.0 gigawatts of

electricity generating nameplate capacity at eight

facilities.73 Three (Baldwin, Hennepin, and Vermilion)

are affected by Phase I of the Acid Rain Program of the

CAAA90. The three plants total 2.2 gigawatts of capacity (Table 15).74 For these plants, the SO2 allowances

received annually by Illinois Power during Phase I will

be more than 150,000 tons below their base emissions

in 1985.

In July 1991, the Illinois State legislature passed a law

effectively requiring Illinois utilities to install scrubbers

for CAAA90 compliance. The intent of the law was to

protect the Illinois coal industry which supplied Illinois

Power. As a result, the utility originally had planned to

install scrubbers on two of the units at Baldwin. Subsequently, a group of western coal producers and

railroads sued the Illinois Commerce Commission,

charging that the law discriminates against out-of-State

coal and, therefore, violates the Commerce Clause of

Table 15. Characteristics of Selected Phase I Utilities

Owning

Utilitya

Affected

Nameplate

Capacity

(megawatts)

Total

Nameplate

Capacityb

(megawatts)

Proportion

Capacity

Affected

(percent)

Allowancesc

(per year)

1985 SO2

Emissions

(tons)

Difference

Between

Base

Emissions &

Allotment

Total

Phase I

Extension

Allowancesd

No. of

Unit

LowNOx

Burnerse

Number

of

CEMse

Illinois Power .......... 2,232 5,005 44.6 171,328 324,584 153,256 0 2.0 9.0

Pennsylvania P&L ....... 2,343 8,704 26.9 168,205 198,554 30,349 58,900 7.2 5.2

Potomac Elec. Power .... 2,162 6,433 33.6 128,770 132,796 4,026 61,494 4.2 3.2

Cincinnati G&E ......... 1,374 5,555 24.7 80,987 128,060 47,073 0 1.4 3.4

Georgia Power ......... 8,087 15,995 50.6 540,768 744,563 203,795 102,258 16.1 17.1

Southern Indiana G&E . . . 530 1,359 39.0 38,095 84,224 46,129 0 2.0 2.5

a

The full utility names are: Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, Cincinnati Gas & Electric Company,

Georgia Power Company, and Southern Indiana Gas & Electric Company. b

Total utility capacity.

c

One SO2 allowance permits one ton of SO2 emissions. d

Extension allowances are as distributed by EPA before any redistribution by the extension allowance pool. Phase I extension allowances were awarded to (1) control

units that install a technology that removes 90 percent or more of their SO2 emissions or (2) control units and other units that use a different compliance strategy but

are associated with the control unit in the extension allowance application. Extension allowances were awarded for 1995 through 1999. e

Number of units retrofitted with low-NOx burners and number of CEMs may be fractional because of partial unit ownership by utility. Also, number of CEMs may

not equal number of units because of boiler exhaust duct and stack configuration.

SO2 = Sulfur dioxide.

NOx = Nitrogen oxides.

CEM = Continuous emission monitor.

Note: Several of these utilities are part owners of affected units. See Appendix G for details.

Source: Based on information from Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power, and Southern

Indiana Gas & Electric (November 1993 through March 1994).

72Fieldston Company, Inc., Compliance Strategies Review: Guide to Phase I Units, 3rd edition (Washington, DC, October 1992), pp. 52 and

87.73The Joppa Steam plant, which is jointly owned by Illinois Power, is not included because it is not in Illinois Power’s ratebase.

74Unit-level details are provided in Appendix G.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 43
Estimates of the annual total cost for compliance at the 1,892-

megawatt Baldwin facility are just under $27 million. Baldwin

will use allowances as its main compliance strategy.

the U.S. Constitution. However, Illinois Power decided

to delay installation of the scrubbers at Baldwin until

Phase II,75 because cost estimates for compliance using

scrubbers were higher than for other methods of compliance.

Several alternatives to scrubbers were considered to

comply with Phase I. Fuel blending was one of them.

Illinois Power tested coal from the Powder River Basin

at Baldwin. The coal tested was subbituminous, low

Btu content, with 28 percent moisture, and required

special preparation and unloading arrangements.

Several blends of Illinois coal and Powder River Basin

coal were tested. The conclusions from the testing were

that all three units at the Baldwin station could use the

blended fuels, but some modifications to the plant

would be necessary if they were to become the normal

fuel at the facility.76

Another alternative considered was allowance purchases. This method is estimated to be slightly less

expensive than fuel blending. As a result, Illinois

Power’s current compliance strategy is to purchase

allowances. As of October 1993, they had purchased

more than 80 percent of the allowances needed for

Phase I. Enough allowances have already been purchased for Hennepin and Vermilion; they are still being

purchased for Baldwin.

Based on its compliance plans, the approximate cost to

Illinois Power of complying with Phase I of the

CAAA90 can be estimated (Table 16). Assuming an

average allowance price of $200 and estimates of the

cost of installing low-nitrogen oxide (NOx) burners and

continuous emission monitors (CEMs), the annual outof-pocket cost of compliance will be $33 million,77 93

percent of which will be used to purchase allowances.78 The overnight capital costs for NOx control

and CEMs total more than $23 million, but they are

allocated over the life of the capital equipment, which

is assumed to be 15 years.

Forty-five percent of the capacity owned by Illinois

Power is affected by Phase I of the CAAA90, and the

effect of Phase I on utility costs, while relatively small,

is the largest of the six utilities considered here. For the

amount of electricity generated at the utility in 1992,

compliance with Phase I comes to 1.9 mills per kilowatthour (Table 17). This is 3.6 percent of the electricity

sales revenue the utility received in 1992.

Pennsylvania Power & Light: Pennsylvania Power &

Light owns 8.7 gigawatts of generating nameplate

capacity at 15 facilities. Four plants—Brunner Island

(generators 1, 2, and 3), Martins Creek (generators 1

and 2), Sunbury (generators 3 and 4) and Conemaugh

(generators 1 and 2)—have been designated Phase I

plants. The total of the Phase I affected capacity is 2.3

gigawatts.

The foundation of this utility’s compliance strategy is

fuel switching. Pennsylvania Power & Light will,

however, install scrubbers at its Conemaugh plant.79

Phase I affected generators at Brunner Island will be

receiving coal with a rating of less than 2.35 pounds of

SO2 per million Btu from southwestern Pennsylvania

(Somerset and Greene counties). Sunbury, on the other

75“Western Coal Group Sues Illinois Commission over State Law Requiring Scrubber Use,” Utility Environment Report (August 6, 1993),

pp. 1-2. 76R.W. Eimer, R.H. Hayes, K.B. Pollman, and D.J. Diewald, “Blending Illinois and Powder River Basin Coals for Testing on a 585

Megawatt Unit,” paper presented at the Engineering Foundation Conference on Coal Switching and Blending of Western Low Sulfur Coals

(Salt Lake City, UT, September 26, 1993). 77All costs in this chapter are in 1993 dollars.

78If Illinois Power had to purchase all of its allowances, annual allowance costs alone would be almost $65 million.

79Conemaugh is jointly owned by Pennsylvania Power & Light (11.4 percent), Potomac Electric Power (9.7 percent), and other utilities.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

44 Clean Air Act Amendments of 1990
Table 16. Costs of Phase I Compliance of Selected Utilities

Owning

Utilitya

SO2 Control NOx

Control

Capital

Costs

(million

dollars)

CEMs

Total

Capital

Costs

(million

dollars)

Annual

Capital

Costs

(million

dollars)

Annual

O&M and

Fuel

Costs

(million

dollars)

Annual

Total

Costs

(million

dollars)

Capital

Costs

(million

dollars)

O&M

Costs

(million

dollars)

Fuel

Premium

(million

dollars)

Capital

Costs

(million

dollars)

O&M

Costs

(million

dollars)

Illinois Powerb . . . . . 0.0 30.7 0.0 13.5 9.8 0.9 23.4 1.6 31.6 33.1

Pennsylvania P&L . . 48.1 2.2 0.0 70.6 7.7 0.0 126.4 8.4 2.2 10.6

Potomac Elec.

Power ......... 62.4 1.7 0.0 149.0 9.4 0.0 220.9 14.7 1.7 16.5

Cincinnati G&Ec . . . 17.5 3.6 5.3 8.1 2.8 0.0 28.4 1.9 8.8 10.7

Georgia Power .... 78.3 1.8 0.7 178.0 16.0 0.0 272.3 18.2 2.5 20.7

Southern Indiana

G&E . . . . . . . . . . 107.0 1.3 0.0 5.0 2.8 0.2 114.8 7.7 1.5 9.1

a

The full utility names are: Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, Cincinnati Gas

& Electric Company, Georgia Power Company, and Southern Indiana Gas & Electric Company. b

Costs do not include the Joppa Steam Plant, which is not included in Illinois Power’s ratebase.

c

Costs do not include East Bend Station as a substituting unit.

SO2 = Sulfur dioxide.

NOx = Nitrogen oxides.

CEM = Continuous emission monitor.

O&M = Operations and maintenance.

Notes: •These are contemporary estimates made by the individual utilities; most dollars are adjusted to 1993. •Capital equipment is depreciated

over 15 years. •The estimates underestimate the cost of compliance to the extent that no cost estimate has been made in some cases. •For unit

level data, see Appendix G.

Source: Based on information from Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia

Power, and Southern Indiana Gas & Electric (November 1993 through March 1994).

Table 17. Effects of Phase I Compliance on Selected Utilities

Owning Utilitya

Average

Capital Costs

(dollars per

affected kilowatt)

Average Annual Utility-Wideb

Capital

Costs

(dollars per

affected

kilowatt)

O&M & Fuel

Costs

(dollars per

affected

kilowatt)

Total Costs

(dollars per

affected

kilowatt)

Average

Costs

(mills per

kilowatthours)

Electric

Operating

Expense

Increase

(percent)

Sales

Revenue

Increase

(percent)

Illinois Power ............... 10.5 0.7 14.1 14.8 1.9 3.6 2.8

Pennsylvania P&L ............ 53.9 3.6 0.9 4.5 0.3 0.5 0.4

Potomac Electric Power ....... 102.2 6.8 0.8 7.6 0.9 1.2 1.0

Cincinnati G&E .............. 20.7 1.4 6.4 7.8 0.5 1.2 1.0

Georgia Power .............. 33.7 2.2 0.3 2.6 0.3 0.6 0.5

Southern Indiana G&E ........ 216.4 14.4 2.8 17.2 1.7 4.7 3.8

a

The full utility names are: Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, Cincinnati Gas

& Electric Company, Georgia Power Company, and Southern Indiana Gas & Electric Company. b

Average generation cost increase and revenue and electric operating expense percentage increase are based on 1992 generation, revenue,

and electric operating expenses.

O&M = Operations and maintenance.

Notes: •For unit level data, see Appendix G.

Source: Based on information from Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia

Power, and Southern Indiana Gas & Electric (November 1993 through March 1994).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 45
hand, will receive its coal from central Pennsylvania

(Clearfield County). The Clearfield County coal will be

cleaned to 2.3 pounds of SO2 per million Btu. It is

expected that any fuel premiums that will be incurred

by the utility in meeting its Phase I requirements will

be negligible.

All four plants will install low-NOx burners at a total

cost estimated by the utility of $71 million. Additionally, precipitator modifications at Brunner Island

generators 1, 2, and 3 will cost approximately $3 million. Dust collectors at Sunbury’s generators 3 and 4

will be modified at a cost over $3 million, and the

precipitators at Martins Creek’s generators 1 and 2 will

also be modified—at a cost of $4 million. The 5.2 Phase

I CEM units will cost a total of $8 million.80 Pennsylvania Power & Light’s share of scrubber installation at

Conemaugh is $38 million.

Pennsylvania Power & Light has the second smallest

proportion of their total capacity affected by Phase I of

the six utilities examined, and Phase I has the smallest

proportional effect on its costs. Average costs increase

by only 0.3 mills per kilowatthour. This cost increase is

only 0.4 percent of their 1992 revenues.

Potomac Electric Power: Potomac Electric Power owns

over 6.4 gigawatts of electricity generating nameplate

capacity at five facilities. Three—Chalk Point, Morgantown, and Conemaugh81—have two units each that

have been designated Phase I units in the CAAA90. The

total of the Phase I affected capacity is 2.2 gigawatts.

Both Chalk Point and Morgantown units will comply

through changing fuels. The current plan is to continue

to receive coal from western Maryland and western

Pennsylvania. However, with the onset of Phase I, the

coal will be washed. Conemaugh will install scrubbers.

Chalk Point will also install the capability to burn

natural gas at a cost of $30 million. At the present time,

however, the utility is not planning to burn gas unless

the price of gas falls dramatically or the prices of the

designated western Maryland and western Pennsylvania coals rise in an equally dramatic manner.

As such, the total Phase I compliance capital cost at

Chalk Point units 1 and 2 is $84 million ($30 million for

gas-burning capability, $51 million for low-NOx burners

and $2 million for CEMS). The total capital cost of

emissions reductions for Morgantown units 1 and 2 is

$101 million (most of which is for the installation of

low-NOx burners). The total capital cost for Potomac

Electric at Conemaugh, even though it will install

scrubbers, is only $32 million, because the utility owns

less than 10 percent of the plant.82

Potomac Electric is one of the median utilities (of the

six considered) in terms of the proportional effect of

Phase I on its costs. Their costs will increase 1.2 percent

as a result of Phase I, although they expect the most

expensive NOx control costs, relative to the amount of

affected capacity, of any of the six utilities.

Cincinnati Gas and Electric: Cincinnati Gas and

Electric owns 5.6 gigawatts of generating nameplate

capacity at six facilities. Three—Walter C. Beckjord

(units 5 and 6), Miami Fort (units 5, 6, and 7) and

Conesville (unit 4), all partially owned by Cincinnati

Gas and Electric—have units that have been designated

Phase I units in the CAAA90. The Phase I units at both

Beckjord and Miami Fort will comply through fuel

changes. The most likely source of the lower sulfur coal

is central Appalachia. Current estimates of fuel

premiums at Beckjord and Miami Fort for Phase I units

are about $5 million annually. Conesville will acquire

additional allowances. Assuming an allowance cost of

$200 each, Cincinnati Gas and Electric’s share of allowance costs at Conesville will be less than $4 million per

year.

Only the Beckjord plant will install low-NOx burners.

The total cost to Cincinnati Gas and Electric for their

installation at the two Beckjord Phase I units is $8

million. Additionally, the Beckjord station’s precipitators will be modified at a capital cost to the utility of

$9 million. Finally, two CEMs will be installed at

Beckjord, costing the utility less than $1 million.

At Miami Fort and Conesville, there will be no lowNOx modifications. However, the precipitators will be

modified at Miami Fort, and gas-conditioning equipment will be installed. The cost of installing this SO2

reduction equipment to Cincinnati Gas and Electric is

estimated at less than $9 million. Units 5 and 6 at

Miami Fort will share a CEM, and Unit 7 will have its

own. The capital cost to the utility of Miami Fort’s

CEMs will be more than $1 million. For the one CEM

at Conesville, the utility will spend about half a million

dollars.83

80Verbal communication with Pennsylvania Power & Light (November 5, 1993).

81Conemaugh is jointly owned by Pennsylvania Power & Light (11.4 percent), Potomac Electric Power (9.7 percent), and other utilities.

82Verbal communication with Potomac Electric Power Company (November 4, 1993).

83Verbal communication with Cincinnati Gas and Electric (November 19, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

46 Clean Air Act Amendments of 1990
For Cincinnati Gas & Electric the costs of complying

with Phase I are also relatively small. They expect a

small increase in their fuel costs resulting from

switching to low-sulfur coal, and their share of

allowance costs at Conesville is small. Costs increase

only 0.5 mills per kilowatthour, which amounts to 1.0

percent of their 1992 electricity sales revenues.

Georgia Power: Georgia Power is an operating

company of the Southern Company. It owns 16.0

gigawatts of nameplate electricity generating capacity

at 34 facilities, including several small hydro-power

plants. Bowen (generators 1 through 4), Hammond

(generators 1 through 4), Jack McDonough (generators

1 and 2), Wansley (generators 1 and 2), Yates

(generators 1 through 7) and Gaston (generators 1

through 3 and ST4) have been designated Phase I

plants. The total of the Phase I affected nameplate

capacity is 8.1 gigawatts. Georgia Power is the largest

utility of the six discussed in this report. It also has the

largest amount and proportion of capacity affected by

Phase I.

The cornerstone of its compliance strategy is fuel

switching. All six Phase I plants will be switching coal.

In addition, one unit, generator 1 at the Yates plant,

will install scrubber equipment with an estimated cost

of $34 million, one-half of which will be paid by the

U.S. Department of Energy.

Georgia Power’s new low-sulfur coal will be Eastern

Appalachian coal with 1.0 to 1.5 pounds of SO2 per

million Btu. According to the utility, because of the

current “soft” market for coal, there is no expected fuel

premium.84

The total annual cost of compliance for Georgia Power

is approximately $21 million. These costs include the

17.1 CEMs85 required for the six plants by the

CAAA90, the cost of installing low-NOx burners at all

six plants, and various capital equipment required for

SO2 reductions. Some of these cost adjustments include

the installation of smokeless igniters, oil-gun upgrades,

and flue gas conditioners.

The increase in Georgia Power’s cost from the CAAA90

is small, 0.3 mills per kilowatthour; this is 0.5 percent

of their electric revenues in 1992. These low costs are

largely because fuel switching was chosen at most of

the affected units, all except the small Yates 1 unit, and

the utility expects to pay no premiums for the lower

sulfur coal.

Southern Indiana Gas and Electric: Southern Indiana

Gas and Electric is the smallest utility owning the

smallest total amount of affected capacity of the six

utilities. Southern Indiana owns electricity generating

units at five plants with a total capacity of 1.4 gigawatts. Two units at Culley and the one (partially

owned) unit at Warrick, totalling 0.5 gigawatts, are

affected by Phase I. The affected units are 39 percent of

the utility’s capacity.

Southern Indiana is installing scrubbers on both of its

affected units at Culley. These two units comprise

almost 20 percent of the total generating capacity and

50 percent of the affected capacity owned by the utility,

a much higher proportion installing scrubbers than any

of the other five utilities discussed here. The Warrick

plant is expected to reduce utilization and use allowances to comply with Phase I, although it may switch

to low-sulfur coal if switching appears to cost less than

using allowances.

Scrubbing at Culley and reducing utilization at Warrick

results in Southern Indiana receiving more allowances

from the EPA than it will use in Phase I. The utility

plans to sell these allowances, which will substantially

reduce their compliance costs. Of course, this is one

kind of activity that a marketable emissions allowance

system is expected to encourage.

The total annual cost of compliance for Southern

Indiana is estimated to be over $9 million, mostly for

capital costs.86 The capital costs are largely for the two

scrubbers, while the operating costs are reduced by $5

million per year because of the sale of unneeded emission allowances. The costs also include (1) installing

low-NOx burners on the two units at Culley, (2) installing and operating two CEMs at Culley, and (3) half of

the CEM cost at Warrick.

While Southern Indiana’s total compliance costs are not

particularly large, the proportional costs to the utility

on the basis of total revenue are larger than the other

five utilities considered here. Per kilowatt of affected

capacity, the average annual costs total over $17. This

is an increase of less than 2 mills per kilowatt hour

generated by the utility in 1992 or 3.8 percent of its

1992 revenues.

84Verbal communication with Georgia Power (November 5, 1993).

85Georgia Power owns only part of Gaston.

86Verbal communication with Southern Indiana Gas and Electric (February 17, 1993).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 47
Summary

Electric utilities are preparing to comply with Phase I

of the Acid Rain Program of the CAAA90. Their response to the SO2 reduction requirements of the

CAAA90 vary from utility to utility. More than half of

the affected utilities are planning to switch to lowsulfur coal, blend with low-sulfur coal, and co-fire with

natural gas to comply with the CAAA90 requirements.

The second most popular option is to obtain SO2 emission allowances in addition to the ones allocated to the

affected utility by the Environmental Protection Agency. Installing scrubber equipment is planned for about

10 percent of the affected units. An equal percentage of

units do not need to take any action, because they have

already reduced their SO2 emissions enough so that the

allowances allotted to them by the Environmental

Protection Agency (EPA) are sufficient for compliance.

Acquiring allowances and switching fuels are usually

the least capital intensive compliance strategy.

This report has discussed in depth the compliance strategies of 6 utilities owning 20 affected plants: Illinois

Power plans to purchase additional allowances for all

of its affected units; Pennsylvania Power and Light

plans to switch to low-sulfur coal, clean the high-sulfur

coal burned, or scrub its Phase I units; Potomac Electric

Power also plans to clean the high-sulfur coal they burn

or scrub its affected units, as well as install the

capability for some of their boilers to co-fire with

natural gas; Cincinnati Gas and Electric plans to switch

to low-sulfur coal and purchase additional allowances;

Georgia Power will switch to low-sulfur coal from

eastern Appalachia or blend it with the high-sulfur they

have been burning and install a scrubber on one unit to

release some of its initially allotted allowances; and

Southern Indiana Gas and Electric plans to use a combination of scrubbing and selling unneeded allowances

for its affected units.

For the units of the six utilities profiled here, scrubbing

is the most costly compliance strategy. The high annual

total cost for units choosing scrubbing results from the

very high capital cost of scrubbers. Crucial to this

conclusion is the assumption to depreciate capital costs

over 15 years in this study. For all five of the units

adding scrubbers, estimated capital costs ranged from

just under $200 to over $300 per kilowatt. This brackets

the cost estimates cited in Chapter 3 of $227 to $266 per

kilowatt. Obtaining additional allowances has the

second highest average annual total costs. Crucial to

this conclusion is the assumed cost of SO2 allowances.

While obtaining additional allowances is a low capital

cost strategy, it is a high operating cost strategy. Finally, fuel switching is the least expensive strategy of

the units profiled here. Crucial to this conclusion is the

assumption by many utilities that lower-sulfur coal will

cost little or no more than the coal that they have been

burning.

A study estimating the overall costs of the Acid Rain

Legislation has been prepared for EPA.87 For the Phase

I requirements, the report estimates the annualized cost

of SO2 reductions to the electric generating sector will

range from $600 million to $1 billion (1992 dollars),

compared to the case where the CAAA90 were not

enacted. The study also estimates the cost imposed by

mandatory reductions specified in the CAAA90 without

allowance trading to range from $1.1 to $1.6 billion,

resulting in the flexible tradeable allowance system

reducing costs by $400 to $600 million.

Unlike with SO2 compliance strategies, electric utilities

affected by Phase I have little choice in how they

comply with NOx emission levels and install CEMs.

However, because NOx controls and CEMs are less

expensive than SO2 controls, the cost of the loss of

flexibility in NOx and CEM compliance strategies is less

than it would have been for SO2 strategies.

87ICF, “Regulatory Impact Analysis of the Final Acid Rain Implementation Regulations,” a report prepared for the U.S. Environmental

Protection Agency (October 19, 1992), pp. 4-6.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

48 Clean Air Act Amendments of 1990
Appendix A

Phase I Affected Units

of the Clean Air Act

Amendments of 1990
Appendix A

Phase I Affected Units of the Clean Air Act

Amendments of 1990

Profile of Affected Units

This appendix provides detailed information concerning

the 261 generating units (263 boilers) listed in the Clean

Air Act Amendments of 1990 as being affected by

Phase I of the Acid Rain Program (Table A1).89 The

data are presented alphabetically by State, operating

utility, plant and then numerically and alphabetically

by generator identification number. The data represent

electric generating plants in 21 States, and involve 64

operating utilities.

The following information is presented for each unit

separately: (1) generator nameplate capacity (given in

megawatts); (2) initial Phase I allowance allocations; (3)

base SO2 emissions (given in tons); (4) Phase I extension

allowance allocations; and (5) code of the method of

compliance. A brief explanation of each of these categories follows.

First, the generator nameplate capacity provides the

operating utility’s nameplate capacity for each generator. This data is taken from the Inventory of Power

Plants in the United States 1992.

Next, the initial Phase I allowance allocation totals were

issued by the U.S. Environmental Protection Agency

(EPA) as published in the Federal Register on January

11, 1993.90 Each unit was allotted a certain number of

allowances. For each allowance, the unit may emit one

ton of SO2 emissions.

Base SO2 emissions are listed next. Base SO2 emissions

are estimates of 1985 coal and oil SO2 emissions. These

estimates are from EPA’s National Allowance Data

Base, version 2.11, dated January 1993. Phase I extension allowances are also presented in Appendix A.

Phase I extension allowances were awarded to (1)

control units that install a technology that removes 90

percent or more of their SO2 emissions, or (2) control

units and other units that use a different compliance

strategy but are associated with the control unit in the

extension allowance application. Those that requested,

but did not receive, extension allowances are shown in

the Phase I Extension Allowances column in Table A1

with zeroes.

Finally, the code for the method of compliance is presented. The compliance strategies have been compiled

into six groupings with coded numbers associated with

each strategy as follows: (1) fuel switching and/or

blending; (2) obtaining additional allowances; (3)

installing flue gas desulfurization equipment (scrubbers); (4) using previously implemented controls; (5)

retiring facilities; and (6) boiler repowering.

Several sources were used to obtained compliance

strategy information about each unit. These sources

include EPA, Coal Week, Compliance Strategies Review, the

Georgia Public Utility Commission, Utility Environment

Report, and McIlvaine Utility Forecast. The method of

compliance was updated as of October 22, 1993.

Methodology for Calculating

Coal Requirements

Estimates of the additional requirements for low-sulfur

coal from the Central Appalachian Region and the

Powder River Basin were made for those utilities that

have chosen to switch to a lower sulfur coal or blend a

lower sulfur coal with their currently used coal. The

new source for obtaining low-sulfur coal was based on

utility plans as reported in news articles or through

communications with the utility. The estimates were

89Table A of the CAAA90 specified 263 boiler units that were affected by Phase I. These boilers are attached to 261 electric power

generators at 261 generating units. This report uses generators to present individual unit data. 90Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 51
calculated using the consumption data for the targeted

boilers only with the following procedure:

(1) The 1992 SO2 emission levels of the targeted

boilers were calculated using coal consumption in

tons, sulfur content, and Btu content as reported

on the Energy Information Administration, Form

EIA-767, “Steam-Electric Plant Operation and

Design Report.”

(2) An algorithm was derived to use the 1992 SO2

emissions of the targeted boilers and the average

Btu and sulfur content of coal from the Central

Appalachian Region or the Powder River Basin

depending on which new source of coal the

utility had chosen. The algorithm was used to

calculate for each targeted boiler, what combination of tonnage of high-sulfur coal from the

existing source and the low-sulfur coal from the

Central Appalachian Region or Powder River

Basin would be required to supply the required

Btu levels and reach the emission compliance

level of 2.5 pounds of SO2 per million Btu.

(3) From that calculation all tonnage from the

Central Appalachian Region was totaled as well

as all tonnage from the Powder River Basin, thus

giving the additional future requirements from

each region.

The 1992 coal receipts at plants that have indicated fuel

switching and/or blending to meet compliance with

Phase I are also listed (Table A2).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

52 Clean Air Act Amendments of 1990
Table A1. Profile of the 261 Generators Affected by Phase I

State

Operating

Utility Plant

Generator

Numbera

Affected

Nameplate

Capacity

(Megawatts)

Allowancesb

(per year)

1985

SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancesc

Code of

Compliance

Methodd

Alabama Alabama Power E C Gaston 1 272.0 17,624 22,220 -- 1

Alabama Alabama Power E C Gaston 2 272.0 18,052 21,862 -- 1

Alabama Alabama Power E C Gaston 3 272.0 17,828 23,369 -- 1

Alabama Alabama Power E C Gaston ST4 244.8 18,773 23,485 -- 1

Alabama Alabama Power E C Gaston 5 952.0 58,265 68,352 -- 1

Alabama TVA Colbert 1 200.0 13,213 20,522 -- 1

Alabama TVA Colbert 2 200.0 14,907 20,227 -- 1

Alabama TVA Colbert 3 200.0 14,995 23,325 -- 1

Alabama TVA Colbert 4 200.0 15,005 24,748 -- 1

Alabama TVA Colbert 5 550.0 36,202 52,318 19,442 1

Florida Gulf Power Crist 6 369.8 18,695 27,469 0 1

Florida Gulf Power Crist 7 578.0 30,846 55,921 39,714 1

Florida Tampa Electric Big Bend 1 445.5 27,662 56,181 -- 1

Florida Tampa Electric Big Bend ST2 445.5 26,387 53,820 -- 1

Florida Tampa Electric Big Bend ST3 445.5 26,036 32,901 -- 1

Georgia Georgia Power Bowen 1 805.8 54,838 71,428 -- 1

Georgia Georgia Power Bowen 2 788.8 53,329 63,727 -- 1

Georgia Georgia Power Bowen 3 952.0 69,862 82,488 -- 1

Georgia Georgia Power Bowen 4 952.0 69,852 87,659 -- 1

Georgia Georgia Power Hammond 1 125.0 8,549 9,830 -- 1

Georgia Georgia Power Hammond 2 125.0 8,977 9,997 -- 1

Georgia Georgia Power Hammond 3 125.0 8,676 9,068 -- 1

Georgia Georgia Power Hammond 4 578.0 36,650 35,539 -- 1

Georgia Georgia Power Jack McDonough 1 299.2 19,386 32,738 27,391 1

Georgia Georgia Power Jack McDonough 2 299.2 20,058 33,749 -- 1

Georgia Georgia Power Wansley 1 952.0 68,908 128,505 -- 1

Georgia Georgia Power Wansley 2 952.0 63,708 120,146 100,186 1

Georgia Georgia Power Yates 1 122.5 7,020 11,673 9,225 3

Georgia Georgia Power Yates 2 122.5 6,855 11,199 -- 1

Georgia Georgia Power Yates 3 122.5 6,767 11,279 -- 1

Georgia Georgia Power Yates 4 156.3 8,676 13,758 -- 1

Georgia Georgia Power Yates 5 156.3 9,162 15,754 -- 1

Georgia Georgia Power Yates 6 403.8 24,108 42,207 9,236 1

Georgia Georgia Power Yates 7 403.8 20,915 23,974 2,806 1

Illinois Central Illinois Public Coffeen 1 389.0 12,925 38,013 -- 1

Service

Illinois Central Illinois Public Coffeen 2 616.5 39,102 102,616 -- 1

Service

Illinois Central Illinois Public Grand Tower 4 113.6 6,479 9,754 -- 2

Service

Illinois Central Illinois Public Meredosia 3 239.4 15,227 27,015 -- 1

Service

Illinois Commonwealth Edison Kincaid 1 659.7 34,565 94,042 -- 1

Illinois Commonwealth Edison Kincaid 2 659.7 37,063 79,919 -- 1

Illinois Electric Energy Inc. Joppa Steam 1 183.4 12,259 18,354 -- 1

Illinois Electric Energy Inc. Joppa Steam 2 183.4 10,487 16,585 -- 1

Illinois Electric Energy Inc. Joppa Steam 3 183.4 11,947 18,839 -- 1

Illinois Electric Energy Inc. Joppa Steam 4 183.4 11,061 18,843 -- 1

Illinois Electric Energy Inc. Joppa Steam 5 183.4 11,119 19,415 -- 1

Illinois Electric Energy Inc. Joppa Steam 6 183.4 10,341 16,348 -- 1

Illinois Illinois Power Baldwin 1 623.1 46,052 89,277 -- 2

Illinois Illinois Power Baldwin 2 634.5 48,695 78,477 -- 2

Illinois Illinois Power Baldwin 3 634.5 46,644 96,840 0 2

Illinois Illinois Power Hennepin 2 231.3 20,182 39,436 0 2

Illinois Illinois Power Vermilion 2 108.8 9,735 18,600 -- 2

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 53
Table A1. Profile of the 261 Generators Affected by Phase I (Continued)

State

Operating

Utility Plant

Generator

Numbera

Affected

Nameplate

Capacity

(Megawatts)

Allowancesb

(per year)

1985

SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancesc

Code of

Compliance

Methodd

Indiana Hoosier Energy REC Inc Frank E. Ratts 1 116.6 9,131 19,069 -- 1

Indiana Hoosier Energy REC Inc Frank E. Ratts 2 116.6 9,296 18,436 -- 1

Indiana Indiana Michigan Power Breed 1 495.6 20,280 70,365 -- 5

Indiana Indiana Michigan Power Tanners Creek 4 579.7 27,209 59,646 -- 1

Indiana Indiana-Kentucky Electric Clifty Creek 1 217.3 19,620 45,690 -- 1

Indiana Indiana-Kentucky Electric Clifty Creek 2 217.3 19,289 44,275 -- 1

Indiana Indiana-Kentucky Electric Clifty Creek 3 217.3 19,873 46,489 -- 1

Indiana Indiana-Kentucky Electric Clifty Creek 4 217.3 19,552 44,856 -- 1

Indiana Indiana-Kentucky Electric Clifty Creek 5 217.3 18,851 41,989 -- 1

Indiana Indiana-Kentucky Electric Clifty Creek 6 217.3 19,844 45,563 -- 1

Indiana Indianapolis Power & Elmer W. Stout 5 113.6 4,253 5,665 0 1

Light

Indiana Indianapolis Power & Elmer W. Stout 6 113.6 5,229 7,743 -- 1

Light

Indiana Indianapolis Power & Elmer W. Stout 7 470.9 25,883 35,007 0 1

Light

Indiana Indianapolis Power & HT Pritchard 6 113.6 6,325 7,586 0 1

Light

Indiana Indianapolis Power & Petersburg ST1 253.4 18,011 21,765 0 3

Light

Indiana Indianapolis Power & Petersburg ST2 471.0 35,496 53,110 0 3

Light

Indiana Northern Indiana Public Bailly 7 194.0 12,256 26,874 46,521 3

Service

Indiana Northern Indiana Public Bailly 8 421.6 17,134 12,312 59,014 3

Service

Indiana Northern Indiana Public Michigan City 12 540.0 25,553 45,434 46,820 1

Service

Indiana PSI Energy Cayuga 1 531.0 36,581 56,848 21,603 1

Indiana PSI Energy Cayuga 2 531.0 37,415 69,254 3,164 1

Indiana PSI Energy Gibson 1 668.0 44,288 71,467 -- 1

Indiana PSI Energy Gibson 2 668.0 44,956 77,864 -- 1

Indiana PSI Energy Gibson 3 668.0 45,033 67,787 -- 1

Indiana PSI Energy Gibson 4 668.0 44,200 77,551 32,242 3

Indiana PSI Energy R Gallagher 1 150.0 7,115 1,770 13,586 1

Indiana PSI Energy R Gallagher 2 150.0 7,980 19,178 9,328 1

Indiana PSI Energy R Gallagher 3 150.0 7,159 20,883 11,936 1

Indiana PSI Energy R Gallagher 4 150.0 8,386 21,980 8,252 1

Indiana PSI Energy Wabash River 1 112.5 4,385 6,713 5,451 6

Indiana PSI Energy Wabash River 2 112.5 3,135 6,308 5,478 1

Indiana PSI Energy Wabash River 3 123.3 4,111 6,889 -- 1

Indiana PSI Energy Wabash River 5 125.0 4,023 8,201 1,630 1

Indiana PSI Energy Wabash River 6 387.0 13,462 26,239 7,800 1

Indiana Southern Indiana Gas & FB Culley 2 103.7 4,703 16,361 0 3

Electric

Indiana Southern Indiana Gas & FB Culley 3 265.2 18,603 38,456 0 3

Electric

Indiana Southern Indiana Gas & Warrick e

4 323.0 29,577 58,813 0 1

Electric

Iowa Interstate Power Milton L Kapp 2 218.5 13,437 31,379 -- 1

Iowa Iowa Electric Light & Prairie Creek 4 148.8 7,965 12,466 -- 1

Power

Iowa Iowa Power Des Moines 7 113.6 2,259 2,490 -- 5

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

54 Clean Air Act Amendments of 1990
Table A1. Profile of the 261 Generators Affected by Phase I (Continued)

State

Operating

Utility Plant

Generator

Numbera

Affected

Nameplate

Capacity

(Megawatts)

Allowancesb

(per year)

1985

SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancesc

Code of

Compliance

Methodd

Iowa Iowa Public Service George Neal North 1 147.1 2,571 1,048 -- 4

Iowa Iowa Southern Utilities Burlington 1 212.0 10,428 23,093 -- 1

Iowa Iowa-Illinois Gas & Riverside 5 136.0 3,885 4,707 -- 1

Electric

Kansas City of Kansas City Quindaro ST2 157.5 4,109 3,255 -- 4

Kentucky Big Rivers Electric Coleman 1 174.3 10,954 18,537 19,916 1

Kentucky Big Rivers Electric Coleman 2 174.3 12,502 19,862 13,722 1

Kentucky Big Rivers Electric Coleman 3 172.8 12,015 19,007 8,380 1

Kentucky Big Rivers Electric HMP&L Station 2 1 180.0 12,989 22,040 27,828 3

Kentucky Big Rivers Electric HMP&L Station 2 2 184.5 11,986 22,831 29,044 3

Kentucky City of Owensboro Elmer Smith 1 151.0 6,348 10,176 0 3

Kentucky City of Owensboro Elmer Smith 2 265.0 14,031 26,755 0 3

Kentucky East Kentucky Power Cooper 1 100.0 7,254 8,605 -- 1

Kentucky East Kentucky Power Cooper 2 220.9 14,917 14,870 -- 1

Kentucky East Kentucky Power HL Spurlock 1 305.2 22,181 29,745 -- 1

Kentucky Kentucky Utilities EW Brown 1 113.6 6,923 6,242 -- 2

Kentucky Kentucky Utilities EW Brown 2 179.5 10,623 10,029 2,996 2

Kentucky Kentucky Utilities EW Brown 3 446.4 25,413 38,577 19,842 2

Kentucky Kentucky Utilities Ghent 1 556.9 27,662 71,102 89,689 3

Kentucky Kentucky Utilities Green River 4 113.6 7,614 12,939 15,966 2

Kentucky TVA Paradise 3 1,150.2 57,613 106,835 156,070 2

Kentucky TVA Shawnee 10 175.0 9,902 34,077 -- 1

Maryland Baltimore Gas & Electric CP Crane 1 190.4 10,058 9,722 4,868 1

Maryland Baltimore Gas & Electric CP Crane 2 209.4 8,987 9,657 -- 1

Maryland Potomac Electric Power Chalk Point ST1 364.0 21,333 20,258 8,140 1

Maryland Potomac Electric Power Chalk Point ST2 364.0 23,690 27,482 0 1

Maryland Potomac Electric Power Morgantown ST1 626.0 34,332 29,388 11,064 1

Maryland Potomac Electric Power Morgantown ST2 626.0 37,467 37,988 16,250 1

Michigan Consumers Power JH Campbell 1 265.0 18,773 27,180 -- 4

Michigan Consumers Power JH Campbell 2 385.0 22,453 33,350 -- 4

Minnesota Northern States Power High Bridge 6 163.2 4,158 2,176 -- 4

Mississippi Mississippi Power Jack Watson 4 250.0 17,439 26,218 0 1

Mississippi Mississippi Power Jack Watson 5 500.0 35,734 46,401 0 1

Missouri Associated Electric Coop New Madrid 1 600.0 27,497 74,430 -- 1

Missouri Associated Electric Coop New Madrid 2 600.0 31,625 77,895 -- 1

Missouri Associated Electric Coop Thomas Hill 1 180.0 9,980 35,874 -- 1

Missouri Associated Electric Coop Thomas Hill 2 285.0 18,880 56,866 -- 1

Missouri City of Springfield James River 5 105.0 4,722 9,096 -- 1

Missouri Empire District Electric Asbury 1 212.8 15,764 68,769 -- 4

Missouri Kansas City Power & Montrose 1 187.5 7,196 28,740 -- 4

Light

Missouri Kansas City Power & Montrose 2 187.5 7,984 32,165 -- 4

Light

Missouri Kansas City Power & Montrose 3 188.1 9,824 35,192 -- 4

Light

Missouri Union Electric Labadie 1 573.8 39,055 72,811 -- 1

Missouri Union Electric Labadie 2 573.8 36,718 63,653 -- 1

Missouri Union Electric Labadie 3 621.0 39,249 67,587 -- 1

Missouri Union Electric Labadie 4 621.0 34,994 65,591 -- 1

Missouri Union Electric Sioux 1 549.8 21,976 42,688 -- 1

Missouri Union Electric Sioux 2 549.8 23,067 14,504 -- 1

Missouri Utilcorp United Sibley 3 418.5 15,170 26,812 -- 1

New Public Service of New Merrimack 1 113.6 9,922 15,258 -- 4

Hampshire Hampshire

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 55
Table A1. Profile of the 261 Generators Affected by Phase I (Continued)

State

Operating

Utility Plant

Generator

Numbera

Affected

Nameplate

Capacity

(Megawatts)

Allowancesb

(per year)

1985

SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancesc

Code of

Compliance

Methodd

New Public Service of New Merrimack 2 345.6 21,421 38,980 -- 4

Hampshire Hampshire

New Jersey Atlantic City Electric BL England 1 136.0 8,822 16,300 11,086 2

New Jersey Atlantic City Electric BL England 2 163.2 11,412 17,822 24,312 3

New York Long Island Lighting Northport ST1 387.1 19,289 26,583 -- 4

New York Long Island Lighting Northport 2 387.1 23,476 25,915 -- 4

New York Long Island Lighting Northport 3 387.1 25,783 27,360 -- 4

New York Long Island Lighting Port Jefferson 3 187.5 10,194 10,602 -- 4

New York Long Island Lighting Port Jefferson 4 187.5 12,006 12,195 -- 4

New York New York State Gas & Greenidge 4 112.5 7,342 11,548 0 1

Electric

New York New York State Gas & Milliken 1 155.3 10,876 9,400 0 3

Electric

New York New York State Gas & Milliken 2 167.2 12,083 15,398 0 3

Electric

New York Niagara Mohawk Dunkirk 3 218.0 12,268 18,214 -- 1

New York Niagara Mohawk Dunkirk ST4 218.0 13,690 16,846 -- 1

Ohio Cardinal Operating Co. Cardinal 1 615.2 37,568 69,012 93,076 2

Ohio Cardinal Operating Co. Cardinal 2 615.2 42,008 71,532 -- 1

Ohio Cincinnati Gas & Electric Miami Fort f

5 100.0 834 262 -- 1

Ohio Cincinnati Gas & Electric Miami Fort 6 163.2 12,475 21,111 -- 1

Ohio Cincinnati Gas & Electric Miami Fort 7 557.1 42,216 62,456 -- 1

Ohio Cincinnati Gas & Electric Walter C Beckjord 5 244.8 9,811 12,735 -- 1

Ohio Cincinnati Gas & Electric Walter C Beckjord 6 460.8 25,235 39,140 -- 1

Ohio Cleveland Electric Illum. Ashtabula 5 256.0 18,351 37,621 0 1

Ohio Cleveland Electric Illum. Avon Lake 8 233.0 12,771 16,952 -- 5

Ohio Cleveland Electric Illum. Avon Lake 9 680.0 33,413 41,322 -- 1

Ohio Cleveland Electric Illum. Eastlake 1 123.0 8,551 16,550 0 1

Ohio Cleveland Electric Illum. Eastlake 2 123.0 9,471 17,267 -- 1

Ohio Cleveland Electric Illum. Eastlake 3 123.0 10,984 19,545 -- 1

Ohio Cleveland Electric Illum. Eastlake 4 208.0 15,906 24,997 -- 1

Ohio Cleveland Electric Illum. Eastlake 5 680.0 37,349 79,918 10,292 1

Ohio Columbus Southern Conesville 1 148.0 4,615 6,468 8,618 1

Power

Ohio Columbus Southern Conesville 2 136.0 5,360 7,008 -- 1

Power

Ohio Columbus Southern Conesville 3 161.5 6,029 9,646 13,128 1

Power

Ohio Columbus Southern Conesville 4 841.5 53,463 98,256 -- 2

Power

Ohio Columbus Southern Picway 5 106.3 5,404 13,671 13,126 1

Power

Ohio Ohio Edison Edgewater 4 113.6 5,536 6,149 -- 1

Ohio Ohio Edison Niles 1 132.8 7,608 14,054 21,528 2

Ohio Ohio Edison Niles g

2 132.8 9,975 16,264 9,177 3

Ohio Ohio Edison REBurger h

3 103.5 6,742 12,965 5,503 2

Ohio Ohio Edison REBurger 4 156.3 11,818 21,956 20,310 2

Ohio Ohio Edison REBurger 5 156.3 13,626 25,973 19,002 2

Ohio Ohio Edison WH Sammis 5 334.1 26,496 34,632 -- 1

Ohio Ohio Edison WH Sammis 6 680.0 43,773 61,391 -- 1

Ohio Ohio Edison WH Sammis 7 680.0 47,380 54,557 -- 1

Ohio Ohio Power Gen JM Gavin 1 1,300.0 86,690 177,338 291,340 3

Ohio Ohio Power Gen JM Gavin 2 1,300.0 88,312 185,911 279,986 3

Ohio Ohio Power Muskingum River 1 219.7 16,312 41,429 43,378 2

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

56 Clean Air Act Amendments of 1990
Table A1. Profile of the 261 Generators Affected by Phase I (Continued)

State

Operating

Utility Plant

Generator

Numbera

Affected

Nameplate

Capacity

(Megawatts)

Allowancesb

(per year)

1985

SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancesc

Code of

Compliance

Methodd

Ohio Ohio Power Muskingum River 2 219.7 15,533 41,796 36,986 2

Ohio Ohio Power Muskingum River 3 237.5 15,293 36,195 41,674 2

Ohio Ohio Power Muskingum River 4 237.5 12,914 35,108 42,478 2

Ohio Ohio Power Muskingum River 5 615.2 44,364 98,907 -- 1

Ohio Ohio Valley Electric Kyger Creek 1 217.3 18,773 45,319 -- 1

Ohio Ohio Valley Electric Kyger Creek 2 217.3 18,072 44,494 -- 1

Ohio Ohio Valley Electric Kyger Creek 3 217.3 17,439 42,499 -- 1

Ohio Ohio Valley Electric Kyger Creek 4 217.3 18,218 43,345 -- 1

Ohio Ohio Valley Electric Kyger Creek 5 217.3 18,247 46,886 -- 1

Pennsylvania Duquesne Light Cheswick 1 565.0 38,139 41,927 -- 1

Pennsylvania Metropolitan Edison Co. Portland 1 171.7 5,784 6,436 7,178 1

Pennsylvania Metropolitan Edison Co. Portland 2 255.0 9,961 10,892 14,696 1

Pennsylvania Pennsylvania Electric Co. Conemaugh 1 936.0 58,217 92,088 145,727 3

Pennsylvania Pennsylvania Electric Co. Conemaugh 2 936.0 64,701 89,804 122,178 3

Pennsylvania Pennsylvania Electric Co. Shawville 1 125.0 10,048 13,485 -- 1

Pennsylvania Pennsylvania Electric Co. Shawville 2 125.0 10,048 14,310 -- 1

Pennsylvania Pennsylvania Electric Co. Shawville 3 187.5 13,846 18,692 -- 1

Pennsylvania Pennsylvania Electric Co. Shawville 4 187.5 13,700 17,683 -- 1

Pennsylvania Pennsylvania Power & Brunner Island 1 363.3 27,030 32,078 -- 1

Light

Pennsylvania Pennsylvania Power & Brunner Island 2 405.0 30,282 34,103 3,426 1

Light

Pennsylvania Pennsylvania Power & Brunner Island 3 790.4 52,404 58,775 16,334 1

Light

Pennsylvania Pennsylvania Power & Martin’s Creek 1 156.3 12,327 14,627 -- 1

Light

Pennsylvania Pennsylvania Power & Martin’s Creek 2 156.3 12,483 14,131 -- 1

Light

Pennsylvania Pennsylvania Power & Sunbury 3 103.5 8,530 10,046 1,206 1

Light

Pennsylvania Pennsylvania Power & Sunbury 4 156.3 11,149 14,077 486 1

Light

Pennsylvania West Pennsylvania Power Armstrong 1 163.2 14,031 16,434 7,414 2

Pennsylvania West Pennsylvania Power Armstrong 2 163.2 15,024 15,423 -- 2

Pennsylvania West Pennsylvania Power Hatfield’s Ferry 1 576.0 36,835 54,286 37,794 2

Pennsylvania West Pennsylvania Power Hatfield’s Ferry 2 576.0 36,338 51,986 42,336 2

Pennsylvania West Pennsylvania Power Hatfield’s Ferry 3 576.0 39,210 54,809 34,740 2

Tennessee TVA Allen 1 330.0 14,917 21,866 -- 2

Tennessee TVA Allen 2 330.0 16,329 25,986 -- 2

Tennessee TVA Allen 3 330.0 15,258 19,696 -- 2

Tennessee TVA Cumberland 1 1,300.0 84,419 148,104 251,040 3

Tennessee TVA Cumberland 2 1,300.0 92,344 196,049 261,583 3

Tennessee TVA Gallatin 1 300.0 17,400 28,846 29,656 2

Tennessee TVA Gallatin 2 300.0 16,855 30,410 29,658 2

Tennessee TVA Gallatin 3 327.6 19,493 35,789 33,392 2

Tennessee TVA Gallatin 4 327.6 20,701 35,351 26,376 2

Tennessee TVA Johnsonville 1 125.0 7,585 11,123 -- 1

Tennessee TVA Johnsonville 2 125.0 7,828 10,657 -- 1

Tennessee TVA Johnsonville 3 125.0 8,189 9,712 -- 1

Tennessee TVA Johnsonville 4 125.0 7,780 8,968 -- 1

Tennessee TVA Johnsonville 5 147.0 8,023 8,544 -- 1

Tennessee TVA Johnsonville 6 147.0 7,682 8,767 -- 1

Tennessee TVA Johnsonville 7 172.8 8,744 10,389 -- 1

Tennessee TVA Johnsonville 8 172.8 8,471 10,207 -- 1

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 57
Table A1. Profile of the 261 Generators Affected by Phase I (Continued)

State

Operating

Utility Plant

Generator

Numbera

Affected

Nameplate

Capacity

(Megawatts)

Allowancesb

(per year)

1985

SO2

Emissions

(tons)

Total

Phase I

Extension

Allowancesc

Code of

Compliance

Methodd

Tennessee TVA Johnsonville 9 172.8 6,894 8,922 -- 1

Tennessee TVA Johnsonville 10 172.8 7,351 8,835 -- 1

West Virginia Monongahela Power Albright 3 140.3 11,684 11,938 -- 2

West Virginia Monongahela Power Fort Martin 1 576.0 40,496 44,309 2,818 2

West Virginia Monongahela Power Fort Martin 2 576.0 40,116 44,824 8,004 2

West Virginia Monongahela Power Harrison 1 684.0 47,341 78,231 132,755 3

West Virginia Monongahela Power Harrison 2 684.0 44,936 78,231 151,144 3

West Virginia Monongahela Power Harrison 3 684.0 40,408 78,231 152,604 3

West Virginia Ohio Power Kammer 1 237.5 18,247 48,863 -- 1

West Virginia Ohio Power Kammer 2 237.5 18,948 57,963 -- 1

West Virginia Ohio Power Kammer 3 237.5 16,932 50,208 -- 1

West Virginia Ohio Power Mitchell 1 816.3 42,823 48,079 -- 1

West Virginia Ohio Power Mitchell 2 816.3 44,312 55,247 -- 1

West Virginia Virginia Electric & Power Mt. Storm 1 570.2 42,570 48,587 13,822 2

West Virginia Virginia Electric & Power Mt. Storm 2 570.2 34,644 35,817 21,118 2

West Virginia Virginia Electric & Power Mt. Storm 3 522.0 41,314 43,906 62,915 3

Wisconsin Dairyland Power Coop. Genoa ST3 345.6 22,103 35,035 -- 4

Wisconsin Wisconsin Electric Power North Oak Creek 1 120.0 5,083 6,810 -- 5

Wisconsin Wisconsin Electric Power North Oak Creek 2 120.0 5,005 7,916 -- 5

Wisconsin Wisconsin Electric Power North Oak Creek 3 130.0 5,229 7,184 -- 5

Wisconsin Wisconsin Electric Power North Oak Creek 4 130.0 6,154 9,323 -- 5

Wisconsin Wisconsin Electric Power South Oak Creek 5 275.0 9,416 16,586 -- 4

Wisconsin Wisconsin Electric Power South Oak Creek 6 275.0 11,723 17,748 -- 4

Wisconsin Wisconsin Electric Power South Oak Creek 7 317.6 15,754 27,888 -- 4

Wisconsin Wisconsin Electric Power South Oak Creek 8 324.0 15,375 22,553 -- 4

Wisconsin Wisconsin Power & Light Edgewater 4 330.0 24,099 39,722 -- 4

Wisconsin Wisconsin Power & Light Nelson Dewey 1 100.0 5,852 13,289 -- 4

Wisconsin Wisconsin Power & Light Nelson Dewey 2 100.0 6,504 12,273 -- 4

Wisconsin Wisconsin Public Service Pulliam 8 136.0 7,312 10,446 -- 4

a

Cincinnati Gas & Electric’s Miami Fort generator 5 has two boilers as does Ohio Edison’s R.E. Burger generator 3. Therefore, the total number of affected boilers

is 263 and the number of affected generators is 261. b

One SO2 allowance permits one ton of SO2 emissions. c

Phase I extension allowances were awarded to (1) control units that install a technology that removes 90 percent or more of their SO2 emissions or (2) control units

and other units that use a different compliance strategy but are associated with the control unit in the extension allowance application. Extension allowances were

awarded for 1995 through 1999. d

The codes for the method of compliance are: (1) fuel switching and/or blending; (2) obtaining additional allowances; (3) installing flue gas desulfurization equipment

(scrubbers); (4) using previously implemented controls; (5) retiring facilities; and (6) boiler repowering. Each plant is shown as using one primary compliance method.

However, many plants intend to also use one or more of the other available options in conjunction with their primary method. These compliance methods are based

on information obtained in late 1993. e

The compliance method for Warrick listed here is based upon information received in late 1993. Southern Indiana Gas and Electric, who owns 50 percent of Warrick’s

power, has since decided to use allowances to meet compliance at Warrick unit 4. Alcoa, who owns the other 50 percent, appears to have not yet finalized their

compliance strategy. f

Miami Fort generator 5 has two boilers. Allowances and 1985 SO2 emissions for the boilers were added to provide generator-level data. g

Niles unit 2 is using a flue gas desulfurization technology that is not considered a scrubber.

h

R.E. Burger generator 3 has two boilers. Allowances and 1985 SO2 emissions for the boilers were added to provide generator-level data.

SO2 = Sulfur dioxide.

TVA = Tennessee Valley Authority.

Source: Compliance Method: U.S. Environmental Protection Agency, Coal Week, Compliance Strategies Review, Georgia Public Utility Commission, Utility

Environment Report, and McIlvaine Utility Forecast. List of Affected Units: Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691. Capacity: Energy

Information Administration, Inventory of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC, October 1993). 1985 Emissions: U.S. Environmental Protection

Agency, National Allowance Data Base, Versions 2.11 (January 1993). Phase I Extension Allowances: Facsimile from the U.S. Environmental Protection Agency

(February 7, 1994).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

58 Clean Air Act Amendments of 1990
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Alabama Power Co Gaston .................................................................. 3,840 12,059 1.67 11.93 174.7 42.14

Alabama ................................................................................................ 2,642 12,126 2.08 12.46 185.2 44.92

Fayette................................................................................................ 1,558 12,033 2.14 12.28 203.7 49.02

Jefferson............................................................................................. 595 12,326 1.83 12.63 181.1 44.65

Tuscaloosa ......................................................................................... 58 12,055 1.92 12.24 113.3 27.31

Walker................................................................................................ 431 12,194 2.22 12.88 134.7 32.86

West Virginia........................................................................................ 1,198 11,911 .77 10.77 151.2 36.02

Lincoln............................................................................................... 1,198 11,911 .77 10.77 151.2 36.02

Associated Electric Coop Inc Hill........................................................ 2,622 10,480 4.01 9.94 163.2 34.20

Missouri ................................................................................................ 2,506 10,555 4.19 10.19 164.8 34.79

Randolph............................................................................................ 2,506 10,555 4.19 10.19 164.8 34.79

Wyoming .............................................................................................. 116 8,844 .21 4.57 121.8 21.54

Campbell............................................................................................ 116 8,844 .21 4.57 121.8 21.54

Associated Electric Coop Inc Madrid................................................. 2,732 10,890 3.06 9.74 116.0 25.25

Illinois................................................................................................... 2,121 10,682 2.93 10.19 115.4 24.65

Randolph............................................................................................ 2,121 10,682 2.93 10.19 115.4 24.65

Indiana .................................................................................................. 63 11,279 3.03 8.50 109.9 24.79

Warrick .............................................................................................. 63 11,279 3.03 8.50 109.9 24.79

Kentucky............................................................................................... 548 11,651 3.56 8.15 118.7 27.66

Muhlenberg........................................................................................ 548 11,651 3.56 8.15 118.7 27.66

Baltimore Gas & Electric Co Crane ................................................... 725 13,449 2.03 6.57 144.6 38.89

Pennsylvania ......................................................................................... 234 13,309 2.14 7.26 140.8 37.47

Greene................................................................................................ 234 13,309 2.14 7.26 140.8 37.47

Virginia ................................................................................................. 78 14,076 .80 5.05 169.9 47.84

Buchanan ........................................................................................... 78 14,076 .80 5.05 169.9 47.84

West Virginia........................................................................................ 413 13,410 2.20 6.46 141.7 38.00

Barbour .............................................................................................. 7 13,232 2.12 8.00 138.6 36.68

Monongalia ........................................................................................ 406 13,413 2.20 6.43 141.7 38.03

Big Rivers Electric Corp Coleman...................................................... 1,133 11,267 2.54 8.08 97.4 21.95

Indiana .................................................................................................. 221 11,258 2.40 8.69 113.1 25.47

Daviess............................................................................................... 196 11,261 2.40 8.68 115.6 26.04

Gibson................................................................................................ 24 11,232 2.44 8.80 92.8 20.86

Kentucky............................................................................................... 912 11,269 2.57 7.93 93.6 21.10

Daviess............................................................................................... 25 11,141 2.16 8.09 92.9 20.70

Henderson .......................................................................................... 888 11,273 2.58 7.92 93.6 21.11

Cardinal Operating Co Cardinal......................................................... 4,277 11,842 2.16 12.88 148.0 35.06

Ohio ...................................................................................................... 1,086 12,211 3.17 11.29 133.5 32.59

Belmont.............................................................................................. 123 11,614 3.16 13.31 106.6 24.75

Harrison ............................................................................................. 500 12,225 3.01 11.47 152.9 37.40

Jefferson............................................................................................. 463 12,355 3.34 10.57 119.3 29.49

West Virginia........................................................................................ 3,191 11,717 1.81 13.42 153.2 35.89

Brooke................................................................................................ 1,548 12,116 2.87 10.40 143.4 34.75

Kanawha ............................................................................................ 1,400 11,219 .80 16.91 169.8 38.09

Logan ................................................................................................. 183 12,055 .70 12.52 131.0 31.59

Monongalia ........................................................................................ 25 12,082 1.10 12.47 108.7 26.28

Ohio ................................................................................................... 11 11,680 2.83 12.33 135.5 31.65

Preston ............................................................................................... 25 12,082 1.10 12.47 108.7 26.28

Central Illinois Pub Serv Co Coffeen ................................................. 1,755 10,562 3.00 8.53 155.6 32.87

Illinois................................................................................................... 1,755 10,562 3.00 8.53 155.6 32.87

Macoupin ........................................................................................... 1,755 10,562 3.00 8.53 155.6 32.87

Central Illinois Pub Serv Co Meredosia............................................. 529 11,570 2.71 6.08 152.9 35.38

Colorado................................................................................................ 53 11,861 .46 8.80 155.7 36.94

Gunnison............................................................................................ 53 11,861 .46 8.80 155.7 36.94

Illinois................................................................................................... 476 11,537 2.96 5.78 152.6 35.21

McDonough ....................................................................................... 13 11,438 3.16 6.30 133.5 30.54

Schuyler............................................................................................. 463 11,540 2.95 5.77 153.1 35.34

Cincinnati Gas & Electric Co Beckjord............................................. 1,351 11,754 1.76 12.46 164.7 38.71

See footnotes at end of table.

Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 59 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Cincinnati Gas & Electric Co Beckjord

Kentucky............................................................................................... 829 11,955 1.25 12.30 161.7 38.67

Breathitt ............................................................................................. 2 11,139 .89 12.00 98.3 21.90

Floyd .................................................................................................. 48 12,320 .72 12.14 131.5 32.41

Greenup.............................................................................................. 10 11,471 2.22 14.17 181.7 41.69

Knott .................................................................................................. 28 11,540 1.12 14.26 98.3 22.69

Magoffin ............................................................................................ 255 12,063 1.27 12.49 176.7 42.62

Martin ................................................................................................ 357 12,033 .81 12.99 179.2 43.12

Muhlenberg........................................................................................ 73 11,566 2.79 8.80 106.9 24.72

Ohio ................................................................................................... 33 11,563 2.81 8.67 107.3 24.80

Perry................................................................................................... 18 11,338 1.14 14.42 95.7 21.70

Union ................................................................................................. 5 11,443 2.81 8.20 102.1 23.37

Ohio ...................................................................................................... 442 11,430 2.64 12.58 168.2 38.45

Belmont.............................................................................................. 58 12,669 3.18 8.99 102.7 26.01

Jackson............................................................................................... 6 10,993 4.37 13.10 78.3 17.22

Lawrence............................................................................................ 377 11,247 2.53 13.12 181.1 40.73

West Virginia........................................................................................ 80 11,454 2.27 13.52 177.1 40.56

Fayette................................................................................................ 6 11,247 2.66 13.60 178.9 40.24

Kanawha ............................................................................................ 71 11,427 2.27 13.72 178.7 40.84

Mason ................................................................................................ 1 11,821 2.55 9.30 95.0 22.46

Mingo................................................................................................. 2 13,112 .70 7.40 158.1 41.46

Cincinnati Gas & Electric Co Miami Fort......................................... 2,501 12,166 1.32 11.04 163.5 39.79

Kentucky............................................................................................... 1,039 11,971 1.15 12.32 153.8 36.82

Floyd .................................................................................................. 276 12,283 .67 11.59 133.3 32.74

Knott .................................................................................................. 5 11,728 1.30 14.40 99.8 23.40

Magoffin ............................................................................................ 207 12,022 1.40 12.56 173.7 41.76

Martin ................................................................................................ 371 11,857 .81 14.04 182.0 43.16

Muhlenberg........................................................................................ 73 11,634 2.80 8.53 104.3 24.28

Ohio ................................................................................................... 40 11,588 2.82 8.53 105.4 24.44

Perry................................................................................................... 8 11,668 .92 12.92 106.8 24.92

Pike .................................................................................................... 35 12,003 .57 12.97 110.8 26.60

Union ................................................................................................. 23 11,425 2.84 8.16 100.6 22.99

Ohio ...................................................................................................... 466 11,423 2.56 12.62 175.1 40.01

Belmont.............................................................................................. 43 12,635 3.17 8.98 104.6 26.44

Jackson............................................................................................... 2 10,853 3.54 13.70 80.6 17.50

Lawrence............................................................................................ 422 11,300 2.50 12.99 183.5 41.48

Pennsylvania ......................................................................................... 40 13,263 2.39 7.13 99.0 26.26

Greene................................................................................................ 40 13,263 2.39 7.13 99.0 26.26

West Virginia........................................................................................ 956 12,696 .85 9.04 171.2 43.48

Clay.................................................................................................... 13 12,104 .64 12.58 116.0 28.09

Fayette................................................................................................ 8 11,216 2.61 12.99 181.5 40.72

Kanawha ............................................................................................ 606 12,546 .88 9.56 183.1 45.94

Logan ................................................................................................. 50 11,975 .64 12.45 119.0 28.49

Mason ................................................................................................ 11 11,784 2.60 9.31 96.7 22.78

Mingo................................................................................................. 268 13,284 .68 6.92 159.6 42.41

Cleveland Electric Illum Co Ashtabula .............................................. 901 12,840 3.22 8.50 150.8 38.73

Ohio ...................................................................................................... 509 12,446 3.95 9.52 175.7 43.72

Belmont.............................................................................................. 509 12,446 3.95 9.52 175.7 43.72

West Virginia........................................................................................ 392 13,353 2.28 7.18 120.8 32.25

Kanawha ............................................................................................ 32 12,397 .80 10.59 161.6 40.06

Monongalia ........................................................................................ 337 13,482 2.51 6.72 115.3 31.09

Nicholas............................................................................................. 23 12,794 .84 9.20 150.3 38.46

Cleveland Electric Illum Co Avon Lake............................................. 1,527 12,543 2.45 9.45 153.5 38.51

Ohio ...................................................................................................... 1,345 12,444 2.49 9.76 158.3 39.41

Belmont.............................................................................................. 262 12,420 3.15 9.54 214.4 53.26

Harrison ............................................................................................. 1,083 12,449 2.33 9.81 144.8 36.06

Pennsylvania ......................................................................................... 125 13,306 2.35 6.93 117.7 31.31

Greene................................................................................................ 125 13,306 2.35 6.93 117.7 31.31

West Virginia........................................................................................ 57 13,225 1.60 7.58 125.5 33.20

Mingo................................................................................................. 30 13,079 .70 9.10 135.1 35.34

Monongalia ........................................................................................ 27 13,388 2.61 5.90 115.1 30.82

Cleveland Electric Illum Co Eastlake ................................................. 2,029 12,920 2.63 8.37 149.6 38.66

See footnotes at end of table.

60 Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Cleveland Electric Illum Co Eastlake

Ohio ...................................................................................................... 987 12,591 3.46 9.34 170.0 42.80

Belmont.............................................................................................. 830 12,618 3.73 9.35 176.3 44.49

Columbiana........................................................................................ 157 12,444 2.05 9.23 135.9 33.83

Pennsylvania ......................................................................................... 675 13,234 1.99 7.33 127.9 33.85

Greene................................................................................................ 605 13,345 1.95 6.83 128.7 34.34

Westmoreland .................................................................................... 70 12,275 2.34 11.66 120.5 29.57

West Virginia........................................................................................ 367 13,227 1.58 7.70 137.4 36.36

Boone................................................................................................. 72 13,450 .85 6.33 155.9 41.95

Monongalia ........................................................................................ 156 13,266 2.60 7.45 117.9 31.28

Nicholas............................................................................................. 125 13,122 .83 8.78 149.7 39.28

Wayne ................................................................................................ 14 12,595 .78 8.00 152.0 38.29

Columbus & Southern Ohio El Co Conesville .................................. 3,422 12,031 3.23 8.27 149.5 35.98

Ohio ...................................................................................................... 3,422 12,031 3.23 8.27 149.5 35.98

Coshocton .......................................................................................... 1,895 12,166 3.26 7.37 169.5 41.24

Guernsey ............................................................................................ 20 11,719 2.45 10.63 99.8 23.39

Harrison ............................................................................................. 195 12,462 2.92 8.97 122.4 30.52

Holmes............................................................................................... 205 11,801 3.30 8.23 98.5 23.25

Jefferson............................................................................................. 72 11,946 2.86 11.45 103.7 24.77

Muskingum........................................................................................ 105 11,901 3.99 8.99 101.4 24.14

Noble.................................................................................................. 8 11,697 3.47 12.91 95.2 22.26

Perry................................................................................................... 127 11,171 2.57 13.27 121.8 27.22

Tuscarawas ........................................................................................ 795 11,835 3.25 8.96 137.2 32.48

Columbus & Southern Ohio El Co Picway........................................ 307 11,457 3.05 9.86 105.4 24.16

Ohio ...................................................................................................... 307 11,457 3.05 9.86 105.4 24.16

Hocking.............................................................................................. 16 11,487 3.15 9.55 100.8 23.15

Holmes............................................................................................... 5 11,747 3.70 8.11 99.1 23.29

Jackson............................................................................................... 20 11,554 3.24 10.14 104.0 24.04

Perry................................................................................................... 98 11,375 3.25 9.64 99.6 22.67

Vinton ................................................................................................ 169 11,481 2.88 10.03 109.6 25.16

Commonwealth Edison Co Kincaid .................................................... 1,716 10,516 3.40 8.68 166.9 35.09

Illinois................................................................................................... 1,716 10,516 3.40 8.68 166.9 35.09

Christian............................................................................................. 1,611 10,445 3.52 8.74 170.6 35.63

Franklin.............................................................................................. 105 11,611 1.46 7.77 115.7 26.87

Duquesne Light Co Cheswick .............................................................. 1,320 12,975 1.75 9.39 128.1 33.23

Pennsylvania ......................................................................................... 975 13,047 1.82 8.89 127.9 33.36

Allegheny........................................................................................... 261 12,832 1.19 8.83 135.7 34.83

Armstrong .......................................................................................... 10 12,998 2.01 11.35 107.4 27.92

Fayette................................................................................................ 121 12,854 1.16 9.46 133.5 34.32

Greene................................................................................................ 551 13,181 2.27 8.82 123.6 32.59

Washington ........................................................................................ 32 13,235 1.51 7.64 123.6 32.70

West Virginia........................................................................................ 345 12,771 1.56 10.79 128.7 32.87

Fayette................................................................................................ 148 12,937 1.10 9.77 130.8 33.85

Monongalia ........................................................................................ 197 12,647 1.91 11.55 127.0 32.13

East Kentucky Power Coop Cooper ................................................... 732 12,361 1.62 10.09 113.1 27.95

Kentucky............................................................................................... 700 12,339 1.60 10.08 113.5 28.01

Clay.................................................................................................... 114 12,677 1.45 8.35 109.9 27.86

Jackson............................................................................................... 8 11,566 2.19 11.96 103.4 23.92

Laurel................................................................................................. 13 11,985 1.41 11.32 90.1 21.60

Leslie.................................................................................................. 46 12,661 1.95 9.16 110.9 28.08

Mccreary ............................................................................................ 25 13,250 .99 5.17 106.9 28.34

Perry................................................................................................... 48 12,456 1.30 9.06 107.0 26.66

Pulaski................................................................................................ 394 12,198 1.65 11.03 118.0 28.80

Whitley .............................................................................................. 34 12,131 1.62 9.95 107.1 25.98

Wolfe ................................................................................................. 18 11,876 1.98 10.58 105.5 25.06

Tennessee.............................................................................................. 32 12,837 2.02 10.31 103.8 26.64

Morgan............................................................................................... 32 12,835 2.03 10.36 103.7 26.62

Scott ................................................................................................... * 13,099 .82 4.80 109.6 28.71

East Kentucky Power Coop Spurlock................................................. 1,542 12,273 1.35 10.74 116.7 28.64

See footnotes at end of table.

Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 61 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

East Kentucky Power Coop Spurlock

Kentucky............................................................................................... 726 12,126 1.46 10.50 116.1 28.16

Boyd................................................................................................... 205 12,666 .80 9.21 116.1 29.40

Floyd .................................................................................................. 159 11,980 1.45 11.26 122.1 29.26

Greenup.............................................................................................. 215 11,493 2.50 11.69 110.2 25.34

Johnson .............................................................................................. 3 11,205 2.47 12.70 100.4 22.50

Knott .................................................................................................. 121 12,617 .70 9.31 121.3 30.60

Martin ................................................................................................ 11 11,583 .80 11.73 106.5 24.68

Perry................................................................................................... 3 11,758 1.84 15.00 76.7 18.04

Wolfe ................................................................................................. 9 11,995 2.16 10.27 100.4 24.08

Pennsylvania ......................................................................................... 33 12,939 2.52 8.02 101.0 26.13

Greene................................................................................................ 19 13,273 2.26 6.94 98.9 26.26

Washington ........................................................................................ 14 12,487 2.87 9.49 103.9 25.96

West Virginia........................................................................................ 783 12,382 1.20 11.08 117.9 29.19

Fayette................................................................................................ 356 12,556 1.76 12.50 122.8 30.83

Harrison ............................................................................................. 13 12,330 2.67 12.48 101.6 25.06

Kanawha ............................................................................................ 27 12,293 .69 11.91 109.5 26.92

Logan ................................................................................................. 100 12,159 .67 11.07 115.2 28.01

Mingo................................................................................................. 140 12,175 .66 9.56 114.3 27.84

Monongalia ........................................................................................ 3 11,295 1.86 15.70 96.2 21.73

Wayne ................................................................................................ 144 12,350 .63 8.66 114.2 28.21

Electric Energy Inc Joppa.................................................................... 3,108 10,915 1.66 7.21 104.3 22.77

Illinois................................................................................................... 2,129 11,898 2.22 8.16 108.2 25.75

Franklin.............................................................................................. 431 11,703 1.79 7.60 107.9 25.26

Perry................................................................................................... 401 11,023 3.01 9.36 99.5 21.93

Saline ................................................................................................. 1,283 12,241 2.11 7.93 110.7 27.11

Williamson......................................................................................... 13 11,448 2.76 11.51 108.0 24.73

Indiana .................................................................................................. 40 11,230 1.93 7.68 121.7 27.33

Gibson................................................................................................ 28 11,226 1.91 7.70 109.1 24.49

Pike .................................................................................................... 12 11,239 1.97 7.65 149.7 33.65

Wyoming .............................................................................................. 939 8,673 .38 5.03 91.2 15.82

Campbell............................................................................................ 939 8,673 .38 5.03 91.2 15.82

Georgia Power Co Atkinson-Mcdonoug ............................................. 1,383 11,877 1.88 9.59 162.9 38.70

Illinois................................................................................................... 34 11,259 2.86 9.48 208.9 47.05

Franklin.............................................................................................. 34 11,259 2.86 9.48 208.9 47.05

Indiana .................................................................................................. 555 11,294 2.51 8.13 138.4 31.26

Pike .................................................................................................... 555 11,294 2.51 8.13 138.4 31.26

Kentucky............................................................................................... 607 12,243 1.38 10.48 174.8 42.79

Leslie.................................................................................................. 170 12,642 1.30 9.59 174.7 44.18

Perry................................................................................................... 434 12,103 1.42 10.74 174.9 42.33

Pike .................................................................................................... 3 9,595 .81 24.70 154.6 29.67

Virginia ................................................................................................. 187 12,537 1.42 11.07 183.3 45.96

Lee ..................................................................................................... 159 12,439 1.38 11.33 185.3 46.09

Wise ................................................................................................... 28 13,097 1.69 9.55 172.7 45.24

Georgia Power Co Bowen..................................................................... 8,082 12,186 1.54 10.47 162.0 39.47

Illinois................................................................................................... 82 11,793 2.49 7.67 215.8 50.90

Franklin.............................................................................................. 82 11,793 2.49 7.67 215.8 50.90

Kentucky............................................................................................... 8,000 12,190 1.53 10.50 161.4 39.36

Bell..................................................................................................... 947 12,095 1.36 11.13 181.4 43.88

Clay.................................................................................................... 229 12,560 1.21 9.75 158.6 39.85

Hopkins.............................................................................................. 1,357 11,737 3.01 10.15 169.6 39.80

Knott .................................................................................................. 760 12,082 1.36 11.55 156.9 37.90

Leslie.................................................................................................. 2,713 12,325 1.28 10.48 158.9 39.17

Letcher............................................................................................... 104 12,402 1.39 11.19 174.8 43.36

Perry................................................................................................... 1,890 12,354 1.03 10.08 151.1 37.34

Georgia Power Co Hammond.............................................................. 803 12,971 1.66 9.86 174.9 45.36

Kentucky............................................................................................... 5 12,594 1.04 9.01 152.0 38.29

Leslie.................................................................................................. 5 12,594 1.04 9.01 152.0 38.29

Virginia ................................................................................................. 798 12,973 1.67 9.86 175.0 45.40

Lee ..................................................................................................... 137 12,722 1.39 10.60 179.5 45.68

Wise ................................................................................................... 661 13,025 1.72 9.71 174.1 45.35

Georgia Power Co Wansley ................................................................. 4,719 11,192 2.65 10.36 202.8 45.39

See footnotes at end of table.

62 Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Georgia Power Co Wansley

Alabama ................................................................................................ 54 12,172 1.99 12.11 135.7 33.03

Fayette................................................................................................ 54 12,172 1.99 12.11 135.7 33.03

Illinois................................................................................................... 4,378 11,269 2.79 9.40 207.8 46.83

Franklin.............................................................................................. 3,224 11,409 2.67 8.94 213.9 48.81

Perry................................................................................................... 1,077 10,879 3.11 10.77 194.0 42.21

Randolph............................................................................................ 77 10,862 2.95 9.50 131.0 28.45

Kentucky............................................................................................... 49 9,657 .68 23.87 147.9 28.57

Perry................................................................................................... 3 8,980 .60 28.04 146.6 26.33

Pike .................................................................................................... 46 9,699 .68 23.61 148.0 28.71

West Virginia........................................................................................ 227 9,918 .73 25.85 127.8 25.36

Fayette................................................................................................ 53 10,504 .73 22.68 138.7 29.14

Kanawha ............................................................................................ 133 9,822 .78 26.71 125.3 24.62

Logan ................................................................................................. 41 9,476 .56 27.12 120.8 22.89

Wyoming .............................................................................................. 11 8,777 .38 4.59 127.5 22.38

Campbell............................................................................................ 11 8,777 .38 4.59 127.5 22.38

Georgia Power Co Yates....................................................................... 1,576 11,965 1.99 10.70 190.3 45.54

Alabama ................................................................................................ 44 12,106 2.14 12.24 135.4 32.77

Fayette................................................................................................ 44 12,106 2.14 12.24 135.4 32.77

Illinois................................................................................................... 644 11,273 2.79 9.36 207.7 46.82

Franklin.............................................................................................. 470 11,423 2.67 8.90 213.7 48.81

Perry................................................................................................... 164 10,867 3.09 10.67 194.3 42.23

Randolph............................................................................................ 10 10,886 2.94 9.31 130.9 28.50

Kentucky............................................................................................... 15 10,138 1.05 21.87 152.1 30.84

Harlan ................................................................................................ 3 12,493 2.37 9.43 148.5 37.10

Pike .................................................................................................... 13 9,637 .77 24.52 153.1 29.51

Virginia ................................................................................................. 843 12,596 1.44 10.91 183.5 46.21

Lee ..................................................................................................... 632 12,458 1.39 11.30 187.2 46.65

Wise ................................................................................................... 210 13,009 1.60 9.71 172.6 44.91

West Virginia........................................................................................ 30 9,875 .72 25.67 130.5 25.77

Fayette................................................................................................ 9 10,323 .79 22.32 147.7 30.50

Kanawha ............................................................................................ 13 9,821 .77 26.91 124.5 24.45

Logan ................................................................................................. 8 9,485 .56 27.19 120.7 22.90

Wyoming .............................................................................................. * 8,777 .38 4.59 127.5 22.38

Campbell............................................................................................ * 8,777 .38 4.59 127.5 22.38

Gulf Power Co Crist ............................................................................. 2,077 11,945 2.71 8.53 172.2 41.13

Alabama ................................................................................................ 72 12,060 2.75 12.94 120.6 29.09

Walker................................................................................................ 72 12,060 2.75 12.94 120.6 29.09

Illinois................................................................................................... 1,780 11,926 2.70 8.37 180.8 43.12

Franklin.............................................................................................. 497 11,734 2.64 8.28 116.5 27.34

Gallatin .............................................................................................. 1,068 12,016 2.74 8.55 222.2 53.39

Saline ................................................................................................. 214 11,922 2.65 7.70 119.7 28.53

Kentucky............................................................................................... 226 12,062 2.73 8.38 121.4 29.28

Ohio ................................................................................................... 10 11,687 2.83 7.80 117.7 27.51

Union ................................................................................................. 216 12,079 2.72 8.40 121.5 29.36

Hoosier Energy R E C Inc Frank E Ratts......................................... 635 11,240 2.72 9.08 136.8 30.74

Indiana .................................................................................................. 635 11,240 2.72 9.08 136.8 30.74

Pike .................................................................................................... 635 11,240 2.72 9.08 136.8 30.74

Indiana & Michigan Electric Co Tanners Creek.............................. 1,323 11,609 1.88 9.22 154.1 35.78

Indiana .................................................................................................. 499 11,163 2.44 8.38 143.7 32.08

Warrick .............................................................................................. 499 11,163 2.44 8.38 143.7 32.08

Kentucky............................................................................................... 823 11,879 1.53 9.73 160.0 38.01

Hopkins.............................................................................................. 373 11,549 2.55 8.25 131.9 30.46

Unknown............................................................................................ 450 12,154 .69 10.95 182.2 44.29

Indiana-Kentucky Electric Corp Clifty Creek................................... 3,765 11,205 2.90 10.01 109.3 24.50

Indiana .................................................................................................. 306 10,892 3.23 10.34 94.6 20.61

Pike .................................................................................................... 61 11,463 3.45 8.29 98.3 22.54

Spencer .............................................................................................. 91 10,818 2.98 11.05 89.3 19.33

Warrick .............................................................................................. 154 10,710 3.29 10.74 96.2 20.61

See footnotes at end of table.

Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 63 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Indiana-Kentucky Electric Corp Clifty Creek

Kentucky............................................................................................... 2,987 11,419 3.26 10.77 106.5 24.32

Christian............................................................................................. 121 11,319 3.08 10.27 101.4 22.97

Daviess............................................................................................... 856 11,223 3.25 10.26 113.2 25.42

Hopkins.............................................................................................. 1,454 11,498 3.47 11.95 105.2 24.18

Letcher............................................................................................... 44 13,037 1.47 6.14 124.0 32.33

Mclean ............................................................................................... 61 11,688 3.01 11.44 101.2 23.66

Ohio ................................................................................................... 451 11,372 2.85 8.41 98.2 22.34

Virginia ................................................................................................. 112 13,888 .73 5.28 160.0 44.44

Buchanan ........................................................................................... 112 13,888 .73 5.28 160.0 44.44

Wyoming .............................................................................................. 360 8,859 .27 4.89 130.5 23.12

Campbell............................................................................................ 64 8,837 .33 4.82 126.1 22.29

Converse ............................................................................................ 296 8,864 .26 4.90 131.4 23.29

Indianapolis Power & Light Co Pritchard......................................... 358 11,376 1.07 6.79 121.9 27.73

Indiana .................................................................................................. 358 11,376 1.07 6.79 121.9 27.73

Greene................................................................................................ 297 11,445 1.10 6.40 119.1 27.26

Knox .................................................................................................. 61 11,040 .95 8.69 136.1 30.04

Indianapolis Power & Light Co Stout................................................ 1,069 11,213 1.60 8.06 128.0 28.70

Indiana .................................................................................................. 1,069 11,213 1.60 8.06 128.0 28.70

Clay.................................................................................................... 297 11,273 1.56 7.04 115.9 26.14

Greene................................................................................................ 534 11,287 1.43 7.94 120.2 27.14

Sullivan .............................................................................................. 238 10,973 2.02 9.59 161.4 35.42

Interstate Power Co Kapp.................................................................... 501 11,381 2.02 7.98 138.1 31.44

Illinois................................................................................................... 250 11,593 2.03 7.62 141.3 32.76

Perry................................................................................................... 250 11,593 2.03 7.62 141.3 32.76

Indiana .................................................................................................. 251 11,170 2.02 8.35 134.9 30.13

Pike .................................................................................................... 251 11,170 2.02 8.35 134.9 30.13

Iowa Electric Light & Power Prairie Creek 1-4 ............................... 439 9,763 1.47 7.15 129.1 25.21

Illinois................................................................................................... 153 11,605 2.08 7.90 136.6 31.72

Franklin.............................................................................................. 153 11,605 2.08 7.90 136.6 31.72

Iowa ...................................................................................................... 55 9,811 4.37 13.56 172.4 33.84

Marion................................................................................................ 55 9,811 4.37 13.56 172.4 33.84

Wyoming .............................................................................................. 231 8,531 .38 5.12 110.4 18.84

Campbell............................................................................................ 231 8,531 .38 5.12 110.4 18.84

Iowa Southern Utilities Co Burlington ............................................... 476 9,489 1.95 7.86 104.0 19.74

Indiana .................................................................................................. 179 11,439 3.09 8.94 123.3 28.20

Perry................................................................................................... 3 10,149 1.19 11.85 84.9 17.23

Warrick .............................................................................................. 175 11,464 3.13 8.88 123.9 28.42

Wyoming .............................................................................................. 297 8,316 1.27 7.21 88.1 14.65

Campbell............................................................................................ 297 8,316 1.27 7.21 88.1 14.65

Iowa-Illinois Gas&Electric Co Riverside............................................ 281 11,162 1.85 7.93 110.9 24.76

Illinois................................................................................................... 237 11,686 2.12 8.28 109.6 25.62

Franklin.............................................................................................. 237 11,686 2.12 8.28 109.6 25.62

Wyoming .............................................................................................. 44 8,338 .40 6.05 120.7 20.12

Campbell............................................................................................ 44 8,338 .40 6.05 120.7 20.12

Metropolitan Edison Co Portland ....................................................... 723 13,188 1.70 6.97 140.6 37.08

Pennsylvania ......................................................................................... 536 13,167 1.65 6.80 138.7 36.53

Armstrong .......................................................................................... 15 12,889 1.65 9.29 146.0 37.64

Clarion ............................................................................................... 24 12,838 2.17 8.68 138.2 35.49

Greene................................................................................................ 497 13,191 1.63 6.63 138.5 36.55

West Virginia........................................................................................ 187 13,250 1.84 7.45 145.9 38.66

Barbour .............................................................................................. 57 13,100 1.70 7.42 166.3 43.57

Monongalia ........................................................................................ 129 13,317 1.90 7.46 137.0 36.50

Mississippi Power Co Watson.............................................................. 1,487 12,665 2.70 8.64 132.4 33.53

Illinois................................................................................................... 1,239 12,757 2.74 8.75 132.7 33.86

Gallatin .............................................................................................. 1,239 12,757 2.74 8.75 132.7 33.86

See footnotes at end of table.

64 Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Mississippi Power Co Watson

Kentucky............................................................................................... 248 12,208 2.50 8.08 130.5 31.87

Greenup.............................................................................................. 26 12,047 1.85 8.28 140.0 33.73

Hopkins.............................................................................................. 143 12,102 2.66 8.51 129.3 31.30

Pike .................................................................................................... 19 12,090 1.62 8.06 141.9 34.31

Union ................................................................................................. 60 12,568 2.69 6.98 125.8 31.63

Missouri Public Service Comm Sibley................................................ 985 11,097 2.63 9.29 133.7 29.68

Colorado................................................................................................ 9 10,964 1.21 4.07 141.0 30.92

Moffat ................................................................................................ 9 10,964 1.21 4.07 141.0 30.92

Illinois................................................................................................... 929 11,131 2.75 9.45 134.1 29.85

Franklin.............................................................................................. 148 11,759 2.15 8.23 107.7 25.33

Perry................................................................................................... 306 10,935 2.92 10.28 125.0 27.33

Randolph............................................................................................ 476 11,062 2.83 9.30 148.6 32.87

Saline ................................................................................................. * 11,875 2.60 7.50 106.0 25.17

Utah....................................................................................................... 27 11,606 .45 8.29 138.9 32.25

Carbon................................................................................................ 27 11,606 .45 8.29 138.9 32.25

Wyoming .............................................................................................. 19 8,763 .46 5.39 96.0 16.82

Campbell............................................................................................ 19 8,763 .46 5.39 96.0 16.82

New York State Gas & Elect Greenridge .......................................... 510 12,808 2.04 8.98 137.6 35.24

Pennsylvania ......................................................................................... 391 12,661 1.94 9.81 139.8 35.39

Armstrong .......................................................................................... 12 12,735 1.68 9.41 143.6 36.57

Clarion ............................................................................................... 84 12,717 2.07 8.75 134.9 34.31

Clearfield ........................................................................................... 130 12,128 1.94 13.09 144.3 35.01

Elk...................................................................................................... 4 11,993 2.27 13.63 143.2 34.34

Greene................................................................................................ 94 13,209 2.04 7.06 135.7 35.85

Jefferson............................................................................................. 16 12,997 1.90 8.95 145.8 37.90

Washington ........................................................................................ 50 12,845 1.63 8.30 141.4 36.32

West Virginia........................................................................................ 119 13,290 2.36 6.27 130.6 34.72

Monongalia ........................................................................................ 119 13,290 2.36 6.27 130.6 34.72

Niagara-Mohawk Power Corp Dunkirk............................................. 1,531 13,178 2.06 6.96 136.0 35.84

Pennsylvania ......................................................................................... 1,117 13,101 1.96 7.19 137.6 36.05

Armstrong .......................................................................................... 62 12,996 1.80 7.27 146.9 38.18

Clarion ............................................................................................... 302 12,686 2.06 8.59 143.6 36.44

Greene................................................................................................ 483 13,281 1.75 6.42 140.8 37.41

Indiana ............................................................................................... 39 13,260 2.37 7.11 134.1 35.56

Mercer................................................................................................ 71 13,143 2.46 7.08 129.3 33.98

Washington ........................................................................................ 160 13,323 2.10 6.87 117.9 31.42

West Virginia........................................................................................ 414 13,385 2.36 6.34 131.8 35.27

Marion................................................................................................ 16 13,550 2.65 7.19 139.0 37.67

Monongalia ........................................................................................ 398 13,379 2.35 6.31 131.5 35.18

Northern Indiana Pub Serv Co Michigan City ................................. 1,022 11,232 2.41 8.34 135.9 30.54

Illinois................................................................................................... 472 11,198 2.97 9.67 128.0 28.67

Perry................................................................................................... 366 10,987 3.07 10.31 135.3 29.72

Saline ................................................................................................. 106 11,929 2.61 7.46 104.9 25.02

Indiana .................................................................................................. 255 11,543 3.52 8.20 108.7 25.09

Pike .................................................................................................... 255 11,543 3.52 8.20 108.7 25.09

Virginia ................................................................................................. 20 13,835 .72 6.00 175.0 48.42

Buchanan ........................................................................................... 20 13,835 .72 6.00 175.0 48.42

Wyoming .............................................................................................. 276 10,815 .56 6.34 173.3 37.49

Campbell............................................................................................ 40 8,584 .30 4.70 100.2 17.21

Carbon................................................................................................ 235 11,199 .60 6.63 183.0 40.99

Ohio Edison Co Sammis....................................................................... 5,531 12,343 1.67 10.52 132.3 32.65

Kentucky............................................................................................... 668 12,091 .86 10.57 125.6 30.37

Floyd .................................................................................................. 157 11,955 .84 10.99 114.2 27.32

Lawrence............................................................................................ 72 11,889 .93 10.32 113.9 27.08

Martin ................................................................................................ 440 12,172 .86 10.47 131.5 32.00

Ohio ...................................................................................................... 1,452 12,147 2.65 10.78 124.0 30.14

Belmont.............................................................................................. 3 12,154 3.37 10.60 98.7 23.99

Carroll................................................................................................ 443 12,114 2.55 10.32 112.4 27.24

Harrison ............................................................................................. 399 12,343 3.37 10.82 106.2 26.22

Jefferson............................................................................................. 607 12,042 2.25 11.09 144.7 34.86

See footnotes at end of table.

Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 65 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Ohio Edison Co Sammis

Pennsylvania ......................................................................................... 1,707 12,532 1.80 10.36 141.6 35.49

Greene................................................................................................ 1,505 12,602 1.71 10.16 141.2 35.59

Washington ........................................................................................ 176 11,998 2.37 11.93 151.3 36.31

Westmoreland .................................................................................... 26 12,104 2.56 11.65 99.6 24.10

West Virginia........................................................................................ 1,703 12,418 1.04 10.42 132.3 32.85

Fayette................................................................................................ 47 12,679 .82 9.20 111.8 28.35

Kanawha ............................................................................................ 976 12,394 .75 10.44 132.8 32.93

Lincoln............................................................................................... 103 12,006 .81 10.72 113.7 27.31

Logan ................................................................................................. 14 12,124 .65 11.20 111.4 27.01

Mingo................................................................................................. 3 11,579 1.01 11.17 115.3 26.70

Monongalia ........................................................................................ 4 11,876 2.92 12.10 102.7 24.39

Nicholas............................................................................................. 79 12,102 .90 11.93 112.1 27.13

Preston ............................................................................................... 475 12,602 1.72 10.16 141.2 35.59

Ohio Power Co Kammer ...................................................................... 1,912 12,250 4.07 12.39 118.3 28.98

West Virginia........................................................................................ 1,912 12,250 4.07 12.39 118.3 28.98

Marshall ............................................................................................. 1,912 12,250 4.07 12.39 118.3 28.98

Ohio Power Co Mitchell ....................................................................... 1,999 12,190 1.45 14.14 166.3 40.55

West Virginia........................................................................................ 1,999 12,190 1.45 14.14 166.3 40.55

Boone................................................................................................. 14 12,361 .88 11.11 148.6 36.73

Clay.................................................................................................... 106 12,135 .81 12.68 144.9 35.16

Kanawha ............................................................................................ 40 12,185 .78 12.10 143.1 34.87

Marion................................................................................................ 1,674 12,183 1.54 14.35 170.7 41.59

Monongalia ........................................................................................ 165 12,283 1.18 13.69 143.2 35.18

Ohio Power Co Muskingum................................................................. 3,238 11,504 4.17 12.65 166.3 38.25

Kentucky............................................................................................... 14 12,191 .60 11.30 150.4 36.67

Floyd .................................................................................................. 11 12,183 .60 11.30 149.3 36.38

Magoffin ............................................................................................ 1 12,222 .61 11.30 155.0 37.89

Martin ................................................................................................ 1 12,222 .61 11.30 155.0 37.89

Ohio ...................................................................................................... 3,074 11,453 4.36 12.76 166.5 38.14

Muskingum........................................................................................ 338 11,453 4.36 12.76 166.5 38.14

Noble.................................................................................................. 2,736 11,453 4.36 12.76 166.5 38.14

West Virginia........................................................................................ 150 12,480 .64 10.39 163.5 40.81

Fayette................................................................................................ 13 12,376 .66 9.57 146.1 36.15

Kanawha ............................................................................................ 6 12,380 .66 9.54 146.3 36.22

Logan ................................................................................................. 131 12,495 .64 10.51 166.0 41.49

Ohio Valley Electric Corp Kyger Creek ............................................ 3,464 12,041 3.73 10.82 122.0 29.39

Kentucky............................................................................................... 125 13,128 1.50 6.19 122.2 32.09

Floyd .................................................................................................. 37 12,998 1.63 6.77 118.7 30.84

Letcher............................................................................................... 53 13,423 1.54 5.27 123.7 33.20

Pike .................................................................................................... 35 12,820 1.31 6.95 123.7 31.71

Ohio ...................................................................................................... 1,097 11,569 3.65 11.01 95.9 22.20

Belmont.............................................................................................. 230 12,551 4.23 9.38 89.9 22.57

Hocking.............................................................................................. 448 11,396 3.52 11.34 97.7 22.27

Jackson............................................................................................... 419 11,216 3.47 11.55 97.7 21.92

West Virginia........................................................................................ 2,242 12,211 3.90 10.99 134.1 32.76

Marshall ............................................................................................. 2,192 12,192 3.95 11.08 134.4 32.77

Mingo................................................................................................. 50 13,056 1.58 7.07 123.1 32.15

Pennsylvania Electric Co Shawville .................................................... 1,417 12,277 1.97 13.09 108.5 26.63

Pennsylvania ......................................................................................... 1,417 12,277 1.97 13.09 108.5 26.63

Cambria.............................................................................................. 4 12,299 2.18 14.70 104.7 25.75

Clearfield ........................................................................................... 1,401 12,278 1.97 13.09 108.5 26.64

Jefferson............................................................................................. 12 12,168 1.86 12.53 106.3 25.87

Pennsylvania Power & Light Co Brunner Island ............................. 3,471 12,718 1.83 11.46 186.9 47.53

Pennsylvania ......................................................................................... 3,471 12,718 1.83 11.46 186.9 47.53

Cambria.............................................................................................. 233 12,547 1.92 12.60 163.6 41.06

Clearfield ........................................................................................... 680 12,514 1.84 13.41 179.7 44.98

Greene................................................................................................ 920 13,303 1.72 7.15 144.7 38.51

Indiana ............................................................................................... 1,638 12,498 1.88 12.91 218.4 54.59

Pennsylvania Power & Light Co Martins Creek .............................. 603 12,954 1.91 9.80 186.5 48.32

See footnotes at end of table.

66 Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Pennsylvania Power & Light Co Martins Creek

Pennsylvania ......................................................................................... 603 12,954 1.91 9.80 186.5 48.32

Armstrong .......................................................................................... 10 12,569 2.28 11.60 138.4 34.79

Clarion ............................................................................................... 10 12,892 2.06 9.30 138.7 35.76

Clearfield ........................................................................................... 11 12,487 2.23 13.40 187.9 46.93

Greene................................................................................................ 244 13,312 1.75 7.02 149.6 39.82

Indiana ............................................................................................... 288 12,641 2.06 12.18 229.4 57.99

Jefferson............................................................................................. 20 13,201 1.58 9.80 136.6 36.07

Washington ........................................................................................ 20 13,320 1.61 6.75 145.5 38.77

Pennsylvania Power & Light Co Sunbury ......................................... 956 10,950 1.57 20.78 125.7 27.53

Pennsylvania ......................................................................................... 956 10,950 1.57 20.78 125.7 27.53

Armstrong .......................................................................................... 12 12,835 1.71 9.89 129.4 33.23

Bedford .............................................................................................. 9 9,490 1.17 32.07 81.6 15.49

Centre................................................................................................. 75 12,203 1.96 14.74 131.3 32.05

Clarion ............................................................................................... 14 12,758 2.15 9.16 134.0 34.19

Clearfield ........................................................................................... 454 12,154 1.98 15.05 145.0 35.26

Fulton................................................................................................. 13 12,556 2.38 12.76 135.9 34.12

Jefferson............................................................................................. 14 12,587 1.62 12.79 135.3 34.05

Lycoming........................................................................................... 9 12,612 1.35 14.18 134.7 33.98

Northumberland................................................................................. 81 8,091 .96 30.03 75.8 12.27

Schuylkill........................................................................................... 221 8,313 .63 34.74 78.4 13.03

Somerset ............................................................................................ 53 12,522 2.02 14.56 134.0 33.55

Sullivan .............................................................................................. 1 8,215 .61 37.00 71.0 11.67

Potomac Electric Power Co Chalk...................................................... 1,615 12,535 1.83 12.26 172.8 43.33

Maryland............................................................................................... 392 12,682 1.73 11.58 171.8 43.58

Garrett................................................................................................ 392 12,682 1.73 11.58 171.8 43.58

Pennsylvania ......................................................................................... 1,200 12,477 1.88 12.53 173.5 43.29

Cambria.............................................................................................. 417 12,345 1.97 12.67 174.3 43.05

Clearfield ........................................................................................... 400 12,445 1.90 12.24 176.8 44.01

Jefferson............................................................................................. 7 12,378 1.61 11.50 167.4 41.44

Somerset ............................................................................................ 375 12,659 1.75 12.71 169.2 42.84

West Virginia........................................................................................ 23 13,044 1.53 9.98 156.2 40.75

Grant .................................................................................................. 23 13,044 1.53 9.98 156.2 40.75

Potomac Electric Power Co Morgantown .......................................... 2,165 12,645 1.77 12.33 171.4 43.34

Maryland............................................................................................... 660 12,803 1.65 11.51 170.4 43.64

Garrett................................................................................................ 660 12,803 1.65 11.51 170.4 43.64

Pennsylvania ......................................................................................... 1,441 12,553 1.83 12.81 172.4 43.28

Cambria.............................................................................................. 466 12,482 1.88 12.62 175.7 43.85

Clearfield ........................................................................................... 433 12,504 1.86 12.87 177.3 44.33

Jefferson............................................................................................. 16 12,051 1.84 14.10 173.8 41.89

Somerset ............................................................................................ 511 12,670 1.76 13.00 165.5 41.93

Westmoreland .................................................................................... 14 12,697 1.99 8.80 166.1 42.18

West Virginia........................................................................................ 64 13,101 1.52 9.88 159.5 41.80

Grant .................................................................................................. 64 13,101 1.52 9.88 159.5 41.80

Public Service Co of IN Inc Cayuga ................................................... 2,863 10,942 2.01 9.93 123.9 27.12

Indiana .................................................................................................. 2,853 10,938 2.01 9.92 124.0 27.13

Clay.................................................................................................... 53 11,371 2.10 7.15 110.8 25.20

Daviess............................................................................................... 147 11,110 1.72 8.38 122.4 27.19

Greene................................................................................................ 122 11,124 2.15 9.41 121.0 26.91

Pike .................................................................................................... 312 11,143 2.18 9.22 117.7 26.24

Sullivan .............................................................................................. 1,982 10,891 1.99 10.18 127.5 27.77

Vermillion.......................................................................................... 227 10,749 2.09 10.62 108.2 23.27

Vigo ................................................................................................... 9 11,119 1.95 10.00 119.2 26.51

Kentucky............................................................................................... 9 12,022 2.41 10.00 101.9 24.50

Webster.............................................................................................. 9 12,022 2.41 10.00 101.9 24.50

Public Service Co of IN Inc Gallagher ............................................... 1,144 11,240 2.04 8.82 137.2 30.84

Illinois................................................................................................... 51 10,841 3.41 7.97 185.5 40.21

Clinton ............................................................................................... 51 10,841 3.41 7.97 185.5 40.21

Indiana .................................................................................................. 827 10,901 2.26 8.78 142.3 31.01

Warrick .............................................................................................. 827 10,901 2.26 8.78 142.3 31.01

See footnotes at end of table.

Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 67 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Public Service Co of IN Inc Gallagher

Kentucky............................................................................................... 120 11,907 1.49 9.48 114.9 27.37

Bell..................................................................................................... 28 12,502 1.53 9.44 106.5 26.62

Daviess............................................................................................... 27 10,766 2.27 10.29 109.9 23.66

Hopkins.............................................................................................. 5 11,469 2.25 9.50 112.0 25.69

Perry................................................................................................... 59 12,191 1.03 9.12 121.4 29.59

West Virginia........................................................................................ 146 12,744 .77 8.82 115.4 29.41

Kanawha ............................................................................................ 8 12,411 .70 13.06 119.4 29.64

Mingo................................................................................................. 139 12,763 .78 8.58 115.2 29.40

Public Service Co of IN Inc Gibson Station ...................................... 8,297 11,106 2.01 10.14 157.2 34.91

Illinois................................................................................................... 6,082 10,761 2.45 10.47 169.2 36.41

Clinton ............................................................................................... 3,031 10,822 3.46 8.10 171.5 37.13

Jefferson............................................................................................. 91 12,206 .81 4.89 119.9 29.26

Wabash .............................................................................................. 2,960 10,655 1.46 13.07 168.4 35.89

Indiana .................................................................................................. 862 11,435 .96 7.12 116.3 26.59

Clay.................................................................................................... 145 11,618 .63 6.44 128.5 29.85

Daviess............................................................................................... 476 11,535 .84 6.54 114.5 26.42

Dubois................................................................................................ 6 11,381 1.00 8.30 102.3 23.29

Perry................................................................................................... 51 11,243 .89 7.94 118.2 26.59

Pike .................................................................................................... 53 11,503 3.51 7.90 89.4 20.57

Sullivan .............................................................................................. 130 10,912 .72 9.29 119.8 26.14

Kentucky............................................................................................... 217 12,219 .80 11.06 123.5 30.18

Floyd .................................................................................................. 134 12,211 .82 11.41 123.9 30.26

Martin ................................................................................................ 25 12,568 .77 7.74 125.0 31.42

Perry................................................................................................... 58 12,090 .77 11.66 121.9 29.48

West Virginia........................................................................................ 1,136 12,489 .73 10.49 136.5 34.09

Boone................................................................................................. 202 12,434 .73 11.15 130.1 32.35

Kanawha ............................................................................................ 377 12,357 .72 12.27 135.9 33.60

Mingo................................................................................................. 434 12,766 .74 8.27 141.3 36.06

Wayne ................................................................................................ 123 12,013 .75 11.79 130.9 31.46

Public Service Co of IN Inc Wabash River ....................................... 1,430 11,036 2.00 9.33 117.2 25.87

Indiana .................................................................................................. 1,430 11,036 2.00 9.33 117.2 25.87

Clay.................................................................................................... 35 11,354 2.08 6.92 107.7 24.46

Daviess............................................................................................... 389 11,136 2.03 8.98 107.0 23.82

Greene................................................................................................ 169 11,312 2.04 8.00 112.4 25.42

Sullivan .............................................................................................. 838 10,921 1.98 9.87 123.5 26.97

 b Southern Indiana Gas & Elec Co Warrick........................................ 475 11,132 2.47 8.64 115.1 25.63

Indiana .................................................................................................. 422 11,109 2.45 8.75 116.7 25.92

Gibson................................................................................................ 22 11,077 2.47 10.10 94.3 20.90

Pike .................................................................................................... 85 11,451 2.61 8.36 101.9 23.33

Warrick .............................................................................................. 315 11,019 2.41 8.77 122.4 26.97

Kentucky............................................................................................... 53 11,315 2.60 7.71 103.2 23.35

Henderson .......................................................................................... 53 11,315 2.60 7.71 103.2 23.35

Springfield City of (MO) James River ............................................... 271 11,599 1.74 7.92 134.4 31.18

Illinois................................................................................................... 230 11,574 1.98 7.91 132.9 30.77

Franklin.............................................................................................. 230 11,574 1.98 7.91 132.9 30.77

Utah....................................................................................................... 41 11,737 .40 8.00 142.5 33.44

Carbon................................................................................................ 41 11,737 .40 8.00 142.5 33.44

Tampa Electric Co Davant Transfer .................................................. 5,528 12,255 2.30 8.09 182.4 44.70

Colorado................................................................................................ 181 13,092 .45 10.01 146.5 38.37

Las Animas........................................................................................ 181 13,092 .45 10.01 146.5 38.37

Illinois................................................................................................... 1,224 11,287 2.87 8.89 181.0 40.86

Franklin.............................................................................................. 48 12,213 1.04 5.07 156.0 38.11

Gallatin .............................................................................................. 126 12,727 2.79 8.73 110.3 28.08

Perry................................................................................................... 1,018 11,076 2.96 9.08 194.6 43.11

Randolph............................................................................................ 33 10,945 2.92 9.10 108.9 23.84

Kentucky............................................................................................... 3,359 12,415 2.30 7.91 178.7 44.37

Bell..................................................................................................... 51 12,909 .62 8.43 167.1 43.14

Daviess............................................................................................... 90 11,629 2.82 9.47 115.4 26.83

Hopkins.............................................................................................. 104 11,973 3.05 10.25 111.2 26.63

Knott .................................................................................................. 19 12,923 .64 8.15 167.1 43.19

Knox .................................................................................................. 7 12,967 .57 8.80 167.1 43.34

See footnotes at end of table.

68 Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Tampa Electric Co Davant Transfer

Kentucky

Muhlenberg........................................................................................ 488 11,767 2.75 8.51 115.1 27.09

Union ................................................................................................. 1,056 12,282 2.84 8.63 171.0 41.99

Webster.............................................................................................. 516 12,599 2.86 8.17 164.8 41.53

Whitley .............................................................................................. 1,029 12,842 1.27 6.36 232.9 59.83

Tennessee.............................................................................................. 269 12,861 1.19 6.20 217.6 55.98

Campbell............................................................................................ 269 12,861 1.19 6.20 217.6 55.98

Utah....................................................................................................... 32 11,596 .39 8.20 163.8 37.99

Carbon................................................................................................ 32 11,596 .39 8.20 163.8 37.99

West Virginia........................................................................................ 452 13,137 2.38 7.64 207.1 54.41

Monongalia ........................................................................................ 452 13,137 2.38 7.64 207.1 54.41

Wyoming .............................................................................................. 12 8,887 .20 4.70 142.3 25.29

Campbell............................................................................................ 12 8,887 .20 4.70 142.3 25.29

Tennessee Valley Authority Colbert ................................................... 2,742 11,970 1.32 10.93 129.6 31.01

Illinois................................................................................................... 850 11,577 1.88 9.26 123.7 28.65

Franklin.............................................................................................. 850 11,577 1.88 9.26 123.7 28.65

Kentucky............................................................................................... 583 12,108 1.48 10.72 124.6 30.18

Breathitt ............................................................................................. 80 12,150 1.30 12.10 119.4 29.00

Daviess............................................................................................... 44 12,200 1.04 12.50 122.5 29.89

Floyd .................................................................................................. 47 12,200 1.26 12.50 123.8 30.21

Johnson .............................................................................................. 324 12,102 1.40 9.26 131.1 31.74

Webster.............................................................................................. 88 12,000 2.30 13.00 106.9 25.65

Tennessee.............................................................................................. 363 12,377 .79 12.53 127.3 31.52

Sequatchie.......................................................................................... 363 12,377 .79 12.53 127.3 31.52

West Virginia........................................................................................ 945 12,081 .93 11.94 138.5 33.46

Boone................................................................................................. 50 12,287 .70 13.95 118.1 29.03

Kanawha ............................................................................................ 666 12,040 .94 12.34 140.8 33.91

Lincoln............................................................................................... 26 12,000 .70 11.00 129.4 31.05

Mingo................................................................................................. 204 12,174 .97 10.24 137.0 33.36

Tennessee Valley Authority Johnsonville ........................................... 2,326 11,992 1.75 9.12 130.8 31.37

Illinois................................................................................................... 1,203 11,681 1.71 8.99 132.9 31.06

Franklin.............................................................................................. 1,062 11,672 1.72 9.01 133.9 31.26

Jefferson............................................................................................. 29 11,700 1.70 8.50 120.0 28.08

Kentucky............................................................................................... 1,123 12,325 1.79 9.24 128.6 31.71

Webster.............................................................................................. 1,123 12,325 1.79 9.24 128.6 31.71

Tennessee Valley Authority Shawnee ................................................. 2,503 12,089 1.30 10.39 129.4 31.28

Kentucky............................................................................................... 1,775 12,017 1.54 9.90 129.7 31.16

Clay.................................................................................................... 13 12,000 .72 14.00 119.7 28.73

Floyd .................................................................................................. 10 12,100 .74 12.00 130.6 31.61

Hopkins.............................................................................................. 327 11,479 3.67 11.56 120.3 27.61

Johnson .............................................................................................. 48 11,300 .70 12.10 115.1 26.02

Magoffin ............................................................................................ 107 12,000 .71 12.11 118.9 28.53

Muhlenberg........................................................................................ 272 11,613 2.52 9.40 123.8 28.75

Perry................................................................................................... 18 12,296 .74 10.96 147.2 36.21

Pike .................................................................................................... 966 12,331 .70 9.08 135.7 33.46

Webster.............................................................................................. 14 13,000 2.25 7.00 138.2 35.94

Tennessee.............................................................................................. 13 12,500 .76 12.10 128.0 32.00

Sequatchie.......................................................................................... 13 12,500 .76 12.10 128.0 32.00

West Virginia........................................................................................ 715 12,260 .73 11.57 128.7 31.56

Boone................................................................................................. 347 12,314 .72 11.35 129.5 31.89

Kanawha ............................................................................................ 128 12,209 .76 13.00 125.4 30.62

Logan ................................................................................................. 142 12,240 .72 11.36 129.4 31.68

Mingo................................................................................................. 79 12,203 .71 10.73 130.6 31.87

Wayne ................................................................................................ 20 12,000 .74 11.00 124.0 29.76

Union Electric Co Labadie ................................................................... 5,468 10,151 1.55 7.50 116.0 23.54

Colorado................................................................................................ 487 11,750 .47 9.60 161.0 37.84

Gunnison............................................................................................ 487 11,750 .47 9.60 161.0 37.84

Illinois................................................................................................... 2,480 11,202 3.09 10.09 128.6 28.82

Jefferson............................................................................................. 9 11,800 1.30 7.30 214.2 50.55

Perry................................................................................................... 2,471 11,200 3.10 10.10 128.3 28.74

See footnotes at end of table.

Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 69 
Table A2. Profile of Coal Received at Plants Planning to Fuel Switch and/or Blend to Meet

Compliance with Phase I, 1992 (Continued)

Average Quality Average Delivered Cost

 a Operating Utility Plant Receipts Sulfur Ash (cents (dollars Origin State (thousand Btu (percent (percent per per County short tons) (per by by million short pound) weight) weight) Btu) ton)

Union Electric Co Labadie

Wyoming .............................................................................................. 2,501 8,798 0.22 4.52 88.3 15.53

Campbell............................................................................................ 2,501 8,798 .22 4.52 88.3 15.53

Union Electric Co Sioux ....................................................................... 1,845 11,317 2.39 8.22 174.8 39.56

Illinois................................................................................................... 1,714 11,521 2.54 8.41 178.9 41.23

Perry................................................................................................... 483 11,321 2.89 9.47 155.3 35.17

Saline ................................................................................................. 1,231 11,600 2.40 8.00 188.0 43.61

Wyoming .............................................................................................. 131 8,650 .52 5.70 102.0 17.65

Campbell............................................................................................ 131 8,650 .52 5.70 102.0 17.65

Total .................................................................................................... 133,245 11,739 2.22 10.02 148.4 34.84

* = Number less than 0.5. a The list of plants planning to fuel switch and/or blend is based upon information obtained late 1993. b Based on information received in late 1993, the Warrick plant intended to use fuel switching as their method of compliance. Southern Indiana Gas

and Electric, which owns 50 percent of the Warrick plant, has since decided to use allowances to meet compliance. Alcoa, which owns the other 50

percent appears to have not yet finalized their compliance strategy.

Notes: • Totals may not equal sum of components because of independent rounding.

Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’

70 Energy Information Administration/Electric Utility Phase I Acid Rain Compliance Strategies 
Appendix B

Engineering

Characteristics of

Retrofitted Flue Gas

Desulfurization Units
Appendix B

Engineering Characteristics of Retrofitted

Flue Gas Desulfurization Units

The control of sulfur dioxide (SO2) emissions resulting

from burning coal can be accomplished in several different ways. Precombustion methods, which remove

sulfur from coal before it is burned, include froth

flotation, electrostatic precipitation, and magnetic

separation. These methods rely on the difference between the physical characteristics of the coal and the

sulfur compounds in the coal, including surface

properties and susceptibility to magnetic or electric

fields. Sulfur reduction can also be achieved during

combustion, through the addition of chemical agents

into the combustion chamber. However, the approach

most commonly used for electric utility coal-fired

power plants is a postcombustion method, flue gas

desulfurization (scrubber) technology.91

In order to comply with clean air regulations and clean

up their emissions, many utilities have installed

scrubbers on their coal-burning plants. One or more

scrubbers are placed in the plant so that flue gas exiting

the boiler unit(s) passes through the scrubber(s). The

flue gas undergoes a chemical reaction inside the scrubber which absorbs or “scrubs” the sulfur and sulfur

compounds out of it. Once scrubbed, the gas is emitted

into the atmosphere.

Scrubber systems differ widely throughout the industry.

The scrubbing agent, or sorbent, which is responsible

for the sulfur absorption, can vary and the structure by

which the flue gas and sorbent are brought together in

the reactor vessel varies. This appendix describes some

of the more popular sorbents and reactor vessel types

for scrubbers for coal-fired plants, as well as the characteristics of the scrubbers used to estimate historical

retrofit scrubber costs in Appendix C.

Scrubber Sorbent Types

Any chemical reagent which, through a chemical process, can absorb SO2 is a potential sorbent in a scrubber.

Different sorbents vary by how the scrubber process is

actuated, by their physical properties, and by the waste

products that are left behind. Sorbents are used in a wet

solution form or in a dry solid form in the scrubber.

Nonregenerable sorbent systems produce wastes which

must be disposed of in a landfill or in some other manner. Regenerable sorbents absorb SO2 in the scrubber

and then are subjected to other chemical processes

which likewise absorb the sulfur products out of the

sorbent, returning the sorbent to its original state, able

to again absorb SO2 in the scrubber. The list of sorbents

presented here is by no means complete. These are

some of the most predominant, which appear as classifications on the Energy Information Administration

Form EIA-767, “Steam-Electric Plant Operation and

Design Report.”

Of all sorbents, lime and limestone are the most popular.92 They are used predominantly in nonregenerable

processes. The chemical process employed involves the

reaction of SO2 with calcium carbonate (CaCO3) present

in the lime or limestone to produce calcium sulphite

(CaSO3) along with carbon dioxide (CO2) and water

(H2O). Some of the calcium sulphite oxidizes to become

calcium sulphate (CaSO4), commonly known as gypsum. If the scrubber system is designed correctly,

industrial-quality gypsum can be produced and sold. A

common industrial use for gypsum is the production of

wallboard. One reason for the popularity of lime and

limestone systems is the relative inexpensiveness of

these sorbents over other types.

91Steven C. Stultz and John B. Kitto, eds., Steam, Its Generation and Use, 40th ed. (Barberton, OH: Babcock and Wilcox Co., 1992), p. 35-1. 92Steven C. Stultz and John B. Kitto, eds., Steam, Its Generation and Use, 40th ed. (Barberton, OH: Babcock and Wilcox Co., 1992), p. 35-2.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 73
Limestone, one of the most popular sorbents for scrubbers, is usually piped into the absorber module in the form of a slurry

(right). Conemaugh uses limestone and stores gypsum, which is released as a by-product, in a nearby storage facility (left).

It is possible to sell the gypsum for industrial use.

Sodium carbonate (Na2CO3), another nonregenerable

sorbent, can be reacted with SO2 to produce sodium

sulphite (Na2SO3) and sodium hydrosulphite (NaHSO3).

It is fairly expensive but is easier to implement in the

scrubber design due to the fact that all the reactants

and products of the reaction stay in solution. The lime

systems described above must use slurries (suspensions

of solids in water), which tend to scale onto equipment

surfaces, clogging valves and openings.

A solution of sodium sulphite can be used as a sorbent,

and then treated in a lime or limestone process and

used again. Although the sodium sulphite is reused, the

lime or limestone is not, and therefore this process is

still considered nonregenerable. This process has the

advantage that the SO2 has a greater affinity for the

sorbent. However, sodium sulphite is expensive.

Magnesium hydroxide (Mg(OH)2) is a very expensive

but regenerable sorbent. The magnesium oxide reacts

with SO2 to produce magnesium sulphite (MgSO3) and

water. The magnesium sulphite is then oxidized to

release the SO2 in a relatively pure state which can be

utilized in the production of sulfuric acid or sulfur. The

magnesium oxide resulting from the oxidation is

recycled to the scrubber.

Reaction Vessel Types

Flue gas and sorbents are mixed in different types of

reactor vessels. Reactor vessels are mass transfer

mechanisms. For wet scrubbers, it is known that the

type of absorption reactions occurring in scrubber

systems between a liquid and gas occur at the surface

of the liquid. For dry scrubbers, the reaction once again

occurs at the surface of the sorbent, but the difference

lies in the fact that a solid does not mix or diffuse like

a fluid. This lack of diffusion implies that a solid

particle of sorbent cannot absorb anymore once the

surface has been saturated from the flue gas stream. A

fluid particle, however, can replace surface sorbent with

fresh sorbent from the interior of the particle and

continue to absorb. In both cases, due to the surface

nature of the reaction, there are two things that must be

maximized for optimum absorption to occur: (1) the

surface area of the sorbent exposed to the flue gas must

be maximized, and (2) the sorbent must be renewed

quickly to allow further absorption. The following

reaction vessel arrangements tend to concentrate on one

or both of these criteria to maximize absorption

capability.

A packed column reactor vessel arrangement seeks to

maximize the surface area criterion. A vertical tower is

usually packed randomly with sorbent particles. The

sorbent is sprayed down from the top of the column

where it covers the packing particles, giving a large

surface area. The flue gas enters the column at the

bottom and rises up through the sorbent coated

packing, allowing the absorption to occur (Figure B1).

A tray column contains a tray with small perforations.

The sorbent liquid flows continuously across this tray,

thereby allowing the sorbent to be renewed quickly.

The flue gas enters at the bottom of the column and

rises up to the tray, where it bubbles through the

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

74 Clean Air Act Amendments of 1990
Scrubbed Flue Gas Exit

Sorbent Mixture

In-Flow

Reactor Vessel Wall

Flue Gas Entrance Sorbent Mixture

Out-Flow

Random Packing

Figure B1. Packed-Type Scrubber

Source: Energy Information Administration, Office of Coal,

Nuclear, Electric and Alternate Fuels.

Scrubbed Flue Gas Exit

Sorbent Mixture

In-Flow

Reactor Vessel Wall

Flue Gas Entrance

Sorbent Mixture

Out-Flow

Perforated Tray

Figure B2. Tray-Type Scrubber

Source: Energy Information Administration, Office of Coal,

Nuclear, Electric and Alternate Fuels.

perforations, gaining contact with the sorbent. This

arrangement maximizes the renewal of the liquid

surface since the sorbent flows continuously over the

contact tray (Figure B2).

Spray towers are basically packed columns without any

packing. The sorbent is sprayed down from the top of

the column in fine droplets, giving a large surface area.

The flue gas, having been introduced at the bottom,

rises up through this spray where it reacts (Figure B3).

In a venturi arrangement, the liquid sorbent is injected

into the flue gas just upstream of a constriction in the

flue pipe Figure B4). In the constriction, conservation

Scrubbed Flue Gas Exit

Sorbent Mixture

In-Flow

Reactor Vessel Wall

Flue Gas Entrance Sorbent Mixture

Out-Flow

Falling Sorbent Spray

Sprayers

Figure B3. Spray-Type Scrubber

Source: Energy Information Administration, Office of Coal,

Nuclear, Electric and Alternate Fuels.

Sorbent Mixture

In-Flow Flue Pipe Constriction

Flue Gas Entrance

Reactor Vessel Wall

Scrubbed Flue Gas Exit

Sorbent Mixture

Out-Flow

Figure B4. Venturi-Type Scrubber

Source: Energy Information Administration, Office of Coal,

Nuclear, Electric and Alternate Fuels.

of mass requires that the velocity of the flue

gas/sorbent mixture increase, thereby increasing the

amount of mixing. Venturi scrubbers have also been

shown to be efficient for particulate removal. The

previously described systems usually will require some

particle collector upstream of the unit (baghouses or

electrostatic precipitators are common). Venturis require

a higher energy input due to the constriction in the

flue, however, and therefore are more costly to operate.

One example of a purely dry scrubbing process is the

spray dryer scrubber system. Spray dryers are

essentially the same as spray towers, except that sorbent

is sprayed into the reactor vessel in a fine enough mist

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 75
that water in the sorbent mix is evaporated by the hot

flue gas at the same time that sulfur dioxide is absorbed

from the flue gas. What is left is a dry powder which

leaves the vessel with the exiting flue gas. To capture

this dry waste, particulate collectors such as baghouses

or electrostatic precipitators must be present downstream from the scrubber unit.

All of the above systems rely on natural processes for

the mixing and absorption of the flue gas contaminants

by the sorbent. Some systems use mechanical devices to

enhance the mixing or absorption process, in order to

optimize its effectiveness. These are the so-called

“mechanically aided” scrubber systems.

There are of course systems which are hybrids of those

mentioned above. Form EIA-767, “Steam-Electric Plant

Operation and Design Report” allows scrubbers to be

classified with up to four of the above types.

Characteristics of Retrofitted

Scrubbers in Sample

Data from a sample of retrofit scrubbers were

assembled for this report from the Form EIA-767,

“Steam-Electric Plant Operation and Design Report”

database. The sample includes some information on 32

retrofit scrubbers.93 It includes all utility retrofit

scrubbers on plants of 100 or more megawatts operating

between 1985 and 1991. The sample includes data

reported for each of these years; however, information

is not available for all plants for all years.

The number of sample retrofit scrubbers installed in

each State varies from one to seven (Table B1). The

retrofit scrubbers are located in western as well as

eastern States. The geographic distribution of the

retrofit scrubbers in the sample (eastern and midwestern States) is different from the distribution of

retrofits that will result from Phase I. This is a limiting

factor in comparing the sample retrofits with those from

Phase I.

The scrubbers in the sample were placed into service

from 1972 through 1990, with many coming on-line in

Table B1. Number of Retrofit Scrubbers in Sample

by State

State Number

Alabama ..................... 2

Arizona ...................... 1

Colorado ..................... 1

Kentucky ..................... 7

Nevada ...................... 2

New Mexico ................... 7

Pennsylvania .................. 7

Wyoming ..................... 5

Total ....................... 32

Source: Database created from Form EIA-767, “Steam-Electric

Plant Operation and Design Report” (1992) by Decision Analysis

Corporation for the Energy Information Administration under contract

#DE-AC01-92E121946.

1972 1974 1976 1978 1980 1982 1984 1986 1988 1990

0

1

2

3

4

5

6

Number

Year In-Service

Figure B5. Number of Retrofit Scrubbers in

Sample by Year In-Service, 1972-1990

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1991).

the 5-year period from 1978 through 1982 (Figure B5).

Another limitation for comparing the sample scrubbers

and the Phase I scrubbers to be installed is the fact that

all but three of the scrubbers in the sample went into

service before 1988, and scrubber designs have evolved

since then.

93The definition of a retrofit scrubber used here is one that went into service at least 1 year after its related boilers went into service.

The number of units in the sample changed by year, depending on when they came into service and whether data were missing for a

unit. For 1985, there were 26 units, while for 1991 this number was 30. For a more extensive discussion of the sample, see Decision

Analysis Corporation of Virginia, “Analysis of Retrofit Flue Gas Desulfurization Unit Data,” report to the Energy Information

Administration (Vienna, VA, May 28, 1993). The data and analysis regarding the sample of retrofit flue gas desulfurization units discussed

here are drawn from that report.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

76 Clean Air Act Amendments of 1990
The 32 units in the sample mostly use spray or tray

configurations for their reactor vessels. The spray-type

scrubber was the most popular design in operation for

this sample of units, but the tray and spray dryer

designs were the only types that increased between

1985 and 1991 (Figure B6). Spray scrubbers are

relatively easy to design as compared to the other

configurations, and this fact may account for their

earlier popularity.

0

2

4

6

8

10

12

14

Number

1985

1991

Spray

Packed Dryer

Venturi

Spray

Tray

Technology

Figure B6. Number of Scrubbers by Type of

Technology, 1985 and 1991

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1985 and

1991).

Lime and limestone are the most common sorbent types

for the sample (Figure B7). Their lower cost makes them

attractive to utilities. The two scrubbers that were

added from 1985 through 1991 used limestone as a

sorbent. Limestone is easier to handle than lime. Lime

must be safeguarded from moisture at all times, while

limestone does not require such precautions. Such

precautions increase the cost of lime systems, since

extra waterproof structures must be erected for

shipping and storage of the sorbent. Thus, although

lime can be a more efficient SO2 sorbent, limestone

scrubbers have become almost as predominant as lime.

Engineering Performance of

Scrubber Systems

Several key factors must be assessed to evaluate the

engineering performance of an scrubber system in

terms of its ability to meet SO2 emission standards. One

of the most important is the design SO2 removal

0

2

4

6

8

10

Number

1985 1991

Lime

Limestone

Magnesium

Oxide

Sodium

Carbonate

Soda

Liquor

Other

Sorbent

Figure B7. Number of Scrubbers by Type of

Sorbent, 1985 and 1991

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1985 and

1991).

efficiency rate for the scrubber. The design removal

efficiency for a scrubber is the percentage of SO2

present in the flue gas which will be absorbed by the

unit as estimated by the designing engineers before the

scrubber is actually built. The engineers consider the

scrubber design as well as plant and fuel characteristics

to obtain this quantity. The weighted average design

removal efficiency for this sample of units was never

below 80 percent for any one year (Figure B8).

The actual removal efficiency is a measurement taken

after the scrubber is in operation. The weighted average

of the actual removal efficiency was less than the

design removal efficiency in every year except 1986.

Another important factor in the evaluation of a scrubber

is its reliability. A unit which consistently breaks down

or requires large amounts of downtime for maintenance

will not be effective in reducing plant emissions. The

scrubber availability is the percentage of the whole year

that the scrubber was operational. Weighted average

scrubber availability increased 13 percentage points

between 1985 and 1991 (Figure B9).

Scrubber systems may consist of several reactor vessels.

Each of the vessels, called modules, can be operated

independently. Modular scrubber design helps increase

the availability and operability of scrubbers, since any

one module which is forced off-line due to failure or

required maintenance can be replaced by another

module. Because older scrubbers, when engineers had

less experience with them, are less reliable, they often

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 77
1985 1986 1987 1988 1989 1990 1991

60

65

70

75

80

85

90

Percent

Design Removal Efficiency

Removal Efficiency

Actual

0

Figure B8. Weighted Average Design Removal

Efficiency and Weighted Average Actual

Removal Efficiency by Year, 1985-1991

Notes: •Removal Efficiency is the percentage of flue gas S02

removed by the scrubber unit. •Design Removal Efficiency is

specified by the engineers who designed the scrubber unit.

•Actual Removal Efficiency is measured at the plant when the

scrubber unit is operating.

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1985-

1991).

contain a “spare” module to substitute for nonoperating modules. In contrast, newer scrubbers may be

larger, requiring more modules, but the modules may

be larger. The average number of modules in the

sample of scrubbers increased overall for those units

with in-service dates from 1971 through 1986. However,

there has been some decrease in the average number of

modules for units put in service after 1987 (Figure B10).

A predominant cost in the operation of a scrubber is the

amount of sorbent it consumes. The average physical

quantity of sorbent used increased from 1985 through

1991 (Figure B11), partially because of the switch from

earlier lime scrubber designs to limestone scrubber

systems. Limestone absorbs less sulfur per pound than

lime, so more of it is needed to absorb the same

amount of sulfur. In addition, the electricity output per

unit and the amount of sulfur in the coal may have

increased.

Finally, the operation of a scrubber requires electricity

to run scrubber equipment. Usually the electricity is

supplied by the power plant using the scrubber. This

decreases the electricity output of the plant, by reducing

the amount of electricity produced for sale from the

same quantity of inputs. The weighted average elec1985 1986 1987 1988 1989 1990 1991

50

60

70

80

Percent

0

Figure B9. Weighted Average Availability of

Scrubbers by Year, 1985-1991

Note: Availability is the number of hours the scrubber was

operational during the year expressed as a percentage of the

total number of hours in a year.

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1985-

1991).

1971-1974 1975-1978 1979-1982 1983-1986 1987-1990

0

1

2

3

4

5

Number of Modules

Number

Number of Modules

at 100 Percent Load

Year In-Service

Figure B10. Average Number of Modules and

Average Number of Modules Used at

100 Percent Load by Year In-Service,

1971-1990

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1991).

tricity consumption of these scrubbers as a percentage

of plant generation shows that scrubbers require a small

percentage of a unit’s electricity production, and that

weighted averages have varied between 1.8 percent and

4.3 percent (Figure B12).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

78 Clean Air Act Amendments of 1990
1985 1986 1987 1988 1989 1990 1991

20

25

30

35

40

Short Tons

0

Figure B11. Average Amount of Sorbent Used by

Year, 1985-1991

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1985-

1991).

Flue gas desulfurization is accomplished by many different methods and practices. As the electric utility

industry becomes more experienced with scrubber proPercent

1985 1986 1987 1988 1989 1990 1991

0

1

2

3

4

5

Figure B12. Weighted Average Percent of Plant

Generation Used by Retrofit Scrubbers,

1985-1991

Source: Energy Information Administration, Form EIA-767,

“Steam-Electric Plant Operation and Design Report” (1985-

1991).

cesses and systems, scrubbers are expected to become

more reliable and less expensive.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 79
Appendix C

Econometric Estimates

of Scrubber Retrofit

Costs Based on

Historical Costs
Appendix C

Econometric Estimates of Scrubber

Retrofit Costs Based on Historical Costs

Econometric analyses of the cost of scrubber retrofits

was performed on a subset of all utility retrofit

scrubbers for which data were available. The purpose

of this analysis was to examine the effects of a number

of variables on the cost and performance of the retrofitted units. In this analysis, scrubbers are classified as

retrofits if they were installed at least 1 year after the

installation of the boiler. The data base of scrubber

retrofits analyzed here included 32 units located in 8

States. Cost data were obtained from Form EIA-767,

“Steam-Electric Plant Operation and Design Report.”

Most units are located in the western or eastern United

States (Table B1), where utilities, particularly in the

Four Corners area,94 chose scrubbers to meet strict

Prevention of Significant Deterioration air quality

regulations imposed by the States.

The location of a scrubber has an impact on many

aspects of the retrofit decision, which is affected by the

proximity to coal markets, the accessibility of water,

land availability for waste pond storage, regional

material and labor costs, and the State/regional regulatory environment.

Two different variables were estimated using econometric techniques: capital costs and operation and

maintenance costs. In both cases, the ordinary least

squares estimator was used to fit a linear model for

each variable.95 At least two important problems were

encountered in the statistical analysis. One was that

heteroskedasticity, when the disturbance term does not

have uniform variance, was present. Heteroskedasticity

has several consequences when using an ordinary

least squares (OLS) estimator.

OLS is not the most efficient estimator, because it is not

the estimator with the minimum variance; the variance

of the parameter estimates is biased, so internal

estimation and hypothesis testing are not dependable;

and OLS is not the maximum likelihood estimator, so

that the probability of obtaining the observed data is

not maximized. However, the method to correct for this

problem, using a generalized least squares estimator, is

difficult to implement. For the scrubber models,

attempts to correct for heteroskedasticity resulted in

models of worse quality. Fortuitously, the OLS parameter estimates are unbiased even in the presence of

heteroskedasticity and produce the highest coefficient

of determination (R2

). Thus, the OLS parameter estimates have been accepted for this analysis.

The other data problem lies with some uncertainty

regarding the definition of capital costs by respondents

to the Energy Information Administration (EIA) Form

EIA-767. The Accounting and Reporting Requirements for

Public Utilities and Licensees require that overhead costs

be included in reported capital costs.96 Overhead

includes such costs as engineering, supervision, general

office salaries and expenses, insurance, and taxes. The

requirement to include overhead cost does not apply

specifically to the Form EIA-767; it applies directly to

the bookkeeping and accounting practices of utilities

regulated by the Federal Energy Regulatory Commission (FERC). Form EIA-767 instructions do not specify

that the FERC regulations, called the Uniform System

of Accounts, apply to the information reported there,

and the instructions do not mention overhead costs. In

addition, some utilities submitting information on the

Form EIA-767 are not under the FERC’s jurisdiction and

thus are not bound by the Uniform System of Accounts.

In an informal survey of five respondents to the Form

EIA-767, at least one respondent was not able to

confirm that overhead was included in capital costs.

Overhead may be a substantial part of total capital

94Meeting point of Utah, Colorado, New Mexico, and Arizona.

95More detail regarding the econometric methods are available in the Decision Analysis Corporation of Virginia, “Regression Models

for Analysis of Retrofit Flue Gas Desulfurization Unit Cost and Performance,” a report prepared for the Energy Information

Administration (Vienna, VA, May 28, 1993). 96Federal Energy Regulatory Commission, FERC-0114 (Washington, DC, January 17, 1989), ¶15,054.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 83
costs. The engineering estimates used here (Appendix

D) estimate that they are 21 percent of capital costs.97

Thus the statistical estimates probably understate the

capital cost of scrubbers.

Costs

Historical cost data were separated into operation and

maintenance (O&M) costs and installed capital costs.

Two models (equations) were developed to show the

effects of a number of scrubber characteristics on the

cost of the scrubbers. One of these models—the O&M

cost model—employed time series/cross-sectional

estimation procedures, incorporating both across-unit

(cross-sectional) and serial within-unit (time-series)

explanatory effects to estimate the dependent variable.

For installed capital costs, which do not vary over time

for individual units, one observation was used for each

scrubber.

Installed Capital Costs

The installed capital cost model included engineering

design and retrofit unit size variables. As with the

O&M cost model, the engineering design variables

served as cost parameter indicators. The major

explanatory factor for installed capital costs was the

size of the retrofit scrubber, which can be represented

by scale variables such as the boiler firing rate, the

generator nameplate capacity, annual coal consumption,

and the number of absorber modules. Technologyspecific factors that influence capital costs, include the

design operating efficiency, the type of absorber

module technology selected, and installation complex as

indicated by design requirements associated with the

existing boiler/generator/stack configuration.

The dependent variable, installed capital costs per

kilowatt, was estimated with the standard crosssectional ordinary least squares procedure. This

dependent variable is expressed on a per-unit basis.

Since capital costs for each unit can be incurred at

different times, the costs were converted to real dollars

with the use of the Gross Domestic Product Implicit

Price Deflator.

The capital cost model was specified as follows:

where

CAPKW = β0 β1FGDMOD β2MAXMW

β3BGYEAR β4SULFDEFF

β5TYPE2 ε ,

CAPKW = installed capital costs per kilowatt of

nameplate electric capacity,

expressed in real dollars,

FGDMOD = number of absorber modules,

MAXMW = generator nameplate capacity in

megawatts,

BGYEAR = boiler in-service year,

SULFDEFF = percentage design sulfur removal

efficiency,

TYPE2 = absorber technology-type dummy

variable (takes on a value of 1 if

technology is a tray type, and 0 if

otherwise),

ε = error.

The model provided the following results:

• For each absorber module added to the scrubber

system, the mean value of the installed capital cost

increases by $164 per kilowatt (1992 dollars) with

all other influences held constant (Table C1).

• For each 1-megawatt increase in the generator

nameplate capacity, the mean value of the installed capital cost decreases by $1.11 per kilowatt

with all other influences held constant.

• For each incremental boiler in-service year, the

mean value of installed capital cost increases by

$5.2 per kilowatt with all other influences held

constant.

• For each percentage-point increase in the design

sulfur removal efficiency, the mean value of the

installed capital cost increases by $3.0 per kilowatt

with all other influences held constant.

• Selecting the tray type absorber module over other

alternatives increases the mean value of the

installed capital cost by $142 per kilowatt with all

other influences held constant.

97United Engineers and Contractors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High-Sulfur Coal-Fired Power

Plants, UE&C/EIA:921005 (Philadelphia, PA, October 1992).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

84 Clean Air Act Amendments of 1990
Table C1. Retrofit Scrubber Installed Capital Cost

Model Parameter Estimates and Model

Performance Statistics

Variable

Parameter

Estimate t-Statistic

INTERCEPT ............ -475.561 -2.063

FGDMOD .............. 164.223 5.836

MAXMW .............. -1.114 -4.977

BGYEAR .............. 5.174 1.756

SULFDEFF ............ 3.047 2.014

TYPE2 ................ 141.573 2.378

Ra

2 ................... 0.706 --

F Value ............... 12.527 --

Source: Decision Analysis Corporation of Virginia, “Regression

Models for Analyzing Retrofit Flue Gas Desulfurization Unit Costs and

Performance,” report prepared for the Energy Information

Administration (Vienna, VA, May 1993), p. 28.

The level of sulfur removal for which the scrubber is

designed is an important determinant of capital costs.

Capital costs for different levels of design sulfur removal efficiency vary from $83 to $281 (Table C2).

Operation and Maintenance Costs

The O&M cost model was based on a standard cost

function model. Input prices, input quantities, production characteristics, and process activity levels are

the key elements of the cost function that were included

in the model. A linear cost equation that reflects the

major input costs and engineering characteristics of the

underlying scrubber technologies was constructed.98

The pooled modeling approach99 allowed the inclusion

of a per unit cost variable that represents the embedded

price of inputs such as sorbent and associated chemical

additives. This embedded cost variable allows input

price variations to be included as an explanatory factor

for changes in O&M costs over time. Since actual input

prices for sorbent, water, and other chemical inputs

were not known, the unit cost variable was constructed

by dividing the “feed materials and chemicals” component of annual O&M costs by the quantity of sorbent

consumed in the corresponding year. This variable,

measured in dollars per pound of sorbent, captures the

prices of sorbent and other feed materials, as well as

average unit costs associated with materials preparation

and handling.

Table C2. Retrofit Scrubber Installed Capital Costs

by Design Sulfur Removal Efficiency

Design Sulfur

Removal Efficiency

(Percent)

Installed Capital

Cost per Kilowatt

(1992 dollars)

35 83

40 98

45 114

50 129

55 144

60 159

65 175

70 190

75 205

80 220

85 235

90 251

95 266

100 281

Notes: •Based on regression parameter estimates and mean

sample values for variables FGDMOD, MAXMW, BGYEAR, and

TYPE2. •Dollar values were converted to 1992 dollars using the Gross

Domestic Product Implicit Price Deflator.

Source: Decision Analysis Corporation of Virginia, “Regression

Models for Analyzing Retrofit Flue Gas Desulfurization Unit Costs and

Performance,” report prepared for the Energy Information

Administration (Vienna, VA, May 1993), p. 30.

The use of the pooled modeling approach also resulted

in technology type becoming statistically significant—a

benefit that was not possible with the cross-sectional

modeling approach. An analysis of the pooled data

matrix indicated that the venturi module configurations

had a large across-unit impact on O&M costs: units

with a venturi configuration had higher O&M costs

relative to other technology types. Consequently, the

venturi technology type was included in the pooled

model as a dummy variable.

Also included in the model as an explanatory variable

was the average percent sulfur content of the coal

burned. This variable is a measure of the extent of

scrubbing activity required. As the coal sulfur concentration increases, O&M costs are expected to increase as

well, due to greater sorbent input requirements, higher

waste generation, and elevated maintenance requirements stemming from higher flue gas sulfur dioxide

(SO2) concentrations (Table C3).

A variable representing the number of hours per year

the boiler is under load was included to reflect the

98Testing of concave and linear cost curve models indicated that a linear model was superior to other forms.

99Cross-section/time series with the same number of observations for each period.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 85
impact of plant system utilization on per-unit O&M

costs. Higher boiler hours indicates greater fuel

consumption and electric output (given a constant heat

rate), which means that O&M costs are spread across a

greater number of kilowatthours.

Table C3. Retrofit Scrubber Operations and

Maintenance Costs by Coal Sulfur

Content and Technology Type

Percent Coal

Sulfur Content

Operations & Maintenance

Cost

(1992 mills per kilowatthour)

Venturi Other

0.00 .................. 9.48 2.55

0.25 .................. 9.65 2.72

0.50 .................. 9.83 2.90

0.75 .................. 10.00 3.07

1.00 .................. 10.17 3.24

1.25 .................. 10.35 3.42

1.50 .................. 10.52 3.59

1.75 .................. 10.69 3.76

2.00 .................. 10.87 3.94

2.25 .................. 11.04 4.11

2.50 .................. 11.22 4.29

2.75 .................. 11.39 4.46

3.00 .................. 11.56 4.63

3.25 .................. 11.74 4.81

3.50 ................. 11.91 4.98

3.75 .................. 12.08 5.15

4.00 .................. 12.26 5.33

4.25 .................. 12.43 5.50

4.50 .................. 12.60 5.67

Note: • Based on regression parameter estimates and mean sample

values for variables PSORB and LOADHOUR. • Mill values were

converted to 1992 mills using the Gross Domestic Product Implicit

Price Deflator.

Source: Decision Analysis Corporation of Virginia, “Regression

Models for Analyzing Retrofit Flue Gas Desulfurization Unit Costs and

Performance,” report prepared for the Energy Information

Administration (Vienna, VA, May 1993), p. 7.

The model was specified as follows:

OMKWH = β0 β1PSORB β2AVGSULF

β3LOADHOUR β4VENTURI

(vi et εit ) ,

where

OMKWH = O&M costs per kilowatthour

(excluding replacement electricity)

in real mills,

PSORB = embedded price of sorbent and

other chemical additives, in real

dollars per pound of sorbent,

AVGSULF = average coal sulfur content in

percent,

LOADHOUR = number of hours per year the

boiler was under load,

VENTURI = venturi technology type (takes on

a value of 1 for venturi technology

type, and 0 for all other technology

types),

v, e, ε = cross-section, time-series, and

cross-section/time-series errors.

For this version of the O&M model, O&M costs are

expressed in mills per kilowatthour. On average, use of

the venturi technology type increased O&M costs by 6.9

mills per kilowatthour (Table C4).

Table C4. Pooled Retrofit Scrubber Operations

and Maintenance Model Parameter

Estimates

Variable

Parameter

Estimate t-Statistic

Intercept ............... 3.082 1.642

PSORB ............... 0.075 26.542

AVGSULF ............. 0.694 3.138

LOADHOUR ............ -5.8E-4 -2.571

VENTURI .............. 6.928 9.331

Model Ra

2 .............. 0.996 --

F Value ............... 306.670 --

Source: Decision Analysis Corporation of Virginia, “Regression

Models for Analyzing Retrofit Flue Gas Desulfurization Unit Costs and

Performance,” report prepared for the Energy Information

Administration (Vienna, VA, May 1993), p. 5.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

86 Clean Air Act Amendments of 1990
Appendix D

Current Engineering

Estimates of Scrubber

Retrofit Costs
Appendix D

Current Engineering Estimates of Scrubber

Retrofit Costs

These engineering cost estimates use currently available

technology, which would be available to future

builders, for their design. Historical cost estimates are

based on the technology existing at the time they were

built; they do not take into account current design

technologies or current costs (Appendix C). Two different methodologies are used to estimate scrubber

retrofit costs. Each of these offers distinct advantages

and disadvantages. The most important distinction is

that historical cost estimates are based on actual

recorded costs, while engineering costs are estimated by

the expert engineer. Engineering cost estimates may

differ from the actual costs that would be incurred if

the designed scrubber were built.

The engineering cost estimate for flue gas desulfurization systems (scrubbers) presented in this appendix

is based on retrofitting a scrubber to a 488-megawatt

(net) high-sulfur pulverized coal-fired power generating

station. This cost estimate is based on environmental

regulations for coal-fired plants on January 1, 1992, and

reflects the Best Available Control Technology for

scrubber systems currently being used.100 As of

January 1, 1992, coal-fired plants were limited to sulfur

dioxide (SO2) emissions of 0.30 pounds per million

British thermal units (Btu).101

Scrubber Description

Scrubber systems are designed to remove SO2 from the

flue gas exiting an electrostatic precipitator (which

renders it essentially particulate-free) of a coal-fired

power plant and to produce in the process a mixed fly

ash and scrubber waste product suitable for landfill

disposal. The SO2 removal is accomplished by an

absorbent, often lime or limestone. The system design

considered here is a nonrecovery forced oxidation wet

limestone process consisting of: a limestone unloading

and storage facility; a limestone slurry preparation

system; an SO2 absorber system; a waste slurry thickening system; an scrubber waste product system; and a

water distribution system. The performance criterion for

a conventional limestone wet scrubbing system (Figure

D1) is 95 percent SO2 removal efficiency for 3.2-percent

sulfur coal. The system design provides a zero liquid

discharge capability.

The limestone unloading/storage facility is designed to

receive the limestone shipments and to convey the

limestone to storage silos for limestone slurry preparation. The limestone is usually delivered to the plant

via railroad. The rail cars containing limestone are

brought to the unloading shed, which houses the unloading hoppers. Limestone from the hoppers is

crushed and pneumatically conveyed to the limestone

storage silo.

The limestone slurry preparation system receives

limestone from the storage silo of the unloading/storage facility, grinds the limestone more finely,

adds water, and stores the resultant slurry. The

limestone slurry storage tank pumps transfer limestone

slurry to the feed tanks in the absorber island. The

slurry produced is used within the SO2 absorber

system.

The SO2 absorber system brings the flue gas into direct

contact with a recirculating slurry within an absorber

vessel in order to remove SO2 from the flue gas stream.

The major components of the SO2 absorber system

include: spray tower absorber modules fabricated of

rubber-lined carbon steel, recirculation pumps, mist

100United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired Power

Plant, UE&C/EIA: 921005 (Philadelphia, PA, October 1992). The 488 megawatt (net) coal-fired generating station was selected as a typical

plant for new construction. 101Under the current Best Available Control Technology approach, any lower limit technology permitted and installed anywhere for

any reason becomes the benchmark limit for the next installation permit.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 89
D=Damper

Mist

Eliminator

Wet

Scrubber

Reagent

Slurry

Flue

Gas

By

Pass

Reaction

Tank

Clean

Gas to

Stack

Wet Sludge

D

D

D

Indirect Reheater or

Reheat by Unscrubbed

Hot Gas D

D

Stack

Thickner

Filter

Figure D1. Conventional Limestone Wet Scrubbing Schematic

Source: Electric Power Research Institute, Proceedings: Ninth Symposium on Flue Gas Desulfurization, EPRI CS-4390, Volume

2 (Palo Alto, CA, January 1986), p.11-3.

eliminator, wash pumps and blend tank, limestone

slurry feed pumps and storage tank, dampers, agitators,

piping, valves, instrumentation, and controls.

One vertical spray absorber module is usually used. At

valves wide open, 5 percent overpressure turbine operation with design coal, the absorber module treats 100

percent of the flue gas. The absorber module commonly

contains five banks of sprays. Flue gas enters the

absorber module with a slight downward direction and

turns up through a bank of sprays where gas is scrubbed.

Rubber-lined casing centrifugal recirculation pumps are

connected to each spray header, usually two at a time.

The pumps are designed to produce a liquid-to-gas

ratio with all 10 pumps in operation. These pumps take

suction from the recirculation tank that is provided as

an integral component of the absorber module.

Limestone slurry, as required to maintain the alkalinity

within the absorber system, is added to the recirculation tank. The limestone slurry, prepared within the

slurry preparation system, is pumped to the absorber

from the limestone feed tank via a recirculating slurry

feed loop.

The absorber is provided with a mist eliminator, which

removes liquid droplets and particulates contained in

the scrubbed flue gas. The absorber system waste

products are discharged via a bleed stream from the

recirculating slurry. The bleed stream is then directed

to an agitated waste slurry sump. From this sump, the

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

90 Clean Air Act Amendments of 1990
Georgia Power installed a scrubber at Yates unit 1 for an estimated $34 million capital cost, half of which was paid by the

Department of Energy as a demonstration project.

bleed stream is pumped to the waste slurry thickening

system.

The waste slurry thickening system dewaters the bleed

slurry from the absorber module to produce a concentrated underflow slurry and a high-quality (low

suspended solids) overflow. The underflow slurry,

which contains a minimum of 45 percent solids, by

weight, is pumped to the waste product system for

treatment prior to disposal. The overflow is returned

for reuse within the scrubber system.

The waste product system is provided to process fly

ash from the coal combustion process and scrubber

waste product for co-disposal within a solid waste

landfill. While the waste product system normally treats

a combination of scrubber waste product and fly ash, it

is also able to process fly ash alone. The primary

influents to the waste product system are thickener

underflow (from the waste slurry thickening system)

and fly ash (from the fly ash system). The waste is

normally loaded directly onto trucks for transport to the

disposal areas.

The sulfur removal efficiency of 95 percent for the

current engineering estimate yields an SO2 emission of

about 0.29 pounds per million Btu for 3.2-percent sulfur

coal.

Capital Costs

The capital cost, including direct and indirect costs, for

retrofitting scrubber equipment to an existing 488-

megawatt (net) coal-fired plant with no spare module

and 3.2-percent sulfur coal is estimated to be $266 per

kilowatt (1992 dollars). This capital cost includes the

scrubber structures and equipment.

This capital cost includes a scrubber retrofit multiplier

of 1.25 times the cost of an original equipment scrubber.

The multiplier is estimated to vary from 1.1 to 2.0 times

the capital cost of an original equipment scrubber,

depending on the conditions available for installing a

scrubber. The amount of space available to install

scrubbers is the main constraint.102

Spare Absorber Modules

Previously, scrubber systems usually included a spare

absorber module to maintain low emission rates in the

short term, when one absorber module was inoperative.

However, under the Clean Air Act Amendments of

1990, a module or entire scrubber unit may be bypassed

for a short period of time, as long as sufficient

emissions allowances are acquired for the total emissions of the entire year. Therefore, a utility could

102United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired Power

Plant, UE&C/EIA: 921005 (Philadelphia, PA, October 1992), Table 3, pp. 1-3.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 91
overscrub for a period of time or acquire additional

allowances to offset periods when one scrubber module

is out of service. Furthermore, scrubber technology has

advanced so that scrubber units have a high availability

and efficiency without the use of a spare module.

Spare capacity for the auxiliary systems, such as thickeners and mills, is provided where required to support

a single absorber module with a system availability of

99.5 percent. The cost of installing and maintaining a

scrubber system would increase dramatically if there

was a requirement for a spare module.103 The current

engineering capital cost estimate for scrubber systems

for a 488-megawatt (net) coal-fired plant with 3.2-

percent sulfur coal would increase by about one-third

with a spare module.104

Operation and Maintenance Costs

The additional nonfuel operation and maintenance

(O&M) costs for a retrofitted scrubber on a 488-

megawatt (net) coal-fired plant with bituminous 3.2-

percent sulfur coal are determined by comparing costs

at plants with and without a wet limestone scrubber. A

model based on engineering cost estimates developed

by Oak Ridge National Laboratory is used in this report

to determine the additional O&M costs for adding a

scrubber.105

The largest increase in O&M costs for a wet limestone

scrubber on a bituminous coal-fired plant is in supplies

and expenses (including fixed and variable costs) of

$4.5 million (Table D1). The variable costs for limestone

of $2.7 million and waste disposal of $1.3 million are

the largest items in supplies and expenses. The additional onsite staff is increased by 34 personnel to

maintain and monitor the scrubbers at an additional

cost of $1.3 million. Increased maintenance materials

account for $1.4 million. Administrative and general

costs, including benefits and worker’s compensation

and other general expenses, add $1.7 million or 19

percent of the total additional nonfuel O&M costs of

$9.0 million. These costs can be divided into fixed and

variable components. Additional nonfuel O&M fixed

costs are $9.2 per kilowatt per year and variable costs

are 1.6 mills per kilowatthour for the addition of

scrubber equipment to the unit.

Table D1. Operations and Maintenance Costs

for a Scrubber Retrofitting

(1992 Dollars)

Type of Cost

Cost

(million dollars

per year)

On-site Staff (34 persons) . . . . . . . . . . . . 1.3

Maintenance Materials . . . . . . . . . . . . . . 1.4

Fixed . . . . . . . . . . . . . . . . . . . . . . . . 1.1

Variable . . . . . . . . . . . . . . . . . . . . . . 0.3

Supplies and Expenses . . . . . . . . . . . . . . 4.5

Fixed . . . . . . . . . . . . . . . . . . . . . . . . 0.3

Variable—Plant . . . . . . . . . . . . . . . . . 0.2

Variable—Limestone . . . . . . . . . . . . . 2.7

Variable—Waste Disposal . . . . . . . . . 1.3

Offsite Technical Support . . . . . . . . . . . . 0.2

Subtotal, Direct O&M Costs . . . . . . . . . . . 7.3

Fixed . . . . . . . . . . . . . . . . . . . . . . . . 2.8

Variable . . . . . . . . . . . . . . . . . . . . . . 4.5

Administration and General Costs . . . . . . 1.7

Pensions, Benefits, and Worker’s

Compensation . . . . . . . . . . . . . . . . . . 0.3

Other General Expenses . . . . . . . . . . 1.5

Total Nonfuel O&M Costs . . . . . . . . . . . . 9.0

Energy (Electricity) Costs . . . . . . . . . . . . 1.5

Total O&M Costs (Including Electricity) . . 10.5

Fixed . . . . . . . . . . . . . . . . . . . . . . . . 4.5

Variable . . . . . . . . . . . . . . . . . . . . . . 5.9

Type of Cost

Cost

(per unit)

Fixed O&M Costs (dollars per kilowatt per 9.2

Variable O&M Costs (Including Electricity)

(mills per kilowatthour) . . . . . . . . . . . . . 2.1

Variable Nonfuel O&M Costs (mills per

kilowatthour) . . . . . . . . . . . . . . . . . . 1.6

Energy (Electricity) Costs (mills per

kilowatthour) .................. 0.5

O&M=Operations and Maintenance.

Notes: •Costs were calculated for a wet limestone scrubber

retrofitted to a 488-megawatt (net) bituminous coal-fired power plant

burning 3.2 percent sulfur coal. •Costs include direct costs and

indirect costs (administrative and general costs). •Data estimated

using a capacity factor of 65 percent. •Totals may not equal sum of

individual elements because of independent rounding. •Dollar values

were converted to 1992 dollars using the Gross Domestic Product

Implicit Price Deflator.

Source: Model: Oak Ridge National Laboratory, “Nonfuel Operation

and Maintenance Costs for Large Steam-Electric Power Plants—1982,”

ORNL/TM-8324 (September 1982). The model for estimating O&M

costs for coal-fired power plants was updated in 1987. Costs: Energy

Information Administration, Office of Coal, Nuclear, Electric and

Alternate Fuels.

103Antonio J. DoVale, “Acid Rain Scrubber Retrofits May Cost Less than Anticipated,” Power Engineering (February 1991), p. 38. 104United Engineers & Constructors, Update of EEDB Phase X HS5 Base Construction Costs 500 MW (Nominal) High Sulfur Coal-Fired Power

Plant, UE&C/EIA:921005 (Philadelphia, PA, October 1992), Table 3, pp. 1-3. United Engineers & Constructors, Phase IX Update (1987)

Report For The Energy Economic Data Base Program EEDB—IX, DOE/NE-0091 (Philadelphia, PA, July 1988), Table 5, pp. 5-13. 105Oak Ridge National Laboratory Report, “Nonfuel Operation and Maintenance Costs for Large Steam-Electric Power Plants—1982,”

ORNL/TM-8324 (September 1982).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

92 Clean Air Act Amendments of 1990
In addition, the energy needed to operate a scrubber is

estimated to be about 2.1 percent of the capacity of its

associated generating unit(s). This is because when the

retrofit scrubber is operating, it uses about 2.1 percent

of the output of its associated generator(s) to power its

fans and other electrical equipment.106 For a 488-

megawatt (net) plant, these costs amount to $1.5 million, or 0.5 mills per kilowatthour.107 These electricity

costs add 17 percent to the preceding estimates for total

annual scrubber costs and 31 percent to the variable

O&M costs.

106U.S. Environmental Protection Agency as quoted in a memo from Bruce Braine, Carl Leubsdorf, and Barry Kurland to Ann Watkins

(July 14, 1993). 107Using a 65-percent capacity factor and a cost of replacement electricity of 2.5 cents per kilowatthour.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 93
Appendix E

Nitrogen Oxide Controls
Appendix E

Nitrogen Oxide Controls

Nitrogen oxides (NOx) are commonly emitted from

combustion sources, predominantly transportation

sources (e.g. automobiles), utilities, and other industrial

sources.108 One effect commonly attributed to NOx

emissions is acid rain. With the passage of the Clean

Air Act Amendments of 1990 (CAAA90), affected

electricity producers must comply with specified NOx

limits by using an approved and proven NOx control

technology. This appendix summarizes some of the

predominant technologies available for controlling NOx,

the CAAA90 NOx control regulations, and the costs of

installing and using such control technologies.

The Formation of Nitrogen Oxides

NOx is formed in high-temperature environments when

nitrogen and oxygen are present together. In a

combustion chamber, where temperatures can be very

high, the nitrogen present in air can combine with

oxygen to produce NOx. This is called thermal NOx and

has no relation to the fuel used in the combustion

process. Thermal NOx production usually begins at

temperatures above 1300° Celsius (or 2372° Fahrenheit).109 A second NOx production source is the

nitrogen that may be present in the fuel, which when

burned, is released and is able to react with any oxygen

present. This is called fuel NOx. Fuels with higher

percentages of nitrogen are prone to higher emissions

of fuel NOx when they are combusted (Table E1).

NOx Control Technologies

The current state of technology to control NOx emissions can be grouped into three categories: combustion

techniques, flue gas treatment techniques, and advanced

techniques. Combustion techniques include the following methods of control: air staging, fuel staging

(reburning), and flue gas recirculation. “Low-NOx

burners” are one example of an air staging combustion

control technology. Flue gas treatment options include

selective catalytic reduction, selective noncatalytic

reduction, and some advanced techniques which

simultaneously treat flue gas for NOx and sulfur

dioxide (SO2) emissions. Advanced techniques include

techniques used in fluidized-bed combustors, coal

gasification processes, and slagging combustors. In

many cases these techniques are still under investigation, and therefore they are not applicable to Phase I

plants and will not be discussed here. Also, many of

the projects selected in the Department of Energy’s

Clean Coal Technology program are advanced techniques for NOx control.

Table E1. Typical Nitrogen Content of Selected

Fuels from the United States

Fuel

Nitrogen Content

(Weight Percent,

Dry Ash-Free Basis)

Coal, Typical Eastern . . . . . . . . . . . . . . 1.3

Coal, Powder River Basin (Wyoming) . . 0.7

Coal, Powder River Basin (Montana) . . . 0.8

Fuel Oil, No. 1 ................... *

Fuel Oil, No. 2 ................... *

Fuel Oil, No. 4 . . . . . . . . . . . . . . . . . . . 0.2

Fuel Oil, No. 6, Low Sulfur .......... 0.3-0.5

Natural Gas (Pennsylvania) .......... a1.1

Crude Oil, Kern Co. (California) ....... 0.5-0.8

a

Molecular Nitrogen, N2.

*Less than 0.05 weight percent.

Sources: Coal—John H. Pavlish, April A. Anderson, Neil C. Craig,

and Arun K. Mehta, “Using the CQIMTM to Evaluate Switching to

Western Low-Sulfur Coals,” paper presented at the Engineering

Foundation Conference on Coal Blending and Switching of Western

Low-Sulfur Coals (Salt Lake City, UT, September 26-October 1, 1993),

p. 7. Fuel Oil, Natural Gas, Crude Oil—Anna-Karin Hjalmarsson,

NOx Control Technologies For Coal Combustion, IEACR/24 (London:

IEA Coal Research, June 1990), p. 18.

108U.S. Environmental Protection Agency, “EPA Acid Rain Program Nitrogen Oxides Emission Reduction Program Proposed Rule for

Group 1 Boilers,” EPA430/F-92/014 (6204J) (October 1992), p. 1. 109Anna-Karin Hjalmarsson, NOx Control Technologies For Coal Combustion, IEACR/24 (London: IEA Coal Research, June 1990), p. 18.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 97
In most cases, attempts to control NOx emissions are

first made during the combustion process.110 These

techniques are of the most interest for Phase I units for

which NOx control equipment retrofits are being considered.

Combustion Techniques

Combustion techniques and many of the advanced

techniques rely on the fact that NOx formation in

combustion processes is inhibited if less oxygen is

present for the nitrogen to combine with. These techniques attempt to decrease oxygen levels by decreasing

the amount of air present in combustion regions. Stoichiometry is a method for calculating the quantities of

reactants and products in chemical reactions by use of

simple weight ratios of the compounds as they appear

in the chemical reaction equation. It can be used to

calculate the amount of oxygen needed to entirely

combust the fuel through the combustion chemical

equation. Combustion NOx control techniques provide

less than this amount of oxygen to the combustion

region, making the combustion a lean or fuel rich

process (substoichiometric combustion). The combustion

process then uses most or all of the oxygen present,

leaving little for NOx formation. Because of the oxygen

limitation, substoichiometric combustion does not allow

the fuel to burn entirely, so NOx control technologies

must allow for this by creating a second combustion

zone where unburnt fuel can be combusted. This second process can be called the fuel burnout process. By

separating the substoichiometric combustion and the

fuel burnout process, the amount of NOx production is

reduced. Different combustion NOx control techniques

employ different methods for creating the substoichiometric combustion and fuel burnout processes.

Air staging is a NOx combustion control method by

which air to the combustion region in the burner or

furnace is decreased to create the substoichiometric

combustion condition, and the rest of the air needed for

fuel burnout is supplied elsewhere. Air staging can be

done in two ways: in the furnace, or in the burner

(Figure E1). Furnace air staging supplies the burnout air

away from the main combustion zone, creating a second combustion zone elsewhere in the furnace. Burner

air staging creates different combustion zones in the

flame of the burner, one being the substoichiometric

region, the other the burnout region, by special placement of fuel and air nozzles in the burner. Burners with

such nozzle arrangements and designs are called lowNOx burners.

Fuel staging, which is commonly referred to as “reburning,” stages fuel injection into the furnace to create a

primary combustion zone, a secondary combustion zone

which is substoichiometric, and a burnout zone to complete fuel combustion. The secondary combustion zone

produces chemical compounds (hydrocarbon radicals)

which take part in reactions to reduce NOx formation in

the primary combustion zone and increase the production of molecular nitrogen and other products. Since

the primary zone is not substoichiometric, most of the

fuel is burned, so secondary “staged” fuel must be

added to create the secondary combustion zone. Burnout of the secondary fuel is completed in the burnout

zone by staging air into this zone (Figure E2). The

primary and secondary fuels need not be the same,

although in most cases they are.

1 2

1 2

2

1

1 Primary combustion

2 Secondary combustion

Burner

Staging

Furnace

Staging

Figure E1. Air Staging in the Burner and the

Furnace

Source: Anna-Karin Hjalmarsson, NOxControl Technologies

for Coal Combustion, IEACR/24 (London: IEA Coal Research,

June 1990), p. 24.

Flue gas recirculation is another combustion NOx

control technique in which some of the flue gas is

diverted back to the combustion zone. This dilutes the

amount of oxygen available in the combustion zone,

since the flue gas has been oxygen-depleted during the

110Anna-Karin Hjalmarsson, NOx Control Technologies For Coal Combustion, IEACR/24 (London: IEA Coal Research, June 1990), p. 15.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

98 Clean Air Act Amendments of 1990
air

fuel

burnout zone

reburning zone

primary zone

NO reduction x

XN

NO

HCN

NH3

{ { NO

N2

XN + NO N + XN 2

CH + NO XN(NH + NO + HCN) 3

NO, CO , H O

0 , ash, SO 2 2

2 2

Figure E2. Principle of Fuel Staging (Reburning) in

a Furnace

Source: Anna-Karin Hjalmarsson, NOxControl Technologies

for Coal Combustion, IEACR/24 (London: IEA Coal Research,

June 1990), p. 26.

combustion process, allowing less oxygen to be available for NOx formation.

Costs For Retrofitting

Low-NOx Burners

The cost analysis provided in this section for retrofitted

low-NOx burners is obtained from two sources summarizing low-NOx technology cost modeling efforts by

the Department of Energy Clean Coal Technology

program and the Environmental Protection Agency

(EPA).111 In each case, the only significant costs for

low-NOx burner retrofits are the capital costs.

Operations and maintenance costs for low-NOx burners

are assumed to be the same as for regular burners.

These sources evaluate costs for the two types of boilers

covered in Phase I of the CAAA90. These are drybottom wall-fired boilers, and dry-bottom tangentiallyfired boilers. Dry-bottom refers to the form of the ash

that leaves the boiler. In dry-bottom boilers, the

temperature remains below the ash melting point, and

the ash remains in a solid, “dry” form. Another type of

boiler, called a wet-bottom boiler, gets hot enough to

melt the ash before it leaves the boiler. Wall-fired and

tangentially-fired refer to the placement and orientation

of burners in the combustion chamber. Wall-fired

boilers have burners facing perpendicular to the wall of

the chamber, either all on one wall (front) or split

between two facing walls (opposed). Tangentially-fired

burners are spaced around the chamber and angled to

produce a rotating flame within the chamber (Figure

E3).

Model results for two different technologies for each

boiler type show cost estimates for a 300-megawatt unit,

which is in the approximate average size of Phase I

units (Table E2). The two technologies applicable to

wall-fired boilers are low-NOx burners and low-NOx

burners with over fire air from a separate wind box. A

wind box is the device in a boiler which distributes air

to the air ports where it is injected into the combustion

burners

wall-fired

single (front) wall

wall-fired opposed

tangential-fired

(corner-fired)

Figure E3. Options for Burner Placement

Source: Anna-Karin Hjalmarsson, NOxControl Technologies

for Coal Combustion, IEACR/24 (London: IEA Coal Research,

June 1990), p. 29.

111Radian Corporation, “Analysis of Low-NOx Burner Technology Costs,” draft report to the U.S. Environmental Protection Agency

(November 1992), pp. 6-1 through 6-7.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 99
Table E2. Comparison of Low-NOx Burner Retrofit Cost Estimates for a 300-Megawatt Unit

Technology

Capital Cost

(1992 Dollars per Kilowatt)

Average Cost

(1992 Dollars per

Kilowatt)

Department of

Energy Clean Coal

Technology

Environmental

Protection

Agency

Wall-fired:

Low-NOx Burner ................................. 19.0 22.9 --

Low-NOx Burners plus Over Fire Air with a --

Separate Wind Box .............................. 26.0 28.0

Average ....................................... 22.5 25.5 24.0

Tangentially-fired:

Low-NOx Concentric Firing System with Closely

Coupled Over Fire Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.0 NA --

Low-NOx Concentric Firing System with Both

Closely and Loosely Coupled Over Fire Air ............. 23.0 20.9 --

Average ....................................... 14.0 20.9 17.5

NA = Not available.

Source: Radian Corporation, “Analysis of Low-NOx Burner Technology Costs,” unpublished draft report to the U.S. Environmental Protection

Agency (Research Triangle Park, NC, November 1992), p. 6-7.

A view from inside the boiler shows a low-NOx burner

being installed on Hammond unit 4.

chamber. The two technologies shown for tangentiallyfired boilers are both low-NOx concentric firing systems.

The first type of system has closely spaced over fire air

ports, while the second adds air ports spaced further

from the burner unit.

The average capital cost for retrofitting low nitrogen

oxide burners onto a wall-fired boiler is $24.0 per

kilowatt (1992 dollars), whereas for tangentially-fired

boilers, this cost is $17.5 per kilowatt. There are 95

tangentially fired units and 89 dry-bottom wall-fired

units in Phase I.112

112Federal Register, Vol. 57, No. 228 (November 25, 1992), pp. 55679-55682.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

100 Clean Air Act Amendments of 1990
Appendix F

Continuous Emission

Monitoring
Appendix F

Continuous Emission Monitoring

The Clean Air Act Amendments of 1990 (CAAA90)

require the installation of continuous emission monitors

(CEMs) on the smokestacks of most Phase I and Phase

II affected units. CEMs are devices which approximate

a continuous measurement of certain characteristics of

a gas by making separate measurements very frequently.113 CEMs sample the exhaust or flue gas being

emitted into the atmosphere from the burners/boiler of

generating units fired by fossil fuels (coal, gas, or oil).

Characteristics of the flue gas are recorded to allow

calculations of the amount of pollutants being emitted

into the atmosphere from the generating unit. CEM

equipment technologies and configurations, particularly

those that are retrofit, vary widely and are site-specific.

The deadline for Phase I affected units to have

operating CEMs is November 1993 and the deadline for

Phase II units is January 1995. This appendix describes

how the most popular CEMs work and their costs.

Technologies

CEM measurements can be based on any of several

available technologies, each based on different physical

processes depending upon the gas property of interest

(Table F1). The constituents to which they can be

applied include those specified by CAAA90 (Table F2).

CEM equipment is available in two broad types,

extractive and in situ (Figures F1 and F2). Extractive

systems draw exhaust gas away from the combustion

system to the measurement equipment through special

ducts. In situ systems make measurements directly in

the flue or exhaust pipe. These two CEM technology

types differ significantly not only in their configurations

but in their costs.

Table F1. Continuous Emission Monitoring Technologies

Technology Operating Characteristics

Infrared Radiation (IR) . . . . . . . . . . . . . . . . . . . . . . . . An infrared beam passes through a measurement filter and is absorbed by the

constituent gas. A light detector creates a signal which is used to monitor

concentrations.

Ultraviolet Absorption (UV) .................... A split beam measures the difference in light beam absorption between a

reference gas and the sample gas.

Chemiluminescence ......................... Ozone (O3) is injected into the sample to react with NOx, generating light that is

measured by a photocell.

Flame Ionization Detection .................... Hydrocarbons are ionized with strong light. The signals are received by a flame

ionization detector.

Transmissometer ........................... Light is passed through the stack, where it is reflected by a mirror on the

opposite side. The quantity of light returning is proportional to particulate matter

and aerosols in the flue gas.

Electrochemical Cells . . . . . . . . . . . . . . . . . . . . . . . . The voltage measured when an oxygen (O2) sample is injected into a solution

with a strong base is compared to a reference voltage.

Chromatography ............................ A sample, zero, and calibration gas are passed through a column where, due to

chemical and physical considerations, constituents may be separately measured

by such things as flame photometric or thermal conductivity detectors.

Source: Steven C. Stultz and John B. Kitto, eds., Steam, Its Generation and Use, 40th ed. (Barberton, OH: Babcock and Wilcox Co., 1992), p.

36-4.

113For compliance with CAAA90, the measurements must be taken at least every 15 minutes.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 103
Table F2. Continuous Emission Monitoring Measurement Techniques by Gas Constituent

Constituent CEM Measurement Technologies

Particulate Matter (Opacity) .................................... Transmissometer, beta ray absorption

Sulfur Dioxide (SO2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . UV absorption, IR pulsed fluorescence

Nitrogen Oxides (NOx) ....................................... Chemiluminescence, UV spectroscopy, IR

Hydrogen Chloride (Hcl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IR with gas filter

Carbon Monoxide (CO) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IR

Carbon Dioxide (CO2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IR

Oxygen (O2) ............................................... Electrochemical cell

Volatile Organic Compounds (VOC) .............................. Flame ionization detection

Other Organic Air Toxics ...................................... Chromatography

Ammonia (NH3) ............................................ Same as NOx

a

a

NH3 is converted to NOx in one of two split streams. Both are analyzed for NOx. NH3 is determined as the difference.

CEM=Continuous emission monitoring.

IR=Infrared radiation.

UV=Ultraviolet absorption.

Source: Steven C. Stultz and John B. Kitto, eds., Steam, Its Generation and Use, 40th ed. (Barberton, OH: Babcock and Wilcox Co., 1992),

p. 36-5.

Extraction Duct

Stack

Atmosphere

Flue Gas

Gas

Pre-Treatment

Extractive

Measurement

Equipment

Data

Recording and

Analysis

Reports &

Submissions

to EPA

Figure F1. Conceptual Extractive Continuous Emission Monitoring System Design

Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

104 Clean Air Act Amendments of 1990
Stack

Atmosphere

Flue Gas

Data

Recording and

Analysis

In Situ

Measurement

Equipment

Reports &

Submissions

to EPA

Equipment

Shielding

Emitter

Probe

Reflector/Detector

Figure F2. Conceptual In Situ Continuous Emission Monitoring System Design

Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels.

Extractive CEM systems were the first to be developed.

In early designs, ambient air measurement devices were

modified to be used for combustion exhaust measurements.114 Many times these devices could not tolerate

the extreme conditions imposed by combustion

exhausts, and therefore required pretreatment of the

gases to make them more amenable to the measurement

equipment; some modern extractive designs still need

pretreatment. Examples of pretreatment include moisture removal to decrease the corrosiveness of the gas

and dilution with other known gases to decrease the

concentration of pollutants present.

As the design of extractive CEMs improved, techniques

to handle exhaust gas in its original form were

developed. These fully extractive systems do not need

gas pretreatment equipment and are less costly.

However, fully extractive systems do fall victim to

some of the maintenance problems inherent in all

extractive systems due to prolonged contact between

equipment and exhaust gas. This drawback is mitigated

by installing heating elements around the extraction

lines to keep the exhaust gas above the temperature at

which water vapor will condense. Condensation on

equipment surfaces tends to increase the corrosiveness

of the gas on those surfaces.

In situ CEM designs have become a popular alternative

to extractive systems because of their lower equipment

costs. These systems operate by emitting electromagnetic radiation (usually infrared light) or sound

waves into the exhaust gas stream from a probe located

114Electric Power Research Institute, Clean Air Act Response: Continuous Emissions Workshop, EPRI TR-100510 Project 1961 (Palo Alto, CA,

1992), p. 5-8.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 105
in the stack or exhaust pipe. In some systems there is a

detector on the opposite side of the pipe which records

the signal. In other systems, called multi-pass systems,

there are reflecting devices which pass the signal back

and forth across the pipe two or more times before it is

recorded by a detector. In either case the pollutant

concentrations can be calculated from the absorption of

the signal by the gas. In one of the more recent in situ

designs based on Fourier transform infrared spectroscopy, measurements of several pollutants can be

made simultaneously. However, water vapor can interfere with this measurement technique. The extent of

this interference and its effect upon the measurements

are not well known.115 Simultaneous measurement is

a great cost advantage since one set of equipment will

meet most or all of the requirements for pollution

monitoring.

The relative merits of these two types of CEM systems

are highly dependent upon the design specifications of

the plant into which they are being installed. For

instance, in situ equipment must be protected by special

sheds or shielding if the environment around the plant

is particularly hostile. In such cases, an extractive

design, where only the sampling lines are exposed, can

offer a less expensive alternative. Also, early in situ

systems were subject to controversy concerning their

calibration method, resulting in concern that they

would not be able to pass the Environmental Protection

Agency (EPA) standards tests. Later designs have

allowed for easier calibration. Nonetheless, extractive

systems require more periodic maintenance of filters

and other similar equipment than do in situ systems.

Retrofit CEM Capital Costs, First

Costs, and Operations

and Maintenance Costs

The inherent uniqueness of retrofit CEM implementations makes retrofit CEM costing analysis a complex

undertaking. In fact, most reports on the subject give

only general cost characteristics for typical CEM

designs. To comply with the CAAA90, systems must

monitor levels of sulfur dioxide (SO2), nitrogen oxides

(NOx), and diluent gases (i.e., oxygen or carbon dioxide

(CO2), used in extractive systems to dilute the flue

gases), as well as monitoring volumetric flow and

opacity (Table F3). Volumetric flow is a measure of the

volume of gas emitted from a unit in a specified time

period. It is used in the calculation for percentages of

other pollutants. Opacity is a measure of particulate

matter being emitted from the unit, and is expressed as

a percentage, this number being the proportion of

incident light which passes through the gas. Most

constituent measurements also require computer equipment for data handling and analysis. In addition,

affected units must either monitor or estimate CO2

emissions.

Table F3. Continuous Emission Monitoring Components Required for Acid Rain Regulations

Monitoring Requirement

(Units Required)

Required Component

SO2 NOx Flow Opacity Diluent Gas

Data

Handling

Sulfur Dioxide (Pounds per Hour) . . . . . . . . . Yes -- Yes -- -- Yes

Nitrogen Oxide (Pounds per million Btu)a . . . . -- Yes -- -- Yes Yes

Opacity (Percent) . . . . . . . . . . . . . . . . . . . . . -- -- -- Yes -- Yes

Carbon Dioxide (Pounds per Hour)b ........ -- -- Yes -- Yes Yes

a

A measured heat input rate in million Btu per hour would be multiplied by this nitrogen oxide (NOx) continuous emission monitoring measurement

in pounds per million Btu to obtain a NOx emission rate in pounds per hour. b

Alternative methods may be used to monitor carbon dioxide (CO2) (e.g. fuel analysis where constituent weights are used to calculate probable

CO2 emissions).

SO2 = Sulfur dioxide.

NOx = Nitrogen dioxide.

Source: U.S. Environmental Protection Agency, “Acid Rain Program Continuous Emission Monitoring,” EPA430/F-92/021 (Washington, DC,

December 1992), p. 2.

115Electric Power Research Institute, Clean Air Act Response: Continuous Emissions Monitoring Workshop (Palo Alto, CA, May 1992), pp.

12-1,2.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

106 Clean Air Act Amendments of 1990
Generally, CEM costs can be categorized into capital

costs and operations and maintenance (O&M) costs.

Capital costs are the costs accrued to get the CEM

system running for the first time, and include equipment, engineering, planning, installation, testing, and

certification costs. The CAAA90 requires several certification tests for initial approval of a CEM system. O&M

costs include all operation and maintenance costs.

Included in this category are costs for periodic recertification pursuant to the CAAA90 regulations.116 These

cost categories were used in a 1991 CEM cost analysis

model developed for EPA.117 This model separately

estimates costs of extractive and in situ systems. The

following cost figures are based on this model as well

as conversations with CEM vendors who offered cost

data on the equipment they sell.

Several runs of the model were made using both types

of systems designed to comply with the CAAA90 to

estimate typical CEM costs. Equipment cost (cost of

CEM hardware only, without other installation costs)

estimates from the model for in situ systems were

found to be roughly half those for extractive systems,

with extractive equipment costs ranging from $300,000

to $410,000 (1992 dollars). The gas pretreatment and

rerouting in extractive systems require extra equipment,

increasing the equipment cost of these systems. Most

vendors contacted offer extractive systems with equipment costs ranging from over $200,000 to over $600,000.

Vendors offer most in situ systems for under $100,000

in equipment costs. A recent study cites average CEM

equipment costs for both types of systems of

$300,000.118 Because extractive systems have been in

use for a longer period of time and because their

calibration procedures to meet EPA requirements are

more easily met, this report assumes that most CEM

systems will be extractive systems and that the average

equipment costs for CEM systems are $500,000.

The EPA model results in the ratio of capital costs to

equipment costs of 1:1.7.119 It also finds that annual

O&M costs, which include the cost of CAAA90

Continuous emission monitors consist of various

components, including devices on the stacks (top) as well

as computer equipment located inside the plant (bottom).

116Initial certification includes a 7-day calibration test, a linearity check for each pollutant monitor, a relative accuracy test (RATA) for

each monitor, a bias test for each pollutant concentration and flow monitor, and a cycle time/response test for each pollutant concentration

monitor. Periodic CEM testing requirements in CAAA90 include daily calibration error tests, daily interference tests for flow monitors,

and semi-annual or annual RATA and bias tests. U.S. Environmental Protection Agency, “Continuous Emission Monitoring (CEM),”

EPA430/F-92/021 (Washington, DC, December 1992), p. 4. 117Entropy Environmentalists, Inc., “Model for Estimates of CEMs and Annual O&M Costs for New and Existing Facilities,” report to

the U. S. Environmental Protection Agency (March 1991), p. 1. 118W.P. Coffey, J.C. Miller, Sr., M.A. Jones, H.S. Sawhney, “Upgrading Continuous Emissions Monitoring (CEM) Systems for Utility

Units,” paper presented at the Power-Gen ’92 Conference (Orlando, FL, November 18, 1992). 119The previous study suggests that average capital costs of CEM systems are twice the equipment cost. W.P. Coffey, J.C. Miller, Sr.,

M.A. Jones, H.S. Sawhney, “Upgrading Continuous Emissions Monitoring (CEM) Systems for Utility Units,” paper presented at the PowerGen ’92 Conference (Orlando, FL, November 18, 1992).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 107
compliance, range from 40 to 50 percent of the total

capital costs.120

Summary

The average capital cost of a CEM system is estimated

at $850,000 of which the equipment cost is $500,000. The

average annual operations and maintenance costs for a

CEM system is estimated at $425,000. While CEM

technology applications are relatively new, the lifetime

of such equipment is not well known. They probably

will have lifetimes shorter than most other plant

components. There are approximately 170 stacks on the

263 units affected in Phase I.121 Sometimes two or

more units are connected to the same stack, which may

necessitate a lesser or greater number of CEMs than

units, depending on the configuration of ducts from the

boilers to the stacks.

120Entropy Environmentalists, Inc., “Program Users Manual for Estimates of CEMs and Annual O&M Costs for New and Existing

Combustion Facilities,” report to the U.S. Environmental Protection Agency, (Research Triangle Park, NC, March 1991), p. 8-9; this report

assumes 50 percent. Most vendors contacted offered annual maintenance contracts for their systems at about 5 percent of its capital costs.

This figure includes only maintenance to the CEM hardware equipment provided by the vendor, not the other O&M costs for CAAA90

compliance. 121Energy Information Administration, Form EIA-767, “Steam-Electric Plant Operation and Design Report” (1991), and verbal

communications with various utilities owning Phase I affected units.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

108 Clean Air Act Amendments of 1990
Appendix G

Selection Process and

Data Collection

for Individual Utility

Compliance Costs and

Effects for CAAA90

Phase I
Appendix G

Selection Process and Data Collection for

Individual Utility Compliance Costs and Effects for

CAAA90 Phase I

Selection Process

Six utilities were chosen for detailed investigation.

Several characteristics were considered in choosing

these utilities: generating capacity, coal consumption,

sulfur dioxide (SO2) emissions, location, and initial

compliance strategy. The availability of information

from the utility was crucial for inclusion. The intent of

this sample is to provide information on compliance

costs for several different types of compliance strategies

and their effects on electricity generation and electricity

prices. This appendix includes cost estimates for Phase

I of the Clean Air Act Amendments of 1990 from the

selected utilities by unit (Tables G1 and G2).

The six utilities chosen were Illinois Power, Pennsylvania Power and Light, Potomac Electric Power,

Cincinnati Gas and Electric, Georgia Power, and

Southern Indiana Gas and Electric.

Data Collection

In general, the data collection involved contacting the

individual utilities to confirm their strategy for compliance with Phase I and obtaining cost estimates from

the utility for their compliance strategy. Unit data was

aggregated to utility level for Chapter 4. After these

estimates were received, the results were compiled and

provided to the utilities, which were asked for any

comments.

Georgia Power’s Bowen facility has the largest Phase I affected capacity at 3,499 megawatts.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 111
Table G1. Characteristics of Selected Phase I Affected Units by Utility

Unit Plant

Owning

Utilitya Stateb

Year

Online

Affected

Nameplate

Capacityc

(megawatts)

Allowancesd

(per year)

1985 SO2

Emissions

(tons)

Difference

Between

Base

Emissions &

Allotment

Total Phase I

Extension

Allowancese

1 Baldwin Illinois Powerg IL 1970 623 46,052 87,333 41,281 -- 

2 Baldwin Illinois Powerg IL 1973 635 48,695 92,715 44,020 -- 3 Baldwin Illinois Powerg IL 1975 635 46,664 88,825 42,161 0 2 Hennepin Illinois Powerg IL 1959 231 20,182 38,635 18,453 0 2 Vermilion Illinois Powerg IL 1956 109 9,735 17,076 7,341 -- 1 Brunner Island Pennsylvania P&L PA 1961 363 27,030 32,078 5,048 -- 2 Brunner Island Pennsylvania P&L PA 1965 405 30,282 34,103 3,821 3,426 3 Brunner Island Pennsylvania P&L PA 1968 790 52,404 58,775 6,371 16,334 1 Martins Creek Pennsylvania P&L PA 1954 156 12,327 14,627 2,300 -- 2 Martins Creek Pennsylvania P&L PA 1956 156 12,483 14,131 1,648 -- 3 Sunbury Pennsylvania P&L PA 1951 104 8,530 10,046 1,516 486 4 Sunbury Pennsylvania P&L PA 1953 156 11,149 14,077 2,928 8,140 1 Conemaugh* Pennsylvania P&L PA 1970 107 6,631 10,489 3,858 16,598 2 Conemaugh* Pennsylvania P&L PA 1971 107 7,639 10,229 2,859 13,916 ST1 Chalk Point Potomac Elec. Power MD 1964 364 21,333 20,258 -1,075 8,140 ST2 Chalk Point Potomac Elec. Power MD 1965 364 23,690 27,482 3,792 0 ST1 Morgantown Potomac Elec. Power MD 1970 626 34,332 29,388 -4,944 11,064 ST2 Morgantown Potomac Elec. Power MD 1971 626 37,467 37,988 521 16,250 1 Conemaugh* Potomac Elec. Power PA 1970 91 5,659 8,951 3,292 14,165 2 Conemaugh* Potomac Elec. Power PA 1971 91 6,289 8,729 2,440 11,876 5h Miami Fort Cincinnati G&E OH 1949 100 834 262 -572 -- 

6 Miami Fort Cincinnati G&E OH 1960 163 12,475 21,111 8,636 -- 7 Miami Fort* Cincinnati G&E OH 1975 357 27,018 39,972 12,954 -- 5 Beckjord Cincinnati G&E OH 1962 245 9,811 12,735 2,924 -- 6 Beckjord* Cincinnati G&E OH 1969 173 9,463 14,678 5,214 -- 4 Conesville* Cincinnati G&E OH 1973 337 21,385 39,302 17,917 -- 1 Bowen Georgia Power GA 1971 806 54,838 71,428 16,590 -- 2 Bowen Georgia Power GA 1972 789 53,329 63,727 10,398 -- 3 Bowen Georgia Power GA 1974 952 69,862 82,488 12,626 -- 4 Bowen Georgia Power GA 1975 952 69,852 87,659 17,807 -- 1 Hammond Georgia Power GA 1954 125 8,549 9,830 1,281 -- 2 Hammond Georgia Power GA 1954 125 8,977 9,997 1,020 -- 3 Hammond Georgia Power GA 1955 125 8,676 9,068 392 -- 4 Hammond Georgia Power GA 1970 578 36,650 35,539 -1,111 -- 1 McDonough Georgia Power GA 1963 299 19,386 32,738 13,352 27,391 2 McDonough Georgia Power GA 1964 299 20,058 33,749 13,691 -- 1 Wansley* Georgia Power GA 1976 509 36,866 68,750 31,884 -- 

2 Wansley* Georgia Power GA 1978 509 34,084 64,278 30,194 53,600 

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 112
Table G1. Characteristics of Selected Phase I Affected Units by Utility (Continued)

Unit Plant

Owning

Utilitya Stateb

Year

Online

Affected

Nameplate

Capacityc

(megawatts)

Allowancesd

(per year)

1985 SO2

Emissions

(tons)

Difference

Between

Base

Emissions &

Allotment

Total Phase I

Extension

Allowancese

1 Yatesi Georgia Power GA 1950 123 7,020 11,673 4,653 9,225 

2 Yates Georgia Power GA 1950 123 6,855 11,199 4,344 -- 3 Yates Georgia Power GA 1952 123 6,767 11,279 4,512 -- 4 Yates Georgia Power GA 1957 156 8,676 13,758 5,082 -- 5 Yates Georgia Power GA 1958 156 9,162 15,754 6,592 -- 6 Yates Georgia Power GA 1974 404 24,108 42,207 18,099 9,236 7 Yates Georgia Power GA 1974 404 20,915 23,974 3,059 2,806 1 Gaston* Georgia Power AL 1960 136 8,812 11,110 2,298 -- 2 Gaston* Georgia Power AL 1960 136 9,026 10,931 1,905 -- 3 Gaston* Georgia Power AL 1961 136 8,914 11,685 2,771 -- ST4 Gaston* Georgia Power AL 1962 122 9,387 11,743 2,356 -- 2 Culleyj Southern Indiana G&E IN 1966 104 4,703 16,361 11,658 0 3 Culleyj Southern Indiana G&E IN 1973 265 18,603 38,456 19,853 0 

4 Warrick* Southern Indiana G&E IN 1970 162 14,789 29,407 14,618 0 

aThe full utility names are: Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, Cincinnati Gas & Electric Company, Georgia Pow

Gas & Electric Company. bState codes are postal codes.

cAffected capacity at each unit is only that share owned by indicated utility.dOne SO2 allowance permits one ton of SO2 emissions. ePhase I extension allowances were awarded to (1) control units that install a technology that removes 90 percent or more of their SO2 emissions or (2) control units and other u

strategy but are associated with the control unit in the extension allowance application. Extension allowances were awarded for 1995 through 1999. fNumber of units retrofitted with low-NOx burners and number of CEMs may be fractional because of partial unit ownership by utility. Also, number of CEMs may not equal numbe

duct and stack configuration. gIllinois Power is also a part owner of Joppa Steam, an affected Phase I plant. Because Joppa Steam is not included in Illinois Power’s ratebase, it is not included here. hMiami Fort 5 has two boilers.

iIncludes only one-half of scrubber capital costs. The other half is paid by the Department of Energy as a demonstration project.jCEM operation and maintenance costs includes $30,000 of NOx fuel costs.

SO2 = Sulfur dioxide.

NOx = Nitrogen oxides.

CEM = Continuous emission monitor.* = Partially owned unit.Note: All data are for the portion of the unit that is owned by the designated utility. Does not include substitution and compensating units.Source: Based on information from Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power, and Southern Indiana Gas 

March 1994).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 113
Table G2. Costs and Effects of Phase I Compliance for Selected Affected Units by Utility

Unit Plant

SO2 Control

NOx

Control

Capital

Costs

(million

dollars)

CEMs

Total

Capital

Costs

(million

dollars)

Annual

Capital

Costs

(million

dollars)

AnnualO&M &

Fuel

Costs

(million

dollars)

Annual

Total

Costs

(million

dollars)

Averag

Capita

Costs

(dollar

per

affecte

kilowa

Capital

Costs

(million

dollars)

O&M

Costs

(million

dollars)

Fuel

Premium

(million

dollars)

Capital

Costs

(million

dollars)

O&M

Costs

(million

dollars)

1 Baldwin 0.0 8.3 0.0 0.0 1.4 0.1 1.4 0.1 8.4 8.5 2.3 2 Baldwin 0.0 8.8 0.0 0.0 1.3 0.1 1.3 0.1 8.9 9.0 2.1 3 Baldwin 0.0 8.4 0.0 7.8 1.1 0.1 8.9 0.6 8.5 9.1 14.1 2 Hennepin 0.0 3.7 0.0 1.6 4.1 0.3 5.7 0.4 4.0 4.4 24.7 2 Vermilion 0.0 1.5 0.0 4.1 1.9 0.3 6.0 0.4 1.8 2.2 55.1 1 Brunner Island 0.0 a b 13.0 0.8 a 13.8 0.9 0.0 0.9 37.9 

2 Brunner Island 3.0 a b 15.0 0.8 a 18.8 1.3 0.0 1.3 46.3 3 Brunner Island 0.0 a b 17.0 1.5 a 18.5 1.2 0.0 1.2 23.4 1 Martins Creek 2.0 a b 6.0 0.8 a 8.8 0.6 0.0 0.6 56.4 

2 Martins Creek 2.0 a b 5.0 0.8 a 7.8 0.5 0.0 0.5 50.0 3 Sunbury 1.5 a a 5.0 1.5 a 8.0 0.5 0.0 0.5 76.4 4 Sunbury 1.7 a a 5.3 1.5 a 8.5 0.6 0.0 0.6 54.2 1 Conemaugh* 19.0 1.1 b 2.2 0.1 0.0 21.2 1.4 1.1 2.5 198.7 

2 Conemaugh* 19.0 1.1 b 2.2 0.1 0.0 21.2 1.4 1.1 2.5 198.7 

ST1 Chalk Point 15.0 a 0.0 25.3 1.6 a 41.9 2.8 0.0 2.8 115.0 

ST2 Chalk Point 15.0 a 0.0 25.3 1.6 a 41.9 2.8 0.0 2.8 115.0 ST1 Morgantown 0.0 a 0.0 47.2 3.1 a 50.3 3.4 0.0 3.4 80.4 ST2 Morgantown 0.0 a 0.0 47.2 3.1 a 50.3 3.4 0.0 3.4 80.4 

1 Conemaugh* 16.2 0.9 0.0 2.0 0.1 0.0 18.3 1.2 0.9 2.1 201.0 2 Conemaugh* 16.2 0.9 0.0 2.0 0.1 0.0 18.3 1.2 0.9 2.1 201.0 5 Miami Fort 1.4 a 0.5 0.0 0.4 a 1.8 0.1 0.5 0.6 18.0 

6 Miami Fort 2.2 a 0.8 0.0 0.4 a 2.7 0.2 0.8 1.0 16.3 7 Miami Fort* 4.9 a 1.8 0.0 0.5 a 5.4 0.4 1.8 2.2 15.2 5 Beckjord 5.3 a 1.2 4.7 0.7 a 10.7 0.7 1.2 2.0 43.6 

6 Beckjord* 3.7 a 0.9 3.4 0.2 a 7.3 0.5 0.9 1.4 42.4 

4 Conesville* 0.0 3.6 0.0 0.0 0.5 a 0.5 0.0 3.6 3.6 1.4 1 Bowen 3.3 0.0 0.0 11.7 1.3 a 16.4 1.1 0.0 1.1 20.3 

2 Bowen 3.2 0.0 0.0 11.5 1.3 a 16.1 1.1 0.0 1.1 20.4 3 Bowen 3.9 0.0 0.0 13.8 1.3 a 19.1 1.3 0.0 1.3 20.1 4 Bowen 3.9 0.0 0.0 13.8 1.3 a 19.1 1.3 0.0 1.3 20.1 1 Hammond 1.7 0.0 0.0 7.5 0.5 a 9.7 0.6 0.0 0.6 77.5 

2 Hammond 1.7 0.0 0.0 7.5 0.5 a 9.7 0.6 0.0 0.6 77.5 3 Hammond 1.7 0.0 0.0 7.5 0.5 a 9.7 0.6 0.0 0.6 77.5 4 Hammond 7.7 0.0 0.0 34.9 0.5 a 43.1 2.9 0.0 2.9 74.5 

1 McDonough 2.7 0.0 0.0 7.7 0.9 a 11.2 0.7 0.0 0.7 37.4 

2 McDonough 2.7 0.0 0.0 7.7 0.9 a 11.2 0.7 0.0 0.7 37.4 

See footnotes at end of table.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 114
Table G2. Costs and Effects of Phase I Compliance for Selected Affected Units by Utility (Continued)

Unit Plant

SO2 Control

NOx

Control

Capital

Costs

(million

dollars)

CEMs

Total

Capital

Costs

(million

dollars)

Annual

Capital

Costs

(million

dollars)

AnnualO&M &

Fuel

Costs

(million

dollars)

Annual

Total

Costs

(million

dollars)

Averag

Capita

Costs

(dollar

per

affecte

kilowa

Capital

Costs

(million

dollars)

O&M

Costs

(million

dollars)

Fuel

Premium

(million

dollars)

Capital

Costs

(million

dollars)

O&M

Costs

(million

dollars)

1 Wansley* 4.3 0.0 0.0 9.7 1.1 a 15.1 1.0 0.0 1.0 29.6 

2 Wansley* 4.3 0.0 0.0 9.7 1.1 a 15.1 1.0 0.0 1.0 29.6 1 Yatesc 17.0 1.8 0.7 1.6 0.6 a 19.3 1.3 2.5 3.8 157.4 2 Yates 1.8 0.0 0.0 1.6 0.6 a 4.1 0.3 0.0 0.3 33.5 

3 Yates 1.8 0.0 0.0 1.6 0.6 a 4.1 0.3 0.0 0.3 33.5 4 Yates 2.3 0.0 0.0 2.1 0.6 a 5.1 0.3 0.0 0.3 32.4 5 Yates 2.3 0.0 0.0 2.1 0.6 a 5.1 0.3 0.0 0.3 32.4 6 Yates 6.0 0.0 0.0 5.4 0.6 a 12.1 0.8 0.0 0.8 29.9 

7 Yates 6.0 0.0 0.0 5.4 0.6 a 12.1 0.8 0.0 0.8 29.9 1 Gaston* 0.0 0.0 0.0 1.9 0.1 b 2.0 0.1 0.0 0.1 14.9 

2 Gaston* 0.0 0.0 0.0 2.9 0.1 b 3.0 0.2 0.0 0.2 21.8 3 Gaston* 0.0 0.0 0.0 6.5 0.1 b 6.6 0.4 0.0 0.4 48.6 

ST4 Gaston* 0.0 0.0 0.0 3.5 0.1 b 3.6 0.2 0.0 0.2 29.1 

2 Culleyd 30.1 0.0 0.0 1.4 0.8 0.1 32.2 2.1 0.0 2.2 310.8 

3 Culleyd 76.9 -0.1 0.0 3.6 0.8 0.1 81.3 5.4 0.0 5.4 306.4 4 Warrick* 0.0 1.4 0.0 0.0 1.3 0.0 1.3 0.1 1.5 1.6 8.0 

aCost not estimated by utility.bEstimated to be negligible by utility.cIncludes only one-half of scrubber capital costs. The other half is paid by the Department of Energy as a demonstration project.dCEM operations and maintenance costs include $30,000 of NOx fuel costs.

SO2 = Sulfur dioxide.

NOx = Nitrogen oxides.

CEM = Continuous emission monitor.O&M = Operations and maintenance.* = Partially owned unit.Notes: •These are contemporary estimates made by the individual utilities; most dollars are adjusted to 1993. •All data are for the portion of the unit that is owned by the des

is depreciated over 15 years. •The estimates underestimate the cost of compliance to the extent that no cost estimate has been made in some cases.

Source: Based on information from Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power, and Southern Indiana Gas 

March 1994).

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 115
Glossary

Acid Rain: Also called acid precipitation or acid

deposition, acid rain is precipitation containing harmful

amounts of nitric and sulfuric acids formed primarily

by nitrogen oxides and sulfur oxides released into the

atmosphere when fossil fuels are burned. It can be wet

precipitation (rain, snow, or fog) or dry precipitation

(absorbed gaseous and particulate matter, aerosol

particles or dust). Acid rain has a Ph below 5.6. Normal

rain has a pH of about 5.6, which is slightly acidic. The

term pH is a measure of acidity or alkalinity and ranges

from 0 to 14. A pH measurement of 7 is regarded as

neutral. Measurements below 7 indicate increased

acidity, while those above indicate increased alkalinity.

Allowance: One SO2 allowance permits one ton of SO2

emissions.

Anthracite: A hard, black lustrous coal, often referred

to as hard coal, containing a high percentage of fixed

carbon and a low percentage of fixed volatile matter.

Ash: Impurities consisting of silica, iron, alumina, and

other noncombustible matter that are contained in coal.

Ash increases the weight of the coal, adds to the cost of

handling, and can affect its burning characteristics. Ash

content is measured as a percent by weight of coal on

an “as received” or a “dry” (moisture-free, usually part

of a laboratory analysis) basis.

Ash Fusion Temperature: The temperature at which

ash from coal melts.

Bituminous Coal: The most common coal. It is dense

and black (often with well-defined bands of bright and

dull material). Its moisture content usually is less than

20 percent. It is used for generating electricity, making

coke, and space heating.

Boiler: A device for generating steam for power,

processing, or heating purposes or for producing hot

water for heating purposes or hot water supply. Heat

from an external combustion source is transmitted to a

fluid contained within the tubes in the boiler shell. This

fluid is delivered to an end-use at a desired pressure,

temperature, and quality.

Btu (British Thermal Unit): A standard unit for measuring the quantity of heat energy equal to the quantity

of heat required to raise the temperature of 1 pound of

water by 1 degree Fahrenheit.

CAAA90: The Clean Air Act Amendments of 1990.

Capital Costs: The costs of the long-term productive

assets of a utility.

Coal: A black or brownish-black solid combustible

substance formed by the partial decomposition of

vegetable matter without access to air. The rank of coal,

which includes anthracite, bituminous coal,

subbituminous coal, and lignite, is based on fixed

carbon, volatile matter, and heating value. Coal rank

indicates the progressive alternation from lignite to

anthracite. Lignite contains approximately 9 to 17

million Btu per ton. The contents of subbituminous and

bituminous coal range from 16 to 24 million Btu per ton

and from 19 to 30 million Btu per ton, respectively.

Anthracite contains approximately 22 to 28 million Btu

per ton.

Low-sulfur coal: The EIA sulfur content category of

coal with less than 0.60 pounds of sulfur per

million Btu.

Medium-sulfur coal: The EIA sulfur content

category of coal with 0.60 to 1.67 pounds of sulfur

per million Btu.

High-sulfur coal: The EIA sulfur content category

of coal with greater than 1.67 pounds of sulfur per

million Btu.

Consumption (Fuel): The amount of fuel used for

gross generation, providing standby service, start-up

and/or flame stabilization.

Continuous Emission Monitor (CEM): A device which

approximates a continuous measurement of certain

characteristics of a gas by making separate measurements frequently. For compliance with the CAAA90,

the measurements must be taken at least every 15

minutes.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 117
Extractive Continuous Emission Monitor: A CEM

that draws exhaust gas away from the combustion system to the measurement equipment

through special ducts.

In Situ Continuous Emission Monitor: A CEM that

makes measurements directly in the flue or

exhaust pipe.

Cost: The amount paid to acquire resources, such as

plant and equipment, fuel, or labor services.

Demand-Side Management: The planning, implementation, and monitoring of utility activities that are

designed to influence consumer use of electricity in

ways that will produce desired changes in a utility’s

load shape, including direct Load Control, Interruptible

Load, and Conservation and Other Demand-Side

Management categories. Demand-Side Management

includes utility-administered programs that are

designed to reduce load growth, and any other

programs designed for strategic load growth.

Dry Dust Baghouse Collector: A fabric filter which

collects the dry particulate matter as the cooled flue gas

passes through the filter material.

Electric Utility: A corporation, person, agency, authority, or other legal entity or instrumentality that owns

and/or operates facilities within the United States, its

territories, or Puerto Rico for the generation, transmission, distribution, or sale of electric energy primarily

for use by the public and files forms listed in the Code

of Federal Regulations, Title 18, Part 141. Facilities that

qualify as cogenerators or small power producers under

the Public Utility Regulatory Policies Act (PURPA) are

not considered electric utilities.

Electrostatic Precipitator: A unit comprised of a series

of parallel vertical plates through which the flue gas

passes. It electrically charges the ash particles in the

flue gas to collect and remove them.

Energy: The capacity for doing work as measured by

the capability of doing work (potential energy) or the

conversion of this capability to motion (kinetic energy).

Energy has several forms, some of which are easily

convertible and can be changed to another form useful

for work. Most of the world’s convertible energy comes

from fossil fuels that are burned to produce heat that is

then used as a transfer medium to mechanical or other

means in order to accomplish tasks. Electrical energy is

usually measured in kilowatthours, while heat energy

is usually measured in British thermal units.

Facility: An existing or planned location or site at

which prime movers, electric generators, and/or

equipment for converting mechanical, chemical, and/or

nuclear energy into electric energy are situated, or will

be situated. A facility may contain more than one

generator of either the same or different prime mover

type.

Federal Energy Regulatory Commission (FERC): A

quasi-independent regulatory agency within the

Department of Energy having jurisdiction over

interstate electricity sales, wholesale electric rates,

hydroelectric licensing, natural gas pricing, oil pipeline

rates, and gas pipeline certification.

Flue Gas Desulfurization Unit (Scrubber): Equipment

used to remove sulfur oxides from the combustion

gases of a boiler plant before discharge to the

atmosphere. Chemicals, such as lime, are used as the

scrubbing media.

Flue Gas Particulate Collectors: Equipment used to

remove fly as from the combustion gases of a boiler

plant before discharge to the atmosphere. Particulate

collectors include electrostatic precipitators, mechanical

collectors (cyclones), fabric filters (baghouses), and wet

scrubbers.

Fly Ash: Particule matter from coal ash in which the

particle diameter is less that 1 x 10-4 meter. This is

removed from the flue gas using flue gas particulate

collectors such as fabric filters and electrostatic

precipitators.

Fossil Fuel: Any naturally occurring organic fuel, such

as petroleum, coal, and natural gas.

Fouling: The formation of high temperature bonded

deposits on convective heat absorbing surfaces that are

not exposed to radiant heat.

Fuel Expenses: These costs include the fuel used in the

production of steam or driving another prime mover

for the generation of electricity. Other associated

expenses include unloading the shipped fuel and all

handling of the fuel up to the point where it enters the

first bunker, hopper, bucket, tank, or holder in the

boiler-house structure.

Generating Unit: Any combination of physically

connected generator(s), reactor(s), boiler(s), combustion

turbine(s), or other prime mover(s) operated together to

produce electric power.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

118 Clean Air Act Amendments of 1990
Generation (Electricity): The process of producing

electric energy from other forms of energy; also, the

amount of electric energy produced, expressed in

watthours (Wh).

Gross Generation: The total amount of electric

energy produced by the generating units at a

generating station or stations, measured at the

generator terminals.

Net Generation: Gross generation less the electric

energy consumed at the generating station for

station use.

Generator: A machine that converts mechanical energy

into electrical energy.

Generator Nameplate Capacity: The full-load continuous rating of a generator, prime mover, or other

electric power production equipment under specific

conditions as designated by the manufacturer. Installed

generator nameplate rating is usually indicated on a

nameplate physically attached to the generator.

Gigawatt (GW): One billion watts of capacity.

Hardgrove Grindability Index (HGI): A measure of

the relative ease with which coal can be pulverized or

ground. Higher grindability indicates coal which are

easier to grind.

Kilowatt (kW): One thousand watts of capacity.

Kilowatthour (kWh): One thousand watthours.

Lignite: A brownish-black coal of low rank with high

inherent moisture and volatile matter (used almost

exclusively for electric power generation). It is also

referred to as brown coal.

Low-NOx Burners: Burners that utilize special arrangements of fuel and air injection ports, which reduce the

formation of NOx during combustion.

Megawatt (MW): One million watts of capacity.

Megawatthour (MWh): One million watthours of

electric energy.

NOx: Nitrogen oxides.

Natural Gas: A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in porous

geological formations beneath the earth’s surface, often

in association with petroleum. The principal constituent

is methane.

Opacity: The degree of imperviousness to the passage

of light.

Operations and Maintenance Costs: Operations costs

are the components of power production that incur cost

for operations that are directly related to producing

electricity. The major item is almost always fuel that

has to be burned to generate the electricity. Maintenance costs are the portion of operating expenses

consisting of labor, materials, and other direct and

indirect expenses incurred for preserving the operating

efficiency and/or physical condition of utility plants

used for power production, transmission, and distribution of energy.

Petroleum: A mixture of hydrocarbons existing in the

liquid state found in natural underground reservoirs,

often associated with gas. Petroleum includes fuel oil

No. 2, No. 4, No. 5, No. 6; topped crude; Kerosene; and

jet fuel.

Petroleum (Crude Oil): A naturally occurring, oily,

flammable liquid composed principally of hydrocarbons. Crude oil is occasionally found in springs or

pools but usually is drilled from wells beneath the

earth’s surface.

Plant: A facility at which are located prime movers,

electric generators, and auxiliary equipment for

converting mechanical, chemical, and/or nuclear energy

into electric energy. A plant may contain more than one

type of prime mover. Electric utility plants exclude

facilities that satisfy the definition of a qualifying

facility under the Public Utility Regulatory Policies Act

of 1978.

Plant-Use Electricity: The electric energy used in the

operation of a plant. This energy total is subtracted

from the gross energy production of the plant; for

reporting purposes the plant energy production is then

reported as a net figure. The energy required for

pumping-storage plants is, by definition, subtracted,

and the energy production for these plants is then

reported as a net figure.

Pulverizers: Mills of various designs used to finely

grind the coal which is swept from the mills by air for

pneumatic transport directly to the burners.

SO2: Sulfur dioxide.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990 119
Slagging: The formation of molten, partially fused

resolidified deposits on furnace walls or other surface

exposed to radiant heat.

Subbituminous Coal: A dull black coal of rank

intermediate between lignite and bituminous.

Sulfur: One of the elements present in varying

quantities in coal which contributes to environmental

degradation when coal is burned. In terms of sulfur

content by weight, coal is generally classified as low

(less than or equal to 1 percent), medium (greater than

1 percent and less than or equal to 3 percent), and high

(greater than 3 percent). Sulfur content is measured as

a percent by weight of coal on an “as received” or a

“dry” (moisture-free, usually part of a laboratory

analysis) basis.

Watthour (Wh): An electrical energy unit of measure

equal to 1 watt of power supplied to, or taken from, an

electric circuit steadily for 1 hour.

Energy Information Administration/ Electric Utility Phase I Acid Rain Compliance Strategies for the

120 Clean Air Act Amendments of 1990