DOE/EIA-0582(97)

Distribution Category UC-950

The Effects of Title IV of the Clean Air Act Amendments

of 1990 on Electric Utilities: An Update

March 1997

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.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

ii on Electric Utilities: An Update

Contacts

This report was prepared by the staff of the Coal and bobrien@eia.doe.gov). Specific questions regarding the

Electric Analysis Branch , Analysis and Systems Division, preparation and content of the report should be directed

Office of Coal, Nuclear, Electric and Alternate Fuels. to Art Fuldner, project manager (202/426-1125, or e-mail

General information regarding this publication may be at afuldner@eia.doe.gov), or contributing authors Ronald

obtained from Robert M. Schnapp, Director, Analysis and Hankey (202/426-1188, or e-mail at rhankey@eia.

Systems Division (202/426-1211, or e-mail at doe.gov), William Liggett (202/426-1139, or e-mail at

rschnapp@eia.doe.gov) or Betsy O’Brien, Chief, Coal and wliggett@eia.doe.gov), and Thelda McMillian (202/426-

Electric Analysis Branch (202/426-1180, or e-mail at 1127, or e-mail at tmcmilli@eia.doe.gov).
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update iii

Preface

Section 205(a)(2) of the Department of Energy Organ- will be listed in the “Publications” section. The

ization Act of 1977 (Public Law 95-91) requires the “Applications” section can be reached by scrolling down

Administrator of the Energy Information Administration through the “Data” section. From this point, the Clean Air

(EIA) to carry out a central, comprehensive, and unified Act browser can be downloaded. The browser has

energy data information program that will collect, information about compliance activities, fuel shifts,

evaluate, assemble, analyze, and disseminate data and emissions, allowance allocations, and scrubbers.

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, The Effects of Title IV of the Clean Air

Act Amendments of 1990 on Electric Utilities: An Update.

Additional copies of this report can be downloaded from

EIA’s home page on the World Wide Web

(http://www.eia.doe.gov). After contacting the home

page, click on “Electricity” in Fuel Groups. This report

The legislation that created EIA vested the organization

with an element of statutory independence. The EIA does

not take positions on policy questions. Its 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 by 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/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update v

Contents

Page

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

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

SO Compliance Results in 1995 2 ........................................................................ 4

Contents of This Report ............................................................................... 4

2. Phase I Effects on Utilities ............................................................................. 5

Compliance Options for Phase I ....................................................................... 5

Compliance Methods Chosen ......................................................................... 5

Electric Utility Compliance Strategies, Costs, and Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

3. Phase I Effects on Coal Supply and Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Compliance and Fuel Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Compliance and Coal Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Compliance and Coal Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4. Developments Since Phase I Took Effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Programs for the Control of Nitrogen Oxides Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Discussion of Air Toxics–Title III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Technology Refinements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

5. Phase II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Current Strategies for Phase II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Synergy With Clean Air Act Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Utility Compliance Plans on the Internet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

6. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Appendices

A. Federal Legislation To Control Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

B. Profiles of the 261 Table 1 Generators Affected by Phase I (Table B1) and a Profile of the

Coal Received at Table 1 Plants (Table B2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

C. Cost and Characteristics of Selected Phase I Units, by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

vi on Electric Utilities: An Update

Tables Page

1. SO Emissions From Electric Utilities, 1985, 1990, 1994, and 1995 2 ......................................... 4

2. Profile of Compliance Methods for Table 1 Units ....................................................... 6

3. PEPCO’s 1995 Allowance Totals ...................................................................... 9

4. Scrubber Retrofits for Compliance With Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

5. Annualized SO Compliance Cost for CAAA90 Title IV 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

6. Characteristics of Selected Phase I Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

7. Costs of Phase I Compliance for Selected Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

8. Costs and Quality of Fuels for Selected Electric Utility Phase I Plants, 1985, 1990, and 1995 . . . . . . . . . . . . . . . . 16

9. Average Delivered Cost of Low-Sulfur Coal by Origin State, 1985, 1990, and 1995 . . . . . . . . . . . . . . . . . . . . . . . . 23

10. Coal Production by State, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

11. Coal Receipts at Electric Utility Plants by Supply Region and Sulfur Dioxide Level, 1990 and 1995 . . . . . . . . . 26

12. The Number of Mines and the Average Number of Miners Working Daily by State for 1990 and 1995 . . . . . . 36

13. Phase II, Group 1 and Group 2 Boiler Statistics and Emission Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

14. Fossil Units Proposed for Repowering, 1996-2005, as of January 1, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

15. U.S. Electric Utility Planned Coal-, Petroleum-, and Gas-Fired Capacity Retirements, 1996-2005,

as of January 1, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

A1. Chronology of Historic Federal Legislation To Control Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

B1. Profile of the 261 Table 1 Generators Affected by Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

B2. Profile of Coal Received at Table 1 Plants, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

C1. Characteristics of Selected Phase I Units, by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

C2. Cost of Phase I Compliance for Selected Units, by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

Figures

1. Table 1 Unit Emissions, 1985 and 1995 ................................................................ 2

2. Substitution and Compensating Unit Emissions, 1985 and 1995 .......................................... 3

3. 1996 SO Emission Allowance (Spot Market) Supply and Demand at the EPA Auction, March 1996 2 .......... 8

4. Cumulative Investments in Air Pollution Control Facilities by U.S. Major Investor-Owned Utilities,

1986-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. Total Investments in Air Pollution Control Facilities by Major Investor-Owned Utilities,

by NERC Region, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

6. Average Price of Electricity for Six Utilities, 1990-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

7. Coal Produced in Wyoming and Delivered to Electric Utilities, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

8. Coal Demand Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

9. Origin of Coal Received in Illinois, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

10. Origin of Coal Received in Indiana, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

11. Origin of Coal Received in Missouri, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

12. Origin of Coal Received in Michigan, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

13. Origin of Coal Received in Ohio, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

14. Origin of Coal Received in Pennsylvania, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

15. Origin of Coal Received in New York, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

16. Origin of Coal Received in West Virginia, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

17. Origin of Coal Received in Kentucky, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

18. Origin of Coal Received in Georgia, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

19. Origin of Coal Received in Tennessee, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

20. Average Age (Weighted by Capacity) of Fossil-Fuel Units, 1990, 2000, and 2010, as of January 1, 1996 . . . . . . 48

21. Electric Power Regulations Timeline for Provisions Enacted Through the Clean Air Act . . . . . . . . . . . . . . . . . . . 53
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update vii

Phase I affects 435 generating units powered by 445 boilers. Title IV states that 261 generating units are to be covered in Phase I of the 1

program as Table A units (subsequently referred to in EPA’s regulations as Table 1 units). These 261 generators are attached to 263 boiler units.

Miami Fort generator 5 has two boilers. R.E. Burger generator 3 has two boilers. Similarly, the 182 boilers brought into Phase I as substitution

and compensating units are attached to 174 generators. 

Executive Summary

The Clean Air Act Amendments of 1990 address allowances to comply with Title IV in 1995. By comnumerous air quality problems in the United States that plying with Title IV, Phase I units significantly reduced

were not entirely covered in earlier legislation. One of their SO emissions compared to previous years; they

these problems is acid rain caused by sulfur dioxide (SO ) emitted 5.3 million tons of SO in 1995, 45 percent less 2

and nitrogen oxides (NO ) emissions from fossil-fueled than the 9.7 million tons emitted in 1990, and 34 percent x

electric power plants and, to a lesser extent, from other lower than the 8.0 million tons emitted in 1994. In

industrial and transportation sources. contrast, non-Phase I units emitted 6.6 million tons in

Title IV of the Act created a two-phased plan, administered by the U.S. Environmental Protection Agency

(EPA), to reduce acid rain in the United States. Phase I

runs from 1995 through 1999, and Phase II, which is more

stringent than Phase I, begins in 2000. Title IV contains a

table listing 261 generating units that are required to

comply with Phase I. They are generally referred to by

EPA as Table 1 units. Most of these units are coal fired

with relatively high emissions. An additional 174 units

are participating in Phase I based on the rules established

by EPA, allowing a utility to designate substitution or

compensating units as part of their Phase I compliance

plans. Therefore, 435 units are now considered Phase I 1

units. More than 2,000 units will be affected by Phase II.

This report updates and expands a report published by

the Energy Information Administration in 1994 titled,

Electric Utility Phase I Acid Rain Compliance Strategies for the

Clean Air Act Amendments of 1990; it describes the

strategies used to comply with the Acid Rain Program in

1995, the effect of compliance on SO emissions levels, the 2

cost of compliance, and the effects of the program on coal

supply and demand.

SO Emissions Compliance Results in 1995 substituting Phase II units for Phase I units, and (8) com- 2

The acid rain program allocated emissions allowances to

Phase I units, authorizing them to emit one ton of SO for 2

each allowance. Some utilities obtained additional

allowances from three auctions and from bonus provisions in the Act. All 435 generating units had sufficient

2

2

1995, 12 percent higher than the 5.9 million tons they

emitted in 1990, and 5 percent higher than the 6.3 million

tons they emitted in 1994.

Estimated SO Compliance Costs 2

Industry-wide annualized compliance costs are estimated

at $836 million (1995 dollars). These costs represent only

0.6 percent of the $151 billion electric operating expenses

of investor-owned utilities in 1995. Using scrubbers is

estimated to cost $322 per ton of SO removal and is the 2

most expensive compliance method. Modifying a high

sulfur bituminous coal-fired plant to burn lower sulfur

subbituminous coal, which is estimated to cost $113 per

ton of SO removal, is the least expensive. 2

Compliance Methods Used by Table 1 Units

in 1995

A utility could use one or more of the following compliance methods: (1) fuel switching and/or fuel blending

with lower sulfur coal, (2) obtaining additional allowances, (3) installing flue gas desulfurization equipment

(i.e., scrubbers), (4) using previously implemented emissions controls, (5) retiring units, (6) boiler repowering, (7)

pensating Phase I units with Phase II units. Most utilities

(52 percent of Table I units) used fuel switching and

blending in 1995 (Figure ES1). This method accounted for

59 percent of the reduction in SO emissions in 1995 2

compared to 1985 (Figure ES2). Competitive prices of

lower sulfur coal, low shipping costs, lower than expected
Fuel Switch 52

Allowances 32

Scrubbers 10

Other 3

Retired 3

b

Total 

Generating 

Units: 261

Fuel Switch 59

Scrubbers 28

Allowances 9

Retired 2

Other 2 b

c

SO2 Emissions

(million tons)

1985 -- 9.3

1995 -- 4.4

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

viii on Electric Utilities: An Update

Continuous emissions monitors were required to be operational on November 15, 1993 for Phase I units and on January 1, 1995 for Phase 2

II units (with the exception of NO /CO at oil- and gas-fired units). x 2

Figure ES1. Compliance Methods Used by

Table 1 Units in 1995a

(Percent of Table 1 Units)

Does not include 174 substitution and compensating a

units.

Includes switching to natural gas or petroleum and b

repowering. 

Source: Energy Ventures Analysis, Inc., The Utility

Report, December 1995.

Does not include 174 substitution and compensating units. a

Includes switching to natural gas or petroleum and b

repowering.

Nine percent of the 1995 SO emissions reductions were at c

2

units that used allowances as their compliance method. The

average sulfur content of coal consumed by these units was

reduced by 16 percent from 1985 to 1995.

SO = Sulfur dioxide. 2

Note: Percent reductions of SO emissions were computed 2

using 1985 as the base year.

Source: 1985 Emissions: U.S. Environmental Protection

Agency, National Allowance Data Base, Version 2.11 (January

1993). 1995 Emissions: Acid Rain Division, U.S. Environmental Protection Agency.

Figure ES2. SO Reductions by Compliance 2

Method at Table 1 Units in 1995 a

(Percent of SO Reductions) 2

costs for boiler modifications, and little deterioration in

plant performance with lower sulfur coal were the reasons

most utilities switched to lower sulfur coal. Also, because

the industry is restructuring for competition, some utilities

are reluctant to commit funds for more expensive solutions. For instance, scrubbers, which are relatively expensive, were chosen by only 10 percent of Table 1 units.

Effects of Compliance on Regional Coal

Supply and Demand

Because fuel switching has been the compliance method

used by most utilities, lower sulfur coal sales in the United

States have increased substantially. In 1990, for example,

low-to-medium sulfur coal accounted for 67 percent of Compliance strategies and costs were examined in detail

total coal receipts at electric utilities, increasing to 77 for six utilities with a total of 71 units (22.8 gigawatts of

percent by 1995 (Figure ES3). This switch to lower sulfur generating capacity) affected by Phase I. Most of the units

coal has affected regional coal distribution patterns. were switched to lower sulfur coal to meet their SO

Between 1990 and 1995, sales of low-to-medium sulfur emissions limitations. A few scrubbers were installed, but

coal from the Powder River basin (Wyoming and they were expensive relative to other compliance stratMontana) increased by 78 million tons; sales from the egies. Substitution units, which in most instances gencentral Appalachian region (Virginia, eastern Kentucky, erated extra emissions allowances, were used extensively

and southern West Virginia) increased by 15 million tons; by these utilities. Although the compliance costs repreand sales from the Rocky Mountains (Colorado and Utah), sented a relatively small percentage of the utilities’ total

increased by 10 million tons. In contrast, for the same costs, the costs varied widely among the six. Average

period, sales of higher sulfur coal from the northern costs for SO and NO controls and continuous emissions

Appalachian region (Maryland, Pennsylvania, Ohio, and monitoring systems ranged from a low of $16.39 per

northern West Virginia) decreased 29 million tons; and

sales from the Illinois basin (Illinois, Indiana, and Western

Kentucky) decreased by 40 million tons.

Compliance Strategies and Costs of Six

Utilities

2

2 x

2
1990 1995

0

20

40

60

80

100

Percent

 Low-to-Medium Sulfur High Sulfur

827 Million 

Tons

787 Million 

Tons

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update ix

Figure ES3. U.S. Coal Receipts at Electric Utility

Plants by Sulfur Level, 1990 and 1995

(Percent)

 Note: High sulfur level is greater than 2.5 pounds of sulfur per

million Btu. Low-to-medium sulfur level is less than or equal to

2.5 pounds of sulfur per million Btu.

 Source: Federal Energy Regulatory Commission, Form 423,

“Monthly Report of Cost and Quality of Fuels for Electric Plants.”

kilowatt at Cincinnati Gas & Electric to $208.90 per

kilowatt at Southern Indiana Gas and Electric Company.

Annual operation and maintenance costs (which in this

analysis are primarily allowance purchases) ranged from

a high of $19.4 million at Illinois Power to a low of $1.8

million at Potomac Electric Power Company. Depreciating capital costs over 15 years results in annual capital

costs ranging from just over $1 to almost $14 per kilowatt

of Phase I capacity.

Phase II Compliance Strategies

To meet stronger emissions limits under Phase II, some

utilitiesare planning ahead by overcomplying in Phase I.

For example, some utilities are installing scrubbers now

instead of using a less expensive option. Many utilities

have not finalized their Phase II compliance plans. One

survey of 116 utilities conducted by the Industrial

Information Services Company found that 41 percent of

the respondents will switch fuels for Phase II and 28

percent will acquire additional emission allowances. For

many utilities, fuel switching has proved to be the most

cost-effective choice in Phase I, and many of them will

probably continue this strategy in Phase II. For utilities

selecting allowances as a strategy for Phase II, extra

allowances can be obtained from numerous sources.

Utilities receiving extra allowances for installing scrubbers

or for complying earlier than required are selling some of

their allowances at relatively low prices. Some higher

sulfur coal producers have bundled emissions allowances

with their sales to help maintain their customer base. It is

estimated that only 12 to 20 gigawatts of capacity may be

scrubbed to comply with Phase II because a number of

utilities that had originally planned to install scrubbers

have either deferred installation, or canceled them in

favor of fuel switching or purchasing allowances.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 1

Environmental Protection Agency, Allowance System, Proposed Acid Rain Rule, 400/1-91/034 (Washington, DC, December 1991), p.1. 1

Phase I affects 445 boiler units that are associated with 435 generating units. CAAA90 explicitly states that 261 generating units are to 2

be covered in Phase I of the program as Table A units (subsequently referred to in EPA’s regulations as Table 1 units). These 261 generators

are attached to 263 boilers. Miami Fort generator 5 has two boilers. R.E. Burger generator 3 has two boilers. Similarly, the 182 boilers brought

into Phase I as substitution and compensating units are attached to 174 generators. Boilers are referred to throughout the report because SO2

is released into the atmosphere by burning fuel in boilers and allowances are deducted from accounts based on boiler emissions.

Environmental Protection Agency, 1995 Compliance Results, Acid Rain Program, EPA/430-R-96-012 (Washington, DC, July 1996), p. 1. 3

1. Introduction

The Clean Air Act Amendments of 1990 (CAAA90), Title IV explicitly specifies 261 generating units powered

Public Law 101–549, are the latest revisions to the Clean by 263 boiler units at 110 utility plants for Phase I. These

Air Act. Among the numerous provisions of CAAA90 is 261 units, located in 21 eastern and midwestern States,

Title IV, which requires the U.S. Environmental Protection are referred to as “Table 1” units because they were

Agency (EPA) to establish the Acid Rain Program to explicitly identified in Table 1 of the regulation. Howreduce the adverse effects of acidic deposition popularly ever, because of provisions in Title IV that allow utilities

known as acid rain. Acid rain is formed largely from to use other units to substitute or compensate for those

emissions of sulfur dioxide (SO ) and nitrogen oxides originally specified, 174 additional generating units were 2

(NO ) that are emitted primarily by fossil-fueled electric affected by Phase I in 1995 (a x total of 435 affected

power plants, other industrial sources, and transportation generating units) (Figures 1 and 2).

sources. The SO reduction provisions of Title IV of the 2

CAAA90 (hereafter referred to as Title IV) are noteworthy A boiler unit brought into Phase I as a substitution unit

and creative because they represent the first large-scale can assist a Table 1 boiler unit in meeting its emissions

attempt to set overall emissions levels by using market- reductions obligations. Utilities may make cost-effective

able licenses (allowances) and a choice of compliance emissions reductions at the substitution unit instead of at

methods to control emissions rather than using regu- the Table 1 unit by achieving the same overall emissions

lations that specify what actions must be undertaken reductions that would have occurred without the

(command and control). An allowance permits the emis- participation of the substitution unit. After January 1,

sion of 1 ton of SO . Title IV gives electric utilities several 1995, a Table 1 boiler unit may designate any Phase II 2

options for reducing emissions, thus introducing flexi- boiler unit as a substitution unit only if both units are

bility into compliance plans. Because they have several under the control of the same owner or operator. In 1995,

compliance options, many utilities have alternative plans 91 Table 1 boiler units designated 167 Phase II boiler units

for complying with the Acid Rain Program, depending on to be substitution units. Of these 91 Table 1 boiler units,

the circumstances (Table B1 of Appendix B). almost half were located in the Midwest and almost a

Title IV requires a two-phase tightening of the restrictions these Table 1 units designated substitution units that were

placed on fossil-fuel fired power plants. Phase I, from located at the same plant. The other seven Phase II boiler

1995 through 1999, and Phase II, starting in 2000. Phase units that participated in the Acid Rain Program in 1995

I mostly affects those power plants that are the largest entered as compensating units. Table 1 units that reduced

sources of SO and NO . Phase II will affect virtually all their utilization below their baseline may designate 2 x

fossil-fueled electric power producers, including utilities compensating units to provide compensating generation

and nonutilities. Phase II will tighten the annual emissions that would account for the reduced utilization of the Table

limits imposed on these large, higher emitting plants, and 1 unit. A Table 1 unit may designate any Phase II unit as

it will set restrictions on smaller plants fired by coal, oil, a compensating unit if the Phase II compensating unit is

and natural gas. Most existing utility units with an output in the Table 1 unit’s dispatch system or has a contractual

capacity of 25 megawatts or greater and virtually all new agreement with the Table 1 unit, and if the emissions rate

utility and nonutility units will be affected in Phase II. of the compensating unit has not declined substantially

Also, other sources of SO (such as industrial facilities) since 1985. 2

may elect to participate in the Acid Rain SO Program. 2

1

2

quarter were located in the South. Also, almost a third of

3
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

2 on Electric Utilities: An Update

Figure 1. Table 1 Unit Emissions, 1985 and 1995

(Tons of SO )2

State Estimates (from CEMS) State Estimates (from CEMS)

1985 Table 1 1995 Table 1 1985 Table 1 1995 Table 1

Unit Emissions Unit Emissions Unit Emissions Unit Emissions

Alabama 297,195 132,645 Mississippi 83,365 56,621

Florida 224,089 108,552 Missouri 746,219 227,525

Georgia 795,476 276,004 New Hampshire 52,535 36,128

Illinois 766,492 392,177 New Jersey 33,735 21,720

Indiana 1,268,745 636,502 New York 173,882 70,486

Iowa 73,873 27,389 Ohio 1,711,128 770,357

Kansas 3,167 2,893 Pennsylvania 671,216 515,804

Kentucky 461,023 320,074 Tennessee 621,923 287,446

Maryland 133,081 119,804 West Virginia 715,483 372,971

Michigan 59,017 13,171 Wisconsin 220,387 54,669

Minnesota 2,033 1,493 Total 9,114,064 4,444,431

CEMS = Continuous Emissions Monitoring System.

Note: Totals may not equal sum of components because of independent rounding.

Source: 1995: U.S. Environmental Protection Agency, State Summary Data for 445 Phase I Boilers, http://www.epa.gov/

acidrain/comprpt/statesum.html. 1985: Energy Information Administration, Form EIA-867, “Steam-Electric Plant Operation and Design

Report.”
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

 on Electric Utilities: An Update 3

Figure 2. Substitution and Compensating Unit Emissions, 1985 and 1995

(Tons of SO )2

State Estimates (from CEMS) State Estimates (from CEMS)

1985 Substitution 1995 Substitution 1985 Substitution 1995 Substitution

and and and and

Compensating Compensating Compensating Compensating

Unit Emissions Unit Emissions Unit Emissions Unit Emissions

Alabama 25,993 17,350 Mississippi 19,379 24,617

Florida 24,599 22,178 Missouri 140,386 98,522

Georgia 142,033 121,586 New Hampshire 14,265 11,155

Illinois 31,380 40,042 New York 88,686 25,340

Indiana 17,937 44,806 Ohio 281,233 140,635

Kansas 55,567 26,156 Pennsylvania 91,693 13,755

Kentucky 27,151 14,647 Utah 1,783 2

Maryland 15,806 6,018 West Virginia 59,975 63,914

Massachusetts 100,310 72,770 Wisconsin 87,069 52,411

Michigan 21,393 16,330 Wyoming 75,121 30,754

Minnesota 27,645 11,010 Total 1,349,404 853,998

CEMS = Continuous Emissions Monitoring System.

Note: Totals may not equal sum of components because of independent rounding.

Source: 1995: U.S. Environmental Protection Agency, State Summary Data for 445 Phase I Boilers, http://www.epa.gov/

acidrain/comprpt/statesum.html. 1985: Energy Information Administration, Form EIA-867, “Steam-Electric Plant Operation and Design

Report.”
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

4 on Electric Utilities: An Update

Table 1. SO Emissions From Electric Utilities, 1985, 1990, 1994, and 1995 2

(Million Tons)

1995

Capacity

(GW)

Total SO Emissions 2

1985 1990 1994 1995

Phase I Units ............. 130.9 10.5 9.7 8.0 5.3

(28) (67) (62) (56) (45)

Non-Phase I Units ......... 333.2a 5.1 5.9 6.3 6.6

(72) (33) (38) (44) (55)

Total ................... 464.1 15.6 15.6 14.4 11.9

(100) (100) (100) (100) (100)

 Includes units that had SO emissions in 1995 only. a

2

 Note: SO emissions for 1985, 1990, and 1994 are estimated. Percentages are shown in parenthesis. 2

 Sources: 1995: U.S. Environmental Protection Agency, “1995 Compliance Results, Acid Rain Program,” EPA/430-R-96-012,

July 1996. 1994 and prior years: Energy Information Administration, Form EIA-767, “Steam-Electric Plant Operation and

Design Report.”

Some utilities designated Phase II units as substitution

units during Phase I, instead of waiting for Phase II, to

take advantage of the Phase I NO reductions require- x

ments, which are less stringent than the Phase II

requirements. If the utility determines that the benefits of

less stringent NO requirements outweigh the costs of x

more stringent SO requirements, substitution becomes 2

more likely.

SO Compliance Results in 1995 2

During the past decade, utilities with Phase I units have

achieved significant reductions in SO emissions, most 2

notably in 1995, the first year of the program. During

1995, 435 Phase I units emitted 5.3 million tons of SO into 2

the atmosphere. This amount was 50 percent lower than

the estimated 10.5 million tons they emitted in 1985, and

well below EPA’s 1995 goal of 8.7 million tons for Phase

I units (Table 1).

With coal prices decreasing, particularly lower sulfur coal,

some industry observers have suggested that utilities

would have switched to lower sulfur coal regardless of

Title IV’s SO emissions limits. To fully address this issue, 2

however, would require a detailed analysis of regional

low- and high-sulfur coal prices and other factors, which

is beyond the scope of this report. An analysis at a broader

level, however, suggests that Title IV has caused, at least

in part, a reduction in SO emissions. While SO emissions 2 2

from Phase I units have steadily decreased, SO emissions 2

from nonaffected units have increased (Table 1). In 1985,

Phase I units were the largest group of SO emitters, 2

accounting for 67 percent of total SO emissions, and non- 2

Phase I units accounted for 33 percent. By 1995, Phase I

units emitted 45 percent of total SO emissions, whereas 2

non-Phase I units accounted for 55 percent of the total.

Contents of This Report

In 1994, the Energy Information Administration released

an analysis report titled, Electric Utility Phase I Acid Rain

Compliance Strategies for the Clean Air Act Amendments of

1990. The material presented here updates that report

and provides information on the strategies utilities are

using to comply with SO and NO emissions reductions 2 x

requirements during Phase I of Title IV of CAAA90, and

provides estimates of the costs incurred by six utilities in

implementing these strategies through 1995. The discussion covers four SO compliance strategies: (1) fuel 2

switching and/or blending with lower sulfur coal, (2)

obtaining additional allowances, (3) installing flue gas

desulfurization equipment (scrubbers), and (4) other

compliance strategies. The effects of these strategies on

coal supply and demand are also examined. The report

describes utilities’ plans for Phase II, although many

utilities have adopted a wait-and-see approach, choosing

to see how the market for allowances develops and how

competition in the electric power industry progresses. A

key component of this strategy involves the accumulation

of excess Phase I allowances, which can be used at any

point in the future. This strategy allows utilities to delay

installation of pollution control equipment with high

capital costs until after 2000. Also, the evolution of the

electric power industry toward more competition has led

many utilities to view their compliance plans for the

future as proprietary; therefore, they are less than

forthcoming about these plans.

Other topics presented in this update are the proposed

EPA rule for NO emissions reductions in Phase II Group x

1 and Group 2 boilers, detailed descriptions of the shifts in

coal supply, and an evaluation of the structure of the

annual SO allowance auction. 2
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 5

“CAAA Phase I Performance: Overcompliance,” Coal (October 1995), p.11. 4

2. Phase I Effects on Utilities

According to the EPA, all of the Phase I plants, housing methods to reduce SO emissions and reduce their

445 Phase I boilers, were in compliance with Title IV at the pollution control costs at the same time.

end of 1995. The 445 Phase I boilers, associated with 435

generating units, had a total capacity of 130.9 gigawatts. A utility could choose one or a combination of the folThis figure includes 261 Table 1 generating units, ex- lowing methods to meet its annual emissions allowance

plicitly referred to in the text of Title IV, with a total limit:

capacity of 89.0 gigawatts and 174 substitution and compensating units (totaling 41.9 gigawatts of capacity)  Fuel switching and/or blending with lower sulfur

brought into Phase I under provisions of Title IV. A coal, cofiring, switching to another fuel

profile of the 435 Phase I generating units can be found in  Obtaining additional allowances

Table B1 of Appendix B.  Installing flue gas desulfurization equipment

Compliance Options for Phase I

Phase I affects the largest electric utility sources of SO2

emissions and the units that were brought into the

program as substitution or compensating units. In Phase

I, affected units are required to have an allowance for each

ton of SO they emit or they incur a penalty. Affected units 2

are allocated emissions allowances based on the average

annual British thermal units (Btu's) burned from 1985

through 1987 multiplied by 2.5 pounds of SO per million 2

Btu. The initial quantity of allowances in most cases, is 4

not sufficient to meet the amount of SO emitted in 1985. 2

Therefore, Phase I utilities must either reduce their

emissions to the level of allowances allocated, or they can

acquire additional allowances by purchasing them at an

allowance auction or from another allowance owner.

The market-based approach for complying with environmental regulations established a firm annual limit on SO2

emissions from Phase I units (although with substitution

and compensating unit provisions, this annual limit can

vary from year to year during Phase I), but permitted

allowance trading and a choice of compliance strategies.

Utilities with relatively high costs of pollution control can

purchase additional allowances from other utilities whose

emissions reductions exceed the requirements of Title IV.

Together they can meet their emissions requirements

more efficiently than if each utility had to meet the SO2

limits separately. The allowance trading program gives

utilities the flexibility to choose among a variety of

2

(scrubbers)

  Using previously implemented controls

  Retiring units

  Boiler repowering

  Substituting Phase II units

  Compensating with Phase II units.

Compliance Methods Chosen

On January 1, 1995, Phase I compliance methods effectively went into operation for the purpose of SO2

emissions monitoring by EPA. This section includes a

discussion of the compliance methods chosen for the 261

Table 1 units and how the compliance methods relate to

coal purchase price and specific plant implementation

plans. The 174 substitution and compensating units are

not included in the discussion. 

Fuel Switching and/or Blending

Fifty-two percent (136 units) of the Table 1 units switched

to or blended with a lower sulfur coal, accounting for 59

percent of the SO emissions reductions achieved in 1995 2

(Table 2). These choices were propelled mainly by the

innovation of utilities in blending coals of varying sulfur

contents to reduce the average SO emissions and by the 2

availability of large quantities of lower sulfur coal on the

market at favorable prices. This category includes some

units in Kansas, Michigan, New Hampshire, New York,

and Wisconsin that had already been switched to lower
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

6 on Electric Utilities: An Update

Energy Information Administration, Electric Utility Phase I Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990, 5

DOE/EIA-0582 ( Washington, DC, March 1994), p 33. Federal Energy Regulatory Commission (FERC) Form 423, “Monthly Report of Cost and Quality of Fuels for Electric Plants.” 6

Compliance Method

Number

of

Generators

Average

Agea

(years)

Affected

Nameplate

Capacity

(megawatts)

Allowancesb

(per year)

1985 SO2

Emissions

(tons)

1995

Emissions

(tons) 

Percentage

of Total

Nameplate

Capacity

Affected by

Phase I

Percentage

of SO2

Emission

Reductions

in 1995c

Fuel Switching and/or Blending . 136 32 47,280 2,892,422 4,768,480 1,923,691 53 59

Obtaining Additional Allowances 83 35 24,395 1,567,747 2,640,565 2,223,879 27 9

Installing Flue Gas Desulfurization

 Equipment (Scrubbers) . . . . . . 27 28 14,101 923,467 1,637,783 278,284 16 28

Retired Facilities . . . . . . . . . . . . . 7 32 1,342 56,781 121,040 0 2 2

Other . . . . . . . . . . . . . . . . . . . . . 8 33 1,871 110,404 134,117 18,578 2 2

Total ...................... 261 32 88,989 5,550,821 9,301,985 4,444,432 100 100

 Base year of 1996 was used to calculate average age. a

 One SO allowance permits one ton of SO emissions. b

2 2

 Base year of 1985 was used to calculate SO emissions reductions. c

2

 SO = Sulfur dioxide. 2

 Note: Fuel switching includes Phase I units switched to a lower sulfur coal in the 1990's. This category also includes units using state-mandated

previously implemented controls that may have been switched prior to 1990. Other includes units that were repowered and those that switched to natural

gas or petroleum. Totals may not equal sum of components because of independent rounding.

 Sources: Compliance Method: The Utility Report December 1995, Energy Ventures Analysis, Inc. Age and Capacity: Energy Information

Administration, Inventory of Power Plants 1994, DOE/EIA-0095(94) (Washington, DC, October 1995). 1985 Emissions: U.S. Environmental Protection

Agency, National Allowance Data Base, Versions 2.11 (January 1993). 1995 Emissions: Acid Rain Division, U.S. Environmental Protection Agency.

Table 2. Profile of Compliance Methods for Table 1 Units

sulfur coal to meet previously implemented controls particulate control requirements and in anticipation of the

mandated by State environmental regulations. Phase I compliance requirements, the Sammis plant re- 5

It is useful to look at the individual characteristics of a few 7 to accommodate a wide variety of coals. The ESP, one

plants to understand the decisions made regarding means of removing fly ash from flue gas when fuels are

switching. This section discusses the variations in the way burned in suspension, produces an electric charge on the

three plants switched to lower sulfur coal: Ohio Edison's ash particle to be collected and then attracts the charged

Sammis plant switched to coal from the Central particle by electronic forces to the collecting curtain. Fly

Appalachian region, Associated Electric Cooperatives' ash can seriously interfere with the operation of a boiler

Thomas Hill plant switched from Missouri coal in 1990 to unit, and, in some low-sulfur coals, can be resistant to

lower sulfur coal from the Powder River Basin in 1994 and being charged. Thus, in many cases, the flue gas must be

1995, and the Coffeen plant of Central Illinois Public treated with chemical conditioning agents, such as sulfur

Service continued using coal from the Illinois Basin in trioxide (SO ) to reduce ash resistivity and to increase the

1995 as it had in 1990. collection efficiency of the ESP.

The Sammis Plant

The Sammis plant, operated and owned by Ohio Edison,

has a coal-fired nameplate capacity of 2,303.5 megawatts

with four 185.0 megawatt units, one 317.5 megawatt unit

and two 623.0 megawatt units. Units 5, 6, and 7 are Table

1 units and they have a total capacity of 1,563.5 megawatts. In the early and mid-1980's, in response to EPA

placed electrostatic precipitators (ESPs) in units 5, 6, and

3

In 1985 Sammis received 24 percent of its coal from Ohio,

31 percent from Pennsylvania, about 32 percent from

West Virginia and the rest from Kentucky. The average 6

sulfur content of the total receipts was 1.67 percent by

weight and the average delivered price was $46.76 (1995

dollars) per short ton (191.4 cents per million Btu). In 1990,

over 50 percent of Sammis' coal came from Ohio and

Pennsylvania.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 7

This delivered price is an indication of the competitive price of Western coal. The average price of Wyoming coal delivered to all plants 7

in the State of Missouri in 1995 was $15.36 per short ton.

Energy Information Administration, Electric Utility Phase I Acid Rain Compliance Strategies for the CAAA90, DOE/EIA-0582 (Washington, 8

DC, March 1994), p. 19.

However, in 1995, coal from Ohio and Pennsylvania was dumpers, which are rotated, tilted, and dumped by a

significantly reduced; less than one percent of Sammis' specially designed track. In all, the coal-switching modifreceipts came from Pennsylvania and none came from ications totaled approximately $118 million.

Ohio. Most of the coal came from southern West Virginia

(56 percent) and eastern Kentucky (36 percent) by barge

transportation, since Sammis has significant barge unloading capability. The average sulfur content went from

1.67 percent by weight in 1985 to 0.79 percent by weight

in 1995 and the average delivered price of coal was

reduced by 33 percent (1995 dollars) to $31.23 per ton

(128.1 cents per million Btu) in 1995.

Ohio Edison currently operates one lower sulfur coal pile

for fueling all generators at the Sammis plant and recently

has considered using different types of coal for the various

units at the plant. However, that would entail the cost and

burden of maintaining multiple coal piles. Ohio Edison estimates that maintaining a single coal pile could cost as

much as $1 million less than maintaining two separate

piles.

The Thomas Hill Plant

The Thomas Hill plant located in Randolph County, Missouri, is one of two coal-fired plants owned by Associated

Electric Coop., Inc. The Hill plant has a capacity of 1,135

megawatts, 465 megawatts of which are affected by Phase

I at units 1 and 2. In 1985 and 1990 all coal receipts for the

plant originated from Missouri— 2,304,000 and 2,287,000

short tons, respectively. The average sulfur content for the

coal in 1985 was 4.18 percent by weight and the delivered

price was $46.42 (1995 dollars) per short ton (223.4 cents

per million Btu).

In 1992, the Thomas Hill plant received its first shipment

of Powder River Basin coal—116,000 tons, 4 percent of its

total coal purchases in 1992. In 1995, all coal receipts for

the plant originated in Wyoming at an average delivered

price of $12.55 per short ton (71.8 cents per million Btu) 7

with an average sulfur content of 0.20 percent by weight.

The introduction of Powder River basin coal at the

Thomas Hill plant necessitated plant modifications to the

coal handling and crushing systems and boiler modifications, including installation of new dampers and soot

blowers. Western coal brittleness and dust-forming characteristics sometimes require dust suppression equipment

to reduce the potential of explosions. Powder River basin 8

coal is transported to the plant by rail in rotary car

Coal receipts in 1995 at the Thomas Hill plant increased to

4,723,000 tons in part because of the lower heat content

(8,744 Btu’s per pound as compared to a heat content of

10,382 Btu’s per pound in 1985).

The Coffeen Plant

Central Illinois Public Service's Coffeen plant located in

Montgomery County, Illinois, has two Table 1 units,

amounting to a capacity of 1,005.5 megawatts. In 1985,

Coffeen received 1,970,000 short tons of coal from

Macoupin County, Illinois, with an average sulfur content

of 3.68 percent. In 1990, Coffeen received all of its coal

from Macoupin County—1,746,000 short tons with 3.54

percent sulfur at $38.69 (1995 dollars) per ton (182.7 cents

per million Btu).

In response to Title IV, the Coffeen plant decided to

continue using Illinois coal in 1995. This decision was

facilitated by renegotiating a contract with the same

supplier to provide lower sulfur coal and by modifying

the plant with a new limestone addition system and a new

electrode design for the ESP, costing approximately $1.3

million and $500,000, respectively.

Under a renegotiated contract, Coffeen received 1,690,000

short tons of coal from Macoupin County with a sulfur

content of 0.91 percent by weight and average delivered

price of $35.28 per short ton (171.8 cents per million Btu)

in 1995, which was 9 percent lower than the 1990 average

delivered price.

Total capital costs to comply with the Title IV were

approximately $2.2 million with a one-time maintenance

cost of approximately $1.5 million. Operating costs have

increased by approximately $300,000 a year at the plant.

Obtaining Additional Allowances

An allowance authorizes the utility to emit 1 ton of SO .2

Utilities designated the use of additional allowances as

the primary compliance method for 32 percent of the

Table 1 units (83 units). In addition to obtaining more

allowances, these units reduced their emission levels by 9

percent in 1995 compared to 1985, as they decreased coal
0 200 400 600 800 1,000

Quantity (Thousands of Allowances)

0

50

100

150

200

250

300

350

Price (Dollars)

Demand

EPA

Supply

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

8 on Electric Utilities: An Update

“U.S. Utilities Opt Against Scrubbing,“ International Coal Report (October 30, 1995), p. 5. 9

Juan-Pablo Montero, A. Denny Ellermen, and Richard Schmalensee, “The U.S. Allowance Trading Program for SO : An Update After 10

2

the First Year of Compliance,” Massachusetts Institute of Technology, for the Proceedings of the Second Workshop on Energy Externalities

Organized by EC/OECD/IEA, Brussells, September 9-10, 1996, Draft: October 29, 1996, p. 13.

Dallas Burtraw, Cost Savings Sans Allowance Trades? Evaluating the SO Emission Trading Program to Date, Resources for the Future, 11

2

(Washington, DC, February 1996), p. 9.

Communication from Joe Kruger of the Environmental Protection Agency, December 6, 1996. 12

United States General Accounting Office, Report to the Chairman, Environment, Energy and Natural Resources, Subcommittee, Committee 13

on Government Operations, House of Representatives, Air Pollution: Allowance Trading Offers and Opportunity to Reduce Emissions at Less Cost,

GAO/RCED-95-40, (Washington, DC, December 1994), p. 53.

Federal Register, Vol. 61, No. 110 (June 6, 1996), pp. 28761-28763. 14

Figure 3. 1996 SO Emission Allowance (Spot 2

Market) Supply and Demand at the EPA

Auction, March 1996

SO = Sulfur dioxide. 2

EPA = U.S. Environmental Protection Agency.

Note: All bids to the left of the vertical EPA supply at

quantity 150,000 were winning bids.)

Source: U.S. Environmental Protection Agency, Acid

Rain Division, 1996 EPA SO Allowance Auction Summary. 2

consumption by 2.5 million tons and lowered the sulfur

content of coal consumed by 16 percent.

Emissions allowances are available from scrubbed plants

and from plants switching to lower sulfur coal when these

methods produce emissions reductions that exceed the

targeted unit’s reduction requirements. They are also

available from the EPA’s distribution of “bonus allowances” to non-Phase I utilities for using energy conservation strategies and to plants which opted to scrub earlier

than required. These factors have contributed to an ex- 9

cess of allowances on the allowance market, few participants in allowance trading, and lower than projected

market prices. Many attribute the low allowance prices

primarily to the recent declines in coal prices. Therefore, 10

utilities have been able to use allowances for the continued burning of higher sulfur coal from current sources or

to purchase them at low prices, with plans to use the

allowances to defer the higher cost of complying with

Phase II.

Prices for SO emissions allowances have declined since 2

their initial offering in the 1993 EPA allowance auction

run by the Chicago Board of Trade and are well below the

$1,500 level that was estimated by various parties around

the time of passage of CAAA90 (Figure 3). 11

The allowance market has shown a level of development

far removed from the uncertainty associated with the first

allowance auction. Sophisticated financial instruments

typically associated with commodity markets are now

characteristics of the allowance market. Some of these

include forward contracts, options, and futures.

Originally, many economists expressed the following

concerns with the manner in which EPA conducts the

annual auctions each March:12

 1) EPA, the largest seller in the auctions, has no

minimum asking price.

 2) Because winning bidders pay the amount they

actually bid, a range of winning prices is generated.

 3) The lowest-priced offers are matched to the highestpriced bids.

When EPA adopted the current auction design, it said it

would monitor the auctions and identify any necessary

changes to the design “that may be required to assure an

orderly and competitive market.” The General Accounting

Office (GAO) has stated its belief that an auction with a

single price is consistent with CAAA90 and the goals for

the auction expressed in the legislative history. GAO goes

on to say that “a single price auction could result in at

least the same, if not higher, total proceeds to the extent

that the incentive to submit lower bids present in the

price-discriminating design would be removed.”13

In response to the GAO report and general criticism that

EPA received regarding the auction, EPA published an

advanced notice of proposed rulemaking (ANPRM) in the

Federal Register asking market participants whether a

change in the auction design would be desired. The 14

majority of commentors responded that changing the

design at this time could disrupt the allowance market

rather than better inform it, that a change to a single-price
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 9

Communication from Joe Kruger of the Environmental Protection Agency, December 6, 1996. 15

“U.S. Utilities Opt Against Scrubbing,” International Coal Report, October 30, 1995, p 5. 16

Table 3. PEPCO's 1995 Allowance Totals

Unit

1995

Allowance

Allocation

1995 Allowances

Deducted for

Emissions Difference

Allowances

Carried Over

to 1996

Chalk Point ST1 .............. 25,403 20,543 4,860 3,700

Chalk Point ST2 .............. 23,690 20,544 3,146 6,756

Morgantown ST1 ............. 39,864 28,040 11,824 7,257

Morgantown ST2 ............. 45,592 38,515 7,077 10,017

Conemaugh 1 ............... 9,389 460 8,929 106

Conemaugh 2 ............... 8,335 7,131 1,204 1,859

Chalk Point 3 ................ 9,000 3,010 5,990 5,990

Chalk Point 4 ................ 1,519 1,354 165 373

PEPCO Total ................ 162,792 119,597 43,195 36,057

 Note: One allowance permits the emission of 1 ton of sulfur dioxide.

 Source: Environmental Protection Agency, Acid Rain Division, 1995 Compliance Results, EPA/430-R-96-012, July 1996, 

p. D-6.

auction design would probably have been more relevant meeting Phase I compliance requirements and by most as

in 1993 and 1994, when price discovery was very limited, a way to hedge against uncertainty for Phase II.

and the EPA auctions played a large role in

establishing market price. Now that other year-round

price discovery mechanisms exist and a market price for

allowances has become clearly established, the auctions

are no longer setting market prices, they are reflecting

them. According to the EPA, the consensus appears to be

that the current auction design is neither leading nor

misinforming the market and should not be changed and

therefore EPA has no plans to change the auction format.15

One can see that there has been much activity in the

allowance market. For example, the differences between

Potomac Electric Power Company’s (PEPCO’s) 1995

allowance allocations and those deducted for emissions

does not equal the number of allowances that PEPCO is

carrying over to 1996 (Table 3). EPA has acknowledged

that there has been more trading than is reflected in the

Allowance Tracking System.

Because of the low allowance prices relative to other

compliance options, particularly scrubbers, allowances are

seen as an attractive compliance option in some cases.

Illinois Power’s (IP) Baldwin plant did not significantly

reduce its emissions in 1995 because IP decided that

acquiring the additional allowances needed for its SO2

emissions was economically viable. As prices climb, other

actions will become more attractive, but for now, holding

allowances is seen by some as a reasonable approach for

Installing Scrubbers

Units with scrubbers installed for Phase I compliance

accounted for 28 percent of 1995 SO emissions reductions, 2

the second largest share after fuel-switching units (59

percent). Sixteen utilities installed scrubbers at 27 units

(Table 4), 10 percent of the Table 1 units. Fewer utilities

than expected opted to scrub high-sulfur coal supplies,

with some utilities located in higher sulfur coalfields

indicating they will postpone scrubber installations

several years beyond 2000. The availability of emissions 16

allowances and the failure of State legislators in Illinois

and Indiana to enact laws that would protect local higher

sulfur coal supplies are factors contributing to the utilities’

decisions to delay or avoid scrubbing.

All scrubber systems rely on a chemical reaction with a

sorbent to remove SO from flue gases. Scrubber systems 2

are either “wet” or “dry.” In the more common wet

scrubber process, flue gases containing SO are contacted 2

with a sorbent liquid that results in the formation of a wet

solid byproduct. The liquid sorbent is sprayed into the

flue gas in an absorber vessel. Most wet scrubber systems

use alkaline slurries of limestone or slaked lime as

sorbents. Sulfur oxides react with the sorbent to form

calcium sulfite and calcium sulfate, which is a wet
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

10 on Electric Utilities: An Update

“Scrubber myths and realities; don’t let common misperceptions about flue gas desulfurization systems bias a realistic appraisal of this 17

capable control technology,” Power Engineering (January 1995), p. 35.

Ibid. 18

On-Line Year State Boiler Units Plant Utility

1992 ................ Georgia Y1BR Yates Georgia Power

Indiana 7,8 Bailly Northern Indiana Public Service

1994 ................ Kentucky 1,2 Elmer Smith City of Owensboro

Ohio 1 General J.M. Govin Ohio Power

Pennsylvania 2 Conemaugh Pennsylvania Electric Company

West Virginia 1,2,3 Harrison Monongahela Power Company

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

Indiana 4 Gibson PSI Energy

Kentucky H1, H2 Henderson MP&L Big Rivers Electric

Kentucky 1 Ghent Kentucky Utilities

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

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

Ohio 2 General J.M. Gavin Ohio Power

Ohio 1 Niles Ohio Edison

Pennsylvania 1 Conemaugh Pennsylvania Electric Company

Tennessee 1,2 Cumberland Tennessee Valley Authority

West Virginia 3 Mt. Storm Virginia Electric & Power Company

1996 ................ Indiana 1,2 Petersburg Indianapolis Power & Light

 Source: U.S. Environmental Protection Agency, Applications for Acid Rain Program Phase I Bonus and Extension SO Emission 2

Allowances (March 31, 1993).

Table 4. Scrubber Retrofits for Compliance With Phase I

byproduct. Oxidation of this results in a gypsum and material failures were frequently responsible for

byproduct that can be sold. unplanned outages. The availability of these early systems

Dry scrubber systems can be grouped into three catego- configurations, selecting better materials, and using

ries: spray dryers, circulating spray dryers, and dry injec- redundant equipment in critical areas, much higher

tion systems. All three categories avoid total water satura- availability has now been attained. More recently, the

tion of the flue gas, and provide a dry, free-flowing waste North American Electric Reliability Council concluded

product. The elimination of any liquid waste is the ma jor that wet scrubber systems contributed, on average, to

difference between dry scrubbers and wet scrubbers. system availability of 99.7 percent.

Scrubbers have been used for some time and are the Operating data prove that wet scrubbers can reliably

standard by which new technology is judged. The last remove 95 percent or more of the SO from stack emisdecade has seen improvement in process chemistry, sions. In fact, SO removal efficiencies often are as high as

simplified designs, and other technological enhancements. 98 percent or 99 percent. Many scrubbers currently

All these improvements have improved reliability, retrofitted to comply with CAAA90 will remove more SO

efficiency, cost, waste prevention, and reduced energy than required, thus generating marketable emissions

consumption of scrubbers. The wet limestone system has allowances. The use of recently developed additives, such

been the most popular scrubber choice for Phase I large- as dibasic acid, formic acid, and magnesium compounds,

unit retrofits. The Phase II decisions on scrubbers are improve efficiencies, especially for high-sulfur coal. Dry

essentially on hold because of utility competition, the scrubbers also are quite efficient. Spray dryers often

desire to avoid large capital expenditures, and low SO achieve greater than 90 percent SO removal on coals 1 2

allowance prices. percent to 2 percent sulfur.

Before 1980, scrubber systems were unreliable. Scrubber Recent technological advances in wet scrubber systems

components often suffered from plugging and scaling, have reduced capital and operating costs relative to

was as low as 85 percent. By simplifying process

17

2

2

2

2

18
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 11

Ibid. 19

Ibid. 20

Ibid. 21

Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities, DOE/EIA-0437(95/1) (Washington, 22

DC, December 1996 and previous years).

These investments were for all air pollution control requirements, not just to meet the provisions of the acid rain program. 23

historical values. Capital costs have been reduced by nating’s Avon Lake unit 8 was retired in November 1987

more than 30 percent. These innovations include in- and Iowa Power’s Des Moines unit 7 is out of service but 19

stalling larger (and fewer) absorber modules, eliminating can be brought back into service in 180 days.

flue gas reheat components, incorporating additives into

the process design, fitting higher velocity absorbers and

alternative duct work designs, installing absorbers in the

base of a new chimney, and reducing reagent preparation

costs.

The retrofit costs of scrubbers are site-specific and vary

considerably. Site-specific factors, such as space and

access limitations, major modifications to existing equipment, and the operating condition of the units, all affect

retrofit costs. The average costs of Phase I retrofits ranged

from $123 per kilowatt to $317 per kilowatt for different

units. Average operating and maintenance costs for

scrubbers, exclusive of capital recovery, are 1.42 mills per

kilowatt hour. This increase in electrical rates is about onehalf that associated with pre-1990 wet scrubbers. If

commercial grade gypsum, a byproduct of scrubbing, is

produced and sold , it would produce revenue and reduce

disposal costs.20

Advances in design and technology have greatly improved scrubber’s energy efficiency. The current generation of wet scrubbers that incorporate advances in

chimney design, construction materials, regenerative

heaters, and additives to enhance pollutant removal

efficiencies consumes less than 1 percent of total plant

energy. Dry scrubbers consume even less. Some new

scrubber designs even employ heat exchangers, which use

waste heat from stack gases and actually increase power

plant efficiency. Scrubbers with condensing heat exchangers can recover as much as 4 percent of additional

energy, thus offsetting the scrubbers use of plant energy.21

Retiring Facilities

Electric utilities have retired seven Table I units, most of affected under Phase I had cumulative investments of

which are outdated and small capacity units. Retired $14.4 billion in 1995, almost half of the total utility

units accounted for 2 percent of 1995 SO emissions investments in air pollution control facilities. Power 2

reductions. Wisconsin Electric Power Company removed plants in the East Central and Mid-Atlantic regions

four units from service at North Oak Creek in 1988 and (corresponding to the East Central Area Reliability

1989. Indiana-Michigan Power’s Breed plant, shut down Coordination Agreement (ECAR) and the Mid-Atlantic

in March 1994, is undergoing asbestos removal and may Area Council (MAAC) of the North American Reliability

be used again in the future. Cleveland Electric Illumi- Council (NERC)) account for most of these investments

Other

Units in this category accounted for 2 percent of 1995 SO2

emissions reductions. One Table I unit, PSI Energy Inc.’s

Wabash River Station unit 1, has been repowered with an

integrated gasification combined-cycle generator. Using

new technology, the plant burns high-sulfur coal, reduces

SO emissions, and increases the plant capacity by 2

approximately 155 megawatts. One unit each at Illinois

Power’s Vermilion plant and Ohio Edison’s Edgewater

plant were switched to natural gas. Two units at the Long

Island Lighting Company’s Port Jefferson plant and three

units at North Port plant are using No. 6 fuel oil.

Electric Utility Compliance

Strategies, Costs, and Emissions

Electric utilities in the United States have invested heavily

in air pollution control equipment during the last decade.

Scrubbers were installed at some utilities to reduce SO2

emissions, and many utilities have retrofitted low-NOx

burners to reduce NO emissions. Some utilities have x

installed equipment to accommodate cleaner fuel and to

monitor emissions levels. Cumulatively through 1986,

major investor-owned utilities had invested $16.7 billion

in air pollution control facilities (Figure 4). By 1990,

investments had increased to $20.8 billion, and by the end

of 1995 utilities had invested $29.6 billion.22

The level of investment in air pollution control equipment

varies according to the location and size of the plant and

the fuel mix used at the plant. Utilities owning units

23
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

5

10

15

20

25

30

35

Billions of Dollars

All Major IOUs

Major IOUs with Phase 1 Units

ECAR ERCOT MAAC MAIN MAPP NPCC SERC SPP WSCC

0

2

4

6

8

Billions of Dollars

Utilities with Phase I Units

Utilities without Phase I Units

Total Investments = $29.6 Billion

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

12 on Electric Utilities: An Update

General Accounting Office, Air Pollution Alllowance Trading Offers an Opportunity to Reduce Emissions at Less Cost, GAO/RC ED-95-30 24

(Washington, DC, December 1994), p. 37.

Massachusetts Institute of Technology, for the Proceedings of the Second Workshop on Energy Externalities, Brussels, September 9-10, 25

1996, The U.S. Allowance Trading Program for Sulfur Dioxide: An Update After the First Year of Compliance, Draft (Cambridge, MA, October 29,

1996).

Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities 1995, DOE/EIA-0437(95)/1 26

(Washington, DC, December 1996).

Figure 4. Cumulative Investment in Air Pollution

Control Facilities by Major InvestorOwned Utilities, 1986-1995

IOU = Investor-Owned Utilities.

Note: Air pollution control facilities include (1) scrubbers, electrostatic precipitators, tall smokestacks, etc.;

(2) changes necessary to accommodate use of environmentally clean fuels such as low-ash or low-sulfur fuel

including storage and handling equipment; (3) monitoring

equipment; and (4) other equipment.

Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Electric Utilities,

DOE/EIA-0437 (95/1) (Washington, DC, December 1996

and previous years).

IOU = Investor-Owned Utilities.

Note: Air pollution control facilities include (1) scrubbers,

electrostatic precipitators, tall smokestacks, etc.; (2)

Changes necessary to accommodate use of environmentally

clean fuels such as low-ash or low-sulfur fuel including

storage and handling equipment; (3) monitoring equipment;

and (4) other equipment.

ECAR = East Central Area Reliability Coordination

Agreement.

ERCOT = Electric Reliability Council of Texas.

MAAC = Mid-Atlantic Area Council.

MAIN = Mid-America Interconnected Network.

MAPP = Mid-Continent Area Power Pool.

NPCC = Northeast Power Coordinating Council.

SERC = Southeastern Electric Reliability Council.

SPP = Southwest Power Pool

WSCC = Western Systems Coordinating Council.

Source: Energy Information Administration, Financial

Statistics of Major U.S. Investor-Owned Electric Utilities,

DOE/EIA-0437(95/1) (Washington, DC, December 1996).

Figure 5. Total Investments in Air Pollution

Control Facilities by Major InvestorOwned Utilities, by NERC Region, 1995

(Figure 5). These regions have a high concentration of

large coal-fired units, many of which are affected by

Phase I.

Compliance Costs for Title IV

Previous studies have indicated that compliance costs for

Title IV would be lower with the introduction of an

allowance trading system. In 1992 for example, EPA

estimated that the cost of compliance would be up to 50

percent lower using emission allowance trading compared

to command and control regulation. The U.S. General

Accounting Office (GAO) supported that statement. GAO

estimated that by the year 2002, SO reductions under 2

traditional regulation would cost as much as $4.5 billion

annually, but an SO allowance trading program would 2

reduce the costs by $2 to $3 billion annually.24

The Massachusetts Institute of Technology (MIT), in a

preliminary report, estimated an annualized compliance

cost of $836 million (Table 5). This estimate, which was 25

based on program data through 1995, represents less than

0.6 percent of the $151 billion of electric operating 26

expenses of investor-owned utilities in 1995.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 13

Method of

Compliance for Title IV

1995 Emissions

Reduction

(thousand

tons of SO )2

b

Annualized

Compliance Cost

(thousand dollars)c

Annualized

Average Cost per

Ton of SO Removed 2

Scrubbing

 Title IV Scrubbers ...................... 1,734 558,128 322

 NSPS Scrubbers ...................... d 21 1,345 64

Switching

 Bituminous ........................... e 1,547 258,737 167

 Subbituminous (Powder River Basin (PRB)) . 160 18,126 113

 Subtotal .............................. 3,462 836,336 242

No Cost Switchingf

 PRB & CO/UT . . . . . . . . . . . . . . . . . . . . . . . . . 369

 Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

 Midwest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

 Others ............................... 5

Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 426

Total .................................. 3,888 836,336 215

 Preliminary annualized compliance cost for SO could be changed as MIT finalizes their estimates. Costs are not included for low a

2

NO control and continuous emissions monitoring systems. x

 The baseline year to compare 1995 SO emissions is 1993. It is assumed that the reductions before 1993 are not due to the b

2

CAAA90, but to economic reasons. The 1995 SO emissions reductions are the difference between the SO emissions that would 2 2

have been observed in 1995 in the absence of Title IV and the actual emissions. The SO emissions that would have been observed 2

in 1995 was calculated as the product of the emissions rates in 1993 and the heat input in 1995.

 A capital charge of 14 percent is used to annualize initial fixed investments in scrubbers or switching to lower sulfur coal. The 14 c

percent includes 9 percent of capital cost and 5 percent of 20 years’ linear depreciation.

 The New Source Performance Standards (NSPS) scrubbers were installed before Title IV was passed. Only variable costs of extra d

reductions are included for these scrubbers, not any fixed cost.

 Bituminous switching from high-sulfur to low-sulfur coal includes premiums paid for low-sulfur bituminous coal. e

 The “No Cost Switching” for SO reductions would have taken place regardless of Title IV. Most of these are switches to low-sulfur f

2

subbituminous western coal (Powder River Basin and Colorado and Utah) due to the reduction in coal prices, especially the decline

in rail rates.

 Sources: Massachusetts Institute of Technology, Center for Energy and Environmental Policy Research, SO Compliance Costs 2

with Title IV, Memorandum (from Juan-Pablo Montero on December 24, 1996) to Art Fuldner and Ron Hankey, Office of Coal, Nuclear,

Electric and Alternate Fuels, Energy Information Administration. Massachusetts Institute of Technology, Center for Energy and

Environmental Policy Research, More on SO Compliance Costs with Title IV 2 , Memorandum (from Juan-Pablo Montero on January

13, 1997) to Art Fuldner, Office of Coal, Nuclear, Electric and Alternate Fuels, Energy Information Administration. 

Table 5. Annualized SO Compliance Cost for CAAA90 Title IV 2

(1995 Dollars)a

The lowest annualized average cost through 1995 for pared to switching from higher sulfur bituminous coal to

Phase I is switching of bituminous plants to burn lower sulfur subbituminous coal (160 thousand tons).

lower sulfur subbituminous coal, with modifications, from Also, utilities switching to subbituminous coal from PRB

the Powder River basin (PRB) ($113 per ton of SO and Colorado/Utah 2 with no modification cost achieved a

removed). The most expensive is retrofitting scrubbers at large SO reduction (369 thousand tons) compared to

$322 per ton of SO removed. Utilities removed more switching with modifications from bituminous to 2

SO by switching higher sulfur bituminous coal to lower subbituminous coal. 2

sulfur bituminous coal (1,547 thousand tons) com2
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

14 on Electric Utilities: An Update

Sources of information on these utilities consisted of personal contact with each utility; the Securities and Exchange Commission’s, “1995 27

10K”; the Federal Energy Regulatory Commission’s, “Interrogatory on Fuel and Energy Purchases Practices, 1992-1993”; FERC Form 580; and

various articles published in trade journals.

Energy Information Administration, Electric Utility Phase I Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990, 28

DOE/EIA-0582 (Washington, DC, March, 1994).

IP also substituted five PacifiCorp units located in Wyoming and Utah. These units are not included in the total. 29

Table 6. Characteristics of Selected Phase I Utilities

Utilitya

Affected

Nameplate

Capacity

(Utility

Owned)

(MW)

Total

Capacity

(MW)

Percent

Capacity

Affected

Sulfur Dioxide Emissions Allowances

1995

Allocation

of SO2

Allowances

Allowances

Deducted

for 1995

SO2

Emissions

Differences

Between

Allowances

and 1995

Emissions

Allowancesb

Carried

Over

to 1996

Illinois Power ........... 2,699 5,005 53.9 186,579 297,504 (110,925)c 645

Pennsylvania P&L ....... 2,343 8,704 26.9 185,700 136,411 49,289 47,749

Potomac Electric Power . . 3,480 6,433 54.1 162,792 119,597 43,195 36,057

Cincinnati G&E ......... 2,664 5,300 50.3 155,384 107,734 47,650 55,716

Georgia Power .......... 10,252 15,995 64.1 715,187 372,586 342,601 211,835

Southern Indiana G&E . . . 530 1,359 39.0 38,095 21,390 16,705 5,392

The full utility names are Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, a

Cincinnati Gas & Electric Company, Georgia Power Company, and Southern Indiana Gas & Electric Company.

Allowances carried over to 1996 may not equal the differences between allocated and 1995 emissions due to purchases or b

sales of additional allowances. The data in this table do not account for a utility’s purchases and sales of allowances.

Illinois Power purchased enough emissions allowances to cover their 1995 emissions. c

SO = Sulfur dioxide. 2

MW = Megawatt.

Note: For unit level data, see Appendix C.

Source: Environmental Protection Agency, “1995 Compliance Results Acid Rain Program,” EPA/430-R-96-012 (Washington,

DC, July 1996).

Specific Utility Compliance Plans and Costs

This section of the report presents a detailed look at Phase

I compliance strategies and compliance costs through 1995

for six utilities, updating an earlier report on Phase I 27

compliance strategies for these utilities. These utilities 28

were selected to obtain a representative sample of

generating capacities, sulfur dioxide (SO ) emissions, 2

locations, and initial compliance strategies. Also, the Illinois Power (IP) operates eight power plants with an

willingness to participate and share information was electric-generating capacity of 5.0 gigawatts. Initially, 45

essential. Tables 6 through 8 and Figure 6 contain utility percent of IP’s generating capacity (five units) was

level data referred to throughout the discussion. affected by Phase I. Under the substitution revisions of

Appendix C lists detailed information on the character- CAAA90, IP added 8 relatively small units to its Phase

istics and costs of compliance for each of the six utilities’ I-affected units, increasing its affected capacity to 54

plants affected by Phase I. Because the data for these percent of total generating capacity. Phase I affects the

utilities cover only 1 year of a multi-year program, com- generating capacity at Baldwin, Hennepin, Vermillion,

pliance strategies, annual compliance costs, and even total Havana, and Wood River power plants.

capital costs for Phase I will likely change for some units.

One such cost that will most certainly change is emissions IP originally planned to install scrubbers to meet the SO

allowances. Different substitution or compensating units emissions standards at the 1.9 gigawatts Baldwin Plant

might also be selected for participation in future years.

The point is, because utilities are constantly looking for

ways to achieve minimum compliance costs, changes in

compliance strategies and costs are expected over the life

of the acid rain program.

Illinois Power

29

2
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 15

Table 7. Costs of Phase I Compliance for Selected Utilities

Utilitya

Number of

Low-NOx

Burnersb

Number

of

CEMSb

Number

of

Scrubbersb

SO Control 2

NOx

Control CEMS

Total

Capital

Costs

Capital

Cost

Annual

O&M

Cost

Capital

Cost

Capital

Cost

Annual

O&M

Cost

(million dollars)

Illinois Power . . . . . . . . 2.0 13.0 0.0 34.6 18.5 12.7 15.2 0.9 62.5 

Pennsylvania P&L . . . . 7.2 5.2 0.2 51.2 2.2 70.7 11.1 c 133.0 Potomac Electric Power 6.0 6.5 0.2 62.4 1.8 120.6 12.8 c 195.8 Cincinnati G&E . . . . . . 1.4 5.7 1.0 d 12.4 c 6.9 3.5 c 22.8 

Georgia Power ....... 15.1 19.4 1.0 47.0 2.0 125.3 17.1 c 189.5 

Southern Indiana G&E 2.0 2.5 1.0 103.0 4.0 5.0 2.8 0.2 110.8 

 The full utility names are Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, Cincinnati 

a

Georgia Power Company, and Southern Indiana Gas & Electric Company. A fractional value indicates that ownership of equipment was allocated across more than one unit. b Costs not estimated. c The capital costs for the scrubber were not included because the scrubber was installed in 1980, before passage of the Clean Air Act Am

d

 Some of these costs are offset by selling the gypsum produced by the scrubber. e NO = Nitrogen oxides. x SO = Sulfur dioxide. 2 KW = Kilowatt. CEMS = Continuous emissions monitor system. O&M = Operation and maintenance. Notes: In some cases the costs are low because cost estimates were not available for all of the Phase I units. For unit level data, see Ap Sources: Personal contact with Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, GeoIndiana Gas & Electric.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

16 on Electric Utilities: An Update

Table 8. Costs and Quality of Fuels for Selected Electric Utility Phase I Plants, 1985, 1990, and 1995

(Delivered Costs are in 1995 Dollars)

Utility/Plant

1985 1990 1995

Quantity

(thousand

short tons)

Sulfur

Content

(percent)

Delivered

Cost

(dollars/ton)

Quantity

(thousand

short tons)

Sulfur

Content

(percent)

Delivered

Cost

(dollars/ton)

Quantity

(thousand

short tons)

Sulfur

Content

(percent)

Delivered

Cost

(dollars/ton)

Illinois Power

 Baldwin ....... 4,669 2.80 42.53 3,995 3.06 37.02 4,353 2.92 23.75

 Hennepin . . . . . 744 2.80 43.36 688 2.69 35.58 583 2.93 24.29

 Vermillion . . . . . 507 2.50 38.91 387 2.47 30.10 31 1.88 29.41

 Havana . . . . . . . 324 0.50 58.37 496 0.66 45.33 761 0.47 31.05

 Wood River . . . . 701 0.70 66.31 738 0.86 47.66 707 0.73 34.01

 Average . . . . . . -- 2.46 45.50 -- 2.54 38.34 -- 2.39 25.82

Pennsylvania P&L

 Brunner Island . 3,254 1.83 62.05 3,930 1.95 52.18 2,756 1.61 39.25

 Martins Creek . . 785 1.90 73.62 738 1.96 51.74 288 1.59 38.37

 Sunbury ...... 1,283 1.39 37.10 1,103 1.54 30.91 1,205 1.02 24.31

 Conemaugh . . a 441 2.23 51.94 552 2.21 44.07 470 2.25 28.41

 Average . . . . . -- 1.77 57.30 -- 1.90 47.71 -- 1.52 34.30

Potomac Elec. Power

 Chalk Point .... 1,578 1.72 59.66 1,909 1.85 50.99 1,428 1.34 40.60

 Morgantown . . . 1,787 1.70 59.32 2,747 1.68 51.03 2,367 1.39 41.79

 Conemaugh . . a 387 2.23 51.94 462 2.21 44.07 430 2.25 28.41

 Average . . . . . -- 1.76 58.70 -- 1.79 50.39 -- 1.48 39.97

Cincinnati G&E

 Miami Fort ..... 2,627 1.75 55.16 3,269 1.70 39.93 2,663 0.82 34.76

 Beckjord .... a 976 1.97 54.35 2,089 2.04 37.68 1,675 0.98 38.25

 Conesville .... a 541 3.47 51.87 564 3.13 42.86 530 2.88 34.89

 East Bend ... a 1,236 2.56 49.57 1,048 1.89 39.37 1,202 2.28 28.31

 J.M. Stuart .... a 2,347 1.39 57.59 2,713 1.42 40.14 2,266 0.88 33.43

 Average . . . . . -- 1.92 54.67 -- 1.80 39.62 -- 1.21 34.18

Georgia Power

 Bowen ....... 7,945 1.83 58.96 8,340 1.60 47.62 7,545 1.04 40.72

 Hammond ..... 2,005 1.63 57.32 2,004 1.67 49.68 1,037 0.97 36.78

 McDonough . . . 1,175 2.59 52.16 1,471 2.00 46.61 1,202 0.85 33.56

 Wansley .... a 2,296 2.59 51.76 2,472 2.57 48.72 1,499 0.88 48.20

 Yates ........ 2,520 2.37 57.74 2,676 2.02 48.60 1,235 0.90 40.26

 Gaston ...... a 1,061 1.73 68.34 1,015 2.14 52.95 1,019 0.77 42.63

 Arkwright . . . . . 388 2.04 66.52 194 2.09 46.87 110 1.64 41.10

 Harllee Branch . 4,081 1.24 62.73 4,000 1.26 50.22 3,546 1.13 40.08

 Mitchell . . . . . . . 534 1.36 68.57 269 1.37 59.72 149 1.21 58.45

 Scherer ...... a 713 0.68 102.06 718 0.52 49.71 2,132 0.48 34.36

 Average . . . . -- 1.83 60.42 -- 1.70 48.83 -- 0.93 39.80

Southern Indiana G&E

 Culley . . . . . . . . 901 3.01 46.36 1,144 2.75 39.50 1,007 3.10 25.76

 Warrick ...... a 219 3.18 43.27 149 2.87 29.39 220 2.82 23.52

 Average . . . . . -- 3.04 45.76 -- 2.91 38.34 -- 3.05 25.36

 These plants are partially owned by the utility. The quantity of fuel received represents the utility's portion of the total fuel received at the a

plant. It should be noted that these data are available only at the plant level; therefore, Phase I data cannot be broken out.

 -- = Not applicable.

 Source: Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants DOE/EIA-0191(various issues).
1990 1991 1992 1993 1994 1995

5

5.5

6

6.5

7

0

Cents per Kilowatthour (1995 Dollars)

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 17

Figure 6. Average Price of Electricity for Six

Utilities, 1990-1995

 Note: The average is for Pennsylvania Power & Light, Illinois

Power, Potomac Electric Power, Georgia Power, Cincinnati Gas

& Electric, and Southern Indiana Gas & Electric.

 Source: Energy Information Administration, Financial Statistics

of Major U.S. Investor-Owned Electric Utilities, DOE/EIA0437(94/1) (Washington, DC, December 1995 and previous

years).

and to comply with the Illinois Coal Act. This Act, passed

by the Illinois General Assembly in 1991, sought to

discourage the use of low-sulfur western-State coal in

favor of Illinois high-sulfur coal. In December 1993, the

Act was found to be in violation of the Commerce Clause

of the U.S. Constitution. This decision was upheld in the

U.S. Court of Appeals. IP, acting in response to a forecast

of lower allowance prices and anticipating that the Illinois

Coal Act would be overruled, announced in August 1992

that it had suspended construction of the Baldwin Power

Station scrubbers. In 1993, IP reconsidered its alternatives

for compliance.

IP decided to purchase allowances for most of its plants.

In 1995, it purchased almost 118,000 vintage 1995 SO2

emissions allowances. Also, one substitution unit—Vermilion 1—switched to natural gas, freeing emissions

allowances for other plants. The Havana units and Wood

River Unit 1 were not operated in 1995, and the few

allowances allocated to these units for 1995 were used

elsewhere. IP also activated its conditional substitution

plan for Wood River 4 in 1995 because actual emissions of

the unit were less than its allocation. In 1995, IP acquired

enough emissions allowances to meet most of its

anticipated needs for 1996; it will purchase additional

allowances on the spot market. The Illinois Commerce

Commission has approved the recovery of emissions

allowance costs through the Uniform Fuel Adjustment

Clause; therefore, IP’s emissions purchase costs may be

added to its retail customer rates.

IP has three Phase I Group I boilers—Baldwin 3, Hennepin 2, and Vermilion 2. To comply with Phase I NOx

emission reduction requirements, low-NO burners were x

installed at Baldwin 3 and Vermilion 2. Through systemwide averaging, IP will be able to meet the NO emissions x

standards for Hennepin 2.

Through 1995, IP spent almost $63 million on capital

equipment for compliance. However, more than half of

that amount—approximately $35 million—was expended

for the suspended scrubbers. Of course, this increased

compliance costs, but perhaps IP will decide to complete

the scrubbers later and then the utility will not need to

rely as heavily on allowances for compliance. Of the six

utilities examined, IP was the only one that used allowances as a primary compliance strategy. Through 1995, IP

had spent $18.5 million on allowance purchases (classified

as O&M costs in Table 7). They installed 13 continuous

emission monitors (CEMS) at a cost of $15.2 million and

two low-NO burners for $12.7 million. IP has not x

developed a compliance strategy for meeting Phase II

requirements, but they anticipate additional capital expenditures to comply with the Phase II NO requirements x

in 2000 and with future State air quality standards for the

St. Louis and Chicago metropolitan areas.

Pennsylvania Power and Light Company

Pennsylvania Power and Light Company (PP&L), headquartered in Allentown, Pennsylvania, owns 8.7 gigawatts

of capacity. Two gigawatts of PP&L’s generating capacity

were designated as Phase I Table 1 affected units. Unlike

many other Phase I utilities, PP&L did not participate in

the substitution or compensation programs. 

PP&L switched to lower sulfur coal at its owned and

operated units to meet its Phase I obligations in 1995.

Because of a general decline in coal prices throughout the

United States, PP&L did not incur higher fuel prices for

lower sulfur coal. From 1985 to 1995, the delivered cost of

coal for PP&L’s Phase I units decreased from $57.30 per

ton to $34.30 per ton, while the average sulfur content fell

from 1.77 percent to 1.52 percent. PP&L’s Phase I units

showed no major shifts to coal suppliers outside of

Pennsylvania. Over the past 5 years, however, PP&L

reduced its purchases of Central Pennsylvania coal, and

increased its purchases of lower sulfur coal from western

Pennsylvania. They also received a small amount from

Utah and West Virginia in 1995. To meet the NOx

emissions requirements, PP&L installed low-NO burners x

on all its Phase I units and submitted a plan for systemwide NO averaging. x
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

18 on Electric Utilities: An Update

PP&L’s Phase II compliance strategy will be similar to its substitution units burn petroleum, low-NO burners were

Phase I strategy. PP&L plans to purchase lower sulfur not installed on them.

coal, to utilize banked allowances, and to purchase

additional emissions allowances as needed. PP&L does

not plan to use scrubbers for its plants. As a hedge against

the uncertainty of future compliance market conditions,

PP&L, as part owner of the Conemaugh plant, will take

advantage of its share of allowances generated by

Conemaugh’s scrubbers. PP&L estimates that further Title

IV compliance operating costs will be incurred beyond

2000 in amounts that are not now determinable but could

be material.

PP&L spent a total of $51.2 million on equipment for 

Phase I SO emissions compliance. However, $41 million 2

of this is attributable to its share of scrubbing equipment

at the Conemaugh plant. The utility spent $70.7 million

on low-NO burners and $11.1 million on CEMS. PP&L’s x

average cost of Phase I compliance per kilowatt of affected

capacity was $56.76.

Potomac Electric Power Company

The Potomac Electric Power Company (PEPCO) is

headquartered in Washington, DC. It owns 6.4 gigawatts

of capacity. Four units at two power plants—Chalk Point

and Morgantown—with 1.8 gigawatts of capacity, were

designated as Phase I Table 1 affected units. Additionally,

PEPCO owns 9.7 percent of the 2 Table 1 units at the

Conemaugh plant in Pennsylvania. PEPCO decided that

switching to lower sulfur coal would provide the best

strategy for complying with Title IV SO limits. No sig- 2

nificant capital costs are associated with switching to

lower sulfur coal at Chalk Point. In fact, the cost of its

delivered coal fell from $58.70 per ton to $39.97 per ton,

while the average sulfur fell from 1.76 percent to 1.48

percent during the same time period. Although the mix

of PEPCO’s coal supply for Table 1 units changed, its coal

came from Pennsylvania, Maryland, and West Virginia in

1995—the same as in 1985.

By using lower sulfur coal as its primary SO compliance To meet the SO emissions reduction requirements, CG&E 2

strategy, excess allowances were accumulated at these switched to lower sulfur coal at the Miami Fort, Beckjord,

plants. Also, Chalk Point 4 was designated as a substi- and J.M. Stuart plants. Electrostatic precipitator modificatution unit for Chalk Point units 1 and 2, and Chalk Point tions were made on Beckjord unit 5 and on Miami Fort

3 was designated as a substitution unit for Morgantown unit 6. An SO injection system was installed on Miami

units 1 and 2. PEPCO indicated that the marginal cost of Fort unit 7 to accommodate the lower sulfur coals. The

adding these units to Phase I was $3.2 million, for average sulfur content of coal received at these plants in

installation of CEMS. However, by designating these 1995 was 0.88 percent, down from 1.64 percent in 1985.

substitution units, PEPCO obtained additional emissions The average sulfur content of coal received at all of

allowances that can be banked for later use. To meet NO CG&E’s Phase I plants, including those that did not switch x

emissions requirements, PEPCO installed low-NO to lower sulfur coal, decreased from 1.92 percent in 1985 x

burners on all its coal-burning units; because both to 1.21 percent in 1995.

x

Phase I capital compliance costs for PEPCO total $196

million. Like PP&L, most of these costs are a result of the

installation of low-NO burners, and more than half of the x

capital spent on SO control went toward its share of 2

Conemaugh’s scrubbers. Another large portion of the

expenditures was incurred in adding gas-fired capacity to

Chalk Point units 1 and 2 ($30 million). PEPCO spent

almost $13 million on CEMS. The per kilowatt capital cost

for PEPCO’s total Title IV compliance was $56.27, which

was quite similar to PP&L’s $56.76 per kilowatt.

For future compliance actions, PEPCO may continue to

burn lower sulfur coal or low-sulfur oil. Scrubbing is also

a possibility for meeting future emissions reductions

requirements. One possible strategy is fuel switching for

Phase I and scrubbing for Phase II. This strategy avoids

the high capital costs of installing scrubbers for as long as

possible.

Cincinnati Gas and Electric Company

Cincinnati Gas and Electric Company (CG&E) serves Ohio

with power from the nine plants in which it has ownership interest. These nine plants have a total nameplate

generating capacity of about 5.3 gigawatts. Initially, 25

percent of the utility’s total capacity was affected by

Phase I. With the addition of five substitution units,

Phase I capacity increased to 50 percent of total generating capacity.

In October 1994, CG&E and PSI Energy merged to form

the CINergy Corporation, a holding company registered

under the Public Utility Holding Company Act of 1935. 

CG&E’s compliance plan was in place in late 1994, and the

merger did not cause significant changes to the plan.

CG&E and PSI will prepare a joint compliance plan for

Phase II.

2

3
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 19

To accumulate extra emissions allowances, CG&E designated East Bend Power Plant Unit 2 a substitution unit.

This unit originally entered commercial operation in 1981,

and a scrubber had been installed in 1980. By designating

East Bend 2 a substitution unit, CG&E obtained overcompliance allowances that can be used for other units.

SO emissions in 1995 at Conesville unit 4, which is a 2 

jointly-owned unit, were higher than its allowance

allocation; therefore, excess allowances from other units

were applied to this unit.

For short-term contingencies, CG&E intends to build an

operating reserve of SO allowances containing about 13 2

percent of annual allotments. Extra allowances will come

from overcompliance at some units and from participation

in the allowance markets. CG&E purchased allowances in

the 1993 and 1994 EPA allowance auctions; no purchases

were made in the 1995 and 1996 auctions.

Through 1995, CG&E spent approximately $23 million on

capital equipment for compliance with Title IV, and its

average capital costs are $16.91 per kilowatt of affected

capacity. This expenditure is relatively low compared to

the other 5 utilities, primarily because the costs for East

Bend’s unit 2 scrubber were not included. Also, because

of its original low-NO design, the East Bend plant did not x

require NO modifications to meet NO emission require- x x

ments.

Modifications to burn lower sulfur coal at the Beckjord

and Miami plants have cost about $12.4 million. Capital

costs for low-NO burners at the Beckjord plant were $6.9 x

million. Miami Fort 7 and J.M. Stuart units 1 through 4

have been designed with cell burner technology which is

exempt from Phase I NO limits. Interestingly, the cell x

burners at the Stuarts units were installed as part of the

Clean Coal Project, which was funded by the U.S.

Department of Energy (DOE). Conesville 4 is able to meet

NO limits by taking its high NO emitting burners out of x x

service .

CG&E has spent $3.5 million on CEMS, but they expect to

incur more costs as final project enhancements are

implemented and software modifications required by the

EPA are made.

CINergy is investigating alternatives to meet Phase II

requirements. Its current allowance banking strategy

allows them to defer plant modifications for reducing SO2

emissions. CINergy intends to submit a system-wide NO Construction expenditures for GPC’s share of Phase I x

averaging plan to meet Phase II requirements. compliance totaled approximately $189.6 million through

Georgia Power Company 

The Georgia Power Company (GPC) is an operating

company of Southern Company, a registered holding

company headquartered in Atlanta, Georgia. Southern’s

other operating companies are Alabama Power, Mississippi Power, Savannah Power, and Gulf States Power.

GPC owns 16 gigawatts of capacity at 33 plants and 7.6

gigawatts of GPC-owned-and-operated capacity at 5

plants, which were designated as Phase I Table 1 affected

units. Georgia Power owns 53.5 percent of the Wansley

plant, a Table 1 unit, and 75 percent of Scherer Unit 3, a

substitution plant; GPC operates both Wansley and

Scherer. Additionally, GPC owns 50 percent of units 1

through 4 at the EC Gaston plant, operated by Alabama

Power, which were designated Phase I Table 1 affected

units.

GPC’s basic compliance strategy was integrated into the

Southern Company’s overall plan. GPC’s primary method

of compliance with Phase I requirements was to increase

burning of lower sulfur coal. In 1994, GPC was the

recipient of more coal than all but three utilities (Tennessee Valley Authority, PacifiCorp, and Texas Utilities

Electric Company). Clearly, any changes in GPC’s coal

consumption patterns can have significant effects on the

coal market. Yates unit 1 installed a scrubber at an

estimated cost of $34 million, one-half of which was

funded by DOE. GPC also substituted 10 Phase II units

into Phase I and employed a reduced utilization plan,

including increased unit efficiency and sulfur-free

generation.

GPC’s switch to lower sulfur coal required some

equipment upgrades. Switching fuels—from an approximate mix of 1.5 percent high-sulfur coal from the Illinois

basin to lower sulfur sources from central Appalachia—allowed GPC to overcomply and accumulate

unused emissions allowances that were banked for future

use. Additionally, the Scherer plant received subbituminous coal from Wyoming. The average delivered cost

of GPC’s coal fell from an average of $60.42 per ton in

1985 to $39.80 per ton in 1995. During the same period,

the average sulfur content of the coal received at GPC’s

Phase I plants fell from 1.83 percent to 0.93 percent.

Compliance with the acid rain NO emissions reduction x

requirements was achieved through the installation of

new control equipment at 18 of the original 33 affected

boiler units.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

20 on Electric Utilities: An Update

1995. Most of this total, $125 million, was allocated to the To reduce SO emissions, SIGECO installed a single scrubinstallation of low-NO burners. The largest expenditure ber at the Culley Generating Station serving both Culley x

for SO control was GPC’s $17 million share for the 2 and Culley 3. Construction of the scrubber started in 2

scrubber at Yates unit 1. GPC so far has spent $17 million 1992, and it went in-service on February 1, 1995. Because

on CEMS for Phase I. On a per-kilowatt basis, GPC’s of the scrubber, SIGECO overcomplied at the Culley

capital costs for affected Phase I compliance are $18.48. Power Plant and has allowances that can be sold to other

Georgia Power and the Southern Company’s plan to

comply with Phase II are uncertain at this point. Various

options are being considered including using banked

emissions allowances, continued use of fuel switching,

installing scrubbers at selected plants, and/or purchasing

more allowances, depending on their price and availability. In Phase II, equipment to control NO emissions x

will be installed on additional system fossil-fired plants as

required to meet anticipated Phase II limits. From 1996 to

2000, the current compliance strategy may require total

construction expenditures of approximately $45 million.

However, GPC realizes that the full impact of Phase II

compliance cannot be determined with certainty; much

depends on the continuing development of a market for

emission allowances, the completion of EPA regulations,

and the possibility of new emission reduction

technologies. The bottom line is that much uncertainty still

exists regarding Phase II, and GPC wants to remain as

flexible as possible. Phase I and Phase II are not distinct.

Rational utilities will not isolate the two but will integrate

their Phase I and Phase II plans to form an overall

compliance plan. 

An increase of up to 1 percent in GPC’s annual revenue

requirements could be necessary to fully recover the cost

of compliance for both Phase I and Phase II. Compliance

costs include construction expenditures, modification

costs to facilitate switching to lower sulfur coal, and costs

related to emissions allowances. GPC expects to recover

a significant portion of these costs through existing ratemaking provisions. However, GPC states there are no

assurances that all Clean Air Act costs will be recovered.

Southern Indiana Gas and Electric

Company

Southern Indiana Gas and Electric Company (SIGECO) is erating capacity has scrubbers. SIGECO plans to purchase

a relatively small investor-owned utility serving Indiana emissions allowances and/or to blend lower sulfur coal

with a total of 1.4 gigawatts of generating capacity from with coal of a higher sulfur content for the remaining

five power plants. Two units at the Culley Power Plant capacity. Meeting NO standards is more problematic.

and one unit (partially owned) at the Warrick Plant are SIGECO’s largest plant, the A.B. Brown Power Plant, is

Table 1 units. SIGECO’s ownership share of the affected currently in compliance with the 0.5 lbs per million Btu

units is 530 megawatts of capacity. Interestingly, two of NO limits. However, if this standard is lowered, equipSIGECO’s principal coal-fired facilities (A.B. Brown Units ment retrofits will be needed to comply. To meet the NO

1 and 2) had been equipped with scrubbers and were not standards at Warrick 4, SIGECO is installing low-NO

significantly affected by the CAAA90. burners, which will cost an estimated $4 million.

2

parties or banked to meet future emissions reductions

requirements. Some of the allowances from the Culley

Plant were applied to the SO emissions from the Warrick 2

Plant. To meet Phase I NO emissions requirements, x

SIGECO installed low-NO burners at the Culley Plant. x

The Warrick Plant utilizes cell burner technology and is

not affected by the Phase I NO emissions standards. x

A federal court overturned parts of an Indiana law that

was designed to encourage State utilities to use Indiana

coal to meet CAAA90 SO requirements. The December 2

1995 decision—like several other recent cases—rules that

the law violates the U.S. Constitution’s Commerce Clause

because it provides Indiana coal suppliers with an unfair

advantage over coal mined in other States. Although

recently overturned, this law perhaps influenced SIGECO

to install scrubbers instead of using the more popular fuel

switching strategy. In any event, by continuing to use less

expensive high-sulfur coal, SIGECO reduced their real

costs of fuel 34 percent from 1990 to 1995.

Through 1995, SIGECO has spent about $111 million on

capital equipment for compliance, most of which, $103

million, was spent for the Culley Power Plant scrubber.

SIGECO estimates that it will cost approximately $4

million annually to operate and maintain the scrubber,

including the costs of chemicals used in the process. Costs

for scrubber maintenance are offset somewhat by selling

gypsum, which is a byproduct of scrubbing. SIGECO

produces approximately 20 tons of gypsum per hour on

average. About $5 million was spent on NO control x

equipment, and $2.8 million was spent on the installation

of CEMS. The average capital cost through 1995 was

about $209 per kilowatt affected by Phase I.

The majority of SIGECO’s generating capacity is already

positioned to comply with the Phase II SO emissions 2

reductions requirements. Sixty-six percent of its genx

x

x

x
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 21

One could argue that regardless of declining coal prices, the difference in price between higher sulfur and lower sulfur coal represents 30

a fuel premium. Because of the volatility of coal prices in today’s market, however, the six utilities were not asked to estimate a lower sulfur

coal premium.

Conclusions Drawn From These 

Case Studies

Utilities employ a variety of strategies for complying with

the CAAA90 Title IV requirements. For 1995, most of the

6 utilities’ units were switched to lower sulfur coal to meet

the SO emissions limitations. Because of declining coal 2

prices, none of these utilities paid more for low-sulfur coal

in 1995 than they paid for high-sulfur coal in previous

years.30

Although their price has declined from levels estimated in

the early 90's, only a few scrubbers were installed because

they are expensive relative to other compliance methods.

Designation of substitution units, which generated extra

emissions allowances in most instances, was used extensively by utilities. By exceeding the required emissions

reductions, most utilities have excess SO emissions 2

allowances, which they have banked or traded.

Some industry observers thought that compliance with

Title IV would cause electricity prices to increase. A closer

examination suggests that compliance has not caused

electricity prices to increase, at least for the six utilities

examined in this report. Since 1990, which is 5 years prior

to the start of the program, real electricity prices of the six

utilities have remained relatively stable at about 6 cents

per kilowatthour. Prices increased slightly in 1994, but

returned to previous levels in 1995. Admittedly, this is a

rough analysis, and the effect on prices of future

compliance requirements remains to be seen.

For the most part, the six utilities discussed here do not

have firm plans for meeting Phase II requirements. Most

of them are delaying large capital expenditures, while

banking extra allowances as a hedge for the future.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 23

“Fuel Flexibility Underpins Gibson's Long Range Plans,”Power (April 1995). 31

Energy Information Administration, Energy Policy Act Transportation Rate Study: Interim Report on Coal Transportation, DOE/EIA-0597 32

(Washington, DC, October 1995), p. 62.

Energy Information Administration, Energy Policy Act Transportation Rate Study: Interim Report on Coal Transportation, DOE/EIA-0597 33

(Washington, DC, October 1995), p. 73.

Table 9. Average Delivered Cost of Low-Sulfur

Coal by Origin State, 1985, 1990, and 1995

(1995 Dollars Per Short Ton)

State 1985 1990 1995

Alabama .......... 72.89 61.22 47.00

Arizona ........... 27.44 27.29 24.67

Colorado ......... 50.45 35.14 28.83

Illinois ............ 51.39 50.20 35.77

Indiana ........... 47.85 37.05 28.43

Kentucky (eastern) . 64.55 48.60 38.98

Kentucky (western) . 63.58 34.64 26.28

Louisiana ......... 31.52 21.10 17.97

Maryland ......... 48.29 45.89 36.79

Missouri .......... 52.80 –a –a

Montana .......... 42.08 28.32 23.14

New Mexico ....... 35.01 32.31 28.81

North Dakota ...... 16.56 11.07 9.71

Ohio ............. 49.87 38.68 36.00

Oklahoma ........ 63.73 41.98 33.84

Pennsylvania ...... 52.86 44.60 35.84

Tennessee ........ 57.15 42.82 33.82

Texas ............ 17.13 15.93 13.53

Utah ............. 53.39 31.54 26.56

Virginia .......... 68.74 50.96 40.63

W. Virginia (N) ..... 61.44 48.15 36.07

W. Virginia (S) ..... 66.09 47.39 37.93

Washington ....... 37.05 29.78 23.61

Wyoming ......... 40.08 26.43 20.45

U.S. Average ...... 46.25 33.83 27.00

Low-sulfur coal sales less than 1 million tons. a

Note: Low-sulfur coal is defined to have less than or equal

to 2.5 pounds of SO per million Btu. 2

Source: Federal Energy Regulatory Commission (FERC)

Form 423, “Monthly Report of Cost and Quality of Fuels for

Electric Plants.”

3. Phase I Effects on Coal Supply and Demand

Compliance and Fuel Costs

Despite the increased demand for lower sulfur coal

brought on by Phase I compliance programs, the average

delivered price of lower sulfur coal (as well as higher

sulfur coal) declined between 1990 and 1995. The

delivered price of coal generally includes the mine price,

transportation costs, and shipping and loading fees and

may account for as much as 75 percent of the operating

costs at an electric utility plant. The recent decline in 31

coal prices can be attributed to lower mine prices and

lower transportation costs.

New and improved mining technologies such as longwall

mining have increased coal mining productivity by almost

7 percent per year between 1990 and 1995. Also, transportation costs for coal purchased under contract have fallen

for all modes of transportation in the last decade.

Although transportation cost as a percentage of delivered

cost varies greatly across different coal demand and

supply regions because it is influenced by shipping

distance, contract coal transportation costs are a significant

portion of the average delivered cost of coal on average,

accounting for 31 percent of the average delivered price of

contract coal in the United States in 1993. Transportation 32

costs have fallen for varying reasons in different coal

supply regions—in the West because of increased

competition among railroads and substantial productivity

gains made by railroads, and in the East because of an

increase in low-cost barge shipments. These declines, 33

along with electric utilities’ renegotiation of long-term

contracts, may have caused the average delivered price of

lower sulfur coal from almost every producing State to

decrease between 1990 and 1995 (Table 9). The availability of low-cost, lower sulfur coal may have induced

utilities to burn more lower sulfur coal, resulting in a

greater reduction of SO emissions and more allowance 2

credits earned.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

24 on Electric Utilities: An Update

Fossil Plant News, Fall 1996, p. 3. 34

Energy Information Administration, Coal Industry Annual 1995, DOE/EIA-0584(95) (Washington, DC, October 1996), pp. 90-101. 35

Energy Information Administration, Energy Policy Act Transportation Rate Study: Interim Report on Coal Transportation, DOE/EIA-0597 36

(Washington, DC, October 1995), p. 11.

Federal Energy Regulatory Commission, Form 423, “Monthly Report of Cost and Quality of Fuels for Electric Plants.” 37

Compliance and Coal Supply

In 1995, the Powder River Basin (PRB) was the leading

coal supply region, producing 303.3 million tons of coal

(29 percent of U.S. coal production), while the central

Appalachian region was second in coal production at

269.5 million tons (26 percent) (Table 10). After leading

the nation in coal production for many years, the central

Appalachian region slipped to second in 1994 as utilities

found that PRB was a low-cost source of lower sulfur coal

that could often be burned without significantly reducing

the efficiency of their plants. PRB produces a lower 34

sulfur, low-Btu subbituminous coal, which can be economically mined and transported, while a lower sulfur,

high-Btu bituminous coal originates from the central

Appalachian region, where recoverable reserves are

limited and more difficult to mine. Northern Appalachia

and the Illinois basin, with relatively high sulfur and

high-Btu coal, produced 13 percent and 11 percent of total

coal production, respectively, in 1995. The Rocky 35

Mountains are a primary source of lower sulfur

bituminous coal for electric utilities in the Midwest and

accounted for 5 percent of total coal produced in the

United States in 1995.36

Because fuel switching and blending has proven to be the

most popular Phase I compliance method, shifts from

higher sulfur coal regions to lower sulfur coal regions

have occurred. In 1990, low-to-medium sulfur coal

accounted for 67 percent of total coal receipts at electric

utilities, increasing to 77 percent by 1995. Consequently,

high-sulfur coal decreased from 33 percent in 1990 to 23

percent in 1995.37

Of the three coal supply regions with large lower sulfur productive capability and the marketability of higher

reserves—the central Appalachian region (including sulfur coal. This section of the report compares four broad

Virginia, eastern Kentucky, and southern West Virginia), coal demand regions—the Midwest, Northeast, South, and

PRB (including Wyoming and Montana), and the Rocky West (each a combination of the U.S. census divisions)

Mountains (including Colorado and Utah)—PRB and the (Figure 8)—to observe the significant differences in coal

Rocky Mountains increased total coal sales dramatically receipts, coal suppliers, transportation costs, and employbetween 1990 and 1995, while central Appalachia’s total ment in these regions during the 1990's. Particular

coal sales increased marginally (6 percent) (Table 11). attention is given to those coal-producing States with a

Central Appalachia, once thought to be the most popular large number of Phase I generating units to observe shifts

choice for lower sulfur coal by the Phase I plants, in coal supply sources due to compliance. Reductions in

increased its lower sulfur coal sales by 15 million tons as mining jobs and the number of operating mines discussed

its higher sulfur coal sales fell by 5 million tons. Most of in this section are primarily attributable to productivity

the increase was from southern West Virginia. Lower gains in the mining industry resulting from the closing of

sulfur coal receipts originating from PRB in 1995 inefficient, uneconomical mines and the more efficient

increased by 78 million tons over coal receipts from PRB

in 1990, which amounted to a 37-percent increase. For

Wyoming, total coal sales increased by 77 million tons

between 1990 and 1995 (Table 11). Wyoming coal was

shipped to 18 States in 1995, as far east as Indiana and as

far south as Georgia. Several States significantly increased purchases of Wyoming coal between 1990 and

1995 (Figure 7). Missouri led with an increase of 18

million tons. Lower sulfur coal receipts from the Rocky

Mountains increased by almost 10 million tons from 1990.

Total coal receipts from the northern Appalachian region

fell from 127 million short tons in 1990 to 103 million short

tons in 1995 (a 19-percent decrease). Northern Appalachia was able to increase its lower sulfur coal sales by

5 million tons, but not enough to offset the decline of 29

million tons in higher sulfur coal sales. Total coal receipts

from the Illinois Basin dropped to 96 million short tons in

1995 from 129 million tons in 1990 (26 percent). The

Illinois basin was able to double its lower sulfur coal sales

from 1990 to 1995; however, its higher sulfur coal sales

dropped by 40 million tons at the end of 1995.

Compliance and Coal Demand

One general perception of the outcome of Phase I of Title

IV is that compliance has been less costly for electric

utilities than projected because the price of allowances has

dropped and lower sulfur coal prices have not increased

as projected. However, just as this legislation has stimulated the energy markets by producing winners with

innovative and cost-saving compliance methods, it has

also resulted in losses in the higher sulfur coal supply

regions where there are few options to improve the
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 25

Table 10. Coal Production by State, 1990 and 1995

(Thousand Short Tons)

Region

1990 1995

Coal Percent of Coal Percent of

Production U.S. Total Production U.S. Total

Northern Appalachia

 Maryland ...................... 3,487 * 3,667 *

 Pennsylvania ................... 70,514 7 61,576 6

 Ohio .......................... 35,252 3 26,118 3

 Northern West Virginia ........... 56,641 6 46,114 4

Total .......................... 165,894 16 137,475 13

Central Appalachia

 Virginia ........................ 46,917 5 34,099 3

 Eastern Kentucky ............... 128,396 12 118,541 11

 Southern West Virginia ........... 112,564 11 116,883 11

Total ........................... 287,877 28 269,523 26

Southern Appalachia

 Alabama ....................... 29,030 3 24,640 2

 Tennessee ..................... 6,193 1 3,221 *

Total ........................... 35,223 3 27,861 3

Illinois Basin

 Illinois ......................... 60,393 6 48,180 5

 Indiana ........................ 35,907 3 26,007 3

 Western Kentucky ............... 44,926 4 35,198 3

Total ........................... 141,226 14 109,385 11

Texas and Louisiana Lignite

 Texas ......................... 55,755 5 52,684 5

 Louisiana ...................... 3,186 * 3,719 *

Total ........................... 58,941 6 56,403 5

Other Western Interior ........... a 5,506 1 2,738 *

Powder River Basin

 Wyoming ...................... 184,249 18 263,822 26

 Montana ....................... 37,616 4 39,451 4

Total ........................... 221,865 22 303,273 29

North Dakota Lignite

 North Dakota ................... 29,213 3 30,112 3

Total .......................... 29,213 3 30,112 3

Southwest

 Arizona ........................ 11,304 1 11,947 1

 California . . . . . . . . . . . . . . . . . . . . . . 61 * * *

 New Mexico .................... 24,292 2 26,813 3

Total ........................... 35,657 3 38,760 4

Rockies

 Colorado ...................... 18,910 2 25,710 2

 Utah .......................... 22,058 2 25,167 2

Total ........................... 40,968 4 50,877 5

Northwest ..................... b 6,707 1 6,566 1

U.S. Total ...................... 1,029,076 100 1,032,974 100

 Includes Iowa, Oklahoma, Kansas, Arkansas, and Missouri. a

 Includes Alaska and Washington. b

 *= Less than 0.5 percent.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Coal Industry Annual 1995, DOE/EIA-0584(95) (Washington, DC, October 1996),

pp. 90-101.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

26 on Electric Utilities: An Update

Table 11. Coal Receipts at Electric Utility Plants by Supply Region and Sulfur Dioxide Level, 1990 and 1995

Supply Region

1990 Receipts

(thousand short tons)

1995 Receipts

(thousand short tons)

High Sulfur a

Low to

Medium Sulfur b Total High Sulfur a

Low to

Medium Sulfur b Total

Northern Appalachia

 Maryland ................... 1,449 1,555 3,004 544 2,678 3,222

 Pennsylvania ............... 36,389 14,100 50,489 22,098 21,170 43,268

 Ohio ...................... 29,795 308 30,103 21,080 286 21,366

 Northern West Virginia ........ 33,534 9,902 43,436 28,340 7,065 35,405

Total ...................... 101,167 25,865 127,032 72,062 31,199 103,261

Central Appalachia

 Virginia .................... 1,799 15,567 17,366 462 13,992 14,454

 Eastern Kentucky ............ 5,235 79,964 85,199 1,821 85,217 87,038

 Southern West Virginia . . . . . . . . 774 44,398 45,172 66 55,257 55,323

Total ....................... 7,808 139,929 147,737 2,348 154,466 156,814

Southern Appalachia

 Alabama ................... 6,529 9,854 16,383 4,696 10,960 15,656

 Tennessee ................. 1,192 3,426 4,618 41 1,870 1,911

Total ....................... 7,721 13,280 21,001 4,736 12,830 17,566

Illinois Basin

 Illinois ..................... 50,319 3,914 54,233 33,829 8,120 41,949

 Indiana .................... 29,040 1,859 30,899 15,649 4,498 20,147

 Western Kentucky ........... 43,114 504 43,618 33,370 334 33,704

Total ....................... 122,473 6,277 128,750 82,848 12,952 95,800

Texas and Louisiana Lignite

 Texas ..................... 15,772 33,314 49,086 26,974 22,982 49,956

 Louisiana .................. 0 3,186 3,186 1,920 1,505 3,425

Total ....................... 15,772 36,500 52,272 28,894 24,487 53,381

Other Western Interior ....... c 3,302 673 3,975 662 33 695

Powder River Basin

 Wyoming . . . . . . . . . . . . . . . . . . 33 176,444 176,477 0 253,922 253,922

 Montana . . . . . . . . . . . . . . . . . . . 10 35,616 35,626 14 35,676 35,690

Total . . . . . . . . . . . . . . . . . . . . . . . 43 212,060 212,103 14 289,598 289,612

North Dakota Lignite

 North Dakota ............... 2,052 20,931 22,983 1,868 21,789 23,657

Total ....................... 2,052 20,931 22,983 1,868 21,789 23,657

Southwest

 Arizona ................... 0 11,447 11,447 0 11,782 11,782

 New Mexico ................ 0 22,644 22,644 0 25,055 25,055

Total ....................... 0 34,091 34,091 0 36,837 36,837

Rockies

 Colorado ................... 0 15,382 15,382 0 22,198 22,198

 Utah ...................... 0 15,237 15,237 0 18,012 18,012

Total ....................... 0 30,619 30,619 0 40,210 40,210

Northwest ................. d 0 4,696 4,696 0 4,626 4,626

Imported ................... 0 1,366 1,366 0 4,398 4,398

U.S. Total ................... 260,338 526,287 786,625 193,432 633,425 826,860

 High sulfur level is greater than 2.5 pounds of sulfur per million Btu’s. a

 Low-to-medium sulfur level is less than or equal to 2.5 pounds of sulfur per million Btu’s. b

 Includes Iowa, Oklahoma, Kansas, and Missouri. c

 Includes Alaska and Washington. d

 Source: Federal Energy Regulatory Commission (FERC) Form 423, “Monthly Report of Cost and Quality of Fuels for Electric Plants.”
AL AR GA IL IN OK MI MO

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Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 27

Energy Information Administration, State Coal Profiles, DOE/EIA-0576 (Washington, DC, January, 1994), p. 27. 38

Energy Information Administration, Coal Industry Annual 1994, DOE/EIA-0584 (Washington, DC, October 1995), p. 5. 39

Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants 1990, DOE/EIA-0191 (Washington, DC, August 40

1991), p. 56.

Alliance for Clean Coal vs. Craig, Docket No. 93C4391, December 15, 1993. 41

Figure 7. Coal Produced in Wyoming and

Delivered to Electric Utilities, 

1990 and 1995

 Source: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 33 and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

operation of existing mines. Shifts in coal supply sources

brought on by compliance with Phase I has a smaller

impact on these statistics.

The Midwest Demand Region

The Midwest, made up of the East North Central and

West North Central census divisions, had 134 Table 1

units with 42.8 gigawatts of capacity. In 1995, the

Midwest was the second largest recipient of coal of the

four regions, with 302 million tons; the region received

about 24 million tons more than in 1990.

Railroads, the major mode of transporting coal purchased

under contract to this region, were able to reduce rail

transportation costs between 1988 and 1993 because of rail

productivity increases and because coal transporters in

certain regions renegotiated contracts with utilities to

maintain market shares where possible. In 1990, five

States in the Midwest—Illinois, Indiana, Michigan, Ohio,

and Missouri—received more than 64 percent of the coal

received in the region.

The State of Illinois

Coal is abundant in Illinois and is the most valuable

mineral resource, exceeding crude oil and natural gas in

estimated total value. Underlying about two-thirds of the

State in relatively thick, flat-lying coalbeds, the coal is

bituminous in rank and has a high-sulfur content, averaging 2 to 3 percent by weight even when cleaned. In 38

1990, Illinois produced 60.4 million tons of coal, selling 39

15.5 million tons in the State. A large share was sold to

Missouri (12.4 million tons) and Indiana (9.7 million

tons). Two-thirds of the coal produced in Illinois is from 40

underground mines, most of which are large operations.

In choosing between scrubbing and switching, the four

Illinois utilities with 17 Table 1 units were faced with an

important economic decision that affected both the

utilities and the State: Illinois coal could continue to be

used; however, switching to lower sulfur coal meant

obtaining coal from sources outside of Illinois, thus

reducing the demand for a valuable State resource.

In 1991, the Illinois State legislature passed a clean air law

to protect Illinois coal producers. The law required

utilities to inform the State whether their Title IV plans

included use of Illinois coal before State approval was

granted. Similar laws were passed in Indiana, Oklahoma,

and Ohio. However, the Alliance for Clean Coal, a

coalition of western coal producers and railroads, filed

suit against the Illinois clean air law, arguing that it 41

violated Federal interstate commerce statutes; the Alliance

succeeded in having the Illinois law struck down. The
WA

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Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

28 on Electric Utilities: An Update

Figure 8. Coal Demand Regions

 Source: Energy Information Administration, Energy Policy Act Transportation Rate Study: Interim Report on Coal Transportation

DOE/EIA-0597 (Washington, DC, October 1995).

Coal Demand Regions

Northeast

Connecticut

Maine

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

Midwest

Illinois

Indiana

Iowa

Kansas

Michigan

Minnesota

Missouri

Nebraska

North Dakota

Ohio

South Dakota

Wisconsin

South

Alabama

Arkansas

Delaware

District of Columbia

Florida

Georgia

Kentucky

Louisiana

Maryland

Mississippi

North Carolina

Oklahoma

South Carolina

Tennessee

Texas

Virginia

West Virginia

West

Arizona

California

Colorado

Idaho

Montana

Nevada

New Mexico

Oregon

Utah

Washington

Wyoming
CO IL IN KY MT NM TN WV WY

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1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 29

Alliance for Clean Coal vs. Bayh, Docket No. IT94-890-C-T/G. March 22, 1995. Appealed and affirmed December 22, 1995. 42

In a recent ruling, U.S. District Judge John Holschuk dismissed the Alliance for Clean Coal suit to overturn a 1991 Ohio coal law (Case 43

No. C2-95-905) that gives regulatory and tax preferences to Ohio utilities that burn Ohio coal. Utility Environment Report, October 25, 1996,

p. 2. 

Energy Information Administration, Coal Industry Annual 1995, DOE-EIA-0584 (Washington, DC, October 1996), Tables 1 and 40. 44

Energy Information Administration, Coal Industry Annual 1995, DOE/EIA-0584 (Washington, DC, October 1996), p. 7. 45

Energy Information Administration, State Coal Profiles, DOE-EIA-0576 (Washington, DC, January 1994), p. 31. 46

Indiana Business Magazine, Vol. 39, No. 2, February 1995, p. 186. 47

Ibid. 48

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA- 

(Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

Figure 9. Origin of Coal Received in Illinois,

1990 and 1995

Alliance won a similar suit in Indiana and filed a suit 42

against the Ohio law in September 1995.43

Illinois coal production in 1995 fell to 48.2 million tons

(about 11.9 million tons were used in the State). One of

Illinois' main consumers, Missouri, purchased only 4.2

million tons, a reduction of 8 million tons from 1990, and

Indiana received 10.7 million tons, a slight increase from

1990. As consumers, the electric utilities in both Illinois

and Missouri in 1995 substituted a substantial amount of

lower sulfur coal from Wyoming for coal from

Illinois—Illinois received 14 million tons from Wyoming

(Figure 9) and Missouri increased its purchases from

Wyoming by 17.9 million tons. Between 1990 and 1995,

the number of operating mines in Illinois dropped from 45

to 31, while the average number of miners decreased on

average by 11 percent per year between 1990 and 1995

(10,018 to 5,652).44

The State of Indiana

In 1995, Indiana produced 26 million tons of coal, almost 45

10 million tons less than in 1990. Nearly all of the coal

was obtained from surface mines—bituminous in rank

and high in sulfur content. Second only to Texas in

annual consumption, Indiana is a large consumer of coal,

using about three-fifths of coal produced in the State.46

Indiana's excellent rail network and sophisticated port

facilities on Lake Michigan to the north and on the Ohio

River to the south make coal delivery to Indiana utilities

easy, but also makes the State vulnerable to penetration

by lower sulfur western coal.47

Because of the higher sulfur content of Indiana coal,

Indiana utilities affected by Phase I (15 plants housing 37

units) had to either scrub or modify their boiler units to

burn lower sulfur coal from other States. As of December

1995, utilities in the State installed scrubbers on seven

units at four plants and constructed a coal gasification

combined cycle project at the Wabash River Plant. This

clean coal technology project at Wabash River removes 98

percent of the SO from 2,700 tons of high-sulfur bitum- 2

inous coal each day. These compliance choices have

helped Indiana coal producers retain a share of the utility

market and preserve some of the 3,000 jobs (mining and

other coal industry jobs) in the State.48

Public Service of Indiana's Gibson plant, the third largest

coal-fired power plant in the United States, chose to scrub

its No. 4 unit to comply with Title IV and received

virtually all of its 1995 coal from Illinois (as it had in 1990).

In fact, Indiana received almost the same quantity of coal
CO IL IN KY MT OH VA WV WY

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Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

30 on Electric Utilities: An Update

Figure 10. Origin of Coal Received in Indiana, 

1990 and 1995

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report on Cost and Quality of Fuels for Electric Plants.”

Figure 11. Origin of Coal Received in Missouri,

1990 and 1995

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

in 1995 as it did in 1990 (about 49 million tons); however, Michigan combined PRB coal with 13 million tons of coal

this coal had a significantly lower sulfur content (24 from the central Appalachian region, while Missouri

percent lower). From 1990 to 1995, in-state coal use was combined PRB coal with 12 million tons from Illinois.

reduced by 5 million tons and coal from western

Kentucky was reduced by 3 million tons. Indiana utilities

increased their use of Wyoming coal by 6.3 million tons

(Figure 10), and slightly increased their use of coal from

Virginia, Illinois, and Ohio. In 1995, the number of mines

in operation dropped from 64 in 1990 to 42 in 1995.

Employment in the mines decreased on average by about

9 percent per year during this period.

The States of Michigan and Missouri

In 1990, Michigan received 30 million tons of coal and

Missouri received 24 million tons; Michigan had one plant

with 2 Table 1 units, while 8 Missouri plants had 16 Table

1 units. Both States received some coal from PRB in 1990;

In 1995, compliance programs in Missouri reduced Illinois

coal usage by 8 million tons, a large portion of the 23-

percent decline in coal originating from Illinois between

1990 and 1995. Missouri increased its 1995 total receipts

by 6.5 million tons from 1990, purchasing 25.6 million tons

from the PRB, and reduced its average sulfur content to

0.57 percent by weight, a 72 percent reduction in 1995

(Figure 11). Michigan replaced about 3 million tons of

Central Appalachian coal with 3 million tons of Powder

River Basin coal in the same period (Figure 12).

The State of Ohio

Ohio is part of the northern Appalachian coal production

region, which also includes Pennsylvania, Maryland, and
IN KY MT OH PA VA WV WY

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1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

on Electric Utilities: An Update 31

Energy Information Administration, Electric Power Annual 1995 Volume I, DOE/EIA-0384 (Washington, DC, July 1995). 49

“Western Coal Suppliers, Railroads Sue to Overturn Ohio Coal Protection” Law, Electric Utility Week, September 25, 1995, p. 77. 50

Energy Information Administration, State Coal Profiles, DOE/EIA-0576 (Washington, DC, January 1994). 51

Figure 12. Origin of Coal Received in Michigan, 

1990 and 1995

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

the northern portion of West Virginia. Ohio coal is

bituminous in rank and high in sulfur content (more than

3 percent by weight). In 1995, Ohio produced 26 million

tons of coal, 9 million tons less than in 1990; 66 percent of

the 1995 coal production was delivered to consumers in

the State. Ohio is the third largest coal-consuming State

after Texas and Indiana, and second in the Nation in the

amount of electricity generated from coal in 1995.49

Title IV targeted 14.3 gigawatts of Ohio's coal-fired

capacity (57.3 percent) as Table 1 units, which translates

to 41 units in 15 plants in the State. In early 1995, two wet

limestone scrubbers went into commercial operation for

Phase I compliance at the 2,600 MW Gavin plant of the

Ohio Power Company, the largest coal-fired plant in

Ohio.50

This $630-million-dollar project allowed the Gavin plant

to continue using Ohio coal—5.8 million tons in 1995

compared to 6.4 million tons in 1990. Ohio Edison’s Niles

plant used almost 100 percent Ohio coal in 1995 because

of the operating success of a year-old, $31 million LS-2

wet scrubber installed at generator No. 1, a 132.8 megawatt unit. Compliance strategies chosen for the remainder

of the Table 1 units in the State include the following: 16

units switched to lower sulfur coal, 20 units used

allowances, 1 unit was scrubbed, and 1 unit was retired.

Compliance with Phase I had some impact on Ohio’s coal

consumption. In 1995, Ohio received 48 million tons of

coal, a decrease of about 4 million tons from the total

receipts in 1990 and a decrease of 8 million tons of Ohio

coal (Figure 13). An 8-million-ton increase of coal from

central Appalachia supplemented Ohio receipts, resulting

in a drop of the average sulfur content by weight from

2.44 in 1990 to 1.89 in 1995. The number of mines

operating in Ohio in 1990 was 172, decreasing to 113 in

1995, while the number of miners decreased on average

by 10 percent per year during this period.

The Northeast Demand Region

The Northeast demand region is made up of the Middle

Atlantic and New England census divisions, which

include Connecticut, Maine, Massachusetts, New Hampshire, New York, New Jersey, Pennsylvania, Rhode Island,

and Vermont (Figure 8). In 1995, this region received 54

million tons of coal, with more than 70 percent (38 million

tons) received by Pennsylvania. In this region, 35 units at

16 plants were designated as Table 1 units. Pennsylvania

had the most, 21 units at 9 plants.

The Commonwealth of Pennsylvania

Pennsylvania has long been a major producer and

consumer of coal and led the Nation in coal production

until the early 1950's. In 1995, Pennsylvania produced 51

62 million tons of coal; approximately 47 percent
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Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

32 on Electric Utilities: An Update

Energy Information Administration, Coal Industry Annual 1995, DOE/EIA-0584(95) (Washington, DC, October 1996). 52

“Central Pennsylvania Coal Faces an Uncertain Future,” Coal, March 1996, p. 37. 53

Ibid. 54

Figure 13. Origin of Coal Received in Ohio, 1990 

and 1995

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

Figure 14. Origin of Coal Received in Pennsylvania,

1990 and 1995

BOM 1 PA = Bureau of Mines District 1, Pennsylvania.

BOM 2 PA = Bureau of Mines District 2, Pennsylvania.

Note: See glossary for specific counties in BOM Districts 1

and 2 in Pennsylvania.

Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA-0191

(Washington, DC, August 1991), Table 34; and Federal Energy

Regulatory Commission (FERC) Form 423, “Monthly Report of

Cost and Quality of Fuels for Electric Plants.”

remained in the State. The largest out-of-state shipments 52

went to New York, Ohio, and Michigan.

Pennsylvania is part of the northern Appalachian coalproducing region, an area that has seen a decline in

shipments to electric utilities in recent years. From 1990

to 1995, Pennsylvania reduced its total coal receipts by 6.3

million tons, with almost all of this decline occurring in

the central Pennsylvania coal production area (in Clearfield, Jefferson, Indiana, Cambria, Clarion, and Somerset

counties) (Figure 14). These counties are part of the U.S.

Bureau of Mines District 1 (BOM 1), a region populated by

small to mid-size producers facing a depleting reserve

base, escalating mining costs and shrinking demand.53

One large regional coal producer, Rochester & Pittsburgh,

closed two of its Helvetia mines in 1994 and three highcost Keystone mines in December 1995.54

In 1990, PP&L, a utility with three of its four coal-fired

plants targeted for Phase I reductions, purchased over 90

percent of its coal from central Pennsylvania. By 1995,

PP&L receipts from central Pennsylvania had fallen to 43

percent of its total receipts. This utility substituted 80
KY MD OH BOM

1 PA

BOM

2 PA

WV

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1990

KY OH BOM 1 PA BOM 2 PA WV

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1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

on Electric Utilities: An Update 33

Ibid. 55

Energy Information Administration, EPACT Transportation Rate Study: Interim Report on Coal Transportation, DOE/EIA-0597 56

(Washington, DC, October 1995), p. 61.

Energy Information Administration, State Coal Profiles, DOE/EIA-0576 (Washington, DC, January 1994), p. 103. 57

Figure 15. Origin of Coal Received in New York,

1990 and 1995

BOM 1 PA = Bureau of Mines District 1, Pennsylvania.

BOM 2 PA = Bureau of Mines District 2, Pennsylvania.

Note: See glossary for specific counties in BOM Districts

1 and 2 in Pennsylvania.

Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

percent of its Brunner Island plant purchases and 50

percent of its Martins Creek plant purchases with lower

sulfur coal supplies from Pittsburgh No. 8 seam in Greene

County (BOM District 2) (Figure 14). Utilities in the 55

State of New York reduced total coal purchases by almost

3 million tons in 1995; almost all of the decline was in the

central Pennsylvania area (Figure 15). More than twothirds of the coal produced in Pennsylvania comes from

underground mines. The number of miners has dropped

by 6,935 since 1990. The number of mines operating in

Pennsylvania was 459 in 1995, a drop of 32 percent since

1990.

The South Demand Region

The broad South demand region encompasses three census divisions: the South Atlantic census division (Delaware, District of Columbia, Florida, Georgia, Maryland,

North Carolina, South Carolina, Virginia, and West

Virginia); the East South Central census division (Alabama, Kentucky, Mississippi, and Tennessee); and the

West South Central census division (Arkansas, Louisiana,

Oklahoma, and Texas). Transportation to utilities in the

South region is dominated by long-distance rail hauls

from Appalachian and, more recently, western mines. As 56

the distance that contract coal was shipped by rail

increased and rail costs decreased slightly, more contract

coal was shipped by rail to utilities in the South than in

any other region in 1993.

Ninety-two generating units at 33 plants were designated

as Table 1 units in the South region. Tennessee and

Georgia had 19 Table 1 units each, followed by Kentucky

with 17 units, West Virginia with 14, and Alabama with

10 Table 1 units. Florida, Maryland, and Mississippi had

a total of 13 Table 1 units. Texas, the largest consumer of

coal at electric utility plants in the United States, had no

Table 1 units.

In 1995, six States dominated the coal purchases at electric

utilities: Kentucky purchased 37 million tons, West West Virginia has abundant bituminous coal resources

Virginia purchased 30 million tons, Georgia and Alabama underlying more than two-thirds of the State. The coal

each purchased 28 million tons, Florida purchased 24 deposits are divided geologically into the northern and

million tons, and Tennessee purchased 24 million tons. Of southern fields. Coalbeds in the southern field generally

the six States, Georgia, West Virginia, and Tennessee had have a higher heating value and a lower sulfur content

the highest 1985 SO emissions in the South region. than the northern field. With well-established railroad 2

The State of West Virginia

57
E. KY W. KY MD OH PA N. WV S. WV

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1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

34 on Electric Utilities: An Update

Ibid. 58

Energy Information Administration, Coal Industry Annual 1994 and Coal Industry Annual 1995, DOE/EIA-0584(94) and (95) (Washington, 59

DC, October 1994 and 1995).

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

Figure 16. Origin of Coal Received in West Virginia,

1990 and 1995

and river transportation facilities, coal production in the

State was 163 million tons in 1995. Most of the coal

produced is shipped outside the State.58

The 13 coal-fired electric utility plants in West Virginia

received approximately 30 million tons of coal in 1995;

about 86 percent came from within the State. Fourteen

units at six West Virginia plants were designated as Table

1 units. Monongahela Power and Virginia Electric &

Power installed scrubbers at two plants to comply, thus

earning allowance credits for five units at three plants.

Ohio Power used lower sulfur coal at two Table 1 units

and allowances at three Table 1 units.

Northern West Virginia, a higher sulfur coal producing

area, may have been affected by these compliance

strategies because the State decreased its use of coal from

northern West Virginia by about 2 million tons between

1990 and 1995 (Figure 16). The compliance programs of

its other customers had greater impact on northern West

Virginia, which is part of the hard-hit northern Appalachian region. The number of operating mines in

northern West Virginia declined from 205 in 1990 to 98 in

1995, and the number of miners working in the mines fell

on average by 9 percent per year during this period.

Between 1990 and 1995, the southern West Virginia lower

sulfur coal producing area experienced little impact from

the implementation of Phase I from its in-state customers

because these electric utilities maintained the same level

of in-state coal usage in 1995 as in 1990 (approximately 11

million tons). Total receipts originating from southern

West Virginia increased substantially because out-of-state

customers purchased more lower sulfur coal in 1995.

Although coal production from southern West Virginia

increased by 4 million short tons between 1990 and 1995,

the number of operating mines decreased from 566 to 326,

and the number of miners working in southern West

Virginia decreased from 19,525 to 15,220 during this

period. A number of small high cost mines in the region 59

are marginal producers and typically shutdown when the

price of coal is low and operate when prices are higher.

Between 1990 and 1995, the average delivered price of

low sulfur coal from southern West Virginia declined by

$10 per short ton.

The Commonwealth of Kentucky

With production of 154 million tons in 1995, Kentucky is

one of the major coal-producing States, third largest after

Wyoming and West Virginia. Kentucky coal deposits

consist of bituminous coal in two coalfields, one in the east

and the other in the west. The eastern coalfield is part of

the Appalachian coal basin where the coal has a heat

content of about 26 million Btu per short ton and a sulfur

content of 1 to 2 percent by weight. The heat content of
IL IN E. KYW. KY OH PA TN VA WV WY

0

5

10

15

20

25

Million Short Tons

1990

CO IL IN E. KYW. KY OH PA TN UT WV

0

5

10

15

20

25

Million Short Tons

1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

on Electric Utilities: An Update 35

Energy Information Administration, State Coal Profiles, DOE/EIA-0576 (Washington, DC, January 1994). 60

Figure 17. Origin of Coal Received in Kentucky,

1990 and 1995

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

the coal in the western field, which is a continuation of the

Illinois basin, is slightly lower, but the sulfur content is

higher (approximately 3 to 4 percent by weight).60

Electric utilities in Kentucky purchased 37 million tons of

coal in 1995, almost 2 million tons more than were

purchased in 1990. Seventeen units at 10 utilities were

designated as Table 1 units. Phase I compliance programs

resulted in a mixed impact on coal sales from Kentucky.

Eastern Kentucky, the lower sulfur coal producing area,

maintained the same level of coal sales within the State at

9 million tons in 1990 and 1995 (Figure 17). Eastern

Kentucky also increased its total coal shipments to electric

utilities but there was a shift from high to low and

medium sulfur coal. However, total coal production

declined by 10 million short tons. The operating mines in

eastern Kentucky decreased from 902 to 540 and the

number of miners decreased by 8,000, to 16,840. Western

Kentucky's in-state coal sales were reduced by 1 million

tons, having been replaced by coal from Colorado. The

number of operating mines in western Kentucky was

reduced from 85 in 1990 to 58 in 1995, and the number of

miners fell from 5,586 in 1990 to 4,285 in 1995 (Table 12).

Of the 17 Table 1 units in Kentucky, five were retrofitted

with scrubbers, 7 switched to lower sulfur coal, and 5

units were designated as using allowances. The average

sulfur content of the coal received in Kentucky was

reduced from 2.59 percent by weight in 1990 to 2.42

percent by weight in 1995.

The States of Georgia and Tennessee

Two other southern States of interest in the Title IV

program are Georgia and Tennessee because they each

had 19 units designated in Table 1. Georgia emitted

815,000 tons of SO in 2 1985 and 638,000 tons were emitted

in Tennessee. Although these States are not important

coal-producing States (Tennessee produced 3 million tons

in 1995 and Georgia produced none), their compliance

strategies affected coal sales in other States.

Georgia purchased almost the same amount of coal in

1995 as it did in 1990, approximately 28 million tons.

However, in 1995 its lower sulfur coal purchases from the

central Appalachian and PRB regions increased by 8

million tons, while its higher- and medium-sulfur coal

purchases fell by 8 million tons, with a 4-million ton

reduction in purchases from Illinois (Figure 18). Of the 19

Table 1 units, all owned and operated by Georgia Power,

18 were switched to lower sulfur coal and one unit at the

Yates plant was retrofitted with a scrubber.

In Tennessee, the total coal receipts for the State rose by

almost 3 million tons between 1990 and 1995, but no

significant source changes were made during that period.

Lower sulfur coal receipts from Utah and higher sulfur

coal receipts from Illinois increased by more than a

million each (Figure 19). The average sulfur content of

Tennessee's 1995 coal receipts decreased slightly from 2.00

in 1990 to 1.97 in 1995. All of the 19 Table 1 units in Tennessee are operated by the Tennessee Valley Authority

(TVA). TVA designated the use of allowances as the

compliance strategy for 14 units, retrofitted 2 units with

scrubbers and used lower sulfur coal for 3 units.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

36 on Electric Utilities: An Update

Table 12. The Number of Mines and the Average Number of Miners Working Daily by State for 1990 and 1995

State

1990 1995

Minesa Minersb Minesa Minersb

Alabama . . . . . . . . . . . . . . . . . . . . . . . 97 6,534 73 5,567

Alaska . . . . . . . . . . . . . . . . . . . . . . . . 1 84 1 102

Arizona . . . . . . . . . . . . . . . . . . . . . . . . 2 951 2 831

Arkansas . . . . . . . . . . . . . . . . . . . . . . 7 13 3 4

California ...................... 1 5

Colorado . . . . . . . . . . . . . . . . . . . . . . 23 2,009 17 1,777

Georgia .......................

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . 45 10,018 31 5,652

Indiana . . . . . . . . . . . . . . . . . . . . . . . . 64 4,195 42 2,571

Iowa . . . . . . . . . . . . . . . . . . . . . . . . . . 3 135

Kansas . . . . . . . . . . . . . . . . . . . . . . . . 4 132 1 54

Kentucky

 Eastern . . . . . . . . . . . . . . . . . . . . . 902 24,912 540 16,840

 Western . . . . . . . . . . . . . . . . . . . . . 85 5,586 58 4,285

Louisiana . . . . . . . . . . . . . . . . . . . . . . 2 103 2 114

Maryland . . . . . . . . . . . . . . . . . . . . . . 27 589 20 458

Missouri . . . . . . . . . . . . . . . . . . . . . . . 5 347 6 92

Montana . . . . . . . . . . . . . . . . . . . . . . . 9 821 8 722

New Mexico .................... 7 1,472 7 1,747

North Dakota . . . . . . . . . . . . . . . . . . . 11 931 6 716

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . 172 5,866 113 3,386

Oklahoma . . . . . . . . . . . . . . . . . . . . . 23 415 13 241

Pennsylvania

 Anthracite . . . . . . . . . . . . . . . . . . . . 187 1,687 134 1,069

 Bituminous . . . . . . . . . . . . . . . . . . . 486 14,216 325 7,899

Tennessee . . . . . . . . . . . . . . . . . . . . . 86 1,697 25 681

Texas . . . . . . . . . . . . . . . . . . . . . . . . . 15 2,131 14 1,590

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . 18 2,434 13 1,893

Virginia . . . . . . . . . . . . . . . . . . . . . . . . 340 10,342 194 6,919

Washington . . . . . . . . . . . . . . . . . . . . 4 777 3 566

West Virginia

 Northern . . . . . . . . . . . . . . . . . . . . . 205 10,053 98 6,114

 Southern . . . . . . . . . . . . . . . . . . . . . 566 19,525 326 15,220

Wyoming . . . . . . . . . . . . . . . . . . . . . . 33 3,330 29 3,142

U.S. Total ..................... 3,430 131,310 2,104 90,252

 Excludes silt, culm, refuse bank, slurry dam, and dredge operations, except for Pennsylvania anthracite. a

 Includes all employees engaged in production, preparation, processing, development, maintenance, repair, and shop or yard work b

at mining operations; includes mining operations management and all technical and engineering personnel; and excludes office

workers. The average number of miners working daily is the arithmetic mean number of miners working each day at a mining

operation.

 Sources: Energy Information Administration, Coal Industry Annual 1994, DOE/EIA-0584 (Washington, DC, October 1995), Tables

2 and 39; and Coal Industry Annual 1995, DOE/EIA-0584 (Washington, DC, October 1996), Tables 2 and 40.

The West Demand Region

The West demand region includes the Mountain and

Pacific census divisions (Arizona, Colorado, Montana,

Nevada, New Mexico, Utah, Wyoming, Oregon, and

Washington). This region received 108 million tons of coal

in 1995. Contract coal delivered to the region was

transported by rail, truck, conveyor, slurry pipeline, and

a combination of modes. The West demand region had no

Table 1 units because the coal burned in this region is

lower sulfur coal resulting in low SO emissions. 2

Wyoming and Utah, however, each have units that were

designated as substitution units. The West demand

region is an integral part of the Title IV compliance
AL IL E. KY W. KY OH TN VA S. WV WY

0

5

10

15

20

Million Short Tons

1990

AL IL E. KY TN VA S. WV WY

0

5

10

15

20

Million Short Tons

1995

IL IN E. KY W. KY TN VA WV

0

2

4

6

8

10

12

14

Million Short Tons

1990

CO IL IN E. KYW. KY PA TN UT VA WV

0

2

4

6

8

10

12

14

Million Short Tons

1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 

on Electric Utilities: An Update 37

Energy Information Administration, Coal Industry Annual 1995, DOE/EIA-0584 (Washington, DC, October 1996), Table 80. 61

Energy Information Administration, EPACT Transportation Rate Study: Interim Report on Coal Transportation, DOE/EIA-0597 62

(Washington, DC, October 1995), pp. 32-33. 

Figure 18. Origin of Coal Received in Georgia,

1990 and 1995

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

 Sources: Energy Information Administration, Cost and

Quality of Fuels for Electric Utility Plants 1990, DOE/EIA0191 (Washington, DC, August 1991), Table 34; and Federal

Energy Regulatory Commission (FERC) Form 423, “Monthly

Report of Cost and Quality of Fuels for Electric Plants.”

Figure 19. Origin of Coal Received in Tennessee,

1990 and 1995

program because it has become the major supplier of Wyoming coal fell 5 percent per year to $6.58 per ton in

lower sulfur coal to utilities in the Midwest and South 1995, and rail transportation rates for contract coal

demand regions. Central to this growth share by the West originating in Wyoming, Colorado, Utah, and Montana

demand region is the low delivered price of western coal. decreased by more than 20 percent between 1988 and

Between 1991 and 1995, the average mine price of 1993.

61

62
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 39

Energy Information Administration, Electric Utility Phase I Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990, 63

DOE/EIA-0582 (Washington, DC, March 1994), p. 99. Clean Air Act, Section 407 (b) (1). 64

Environmental Protection Agency, EPA Fact Sheet: Nitrogen Oxides Emission Reduction Program, EPA430/F-92/014 (Washington, DC, 65

October 1992).

Federal Register 40 CFR Part 76. 66

Ibid. 67

U.S. Environmental Protection Agency, EPA Fact Sheet, Nitrogen Oxides Emission Reduction Program: Proposed Rule for Phase II, Group 68

1 and Group 2 Boilers, EPA Number (http://www.epa.gov/docs/acidrain/noxfs2.html).

4. Developments Since Phase I Took Effect

Since Phase I began on January 1, 1995, some produce a rotating flame within the chamber. CAAA90

developments have been noteworthy. First, the U.S. instructs EPA to set less rigid standards if it finds that the

Environmental Protection Agency’s (EPA’s) initial rule for legislated limits cannot be achieved using low-NO

a group of Phase I boilers’ nitrogen oxides (NO ) re- burner technology. The legislation specifies the maxi- x

ductions was vacated by a U.S. Court of Appeals; EPA mum allowable emission rates for Group 1 boilers as 0.45

subsequently reissued the rule for these boilers. A rule for pounds of NO /mmBtu for tangentially fired boilers and

other Phase I and Phase II boilers has been issued. Second, as 0.50 pounds/mmBtu for dry-bottom, wall-fired boilers

the regulation of air toxics are unclear at this time. Third, (other than units applying cell-burner technology). About

significant developments have been made in air pollution one-quarter of all Group 1 boilers are covered in Phase I

control technology. This chapter summarizes these latest of the SO program.

developments.

Programs for the Control 

of Nitrogen Oxides Emissions

Original Rule for Phase I, Group 1 Boilers

Title IV of the Clean Air Act Amendments of 1990

(CAAA90) calls for EPA to establish regulations for the

reduction of NO emissions from coal-fired utility boilers x

in two stages. In the first stage, two categories of boilers

affected by Phase I of the sulfur dioxide (SO ) program 2

are covered: tangentially fired boilers and dry bottom

wall-fired boilers (Group 1). “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 The final rule removed a requirement that wall-fired and

to melt the ash before it leaves the boiler. “Wall-fired” tangentially fired boilers must use an over-fire air process

and “tangentially fired” refer to the placement and to be eligible for the previously mentioned less stringent

orientation of burners in the combustion chamber. The emissions controls. The rule also extended the date for

burners of wall-fired boilers are perpendicular to the wall complying with the first stage from January 1, 1995, to

of the chamber, either all on one wall (front) or split January 1, 1996. EPA estimates that the final Phase I rule

between two facing walls (opposed). Tangentially fired will cut annual emissions of NO from Phase I, Group 1

burners are spaced around the chamber and angled to boilers by 400,000 tons beginning in 1996.

63

x

64

x

2

65

Final Rule for Phase I, Group 1 Boilers

On March 22, 1994, EPA promulgated a rule establishing

the Phase I Group 1 NO emissions reduction program. x

66

However, on November 29, 1994, after a challenge from

utility groups, the U.S. Court of Appeals for the District of

Columbia Circuit found that the definition of low-NO –x

burner technology contained in the March 22 rule

exceeded EPA’s statutory authority. The Court vacated

the rule and sent it back to EPA. On March 28, 1995, EPA

signed an agreement with environmental and utilityindustry parties that addressed the March 22, 1994,

regulations and the issues raised by the Court’s remand,67

and on April 13, 1995, it issued a final rule revising the 68

definition of low-NO –burner technology. x

x
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

40 on Electric Utilities: An Update

Ibid. 69

Ibid. 70

Mining Week, National Mining Association, Issue 48, Vol. 2, Washington, DC, December 23, 1996, p. 2. 71

Rule for Phase II, Group 1 Boilers and for

Group 2 Boilers

On December 19, 1996, EPA issued a rule to implement

the second stage of the NO reduction program by estab- x

lishing NO emissions limitations for additional coal-fired x

boiler units and by revising NO emissions limitations for x

Group 1 boilers. EPA’s charge for the second stage of the

NO program was twofold: (1) to determine whether the x

technology existed that would make it feasible for EPA to

establish more stringent standards in Phase II for the

Group 1 boilers than those established in Phase I; and

(2) to establish limitations for the boilers known as Group

2 (boilers applying cell-burner technology, cyclone boilers,

wet-bottom boilers, and other types of coal-fired boilers)

based on NO control technologies that are comparable in x

cost to low-NO burners. x

According to EPA, the total Group 1 reductions beginning

in 2000 will be approximately 1.2 million tons. The total

cost of this regulation to the industry is estimated to be

$267 million per year, resulting in an overall cost of $227

per ton of NO removed. Group 2 reductions beginning in x

2000 are estimated to be 890,000 tons annually. The

annual cost of the Group 2 regulations is estimated to be

approximately $200 million with an average cost of $229

per ton of NO removed. x

69

Toughening of Phase II, Group I Boiler

Limitations Based on Modeling

From the results of two analyses, EPA concluded that data

currently available on the effectiveness of low-NO burner x

technology supported revisions of the annual limitations

for both dry-bottom, wall-fired boilers and tangentially

fired boilers under the second stage of the NO program. x

EPA projects that 85 percent to 90 percent of the

uncontrolled bottom wall-fired boilers and tangentially

fired boilers could individually meet the proposed

standards.

The NO emission limitations for each boiler type follow x

in Table 13. 

A utility can choose to comply with the rule in one of

three ways: 

1. Meet the standard annual emission limitations

2. Average the emissions rates of two or more boilers

(This allows utilities to “over-control” the emissions

of those units that can be controlled more easily

and less expensively than others.)

3. Apply for a less stringent alternative emissions

limit if the utility cannot meet the standard

emissions limit if it uses the applicable NOx

emission control technology.

EPA’s determination of an alternative emissions limitation

will be based on evidence that control equipment was

properly designed, installed, and operated during a

demonstration period. 

Phase II, Group 1 and Group 2 boilers are required to

meet applicable limits by 2000. The highlight of the new

rule is that, although it relies upon target performance

standards, it also allows for emissions averaging and the

use of alternative, higher emissions limits where meeting

the applicable limits is not feasible. Utilities choose the

method of compliance that best suits their needs. EPA

states that this approach provides flexibility, promotes

technology development and competition, and provides

opportunities to reduce the cost of control. However, 70

some industry groups state that the new rule “will impose

unreasonable burdens on up to 1,000 coal-fired units.”71

EPA has also devised an option whereby a state or group

of states could petition EPA to accept an emissions cap

and trade program under authority of Title I as a substitute for compliance with the final Title IV rule. Under

such an option, EPA retains the authority to allow boilers

subject to the final rule to achieve emissions reductions

under a Title I cap and trade program as long as capping

and trading would achieve lower emissions than the final

rule. Existing limits for Phase I, Group 1 boilers would

remain in effect. EPA believes that such a trading
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 41

U.S. Environmental Protection Agency, Nitrogen Oxides Emission Reduction Program, Final Rule for Phase II, Group 1 and Group 2 72

Boilers (http://www.epa.gov/docs/acidrain/noxfs3.html).

“EPA’s Utility Toxics Report Will Be Delayed by at Least Two Months,” Inside EPA’s Clean Air Report (April 18, 1996), p. 18. 73

Environmental Protection Agency, Office of Air Quality Planning and Standards, Study of Hazardous Air Pollutant Emissions from Electric 74

Utility Steam Generating Units—Interim Final Report, EPA-453/R-96-013a (Research Triangle Part, NC, October 1996).

Teresa Hansen, “Air Toxicities Controls Unlikely,” Electric Light & Power (December 1995), p. 21. 75

Ibid. 76

“Improving Common Control Devices,” Atmospheric Monitoring & Abatement News (August 1995), No. 7, Vol. 3. 77

Table 13. Phase II, Group 1 and Group 2 Boiler Statistics and Emission Limitations

Boiler Types Number of Boilers

Proposed Phase II NOx

Emissions Limits

(Pounds/mmBtu)

Phase II, Group 1

 Dry-Bottom, Wall-Fired . . . . . . . . . . . . . . . . . . . . . . . . . 308 0.46

 Tangentially fired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299 0.40

Group 2

 Cell Burners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 0.68

 Cyclones > 155 MW . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 0.86

 Wet-Bottom, Wall-Fired > 65 MW . . . . . . . . . . . . . . . . 26 0.84

 Vertically Fired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 0.80

 Source: United States Environmental Protection Agency, Nitrogen Oxides Emission Reduction Program, Final Rule for Phase II,

Group 1 and Group 2 Boilers (http://www.epa.gov/docs/acidrain/noxfs3.html).

provision provides for coordination of NO reduction interim report and plans to publish a final utility HAP x

initiatives under Titles I and IV and promotes the goal of report at a later date.

achieving necessary NO reductions in a c x ost-effective

manner.72

Discussion of Air Toxics–Title III

Under Title III of CAAA90, EPA is responsible for determining the hazards to public health posed by 189

hazardous air pollutants (HAP’s). Title III specifically

directs EPA to perform a study of the HAP’s (also known

as air toxics) to determine which hazards are likely to

occur as a result of emissions by electric utility steamgenerating units, and to report the results to Congress.

This study must be completed prior to promulgating any

new regulations. CAAA90 also required EPA to recommend whether to control 189 air toxics, including mercury, by November 15, 1995. However, this deadline has

been delayed. The mercury studies, while still pending,

are intended to evaluate human health and ecological

impacts of all mercury emitting sources in the United

States. EPA has submitted to Congress an interim final 73

report on the “Study of Hazardous Air Pollutant

Emissions from Electric Utility Steam Generating Units”

regarding the emissions, fate, and transport of utility

HAP’s. EPA has not evaluated exposure to mercury 74

emissions from utilities for humans or wildlife in this

In addition to the studies required by CAAA90, studies on

air toxics and mercury and potential regulations are being

considered at the State level. Minnesota, Florida, and

New Jersey are among those States that are currently addressing the potential impact of air toxics.75

Title III states that individual facilities may not exceed

emissions of 10 tons per year (t/yr) for a single HAP or

25 t/yr for any combination of HAP’s. However, even if

a power plant falls below these limits, control requirements for a single HAP could be imposed because limits

can be lowered based on pollutant potency, persistence,

bioaccumulation, or other factors. Mercury is a special 76

concern because of its environmental behavior and the

level of mercury contamination in water due to its bioaccumulation in fish. The level of mercury in raw coal is

very small, typically only 0.05-0.10 parts per million

(ppm). This results in trace mercury concentrations from

stack emissions of about 1 part per billion (ppb).77

The U.S. Department of Energy (DOE) and the Electric

Power Research Institute (EPRI) have performed extensive

research on mercury. Results of the studies show significant variations in the amount of mercury removed by
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

42 on Electric Utilities: An Update

Teresa Hansen, “Air Toxicities Controls Unlikely,” Electric Light & Power (December 1995), p. 21. 78

Ibid. 79

Jason Makansi, “Despite market uncertainty, a few new approaches come forward,” Power (March, 1996), p. 25. 80

Electric Power Research Institute, PSE&G Demonstrated SNCR Technology for NOx Control at Mercer Station (July/August 1996), p. 34. 81

Jason Makansi, “Work with existing hardware to maximize emissions control,” Power (March 1995), p. 41. 82

electrostatic precipitators; these variations range from ammonia react to form nitrogen and water vapor. SNCR

about 15 percent to 75 percent. Although data are limited, involves uncatalyzed or thermal reaction with ammonia.

mercury removed from baghouses ranges from 10 percent SCR technology is now incorporated in some new coalto 70 percent. Mercury removal from wet scrubber fired plants and is the mainstay of NO reduction efforts.

systems ranged from 0 percent to about 50 percent. Several large coal-fired units have incorporated SCR 78

Much of the variation in removal performance may have technology, including two plants in New Jersey and one

been caused by the difference in the chemical form of the in Florida, and a fourth plant in Florida with full-flow

mercury in the flue gas. Mercury emissions from coal SCR units. One development that may enhance SCR

combustion have been shown to vary considerably from applications even further is the evolution of lightweight

site to site. The chemical composition of coal varies widely catalysts. Some of these new catalysts weigh more than 50

and so does the concentration of mercury. If EPA decides percent less than traditional extruded ceramic or metalthat hazardous air pollutants pose a risk, then it must based catalysts.

propose air toxic emissions controls by November 15,

1998, and make them final by November 15, 2000. Such Another technology for controlling NO emissions from

controls are potentially costly, especially for coal-fired wet-bottom boilers—SNCR—was demonstrated by Public

power plants. Service Electric and Gas Company of New Jersey 79

Technology Refinements

The electric industry faces a number of potential environmental control regulations in addition to Title IV of

CAAA90, such as fine particulate and air-toxics (Title III)

regulations; solid-waste restrictions; global warming and

carbon dioxide (CO ) discharges; water management; and 2

differing State, regional, and local regulations. Increased

competition and the eventual disappearance of the

regulated rate of return have caused the electric utility

industry to attempt to reduce the costs of compliance with

Title IV of Phase II in 2000 or to coordinate the compliance

strategies so they also comply with other regulations.

Also, efforts may be necessary to meet regional NOx

reduction requirements associated with Title I and ozone

nonattainment. Thus, refinements continue with the

primary NO reduction technologies and with particulate x

control.

Nitrogen Oxides Reduction

Combustion in conventional pulverized coal systems

occurs at temperatures that produce significant amounts

of thermal NO as well as fuel-bound NO . Ad- x x

vanced techniques for post-combustion NO control x

include Selective Catalytic NO Reduction (SCR) and x

Selective Noncatalytic Reduction (SNCR). SCR technology

consists of injecting ammonia into boiler flue gas and

passing it through a catalyst bed where the NO and x

x

80

x

(PSE&G), at its coal-fired Mercer Station. This technology

is less costly than SCR. The New Jersey demonstration

should benefit other utilities with wall-turbo-fired boilers

and cyclone-fired boilers for which SNCR is now a viable

NO control option. The results indicate that SNCR may x

be adequate to bring some boilers into compliance with

CAAA90. In addition, PSE&G demonstrated in subsequent testing that SNCR can be combined in a hybrid

SNCR/SCR system to achieve 90 percent NO reduc- x

tions—a level equivalent to that achievable with

conventional SCR.81

Other methods to reduce NO emissions include replacing x

or tuning pulverizers, upgrading components, balancing

coal and air flows to individual burners, and correlating

coal specifications with boiler operating parameters more

closely. Experts concede that these strategies can approach

or exceed the reduction available from low-NO burners. x

So much progress has been made in reducing NO emis- x

sions through combustion modifications that the term

low-NO burner has less meaning today than when the x

CAAA90 was passed. The entire fuel preparation and

furnace system must be optimized for minimum NOx

formation.82

Control system upgrades, which are often applied in

combination with hardware modifications and instrumentation additions, can also achieve low-cost NO reductions. x

By measuring and manipulating air and/or fuel flows

accurately with better process software and computer

technologies, it is possible to automate and optimize the
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 43

Ibid. 83

Ibid. 84

Ibid. 85

Jason Makansi, “Despite market uncertainty, a few new approaches come forward,” Power (March 1996), p. 25. 86

Ramsy Chang, “COHPAC compacts emission equipment into smaller, denser unit: Compact Hybrid Particulate Collector,” Power 87

Engineering (July 1996), p. 22

process. A variety of software packages have been de- statically. The electrostatic force promotes the

veloped for this process, resulting in sizeable reductions attraction between SO and fly ash particle surfaces.

in NO emissions. These software packages have the A discharge frame with a high-tension power x

potential to greatly reduce or possibly eliminate the hard- source is added to the ductwork upstream, which

ware component of a NO control retrofit. complements the diffusion mass transfer process x

83

Particulate Collection

U.S. utilities have used electrostatic precipitators (ESP’s)

and fabric filters or baghouses to control particulate

emissions at coal-fired plants for some time. These devices have enabled utilities to meet applicable emissions

and opacity standards. However, the possible impact

of more stringent particulate emissions requirements and

the differences in ash quality as coals are switched to lowsulfur have prompted utilities to make these control

devices more effective. Given these factors and the pressures of competition, utilities with coal-fired plants will

have to determine how to cost-effectively improve particulate control. A list of some options follows.

  Flue-gas conditioning (FGC), usually with sulfur

trioxide (SO ) injection, is a proven method of 3

improving the collection of fly ash in ESP’s. With

increasing competition among suppliers in

emissions-control systems, costs are falling and

performance is improving. This system converts

the SO already in the gas stream into SO and 2 3

avoids a separate feedstock/reagent. This system

has been demonstrated and commercially installed.84

  Another approach to improving fly ash removal is

to enhance the conventional FGC process electro3

that normally occurs with FGC.85

  In the last 2 years the Compact Hybrid Particulate

Collection System (COHPAC) was developed,

which is a high-efficiency, compact pulse-jet fabric

filter (PJFF) that operates downstream as a separate

collector of an existing ESP or in the last one or two

fields of the ESP. COHPAC systems utilize PJFF’s

because utilities can pack the filter bags closely in

baghouse compartments with a reduction in baghouse size and cost when compared to a

conventional fabric-filter application. At a minimum, COHPAC systems allow utilities to upgrade

some underperforming ESP’s and achieve clear

stacks. In addition, because this process collects fine

particles efficiently, it shows promise for its ability

to control air toxics as well. 86 87

These techniques can form the basis for improvements in

basic power plant design when emissions control considerations are factored into every major power plant

component. Selection of techniques or equipment is based

on optimizing project priorities, such as initial capital cost,

operating costs, efficiency, emissions, maintainability, and

unit operating flexibility. Most of these techniques seek to

accomplish critical processes in smaller spaces, which

leads to constraints on residence times, flow distribution,

measuring capabilities, maintenance procedures, and

operating flexibility.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 45

“Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery 88

of Stranded Costs by Public Utilities and Transmitting Utilities,” Docket Nos. RM95-8-000 and RM94-7-001, Order No. 888 (April 24, 1996).

Edison Electric Institute, Financial Information, 1995 Construction Expenditures Surveys (Washington, DC, September 9, 1996). 89

“Fuel-Switching Outpacing Scrubbers as U.S. Utilities Comply with CAA,” Asbestos & Lead Report, No. 1, Vol. 8 (January 23, 1995). 90

For the impact of lower sulfur coal on an individual plant, see Energy Information Administration, Electric Utility Phase I Acid Rain 91

Compliance Strategies for the Clean Air Act Amendments of 1990, DOE/EIA-0582 (Washington, DC, March 1994), p. 13. 

5. Phase II

Increased competition has caused the electric utility However, Phase II, which takes effect on January 1, 2000,

industry to face major changes in the way it is structured. will have an even larger impact on more generating units

On April 24, 1996, the Federal Energy Regulatory Com- than Phase I. In Phase II, allowances are allocated at the

mission (FERC) issued the final rule, Order No. 888, in rate of 1.2 pounds of SO times the number of million 88

response to provisions of the Energy Policy Act (EPACT) Btu’s consumed in the baseline. Although utilities have

of 1992. Order No. 888 opens wholesale electric power not finalized their plans to comply with the more stringent

sales to competition and requires each utility that owns Phase II requirements, most of them have elected to

transmission lines to allow buyers and sellers of power the overcomply with Phase I requirements, thus creating a

same access to those lines as the utility provides to its own surplus of excess allowances. This is one way of deferring

generation. higher-cost Phase II compliance strategies beyond 2000. 

In a noncompetitive environment, State regulators allowed electric utilities to pass on the costs of pollution

control requirements to consumers in the form of higher

electricity rates. In a competitive market, utilities that

have higher rates because of environmental controls

would be at a relative disadvantage, while those with

lower overall costs could increase their market share.

With increasing competition and with Phase II of

CAAA90 slated for implementation on January 1, 2000,

utilities are showing less interest in making capital investments in expensive pollution control equipment, are

uncertain about cost recovery, and want to be more

competitive. In 1995, an Edison Electric Institute survey

of investor-owned utilities for Phase II compliance shows

they have not yet significantly increased construction

spending; however, utilities are expected to spend $789

million per year from 1996 through 1998.89

.

Current Strategies for Phase II

Compliance with Phase I of CAAA90 has required major

investments by utilities. In Phase I, allowances are allocated at the rate of 2.5 pounds of sulfur dioxide (SO )2

times the number of million British thermal units (Btu’s)

consumed in the 1985-1987 baseline. 

2

The following is a general discussion of what is currently

known about compliance plans for Phase II. It is derived

from a survey of 116 utilities conducted by Industrial Information Services of Reno, Nevada. Forty-one percent of

the respondents plan to switch fuels. The acquisition of

acid-rain emissions allowances is the second most popular

compliance choice, with 28 percent indicating they will do

so.90

Fuel Switching/Blending

Fuel switching/blending to lower sulfur coal in generating units will probably be the predominant strategy

used by utilities to comply with Phase II of the CAAA90,

just as it was for Phase I. Compared to scrubbing and

repowering, the fuel switching/blending strategy involves lower capital costs, takes less time to implement,

and offers flexibility in meeting future emission requirements. Because power plants are generally designed for a

particular type of coal, switching to a different coal, such

as lower sulfur coal, requires an assessment of the new

fuel’s effects on the individual plant. The new coal can

affect the performance of boilers and ESP’s, as well as

operations and maintenance procedures.91
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

46 on Electric Utilities: An Update

A layer of ash, resistant to being charged, accumulates on the precipitator causing the degrading of the performance and necessitating 92

manual cleaning. Sodium treatment of the particulate material can be used to reduce ash resistivity and improve the precipitator performance.

“Environment Week: Environmental Brokerage Services SO Allowance’s Sharp Price Decline Attributed Mainly to Low-Sulfur Coal,” 93

2

Air/Water Pollution Report, No. 4, Vol. 34 (January 19, 1996).

Massachusetts Institute of Technology, for the Proceedings of the Second Workshop on Energy Externalities, Brussels, September 9-10, 94

1996, Draft, The U.S. Allowance Trading Program for Sulfur Dioxide: An Update After the First Year of Compliance (Cambridge, MA, October 29,

1996), p. 14.

“Pollution Control for Cash,” Independent Energy, Vol. 25, No. 1 (January 1995), p. 52. 95

“Environment Week: Environmental Brokerage Services SO Allowance’s Sharp Price Decline Attributed Mainly to Low-Sulfur Coal,” 96

2

Air/Water Pollution Report, No. 4, Vol. 34 (January 19, 1996).

Because lower sulfur coal is usually lower in heating decrease in efficiency. However, the high capital cost of

value (Btu rating), fuel switching/blending may require retrofitting coal-fired boilers to burn natural gas is the

the firing of a larger volume of coal to generate the same reason that utilities seldom choose this strategy for

amount of power. A larger volume of coal requires more meeting emission requirements of CAAA90.

storage space and an increase in coal-handling facilities.

Generating capability could be constrained by coalhandling considerations if the volume of lower sulfur coal

is increased substantially. In addition, an increased

volume of coal could require ESP modifications to handle

the increased fly ash or boiler derating so as not to

overload the ESP. Also, the boiler heat rate could be

adversely affected if boiler redesign is required to

accommodate the new lower sulfur coal. 

Burning western lower sulfur coal results in more

particulate matter (PM) emissions than burning eastern

high-sulfur coal. In addition, the coal resistivity may 92

change and degrade ESP collection efficiency. These

changes can require alterations to the ESP’s. Finally, different coals may cause different HAP emissions. Because

utility coal-fired plants are designed for certain coal types,

it takes a couple of years to test fire several lower sulfur

coals to determine which one reduces emissions.

Co-firing With Natural Gas

Natural gas is the cleanest of the fossil fuels available for

use in power generation and has the potential to reduce

emissions without great cost. The use of nearly sulfur-free

natural gas instead of sulfur-containing coal can significantly reduce SO emissions, and the potential exists for The typical allowance sales have been made by an eastern 2

reduced NO emissions, depending on burner charac- ut x ility that has installed scrubbers to a midwestern utility

teristics. Co-firing with natural gas can also reduce without scrubbers. Also, many utilities bank their allowHAP’s, carbon dioxide, fly ash, and disposal needs. ances. For instance, the Atlantic City Electric Company,

Natural gas firing has lower operation and maintenance which owns two coal-fired generating stations, cut its

costs than coal firing. However, the fuel costs are higher, emissions in half between 1990 and 1995, primarily by

and access to a nearby pipeline is a requirement for this adding a stack scrubber. The excess emission allowances

option to be economical. In addition, few coal-fired boilers will be held for use in Phase II. The allowances will be

are designed to co-fire natural gas. Although many can be depleted by 2012, so the company must decide before then

retrofitted, usually with separate burners for gas and coal, how to meet future long-term generating and emission

a boiler switched from coal to gas may experience a requirements.

Allowances

Just as it has been for Phase I, allowance acquisition is

expected to be the second most popular choice for Phase

II compliance—after fuel switching/blending. According

to a study by Resource Data International, a Colorado

research firm, utilities are over complying because the

price of buying and using lower sulfur coal is less than

originally projected and because of the flexibility

provided by the EPA Title IV sulfur dioxide allowance

program. The coincidence of mining efficiencies and rail

deregulation and competition have made clean-burning

coal from Wyoming’s Powder River Basin as cheap, or

cheaper, than the high-sulfur coal of the Midwest.93

Allowance credits are so inexpensive today that years of

allowance credits can be purchased for less than the cost

of the capital equipment for pollution control. Allowance

prices are much lower than expected primarily because of

the reduction in lower sulfur coal prices. Allowance and

the coal markets are increasingly integrated. This activity 94

in emission allowance credits, which can be traded or

sold, creates the possibility of running a pollution control

system as a revenue source at least in the short term.95

96
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 47

“Why Taxes Do Distort Emission Trading,” Fortnightly (February 15, 1995), p. 42. 97

“U.S. Utilities Opt Against Scrubbing,” International Coal Report (October 30, 1995). 98

Ibid. 99

Ibid. 100

Energy Information Administration, Inventory of Power Plants in the United States, DOE/EIA-0095(95) (Washington, DC, December 1996), 101

p. 20.

Some utilities have expressed that the Federal tax system The Electric Power Research Institute (EPRI) estimates

interferes with the intended operation of the emission that no more than 12 gigawatts to 20 gigawatts of

allowance market. Because the Internal Revenue Service generation capacity may be scrubbed to comply with

(IRS) assigns a zero tax basis to the allowances in the Phase II requirements, and the actual total is likely to be

hands of the original owners, all proceeds from the sale of closer to 12 gigawatts than 20 gigawatts. This modest

allowances are fully taxable and subject to a capital gains scrubber forecast reflects the impact of fuel switching, low

tax. Internal utility uses, however, such as stockpiling of SO allowance prices, and the delay in fulfilling scrubber

emissions allowances, do not trigger taxation. This commitments for as long as possible. The utilities that are

situation obviously favors internal use by utilities. over complying with Phase I have allowance credits they

Legislation has been submitted to Congress to address this can use to delay their own Phase II scrubbing, or to sell to

problem. other utilities that want to delay Phase II actions. 97

The SO allowance and market trading system has been many cases capital for scrubbers will not be committed 2

successful in producing SO reductions faster and less until after the year 2000. 2

expensively than expected. It has also encouraged technological and economic innovation. For example, high- This scenario could change if EPA air toxics regulations

sulfur coal companies are buying allowances to package are issued in the future, requiring reductions in air toxics,

with their coal sales. By bundling allowances with the including mercury. Most of these hazardous emissions

coal, these companies can compete with lower sulfur coal are fairly easily controlled, except mercury, with wet

because the allowances included in the “bundle” scrubbers. Some States in the East and the Midwest are

compensates for the higher sulfur content. considering air toxics control.

Scrubbers Repowering

A number of scrubbers planned for Phase II are being As of January 1, 1996, fossil-fuel electric operable capacity

deferred. For example, scrubbers on Mount Storm No. 1 accounted for 72 percent of U.S. electric utility net summer

and No. 2, Virginia Power; Montour, Pennsylvania Power generating capability. In the year 2010, average

and Light (PP&L); and Homer City No. 3, Pennsylvania age—weighted by capacity—of the Nation’s coal-fired

Electric are no longer planned for 2000, although they units will be 39 years, gas-fired units 40 years, and oilmay be retrofitted later. The two 750-megawatt coal-fired fired units 40 years (Figure 20). One method for

generating units at the Montour station will not be fitted maintaining generating capacity online or adding capacity

with scrubbers before 2004 at the earliest, a decision that to a utility system, while working toward meeting SO

PP&L projects will save an estimated $400 million in requirements, is to repower older fossil-fuel units.

capital costs over the next 5 years. PP&L will buy lower

sulfur coal, use emission allowances already earned, and Repowering existing power plants can be an economical

purchase additional allowances to achieve Phase II way to turn unused or underutilized plants into profitable 98

compliance. assets. The newer technology can be used to reduce emisCarolina Power & Light plans to switch all of its plants to The technologies used for repowering include gas

compliance coal by 2000. In 2007, it will install a scrubber turbines; heat-recovery steam generators and feed water

at one of the largest of its 20 coal-fired units. Dayton heaters; and coal-gasification combined-cycle, atmosPower & Light, owner or part-owner of a number of pheric fluidized-bed, or pressurized fluidized-bed

plants located in the high-sulfur coalfields of Ohio, plans combustion combined-cycle systems. 

to switch to lower sulfur coal and to bank a substantial

number of credits during Phase I, to make up for the Repowering candidates include oil- and gas-fired plants

expected allowance deficits after 2000. as well as coal-fired plants that face significant emissions 99

2

100

Planning and building a scrubber takes 4 years, so in

101

2

sions to comply with CAAA90 and increase efficiency.
19

29

39

22

30

40

23

30

40

1990 2000 2010

0

10

20

30

40

50

Coal

Oil

Gas

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

48 on Electric Utilities: An Update

Teresa Hansen, “Utilities to Spend $1.4 Billion on Power Plant Maintenance,” Electric Light & Power (February 1996), p. 17. 102

“SO Banking Allows Utilities to Delay Repowering of Coal-Fired Plants,” Energy Report, No. 42, Vol. 23 (October 30, 1995). 103

2

Figure 20. Average Age (Weighted by Capacity) of

Fossil-Fuel Units, 1990, 2000, and 2010,

as of January 1, 1996

 Note: The average unit age includes existing units, planned

retirements, and planned capacity additions.

 Source: Energy Information Administration, Form EIA-860,

“Annual Electric Generator Report.”

reductions to satisfy Phase II of CAAA90. Repowering

power plants usually increases their capacity, the extent of

which depends on the repowering procedure is used.

However, even though Title IV includes specific incentives to repower fossil plants with clean-coal technology,

barring the DOE’s Clean Coal Technology projects, no

utility has announced a repowering project for the sole

purpose of meeting CAAA90 Phase I or II emission

requirements.102

Most of the fossil units proposed for repowering from

1996 through 2005 (Table 14) have relatively small net

summer capabilities. The proposed repowering of fossil

capacity from 1996 through 2005 is 2,501.1 megawatts.

This includes repowering 589.5 megawatts of natural gas

steam turbine-boilers to burn natural gas again,

repowering 219.0 megawatts of bituminous steam-turbine

boilers to burn bituminous coal again, repowering 536.9

megawatts of natural gas combustion turbines to burn

natural gas, repowering 43.2 megawatts of No. 2 fuel oil

combustion turbines to burn natural gas, and repowering

80.0 megawatts of No. 6 fuel oil steam turbines to burn

natural gas. The last two repowering options are the only

ones that change fuel. Repowering with natural gas is a

significant option for fossil units.

Some estimates indicate that utilities could bank an excess

of up to 15 million SO allowance credits by the time 2

Phase II begins on January 1, 2000. After the Phase I

credits are depleted, the utilities will then have to reduce

emissions, and repowering can help meet that need.

Because repowering is cheaper than building a new

generating unit, repowering will be used to meet some of

the future capacity needs.103

Retirements

The planned fossil-fuel capacity retirements slated to take

place from 1996 through 2005 (Table 15) include much

smaller percentages of coal-fired units than petroleum or

gas when compared to the generator nameplate capacity

for the energy source. Just six coal-fired units are

projected to retire before the start of Phase II, with six

other coal-fired units retiring after the year 2000.

However, 79 petroleum- and 70 gas-fired units will retire

throughout the 10-year period.

Synergy With 

Clean Air Act Requirements

As utilities make plans to meet the requirements of

CAAA90 for SO and NO , they must also consider other 2 x

existing Clean Air Act (CAA) requirements and possible

new regulations. Through 2005, the CAA requires EPA to

consider a number of actions and new regulations that

would directly or indirectly result in the need to reduce

emissions from electric power generation (Figure 21).

CAAA90 contain many requirements that will affect the

electric power generating industry well into the future,

such as NO limitations under Titles I and IV, New Source x

Performance Standards, new Ozone and Fine Particle

Standards, and possibly, Utility Air Toxics requirements.

EPA has traditionally implemented standards and

requirements on a statutory provision-by-provision basis.

This approach has been effective in protecting the

environment though it is not likely to be the most economically efficient. For this reason, EPA is working with

power generators to develop a more efficient approach

called the Clean Air Power Initiative (CAPI).
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 49

Table 14. Fossil Units Proposed for Repowering, 1996-2005, as of January 1, 1996

State Summer

Company Capability Unit Energy Repowering Repowering

Plant (County) Unit ID (Megawatts) Type Source Year Fuel

Net

a

Alabama

 Alabama Electric Coop Inc. 

 Charles R. Lowman (Washington) ............ 1 79.4 ST BIT 2001 WH

 McWilliams (Covington) . . . . . . . . . . . . . . . . . . . . 1 9.7 ST NG 1996 WH

2 9.7 ST NG 1996 WH

3 23.0 ST NG 1996 WH

California

 City of Pasadena 

 Glenarm (Los Angeles) . . . . . . . . . . . . . . . . . . . . GT1 30.3 GT NG 2000 UNK

GT2 30.3 GT NG 2000 UNK

Delaware

 Delmarva Power & Light Co.

 Indian River (Sussex) ...................... 1 89.0 ST BIT 2003 BIT

2 89.0 ST BIT 2001 BIT

Florida

 Florida Power Corp.

 G E Turner (Volusia) . . . . . . . . . . . . . . . . . . . . . . ST3 70.0 ST NG 2003 NG

ST4 71.0 ST NG 2004 NG

 Higgins (Pinellas) . . . . . . . . . . . . . . . . . . . . . . . . . ST1 39.0 ST NG 2004 NG

ST2 41.0 ST FO6 2004 NG

ST3 39.0 ST FO6 2004 NG

 City of Lakeland

 Larsen Memorial (Polk) .................... 6 25.0 ST NG 1998 WH

 City of Tallahassee

 S O Purdom (Wakulla) ..................... 5 23.0 ST NG 2000 NG

6 23.0 ST NG 2000 NG

Illinois

 Commonwealth Edison Co.

 Bloom (Cook) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333 11.2 GT FO2 2000 FO2

334 16.1 GT FO2 2000 FO2

341 19.2 GT FO2 2000 FO2

344 19.2 GT FO2 2000 FO2

 Calumet (Cook) . . . . . . . . . . . . . . . . . . . . . . . . . . 311 14.7 GT NG 1998 NG

312 14.1 GT NG 1998 FO2

313 12.3 GT NG 1998 NG

314 14.8 GT NG 1998 NG

331 15.1 GT NG 1998 NG

332 13.0 GT NG 1998 NG

333 13.6 GT NG 1998 NG

341 14.0 GT NG 1998 NG

342 13.6 GT NG 1998 NG

343 8.3 GT NG 1998 NG

 Crawford (Cook) . . . . . . . . . . . . . . . . . . . . . . . . . . 311 13.3 GT NG 1996 NG

312 10.9 GT NG 1996 NG

313 14.5 GT NG 1996 NG

314 14.2 GT NG 1996 NG

321 13.7 GT NG 1996 NG

322 11.8 GT NG 1996 NG

323 11.9 GT NG 1996 NG

 See notes at end of table.
Table 14. Fossil Units Proposed for Repowering, 1996-2005, as of January 1, 1996 (Continued)

State Summer

Company Capability Unit Energy Repowering Repowering

Plant (County) Unit ID (Megawatts) Type Source Year Fuel

Net

a

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

50 on Electric Utilities: An Update

 Crawford (Cook) (continued) . . . . . . . . . . . . . . . . 324 10.8 GT NG 1996 NG

331 10.9 GT NG 1996 NG

332 10.0 GT NG 1996 NG

333 13.5 GT NG 1996 NG

334 13.3 GT NG 1996 NG

 Electric Junction (Kane) . . . . . . . . . . . . . . . . . . . . 311 14.6 GT NG 1996 NG

312 13.1 GT NG 1996 NG

313 14.4 GT NG 1996 NG

314 14.9 GT NG 1996 NG

321 14.3 GT NG 1996 NG

322 15.5 GT NG 1996 NG

323 7.3 GT NG 1996 NG

324 8.7 GT NG 1996 NG

331 15.6 GT NG 1996 NG

332 15.3 GT NG 1996 NG

333 9.7 GT NG 1996 NG

334 10.4 GT FO2 1996 FO2

343 10.4 GT NG 1996 NG

 Fish (Cook) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 20.0 JE JF 1999 JF

312 19.0 JE JF 1999 JF

321 18.0 JE JF 1999 JF

322 20.0 JE JF 1999 JF

331 20.0 JE JF 1999 JF

332 20.0 JE JF 1999 JF

341 20.0 JE JF 1999 JF

342 20.0 JE JF 1999 JF

 Joliet 9 (Will) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 14.1 GT NG 1996 NG

312 15.5 GT NG 1996 NG

313 8.1 GT NG 1996 NG

314 12.0 GT NG 1996 NG

321 15.2 GT NG 1996 NG

322 12.8 GT NG 1996 NG

323 11.0 GT NG 1996 NG

324 14.2 GT NG 1996 NG

 Lombard (Du Page) . . . . . . . . . . . . . . . . . . . . . . . 311 18.6 JE JF 1998 NG

321 17.4 JE JF 1998 JF

322 17.8 JE JF 1998 NG

 Sabrooke (Winnebago) . . . . . . . . . . . . . . . . . . . . 311 14.1 GT FO2 1997 FO2

312 13.0 GT FO2 1997 FO2

321 13.9 GT FO2 1997 NG

322 15.8 GT FO2 1997 NG

331 14.0 GT FO2 1997 FO2

332 13.5 GT FO2 1997 NG

341 10.6 GT FO2 1997 FO2

 Waukegan (Lake) . . . . . . . . . . . . . . . . . . . . . . . . . 311 24.6 JE JF 1997 JF

312 29.9 JE JF 1997 FO1

321 28.8 JE JF 1997 FO1

322 29.9 JE JF 1997 FO1

 See notes at end of table.
Table 14. Fossil Units Proposed for Repowering, 1996-2005, as of January 1, 1996 (Continued)

State Summer

Company Capability Unit Energy Repowering Repowering

Plant (County) Unit ID (Megawatts) Type Source Year Fuel

Net

a

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 51

U.S. Environmental Protection Agency, EPA’S Clean Air Power Initiative, EPA Number (Washington, DC, April 1996), p. 1. 104

Mississippi

 City of Clarksdale

 Wilkins (Coahoma) ........................ 8 12.0 GT NG 1996 NG

 Public Service Commission of Yazoo City

 Yazoo (Yazoo) ........................... 3 11.5 ST NG 1996 NG

 South Mississippi El Power Assn.

 Moselle (Jones) .......................... 3 59.0 ST NG 2001 NG

Oklahoma

 Oklahoma Gas & Electric Co.

 Arbuckle (Murray) ......................... 1 74.0 ST NG 2001 NG

 Mustang (Canadian) ....................... 1 58.0 ST NG 2001 NG

2 57.0 ST NG 2000 NG

Pennsylvania

 Borough of Chambersburg

 Chambersburg Diesel (Franklin) . . . . . . . . . . . . . 5 2.1 IC NG 1996 NG

 Pennsylvania Electric Co.

 Warren (Warren) ......................... 2 41.0 ST BIT 1997 BIT

Texas

 Central Power & Light Co.

 J L Bates (Hidalgo) ........................ 1 72.0 ST NG 2002 NG

 Laredo (Webb) ........................... 2 32.0 ST NG 2001 NG

Southwestern Electric Power Co.

 Wilkes (Marion) .......................... 2 357.0 ST NG 2002 UNK

U.S. Total ................................. 2,501.1

 Summer Capability is the maximum load that a generating unit, generating station, or other electrical apparatus can carry under specified conditions a

for a given period of time without exceeding approved limits of temperature and stress at the time of summer peak demand.

 Notes: Unit Type: GT = Combustion (gas) Turbine, IC = Internal Combustion (diesel), ST = Steam Turbine-Boiler. Energy Source: BIT = Bituminous

Coal, FO2 = No. 2. Fuel Oil, NG = Natural Gas, WH = Waste Heat, and UNK = Unknown.

 Source: Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.”

CAPI recognizes the need to improve and coordinate the more pollutants at a lower cost than separate controls for

development of air pollution regulations for the electric each of those pollutants. Failure to take advantage of costpower generation sector. This sector includes utilities, effective synergies and incremental compliance planning

independent power producers, cogenerators, and indus- could increase control costs and utility user rates, and

trial boilers that produce electricity for their own needs. possibly reduce environmental benefits. 104

The numerous air pollution regulations and possible

future regulatory mandates have potential synergies and Title IV gives utilities the innovative allowance trading

conflicts. A complete analysis of utility compliance mechanism for SO , as well as other potential marketstrategies should contemplate the entire range of environ- based mechanisms for NO . However, this unprecedented

mental regulations, including CAAA90. For example, flexibility gives rise to other concerns. Each fuel or

certain control options and strategies can reduce two or process change adopted by a utility for SO compliance

2

x

2
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

52 on Electric Utilities: An Update

Argonne National Laboratory, Policy and Economic Analysis Group, Decision and Information Sciences Division, Synergies and 105

Conflicts in Multimedia Pollution Control Related to Utility Compliance with Title IV of the Clean Air Act Amendments of 1990, ANL/DIS/TM-3

(January 1994), p. 4.

Ibid., pp. 79-80. 106

Table 15. U.S. Electric Utility Planned Coal-, Petroleum-, and Gas-Fired Capacity Retirements, 1996-2005,

as of January 1, 1996

Coal Petroleum Gas

Number

of Units

Generator

Nameplate

(megawatts)

Number

of Units

Generator

Nameplate

(megawatts)

Number

of Units

Generator

Nameplate

(megawatts)

1996 .................... – – 4 60.9 – –

1997 .................... 2 60.0 20 43.0 5 147.6

1998 . . . . . . . . . . . . . . . . . . . . – – 1 2.5 3 39.4

1999 .................... 4 392.0 2 24.6 2 48.5

2000 .................... – – 6 19.5 2 125.6

2001 .................... – – 8 67.0 4 165.0

2002 . . . . . . . . . . . . . . . . . . . . – – 14 232.5 30 776.3

2003 . . . . . . . . . . . . . . . . . . . . – – 11 424.6 1 22.5

2004 .................... 3 159.2 11 472.4 9 664.1

2005 .................... 3 155.1 2 83.7 14 611.9

U.S. Total ............... 12 766.4 79 1,430.6 70 2,600.9

 Source: Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.”

will also affect other combustion emissions and by- mercury, and organic HAP’s. Flue gas treatment techproducts. In addition to SO and NO , the uncontrolled nologies have important HAP-SO control synergies. 2 x

combustion of fossil fuels produces fly ash emitted as Except for mercury emissions, most trace metal emissions

particulates; HAP’s such as mercury; and other trace from coal-fired plants either are absorbed onto the fly ash

metals, radionuclides, and CO . Many of these pollutants or they precipitate with the bottom ash. Trace metal 2

are subject to their own regulatory requirements. emissions absorbed onto the fly ash can be controlled by

However, fossil-fuel utility units have not been regulated particulate control technologies, such as baghouses and

for HAP’s, radionuclides, or CO emissions. ESP’s. Mercury emissions can be partially removed with 2

The uncontrolled combustion of fossil fuels also produces reduced if a utility selects low-NO burners. Combustion

discharges of heat, waste water, and potentially large temperatures are lowered, and mercury is absorbed in the

amounts of slag and bottom ash as solid waste. Thermal fly ash. The mercury can then be effectively controlled

and wastewater discharges are regulated by the Clean with particulate controls. While particulate controls

Water Act (CWA). Thermal discharges are controlled reduce trace metal emissions, and wet scrubbers partially

through cooling towers, cooling pools, and recycling. reduce mercury, organic HAPs, and in particular, chlorine

Combustion wastes are regulated as solid wastes by the may not be controlled using these two methods.

Resource Conservation and Recovery Act (RCRA), which

requires waste generators to dispose of such wastes in Fuel switching/blending between coals have different

sludge pools or landfills. effects on co-pollutants and synergies, and a trade-off 105

A number of examples demonstrate the synergy of control and blending. When utilities switch from high-sulfur

options in reducing pollutants of fossil-fired utility plants. eastern coal to low-sulfur western coal, there is some

For example, many of the options to reduce particulate or indication that toxic particulates may result from comSO emissions also reduce many of the air toxics. Utilities bustion. In addition, coals vary by trace metal contents. 2

emit three types of air toxics: trace metals as particulates, Fuel switching or blending may reduce SO emissions,

2

wet scrubber controls. Mercury emissions are usually

x

106

exists between Title IV and Title III in coal fuel switching

2
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 53

Figure 21. Electric Power Regulations Timeline for Provisions Enacted Through the Clean Air Act

 NO = Nitrogen oxides. x

 SO = Sulfur dioxide. 2

 PM = Particulate matter.

 ? = Under study–possible future regulation.

 NAAQS = National Ambient Air Quality Standards.

 OTC = Ozone Transportation Commission.

 NSR = New Source Review. 

 OTAG = Ozone Transport Assessment Group.

 NSPS = New Source Performance Standards. 

 RACT = Reasonably Available Control Technology.

 SIP = State Implementation Plan.

 Source: Environmental Protection Agency, Clean Air Power Initiative Forum, April 1996.

but without the presence of a wet scrubber or a low-NO and fly ash waste, and, to a certain extent, fuel switching x

burner, toxic metal emissions may grow. or blending do the same thing. Scrubbing options tend

Synergies resulting from controls to reduce the interaction the need for additional sludge treatment ponds. Some

of SO reductions with the regulation of high-volume types of coal fuel switching also become less economical 2

combustion waste streams are limited. Many of the flue based on the amount of ash and slag generated. To

gas treatment processes generate greater levels of bottom reduce disposal costs, some utilities are finding

to be less economical because of landfill disposal costs and
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

54 on Electric Utilities: An Update

U.S. Environmental Protection Agency, EPA’s Clean Air Power Initiative, EPA Number (Washington, DC, April 1996), p. 6. 107

commercial uses for wastes, such as gypsum for wall

board, roadfill, concrete additives, and fertilizers.

In assessing the control costs of a single pollutant, both the

direct costs associated with the control of that pollutant In many cases, utilities are uncertain about their Phase II

and the indirect costs associated with controlling multiple compliance strategies, and even when utilities are certain,

pollutants should be considered. In addition, the syner- some are less than forthcoming about their plans. The

gistic control effects of particular strategies should be evolution of the industry toward more competition makes

examined. To be cost-effective, utilities choose, if possible, some utilities reluctant to discuss their plans because they

those controls that minimize the total cost of compliance feel that doing so would erode their competitive edge. A

with all pollutant regulations. Regulatory barriers and list of some known Phase II compliance strategies can be

control uncertainties, however, make the choice of cost- found on the Internet at the home page of the Energy

effective compliance difficult. Under these circumstances, Information Administration (http://www.eia.doe.gov).

flexibility is a key component of any utility compliance Once the connection to the home page has been

strategy. CAPI is an attempt to reduce the administrative established, click on “Electricity” in Fuel Groups. A new

complexity and break the costly pattern of regulation by screen will appear. Scroll down through “Publications”

providing the power-generation industry with more and “Data” to “Applications.” Go to the “Clean Air Act

certainty of future regulatory requirements, greater Browser” and follow the instructions.

flexibility, and cost savings.107

Utility Compliance Plans 

on the Internet
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 55

6. Conclusion

The first year of Phase I demonstrated that the new program helped to create an active coal market in which

market-based sulfur dioxide emissions control system the delivered price of higher and lower sulfur coal

could achieve significant reductions in emissions at lower dropped between 1990 and 1995. Other factors conthan expected costs. The U.S. General Accounting Office tributed to this price reduction, including an oversupply

has estimated an annual savings of $2-3 billion with the of lower sulfur coal, penetration of competitively priced

market-based system (versus traditional regulation) western lower sulfur coal, and lower transportation costs.

depending upon the level of allowance trading taking Also, utility boiler modifications to burn lower sulfur coal

place. Utilities reduced their aggregate emissions far were less expensive than predicted. The tendency for

below what was required by law. CAAA90 provided an utilities to purchase lower sulfur coal may have resulted

economic incentive to overcomply, and many utilities in early reduction of sulfur dioxide emissions and more

seized the opportunity. allowance credits earned. 

The $2,000 per ton penalty for noncompliance dwarfed The evolution of the electric power industry toward more

the unexpectedly low prices of sulfur dioxide allowances competition has led utilities to delay capital expenditures

throughout the first year of Phase I. Many utilities for pollution control equipment as long as possible. Phase

exceeded the required emissions reductions for Phase I II emissions requirements are more stringent and affect

through fuel switching and the use of scrubbers, but even many more generating units than those of Phase I.

those units that emitted more sulfur dioxide than their Utilities are reluctant to make commitments for Phase II

original allowance allocation would have permitted found because of competition and uncertainty about possible

it easy to acquire enough allowances to avoid the fine. future regulatory requirements. Utility Phase I allowMore than half of the Phase I plants switched to or reduce emissions to meet the more stringent Phase II

blended with lower sulfur coal partially because of the requirements, and scrubbers and repowering most likely

allowance trading program. The allowance trading will be more attractive options than they are currently.

ances are estimated to last until 2005. Utilities will have to
Appendix A

Federal Legislation

To Control Air

Pollution
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 59

Legislation and Date Role of Federal Government

An Act To Provide Research and Technical Assistance

Relating to Air Pollution Control (1955)

Provide research, technical, and financial aid to States

Clean Air Act of 1963 Mediate among States, if requested

Air Quality Act of 1967 Create air quality control regions; establish criteria for health protection; recommend

control techniques; set national emissions standards for vehicles

Clean Air Act 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

Amendments and extensions of Clean Air Act (1971, 1973,

1974, 1976)

Establish waivers and extensions of motor vehicle emissions standards

Clean Air Act Amendments of 1977 Classify air quality control regions as attainment or nonattainment; establish program

for prevention of significant deterioration; provide special treatment for eastern coal;

strengthen new source performance standards and hazardous pollutant sections;

tighten motor vehicle emissions standards.

Clean Air Act Amendments of 1990 Establish new provisions designed to reduce emissions of SO . Establish an 2

allowance system, based on a nationwide limit of 8.9 million tons of SO per year. 2

Establish a list of 189 regulated hazardous air pollutants. Require all major sources

of air pollution to obtain an operating permit. Strengthen enforcement provisions for

EPA.

 Sources: Lester B. Lave and Gilbert S. Omenn, Clearing the Air: Reforming the Clean Air Act (Washington, DC: Brookings Institution, 1981),

p. 6. Environmental Law Institute, Clean Air Deskbook (Washington DC, March 1992) and Clean Air Act Handbook, A Practical Guide to Compliance,

Third Edition, 1993.

Table A1. Chronology of Historic Federal Legislation To Control Air Pollution

Appendix A

Federal Legislation To Control Air Pollution

Federal legislative efforts aimed at controlling air pol- The Clean Air Act Amendments of 1990 is the latest air

lution in the United States began in the mid-1950's when pollution control legislation enacted by the U.S. Congress.

Congress passed an act requiring the provision of research Other Federal legislation controlling air pollution includes

and technical assistance relating to air pollution control to the Clean Air Act of 1963, the Air Quality Act of 1967, the

the States. Since then, the Federal role in air pollution Clean Air Act Amendments of 1970 and 1977, and various

control has grown considerably, and today the Federal additional amendments and extensions of the Clean Air

Government sets national emissions standards for specific Act passed in 1971, 1973, 1974, and 1976 (Table A1).

air pollutants. It also monitors industry’s compliance with

these standards.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

60 on Electric Utilities: An Update

An Act To Provide Research and Technical

Assistance Relating to Air Pollution Control

Passed in 1955, an Act To Provide Research and Technical

Assistance Relating to Air Pollution Control was, in part,

a response to the growing concentration of the U.S.

population in urban areas, many of which were spread

over more than one State (e.g., New York, Chicago, and

Washington, D.C.). 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.”

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. The

Federal Government had no direct regulatory role.

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 that “endangered 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, because

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 consistent with these criteria.

The Clean Air Act Amendments of 1970

The Clean Air Act Amendments of 1970 substantially

expanded the Federal role in air pollution control. The act

came about because, with the exception of California,

State and local governments had taken only limited action

to control air pollution. Congress decided that the

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

6 criteria pollutants: particulate matter, sulfur oxides,

carbon monoxide, nitrogen dioxide, ozone, 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.”

Distinct from ambient standards, the 1970 amendments

also introduced national emissions standards for new

stationary sources of air pollution, limiting the amounts

of sulfur dioxide (SO ), nitrogen oxides (NO ), and par- 2 X

ticulates 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 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.

The amendments also imposed new requirements on

areas already in attainment. The concept of prevention of

significant deterioration (PSD) was introduced whereby
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 61

the amendments established specific increments for maxi- emissions from electric utilities to a level that is 10 million

mum allowable increases in ambient concentrations for tons below the 1980 level. Emission allowances serve as

three classes of PSD areas. The PSD program included a the mechanism for compliance. Each affected unit is

permit program for new major emission sources and allocated its allowances based on its baseline fuel

modifications to existing sources. It required sources to consumption. The baseline is calculated from the average

apply “best available technology,” which would be deter- yearly fuel consumption for the period 1985-1987. In

mined case by case. Phase I, allowances are allocated at the rate of 2.5 pounds

The Clean Air Act Amendments of 1990

The 1990 amendments establish a list of 189 regulated

hazardous air pollutants. EPA is required to establish

standards for major sources, which are defined as those

with the potential to emit 10 tons per year of any single

hazardous pollutant or 25 tons of any combination of

pollutants.

The amendments establish a new permit program

whereby all major sources are required to obtain an

operating permit. States with approved permitting programs issue permits, but EPA has the power to veto State

permits. Citizens also have certain rights to challenge

State permits.

The 1990 amendments also establish the Acid Rain Program, which is designed to reduce the adverse effects of

acid deposition. This improvement will be achieved

primarily through reductions of SO and NO emis- 2 x

sions by electricity producers, while concurrently

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

production. The primary goal of the Acid Rain Program,

which will be nstituted in 2010, is to reduce annual SO2

of SO times the number of mmBtu consumed in the 2

baseline. In Phase II, allowances are allocated at the rate

of 1.2 pounds of SO times the number of mmBtu 2

consumed in the baseline.

The legislation also requires a reduction of 2 million tons

of NO emissions from utility boilers. Utilities were x

required to apply low-NO –burner technologies to meet x

regulations that become effective on the date the unit

must meet the SO standard, i.e., January 1, 1995, for 2

Phase I units; January 1, 1997, for Phase I units employing

scrubber technology; and January 1, 2000, for all Phase II

units. However, a lawsuit pushed the date of compliance

back to January 1, 1996, for the Phase I units that had been

required to be in compliance on January 1, 1995. NOx

limits for dry-bottom, wall-fired and tangentially fired

boilers affected in Phase I have been selected as 0.50

pounds per million Btu and 0.45 pounds per million Btu,

respectively. Regarding Phase II compliance, NO limits x

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 drybottom, wall-fired and tangentially fired boilers can be

revised, if EPA deems it feasible with new technology. An

emissions averaging provision allows individual utilities

to average NO emissions over multiple units, if the same x

or lower emissions result.
Appendix B

Profiles of the 261 Table 1

Generators Affected by Phase I

(Table B1) and a Profile of the

Coal Received at Table 1 Plants

(Table B2)
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 65

Appendix B

Profiles of the 261 Table 1 Generators Affected

by Phase I (Table B1) and a Profile of the

Coal Received at Table 1 Plants (Table B2)

Table B1 presents detailed information about the 261 estimates and 1995 SO emissions as determined by

Table 1 generator units affected by Phase I of the Clean continuous emissions monitors (CEMS). Compliance

Air Act Amendments of 1990 and the 174 substitution and methods and ages are also provided for the 261 Table 1

compensating generator units associated with them. The generators.

table is organized around those generators that were

explicitly named in the legislation as Table 1 units. The For each associated substitution and compensating unit,

substitution and compensating units are listed to the right 1985 SO emissions estimates and 1995 SO emissions as

of each Table 1 unit. determined by CEMS are provided.

Capacities and annual Phase I allowance allocations are Table B2 shows the origin, quality, and delivered price of

provided along with 1985 sulfur dioxide (SO ) emissions coal received at the Table 1 plants in 1995. 2

2

2 2
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 67

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Alabama Alabama Power

E C Gaston ST4 245 18,773 23,485 7,251 1E C Gaston 1 272 17,624 22,220 8,017 1E C Gaston 2 272 18,052 21,862 7,515 1E C Gaston 3 272 17,828 23,369 9,785 1E C Gaston 5 952 58,265 68,352 23,170 1 Alabama Alabama Power Gadsden 1 

Alabama Alabama Power Gadsden 2 

TVAColbert 1 200 13,213 20,522 8,234 1Colbert 2 200 14,907 20,227 10,846 1Colbert 3 200 14,995 23,325 9,218 1Colbert 4 200 15,005 24,748 9,209 1Colbert 5 550 45,923 52,318 39,400 1

Florida Gulf Power

Crist 6 370 18,695 27,469 9,678 1Crist 7 578 50,703 55,921 18,352 1 Florida Gulf Power Crist 4 

Florida Gulf Power Crist 5 Florida Gulf Power Scholz 1 Florida Gulf Power Scholz 2 

Tampa ElectricBig Bend ST2 446 26,387 53,820 35,489 1 Florida Tampa Electric Big Bend BB04 Big Bend ST3 446 26,036 32,901 9,101 1 Florida Tampa Electric Big Bend BB04 Big Bend 1 446 27,662 56,181 35,932 1 Florida Tampa Electric Big Bend BB04 

Georgia Georgia Power

Bowen 1 806 54,838 71,428 32,617 1 Georgia Georgia Power Harllee Branch 1 Bowen 2 789 53,329 63,727 39,641 1 Georgia Georgia Power Harllee Branch 2 Bowen 3 952 69,862 82,488 42,137 1 Georgia Georgia Power Harllee Branch 3 Bowen 4 952 69,852 87,659 46,258 1 Georgia Georgia Power Harllee Branch 4 Hammond 1 125 8,549 9,830 3,516 1 Georgia Georgia Power Arkwright 1 Hammond 2 125 8,977 9,997 1,834 1 Georgia Georgia Power Arkwright 2 Hammond 3 125 8,676 9,068 2,047 1 Georgia Georgia Power Arkwright 3 Hammond 4 578 36,650 35,539 14,297 1 Georgia Georgia Power Arkwright 4 Jack McDonough 1 299 33,290 32,738 8,862 1Jack McDonough 2 299 20,058 33,749 10,724 1 Georgia Georgia Power Mitchell 3 Wansley 1 952 68,908 128,505 26,797 1Wansley 2 952 113,801 120,146 27,004 1 Georgia Georgia Power Scherer 3 Yates 1 123 7,863 11,673 118 3

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 68 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Georgia Yates 2 123 6,855 11,199 2,267 1 Georgia Savannah Electric and Power Kraft 1 

Yates 3 123 6,767 11,279 1,787 1 Georgia Savannah Electric and Power Kraft 2 

Yates 4 156 8,676 13,758 1,738 1 Georgia Savannah Electric and Power Kraft 3 

Yates 5 156 9,162 15,754 2,141 1 Georgia Savannah Electric and Power McIntosh 1 Yates 6 404 28,726 42,207 6,535 1 Yates 7 404 22,318 23,974 5,683 1 Illinois Central Illinois Public Service Coffeen 1 389 12,925 38,013 8,085 1 Coffeen 2 617 39,102 102,616 23,143 1 Grand Tower 4 114 6,479 9,754 6,950 2 Meredosia 3 239 15,227 27,015 19,610 2 Illinois Central IL Public Service Co. Meredosia 1 

Illinois Central IL Public Service

Co.

Meredosia 2 

Illinois Central IL

Public ServiceCo.

Meredosia 3 

Illinois Central IL

Public ServiceCo.

Meredosia 4 

Illinois Central IL

Public ServiceCo.

Meredosia 6 

Illinois Central IL

Public ServiceCo.

Hutsonville 5 

Illinois Central IL

Public ServiceCo.

Hutsonville 6 

See notes at end of table
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 69

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Illinois Illinois Central IL

Public ServiceCo.

Newton 1 

Illinois Central IL

Public ServiceCo.

Newton 2 

Illinois Central IL

Public ServiceCo.

Grand Tower 7 

Illinois Central IL

Public ServiceCo.

Grand Tower 8 

CommonwealthEdisonKincaid 1 660 34,564 94,042 4,292 1 Illinois Commonwealth

Edison

Collins 1 

Illinois Commonwealth

Edison

Collins 2 

Illinois Commonwealth

Edison

Collins 3 

Kincaid 2 660 37,063 79,919 6,878 1 Illinois Commonwealth

Edison

Collins 1 

Illinois Commonwealth

Edison

Collins 2 

Electric Energy Inc. Illinois Commonwealth

Edison

Collins 3 

Joppa Steam 1 183 12,259 18,354 3,960 1Joppa Steam 2 183 10,487 16,585 4,130 1Joppa Steam 3 183 11,947 18,839 3,818 1Joppa Steam 4 183 11,061 18,843 3,874 1Joppa Steam 5 183 11,119 19,415 5,532 1Joppa Steam 6 183 10,341 16,348 6,634 1Illinois PowerBaldwin 1 623 46,052 89,277 75,004 2 Illinois Illinois Power Wood River 4 Baldwin 2 635 48,695 78,477 104,172 2 Wyoming PacifiCorp Jim Bridger BW71 

Wyoming PacifiCorp Jim Bridger BW72 Wyoming PacifiCorp Jim Bridger BW73 Wyoming PacifiCorp Wyodak BW91 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 70 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Illinois Utah PacifiCorp Gadsby 3 

Baldwin 3 635 46,644 96,840 86,789 2 Illinois Illinois Power Havana 1 

Illinois Illinois Power Havana 2 Illinois Illinois Power Havana 3 Illinois Illinois Power Havana 4 Illinois Illinois Power Havana 5 Illinois Illinois Power Havana 6 Illinois Illinois Power Havana 7 Illinois Illinois Power Havana 8 Illinois Illinois Power Wood River 1 

Hennepin 2 231 20,182 39,436 27,560 2 Vermilion 2 109 9,735 18,600 1,706 5 Illinois Illinois Power Vermilion 1 

Indiana Hoosier Energy REC Inc. Frank E. Ratts 1 117 9,131 19,069 10,038 1 Frank E. Ratts 2 117 9,296 18,436 10,604 1 Indiana Michigan Power Breed 1 496 20,280 70,365 0 4 Tanners Creek 4 580 27,209 59,646 29,318 1 Indiana-Kentucky Electric

Clifty Creek 1 217 19,620 45,690 16,357 1Clifty Creek 2 217 19,289 44,275 15,724 1Clifty Creek 3 217 19,873 46,489 15,553 1Clifty Creek 4 217 19,552 44,856 13,979 1Clifty Creek 5 217 18,851 41,989 15,313 1Clifty Creek 6 217 19,844 45,563 14,578 1Indianapolis Power &LightElmer W. Stout 5 114 4,253 5,665 5,282 1Elmer W. Stout 6 114 5,229 7,743 6,151 1Elmer W. Stout 7 471 25,883 35,007 27,424 1H T Pritchard 6 114 6,325 7,586 4,579 1Petersburg ST1 253 18,011 21,765 20,586 3 Indiana Indianapolis

Power &Light

H T Pritchard 3 

Indiana Indianapolis

Power &Light

H T Pritchard 4 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 71

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Indiana Indiana Indianapolis

Power &Light

H T Pritchard 5 

Indiana Indianapolis

Power &Light

Petersburg 3 

Indiana Indianapolis

Power &Light

Petersburg 4 

Petersburg ST2 471 35,496 53,110 42,075 3 Indiana Indianapolis

Power &Light

H T Pritchard 3 

Indiana Indianapolis

Power &Light

H T Pritchard 4 

Indiana Indianapolis

Power &Light

H T Pritchard 5 

Indiana Indianapolis

Power &Light

Petersburg 3 

Indiana Indianapolis

Power &Light

Petersburg 4 

Northern IndianaPublic ServiceBailly 7 194 30,088 26,874 2,307 3Bailly 8 422 39,951 12,312 3,938 3Michigan City 12 540 48,963 45,434 12,261 1PSI EnergyCayuga 1 531 47,631 56,848 44,666 1Cayuga 2 531 40,579 69,254 46,504 1Gibson 1 668 44,288 71,467 51,701 2Gibson 2 668 44,956 77,864 48,279 2Gibson 3 668 45,033 67,787 60,912 2Gibson 4 668 64,632 77,551 3,783 3R Gallagher 1 150 13,908 1,770 13,127 2R Gallagher 2 150 12,644 19,178 12,266 2R Gallagher 3 150 13,127 20,883 11,766 2R Gallagher 4 150 12,512 21,980 14,471 2Wabash River 1 113 5,558 6,713 197 5Wabash River 2 113 5,874 6,308 2,867 2Wabash River 3 123 4,111 6,889 3,149 2Wabash River 5 125 4,838 8,201 2,615 2Wabash River 6 387 17,362 26,239 13,902 2

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 72 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Indiana Southern Indiana Gas & Electric FB Culley 2 104 4,703 16,361 564 3 FB Culley 3 265 18,603 38,456 1,985 3 Warrick 4 323 29,577 58,813 37,682 2 Iowa Interstate Power Milton L Kapp 2 219 13,437 31,379 7,450 1 Iowa Electric Light & Power Prairie Creek 4 149 7,965 12,466 5,279 1 Iowa Power Des Moines 7 114 2,259 2,490 0 4 Iowa Public Service George Neal North 1 147 2,571 1,048 3,812 1 Iowa Southern Utilities Burlington 1 212 10,428 23,093 9,020 1 Iowa-Illinois Gas & Electric Riverside 5 136 3,885 4,707 1,828 1 Kansas City of Kansas City Quindaro ST2 158 4,109 3,255 2,893 1 Kentucky Big Rivers Electric

Coleman 1 174 20,912 18,537 15,759 2 Kentucky Big Rivers R D Green G1 

Kentucky Big Rivers R D Green G2 

Coleman 2 174 19,363 19,862 18,500 2 Kentucky Big Rivers R D Green G1 

Kentucky Big Rivers R D Green G2 

Coleman 3 173 16,205 19,007 18,013 2HMP&L Station 2 1 180 19,533 22,040 11,638 3HMP&L Station 2 2 185 18,597 22,831 9,594 3City of OwensboroElmer Smith 1 151 6,348 10,176 3,171 3Elmer Smith 2 265 14,031 26,755 4,684 3East KentuckyPowerCooper 1 100 7,254 8,605 5,836 1Cooper 2 221 14,917 14,870 12,553 1H L Spurlock 1 305 22,181 29,745 15,297 1

See notes at end of table
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 73

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Kentucky Kentucky Utilities

E W Brown 1 114 6,923 6,242 4,259 1E W Brown 2 180 12,121 10,029 8,622 1E W Brown 3 446 35,334 38,577 14,824 1Ghent 1 557 63,448 71,102 8,311 3Green River 4 114 15,597 12,939 10,448 2TVAParadise 3 1,150 135,688 106,835 155,612 2Shawnee 10 175 9,902 34,077 2,953 1

Maryland Baltimore Gas &

ElectricC P Crane 1 190 12,492 9,722 6,138 1C P Crane 2 209 8,987 9,657 6,024 1 Alabama Alabama

Electric Coop

Charles

Lowman

2 

Alabama Alabama

Electric Coop

Charles

Lowman

3 

Mississippi South MS El

Power Assn.

R D Morrow 1 

Mississippi South MS El

Power Assn.

R D Morrow 2 

Potomac ElectricPower Chalk Point ST1 364 25,403 20,258 18,660 1 Maryland PEPCO Chalk Point 4 Chalk Point ST2 364 23,690 27,482 22,427 1 Maryland PEPCO Chalk Point 4 Morgantown ST1 626 39,864 29,388 28,040 1 Maryland PEPCO Chalk Point 3 Morgantown ST2 626 45,592 37,988 38,515 1 Maryland PEPCO Chalk Point 3 

Michigan Consumers Power

J H Campbell 1 265 18,773 27,180 10,175 1 Michigan Consumers

Power

Dan E Karn 1 

Michigan Consumers

Power

J R Whiting 2 

Michigan Consumers

Power

J R Whiting 3 

J H Campbell 2 385 22,453 33,350 2,996 1 Michigan Consumers

Power

Dan E Karn 1 

Michigan Consumers

Power

J R Whiting 2 

Michigan Consumers

Power

J R Whiting 3 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 74 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Minnesota Northern States Power High Bridge 6 163 4,158 2,176 1,493 1 Minnesota Northern States Power High Bridge 3 

Minnesota Northern States Power High Bridge 4 Minnesota Northern States Power High Bridge 5 Minnesota Northern States Power Sherburne Co. 1 Minnesota Northern States Power Sherburne Co. 2 

Mississippi Mississippi Power Jack Watson 4 250 17,439 26,218 18,577 2 Jack Watson 5 500 35,734 46,401 38,044 2 Mississippi Mississippi Power Victor J Daniel 1 

Mississippi Mississippi Power Victor J Daniel 2 

Missouri Associated Electric Coop New Madrid 1 600 27,497 74,430 8,827 1 New Madrid 2 600 31,625 77,895 7,926 1 Thomas Hill 1 180 9,980 35,874 2,817 1 Missouri Associated Electric Coop Thomas Hill MB3 

Thomas Hill 2 285 18,880 56,866 3,749 1 Missouri Associated

Electric Coop

Thomas Hill MB3 

City of SpringfieldJames River 5 105 4,722 9,096 2,054 1 Missouri City of

Springfield

James River 3 

Missouri City of

Springfield

James River 4 

Missouri City of

Springfield

Southwest 1 

Empire DistrictElectricAsbury 1 213 15,764 68,769 8,112 1Kansas City Power &LightMontrose 1 188 7,196 28,740 2,317 1 Missouri Kansas City

P&L

Hawthorn 5 

Missouri Kansas City

P&L

Iatan 1 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 75

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Missouri Kansas Kansas City

P&L

La Cygne 1 

Kansas Kansas City

P&L

La Cygne 2 

Montrose 2 188 7,984 32,165 2,735 1 Missouri Kansas City

P&L

Hawthorn 5 

Missouri Kansas City

P&L

Iatan 1 

Kansas Kansas City

P&L

La Cygne 1 

Missouri Kansas City

P&L

La Cygne 2 

Montrose 3 188 9,824 35,192 2,909 1 Missouri Kansas City

P&L

Hawthorn 5 

Missouri Kansas City

P&L

Iatan 1 

Kansas Kansas City

P&L

La Cygne 1 

Kansas Kansas City

P&L

La Cygne 2 

Union ElectricLabadie 1 574 125,282 72,811 23,321 1 Missouri Union Electric Meramec 1 

Missouri Union Electric Meramec 2 Missouri Union Electric Meramec 3 Missouri Union Electric Meramec 4 Missouri Union Electric Rush Island 1 Missouri Union Electric Rush Island 2 

Labadie 2 574 117,392 63,653 23,236 1 Missouri Union Electric Meramec 1 

Missouri Union Electric Meramec 2 Missouri Union Electric Meramec 3 Missouri Union Electric Meramec 4 Missouri Union Electric Rush Island 1 Missouri Union Electric Rush Island 2 

Labadie 3 621 111,919 67,587 38,025 1 Missouri Union Electric Meramec 1 

Missouri Union Electric Meramec 2 Missouri Union Electric Meramec 3 Missouri Union Electric Meramec 4 Missouri Union Electric Rush Island 1 Missouri Union Electric Rush Island 2 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 76 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Missouri Labadie 4 621 106,044 65,591 44,223 1 Missouri Union Electric Meramec 1 

Missouri Union Electric Meramec 2 Missouri Union Electric Meramec 3 Missouri Union Electric Meramec 4 Missouri Union Electric Rush Island 1 Missouri Union Electric Rush Island 2 

Sioux 1 550 25,603 42,688 27,477 1 Missouri Kansas City Power &Light Hawthorn 5 

Missouri Kansas City Power &Light Iatan 1 Kansas Kansas City Power &Light La Cygne 1 Kansas Kansas City Power &Light La Cygne 2 

Sioux 2 550 23,067 14,504 20,379 1 Missouri Kansas City Power &Light Hawthorn 5 

Missouri Kansas City Power &Light Iatan 1 Missouri Kansas City Power &Light La Cygne 1 Missouri Kansas City Power &Light La Cygne 2 

Utilcorp United Sibley 3 419 15,170 26,812 9,417 1 Missouri UtilCorp United Sibley 1 

Missouri UtilCorp United Sibley 2 

NewHampshire

Public Service ofNew HampshireMerrimack 1 114 9,922 15,258 10,450 1 New

Hampshire

Public Serviceof NH

Newington 1 

Massachusetts Holyoke Water

Power

Mount Tom 1 

Merrimack 2 346 21,421 38,980 25,678 1 New

Hampshire

Public Serviceof NH

Newington 1 

Massachusetts Holyoke Water

Power

Mount Tom 1 

New Jersey Atlantic City Electric

BL England 1 136 14,365 16,300 18,101 2BL England 2 163 18,357 17,822 3,619 3

New York Long Island Lighting

Northport ST1 387 19,824 26,583 4,114 5 New York LILCO Northport 4 Northport 2 387 23,476 25,915 2,228 5 New York LILCO Northport 4 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 77
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 77

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

New York Northport 3 387 25,783 27,360 4,047 5 New York LILCO Northport 4 

Port Jefferson 3 188 10,194 10,602 3,640 5 New York LILCO Northport 4 Port Jefferson 4 188 12,006 12,195 2,636 5 New York Northport 4 New York State Gas& ElectricGreenidge 4 113 7,342 11,548 9,824 2Milliken 1 155 11,018 9,400 5,158 3Milliken 2 167 12,083 15,398 4,218 3Niagara MohawkDunkirk ST4 218 13,690 16,846 19,061 2 New York Niagara

Mohawk

C R Huntley 63 

New York Niagara

Mohawk

C R Huntley 64 

New York Niagara

Mohawk

C R Huntley 65 

New York Niagara

Mohawk

C R Huntley 66 

New York Niagara

Mohawk

Oswego 3 

New York Niagara

Mohawk

Oswego 4 

New York Niagara

Mohawk

Oswego 5 

New York Niagara

Mohawk

Oswego 6 

New York Central Hudson

G&E

Roseton 1 

New York Central Hudson

G&E

Roseton 2 

Dunkirk 3 218 13,162 18,214 15,560 2 New York Niagara

Mohawk

C R Huntley 63 

New York Niagara

Mohawk

C R Huntley 64 

New York Niagara

Mohawk

C R Huntley 65 

New York Niagara

Mohawk

C R Huntley 66 

New York Niagara

Mohawk

Oswego 3 

New York Niagara

Mohawk

Oswego 4 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 78 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

New York New York Niagara Mohawk Oswego 5 

New York Niagara Mohawk Oswego 6 New York Central Hudson G&E Roseton 1 New York Central Hudson G&E Roseton 2 

Ohio Cardinal Operating Co. Cardinal 1 615 84,106 69,012 83,160 2 Cardinal 2 615 42,008 71,532 22,146 1 Cincinnati Gas & Electric Miami Fort 5 d 100 834 262 332 1 Miami Fort 6 163 12,475 21,111 3,862 1 Miami Fort 7 557 42,216 62,456 21,301 1 Kentucky Cinergy East Bend 2 

Walter C Beckjord 5 245 9,822 12,735 8,347 1 Walter C Beckjord 6 461 25,235 39,140 17,479 1 Cleveland Electric Illum. Ashtabula 5 256 18,351 37,621 18,183 2 Ohio Toledo Edison Acme 13 

Ohio Toledo Edison Acme 14 Ohio Toledo Edison Acme 15 Ohio Toledo Edison Acme 16 Ohio Toledo Edison Acme 91 Ohio Toledo Edison Acme 92 Ohio Cleveland

Electric Illum.

Lake Shore 18 

Ohio Cleveland

Electric Illum.

Lake Shore 91 

Ohio Cleveland

Electric Illum.

Lake Shore 92 

Ohio Cleveland

Electric Illum.

Lake Shore 93 

Ohio Cleveland

Electric Illum.

Lake Shore 94 

Ohio Toledo Edison Bay Shore 1 Ohio Toledo Edison Bay Shore 2 Ohio Toledo Edison Bay Shore 3 Ohio Toledo Edison Bay Shore 4 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 79

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Ohio Avon Lake 8 233 12,771 16,952 0 4

Avon Lake 9 680 33,413 41,322 21,921 1 Ohio Cleveland

Electric Illum.

Avon Lake 9 

Ohio Cleveland

Electric Illum.

Avon Lake 10 

Eastlake 1 123 8,551 16,550 8,635 2Eastlake 2 123 9,471 17,267 13,025 2Eastlake 3 123 10,984 19,545 14,451 2Eastlake 4 208 15,908 24,997 23,405 2Eastlake 5 680 42,495 79,918 57,855 2Columbus SouthernPowerConesville 1 148 8,924 6,468 6,734 2Conesville 2 136 5,360 7,008 13,019 2Conesville 3 162 12,593 9,646 8,125 2Conesville 4 842 53,463 98,256 62,940 2 Ohio Dayton Power

and Light

J M Stuart 1 

Ohio Dayton Power

and Light

J M Stuart 2 

Ohio Dayton Power

and Light

J M Stuart 3 

Ohio Dayton Power

and Light

J M Stuart 4 

Picway 5 106 11,967 13,671 4,722 2 Ohio Columbus

Southern 

Poston 1 

Ohio Columbus

Southern 

Poston 2 

Ohio Columbus

Southern 

Poston 3 

Edgewater 4 114 5,536 6,149 10 5 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 80 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Ohio Pennsylvania Pennsylvania Power New Castle 1 

Pennsylvania Pennsylvania Power New Castle 2 Massachusetts New England Power Brayton Point 1 Massachusetts New England Power Brayton Point 2 Massachusetts New England Power Brayton Point 3 Massachusetts New England Power Brayton Point 4 Massachusetts New England Power Salem Harbor 1 Massachusetts New England Power Salem Harbor 2 Massachusetts New England Power Salem Harbor 3 

Niles 2 133 14,806 16,264 12,340 3 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

Pennsylvania Pennsylvania

Power

New Castle 1 

Pennsylvania Pennsylvania

Power

New Castle 2 

Niles 1 133 18,240 14,054 13,080 1 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 81

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Ohio Ohio Ohio Edison R E Burger 2 

Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

Pennsylvania Pennsylvania

Power

New Castle 1 

Pennsylvania Pennsylvania

Power

New Castle 2 

R E Burger 3 e 104 9,383 12,965 2,252 2 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

Pennsylvania Pennsylvania

Power

New Castle 1 

Pennsylvania Pennsylvania

Power

New Castle 2 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 82 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Ohio R E Burger 4 156 21,973 21,956 13,826 2 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania Power Bruce Mansfield 1 

Pennsylvania Pennsylvania Power Bruce Mansfield 2 

Pennsylvania Pennsylvania Power New Castle 1 Pennsylvania Pennsylvania Power New Castle 2 

R E Burger 5 156 23,127 25,973 23,539 2 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

Pennsylvania Pennsylvania

Power

New Castle 1 

Pennsylvania Pennsylvania

Power

New Castle 2 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 83

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Ohio W H Sammis 5 334 26,496 34,632 12,627 1 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

Pennsylvania Pennsylvania

Power

New Castle 1 

Pennsylvania Pennsylvania

Power

New Castle 2 

W H Sammis 6 680 43,773 61,391 27,041 1 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania

Power

Bruce

Mansfield

1 

Pennsylvania Pennsylvania

Power

Bruce

Mansfield

2 

Pennsylvania Pennsylvania

Power

New Castle 1 

Pennsylvania Pennsylvania

Power

New Castle 2 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 84 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Ohio W H Sammis 7 680 47,380 54,557 22,162 1 Ohio Ohio Edison Edgewater 11 

Ohio Ohio Edison Edgewater 12 Ohio Ohio Edison R E Burger 1 Ohio Ohio Edison R E Burger 2 Ohio Ohio Edison R E Burger 3 Ohio Ohio Edison R E Burger 4 Ohio Ohio Edison Gorge 25 Ohio Ohio Edison Gorge 26 Ohio Ohio Edison Toronto 9 Ohio Ohio Edison Toronto 10 Ohio Ohio Edison Toronto 11 Pennsylvania Pennsylvania Power Bruce Mansfield 1 

Pennsylvania Pennsylvania Power Bruce Mansfield 2 

Pennsylvania Pennsylvania Power New Castle 1 Pennsylvania Pennsylvania Power New Castle 2 

Ohio Power Gen Jm Gavin 1 1,300 192,637 177,338 11,945 3 Gen Jm Gavin 2 1,300 188,168 185,911 11,533 3 Muskingum River 1 220 38,001 41,429 19,235 2Muskingum River 2 220 34,026 41,796 25,074 2Muskingum River 3 238 36,130 36,195 26,647 2Muskingum River 4 238 34,153 35,108 31,952 2Muskingum River 5 615 44,364 98,907 14,648 2Ohio Valley ElectricKyger Creek 1 217 18,773 45,319 18,313 1Kyger Creek 2 217 18,072 44,494 18,487 1Kyger Creek 3 217 17,439 42,499 19,265 1Kyger Creek 4 217 18,218 43,345 18,018 1Kyger Creek 5 217 18,247 46,886 18,723 1

Pennsylvania Duquesne Light

Cheswick 1 565 38,139 41,927 42,900 2Metropolitan EdisonCo.Portland 1 172 9,373 6,436 11,088 2Portland 2 255 17,309 10,892 11,055 2

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 85

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compensating

Plant

Substitution/

Compensating

Boilers

Pennsylvania Pennsylvania

Electric Co.Conemaugh 1 936 96,594 92,088 4,729 3Conemaugh 2 936 85,753 89,804 73,364 3Shawville 1 125 10,048 13,485 14,265 2Shawville 2 125 10,048 14,310 10,837 2Shawville 3 188 13,846 18,692 17,155 2Shawville 4 188 13,700 17,683 16,147 2PennsylvaniaPower & LightBrunner Island 1 363 27,030 32,078 21,128 1Brunner Island 2 405 31,995 34,103 19,933 1Brunner Island 3 790 60,571 58,775 56,335 1Martin's Creek 1 156 12,327 14,627 5,988 1Martin's Creek 2 156 12,483 14,131 4,774 1Sunbury 3 104 9,133 10,046 9,847 1Sunbury 4 156 11,392 14,077 9,511 1West PennsylvaniaPowerArmstrong 1 163 17,738 16,434 4,711 2 West Virginia Monongahela

Power

Albright 1 

Armstrong 2 163 15,024 15,423 17,196 2 West Virginia Monongahela

Power

Albright 2 

Hatfield's Ferry 1 576 55,732 54,286 66,839 2 West Virginia Monongahela

Power

Pleasants 1 

Hatfield's Ferry 2 576 57,506 51,986 47,799 2 West Virginia Monongahela

Power

Pleasants 2 

Hatfield's Ferry 3 576 56,580 54,809 50,203 2 Pennsylvania West Penn

Power

Mitchell 33 

Tennessee TVA

Allen 1 330 14,917 21,866 13,144 1Allen 2 330 16,329 25,986 16,512 1Allen 3 330 15,258 19,696 18,618 1Cumberland 1 1,300 165,080 148,104 12,445 3Cumberland 2 1,300 172,416 196,049 13,685 3Gallatin 1 300 32,218 28,846 24,174 2Gallatin 2 300 31,674 30,410 23,069 2Gallatin 3 328 36,179 35,789 26,797 2Gallatin 4 328 33,879 35,351 24,325 2

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 86 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Tennessee Johnsonville 1 125 7,585 11,123 9,722 2 Johnsonville 2 125 7,828 10,657 9,278 2 Johnsonville 3 125 8,189 9,712 8,543 2 Johnsonville 4 125 7,780 8,968 9,853 2 Johnsonville 5 147 8,023 8,544 12,233 2 Johnsonville 6 147 7,682 8,767 10,583 2 Johnsonville 7 173 8,744 10,389 15,784 2 Johnsonville 8 173 8,471 10,207 12,397 2 Johnsonville 9 173 6,894 8,922 13,292 2 Johnsonville 10 173 7,351 8,835 12,991 2 West Virginia Monongahela Power Albright 3 140 11,684 11,938 11,444 2 Maryland Potomac Edison R P Smith 9 

Fort Martin 1 576 41,905 44,309 26,803 2 Fort Martin 2 576 44,118 44,824 43,171 2 Maryland Potomac Edison RP Smith 11 

Harrison 1 684 82,613 78,231 3,323 3 West Virginia Monongahela Power Rivesville 7 

West Virginia Monongahela Power Rivesville 8 

Harrison 2 684 91,180 78,231 3,373 3Harrison 3 684 90,727 78,231 3,249 3 West Virginia Monongahela

Power

Willow Island 1 

West Virginia Monongahela

Power

Willow Island 2 

Ohio PowerKammer 1 238 18,247 48,863 36,224 2Kammer 2 238 18,948 57,963 42,224 2Kammer 3 238 16,932 50,208 43,745 2Mitchell 1 816 42,823 48,079 26,492 1Mitchell 2 816 44,312 55,247 35,131 1Virginia Electric &PowerMt. Storm 1 570 49,481 48,587 45,556 2Mt. Storm 2 570 45,203 35,817 49,688 2Mt. Storm 3 522 49,859 43,906 2,549 3

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 87

Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)

State

Operating Utility/

Plant

Generator

Numbera

Affected 

Nameplate

Capacity

(megawatts)

1995

Allowanceb

Allocations

1985 SO2

Emissions

Estimates

(tons)

1995 SO2

Emissions

(tons)

Code of

Compliance

Methodc

Substitution/

Compensating

State

Substitution/

Compensating

Utility

Substitution/

Compen-sating

Plant

Substitution/

Compensating

Boilers

Wisconsin Dairyland Power

Coop.Genoa ST3 346 22,103 35,035 15,304 1 Wisconsin Dairyland

Power Coop

Alma B4 

Wisconsin Dairyland

Power Coop

Alma B5 

Wisconsin ElectricPowerNorth Oak Creek 1 120 5,083 6,810 0 4North Oak Creek 2 120 5,005 7,916 0 4North Oak Creek 3 130 5,229 7,184 0 4North Oak Creek 4 130 6,154 9,323 0 4South Oak Creek 5 275 9,416 16,586 5,343 1 Wisconsin WEPCO Port Washington 1 

Wisconsin WEPCO Port Washington 2 Wisconsin WEPCO Port Washington 3 Wisconsin WEPCO Port Washington 4 Wisconsin WEPCO Port Washington 5 Wisconsin WEPCO Valley 1 Wisconsin WEPCO Valley 2 Wisconsin WEPCO Valley 3 Wisconsin WEPCO Valley 4 

South Oak Creek 6 275 11,723 17,748 5,663 1South Oak Creek 7 318 15,754 27,888 9,658 1South Oak Creek 8 324 15,375 22,553 6,005 1Wisconsin Power &LightEdgewater 4 330 24,099 39,722 6,482 1 Wisconsin WEPCO Edgewater 3 

Wisconsin Dairyland

Power Coop

J P Madgett B1 

Nelson Dewey 1 100 5,852 13,289 2,046 1 Wisconsin WEPCO Rock River 1 

Wisconsin WEPCO Rock River 2 

Nelson Dewey 2 100 6,504 12,273 2,081 1 Wisconsin WEPCO Rock River 1 

Wisconsin WEPCO Rock River 2 

Pulliam 8 136 7,312 10,446 2,087 1 Wisconsin Wisconsin

Public Service

Pulliam 5 

See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 88 Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued) State Operating Utility/ Plant Generator Numbera Affected Nameplate Capacity (megawatts) 1995 Allowanceb Allocations 1985 SO2 Emissions Estimates (tons) 1995 SO2 Emissions (tons) Code of Com- pliance Methodc Substitution/ Compen- sating State Substitution/ Compen- sating Utility Substitution/ Compen- sating Plant Substitution/ Compen- sating Boilers 

Wisconsin Wisconsin Wisconsin Public Service Pulliam 6 

Wisconsin Wisconsin Public Service Pulliam 7 Wisconsin Wisconsin Public Service Weston 1 

Wisconsin Wisconsin Public Service Weston 2 

Wisconsin Wisconsin Public Service Weston 3 

 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 Table 1 boilers is 263 and the n

a One SO allowance permits one ton of SO emissions. b 2 2 The codes for the method of compliance are: (1) fuel switching and/or blending with lower-sulfur coal; (2) obtaining additional allowances; (3) scrubbing; 4) retired; and (5) other–c petroleum. Miami Fort generator 5 has two boilers. Allowances, 1985 SO emissions estimates, and 1995 emissions for the boilers were added to provide generator-level data. d

2

 R.E. Burger generator 3 has two boilers. Allowances and 1985 SO emissions estimates and 1995 emissions for the boilers were added to provide generator-level data. e

2

 SO = Sulfur dioxide. 2 TVA = Tennessee Valley Authority. Sources: The Utility Report, December 1995, Energy Ventures Analysis, Inc. List of Table 1 Units: Federal Register, Vol. 58, No. 6 (January 11, 1993), pp. 3687-3691. Capac

of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC, October 1993). 1985 Emissions: U.S. Environmental Protection Agency, National Allowance Data Base, Versions 2.1

Environmental Protection Agency.
Table B2. Profile of Coal Received at Table 1 Plants, 1995

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Alabama Power Co Gaston .................................................................. 3,832 12,318 0.77 0.62 11.60 173.1 42.63

Alabama ................................................................................................ 2,664 12,387 .77 .62 11.52 184.0 45.60

Fayette ................................................................................................ 107 12,060 1.84 1.53 12.28 116.3 28.05

Jefferson ............................................................................................. 278 12,829 .83 .65 10.53 207.7 53.30

Shelby ................................................................................................ 653 12,663 .84 .67 10.33 150.1 38.00

Tuscaloosa ......................................................................................... 624 12,583 .65 .52 10.40 212.7 53.52

Walker ................................................................................................ 1,000 11,995 .67 .56 13.19 189.2 45.38

Unknown1 .......................................................................................... 2 12,700 1.20 .94 10.00 102.4 26.01

Kentucky ............................................................................................... 214 12,173 .94 .77 10.48 143.9 35.04

Breathitt ............................................................................................. 9 12,402 .81 .65 11.50 148.3 36.78

Harlan ................................................................................................ 97 12,512 1.01 .81 9.16 146.2 36.59

Jackson ............................................................................................... 108 11,848 .88 .74 11.58 141.4 33.50

Leslie .................................................................................................. * 12,500 1.01 .81 10.00 151.1 37.77

West Virginia........................................................................................ 954 12,156 .73 .60 12.08 148.3 36.06

Lincoln ............................................................................................... 934 12,169 .73 .60 12.02 148.4 36.11

Mingo ................................................................................................. 20 11,543 .79 .68 14.64 147.3 34.01

Associated Electric Coop Inc Hill........................................................ 4,723 8,744 .20 .23 4.56 71.8 12.55

Wyoming .............................................................................................. 4,723 8,744 .20 .23 4.56 71.8 12.55

Campbell ............................................................................................ 4,723 8,744 .20 .23 4.56 71.8 12.55

Associated Electric Coop Inc Madrid................................................. 4,263 8,761 .23 .26 4.61 94.5 16.56

Illinois ................................................................................................... 19 10,704 2.95 2.76 10.46 118.0 25.26

Randolph ............................................................................................ 19 10,704 2.95 2.76 10.46 118.0 25.26

Indiana .................................................................................................. 19 10,879 2.92 2.68 9.03 118.0 25.67

Warrick .............................................................................................. 19 10,879 2.92 2.68 9.03 118.0 25.67

Wyoming .............................................................................................. 4,225 8,743 .20 .23 4.56 94.2 16.48

Campbell ............................................................................................ 4,225 8,743 .20 .23 4.56 94.2 16.48

Atlantic City Electric Co England....................................................... 594 12,822 2.43 1.89 10.31 168.4 43.19

West Virginia........................................................................................ 594 12,822 2.43 1.89 10.31 168.4 43.19

Marion ................................................................................................ 221 12,865 2.49 1.94 9.88 168.4 43.33

Monongalia ........................................................................................ 7 13,304 1.90 1.43 6.20 145.5 38.71

Upshur ................................................................................................ 366 12,787 2.40 1.88 10.66 168.9 43.19

Baltimore Gas & Electric Co Crane ................................................... 645 13,528 .93 .69 6.65 170.6 46.14

Pennsylvania ......................................................................................... 8 13,122 1.57 1.20 6.80 144.9 38.03

Greene ................................................................................................ 8 13,122 1.57 1.20 6.80 144.9 38.03

Virginia ................................................................................................. 394 13,798 .71 .52 5.97 180.2 49.74

Buchanan ........................................................................................... 394 13,798 .71 .52 5.97 180.2 49.74

West Virginia........................................................................................ 243 13,103 1.26 .96 7.76 154.9 40.59

Barbour .............................................................................................. 221 13,078 1.15 .88 7.88 157.8 41.28

Monongalia ........................................................................................ 22 13,355 2.34 1.75 6.50 125.9 33.63

Big Rivers Electric Corp Coleman...................................................... 1,367 11,437 1.94 1.69 9.74 107.6 24.62

Indiana .................................................................................................. 258 11,490 1.45 1.26 8.02 116.7 26.81

Knox .................................................................................................. 2 11,119 1.44 1.30 13.30 124.5 27.69

Spencer .............................................................................................. 256 11,493 1.45 1.26 7.98 116.6 26.81

Kentucky ............................................................................................... 877 11,301 2.18 1.93 8.80 107.6 24.33

Floyd .................................................................................................. 72 11,810 1.45 1.23 11.46 116.2 27.44

Henderson .......................................................................................... 608 11,202 2.51 2.24 8.27 102.8 23.04

Lawrence ............................................................................................ 22 11,841 1.47 1.24 11.12 123.5 29.24

Martin ................................................................................................ 22 11,841 1.47 1.24 11.12 123.5 29.24

Ohio ................................................................................................... 136 11,250 1.43 1.27 8.46 119.1 26.80

Pike .................................................................................................... 18 11,686 1.42 1.21 13.25 107.1 25.04

Pennsylvania ......................................................................................... 186 11,885 1.45 1.22 14.96 96.7 22.99

Greene ................................................................................................ 186 11,885 1.45 1.22 14.96 96.7 22.99

West Virginia........................................................................................ 45 11,926 1.86 1.56 16.20 102.2 24.37

Kanawha ............................................................................................ 1 11,119 1.44 1.30 13.30 124.5 27.69

Monongalia ........................................................................................ 44 11,944 1.87 1.57 16.26 101.7 24.29

Big Rivers Electric Corp Reid-Henderson II..................................... 796 11,827 2.77 2.34 9.29 109.9 25.99

Kentucky ............................................................................................... 796 11,827 2.77 2.34 9.29 109.9 25.99

Daviess ............................................................................................... 181 11,194 2.46 2.20 9.57 101.0 22.61

Henderson .......................................................................................... 12 11,204 2.72 2.43 9.54 76.5 17.15

Webster .............................................................................................. 603 12,030 2.86 2.38 9.21 112.9 27.17

Cardinal Operating Co Cardinal......................................................... 4,123 12,187 1.47 1.21 11.56 158.1 38.55

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities1 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Cardinal Operating Co Cardinal

Kentucky ............................................................................................... 611 12,111 0.67 0.55 10.56 138.3 33.49

Floyd .................................................................................................. 43 12,139 .71 .59 12.28 138.0 33.51

Knott .................................................................................................. 175 12,099 .65 .54 9.89 138.4 33.49

Magoffin ............................................................................................ 219 12,099 .65 .54 9.89 138.4 33.49

Perry ................................................................................................... 44 12,099 .65 .54 9.89 138.4 33.49

Pike .................................................................................................... 130 12,140 .71 .59 12.25 138.0 33.51

Ohio ...................................................................................................... 254 11,906 2.87 2.41 12.30 103.9 24.73

Belmont .............................................................................................. 211 11,836 2.83 2.39 12.37 110.3 26.12

Jefferson ............................................................................................. 43 12,254 3.09 2.52 11.94 72.9 17.86

West Virginia........................................................................................ 3,258 12,223 1.51 1.24 11.69 166.0 40.57

Boone ................................................................................................. 89 12,146 .68 .56 12.24 136.9 33.25

Brooke ................................................................................................ 1,040 12,306 3.27 2.66 9.96 194.4 47.84

Kanawha ............................................................................................ 331 12,344 .70 .57 12.07 164.7 40.67

Logan ................................................................................................. 1,477 12,125 .65 .53 12.67 156.3 37.91

Mingo ................................................................................................. 89 12,151 .68 .56 12.11 137.2 33.34

Webster .............................................................................................. 232 12,356 .92 .74 12.26 122.8 30.34

Central Illinois Pub Serv Co Coffeen ................................................. 1,690 10,266 .91 .88 8.16 171.8 35.28

Illinois ................................................................................................... 1,690 10,266 .91 .88 8.16 171.8 35.28

Macoupin ........................................................................................... 1,690 10,266 .91 .88 8.16 171.8 35.28

Central Illinois Pub Serv Co Grand Tower....................................... 150 11,401 2.85 2.50 11.40 190.8 43.50

Illinois ................................................................................................... 150 11,401 2.85 2.50 11.40 190.8 43.50

Perry ................................................................................................... 28 10,923 3.05 2.79 10.20 192.3 42.01

Williamson ......................................................................................... 122 11,509 2.81 2.44 11.67 190.5 43.84

Central Illinois Pub Serv Co Meredosia............................................. 509 11,067 2.19 1.98 5.69 152.6 33.79

Illinois ................................................................................................... 509 11,067 2.19 1.98 5.69 152.6 33.79

Macoupin ........................................................................................... 116 10,311 .89 .86 8.15 138.3 28.52

Schuyler ............................................................................................. 393 11,290 2.57 2.28 4.97 156.5 35.34

Cincinnati Gas & Electric Co Beckjord............................................. 2,192 11,915 .98 .82 12.88 160.5 38.25

Kentucky ............................................................................................... 1,781 11,820 .88 .74 13.45 171.1 40.44

Breathitt ............................................................................................. 100 12,016 .91 .76 10.52 119.5 28.72

Floyd .................................................................................................. 52 11,858 .86 .73 12.09 109.3 25.93

Johnson .............................................................................................. 10 11,513 .93 .80 13.04 102.5 23.61

Knott .................................................................................................. 8 11,650 .91 .78 12.61 113.6 26.48

Knox .................................................................................................. 8 11,979 1.17 .98 12.50 101.8 24.39

Magoffin ............................................................................................ 167 11,744 1.14 .97 12.43 154.5 36.28

Martin ................................................................................................ 1,189 11,763 .84 .72 14.60 192.8 45.36

Pike .................................................................................................... 245 12,074 .85 .70 10.10 120.1 29.00

Ohio ...................................................................................................... 55 12,478 4.01 3.21 9.48 94.0 23.46

Belmont .............................................................................................. 49 12,521 3.98 3.18 9.34 94.3 23.62

Harrison ............................................................................................. 6 12,115 4.25 3.51 10.68 91.2 22.11

Pennsylvania ......................................................................................... 35 13,186 1.62 1.23 7.39 104.9 27.66

Greene ................................................................................................ 35 13,186 1.62 1.23 7.39 104.9 27.66

West Virginia........................................................................................ 320 12,206 .97 .79 10.93 121.9 29.76

Boone ................................................................................................. 11 12,245 .71 .58 13.32 114.1 27.94

Fayette ................................................................................................ 5 12,157 2.20 1.81 13.70 83.7 20.35

Kanawha ............................................................................................ 169 12,129 .83 .68 11.48 124.4 30.17

Logan ................................................................................................. 3 11,310 1.12 .99 14.10 101.0 22.85

Mingo ................................................................................................. 108 12,102 .86 .71 10.56 125.0 30.27

Monongalia ........................................................................................ 24 13,348 2.36 1.77 6.49 105.7 28.21

Cincinnati Gas & Electric Co Miami Fort......................................... 2,663 12,138 .82 .68 11.79 143.2 34.76

Kentucky ............................................................................................... 1,254 11,901 .82 .69 12.55 149.0 35.46

Breathitt ............................................................................................. 42 11,950 .88 .73 10.30 117.9 28.18

Floyd .................................................................................................. 567 11,980 .69 .57 12.09 127.8 30.63

Johnson .............................................................................................. 8 11,316 .93 .82 14.58 99.4 22.50

Knott .................................................................................................. 48 11,867 .68 .57 11.13 123.0 29.20

Lawrence ............................................................................................ 8 11,742 1.77 1.51 11.32 91.1 21.40

Magoffin ............................................................................................ 174 11,657 1.29 1.11 13.92 189.7 44.22

Martin ................................................................................................ 296 11,865 .83 .70 13.59 187.0 44.38

Pike .................................................................................................... 110 12,027 .72 .60 11.34 125.2 30.12

See footnotes at end of table.

2Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Cincinnati Gas & Electric Co Miami Fort

Ohio ...................................................................................................... 31 12,554 4.01 3.20 9.31 92.2 23.15

Belmont .............................................................................................. 30 12,579 4.00 3.18 9.24 92.0 23.14

Harrison ............................................................................................. 2 12,124 4.22 3.48 10.60 96.0 23.28

Pennsylvania ......................................................................................... 11 13,204 2.46 1.86 8.00 103.8 27.41

Greene ................................................................................................ 11 13,204 2.46 1.86 8.00 103.8 27.41

West Virginia........................................................................................ 1,367 12,338 .74 .60 11.18 139.6 34.44

Boone ................................................................................................. 9 12,340 .72 .58 12.90 118.3 29.20

Clay .................................................................................................... 381 12,206 .68 .55 11.88 119.8 29.25

Kanawha ............................................................................................ 805 12,403 .71 .57 11.06 152.7 37.87

Logan ................................................................................................. 102 12,155 .69 .57 10.97 126.3 30.71

Marion ................................................................................................ 2 12,742 2.61 2.05 10.00 114.8 29.26

Mingo ................................................................................................. 42 12,094 .80 .66 10.14 124.6 30.13

Monongalia ........................................................................................ 26 13,339 2.40 1.80 6.49 106.2 28.33

Cleveland Electric Illum Co Ashtabula .............................................. 621 12,635 3.86 3.06 9.31 165.3 41.76

Ohio ...................................................................................................... 621 12,635 3.86 3.06 9.31 165.3 41.76

Belmont .............................................................................................. 539 12,682 4.03 3.18 9.07 171.2 43.42

Columbiana ........................................................................................ 82 12,324 2.75 2.23 10.91 125.3 30.88

Cleveland Electric Illum Co Avon Lake............................................. 1,615 12,741 .85 .67 8.88 152.3 38.82

Kentucky ............................................................................................... 263 12,416 .66 .53 8.91 155.5 38.62

Pike .................................................................................................... 263 12,416 .66 .53 8.91 155.5 38.62

Virginia ................................................................................................. 89 12,646 .85 .67 8.51 146.7 37.10

Buchanan ........................................................................................... 89 12,646 .85 .67 8.51 146.7 37.10

West Virginia........................................................................................ 1,263 12,815 .89 .70 8.90 152.1 38.98

Mingo ................................................................................................. 1,123 12,767 .69 .54 9.07 155.4 39.68

Monongalia ........................................................................................ 140 13,196 2.48 1.88 7.59 126.7 33.43

Cleveland Electric Illum Co Eastlake ................................................. 2,398 12,999 2.39 1.84 7.69 142.0 36.90

Ohio ...................................................................................................... 1,008 12,726 3.55 2.79 8.83 162.9 41.45

Belmont .............................................................................................. 758 12,762 4.10 3.21 8.99 175.5 44.80

Columbiana ........................................................................................ 250 12,615 1.89 1.50 8.37 124.0 31.28

Pennsylvania ......................................................................................... 1,279 13,215 1.50 1.13 6.87 127.8 33.78

Clarion ............................................................................................... 60 12,949 1.45 1.12 7.83 129.5 33.54

Greene ................................................................................................ 876 13,177 1.50 1.14 6.84 127.7 33.66

Washington ........................................................................................ 343 13,361 1.49 1.12 6.77 127.7 34.12

West Virginia........................................................................................ 111 12,987 2.13 1.64 6.68 121.8 31.64

Monongalia ........................................................................................ 93 13,030 2.17 1.67 6.21 120.5 31.40

Nicholas ............................................................................................. 9 12,785 1.68 1.31 8.70 133.9 34.24

Preston ............................................................................................... 9 12,739 2.16 1.70 9.60 124.0 31.59

Columbus & Southern Ohio El Co Conesville .................................. 3,417 11,910 2.88 2.42 8.81 146.5 34.89

Ohio ...................................................................................................... 3,417 11,910 2.88 2.42 8.81 146.5 34.89

Belmont .............................................................................................. 64 11,609 3.61 3.11 12.25 93.8 21.78

Coshocton .......................................................................................... 1,625 11,953 2.52 2.10 7.27 180.9 43.24

Guernsey ............................................................................................ 17 11,519 3.12 2.71 11.83 101.1 23.28

Harrison ............................................................................................. 608 12,618 3.02 2.39 8.62 115.1 29.04

Holmes ............................................................................................... 27 11,238 3.63 3.23 10.72 94.9 21.33

Jefferson ............................................................................................. 88 11,963 2.54 2.13 11.46 101.4 24.27

Perry ................................................................................................... 316 11,294 3.20 2.83 11.93 112.2 25.35

Pike .................................................................................................... 102 11,941 2.60 2.18 6.80 192.8 46.04

Tuscarawas ........................................................................................ 570 11,438 3.58 3.13 11.07 108.1 24.72

Columbus & Southern Ohio El Co Picway........................................ 91 11,236 3.05 2.71 11.33 103.4 23.24

Ohio ...................................................................................................... 91 11,236 3.05 2.71 11.33 103.4 23.24

Jackson ............................................................................................... 7 11,147 4.07 3.65 12.80 97.1 21.65

Vinton ................................................................................................ 85 11,243 2.97 2.64 11.21 103.9 23.36

Commonwealth Edison Co Kincaid .................................................... 1,266 11,620 .45 .39 7.78 145.2 33.75

Illinois ................................................................................................... 41 10,398 .85 .82 8.20 100.8 20.95

Macoupin ........................................................................................... 41 10,398 .85 .82 8.20 100.8 20.95

Utah ....................................................................................................... 1,153 11,842 .45 .38 7.93 138.7 32.85

Carbon ................................................................................................ 795 11,743 .44 .38 7.77 136.9 32.15

Emery ................................................................................................. 328 12,105 .46 .38 8.38 143.1 34.65

Sevier ................................................................................................. 30 11,598 .34 .29 7.20 137.5 31.89

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities3 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Commonwealth Edison Co Kincaid

Wyoming .............................................................................................. 72 8,766 0.29 0.33 5.07 315.5 55.31

Campbell ............................................................................................ 24 8,776 .21 .24 4.50 295.3 51.83

Converse ............................................................................................ 48 8,761 .32 .37 5.35 325.6 57.05

Consumers Power Co Campbell.......................................................... 3,030 11,631 .65 .56 9.54 158.2 36.81

Kentucky ............................................................................................... 1,201 12,586 .76 .60 9.54 161.8 40.73

Breathitt ............................................................................................. 105 12,356 .71 .57 9.65 165.4 40.87

Floyd .................................................................................................. 305 12,455 .87 .70 10.56 160.5 39.97

Knott .................................................................................................. 114 12,304 .78 .64 10.93 158.5 39.00

Perry ................................................................................................... 10 12,178 .89 .73 10.77 178.7 43.53

Pike .................................................................................................... 655 12,732 .71 .56 8.83 162.3 41.33

Unknown1 .......................................................................................... 13 12,900 .90 .70 7.50 157.3 40.58

Montana ................................................................................................ 12 9,352 .36 .38 4.10 122.0 22.82

Big Horn ............................................................................................ 12 9,352 .36 .38 4.10 122.0 22.82

West Virginia........................................................................................ 1,170 12,263 .72 .59 11.93 169.8 41.64

Boone ................................................................................................. 988 12,220 .73 .60 12.02 170.7 41.72

Logan ................................................................................................. 182 12,499 .63 .51 11.46 164.9 41.22

Wyoming .............................................................................................. 648 8,759 .33 .38 5.30 120.1 21.04

Campbell ............................................................................................ 616 8,756 .34 .39 5.30 119.9 21.00

Converse ............................................................................................ 31 8,815 .21 .24 5.23 124.4 21.94

Dairyland Power Coop Genoa No.3 .................................................... 953 10,723 .75 .70 5.15 127.5 27.35

Illinois ................................................................................................... 592 12,093 .99 .82 5.23 131.1 31.72

Jefferson ............................................................................................. 592 12,093 .99 .82 5.23 131.1 31.72

Wyoming .............................................................................................. 361 8,475 .36 .42 5.02 119.1 20.19

Campbell ............................................................................................ 361 8,475 .36 .42 5.02 119.1 20.19

Duquesne Light Co Cheswick .............................................................. 1,237 13,016 1.72 1.33 8.69 115.9 30.17

Pennsylvania ......................................................................................... 981 13,060 1.92 1.47 8.55 112.8 29.46

Fayette ................................................................................................ 302 12,790 1.19 .93 9.36 133.1 34.05

Greene ................................................................................................ 679 13,181 2.25 1.70 8.18 104.0 27.42

West Virginia........................................................................................ 256 12,848 .98 .76 9.23 128.1 32.92

Fayette ................................................................................................ 256 12,848 .98 .76 9.23 128.1 32.92

East Kentucky Power Coop Cooper ................................................... 609 12,398 1.28 1.03 9.74 120.4 29.85

Kentucky ............................................................................................... 609 12,398 1.28 1.03 9.74 120.4 29.85

Bell ..................................................................................................... 50 12,690 .98 .77 8.17 107.8 27.37

Breathitt ............................................................................................. 4 12,166 1.26 1.04 10.75 121.3 29.51

Clay .................................................................................................... 147 12,769 1.15 .90 7.19 114.2 29.16

Laurel ................................................................................................. 1 11,145 1.63 1.46 12.70 74.1 16.52

Lee ..................................................................................................... 6 11,974 1.15 .96 9.05 99.8 23.91

Leslie .................................................................................................. 22 12,456 1.13 .91 9.53 114.7 28.57

Letcher ............................................................................................... 2 12,344 1.21 .98 10.30 114.3 28.22

Perry ................................................................................................... 33 12,473 .91 .73 8.94 111.9 27.90

Pulaski ................................................................................................ 318 12,194 1.41 1.16 11.27 128.1 31.25

Whitley .............................................................................................. 18 12,440 1.71 1.38 8.77 108.6 27.01

Wolfe ................................................................................................. 8 11,908 1.52 1.28 11.00 111.8 26.63

East Kentucky Power Coop Spurlock................................................. 2,203 12,424 .76 .61 10.55 116.8 29.03

Kentucky ............................................................................................... 1,250 12,461 .74 .59 9.73 117.9 29.39

Boyd ................................................................................................... 407 12,563 .76 .60 8.80 116.2 29.19

Breathitt ............................................................................................. 219 12,223 .69 .56 10.19 121.2 29.62

Floyd .................................................................................................. 96 12,163 .74 .61 10.49 117.1 28.49

Greenup .............................................................................................. 236 12,379 .80 .65 12.26 114.5 28.36

Knott .................................................................................................. 157 12,634 .67 .53 8.49 125.8 31.78

Letcher ............................................................................................... 81 13,118 .75 .57 6.74 114.7 30.09

Pike .................................................................................................... 54 12,053 .66 .55 10.63 116.6 28.11

Pennsylvania ......................................................................................... 61 13,210 1.54 1.17 7.06 107.2 28.32

Greene ................................................................................................ 61 13,210 1.54 1.17 7.06 107.2 28.32

West Virginia........................................................................................ 892 12,319 .73 .59 11.93 116.0 28.57

Boone ................................................................................................. 24 12,256 .67 .54 12.97 109.3 26.80

Fayette ................................................................................................ 365 12,333 .80 .65 12.70 114.8 28.32

Kanawha ............................................................................................ 79 12,387 .66 .53 10.94 118.3 29.32

Logan ................................................................................................. 340 12,318 .71 .58 11.78 115.3 28.41

Wayne ................................................................................................ 84 12,218 .61 .50 9.81 123.2 30.11

Electric Energy Inc Joppa.................................................................... 4,890 8,746 .28 .32 4.53 84.5 14.79

See footnotes at end of table.

4Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Electric Energy Inc Joppa

Illinois ................................................................................................... 96 12,414 1.65 1.33 7.92 108.5 26.94

Franklin .............................................................................................. 12 12,308 .77 .63 4.70 108.5 26.71

Saline ................................................................................................. 84 12,429 1.77 1.43 8.38 108.5 26.97

Wyoming .............................................................................................. 4,794 8,673 .25 .29 4.46 83.8 14.54

Campbell ............................................................................................ 4,794 8,673 .25 .29 4.46 83.8 14.54

Empire District Electric Co Asbury.................................................... 860 9,136 .58 .64 5.58 103.5 18.90

Kansas ................................................................................................... 101 11,811 3.42 2.89 13.47 125.8 29.72

Crawford ............................................................................................ 101 11,811 3.42 2.89 13.47 125.8 29.72

Wyoming .............................................................................................. 759 8,781 .21 .24 4.53 99.5 17.47

Campbell ............................................................................................ 759 8,781 .21 .24 4.53 99.5 17.47

Georgia Power Co Atkinson-Mcdonough........................................... 1,202 12,572 .85 .68 9.74 133.5 33.56

Kentucky ............................................................................................... 1,202 12,572 .85 .68 9.74 133.5 33.56

Harlan ................................................................................................ 1,202 12,572 .85 .68 9.74 133.5 33.56

Georgia Power Co Bowen..................................................................... 7,545 12,493 1.04 .83 9.90 163.0 40.72

Kentucky ............................................................................................... 7,545 12,493 1.04 .83 9.90 163.0 40.72

Harlan ................................................................................................ 427 12,561 .97 .77 9.54 139.2 34.97

Knott .................................................................................................. 249 12,289 1.02 .83 11.03 141.3 34.73

Leslie .................................................................................................. 4,173 12,472 1.11 .89 10.07 175.1 43.68

Letcher ............................................................................................... 296 12,835 .96 .75 8.20 137.7 35.34

Perry ................................................................................................... 2,400 12,497 .92 .74 9.74 151.6 37.90

Georgia Power Co Hammond.............................................................. 1,037 12,552 .97 .77 10.02 146.5 36.78

Illinois ................................................................................................... 71 12,108 1.16 .96 5.99 140.6 34.04

Saline ................................................................................................. 71 12,108 1.16 .96 5.99 140.6 34.04

Kentucky ............................................................................................... 333 12,513 .86 .69 9.08 143.5 35.90

Martin ................................................................................................ 294 12,415 .86 .69 9.67 144.2 35.80

Whitley .............................................................................................. 39 13,267 .88 .66 4.60 138.4 36.72

Virginia ................................................................................................. 450 12,647 1.15 .91 11.38 148.5 37.56

Lee ..................................................................................................... 20 12,455 1.11 .89 11.22 184.2 45.88

Wise ................................................................................................... 430 12,656 1.15 .91 11.39 146.9 37.17

West Virginia........................................................................................ 183 12,563 .66 .52 9.96 149.3 37.53

Logan ................................................................................................. 79 12,753 .66 .52 10.39 151.9 38.74

Mingo ................................................................................................. 104 12,421 .65 .53 9.63 147.4 36.62

Georgia Power Co Wansley ................................................................. 2,801 12,722 .88 .69 8.40 189.4 48.20

Alabama ................................................................................................ 104 12,178 1.85 1.52 12.22 133.7 32.55

Fayette ................................................................................................ 104 12,178 1.85 1.52 12.22 133.7 32.55

Illinois ................................................................................................... 487 12,086 1.11 .92 6.41 157.1 37.97

Saline ................................................................................................. 487 12,086 1.11 .92 6.41 157.1 37.97

Kentucky ............................................................................................... 1,663 12,948 .72 .56 8.50 204.0 52.82

Bell ..................................................................................................... 9 11,913 .90 .76 10.14 205.3 48.91

Harlan ................................................................................................ 1,634 12,989 .73 .56 8.26 204.6 53.15

Pike .................................................................................................... 20 10,001 .56 .56 27.14 132.5 26.50

Virginia ................................................................................................. 113 12,769 .96 .75 10.06 151.2 38.63

Wise ................................................................................................... 113 12,769 .96 .75 10.06 151.2 38.63

West Virginia........................................................................................ 434 12,690 .95 .75 8.93 189.9 48.19

Logan ................................................................................................. 30 12,748 .83 .65 10.37 154.0 39.26

Mingo ................................................................................................. 404 12,686 .96 .76 8.82 192.6 48.85

Georgia Power Co Yates....................................................................... 1,235 12,534 .90 .72 10.14 160.6 40.26

Alabama ................................................................................................ 29 12,191 1.89 1.55 11.96 132.4 32.28

Fayette ................................................................................................ 29 12,191 1.89 1.55 11.96 132.4 32.28

Illinois ................................................................................................... 46 12,109 1.12 .92 6.72 146.9 35.58

Saline ................................................................................................. 46 12,109 1.12 .92 6.72 146.9 35.58

Kentucky ............................................................................................... 108 12,239 .83 .68 10.94 155.2 37.99

Martin ................................................................................................ 50 12,126 .87 .72 10.75 147.6 35.79

Pike .................................................................................................... 58 12,336 .80 .65 11.10 161.6 39.87

Virginia ................................................................................................. 682 12,608 .98 .78 10.27 168.5 42.50

Lee ..................................................................................................... 357 12,426 1.10 .89 11.17 189.8 47.18

Wise ................................................................................................... 325 12,809 .84 .66 9.29 145.8 37.36

West Virginia........................................................................................ 370 12,564 .67 .53 9.94 151.2 37.99

Logan ................................................................................................. 174 12,813 .67 .52 9.56 152.2 39.01

Mingo ................................................................................................. 196 12,343 .68 .55 10.27 150.3 37.10

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities5 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Gulf Power Co Crist ............................................................................. 1,574 12,354 0.93 0.75 6.31 229.6 56.74

Illinois ................................................................................................... 797 12,346 .95 .77 6.34 228.4 56.40

Franklin .............................................................................................. 20 11,690 2.17 1.86 8.29 128.1 29.96

Saline ................................................................................................. 777 12,363 .92 .74 6.29 230.9 57.09

Imported ................................................................................................ 777 12,363 .92 .74 6.29 230.9 57.09

Imported Coal.................................................................................... 777 12,363 .92 .74 6.29 230.9 57.09

Hoosier Energy R E C Inc Frank E Ratts......................................... 753 11,151 1.30 1.16 7.45 132.6 29.57

Indiana .................................................................................................. 753 11,151 1.30 1.16 7.45 132.6 29.57

Pike .................................................................................................... 753 11,151 1.30 1.16 7.45 132.6 29.57

Illinois Power Co Baldwin.................................................................... 4,353 10,824 2.92 2.70 10.16 109.7 23.75

Illinois ................................................................................................... 4,353 10,824 2.92 2.70 10.16 109.7 23.75

Perry ................................................................................................... 2,074 10,941 2.93 2.68 10.04 113.0 24.72

Washington ........................................................................................ 2,279 10,718 2.91 2.72 10.27 106.7 22.87

Illinois Power Co Hennepin ................................................................. 583 10,703 2.93 2.74 10.32 113.5 24.29

Illinois ................................................................................................... 583 10,703 2.93 2.74 10.32 113.5 24.29

Washington ........................................................................................ 583 10,703 2.93 2.74 10.32 113.5 24.29

Illinois Power Co Vermilion................................................................. 31 11,142 2.10 1.88 8.81 132.0 29.41

Indiana .................................................................................................. 31 11,142 2.10 1.88 8.81 132.0 29.41

Sullivan .............................................................................................. 31 11,142 2.10 1.88 8.81 132.0 29.41

Indiana & Michigan Electric Co Tanners Creek.............................. 1,428 12,265 1.19 .97 8.78 146.9 36.04

Illinois ................................................................................................... 61 11,377 1.88 1.66 8.74 109.1 24.82

Franklin .............................................................................................. 61 11,377 1.88 1.66 8.74 109.1 24.82

Kentucky ............................................................................................... 713 12,514 1.65 1.32 7.40 134.2 33.60

Hopkins .............................................................................................. 336 11,611 1.95 1.68 9.63 111.9 25.98

Letcher ............................................................................................... 377 13,320 1.38 1.04 5.42 151.6 40.39

West Virginia........................................................................................ 553 12,684 .70 .56 11.34 168.8 42.82

Fayette ................................................................................................ 249 12,743 .70 .55 11.06 174.1 44.36

Kanawha ............................................................................................ 249 12,743 .70 .55 11.06 174.1 44.36

Logan ................................................................................................. 53 12,155 .67 .55 13.99 119.3 29.01

Marshall ............................................................................................. 2 11,822 2.67 2.26 11.60 98.7 23.34

Wyoming .............................................................................................. 100 8,730 .19 .22 4.39 131.0 22.87

Campbell ............................................................................................ 100 8,730 .19 .22 4.39 131.0 22.87

Indiana-Kentucky Electric Corp Clifty Creek................................... 4,890 10,297 1.03 1.00 6.42 109.4 22.53

Ohio ...................................................................................................... 912 11,156 4.01 3.60 11.85 100.6 22.44

Belmont .............................................................................................. 93 12,213 4.40 3.60 10.18 94.4 23.05

Jackson ............................................................................................... 819 11,036 3.97 3.60 12.04 101.4 22.37

Virginia ................................................................................................. 1,014 13,792 .73 .53 6.06 152.4 42.04

Buchanan ........................................................................................... 1,014 13,792 .73 .53 6.06 152.4 42.04

West Virginia........................................................................................ 7 12,050 3.96 3.29 13.57 110.3 26.58

Marshall ............................................................................................. 7 12,050 3.96 3.29 13.57 110.3 26.58

Wyoming .............................................................................................. 2,957 8,830 .20 .23 4.86 89.8 15.85

Campbell ............................................................................................ 95 8,774 .19 .22 4.26 81.9 14.37

Converse ............................................................................................ 2,862 8,831 .20 .23 4.88 90.0 15.90

Indianapolis Power & Light Co Petersburg ...................................... 4,598 11,099 2.42 2.18 8.95 101.1 22.45

Indiana .................................................................................................. 4,598 11,099 2.42 2.18 8.95 101.1 22.45

Daviess ............................................................................................... 1,901 11,319 2.24 1.98 8.67 92.7 20.98

Greene ................................................................................................ 4 11,531 2.44 2.12 8.03 88.7 20.46

Knox .................................................................................................. 360 10,871 .63 .58 8.35 120.4 26.18

Pike .................................................................................................... 156 11,114 2.56 2.31 8.62 96.5 21.44

Warrick .............................................................................................. 2,177 10,942 2.86 2.62 9.32 106.0 23.19

Indianapolis Power & Light Co Pritchard......................................... 340 11,368 1.24 1.09 7.31 112.0 25.45

Indiana .................................................................................................. 340 11,368 1.24 1.09 7.31 112.0 25.45

Daviess ............................................................................................... 52 11,169 1.31 1.17 8.04 109.8 24.52

Greene ................................................................................................ 147 11,487 1.28 1.11 6.99 111.3 25.57

Owen .................................................................................................. 141 11,316 1.17 1.03 7.37 113.4 25.67

Indianapolis Power & Light Co Stout................................................ 1,335 11,255 1.46 1.30 8.11 113.5 25.54

See footnotes at end of table.

6Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Indianapolis Power & Light Co Stout

Indiana .................................................................................................. 1,335 11,255 1.46 1.30 8.11 113.5 25.54

Daviess ............................................................................................... 505 11,151 1.49 1.33 8.48 111.9 24.95

Greene ................................................................................................ 665 11,392 1.48 1.30 7.47 118.0 26.88

Knox .................................................................................................. 42 11,199 1.43 1.28 8.22 115.6 25.90

Sullivan .............................................................................................. 123 10,956 1.28 1.17 10.06 93.7 20.54

Interstate Power Co Kapp.................................................................... 372 11,334 .58 .52 11.32 126.9 28.78

Colorado ................................................................................................ 372 11,334 .58 .52 11.32 126.9 28.78

Mesa ................................................................................................... 372 11,334 .58 .52 11.32 126.9 28.78

Iowa Electric Light & Power Prairie Creek 1-4 ............................... 846 8,868 .56 .63 5.66 112.7 19.98

Illinois ................................................................................................... 117 11,459 1.96 1.71 8.70 121.6 27.86

Franklin .............................................................................................. 103 11,603 2.10 1.81 8.78 121.8 28.27

Macoupin ........................................................................................... 14 10,401 .92 .88 8.06 119.4 24.83

Wyoming .............................................................................................. 729 8,452 .33 .39 5.17 110.7 18.72

Campbell ............................................................................................ 729 8,452 .33 .39 5.17 110.7 18.72

Iowa Public Service George Neal ........................................................ 5,934 8,728 .38 .44 5.31 81.4 14.21

Wyoming .............................................................................................. 5,934 8,728 .38 .44 5.31 81.4 14.21

Campbell ............................................................................................ 5,316 8,526 .37 .44 5.14 76.9 13.11

Carbon ................................................................................................ 618 10,467 .45 .43 6.79 113.3 23.72

Iowa Southern Utilities Co Burlington ............................................... 482 9,691 1.05 1.08 6.46 99.5 19.29

Illinois ................................................................................................... 179 11,589 2.02 1.74 8.81 105.4 24.42

Franklin .............................................................................................. 179 11,589 2.02 1.74 8.81 105.4 24.42

Indiana .................................................................................................. 18 11,434 2.68 2.34 8.33 132.2 30.23

Warrick .............................................................................................. 18 11,434 2.68 2.34 8.33 132.2 30.23

Wyoming .............................................................................................. 285 8,389 .33 .40 4.86 91.7 15.38

Campbell ............................................................................................ 285 8,389 .33 .40 4.86 91.7 15.38

Iowa-Illinois Gas&Electric Co Riverside............................................ 348 8,779 .67 .76 6.65 123.1 21.62

Illinois ................................................................................................... 55 11,281 1.96 1.74 8.67 108.2 24.41

Franklin .............................................................................................. 55 11,281 1.96 1.74 8.67 108.2 24.41

Wyoming .............................................................................................. 293 8,309 .43 .51 6.28 127.0 21.10

Campbell ............................................................................................ 293 8,309 .43 .51 6.28 127.0 21.10

Kansas City City of Quindaro ............................................................. 402 10,817 1.07 .99 7.84 207.4 44.88

Illinois ................................................................................................... 138 11,521 2.33 2.02 10.25 339.2 78.16

Franklin .............................................................................................. 9 11,280 1.90 1.68 10.05 112.5 25.38

Williamson ......................................................................................... 128 11,538 2.36 2.04 10.26 355.5 82.05

Wyoming .............................................................................................. 264 10,450 .41 .39 6.59 131.7 27.53

Carbon ................................................................................................ 264 10,450 .41 .39 6.59 131.7 27.53

Kansas City Power & Light Co Montrose ......................................... 1,653 8,674 .21 .24 5.02 97.5 16.91

Wyoming .............................................................................................. 1,653 8,674 .21 .24 5.02 97.5 16.91

Campbell ............................................................................................ 1,653 8,674 .21 .24 5.02 97.5 16.91

Kentucky Utilities Co Brown ............................................................... 1,031 11,913 1.29 1.08 11.72 118.3 28.18

Kentucky ............................................................................................... 1,022 11,905 1.28 1.07 11.72 118.3 28.17

Breathitt ............................................................................................. 387 11,845 1.05 .89 11.56 118.2 28.00

Perry ................................................................................................... 635 11,943 1.42 1.19 11.82 118.3 28.27

Tennessee .............................................................................................. 9 12,791 2.54 1.99 11.56 115.8 29.62

Morgan ............................................................................................... 9 12,791 2.54 1.99 11.56 115.8 29.62

Kentucky Utilities Co Ghent................................................................ 4,728 12,234 1.38 1.13 9.92 117.3 28.70

Indiana .................................................................................................. 285 11,204 2.97 2.65 9.37 94.5 21.17

Pike .................................................................................................... 178 11,331 3.21 2.83 9.19 94.5 21.42

Spencer .............................................................................................. 90 10,976 2.44 2.23 9.61 96.5 21.18

Warrick .............................................................................................. 17 11,075 3.13 2.83 10.08 83.6 18.51

Kentucky ............................................................................................... 1,837 12,060 1.28 1.07 9.53 125.7 30.31

Boyd ................................................................................................... 23 11,864 .65 .55 10.59 121.2 28.77

Daviess ............................................................................................... 157 11,178 2.91 2.60 9.66 95.6 21.38

Floyd .................................................................................................. 213 12,155 .66 .54 11.71 121.3 29.49

Harlan ................................................................................................ 327 12,589 .73 .58 8.37 136.7 34.43

Henderson .......................................................................................... 250 11,228 2.88 2.56 9.16 101.2 22.73

Knott .................................................................................................. 334 12,524 .67 .54 8.81 143.5 35.94

Ohio ................................................................................................... 80 11,166 3.32 2.98 10.28 81.6 18.23

Pike .................................................................................................... 452 12,225 .66 .54 9.83 135.3 33.09

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities7 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Kentucky Utilities Co Ghent

Pennsylvania ......................................................................................... 198 13,228 2.50 1.89 8.16 102.8 27.20

Greene ................................................................................................ 198 13,228 2.50 1.89 8.16 102.8 27.20

West Virginia........................................................................................ 2,408 12,407 1.18 .95 10.42 114.8 28.48

Boone ................................................................................................. 43 12,430 .68 .55 11.18 118.3 29.40

Clay .................................................................................................... 43 12,073 .69 .57 12.10 126.3 30.50

Kanawha ............................................................................................ 821 12,657 .70 .55 10.51 120.2 30.41

Logan ................................................................................................. 345 12,253 .67 .54 11.89 124.0 30.40

Marshall ............................................................................................. 436 12,339 3.46 2.80 10.17 84.0 20.73

Mingo ................................................................................................. 398 12,298 .68 .55 9.78 119.6 29.41

Wayne ................................................................................................ 322 12,201 .62 .51 9.45 124.7 30.43

Kentucky Utilities Co Green River ..................................................... 372 11,605 2.49 2.14 8.36 103.7 24.08

Kentucky ............................................................................................... 372 11,605 2.49 2.14 8.36 103.7 24.08

Hopkins .............................................................................................. 372 11,605 2.49 2.14 8.36 103.7 24.08

Metropolitan Edison Co Portland ....................................................... 496 13,111 1.88 1.43 7.47 136.1 35.70

Pennsylvania ......................................................................................... 23 12,732 1.85 1.46 8.81 166.1 42.29

Armstrong .......................................................................................... 15 12,852 2.04 1.58 8.97 166.9 42.90

Jefferson ............................................................................................. 8 12,500 1.50 1.20 8.50 164.5 41.12

West Virginia........................................................................................ 473 13,129 1.88 1.43 7.40 134.7 35.38

Monongalia ........................................................................................ 473 13,129 1.88 1.43 7.40 134.7 35.38

Mississippi Power Co Watson.............................................................. 1,247 12,436 2.33 1.87 8.86 123.2 30.65

Colorado ................................................................................................ 11 11,972 .50 .42 7.91 145.8 34.91

Gunnison ............................................................................................ 11 11,972 .50 .42 7.91 145.8 34.91

Illinois ................................................................................................... 1,236 12,440 2.35 1.89 8.86 123.0 30.61

Gallatin .............................................................................................. 765 12,678 2.73 2.15 9.00 120.0 30.44

Jefferson ............................................................................................. 10 12,120 .83 .68 5.03 142.8 34.61

Saline ................................................................................................. 460 12,052 1.75 1.45 8.73 127.8 30.81

Missouri Public Service Comm Sibley................................................ 1,275 10,103 .43 .42 5.63 100.8 20.36

Utah ....................................................................................................... 56 11,484 .34 .30 8.05 118.4 27.19

Carbon ................................................................................................ 22 11,573 .37 .32 8.99 118.8 27.50

Sevier ................................................................................................. 33 11,424 .32 .28 7.41 118.1 26.98

Wyoming .............................................................................................. 1,219 10,040 .43 .43 5.52 99.9 20.05

Campbell ............................................................................................ 200 8,747 .22 .26 4.59 70.9 12.41

Carbon ................................................................................................ 1,019 10,294 .47 .46 5.70 104.7 21.56

Monongahela Power Co Albright........................................................ 467 12,452 1.65 1.32 12.44 96.9 24.13

Pennsylvania ......................................................................................... 65 12,217 1.70 1.39 13.02 94.8 23.15

Fayette ................................................................................................ 65 12,217 1.70 1.39 13.02 94.8 23.15

West Virginia........................................................................................ 401 12,491 1.64 1.31 12.34 97.2 24.29

Monongalia ........................................................................................ 64 12,154 1.70 1.40 13.46 94.2 22.89

Preston ............................................................................................... 337 12,555 1.63 1.30 12.13 97.8 24.56

Monongahela Power Co Ft Martin ..................................................... 1,946 12,736 1.59 1.25 10.34 148.7 37.88

Kentucky ............................................................................................... 471 12,651 .83 .66 8.45 188.7 47.75

Martin ................................................................................................ 471 12,651 .83 .66 8.45 188.7 47.75

Maryland ............................................................................................... 285 12,732 1.52 1.20 13.41 134.9 34.34

Garrett ................................................................................................ 285 12,732 1.52 1.20 13.41 134.9 34.34

Pennsylvania ......................................................................................... 57 12,902 1.87 1.45 9.60 130.6 33.70

Greene ................................................................................................ 57 12,902 1.87 1.45 9.60 130.6 33.70

West Virginia........................................................................................ 1,133 12,764 1.90 1.49 10.38 136.6 34.88

Monongalia ........................................................................................ 1,133 12,764 1.90 1.49 10.38 136.6 34.88

Monongahela Power Co Harrison....................................................... 4,992 12,483 3.48 2.79 12.30 112.0 27.95

West Virginia........................................................................................ 4,992 12,483 3.48 2.79 12.30 112.0 27.95

Harrison ............................................................................................. 4,351 12,457 3.58 2.88 12.56 113.6 28.30

Lewis .................................................................................................. 30 12,577 2.99 2.38 11.64 92.8 23.35

Marion ................................................................................................ 84 12,370 3.54 2.86 12.68 87.3 21.60

Monongalia ........................................................................................ 446 12,768 2.58 2.02 9.62 107.5 27.45

Upshur ................................................................................................ 81 12,373 3.18 2.57 12.44 81.8 20.25

New York State Elec & Gas Corp Milliken....................................... 716 13,035 2.00 1.53 7.65 130.4 33.99

See footnotes at end of table.

8Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

New York State Elec & Gas Corp Milliken

Pennsylvania ......................................................................................... 239 13,013 1.56 1.20 6.97 134.0 34.87

Greene ................................................................................................ 232 13,023 1.54 1.19 6.80 133.7 34.82

Jefferson ............................................................................................. 8 12,693 2.06 1.62 12.10 143.2 36.35

West Virginia........................................................................................ 477 13,046 2.21 1.70 7.99 128.6 33.55

Monongalia ........................................................................................ 477 13,046 2.21 1.70 7.99 128.6 33.55

New York State Gas & Elect Greenridge .......................................... 242 13,005 1.80 1.39 8.54 131.1 34.10

Pennsylvania ......................................................................................... 108 12,589 1.30 1.04 10.78 133.8 33.68

Greene ................................................................................................ 67 12,869 1.51 1.17 7.28 133.1 34.26

Lycoming ........................................................................................... 37 11,976 .90 .75 17.64 133.6 32.00

Washington ........................................................................................ 5 13,367 1.52 1.14 7.00 143.3 38.31

West Virginia........................................................................................ 133 13,344 2.21 1.66 6.72 129.1 34.45

Monongalia ........................................................................................ 133 13,344 2.21 1.66 6.72 129.1 34.45

Niagara-Mohawk Power Corp Dunkirk............................................. 1,356 13,044 2.06 1.58 8.30 126.6 33.03

Pennsylvania ......................................................................................... 1,043 12,969 1.92 1.48 8.57 126.8 32.89

Armstrong .......................................................................................... 49 13,052 2.38 1.83 7.02 136.0 35.50

Elk ...................................................................................................... 34 11,256 1.03 .92 13.00 122.1 27.49

Greene ................................................................................................ 960 13,026 1.93 1.48 8.49 126.5 32.95

West Virginia........................................................................................ 313 13,294 2.50 1.88 7.40 126.0 33.51

Marion ................................................................................................ 17 13,143 2.50 1.90 7.95 129.9 34.15

Monongalia ........................................................................................ 296 13,303 2.50 1.88 7.37 125.8 33.48

Northern Indiana Pub Serv Co Bailly ................................................ 1,336 10,970 2.94 2.68 9.99 137.6 30.18

Illinois ................................................................................................... 1,227 10,968 3.01 2.75 10.04 139.5 30.59

Montgomery ...................................................................................... 79 10,750 3.28 3.05 8.28 113.1 24.31

Perry ................................................................................................... 1,148 10,984 2.99 2.72 10.16 141.2 31.03

Indiana .................................................................................................. 109 10,993 2.08 1.90 9.45 116.4 25.60

Sullivan .............................................................................................. 109 10,993 2.08 1.90 9.45 116.4 25.60

Northern Indiana Pub Serv Co Michigan City ................................. 1,444 9,782 .46 .47 5.84 146.5 28.66

Wyoming .............................................................................................. 1,444 9,782 .46 .47 5.84 146.5 28.66

Campbell ............................................................................................ 770 8,719 .33 .38 5.33 102.6 17.89

Carbon ................................................................................................ 674 10,997 .60 .55 6.43 186.2 40.96

Northern States Power High Bridge ................................................... 580 8,753 .21 .23 4.64 114.9 20.12

Wyoming .............................................................................................. 580 8,753 .21 .23 4.64 114.9 20.12

Campbell ............................................................................................ 526 8,750 .21 .23 4.64 114.8 20.10

Converse ............................................................................................ 54 8,777 .21 .24 4.60 115.5 20.27

Ohio Edison Co Burger ........................................................................ 564 12,470 2.98 2.39 10.57 93.1 23.23

Ohio ...................................................................................................... 226 12,444 3.78 3.04 10.17 95.2 23.68

Belmont .............................................................................................. 106 12,580 4.22 3.35 9.35 82.6 20.79

Harrison ............................................................................................. 120 12,324 3.39 2.75 10.89 106.5 26.24

Pennsylvania ......................................................................................... 180 12,635 2.41 1.90 10.26 93.0 23.49

Greene ................................................................................................ 73 13,231 2.43 1.84 8.05 94.7 25.06

Washington ........................................................................................ 64 11,951 2.83 2.37 11.93 87.4 20.88

Westmoreland .................................................................................... 42 12,638 1.72 1.36 11.54 97.9 24.74

West Virginia........................................................................................ 158 12,320 2.49 2.02 11.49 90.5 22.29

Brooke ................................................................................................ 10 12,113 3.52 2.91 10.20 86.7 21.00

Marshall ............................................................................................. 73 12,426 3.31 2.66 10.13 79.0 19.63

Monongalia ........................................................................................ 75 12,245 1.55 1.27 12.99 102.3 25.04

Ohio Edison Co Niles............................................................................ 473 12,154 2.92 2.40 10.98 107.3 26.08

Ohio ...................................................................................................... 460 12,145 2.91 2.40 11.02 107.2 26.03

Carroll ................................................................................................ 133 12,127 2.64 2.18 10.84 121.7 29.51

Columbiana ........................................................................................ 59 12,100 2.69 2.22 10.36 112.1 27.13

Harrison ............................................................................................. 147 12,390 3.40 2.74 10.44 96.6 23.93

Jefferson ............................................................................................. 86 11,964 2.43 2.04 12.20 106.0 25.35

Mahoning ........................................................................................... 10 11,923 3.02 2.53 11.58 104.5 24.92

Tuscarawas ........................................................................................ 25 11,628 3.64 3.13 12.51 86.5 20.12

Pennsylvania ......................................................................................... 13 12,487 3.00 2.40 9.76 111.8 27.92

Armstrong .......................................................................................... 2 12,579 2.88 2.29 8.90 110.5 27.79

Butler ................................................................................................. 11 12,468 3.02 2.42 9.93 112.1 27.95

Ohio Edison Co Sammis....................................................................... 5,449 12,188 .79 .65 10.92 128.1 31.23

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities9 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Ohio Edison Co Sammis

Kentucky ............................................................................................... 1,954 12,057 0.80 0.67 10.65 124.0 29.89

Breathitt ............................................................................................. 115 11,900 .83 .70 10.89 114.0 27.13

Floyd .................................................................................................. 821 12,093 .82 .68 10.12 121.1 29.28

Johnson .............................................................................................. 16 11,766 .88 .75 10.91 113.6 26.73

Knott .................................................................................................. 10 11,639 .75 .65 10.72 113.3 26.38

Lawrence ............................................................................................ 25 11,797 .89 .76 11.56 116.3 27.44

Magoffin ............................................................................................ 144 11,711 .80 .69 11.24 117.4 27.49

Martin ................................................................................................ 711 12,147 .80 .66 10.90 132.3 32.14

Pike .................................................................................................... 112 11,955 .63 .53 11.79 114.3 27.32

Pennsylvania ......................................................................................... 32 12,192 .81 .67 10.27 119.2 29.06

Fayette ................................................................................................ 3 11,987 .96 .80 10.80 124.0 29.73

Washington ........................................................................................ 9 11,949 .87 .73 9.16 113.8 27.20

Westmoreland .................................................................................... 19 12,342 .76 .62 10.72 120.9 29.85

West Virginia........................................................................................ 3,464 12,263 .78 .64 11.08 130.5 32.00

Boone ................................................................................................. 13 11,875 .77 .65 12.10 115.6 27.45

Clay .................................................................................................... 48 12,208 .77 .63 12.86 112.9 27.55

Fayette ................................................................................................ 69 12,596 .73 .58 8.82 118.6 29.89

Kanawha ............................................................................................ 2,054 12,290 .76 .62 11.06 131.1 32.23

Lincoln ............................................................................................... 12 11,542 .81 .70 11.30 127.2 29.36

Logan ................................................................................................. 60 11,990 .82 .68 11.04 113.5 27.22

Mingo ................................................................................................. 821 12,190 .78 .64 10.72 137.3 33.46

Webster .............................................................................................. 387 12,301 .86 .70 12.09 120.4 29.61

Ohio Power Co Gavin........................................................................... 5,805 11,416 3.02 2.65 11.58 160.3 36.60

Kentucky ............................................................................................... 2 12,000 .72 .60 12.00 131.3 31.51

Knott .................................................................................................. 1 12,000 .72 .60 12.00 131.3 31.51

Magoffin ............................................................................................ 1 12,000 .72 .60 12.00 131.3 31.51

Perry ................................................................................................... * 12,000 .72 .60 12.00 131.3 31.51

Ohio ...................................................................................................... 5,804 11,416 3.02 2.65 11.58 160.3 36.60

Belmont .............................................................................................. 225 11,866 2.83 2.39 12.27 114.0 27.05

Gallia .................................................................................................. 305 11,112 2.99 2.69 11.85 109.6 24.36

Jackson ............................................................................................... 305 11,112 2.99 2.69 11.85 109.6 24.36

Meigs ................................................................................................. 4,656 11,454 3.04 2.65 11.50 172.4 39.48

Vinton ................................................................................................ 313 11,112 2.99 2.69 11.85 109.6 24.36

Ohio Power Co Kammer ...................................................................... 1,952 12,307 3.44 2.79 10.76 86.3 21.23

West Virginia........................................................................................ 1,952 12,307 3.44 2.79 10.76 86.3 21.23

Marshall ............................................................................................. 1,952 12,307 3.44 2.79 10.76 86.3 21.23

Ohio Power Co Mitchell ....................................................................... 3,257 12,310 .96 .78 12.88 141.9 34.95

West Virginia........................................................................................ 3,257 12,310 .96 .78 12.88 141.9 34.95

Boone ................................................................................................. 1,445 12,431 .75 .60 11.73 147.9 36.76

Clay .................................................................................................... 488 12,195 .74 .61 13.41 142.3 34.72

Kanawha ............................................................................................ 54 12,643 .72 .57 11.09 112.5 28.45

Logan ................................................................................................. 154 12,328 .66 .54 12.74 117.9 29.06

Marion ................................................................................................ 855 12,120 1.51 1.24 14.75 148.2 35.93

Monongalia ........................................................................................ 38 12,227 1.33 1.08 13.31 101.8 24.89

Webster .............................................................................................. 223 12,426 .85 .68 12.42 109.9 27.30

Ohio Power Co Muskingum................................................................. 2,229 12,010 2.56 2.13 11.54 182.3 43.80

Ohio ...................................................................................................... 1,064 11,722 4.57 3.90 11.59 239.3 56.10

Columbiana ........................................................................................ 12 12,336 1.11 .90 8.38 173.2 42.72

Gallia .................................................................................................. 3 10,920 .87 .80 8.75 186.0 40.63

Jackson ............................................................................................... 3 10,920 .87 .80 8.75 186.0 40.63

Jefferson ............................................................................................. 77 12,274 .68 .55 10.46 180.0 44.19

Muskingum ........................................................................................ 106 11,678 4.63 3.97 11.75 245.7 57.38

Noble .................................................................................................. 858 11,678 5.01 4.29 11.75 245.7 57.38

Vinton ................................................................................................ 3 10,919 .87 .80 8.75 186.0 40.62

Unknown1 .......................................................................................... 1 12,463 1.11 .89 8.40 179.5 44.74

West Virginia........................................................................................ 1,165 12,273 .72 .58 11.49 132.7 32.58

Boone ................................................................................................. 95 12,040 .78 .65 12.77 122.1 29.40

Logan ................................................................................................. 998 12,281 .70 .57 11.37 134.3 32.98

Webster .............................................................................................. 72 12,473 .88 .70 11.49 124.9 31.17

Ohio Valley Electric Corp Kyger Creek ............................................ 2,663 13,092 1.56 1.19 6.65 122.9 32.18

See footnotes at end of table.

10Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Ohio Valley Electric Corp Kyger Creek

Kentucky ............................................................................................... 1,224 13,333 1.39 1.04 5.69 125.7 33.51

Floyd .................................................................................................. 238 13,203 1.39 1.05 6.36 124.9 32.97

Letcher ............................................................................................... 986 13,364 1.39 1.04 5.53 125.9 33.65

Ohio ...................................................................................................... 132 11,294 3.71 3.29 11.94 86.8 19.60

Belmont .............................................................................................. 22 12,171 3.93 3.23 12.15 83.1 20.24

Jackson ............................................................................................... 110 11,118 3.67 3.30 11.89 87.6 19.47

Pennsylvania ......................................................................................... 977 13,047 1.49 1.14 6.96 122.2 31.88

Greene ................................................................................................ 977 13,047 1.49 1.14 6.96 122.2 31.88

West Virginia........................................................................................ 330 13,049 1.54 1.18 7.18 127.0 33.15

Mingo ................................................................................................. 330 13,049 1.54 1.18 7.18 127.0 33.15

Owensboro City of Smith ..................................................................... 1,065 11,202 2.97 2.65 8.71 95.1 21.30

Indiana .................................................................................................. 278 11,352 3.00 2.64 7.96 97.0 22.02

Warrick .............................................................................................. 278 11,352 3.00 2.64 7.96 97.0 22.02

Kentucky ............................................................................................... 787 11,149 2.95 2.65 8.98 94.4 21.05

Daviess ............................................................................................... 551 11,177 2.81 2.52 8.38 96.0 21.46

Ohio ................................................................................................... 236 11,082 3.28 2.96 10.38 90.7 20.10

Pennsylvania Electric Co Conemaugh ................................................ 4,123 12,502 2.25 1.80 13.40 114.1 28.53

Pennsylvania ......................................................................................... 4,123 12,502 2.25 1.80 13.40 114.1 28.53

Armstrong .......................................................................................... 508 12,579 2.36 1.88 11.63 108.4 27.27

Cambria .............................................................................................. 144 12,770 2.18 1.70 11.15 112.8 28.81

Centre ................................................................................................. 18 12,355 2.44 1.98 15.10 116.3 28.72

Clearfield ........................................................................................... 42 12,480 2.31 1.85 14.41 106.2 26.51

Fayette ................................................................................................ 247 12,523 2.37 1.90 13.24 103.1 25.81

Indiana ............................................................................................... 375 12,400 2.14 1.72 13.70 110.7 27.46

Somerset ............................................................................................ 2,589 12,497 2.23 1.78 13.82 117.4 29.35

Westmoreland .................................................................................... 200 12,361 2.37 1.92 13.23 107.9 26.68

Pennsylvania Electric Co Shawville .................................................... 1,530 12,279 1.82 1.48 13.30 113.3 27.82

Pennsylvania ......................................................................................... 1,530 12,279 1.82 1.48 13.30 113.3 27.82

Cambria .............................................................................................. 84 12,238 1.65 1.35 12.18 117.1 28.67

Clearfield ........................................................................................... 1,401 12,285 1.83 1.49 13.37 113.2 27.80

Indiana ............................................................................................... 14 12,162 1.84 1.51 14.36 112.8 27.44

Somerset ............................................................................................ 16 12,201 1.68 1.38 11.99 110.6 26.98

Westmoreland .................................................................................... 15 12,129 2.09 1.72 13.93 109.2 26.48

Pennsylvania Power & Light Co Brunner Island ............................. 2,756 13,067 1.61 1.23 8.06 150.2 39.25

Pennsylvania ......................................................................................... 2,747 13,070 1.61 1.23 8.05 150.1 39.23

Clarion ............................................................................................... 90 12,704 1.60 1.26 8.97 139.7 35.49

Greene ................................................................................................ 2,257 13,127 1.56 1.19 7.43 151.5 39.78

Indiana ............................................................................................... 351 12,786 2.00 1.56 11.57 145.3 37.17

Jefferson ............................................................................................. 49 13,166 1.16 .88 9.83 135.7 35.74

Utah ....................................................................................................... 9 12,239 .50 .41 10.10 184.9 45.26

Carbon ................................................................................................ 9 12,239 .50 .41 10.10 184.9 45.26

Pennsylvania Power & Light Co Martins Creek .............................. 288 13,055 1.59 1.21 8.71 146.9 38.37

Pennsylvania ......................................................................................... 269 13,030 1.55 1.19 8.83 148.5 38.71

Clarion ............................................................................................... 21 12,776 1.65 1.29 8.83 143.3 36.61

Greene ................................................................................................ 147 13,106 1.58 1.21 7.72 155.2 40.68

Indiana ............................................................................................... 10 12,817 2.30 1.79 11.90 137.6 35.27

Jefferson ............................................................................................. 81 13,044 1.31 1.00 9.77 139.8 36.48

Somerset ............................................................................................ 10 12,557 2.04 1.62 14.50 142.1 35.69

West Virginia........................................................................................ 19 13,412 2.13 1.59 7.00 124.8 33.48

Monongalia ........................................................................................ 19 13,412 2.13 1.59 7.00 124.8 33.48

Pennsylvania Power & Light Co Sunbury ......................................... 1,205 9,729 1.02 1.05 26.15 124.9 24.31

Pennsylvania ......................................................................................... 1,205 9,729 1.02 1.05 26.15 124.9 24.31

Butler ................................................................................................. 2 9,305 1.16 1.25 27.90 96.7 18.00

Centre ................................................................................................. 31 12,321 1.17 .95 15.08 130.8 32.24

Clarion ............................................................................................... 26 12,676 1.60 1.26 9.47 135.7 34.41

Clearfield ........................................................................................... 363 12,263 1.55 1.27 14.76 142.8 35.03

Fulton ................................................................................................. 3 12,306 1.54 1.25 14.27 136.4 33.58

Indiana ............................................................................................... 2 12,522 1.82 1.45 13.50 139.0 34.81

Jefferson ............................................................................................. 25 12,784 1.61 1.26 11.08 136.1 34.80

Lycoming ........................................................................................... 12 12,303 .89 .72 16.57 134.8 33.17

Northumberland ................................................................................. 79 7,738 .74 .95 33.48 71.2 11.02

Schuylkill ........................................................................................... 384 7,253 .50 .69 38.01 95.6 13.86

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities11 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Pennsylvania Power & Light Co Sunbury

Pennsylvania

Somerset ............................................................................................ 19 12,641 1.77 1.40 13.92 137.6 34.79

Unknown1 .......................................................................................... 259 9,172 .93 1.02 28.32 133.8 24.54

Potomac Electric Power Co Chalk...................................................... 1,353 13,206 1.36 1.03 9.20 153.7 40.60

Maryland ............................................................................................... 244 13,210 1.46 1.11 9.60 162.3 42.88

Garrett ................................................................................................ 244 13,210 1.46 1.11 9.60 162.3 42.88

Pennsylvania ......................................................................................... 872 13,190 1.34 1.02 9.24 149.5 39.45

Cambria .............................................................................................. 186 12,860 1.35 1.05 9.18 147.6 37.95

Clearfield ........................................................................................... 344 13,285 1.51 1.14 8.94 149.4 39.69

Somerset ............................................................................................ 342 13,273 1.17 .88 9.56 150.8 40.02

West Virginia........................................................................................ 237 13,261 1.34 1.01 8.67 160.2 42.48

Barbour .............................................................................................. 28 14,210 .98 .69 6.65 151.8 43.15

Grant .................................................................................................. 150 13,139 1.38 1.05 9.21 158.0 41.51

Preston ............................................................................................... 59 13,122 1.41 1.07 8.27 170.0 44.62

Potomac Electric Power Co Morgantown .......................................... 2,250 13,169 1.39 1.06 9.35 158.7 41.79

Maryland ............................................................................................... 776 13,247 1.49 1.12 9.57 161.5 42.78

Garrett ................................................................................................ 776 13,247 1.49 1.12 9.57 161.5 42.78

Pennsylvania ......................................................................................... 694 13,084 1.34 1.02 9.77 152.6 39.93

Cambria .............................................................................................. 154 13,022 1.33 1.02 9.21 147.8 38.50

Clearfield ........................................................................................... 235 12,893 1.52 1.18 10.39 157.2 40.54

Jefferson ............................................................................................. 16 12,925 1.49 1.16 9.75 147.9 38.22

Somerset ............................................................................................ 289 13,282 1.19 .90 9.55 151.7 40.30

West Virginia........................................................................................ 780 13,166 1.35 1.02 8.75 161.2 42.45

Barbour .............................................................................................. 105 13,242 1.16 .88 7.59 163.2 43.22

Grant .................................................................................................. 477 13,134 1.35 1.03 9.25 157.8 41.44

Preston ............................................................................................... 198 13,205 1.45 1.10 8.17 168.3 44.46

Public Service Co of IN Inc Cayuga ................................................... 2,514 10,978 1.56 1.42 9.56 129.0 28.32

Indiana .................................................................................................. 2,514 10,978 1.56 1.42 9.56 129.0 28.32

Greene ................................................................................................ 10 11,153 1.33 1.19 8.80 127.6 28.46

Sullivan .............................................................................................. 2,504 10,978 1.56 1.42 9.57 129.0 28.32

Public Service Co of IN Inc Gallagher ............................................... 1,126 12,405 1.86 1.50 7.80 111.9 27.75

Illinois ................................................................................................... 445 11,913 1.43 1.20 7.05 123.4 29.41

Jefferson ............................................................................................. 120 11,698 1.62 1.38 7.42 119.6 27.99

Saline ................................................................................................. 325 11,993 1.36 1.14 6.91 124.8 29.93

Indiana .................................................................................................. 133 11,064 1.31 1.18 9.65 116.2 25.72

Clay .................................................................................................... 6 11,210 1.05 .94 7.80 114.6 25.69

Dubois ................................................................................................ 114 11,100 1.24 1.12 9.69 119.0 26.42

Pike .................................................................................................... 2 12,132 2.40 1.98 8.00 101.5 24.63

Spencer .............................................................................................. 11 10,431 2.00 1.92 10.50 88.6 18.48

Pennsylvania ......................................................................................... 547 13,131 2.35 1.79 7.97 102.4 26.90

Greene ................................................................................................ 538 13,128 2.37 1.80 8.01 102.6 26.95

Washington ........................................................................................ 9 13,299 1.21 .91 5.60 89.3 23.75

Public Service Co of IN Inc Gibson Station ...................................... 7,517 10,951 2.22 2.03 9.42 143.9 31.52

Illinois ................................................................................................... 7,108 10,937 2.26 2.07 9.47 145.0 31.72

Clinton ............................................................................................... 3,002 10,868 3.30 3.03 7.92 142.9 31.07

Wabash .............................................................................................. 4,106 10,988 1.50 1.37 10.61 146.6 32.21

Indiana .................................................................................................. 409 11,198 1.53 1.37 8.58 125.1 28.01

Clay .................................................................................................... 26 10,977 .78 .71 8.81 124.8 27.40

Daviess ............................................................................................... 111 11,873 .63 .53 5.51 124.1 29.46

Knox .................................................................................................. 271 10,943 1.97 1.80 9.82 125.5 27.47

Public Service Co of IN Inc Wabash River ....................................... 1,156 11,126 1.58 1.42 8.50 118.8 26.43

Indiana .................................................................................................. 1,156 11,126 1.58 1.42 8.50 118.8 26.43

Clay .................................................................................................... 50 11,075 1.28 1.16 8.83 123.8 27.43

Daviess ............................................................................................... 16 11,335 1.55 1.37 7.50 119.1 27.00

Greene ................................................................................................ 794 11,240 1.64 1.46 8.05 121.3 27.27

Owen .................................................................................................. 58 11,106 1.38 1.25 8.63 124.9 27.74

Sullivan .............................................................................................. 239 10,747 1.48 1.38 9.95 107.2 23.05

Public Service Co of NH Merrimack.................................................. 1,013 13,234 1.64 1.24 6.73 157.9 41.80

See footnotes at end of table.

12Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Public Service Co of NH Merrimack

Pennsylvania ......................................................................................... 759 13,203 1.49 1.12 6.90 161.1 42.53

Greene ................................................................................................ 750 13,202 1.49 1.13 6.91 161.1 42.53

Westmoreland .................................................................................... 9 13,345 1.44 1.08 6.20 159.8 42.65

Virginia ................................................................................................. 19 13,910 .68 .49 7.00 203.5 56.61

Buchanan ........................................................................................... 19 13,910 .68 .49 7.00 203.5 56.61

West Virginia........................................................................................ 223 13,366 2.29 1.72 6.28 141.7 37.89

Monongalia ........................................................................................ 223 13,366 2.29 1.72 6.28 141.7 37.89

Imported ................................................................................................ 12 11,578 .53 .46 3.80 192.9 44.67

Imported Coal.................................................................................... 12 11,578 .53 .46 3.80 192.9 44.67

Southern Indiana Gas & Elec Co Culley ........................................... 1,007 11,265 3.10 2.75 9.50 114.3 25.76

Indiana .................................................................................................. 1,000 11,262 3.11 2.76 9.53 114.1 25.71

Dubois ................................................................................................ 106 11,022 1.83 1.66 10.21 132.4 29.19

Gibson ................................................................................................ 130 11,390 3.22 2.83 9.27 120.2 27.38

Knox .................................................................................................. 10 10,979 1.33 1.21 8.90 146.5 32.17

Warrick .............................................................................................. 753 11,278 3.30 2.92 9.48 110.1 24.84

Kentucky ............................................................................................... 8 11,581 1.76 1.52 6.21 141.6 32.81

Daviess ............................................................................................... 2 11,024 3.50 3.17 10.20 119.8 26.41

Ohio ................................................................................................... 6 11,719 1.33 1.13 5.22 146.7 34.38

Southern Indiana Gas & Elec Co Warrick........................................ 439 11,276 2.82 2.50 8.46 104.3 23.52

Indiana .................................................................................................. 439 11,276 2.82 2.50 8.46 104.3 23.52

Daviess ............................................................................................... 14 11,451 2.24 1.96 9.10 102.0 23.36

Dubois ................................................................................................ 9 11,193 2.73 2.44 9.70 96.7 21.65

Gibson ................................................................................................ 265 11,441 2.78 2.43 8.07 103.3 23.64

Warrick .............................................................................................. 150 10,972 2.97 2.71 9.02 106.8 23.44

Springfield City of (MO) James River ............................................... 351 11,786 .54 .46 8.31 150.3 35.42

Illinois ................................................................................................... 18 11,658 2.56 2.20 8.53 138.6 32.33

Franklin .............................................................................................. 18 11,658 2.56 2.20 8.53 138.6 32.33

Utah ....................................................................................................... 333 11,793 .43 .37 8.30 150.9 35.58

Carbon ................................................................................................ 333 11,793 .43 .37 8.30 150.9 35.58

Tampa Electric Co Davant Transfer2 ................................................ 5,388 11,713 1.95 1.66 7.76 162.5 38.06

Colorado ................................................................................................ 811 12,745 .43 .34 9.84 184.3 46.99

Las Animas........................................................................................ 811 12,745 .43 .34 9.84 184.3 46.99

Illinois ................................................................................................... 2,371 11,536 2.26 1.96 8.27 170.5 39.33

Gallatin .............................................................................................. 28 12,703 2.71 2.13 8.85 142.9 36.30

Perry ................................................................................................... 1,132 11,002 3.03 2.75 9.44 195.1 42.94

Randolph ............................................................................................ 119 10,995 3.06 2.78 9.56 135.9 29.88

Saline ................................................................................................. 1,092 12,120 1.36 1.12 6.89 151.4 36.70

Kentucky ............................................................................................... 1,737 11,818 2.62 2.22 7.35 139.0 32.86

Henderson .......................................................................................... 388 11,249 2.48 2.21 8.26 130.0 29.26

Knox .................................................................................................. 2 12,541 .90 .72 10.50 166.6 41.79

Ohio ................................................................................................... 335 11,407 2.69 2.36 8.89 122.0 27.83

Union ................................................................................................. 783 12,028 2.79 2.32 6.18 135.7 32.65

Webster .............................................................................................. 146 12,704 2.82 2.22 7.44 160.9 40.88

Whitley .............................................................................................. 84 12,572 1.09 .87 7.73 227.8 57.28

Tennessee .............................................................................................. 120 12,565 1.12 .89 8.66 229.2 57.59

Campbell ............................................................................................ 120 12,565 1.12 .89 8.66 229.2 57.59

Imported ................................................................................................ 349 9,696 .31 .32 1.16 143.8 27.88

Imported Coal.................................................................................... 349 9,696 .31 .32 1.16 143.8 27.88

Tennessee Valley Authority Allen ....................................................... 873 12,040 1.98 1.64 8.42 116.9 28.15

Illinois ................................................................................................... 338 11,913 1.81 1.52 8.47 112.9 26.91

Jefferson ............................................................................................. 166 11,746 1.79 1.52 7.69 112.5 26.44

Saline ................................................................................................. 173 12,074 1.83 1.51 9.22 113.3 27.36

Kentucky ............................................................................................... 459 12,207 2.13 1.75 8.54 120.5 29.43

Hopkins .............................................................................................. 245 11,906 2.03 1.71 8.15 119.8 28.52

Union ................................................................................................. 13 12,200 2.37 1.94 12.00 117.8 28.75

Webster .............................................................................................. 201 12,574 2.24 1.78 8.80 121.6 30.58

West Virginia........................................................................................ 76 11,600 1.80 1.55 7.50 111.9 25.96

Monongalia ........................................................................................ 76 11,600 1.80 1.55 7.50 111.9 25.96

Tennessee Valley Authority Colbert ................................................... 2,746 12,000 1.23 1.02 11.04 118.9 28.53

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities13 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Tennessee Valley Authority Colbert

Colorado ................................................................................................ 10 11,013 0.37 0.34 8.79 126.9 27.95

Delta ................................................................................................... 10 11,013 .37 .34 8.79 126.9 27.95

Illinois ................................................................................................... 660 11,658 1.74 1.49 8.26 107.0 24.95

Franklin .............................................................................................. 49 11,500 2.24 1.95 8.46 118.0 27.15

Jefferson ............................................................................................. 516 11,576 1.68 1.45 8.13 106.5 24.65

Saline ................................................................................................. 94 12,193 1.80 1.48 8.89 104.4 25.45

Kentucky ............................................................................................... 904 12,003 1.27 1.05 10.74 119.2 28.62

Daviess ............................................................................................... 3 11,300 1.15 1.02 9.54 116.0 26.22

Floyd .................................................................................................. 323 11,883 .86 .72 11.04 119.2 28.33

Harlan ................................................................................................ 25 12,182 .62 .51 11.72 129.7 31.59

Johnson .............................................................................................. 161 11,903 1.14 .96 10.76 127.1 30.27

Knox .................................................................................................. 17 11,832 .82 .69 11.80 113.0 26.74

Martin ................................................................................................ 3 11,331 .71 .63 11.96 132.2 29.95

Perry ................................................................................................... 7 12,307 .78 .63 9.96 115.1 28.32

Pike .................................................................................................... 54 11,881 1.04 .88 11.17 115.6 27.46

Webster .............................................................................................. 310 12,204 1.89 1.55 10.21 115.4 28.16

Pennsylvania ......................................................................................... 38 13,259 1.63 1.23 7.02 120.6 31.98

Greene ................................................................................................ 38 13,259 1.63 1.23 7.02 120.6 31.98

Tennessee .............................................................................................. 114 12,356 .88 .71 12.71 135.4 33.45

Sequatchie .......................................................................................... 114 12,356 .88 .71 12.71 135.4 33.45

West Virginia........................................................................................ 1,020 12,141 .89 .74 13.09 123.9 30.08

Boone ................................................................................................. 33 11,999 1.00 .83 12.97 111.7 26.81

Kanawha ............................................................................................ 966 12,151 .88 .73 13.10 124.5 30.25

Mcdowell ........................................................................................... 19 11,842 1.03 .87 13.29 114.3 27.08

Monongalia ........................................................................................ 2 12,725 2.34 1.84 8.77 113.6 28.90

Tennessee Valley Authority Cumberland........................................... 8,619 11,637 2.83 2.43 8.97 102.4 23.84

Illinois ................................................................................................... 1,639 11,620 2.63 2.27 9.08 93.2 21.66

Franklin .............................................................................................. 1,128 11,346 2.59 2.29 9.09 93.3 21.18

Gallatin .............................................................................................. 199 12,722 2.76 2.17 8.90 96.7 24.60

Randolph ............................................................................................ 152 11,621 2.52 2.17 8.48 82.8 19.25

Saline ................................................................................................. 159 12,182 2.89 2.37 9.76 97.1 23.67

Kentucky ............................................................................................... 6,416 11,513 2.91 2.53 9.03 104.3 24.02

Christian ............................................................................................. 81 11,057 2.79 2.53 9.93 102.0 22.55

Henderson .......................................................................................... 9 11,190 2.57 2.30 8.40 94.5 21.15

Hopkins .............................................................................................. 280 11,936 2.55 2.13 8.46 108.7 25.94

Ohio ................................................................................................... 257 11,439 3.27 2.85 9.09 85.7 19.60

Union ................................................................................................. 5,371 11,435 2.89 2.53 9.08 104.2 23.84

Webster .............................................................................................. 419 12,371 3.26 2.64 8.48 113.9 28.18

Pennsylvania ......................................................................................... 543 13,136 2.43 1.85 7.86 107.0 28.12

Greene ................................................................................................ 543 13,136 2.43 1.85 7.86 107.0 28.12

West Virginia........................................................................................ 21 12,200 4.00 3.28 11.00 103.3 25.20

Monongalia ........................................................................................ 21 12,200 4.00 3.28 11.00 103.3 25.20

Tennessee Valley Authority Gallatin................................................... 2,322 12,264 2.04 1.67 9.50 122.7 30.09

Colorado ................................................................................................ 23 11,600 .70 .60 9.75 141.6 32.86

Gunnison ............................................................................................ 23 11,600 .70 .60 9.75 141.6 32.86

Illinois ................................................................................................... 119 11,565 2.37 2.05 9.75 132.5 30.65

Jefferson ............................................................................................. 18 11,519 1.66 1.44 7.33 136.0 31.34

Saline ................................................................................................. 101 11,573 2.50 2.16 10.18 131.9 30.53

Indiana .................................................................................................. 9 10,949 1.55 1.42 8.14 115.2 25.23

Sullivan .............................................................................................. 9 10,949 1.55 1.42 8.14 115.2 25.23

Kentucky ............................................................................................... 2,172 12,314 2.04 1.66 9.49 122.0 30.05

Hopkins .............................................................................................. 425 12,073 2.57 2.12 7.81 108.8 26.28

Perry ................................................................................................... 17 12,194 1.44 1.18 10.02 132.6 32.34

Union ................................................................................................. 268 12,282 2.16 1.76 11.03 129.6 31.84

Webster .............................................................................................. 1,462 12,391 1.88 1.51 9.69 124.2 30.79

Tennessee Valley Authority Johnsonville ........................................... 2,901 11,936 1.77 1.49 9.16 119.7 28.58

Illinois ................................................................................................... 1,853 11,728 1.78 1.52 8.75 123.4 28.95

Franklin .............................................................................................. 1,219 11,639 1.79 1.54 9.20 131.3 30.56

Jefferson ............................................................................................. 275 11,700 1.68 1.44 7.50 109.5 25.62

Saline ................................................................................................. 359 12,052 1.81 1.51 8.21 108.1 26.05

Kentucky ............................................................................................... 919 12,252 1.78 1.46 9.93 112.5 27.57

Webster .............................................................................................. 919 12,252 1.78 1.46 9.93 112.5 27.57

See footnotes at end of table.

14Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

Tennessee Valley Authority Johnsonville

Pennsylvania ......................................................................................... 73 13,040 1.59 1.22 7.33 121.5 31.68

Greene ................................................................................................ 73 13,040 1.59 1.22 7.33 121.5 31.68

West Virginia........................................................................................ 56 12,211 1.58 1.29 12.62 118.3 28.88

Monongalia ........................................................................................ 56 12,211 1.58 1.29 12.62 118.3 28.88

Tennessee Valley Authority Paradise.................................................. 7,095 10,677 4.35 4.07 17.90 92.7 19.81

Illinois ................................................................................................... 22 11,649 2.83 2.43 8.80 112.5 26.20

White .................................................................................................. 22 11,649 2.83 2.43 8.80 112.5 26.20

Kentucky ............................................................................................... 7,073 10,674 4.35 4.08 17.93 92.7 19.79

Christian ............................................................................................. 1,419 10,479 4.56 4.35 16.11 85.4 17.90

Henderson .......................................................................................... 225 11,231 2.64 2.35 8.59 91.4 20.54

Hopkins .............................................................................................. 1,165 10,840 3.96 3.65 18.10 88.8 19.24

Muhlenberg ........................................................................................ 2,263 10,317 4.64 4.50 20.60 95.4 19.69

Ohio ................................................................................................... 587 11,366 3.58 3.15 10.84 80.2 18.23

Union ................................................................................................. 275 10,252 3.94 3.84 18.86 89.7 18.38

Webster .............................................................................................. 1,137 11,091 4.77 4.30 19.99 107.7 23.88

Tennessee Valley Authority Shawnee ................................................. 3,821 11,861 .84 .71 10.83 121.4 28.79

Colorado ................................................................................................ 1,781 11,536 .49 .42 9.42 121.4 28.02

Delta ................................................................................................... 30 11,336 .50 .44 8.01 98.3 22.28

Gunnison ............................................................................................ 1,018 11,804 .49 .41 8.53 123.3 29.11

Routt .................................................................................................. 734 11,174 .48 .43 10.72 119.6 26.73

Illinois ................................................................................................... 11 10,700 3.65 3.41 8.50 91.9 19.67

Macoupin ........................................................................................... 11 10,700 3.65 3.41 8.50 91.9 19.67

Kentucky ............................................................................................... 1,518 12,009 1.30 1.08 12.30 118.9 28.56

Floyd .................................................................................................. 38 11,776 .69 .59 12.69 122.7 28.91

Harlan ................................................................................................ 1,009 12,143 .67 .55 13.04 122.3 29.71

Hopkins .............................................................................................. 422 11,653 2.92 2.50 10.82 107.9 25.14

Martin ................................................................................................ 3 12,000 .72 .60 13.50 118.8 28.50

Pike .................................................................................................... 45 12,542 .63 .50 9.24 137.9 34.59

Utah ....................................................................................................... 12 12,395 .65 .52 9.98 144.0 35.71

Carbon ................................................................................................ 12 12,395 .65 .52 9.98 144.0 35.71

West Virginia........................................................................................ 499 12,581 .66 .52 11.42 128.4 32.31

Boone ................................................................................................. 499 12,581 .66 .52 11.42 128.4 32.31

Union Electric Co Labadie ................................................................... 6,951 9,591 .92 .96 6.65 110.6 21.22

Colorado ................................................................................................ 395 11,750 .47 .40 9.60 160.2 37.65

Gunnison ............................................................................................ 395 11,750 .47 .40 9.60 160.2 37.65

Illinois ................................................................................................... 1,937 11,280 2.61 2.31 10.61 134.6 30.36

Jefferson ............................................................................................. 519 11,500 1.27 1.10 12.00 142.1 32.67

Perry ................................................................................................... 1,418 11,200 3.10 2.77 10.10 131.7 29.51

Wyoming .............................................................................................. 4,619 8,698 .24 .28 4.73 91.8 15.98

Campbell ............................................................................................ 4,619 8,698 .24 .28 4.73 91.8 15.98

Union Electric Co Sioux ....................................................................... 2,108 9,119 1.13 1.24 6.62 108.1 19.71

Illinois ................................................................................................... 583 11,209 3.07 2.74 10.05 144.9 32.48

Perry ................................................................................................... 573 11,200 3.10 2.77 10.10 144.9 32.45

Saline ................................................................................................. 10 11,700 1.28 1.09 7.10 147.2 34.44

Wyoming .............................................................................................. 1,525 8,320 .38 .46 5.31 89.1 14.83

Campbell ............................................................................................ 1,525 8,320 .38 .46 5.31 89.1 14.83

Virginia Electric & Power Co Mount Storm..................................... 4,230 12,341 1.68 1.36 14.45 126.8 31.31

Maryland ............................................................................................... 1,573 12,563 1.60 1.28 13.51 123.2 30.95

Allegany ............................................................................................. 79 11,904 1.66 1.40 16.89 110.2 26.24

Garrett ................................................................................................ 1,494 12,598 1.60 1.27 13.33 123.8 31.20

Pennsylvania ......................................................................................... 32 11,683 1.55 1.33 16.46 108.0 25.24

Somerset ............................................................................................ 32 11,683 1.55 1.33 16.46 108.0 25.24

West Virginia........................................................................................ 2,625 12,216 1.73 1.41 14.99 129.3 31.59

Barbour .............................................................................................. 123 11,770 1.75 1.49 17.98 110.4 25.98

Grant .................................................................................................. 2,426 12,251 1.73 1.41 14.83 130.7 32.03

Mineral ............................................................................................... 53 11,811 1.66 1.40 14.76 114.1 26.94

Randolph ............................................................................................ 4 11,782 1.86 1.58 13.37 100.0 23.56

Upshur ................................................................................................ 19 11,952 1.49 1.25 16.56 110.4 26.39

West Penn Power Co Armstrong ........................................................ 551 12,598 1.68 1.33 10.70 129.5 32.63

See footnotes at end of table.

Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities15 
Table B2. Profile of Coal Received at Table 1 Plants, 1995 (Continued)

Average Delivered Average Quality Cost

Electric Utility Plant Receipts

 Origin State (thousand Sulfur Sulfur Ash (cents (dollars Btu County short tons) (percent (pounds (percent per per (per by per by million short pound) weight) MM Btu) weight) Btu) ton)

West Penn Power Co Armstrong

Pennsylvania ......................................................................................... 551 12,598 1.68 1.33 10.70 129.5 32.63

Armstrong .......................................................................................... 72 12,278 1.94 1.58 11.68 99.9 24.54

Butler ................................................................................................. 29 12,110 1.97 1.63 12.37 99.1 24.01

Jefferson ............................................................................................. 450 12,681 1.62 1.28 10.43 136.0 34.49

West Penn Power Co Hatfield ............................................................. 3,361 13,013 2.31 1.77 8.86 130.9 34.06

Pennsylvania ......................................................................................... 485 13,021 2.30 1.76 8.77 130.7 34.03

Greene ................................................................................................ 485 13,021 2.30 1.76 8.77 130.7 34.03

West Virginia........................................................................................ 2,877 13,012 2.31 1.77 8.87 130.9 34.07

Marion ................................................................................................ 14 13,149 2.25 1.71 7.80 123.8 32.56

Monongalia ........................................................................................ 2,862 13,011 2.31 1.77 8.88 130.9 34.07

Wisconsin Electric Power Co Oak Creek........................................... 2,091 12,289 .60 .49 11.21 150.8 37.08

Illinois ................................................................................................... 258 12,227 .88 .72 7.49 126.2 30.87

Jefferson ............................................................................................. 258 12,227 .88 .72 7.49 126.2 30.87

New Mexico ......................................................................................... 1,578 12,372 .50 .41 12.53 158.1 39.13

Colfax ................................................................................................ 1,578 12,372 .50 .41 12.53 158.1 39.13

Pennsylvania ......................................................................................... 124 13,146 1.54 1.17 6.70 133.0 34.98

Greene ................................................................................................ 124 13,146 1.54 1.17 6.70 133.0 34.98

West Virginia........................................................................................ 57 12,908 .66 .51 9.39 152.7 39.42

Mingo ................................................................................................. 57 12,908 .66 .51 9.39 152.7 39.42

Wyoming .............................................................................................. 73 8,809 .18 .20 4.92 93.9 16.54

Campbell ............................................................................................ 73 8,809 .18 .20 4.92 93.9 16.54

Wisconsin Power & Light Co Edgewater........................................... 2,633 8,831 .34 .38 5.57 122.8 21.70

Illinois ................................................................................................... 108 12,127 1.00 .83 5.74 157.9 38.29

Jefferson ............................................................................................. 108 12,127 1.00 .83 5.74 157.9 38.29

Utah ....................................................................................................... 72 12,585 .55 .44 8.02 154.4 38.87

Emery ................................................................................................. 72 12,585 .55 .44 8.02 154.4 38.87

Wyoming .............................................................................................. 2,452 8,576 .30 .35 5.49 119.3 20.46

Big Horn ............................................................................................ 111 10,398 .49 .47 6.63 144.8 30.12

Campbell ............................................................................................ 2,342 8,490 .29 .34 5.43 117.8 20.00

Wisconsin Power & Light Co Nelson Dewey..................................... 588 9,472 .37 .39 4.33 119.3 22.61

Illinois ................................................................................................... 30 12,126 .95 .79 5.09 140.0 33.96

Jefferson ............................................................................................. 30 12,126 .95 .79 5.09 140.0 33.96

Montana ................................................................................................ 499 9,394 .34 .36 4.14 118.3 22.23

Big Horn ............................................................................................ 499 9,394 .34 .36 4.14 118.3 22.23

Wyoming .............................................................................................. 59 8,763 .33 .37 5.51 113.9 19.96

Converse ............................................................................................ 59 8,763 .33 .37 5.51 113.9 19.96

Wisconsin Public Service Corp Pulliam ............................................. 1,171 8,834 .21 .24 4.54 115.3 20.36

Wyoming .............................................................................................. 1,171 8,834 .21 .24 4.54 115.3 20.36

Campbell ............................................................................................ 1,171 8,834 .21 .24 4.54 115.3 20.36

Total .................................................................................................... 226,244 11,406 1.62 1.42 9.39 129.3 29.49

1 Refers to coal in which the county of origin in not known.

2 The Tampa Electric Company reports coal destined for the Big Bend power plant as it is received at this facility located in Louisiana. The cost reported

under Davant Transfer is the weighted average cost of coal delivered to this facility. The Tampa Electric Company incurs additional costs for transporting coal

from Davant to the Big Bend power plant located in Florida.

* = Number less than 0.5 thousand short tons.

 Notes: • Plants affected by Phase 1 but not shown in this table include the following: Edgewater (Ohio Edison) is using natural gas. Northport and Port

Jefferson (Long Island Lighting) use petroleum. Des Moines (Midwest Power) is out of service. Breed (Indiana Michigan Power) is retired. • Totals may not

equal sum of components because of independent rounding. • Data are for electric generating plants with a total steam-electric and combined-cycle nameplate

capacity of 50 or more megawatts.

Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’

16Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities
Appendix C

Costs and Characteristics of

Selected Phase I Units, by Utility
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 107

Energy Information Administration, Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990, DOE/EIA-0582 108

(Washington, DC, March 1994).

Appendix C

Costs and Characteristics of Selected Phase I Units, by Utility

This appendix presents detailed information pertaining to Monitoring System (CEMS) components. Capital costs

the compliance activities of the six utilities discussed in and operations and maintenance costs are also provided.

Chapter 2. These utilities were selected to obtain a representative sample of generating capacities, sulfur dioxide A detailed analysis of compliance strategies and prelimi-

(SO ) emissions, locations, and initial compliance nary compliance costs for these six utilities was presented 2

strategies. Also, the willingness to participate and share in a previous report. This report updates the earlier

information was essential. The six utilities are Cincinnati analysis by (1) taking into consideration substitution units,

Gas and Electric Company, Georgia Power Company, (2) finalizing cost data, and (3) accounting for changes in

Illinois Power Company, Potomac Electric Power compliance strategies.

Company, Pennsylvania Power and Light Company, and

Southern Indiana Gas and Electric Company. Each utility was asked to update its compliance strategies

Information on allowance allocations and sulfur dioxide similar information on Phase II units. Definitive plans for

(SO ) emissions, compliance strategies and compliance Phase II have not been developed. Further, because of 2

costs is provided for each unit. Cost information covers increased competition in the electric industry, some

SO , nitrogen oxides (NO ), and Continuous Emission utilities are reluctant to share detailed information. 2 x

108

and costs for all units affected by Phase I and to provide
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 109

Table C1. Characteristics of Selected Phase I Units, by Utility

Type of Unit Unit Plant State Online (MW) Allowances (tons) Deductions to 1996 Strategy

Year Capacity of SO Emissions Emissions Over Compliance

Affected Difference

Utility Between

 Owned 1995 Allowances Total and Allowances

Nameplate Allocation Deducted for 1995 Carried 1995 SO

2

a

2

Cincinnati Gas & Electric Company

Table 1 ......... 5 Miami Fort OH 1949 100 834 263 571 571 Fuel Switch

Table 1 ......... 6 Miami Fort OH 1960 163 12,475 3,930 8,545 8,545 Fuel Switch

Table 1 ......... 7 Miami Fort * OH 1975 320 27,018 13,633 13,385 6,609 Fuel Switch

Table 1 ......... 5 Beckjord OH 1962 238 9,822 8,347 1,475 4,525 Fuel Switch

Table 1 ......... 6 Beckjord * OH 1969 158 9,463 6,555 2,908 3,213 Fuel Switch

Table 1 ......... 4 Conesville * OH 1973 312 21,385 25,176 (3,791) 8,498 Allowances

Substitution ...... 2 East Bend* KY 1981 414 12,038 7,851 4,187 3,425 Scrubber

Substitution . . . . . . 1 J. M. Stuart* OH 1971 238 16,064 8,916 7,148 7,109 Fuel Switch

Substitution . . . . . . 2 J. M. Stuart* OH 1970 238 15,226 12,442 2,784 2,784 Fuel Switch

Substitution . . . . . . 3 J. M. Stuart* OH 1972 238 15,098 9,763 5,335 5,334 Fuel Switch

Substitution . . . . . . 4 J. M. Stuart* OH 1974 238 15,961 10,858 5,103 5,103 Fuel Switch

Total for Utility . . 2,657 155,384 107,734 47,650 55,716

Georgia Power Company

Table 1 ......... 1 Bowen GA 1971 806 54,838 32,617 22,221 4,217 Fuel Switch

Table 1 ......... 2 Bowen GA 1972 789 53,329 39,641 13,688 5,684 Fuel Switch

Table 1 ......... 3 Bowen GA 1974 952 69,862 42,137 27,725 10,221 Fuel Switch

Table 1 ......... 4 Bowen GA 1975 952 69,852 46,258 23,594 6,090 Fuel Switch

Table 1 ......... 1 Hammond GA 1954 125 8,549 2,466 6,083 6,083 Fuel Switch

Table 1 ......... 2 Hammond GA 1954 125 8,977 2,466 6,511 6,511 Fuel Switch

Table 1 ......... 3 Hammond GA 1955 125 8,676 2,466 6,210 6,210 Fuel Switch

Table 1 ......... 4 Hammond GA 1970 578 36,650 14,297 22,353 14,353 Fuel Switch

Table 1 ......... 1 McDonough GA 1963 299 33,290 9,793 23,497 11,285 Fuel Switch

Table 1 ......... 2 McDonough GA 1964 299 20,058 9,793 10,265 10,265 Fuel Switch

Table 1 ......... 1 Wansley * GA 1976 509 36,866 14,336 22,530 8,817 Fuel Switch

Table 1 ......... 2 Wansley * GA 1978 509 60,884 14,447 46,437 9,313 Fuel Switch

Table 1 ......... 1 Yates GA 1950 123 7,863 118 7,745 7,659 Scrubber

Table 1 ......... 2 Yates GA 1950 123 6,855 2,027 4,828 4,828 Fuel Switch

Table 1 ......... 3 Yates GA 1952 123 6,767 2,027 4,740 4,740 Fuel Switch

Table 1 ......... 4 Yates GA 1957 156 8,676 1,939 6,737 6,737 Fuel Switch

Table 1 ......... 5 Yates GA 1958 156 9,162 1,940 7,222 7,222 Fuel Switch

Table 1 ......... 6 Yates GA 1974 404 28,726 6,535 22,191 13,718 Fuel Switch

Table 1 ......... 7 Yates GA 1974 404 22,318 5,683 16,635 8,491 Fuel Switch

Table 1 ......... 1 Gaston * AL 1960 136 8,812 4,009 4,803 4,804 Fuel Switch

Table 1 ......... 2 Gaston * AL 1960 136 9,026 3,758 5,268 5,269 Fuel Switch

Table 1 ......... 3 Gaston * AL 1961 136 8,914 4,893 4,021 4,022 Fuel Switch

Table 1 . . . . . . . . . ST4 Gaston * AL 1962 122 9,387 3,626 5,761 5,761 Fuel Switch

Substitution . . . . . . ST1 Arkwright GA 1941 46 2,437 784 1,653 1,653 Fuel Switch

Substitution . . . . . . ST2 Arkwright GA 1942 46 2,240 783 1,457 1,457 Fuel Switch

Substitution ...... 3 Arkwright GA 1943 40 3,944 783 3,161 3,161 Fuel Switch

Substitution ...... 4 Arkwright GA 1948 49 3,159 784 2,375 2,375 Fuel Switch

Substitution ...... 1 Harlee Branch GA 1965 299 19,221 13,715 5,506 5,506 Fuel Switch

Substitution ...... 2 Harlee Branch GA 1967 359 22,735 13,715 9,020 9,020 Fuel Switch

Substitution ...... 3 Harlee Branch GA 1968 544 31,280 27,014 4,266 4,266 Fuel Switch

Substitution ...... 4 Harlee Branch GA 1969 544 31,042 27,015 4,027 4,027 Fuel Switch

Substitution ...... 3 Mitchell GA 1964 163 10,792 3,570 7,222 7,222 Fuel Switch

Substitution ...... 3 Scherer* GA 1986 75 0 17,151 (17,151) 849 Fuel Switch

Total for Utility . . 10,252 715,187 372,586 342,601 211,835

 See notes at end of table.
Table C1. Characteristics of Selected Phase I Units, by Utility (Continued)

Type of Unit Unit Plant State Online (MW) Allowances (tons) Deductions to 1996 Strategy

Year Capacity of SO Emissions Emissions Over Compliance

Affected Difference

Utility Between

 Owned 1995 Allowances Total and Allowances

Nameplate Allocation Deducted for 1995 Carried 1995 SO

2

a

2

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

110 on Electric Utilities: An Update

Illinois Power Companyb

Table 1 ......... 1 Baldwin IL 1970 623 46,052 75,044 (28,992) 303 Allowances

Table 1 ......... 2 Baldwin IL 1973 635 48,695 104,172 (55,477) 35 Allowances

Table 1 ......... 3 Baldwin IL 1975 635 46,644 86,789 (40,145) 24 Allowances

Table 1 ......... 2 Hennepin IL 1959 231 20,182 27,560 (7,378) 122 Allowances

Table 1 . . . . . . . . . 1&2 Vermilion(c) IL 1956 183 22,707 2,623 20,084 134 Burn Nat. Gas

Substitution . . . . . . 1-5 Havana IL 1947 230 281 0 281 0 Shutdown

Substitution . . . . . . 1&4 Wood River IL 1954 163 2,018 1,316 702 27 Allowances

Total for Utility . . 2,699 186,579 297,504 (110,925) 645

Potomac Electric Power Company

Table 1 . . . . . . . . . ST1 Chalk Point MD 1964 364 25,403 20,543 4,860 3,700 Fuel Switch

Table 1 . . . . . . . . . ST2 Chalk Point MD 1965 364 23,690 20,544 3,146 6,756 Fuel Switch

Table 1 . . . . . . . . . ST1 Morgantown MD 1970 626 39,864 28,040 11,824 7,257 Fuel Switch

Table 1 . . . . . . . . . ST2 Morgantown MD 1971 626 45,592 38,515 (7,077) 10,017 Fuel Switch

Table 1 ......... 1 Conemaugh * PA 1970 91 9,389 460 8,929 106 Scrubber

Table 1 ......... 2 Conemaugh * PA 1971 91 8,335 7,131 1,204 1,859 Scrubber

Substitution ...... 3 Chalk Point MD 1975 659 9,000 3,010 5,990 5,990 Burn Oil

Substitution ...... 4 Chalk Point MD 1981 659 1,519 1,354 165 373 Burn Oil

Total for Utility . . 3,480 162,792 119,597 43,195 36,057

Pennsylvania Power & Light Company

Table 1 ......... 1 Brunner Island PA 1961 363 27,030 20,530 6,500 6,500 Fuel Switch

Table 1 ......... 2 Brunner Island PA 1965 405 31,995 20,531 11,464 9,751 Fuel Switch

Table 1 ......... 3 Brunner Island PA 1968 790 60,571 56,335 4,236 10,713 Fuel Switch

Table 1 ......... 1 Martins Creek PA 1954 156 12,327 5,381 6,946 6,946 Fuel Switch

Table 1 ......... 2 Martins Creek PA 1956 156 12,483 5,381 7,102 7,102 Fuel Switch

Table 1 ......... 3 Sunbury PA 1951 104 9,133 9,847 (714) 2,797 Fuel Switch

Table 1 ......... 4 Sunbury PA 1953 156 11,392 9,511 1,881 1,638 Fuel Switch

Table 1 ......... 1 Conemaugh * PA 1970 107 11,002 539 10,463 124 Scrubber

Table 1 ......... 2 Conemaugh * PA 1971 107 9,767 8,356 1,411 2,178 Scrubber

Total forUutility . . 2,343 185,700 136,411 49,289 47,749

Southern Indiana Gas & Electric Company

Table 1 ......... 2 Culley IN 1966 104 4,703 2,549 2,154 2,154 Scrubber

Table 1 ......... 3 Culley IN 1973 265 18,603 0 18,603 2,003 Scrubber

Table 1 ......... 4 Warrick * IN 1970 162 14,789 18,841 (4,052) 1,235 Allowances

Total for Utility . . 530 38,095 21,390 16,705 5,392

 Allowances carried over to 1996 may not equal the differences between allocated and 1995 emissions (e.g., Cincinnati Gas and Electric) due to a

purchases or sales of additional allowances. The data in this table do not account for purchases and sale transactions of the utility.

Illinois Power purchased enough emission allowances to cover its 1995 emissions. b

Vermillion 1 is a substitution unit. c

SO = Sulfur dioxide. 2

MW = Megawatt.

* = Plant jointly owned by more than one utility.

Sources: Personal contact with Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power,

and Southern Indiana Gas and Electric; Environmental Protection Agency, “1995 Compliance Results Acid Rain Program,” EPA/430-R-96-012

(Washington, DC, July 1996).
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 111

Table C2. Cost of Phase I Compliance for Selected Units, by Utility

Type of Unit Unit Plant

Numbera

of

Low-NOx

Burners

Numbera

of CEMs

Numbera

of

Scrubbers

 SO Control 2

NOx

Control CEMS T

Ca

C

Capital

Cost

O&M

Cost

Capital

Cost

Capital

Cost

O&M

Cost

million dollars

Cincinnati Gas & Electric CompanyTable 1 ......... 5 Miami Fort 0.0 0.5 0.0 0.00 0.00 0.00 0.59 c 0Table 1 ......... 6 Miami Fort 0.0 0.5 0.0 2.24 c 0.00 0.62 c 2Table 1 ......... 7 Miami Fort * 0.0 0.6 0.0 4.89 c 0.00 0.52 c 5.Table 1 ......... 5 Beckjord 1.0 1.0 0.0 5.28 c 5.00 0.90 c 11.Table 1 ......... 6 Beckjord * 0.4 0.4 0.0 0.00 0.00 1.90 0.29 c 2.Table 1 ......... 4 Conesville * 0.0 0.4 0.0 0.00 b 0.00 b c Substitution ...... 2 East Bend* 0.0 0.7 1.0 b b 0.00 0.61 b 0Substitution . . . . . . 1 J. M. Stuart* 0.0 0.4 0.0 b b 0.00 b b Substitution . . . . . . 2 J. M. Stuart* 0.0 0.4 0.0 b b 0.00 b b Substitution . . . . . . 3 J. M. Stuart* 0.0 0.4 0.0 b b 0.00 b b Substitution . . . . . . 4 J. M. Stuart* 0.0 0.4 0.0 b b 0.00 b b  Total for Utility . . 1.4 5.7 1.0 12.40 b 6.90 3.53 b 22.Georgia Power CompanyTable 1 ......... 1 Bowen 1.0 1.0 0.0 0.40 0.00 7.19 0.74 b 8Table 1 ......... 2 Bowen 1.0 1.0 0.0 0.27 0.00 8.23 0.82 b 9Table 1 ......... 3 Bowen 1.0 1.0 0.0 2.06 0.00 9.11 0.61 b 11Table 1 ......... 4 Bowen 1.0 1.0 0.0 1.94 0.00 9.28 0.55 b 11Table 1 ......... 1 Hammond 0.0 0.5 0.0 1.45 0.00 0.00 0.53 b 1Table 1 ......... 2 Hammond 0.0 0.5 0.0 2.77 0.00 0.00 0.73 b 3Table 1 ......... 3 Hammond 0.0 0.5 0.0 0.64 0.00 0.00 0.47 b 1Table 1 ......... 4 Hammond 1.0 0.5 0.0 1.00 0.00 22.00 0.45 b 23Table 1 ......... 1 McDonough 1.0 0.5 0.0 2.35 0.00 9.18 0.62 b 12Table 1 ......... 2 McDonough 1.0 0.5 0.0 2.34 0.00 8.47 0.48 b 11Table 1 ......... 1 Wansley * 0.5 0.3 0.0 2.51 0.00 9.13 0.77 b 12Table 1 ......... 2 Wansley * 0.5 0.3 0.0 2.15 0.00 5.95 0.59 b 8Table 1 ......... 1 Yates (d) 0.0 0.7 1.0 17.00 2.00 0.00 0.78 b 17.Table 1 ......... 2 Yates 0.0 0.7 0.0 1.98 0.00 0.00 0.47 b 2Table 1 ......... 3 Yates 0.0 0.7 0.0 1.53 0.00 0.00 0.40 b 1Table 1 ......... 4 Yates 1.0 0.7 0.0 1.59 0.00 2.07 0.40 b 4Table 1 ......... 5 Yates 1.0 0.7 0.0 1.36 0.00 2.07 0.33 b 3Table 1 ......... 6 Yates 1.0 0.7 0.0 1.82 0.00 6.13 0.85 b 8See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 112 Table C2. Cost of Phase I Compliance for Selected Units, by Utility (Continued) Type of Unit Unit Plant Numbera of Low-NOx Burners Numbera of CEMs Numbera of Scrubbers SO Control 2 NOx Control CEMS Tot

Cap

Cos

Capital Cost O&M Cost Capital Cost Capital Cost O&M Cost million dollars Table 1 ......... 7 Yates 1.0 0.7 0.0 1.89 0.00 6.51 0.52 b 8.

Table 1 ......... 1 Gaston * 0.5 0.5 0.0 0.00 0.00 2.00 0.25 c 2.Table 1 ......... 2 Gaston * 0.5 0.5 0.0 0.00 0.00 3.00 0.25 c 3.Table 1 ......... 3 Gaston * 0.5 0.5 0.0 0.00 0.00 7.00 0.25 c 7.Table 1 . . . . . . . . . ST4 Gaston * 0.5 0.5 0.0 0.00 0.00 3.00 0.25 c 3.Substitution . . . . . . ST1 Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.34 b 0.

Substitution . . . . . . ST2 Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.27 b 0.

Substitution ...... 3 Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.30 b 0.

Substitution ...... 4 Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.30 b 0.

Substitution ...... 1 Harlee Branch 0.0 0.5 0.0 0.00 0.00 0.00 0.34 b 0.

Substitution ...... 2 Harlee Branch 1.0 0.5 0.0 0.00 0.00 5.00 0.87 b 5.

Substitution ...... 3 Harlee Branch 0.0 0.5 0.0 0.00 0.00 0.00 0.30 b 0.

Substitution ...... 4 Harlee Branch 0.0 0.5 0.0 0.00 0.00 0.00 0.30 b 0.

Substitution ...... 3 Mitchell 0.0 1.0 0.0 0.00 0.00 0.00 1.23 b 1.

Substitution ...... 3 Scherer* 0.0 1.0 0.0 0.00 0.00 0.00 0.77 b 0.

 Total for Utility . 15.1 19.4 1.0 47.05 2.00 125.32 17.13 b 189.Illinois Power Company Table 1 ......... 1 Baldwin (e) 0.0 1.0 0.0 34.60 3.90 0.00 2.10 0.10 36.Table 1 ......... 2 Baldwin 0.0 1.0 0.0 0.00 7.40 0.00 2.20 0.10 2.Table 1 ......... 3 Baldwin 1.0 1.0 0.0 0.00 5.40 9.00 2.10 0.10 11.Table 1 ......... 2 Hennepin 0.0 1.0 0.0 0.00 1.70 0.00 1.90 0.10 1.Table 1 . . . . . . . . . 1&2 Vermilion(f) 1.0 2.0 0.0 0.00 0.10 3.70 1.70 0.10 5.Substitution . . . . . . 1-6 Havana 0.0 4.0 0.0 0.00 0.00 0.00 2.60 0.20 2.

Substitution . . . . . . 1&4 Wood River 0.0 3.0 0.0 0.00 0.00 0.00 2.60 0.20 2.

 Total for Utility . 2.0 13.0 0.0 34.60 18.50 12.70 15.20 0.90 62.Potomac Electric Power CompanyTable 1 . . . . . . . . . ST1 Chalk Point 1.0 0.5 0.0 15.00 b 18.10 1.60 b 34.Table 1 . . . . . . . . . ST2 Chalk Point 1.0 0.5 0.0 15.00 b 18.10 1.60 b 34.Table 1 . . . . . . . . . ST1 Morgantown 1.0 1.0 0.0 0.00 b 40.20 3.10 b 43.Table 1 . . . . . . . . . ST2 Morgantown 1.0 1.0 0.0 0.00 b 40.20 3.10 b 43.Table 1 ......... 1 Conemaugh * 1.0 1.0 0.1 16.20 0.90 2.00 0.10 0.00 18.Table 1 ......... 2 Conemaugh * 1.0 0.5 0.1 16.20 0.90 2.00 0.10 0.00 18.See notes at end of table.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 113

Table C2. Cost of Phase I Compliance for Selected Units, by Utility (Continued)

Type of Unit Unit Plant

Numbera

of

Low-NOx

Burners

Numbera

of CEMs

Numbera

of

Scrubbers

 SO Control 2

NOx

Control CEMS 

Capital

Cost

O&M

Cost

Capital 

Cost

Capital

Cost

O&M 

Cost

million dollars

Substitution ...... 3 Chalk Point 0.0 1.0 0.0 0.00 0.00 0.00 1.60 b 

Substitution ...... 4 Chalk Point 0.0 1.0 0.0 0.00 0.00 0.00 1.60 b 

Total for Utility . 6.0 6.5 0.2 62.40 1.80 120.60 12.80 b 1

Pennsylvania Power & Light CompanyTable 1 ......... 1 Brunner Island 1.0 0.5 0.0 0.00 b 13.00 1.20 b Table 1 ......... 2 Brunner Island 1.0 0.5 0.0 3.00 b 15.00 1.20 b Table 1 ......... 3 Brunner Island 1.0 1.0 0.0 0.00 b 17.00 2.40 b Table 1 ......... 1 Martins Creek 1.0 1.0 0.0 2.00 b 6.00 1.25 b Table 1 ......... 2 Martins Creek 1.0 1.0 0.0 2.00 b 5.00 1.25 b Table 1 ......... 3 Sunbury 1.0 0.5 0.0 1.50 b 5.00 1.80 b Table 1 ......... 4 Sunbury 1.0 0.5 0.0 1.70 b 5.30 1.80 b Table 1 ......... 1 Conemaugh * 0.1 0.1 0.1 20.50 1.10 2.20 0.10 0.00 Table 1 ......... 2 Conemaugh * 0.1 0.1 0.1 20.50 1.10 2.20 0.10 0.00 

Total for Utility . 7.2 5.2 0.2 51.20 2.20 70.70 11.10 b 1

Southern Indiana Gas & Electric CompanyTable 1 ......... 2 Culley 1.0 1.0 0.5 28.84 1.12 1.41 0.75 0.06 Table 1 ......... 3 Culley 1.0 1.0 0.5 74.16 2.88 3.59 0.75 0.06 Table 1 ......... 4 Warrick * 0.0 0.5 0.0 0.00 0.00 0.00 1.30 0.04 

Total for Utility . 2.0 2.5 1.0 103.00 4.00 5.00 2.80 0.16 1

Note: Totals may not equal sum of individual components because of rounding.

A fractional value indicates that ownership of equipment was allocated across more than 1 unit.

a

Costs not estimated.

b

Estimated to be negligible by utility.

c

Includes only one-half of scrubber capital costs. The other half is paid by the Department of Energy as a demonstration project.

d

Installation of the scrubber for the Baldwin 1 unit was suspended in 1992.

e

Vermillion 1 is a substitution unit.

f*Partially owned unit.

CEMS = Continuous emission monitoring systems.NO = Nitrogen oxides. x

SO = Sulfur dioxide. 2KW = Kilowatts.Sources: Personal contact with Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Pow

and Electric.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 115

Glossary

Acid Rain: Also called acid precipitation or acid Bedford, Blair, Bradford, Cambria, Cameron, Centre,

deposition, acid rain is precipitation containing harmful Clarion, Clearfield, Clinton, Elk, Forest, Fulton,

amounts of nitric and sulfuric acids formed primarily by Huntingdon, Jefferson, Lycoming, McKean, Mifflin,

nitrogen oxides and sulfur oxides released into the Potter, Somerset, and Tioga. Selected mines in the

atmosphere when fossil fuels are burned. It can be wet following counties: Armstrong County (part), all mines

precipitation (rain, snow, or fog) or dry precipitation east of the Allegheny River, and those mines served by the

(absorbed gaseous and particulate matter, aerosol Pittsburgh and Shawmut Railroad located on the west

particles, or dust). Acid rain has a pH below 5.6. Normal bank of the river; Fayette County (part), all mines located

rain has a pH of about 5.6, which is slightly acidic. The on and east of the line of Indian Creek Valley branch of

term pH is a measure of acidity or alkalinity and ranges the Baltimore & Ohio Railroad; Indiana County (part), all

from 0 to 14. A pH measurement of 7 is regarded as mines not served by the Saltsburg branch of the

neutral. Measurements below 7 indicate increased acidity, Consolidated Railroad Corporation; and Westmoreland

while those above indicate increased alkalinity. County (part), all mines served by the Consolidated Rail

Allowance: One SO allowance permits one ton of mines in the following counties: Grant, Mineral, and 2

 SO emissions. Tucker. 2

Anthracite: A hard, black lustrous coal, often referred to Bureau of Mines District 2: Pennsylvania - All mines in

as hard coal, containing a high percentage of fixed carbon the following counties: Allegheny, Beaver, Butler, Greene,

and a low percentage of fixed volatile matter. Lawrence, Mercer, Venango, and Washington. Selected

Ash: Impurities consisting of silica, iron, alumina, and all mines west of the Allegheny river except those mines

other noncombustible matter that are contained in coal. served by the Pittsburgh & Shawmutt Railroad; Fayette

Ash increases the weight of the coal, adds to the cost of County (part), all mines except those on and east of the

handling, and can affect its burning characteristics. Ash line of Indian Creek Valley branch of the Baltimore &

content is measured as a percent by weight of coal on an Ohio Railroad; Indiana County (part), all mines served by

“as received” or a “dry” (moisture-free, usually part of a the Saltsburg branch of the Consolidated Rail Corlaboratory analysis) basis. poration; and Westmoreland County (part), all mines

Ash Fusion Temperature: The temperature at which ash from Torrance, east.

from coal melts.

Bituminous Coal: The most common coal. It is dense and suring the quantity of heat energy equal to the quantity of

black (often with well-defined bands of bright and dull heat required to raise the temperature of 1 pound of water

material). Its moisture content usually is less than 20 by 1 degree Fahrenheit.

percent. It is used for generating electricity, making coke,

and space heating. CAAA90: The Clean Air Act Amendments of 1990.

Boiler: A device for generating steam for power, Capital Costs: The costs of the long-term productive

processing, or heating purposes or for producing hot assets of a utility including scrubbers and continuous

water for heating purposes or hot water supply. Heat emissions monitors.

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.

Bureau of Mines, District 1: Maryland - All mines in the

State. Pennsylvania - All mines in the following counties:

Corporation from Torrance, east. West Virginia - All

mines in the following counties: Armstrong County (part),

except those served by the Consolidated Rail Corporation

Btu (British Thermal Unit): A standard unit for meaCoal: 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
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

116 on Electric Utilities: An Update

progressive alternation from lignite to anthracite. Lignite administered programs that are designed to reduce load

contains approximately 9 million to 17 million Btu per ton. growth, and any other programs designed for strategic

The contents of subbituminous and bituminous coal range load growth.

from 16 million to 24 million Btu per ton and from 19

million to 30 million Btu per ton, respectively. Anthracite Dry Dust Baghouse Collector: A fabric filter that collects

contains approximately 22 million to 28 million Btu per the dry particulate matter as the cooled flue gas passes

ton. through the filter material.

Low-sulfur coal: The EIA sulfur content category of Electric Utility: A corporation, person, agency, authority,

coal with less than 0.60 pounds of sulfur per million or other legal entity or instrumentality that owns and/or

Btu. operates facilities within the United States, its territories,

Medium-sulfur coal: The EIA sulfur content category distribution, or sale of electric energy primarily for use by

of coal with 0.60 to 1.67 pounds of sulfur per million the public and files forms listed in the Code of Federal

Btu. Regulations, Title 18, Part 141. Facilities that qualify as

High-sulfur coal: The EIA sulfur content category of Utility Regulatory Policies Act (PURPA) are not

coal with greater than 1.67 pounds of sulfur per considered electric utilities.

million Btu.

Compensating Unit: A unit designated by a Table 1 unit series of parallel vertical plates through which the flue gas

that reduced its utilization below its baseline. The passes. It electrically charges the ash particles in the flue

compensating unit provides compensating generation to gas to collect and remove them.

account for the reduced utilization of the Table 1 unit.

Consumption (Fuel): The amount of fuel used for gross capability of doing work (potential energy) or the

generation, providing standby service, start-up and/or conversion of this capability to motion (kinetic energy).

flame stabilization. Energy has several forms, some of which are easily

Continuous Emission Monitor (CEM): A device that work. Most of the world’s convertible energy comes from

approximates a continuous measurement of certain fossil fuels that are burned to produce heat that is then

characteristics of a gas by making separate measurements used as a transfer medium to mechanical or other means

frequently. For compliance with the CAAA90, the in order to accomplish tasks. Electrical energy is usually

measurements must be taken at least every 15 minutes. measured in kilowatthours, while heat energy is usually

Extractive Continuous Emission Monitor: A CEM

that draws exhaust gas away from the combustion Facility: An existing or planned location or site at which

system to the measurement equipment through prime movers, electric generators, and/or equipment for

special ducts. converting mechanical, chemical, and/or nuclear energy

In Situ Continuous Emission Monitor: A CEM that facility may contain more than one generator of either the

makes measurements directly in the flue or exhaust same or different prime mover type.

pipe.

Cost: The amount paid to acquire resources, such as plant quasi-independent regulatory agency within the

and equipment, fuel, or labor services. Department of Energy having jurisdiction over interstate

Demand-Side Management: The planning, implemen- licensing, natural gas pricing, oil pipeline rates, and gas

tation, and monitoring of utility activities that are pipeline certification.

designed to influence consumer use of electricity in ways

that will produce desired changes in a utility's load Flue Gas Desulfurization Unit (Scrubber): Equipment

shape, including direct Load Control, Interruptible Load, used to remove sulfur oxides from the combustion gases

and Conservation and Other Demand-Side Management of a boiler plant before discharge to the atmosphere.

categories. Demand-Side Management includes utility- Chemicals, such as lime, are used as the scrubbing media.

or Puerto Rico for the generation, transmission,

cogenerators or small power producers under the Public

Electrostatic Precipitator (ESP): A unit comprised of a

Energy: The capacity for doing work as measured by the

convertible and can be changed to another form useful for

measured in British thermal units.

into electric energy are situated, or will be situated. A

Federal Energy Regulatory Commission (FERC): A

electricity sales, wholesale electric rates, hydroelectric
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

on Electric Utilities: An Update 117

Flue Gas Particulate Collectors: Equipment used to Gigawatt (GW): One billion watts of capacity.

remove fly ash 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: Particulate matter from coal ash in which the

particle diameter is less than 1 x 10 meter. This is -4

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.

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.

Greenfield Unit: A newly constructed generating unit.

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-NO Burners: Burners that utilize special arrange- x

ments of fuel and air injection ports, which reduce the

formation of NO during combustion. x

Megawatt (MW): One million watts of capacity.

Megawatthour (MWh): One million watthours of electric

energy.

NO : Nitrogen oxides. x

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.
Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990

118 on Electric Utilities: An Update

Petroleum (Crude Oil): A naturally occurring, oily, Subbituminous Coal: A dull black coal of rank

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.

SO : Sulfur dioxide. 2

Slagging: The formation of molten, partially fused

resolidified deposits on furnace walls or other surface

exposed to radiant heat.

intermediate between lignite and bituminous.

Substitution Unit: A unit brought into Phase I to assist a

Table 1 unit in meeting emissions reduction obligations.

Utilities may make cost-effective emissions reductions at

the substitution unit instead of at the Table 1 unit by

achieving the same overall emissions reductions that

would have occurred without the participation of the

substitution unit.

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” (moisturefree, 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.