### 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 Ene rgy 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 on Electric Utilities: An Update ii 

# 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.g ov), 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- w ill be listed in the “Publications” section. The
ization Act of 1977 (Public Law 95-91) requires the “Appl ications” 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 ........................................................................ 4 2 

### 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update vi 

# Tables Page

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

### 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2 

### 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 .......... 8 2 

### 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 . . . . . . . . . . . . . . . . . . . 53Energy 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 R ain 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 c ompliance 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 additionalallowances 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 ut ilities 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 blendingwith 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 (Fig ure 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 expectedFuel 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 Emissions SO 2

(million tons)

1985 -- 9.3
1995 -- 4.4

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update viii 

### 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 1995 a 

### (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 utilitiesare 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) a ffected by Ph ase 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, butcoal 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 c osts, the c osts 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 (I llinois, Indiana, and Western Kentucky) decreased by 40 million tons.



# Compliance Strategies and Costs of Six
Utilities

2

2 x 21990 1995 0 20 40 60 80 100Percent 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 c osts (which in this analysis are primarily allowance purchases) ranged from a high of $19.4 million at Illinois Power to a low of $1.8million 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
utilities are 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-effec tive 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
utilit ies 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 SO 2 

### 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 wereAgency (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 total of 435 affected

x 

### 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 nonut ility 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 on Electric Utilities: An Update 2 

### 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 on Electric Utilities: An Update 4 

### 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

......... 333.2 a 

### 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 inimplementing 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 c osts 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. 2Energy 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 ut ility could ch oose 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 SO 2 

### 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 multip lied 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 SO 2 

### 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 rel atively 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 ut ility had to meet the SO 2 

### 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 SO 2 

### 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 lowerEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 6 

### 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 Age a (years) Affected Nameplate Capacity (megawatts) Allowances b (per year) 1985 SO 2 Emissions

(tons) 1995
Emissions

(tons) Percentage
of Total Nameplate Capacity Affected by

Phase I Percentage
of SO 2 Emission
Reductions

in 1995 c

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 incl udes 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, A ssociated 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 me gawatt units, one 317.5 megawatt unit and two 623.0 megawatt units. Units 5, 6, and 7 are Table1 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 asignificantly 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 bargetransportation, 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 andburden 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 w hich 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 p ercent 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 thecoal handling and crushing systems and boiler modifications, including installation of new dampers and sootblowers. 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 Th omas 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 megawa tts. 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 coal0 200 400 600 800 1,000

Quantity (Thousands of Allowances) 0 50 100 150 200 250 300 350Price (Dollars)

Demand EPA Supply

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 8 

### “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 estim ated 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 a ssociated with commodity markets are now
characteristics of the allowance market. Some of these include forward contracts, options, and futures.

Originally, many economi sts 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-priceEnergy 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 19 94, 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 SO 2 

### 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 p ostpone 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 t hat 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 wetEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 10 

### “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 availab ility 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 reliablystandard 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 m ost 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 18Energy 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 andaccess 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, exclu sive 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
effici encies 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 powerplant 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 a ffec ted under Phase I had cumulative investments of which are outdated and small capacity units. Retired $14.4 bi llion in 1995, alm ost half of the total ut ility units accounted for 2 percent of 1995 SO emissions inv estments 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 (cor responding to the East Central Area Reliability
1989. In diana-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 SO 2 

### 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 megawa tts. One unit each at I llinois 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 Uni ted States have invested heavily in air pollution control equipment during the last decade.
Scrubbers were installed at some utilities to reduce SO 2 

### emissions, and many utilities have retrofitted low-NO

x 

### 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 b illion, 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

231986 1987 1988 1989 1990 1991 1992 1993 1994 1995 0 5 10 15 20 25 30 35Billions of Dollars All Major IOUs

Major IOUs with Phase 1 Units

ECAR ERCOT MAAC MAIN MAPP NPCC SERC SPP WSCC 0 2 4 6 8Billions 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 on Electric Utilities: An Update 12 

### 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 PollutionControl 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 Ut ilities, 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 smokesta cks, 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 Reliab ility 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 Ut ilities, DOE/EIA-0437(95/1) (Washington, DC, December 1996). 

### Figure 5. Total Investments in Air PollutionControl 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 Massachuse tts 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 Switching f



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

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

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

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

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

Total

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

Preliminary annualized compliance c ost 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 Ti tle 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 inst alled 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 wes tern 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, 19 96) to Art Fuldner and Ron Hankey, Office of Coal, Nuclear, Electric and Alternate Fuels, Energy Information Administration. Massachusetts Institute of Tec hnology, Center for Energy and Environmental Policy Research, More on SO Compliance Costs with Title IV , Memorandum (from Juan-Pablo Montero on January 2 

### 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 c ost 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 with no modification cost achieved a 2 

### 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) com2Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 14 

### 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

Utility a 

### Affected Nameplate Capacity

(Utility Owned)

(MW) Total Capacity

(MW) Percent Capacity
Affected Sulfur Dioxide Emissions Allowances

1995
Allocation

of SO 2 

### Allowances Allowances
Deducted
for 1995

SO 2 

### Emissions Differences
Between
Allowances

and 1995
Emissions Allowances b



### 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 P lans 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 I llinois 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. a ffected by Phase I. Under the substitution revisions of Appendix C li sts detailed information on the character- C AAA90, 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

2Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 15Table 7. Costs of Phase I Compliance for Selected UtilitiesUtilityaNumber ofLow-NOxBurnersbNumberofCEMSbNumberofScrubbersbSO Control2NOxControl CEMSTotalCapitalCostsTotalAnnualO&MCostsAverageCapitalCost(dollars/ kWaffected)CapitalCostAnnualO&MCostCapitalCostCapitalCostAnnualO&MCost(million dollars)Illinois Power. . . . . . . . 2.013.0 0.0 34.6 18.5 12.7 15.2 0.9 62.5 19.4 23.15Pennsylvania P&L. . . . 7.2 5.2 0.251.2 2.2 70.7 11.1 c 133.0 2.2 56.76Potomac Electric Power 6.0 6.5 0.2 62.4 1.8 120.6 12.8 c 195.8 1.8 56.27Cincinnati G&E. . . . . . 1.4 5.7 1.0d12.4 c 6.9 3.5 c 22.8 c 16.39Georgia Power.......15.1 19.4 1.0 47.0 2.0 125.3 17.1 c 189.5 2.0 18.48Southern Indiana G&E 2.0 2.5 1.0 103.0 4.0 5.0 2.8 0.2 110.8 4.2 208.90The full utility names are Illinois Power Company, Pennsylvania Power & Light Company, Potomac Electric Power Company, Cincinnati Gas & Electric Company,aGeorgia Power Company, and Southern Indiana Gas & Electric Company.A fractional value indicates that ownership of equipment was allocated across more than one unit.bCosts not estimated.cThe capital costs for the scrubber were not included because the scrubber was installed in 1980, before passage of the Clean Air Act Amendments of 1990.dSome of these costs are offset by selling the gypsum produced by the scrubber.eNO = Nitrogen oxides.xSO = Sulfur dioxide.2KW = 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 Appendix C.Sources: Personal contact with Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power, and SouthernIndiana Gas & Electric.Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 16 

### 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

0Cents 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 Ut ilities, 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 reconsi dered its alternatives for compliance.

IP decided to purchase allowances for most of its plants. In 1995, it purchased alm ost 118,000 vintage 1995 SO 2

### 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 m ost 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 c osts 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 NO

x 

### 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 alm ost $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 sixutilities examined, IP was the only one that used allowances as a primary compliance strategy. Through 1995, IP had spent $18.5 m illion 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 IIrequirements, but they anticipate additional capital expenditures to comply with the Phase II NO requirements

x 

### in 2000 and with f uture 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 NO

x 

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

x

### on all its Phase I units and submitted a plan for systemwide NO averaging.

xEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 18 

### 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 est imates that further Title IV compliance operating costs w ill be incurred beyond
2000 in amounts t hat 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 c osts 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, m ost 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 m illion on CE MS. 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 possib ility 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 Ohiowith 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

3Energy 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 designatingEast 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 c osts are $16.91 per kilowatt of affected capacity. This expenditure is relatively low compared to the other 5 utilities, primarily because the c osts 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 p lant modifications for reducing SO 2 

### 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’sother 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 Ga ston 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 therecipient 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 someequipment upgrades. Switching fuels—from an approximate mix of 1.5 percent high-sulfur coal from the Illinoisbasin to lower sulfur sources from central Appalachia—allowed GPC to overcomply and accumulate
unused emissions allowances that were banked for futureuse. 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 on Electric Utilities: An Update 20 

### 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 purchasingmore 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 p ossib ility 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 p ossible. Phase I and Phase II are not distinct.
Rational utilities w ill 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 recovera 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 scru bbers. 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 Btuunits 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 w ill 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 deci sion—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 inst ead 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 c ost 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

xEnergy 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 extraemissions allowances in most instances, was used extensively by utilities. By exceeding the required emissions reductions, most ut ilities 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 ut ilities 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 ut ility 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 almost7 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 acr oss 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-c ost 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 todecrease 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 on Electric Utilities: An Update 24 

### 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 coalRocky 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 in efficient, 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 asfar south as Georgia. Several States significantly increased purchases of Wyoming coal between 1990 and 1995 (Figure 7). Mi ssouri 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 m illion short tons in 1990 to 103 million shorttons 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 increasedas 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 theEnergy 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 on Electric Utilities: An Update 26 

### 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 0 5 10 15 20 25 30Million Short Tons 1990

AL AR GA IL IN OK MI MO 0 5 10 15 20 25 30Million Short Tons 1995

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, Au gust 1991), Table 33 and Federal Energy Regulatory Comm ission (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 m ost 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 isbituminous 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: I llinois 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 I llinois 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. TheWA

OR

CA NV ID MT

UT

AZ WY

CO

NM ND

SD

NE

KS

OK

TX MN

IA

MO

AR

LA

WI

IL IN OH

KY
TN

MS AL GA

FL SC NC WV VA MD

DE

DC PA NY VT

NH ME

MA

CT RI

NJ MI 

### West Midwest

South Northeast

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 28 

### 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 WyomingCO IL IN KY MT NM TN WV WY 0 5 10 15 20Million Short Tons 1990

CO IL IN KY MT UT WV WY 0 5 10 15 20Million Short Tons 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 Comm ission (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



### Illin ois 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 Illin ois 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 Il linois (as it had in 1990). In fact, Indiana received almost the same quantity of coalCO IL IN KY MT OH VA WV WY 0 5 10 15 20 25Million Short Tons 1990

IL IN KY MT OH PA VA WV WY 0 5 10 15 20 25Million Short Tons 1995 CO IL IN KS KY MO NM OH OK WY 0 5 10 15 20 25 30Million Short Tons 1990

CO IL IN KS KY MO UT WY 0 5 10 15 20 25 30Million Short Tons 1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 30 

### 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 Comm ission (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 Comm ission (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 m illion 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 M issouri 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, purcha sing 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, andIN KY MT OH PA VA WV WY 0 3 6 9 12 15Million Short Tons 1990

C0 IL IN KY MT OH PA UT VA WV WY 0 3 6 9 12 15Million Short Tons 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 Comm ission (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 alm ost 100 percent Ohio coal in 1995 because of the operating success of a year-old, $31 million LS-2wet 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, whichinclude 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 percentIL IN KY OH PA WV 0 5 10 15 20 25 30Million Short Tons 1990

IN KY OH PA VA WV 0 5 10 15 20 25 30Million Short Tons 1995

OH BOM 1 PA BOM 2 PA UT WV 0 5 10 15 20 25 30Million Short Tons 1995 KY OH BOM 1 PA BOM 2 PA WV 0 5 10 15 20 25 30Million Short Tons 1990

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 32 

### 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 Comm ission (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 redu ced its total coal receipts by 6.3 million tons, with alm ost all of this decline occurring inthe 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 c osts 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 ut ility 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 80KY MD OH BOM
1 PA BOM
2 PA WV 0 3 6 9 12 15Million Short Tons 1990

KY OH BOM 1 PA BOM 2 PA WV 0 3 6 9 12 15Million Short Tons 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 Comm ission (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 thecentral 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 WestVirginia); 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

57E. KY W. KY MD OH PA N. WV S. WV 0 5 10 15 20Million Short Tons 1990

E. KY MD OH PA N. WV S. WV 0 5 10 15 20Million Short Tons 1995

Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 34 

### 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 Comm ission (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. M ost 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 WestVirginia, 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 num ber 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 ofIL IN E. KYW. KY OH PA TN VA WV WY 0 5 10 15 20 25Million Short Tons 1990

CO IL IN E. KYW. KY OH PA TN UT WV 0 5 10 15 20 25Million 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 Comm ission (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
Illin ois 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, alm ost 2 m illion 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
utilit ies 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 1985 and 638,000 tons were emitted 2 

### 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 l ower 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 decrea sed 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 on Electric Utilities: An Update 36 

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

State 1990 1995

Mines a 

### Miners b 

### Mines a 

### Miners b



### 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 complianceAL IL E. KY W. KY OH TN VA S. WV WY 0 5 10 15 20Million Short Tons 1990

AL IL E. KY TN VA S. WV WY 0 5 10 15 20Million Short Tons 1995 IL IN E. KY W. KY TN VA WV 0 2 4 6 8 10 12 14Million Short Tons 1990

CO IL IN E. KYW. KY PA TN UT VA WV 0 2 4 6 8 10 12 14Million 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 Comm ission (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 Comm ission (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

62Energy 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 r otating 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 A ppeals; 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-b ottom” 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. Co urt 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, EPAsigned 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

xEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 40 

### 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 w ill 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 c ost 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 effecti veness 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 ch oose 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-c ontrol” 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 NO

x 

### 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 ch oose 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 capand 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 tradingEnergy 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 NO

x 

### 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 ost-effective

x 

### 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
hazar dous 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 tooccur 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 anynew 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. Minne sota, Florida, andNew 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 ifa 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 thelevel 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). T his 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 extensiveresearch on mercury. Results of the studies show significant variations in the amount of mercury removed byEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 42 

### 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 50and 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 disa ppearance 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 NO

x 

### 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-fi red 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 withCAAA90. 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 NO

x 

### 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 theEnergy 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 electr ostatic 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 electr ostatic precipitators (ESP’s) and fabric filters or baghouses to control particulateemissions 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 controldevices more effective. Given these factors and the pressures of competition, utilities with coal-fired plants willhave 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 fa lling 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 systemhas been demonstrated and commercially installed. 84



###  Another approach to improving fly ash removal isto 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 inbaghouse compartments with a reduction in baghouse size and cost when compared to aconventional 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 inbasic 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, em issions, 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. w ill 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, m ost 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 c osts 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 c ost 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 majorinvestments 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 derivedfrom 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 andrepowering, 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. 91Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 46 

### 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 ch oose 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. Thesechanges can require alterations to the ESP’s. Finally, different coals may cause different HAP emissions. Because utility coal-fired plants are des igned 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-freenatural 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 ility that has installed scrubbers to a midwestern utility

x

### 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 w ill be held for use in Phase II. The allowances w ill be are designed to co-fire natural gas. Although many can be depleted by 2012, so the company must d ecide 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

96Energy 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 scru bber 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 Co ngress 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. M ost of these h azardous 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, f ossil-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 c osts 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 underut ilized 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 waterat 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 on Electric Utilities: An Update 48 

### 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 megawa tts. 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 megawa tts 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 theenvironment 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 on Electric Utilities: An Update 50 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 fordevelopment of air pollution regulations for the electric each of those pollutants. Failure to take advantage of costpower generation sector. This sector includes utilities, effective sy nergies and incremental compliance planning independent power producers, cogenerators, and indus- could increase control c osts and ut ility 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 tradingconflicts. 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

2Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 52 

### 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 someFor 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

2Energy 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 c osts, some ut ilities are finding to be less economical because of landfill disposal costs andEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 54 

### 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-effect ive, utilities choose, if possible, some ut ilities 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 InternetEnergy 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 c osts. 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, ut ility boiler m odifications 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 possibleit 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
PollutionEnergy 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 qual ity 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; strengt hen new source performance standards and hazardous pollutant sections; tighten motor vehicle emissions standards.

Clean Air Act Amendments of 1990 Est ablish new provisions desi gned to reduce emissions of SO . Establish an 2 allowance system, based on a nationwide limit of 8.9 m illion 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 on Electric Utilities: An Update 60 

# An Act To Provide Research and Technical Assistance Relating to Air Pollution Control

Passed in 1955, an Act To P rovide 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 aboutby 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 pollutionproblem 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 toabatement” 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. Itauthorized 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 withinState boundaries where the ambient pollutant concentrations were below or met the NAAQS were designatedas “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 calledfor 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 specialimplementation 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 wherebyEnergy 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
hazard ous 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
hazar dous pollutant or 25 tons of any combination of pollutants.

The amendments establish a new permit program whereby all major sources are required to obtain anoperating 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 concurrentlyencouraging 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 SO 2 

### 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 Ph ase I units that had been required to be in compliance on January 1, 1995. NO

x 

### 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- andcyclone-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 2Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 

### 67Table B1. Profile of the 261 Table 1 Generators Affected by Phase IStateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)Alabama Alabama PowerE 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 1 5,158 4,278Alabama Alabama Power Gadsden 2 2 5,374 4,043TVAColbert 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 1Florida Gulf PowerCrist 6 370 18,695 27,469 9,678 1Crist 7 578 50,703 55,921 18,352 1 Florida Gulf Power Crist 4 4 9,953 3,849Florida Gulf Power Crist 5 5 9,374 3,071Florida Gulf Power Scholz 1 1 8,282 2,087Florida Gulf Power Scholz 2 2 8,572 2,561Tampa ElectricBig Bend ST2 446 26,387 53,820 35,489 1 Florida Tampa Electric Big Bend BB04 ST4 6,400 10,610Big Bend ST3 446 26,036 32,901 9,101 1 Florida Tampa Electric Big Bend BB04 ST4 6,400 10,610Big Bend 1 446 27,662 56,181 35,932 1 Florida Tampa Electric Big Bend BB04 ST4 6,400 10,610Georgia Georgia PowerBowen 1 806 54,838 71,428 32,617 1 Georgia Georgia Power Harllee Branch 1 1 19,221 12,295Bowen 2 789 53,329 63,727 39,641 1 Georgia Georgia Power Harllee Branch 2 2 22,735 15,135Bowen 3 952 69,862 82,488 42,137 1 Georgia Georgia Power Harllee Branch 3 3 31,280 26,085Bowen 4 952 69,852 87,659 46,258 1 Georgia Georgia Power Harllee Branch 4 4 31,042 27,944Hammond 1 125 8,549 9,830 3,516 1 Georgia Georgia Power Arkwright 1 ST1 2,437 795Hammond 2 125 8,977 9,997 1,834 1 Georgia Georgia Power Arkwright 2 ST2 2,240 667Hammond 3 125 8,676 9,068 2,047 1 Georgia Georgia Power Arkwright 3 3 3,944 971Hammond 4 578 36,650 35,539 14,297 1 Georgia Georgia Power Arkwright 4 4 3,159 701Jack 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 3 10,792 3,570Wansley 1 952 68,908 128,505 26,797 1Wansley 2 952 113,801 120,146 27,004 1 Georgia Georgia Power Scherer 3 3 0 22,868Yates 1 123 7,863 11,673 118 3See 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 

### 68Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)GeorgiaYates 2 123 6,855 11,199 2,267 1 Georgia SavannahElectric andPowerKraft 1 1 2,265 1,051Yates 3 123 6,767 11,279 1,787 1 Georgia SavannahElectric andPowerKraft 2 2 2,137 954Yates 4 156 8,676 13,758 1,738 1 Georgia SavannahElectric andPowerKraft 3 3 4,121 1,940Yates 5 156 9,162 15,754 2,141 1 Georgia SavannahElectric andPowerMcIntosh 1 1 7,146 6,611Yates 6 404 28,726 42,207 6,535 1Yates 7 404 22,318 23,974 5,683 1Illinois Central IllinoisPublic ServiceCoffeen 1 389 12,925 38,013 8,085 1Coffeen 2 617 39,102 102,616 23,143 1Grand Tower 4 114 6,479 9,754 6,950 2Meredosia 3 239 15,227 27,015 19,610 2 Illinois Central ILPublic ServiceCo.Meredosia 1 1 1,245 1,021Illinois Central ILPublic ServiceCo.Meredosia 2 1 1,355 985Illinois Central ILPublic ServiceCo.Meredosia 3 2 1,173 918Illinois Central ILPublic ServiceCo.Meredosia 4 2 1,078 1,101Illinois Central ILPublic ServiceCo.Meredosia 6 4 44 63Illinois Central ILPublic ServiceCo.Hutsonville 5 3 9,661 4,455Illinois Central ILPublic ServiceCo.Hutsonville 6 4 9,837 3,355See notes at end of tableEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 

### 69Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)IllinoisIllinois Central ILPublic ServiceCo.Newton 1 1 14,599 11,221Illinois Central ILPublic ServiceCo.Newton 2 2 6,346 12,258Illinois Central ILPublic ServiceCo.Grand Tower 7 3 1,068 1,043Illinois Central ILPublic ServiceCo.Grand Tower 8 3 1,015 1,017CommonwealthEdisonKincaid 1 660 34,564 94,042 4,292 1 Illinois CommonwealthEdisonCollins 1 1 1,263 153Illinois CommonwealthEdisonCollins 2 2 1,079 118Illinois CommonwealthEdisonCollins 3 3 1,905 104Kincaid 2 660 37,063 79,919 6,878 1 Illinois CommonwealthEdisonCollins 1 1 1,263 153Illinois CommonwealthEdisonCollins 2 2 1,079 118Electric Energy Inc.Illinois CommonwealthEdisonCollins 3 3 1,905 104Joppa 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 4 2,018 1,316Baldwin 2 635 48,695 78,477 104,172 2 Wyoming PacifiCorp Jim Bridger BW71 1 12,775 7,919Wyoming PacifiCorp Jim Bridger BW72 2 12,212 6,760Wyoming PacifiCorp Jim Bridger BW73 3 11,988 7,794Wyoming PacifiCorp Wyodak BW91 1 11,958 8,281See 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 

### 70Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)IllinoisUtah PacifiCorp Gadsby 3 3 766 2Baldwin 3 635 46,644 96,840 86,789 2 Illinois Illinois Power Havana 1 1-5 34 0Illinois Illinois Power Havana 2 1-5 43 0Illinois Illinois Power Havana 3 1-5 34 0Illinois Illinois Power Havana 4 1-5 34 0Illinois Illinois Power Havana 5 1-5 34 0Illinois Illinois Power Havana 6 1-5 34 0Illinois Illinois Power Havana 7 1-5 34 0Illinois Illinois Power Havana 8 1-5 34 0Illinois Illinois Power Wood River 1 1-3 0 0Hennepin 2 231 20,182 39,436 27,560 2Vermilion 2 109 9,735 18,600 1,706 5 Illinois Illinois Power Vermilion 1 ST1 12,972 917Indiana Hoosier Energy RECInc.Frank E. Ratts 1 117 9,131 19,069 10,038 1Frank E. Ratts 2 117 9,296 18,436 10,604 1Indiana MichiganPowerBreed 1 496 20,280 70,365 0 4Tanners Creek 4 580 27,209 59,646 29,318 1Indiana-KentuckyElectricClifty 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 IndianapolisPower &LightH T Pritchard 3 3 586 749Indiana IndianapolisPower &LightH T Pritchard 4 4 1,305 1,184See 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 

### 71Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)IndianaIndiana IndianapolisPower &LightH T Pritchard 5 5 1,458 1,353Indiana IndianapolisPower &LightPetersburg 3 ST3 15,471 20,479Indiana IndianapolisPower &LightPetersburg 4 4 12,864 21,041Petersburg ST2 471 35,496 53,110 42,075 3 Indiana IndianapolisPower &LightH T Pritchard 3 3 15,471 749Indiana IndianapolisPower &LightH T Pritchard 4 4 12,864 1,184Indiana IndianapolisPower &LightH T Pritchard 5 5 1,458 1,353Indiana IndianapolisPower &LightPetersburg 3 ST3 15,471 20,479Indiana IndianapolisPower &LightPetersburg 4 4 12,864 21,041Northern 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 2See 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 

### 72Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)Indiana Southern IndianaGas & ElectricFB Culley 2 104 4,703 16,361 564 3FB Culley 3 265 18,603 38,456 1,985 3Warrick 4 323 29,577 58,813 37,682 2Iowa Interstate PowerMilton L Kapp 2 219 13,437 31,379 7,450 1Iowa Electric Light &PowerPrairie Creek 4 149 7,965 12,466 5,279 1Iowa PowerDes Moines 7 114 2,259 2,490 0 4Iowa Public ServiceGeorge Neal North 1 147 2,571 1,048 3,812 1Iowa SouthernUtilitiesBurlington 1 212 10,428 23,093 9,020 1Iowa-Illinois Gas &ElectricRiverside 5 136 3,885 4,707 1,828 1Kansas City of Kansas CityQuindaro ST2 158 4,109 3,255 2,893 1Kentucky Big Rivers ElectricColeman 1 174 20,912 18,537 15,759 2 Kentucky Big Rivers R D Green G1 1 5,041 1,580Kentucky Big Rivers R D Green G2 2 6,073 1,689Coleman 2 174 19,363 19,862 18,500 2 Kentucky Big Rivers R D Green G1 1 5,041 1,580Kentucky Big Rivers R D Green G2 2 6,073 1,689Coleman 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 1See notes at end of tableEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 

### 73Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)Kentucky Kentucky UtilitiesE 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 1Maryland 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 AlabamaElectric CoopCharlesLowman2 2 6,226 4,443Alabama AlabamaElectric CoopCharlesLowman3 3 5,281 4,586Mississippi South MS ElPower Assn.R D Morrow 1 1 4,571 2,914Mississippi South MS ElPower Assn.R D Morrow 2 2 5002 3,618Potomac ElectricPowerChalk Point ST1 364 25,403 20,258 18,660 1 Maryland PEPCO Chalk Point 4 4 1,519 1,354Chalk Point ST2 364 23,690 27,482 22,427 1 Maryland PEPCO Chalk Point 4 4 1,519 1,354Morgantown ST1 626 39,864 29,388 28,040 1 Maryland PEPCO Chalk Point 3 3 9,000 3,010Morgantown ST2 626 45,592 37,988 38,515 1 Maryland PEPCO Chalk Point 3 3 9,000 3,010Michigan Consumers PowerJ H Campbell 1 265 18,773 27,180 10,175 1 Michigan ConsumersPowerDan E Karn 1 1 10,151 7,272Michigan ConsumersPowerJ R Whiting 2 2 4,304 4,251Michigan ConsumersPowerJ R Whiting 3 3 5,498 4,807J H Campbell 2 385 22,453 33,350 2,996 1 Michigan ConsumersPowerDan E Karn 1 1 10,151 7,272Michigan ConsumersPowerJ R Whiting 2 2 4,304 4,251Michigan ConsumersPowerJ R Whiting 3 3 5498 4,807See 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 

### 74Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)Minnesota Northern StatesPowerHigh Bridge 6 163 4,158 2,176 1,493 1 Minnesota Northern StatesPowerHigh Bridge 3 3 1,771 233Minnesota Northern StatesPowerHigh Bridge 4 4 1,326 426Minnesota Northern StatesPowerHigh Bridge 5 5 2,436 888Minnesota Northern StatesPowerSherburne Co. 1 1 10,420 4,681Minnesota Northern StatesPowerSherburne Co. 2 2 10,493 4,782Mississippi Mississippi PowerJack Watson 4 250 17,439 26,218 18,577 2Jack Watson 5 500 35,734 46,401 38,044 2 Mississippi MississippiPowerVictor J Daniel 1 1 9,427 7,917Mississippi MississippiPowerVictor J Daniel 2 2 9,851 10,168Missouri Associated ElectricCoopNew Madrid 1 600 27,497 74,430 8,827 1New Madrid 2 600 31,625 77,895 7,926 1Thomas Hill 1 180 9,980 35,874 2,817 1 Missouri AssociatedElectric CoopThomas Hill MB3 3 14,011 10,404Thomas Hill 2 285 18,880 56,866 3,749 1 Missouri AssociatedElectric CoopThomas Hill MB3 3 14,011 10,404City of SpringfieldJames River 5 105 4,722 9,096 2,054 1 Missouri City ofSpringfieldJames River 3 3 3,802 744Missouri City ofSpringfieldJames River 4 4 6,828 966Missouri City ofSpringfieldSouthwest 1 ST1 3,922 2,144Empire DistrictElectricAsbury 1 213 15,764 68,769 8,112 1Kansas City Power &LightMontrose 1 188 7,196 28,740 2,317 1 Missouri Kansas CityP&LHawthorn 5 5 25,734 5,634Missouri Kansas CityP&LIatan 1 1 14,479 19,289See 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 

### 75Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)MissouriKansas Kansas CityP&LLa Cygne 1 1 23,489 3,872Kansas Kansas CityP&LLa Cygne 2 2 12,682 22,284Montrose 2 188 7,984 32,165 2,735 1 Missouri Kansas CityP&LHawthorn 5 5 25,734 5,634Missouri Kansas CityP&LIatan 1 1 14,479 19,289Kansas Kansas CityP&LLa Cygne 1 1 23,489 3,872Missouri Kansas CityP&LLa Cygne 2 2 12,682 22,284Montrose 3 188 9,824 35,192 2,909 1 Missouri Kansas CityP&LHawthorn 5 5 25,734 5,634Missouri Kansas CityP&LIatan 1 1 14,479 19,289Kansas Kansas CityP&LLa Cygne 1 1 23,489 3,872Kansas Kansas CityP&LLa Cygne 2 2 12,682 22,284Union ElectricLabadie1 574 125,282 72,811 23,321 1 Missouri Union Electric Meramec 1 1 1,816 1,852Missouri Union Electric Meramec 2 2 1,948 1,209Missouri Union Electric Meramec 3 3 4,166 4,702Missouri Union Electric Meramec 4 4 4,507 5,161Missouri Union Electric Rush Island 1 1 26,935 21,412Missouri Union Electric Rush Island 2 2 30,146 22,209Labadie 2 574 117,392 63,653 23,236 1 Missouri Union Electric Meramec 1 1 1,816 1,852Missouri Union Electric Meramec 2 2 1,948 1,209Missouri Union Electric Meramec 3 3 4,166 4,702Missouri Union Electric Meramec 4 4 4,507 5,161Missouri Union Electric Rush Island 1 1 26,935 21,412Missouri Union Electric Rush Island 2 2 30,146 22,209Labadie 3 621 111,919 67,587 38,025 1 Missouri Union Electric Meramec 1 1 1,816 1,852Missouri Union Electric Meramec 2 2 1,948 1,209Missouri Union Electric Meramec 3 3 4,166 4,702Missouri Union Electric Meramec 4 4 4,507 5,161Missouri Union Electric Rush Island 1 1 26,935 21,412Missouri Union Electric Rush Island 2 2 30,146 22,209See 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 

### 76Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)MissouriLabadie 4 621 106,044 65,591 44,223 1 Missouri Union Electric Meramec 1 1 1,816 1,852Missouri Union Electric Meramec 2 2 1,948 1,209Missouri Union Electric Meramec 3 3 4,166 4,702Missouri Union Electric Meramec 4 4 4,507 5,161Missouri Union Electric Rush Island 1 1 26,935 21,412Missouri Union Electric Rush Island 2 2 30,146 22,209Sioux 1 550 25,603 42,688 27,477 1 Missouri Kansas CityPower &LightHawthorn 5 5 25,734 5,634Missouri Kansas CityPower &LightIatan 1 1 14,479 19,289Kansas Kansas CityPower &LightLa Cygne 1 1 23,489 3,872Kansas Kansas CityPower &LightLa Cygne 2 2 12,682 22,284Sioux 2 550 23,067 14,504 20,379 1 Missouri Kansas CityPower &LightHawthorn 5 5 25,734 5,634Missouri Kansas CityPower &LightIatan 1 1 14,479 19,289Missouri Kansas CityPower &LightLa Cygne 1 1 23,489 3,872Missouri Kansas CityPower &LightLa Cygne 2 2 12,682 22,284Utilcorp UnitedSibley 3 419 15,170 26,812 9,417 1 Missouri UtilCorp United Sibley 1 1 2,810 1,414Missouri UtilCorp United Sibley 2 2 3,462 1,382NewHampshirePublic Service ofNew HampshireMerrimack 1 114 9,922 15,258 10,450 1 NewHampshirePublic Serviceof NHNewington 1 1 20,127 11,155Massachusetts Holyoke WaterPowerMount Tom 1 1 10,708 8,223Merrimack 2 346 21,421 38,980 25,678 1 NewHampshirePublic Serviceof NHNewington 1 1 20,127 11,155Massachusetts Holyoke WaterPowerMount Tom 1 1 10,708 8,223New Jersey Atlantic City ElectricBL England 1 136 14,365 16,300 18,101 2BL England 2 163 18,357 17,822 3,619 3New York Long Island LightingNorthport ST1 387 19,824 26,583 4,114 5 New York LILCO Northport 4 4 5,516 538Northport 2 387 23,476 25,915 2,228 5 New York LILCO Northport 4 4 5,516 538See 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 

### 77Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 

### 77Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)New YorkNorthport 3 387 25,783 27,360 4,047 5 New York LILCO Northport 4 4 5,516 538Port Jefferson 3 188 10,194 10,602 3,640 5 New York LILCO Northport 4 4 5,516 538Port Jefferson 4 188 12,006 12,195 2,636 5 New York Northport 4 4 5,516 538New 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 NiagaraMohawkC R Huntley 63 63 5,460 3,497New York NiagaraMohawkC R Huntley 64 64 5,803 3,350New York NiagaraMohawkC R Huntley 65 65 5,969 6,265New York NiagaraMohawkC R Huntley 66 66 5,916 6,866New York NiagaraMohawkOswego 3 3 86 0New York NiagaraMohawkOswego 4 4 379 0New York NiagaraMohawkOswego 5 ST5 14,898 0New York NiagaraMohawkOswego 6 ST6 4,578 837New York Central HudsonG&ERoseton 1 1 19,147 1,607New York Central HudsonG&ERoseton 2 2 16,872 2,381Dunkirk 3 218 13,162 18,214 15,560 2 New York NiagaraMohawkC R Huntley 63 63 5,460 3,497New York NiagaraMohawkC R Huntley 64 64 5,803 3,350New York NiagaraMohawkC R Huntley 65 65 5,969 6,265New York NiagaraMohawkC R Huntley 66 66 5,916 6,866New York NiagaraMohawkOswego 3 3 86 0New York NiagaraMohawkOswego 4 4 379 0See 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 

### 78Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)New YorkNew York NiagaraMohawkOswego 5 ST5 14,898 0New York NiagaraMohawkOswego 6 ST6 4,578 837New York Central HudsonG&ERoseton 1 1 19,147 1,607New York Central HudsonG&ERoseton 2 2 16,872 2,381Ohio Cardinal OperatingCo.Cardinal 1 615 84,106 69,012 83,160 2Cardinal 2 615 42,008 71,532 22,146 1Cincinnati Gas &ElectricMiami Fort 5d100 834 262 332 1Miami Fort 6 163 12,475 21,111 3,862 1Miami Fort 7 557 42,216 62,456 21,301 1 Kentucky Cinergy East Bend 2 2 17,447 11,378Walter C Beckjord 5 245 9,822 12,735 8,347 1Walter C Beckjord 6 461 25,235 39,140 17,479 1Cleveland ElectricIllum.Ashtabula 5 256 18,351 37,621 18,183 2 Ohio Toledo Edison Acme 13 1,4,5,TOPR 9 0Ohio Toledo Edison Acme 14 1,4,5,TOPR 13 0Ohio Toledo Edison Acme 15 1,4,5,TOPR 17 0Ohio Toledo Edison Acme 16 2 1,930 0Ohio Toledo Edison Acme 91 6 740 0Ohio Toledo Edison Acme 92 6 662 0Ohio ClevelandElectric Illum.Lake Shore 18 18 4,767 0Ohio ClevelandElectric Illum.Lake Shore 91 14 44 0Ohio ClevelandElectric Illum.Lake Shore 92 15 80 0Ohio ClevelandElectric Illum.Lake Shore 93 16 62 0Ohio ClevelandElectric Illum.Lake Shore 94 17 102 0Ohio Toledo Edison Bay Shore 1 1 7,546 5,901Ohio Toledo Edison Bay Shore 2 2 7,311 5,722Ohio Toledo Edison Bay Shore 3 3 7,585 5,920Ohio Toledo Edison Bay Shore 4 4 12,481 7,508See 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 

### 79Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)OhioAvon Lake 8 233 12,771 16,952 0 4Avon Lake 9 680 33,413 41,322 21,921 1 Ohio ClevelandElectric Illum.Avon Lake 9 6 9,849 2,594Ohio ClevelandElectric Illum.Avon Lake 10 7 8,648 3,309Eastlake 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 Powerand LightJ M Stuart 1 1 41,189 22,861Ohio Dayton Powerand LightJ M Stuart 2 2 39,041 31,903Ohio Dayton Powerand LightJ M Stuart 3 3 38,712 25,034Ohio Dayton Powerand LightJ M Stuart 4 4 40,925 27,841Picway 5 106 11,967 13,671 4,722 2 Ohio ColumbusSouthernPoston 1 1 3,797 0Ohio ColumbusSouthernPoston 2 2 3,542 0Ohio ColumbusSouthernPoston 3 3 4,642 0Edgewater 4 114 5,536 6,149 10 5 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532See 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 

### 80Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)OhioPennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0Massachusetts New EnglandPowerBrayton Point 1 1 15,085 11,379Massachusetts New EnglandPowerBrayton Point 2 2 15,838 11,130Massachusetts New EnglandPowerBrayton Point 3 3 32,977 21,915Massachusetts New EnglandPowerBrayton Point 4 4 21,238 7,564Massachusetts New EnglandPowerSalem Harbor 1 1 6,555 3,206Massachusetts New EnglandPowerSalem Harbor 2 2 6,696 3,141Massachusetts New EnglandPowerSalem Harbor 3 3 10,727 5,852Niles 2 133 14,806 16,264 12,340 3 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0Niles 1 133 18,240 14,054 13,080 1 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708See 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 

### 81Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)OhioOhio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0R E Burger 3e104 9,383 12,965 2,252 2 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0See 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 

### 82Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)OhioR E Burger 4 156 21,973 21,956 13,826 2 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0R E Burger 5 156 23,127 25,973 23,539 2 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0See 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 

### 83Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)OhioW H Sammis 5 334 26,496 34,632 12,627 1 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0W H Sammis 6 680 43,773 61,391 27,041 1 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0See 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 

### 84Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)OhioW H Sammis 7 680 47,380 54,557 22,162 1 Ohio Ohio Edison Edgewater 11 2, 3 1,062 0Ohio Ohio Edison Edgewater 12 2, 3 1,145 0Ohio Ohio Edison R E Burger 1 1 2,820 708Ohio Ohio Edison R E Burger 2 1 2,751 604Ohio Ohio Edison R E Burger 3 2 2,891 518Ohio Ohio Edison R E Burger 4 2 2,956 212Ohio Ohio Edison Gorge 25 6 2,553 0Ohio Ohio Edison Gorge 26 7 2,860 0Ohio Ohio Edison Toronto 9 5, 6, 7 5,325 0Ohio Ohio Edison Toronto 10 5, 6, 7 9,505 0Ohio Ohio Edison Toronto 11 5, 6, 7 10,274 0Pennsylvania PennsylvaniaPowerBruceMansfield1 1 10,510 7,388Pennsylvania PennsylvaniaPowerBruceMansfield2 2 11,537 5,532Pennsylvania PennsylvaniaPowerNew Castle 1 1, 2 1,367 0Pennsylvania PennsylvaniaPowerNew Castle 2 1, 2 1,520 0Ohio PowerGen Jm Gavin 1 1,300 192,637 177,338 11,945 3Gen Jm Gavin 2 1,300 188,168 185,911 11,533 3Muskingum 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 1Pennsylvania Duquesne LightCheswick 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 2See 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 

### 85Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/CompensatingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)Pennsylvania PennsylvaniaElectric 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 MonongahelaPowerAlbright 1 1 4,831 2,386Armstrong 2 163 15,024 15,423 17,196 2 West Virginia MonongahelaPowerAlbright 2 2 5,024 2,358Hatfield's Ferry 1 576 55,732 54,286 66,839 2 West Virginia MonongahelaPowerPleasants 1 1 16,762 23,614Hatfield's Ferry 2 576 57,506 51,986 47,799 2 West Virginia MonongahelaPowerPleasants 2 2 19,230 23,704Hatfield's Ferry 3 576 56,580 54,809 50,203 2 Pennsylvania West PennPowerMitchell 33 3 1,101 835Tennessee TVAAllen 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 2See 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 

### 86Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)TennesseeJohnsonville 1 125 7,585 11,123 9,722 2Johnsonville 2 125 7,828 10,657 9,278 2Johnsonville 3 125 8,189 9,712 8,543 2Johnsonville 4 125 7,780 8,968 9,853 2Johnsonville 5 147 8,023 8,544 12,233 2Johnsonville 6 147 7,682 8,767 10,583 2Johnsonville 7 173 8,744 10,389 15,784 2Johnsonville 8 173 8,471 10,207 12,397 2Johnsonville 9 173 6,894 8,922 13,292 2Johnsonville 10 173 7,351 8,835 12,991 2West Virginia MonongahelaPowerAlbright 3 140 11,684 11,938 11,444 2 Maryland PotomacEdisonR P Smith 9 3 386 118Fort Martin 1 576 41,905 44,309 26,803 2Fort Martin 2 576 44,118 44,824 43,171 2 Maryland PotomacEdisonRP Smith 11 4 3,128 1,536Harrison 1 684 82,613 78,231 3,323 3 West Virginia MonongahelaPowerRivesville 7 5 1,009 488West Virginia MonongahelaPowerRivesville 8 6 3,059 1,357Harrison 2 684 91,180 78,231 3,373 3Harrison 3 684 90,727 78,231 3,249 3 West Virginia MonongahelaPowerWillow Island 1 1 1,855 2,099West Virginia MonongahelaPowerWillow Island 2 2 7,765 7,908Ohio 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 3See 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 

### 87Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofComplianceMethodcSubstitution/CompensatingStateSubstitution/CompensatingUtilitySubstitution/Compen-satingPlantSubstitution/CompensatingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)Wisconsin Dairyland PowerCoop.Genoa ST3 346 22,103 35,035 15,304 1 Wisconsin DairylandPower CoopAlma B4 4 5,105 572Wisconsin DairylandPower CoopAlma B5 5 8,155 2,192Wisconsin 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 1 1,968 1,432Wisconsin WEPCO Port Washington 2 2 3,782 3,555Wisconsin WEPCO Port Washington 3 3 3,108 3,869Wisconsin WEPCO Port Washington 4 4 2,745 2,242Wisconsin WEPCO Port Washington 5 5 3,412 0Wisconsin WEPCO Valley 1 1 3,675 4,299Wisconsin WEPCO Valley 2 1 3,713 4,219Wisconsin WEPCO Valley 3 2 3,404 3,627Wisconsin WEPCO Valley 4 2 3,311 3,420South 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 3 4,493 1,166Wisconsin DairylandPower CoopJ P Madgett B1 1 6,862 5,746Nelson Dewey 1 100 5,852 13,289 2,046 1 Wisconsin WEPCO Rock River 1 1 5,398 1,637Wisconsin WEPCO Rock River 2 2 4,034 1,434Nelson Dewey 2 100 6,504 12,273 2,081 1 Wisconsin WEPCO Rock River 1 1 5,398 1,637Wisconsin WEPCO Rock River 2 2 4,034 1,434Pulliam 8 136 7,312 10,446 2,087 1 Wisconsin WisconsinPublic ServicePulliam 5 5 2,097 432See 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 

### 88Table B1. Profile of the 261 Table 1 Generators Affected by Phase I (Continued)StateOperating Utility/PlantGeneratorNumberaAffectedNameplateCapacity(megawatts)1995AllowancebAllocations1985 SO2EmissionsEstimates(tons)1995 SO2Emissions(tons)Code ofCom-plianceMethodcSubstitution/Compen-satingStateSubstitution/Compen-satingUtilitySubstitution/Compen-satingPlantSubstitution/Compen-satingBoilersAffectedGenerators1985 SO2EmissionsEstimates(tons)1995Sub/CompSO2Emissions(tons)WisconsinWisconsin WisconsinPublic ServicePulliam 6 6 2,844 720Wisconsin WisconsinPublic ServicePulliam 7 7 7,317 1,466Wisconsin WisconsinPublic ServiceWeston 1 1 1,579 969Wisconsin WisconsinPublic ServiceWeston 2 2 3,580 1,936Wisconsin WisconsinPublic ServiceWeston 3 3 6,555 7,478Cincinnati 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 number of Table 1 generators is 261.aOne SO allowance permits one ton of SO emissions.b2 2The 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–includes repowering, switching to natural gas orcpetroleum.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.d2R.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.e2SO = Sulfur dioxide.2TVA = 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.Capacity: Energy Information Administration, Inventory

of Power Plants 1992, DOE/EIA-0095(92) (Washington, DC, October 1993).1985 Emissions: U.S. Environmental Protection Agency, National Allowance Data Base, Versions 2.11 (January 1993).1995 Emissions: U.S.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
Unknown 1 .......................................................................................... 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 Utilities 1

## 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 2

## 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 Utilities 3

## 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
Unknown 1 .......................................................................................... 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 4

## 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 Utilities 5

## 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 6

## 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 Utilities 7

## 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 8

## 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 Utilities 9

## 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
Unknown 1 .......................................................................................... 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 10

## 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 Utilities 11

## 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 Unknown 1 .......................................................................................... 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 12

## 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 Transfer 2

................................................ 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 Utilities 13

## 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.



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 14

## 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 Utilities 15

## 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.’’



## Energy Information Administration/The Effects of the Clean Air Act Amendments of 1990 on Electric Utilities 16

# Appendix C



# Costs and Characteristics of Selected Phase I Units, by UtilityEnergy 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 ut ility was as ked 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 c osts for all units affected by Phase I and to provideEnergy 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 on Electric Utilities: An Update 110 Illinois Power Company b

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 w ith Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power,
and Southern Indi ana 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 111Table C2. Cost of Phase I Compliance for Selected Units, by UtilityType of Unit Unit PlantNumberaofLow-NOxBurnersNumberaof CEMsNumberaofScrubbersSO Control2NOxControl CEMSTotalCapitalCostAnnualO&MCostAverageCapitalCost(dollars/KWaffected)CapitalCostO&MCostCapitalCostCapitalCostO&MCostmillion dollarsCincinnati Gas & Electric CompanyTable 1......... 5Miami Fort 0.0 0.5 0.0 0.00 0.00 0.00 0.59 c 0.59 0.00 5.90Table 1......... 6Miami Fort 0.0 0.5 0.0 2.24 c 0.00 0.62 c 2.86 0.00 17.51Table 1......... 7Miami Fort * 0.0 0.6 0.0 4.89 c 0.00 0.52 c 5.41 0.00 16.90Table 1......... 5Beckjord 1.0 1.0 0.0 5.28 c 5.00 0.90 c 11.17 0.00 46.94Table 1......... 6Beckjord * 0.4 0.4 0.0 0.00 0.00 1.90 0.29 c 2.19 0.00 13.89Table 1......... 4Conesville * 0.0 0.4 0.0 0.00 b 0.00 b c b 0.00 bSubstitution...... 2East Bend* 0.0 0.7 1.0 b b 0.00 0.61 b 0.61 b 1.47Substitution. . . . . . 1 J. M.Stuart* 0.0 0.4 0.0 b b0.00 b b b b bSubstitution. . . . . . 2 J. M.Stuart* 0.0 0.4 0.0 b b0.00 b b b b bSubstitution. . . . . . 3 J. M.Stuart* 0.0 0.4 0.0 b b0.00 b b b b bSubstitution. . . . . . 4 J. M.Stuart* 0.0 0.4 0.0 b b0.00 b b b b bTotal for Utility . . 1.4 5.7 1.012.40 b 6.90 3.53 b 22.83 b 16.39Georgia Power CompanyTable 1......... 1Bowen 1.0 1.0 0.0 0.40 0.00 7.19 0.74 b 8.33 0.00 10.34Table 1......... 2Bowen 1.0 1.0 0.0 0.27 0.00 8.23 0.82 b 9.32 0.00 11.82Table 1......... 3Bowen 1.0 1.0 0.0 2.06 0.00 9.11 0.61 b 11.78 0.00 12.37Table 1......... 4Bowen 1.0 1.0 0.0 1.94 0.00 9.28 0.55 b 11.77 0.00 12.36Table 1......... 1Hammond 0.0 0.5 0.0 1.45 0.00 0.00 0.53 b 1.98 0.00 15.84Table 1......... 2Hammond 0.0 0.5 0.0 2.77 0.00 0.00 0.73 b 3.50 0.00 28.00Table 1......... 3Hammond 0.0 0.5 0.0 0.64 0.00 0.00 0.47 b 1.16 0.00 8.88Table 1......... 4Hammond 1.0 0.5 0.0 1.00 0.00 22.00 0.45 b 23.45 0.00 40.57Table 1......... 1McDonough 1.0 0.5 0.0 2.35 0.00 9.18 0.62 b 12.15 0.00 40.61Table 1......... 2McDonough 1.0 0.5 0.0 2.34 0.00 8.47 0.48 b 11.29 0.00 37.73Table 1......... 1Wansley * 0.5 0.3 0.0 2.51 0.00 9.13 0.77 b 12.41 0.00 24.37Table 1......... 2Wansley * 0.5 0.3 0.0 2.15 0.00 5.95 0.59 b 8.69 0.00 17.06Table 1......... 1Yates (d) 0.0 0.7 1.0 17.00 2.00 0.00 0.78 b 17.78 2.00 145.14Table 1......... 2Yates 0.0 0.7 0.0 1.98 0.00 0.00 0.47 b 2.45 0.00 20.00Table 1......... 3Yates 0.0 0.7 0.0 1.53 0.00 0.00 0.40 b 1.93 0.00 15.76Table 1......... 4Yates 1.0 0.7 0.0 1.59 0.00 2.07 0.40 b 4.06 0.00 25.98Table 1......... 5Yates 1.0 0.7 0.0 1.36 0.00 2.07 0.33 b 3.76 0.00 24.06Table 1......... 6Yates 1.0 0.7 0.0 1.82 0.00 6.13 0.85 b 8.80 0.00 21.79See 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 112Table C2. Cost of Phase I Compliance for Selected Units, by Utility (Continued)Type of Unit Unit PlantNumberaofLow-NOxBurnersNumberaof CEMsNumberaofScrubbersSO Control2NOxControl CEMSTotalCapitalCostAnnualO&MCostAverageCapitalCost(dollars/KWaffected)CapitalCostO&MCostCapitalCostCapitalCostO&MCostmillion dollarsTable 1......... 7Yates 1.0 0.7 0.0 1.89 0.00 6.51 0.52 b 8.92 0.00 22.09Table 1......... 1Gaston * 0.5 0.5 0.0 0.00 0.00 2.00 0.25 c 2.25 0.00 16.54Table 1......... 2Gaston * 0.5 0.5 0.0 0.00 0.00 3.00 0.25 c 3.25 0.00 23.90Table 1......... 3Gaston * 0.5 0.5 0.0 0.00 0.00 7.00 0.25 c 7.25 0.00 53.31Table 1. . . . . . . . . ST4Gaston * 0.5 0.5 0.0 0.00 0.00 3.00 0.25 c 3.25 0.00 26.55Substitution. . . . . . ST1Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.34 b 0.34 0.00 7.39Substitution. . . . . . ST2Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.27 b 0.27 0.00 5.87Substitution...... 3Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.30 b 0.30 0.00 7.50Substitution...... 4Arkwright 0.0 0.3 0.0 0.00 0.00 0.00 0.30 b 0.30 0.00 6.12Substitution...... 1Harlee Branch 0.0 0.5 0.0 0.00 0.00 0.00 0.34 b 0.34 0.00 1.14Substitution...... 2Harlee Branch 1.0 0.5 0.0 0.00 0.00 5.00 0.87 b 5.87 0.00 16.35Substitution...... 3Harlee Branch 0.0 0.5 0.0 0.00 0.00 0.00 0.30 b 0.30 0.00 0.55Substitution...... 4Harlee Branch 0.0 0.5 0.0 0.00 0.00 0.00 0.30 b 0.30 0.00 0.55Substitution...... 3Mitchell 0.0 1.0 0.0 0.00 0.00 0.00 1.23 b 1.23 0.00 7.55Substitution...... 3Scherer* 0.0 1.0 0.0 0.00 0.00 0.00 0.77 b 0.77 0.00 10.27Total for Utility .15.1 19.4 1.0 47.05 2.00 125.32 17.13 b 189.50 2.00 18.48Illinois Power CompanyTable 1......... 1Baldwin (e) 0.0 1.0 0.0 34.60 3.90 0.00 2.10 0.10 36.70 4.00 58.90Table 1......... 2Baldwin 0.0 1.0 0.0 0.00 7.40 0.00 2.20 0.10 2.20 7.50 3.47Table 1......... 3Baldwin 1.0 1.0 0.0 0.00 5.40 9.00 2.10 0.10 11.10 5.50 17.49Table 1......... 2Hennepin 0.0 1.0 0.0 0.00 1.70 0.00 1.90 0.10 1.90 1.80 8.21Table 1. . . . . . . . . 1&2Vermilion(f) 1.0 2.0 0.0 0.00 0.10 3.70 1.70 0.10 5.40 0.20 29.51Substitution. . . . . . 1-6Havana 0.0 4.0 0.0 0.00 0.00 0.00 2.60 0.20 2.60 0.20 11.30Substitution. . . . . . 1&4Wood River 0.0 3.0 0.0 0.00 0.00 0.00 2.60 0.20 2.60 0.20 15.95Total for Utility . 2.013.0 0.0 34.60 18.50 12.70 15.20 0.90 62.50 19.40 23.15Potomac Electric Power CompanyTable 1. . . . . . . . . ST1Chalk Point 1.0 0.5 0.0 15.00 b 18.10 1.60 b 34.70 0.00 95.33Table 1. . . . . . . . . ST2Chalk Point 1.0 0.5 0.0 15.00 b 18.10 1.60 b 34.70 0.00 95.33Table 1. . . . . . . . . ST1Morgantown 1.0 1.0 0.0 0.00 b 40.20 3.10 b 43.30 0.00 69.17Table 1. . . . . . . . . ST2Morgantown 1.0 1.0 0.0 0.00 b 40.20 3.10 b 43.30 0.00 69.17Table 1......... 1Conemaugh * 1.0 1.0 0.1 16.20 0.90 2.00 0.10 0.00 18.30 0.90 201.14Table 1......... 2Conemaugh * 1.0 0.5 0.1 16.20 0.90 2.00 0.10 0.00 18.30 0.90 201.14See 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 113Table C2. Cost of Phase I Compliance for Selected Units, by Utility (Continued)Type of Unit Unit PlantNumberaofLow-NOxBurnersNumberaof CEMsNumberaofScrubbersSO Control2NOxControl CEMSTotalCapitalCostAnnualO&MCostAverageCapitalCost(dollars/KWaffected)CapitalCostO&MCostCapitalCostCapitalCostO&MCostmillion dollarsSubstitution...... 3Chalk Point 0.0 1.0 0.0 0.00 0.00 0.00 1.60 b 1.60 b 2.43Substitution...... 4Chalk Point 0.0 1.0 0.0 0.00 0.00 0.00 1.60 b 1.60 b 2.43Total for Utility.6.0 6.5 0.2 62.40 1.80 120.60 12.80 b 195.80 1.80 56.27Pennsylvania Power & Light CompanyTable 1......... 1Brunner Island 1.0 0.5 0.0 0.00 b 13.00 1.20 b 14.20 0.00 39.12Table 1......... 2Brunner Island 1.0 0.5 0.0 3.00 b 15.00 1.20 b 19.20 0.00 47.41Table 1......... 3Brunner Island 1.0 1.0 0.0 0.00 b 17.00 2.40 b 19.40 0.00 24.56Table 1......... 1Martins Creek 1.0 1.0 0.0 2.00 b 6.00 1.25 b 9.25 0.00 59.29Table 1......... 2Martins Creek 1.0 1.0 0.0 2.00 b 5.00 1.25 b 8.25 0.00 52.88Table 1......... 3Sunbury 1.0 0.5 0.0 1.50 b 5.00 1.80 b 8.30 0.00 79.81Table 1......... 4Sunbury 1.0 0.5 0.0 1.70 b 5.30 1.80 b 8.80 0.00 56.41Table 1......... 1Conemaugh * 0.1 0.1 0.1 20.50 1.10 2.20 0.10 0.00 22.80 1.10 213.86Table 1......... 2Conemaugh * 0.1 0.1 0.1 20.50 1.10 2.20 0.10 0.00 22.80 1.10 213.86Total for Utility.7.2 5.2 0.2 51.20 2.20 70.70 11.10 b 133.00 2.20 56.76Southern Indiana Gas & Electric CompanyTable 1......... 2Culley 1.0 1.0 0.5 28.84 1.12 1.41 0.75 0.06 31.00 1.18 298.90Table 1......... 3Culley 1.0 1.0 0.5 74.16 2.88 3.59 0.75 0.06 78.50 2.94 296.02Table 1......... 4Warrick * 0.0 0.5 0.00.00 0.00 0.00 1.30 0.04 1.30 0.04 8.05Total for Utility.2.0 2.5 1.0 103.00 4.00 5.00 2.80 0.16 110.80 4.16 208.90Note: 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.aCosts not estimated.bEstimated to be negligible by utility.cIncludes only one-half of scrubber capital costs. The other half is paid by the Department of Energy as a demonstration project.dInstallation of the scrubber for the Baldwin 1 unit was suspended in 1992.eVermillion 1 is a substitution unit.f*Partially owned unit.CEMS = Continuous emission monitoring systems.NO = Nitrogen oxides.xSO = Sulfur dioxide.2KW = Kilowatts.Sources: Personal contact with Illinois Power, Pennsylvania Power and Light, Potomac Electric Power, Cincinnati Gas and Electric, Georgia Power, and Southern Indiana Gasand 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 P otter, 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 theEnergy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 116 

### 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 f ossil 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, hydroelectricEnergy 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 dis charge to the atmosphere. Particulate collectors
include electr ostatic 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 foroperations 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 on Electric Utilities: An Update 118 

### 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-storageplants 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.

Subst itution 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 byweight 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.