DOE/EIA-0582(97) Distribution Category UC-950 The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update March 1997 Energy Information Administration Office of Coal, Nuclear, Electric and Alternate Fuels U.S. Department of Energy Washington, DC 20585 This report was prepared by the Energy Information Administration, the independent statistical and analytical agency within the Department of Energy. The information contained herein should not be construed as advocating or reflecting any policy position of the Department of Energy or of any other organization. Contacts
This report was prepared by the staff of the Coal and Electric Analysis Branch , Analysis and Systems Division, Office of Coal, Nuclear, Electric and Alternate Fuels. General information regarding this publication may be obtained from Robert M. Schnapp, Director, Analysis and Systems Division (202/426-1211, or e-mail at rschnapp@eia.doe.gov) or Betsy O'Brien, Chief, Coal and Electric Analysis Branch (202/426-1180, or e-mail at bobrien@eia.doe.gov). Specific questions regarding the preparation and content of the report should be directed to Art Fuldner, project manager (202/426-1125, or e-mail at afuldner@eia.doe.gov), or contributing authors Ronald Hankey (202/426-1188, or e-mail at rhankey@eia. doe.gov), William Liggett (202/426-1139, or e-mail at wliggett@eia.doe.gov), and Thelda McMillian (202/4261127, or e-mail at tmcmilli@eia.doe.gov). ii Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update Preface
Section 205(a)(2) of the Department of Energy Organization Act of 1977 (Public Law 95-91) requires the Administrator of the Energy Information Administration (EIA) to carry out a central, comprehensive, and unified energy data information program that will collect, evaluate, assemble, analyze, and disseminate data and information relevant to energy resources, reserves, production, demand, technology, and related economic and statistical information. To assist in meeting these responsibilities in the area of electric power, EIA has prepared this report, 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 will be listed in the "Publications" section. The "Applications" section can be reached by scrolling down through the "Data" section. From this point, the Clean Air Act browser can be downloaded. The browser has information about compliance activities, fuel shifts, emissions, allowance allocations, and scrubbers. 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 iii Contents
Page Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii 1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 SO2 Compliance Results in 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Contents of This Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 2. Phase I Effects on Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compliance Options for Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compliance Methods Chosen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Electric Utility Compliance Strategies, Costs, and Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3. Phase I Effects on Coal Supply and Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compliance and Fuel Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compliance and Coal Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compliance and Coal Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4. Developments Since Phase I Took Effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Programs for the Control of Nitrogen Oxides Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Discussion of Air Toxics­Title III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technology Refinements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5. Phase II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current Strategies for Phase II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Synergy With Clean Air Act Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Utility Compliance Plans on the Internet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 5 5 11 23 23 24 24 39 39 41 42 45 45 48 54 6. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Appendices A. Federal Legislation To Control Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 B. Profiles of the 261 Table 1 Generators Affected by Phase I (Table B1) and a Profile of the Coal Received at Table 1 Plants (Table B2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 C. Cost and Characteristics of Selected Phase I Units, by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105 Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115 Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update v Tables
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. A1. B1. B2. C1. C2. Page SO2 Emissions From Electric Utilities, 1985, 1990, 1994, and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Profile of Compliance Methods for Table 1 Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 PEPCO's 1995 Allowance Totals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Scrubber Retrofits for Compliance With Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Annualized SO 2 Compliance Cost for CAAA90 Title IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Characteristics of Selected Phase I Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Costs of Phase I Compliance for Selected Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Costs and Quality of Fuels for Selected Electric Utility Phase I Plants, 1985, 1990, and 1995 . . . . . . . . . . . . . . . . 16 Average Delivered Cost of Low-Sulfur Coal by Origin State, 1985, 1990, and 1995 . . . . . . . . . . . . . . . . . . . . . . . . 23 Coal Production by State, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Coal Receipts at Electric Utility Plants by Supply Region and Sulfur Dioxide Level, 1990 and 1995 . . . . . . . . . 26 The Number of Mines and the Average Number of Miners Working Daily by State for 1990 and 1995 . . . . . . 36 Phase II, Group 1 and Group 2 Boiler Statistics and Emission Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Fossil Units Proposed for Repowering, 1996-2005, as of January 1, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 U.S. Electric Utility Planned Coal-, Petroleum-, and Gas-Fired Capacity Retirements, 1996-2005, as of January 1, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Chronology of Historic Federal Legislation To Control Air Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Profile of the 261 Table 1 Generators Affected by Phase I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Profile of Coal Received at Table 1 Plants, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 Characteristics of Selected Phase I Units, by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Cost of Phase I Compliance for Selected Units, by Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111 Figures
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. Table 1 Unit Emissions, 1985 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Substitution and Compensating Unit Emissions, 1985 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1996 SO 2 Emission Allowance (Spot Market) Supply and Demand at the EPA Auction, March 1996 . . . . . . . . . . Cumulative Investments in Air Pollution Control Facilities by U.S. Major Investor-Owned Utilities, 1986-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Investments in Air Pollution Control Facilities by Major Investor-Owned Utilities, by NERC Region, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average Price of Electricity for Six Utilities, 1990-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal Produced in Wyoming and Delivered to Electric Utilities, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Coal Demand Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Illinois, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Indiana, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Missouri, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Michigan, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Ohio, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Pennsylvania, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in New York, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in West Virginia, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Kentucky, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Georgia, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of Coal Received in Tennessee, 1990 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average Age (Weighted by Capacity) of Fossil-Fuel Units, 1990, 2000, and 2010, as of January 1, 1996 . . . . . . Electric Power Regulations Timeline for Provisions Enacted Through the Clean Air Act . . . . . . . . . . . . . . . . . . . 2 3 8 12 12 17 27 28 29 30 30 31 32 32 33 34 35 37 37 48 53 vi Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update Executive Summary
The Clean Air Act Amendments of 1990 address numerous air quality problems in the United States that were not entirely covered in earlier legislation. One of these problems is acid rain caused by sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions from fossil-fueled electric power plants and, to a lesser extent, from other industrial and transportation sources. 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.1 Therefore, 435 units are now considered Phase I units. More than 2,000 units will be affected by Phase II. This report updates and expands a report published by the Energy Information Administration in 1994 titled, Electric Utility Phase I Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990; it describes the strategies used to comply with the Acid Rain Program in 1995, the effect of compliance on SO2 emissions levels, the cost of compliance, and the effects of the program on coal supply and demand. allowances to comply with Title IV in 1995. By complying with Title IV, Phase I units significantly reduced their SO2 emissions compared to previous years; they emitted 5.3 million tons of SO2 in 1995, 45 percent less than the 9.7 million tons emitted in 1990, and 34 percent lower than the 8.0 million tons emitted in 1994. In contrast, non-Phase I units emitted 6.6 million tons in 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 SO2 Compliance Costs
Industry-wide annualized compliance costs are estimated at $836 million (1995 dollars). These costs represent only 0.6 percent of the $151 billion electric operating expenses of investor-owned utilities in 1995. Using scrubbers is estimated to cost $322 per ton of SO2 removal and is the 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 SO2 removal, is the least expensive. Compliance Methods Used by Table 1 Units in 1995
A utility could use one or more of the following compliance methods: (1) fuel switching and/or fuel blending with lower sulfur coal, (2) obtaining additional allowances, (3) installing flue gas desulfurization equipment (i.e., scrubbers), (4) using previously implemented emissions controls, (5) retiring units, (6) boiler repowering, (7) substituting Phase II units for Phase I units, and (8) compensating Phase I units with Phase II units. Most utilities (52 percent of Table I units) used fuel switching and blending in 1995 (Figure ES1). This method accounted for 59 percent of the reduction in SO2 emissions in 1995 compared to 1985 (Figure ES2). Competitive prices of lower sulfur coal, low shipping costs, lower than expected SO2 Emissions Compliance Results in 1995
The acid rain program allocated emissions allowances to Phase I units, authorizing them to emit one ton of SO2 for each allowance. Some utilities obtained additional allowances from three auctions and from bonus provisions in the Act. All 435 generating units had sufficient 1 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 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. Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update vii Figure ES1. Compliance Methods Used by Table 1 Units in 1995a (Percent of Table 1 Units)
Fuel Switch 52 Figure ES2. SO2 Reductions by Compliance Method at Table 1 Units in 1995 a (Percent of SO2 Reductions)
Fuel Switch 59 SO2 Emissions (million tons) 1985 -- 9.3 1995 -- 4.4 Total Generating Units: 261 Retired 3 Other 3 Other 2 Retired 2 b Allowances 9 Scrubbers 10 Allowances 32 b
a a b c Scrubbers 28 Does not include 174 substitution and compensating units. b Includes switching to natural gas or petroleum and repowering. Source: Energy Ventures Analysis, Inc., The Utility Report, December 1995. costs for boiler modifications, and little deterioration in plant performance with lower sulfur coal were the reasons most utilities switched to lower sulfur coal. Also, because the industry is restructuring for competition, some utilities are reluctant to commit funds for more expensive solutions. For instance, scrubbers, which are relatively expensive, were chosen by only 10 percent of Table 1 units. Does not include 174 substitution and compensating units. Includes switching to natural gas or petroleum and repowering. c Nine percent of the 1995 SO2 emissions reductions were at 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. SO2 = Sulfur dioxide. Note: Percent reductions of SO2 emissions were computed 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. 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 total coal receipts at electric utilities, increasing to 77 percent by 1995 (Figure ES3). This switch to lower sulfur coal has affected regional coal distribution patterns. Between 1990 and 1995, sales of low-to-medium sulfur coal from the Powder River basin (Wyoming and Montana) increased by 78 million tons; sales from the central Appalachian region (Virginia, eastern Kentucky, and southern West Virginia) increased by 15 million tons; and sales from the Rocky Mountains (Colorado and Utah), increased by 10 million tons. In contrast, for the same period, sales of higher sulfur coal from the northern Appalachian region (Maryland, Pennsylvania, Ohio, and northern West Virginia) decreased 29 million tons; and sales from the Illinois basin (Illinois, Indiana, and Western Kentucky) decreased by 40 million tons. Compliance Strategies and Costs of Six Utilities
Compliance strategies and costs were examined in detail for six utilities with a total of 71 units (22.8 gigawatts of generating capacity) affected by Phase I. Most of the units were switched to lower sulfur coal to meet their SO2 emissions limitations. A few scrubbers were installed, but they were expensive relative to other compliance strategies. Substitution units, which in most instances generated extra emissions allowances, were used extensively by these utilities. Although the compliance costs represented a relatively small percentage of the utilities' total costs, the costs varied widely among the six. Average costs for SO2 and NOx controls and continuous emissions monitoring systems2 ranged from a low of $16.39 per 2 Continuous emissions monitors were required to be operational on November 15, 1993 for Phase I units and on January 1, 1995 for Phase II units (with the exception of NOx /CO2 at oil- and gas-fired units). viii Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update Figure ES3. U.S. Coal Receipts at Electric Utility Plants by Sulfur Level, 1990 and 1995 (Percent)
Low-to-Medium Sulfur
100 costs ranging from just over $1 to almost $14 per kilowatt of Phase I capacity. Phase II Compliance Strategies
High Sulfur 827 Million Tons
80 787 Million Tons Percent 60 40 20 0 1990 1995 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." To meet stronger emissions limits under Phase II, some utilitiesare planning ahead by overcomplying in Phase I. For example, some utilities are installing scrubbers now instead of using a less expensive option. Many utilities have not finalized their Phase II compliance plans. One survey of 116 utilities conducted by the Industrial Information Services Company found that 41 percent of the respondents will switch fuels for Phase II and 28 percent will acquire additional emission allowances. For many utilities, fuel switching has proved to be the most cost-effective choice in Phase I, and many of them will probably continue this strategy in Phase II. For utilities selecting allowances as a strategy for Phase II, extra allowances can be obtained from numerous sources. Utilities receiving extra allowances for installing scrubbers or for complying earlier than required are selling some of their allowances at relatively low prices. Some higher sulfur coal producers have bundled emissions allowances with their sales to help maintain their customer base. It is estimated that only 12 to 20 gigawatts of capacity may be scrubbed to comply with Phase II because a number of utilities that had originally planned to install scrubbers have either deferred installation, or canceled them in favor of fuel switching or purchasing allowances. kilowatt at Cincinnati Gas & Electric to $208.90 per kilowatt at Southern Indiana Gas and Electric Company. Annual operation and maintenance costs (which in this analysis are primarily allowance purchases) ranged from a high of $19.4 million at Illinois Power to a low of $1.8 million at Potomac Electric Power Company. Depreciating capital costs over 15 years results in annual capital Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update ix 1. Introduction
The Clean Air Act Amendments of 1990 (CAAA90), Public Law 101­549, are the latest revisions to the Clean Air Act. Among the numerous provisions of CAAA90 is Title IV, which requires the U.S. Environmental Protection Agency (EPA) to establish the Acid Rain Program to reduce the adverse effects of acidic deposition popularly known as acid rain. Acid rain is formed largely from emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) that are emitted primarily by fossil-fueled electric power plants, other industrial sources, and transportation sources. The SO2 reduction provisions of Title IV of the CAAA90 (hereafter referred to as Title IV) are noteworthy and creative because they represent the first large-scale attempt to set overall emissions levels by using marketable licenses (allowances) and a choice of compliance methods to control emissions rather than using regulations that specify what actions must be undertaken (command and control). An allowance permits the emission of 1 ton of SO2. Title IV gives electric utilities several options for reducing emissions, thus introducing flexibility into compliance plans. Because they have several compliance options, many utilities have alternative plans for complying with the Acid Rain Program, depending on the circumstances (Table B1 of Appendix B). Title IV requires a two-phase tightening of the restrictions placed on fossil-fuel fired power plants. Phase I, from 1995 through 1999, and Phase II, starting in 2000. Phase I mostly affects those power plants that are the largest sources of SO2 and NOx . Phase II will affect virtually all fossil-fueled electric power producers, including utilities and nonutilities. Phase II will tighten the annual emissions limits imposed on these large, higher emitting plants, and it will set restrictions on smaller plants fired by coal, oil, and natural gas. Most existing utility units with an output capacity of 25 megawatts or greater and virtually all new utility and nonutility units will be affected in Phase II. Also, other sources of SO2 (such as industrial facilities) may elect to participate in the Acid Rain SO2 Program.1
1 2 Title IV explicitly specifies 261 generating units powered by 263 boiler units at 110 utility plants for Phase I.2 These 261 units, located in 21 eastern and midwestern States, are referred to as "Table 1" units because they were explicitly identified in Table 1 of the regulation. However, because of provisions in Title IV that allow utilities to use other units to substitute or compensate for those originally specified, 174 additional generating units were affected by Phase I in 1995 (a total of 435 affected generating units) (Figures 1 and 2). A boiler unit brought into Phase I as a substitution unit can assist a Table 1 boiler unit in meeting its emissions reductions 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. After January 1, 1995, a Table 1 boiler unit may designate any Phase II boiler unit as a substitution unit only if both units are under the control of the same owner or operator. In 1995, 91 Table 1 boiler units designated 167 Phase II boiler units to be substitution units. Of these 91 Table 1 boiler units, almost half were located in the Midwest and almost a quarter were located in the South. Also, almost a third of these Table 1 units designated substitution units that were located at the same plant.3 The other seven Phase II boiler units that participated in the Acid Rain Program in 1995 entered as compensating units. Table 1 units that reduced their utilization below their baseline may designate compensating units to provide compensating generation that would account for the reduced utilization of the Table 1 unit. A Table 1 unit may designate any Phase II unit as a compensating unit if the Phase II compensating unit is in the Table 1 unit's dispatch system or has a contractual agreement with the Table 1 unit, and if the emissions rate of the compensating unit has not declined substantially since 1985. Environmental Protection Agency, Allowance System, Proposed Acid Rain Rule, 400/1-91/034 (Washington, DC, December 1991), p.1. Phase I affects 445 boiler units that are associated with 435 generating units. CAAA90 explicitly states that 261 generating units are to be covered in Phase I of the program as Table A units (subsequently referred to in EPA's regulations as Table 1 units). These 261 generators are attached to 263 boilers. Miami Fort generator 5 has two boilers. R.E. Burger generator 3 has two boilers. Similarly, the 182 boilers brought into Phase I as substitution and compensating units are attached to 174 generators. Boilers are referred to throughout the report because SO2 is released into the atmosphere by burning fuel in boilers and allowances are deducted from accounts based on boiler emissions. 3 Environmental Protection Agency, 1995 Compliance Results, Acid Rain Program, EPA/430-R-96-012 (Washington, DC, July 1996), p. 1. Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 1 Figure 1. Table 1 Unit Emissions, 1985 and 1995 (Tons of SO2) State Alabama Florida Georgia Illinois Indiana Iowa Kansas Kentucky Maryland Michigan Minnesota 1985 Table 1 Unit Emissions Estimates 297,195 224,089 795,476 766,492 1,268,745 73,873 3,167 461,023 133,081 59,017 2,033 1995 Table 1 Unit Emissions (from CEMS) 132,645 108,552 276,004 392,177 636,502 27,389 2,893 320,074 119,804 13,171 1,493 State Mississippi Missouri New Hampshire New Jersey New York Ohio Pennsylvania Tennessee West Virginia Wisconsin Total 1985 Table 1 Unit Emissions Estimates 83,365 746,219 52,535 33,735 173,882 1,711,128 671,216 621,923 715,483 220,387 9,114,064 1995 Table 1 Unit Emissions (from CEMS) 56,621 227,525 36,128 21,720 70,486 770,357 515,804 287,446 372,971 54,669 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." 2 Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update Figure 2. Substitution and Compensating Unit Emissions, 1985 and 1995 (Tons of SO2) State Alabama Florida Georgia Illinois Indiana Kansas Kentucky Maryland Massachusetts Michigan Minnesota 1985 Substitution and Compensating Unit Emissions Estimates 25,993 24,599 142,033 31,380 17,937 55,567 27,151 15,806 100,310 21,393 27,645 1995 Substitution and Compensating Unit Emissions (from CEMS) 17,350 22,178 121,586 40,042 44,806 26,156 14,647 6,018 72,770 16,330 11,010 State Mississippi Missouri New Hampshire New York Ohio Pennsylvania Utah West Virginia Wisconsin Wyoming Total 1985 Substitution and Compensating Unit Emissions Estimates 19,379 140,386 14,265 88,686 281,233 91,693 1,783 59,975 87,069 75,121 1,349,404 1995 Substitution and Compensating Unit Emissions (from CEMS) 24,617 98,522 11,155 25,340 140,635 13,755 2 63,914 52,411 30,754 853,998 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 3 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 NOx reductions requirements, which are less stringent than the Phase II requirements. If the utility determines that the benefits of less stringent NOx requirements outweigh the costs of more stringent SO2 requirements, substitution becomes more likely. 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 SO2 and NO x emissions reductions requirements during Phase I of Title IV of CAAA90, and provides estimates of the costs incurred by six utilities in implementing these strategies through 1995. The discussion covers four SO2 compliance strategies: (1) fuel switching and/or blending with lower sulfur coal, (2) obtaining additional allowances, (3) installing flue gas desulfurization equipment (scrubbers), and (4) other compliance strategies. The effects of these strategies on coal supply and demand are also examined. The report describes utilities' plans for Phase II, although many utilities have adopted a wait-and-see approach, choosing to see how the market for allowances develops and how competition in the electric power industry progresses. A key component of this strategy involves the accumulation of excess Phase I allowances, which can be used at any point in the future. This strategy allows utilities to delay installation of pollution control equipment with high capital costs until after 2000. Also, the evolution of the electric power industry toward more competition has led many utilities to view their compliance plans for the future as proprietary; therefore, they are less than forthcoming about these plans. Other topics presented in this update are the proposed EPA rule for NOx emissions reductions in Phase II Group 1 and Group 2 boilers, detailed descriptions of the shifts in coal supply, and an evaluation of the structure of the annual SO 2 allowance auction. SO2 Compliance Results in 1995
During the past decade, utilities with Phase I units have achieved significant reductions in SO2 emissions, most notably in 1995, the first year of the program. During 1995, 435 Phase I units emitted 5.3 million tons of SO2 into 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 SO2 emissions limits. To fully address this issue, 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 SO2 emissions. While SO2 emissions from Phase I units have steadily decreased, SO2 emissions from nonaffected units have increased (Table 1). In 1985, Phase I units were the largest group of SO2 emitters, accounting for 67 percent of total SO2 emissions, and nonPhase I units accounted for 33 percent. By 1995, Phase I units emitted 45 percent of total SO2 emissions, whereas non-Phase I units accounted for 55 percent of the total. Table 1. SO2 Emissions From Electric Utilities, 1985, 1990, 1994, and 1995 (Million Tons)
1995 Capacity (GW) Phase I Units . . . . . . . . . . . . . Non-Phase I Units . . . . . . . . . Total . . . . . . . . . . . . . . . . . . .
a Total SO2 Emissions 1985 10.5 (67) 5.1 (33) 15.6 (100) 1990 9.7 (62) 5.9 (38) 15.6 (100) 1994 8.0 (56) 6.3 (44) 14.4 (100) 1995 5.3 (45) 6.6 (55) 11.9 (100) 130.9 (28) a 333.2 (72) 464.1 (100) Includes units that had SO2 emissions in 1995 only. Note: SO2 emissions for 1985, 1990, and 1994 are estimated. Percentages are shown in parenthesis. 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." 4 Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 2. Phase I Effects on Utilities
According to the EPA, all of the Phase I plants, housing 445 Phase I boilers, were in compliance with Title IV at the end of 1995. The 445 Phase I boilers, associated with 435 generating units, had a total capacity of 130.9 gigawatts. This figure includes 261 Table 1 generating units, explicitly referred to in the text of Title IV, with a total capacity of 89.0 gigawatts and 174 substitution and compensating units (totaling 41.9 gigawatts of capacity) brought into Phase I under provisions of Title IV. A profile of the 435 Phase I generating units can be found in Table B1 of Appendix B. methods to reduce SO2 emissions and reduce their pollution control costs at the same time. A utility could choose one or a combination of the following methods to meet its annual emissions allowance limit: Compliance Options for Phase I
Phase I affects the largest electric utility sources of SO2 emissions and the units that were brought into the program as substitution or compensating units. In Phase I, affected units are required to have an allowance for each ton of SO2 they emit or they incur a penalty. Affected units are allocated emissions allowances based on the average annual British thermal units (Btu's) burned from 1985 through 1987 multiplied by 2.5 pounds of SO2 per million Btu.4 The initial quantity of allowances in most cases, is not sufficient to meet the amount of SO2 emitted in 1985. Therefore, Phase I utilities must either reduce their emissions to the level of allowances allocated, or they can acquire additional allowances by purchasing them at an allowance auction or from another allowance owner. The market-based approach for complying with environmental regulations established a firm annual limit on SO2 emissions from Phase I units (although with substitution and compensating unit provisions, this annual limit can vary from year to year during Phase I), but permitted allowance trading and a choice of compliance strategies. Utilities with relatively high costs of pollution control can purchase additional allowances from other utilities whose emissions reductions exceed the requirements of Title IV. Together they can meet their emissions requirements more efficiently than if each utility had to meet the SO2 limits separately. The allowance trading program gives utilities the flexibility to choose among a variety of Fuel switching and/or blending with lower sulfur coal, cofiring, switching to another fuel Obtaining additional allowances Installing flue gas desulfurization equipment (scrubbers) Using previously implemented controls Retiring units Boiler repowering Substituting Phase II units Compensating with Phase II units. Compliance Methods Chosen
On January 1, 1995, Phase I compliance methods effectively went into operation for the purpose of SO2 emissions monitoring by EPA. This section includes a discussion of the compliance methods chosen for the 261 Table 1 units and how the compliance methods relate to coal purchase price and specific plant implementation plans. The 174 substitution and compensating units are not included in the discussion. Fuel Switching and/or Blending
Fifty-two percent (136 units) of the Table 1 units switched to or blended with a lower sulfur coal, accounting for 59 percent of the SO2 emissions reductions achieved in 1995 (Table 2). These choices were propelled mainly by the innovation of utilities in blending coals of varying sulfur contents to reduce the average SO2 emissions and by the availability of large quantities of lower sulfur coal on the market at favorable prices. This category includes some units in Kansas, Michigan, New Hampshire, New York, and Wisconsin that had already been switched to lower 4 "CAAA Phase I Performance: Overcompliance," Coal (October 1995), p.11. Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 5 Table 2. Profile of Compliance Methods for Table 1 Units
Percentage Percentage of Total of SO2 Nameplate Capacity Emission 1985 SO2 1995 Emissions Emissions Affected by Reductions (tons) (tons) Phase I in 1995c 4,768,480 2,640,565 1,637,783 121,040 134,117 9,301,985 1,923,691 2,223,879 278,284 0 18,578 4,444,432 53 27 16 2 2 100 59 9 28 2 2 100 Compliance Method Fuel Switching and/or Blending . Obtaining Additional Allowances Installing Flue Gas Desulfurization Equipment (Scrubbers) . . . . . . Retired Facilities . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . .
a b Number of Generators 136 83 27 7 8 261 Average Agea (years) 32 35 28 32 33 32 Affected Nameplate Capacity Allowancesb (megawatts) (per year) 47,280 24,395 14,101 1,342 1,871 88,989 2,892,422 1,567,747 923,467 56,781 110,404 5,550,821 Base year of 1996 was used to calculate average age. One SO2 allowance permits one ton of SO2 emissions. c Base year of 1985 was used to calculate SO2 emissions reductions. SO2 = Sulfur dioxide. Note: Fuel switching includes Phase I units switched to a lower sulfur coal in the 1990's. This category also includes units using state-mandated previously implemented controls that may have been switched prior to 1990. Other includes units that were repowered and those that switched to natural gas or petroleum. Totals may not equal sum of components because of independent rounding. Sources: Compliance Method: The Utility Report December 1995, Energy Ventures Analysis, Inc. Age and Capacity: Energy Information Administration, Inventory of Power Plants 1994, DOE/EIA-0095(94) (Washington, DC, October 1995). 1985 Emissions: U.S. Environmental Protection Agency, National Allowance Data Base, Versions 2.11 (January 1993). 1995 Emissions: Acid Rain Division, U.S. Environmental Protection Agency. sulfur coal to meet previously implemented controls mandated by State environmental regulations.5 It is useful to look at the individual characteristics of a few plants to understand the decisions made regarding switching. This section discusses the variations in the way three plants switched to lower sulfur coal: Ohio Edison's Sammis plant switched to coal from the Central Appalachian region, Associated Electric Cooperatives' Thomas Hill plant switched from Missouri coal in 1990 to lower sulfur coal from the Powder River Basin in 1994 and 1995, and the Coffeen plant of Central Illinois Public Service continued using coal from the Illinois Basin in 1995 as it had in 1990. particulate control requirements and in anticipation of the Phase I compliance requirements, the Sammis plant replaced electrostatic precipitators (ESPs) in units 5, 6, and 7 to accommodate a wide variety of coals. The ESP, one means of removing fly ash from flue gas when fuels are burned in suspension, produces an electric charge on the ash particle to be collected and then attracts the charged particle by electronic forces to the collecting curtain. Fly ash can seriously interfere with the operation of a boiler unit, and, in some low-sulfur coals, can be resistant to being charged. Thus, in many cases, the flue gas must be treated with chemical conditioning agents, such as sulfur trioxide (SO3) to reduce ash resistivity and to increase the collection efficiency of the ESP. 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.6 The average 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. The Sammis Plant
The Sammis plant, operated and owned by Ohio Edison, has a coal-fired nameplate capacity of 2,303.5 megawatts with four 185.0 megawatt units, one 317.5 megawatt unit and two 623.0 megawatt units. Units 5, 6, and 7 are Table 1 units and they have a total capacity of 1,563.5 megawatts. In the early and mid-1980's, in response to EPA 5 Energy Information Administration, Electric Utility Phase I Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990, DOE/EIA-0582 ( Washington, DC, March 1994), p 33. 6 Federal Energy Regulatory Commission (FERC) Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants." 6 Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update However, in 1995, coal from Ohio and Pennsylvania was significantly reduced; less than one percent of Sammis' receipts came from Pennsylvania and none came from Ohio. Most of the coal came from southern West Virginia (56 percent) and eastern Kentucky (36 percent) by barge transportation, since Sammis has significant barge unloading capability. The average sulfur content went from 1.67 percent by weight in 1985 to 0.79 percent by weight in 1995 and the average delivered price of coal was reduced by 33 percent (1995 dollars) to $31.23 per ton (128.1 cents per million Btu) in 1995. Ohio Edison currently operates one lower sulfur coal pile for fueling all generators at the Sammis plant and recently has considered using different types of coal for the various units at the plant. However, that would entail the cost and burden of maintaining multiple coal piles. Ohio Edison estimates that maintaining a single coal pile could cost as much as $1 million less than maintaining two separate piles. dumpers, which are rotated, tilted, and dumped by a specially designed track. In all, the coal-switching modifications totaled approximately $118 million. Coal receipts in 1995 at the Thomas Hill plant increased to 4,723,000 tons in part because of the lower heat content (8,744 Btu's per pound as compared to a heat content of 10,382 Btu's per pound in 1985). The Coffeen Plant
Central Illinois Public Service's Coffeen plant located in Montgomery County, Illinois, has two Table 1 units, amounting to a capacity of 1,005.5 megawatts. In 1985, Coffeen received 1,970,000 short tons of coal from Macoupin County, Illinois, with an average sulfur content of 3.68 percent. In 1990, Coffeen received all of its coal from Macoupin County--1,746,000 short tons with 3.54 percent sulfur at $38.69 (1995 dollars) per ton (182.7 cents per million Btu). In response to Title IV, the Coffeen plant decided to continue using Illinois coal in 1995. This decision was facilitated by renegotiating a contract with the same supplier to provide lower sulfur coal and by modifying the plant with a new limestone addition system and a new electrode design for the ESP, costing approximately $1.3 million and $500,000, respectively. Under a renegotiated contract, Coffeen received 1,690,000 short tons of coal from Macoupin County with a sulfur content of 0.91 p