The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update
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 . 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
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
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 1 units) used fuel switching and blending in 1995. This method accounted for 59 percent of the reduction in SO2 emissions in 1995 compared to 1985. Competitive prices of lower sulfur coal, low shipping costs, lower than expected costs for boiler modifications, and little deterioration in plant performance with lower sulfur coal were the reasons most utilities switched to lower sulfur coal. Also, because the industry is restructuring for competition, some utilities are reluctant to commit funds for more expensive solutions. For instance, scrubbers, which are relatively expensive, were chosen by only 10 percent of Table 1 units.
Effects of Compliance on Regional Coal Supply and Demand
Because fuel switching has been the compliance method used by most utilities, lower sulfur coal sales in the United States have increased substantially. In 1990, for example, low-to-medium sulfur coal accounted for 67 percent of total coal receipts at electric utilities, increasing to 77 percent by 1995. 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 systems  ranged from a low of $16.39 per kilowatt at Cincinnati Gas & Electric to $208.90 per kilowatt at Southern Indiana Gas and Electric Company.
Annual operation and maintenance costs (which in this analysis are primarily allowance purchases) ranged from a high of $19.4 million at Illinois Power to a low of $1.8 million at Potomac Electric Power Company. Depreciating capital costs over 15 years results in annual capital costs ranging from just over $1 to almost $14 per kilowatt of Phase I capacity.
Phase II Compliance Strategies
To meet stronger emissions limits under Phase II, some 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-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.
 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
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