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Home > Electricity > Electricity Publications > The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update


The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update

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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.

SO2 Emissions From Electric Utilities, 1985, 1990, 1994, and 1995
(Million Tons)

1995 Capacity (GW) Total SO2 Emissions
1985 1990 1994 1995
Phase I Units 130.9 10.5 9.7 8.0 5.3
(28) (67) (62) (56) (45)
Non-Phase I Units 333.2a 5.1 5.9 6.3 6.6
(72) (33) (38) (44) (55)
Total 464.1 15.6 15.6 14.4 11.9
(100) (100) (100) (100) (100)
aIncludes units that had SO2 emissions in 1995 only.
Note: SO2 emissions for 1985, 1990, and 1994 are estimated. Percentages are shown in parentheses.
Sources: 1995: U.S. Environmental Protection Agency, “1995 Compliance Results, Acid Rain Program,” EPA/430-R-96-012 (Washington, DC, July 1996). 1994 and prior years: Energy Information Administration, Form EIA-767, “Steam-Electric Plant Operation and Design Report.”

Average Price of Electricity for Six Utilities, 1990-1995

Figure: Average Price of Electricity for Six Utilities, 1990-1995

Note: The average is for Pennsylvania Power & Light, Illinois Power, Potomac Electric Power, Georgia Power, Cincinnati Gas & Electric, and Southern Indiana Gas & Electric.
Source: Energy Information Administration, Financial Statistics of Major U.S. Investor-Owned Electric Utilities, DOE/EIA-0437(94/1) (Washington, DC, December 1995 and previous years).

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.


1996 SO2 Emissions Allowance (Spot Market) Supply and Demand at the EPA Auction, March 1996

Figure: 1996 SO2 Emissions Allowance (Spot Market)
Supply and Demand at the EPA Auction, March 1996

SO2 = sulfur dioxide.
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 SO2 Allowance Auction Summary.

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.

Annualized SO2 Compliance Cost for CAAA90 Title IV
(1995 Dollars)a
Method of Compliance for Title IV 1995 Emissions Reduction (Thousand Tons of SO2)b Annualized Compliance Cost (Thousand Dollars)c Annualized Average Cost per Ton of SO2 Removed
Scrubbing
Title IV Scrubbers 1,734 558,128 322
NSPS Scrubbersd 21 1,345 64
Switching
Bituminouse 1,547 258,737 167
Subbituminous (Powder River Basin (PRB)) 160 18,126 113
Subtotal 3,462 836,336 242
No Cost Switchingf
PRB & CO/UT 369
Natural Gas 20
Midwest 32
Others 5
Subtotal 426
Total 3,888 836,336 215
aPreliminary annualized compliance cost for SO2 could be changed as MIT finalizes their estimates. Costs are not included for low NOx control and continuous emissions monitoring systems.
bThe baseline year to compare 1995 SO2 emissions is 1993. It is assumed that the reductions before 1993 are not due to the CAAA90, but to economic reasons. The 1995 SO2 emissions reductions are the difference between the SO2 emissions that would have been observed in 1995 in the absence of Title IV and the actual emissions. The SO2 emissions that would have been observed in 1995 was calculated as the product of the emissions rates in 1993 and the heat input in 1995.
cA capital charge of 14 percent is used to annualize initial fixed investments in scrubbers or switching to lower sulfur coal. The 14 percent includes 9 percent of capital cost and 5 percent of 20 years' linear depreciation.
dThe New Source Performance Standards (NSPS) scrubbers were installed before Title IV was passed. Only variable costs of extra reductions are included for these scrubbers, not any fixed cost.
eBituminous switching from high-sulfur to low-sulfur coal includes premiums paid for low-sulfur bituminous coal.
fThe “No Cost Switching” for SO2 reductions would have taken place regardless of Title IV. Most of these are switches to low-sulfur subbituminous western coal (Powder River Basin and Colorado and Utah) due to the reduction in coal prices, especially the decline in rail rates.
Sources: Massachusetts Institute of Technology, Center for Energy and Environmental Policy Research, SO2 Compliance Costs with Title IV, Memorandum (from Juan-Pablo Montero on December 24, 1996) to Art Fuldner and Ron Hankey, Office of Coal, Nuclear, Electric and Alternate Fuels, Energy Information Administration. Massachusetts Institute of Technology, Center for Energy and Environmental Policy Research, More on SO2 Compliance Costs with Title IV, Memorandum (from Juan-Pablo Montero on January 13, 1997) to Art Fuldner, Office of Coal, Nuclear, Electric and Alternate Fuels, Energy Information Administration.


Compliance Methods Used by Table 1 Units in 1995

Compliance Methods Used by Table 1 Units in 1995a
(Percent of Table 1 Units)

Figure: Compliance Methods Used by Table 1 Units in 1995 (Percent of Table 1 Units)

aDoes not include 174 substitution and compensating units.
bIncludes switching to natural gas or petroleum and repowering.
Source: Energy Ventures Analysis, Inc., The Utility Report (December 1995).
SO2 Reductions by Compliance Method at Table 1 Units in 1995a
(Percent of SO2 Reductions)

Figure: SO2 Reductions by Compliance Method at
Table 1 Units in 1995 (Percent of SO2 Reductions)

aDoes not include 174 substitution and compensating units.
bIncludes switching to natural gas or petroleum and repowering.
cNine 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.

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.

Profile of Compliance Methods for Table 1 Units
Compliance Method Number of Generators Average Agea (years) Affected Nameplate Capacity (megawatts) Allowancesb (per year) 1985 SO2 Emissions (tons) 1995 Emissions (tons) Percentage of Total Nameplate Capacity Affected by Phase I Percentage of SO2 Emission Reductions in 1995c
Fuel Switching and/or Blending 136 32 47,280 2,892,422 4,768,480 1,923,691 53 59
Obtaining Additional Allowances 83 35 24,395 1,567,747 2,640,565 2,223,879 27 9
Installing Flue Gas Desulfurization Equipment (Scrubbers) 27 28 14,101 923,467 1,637,783 278,284 16 28
Retired Facilities 7 32 1,342 56,781 121,040 0 2 2
Other 8 33 1,871 110,404 134,117 18,578 2 2
Total 261 32 88,989 5,550,821 9,301,985 4,444,432 100 100
aBase year of 1996 was used to calculate average age.
bOne SO2 allowance permits one ton of SO2 emissions.
cBase 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 1990s. 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: Energy Ventures Analysis, Inc., The Utility Report December 1995. 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, Version 2.11 (January 1993). 1995 Emissions: Acid Rain Division, U.S. Environmental Protection Agency.


U.S. Coal Receipts at Electric Utility Plants by Sulfur Level, 1990 and 1995
(Percent)

Figure: U.S. Coal Receipts at Electric Utility Plants by Sulfur Level, 1990 and 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.”

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 [2] 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.


Notes

[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.
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[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).
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Contact:
Betsy O'Brien
bobrien@eia.doe.gov
Phone: 202/287-1793