The Acid Rain Program is a market-based initiative taken by the United States Environmental Protection Agency in an effort to reduce overall atmospheric levels of sulfur dioxide and nitrogen oxides, which cause acid rain. The program is an implementation of emissions trading that primarily targets coal-burning power plants, allowing them to buy and sell emission permits (called "allowances") according to individual needs and costs. In 2011, the trading program that existed since 1995 was supplemented by four separate trading programs under the Cross-State Air Pollution Rule (CSAPR). On August 21, 2012, the United States Court of Appeals for the District of Columbia issued its Opinion and Order in the appeal of the Cross State Air Pollution Rule (CSAPR) for two independent legal reasons. The stay on CSAPR was lifted in October 2014, allowing implementation of the law and its trading programs to begin.
A 2021 study found that the "Acid Rain Program caused lasting improvements in ambient air quality," reducing mortality risk by 5% over 10 years.
History Title IV of the Clean Air Act Amendments of 1990 established the allowance market system known today as the Acid Rain Program. Initially targeting only sulfur dioxide, Title IV set a decreasing cap on total SO2 emissions for each of the following several years, aiming to reduce overall emissions to 50% of 1980 levels. The program did not begin immediately, but was implemented in two stages: Phase I (starting January 1, 1995) and Phase II (starting January 1, 2000)."Reducing Acid Rain", U.S. Environmental Protection Agency
The Clean Air Act Amendments of 1990 set as its primary goal the reduction of annual SO2 emissions by 10 million tons below 1980 levels of about 18.9 million tons. To achieve these reductions by 2000, when a nationwide sulfur dioxide emissions cap of 8.95 million tons per year began, the law required a two phase tightening of operating restrictions placed on fossil fuel fired (e.g., coal, oil, natural gas) power plants. The operation and pricing of a market for emissions allowances would not be viable in the absence of an effective regulatory cap on the total number of allowances available.
Scope of Phase I requirements In Phase I, half the total reductions were required by January 1, 1995, largely by requiring 110 electric power generating plants (261 units in 21 states) to cut sulfur dioxide emission rates to . Each of these generating units was identified by name and location, and a quantity of emissions allowances was specified in the statute in tons of allowable SO2 emissions per year.42 U.S. Code 7651c.
For comparison, new generating units built since 1978 were required to limit sulfur dioxide to a "lowest achievable emissions rate" of about . Coal with 1.25% sulfur and produces sulfur dioxide emissions of , with lower emissions produced by either lower sulfur content or higher Btu content.U.S. Department of the Interior, Office of Surface Mining Reclamation and Enforcement. (1993). Impact of Acid Rain Controls on Surface Mining Reclamation and Enforcement: Programs and Workload. Washington, D.C.: Office of Surface Mining Reclamation and Enforcement.
As an incentive for reducing emissions, for each ton of sulfur dioxide reduced below the applicable emissions limit, owners of a generating unit received an emissions allowance they could use at another unit, keep for future use, or sell. This legitimized a market for sulfur dioxide emissions allowances, administered by the Chicago Board of Trade.Taylor, Jeffrey, and Rose Gutfeld. (1992). "CBOT Selected to Run Auction for Polluters," Wall Street Journal, September 25, 1992, p. C1. Units that installed flue-gas desulfurization equipment (e.g., scrubbers) or other "qualifying Phase I technology" which reduced sulfur dioxide emissions by 90%, qualified for a two-year extension of the 1995 deadline, provided they owned allowances to cover their total actual emissions for each year of the extension period.
Scope of Phase II requirements In Phase II, all fossil-fired units over 75 MWe were required to limit emissions of sulfur dioxide to by January 1, 2000. Thereafter, they were required to obtain an emissions allowance for each ton of sulfur dioxide emitted, subject to a mandatory fine of $2,000.00 for each ton emitted in excess of allowances held. The U.S. Environmental Protection Agency (EPA) distributes allowances equivalent to 8.95 million tons each year (the emissions cap), based on calculations of historical Btu usage for each unit, and may allocate various small "bonus reserves" of allowances.
Nitrogen oxide reduction The 1990 Amendments also required reductions in nitrogen oxide (NOx) emissions at Phase I units. The key factors in NOx formation are flame temperature and oxygen levels present for combustion.Bretz, Elizabeth A. (1991). "New Boiler Designs for Utility Service," Electrical World, May, pp. 44–49. Installation of low-NOx burner retrofits are the most common means of compliance, generally reducing emissions from uncontrolled levels by up to 50%.Bretz, Elizabeth A. (1991). "Equipment Options for Meeting the New Clean-Air Laws," Electrical World, October, pp. 51–59. Many utilities complied with requirements by installing stack-gas scrubbers and low-NOx burners at the same time. Low-NOx burner technology was readily available, and considerably less expensive than installation of scrubbers,Smock, Robert. (1991). "Utilities Struggle with Acid Rain Control Compliance Decisions," Power Engineering. August, pp. 17–22. so control of NOx was considered less demanding by most electric utilities.
Compliance strategies The market based SO2 allowance trading component of the Acid Rain Program was intended to allow utilities to adopt the most cost effective strategy to reduce SO2 emissions. Every Acid Rain Program operating permit outlines specific requirements and compliance options chosen by each source. Affected utilities also were required to install systems that continuously monitor emissions of SO2, NOx, and other related pollutants in order to track progress, ensure compliance, and provide credibility to the trading component of the program. Monitoring data is transmitted to EPA daily via telecommunications systems.
Strategies for compliance with air quality controls have been major components of electric utility planning and operations since the mid-1970s, affecting choice of fuels, technologies and locations for construction of new generating capacity.Hamilton, Michael S. (1980). Regional Interconnections, The Western Systems Coordinating Council, Regional Reliability, Economy and Efficiency. In N. Wengert and R.M. Lawrence, Regional Factors in Siting and Planning Energy Facilities in the Eleven Western States. A Report to the Western Interstate Energy Board. Fort Collins, CO: Colorado State University Experiment Station. Utility strategies for compliance with new sulfur dioxide standards included a mix of options with varying financial costs:Bretz, Elizabeth A. (1991). "New Boiler Designs for Utility Service," Electrical World, May, pp. 44-49; Bretz, Elizabeth A. (1991). "Equipment Options for Meeting the New Clean-Air Laws," Electrical World, October, pp. 51-59; Habiger, Kenneth, and Ronald Ott (1989). "Fluidized-Bed Combustion: Retrofit, New Plant Option," Electrical World, May, pp. 62-64; Platt, J.B. (1991). "Scrub Versus Trade: Enemies or Allies?" Presented to the EPRI-EPA-DOE Sulfur Dioxide Control Symposium, Washington, DC, December 3; U.S. Department of Energy, Energy Information Administration. (1991a). Annual Outlook for U.S. Electric Power 1991. Washington, DC: USGPO.
several existing and new stack-gas scrubbing and clean coal technologies; switching to all, or blending high-sulfur coal with, low-sulfur coal; switching to all natural gas, or cofiring coal and natural gas; "trimming," or reducing annual hours of plant utilization; retiring old units; repowering existing units with new coal or non-coal boilers; purchasing or transferring emissions allowances from other units; increasing demand-side management and conservation; or bulk power purchases from other utilities or non-utility generators from units using coal or other fuels.
Some coal cleaning may occur in combination with other actions such as scrubbing, or blending coals with varying sulfur content, but utilities generally prefer that coal suppliers bear the costs of cleaning operations. Some observers estimated 20% - 30% of the sulfur can be removed through coal cleaning or blending, and 50%–70% taken out with emissions control equipment.
For Phase II compliance the options were numerous, but for Phase I they were constrained by the time available to implement a decision. Because it takes 3–5 years to design and build a scrubber at an existing coal-fired unit, and longer to repower or build a new facility (e.g., 6–11 years for coal, 10–14 years for nuclear units),Hamilton, Michael S., and Norman Wengert. (1980). Environmental, Legal and Political Constraints on Power Plant Siting in the Southwestern United States. A Report to the Los Alamos Scientific Laboratory. Fort Collins, CO: Colorado State University Experiment Station. electric utility decision options for Phase I plants were limited to scrubbing, switching fuels, purchasing or transferring emissions allowances to allow continued use of high-sulfur coal, retiring units, or trimming unit utilization and substituting capacity from another source.
Delays in allocating "early scrub" bonus credits and scheduling of the first auction of emissions allowances in March 1993Coal Outlook, February 4, 1991, p. 3; November 2, 1992, p. 5. effectively removed these incentives from actual compliance decision making of most electric utilities. Because of the time it takes to build air pollution control equipment, financial and contractual commitments to scrubbers had to be made by summer 1992 if plant modifications were to be operational in time to meet new standards in 1995. Thus, decisions had to be made before price and allocation of emissions allowances were known. Consequently, most scrubber projects to meet the 1995 deadline were well under way by fall of 1992.
Windfalls Of the 261 units at 110 plant locations affected by Phase I emission limitations, five were oil-fired, five coal-fired units were retired, and one coal-fired unit was placed on cold standby status prior to passage of the legislation in 1990. The 6 inactive coal-fired units were statutory recipients of a total of 36,020 tons of Phase I sulfur dioxide emissions allowances.
This marketable windfall was estimated by the U.S. Department of Energy (DOE) in 1991 to be worth $665 to $736 per ton,U.S. Department of Energy, Energy Information Administration. (1991). Annual Outlook for U.S. Electric Power 1991. Washington, DC: USGPO. totaling $23.9 to $26.5 million. However, actual purchases of emissions allowances in 1992 were reported at a lower price than expected of $300 per ton.Coal Voice, Nov/Dec, 1992, p. 24. Allowances auctioned in March 1993 sold for $122 to $450 per ton,58 Federal Register 27563-27567, May 10, 1993. reducing the windfall from these allowances to $4.4 to $16.2 million. In the interim, owners of one unit retired in 1985, the 119 MWe Des Moines Energy Center, received $93 million in DOE funding for a Clean Coal Technology project to repower with a coal-fired 70 MWe pressurized fluidized-bed combustion unit, bringing it back into production in 1996.
Location of generating units