Acid Rain Program

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 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. 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 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 and Phase II.
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 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 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.
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.
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. Units that installed flue-gas desulfurization equipment 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 distributes allowances equivalent to 8.95 million tons each year, 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 emissions at Phase I units. The key factors in NO_x formation are flame temperature and oxygen levels present for combustion. Installation of low-NO_x burner retrofits are the most common means of compliance, generally reducing emissions from uncontrolled levels by up to 50%. Many utilities complied with requirements by installing stack-gas scrubbers and low-NO_x burners at the same time. Low-NO_x burner technology was readily available, and considerably less expensive than installation of scrubbers, so control of NO_x 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, NO_x, 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. Utility strategies for compliance with new sulfur dioxide standards included a mix of options with varying financial costs:

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, 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 1993 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 in 1991 to be worth $665 to $736 per ton, 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. Allowances auctioned in March 1993 sold for $122 to $450 per ton, 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

Excluding those 11 units, 250 active coal-fired units at 105 plants in 21 states were subject to Phase I sulfur dioxide emissions reductions in 1995. States having the greatest number of generating units affected by the Phase I requirements were: Ohio, Indiana, Pennsylvania, Georgia, Tennessee, Kentucky, Illinois, Missouri and West Virginia. Together, Phase I units represented 20% of the 1,250 operable coal-fired generating units in the U.S. in 1990.
These 250 units had a summer peak generating capability of 79,162 MWe in 1990, with a mean of 317 MWe/unit. This capacity represented about 27% of installed summer coal-fired capability, and about 11.5% of total U.S. installed summer generating capability in 1990. About 207 million tons, almost 90% of the coal purchased by Phase I plants in 1990, produced sulfur dioxide emissions exceeding the 1995 emissions rate of 2.5 lbs/mm Btu using no pollution control equipment.