Acid Rain Program Wikipedia. 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 2. 01. 1, the trading program that existed since 1. Cross State Air Pollution Rule CSAPR. On August 2. 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 2. A 2. 01. 7 NBER paper found that the Acid Rain Program caused lasting improvements in ambient air quality, reducing reduced mortality risk by 5 over 1. HistoryeditTitle IV of the 1. Clean Air Act established the allowance market system known today as the Acid Rain Program. Support Materials Operational Mission Inflight Guide Visual Search Planning Basic Rhotheta 600 Presentation Becker SAR DF 517 Manual Becker SAR DF Training. Computer, Telephony and Electronics Glossary and Dictionary C CSGNetwork. Coms award winning online glossary of computer, telephony and electronics terms. This. 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 5. The program did not begin immediately, but was implemented in two stages Phase I starting January 1, 1. Phase II starting January 1, 2. The Clean Air Act Amendments of 1. The Acid Rain Program is a marketbased initiative taken by the United States Environmental Protection Agency in an effort to reduce overall atmospheric levels of. Cap Cost Program Download' title='Cap Cost Program Download' />SO2 emissions by 1. To achieve these reductions by 2. 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 requirementseditIn Phase I, half the total reductions were required by January 1, 1. British thermal units mm. Btu. 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 1. Btu. Coal with 1. Btulb produces sulfur dioxide emissions of 2. Btu, 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 e. Phase I technology which reduced sulfur dioxide emissions by 9. Scope of Phase II requirementseditIn Phase II, all fossil fired units over 7. MWe were required to limit emissions of sulfur dioxide to 1. Btu by January 1, 2. Thereafter, they were required to obtain an emissions allowance for each ton of sulfur dioxide emitted, subject to a mandatory fine of 2,0. The U. S. Environmental Protection Agency EPA distributes allowances equivalent to 8. Btu usage for each unit, and may allocate various small bonus reserves of allowances. Nitrogen oxide reductioneditThe 1. 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. Installation of low NOx burner retrofits are the most common means of compliance, generally reducing emissions from uncontrolled levels by up to 5. 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,1. NOx was considered less demanding by most electric utilities. Compliance strategieseditThe 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 1. Utility strategies for compliance with new sulfur dioxide standards included a mix of options with varying financial costs 1. 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 2. 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 35 years to design and build a scrubber at an existing coal fired unit, and longer to repower or build a new facility e. 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 1. Because of the time it takes to build air pollution control equipment, financial and contractual commitments to scrubbers had to be made by summer 1. Thus, decisions had to be made before price and allocation of emissions allowances were known. Consequently, most scrubber projects to meet the 1. WindfallseditOf the 2. 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 1. The 6 inactive coal fired units were statutory recipients of a total of 3. Phase I sulfur dioxide emissions allowances. This marketable windfall was estimated by the U. Indesign Batch Pdf Script. S. Department of Energy DOE in 1. However, actual purchases of emissions allowances in 1. Allowances auctioned in March 1. In the interim, owners of one unit retired in 1. MWe Des Moines Energy Center, received 9. DOE funding for a Clean Coal Technology project to repower with a coal fired 7. MWe pressurized fluidized bed combustion unit,8 bringing it back into production in 1. Location of generating unitseditExcluding those 1. Phase I sulfur dioxide emissions reductions in 1. States having the greatest number of generating units affected by the Phase I requirements were Ohio 4. Indiana 3. 7, Pennsylvania 2. Georgia 1. 9, Tennessee 1. Kentucky 1. 7, Illinois 1. Missouri 1. 6 and West Virginia 1. Together, Phase I units represented 2. U. S. in 1. 99. 0. These 2. 50 units had a summer peak generating capability of 7. MWe in 1. 99. 0, with a mean of 3. MWeunit. This capacity represented about 2. U. S. installed summer generating capability in 1. About 2. 07 million tons, almost 9. Phase I plants in 1. Btu using no pollution control equipment. Age matterseditAge of the 2. Phase I coal units ranged from 1. In 1. 99. 5, 1. 11 active Phase I units 2. The average age of 3. These units ranged in size from 1 1. MWe summer capability.