Electric Utility Phase I Acid Rain Compliance Strategies for the Clean Air Act Amendments of 1990
Release date: March 1994
Executive Summary
The Clean Air Act Amendments of 1990 (CAAA90)— Public Law 101-549—are the latest revisions to the Clean Air Act. Among the numerous provisions of the CAAA90 is Title IV, which requires the U.S. Environmental Protection Agency (EPA) to establish the Acid Rain Program to reduce the adverse effects of acidic deposition (acid rain). Acid rain is formed largely from emissions of sulfur dioxide (SO2 ) and nitrogen oxides (NOx) which are emitted primarily by fossil-fueled electric power plants, other industrial sources, and transportation sources. The SO2 reduction provisions of CAAA90 are noteworthy and controversial, because they represent the first large-scale attempt to set overall emissions levels using marketable licenses (allowances) to control emissions, as opposed to regulations that specify what actions must be undertaken by those affected (command and control). An allowance permits the emission of one ton of SO2 . The use of allowances leaves electric utilities with several options for compliance strategies and, thus, introduces flexibility into compliance plans. Many utilities, because they have several compliance options, have alternative plans that can be used to comply with Phase I, depending on the circumstances.
The Acid Rain Program is divided into two time periods; Phase I, from 1995 through 1999, and Phase II, starting in 2000. Phase I mostly affects power plants that are the largest sources of SO2 and NOx. Phase II affects virtually all electric power producers, including utilities and nonutilities. This report is a study of the effects of compliance with Phase I regulations on the costs and operations of electric utilities, but does not address any Phase II impacts.
The CAAA90 specifies 261 generating units1 (mostly coal-burning) at 110 utility plants that are affected by Phase I. These units, located in 21 eastern and midwestern States, are high emitters of SO2 and NOx. However, because of provisions in the CAAA90 that allow utilities to use other units to substitute or compensate for those originally specified, additional generator units may be affected by Phase I.2 This report focuses on the original 261 Phase I affected units specified in Table A of the CAAA90. During Phase I, those 261 units will receive an annual allocation of allowances for SO2 emissions equal to approximately 2.5 pounds of SO2 per million Btu of heat input during the historic baseline period (the average for 1985 through 1987). For most of the units, the allowances are lower than historical emission levels. Phase I also specifies maximum levels of NOxNOx emissions that affected units may emit.
Options to comply with the SO2 limitations of Phase I are grouped into six categories: (1) fuel switching and/or blending, (2) obtaining additional allowances, (3) installing flue gas desulfurization equipment (scrubbers), (4) using previously implemented controls, (5) retiring facilities, and (6) boiler repowering. Fuel switching consists of either switching to lower sulfur coal, blending lower sulfur coal with higher sulfur coal, or co-firing with another fuel, usually natural gas. Obtaining additional allowances entails obtaining a sufficient number of allowances in addition to the initial allocation so that no other action needs to be taken. The use of scrubbers involves installing equipment that removes sulfur dioxide from the boiler flue gas. Previously implemented controls are actions already taken, usually because of State requirements, that have already reduced emissions. Boiler repowering involves replacing an existing boiler with one using a different fuel or technology that may emit less SO2 . Permanently retiring a facility is also an option. Several additional strategies are available: energy conservation (including supply-side and demand-side management), reduced utilization, and substitution of units. Most Phase I affected utilities are using one or more of these in conjunction with their main method of compliance
The main strategy planned for compliance with the SO2 requirements of Phase I is fuel switching. Utilities currently plan to change fuels at more than half (about 62 percent) of the affected units. Fuel switching is favored not only because of the low cost of low-sulfur coal but also because its usually smaller capital expenditures make it a more cost-effective compliance method given the uncertainty associated with compliance costs. The second most frequently chosen strategy is allowance acquisition. For about 15 percent of the affected units, the operating utilities plan to comply by acquiring enough SO2 allowances, largely from other utilities that have reduced their allowance requirements below their annual allocation of allowances, to cover their emissions. About 10 percent of the affected units will install scrubbers to reduce emissions. While this percentage is small compared to the percentage of utilities switching fuels or acquiring additional allowances, it should be noted that scrubbers will account for a large share of the required SO2 emissions reduction in Phase I. At another 10 percent of the affected units, emissions have already been reduced below the number of allowances that have been allotted. Phase I affected utilities plan to repower only one unit.
Utilities switching to low-sulfur coal are expected to obtain two-thirds of the low-sulfur coal (approximately 24 million tons) from central Appalachia, located in eastern Kentucky, western Virginia, and southern West Virginia and the remainder (approximately 12 million tons) from the Powder River Basin, located in southwestern Montana and northwestern Wyoming. An electric utility that switches to burning a subbituminous western low-sulfur coal may need to modify its plant, including the coal handling system, fuel preparation and firing system, steam generator, particulate removal system, ash and waste disposal system, and building structures. These modifications are necessary because of the higher moisture content and different ash properties of western coal, and may cost between $25 and $119 per kilowatt (1992 dollars).
The responses of electric utilities to Phase I SO2 emissions limits, however, have been evolving since the CAAA90 was enacted. Two trends in this development are evident. One is that an increasing number of utilities are purchasing allowances from others who own them. Prices for allowances have been lower than many expected. As a result, fewer scrubbers are being installed at affected plants than originally planned. For example, Illinois Power originally began installing scrubbers at its Baldwin plant, but has since stopped construction and announced that it will buy allowances to comply with Phase I. The other trend is that the price of low-sulfur coal has not risen as much as expected, resulting in lower costs to switch to lowsulfur coal. Several utilities report that they are not paying any premium for low-sulfur coal. Both trends have reduced the expected cost of compliance with Phase I for many utilities.
There are two other basic requirements of Phase I: NOx emission performance standards for certain types of boilers, and installation of continuous emission monitors (CEMs). The NOx performance standards limit each affected unit to specific maximum emission rates. CEMs measure emissions in the flue gas from a boiler. Although these requirements are more straightforward than the SO2 requirements, NOx control and CEM requirements will be costly to Phase I affected utilities in part because of their less flexible compliance options.
The costs of complying with Phase I of the Acid Rain Program, while relatively small, vary substantially among utilities. For a small sample of six utilities, total capital costs for SO2 and NOx controls and CEMs range from $10 to $216 per kilowatt (1993 dollars) of affected capacity. Annual operation and maintenance and fuel expenses range up to over $14 per kilowatt per year. Depreciating Phase I capital expenditures over 15 years results in annual total costs ranging from less than $1 to more than $14 per kilowatt. The effect of these costs on electricity rates is small, ranging from 0.3 to 1.9 mills per kilowatthour; the additional electricity sales revenue requirements range between 0.4 and 3.8 percent for an entire utility.