Representation of New Environmental Rules and Regulations

In Energy Information Administration (EIA) analyses, the reference case incorporates rules and regulations in place at the time of the analysis. Rules or regulations not finalized, in early stages of implementation (without specific guidelines), or still being developed or debated are not represented. As an independent statistical and analytical agency, EIA does not take positions on how legislative or regulatory issues will be resolved or how regulations will, or should, be implemented.

The reference case for this analysis excludes several potential environmental actions, such as new regulations affecting regional haze, for which States are developing implementation plans; new National Ambient Air Quality Standards (NAAQS) for particulates, still being reviewed by the U.S. Environmental Protection Agency (EPA) and the courts; and the possible ratification of the Kyoto Protocol. In addition, no effort is made to predict the Hg emission reductions that may be required^a or the outcome of lawsuits against the owners of 32 coal-fired power plants accused of violating the Clean Air Act (CAA).^b

In 1999, the EPA issued regulations to improve visibility (reduce regional haze) in 156 national parks and wilderness areas across the United States. It is expected that these rules will have an effect on electric power plants, but the degree to which they will be affected is not known. Emissions of SO₂ and NO_x contribute to regional haze, and reductions could improve visibility in some areas. The regulations call for States to establish goals and design plans for improving visibility in affected areas; however, State implementation plans (SIPs), which are not required until 2004 or later, are not represented in this analysis.

The revised NAAQS, issued by the EPA in 1997, created a standard for fine particles smaller than 2.5 micrometers in diameter (PM_2.5). Power plant emissions of SO₂ and NO_x are also a component of fine particulate emissions. The EPA is now reviewing scientific data on fine particulate emissions to determine whether the standard should be revised. The review is expected to be completed in 2002. If the standard is not changed, States will be required to submit plans to comply by 2005; however, the NAAQS for fine particulates has been challenged in court, and the resolution of the case is uncertain.

In December 1997, 160 countries met to negotiate binding limitations on greenhouse gas emissions for the developed nations. CO₂ emissions from fossil-fired power plants are a key component of greenhouse gas emissions. The developed nations agreed to limit their greenhouse gas emissions to 5 percent below the levels emitted in 1990, on average, between 2008 and 2012. The target for the United States is 7 percent below the 1990 emission level for all greenhouse gases. Reductions would be required if the U.S. Senate ratified the protocol. At this time, while 29 countries have ratified the protocol, none of the Annex I countries (the developed countries) has ratified the agreement. Various elements of the Protocol are still under negotiation. In addition, the Bush Administration opposes ratification of the Protocol in its present form.

The Clean Air Act Amendments of 1990 (CAAA90), Section 112(n)(1)(A), required that the EPA prepare a study of hazardous air emissions from steam generating units. The report was submitted to Congress on February 24, 1998. Its key finding was that Hg emissions from coal-fired power plants posed the greatest potential for harm. The EPA is now collecting and analyzing data on Hg emissions from specific power plants. The data, together with continuing studies on the health effects of mercury, will be used to determine the extent to which emissions need to be reduced. The EPA will be developing proposed regulations for reducing Hg emissions over the next 3 years.

On November 3, 1999, the Justice Department, on behalf of the EPA, filed suit against seven electric utility companies, accusing them of violating CAAA90 by not installing state-of-the-art emissions control equipment on power plants when major modifications were made. CAAA90 requires that when major modifications are made to older power plants they must also be upgraded to comply with emissions standards for new plants. The EPA is arguing that the seven companies and the Tennessee Valley Authority made major modifications to 32 power plants but did not add required emissions control equipment. Settlements have been reached in some cases, but most are ongoing.

Readers should keep in mind that some of the projected actions and costs incurred to comply with the emissions caps analyzed in this report may also result from the other pending rules and regulations discussed above when they are finalized. Projections in the reference case in this report are not statements of what will happen but of what might happen, given the assumptions and methodologies used. The reference projections are business-as-usual trend forecasts, given known technology, technological and demographic trends, and current laws and regulations. Thus, they provide a policy-neutral reference case that can be used to analyze policy initiatives. All laws are assumed to remain as now enacted, although the impacts of emerging regulatory changes, when defined, are reflected.

aOn December 15, 2000, the EPA announced that Hg emissions need to be reduced, and that regulations will be issued by 2004.

^bSee Chapter 5 of the earlier EIA report for discussion of New Source Review issues.

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Power Sector Mercury Emissions

Many factors, including the Hg content (by speciation—elemental Hg versus various Hg-containing compounds), chlorine content, and other chemical constituents of the coal used; the rank of the coal (i.e., bituminous or subbituminous); the boiler temperature and firing type and the flue gas temperature; and the types of existing control equipment for NO_x, SO₂, and particulates affect the level of Hg emissions from a particular power plant. In recent years data collection and analysis efforts have focused on these factors so that better estimates of current power sector Hg emissions could be developed; however, substantial uncertainty remains. As additional tests are performed, factors currently unaccounted for may turn out to be important.

Section 112(n)(1)(A) of the Clean Air Act Amendments of 1990 required the U.S. Environmental Protection Agency (EPA) to perform a study of possible public health problems associated with hazardous air pollutants from steam-electric power plants. That study was completed in December 1997 and transmitted to the Congress.^a One of its key findings was that Hg emissions from coal-fired power plants posed the greatest public health concern among the hazardous air pollutants identified; however, the EPA determined that more data were needed before regulatory decisions could be made.

Using its authority under section 114 of the Clean Air Act, in November 1998 the EPA issued an information collection request (ICR) requiring coal-fired power plants to provide data associated with Hg emissions. The ICR data were collected in three phases. The first phase involved the collection of basic information—boiler type, size, existing emissions control equipment, etc.—for every coal-fired generator with 25 megawatts or greater capacity. The second phase was the collection of fuel shipment information for each of the electric power plants identified in the first phase. Each of the electric power plants was required to report the quantity and source of each coal shipment received for the calendar year 1999. For every sixth shipment (a minimum of 3 analyses per month) the plants also had to report the Hg and chlorine content of the coal received. In the third phase of the ICR, 75 plants were selected to test the Hg emissions at the inlet and outlet of the last pollution control device on one or more units. The plants used were chosen to be representative of the different types of existing coal plants.

The ICR data are the primary information used in this report to assign Hg content to the coal supply curves in the NEMS Coal Market Module and the Hg emissions modification factors for each coal plant type represented in the Electricity Market Module. On average the sample data show that the Hg content of coal shipped in 1999 was 7.3 pounds per trillion Btu (approximately 0.2 pounds of Hg per thousand short tons of coal); however, there was considerable variation among coals from different seams, even within a given coal supply region. For example, the 1999 ICR data indicated that coal shipments from the Pittsburgh seam in Northern Appalachia had an average Hg content of 8.2 pounds per trillion Btu, whereas shipments from the Upper Freeport seam averaged 16.4 pounds Hg per trillion Btu. Even within the same coal seam the tested shipment data show considerable variation in Hg content. For example, although the average Hg content for the Pittsburgh seam was 8.2 pounds per trillion Btu, the minimum for shipments from that seam was 0.1 pounds per trillion Btu and the maximum was 73.1 pounds per trillion Btu. In statistical terms, the standard deviation for Hg content at the Pittsburgh seam is 4.04, indicating that most samples should have Hg contents between 0.1 and 16.3 pounds of Hg per trillion Btu.

The Hg removal rates for the various coal plant configurations also showed significant variation. Data from the third phase of the ICR show that on average a cold-side electrostatic precipitator (CSE)—a particulate removal device—removes 31 percent of the Hg that passes through it. However, the variation among plants with CSEs was large, ranging between 0 percent and 87 percent removal. The situation was similar for facilities with fabric filters—another type of particulate removal device. On average they removed 69 percent of the Hg passing through them, but, after excluding plants that actually reported increases in Hg after passing flue gas through the fabric filter, the removal rate ranged between 54 percent and nearly 100 percent. In addition, there is very little information on the impact of new NO_x control devices—selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR) equipment—on Hg emissions because, while many plants plan to add them in the near future, only a few are using them now. This study assumes that, when combined with an SO₂ scrubber, an SCR enhances Hg removal with an emissions modification factor of 0.65; however, no additional removal is assumed for plant configurations that have an SCR but do not have an SO₂ scrubber.

Additional research is needed on the variations seen in the available data. Over the next several years the National Energy Technology Laboratory (NETL), the EPA, and others plan to conduct full-scale tests of various Hg removal technologies on several coal plants. This analysis assumes the use of activated carbon injection technologies to remove Hg, because they have been tested at pilot scale; however, there are other technologies in development, including advanced coal cleaning techniques, alternative absorbents, and more efficient use of absorbents (recycling absorbents rather than once-through systems) to remove Hg from flue gas.

In addition, efforts to understand the role of chlorine and other chemicals in coal on the amount of Hg removed are underway. Data from those tests and from other ongoing research should allow a better understanding of the factors influencing Hg emissions and improve analyses of options for reducing them. Although this report uses the best data available, considerable uncertainty exists about the measurement of and options for reducing Hg emissions from coal-fired power plants.

aU.S. Environmental Protection Agency, Mercury Study Report to Congress, EPA-452/R-97-003 (Washington, DC, December 1997).

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Representation of Coal Rank in the NEMS Coal Market Module

The thermal grades represented in the NEMS Coal Market Module (CMM) primarily correspond to three ranks of coal: bituminous, subbituminous and lignite. In the United States, coals are grouped into specific rank categories based on fixed carbon content, volatile matter, heating value, and agglomerating (or caking) properties. The classification of coals according to rank is based on their degree of progressive alteration from lignite to anthracite.

In the CMM, bituminous coal is represented by two thermal grades: (1) a premium bituminous coal that is supplied to the domestic and foreign coking coal sectors and used to make coke for the steelmaking process; and (2) a bituminous steam coal consumed in the electricity, industrial, and residential/commercial sectors. Like bituminous steam coal, subbituminous coal and lignite also are consumed in the electricity, industrial, and residential/commercial sectors. Anthracite coal from Pennsylvania is not uniquely modeled in the CMM but is grouped with bituminous coal in Northern Appalachia (Pennsylvania, Ohio, northern West Virginia, and Maryland). An additional supply curve representing supplies of waste bituminous and anthracite coals in Northern Appalachia is also represented in the CMM. Currently, waste coals are consumed primarily by independent power producers.

There is some indication coal rank is correlated with the capability of different technologies to remove Hg from the stack gases of electric power plants (see Table 5), but it is not entirely clear why Hg removal rates vary by coal rank. A number of factors are known to affect Hg removal, such as chlorine content of the coal, the chemical state of the Hg in the coal (elemental or in compound), boiler temperature and firing type, and flue gas temperature. Others are not yet well understood, such as the ability of fly ash itself (generated during combustion) to absorb Hg. Chlorine reacts with elemental Hg during combustion to form oxidized Hg, which is more effectively removed from the flue gas of coal-fired units equipped with wet SO₂ scrubbers.^a

Data on chlorine content, from the U.S. Environmental Protection Agency’s 1999 Information Collection Request, typically indicate a substantial difference in chlorine content between bituminous and subbituminous coals. For example, the average chlorine content associated with the CMM coal supply curves for bituminous coals from the Northern Appalachian and Central Appalachian (southern West Virginia, Virginia and eastern Kentucky) regions ranges from approximately 800 to 1,200 parts per million (ppm), whereas the average chlorine content of low-sulfur subbituminous coal from the Powder River Basin (Wyoming and Montana) region is 120 ppm.

^aN. Shick, “Mercury’s Pathways to Fish,” EPRI Journal, Vol. 8 (December 22, 2000).

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