After many decades of operating in a comprehensive regulated market structure, the electric utility industry is facing significant change, both from new generating and transmission technology and from shifting policy perspectives with respect to competition and regulation. The electric utility industry is a major source of air pollution, particularly sulfur dioxide (SO₂), nitrogen oxides (NOx), and Mercury (Hg), as well as of suspected greenhouse gases, particularly carbon dioxide (CO₂). At issue is whether proposed legislation to restructure the industry should include environmental protections.

Future electricity demand and implementation of air quality regulations will determine air emission impacts from electricity restructuring. Those who are concerned that the existing regulatory regimen will not work effectively as the industry restructures have introduced legislation to strengthen pollution control on electric generating facilities. Currently, ten bills have been introduced, and more are anticipated as the restructuring debate continues.

This report provides a side-by-side comparison of the major provisions of environmentally related legislation introduced with respect to electric restructuring. It will be updated as events warrant.

Introduction

Electric utility generating facilities are a major source of air pollution. The combustion of fossil fuels (petroleum, natural gas, and coal), which account for 67% of U.S. electricity generation, results in the emission of a stream of gases. These gases include several pollutants that directly pose risks to human health and welfare, including sulfur dioxides (SO₂), nitrogen oxides (NOx), and mercury (Hg). Other gases may pose indirect risks, notably carbon dioxide (CO₂), which may contribute to global warming. ⁽¹⁾ Table 1 provides estimates of SO₂, NOx, and CO₂ emissions from electric generating facilities. Emissions of Hg from utility facilities are more uncertain, and are estimated at about 52 tons. Utilities are currently subject to an array of environmental regulations, which differentially affect both the cost of operating existing generating facilities and of constructing new ones.

Table 1: Emissions From U.S. Fossil-fuel Electric Generating Plants
(thousands of short tons)

Source: Energy Information Administration, Electric Power Annual 1998, vol. II, p. 40

After many decades of operating in a comprehensive regulated market structure, the electric utility industry is facing significant change, both from new generating and transmission technology and from shifting policy perspectives with respect to competition and regulation. At issue is whether these changes will increase air pollution emissions. Specifically, some argue that this singular focus on economic efficiency could come at the expense of other values that the regulatory system traditionally has balanced against economic efficiency, particularly equity and environmental considerations. The environmental concern with respect to restructuring is that the new economic signals being given by a competitive generation market could result in increased emissions of undesirable pollutants, particularly NOx.

Previous CRS analysis suggests that the environmental effects of restructuring depend on whether, for conventional air pollutants, the existing regulatory regimen will work effectively as the industry structure changes. For some pollutants, such as SO₂, the nationwide emission "cap" seems secure; but for others, particularly NOx, the state-led implementation process may have difficulty coping with regional disparities in emissions. For CO₂, any controls would be contingent on future ratification of the Kyoto Agreement to curtail emissions and on domestic implementing legislation. ⁽²⁾

Proposed Legislation in the 106^th Congress

Currently, ten bills have been introduced in the 106^th Congress to increase pollution controls on electric generating facilities. They are summarized in table 2. All of the bills control at least NOx and SO₂; others include CO₂ and Hg. S. 673, was not included as it pertains only to Hg, and its scope extends beyond electric generating facilities.

Two of the bills, H.R. 25 and S. 172 are companion legislation focused on SO₂ and NOx, with EPA to regulate Hg after a monitoring network has been installed. The bills build on the SO₂ allowance trading scheme contained in title IV of the 1990 Clean Air Act Amendments (CAAA); under this program utilities are given a specific allocation of permitted emissions (called allowances), and may choose to use those allowances at their own facilities, bank them for future use, or sell them to other utilities needing additional allowances. A third bill, H.R. 657 is very similar to H.R. 25/S. 172 except that the penalties for non-compliance with the NOx provisions are more severe.

S. 1369 and H.R. 2569 also have similarities in terms of controlling SO₂, NOx, CO₂ and Hg, but have significant differences, particularly with respect to implementation strategies. H.R. 2569, like H.R. 25/S. 173 and H.R. 4861, builds on the allowance system contained in title IV of the 1990 CAAA. In contrast, S. 1369 uses a credit system, as used in EPA's offset program, to allow facilities to gain credits from reducing their emissions below that specified in the legislation. Thus, a utility would get an emission credit after it has shown its over-compliance with the bill's provisions. How this post facto system would work with the allowance type system of title IV is unclear. ⁽³⁾

The sixth bill introduced, H.R. 2645, is the most stringent with respect to mandating "elimination" of Hg emissions. The bill is also unique in employing an emission rate approach to implementation. Utilities would be required to meet a specified emission rate, rather than a tonnage cap as the above bills employed. The rate would be based on the desired emission cap specified in the bill and an EPA estimate of expected electricity generation in a given year.

The seventh bill introduced, H.R. 2900, controls SO₂, NOx, CO₂, and Hg, but provides considerable flexibility to EPA in developing implementation strategies. Specifically, EPA implementing regulations are required to allocate reductions equitably and may consider market-oriented mechanisms (except for Hg).

The eighth bill introduced, H.R. 2980, controls SO₂, NOx, CO₂, and Hg, but with individual unit-by-unit requirements for SO₂ and NOx based on output-based emission rates and average 1996-1998 fuel consumption, a percentage reduction requirement for Hg, and an allowance based system for CO₂. Apparently, plants built after 1998 must emit no SO₂ or NOx, as their historical fuel consumption would be zero.

The ninth bill introduced, S. 1949, is unique in combining individual unit-by-unit emission rate limitations and/or percentage reduction requirements with mandated combustion efficiency standards to control SO₂, NOx, CO₂, and Hg. The bill does not include any sort of allowance or credit trading program.

The tenth bill introduced, H.R. 4861, is an expansion and strengthening of H.R. 25. Besides extending controls to include CO2, the bill includes a renewable portfolio standard and net metering provisions.

Table 2: Comparison of NOx Control Proposals

Unless otherwise noted, estimates by CRS using Department of Energy and Environmental Protection Agency data.

Footnotes

1. ^(back)Steam-electric utilities produce only minor amounts of volatile organic compounds (VOCs), carbon monoxide (CO), and lead -- on the order of 2% or less of all sources.

2. ^(back)Larry Parker and John Blodgett, Electricity Restructuring: The Implications for Air Quality, CRS Report 98-615, updated July 14, 2000.

3. ^(back)For more on the difference between allowance type and credit type schemes, see: Larry Parker, Global Climate Change: Market-Based Strategies to Reduce Greenhouse Gases, CRS Issue Brief IB97057, updated regularly.