Electricity Restructuring: The Implications for Air Quality

Congressional research reportJan 4, 2001

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Electricity Restructuring:

The Implications for Air Quality

Updated January 4, 2001

Larry Parker and John Blodgett

Specialists

Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

ABSTRACT

In the context of federal and state proposals to restructure the electric utility industry, this

paper analyzes forces and policies affecting utility generation that may have consequences for

emissions of air pollutants and of greenhouse gases. Key concerns are potential increases in

nitrogen oxide emissions, raising questions about the effectiveness of the Clean Air Act to

regulate a restructured industry, and in carbon dioxide emissions, which are not currently

regulated but could be if the U.S. ratifies the Kyoto Agreement. These issues may be raised

in the context of electricity restructuring legislation. For ongoing legislative activities, see

CRS Issue Brief IB10006, Electricity: The Road Toward Restructuring. This report will be

updated as events warrant.

Electricity Restructuring: The Implications for Air Quality

Summary

The electricity generating industry is currently undergoing change, both from

new generating and transmission technologies and from shifting policy perspectives

with respect to competition and regulation. As the industry is a major source of air

pollution as well as of greenhouse gases, the changes underway are being closely

examined for their potential environmental effects. 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. Projected increases in

electricity demand in the short- to mid-term suggest that restructuring may further

encourage utilities to renovate a sizeable amount of existing coal-fired capacity, which

generally produces more air pollutants and greenhouse gases than alternative types

of generation. The analysis indicates that renovating existing coal-fired facilities is

often very cost-effective compared with new, less polluting construction, portending

the potential for an increase in emissions of some air pollutants, especially nitrogen

oxides, and of carbon dioxide, a greenhouse gas.

The Clean Air Act regulates emissions of conventional air pollutants from

electric utilities. While it has historically focused on new construction in applying its

most stringent standards, several current and prospective regulations and enforcement

actions could significantly increase controls on existing, coal-fired facilities. These

controls may diminish the attractiveness of renovating older, more polluting facilities,

but the effectiveness of the regulations in coping with a restructured industry remains

to be seen. In addition, greenhouse gas emissions are not currently regulated, so any

increases in carbon dioxide would not be controlled under existing authorities.

Thus 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 sulfur oxides, a nationwide

emissions “cap” seems secure; but for others, particularly nitrogen oxides, the stateled implementation process may have difficulty coping with regional disparities in

emissions. For carbon dioxide, any controls would be contingent on future

ratification of the Kyoto Agreement to curtail emissions and on domestic legislation.

The potential for environmental deterioration from restructuring electricity

generation is difficult to project — both because various technical and economic

changes are affecting the industry at the same time and because of an evolving policy

context. Those focused on preventing environmental deterioration tend to take a

precautionary stance, to propose immediate preventative measures, and to argue that

such measures be attached to available legislative vehicles. In contrast, those who

believe the substantial regulatory structure in place will suffice tend to take a waitand-see position. Further complicating this picture is that attitudes about

restructuring are embedded in and partly a surrogate for a more fundamental debate

that is underway because of global climate change concerns — about the future

direction of energy use in the U.S. and the federal role in affecting it.

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

The Electric Utility Industry and Air Emissions . . . . . . . . . . . . . . . . . . . . . 2

The Argument about Restructuring and the Environment . . . . . . . . . . . . . . 3

Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Restructuring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Environmental Implications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

The Utility Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Meeting Future Electricity Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Transmission Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Implications of Utility Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Environmental Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Example: Nitrogen Oxide Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Air Quality Regulations Impacting on Utilities . . . . . . . . . . . . . . . . . . . . . 12

Implications of Air Quality Regulations for Utilities . . . . . . . . . . . . . . . . . 14

New Construction and Existing Sources . . . . . . . . . . . . . . . . . . . . . . 14

Implementation under Restructuring . . . . . . . . . . . . . . . . . . . . . . . . . 16

The Effects of Restructuring and Environmental Actions on Emissions . . . . . . 18

Economics and Coal-Fired Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Air Quality and Coal-fired Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Assessing the Impacts of Restructuring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Electricity Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Air Quality Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Responses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

List of Tables

Table 1: National Estimated Emissions from Fossil-Fuel, Steam-Electric Utilities —

1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Table 2: NOx and CO2 Emission Rates by Fuel Source . . . . . . . . . . . . . . . . . . . 4

Table 3: Potential Control on Existing Sources . . . . . . . . . . . . . . . . . . . . . . . . 16

Table 4. Costs of New Natural Gas-fired Combined-cycle Facility

(1995 dollars) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Table 5. Potential Pollution Control Cost for Existing Coal-fired Power Plants (500

Mw, 1995$) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Electricity Restructuring:

The Implications for Air Quality

Introduction

Electricity generation is a major source of air pollution as well as of greenhouse

gases. As a result, changes in the electric utility industry raise concern about

environmental consequences. Such changes are currently in the offing, both from new

generating and transmission technologies and from shifting policy perspectives with

respect to competition and regulation. Whether legislation to restructure the industry

should include environmental protections has become an issue. Several bills were

introduced in the 106th Congress to incorporate such protections into any potential

federal restructuring legislation.1 More legislative proposals are expected to be

introduced in the 107th Congress.

This paper reviews the changes now underway in the utility industry from the

perspective of their environmental implications — specifically, the potential for

electric utility restructuring to increase emissions of air pollutants regulated by the

Clean Air Act (CAA) and of greenhouse gases that could be affected by the Kyoto

agreement to address climate change.2 The paper is divided into six parts.

! The Overview provides background on the electric utility industry and current

restructuring efforts, the industry's emissions, and the fundamental argument

with respect to current restructuring activities and potential air pollutant

effects. It identifies electricity demand and air quality regulation as critical to

determining air emission impacts from electricity restructuring.

! The Utility Industry examines the electricity demand component in more detail.

Estimating electricity demand increases in the short- to mid-term and

discussing the implications of transmission capacity for interregional electricity

transfers, the analysis suggests that restructuring may encourage current trends

among utilities to renovate a sizeable amount of existing coal-fired electricity,

which generally produces more air pollution and greenhouse gases than

alternative kinds of electricity generation.

! Environmental Regulation provides background on current air pollution

regulations affecting electric utilities and on the resulting complex system of

For a current review of legislation, see Larry Parker and Amy Abel, Electricity: The Road

Toward Restructuring, Issue Brief IB10006, updated regularly. For a comparison of

initiatives introduced in the 106th Congress, see: Larry Parker, Electricity Restructuring and

Air Quality: Comparison of Proposed Legislation, CRS Report RS20326, updated July 26,

2000.

For current information on the status of the Kyoto agreement and related legislation, see

Wayne A. Morrissey and John R. Justus, Global Climate Change, Issue Brief IB89005.

CRS-2

federal and state, pollutant-by-pollutant controls. It discusses regulatory

implications for existing capacity and new construction, noting that while the

CAA has historically focused on new construction in applying its most

stringent standards, several current and prospective regulations would

significantly increase controls on existing, coal-fired facilities. It also notes

that an increasingly competitive generating market may present significant

challenges to the state-directed environmental regimen of the CAA.

! The Effects of Restructuring and Environmental Actions on Emissions

analyzes the cost-effectiveness of existing coal-fired facilities versus new

construction and the environmental effects of increased utilization of existing

coal-fired facilities. The analysis indicates that renovating existing coal-fired

facilities is generally very cost-effective compared with new, less polluting

construction, pointing to a potential for increasing emissions of some air

pollutants, especially nitrogen oxides, depending on regulatory actions, and of

the greenhouse gas carbon dioxide, which is not regulated.

! Assessing the Impacts of Restructuring examines the Federal Energy

Regulatory Commission’s attempt to estimate the environmental impacts of

introducing competition into the wholesale electricity market, and reactions

to that analysis. It notes the considerable difficulties in attempting to isolate

the potential impact on emissions of restructuring the electricity generation

from other technological and policy trends occurring in the industry.

! The Conclusion reviews possible responses to potential risks to the

environment arising from electricity restructuring. Critical issues are: (1) For

conventional air pollutants, whether the existing regulatory regimen will work

effectively as the industry structure changes; for some pollutants, such as sulfur

oxides, a nationwide emissions “cap” seems secure, but for others, particularly

nitrogen oxides, the state-led implementation process may find it difficult to

cope with increasingly regional utility industry and environmental challenges.

And (2) for greenhouse gases, any controls are contingent on future ratification

of the Kyoto Agreement to curtail emissions and on domestic implementation

legislation.

Overview

The Electric Utility Industry and Air Emissions

The industry is massive, with 1996 assets totaling $696 billion, retail sales of

$212 billion, and wholesale sales (sales for resale) of $47 billion. It consists of 3,195

utilities — 243 investor-owned, 2010 publicly owned, 932 cooperatives, and 10

federal entities. It is difficult to overestimate the importance of electric service to the

nation’s economy and individuals’ quality of life. In 1996, the average residential

customer paid $861 to buy 9,707 kilowatt-hours (809 Kwh monthly) of electricity.3

Based on revenues. Statistics from: Energy Information Administration, Financial Statistics

of Major U.S. Investor-Owned Electric Utilities: 1996, DOE/EIA-0437(96)/1 (Washington,

D.C.: December 1997); and Energy Information Administration, Statistics of Major U.S.

Publicly Owned Electric Utilities: 1996, DOE/EIA-437(96)/2 (Washington, D.C.: March

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The industry is also a major source of air pollution. The combustion of fossil

fuels, which account for 67% of 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 oxides (SO2), nitrogen oxides (NOx,),

particulate matter (PM), volatile organic compounds (VOCs), carbon monoxide (CO),

and various heavy metals, including lead and mercury (Hg). Other gases may pose

indirect risks, notably carbon dioxide (CO2), which may contribute to global

warming.4 (See table 1.)

Of the fossil-fired steam generators, coal-fired facilities contribute a

disproportionately large share of these gases. While coal accounts for about 84% of

fossil-fuel fired electricity generated, it accounts for 90% or more of the gases listed

in table 1 (99% of the Hg). Besides the fuel, the location of a generator can also have

important consequences for air pollution impacts (for CO2, source location is

immaterial). Location can be important both with respect to local ambient conditions

and, because of long-range transport, to downwind areas. For example, with

prevailing air movement from west to east, nonattainment of the ozone air pollution

standard in the Northeast has directed attention to the concentration of coal-fired

generating facilities in the Midwest as possible contributing sources, particularly of

NOx, which is a precursor of smog-forming ozone, among other effects.

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. In particular, air pollution controls impact the construction

and operating costs of fossil-fuel fired facilities — hydropower, nuclear, solar, wind,

and other nonfossil-fueled fired electricity sources produce essentially zero air

pollutants (although they have other environmental impacts). Generally, air quality

regulations impose the greatest costs on coal-fired facilities and the least on natural

gas-fired ones. This disparity would become greater if the U.S. were to accept the

greenhouse gas reduction goals of the Kyoto Agreement. Table 2 illustrates the

variation among fossil fuels for emissions of NOx and CO2.

The Argument about Restructuring and the Environment

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 shifting policy perspectives with respect to competition

and regulation. At issue is whether these changes will increase air pollution emissions.

(...continued)

1998).

Steam-electric utilities produce only minor amounts of VOCs, CO, and lead — on the order

of 2% or less of all sources.

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Table 1: National Estimated Emissions from Fossil-Fuel, Steam-Electric Utilities — 1996

CO2

NOx

PM10

SO2

1000

short

tons

% all

sources

1000

short

tons

% all

sources

1000

short

tons

% all

sources

1000

short

tons

% all

sources

tons

% all

sources

Electric Utilities

2,209,287

6,103

302

13,217

Coal

1,911,627

5,395

273

12,426

51.6

Oil

100,895

208

730

0.2

Gas

195,868

344

Other/Internal

Combustion

897

156

Sources: CO2 — DOE, Energy Information Administration, Electric Power Annual 1998, Vol. II, p. 42; NOx, PM10,

SO2 — EPA, National Air Quality and Emissions Trends Report, 1998 EPA 454/R-00-003 (March 2000), Tables A-4, A-6, and

A-8 [http://www.epa.gov/oar/aqtrnd98/fr_table.html]; Hg — EPA, Mercury Study Report to Congress, Vol. 1, “Executive

Summary” EPA-452/R-97-003 (December 1997), p. 3-6 [Hg data estimated annual emissions 1994/1995].

Table 2: NOx and CO2 Emission Rates by Fuel Source

Fuel

NOx Emissions

(lb./mmBtu)

CO2 Emissions (lbs.

carbon/mmBtu)

Coal

0.1 - >2

55.9

Natural Gas

0.005 - >1

31.7

Residual Fuel Oil

0.05 - >1

46.8

Range for NOx reflects the difference between best available control technology and emissions from an uncontrolled existing power plant.

Sources: NOx — Larry Parker, Nitrogen Oxides and Electric Utilities: Revising the NSPS, CRS Report 96-737, July 25, 1997;

CO2 — EIA, Emissions of Greenhouse Gases in the United States: 1987-1992 (Washington, D.C., 1994), Appendix A; and EIA,

Emissions of Greenhouse Gases in the United States: 1987-1994 (Washington, D.C., 1995), p. 18.

CRS-5

Technology. The advent of new generating technologies, particularly natural

gas-fired combined cycle, has both lowered entry barriers to competitors of traditional

utilities and lowered the marginal costs of those competitors below that of some

traditional utilities. As noted by the Federal Energy Regulatory Commission (FERC),

smaller and more efficient natural gas-fired, combined cycle generation plants can

produce power on the grid for between 3 cents and 5 cents per kilowatt-hour (Kwh).

This is typically less than for the larger coal-fired (4-7 cents/Kwh) or nuclear (9-15

cents/Kwh) plants built by traditional utilities over the past decade.5 Indeed, it is less

than the average generating costs of some utilities. Coupled with advances in

generating technology have been advances in transmission technology that permit long

distance transmission economically and permit increasingly coordinated operations

and reduced reserve margins.

This technological advancement has been combined with legislative initiatives,

such as the Energy Policy Act of 1992 (EPACT), to encourage the introduction of

competitive forces into the electric generating sector. This shift in policy continues

with the promulgation of FERC Order 888 encouraging competition in the wholesale

electricity market and implementation by some states of retail competition initiatives.

Restructuring. The policy shift underlying the changes occurring in the electric

utility industry is a growing belief that the rationale for the current economic

regulation of electric utilities at both the federal and state levels — that electric

utilities are natural monopolies — is being overtaken by events, and that market

forces can and should replace some of the current regulatory structure. Regulation

and rate-of-return ratemaking6 arguably exist as a partial substitute for the

marketplace. The emerging trend in the industry suggests that regulation is an

imperfect substitute for the marketplace and that with emerging new generating and

transmission technologies, real self-regulating market forces are now able to replace

government regulation in many instances. This substitution could result in a more

efficient allocation of the country's resources and provide consumers with more

accurate price signals regarding the actual cost of electricity.

The restructuring effort attempts to reduce and alter the role of government in

electric utility regulation by identifying transactions, industry segments, regions, or

specific activities that might no longer be the subject of economic regulation. Current

proposals to increase competition in the electric utility industry involve segmenting

electric functions (generation, transmission, distribution) that are currently integrated

(or bundled) in most cases (both in terms of corporate and rate structures). The

overall purpose of restructuring is to promote economic efficiency, which will

presumably lead to lower overall rates.

FERC, “Promoting Wholesale Competition ... [Final Rule],” 61 Federal Register (May 10,

1996), 21544.

Rate-of-return ratemaking means that a regulatory body allows the utility to obtain a

guaranteed rate of return on investment. The regulatory body specifies a utility’s legitimate

costs and approves rates that allow the recovery of those costs plus a regulatorily determined

acceptable profit. Wholesale sales are regulated by FERC; retail sales are regulated by state

Public Utilities Commissions, which may also regulate investment and debt.

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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 for two basic reasons: (1) lower baseload prices resulting from

restructuring would increase electricity demand and, therefore, increase generation

and emissions; and (2) the restructured generating market’s revaluation of existing

facilities to the marginal cost of constructing new capacity (along with their low

operating costs) would encourage the rehabilitation and full utilization of these older,

more polluting generating facilities.

Proponents of restructuring argue that it would increase efficiency and reduce

electricity costs. To the extent greater competition and lower costs translate into

lower prices, demand can be expected to rise (and incentives to conserve electricity

and for new technologies such as renewable energy can be expected to decline).

More demand would require more generation, resulting in more emissions. How

much emissions might increase would depend on what facilities generate the

additional power and on controls imposed by existing or prospective Clean Air Act

requirements, as discussed below. Some cost studies indicate that the lion's share of

cost savings from restructuring would come from the increased use of existing coalfired capacity7 — which is disproportionately more polluting than alternative sources

of power. If true, then the need for new (cleaner) generating capacity could be

delayed by restructuring, as production from existing capacity is maximized.

Based on the above, the general scenario goes as follows. A competitive

generating sector would result in a revaluation of generating assets — i.e., moving

from a traditional embedded-cost valuation scheme to a market valuation scheme,

which would increase the value of some generating capacity and decrease the value

of other generating capacity. Competition would tend to move the value of

generating capacity to the marginal cost of constructing new capacity, generally

represented at the current time by a new natural gas-fired, combined-cycle facility.

In general, older facilities that have been fully depreciated would tend to have market

values greater than their current book value under regulation; in contrast, newer,

capital intensive facilities (such as some nuclear plants) would have market values less

than their current book value. (Case-by-case valuation would be affected by location,

availability of alternatives, and electricity demand.) In addition, the Clean Air Act

typically imposes its most stringent pollution controls on new powerplant

construction, permitting existing capacity to meet less stringent and less costly

standards. This differential impact may give some older facilities a competitive

operating cost advantage to complement their low, depreciated cost basis.

The new valuation, combined with low operating costs, would encourage

operators to maximize generation from their existing facilities. The trend toward

increased utilization have already begun. In 1995, coal-fired facilities operated at a

For example, see Michael T. Maloney and Robert E. McCormick, Customer Choice,

Consumer Value: An Analysis of Retail Competition in America's Electric Industry, prepared

for the Citizens for a Sound Economy Foundation (1996 ).

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62% capacity factor. By 1999, operation of coal-fired capacity had increased to 67%.

The upper limit here is unclear -- the economic and environmental advantages of new

technology, such as natural gas-fired, combined-cycle technology (a very clean

technology) may be sufficient in some cases to overcome the advantages of expanding

use of existing plants.

Environmental Implications. It is this renewed attractiveness of existing

capacity under restructuring, specifically of coal-fired capacity, along with the

potential that demand for electricity may rise (and energy conservation slacken) if

prices decline, that raises environmental concerns. Absent effective controls, burning

more coal will produce more emissions than alternative sources of electricity

generation — and much of that coal capacity is in the Midwest, which is currently a

center of attention for reducing NOx emissions.

Except for CO2, the regulatory regimen of the Clean Air Act provides authorities

for controlling the potential increase in emissions — assuming they are effectively

implemented. Existing controls “cap” SO2 emissions in the 48 contiguous states and

the District of Columbia, and there is no reason to question the effectiveness of the

cap in the future, regardless of the changes underway in the utility industry. For NOx

emissions, control and implementation is more complicated, primarily because

implementation of much of the process lies with the states. Any increase in NOx

emissions in the Midwest could complicate an already difficult process underway to

reduce the region’s NOx emissions, which contribute to ozone nonattainment in the

Northeast.8 How this regional, state-implemented process would be affected by

restructuring is not certain.

CO2 is not currently regulated. Any increase in fossil fuel-fired generation will

increase CO2 emissions, with coal producing about 75% more carbon emissions than

natural gas on a Btu basis. If the U.S. were to ratify the Kyoto Agreement, which

would require the U.S. to reduce greenhouse gas emissions to below 1990 levels, any

increases would have to be rolled back or offset.9 The effort required would be

increased if restructuring differentially advantaged coal.

Ultimately, whether developments in electricity generation and demand lead to

increased emissions of air pollutants depends on the implementation of the CAA (and

on any new requirements that might be enacted); while for CO2, increases are likely

unless Congress ratifies the Kyoto Agreement and enacts implementing legislation (an

uncertain prospect). Those who are focused on preventing environmental

deterioration tend to take a precautionary stance, to propose immediate preventative

measures, and to argue that such measures be attached to available legislative

vehicles. In contrast, those who doubt that there will be significant environmental

For a discussion of those efforts, see Larry Parker and John Blodgett, Air Quality: EPA’s

Ozone Transport Rule, OTAG, and Section 126 Petitions — A Hazy Situation? CRS Report

98-236, updated July 14, 2000.

For a discussion of U.S. global climate change policy, see Larry Parker and John Blodgett,

Global Climate Change Policy: From “No Regrets” to S. Res. 98, CRS Report RL30024,

January 12, 1999.

CRS-8

effects and/or who are focused on the substantial regulatory structure in place tend

to take a wait-and-see position.

The current attention on increased emissions from coal-fired generation may

address the clearest and most quantifiable risk to the environment from restructuring,

but with so many changes underway, the ultimate outcome remains uncertain. Some

trends are already manifest, such as renovation of existing coal-fired capacity. Others

are just emerging, such as a “green market” in California, in which consumers can

take into account environmental costs in their purchasing decisions. Some effects

remain to be determined in the future, such as the implications of new price signals for

demand and conservation; the implication of new cost valuations for the choice of

new generating technologies; developments in transmission capacity; and the

effectiveness of ongoing environmental programs. These complexities and their

interactions are explored in more detail in the following discussions.

The Utility Industry

Utility industry variables affecting emissions include: overall demand for

electricity, which will respond to any changes in prices; the mix of fuels, which will

be strongly affected by demand, especially for baseload capacity; and transmission

capacity, which will affect what generators can respond to demand. Also crucial are

environmental regulations that set limits on certain emissions and/or shift costs among

generating facilities. This interactive matrix makes it difficult to separate out the

environmental effects of any one component, such as restructuring.

Meeting Future Electricity Demand

In general, the United States has more electric generating capacity than it needs

to maintain reliability. Currently, capacity margins10 of between 12% and 17% are

considered necessary to maintain adequate reliability.11 Nationwide, U.S. capacity

margins average 15% — varying from about 13% to 18% on a regional basis.12

These capacity margins are expected to fall in the future as demand increases. The

planned capacity margin in 2008 is 9.1%, unless announced new merchant plant

capacity comes on line as intended. In that case, the 2008 capacity margin would be

15.6%.

Capacity margins should not be confused with reserve margins. Capacity margin is the

difference between generating capacity and peak load expressed as a percent of generating

capacity. Reserve margin is the difference between generating capacity and peak load,

expressed as a percent of peak load. Thus, a 17% capacity margin is roughly equivalent to

a 20% reserve margin.

Capacity margins are generally set according to a Loss of Load Probability (LOLP)

calculation — a measure of the long-term expectation that a utility will be unable to meet

demand. A 1 day in 10 year LOLP is typical.

Data for 1999. North American Electric Reliability Council, Reliability Assessment: 19992008 (Princeton, NJ: NERC, May, 2000), p. 14.

CRS-9

On the surface, these numbers would suggest that there would be a general need

for new capacity in the short- to mid-term (5-10 years), providing opportunities for

different generating technologies, such as natural gas combined-cycle technology,

coal-fired technologies, renewables, and nuclear power. However, this may not be

the case for some regions. Much of the planned construction to meet the capacity

growth needs identified above is designed to meet anticipated peak load, not baseload

needs.13 Capacity that is not dispatchable on demand, such as some renewables and

nuclear power, may not fit the demand curve over this time period. For example,

utilities representing the southeastern U.S. estimate that nearly 90% of the projected

26,990 Mw of new capacity coming on line over the next 10 years will be nonbaseload capacity. Similarly, the utilities representing the industrial Midwest estimate

that 94% of the projected 13,500 MW of new capacity coming on line will be

combustion turbines (a technology typically used for meeting peak load).14

This lack of planned construction for new baseload generating units reflects, in

part, an existing surplus of baseload capacity, particularly coal-fired capacity. 15 In

1995, coal-fired capacity operated at a 62% capacity factor. By 1999, this had

increased to 67%.16 If demand and economics justified it, this average could improve

to 75% or more. An increase to 75% capacity would be equivalent to about 23,000

Mw of baseload capacity — sufficient to meet increases in aggregate baseload

demand for a couple of years, depending on transmission capacity constraints. (An

increase to 85% capacity would be equivalent to about 53,000 Mw.) Thus, it would

appear that under current expectations, existing baseload facilities, such as nuclear

plants, and new baseload construction, such as natural gas combined-cycle, may in

many cases be competing against existing coal-fired facilities for the next 5-10 years.

Transmission Capacity

The degree to which existing coal-fired capacity competes against other baseload

technologies will be partially dependent on transmission capacity. Under ideal

economic conditions, the price of providing baseload electricity would tend to levelize

across the country, reflecting a nationwide market for such electricity. In reality, this

is unlikely to occur until and unless substantial improvements are made in transmission

capacity and the robustness of the transmission grid. An increase in market forces in

the generating sector does not necessarily translate into the increased transmission

Baseload refers to the minimum amount of electric power delivered or required over a given

period at a constant rate. Baseload powerplants, like nuclear plants, are designed to operated

whenever they are available (generally over 60% of the time).

North American Electric Reliability Council, Reliability Assessment: 1996-2005 (Princeton,

NJ: NERC, October 1996).

The lack of planning also reflects the shortening of lead-times for new construction,

uncertainty about future demand, and uncertainty about the future structure of the generating

sector.

It is this trend in coal-fired generation utilization that caught the attention of EPA and the

possibility for action under the New Source Review requirements of the Clean Air Act. For

more information, see Larry B. Parker and John E. Blodgett, Air Quality and Electricity:

Enforcing New Source Review, CRS Report RL30432 (January 31, 2000).

CRS-10

capacity and robustness that would allow consumers to fully exploit potential

generation savings.

Under current restructuring proposals, the transmission sector remains a

monopoly controlled by rate-of-return regulation. The history of this approach to

transmission planning has resulted in a system focused on and justified by local

reliability concerns, not a system concerned with maximizing economic efficiency on

a nationwide or even interregional basis. How well and how completely the

regulatory structure can be changed to facilitate the dynamics of a deregulated

generating sector is difficult to predict. Market prices may regionalize, reflecting the

increasingly regional control of transmission, but large-scale interregional

transactions may be several years away.

If transmission barriers result in largely regional markets, marginal costs for

baseload capacity may differ between regions. For example, regions with substantial

excess coal-fired capacity may have low marginal costs based on the incremental costs

of increased capacity utilization. Other regions, with substantial increasing demand,

may have marginal costs based on new construction costs, such as building a natural

gas-fired combined-cycle plant or a coal-fired fluidized bed combustor. Depending

on price, a generating technology that is competitive “on average” may not be

competitive within a specific region, because of low-cost alternatives; likewise, a

“higher cost” generating technology that is non-competitive “on average” may be

competitive within a specific region because of the higher cost of alternatives.

Implications of Utility Developments

All of these factors will be summed up in the price for baseload power. It is

generally assumed that deregulation of the generating sector will encourage the

development of marginal cost pricing.17 In particular, deregulation will clearly expose

the substantial cost differences between baseload generation and peak generation.

While baseload facilities generally run at over 60 percent capacity, peak demand

facilities run at under 20 percent capacity. This substantial difference in utilization,

among other differences, means that peak power will cost more under restructuring

than it does now, when the cost is generally rolled in with the less expensive baseload

power.18

Marginal cost has been used by some public utility commissions to determine appropriate

rates between different customer classes for several years, and utilities have also experimented

with “time-of-day” rates that reflect marginal costs across time. Under restructuring,

generating costs may move more in the direction of “time of day” pricing as more reflective

of actual costs than the current average cost method.

As stated by a study done for the American Gas Association study of future electric

generation: “In principle, retail deregulation and retail wheeling, should radically change the

current pricing structure for end-use electricity. Peak pricing will increase sharply and offpeak pricing will decrease sharply.” Harry Chernoff, Existing and Future Electric

Generation: Implication for Natural Gas, Study prepared for the American Gas Association,

Policy Analysis Group, by Science Applications International Corporation (October 1996)

p. 23.

CRS-11

At least in the short-term, this stratification of electricity pricing may mean that

the market price for baseload power will be considerably lower than the current

average electricity price would indicate. This would encourage the use of existing

baseload capacity with low operating costs (e.g., coal-fired capacity) and discourage

constructing new baseload facilities, particularly those technologies requiring

substantial investment (e.g., nuclear power). Low baseload prices may also discourage

development of non-dispatchable power sources (e.g., some renewable technologies)

and installation of some conservation technologies. Higher prices for peaking power

would encourage technologies designed for such load (e.g., combustion turbines), and

technologies designed to reduce such loads (e.g., load management techniques). In

the long term, if prices for electricity decline, electricity use is likely to increase and

incentives to conserve electricity are likely to decrease. Long-term declining prices

could also reduce incentives for new technologies, including some renewable energy

technologies.

How these different effects play out will determine the potential for increased

emissions from restructuring. Although the overall effect on emissions is difficult to

assess, involving several currently unquantifiable variables, the most substantial

environmental effect in the short- to mid-term is likely to come from enhanced

operation of existing coal-fired capacity. Whether one can ascribe that effect strictly

to restructuring is debatable, however.

Environmental Regulation

The Clean Air Act imposes a complex regulatory structure on air pollution

sources. From an historical perspective, the regulatory environment for a major

emission source, like an electric generating facility, has been largely dependent on two

factors: (1) Where the facility is located (in an area meeting clean air standards, or in

an area not attaining them) and, (2) How old the facility is (new or old source). Other

factors, such as facility size and specific pollutants controlled, feed off these two

factors. This framework is changing, however, as illustrated in the following case

study on NOx.

Example: Nitrogen Oxide Control

Nitrogen oxides, both directly and because they contribute to formation of

ozone, raise human health and environmental concerns that bring them under the

purview of the CAA. Nitrogen dioxide (NO2), the index compound for nitrogen

oxides, can irritate the lungs and lower human resistance to various respiratory

infections, such as influenza. In combination with volatile organic compounds

(VOCs) and in the presence of heat and sunlight, NOx forms ozone, for which human

health concerns include lung damage, chest pain, coughing, nausea, throat irritation,

and congestion. Ozone also exacerbates the effects of bronchitis, heart disease,

emphysema, and asthma.19 In addition, nitrogen oxides contribute to the formation

For a discussion of human health effects of air pollution, see Morton Lippmann, “Health

Benefits from Controlling Exposure to Criteria Air Pollutants,” in John Blodgett, ed., Health

(continued...)

CRS-12

of fine particulates, suspected of significant human mortality and morbidity effects and

for which EPA recently set new standards that will become effective in 10 to 15

years.20

Environmental concerns about NOx emissions include its transformation into

nitric acid, a component of acid precipitation; visibility impairment; and adverse

effects of ozone on plant life.21 In addition, EPA estimates that up to 40% of the

nitrogen “loading” in the Chesapeake Bay, resulting in excessive nutrient enrichment,

is the result of deposition of air-borne nitrogen oxides. In the West, nitrogen oxides

contribute to visibility impairment, particularly in southern California.

These multiple effects result in multiple control measures under the Clean Air

Act, as described below.

Air Quality Regulations Impacting on Utilities

Primary National Ambient Air Quality Standards (NAAQS) set maximum

levels of permitted pollution concentrations nationwide. NAAQS are federally

enforceable with specific deadlines for compliance; they are required by Section 109

of the CAA to protect the public health with an “adequate margin of safety.” They

are periodically reviewed to take into account the most recent health data. Three

NAAQS may result in NOx controls: NAAQS for nitrogen dioxide, ozone, and fine

particulates.

In 1994, all monitoring locations in the U.S. were in compliance with the NO2

NAAQS; however, compliance with the ozone NAAQS remains elusive in several

parts of the country, particularly in southern California, the Texas Gulf Cost, and the

Northeast corridor (from Virginia to Maine). Because NOx is a precursor to ozone

formation, NOx control represents an important component in reducing ozone

pollution. In recognition of the multi-state nature of the ozone problem in the

Northeast, the 1990 CAA Amendments created an Ozone Transport Commission

(OTC) to development and coordinate emission reduction efforts for the area. In

addition, in 1998, the EPA promulgated a new ozone transport rule that would

control NOx emissions for 21 eastern states, and ten states petitioned the EPA to

control NOx emissions in the Midwest under section 126 of the CAA. 22

(...continued)

Benefits of Air Pollution Control: A Discussion, CRS Report 89-161, February 27, 1989,

pp. 75-144.

John Blodgett, et al., Air Quality Standards: EPA’s Final Ozone and Particulate Matter

Standards, CRS Report 97-721 (Updated June 19, 1998).

For a discussion of ozone and acid precipitation effects on vegetation, see David S. Shriner,

et. al., Response of Vegetation to Atmospheric Deposition and Air Pollution: State of

Science and Technology Report 18 (Washington, D.C.: National Acid Precipitation

Assessment Program, December 1990).

For more information, see Larry Parker and John Blodgett, Air Quality: EPA's Ozone

Transport Rule, OTAG, and Section 126 Petitions — A Hazy Situation? CRS Report

(continued...)

CRS-13

For areas in attainment with these NAAQS, the CAA mandates states to require

new sources, such as powerplants, to install Best Available Control Technology

(BACT) as the minimum level of NOx control required of a new powerplant.23 State

permitting agencies determine BACT on a case-by-case basis, taking into account

energy, environmental and economic impacts. BACT can be much more stringent than

the federal New Source Performance Standard (NSPS — described below), but can

not be less stringent than NSPS. Existing sources are not required to install controls

in attainment areas.

For areas not in attainment with one or more of these NAAQS, the CAA

mandates states to require new sources to install Lowest Achievable Emissions Rate

(LAER) technology. Along with offset rules, LAER ensures that overall emissions

do not increase as a result of a new plant's operation. LAER is based on the most

stringent emission rate of any state implementation plan or achieved in practice

without regard to cost or energy use. It may not be less stringent than NSPS.

Existing sources are required to install Reasonably Available Control Technology

(RACT), a state determination based on federal guidelines.

A Prevention of Significant Deterioration (PSD) program (Part C of the

CAA) focuses on ambient concentrations of pollutants (including NO2) in “clean” air

areas of the country (i.e., areas where air quality is better than the NAAQS). The

provision allows some increase in clean areas’ pollution concentrations depending on

their classification. In general, historic or recreation areas (e.g., national parks) are

classified class 1 with very little degradation allowed while most other areas are

classified class 2 with moderate degradation allowed. Class 3 areas are permitted to

degrade up to the NAAQS. New sources in PSD areas must undergo preconstruction

review and must install BACT; state permitting agencies determine BACT on a caseby-case basis, taking into account energy, environmental, and economic impacts.

More stringent controls can be required if modeling indicates that BACT is

insufficient to avoid violating PSD emission limitations, or the NAAQS itself.

A complement to the PSD program for existing sources is the regional haze

program (section 169A) that focuses on “prevention of any future, and the remedying

of any existing, impairment of visibility” resulting from manmade air pollution in

national parks and wilderness areas.24 Among the pollutants that impair visibility are

sulfates, organic matter, and nitrates. In 1999, the EPA promulgated a regional haze

program, which, would entail more stringent controls on NOx and SO2. However,

like the fine particulate NAAQS, it will be several years before any regional haze

program might result in controls.

(...continued)

98-236, updated July 14, 2000. For recent activities with respect to these initiatives, see:

Larry B. Parker and John E. Blodgett, Air Quality and Electricity: Initiatives to Increase

Pollution Controls, CRS Report RS20553, December 28, 2000.

More stringent controls can be required if modeling indicates that BACT is insufficient to

avoid violating the NAAQS.

See James McCarthy, et al., Regional Haze: EPA's Proposal to Improve Visibility in

National Parks and Wilderness Areas, CRS Report 97-1010, updated July 9, 1998.

CRS-14

New Source Performance Standards (NSPS) are federal standards defining the

minimum controls necessary for new sources regardless of their location — in

contrast to the PSD and NAAQS standards that focus on ambient concentrations of

pollutants. EPA's NSPS determinations represent the floor for state BACT and

LAER determinations in case-by-case situations.

Required under Section 111 of the CAA, NSPS require major new sources to

install the best system of continuous emission reduction which has been adequately

demonstrated. In making such an assessment, the CAA requires EPA to take into

account “the cost of achieving such reduction and any nonair quality health and

environmental impact and energy requirements.” To keep controls abreast of

technological innovations, the CAA originally required EPA to review and revise

NSPS every four years. But at the time of enactment of the 1990 CAA Amendments,

the last revision of the NOx NSPS for electric and non-electric steam generating units

had occurred in 1979. With substantial technological improvements in controlling

NOx having occurred during the 1980s, the 1990 Amendments (title IV, section

407(c)) required EPA to promulgate a new NOx NSPS for electric and non-electric

steam generating units by 1994 — a deadline EPA did not meet. In September, 1998,

EPA did promulgated a new NOx NSPS. It is considerably more stringent than the

1979 standard for coal-fired facilities, but not particularly stringent for natural gas or

oil-fired facilities.25

The acid deposition control provisions of title IV of the 1990 Amendments

focus on total emissions from existing sources of sulfur dioxide and nitrogen oxides.

For nitrogen oxides, section 407 of title IV requires tangential- and wall-fired (dry

bottom, not cell burner equipped) boilers (group 1 boilers) designated to meet 1995

phase 1 reductions to meet an emission limitation based on low-NOx burner

technology. Regulations for phase 1 NOx reductions were finalized in 1995. For

phase 2 in the year 2000, remaining group 1 boilers are required to meet the same

standard (or more stringent if technology and costs permit) as those covered in phase

1, and boilers with other firing configurations (group 2 boilers) are required to meet

standards based on available technology that is comparable in cost to low-NOx

burners. EPA finalized regulations for phase 2 group 1 and group 2 boilers in 1996

(61 Federal Register 245, pp. 67112-67164).

Implications of Air Quality Regulations for Utilities

In the light of changes in the utility industry, this mix of air quality regulations

has important consequences for (1) utilities’ choices both for construction of new

facilities and operation of existing ones, and (2) the potential effectiveness by which

federal and state air pollution controls apply to a changing industry structure.

New Construction and Existing Sources.

For constructing new powerplants,

the CAA envisions the federal NSPS and the state PSD/BACT program as the

baseline for control efforts in attainment areas, and the state-set LAER and federallybased offset requirements as the baseline in nonattainment areas. For SO2, federal

See Larry Parker, Nitrogen Oxides and Electric Utilities: Revising the NSPS, CRS Report

96-737, updated October 13, 1998.

CRS-15

offset requirements overlay these other requirements. The costs of installing NSPS

(or BACT or LAER or obtaining offsets) on new construction fall most sharply on

coal-fired facilities. This could disadvantage coal in choices among technologies for

new generation.

At the same time, the historically less stringent controls on existing coal-fired

facilities — none in attainment areas, RACT in nonattainment areas — have clearly

advantaged existing sources, particularly coal, in competing with new sources for

meeting generating needs. This may be changing. For existing facilities, especially

coal-fired facilities, a host of new regulatory initiatives may result in more stringent

controls for a number of possible pollutants.

In addition, in what could crucially affect the potential costs of reconditioning

and extending the life of existing coal-fired plants, EPA, together with the Department

of Justice, has initiated a New Source Review (NSR) enforcement process to reduce

pollution from existing sources. The first overt action under this process occurred

November 3, 1999, when the Justice Department filed seven lawsuits against electric

utilities in the Midwest and South, charging them with violations of the NSR

requirements of the CAA. EPA also issued an administrative order against the

Tennessee Valley Authority, alleging similar violations.

The crux of the enforcement actions is the “preconstruction” permitting process

of the NSR, which is designed to ensure that newly constructed facilities, or

substantially modified existing ones, do not result in violations of applicable air quality

standards. The question the enforcement actions raise is whether the specified

facilities engaged in rehabilitation actions that represent “major modifications” of the

plants, in which case the CAA would require the installation of best available control

technology – BACT.

The crucial definition of “major modification” derives from an EPA ruling that

a life extension project by Wisconsin Electric Power Company (WEPCO) triggered

NSR requirements. Since 1992, after considerable litigation and congressional

debate, the “test” to determine the applicability of NSR compares whether a facility’s

projected actual emissions after the modification are more than its actual emissions

before the modification. Utilities argue that the “modifications” EPA cites in the suits

were just routine maintenance, which does not trigger NSR. If EPA’s position in

these suits is upheld, this could have the dual effects of increasing the costs to utilities

of expanding the use of coal-fired utilities in the future and of reducing the emissions

from coal-fired facilities.26

Table 3 identifies the range of environmental actions that are beginning to affect

or may in the future affect emissions from fossil-fuel fired facilities. As discussed in

the next section, these controls could have a substantial influence on the cost of

power from coal-fired facilities, making them less attractive in a competitive

marketplace.

On the NSR enforcement actions, see Larry B. Parker and John E. Blodgett, Air Quality

and Electricity: Enforcing New Source Review, CRS Report RL30432, Jan. 31, 2000.

CRS-16

Table 3: Potential Control on Existing Sources

Pollutant

Potential Controls on Existing Sources

Nitrogen Oxides

Title IV, sec. 407

Ozone Transport Commission (OTC) Rules

Ozone Transport Rule

Section 126 Petitions

Revised Ozone NAAQS

Fine Particulate NAAQS

New Source Review Enforcement

Regional Haze Rule

More stringent Legislationa

Sulfur Oxides

Title IV

Fine Particulate NAAQS

New Source Review Enforcement

Regional Haze Rule

More stringent Legislationa

Mercury

Potential EPA regulation as a HAP

NE Action Plan on Mercury

Potential Legislationa

Carbon Dioxide

Potential ratification of Kyoto Agreement

Potential Legislationa

For information on current legislative proposals relating restructuring to environmental

controls, see Larry Parker and Amy Abel, Electricity: The Road Toward Restructuring, CRS

Issue Brief IB10006. For a review of legislation introduced in the 106th Congress, see: Larry

Parker, Electricity Restructuring: Comparison of Comprehensive Bills, CRS Report

RL30087, July 24, 2000; and, Larry Parker, Electricity Restructuring and Air Quality:

Comparison of Proposed Legislation, CRS Report RS20326, July 26, 2000.

Implementation under Restructuring. The mix of regulatory authorities

results in a complex federal-state process for regulating the industry. The stateregulated utility system meshed reasonably well with the state-implemented air quality

controls. As the utility industry becomes more competitive and potentially more

regional, and as air quality problems also become more regional (regional haze, longrange pollutant transport), state-directed controls on existing sources may prove less

efficient and effective than previously.

These regional challenges may reprise the past inability of the state-led process

to control acid rain, the result of long range transport of SO2, for which utilities are

a major source. As a result of the failure of the state-based process to address this

problem, Congress in 1990 added the acid rain program to the CAA, which

established a national “cap” on emissions. This has proven an efficient program; SO2

credits are not excessively expensive and the most popular technology for new

construction — natural gas-fired combined-cycle technology — produces almost no

CRS-17

SO2 emissions.27 The flexibility and straight-forward compliance mechanism of this

“cap and trade” program would seem to mesh well with a flexible, competitive utility

industry, so electricity restructuring would not appear to create any serious

implementation problems for this SO2 control program.

However, the acid rain program is discrete; there is no comparable nation-wide

“cap and trade” program for other pollutants. For example, as noted earlier, the 1990

CAA Amendments did create an Ozone Transport Region in ten northeastern states

for addressing ozone transport (and NOx, as a precursor) and it authorized EPA to

create others. However, this effort may be inadequate to bring the Northeast into

compliance with the Ozone NAAQS. To bring under control additional sources of

long-range transport, EPA created a 21-state Midwest-Northeast region (where

substantial coal-fired NOx emission increases could occur) subject to the promulgated

Ozone Transport Rule, a feature of which is a voluntary, state-implemented NOx “cap

and trade” program. However, EPA does not have authority to require the states

within the region to act in concert or to impose uniform rules for cap and trade as in

the acid rain program. Thus, how this regional effort to control NOx would work in

practice remains to be seen; interstate disagreements have surfaced, and industry

restructuring could change emissions patterns in ways that could exacerbate them.28

The potential for diverse state requirements in the region could lead to

inconsistent requirements that could pose barriers to restructuring the industry — or

opportunities. Differing requirements could allow utilities to choose which state had

the least stringent requirements, while the power could be transmitted to the location

of demand; or inconsistent requirements — or uncertain ones — might be an added

incentive for construction of generating capacity that is clean and hence not subject

to them.

The regulatory dynamic of the Clean Air Act has no direct consequence for

potential increases in CO2 emissions under utility restructuring: CO2 is not subject to

CAA regulation and any controls are prospective, contingent on U.S. ratification of

the Kyoto agreement and on domestic implementing legislation. The uncertainty of

legislative action on CO2 compared to the potential for action on restructuring

legislation in the next couple of years has led some to find in the restructuring issue

a surrogate for a debate on CO2 controls and global climate change in general. This

situation adds complexity to the restructuring debate.

U.S. Environmental Protection Agency, 1996 Compliance Report, Acid Rain Program, EPA

430-R-97-025 (June 1997).

For recent actions with respect to the Ozone Transport Rule, see: Larry B. Parker and John

E. Blodgett, Air Quality and Electricity: Initiatives to Increase Pollution Control, CRS

Report RS20553, December 28, 2000.

CRS-18

The Effects of Restructuring and Environmental Actions

on Emissions

As suggested previously, restructuring involves the interplay of many factors

affecting emissions. As indicated, some, such as renovating existing coal-fired

capacity, represent a furthering of an existing trend. Others, such as green pricing,

represent a new trend created by restructuring. Although the overall effect on

emissions is difficult to assess, involving several currently unquantifiable variables, the

most substantial environmental effect in the short- to mid-term arises from the

potential for enhanced operation of existing coal-fired capacity. However, how much

one should ascribe that effect to general trends in the industry vis a vis restructuring

is debatable.

Economics and Coal-Fired Generation

A general trend in the electric utility industry for over a decade has been the

renovation of existing capacity beyond its initial lifespan (especially coal-fired

capacity) in lieu of constructing new capacity. If restructuring results in a stratification

of electricity pricing in terms of baseload, intermediate, and peak power, the low price

of baseload capacity could provide additional impetus to refurbish existing coal-fired

capacity and to maximize operation of such power. Likewise, lower baseload prices

would likely reduce incentives to conserve electricity and to develop new non-peaking

technologies, including renewable energy. As noted above, substantial amounts of

underused coal-fired capacity currently exist. The degree to which it is competitive

over the next 5-10 years will depend primarily on two factors — cost of enhanced

maintenance to extend the life of the facilities (life extension), and potential for

additional pollution control costs (which is discussed in the next section).

Depending on the condition of an existing coal-fired facility, reconditioning can

be a very economic means of adding baseload capacity.29 This reconditioning process,

called life extension, can help halt and partially reverse the deterioration of a power

plant’s efficiency and reliability during continued operation. Over time, the operation

and maintenance (O&M) of a powerplant increases, along with its heat rate. For

example, based on FERC data, EPA assumes the median O&M costs for coal-fired

facilities up to 10 years old is $17.60/Kw , compared with the median costs for a

facility more than 30 years old of $31.20/Kw.30 However, EPA believes that much

of this increase (about $9.40/Kw) represents continuous reconditioning efforts to

extend the life of the plant — that “life extension” efforts increasingly represent a

continuing upgrading process, rather than a one-time reconstruction of the power

plant.31

ICF Incorporated, Repowering and Life Extension: Background Paper, prepared for the

Office of Atmospheric Programs and Office of Air Quality Planning and Standards, EPA

(draft report) (February 1995).

U.S. Environmental Protection Agency, Office of Air and Radiation, Analyzing Electric

Power Generation Under the CAAA (July 1996), p. A3-11. Estimates in 1995 $.

Part of this represents a strategy by utilities to avoid having to comply with New Source

(continued...)

CRS-19

Thus, one-time projections for life-extension costs overestimate the incremental

cost of this effort. EPA estimates that the cost to extend power plant life from 40 to

65 years will be on the order of $8.8/Kw per year in additional O&M costs — or 1.4

mills/Kwh. Assuming the power plant has been well-maintained up to now, this cost

would appear quite attractive for an additional 20-25 years of operation. Including

estimated O&M and fuel costs, such power plants would generate electricity for about

2 cents/Kwh.32 In general, the potential for rising fuel prices is considered small in the

case of coal. There appears to be ample supply of coal available at current prices.

Against existing coal-fired capacity is newly constructed natural gas combinedcycle technology. Conventional wisdom within the industry is that, based on current

trends in generating technology and fuel costs, the technology of choice for new

construction will be natural gas-fired combined-cycle plants. To illustrate the

sensitivity of new natural gas-fired facilities to fuel costs and technology

improvements, CRS analyzed four different cases. The results are presented in table

4. CRS estimates the annual costs on a levelized basis for a natural gas combinedcycle plant at about 2.4-2.5 cents/Kwh, with costs rising to 3.4-3.5 cents/Kwh if

natural gas prices rise to $3.50/mmBtu compared with $2.25/mmBtu assumed in the

base-case calculations. While very competitive for new construction, it is not quite

competitive, in general, to renovating existing coal-fired capacity. 33

Table 4. Costs of New Natural Gas-fired Combined-cycle Facility

(1995 dollars)

Base case

High fuel cost

case

Higher

efficiency base

case

Higher efficiency/high fuel

cost case

Efficiency

Assumption

7,300

Btu/Kwh

7,300

Btu/Kwh

6,800

Btu/Kwh

6,800

Btu/Kwh

Fuel Cost

Assumption

$2.25/mmBtu

$3.50/mmBtu

$2.25/mmBtu

$3.50/mmBtu

Total Costs

2.5 cents/Kwh

3.4 cents/Kwh

2.4 cents/Kwh

3.3 cents/Kwh

Other assumptions include capital costs of $593/Kw, fixed O&M of $10/Kw/yr., variable

O&M of 0.5 mills/Kwh, capacity factor of 85%, and a real capital charge rate of 10.4%.

(...continued)

Performance Standards (NSPS) at their existing facilities by not triggering the WEPCO rule,

which requires existing facilities to achieve NSPS under some circumstances. It is this

strategy that EPA and Department of Justice are attacking with the NSR enforcement actions

discussed previously.

Calculation assumes heat rate of 10,000 Btu/Kwh, fixed O&M costs of $31 Kw/yr (not

including incremental life extension costs discussed in the text), fuel costs of $1.30 Btu/Kwh,

and a 70% capacity factor.

For reference, CRS calculates that a new coal-fired steam generator would produce

electricity for about 3.5 cents/Kwh, confirming the conventional wisdom with respect to

natural gas.

CRS-20

SOURCES: Environmental Protection Agency, Electric Power Research Institute, CRS

estimates.

As indicated, the analysis strongly suggests that natural gas pricing is the most

important variable in determining generating costs from such plants. In the base-case

analyses, fuel costs represent about two-thirds of the total costs (including capital

charges). In the high cost analyses, fuel costs represent about three-fourths of the

total costs. The importance of fuel costs is lessened a little by continuing

improvements in generating efficiency. However, it is likely to remain the dominant

cost factor over the time period discussed here. This variable would also have to be

factored into any decision about existing coal-fired versus newly constructed natural

gas-fired capacity.

Air Quality and Coal-fired Generation

If restructuring further encourages the increased utilization of existing coal-fired

capacity in lieu of constructing new capacity and discourages energy conservation and

development of cleaner technology because of low baseload pricing or other factors,

the short- to mid-term effects could be increased air pollution. Operating an

additional 23,000 Mw of coal-fired capacity would have significant air emissions,

particularly for CO2, and, depending on the fate of various EPA rulemakings, on NOx.

As SO2 emissions are currently capped by title IV of the 1990 Clean Air Act

Amendments, the effects of restructuring on SO2 emissions should be negligible.

The most substantial effects of restructuring would be for carbon dioxide

emissions, because they are currently uncontrolled. CO2 emissions from 23,000 Mw

of coal-fired capacity would be about 200,000,000 short tons, an increase of about

11% over 1996 CO2 emissions by coal-fired electricity generation. This compares

with emissions from a natural gas combined-cycle equivalent capacity of about

80,000,000 short tons, or a difference of 120,000,000 short tons.

Calculating the potential effects on NOx emissions is more difficult as existing

sources could be controlled under several provisions of the Clean Air Act (see table

3). For example, the final rule for the NOx reduction program under section 407 of

title IV of the Clean Air Act Amendments of 1990 was promulgated in 1996.34 The

rule will reduce the NOx emission rate of coal-fired facilities examined here to an

average of 0.48 lb/mmBtu. Based on this result, emissions from 23,000 Mw would

come to about 480,000 tons, an increase of about 9% over 1996 coal-fired NOx

emissions. This would compare with emission of 70,000 tons from equivalent natural

gas combined-cycle technology, or a difference of 410,000 tons.35

Environmental Protection Agency, “Acid Rain Program; Nitrogen Oxide Emission

Reduction Program,” 61 Federal Register 67111-67264 (December 19, 1996).

Based on an average BACT determination of 0.1 lb./mmBtu. See Larry Parker, Nitrogen

Oxides and Electric Utilities: Revising the NSPS. CRS Report 96-737, updated October 13,

1998.

CRS-21

As identified earlier, other control possibilities, such as implementation of EPA’s

Ozone Transport Rule, also could reduce these emissions substantially.36 Under this

regulation, NOx emissions across a 21-state area are “capped” at a specific level

beginning September 30, 2007. That level of emissions can not be exceeded

regardless of the electric utility industry’s structure.

Similarly, successful prosecution of the NSR enforcement actions could impose

additional control requirements on existing coal-fired facilities.37 Under a restructured

electric generating market, increased pollution control requirements would adversely

affect the economics of affected facilities, which would become more expensive to

operate. Increased capital and operating costs would make coal-fired capacity less

attractive in a more competitive system.

As discussed above, existing coal-fired facilities are particularly vulnerable to

future regulation of several pollutants. To illustrate the sensitivity of these facilities

to increased pollution-control costs, CRS analyzed a representative sample of such

potential costs. The results are presented in table 5. As indicated, control costs for

each of these pollutants would add about 10% or more to the total generation costs

from existing coal-fired facilities. Combinations of control measures would raise

these costs even more.38 With new natural gas combined-cycle technology potentially

available for 2.5 cents/Kwh, increased air pollution control represents a real threat to

the continuing operation of at least some existing coal-fired capacity.

These environmental concerns are not necessarily hypothetical. For example,

member states of the Ozone Transport Commission (OTC) have agreed to stringent

nitrogen oxide controls on stationary sources, including electric generating plants, in

ten northeastern states. Depending on how the states and utilities choose to

implement the program, selective catalytic reduction (SCR) or other control devices

may have to be installed on some coal-fired power plants. This could also be the

result of EPA's Ozone Transport Rule and/or a successful Section 126 petition with

respect to interstate ozone pollution.

For natural gas combined-cycle facilities, the major potential environmentally

related cost increase would be control of carbon dioxide.39 If a new natural gas

combined-cycle plant were required to offset all its potential CO2 emissions under a

For a discussion of the transport rule, see Larry Parker and John Blodgett, Air Quality:

EPA's Ozone Transport Rule, OTAG, and Section 126 Petitions — A Hazy Situation? CRS

Report 98-236, updated July 14, 2000.

For an update on events surrounding EPA NSR enforcement activities, see: Larry B. Parker

and John E. Blodgett, Air Quality and Electricity: Initiatives to Increase Pollution Control,

CRS Report RS20553, updated December 28, 2000.

Readers are cautioned not to simply add the incremental costs of these control measures

together. There may be overlaps or efficiencies to be gained from controlling some of

pollutants together that are presented in Table 5.

The costs estimates cited above already include installation and operation of SCR. Natural

gas plants emit very minor amounts of sulfur dioxide and mercury.

CRS-22

future emissions cap, it could increase operating costs by about 0.2 cents/Kwh.40 This

would raise the total production costs for such facilities to 2.6-2.7 cents/Kwh, or 3.63.7 cents/Kwh if the high-cost gas scenarios were operative.

Table 5. Potential Pollution Control Cost for Existing Coal-fired Power

Plants (500 Mw, 1995$)

Cost Factor

Nitrogen

Oxides

Carbon

Dioxide

Mercury

Sulfur

Dioxide

Capital Costs

$49/Kw

$40.5/Kw

$190/Kw

Fixed O&M

$4.27/Kw

$6.9/Kw

$6.8/Kw

Variable

O&M

0.023

cents/Kwh

0.2

cents/Kwh

0.04

cents/Kwh

0.1

cents/Kwh

Total Costs

of Control

0.17

cents/Kwh

0.2

cents/Kwh

0.22

cents/Kwh

0.53

cents/Kwh

Total

Production

Costs

2.17

cents/Kwh

2.2

cents/Kwh

2.22

cents/Kwh

2.53

cents/Kwh

Control Assumptions: For nitrogen oxides — installation of Selective Catalytic

Reduction (SCR) with 70% removal; for carbon dioxide — buying carbon offsets for 50%

of emissions at $5 a ton; for mercury — installation of carbon injection with spray cooling

and fabric filter; for sulfur dioxide — installation of flue-gas desulfurization (FGD) with 95%

removal.

Sources: U.S. EPA, Office of Air and Radiation, Analyzing Electric Power Generation

under the CAAA (July 1996); and Larry Parker, Coal Market Effects of CO2 Control

Strategies as Embodied in H.R. 1086 and H.R. 2663, CRS Report 91-883, December 13,

1991.

Assessing the Impacts of Restructuring

Emissions from electricity generation are determined by an interactive process

involving a utility industry and an environmental regulatory system that are both

undergoing change. The dynamic linkages between electricity generation, resulting

emissions, and pollution control make it difficult to separate out one factor (in this

case, electricity restructuring) for analysis. The difficulty in doing this has been

illustrated by various studies attempting to estimate the impact of restructuring on the

environment.

This cost is very speculative. For a further discussion, see Larry Parker, Coal Market

Effect of CO2 Control Strategies as Embodied in H.R. 1086 and H.R. 2663, CRS Report

91-883, December 13, 1991.

CRS-23

For example, an early component of electricity restructuring is the Federal

Energy Regulatory Commission’s (FERC) Order 888 that promotes wholesale

competition through open, non-discretionary access to transmission services to all

participants in the wholesale generation market. In developing the Order, FERC

conducted an environmental impact statement (EIS) to examine the implications of

the proposed Order for emissions of pollutants by affected generating facilities. This

assessment covered only a limited part of what would be affected by a comprehensive

restructuring of the electricity generating industry; specifically, the Order is limited to

the transmission of wholesale electricity, about 10% of total sales. Nevertheless,

studies of the rule, including those critical of FERC’s analysis, illustrate the difficulties

in isolating the impacts of restructuring from other factors present in the system.

FERC issued its findings in a draft EIS41 in November 1995. From two baselines

— projections about electricity generation without the proposed rule — FERC

analyzed changes in electricity generation that might result from the proposed rule,

and the consequent changes in emissions that would therefore be expected. The two

baselines differed in assumptions about the relative prices of gas and coal. Based on

the models used by FERC and the assumptions adopted, the analyses indicated that

the proposed rule would have a small effect on emissions. In general, through 2010,

assumptions that favor gas could slightly decrease overall emissions, and assumptions

that favor coal could slightly increase overall emissions. A regional analysis similarly

found relatively small effects. Given the modest environmental impacts, FERC

concluded that there was no need to undertake mitigation — although it discussed

options — and in fact concluded that it had little appropriate authority to require any

mitigation.

Comments on the draft were numerous; they are summarized in the final EIS

issued in April 1996.42 Three issues received particular attention. Two sets of

comments addressed two aspects of the analyses that commenters argued could have

underestimated potential increases in emissions. A third set of comments focused on

the issue of mitigation.

One set of these comments concerned the possibility that restrictions built into

FERC’s analysis on the amount of power that could be transmitted among regions

unduly limited projections of the amount of electricity generated and exported from

high-emitting, coal-fired sources in the Ohio River valley. These comments43

suggested that the rule would increase the amount of power transported, leading to

additional construction of more transmission capacity if necessary, and would thus

result in more emissions than projected. In particular, it would increase NOx

emissions that could be expected to affect the Northeast. As a result, for its final EIA,

Federal Energy Regulatory Commission, Promoting Wholesale Competition through Open

Access Non-Discriminatory Transmission Services by Public Utilities (RM95-8-000) ...

Draft Environmental Impact Statement (November 1995) FERC/EIS-0096D.

Federal Energy Regulatory Commission, Promoting Wholesale Competition through Open

Access Non-Discriminatory Transmission Services by Public Utilities (RM95-8-000) ...

Final Environmental Impact Statement (April 1996) FERC/EIS--0096, Appendix J.

See, for example, Alliance for Affordable Energy, et al., Joint Comment on Draft

Environmental Impact Statement (February 1, 1996), p. 32.

CRS-24

FERC added further analysis of this possibility, but concluded the effects would not

be significant.44

Another set of comments argued that the rule would have the effect of

decreasing electricity prices and therefore would likely increase demand, leading to

the generation of more electricity than assumed in the base cases. FERC basically said

this possibility would be a second-order effect that lay outside appropriate analysis.45

Despite FERC’s response, ignoring demand seems unrealistic. As noted earlier,

electricity demand is a critical component in assessing emission-related impacts.

However, the model FERC used for its analysis is incapable of analyzing the pricedemand effects of restructuring because its demand assumption is exogenous to the

model. FERC chose to assume that the lower prices of restructuring would not result

in any increase in electricity demand from baseline conditions — an unlikely outcome.

To ignore the price-demand relationship reduces confidence in FERC’s conclusion.

The third set of comments, on mitigation, ranged from those supporting FERC’s

conclusion that there was nothing that needs mitigating to arguments that FERC was

obligated and has the authority to require mitigation.46

Subsequent reports challenge the FERC analysis. In April 1997, the Natural

Resources Defense Council, Public Service Electric and Gas Co., and Pace

University’s Mid-Atlantic Energy Project jointly issued a report evaluating the

contribution of utility generating companies to air pollution. Presenting data

indicating that “the ‘lowest cost’ producers of electricity” are often “some of the

highest emitters of pollutants,” the authors concluded that

In order to implement fair competition and to prevent a considerable

increase in electric utility emissions due to increased use of older, higheremitting units, the restructuring process should apply consistent

environmental standards to all competitors.47

In January 1998, the Northeast States for Coordinated Air Use Management

(NESCAUM) issued a report concluding that recent trends contradict FERC’s finding

in the EIS. Specifically, NESCAUM presented data challenging two assumptions that

had led to the EIS conclusion that emissions growth would be negligible. Contrary

to the EIS analysis, NESCAUM shows that between 1995 and 1996, coal-fired

generation increased while natural gas-fired generation declined and that growth in

the use of interregional power transmission had “outstripped FERC’s longer-term

growth assumptions.”48 According to NESCAUM, these

FERC, Final EIS, pp. J-34 - J-39 and pp. 6-25 - 6-41.

See FERC, Final EIS, pp. J-69 - J-70.

Mitigation is discussed in Chapter 7 of the EIS; comments are discussed in the Final EIS at

pp. J-78 - J-105.

Natural Resources Defense Council, et al., Benchmarking Air Emissions of Electric Utility

Generators in the Eastern United States, 2nd Edition (April 1997), p. 41.

Northeast States for Coordinated Air Use Management, Air Pollution Impacts of Increased

(continued...)

CRS-25

preliminary findings suggest that increased competition is contributing to

increased emissions at coal-intensive utilities, and that some form of midcourse public policy correction may be necessary. These findings

underscore the need for comprehensive efforts to document the impacts of

restructuring on air quality, and lend impetus to state and federal efforts to

establish adequate emissions tracking and disclosure systems. Moreover,

these findings suggest that equitable environmental standards must be made

an integral part of ongoing competitive reforms.49

Thus, environmental interest groups continue to warn that FERC underestimated

emissions resulting from its rule — and that restructuring portends even greater

impacts; and that, therefore, mitigation of the effects of the rule and of restructuring

is necessary. However, as suggested above, increased emissions may be the result of

existing trends in the industry, and not strictly due to restructuring. As noted,

renovating coal-fired capacity has been an increasing trend in the industry for over a

decade. As the NESCAUM data reflect a time period before implementation of Order

888, ascribing emission increases solely to restructuring is debatable. This situation

illustrates the difficulties in assigning cause to potential emission increases over the

next 5-10 years from existing coal-fired facilities.

Conclusion

The relationship between restructuring electricity generation and environmental

consequences is not a simple one. The environmental outcome will result from an

interactive, iterative process of many changes in existing trends affecting electricity

generation. The two most crucial trends are: (1) decisions with respect to meeting

future electricity demand, including the renovation of existing generating capacity,

choice of new generating technologies for new construction, and enhancement of

transmission capacity; and, (2) decisions with respect to implementing existing

environmental regulations, and the potential approval of future environmental

regulations. Restructuring would influence each of these trends to varying degrees,

encouraging some, such as renovating existing capacity, and challenging others, such

as existing environmental regulations.

Electricity Demand

Restructuring and the other trends underway point to changes in demand and

technological developments that will ultimately be reflected in environmental

consequences. To the extent restructuring and the other changes lead to a more

efficient generation industry, baseload prices should decline, which would be expected

to lead to higher demand and greater consumption. Lower baseload prices could

encourage owners of existing coal-fired facilities with low operating costs to extend

(...continued)

Deregulation in the Electric Power Industry: An Initial Analysis (January 15, 1998), p. 1.

At [http://www.nescaum.org/about.html]

Ibid., p. 2.

CRS-26

and enhance electricity generation from such facilities rather than risk investing in new

construction. CRS estimates that between 23,000 and 53,000 Mw of existing coalfired capacity is currently underutilized and could be made available if economics and

transmission capacity justified such a decision. Renovating existing coal-fired

capacity has been an increasing trend in the industry for over a decade. The more

competitive generating market of a restructured electric utility industry could further

encourage this trend.

Reduced baseload electricity prices also change the signals affecting consumer

choices related to energy efficiency. Lower baseload electricity prices could diminish

the incentive to invest in increased conservation, such as more efficient refrigerators

or insulation. Cost-considerations may also work against power generation by

renewables such as solar, wind power, and geothermal, which currently are not costcompetitive with natural gas or coal technologies. It may also work against nuclear,

which is a capital intensive technology, and which has contradictory environmental

implications — being essentially free of air emissions, but posing waste disposal

problems that some see as more hazardous and less controllable. Finally, cost

concerns may further encourage natural gas-generated power in new construction (the

existing technology of choice), which is more environmentally friendly than coal or

oil alternatives.

But at the same time, if prices reflect marginal costs, the price signal is likely to

dampen peak demand, which typically is met by the most costly and inefficient

generating capacity — thereby leveling the demand curve. Higher prices for peak load

power could strengthen the signal for load management — conservation measures

that reduce peak usage, such as automatic shutoffs of hot water heating during peak

demand. Also, to the degree consumers are given the choice of electricity suppliers,

they may create new markets for different types of generation by basing their

decisions on factors other than economics, such as environmental ones. One such

possibility is “green pricing,” where some consumers choose to purchase electricity

that costs more economically but costs less environmentally — such as that produced

by renewables. Such a “green market” is being developed in California, but it is too

early to anticipate the size that it may achieve.

How these differing effects play out will determine the potential for increased

emissions from restructuring. As indicated, some, such as renovating existing coalfired capacity, represent a furthering of an existing trend. Others, such as green

pricing, represent a new trend created by restructuring. Although the overall effect

on emissions is difficult to assess, involving several currently unquantifiable variables,

the most substantial environmental effect in the short- to mid-term is likely to come

from enhanced operation of existing coal-fired capacity. Whether one can ascribe that

effect to general trends in the industry or to restructuring is debatable.

Air Quality Regulations

Restructuring, combined with the outcome of the other trends, has the potential

to increase emissions of some pollutants of concern; the question is whether existing

(or proposed) regulatory limits on those emissions would effectively prevent adverse

effects.

CRS-27

! For SO2, restructuring is unlikely to have any effects on emissions. The CAA

requirements statutorily “cap” the nation’s utility SO2 emissions, making

industry structure essentially irrelevant. Increasing numbers of participants

may make monitoring and enforcement more demanding, but the SO2 program

contains substantial penalties for non-compliance, and no compliance

difficulties have emerged to date.

! For NOx, the potential of extended and enhanced coal-fired capacity utilization

encouraged by restructuring could significantly increase emissions. NOx

emissions from an additional 23,000 MW of coal-fired capacity could be in the

range of 480,000 tons, compared with about 70,000 tons if that electricity was

generated from natural gas. However, several EPA regulatory actions could

reduce or eliminate that potential increase. For example, EPA’s Ozone

Transport Rule would in effect set a “cap” on emissions in 21 eastern states

where they currently contribute to unacceptable ozone pollution; these 21

states are where the majority of potential coal-fired related NOx emission

increases could occur. However, the primary implementation of the process

lies with the states. As a result, the NOx control program would be

administratively more complicated and could be less economically efficient

than the SO2 control program. A system of state-based programs to control

NOx emissions might dovetail with the current electricity generation system in

which state regulation plays a large role; but if restructuring leads to a more

regionally-based, competitive electricity generating system, then implementing

a NOx control program based on state programs could lead to industry

segments being subject to inconsistent requirements in the various states.

Indeed, the inconsistencies could constitute barriers — or opportunities — to

the restructuring process. But if the process works, then there would be no

increase in NOx emissions in the 21-state region, and the structure of the

industry would be irrelevant. If this process is delayed, other regimens,

including section 126 petitions, are available for relief.

! For CO2, the potential of extended and enhanced coal-fired capacity utilization

encouraged by restructuring could significantly increase emissions. CO2

emissions from an additional 23,000 Mw of coal-fired capacity would be about

200,000,000 short tons, compared with 80,000,000 tons if that electricity was

generated from natural gas. CO2 emissions are not controlled by the Clean Air

Act, nor does there appear to be any readily applicable provision that could

used to control such emissions. If the U.S. ratifies the Kyoto Agreement, it

would effectively “cap” emissions, and restructuring would become irrelevant

in terms of emission increases. But how emissions would be controlled and

how reductions would be allocated and implemented would remain to be

determined by future domestic legislation.

! For Hg, increased utilization of coal-fired capacity would result in increased

Hg emissions, although uncertainty exists as to how much that increase would

be. Studies have been completed that could be the basis for regulation under

existing CAA authorities, if EPA were to conclude controls are necessary. 50

How well these would mesh with a more competitive electric generating

market is unclear.

Specifically, see: Environmental Protection Agency, Mercury Study Report to Congress,

EPA-452/R-97-003 (December 1997).

CRS-28

Ultimately, whether future developments in electricity generation will lead to

pollution increases of health and environmental concern depends on the effectiveness

of CAA requirements and of EPA implementation and enforecement (or on future

enactments of new controls) — and, in the case of CO2, on whether the U.S. ratifies

the Kyoto Convention and its requirements are implemented.

Responses

If one has confidence that these authorities will prove adequate to protect human

health and the environment and will be effectively implemented, one may be

comfortable in adopting the stance that “no action” is necessary to address any

emissions implications of restructuring proposals. The result might not be as costeffective as a regulatory regime more tied to a competitive market (such as a SO2

style “cap and trade” program), but except for CO2 (for which the need for controls

is highly contentious), the CAA provides control authorities — notably for emissions

of particular concern, NOx and Hg.51

Conversely, if one fears that existing approaches to pollution control will not be

effective or not be implemented, or that controls on CO2 are requisite, then one is

likely to press actions for immediate response. Those having such concerns could be

expected to pursue several actions to address perceived unacceptable environmental

impacts, such as:

! aggressively using the existing regulatory regimen to address environmental

deterioration;

! proposing to embed environmental protections in any restructuring programs;

and

! proposing revisions of appropriate environmental statutes, in particular, the

CAA — and supporting prompt ratification of the Kyoto Agreement and

enactment of appropriate implementation legislation.

Those seeking to assure rigorous application of existing air pollution controls

could aggressively use the citizen suit or section 126 provisions of the CAA to press

their case whenever they perceive inadequate or ineffective implementation. While

this may be effective for controlling NOx and Hg emissions, it would not appear to

be a fruitful course with respect to CO2 emissions for which any controls are only

prospective.

The case for adding environmental protections to restructuring proposals

depends in part on the extent to which restructuring itself is a likely cause of more

pollution; or if the restructured industry were to pose implementation, enforcement,

or other problems that the current regulatory structure proves ill-equipped to cope

with. (For some, attaching environmental issues to restructuring may be a surrogate

for debates on a comprehensive review of the CAA or for CO2 controls.) As

indicated by the analysis of this paper, restructuring’s role is not clear; it is quite

While Hg emissions from electric utilities are not currently regulated, the 1990 CAA

Amendments provide EPA with the authority to do so based on studies mandated by the Act

(section 112(n)).

CRS-29

possible that some utility emissions of concern could increase as a result of other

trends underway, and in fact that may be happening. As the NESCAUM report

indicates, coal-fired generation appears already to be on the rise, before restructuring

efforts such as FERC’s rule to promote wholesale competition through open access

to transmission services could be having an effect. Likewise, monitoring shows that

(unregulated) CO2 emissions have risen since 1990.52 Thus, tying environmental

protection to restructuring might fail to address actual causes for increased emissions.

Responding to any problems that arise by then revising environmental statutes

may seem risky to those who already perceive significant environmental risks from

changes in electricity generation. They could point to the history of acid rain

legislation as an example of the risk: it took about 10 years from the time legislation

was first proposed to address acid rain to enactment of a program — which required

movement of a comprehensive set of CAA amendments. The lesson many draw is

that consideration and enactment of environmental legislation separate from

legislation that might have the potential to cause environmental problems can be

delayed and difficult. From this perspective, at least, it could make sense that if

Congress is to enact restructuring legislation, to attach to those bills any potentially

necessary environmental responses even if the problem is not solely due to

restructuring.53

All in all, as the preceding analysis and discussion indicates, the potential for

environmental deterioration from restructuring electricity generation is difficult to

project — both because various technical and economic changes are affecting the

industry at the same time and because of an evolving policy context. As a result of

this uncertainty, those who are focused on preventing environmental deterioration

tend to take a precautionary stance, to propose immediate preventative measures, and

to argue that such measures be attached to available legislative vehicles. In contrast,

those who doubt that there will be significant environmental effects or who are

focused on the substantial regulatory structure in place tend to take a wait-and-see

position. Further complicating this picture is that some attitudes about restructuring

are related to and partly a surrogate for a more fundamental debate that is underway

because of global climate change concerns — about the future direction of energy use

in the United States and the federal role in affecting it.

Larry Parker and John Blodgett, Global Climate Change: Reducing Greenhouse Gases —

How Much from What Baseline? CRS Report 98-235, March 11, 1998.

For information on legislative proposals relating restructuring to environmental controls, see

Larry Parker and Amy Abel, Electricity: The Road Toward Restructuring, CRS Issue Brief

IB10006 (updated regularly); and Larry Parker, Electricity Restructuring: Comparison of

Comprehensive Bills, CRS Report RL30087, (updated regularly); and, Larry Parker,

Electricity Restructuring and Air Quality: Comparison of Proposed Legislation, CRS

Report RS20326 (July 26, 2000).

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.