Electricity Restructuring: The Implications for Air Quality

Electricity Restructuring: The Implications for Air Quality

98-615 ENR
CRS Report for Congress
Received through the CRS Web
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 conven-
tional 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 state-
led 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 wait-
and-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 CO Emission Rates by Fuel Source . . . . . . . . . . . . . . . . . . . 4
2
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
1For 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.
2For 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
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

CRS-3
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 (SO ), nitrogen oxides (NOx,),
2
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 (CO ), which may contribute to global
2
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 CO , source location is
2
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 CO .
2
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.
3(...continued)
1998).
4Steam-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
CO
NOx
PM
SO
Hg
2
10
2
1000
% all
1000
% all
1000
% all
1000
% all
tons
% all
short
sources
short
sources
short
sources
short
sources
sources
tons
tons
tons
tons
Electric Utilities
2,209,287
36
6,103
25
302
11
13,217
67
52
33
Coal
1,911,627
5,395
273
12,426
51.6
Oil
100,895
208
9
730
0.2
Gas
195,868
344
1
2
Other/Internal
897
156
19
60
Combustion
Sources: CO — DOE, Energy Information Administration, Electric Power Annual 1998, Vol. II, p. 42; NOx, PM ,
2
10
SO — EPA, National Air Quality and Emissions Trends Report, 1998 EPA 454/R-00-003 (March 2000), Tables A-4, A-6, and
2
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 CO Emission Rates by Fuel Source
2
Fuel
NOx Emissions
CO Emissions (lbs.
2
(lb./mmBtu)
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;
CO — EIA, Emissions of Greenhouse Gases in the United States: 1987-1992 (Washington, D.C., 1994), Appendix A; and EIA,
2
Emissions of Greenhouse Gases in the United States: 1987-1994 (Washington, D.C., 1995), p. 18.

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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.

5FERC, “Promoting Wholesale Competition ... [Final Rule],” 61 Federal Register (May 10,
1996), 21544.
6 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.

CRS-6
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 coal-
fired 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
7 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 CO , the regulatory regimen of the Clean Air Act provides authorities
2
for controlling the potential increase in emissions — assuming they are effectively
implemented. Existing controls “cap” SO emissions in the 48 contiguous states and
2
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.
CO is not currently regulated. Any increase in fossil fuel-fired generation will
2
increase CO emissions, with coal producing about 75% more carbon emissions than
2
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 CO , increases are likely
2
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
8For 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.
9 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%.
10Capacity 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.
11Capacity 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.
12Data for 1999. North American Electric Reliability Council, Reliability Assessment: 1999-
2008 (Princeton, NJ: NERC, May, 2000), p. 14.

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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 non-
baseload 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
13Baseload 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).
14North American Electric Reliability Council, Reliability Assessment: 1996-2005 (Princeton,
NJ: NERC, October 1996).
15The 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.
16 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
17Marginal 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.
18As 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 off-
peak 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 (NO ), the index compound for nitrogen
2
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
19 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
19(...continued)
Benefits of Air Pollution Control: A Discussion, CRS Report 89-161, February 27, 1989,
pp. 75-144.
20John Blodgett, et al., Air Quality Standards: EPA’s Final Ozone and Particulate Matter
Standards, CRS Report 97-721 (Updated June 19, 1998).
21 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).
22 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 NO ) in “clean” air
2
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 case-
by-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 SO . However,
2
like the fine particulate NAAQS, it will be several years before any regional haze
program might result in controls.
22(...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.
23 More stringent controls can be required if modeling indicates that BACT is insufficient to
avoid violating the NAAQS.
24See 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 federally-
based offset requirements as the baseline in nonattainment areas. For SO , federal
2
25 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.
26 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
a 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 state-
regulated 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, long-
range 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 SO , for which utilities are
2
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
SO emissions.27 The flexibility and straight-forward compliance mechanism of this
2
“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 SO control program.
2
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 CO emissions under utility restructuring: CO is not subject to
2
2
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 CO compared to the potential for action on restructuring
2
legislation in the next couple of years has led some to find in the restructuring issue
a surrogate for a debate on CO controls and global climate change in general. This
2
situation adds complexity to the restructuring debate.
27U.S. Environmental Protection Agency, 1996 Compliance Report, Acid Rain Program, EPA
430-R-97-025 (June 1997).
28For 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
29ICF 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).
30U.S. Environmental Protection Agency, Office of Air and Radiation, Analyzing Electric
Power Generation Under the CAAA (July 1996), p. A3-11. Estimates in 1995 $.
31Part 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 combined-
cycle 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 combined-
cycle 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
Higher
Higher effici-
case
efficiency base
ency/high fuel
case
cost case
Efficiency
7,300
7,300
6,800
6,800
Assumption
Btu/Kwh
Btu/Kwh
Btu/Kwh
Btu/Kwh
Fuel Cost
$2.25/mmBtu
$3.50/mmBtu
$2.25/mmBtu
$3.50/mmBtu
Assumption
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%.
31(...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.
32Calculation 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.
33For 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 CO , and, depending on the fate of various EPA rulemakings, on NOx.
2
As SO emissions are currently capped by title IV of the 1990 Clean Air Act
2
Amendments, the effects of restructuring on SO emissions should be negligible.
2
The most substantial effects of restructuring would be for carbon dioxide
emissions, because they are currently uncontrolled. CO emissions from 23,000 Mw
2
of coal-fired capacity would be about 200,000,000 short tons, an increase of about
11% over 1996 CO emissions by coal-fired electricity generation. This compares
2
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
34Environmental Protection Agency, “Acid Rain Program; Nitrogen Oxide Emission
Reduction Program,” 61 Federal Register 67111-67264 (December 19, 1996).
35Based 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 CO emissions under a
2
36For 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.
37For 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.
38Readers 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.
39 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 3.6-
3.7 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
Carbon
Sulfur
Oxides
Dioxide
Mercury
Dioxide
Capital Costs
$49/Kw
0
$40.5/Kw
$190/Kw
Fixed O&M
$4.27/Kw
0
$6.9/Kw
$6.8/Kw
Variable
0.023
0.2
0.04
0.1
O&M
cents/Kwh
cents/Kwh
cents/Kwh
cents/Kwh
Total Costs
0.17
0.2
0.22
0.53
of Control
cents/Kwh
cents/Kwh
cents/Kwh
cents/Kwh
Total
2.17
2.2
2.22
2.53
Production
cents/Kwh
cents/Kwh
cents/Kwh
cents/Kwh
Costs
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 CO Control
2
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.

40 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,
41Federal 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.
42Federal 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.
43See, 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 price-
demand 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, higher-
emitting 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
44FERC, Final EIS, pp. J-34 - J-39 and pp. 6-25 - 6-41.
45See FERC, Final EIS, pp. J-69 - J-70.
46Mitigation is discussed in Chapter 7 of the EIS; comments are discussed in the Final EIS at
pp. J-78 - J-105.
47Natural Resources Defense Council, et al., Benchmarking Air Emissions of Electric Utility
Generators in the Eastern United States, 2nd Edition (April 1997), p. 41.
48Northeast 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 mid-
course 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
48(...continued)
Deregulation in the Electric Power Industry: An Initial Analysis (January 15, 1998), p. 1.
At [http://www.nescaum.org/about.html]
49Ibid., 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 coal-
fired 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 cost-
competitive 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 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 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 SO , restructuring is unlikely to have any effects on emissions. The CAA
2
requirements statutorily “cap” the nation’s utility SO emissions, making
2
industry structure essentially irrelevant. Increasing numbers of participants
may make monitoring and enforcement more demanding, but the SO program
2
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 SO control program. A system of state-based programs to control
2
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 CO , the potential of extended and enhanced coal-fired capacity utilization
2
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. CO emissions are not controlled by the Clean Air
2
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.
50 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 CO , on whether the U.S. ratifies
2
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 cost-
effective as a regulatory regime more tied to a competitive market (such as a SO2
style “cap and trade” program), but except for CO (for which the need for controls
2
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 CO are requisite, then one is
2
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 CO emissions for which any controls are only
2
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 CO controls.) As
2
indicated by the analysis of this paper, restructuring’s role is not clear; it is quite
51 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) CO emissions have risen since 1990.52 Thus, tying environmental
2
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.
52Larry Parker and John Blodgett, Global Climate Change: Reducing Greenhouse Gases —
How Much from What Baseline? CRS Report 98-235, March 11, 1998.
53For 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).