Electricity Generation and Air Quality: Multi-Pollutant Strategies

Congressional research reportMar 13, 2001

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Electricity Generation and Air Quality: MultiPollutant Strategies

-name redactedSpecialist in Energy and Environmental Policy

-name redactedSpecialist in Environmental Policy

March 13, 2001

Congressional Research Service

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www.crs.gov

RL30878

CRS Report for Congress

Prepared for Members and Committees of Congress

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Summary

Fossil fuel fired electric generating facilities are major sources of air pollutants, including

particulate matter (PM), sulfur dioxide (SO2), nitrogen oxides (NOx), and mercury (Hg), and of

the greenhouse gas carbon dioxide (CO2). A patchwork of regulations to limit PM, SO2, and NOx

emissions exists, with further requirements on the horizon. The piecemeal nature of the

regulations and the uncertainty of future requirements impose not only direct costs on utilities,

but also make planning difficult in an environment already characterized by industry

restructuring, volatile energy prices, and technological changes.

To bring some consistency and stability to the regulations affecting utility emissions, legislative

initiatives have proposed a “multi-pollutant” strategy. Key elements of the strategy include:

•

aligning pollution control processes and procedures for PM, SO2, and NOx so

that both regulators and utility managers could anticipate requirements and

integrate their decisions about how to control emissions;

•

adopting efficient economic mechanisms—most notably “cap and trade”

strategies—for the control of the pollutants;

•

stabilizing requirements over time; and

•

incorporating potential future control requirements for other emitted gases (e.g.,

Hg, CO2) into this more stable scheme.

This approach to controlling powerplant emissions would have several tradeoffs. Overall, it

exchanges regulatory and economic uncertainty for short to mid-term certainty. For the

environment, the current controversy that accompanies the setting of standards and the

implementing of regulatory reduction requirements would be exchanged for a specific reduction

target that would not change for 10-15 years. From an economic standpoint, implementing

emission caps through emission trading would reduce costs, and the straightforward enforcement

mechanism would also provide industry with certainty with respect to their responsibilities and

potential penalties, and allow industry to plan for the future in the context of a consistent

regulatory regime. Finally, the program might open the door for simplifying or replacing elements

of the current piecemeal requirements. However, cap and trade systems could conflict with health

standards to protect local areas from “hot spot” emissions.

Although the Clean Air Act’s evolution has resulted in a structure that some characterize as

unwieldy, the number of persons living in areas where air pollution exceeds standards has

diminished. Arguably, the Act’s success puts the burden of proof concerning amendment on those

favoring change. Amending the Act has always proved contentious; but for many, the

opportunities for greater predictability of requirements, fixed emission reductions, and cost

efficiency are enticing.

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Contents

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

The Regulatory Framework: Utility Air Quality Regulation...................................................4

National Ambient Air Quality Standards—New Source Performance Standards—

Lowest Achievable Emissions Rate ..............................................................................5

Prevention of Significant Deterioration—New Source Review—Best Available

Control Technology......................................................................................................6

Acid Rain—Statutory SO2 Cap and Allowance Trading System.......................................7

Pending and Prospective Utility Air Quality Controls ............................................................7

Health and Environmental Concerns Driving New Air Quality Initiatives ........................8

Economic and Regulatory Drivers Affecting Perspectives on Air Quality Controls ..........9

Alternative: The Four Pollutant Strategies ........................................................................... 10

Specific Pollutant Issues...................................................................................................... 11

Sulfur Dioxide .............................................................................................................. 11

Nitrogen Oxides............................................................................................................ 12

Mercury ........................................................................................................................ 14

Carbon Dioxide............................................................................................................. 14

Integrative Effects of Multi-Pollutant Strategy..................................................................... 15

Environmental .............................................................................................................. 16

Economic Effects .......................................................................................................... 16

Economic Benefits ........................................................................................................ 19

Regulatory Effects ........................................................................................................ 19

Legislative Options ............................................................................................................. 21

Dimensions of a Cap and Trade Program....................................................................... 21

Regulatory Changes ...................................................................................................... 22

Conclusion.......................................................................................................................... 23

Tables

Table 1. National Estimated Emissions from Fossil-Fuel, Steam-Electric Utilities—1998 ............3

Table 2. Simplified Summary of Air Quality Control Requirements for Electric

Generating Facilities ................................................................................................................7

Table 3. Pending and Potential Controls on Existing Sources.......................................................9

Table 4. : Estimated 2010 Cost and Benefits of S. 172/H.R. 25 and H.R. 2569........................... 16

Table 5. 2010 Annual Costs of Emission Reduction Provisions of H.R. 2569............................. 18

Table 6. Illustrative Estimates of 2010 Coal Production Impacts from Carbon Reductions ......... 18

Table 7. Current Status of Four Pollutants.................................................................................. 22

Table 8. Regulatory Issues Raised by Cap and Trade Proposals.................................................. 22

Table A-1. Timeline of Major Federal SO2 Regulations ............................................................. 25

Table A-2. Timeline of Major Federal NOx Regulations ............................................................ 26

Table A-3. Timeline of Major Federal PM Regulations .............................................................. 28

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Appendixes

Appendix. ................................................................................................................................. 25

Contacts

Author Contact Information ...................................................................................................... 29

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Introduction

Beginning with the Clean Air Act of 1970, and with substantive additional measures enacted in

amendments of 1977 and 1990, electric utilities have been subjected to a multilayered patchwork

of air pollution emission requirements. Fossil fuel fired electric generating facilities are major

emitters of gases (see table 1), with clean air controls currently directed at three pollutants: sulfur

dioxide (SO2), nitrogen oxides (NOx), and particulates (PM). Sulfur oxides have health effects

and are a major contributor to acid rain and visibility impairment. Nitrogen oxides have direct

health effects, contribute to acid rain and visibility impairment, and are a precursor to ozone, a

primary constituent of smog. Particulates have health effects, with the smallest particles now

thought to be the most serious causative agents; current regulations focus on particles 10 microns

in size or smaller (PM10) and new regulations would control particles less than 2.5 microns in

diameter (PM2.5). Emissions of SO2 and of NOx contribute to the formation of these very fine

particles. In 1998, electric utilities accounted for approximately 67% of U.S. emissions of SO2,

25% of NOx, and 11% of PM10.

The evolution of air pollution controls over time and as a result of developing scientific

understanding of health and environmental impacts has led to the multilayered and interlocking

patchwork of controls, which are outlined in more detail below. Moreover, additional controls are

in the process of development, in particular with respect to NOx as a precursor to ozone, and to

both NOx and SO2 as contributors to PM2.5.

In addition, fossil fuel fired electric generating facilities produce two other gases of

environmental and health concern: mercury (Hg) and carbon dioxide (CO2). While some sources

of mercury are currently regulated, emissions from electric utilities are not. However the Clean

Air Act Amendments of 1990 designated Hg as a hazardous air pollutant subject to a regulatory

regime spelled out in §112. EPA was also required to study hazards to public health from

hazardous air pollutant emissions of electric utility steam generating units in general; and,

separately, to report to Congress on mercury emissions from major sources, including electric

utility steam generating units. This study, completed in 1997, concluded mercury is a hazard to

public health; and it found that electric utility steam generating units account for about one-third

of the nation’s mercury emissions.1 On December 14, 2000, EPA announced its intention to

regulate utility Hg emissions in 2004, with an effective date of 2007 or 2008.2

Carbon dioxide is a major greenhouse gas, and fossil fuel fired electric generating facilities

account for about 36% of U.S. emissions. While CO2 emissions are not currently regulated, the

United States is a signatory of the United Nation Framework Convention on Climate Change,

which involves a voluntary commitment to hold greenhouse gas emissions to 1990 levels. At

present, U.S. emissions of CO2 are running some 10% over that goal.3 Further, the U.S. has

signed the Kyoto Protocol, under which the U.S. would be legally committed to reduce emissions

in the 2008-2012 period by 7% from a baseline that includes 1990 CO2 levels; however, that

Protocol has not yet been submitted to the Senate for advice and consent and is not in force. But it

U.S. Environmental Protection Agency, Mercury Study Report, EPA-452/R-97-003, December 1997.

EPA, “Regulatory Finding on the Emissions of Hazardous Air Pollutants From Electric Utility Steam Generating

Units,” Federal Register, Vol. 65, no. 245 (December 20, 2000), 79825-79831.

John E. Blodgett and (name redacted),

Global Climate Changes: Reducing Greenhouse Gases–How Much from What

Baseline? CRS Report 98-235 ENR. Updated Jan. 29, 2001.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

remains possible that, beyond the already existing voluntary goal, utilities will be subjected to

emissions limits on CO2 at some time in the future.4

As described below, this patchwork of existing and potential emissions requirements applicable to

fossil fuel fired electric generating facilities has a direct impact on strategic decisions concerning

investment in new facilities as well as operational decisions with respect to the timing of

maintenance and scheduling of operation. At the same time, the electric utility industry is

undergoing major restructuring changes. Proponents of change argue that the air quality

requirements add confusion and uncertainty to a utility decisionmaking environment already

challenged by new generating technology and new policies concerning competition and economic

regulation.

A restructured electricity generating sector may have consequences for emissions: current

electricity generating economics favor the continued operation of older, more polluting coal-fired

facilities, at the expense of building newer, cleaner, natural gas-fired facilities. Previous CRS

analysis suggests that the environmental effects of restructuring depend on how well the existing

regulatory regimen will work as the industry structure changes. 5 It appears that pollutants

controlled under emissions caps, such as SO2 under the acid rain title of the 1990 CAA

Amendments, would retain their efficacy regardless of the industry’s structure. The robustness of

emissions caps and the possible cost savings that tradeable emissions credits provide are seen by

some as a better fit for a restructured industry than the current regulatory system.

For a review of U.S. global climate change policy, see: (name redacted) and (name redacted),

Global Climate Change

Policy: From “No Regrets” to S. Res. 98, CRS Report RL30024, January 12, 1999.

(name redacted) and (name redacted),

Electricity Restructuring: The Implications for Air Quality, CRS Report 98-615,

updated January 4, 2001.

Congressional Research Service

Table 1. National Estimated Emissions from Fossil-Fuel, Steam-Electric Utilities—1998

CO2

NOx

PM10

SO2

1000

short

tons

% all

sources

1000

short

tons

% all

sources

1000

short

tons

% all

sources

1000

short

tons

% all

sources

tons

% all sources

Electric Utilities

2,209,287

6,103

302

13,217

~33

Coal

1,911,627

5,395

273

12,426

Oil

100,895

208

730

Gas

195,868

344

Other/Internal

Combustion

897

156

Sources: CO2—DOE, Energy Information Administration, Electric Power Annual 1998, Vol. II, p. 42; NOx, PM10, SO2—EPA, National Air Quality and Emissions Trends Report,

1998 EPA 454/R-00-003 (March 2000), Tables A-4, A-6, and A-8 http://www.epa.gov/oar/aqtrnd98/fr_table.html; Hg—”EPA Determination on Mercury Emissions from

Electric-Steam Generating Units,” text in Environment Reporter, Vol. 31, no. 50 (December 15, 2000), 2677-83.

CRS-3

Electricity Generation and Air Quality: Multi-Pollutant Strategies

For many years the complexity of the air quality control regime has caused some observers to call

for a simplified approach. Now, with the potential both for additional control programs on SO2

and NOx and for new controls directed at Hg and CO2 intersecting with the technological and

policy changes affecting the electric utility industry, such observers have become more numerous

and are pushing more strongly for a simplified approach.

Several simplifying approaches have been proposed, ranging from repeal of various components

of the air pollution regulatory system, to comprehensive replacement of the “command and

control” regulatory approach with some economic mechanism, which is often touted as more

efficient and transparent. In the mid-1990s, EPA began investigating the merits of a

comprehensive approach to utility emissions control. Called the “Clean Air Power Initiative,” the

purpose was “to develop, in consultation with stakeholders, an integrated regulatory strategy for

pollutants emitted from electric powerplants: sulfur dioxide, nitrogen oxides, and, potentially,

mercury.” It was “a collaborative effort to seek new approaches to future pollution control that

cost less, rely on market mechanisms, and reduce the number and complexity of

requirements....”6

As the effort evolved, a “multi-pollutant”or “four pollutants” approach has come to the fore. This

approach involves a mix of regulatory and economic mechanisms that would apply to utility

emissions of up to four pollutants—SO2, NOx, Hg, and CO2. The objective would be to balance

the environmental goal of effective controls across these pollutants with the industry goal of a

stable regulatory regime for a period of years.

During the 106th Congress, ten bills were introduced to increase pollution controls on electric

generating facilities.7 The pollutants targeted under these bills included SO2, NOx, Hg, and CO2.

All of these bills involved some form of emissions caps, and most included a tradeable credit

program to implement that cap. With President Bush endorsing a four pollutant emissions cap

with tradeable permits program during the campaign, attempts to address the issue are possible in

the 107th Congress.8

This report proceeds by (1) laying out the existing regulatory framework, with emphasis on how

it can affect strategic and operational decisions in the utility industry; (2) identifying the “drivers”

for rethinking the way air pollution controls are imposed on the industry; (3) describing the

elements of a “four pollutants” approach; and (4) discussing the ways that this approach would

affect the control of emissions and the industry’s decisonmaking. It concludes with a brief outline

of legislative options for achieving the goal of balancing environmental and industry objectives.

The Regulatory Framework: Utility Air Quality Regulation

To understand the interest in an integrated approach to controlling utilities emissions of air

pollutants, it is necessary to recognize the diverse requirements imposed by the CAA. Within the

general regulatory structure, several distinctions arise that affect utility planning and operations

“EPA’s Clean Air Power Initiative (CAPI), October 22, 1996, athttp://www.epa.gov/capi/capifs3.htm

(name redacted),

Electricity Restructuring and Air Quality: Comparison of Proposed Legislation, CRS Report RS20326,

updated July 26, 2000.

George W. Bush for President, Energy: Propose Legislation that Will Require Utilities to Reduce Emissions and

Significantly Improve Air Quality, George W. Bush for President Official Site: Issues, 2000.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

(e.g., whether the facility is located in clean or dirty air areas, whether a facility is existing or

new, and what fuel it burns). And while the underlying regulatory structure generally applies to

SO2, NOx, and PM, the specific requirements for each differ.

National Ambient Air Quality Standards—New Source Performance

Standards—Lowest Achievable Emissions Rate

As enacted in 1970, the CAA established a two-pronged approach to protect and enhance the

quality of the nation’s air. First, the Act established National Ambient Air Quality Standards

(NAAQS), which set limits on the level of specified air pollutants in ambient air. Second, the Act

required national emission limits to be set for major new polluting facilities; these are called New

Source Performance Standards (NSPS).

NAAQS have been established for six pollutants, including SO2, NOx, and PM. Under the law,

EPA sets primary NAAQS 9 to protect the public health with an “adequate margin of safety.”10

EPA periodically reviews NAAQS to take into account the most recent health data. NAAQS are

federally enforceable with specific deadlines for compliance, but states are primarily responsible

for actually implementing the standards, through development and enforcement of State

Implementation Plans (SIPs). In general, these plans focus on reducing emissions from existing

facilities to the extent necessary to ensure that ambient levels of pollution do not exceed the

NAAQS.

For areas not in attainment with one or more of these NAAQS, the 1970 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. 11 Existing sources in a non-attainment

area are required to install Reasonably Available Control Technology (RACT), a state

determination based on federal guidelines.

The 1970 CAA also established New Source Performance Standards (NSPS), which are emission

limitations imposed on designated categories of major new (or substantially modified) stationary

sources of air pollution. For fossil fuel fired electric generating facilities, EPA has set NSPS for

SO2, NOx, and PM10, and is required by the Act to review the standards every eight years. A new

source is subject to NSPS regardless of its location or ambient air conditions.

In summary, under this overall regulatory regimen, existing sources in non-attainment areas are

subject to controls determined by the state as necessary to meet NAAQS; existing sources are

essentially free from controls in attainment areas. And major new sources, including fossil fuel

fired electric generating facilities, are subject to NSPS as the minimum requirement, anywhere.12

“Secondary” NAAQS, also nationwide standards, protect “welfare” values, such as visibility and agricultural

productivity. There is no specific deadline for achieving secondary NAAQS.

For a further discussion of NAAQS standard-setting, see: (name redacted), (name redacted), and James McCarthy,

Air

Quality Standards: The Decisionmaking Process, CRS Report 97-722 ENR.

LAER may not be less stringent than NSPS, described below.

The federal focus on new facilities arose from several factors. First, it is generally less expensive to design into new

construction necessary control features than to retrofit those features on existing facilities not designed to incorporate

them. Second, uniform standards for new construction ensures that individual states will not be tempted to slacken

(continued...)

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Prevention of Significant Deterioration—New Source Review—Best Available

Control Technology

The 1977 CAA broadened the air quality control regimen with the addition of the Prevention of

Significant Deterioration (PSD) and visibility impairment provisions. The PSD program (Part C

of the CAA) focuses on ambient concentrations of SO2, NOx, and PM in “clean” air areas of the

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

increase in clean areas’ pollution concentrations depending on their classification. In general,

historic or recreation areas (e.g., national parks) are classified class 1 with very little degradation

allowed while most other areas are classified class 2 with moderate degradation allowed. States

are allowed to reclassify Class 2 areas to Class 3 areas, which would be permitted to degrade up

to the NAAQS.13 New sources in PSD areas must undergo preconstruction review (called New

Source Review or NSR) and must install Best Available Control Technology (BACT) as the

minimum level of control. State permitting agencies determine BACT on a case-by-case basis,

taking into account energy, environmental and economic impacts. BACT cannot be less stringent

than the federal NSPS, but it can be more so. 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.14

Among the pollutants that impair visibility are sulfates, organic matter, and nitrates. Existing

sources are required to install Best Available Retrofit Technology (BART). In 1999, the EPA

promulgated a regional haze program, which would entail more stringent controls on NOx and

SO2.

With a comprehensively regulated electric utility industry, the above regime resulted in

significant reductions in pollutant emissions, particularly from new sources. However,

environmental and economic factors have evolved over the past thirty years that expose cracks

and discontinuities in the regime. Environmentally, it became increasingly clear that ecological

effects were occurring at pollutant levels below those necessary to protect human health. The

classic example is acid rain, in which total pollutant loadings are more important that ambient

concentrations. Economically, the requirements on new sources were proving to be a strong

incentive for the “life extension” of older, existing facilities that could operate more

inexpensively but which were emitting pollutants at higher rates than new facilities.15

(...continued)

environmental control requirements to compete for new industry.

None have been reclassified to Class 3, however.

See James McCarthy, et al., Regional Haze: EPA’s Proposal to Improve Visibility in National Parks and Wilderness

Areas, CRS Report 97-1010, updated July 9, 1998.

See (name redacted) and (name redacted),

Electricity Restructuring: The Implications for Air Quality, CRS Report 98-615

ENR, updated January 4, 2001.

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Acid Rain—Statutory SO2 Cap and Allowance Trading System

To address acid rain, title IV of the 1990 CAAA established a new control regime essentially

independent of the NAAQS-NSPS processes. Instead of the NAAQS-based focus on acceptable

ambient concentrations of a pollutant enforced on a plant-by-plant basis, title IV establishes a cap

and trade scheme that limits SO2 (the primary precursor of acid rain) emissions more stringently

than NAAQS levels. (Although total emissions, not ambient concentrations, become the focus of

reductions, concentrations are still limited by NAAQS, so “hot spots” are prevented). Such an

approach is appropriate where regional, national, or global loadings of a pollutant reaches critical

levels despite acceptable localized effects. The ability to trade emission rights increases the

economic efficiency of the system and, assuming rigorous monitoring, simplifies enforcement.

Title IV also required reductions in NOx emissions. However, in contrast the SO2 cap and trade

program, the NOx program set performance standards based on low-NOx burner technology on a

boiler-specific basis for facilities affected by the SO2 requirements.

Statutorily, then, the air quality control requirements imposed on fossil fuel fired electric

generating facilities can be summarized as shown in table 2.

Pending and Prospective Utility Air Quality Controls

The preceding section outlined the air quality controls that have directly affected fossil fuel fired

electric generating facilities. Continuing developments in understanding of the effects of different

pollutants, especially of SO2 and NOx, both individually and in combination, are heightening

concerns about the adequacy of existing controls. Issues include continuing difficulties in meeting

the ozone NAAQS, health effects of fine particulates, impaired visibility, and global warming.

These concerns are driving new initiatives to increase controls at existing sources of these

pollutants. As a result, more air quality controls on utilities are pending or prospective. At the

same time, the increasingly complex and interactive structure of the air quality control regime is

raising questions about the effectiveness and economic efficiency of the individual initiatives.

Table 2. Simplified Summary of Air Quality Control Requirements for Electric

Generating Facilities

New

Source

Attainment Area

Nonattainment Area

NSPS (PM10, SO2, NOx).

NAAQS-LAER as determined by individual states;

can not be less stringent than the federal NSPS.

Offset rules also apply.

PSD-BACT, as determined by individual states;

can not be less stringent than federal NSPS.

Increment rules also apply.

Acid Rain—offsets for all SO2 emissions must be obtained through the allowance trading system.

Existing

Source

No general federal requirements, except:

BART required in areas affected by visibility

provisions.

NAAQS-RACT as determined by individual states

under federal guidelines.

Acid Rain—SO2 emission limits specified for facilities over 25 Mw; allowable emissions maybe traded

or banked through an allowance trading system. Title IV provisions include NOx emissions limits.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Health and Environmental Concerns Driving New Air Quality Initiatives

Achieving the NAAQS for certain pollutants (particularly ozone), has called for new control

regimes. EPA’s NOx SIP Call is an example of one such approach.16 Under the SIP Call, the

affected states are given emission budgets that they can achieve in whatever manner they choose.

Noting the regional nature of the ozone problem in the eastern U.S., EPA is strongly encouraging

states to implement the rule through a cap and trade program. As the ozone problem is seasonal,

the controls are only for the summer months. This seasonal requirement may be adequate for

meeting the ozone NAAQS, but may not fall short in addressing other environmental concerns

(fine particulates and visibility, for example). Moreover, this ozone control regime is based on

EPA regulation, whereas the acid rain control regime is statutory. As a result, the ozone

requirements are subject to some uncertainty, in particular the potential cap and trade provisions

for NOx which would be implemented by states individually.

Along with the pending NOx controls resulting from the continuing difficulties in meeting the

ozone NAAQS, concern has been growing about the health and/or environmental impacts of

mercury and greenhouse gases.

Under the 1990 CAAA, mercury was listed as a toxic air pollutant under Section 112. This

requires EPA to set standards for sources of Hg that achieve “the maximum degree of reduction in

emissions” taking into account cost and other non-air-quality factors. These Maximum

Achievable Control Technology (MACT) requirements for new sources “shall not be less

stringent than the most stringent emissions level that is achieved in practice by the best controlled

similar source.” The standards for existing sources may be less stringent than those for new

sources, but must be no less stringent than the emission limitations achieved by the best

performing 12% of existing sources (if there are more than 30 such sources in the category or

subcategory).

As previously noted, EPA stated on December 14, 2000 that it would be regulating utility

emissions of Hg. However, the exact form those regulations will take remains to be seen.

The possibility of carbon dioxide emission controls is less clear. No federal policy currently

imposes a control program on CO2 emissions, but global climate change concerns seem to be

growing. If such a policy were to be adopted, utilities would be among the most affected sectors.

The prospect of controls is underlined by a provision of the CAAA of 1990 (§ 821), which

requires the monitoring of greenhouse gases, and a provision of the 1992 Energy Policy Act (§

1605(b)), which provides a mechanism for reporting voluntary reductions in greenhouse gases.

Electricity projects account for half the voluntary reductions that have been reported under §

1605(b).17

These several concerns—emissions of SO2 and NOx, ozone nonattainment and fine particulates,

and mercury and global warming—introduce uncertainty and the prospect of new layers of air

pollution controls. As major sources of emissions of these pollutants, fossil fuel fired electric

For further information on the NOx SIP Call, see: (name redacted) and (name redacted),

Air Quality: EPA’s Ozone

Transport Rule, OTAG, and Section 126 Petitions—A Hazy Situation? CRS Report 98-236 ENR. For recent activities,

see: (name redacted) and (name redacted)

, Air Quality and Electricity: Initiatives to Increase Pollution Control, CRS Report

RS20553.

The Greenhouse Gas Volunteer, Vol. 6, no. 3 (Dec. 2000).

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

generating facilities thus have a particular interest in the outcome of these initiatives, which are

summarized in Table 3.

Table 3. Pending and Potential Controls 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

EPA regulation as a HAP

NE Action Plan on Mercury

Potential Legislationa

Carbon Dioxide

U.N. Framework Convention on Climate Change

Potential ratification of Kyoto Agreement

Potential Legislationa

For information on legislative proposals relating restructuring to environmental controls, see (name redacted)

and (name redacted),

Electricity: The Road Toward Restructuring, CRS Issue Brief IB10006; for information on

Electricity Restructuring: Comparison of

legislation that was proposed in the 106th Congress, see (name redacted),

Comprehensive Bills, CRS Report RL30087 and (name redacted),

Electricity Restructuring and Air Quality: Comparison

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

Economic and Regulatory Drivers Affecting Perspectives on Air Quality

Controls

The control measures needed to address these environmental concerns have emphasized the basic

economic decisions made in 1970. First, the 1970 CAAA created an economic bias in the system

because existing sources can often achieve compliance with its provisions at less cost than new

sources. It was perceived to be more economically efficient to require the most stringent control

on new sources while giving states discretion through the SIP process to require existing sources

to retrofit controls only when, and to the extent, necessary. This situation was not changed by the

addition of market mechanisms in the 1990 CAAA. Under the acid rain provisions, existing

sources were allocated credits based on a reduction requirement less stringent than the current

NSPS, while new sources were allocated no credits at all. This disadvantage may not have been

particularly significant during a time when electric utilities were comprehensively regulated and

new sources were needed to meet increased electric demand. However, in the emerging

competitive electric supply market, the bias arguably discriminates against new entrants as

existing suppliers have the advantage of less stringent control requirements and a pool of free

emission credits.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Economic bias has also been created on a regional basis. For example, under the 1990 CAAA, an

Ozone Transport Region was created among 12 northeastern states (and the District of Columbia).

In this region, it is virtually impossible for an individual state to achieve the ozone NAAQS

because of interstate movement of air masses. Among the control mechanisms to reduce the

region’s ozone load, these states have instituted significant NOx controls not required in

neighboring states, and 11 of the states (and the District of Columbia) have joined in a regional

NOx trading system. These regional ozone controls impose costs not borne by other states.

Second, the mixture of control requirements, standards, and market mechanisms has complicated

corporate planning with respect to renovating existing capacity and building new capacity.

Uncertainty with respect to planning is increasing with the possibility of new pollutants being

added (e.g., carbon dioxide and mercury), and with potentially conflicting control regimes for

existing pollutants. For example, EPA’s NOx SIP Call requiring pollution controls in the eastern

U.S. is based on ozone concerns. Therefore, the controls are only in place for the season of the

year that ozone is a problem (i.e., May-September). However, potential fine particulate NAAQS

implementation strategies would involve year-round NOx controls. Compliance strategies that

might be optimal for a seasonal program might not be the strategies of choice under a year-round

control regime. Thus, a utility may find itself having to make an expensive mid-course correction,

or living with a sub-optimal compliance scheme, because of changing regulatory requirements.

Third, the market forces unleashed by electricity restructuring are providing impetus to

companies’ desires for flexibility in complying with environmental standards, and for what they

see as a level playing field between competitors. Producers of newer “clean electricity” wants

their competitors to meet the same or equivalent standards that they have had to meet. All

producers want more certainty in terms of the standards they are likely to see imposed in the near

to mid term.

Alternative: The Four Pollutant Strategies

With the prospect of new layers of complexity being added to air pollution controls and with

electricity restructuring putting a premium on economic efficiency, it is not surprising that interest

in finding mechanisms to achieve these new health and environmental goals in simpler, more

cost-effective ways has been on the rise. Taking the acid rain program—widely viewed as highly

successful both in controlling emissions and in economic efficiency—as a model, the proposed

“multi-pollutant” approach would establish a consistent framework of emissions caps,

implemented through emissions trading. Just how the proposed approach would fit with the

current (and proposed) diverse regulatory regimes remains to be worked out; they might be

replaced to the greatest extent feasible, or they might be overlaid by the framework of emissions

caps. The key assumption of this approach is that the current process of addressing pollution

problems on a sequential, pollutant-by-pollutant basis can be superceded with a coordinated and

integrated national program that would stabilize requirements for a number of years.

Such an approach to powerplant emissions would have several tradeoffs. Overall, the primary

tradeoff is exchanging regulatory and economic uncertainty for short to mid-term certainty.

The environmental advantage of this approach is the probability that emission reductions would

occur earlier than under the current regulatory process. If the current acid rain program is any

indication, a legislated cap and trade program could result in earlier emission reductions than the

current, often adversarial regulatory process. Challenges to the system, and resulting delays,

might be reduced under a cap and trade system. The potential environmental disadvantage would

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

be that any reduction target agreed to might be frozen for a specific period of time. Arguably,

however, it could be easier (administratively or statutorily) to reduce an emissions cap in the

future after the agreed upon time has expired than to develop a new, potentially overlapping

regulatory scheme as would be currently the case. For example, many proposals to further reduce

SO2 emissions simply call for a reduction in the current title IV cap, rather than the development

of new control structures.

Economic analysis projects that implementing emission caps through emission trading would

reduce costs by a significant amount, although the actual savings that might be realized is

debatable. For industry, a cap and trade system could not only save costs directly, but would

likely reduce uncertainties with respect to utility responsibilities and potential penalties, thus

allowing the industry to plan for the future in the context of a more coherent regulatory regime.

Finally, a flexible cap and trade program might open the door for reforming or replacing the

current, sometimes burdensome, NSR/PSD permitting process. Specifically, the cap and trade

programs might be coupled with a streamlined permitting process along the line of the Title V

permit program.

A disadvantage of emissions caps would be the possibility that unnecessary emission reductions

could be required. Emission caps could overshoot the mark, resulting in unnecessary costs.18

Also, the certainty of reductions could also result in costs being incurred earlier than would be the

case under the current system. Finally, most proposals for a cap and trade system do not eliminate

the requirement to protect local air quality, so mechanisms to ensure NAAQS would not be

exceeded locally—such as some sort of trading restrictions—might be imposed.19

Specific Pollutant Issues

Although the four pollutant approach calls for a coordinated cap and trade system to supplement,

and, in some cases, replace the existing structure, the resulting caps would not necessarily be the

same. Each pollutant presents unique issues with respect to baselines, allocation schemes,

reduction targets, and compliance measures.

Sulfur Dioxide

Utility emissions of sulfur dioxide are the only pollutant of the four identified here that is

currently controlled with a cap-and-trade system. Specifically targeting acid rain concerns, this

cap and trade system is laid on top of a number of regulatory schemes (as illustrated in Table A-1

in the appendix). When enacting the title IV acid rain provisions, Congress did not remove any

existing provisions with respect to utility SO2 emissions, except for an ambiguous repeal of the

percent reduction requirement (ambiguous in that the repeal prohibits any backsliding). Thus, in

one sense, title IV is little more than another patch in the current patchwork that constitutes

current air policy.

However, the CAA assumes that achieving levels of air quality cleaner than NAAQS is intrinsically good, as it

provides a greater margin of safety, leaves more room for future development, and discourages sources from

“shopping” for clean air areas to pollute.

Such constraints exist in existing trading situations: see Barry D. Solomon and Russell Lee, “Emissions Trading

Systems and Environmental Justice,” Environment, Vol 42, no. 8 (October 2000), p. 41.

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However, in terms of mechanics, the SO2 program provides a working example of how a system

employing emission caps and trades can operate successfully. By just about any criterion—

economic, environmental, implementation—the program has met or exceeded its goals.

Economically, the SO2 program is costing about $1 billion annually. This is substantially below

EPA’s costs estimates in 1990 of $2-$4 billion annually, and an order of magnitude lower than the

$10 billion annual cost estimate provided by the utility industry. Environmentally, reductions

achieved from 1995-1999 have exceeded the mandated target by between 23% (1997) and 40%

(1995).20 In terms of implementation, compliance with the program has been 100%, with no

delays in implementation of the SO2 program.

Thus the current SO2 program might be seen as a good model for developing a coordinated policy

for more stringent control of utility air emissions—both of SO2 and potentially of other

pollutants. The model includes an established baseline (1990 emissions) with a credible inventory

and continuous monitoring system. The trading mechanics, including the automatic tracking

system, outside brokers, and banking, are well established and functioning efficiently. The

permitting, monitoring, and enforcement provisions are well-understood. In theory, to more

stringently control SO2 the overall cap and individual allowance values would simply need to be

reduced by an agreed upon percentage.

It is possible that more stringent control could expose difficulties with the current system that

have not shown up. For example, a more stringent program would increase the value of

allowances and make issues of economic bias more transparent, both regionally and between

competitors. The allocation system for the 1990 CAAA title IV program was a hard-fought

compromise. It was also arrived at during a time when non-utility emissions were minor. Schemes

designed to protect new competitors have proven unnecessary, as allowance prices have remained

low. Higher valued allowances could change all that. Under the current system, newly constructed

power plants receive no allocation of allowances; instead, new sources must obtain any necessary

allowances from owners of existing facilities on the open market or through the EPA-sponsored

auction. In either case, a more stringent cap would make this process more expensive.

Opening the allowance allocation scheme to revision could involve a protracted debate between

the different interest groups. Both baseline issues and distribution issues would be involved. The

current system provides free allocation of allowances to existing facilities based on a 1985-87

database and a legislated emissions rate. Alternatives range from a new source pool of free

allowances to wholesale auctions to allocate all allowances. Any decision made with respect to

SO2 allowances could spill over into any NOx, Hg, or CO2 allocation scheme.

Nitrogen Oxides

NOx illustrates many of the concerns driving the current interest in a four pollutant strategy. As

indicated in Table A-2 in the appendix, the multiple effects resulting from NOx emissions have

led to their control under several different parts of the CAA. 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. In addition, nitrogen oxides are precursors of fine

particulates, which are suspected of significant human mortality and morbidity effects.

Environmental concerns about NOx emissions include its transformation into nitric acid, a

U.S. Environmental Protection Agency, Acid Rain Program: 1999 Compliance Report, EPA-430-R-00-007, July,

2000. p. 22.

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component of acid precipitation; visibility impairment; and known 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.

For proponents of a four pollutant strategy, this discovery of one effect after another for NOx,

resulting in one regulation after another, illustrates the need for a more stable and coherent

regime. However, each component of the existing structure has emerged from a set of

negotiations and compromises; imposing a new structure could likely disrupt agreed-upon

outcomes, and keeping all stakeholders whole would be very difficult.

Under title IV of the 1990 CAAA, a continuous monitoring network has been set up to measure

NOx emissions at the stack. Thus, inventories and monitoring of NOx emissions are not problems

in developing a NOx cap and trade program. There is also some experience in trading NOx

credits, thanks to the Ozone Transport Commission’s trading regime for the eleven northeastern

states (plus D.C.). Experience there suggest a more volatile market than for the larger 48 state

SO2 market. Interest in the market has spawned outside brokers to facilitate trades in the

Northeast.

However, the regional nature of current NOx markets may present problems for a national cap

and trade program. This situation will not necessarily be improved by implementation of EPA’s

Ozone Transport Rule (NOx SIP Call). Under the SIP process, EPA does not have the authority to

require that individual states employ compatible cap and trade systems to implement the rule; or

even to use a cap and trade program at all. EPA has provided guidance through a model cap and

trade program. And it has proposed Federal Implementation Plan (FIP)22 requirements as to what

kind of cap and trade program it would feel appropriate to implement the rule. However, states

are free to ignore EPA’s model rule, and comply with the NOx SIP Call in any fashion they

believe appropriate to their state’s conditions.

Besides this lack of uniformity, existing and potential future NOx regulatory regimes create other

difficulties. Some of these difficulties resemble those surrounding SO2 regulation. Developing an

acceptable allocation scheme would be at least as difficult as it was for the SO2 Title IV program.

Indeed, it may be more contentious because NOx allowances would potentially be more

expensive to buy than SO2 allowances. Over the past year, SO2 per ton allowances have run in the

range of $150 or less. In contrast, NOx allowances under the OTC program has fluctuated

between $500 and $1000 each. A larger market might reduce the price instability in the current

OTC market, but the clearing price is still likely to be higher than the current SO2 price. This

situation might be of particular concern to new competitors in the generation market who would

object to any allocation scheme that grandfathered existing facilities at their expense—i.e., that

allocated free allowances to existing facilities but not to future ones.

However, other difficulties are unique to the development of NOx regulation. A major problem is

the current focus on NOx as precursor to ozone, which results in it being treated as a regional, not

national problem. Efforts to control NOx have concentrated on the northeast and California,

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

Vegetation to Atmospheric Deposition and Air Pollution: State of Science and Technology Report 18. Washington, DC:

National Acid Precipitation Assessment Program, December 1990.

The CAA provides that EPA ultimately impose a FIP in any state which fails to implement an adequate SIP. For

details on the proposed NOx FIP, see (name redacted) and (name redacted),

Air Quality: EPA’s Ozone Transport Rule,

OTAG, and Section 126 Petition—A Hazy Situation? CRS Report 98-236 ENR, pp. 14-16.

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where the ozone problem is most acute. EPA’s NOx SIP Call covers only the eastern 21 states and

D.C. Likewise, because ozone is a summer pollutant, a second major problem is that controls are

only required during the summer season (May-September), not year-round. With other

environmental concerns, such as fine particulates and visibility calling for year-round controls,

confusion with respect to appropriate control strategies is common. Would a new regime have any

obligation to provide a transitional period to polluters who in good faith installed seasonal

controls, only to have the rules changed by further regulation?

Laying a national four-pollutant strategy over these individual programs is problematic. The

Northeast has a working cap and trade program for the summer months. Much of the rest of the

East would be incorporated into a summer program under the NOx SIP Call, which may or may

not include cap and trade. California has its own control program with NOx credits. Much of the

rest of the country only has special NOx controls as required by the low-NOx burner requirement

of title IV. How could these diverse elements be integrated into a national cap and trade program?

The development of an allocation scheme that deals equitably with these elements within

acceptable time frames would be a tremendous challenge.

Mercury

While not currently regulated, utility emissions of Hg are prospective. While SO2, PM, and NOx

are regulated under the NAAQS process, Hg would be regulated as a toxic air pollutant under the

hazardous air pollutants section of the CAA (§ 112), which would require maximum achievable

control technology (MACT). Moreover, Hg regulation would be starting from a more

rudimentary position than regulation of SO2, PM, and NOx.

Despite these challenges, EPA has stated it will be regulating Hg in the next few years; thus its

inclusion in a four-pollutant strategy seems reasonable. The lack of experience in regulating Hg is

reflected in proposed four-pollutant strategies. Some proposals simply defer the decision and

implementation strategy to EPA; some require MACT on a unit-by-unit basis; and others would

allow a trading system under an emissions cap ranging from 70% to 90% reduction.23 At a 90%

reduction cap, Hg allowances are likely to be very expensive, so the initial allocation of

allowances would be a critical step in finding any acceptable strategy. Besides starting from near

zero, any Hg trading system would also have to develop market institutions, including tracking,

trading and other mechanisms to ensure a smooth working market.

Carbon Dioxide

Except for requiring utility monitoring of emissions, CO2 is not controlled under the CAA, and

controversy exists as to whether CO2 should be considered a pollutant at all. The slim chance that

the regulatory regime adopted at Kyoto would be ratified by the Senate contributed to the Clinton

Administration’s refusal to even submit the treaty to that body. At the same time, the country is

obligated under the 1992 United Nations Framework Convention on Climate Change (FCCC) to

pursue strategies with the goal of maintaining CO2 emissions at their 1990 levels.24 Current CO2

emissions are about 10% above their 1990 levels.

For proposals introduced in the 106th Congress, see: (name redacted),

Electricity Restructuring and Air Quality:

Comparison of Proposed Legislation, CRS Report RS20326.

See (name redacted) and (name redacted),

Global Climate Change: Reducing Greenhouse Gases—How Much from What

(continued...)

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In the face of scientific uncertainty, the focus of U.S. debate on a climate change policy can be

categorized by the three-Cs: (1) cost (the impact on the economy); (2) competitiveness (impact of

U.S. global competitiveness); and (3) comprehensiveness (desire for a level playing field for all

countries). Consensus is difficult because of the wide range of cost estimates presented. A CRS

survey of 17 costs estimates for the Kyoto Protocol resulted in a range of between $23 and $348 a

metric ton of CO2 removed. 25 Such an order of magnitude difference makes consensus difficult.

Several factors can both lower the cost and reduce the range of cost estimates presented above.

One major factor in producing the $23 - $348 range is assumptions made about the viability of

emissions trading under Kyoto. CO2 reduction cost estimates for global emissions trading

scenarios are in the range of $23-$50 a ton. However, serious questions have been raised as to

whether the trading mechanisms embodied in the Kyoto Protocol could produce the cost savings

suggested by some studies.26 Some of the these objections could be swept away under a properly

designed four-pollutant strategy as its purpose would not necessarily be to comply with, or be

compatible with, Kyoto. Indeed, several of the four-pollutant strategies proposed in the 106th

Congress chose the FCCC 1990 stabilization target for their CO2 cap, not the Kyoto reduction

requirement.

Setting a CO2 reduction target under a four pollutant strategy would be a very contentious issue.

CO2 emissions from electric generation have risen about 23% from 1990 to 2000. Add to this an

additional 19% for increased emissions anticipated between 2000 and 2010, and a reduction

requirement back to the FCCC target would be a substantial undertaking. However, the cost

would be less than if the additional 7% required by Kyoto was added to the reduction

requirement.

Several of the building blocks for a CO2 cap and trade program are in place. There is an

established baseline (1990), and a credible inventory for powerplant emissions. Continuous

monitoring is required for powerplants under the 1990 CAAA. There is some experience with

international emission credits thanks to the Joint Implementation program pioneered by the U.S.

in the mid-1990s. The issues of baselines for international projects and domestic allocations

would be contentious, but there is not the baggage included in those issues that there is with NOx

control. The advantage of CO2 not having been controlled is that policymakers can begin with a

pretty clean sheet.27

Integrative Effects of Multi-Pollutant Strategy

The integrative effects of a multi-pollutant strategy are environmental, economic, and regulatory.

(...continued)

Baseline? CRS Report 98-235 ENR.

(name redacted),

Global Climate Change: Lowering Cost Estimates through Emissions Trading—Some Dynamics and

Pitfalls, CRS Report RL30285.

ibid.

For a discussion of alternative market mechanisms for CO2 control, see: (name redacted),

Global Climate Change:

Market-Based Strategies to Reduce Greenhouse Gases, CRS Issue Brief IB97057, updated regularly.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Environmental

Multi-pollutant controls would integrate efforts to address several environmental problems,

including aquatic loadings (Hg deposition and acid rain (SO2 and NOx)), health effects of fine

particulates (SO2 and NOx), and visibility impairment (SO2 and NOx). Given the numerous

effects and interactions of pollutants, a multi-pollutant strategy is likely to enjoy considerable

benefits—along with the costs. What is hoped for is that the benefits will accrue at a rate faster

than the rate at which costs rise.

Economic Effects

Economic effects—including energy effects—include both planning issues and compliance costs.

EPA analyzed the costs and benefits of two multipollutant initiatives introduced in the 106th

Congress: S. 172/H.R. 25 and H.R. 2569.28 S. 172/H.R. 25 was a three-pollutant bill mandating

50% reductions in SO2 and NOx emissions by 2005, plus requiring an Hg regulation within one

year, but without specifying a reduction percentage or target. The effect of this mandate would

have been to cap SO2 emissions from powerplants at 4.45 million tons annually (reducing

emissions by approximately 3.7 million tons), and NOx emissions at 2.36 million tons (reducing

emissions by approximately 2.1 million tons) annually. H.R. 2569 was a four-pollutant bill

mandating annual emission caps on utilities of 4.0 million tons for SO2 (reducing emissions by

approximately 5.7 million tons), 1.66 million tons for NOx (reducing emissions approximately

2.4 million tons), 1.914 billion tons for CO2, and a 90% reduction on a unit-by-unit basis for Hg

from 1990 levels.29

Table 4 is derived from EPA analyses of the SO2 and NOx reduction requirements of these two

proposals. At first glance, the costs are not what one would expect. First, although the tonnage

reduced by H.R. 2569 is 40% greater than S. 172/H.R. 25, the costs only rise 42%, whereas one

would expect costs rising more quickly as more reductions are achieved. Some of the reduction in

anticipated costs can be explained by the combination of NOx and SO2 included under each bill.

Two million of the 2.3 million ton difference between S. 172/H.R. 25 and H.R. 2569 is SO2

reduction, the less expensive of the two pollutants to reduce.

Table 4. : Estimated 2010 Cost and Benefits of S. 172/H.R. 25 and H.R. 2569

(1997$)

S. 172/H.R. 25

H.R. 2569

SO2 Reduced

3.7 million tons

5.7 million tons

NOx Reduced

2.1 million tons

2.4 million tons

SO2/NOx Cost Per ton

$569

$580

Total Annual Cost in 2010

$3.3 billion

$4.7 billion

Total Annual Benefits in 2010

$33-$56 billion

$76.2 billion

EPA, Analysis of the Acid Deposition and Ozone Control Act (S. 172), prepared for the Senate Subcommittee on

Clean Air, Wetlands, Private Property, and Nuclear Safety, U.S. Senate, July, 2000; and, EPA, Technical Assistance on

H.R. 2569, The Fair Energy Competition Act of 1999, prepared for Congressman Pallone, January 5, 2001.

See (name redacted),

Electricity Restructuring and Air Quality: Comparison of Proposed Legislation, CRS Report

RS20326, July 26, 2000.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Source: EPA analyses. Calculations adjusted to same baselines; costs exclude costs of Title IV compliance and

the NOx SIP Call; benefits exclude the benefits of Title IV compliance but include the NOx SIP Call, for which

relevant (PM) benefits would be minor, on the order of $0.5 to $2 billion per year; per ton costs derived by CRS

from EPA analyses.

EPA did not calculate separate cost-per-ton estimates for NOx and SO2. As indicated in Table 4,

the combined NOx/SO2 cost per ton estimates only differ by about 2%. In its analysis of S. 172,

EPA did calculate separate cost-per-ton estimates for NOx and SO2 assuming separate

implementation of the bill’s provisions. Using the ratio of per ton costs resulting from those

estimates, CRS estimated the per ton costs for the full bill at $482 for SO2 and $728 for NOx. If it

is assumed that the ratio holds for H.R. 2569, the resulting per ton costs are $508 and $762—a

5% increase from S. 172. This increase seems low, given a 15% difference in NOx reductions and

a 54% difference in SO2 reductions between the two bills. EPA explains the relatively flat cost

curves in the case of SO2 emissions by arguing that the current 11 million tons of surplus SO2

allowances under the title IV program hold down the increase in per ton costs.30 These surpluses

are seen by EPA as sufficient to dampen the effects of the controls mandated for 2005 even

through the 2010 time period examined here.

However, this surplus does not explain the relatively flat NOx reduction costs. There are several

possible explanations. 31 If the 11 million ton SO2 allowance surplus projected by EPA is sufficient

to prevent any per ton cost increase from the 2 million additional tons of SO2 reduced annually by

H.R. 2569, the resulting NOx cost per ton is $813—about 12% above the NOx costs of S. 172.

This estimate would appear more in line with the NOx reduction increase of 15% between the

two bills. However, if correct, this result would suggest that the SO2 allowance surplus is masking

a significant increase in H.R. 2569 SO2 compliance cost just beyond the year 2010.

The EPA analysis for H.R. 2569 also included Hg and CO2 controls. For CO2, the cost of reducing

emissions to their 1990 levels is estimated by EPA at $3.82 billion. 32 EPA modeled the Hg

provisions in a two-step process beginning with a source specific reduction of 73%, followed by a

5 ton Hg cap (equal to a 90% reduction in Hg) beginning in 2005. According to the analysis, the

source specific reduction would cost $1.56 billion in 2010 and the further reduction via the cap

would cost $1.43 billion. Thus, total Hg cost for a 90% reduction is about $3 billion annually in

the year 2010. The total costs of the pollution control requirements of H.R. 2569 is presented in

Table 5.

Utilities would meet these reduction requirements through a mix of technology, fuel choice

decisions, and other means. EPA’s analysis of S. 172/H.R. 25 suggests that NOx control would be

primarily achieved through installation of control equipment. For coal-fired capacity, it is

projected that half would install Selective Catalytic Reduction (SCR) and a quarter would install

Selective Non-Catalytic Reduction (SNCR). For SO2, it is projected that about a fifth of coal-fired

capacity would install Flue Gas Desulfurization (FGD or scrubbers), while an undisclosed

amount of capacity would switch to lower sulfur coal. Less than 1% of coal-fired capacity is

projected to be repowered in order to burn natural gas.

Telephone communication with the Office of Clean Air Markets, U.S. EPA, February 2, 2001.

For example, it is possible that achieving the reduction requirement involves technologies whose costs on a per ton

basis are comparable, and the choice is dependent on the percentage reduction necessary and site specific

considerations.

Assuming EPA is using their base case as published in Analysis of Emissions Reduction Options For the Electric

Power Industry (U.S. EPA, March, 1999), the per ton costs works out to about $24 per metric ton of carbon reduced.

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Electricity Generation and Air Quality: Multi-Pollutant Strategies

Table 5. 2010 Annual Costs of Emission Reduction Provisions of H.R. 2569

(Billions of 1997 dollars)

Pollutant

Costs (incremental to title IV and NOx SIP Call compliance

costs)

SO2 and NOx (75% reduction from 1990

levels)

$4.72

CO2 (return to 1990 level)

$3.82

Hg (90% reduction)

$2.99

Total

$11.53

Source: EPA analysis, January 5, 2001.

Proposals that include significant reductions in CO2 emissions greatly increase the likelihood that

natural gas may displace coal in fueling electric generating facilities. As stated by EPA in its H.R

2569 analysis: “The reduction in CO2 to 1990 levels is projected under the current model to be

accomplished through a shift towards lower emitting generating technologies and fuels, primarily

natural gas-fired electricity generation.”33 Unfortunately EPA’s H.R. 2569 analysis presents no

data on its fuel source effects. However, other analyses done by EPA in 1999 do provide some

idea as to the magnitude of this effect.34 Using analyses incorporating a 50% SO2 reduction from

title IV levels, coal production in 2010 is projected at almost 1 billion tons. To reduce U.S. CO2

emissions to their 1990 levels, as would have been required under H.R. 2569, these analyses

indicate a 158 million metric ton reduction in carbon from EPA’s 2010 baseline. Using EPA

analyses of other reduction requirements as a guide, CRS estimates that coal production losses

from such a requirement would be in the range of 300 million short tons (table 6). This

production would be replaced mostly with natural gas, along with some additional conservation.

Table 6. Illustrative Estimates of 2010 Coal Production Impacts from Carbon

Reductions

Carbon Reduced

(from 2010 baseline)

(million metric tonnes)

Coal Production Loss

(from 2010 baseline)

(million short tons)

137

106

214

158

~300

Source: 70 million and 106 million estimate from EPA, Analysis of Emissions Reduction Options for the Electric Power

Industry, March 1999, p. 3-46. 158 million estimate derived by CRS from EPA report. Baseline includes an

assumed 50% reduction in SO2 below title IV levels.

Such a substantial change in compliance strategies highlights the arguments in favor of a

comprehensive approach to controlling these four emissions in contrast to addressing them

individually. Upfront knowledge of the reduction requirements could permit facilities to optimize

compliance strategies rather than make costly investments that could be rendered obsolete by

U.S. EPA, Technical Assistance on H.R. 2569, The Fair Energy Competition Act of 1999, January 5, 2001, p. 6.

U.S. EPA, Analysis of Emissions Reduction Options for the Electric Power Industry, Office of Air and Radiation,

March 1999.

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future regulatory decisions. The cost and other effects of control strategies for these pollutants are

highly interdependent. As stated by EPA in its 1999 analysis of multi-pollutant options: “The

analysis shows that having advance knowledge of potential requirements for all four pollutants

could lead firms to follow significantly different compliance strategies at individual plants,

compared with compliance choices made when the pollutants are addressed one-by-one.”

These potential costs and fuel disruptions do not occur in isolation, however; the benefits must

also be taken into account, as discussed below. Further, a integrated, multi-pollutant air pollution

control regime may offer opportunities for utilities to reduce costs through comprehensive

approaches to generation and control technologies and fuel choices.

Economic Benefits

As shown in table 4, EPA estimates that the benefits of S. 172/H.R. 25 and of H.R. 2569 greatly

exceed costs. These figures are consistent with other EPA analyses of pollution control that find

very substantial health benefits in terms of annual avoided costs from reductions in SO2 and NOx.

These benefits accrue primarily from avoided adverse health effects of PM2.5 (SO2 and, to a lesser

extent, NOx contribute to PM2.5). For the benefits shown in table 4, all but 1% or 2% are

accounted for by the health benefits of PM2.5 reductions, with the balance attributed to visibility

improvements. EPA’s analyses indicate that other benefits are likely, but they are not quantified.

(It should be noted that these large estimates of benefits from PM2.5 reductions have their

critics.35)

However, whether the costs of an integrated, multi-pollutant air quality program are justified can

be evaluated not just in terms of the net benefits, but also from the comparison of the costs of the

integrated approach to the costs of the current, pollutant-by-pollutant approach. This is discussed

below.

Regulatory Effects

The regulatory effects of a four-pollutant strategy are probably the most difficult to determine.

Two key dimensions of these effects would be (1) their impact on the other elements of the air

quality control regimen and (2) their impact on the state, local, and private sector managers

implementing the program.

In terms of the impacts on air quality control programs, integrating the four-pollutant strategy

with the Title V permit process would probably be the easiest. Integrating the strategy with the

NAAQS/SIP process would probably be the most difficult, since the cap and trade framework

central to most multi-pollutant approaches focuses on total loadings, while the NAAQS process

focuses on local ambient concentrations. The final disposition of other regulatory requirements,

such as NSPS, NSR, visibility, and PSD would be problematic and surely the subject of

considerable discussion.

On the issue of assessing PM health effects, see, for example, EPA, Regulatory Impact Analysis for Proposed

Particulate Matter National Ambient Air Quality Standard (December 1996); on the debate on effects, see, for

example, U.S. Congress, House, Committee on Commerce, Subcommittee on Health and Environment and

Subcommittee on Oversight and Investigations, Review of EPA’s Proposed Ozone and Particulate Matter NAAQS

Revisions, Parts 1 & 2 [Serial No. 105-19 & 105-24] (105th Congress, 1st session) (Washington, D.C.: U.S. Govt. Print.

Off., 1997).

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

If the debate on title IV is any indication, it might be argued that continuation of NSPS would be

unnecessary under a comprehensive cap and trade program. Likewise, modification or

streamlining of the NSR/PSD siting processes might also make sense. The logic for a multipollutant strategy modifying or replacing NSPS and NSR for the affected pollutants would be that

neither program focuses on local ambient concentrations. A cap and trade approach could allow

some new sources to emit more than allowed under NSPS or through NSR, if counterbalancing

reductions occurred elsewhere.

The disposition of PSD and visibility requirements could be quite controversial. Unlike NSPS

and NSR that focus on total emissions (like a cap and trade program does), visibility and PSD are

concerned with ambient concentrations as well as loadings. If the cap were set stringent enough,

it is possible that these ambient concentration concerns could be eliminated. Otherwise, some

restriction on trading might be considered necessary.

From a political point of view, there would be tensions between the mix of potential synergies,

certainties, and flexibilities introduced by a multi-pollutant approach on the one hand, and the

fear that deleting any existing program could erode control capabilities on the other. Each existing

element of the air quality control program developed through a legislative process involving

negotiation and tradeoffs; those with stakes in those efforts might be expected to resist changes

unless the compensating advantages were obvious and substantial—and even then perceived

symbolic values associated with a program might be hard to overcome.

Even harder to assess prospectively is the way in which a multi-pollutant approach might affect

the air pollution control management task of state, local, and private sector managers. Past

experience with the CAA suggests estimates of projected costs of compliance tend to be too high,

as technological and managerial innovations bring down costs. A cap and trade approach,

included in most multi-pollutant proposals, facilitates each manager’s flexibility in seeking leastcost solutions to controlling emissions. At present, the CAA (with some exceptions, most

obviously title IV) is based on each source making pollution control decisions pollutant-bypollutant, smokestack by smokestack. The underlying presumption is that each manager will

make the most cost-efficient decision, and the sum of those decisions will be an efficient

outcome. Where the CAA provides for taking costs, energy, or other factors into account in

setting standards, it is always in a pollutant-by-pollutant context.

The multi-pollutant approach pursues a new direction: that individual decisions within a

collective framework, such as cap and trade, can be more efficient, by shifting controls to those

sources where reductions can be least-cost. Thus it builds on the experience of the title IV

program. Virtually all studies of trading mechanisms find that they lower costs, although by how

much varies, depending on assumptions about transactions costs, the number of participants, and

so on. But it is one thing to conclude that cap and trade will reduce costs of achieving reductions

for any one pollutant; it is another to anticipate the implications of a multi-pollutant system

allowing caps and trades for each pollutant, and giving managers the opportunity to address a

suite of requirements across several pollutants. As noted above, compliance strategies for these

pollutants are highly interdependent. EPA analyses suggest that synergies exist when addressing

these pollutant comprehensively; for example, EPA estimates that controlling SO2 and NOx

separately would cost $300 million more than the integrated control program proposed under S.

172.36

EPA, Analysis of the Acid Deposition and Ozone Control Act (S. 172), July 2000, p. 22. For a further discussion of

(continued...)

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Legislative Options

One thing is clear: a multi-pollutant approach would require legislation. As it stands, the CAA

leads EPA to identify and assess the effects of pollutants one by one; and it directs EPA and the

states to evaluate and mandate controls on most sources individually or by subdivided category

(existing or new; large or small, etc.). With only a few exceptions, mainly involving mobile

sources, the Act does not provide for integrating regulatory decisions, even when pollutants

interact or have similar effects or are emitted by separate but similar sources. EPA therefore has

little authority to develop and implement a regulatory approach that would embrace the collective

emissions of a group of sources, even if it would achieve more cost-effective reductions and more

efficient compliance by sources. At best, as in the NOx SIP Call, EPA can ask states to cleave

voluntarily to such a system—in this case a NOx cap and trade one.

Dimensions of a Cap and Trade Program

Essentially all multi-pollutant proposals have included cap and trade programs for all or most of

the pollutants.37 This common element underscores the presumption that cap and trade programs

can be more efficient than command and control requirements on individual sources. Each

pollutant raises particular questions about a cap and trade program. These include the following:

•

Scope. For which pollutants would cap and trade programs be created—all or

only some? (A national one exists for SO2, and some regional efforts for NOx.)

Would cap and trade programs be restricted only to power plants, or could other

sources, stationary or mobile, opt in? How large would facilities have to be in

order to be included?

•

Reduction Requirements. At what levels would emissions caps be set? What

baselines would be used? Would emission credits or allowances be allocated to

sources free (as with acid rain), or would affected sources initially have to bid on

pooled allowances? Would the caps be phased in with interim reductions? Would

some regions get treated differently than others?

•

Time Frame. Within what time frame should compliance be expected? Should

there be exceptions for facilities that choose innovative control measures?

•

Techniques Permitted. Should there be any restrictions on the methods used for

compliance? Should incentives be included to encourage specific techniques or

technologies?

•

Enforcement. How would the cap and trade program be enforced? What changes

in existing emissions monitoring requirements, or new monitoring, would be

required? What would be the penalties for non-compliance?

Table 7 summarize the current status of the four pollutants with respect to a cap and trade

program, which implies at least partial answers to some of the above questions. As indicated, each

(...continued)

cost savings from integrated control schemes, see EPA, Analysis of Emissions Reduction Options for the Electric

Power Industry, Office of Air and Radiation, April, 1999.

These cap and trade programs would be pollutant by pollutant; at the time of the acid rain debate there were some

discussions of SOx-NOx interpollutant trading, but this idea has not been resurrected in the current debate.

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

pollutant is differently positioned to incorporate a cap and trade program, and each raises several

specific concerns that must be addressed.

Table 7. Current Status of Four Pollutants

Issue

SO2

NOx

CO2

Baseline and

Emissions

Inventory

Established national

baseline and

emissions

inventory

Established

emissions inventory

- regional, not

national baseline

No established baseline

or emissions inventory

Established global baseline

and national emissions

inventory

Allocation

Scheme

Existing national

scheme

Some regional

schemes (OTC)

Focus tends to be on

percentage reduction

and technology

Focus on 1990 emissions

as allocation

Reduction

Targets

Proposed 50%-70%

below Title IV

levels

Proposed 50%-70%

reductions

Proposed 73% -90%

reductions

Proposed 1990

stabilization (FCCC);

Kyoto target proposes 7%

reduction

Trading

Schemes

Established trading

system and

institutions

Established regional

trading systems and

institutions

No experience and

viability questioned

Some spotty domestic and

international

experience—mostly

bilateral transactions

Monitoring

Existing

Limited

Existing

Comment

More stringent

controls could

reopen debate on

allocations

Integrating regional/

seasonal programs

difficult

Viability of trading

questioned; baseline and

inventory data, and

monitoring inadequate

Setting targets,

allocations, and the scope

of acceptable credit

sources are major issues

Regulatory Changes

Another aspect of establishing cap and trade programs for additional pollutants is what parts of

the existing regulatory system (if any) would need to be modified—or might become superfluous

and hence could be repealed. Table 8 summarizes some of the possibilities, along with potential

concerns. As is evident, a concern inherent to the cap and trade approach is the possibility of

creating

Table 8. Regulatory Issues Raised by Cap and Trade Proposals

Issue

Current Purpose

Issues Raised by Cap and

Trade Proposal

Potential Concerns

NAAQS (including

PM10 [potentially PM2.5],

SO2, NOx, and Ozone

(NOx SIP Call, Section

126 petitions, OTC))

Protection of human

health with an

adequate margin of

safety

Emission caps are potentially a

more efficient approach to

reduce emissions—may make

certain regulatory schemes such

as the NOx SIP Call redundant

and unnecessary

Protection against local “hot

spots” that could violate

NAAQS; modeling/

restriction of trades might be

necessary to ensure

compliance

PSD/NSR Permitting

Procedures (New

Sources or Major

Modifications to

Protect the integrity

of the NAAQS and

PSD increments (SO2

and NOx)

Cap arguably makes plant

specific review redundant;

possible overlapping permitting

requirements. Streamlining

Protection against local “hot

spots” that could violate

NAAQS or PSD increments;

modeling/ restriction of

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Issue

Current Purpose

Existing Sources)

Issues Raised by Cap and

Trade Proposal

Potential Concerns

efforts could focus on existing

Title V program

trades might be necessary to

ensure compliance

NSPS/MACT

Minimize the

environmental effects

of new facilities (SO2

and NOx)

Cap arguably makes separate

control requirements on new

facilities redundant

Hg MACT for utilities in

future

PSD -Visibility

Protect currently

pristine areas, and

areas of particular

importance (PM, SO2,

and NOx)

Cap arguably makes separate

control requirements—PSD and

BART—redundant and

unnecessary.

Protection against local

concentrations that

compromise visibility;

modeling/ restriction of

trades might be necessary to

ensure compliance

localized “hot spots” because of unrestricted trading. Such hot spots could potentially hinder

compliance with NAAQS, PSD, or visibility objectives. Very stringent emissions caps would

minimize the risk; modeling of major trades to determine their effect on local emission

concentrations and restrictions on trades in certain areas could help ensure compliance with

ambient requirements. The title IV SO2 program prohibits any trade that would violate NAAQS.

Terms that would have to be fleshed out would include “stringent,” “major trades,” and “certain

areas.”

Conclusion

The Clean Air Act has evolved over time in response to a developing understanding of the

environment, new technologies, and changes in the nation’s transportation, energy, and industrial

sectors. The result has been a patchwork of requirements that are not always consistent—and may

even be incompatible—at any given moment. Moreover, these requirements change and are

added to over time. Although the resulting development of the Act has resulted in a structure that

some consider unwieldy, emissions of most air pollutants have substantially declined, and the

number of persons living in areas where pollution exceeds standards has diminished. Arguably,

the Act’s success puts the burden of proof for revising the existing structure on those favoring

change.

The multi-pollutant proposals seek to bring more consistency and stability to the diverse elements

of the Act, with the focus being on pollutants emitted by utilities, one of the largest emitting

sectors. In a way, “multi-pollutant” may be misleading, as the proposals would not combine

regulations or controls on several pollutants; rather, the proposals typically do several things:

•

they would align pollution control processes and procedures for several currently

regulated pollutants (SO2 and NOx, and, indirectly, PM and ozone) so that both

regulators and utility managers could anticipate requirements and integrate their

decisions about how to control emissions;

•

they would adopt the efficiency of economic mechanisms—most notably “cap

and trade”—into the control of most or all of the pollutants;

•

they would stabilize requirements over time; and

•

they would anticipate incorporating potential future control requirements for

other emitted gases (e.g., Hg, CO2) into this more stable scheme.

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

For regulators, the advantages of this approach could be to reduce complaints about the costs and

inefficiencies of the current system, and possibly to forestall litigation. For utility managers, the

advantages of this approach could be to provide a certainty about environmental requirements

over a several-year planning horizon (that must cope with restructuring changes and volatile

energy prices), and to expand an existing method designed to achieve more cost-effective

compliance. For environmental and health interests, the advantages of this approach could be to

speed up reductions in emissions and, especially, to advance the controls on Hg and CO2.

There are potential disadvantages, as well, depending on how the old (existing) system is adapted

when and if a new, multi-media approach is enacted. Regulators and utility managers could find

that the new approach merely adds more requirements, compounding the current complaints of

regulatory overload. Utility managers could face having to control emissions (Hg and CO2) not

now regulated. Environmental and health interests might find that some existing protections

would be removed, with the risk of local “hot spots” emerging where emissions threaten or even

exceed current health standards or visibility requirements.

For legislators, then, the multi-pollutant approach represents an interlocking series of tradeoffs

among numerous stakeholders. Achieving balance may be difficult, but the potential for all

parties to find advantages could give impetus to the proposals.

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Appendix.

Table A-1.Timeline of Major Federal SO2 Regulations

SO2 Emission

Limitation

(lb.\MMBtu)

Comment

Date

Affected Units

1971 National

Ambient Air

Quality Standard

(NAAQS) for SO2

Affected Units determined by

individual States in their EPAapproved State Implementation

Plan (SIP)

Limitation calculated by

State as that necessary to

achieve the SO2 NAAQS

SIP limitations generally met

through increased use of

lower sulfur coal

Fossil-fuel-fired steam

generators over 73 MW on

which construction

commenced after 8/17/1971

Coal: 1.2 on a 30-day

rolling average

NSPS was met through lowsulfur fuels; natural gas emits

virtually no SO2 (0.0006

lb./MMBtu)

(40 CFR 50.4)

1971 New Source

Performance

Standard (NSPS)

(40 CFR 60.43)

Natural Gas: none

Oil: 0.8 on a 30-day rolling

average

1977 Prevention of

Significant

Deterioration

(PSD) Provisions

(1977 CAAA, Part

Stationary sources in areas not

covered by NAAQS nonattainment provisions

All new plants and

modified existing plants

must install Best Available

Control Technology

(BACT)

Additional controls or offset

may be required unless the

remaining emissions can be

accommodated under the

increment of increased SO2

concentrations allowed under

the area’s PSD classification

1979 NSPS

Fossil-fuel-fired steam

generators over 73 MW on

which construction

commenced after 9/18/78

Low sulfur coal: 70%

reduction when emissions

are less than 0.6 on a 30day rolling average

New coal NSPS standard

generally called the “scrubber

requirement” because it led to

installation of flue-gas

desulfurization (FGD) units at

facilities. About 25% of U.S.

coal-fired capacity has FGD

units installed

(40 CFR 60.43a)

High sulfur coal: 1.2 and

90% reduction of

uncontrolled

concentrations on a 30day rolling average

Natural gas and Oil: 0.2

with no percentage

reduction or 0.8 and 90%

reduction of uncontrolled

concentrations on a 30day rolling average

1996 Title IV

requirements

effective 1/1/96

(40 CFR 73.173.90)

2000 Title IV

Requirements

effective 1/1/2000

(40 CFR 73.173.90)

265 existing coal-fired utility

generating units specified for

Phase 1 by Title IV of the 1990

Clean Air Act Amendments

(Acid Rain Provisions)

Emission tonnage

limitation based on a 2.5

lb. emission rate times a

historical fuel

consumption factor met

on an annual average basis

Compliance generally achieved

through use of low-sulfur coal

on existing non-NSPS units

1,044 existing coal-fired utility

generating units specified for

Phase 2 by Title IV of the 1990

Clean Air Act Amendments

(Acid Rain Provisions)

Emission tonnage

limitation on existing

facilities based on a 1.2 lb.

emission rate times a

historical fuel

consumption factor met

on an annual average basis

Emission limitation based on

compliance through use of

low-sulfur coal on existing

non-NSPS units, although

there are no restrictions on

control methods

Emissions from all newly

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Date

Affected Units

1997 PM2.5

National Ambient

Air Quality

Standard (NAAQS)

(62 FR 3865238760)

SO2 Emission

Limitation

(lb.\MMBtu)

Comment

constructed fossil-fuel-fired

electric generating units over

25 MW that commenced

operation after 11/15/90 must

be offset to maintain a 8.95

million ton emissions cap on all

fossil-fuel units

New units may purchase

SO2 allowances from

existing facilities to offset

emissions

Nationwide standard, but lack

of monitoring data makes

NAAQS non-compliance

determinations difficult. Actual

units affected would depend on

individual State Implementation

Plans (SIPs)

Depends on individual

State Implementation

Plans. A mixture of

control methods at existing

units would be a likely

possibility

PM2.5 NAAQS is in litigation

Lack of data and future

reassessments of standard

make any compliance deadline

speculative at the current time

[NOTE: SO2

emissions transform

into PM2.5 in the

atmosphere]

Table A-2.Timeline of Major Federal NOx Regulations

Date

Affected Units

1971 New Source

Performance

Standard (NSPS)

Fossil-fuel-fired steam

generators over 73 MW that

construction is commenced

after 8/17/1971

(40 CFR 60.44)

NOx Emission

Limitation

(lb.\MMBtu)

Comment

Coal: 0.7 on a 30-day

rolling average

NSPS was met through

relatively simple boiler design

and combustion modifications

Natural Gas: 0.2 on a 30day rolling average

Oil: 0.3 on a 30-day rolling

average

1979 NSPS

(40 CFR 60.44a)

Fossil-fuel-fired steam

generators over 73 MW that

construction is commenced

after 9/18/78

Subbituminous coal: 0.6 on

a 30-day rolling average

Bituminous coal: 0.5 on a

30-day rolling average

New coal NSPS standards

generally met through more

combustion modifications or

installation of Low NOx

burners

Natural gas: same as 1971

NSPS

Oil: same as 1971 NSPS

1977 Prevention of

Significant

Deterioration (PSD)

Provisions (1977

CAAA, Part C). NOx

added in 1988

Stationary sources in areas

not covered by NAAQS

non-attainment provisions

All new plants and

modified existing plants

must install Best Available

Control Technology

(BACT)

Additional controls or offset

may be required unless the

remaining emissions can be

accommodated under the

increment of increased NOx

concentrations allowed under

the area’s PSD classification

265 existing coal-fired utility

generating units affected by

Phase 1 of Title IV of the

Tangentially-fired boilers:

0.45 on an annual average

Compliance achieved through

installation of Low-NOx

burners on existing non-NSPS

(40 CFR 51.166)

1996 Title IV

requirements

effective 1/1/96

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Date

Affected Units

NOx Emission

Limitation

(lb.\MMBtu)

(40 CFR 76.5)

1990 Clean Air Act

Amendments (Acid Rain

Provisions)

Dry bottom wall-fired

boilers: 0.50 on an annual

average

units. Affected units emitted

1.33 million tons in 1990;

reduced to 0.94 million tons in

1998.

1997 NSPS

Fossil-fuel-fired steam

generators over 73 MW that

construction is commenced

after 7/9/1997

Standard of 1.6 lb. per

megawatt-hour gross

energy output for new

construction (equivalent

to about 0.15 lb.\MMbtu

heat input) on a 30-day

rolling average is the same

for all fossil fuels;

Not a major change for new

natural gas/oil units which

employ combined-cycle

technology. Compliance by

coal-fired units could involve a

post-combustion device, such

as Selective Catalytic

Reduction (SCR) or Selective

Non-catalytic Reduction (SNR)

(40 CFR 60.44a(d))

standard of 0.15 lb.\MMbtu

for modified or

reconstructed facilities, on

a 30-day rolling average

2000 Title IV

Requirements

effective 1/1/2000

(40 CFR 76.6-76.7)

1,044 existing coal-fired utility

generating units affected by

Phase 2 of Title IV of the

1990 Clean Air Act

Amendments (Acid Rain

Provisions)

Tangentially-fired boilers:

0.4 on an annual average

Dry bottom wall-fired

boilers: 0.46 on an annual

average

Cell burner boilers: 0.68

on an annual average

2003 NOx SIP Call

(and possible Section

126 determinations)

(63 FR 57356-57538)

Affects 21 eastern States and

D.C. Actual units affected

depends on individual State

Implementation Plans (SIPs).

EPA budgets based on

existing coal-fired boilers

meeting a 0.15 lb. per

MMBtu standard on an

annual basis

Comment

Tangentially-fired and wallfired boiler standard based on

Low-NOx burner technology

C-burner standard based on

non-plug-in combustion

controls

Cyclone boilers: 0.86 on

an annual average

Cyclone and wet bottom

boiler standard based on SCR

or natural gas reburning

technology

Wet bottom boilers: 0.84

on annual average

Vertically fired boiler standard

based on combustion controls

Vertically fired boilers:

0.80 on annual average

Incremental NOx reductions:

0.9 million tons annually

Depends on individual

State Implementation

Plans. EPA budgets based

on existing coal-fired

boilers meeting a 0.15 lb.

per MMBtu standard on an

annual basis

NOx SIP Call and Section 126

determinations are in litigation

Estimated NOx reductions

from projected 2007 baseline:

0.96 million tons

Flexible cap and trade

implementation possibilities

suggest a variety of potential

control scenarios

NOTE: The Court has extended

the deadline to May 31, 2004

and dropped one state from the

rule’s provision (Michigan v. EPA,

No. 98-1497 (D.C. Cir., August

30, 2000))

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Table A-3.Timeline of Major Federal PM Regulations

PM Emission Limitation

(lb.\MMBtu)

Date

Affected Units

1971 New Source

Performance

Standard (NSPS)

Fossil-fuel-fired steam

generators over 73 MW on

which construction

commenced after 8/17/1971

All fossil-fuel-fired

generators: 0.10 on a 30day rolling average

NSPS was generally met

through installation of

electrostatic precipitators

(ESP); natural gas emits virtually

no PM (0.01 lb./MMBtu)

1977 Prevention of

Significant

Deterioration

(PSD) Provisions

(1977 CAAA, Part

Stationary sources in areas

not covered by NAAQS

non-attainment provisions

All new plants and modified

existing plants must install

Best Available Control

Technology (BACT)

Additional controls or offset

may be required unless the

remaining emissions can be

accommodated under the

increment of increased TSP

concentrations allowed under

the area’s PSD classification

1979 NSPS

Fossil-fuel-fired steam

generators over 73 MW on

which construction

commenced after 9/18/78

Coal: 0.03 and 99%

reduction of uncontrolled

concentrations on a 30-day

rolling average

New coal NSPS standard

generally met through larger

ESPs, or with baghouses in the

case of low-sulfur coal facilities

(40 CFR 60.42)

Comment

[Note: PM defined as

total suspended

particulate matter 45

microns in diameter

or less]

(40 CFR 60.42a)

Oil: 0.03 and 70% reduction

of uncontrolled

concentrations on a 30-day

rolling average

Natural gas: none

1987 PM10

National Ambient

Air Quality

Standard (NAAQS)

(40 CFR 50.6)

[Note: PM10 defined

as particulate matter

10 microns in

diameter or less]

1997 PM10

National Ambient

Air Quality

Standard (NAAQS)

(62 FR 3865238760)

1997 PM2.5

NAAQS

(62 FR 3865238760)

Nationwide standard with

most of the country

currently in compliance.

Actual compliance strategies

were determined by

individual State

Implementation Plans (SIPs)

Dependant on individual

State Implementation Plans.

However, increased PM

controls at existing

generating units was a major

component in most States’

SIPs

Compliance was generally

achieved through use of more

sophisticated or larger ESPs

Only a slight refinement to

PM10 NAAQS. Actual units

affected would depend on

individual State

Implementation Plans (SIPs)

Depends on individual State

Implementation Plans

1997 PM10 NAAQS is in

litigation

See discussion in SO2 table

The 1997 NAAQS is not a

major change from the 1987

NAAQS, and may not have a

great effect on generating units

Primary PM2.5 precursors

include SO2 and NOx. See

discussion in SO2 table

[Note: PM2.5 defined

Congressional Research Service

Electricity Generation and Air Quality: Multi-Pollutant Strategies

Date

Affected Units

PM Emission Limitation

(lb.\MMBtu)

Comment

as particulate matter

2.5 microns in

diameter or less]

Author Contact Information

(name redacted)

Specialist in Energy and Environmental Policy

[redacted]@crs.loc.gov, 7-....

Congressional Research Service

(name redacted)

Specialist in Environmental Policy

[redacted]@crs.loc.gov, 7-....

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