EPA’s Regulation of Coal-Fired Power: Is a
“Train Wreck” Coming?
James E. McCarthy
Specialist in Environmental Policy
Claudia Copeland
Specialist in Resources and Environmental Policy
July 11, 2011
Congressional Research Service
7-5700
www.crs.gov
R41914
CRS Report for Congress
P
repared for Members and Committees of Congress
EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Summary
Given the central role of electric power in the nation’s economy, and the importance of coal in
power production, concerns have been raised recently about the cost and potential impact of
regulations under development at the Environmental Protection Agency (EPA) that would impose
new requirements on coal-fired power plants. Six of the rules, which have drawn much of the
recent attention, are Clean Air Act regulations. Two others are Clean Water Act rules, and one is a
Resource Conservation and Recovery Act rule. The majority are expected to be promulgated over
the next 18 months. All together, these rules have been characterized by critics as a regulatory
“train wreck” that would impose excessive costs and lead to plant retirements that could threaten
the adequacy of electricity capacity (i.e., reliability of supply) across the country, especially from
now through 2017.
Although some question why EPA is undertaking so many regulatory actions in such a short time-
frame, supporters of the regulations assert that it is decades of regulatory delays and court
decisions that have led to this point, resulting in part from special consideration given electric
utilities by Congress under several statutes. Further, several of the current regulatory
developments have been under consideration for a decade or longer, or are being reevaluated after
an earlier action was vacated or remanded to EPA by the courts. The regulations are supported by
proponents and EPA as having substantial benefits for public health and the environment.
Recent reports by industry trade associations and others have discussed potential harm of EPA’s
prospective regulations to U.S. electricity generating capacity, with emphasis on coal-fired
generation. One of these reports, by the Edison Electric Institute, which represents investor-
owned utilities, has attracted considerable attention by depicting a timeline in which multiple
rules would take effect more or less simultaneously over the next five years. Congress has shown
significant interest in these issues, and bills have been introduced that would de-fund or restrict
EPA’s ability to develop rules, and which would legislate new regulatory analytic requirements.
This report describes nine rules in seven categories that are at the core of recent critical analyses,
with background on the rule and its requirements and, where possible, a discussion of the rule’s
potential costs and benefits.
The EEI and other analyses discussed here generally predate EPA’s actual proposals and reflect
assumptions about stringency and timing (especially for implementation) that differ significantly
from what EPA actually may propose or has promulgated. Some of the rules are expected to be
expensive; costs of others are likely to be moderate or limited, or they are unknown at this point
because a rule has not yet been proposed. Rules when actually proposed or issued may well differ
enough that a plant operator’s decision about investing in pollution controls or facility retirement
will look entirely different from what these analyses project. Further, promulgation of standards is
not the end of the road: court challenges are likely, potentially delaying implementation for years,
and even when final, EPA rules must be adopted by states and implemented over time through
state-issued permits. The primary impacts of many of the rules will largely be on coal-fired plants
more than 40 years old that have not, until now, installed state-of-the-art pollution controls. Many
of these plants are inefficient and are being replaced by more efficient combined cycle natural gas
plants, a development likely to be encouraged if the price of competing fuel—natural gas—
continues to be low, almost regardless of EPA rules.
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Contents
Introduction ................................................................................................................................ 1
Coal’s Place in Electric Power Production ............................................................................. 3
The “Train Wreck” Rules ............................................................................................................ 6
General Observations ............................................................................................................ 6
Cross-State Air Pollution (Clean Air Transport) Rule............................................................. 8
Mercury and Air Toxics Standards/Utility MACT................................................................ 11
New Source Performance Standards for Greenhouse Gas Emissions.................................... 14
NAAQS Revisions .............................................................................................................. 16
Revised Cooling Water Intake Rule ..................................................................................... 20
Revised Steam Electric Effluent Guidelines......................................................................... 22
Coal Combustion Waste ...................................................................................................... 23
Other Regulatory Actions Affecting Coal Power.................................................................. 26
The Future for Coal-Fired Power............................................................................................... 27
Train Wreck? ............................................................................................................................ 29
Legislation ................................................................................................................................ 36
Concluding Thoughts About the “Train Wreck” Analyses .......................................................... 38
Implementation ............................................................................................................. 39
Figures
Figure 1. EEI’s Timeline for Environment Requirements for the Electric Utility Industry ............ 2
Figure 2. U.S. Electric Power, 2009, by Fuel Type....................................................................... 4
Figure 3. Average Cost of Fossil Fuels for the Electric Power Industry, 1998 through
2009 ........................................................................................................................................ 4
Figure 4. Emissions from Fossil-Fueled Power Plants as a Percent of Total U.S. Air
Emissions ................................................................................................................................ 5
Figure 5. Coal Plants by Age and Emission Controls ................................................................. 28
Figure 6. Power Plant Capacity, by Type and Year It Entered Service......................................... 30
Figure 7. Cumulative SCR and Scrubber Installations, by Year .................................................. 33
Tables
Table 1. Timing of EPA Rules and Impacts on Coal-Fired Utilities .............................................. 7
Appendixes
Appendix A. Regulatory Actions Affecting Mountaintop Removal Mining ................................ 41
Appendix B. Bibliography of Analytic Reports.......................................................................... 43
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Contacts
Author Contact Information ...................................................................................................... 44
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Introduction
Given the central role of electric power in the nation’s economy, and the importance of coal in
power production, concerns have been raised about the cost and potential impact of numerous
regulatory actions that would impose new requirements on coal-fired power plants. In the summer
of 2010, for example, the Edison Electric Institute (EEI), which represents the nation’s investor-
owned electric utilities, prepared a chart, “Possible Timeline for Environmental Regulatory
Requirements for the Electric Utility Industry,” which is reproduced here as Figure 1. Using
color-coded categories, the chart identified rules under development at the U.S. Environmental
Protection Agency (EPA) and depicted a schedule for development and implementation of the
rules between 2008 and 2017.
The rules identified by EEI were:
• the Cross-State Air Pollution Rule, and its predecessor, the Clean Air Interstate
Rule (identified as “CAIR/Transport” on the timeline), which would establish
cap-and-trade programs for utility emissions of sulfur dioxide and nitrogen
oxides;
• Maximum Achievable Control Technology emission standards for mercury and
other hazardous air pollutants, a rule generally referred to as the “Utility MACT”
(“Hg/HAPS” on the timeline);
• National Ambient Air Quality Standards (NAAQS) for ozone, sulfur dioxide,
nitrogen dioxide, and particulate matter (“Ozone,” “SOx/NOx,” and “PM/PM2.5”
on the timeline);
• regulation of greenhouse gas emissions (“CO2” on the timeline);
• cooling water intake regulations (“316(b)” on the timeline);
• clean water effluent guidelines (identified under “Water” on the timeline); and
• coal combustion waste management rules (“Ash” or “CCBs Management”).
EEI subsequently produced a report, Potential Impacts of Environmental Regulation on the U.S.
Generation Fleet, which concluded that new EPA regulations would cause the unplanned
retirement of 17 to 59 gigawatts (GW) of coal-fired electric capacity (5.4% to 18.8% of the
current coal-fired total of about 315 GW) by 2015, and would require incremental capital
expenditures of $85 billion to $129 billion.1
1 ICF International, Potential Impacts of Environmental Regulation on the U.S. Generation Fleet, Final Report,
prepared for the Edison Electric Institute, January 2011, available at http://www.pacificorp.com/content/dam/
pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2011IRP/EEIModelingReportFinal-28January2011.pdf.
Hereinafter referred to as the “EEI report.”
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1
Figure 1. EEI’s Timeline for Environment Requirements for the Electric Utility Industry
Source: Edison Electric Institute, http://www.eei.org/whatwedo/PublicPolicyAdvocacy/TFB%20Documents/100525SheaCongressCoalImpacts.pdf (Figure 7).
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
EEI is not the only group to have focused on EPA’s prospective regulations. The American
Legislative Exchange Council (ALEC) picked up EEI’s chart, added to it the separate EPA rules
that will affect industrial and commercial boilers, and labeled it “EPA’s Regulatory Train Wreck.”
The National Mining Association also refers to “EPA’s Regulatory Train Wreck” in materials that
it distributes, and the North American Electric Reliability Corporation (NERC), in an October
2010 Special Reliability Assessment, concluded that implementation of four EPA rules could
result in a loss of up to 19% of fossil-fuel-fired steam capacity in the United States by 2018, with
the potential for “significantly deteriorating future … system reliability.”2 In addition to these, a
large number of other analyses have been prepared by other policy and research groups; some are
similarly critical of EPA’s rules, while others counter or rebut the criticisms. Many of these
reports are identified below in Appendix B.
The “train wreck” charts and related studies have been widely circulated on Capitol Hill, where
they have stimulated concern. Several bills aimed at reducing the regulatory burden or requiring
additional analyses of the combined rules’ impacts have been introduced. As discussed below in
“Legislation,” as of early July 2011, two of these bills had passed the House.
Opponents of these bills maintain that regulation of the affected plants is overdue. Coal-fired
power plants are major sources of pollution; many are decades old; and regulation of their
emissions, effluent, and waste has lagged that of other industries.
Coal’s Place in Electric Power Production
Coal fueled 44.6% of the nation’s electric power in 2009. This was a decline from 52% in 2000,
but coal is still the electric power industry’s dominant fuel source (as shown in Figure 2).
Many coal-fired electric generating units, along with most nuclear and hydroelectric plants,
provide what is called “base-load” power. Many of the plants run 24 hours a day and provide the
relatively cheap power that is the foundation of electric service. (Other plants, known as peaking
plants, are brought into service at times of peak demand. Peaking plants tend to have higher
operating costs, but since they operate for short periods of time, the higher cost is of less
concern.)
Low Cost
Coal-fired power has been cheap for multiple reasons. The average coal-fired power plant is more
than 40 years old and its capital cost fully amortized, whereas many natural gas plants (the second
largest source, producing about 23% of the nation’s electricity) have been built in the last 10
years. Coal itself (i.e., the fuel) is abundant and cheap: as shown in Figure 3, its price—expressed
in dollars for the same energy content, i.e., dollars per million Btu—has sometimes been less than
one-fourth the cost of natural gas, its main competitor. Averaged over a 12-year period, coal cost
less than one-third as much as gas.
2 North American Electric Reliability Corporation, 2010 Special Reliability Scenario Assessment: Resource Adequacy
Impacts of Potential U.S. Environmental Regulations, October 2010, pp. I and IV, http://www.nerc.com/files/
EPA_Scenario_Final.pdf. Hereinafter referred to as the “NERC report.” NERC is an independent organization, founded
by the electric utility industry, that conducts periodic, independent assessments of the reliability and adequacy of the
bulk power system in North America.
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Figure 2. U.S. Electric Power, 2009, by Fuel Type
Source: U.S. Energy Information Administration, Electric Power Annual, 2009, April 2011, Table 2.1.
Of course, other factors also affect the price of power, including the efficiency with which the
plant converts fuel into electric power, maintenance costs, and the cost of operating the unit—
which, in the case of coal must include costs for removal and management of ash. But, in general,
these factors did not outweigh coal’s basic cost advantage until the advent of natural gas
combined cycle technology in the 1990s.
Figure 3. Average Cost of Fossil Fuels for the Electric Power Industry,
1998 through 2009
($/million Btu)
Source: U.S. EIA, Electric Power Annual 2009, April 2011, Table 3.5.
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Clean Air Act Exceptions
Besides the age of the plants and the cost of the fuel, a third factor that has resulted in lower cost
is that many of the coal-fired plants, particularly the older ones, have been allowed to operate
with little in the way of pollution control equipment. Coal is an inherently “dirty” fuel. Burning it
produces sulfur dioxide (SO2), nitrogen oxides (NOx), particulates, mercury, acid gases, and other
pollutants, in greater abundance than other fossil fuels. As shown in Figure 4, coal-fired power is
a major or the major source of the air emissions of many of these pollutants.
Figure 4. Emissions from Fossil-Fueled Power Plants as a Percent of Total U.S. Air
Emissions
Source: U.S. EPA, “Reducing Toxic Pol ution from Power Plants,” March 16, 2011, p. 6.
Note: The figure includes emissions from oil-fired units as well as coal-fired, but oil-fired units account for only
1% of U.S. electric generation. Air emissions are not necessarily the major source of exposure for each of these
pollutants.
Despite the industry’s emissions, the structure of the Clean Air Act has allowed many of the older
coal plants to operate with minimal controls. The statute’s focus is on new sources of pollution
(including major modifications of existing plants). Under Sections 165 and 169 of the act, new
plants and major modifications are required to install the Best Available Control Technology
(BACT) in order to obtain an operating permit. Other plants (so-called “grandfathered plants”)
are not required to have best available controls, unless subject to state or local requirements
needed to address local air quality. The majority of the grandfathered plants are coal-fired.
In addition, the act’s major requirements for existing power plants, the acid rain program and the
NOx control program (generally known as the “NOx SIP call”), have both been cap-and-trade
programs. These allowed companies to decide how they wanted to meet system-wide emission
caps: by switching to lower sulfur fuels, by installing the best control equipment on a few plants,
by operating their dirtiest plants less frequently, or by purchasing allowances from facilities that
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
had over-complied. Since controls weren’t required on each individual plant, many of the older
plants could keep running without them.3
The “Train Wreck” Rules
General Observations
Burning coal to generate electricity can affect the environment in a number of ways, producing
air pollution, water pollution, and solid waste residuals. As reflected in the EEI timeline and other
analyses, EPA’s regulatory activities touch on all of these, although much of the recent critical
attention has focused on air pollution.
EEI’s chart contains 32 entries covering a 10-year period, 2008-2017. Not all of these entries
represent actions by the Obama Administration’s EPA. Of the first seven, for example, three are
court decisions vacating and remanding Bush Administration EPA rules, and the other four are
rules that were promulgated during the Bush Administration with implementation scheduled for
2009 or 2010. Because the Bush Administration’s Clean Air Interstate Rule (CAIR) was the
subject of two court decisions and was designed to be implemented in phases, it gets numerous
entries: three entries for implementation (for its seasonal NOx cap), its annual NOx cap, and its
SO2 cap) and two for the court decisions that vacated and remanded it.
CAIR and its replacement rules are the extreme example of repetition on the “train wreck” charts,
accounting for 10 of the 32 total entries, but most of the other rules on the chart have at least three
entries—for proposal, promulgation, and implementation. Only implementation imposes an actual
burden on the regulated community. Thus, the chart tends to exaggerate the regulatory burden
through repetition.
The timeline also treats as imminent the promulgation of rules that may not be so. For example,
the coal combustion waste rule, which has been the object of some concern, was authorized in the
Solid Waste Disposal Act Amendments of 1980. The legislation required that EPA conduct a
study of whether such waste should be considered hazardous waste and report to Congress before
taking regulatory action. EPA has conducted numerous studies over the three decades since then
and proposed to regulate the management of the waste in June 2010. Since then, however, the
agency has stated that it does not anticipate promulgating a final rule in 2011, leaving uncertain
when a rule will be promulgated. The EEI timeline assumed promulgation in 2011 with
compliance five years later.
Nevertheless, it is safe to say that several major rules under development at EPA are due to be
promulgated within the next 18 months and will affect coal-fired power plants, as shown in Table
1. Some of them are expected to be expensive; the costs of others are likely to be moderate or
limited, or they are unknown at this point because a rule has not yet been proposed.
3 Power plant operations also can affect water quality in several ways, and EPA is developing regulations to strengthen
requirements for both water intake and water effluent. These regulations affect a broader range of power plants,
however, including natural gas and nuclear, as well as coal-fired.
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Table 1. Timing of EPA Rules and Impacts on Coal-Fired Utilities
EPA Estimate of
Rule or Standard
Final Rule
Costs/Impactsa
Cross-State Air Pol ution
Finalized July 6, 2011 $2.4
billion/yearb
Rule
Utility MACT Rule Expected
November
16,
2011 $10-$11
billion/year
National Ambient Air
Promulgated June 22, 2010
$1.5 billion/year for all
Quality Standard
sources, but limited impact
(NAAQS) for sulfur
on electric generating units
dioxide
(EGUs)a
NAAQS for ozone
Expected July 2011 $19-$25
billion/year for all
sources but limited impact on
EGUsa
NAAQS for particulate
Not yet proposed; expected
Unknown
matter
in 2012
New Source Performance
Not yet proposed; expected
Unknown
Standards for Greenhouse
May 26, 2012
Gases
Cooling Water Intake
Expected July 27, 2012 $319
million/year
Structure Rule
Clean Water Effluent
Not yet proposed; expected
Unknown
Limitation Guidelines Rule
January 31, 2014
Coal Combustion Waste
Expected 2012 or later
$587 million-$1.5 billion/year
Rule
Source: Compiled by CRS.
a. Costs as estimated by EPA. See text for discussion of costs and impacts of specific rules.
b. Of the $2.4 billion annual cost, $1.6 billion is attributed to the Clean Air Interstate Rule (CAIR), a 2005 rule
that the Cross-State Rule is replacing.
This report will discuss each of the rules identified on EEI’s timeline individually; but before
discussing individual rules, a few general statements are in order.
First, most of these rules have been a long time in the making. As noted, the coal combustion
waste rule is the result of legislation passed in 1980; another rule, the utility air toxics rule (or
“Utility MACT”), which appears to be the most costly of the rules thus far proposed, is required
by the Clean Air Act Amendments of 1990. Some may question why EPA is undertaking so many
regulatory actions at once, but it is the decades of regulatory inaction that led to this point that
strike other observers.
The inaction stemmed in large part from special consideration given electric utilities by Congress:
both the Clean Air Act and the Solid Waste Disposal Act required special studies and reports to
Congress before EPA could set standards for certain pollutants emitted or wastes disposed by
electric utilities. Meanwhile, other industries that emitted the same pollutants or similar wastes
(e.g., municipal solid waste incinerators and medical waste incinerators, and any industry
generating hazardous waste) have been subject to more stringent emission controls or waste
management standards for a decade or more.
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Second, as we have noted in an earlier report on EPA regulations,4 both the legislative authority
for these rules and, in most cases, the development of the rules themselves predate the current
Administration. With the exception of greenhouse gas emission rules, all of the rules discussed
below began development under the Bush Administration or earlier, including several that were
promulgated under that Administration and subsequently were vacated or remanded to EPA by the
courts. The Cross-State Air Pollution Rule, the Utility MACT rule, and the Cooling Water Intake
rule, for example, fit that description. Other EPA actions, such as the Obama Administration’s
reconsideration of the ozone National Ambient Air Quality Standard, have actually delayed for
several years implementation of Bush Administration rules that would have strengthened existing
standards. Each of these actions is described in more detail below.
Third, one criticism highlighted by the EEI and others of EPA’s pending and upcoming rules is
the impact of multiple requirements. The critics point out that, although EPA conducts detailed
economic impact analyses of individual rules, the CAA and other federal environmental laws do
not provide a mechanism or require that the agency analyze cumulative impacts, including jobs.
Viewed separately, they argue, a particular rule may have limited economic impact, while the
second, third, or fourth rule that takes effect more or less simultaneously may drive the power
plant operator to decide to retire a given facility. As discussed in this report, such decisions are
highly case-specific, involving unique considerations and potentially mitigating factors.
The following sections of this report describe seven rules or categories of rules that are the core
of the “train wreck” debate, with background on the rule, information on its requirements (for
those rules that have been proposed or promulgated), and where possible, a discussion of the
rule’s potential costs and benefits. We also examine two of the studies—those of the electric
industry’s trade association (EEI) and the North American Electric Reliability Corporation—that
have attempted to estimate their cumulative economic impacts.
Cross-State Air Pollution (Clean Air Transport) Rule
The Cross-State Air Pollution Rule (hereinafter, the “Cross-State Rule”) replaces EPA’s major
clean air initiative under the Bush Administration, the Clean Air Interstate Rule (CAIR). CAIR
was promulgated in 2005, but was vacated and remanded to the agency by the D.C. Circuit Court
of Appeals in 2008.5 On appeal, the court left the rule in place until such time as EPA
promulgated a replacement. The agency proposed the replacement August 2, 2010,6 and it
finalized the rule July 6, 2011.7
4 CRS Report R41561, EPA Regulations: Too Much, Too Little, or On Track?, by James E. McCarthy and Claudia
Copeland.
5 The promulgated rule was published at 70 Federal Register 25162, May 12, 2005. The court decision was North
Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).
6 U.S. Environmental Protection Agency, “Federal Implementation Plans To Reduce Interstate Transport of Fine
Particulate Matter and Ozone; Proposed Rule,” 75 Federal Register 45210, August 2, 2010.
7 The final rule has not appeared in the Federal Register as of this writing, but a pre-publication copy as well as
explanatory and background material can be found on EPA’s website at http://www.epa.gov/crossstaterule/
actions.html. When proposed in August 2010, the Cross-State Rule was referred to as the Clean Air Transport Rule.
The name change to “Cross-State Rule” occurred late in the development of the final rule. As a result, many of the
explanatory materials, including the final Regulatory Impact Analysis, refer to the “Transport Rule.”
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EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?
Both CAIR and its replacement, the Cross-State Rule, are designed to control emissions of air
pollution that cause air quality problems in downwind states. The original, Bush-era rule did so
by establishing region-wide cap-and-trade programs8 for SO2 and NOx emissions from coal-fired
electric power plants in 28 Eastern states, at an estimated annual compliance cost of $3.6 billion
in 2015.9 CAIR covered only the eastern half of the country, but since most of the coal-fired
generation capacity lacking emission controls is located there, EPA projected that nationwide
emissions of SO2 would decline 53% and NOx emissions 56% by 2015, as compared to
nationwide emissions from electric generating units (EGUs) in 2001.
The replacement rule, finalized July 6, 2011, is a modified cap-and-trade rule. It would allow
unlimited trading of allowances within individual states; interstate trading would be allowed so
long as a state remained within 18%-21% of its emissions caps. Limiting interstate trading would
address the D.C. Circuit’s ruling, which found CAIR’s interstate allowance trading program
unlawful.
The rule applies to 28 states (adding Oklahoma, Kansas, and Nebraska to the 28 covered by
CAIR, but removing Connecticut, Delaware, and Massachusetts from the CAIR group). Its annual
compliance cost is estimated at $3.0 billion in 2012 and $2.4 billion in 2014.10
The Cross-State Rule would leave the CAIR Phase 1 (2009-2010) caps in place and would set
new limits replacing CAIR’s second phase in 2012 and 2014, up to three years earlier than CAIR
would have done. The 2012 and 2014 requirements place particular emphasis on SO2—emissions
of which would decline to 2.4 million tons in the covered states (73% below 2005 levels) in 2014.
To insure that the Cross-State Rule is implemented quickly, EPA is promulgating a Federal
Implementation Plan (FIP) for each of the states: the FIP specifies emission budgets for each state
based on controlling emissions from electric power plants. States may develop their own State
Implementation Plans and may choose to control other types of sources if they wish, but the
federal plan will take effect until the state acts to replace it.
The CAIR Phase 1 rules already appear to be having substantial effects. In August 2010, EPA
reported that emissions of SO2 had declined sharply in both 2008 and 2009: in the latter year,
emissions from fossil-fueled power plants in the lower 48 states (at 5.7 million tons) were 44%
below 2005 levels. NOx emissions from the same sources declined to 1.8 million tons in 2009, a
8 A cap-and-trade system sets a declining national cap on emissions and allocates emission allowances that can be
bought and sold on open markets.
9 70 Federal Register 25306, May 12, 2005.
10 These cost estimates include $1.6 billion in annualized costs already incurred to comply with Phase 1 of CAIR. EPA
estimates the additional cost of the Cross-State Rule at $1.4 billion in 2012 and $0.8 billion in 2014. The 2014 cost of
compliance with the Cross-State is less than that estimated for 2012 or for final implementation of CAIR in 2015
because the Regulatory Impact Analyses for the two rules use different base years for comparison. As the agency’s RIA
for the Cross-State Rule notes, “The base case in this RIA assumes that CAIR is not in effect, but does take into
account emissions reductions associated with the implementation of all federal rules, state rules and statutes, and other
binding, enforceable commitments finalized by December 1, 2010, that are applicable (sic) the power industry and
which govern the installation and operation of SO2 and NOx emissions controls in the timeframe covered in the
analysis.” Thus, the base with which control requirements are compared already accounts for some reductions realized
since the original CAIR rule was promulgated. See U.S. EPA, Office of Air and Radiation, Regulatory Impact Analysis
(RIA) for the final Transport Rule, June 2011, p. 244, at http://www.epa.gov/crossstaterule/pdfs/FinalRIA.pdf.
Hereafter, “Cross-State Rule RIA.”
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decline of 45% compared to 2005.11 The reductions occurred well in advance of CAIR’s
compliance dates: in fact, for both SO2 and NOx, the affected units had achieved about 80% of
the required 2015 reductions six years ahead of that deadline. Further reductions of both SO2 and
NOx can be expected as Phase 1 takes effect. The Cross-State Rule would build on these
reductions.
As noted earlier, EPA estimated that compliance with the rule will cost the power sector $2.4
billion annually when fully effective. It expects the benefits to be 50 to almost 120 times as
great—an estimated $120 billion to $280 billion annually. The most important benefit would be
13,000 to 34,000 fewer premature deaths annually. Avoided deaths and other benefits would
occur throughout the East, Midwest, and South, according to EPA, with Ohio and Pennsylvania
benefitting the most.12
Both EEI and NERC included the Cross-State Rule in their analyses, and their estimates of the
rule’s cost and the impact on coal-fired power do not appear to differ greatly from those of EPA,
particularly in the “train wreck” years, from now until 2017. NERC, for example, concluded that
the Cross-State Rule as proposed (then referred to as the “Transport Rule”) would lead to 2.9 GW
of deratings13 or retirements by 2015.14 This would represent less than 1% of coal-fired capacity,
and less than 0.3% of all EGU capacity. EPA, by comparison, projects that 4.8 GW of coal-fired
capacity would be uneconomic to maintain as a result of the rule.15
EEI’s analysis stated that it used EPA’s Integrated Planning Model assumptions with “no
additional controls for SO2-specific compliance” and with EPA’s preferred option for NOx
compliance through 2017. With the same assumptions and the same model, EEI’s projected
compliance costs should not differ from those of EPA.
For the years after 2017, however, EEI’s analysis did differ from that of EPA: it assumed that
selective catalytic reduction (SCR) would be required on all units to reduce NOx emissions. This
would impose additional cost, since about 54% of coal-fired capacity will not have installed SCR
to comply with the Cross-State Rule’s 2014 requirements, according to EPA.16 These costs are
speculative: to date, EPA has not proposed additional post-2014 requirements, and, as a result, the
agency has not estimated costs of compliance or a schedule for implementation of any future
pollution transport regulations.17
11 Data are from EPA’s “2009 Acid Rain Program Emission and Compliance Data Report,” August 11, 2010, at
http://www.epa.gov/airmarkets/progress/ARP09.html. Some of the emission reduction was the result of the recession,
which resulted in a decline in electric power generation of 5% from 2007 to 2009. Coal use for electricity generation
declined even more (11% from 2007 to 2009).
12 U.S. EPA, Office of Air and Radiation, “Final Air Pollution Cross-State Air Pollution Rule,” Overview Presentation,
undated, pp. 12-14, at http://www.epa.gov/crossstaterule/pdfs/CSAPRPresentation.pdf.
13 “Derating,” in these analyses, refers to the loss of available capacity because of the power needed to operate the
pollution control equipment.
14 NERC report, p. 20.
15 Cross-State Rule RIA, p. 262.
16 Cross-State Rule RIA, p. 259.
17 Given the need to meet the more stringent ambient air quality standard (NAAQS) requirements, especially those for
ozone and PM (described below), which EPA is expected to propose or promulgate this year, the agency stated its
intention to propose a further set of requirements addressing interstate transport of air pollution in 2011. (These
potential further rules appear on EEI’s chart as “Transport Rule II (NOx) Proposal” and “PM Transport Rule.”)
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To summarize, CAIR and its replacement, the Cross-State Air Pollution Rule, would impose
annual costs in the $2 billion to $3 billion range on previously uncontrolled coal-fired electric
generating units. Although these are significant costs, the industry has already complied with
Phase 1, which was the most ambitious of the rules’ requirements. Prompted by the ability to
generate tradable allowances, the industry complied well ahead of schedule. The final version of
the Cross-State Rule allows additional allowance trading as compared to the proposed rule, giving
EGUs additional flexibility in determining how to comply and lowering compliance costs.
Mercury and Air Toxics Standards/Utility MACT
In 2005, EPA promulgated regulations establishing a cap-and-trade system to limit emissions of
mercury from coal-fired power plants. Coal-fired electric generating units (EGUs) account for
about half of U.S. mercury emissions. Mercury is a potent neurotoxin that can harm health
(principally delayed development, neurological defects, and lower IQ in fetuses and children) at
very low concentrations.18
The mercury cap-and-trade rules promulgated in 2005 were a change in policy by EPA. All
previous sources of mercury subject to emission standards had been required to meet plant-
specific Maximum Achievable Control Technology (MACT) standards under CAA Section 112.19
Section 112 sets out very detailed requirements for MACT standards, including a list of the
pollutants that need to be controlled (not just mercury, but any of 187 hazardous air pollutants, or
HAPs) and the level of control that the standards must achieve. The 2005 cap-and-trade rules
addressed only mercury, and would have allowed many power plants to avoid control provided
they obtained allowances from others who achieved lower pollution levels than required, or
reduced emissions sooner than required. The ability of plants to avoid emission control by
purchasing allowances could lead to the continuation of “hot spots,” areas where mercury
concentrations in waterbodies are greater than elsewhere.
By contrast, the statute requires MACT standards applicable at each existing plant to be no less
stringent than the average emission limitation achieved by the best performing 12% of existing
sources in the industry subcategory.20 These statutory requirements are referred to as the “MACT
floor,” because the agency is not allowed to set less stringent standards, nor may it take economic
factors into account in determining what the floor will be.
Whether the agency could substitute cap-and-trade rules for the MACT requirements was
challenged by the State of New Jersey and others, and, in a 3-0 decision, the D.C. Circuit Court of
Appeals vacated the cap-and-trade rules in 2008.21 The court found that, under Section 112,
18 The principal route of exposure to mercury is through consumption of fish. Mercury enters water bodies, often
through air emissions, and is taken up through the food chain, ultimately affecting humans as a result of fish
consumption. All 50 states have issued fish consumption advisories due to mercury pollution, covering 16.8 million
acres of lakes, 1.25 million river miles, and the coastal waters of 20 entire states. For a more detailed discussion of
mercury’s health effects, see CRS Report RL32420, Mercury in the Environment: Sources and Health Risks, by Linda-
Jo Schierow. For EPA’s “2008 Biennial National Listing of Fish Advisories,” September 2009, see
http://water.epa.gov/scitech/swguidance/fishshellfish/fishadvisories/upload/2009_09_16_fish_advisories_tech2008.pdf.
19 EPA identified 174 industrial categories to be regulated under the MACT provisions. Standards have been
promulgated for almost all these categories except EGUs.
20 For new sources, the standards are to be based on the emission control achieved by the best controlled similar source.
21 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
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unless EPA “delisted” the category of sources, it had to require that each plant in the category
meet MACT standards. Under the statute, delisting would have required a finding that no EGU’s
emissions exceeded a level adequate to protect public health with an ample margin of safety, and
that no adverse environmental effect would result from any source.
Rather than appeal the court’s ruling to the Supreme Court or attempt to delist the category, EPA
proposed what is referred to as the “Utility MACT,” March 16, 2011.22 The proposal appeared in
the Federal Register May 3, beginning a public comment period that runs through August 4.
Under a consent agreement, the final MACT standards are to be promulgated by November 16,
2011.
The Proposed Rule
As proposed, the Utility MACT would require coal-fired power plants to achieve a 91% reduction
from uncontrolled emissions of mercury, nine other toxic metals, and three acid gases, all of
which were listed by Congress as hazardous air pollutants in the 1990 Clean Air Act
Amendments. Power plants are the largest emitters of many of these pollutants, accounting for
about 50% of the nation’s mercury emissions, 62% of arsenic emissions, and 82% of hydrochloric
acid emissions, for example.23 The Utility MACT would also reduce emissions of fine
particulates (PM2.5), which, although not categorized as hazardous air pollutants, are estimated to
cause thousands of premature deaths annually.
In proposing the standards, EPA noted that while the requirements are stringent for those facilities
lacking controls, 56% of existing coal-fired power plants already are in compliance. Thus, the
standards are expected to level the playing field, bringing older, poorly controlled plants up to the
standards being achieved by a majority of the existing units. In this respect, the proposed
standards reflect the statute’s requirement that existing sources of HAPs should meet standards
based on the current emissions of the best performing similar sources.
The agency also concluded that some plants, representing less than 10 GW of coal-fired capacity,
will be retired by 2015, rather than invest in control technologies. In all, it said, coal-fired
generation will decline about 2% compared to estimated generation in the absence of the rule.24
Costs, Benefits, and Control Technology
EPA projected the annualized cost of compliance with the proposed rule at $10.9 billion in 2015,
and remaining at $10 billion - 11 billion annually through 2030.25 The average consumer would
see an increase of $3-$4 per month in the cost of electricity due to the rule, according to the
agency.26 These costs will go largely to the installation of scrubbers and fabric filters. As a result
22 For a link to the proposed rule as well as explanatory material, see U.S. EPA, “Reducing Toxic Air Emissions from
Power Plants,” at http://www.epa.gov/airquality/powerplanttoxics/actions.html.
23 See U.S. EPA, “Emissions Overview: Hazardous Air Pollutants in Support of the Proposed Toxics Rule,”
Memorandum from Madeleine Strum, Emission Inventory and Analysis Group, to Marc Houyoux, Group Leader,
Emission Inventory and Analysis Group, March 15, 2011, Tables 3 and 4.
24 U.S. EPA, Regulatory Impact Analysis of the Proposed Toxics Rule: Final Report, March 2011, p. 8-17 at
http://www.epa.gov/ttn/ecas/regdata/RIAs/ToxicsRuleRIA.pdf. Hereafter, “Utility MACT RIA.”
25 Utility MACT RIA, p. 8-12.
26 U.S. EPA, “Power Plant Mercury and Air Toxics Standards: Overview of Proposed Rule and Impacts,” p. 3, at
(continued...)
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of the rule, 26 GW of coal-fired units, about 9% of total coal-fired capacity, are expected to install
scrubbers. (EPA estimated that by the time the rule requires compliance, 203 GW will already
have installed scrubbers anyway, as a result of other regulations.)27
More than half of the coal-fired EGU capacity (166 GW) are expected to add fabric filters
because of the rule, while 77 GW would have them whether or not there were a rule. In most
cases, the fabric filters will be coupled with activated carbon injection or dry sorbent injection.28
Mercury and other HAPs become attached to the carbon or sorbent after it is injected into the flue
gas, and the fabric filter collects the particles, removing them from the plant’s emissions. EPA
estimates that 62 GW of coal-fired capacity (about one-fifth of the U.S. total) would have either
activated carbon or dry sorbent injection in 2015 without the rule. The rule adds another 149 GW
of carbon/sorbent installations.
This is not complicated or new technology. Other types of facilities (notably solid waste
incinerators) have used this technology for the past 15 years to reduce their mercury and other
HAP emissions by 95% or more. As a result of state-level pollution control regulations, a growing
percentage of coal-fired power plants do the same.
The benefits of the rule are estimated by EPA at $59 billion to $140 billion annually—5 to 13
times as great as the costs—due primarily to the avoidance of 6,800 to 17,000 premature deaths
each year.29 Other benefits, only some of which were given dollar values, include the annual
avoidance of 11,000 nonfatal heart attacks, 120,000 cases of aggravated asthma, and
developmental effects on children, including effects on IQ, learning, and memory.30
Of the proposed EPA rules, the Utility MACT is probably the most costly and most likely to
affect older coal-fired plants that have not yet installed current pollution control technology.
EPA’s proposal does allow averaging of emissions from multiple units at a single location, which
may allow some older units that are operated infrequently to remain in service, but the absence of
broader allowance trading provisions in the law and the stringency of the emission requirements
mean that most units will not be able to escape regulation.
EEI’s and NERC’s Analyses of the Utility MACT Rule
In its report, which was written before EPA’s Utility MACT proposal, EEI concluded that, “All
coal units [would be] required to install a scrubber (wet or dry), activated carbon injection (ACI)
and a baghouse/fabric filter” for compliance with the MACT.31 This goes well beyond what EPA
proposed. Compared to EPA’s projections, it concluded that five times as much scrubber capacity,
nearly three times as much ACI, and about one and one-half times as much baghouse capacity
(...continued)
http://www.epa.gov/airquality/powerplanttoxics/pdfs/overviewfactsheet.pdf.
27 U.S. EPA, “Reducing Toxic Pollution from Power Plants: EPA’s Proposed Mercury and Air Toxics Standards,”
Overview Presentation, March 16, 2010, p. 15, http://www.epa.gov/airquality/powerplanttoxics/pdfs/presentation.pdf.
28 Ibid.
29 Ibid., p. 13.
30 U.S. EPA, “Fact Sheet: Proposed Mercury and Air Toxics Standards,” March 2011, p. 3, at http://www.epa.gov/
airquality/powerplanttoxics/pdfs/proposalfactsheet.pdf. For additional information, see Utility MACT RIA, pp. 1-2 to
1-10, and Chapter 5.
31 EEI report, p. 43.
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would need to be added, making the rule substantially more costly and far more difficult to
comply with in the limited time provided by the statute.
NERC’s report, which was also written before EPA proposed the Utility MACT, also assumed
that vastly more pollution control equipment would need to be added to coal-fired plants than
EPA believes will be necessary. The NERC analysis assumed wet scrubbers would be added to all
coal-fired plants that don’t already have them, that selective catalytic reduction (SCR) will be
added to all bituminous coal-powered facilities, and that activated carbon injection and baghouses
would be added at all facilities burning other types of coal.32 These assumptions are similar to
EEI’s except that by assuming wet scrubbers (instead of EPA’s general assumption that dry
scrubbers will suffice) and by assuming SCR at bituminous facilities, the cost impacts would
most likely be even greater than the costs in EEI’s assessment.33 NERC concluded that 8.4 GW to
17.6 GW of capacity would be retired or derated as a result of the MACT rule. If fewer units need
controls and less expensive pollution control equipment is needed on those that do, the
retirements and deratings would be fewer.
Following promulgation of these standards, existing power plants will have three years, with a
possible one-year extension, to meet the standards. (The three-to-four-year timeframe is mandated
by the statute.) Many in industry argue that three or four years is not enough time to complete the
required pollution control equipment installation, and as a result that the reliability of the nation’s
electric power supply could be affected by the rule. NERC did not say this directly, in part
because its analysis combines the effects of four rules, making it difficult to disaggregate the
Utility MACT’s effect. What it did say was:
The MACT Rule considered alone could drive Planning Reserve Margins of 8
regions/subregions below the NERC Reference Margin Levels standards and trigger the
retirement of 2-15 GW ... of existing coal capacity by 2015. To comply, owners of the
remaining capacity need to retrofit from 277 to 753 units with added environmental controls.
The “hard stop” 2015 compliance deadline proposed by the MACT Rule makes retrofit
timing a significant issue and potentially problematic.34
In part, whether or not there is sufficient time to implement the rule without threatening electric
system reliability will depend on the number of units that require retrofits. EPA is the only one of
the three sources discussed herein that analyzed the actual proposal. Both EEI and NERC
assumed requirements that appear to be substantially more stringent than what EPA proposed. If
EPA is correct in its analysis, the number of retrofits appears to be within the range of what the
industry has accomplished in the past as a result of earlier regulations. This point is discussed
below in more detail, under “Train Wreck?”
New Source Performance Standards for Greenhouse Gas Emissions
On December 23, 2010, EPA released the text of a settlement agreement with 11 states, two
municipalities, and three environmental groups, under which it agreed to propose New Source
Performance Standards (NSPS) to address greenhouse gas emissions from power plants by July
26, 2011, and take final action on the proposal by May 26, 2012. (The agency recently announced
32 NERC report, p. 50.
33 For a detailed comparison of equipment cost, see EEI report, p. 33.
34 NERC report, p. V.
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that it will delay proposal until September 30, 2011, but it expects to retain the May 26, 2012 date
for final action.) Electric generating units are the largest U.S. source of greenhouse gas (GHG)
emissions, accounting for about one-third of total U.S. emissions. Coal-fired plants accounted for
81% of the electric power industry’s total GHG emissions in 200935 and, thus, are expected to be
the main focus of EPA’s NSPS rules.
New Source Performance Standards are emission limitations imposed on designated categories of
major new (including substantially modified) stationary sources of air pollution. CAA Section
111 gives EPA authority to set NSPS for emissions of “air pollutants,” a term that includes
greenhouse gases.36 A new source is subject to NSPS regardless of its location (i.e., the same
standards apply to all new and modified major facilities anywhere in the United States). The
statute provides authority for EPA to impose such standards directly in the case of new (or
modified) sources (Section 111(b)), and through the states in the case of existing sources (Section
111(d)). The authority to impose performance standards on new and modified sources refers to
any category of sources that the EPA Administrator judges “causes, or contributes significantly to,
air pollution which may reasonably be anticipated to endanger public health or welfare” (Sec.
111(b)(1)(A))—language similar to the endangerment and cause-or-contribute findings EPA used
to promulgate GHG emission standards for motor vehicles in 2010.
In establishing these standards, Section 111 gives EPA considerable flexibility with respect to the
source categories regulated, the size of the sources regulated, and the particular gases regulated,
along with the timing and phasing in of regulations. This flexibility extends to the stringency of
the regulations with respect to costs and secondary effects, such as non-air-quality, health and
environmental impacts, along with energy requirements. This flexibility is encompassed within
the Administrator’s authority to determine the control systems that have been “adequately
demonstrated.” Standards of performance developed by the states for existing sources under
Section 111(d) can be similarly flexible.
Assuming EPA promulgates the greenhouse gas NSPS on schedule, how quickly such standards
would be applied to existing sources is an open question. EPA must first propose and promulgate
guidelines, following which the states would be given time to develop implementation plans.37
Following approval of the plans, the act envisions case-by-case determinations of emission limits,
in which the states may consider, among other factors, the remaining useful life of a source in
setting an emission limit. Thus, it is likely to be several years before existing power plants are
subject to emission limits for GHGs.
Since EPA has not yet proposed NSPS, the agency has not provided a Regulatory Impact Analysis
or cost estimate for such a rule.38 EEI, on the other hand, in six of the nine scenarios in its
35 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009, April 2011, Table 2-13, available at
http://epa.gov/climatechange/emissions/usinventoryreport.html.
36 In Massachusetts v. EPA (549 U.S. 497 (2007)), the Supreme Court held, in a 5-4 decision, that greenhouse gases are
clearly air pollutants under the Clean Air Act’s definition of that term.
37 How much time the states would be given to submit plans is unclear. The statute says that the regulations shall
establish a procedure “similar to that” provided for State Implementation Plans under Section 110, which generally
give states three years to submit a plan, following which EPA reviews it to determine its adequacy.
38 Agency guidance for state GHG permitting decisions, issued in November 2010, is perhaps the best example of what
the agency might require: the guidance focuses on energy efficiency as the best available control technology, and states
that both conversion to natural gas and carbon capture and sequestration can be eliminated from consideration. While
cost is not estimated in the guidance, the requirements would not appear to be stringent. For a discussion of EPA’s
guidance, see CRS Report R41505, EPA’s BACT Guidance for Greenhouse Gases from Stationary Sources, by Larry
(continued...)
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analysis, assumed there would be CO2 regulations in place by 2017. In five of the scenarios, it
estimated the cost of CO2 regulation or legislation at $25 per ton of emissions in 2017, with price
escalation of 5% annually thereafter. This assumption would impose a larger burden on coal-fired
power plants than any of the other rules considered in EEI’s report. In 2009, coal-fired electric
power plants emitted 1,748 million tons of CO2.39 Assuming roughly the same level of emissions
in 2017, EEI’s $25/ton assumption would result in a cost of CO2 regulation of $43.7 billion in
2017, with 5% increases each year thereafter. This cost, which appears to have been based on its
analysis of legislation not enacted in the 111th Congress, dwarfs every other projected regulatory
cost in the regulatory impact analyses that CRS examined. Inclusion of this requirement leads, in
EEI’s analysis, to an additional 23 GW of retired capacity in 2015 and 40 GW of incremental
retirements in 2020, accounting for more than half of all retirements in the latter year.40
NERC, on the other hand, did not include CO2 regulation in its study.
NAAQS Revisions
EPA is required in CAA Sections 108 and 109 to set National Ambient Air Quality Standards
(NAAQS) for air pollutants that endanger public health (“primary” NAAQS) or welfare
(“secondary” NAAQS) and that are emitted by numerous or diverse sources. NAAQS do not
directly regulate emissions. Rather, the primary NAAQS identify pollutant concentrations in
ambient air that must be attained to protect public health with an adequate margin of safety.
Secondary NAAQS identify concentrations necessary to protect public welfare, a broad term that
includes damage to crops, vegetation, property, building materials, and more.
In essence, NAAQS are standards that define what EPA considers to be clean air. Their
importance stems from the long and complicated implementation process that is set in motion by
their establishment. Once NAAQS have been set, EPA, using monitoring data and other
information submitted by the states to identify areas that exceed the standards and must,
therefore, reduce pollutant concentrations to achieve them. State and local governments then have
three years to produce State Implementation Plans which outline the measures they will
implement to reduce the pollution levels in these “nonattainment” areas. Nonattainment areas are
given anywhere from three to 20 years to attain the standards, depending on the pollutant and the
severity of the area’s pollution problem.
EPA also acts to control many of the NAAQS pollutants wherever they are emitted through
national standards for certain products that emit them (particularly mobile sources, such as
automobiles) and emission standards for new stationary sources, such as power plants.
In the 1970s, EPA identified six pollutants or groups of pollutants for which it set NAAQS.41 But
that was not the end of the process. When it gave EPA the authority to establish NAAQS,
Congress anticipated that the understanding of air pollution’s effects on public health and welfare
(...continued)
Parker and James E. McCarthy.
39 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009, April 2011, Table 2-13, available at
http://epa.gov/climatechange/emissions/usinventoryreport.html.
40 EEI report, p. v.
41 The six pollutants are ozone, particulates, carbon monoxide, SO2, NOx, and lead.
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would change with time, and it required that EPA review the standards at five-year intervals and
revise them, as appropriate.
The agency is currently conducting the required reviews of these standards: it has already
completed reviews for five of the six standards, but two of them have been remanded by the D.C.
Circuit Court of Appeals for further agency action, and others are being challenged in court. The
electric power industry and others are following this process closely, because more stringent
standards could begin a process that would lead to more stringent emission standards.42
The three standards most likely to affect power plants are those for SO2, ozone, and particulate
matter (PM).
Sulfur Dioxide (SO2)
On June 22, 2010, EPA revised the NAAQS for SO2, focusing on short-term (1-hour) exposures.
The prior standards (for 24-hour and annual concentrations), which were set in 1971, were
revoked as part of the revision. Since 1971, EPA had conducted three reviews of the SO2 standard
without changing it. However, following the last of these reviews, in 1998, the D.C. Circuit Court
of Appeals remanded the SO2 standard to EPA, finding that the agency had failed adequately to
explain its conclusion that no public health threat existed from short-term exposures to SO2.43
Twelve years later, EPA revised the standard to respond to the court’s decision.
The new short-term standard is substantially more stringent than the previous standards: it
replaces a 24-hour standard of 140 parts per billion (ppb) with a 1-hour maximum of 75 ppb. This
means that there could be an increase in the number of SO2 nonattainment areas (especially since
there were no nonattainment areas under the old standards), with additional controls required on
the sources of SO2 emissions in any newly designated areas. Since electric generating units
accounted for 60% of total U.S. emissions of SO2 in 2009, additional controls on EGUs would be
likely.
The timing and extent of any additional controls is uncertain, however, for several reasons. First,
the monitoring network needed to determine attainment status is incomplete and is not primarily
configured to monitor locations of maximum short-term SO2 concentrations.44 The agency says it
will need 41 new monitoring sites to supplement the existing network in order to have a more
complete data base. Since three years of data must be collected after a site’s startup to determine
attainment status, it may be as late as 2016 before some areas will have sufficient data to be
classified. Even if the areas can be designated sooner based on modeling data, it would be at least
2015 before State Implementation Plans with specific control measures would be due, and actual
compliance with control requirements would occur several years later.
Meanwhile, SO2 emissions will be significantly reduced as a result of the CAIR, Cross-State, and
Utility MACT rules described above. Thus, although EPA identified 59 counties that would have
42 Five of the entries on EEI’s “train wreck” chart (Figure 1) refer to NAAQS reviews.
43 American Lung Association v. EPA, 134 F.3d 388 (D.C. Cir 1998).
44 U.S. EPA, “Fact Sheet: Revisions to the Primary National Ambient Air Quality Standard Monitoring Network, and
Data Reporting Requirements for Sulfur Dioxide,” June 2, 2010, p. 3, at http://www.epa.gov/air/sulfurdioxide/pdfs/
20100602fs.pdf.
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violated the new SO2 NAAQS based on 2007-2009 data, it is not clear whether any of these
counties will be in nonattainment by the time EPA designates the nonattainment areas.
In its Regulatory Impact Analysis of the SO2 NAAQS, the agency estimated that attainment
would require a reduction of 370,000 tons of SO2 by 2020, about two-thirds of which would need
to come from EGUs.45 The agency estimated the annualized cost of these controls (for all sources,
not just EGUs) at $1.5 billion. Benefits would range from $15 billion to $37 billion annually.46
These costs and benefits do not take account of CAIR, the Cross-State Rule, or the Utility MACT,
however. (As may be recalled, the CAIR and Cross-State Rules will result in more than 6 million
tons of SO2 emission reductions by 2014.) The agency assumed for purposes of analysis that none
of these rules was in effect, because none of them was in effect in 2005, the base year used for
analytical purposes. As the agency’s RIA states:
The baseline for this analysis is complicated by the expected issuance of additional air
quality regulations. The SO2 NAAQS is only one of several regulatory programs that are
likely to affect EGU emissions nationally in the next several years. We thus expect that
EGUs will apply controls in the coming years in response to multiple rules. These include
the maximum achievable control technology (MACT) rule for utility boilers, revisions to the
Clean Air Interstate Rule, and reconsideration of the Clean Air Mercury Rule. Therefore
controls and costs attributed solely to the SO2 NAAQS in this analysis will likely be needed
for compliance with other future rules as well.47
In short, compared to the Utility MACT and the Cross-State Rule, the SO2 NAAQS has relatively
little impact on coal-fired power plants in EPA’s analysis, and the agency’s analysis relied on
assumptions that probably overstate the impact of the standard.
EEI included the SO2 NAAQS on its “train wreck” timeline, but neither EEI nor NERC
considered the standard in their analyses.
Ozone
On January 19, 2010, EPA proposed a revision of the NAAQS for ozone.48 EPA currently expects
to finalize this revision by the end of July 2011 (although it has already postponed the review’s
completion date three times). As noted above, NAAQS do not directly limit emissions, but they
set in motion a process under which “nonattainment areas” are identified and states and EPA
develop plans and regulations to reduce pollution in those areas.
Ozone is not directly emitted by coal-fired power plants (or most other sources). It forms in the
atmosphere as the result of a chemical reaction between nitrogen oxides (NOx), volatile organic
compounds (VOCs), and carbon monoxide (CO) in the presence of sunlight. Power plants emit
45 U.S. EPA, Office of Air Quality Planning and Standards, Final Regulatory Impact Analysis (RIA) for the SO2
National Ambient Air Quality Standards (NAAQS), June 2010, page ES-7, Table ES.2, at http://www.epa.gov/ttnecas1/
regdata/RIAs/fso2ria100602full.pdf.
46 Ibid., p. ES-9, Table ES.4.
47 Ibid., p. ES-3.
48 U.S. Environmental Protection Agency, “National Ambient Air Quality Standards for Ozone; Proposed Rule,” 75
Federal Register 2938, January 19, 2010.
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one of these precursor emissions, NOx. Thus, the setting of a more stringent ozone standard
might lead to tighter controls on their NOx emissions.
The ozone standard affects a large percentage of the population: as of September 2010, 119
million people (nearly 40% of the U.S. population) lived in areas classified “nonattainment” for
the current ozone standard. The proposed revision would lower the primary (health-based)
standard from 0.075 parts per million—75 parts per billion (ppb)—averaged over 8 hours to
somewhere in the range of 70 to 60 ppb averaged over the same time.
EPA has identified at least 515 counties that would violate the proposed ozone NAAQS if the
most recent three years of data available at the time of proposal were used to determine
attainment (compared to 85 counties that violated the standard in effect at that time). The
proposal would also, for the first time, set a separate standard for public welfare, the principal
effect of which would be to call attention to the damage by ozone to forests and agricultural
productivity.
As with other NAAQS, the standards, when finalized, would set in motion a long implementation
process that has far-reaching impacts. The first step, designation of nonattainment areas, is
expected to take place within a year of the new standards’ promulgation; the areas so designated
would then have 3 to 20 years to reach attainment.
EPA is prohibited by the statute from considering costs in setting NAAQS, but it does prepare
cost and benefit estimates for information purposes. The agency estimated that the costs of
implementing the revised ozone NAAQS (for all sources of ozone precursors) would range from
$19 billion to $25 billion annually in 2020 if the standard chosen is 70 ppb, or $52 billion to $90
billion if the standard chosen is 60 ppb,49 with benefits of roughly the same amount.
Although the ozone NAAQS revision is one of the most expensive EPA rules under development,
it is unlikely to have major impacts on electric generating units. Fuel combustion by electric
utilities accounted for 13% of NOx emissions nationally in 2009, and less than 1% of VOC and
CO emissions. Thus, other sources account for most of the emissions and are likely to be the main
focus of the emission controls necessary to reach attainment of the standard. Furthermore, to the
extent that utility NOx emissions are targeted, it will likely be through the Cross-State Rule, or a
successor to it, whose impacts were discussed above. The ozone NAAQS would primarily serve
as a driver in the development of these other rules.
As with the SO2 NAAQS, EEI included the ozone NAAQS on its “train wreck” diagram, but
neither EEI nor NERC considered the standard in their analyses.
Particulate Matter
A third NAAQS whose revision could affect coal-fired power plants is that for particulate matter
(PM). The PM NAAQS, which includes standards for both coarse and fine particulates (PM10 and
PM2.5, respectively), was last revised in October 2006. The D.C. Circuit Court of Appeals
remanded the PM2.5 standards to EPA in February 2009,50 so EPA is both conducting the statutory
49 U.S. EPA, “Fact Sheet: Supplement to the Regulatory Impact Analysis for Ozone,” January 7, 2010, at
http://www.epa.gov/air/ozonepollution/pdfs/fs20100106ria.pdf.
50 American Farm Bureau Fed'n v. EPA, 559 F.3d 512 (D.C. Cir. 2009).
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five-year review of the standard and responding to the D.C. Circuit decision. The agency expects
to propose revised standards for both PM2.5 and PM10 by summer 2011, with promulgation
perhaps taking place in 2012.
EPA staff have recommended a strengthening of the PM NAAQS,51 but at this time, there is no
proposal to be evaluated. Fuel combustion by electric utilities is the source of 8.3% of PM2.5 and
3.5% of PM10.
As with the other NAAQS, EEI included the PM NAAQS on its “train wreck” diagram, but
neither EEI nor NERC considered the standard in their analyses.
Revised Cooling Water Intake Rule
Power plants withdraw large volumes of water for production and, especially, to absorb heat from
their industrial processes. Water withdrawals by electric generating plants, used primarily for
cooling, are the largest water use category by sector in the United States—201 billion gallons per
day (BGD) in 2005. Although water withdrawal is a necessity for these facilities, it also presents
special problems for aquatic resources. Cooling water intake structures (CWIS) can cause two
types of environmental harm. First, impingement occurs when fish, invertebrates, and other
aquatic life are trapped on equipment on intake screens at the entrance to the CWIS. Second,
entrainment occurs when small organisms pass through the intake screening system, travel
through the cooling system pumps and tubes, and then are discharged back into the source water.
Impingement and entrainment injure or kill large numbers of aquatic organisms at all life stages.
Section 316(b) of the Clean Water Act (CWA) authorizes regulation of CWIS to protect such
organisms from being harmed or killed.
Regulatory efforts by EPA to implement Section 316(b) have a complicated history over 35 years,
including legal challenges at every step by industry groups and environmental advocates.
Currently most new facilities are regulated under rules issued in 2001, while rules for existing
facilities issued in 2004 were challenged and remanded to EPA for revisions. In response to the
remand, in March 2011 EPA proposed national requirements expected to affect 559 existing
electric generators; 483 are fossil-fuel facilities. The affected facilities comprise approximately
11% of the steam electric generating facilities and over 45% of the electric power sector capacity
in the United States. Publication of the CWIS proposal in the Federal Register on April 20
triggered a 90-day public comment period that ends on July 19, 2011.52 EPA is under a court-
ordered schedule to issue a final CWIS rule by July 27, 2012.
Even before release, the proposed regulations were highly controversial among stakeholders and
some Members of Congress who questioned whether a stringent and costly environmental
mandate could jeopardize reliability of U.S. electricity supply. Many in industry feared, while
51 On July 2, 2010, EPA released the Second External Review Draft of its Policy Assessment for the Review of the
Particulate Matter NAAQS. The draft represented EPA staff’s recommendations to the Administrator. It outlined
options for revising both the fine and coarse particulate standard, both of which would make the standards more
stringent. The draft is available at http://www.epa.gov/ttn/naaqs/standards/pm/s_pm_2007_pa.html.
52 U.S. Environmental Protection Agency, “National Pollutant Discharge Elimination System—Cooling Water Intake
Structures at Existing Facilities and Phase 1 Facilities,” 76 Federal Register 22174-22228, April 20, 2011. For
information, see CRS Report R41786, Cooling Water Intake Structures: Summary of EPA’s Proposed Rule, by Claudia
Copeland.
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environmental groups hoped, that EPA would require installation of technology called closed-
cycle cooling that most effectively minimizes the environmental damage of CWIS, but also is the
most costly technology option.
In its proposed rule, EPA evaluated four regulatory options expected to minimize the harm to
aquatic species of CWIS at existing facilities, each with varying environmental benefits and
costs.53 The agency concluded that closed-cycle cooling reduces CWIS impacts to a greater extent
than other technologies, but declined to mandate closed-cycle cooling universally and instead
favored a less costly, more flexible regulatory option. EPA’s recommended approach would
essentially codify current CWIS permitting procedures for existing facilities, which are based on
site-specific determinations and have been in place administratively for some time because of
legal challenges to previous rules. The agency based the conclusion to not mandate closed-cycle
cooling on four factors: additional energy needed by electricity and manufacturing facilities to
operate cooling equipment, and threats to reliability of energy delivery (i.e., energy penalty);
additional air pollutants that would be emitted because fossil-fueled facilities would need to burn
more fuel as compensation for the energy penalty; land availability concerns in some locations;
and limited remaining useful life of some facilities such that retrofit costs would not be justified.
EPA estimates that more than 90 of the 559 affected electric generators already have the
technology required to demonstrate compliance with the proposed rule.
Compliance with the rule, when promulgated in 2012, will be required as soon as possible. For
individual facilities, specific compliance deadlines will be set when the facility next seeks to
renew its existing CWA discharge permit; such permits are issued for five-year periods and then
must be reissued by the permitting authority (state or EPA). Permitting agencies often allow
facilities some time to come into compliance with new requirements. As proposed by EPA, for
facilities already in compliance with the rule or needing to install technologies other than cooling
towers, the compliance period is assumed to be a five-year period from 2013 to 2017. EPA
expects that facilities required to install cooling towers for entrainment mortality control will
require a longer period of time. Fossil-fuel electric power generating facilities would achieve
compliance from 2018 to 2022.54 EPA estimated that the annual costs of the proposed rule will be
$319 million, while benefits will be $17.6 million annually.55 EPA also estimated that a net nine
generating units would be retired as a result of the rule.56 EPA did not identify potential
retirements by fuel source.
Industry groups generally view the March 2011 proposal favorably (at least in comparison with
what had been anticipated), while environmental advocates are critical that the proposal does not
mandate stricter technological options to provide greater protection of aquatic resources. States
53 Three of the regulatory options considered by EPA would require all existing electric generators covered by the rule
to use screens to prevent impingement of fish, but they differ with respect to requiring closed-cycle cooling towers to
prevent entrainment. The fourth option would allow permitting authorities to establish impingement and entrainment
controls on a case-by-case basis for small and medium EGUs and would require uniform controls for larger facilities.
The agency’s preferred option would require uniform impingement standards (i.e., screens) for all power plants and
case-by-case determination of need for cooling towers for all facilities.
54 EPA believes that permitting authorities would need to coordinate outages by multiple power generating facilities in
a geographic area so as to minimize impacts on reliability of power generation. In these circumstances, EPA expects a
facility could reasonably require as long as eight years to attain compliance.
55 Costs and benefits are annualized over 50 years and discounted at a 3% rate.
56 EPA concluded that 39 EGUs would be retired, but that 30 others would avoid closure because of EPA’s
recommendation of a rule that does not mandate cooling tower retrofits.
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will be responsible for most permitting actions to implement the rule. Since many states are
coping with constrained budgets, some of them favor a regulatory approach that requires them to
make fewer case-by-case decisions, thus imposing less administrative cost.
Prior to release of the EPA proposal, industry assumed that the agency would propose a more
stringent rule with a more rapid timeline for compliance. Both EEI and NERC assumed that EPA
would mandate that existing power plants retrofit by installing closed-cycle cooling systems. EEI
assumed that the CWIS rule would affect 314 GW of capacity and a total of 400 electric
generating units, at a cost of $16 billion through 2020. EEI did not estimate or separate out how
many plant retirements would result from the anticipated CWIS rule.
The NERC analysis assumed that mandatory cooling tower retrofits would be required by 2018,
and on that basis, NERC concluded that the CWIS rule would be the most costly of the four EPA
rules that it examined (although NERC did not estimate compliance costs for this rule), with the
greatest likely impact on electricity capacity. NERC concluded that such a rule would lead to
power plant retirements totaling 33 GW of capacity. However, NERC also concluded that only
2.5 GW of that total would be coal-fired power plants (representing 94 coal steam units).
According to NERC, the largest impact of such a CWIS rule would be on older oil- and gas-fired
units, with 253 units totaling 30 GW of capacity expected to be economically vulnerable and thus
likely to be retired.57
Revised Steam Electric Effluent Guidelines
Under authority of CWA Section 304, EPA establishes national technology-based regulations,
called effluent limitation guidelines (ELGs), to reduce pollutant discharges from industries
directly to waters of the United States and indirectly to municipal wastewater treatment plants.
EPA has issued ELGs for 56 industries that include many types of dischargers, such as
manufacturing and service industries. These requirements are incorporated into discharge permits
issued by EPA and states. The current steam electric power plant rules,58 which were promulgated
in 1982, apply to about 1,200 nuclear- and fossil-fueled steam electric power plants nationwide,
500 of which are coal-fired.
In a 2009 study, 59 EPA found that the current regulations do not adequately address the pollutants
being discharged and have not kept pace with changes that have occurred in the electric power
industry over the last three decades, specifically the increase of flue gas desulfurization (FGD)
systems, or scrubbers, at coal-fired power plants to control air pollution. According to EPA, as of
June 2008, 30% of coal-fired power plants were using FGD systems to control SO2 emissions
from the flue gas generated in the plants’ boilers and prevent buildup of certain corrosive
constituents such as chlorides, and by 2025, nearly 80% of coal-fired generating capacity is
expected to employ FGD systems. While scrubbers dramatically reduce emissions of harmful
pollutants into the air, some create a significant liquid waste stream (especially wet scrubbers). In
addition, discharges from coal combustion waste (CCW) ash impoundments at steam electric
power plants have a potential to degrade water quality. Concern about releases of CCW grew
57 NERC report, pp. 14-15.
58 40 CFR § 423.10.
59 U.S. Environmental Protection Agency, Steam Electric Power Generating Point Source Category: Final Detailed
Study Report, EPA 821-R-09-008, October 2009.
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following the collapse of ash impoundment dams at Tennessee Valley Authority (TVA) power
plants, discussed further under “Coal Combustion Wastes,” below. Pollutants of concern
associated with FGD systems and CCW include a large number of metals (e.g., mercury, arsenic,
chromium, and selenium), chloride, nitrogen compounds, and total dissolved and suspended
solids. EPA believes that many current CWA permits for power plants do not fully address
potential water quality impacts of these discharges through appropriate pollutant limits and
monitoring and reporting requirements.
Under the CWA , EPA has a duty to review existing ELGs at least every five years and, if
appropriate, revise them. EPA had been studying the effluent limitations for the steam electric
power generating category since the mid-1990s and on several occasions indicated that a
preliminary study of discharges from this category was necessary. In 2009, environmental groups
sued EPA to compel the agency to commit to a schedule for issuing revised guidelines. Pursuant
to a November 8, 2010 consent decree that it entered into with environmental litigants, EPA
agreed to propose the revised power plant ELG by July 23, 2012, and to finalize the rule by
January 31, 2014. The rulemaking will address wastewater discharges from CCW ash storage
ponds and FGD air pollution controls, as well as other power plant waste streams.60 As with the
CWIS rule discussed above, compliance with specific regulations, which cannot be anticipated at
this time, will occur over several years with full compliance likely not required before 2019 or
2020.
Until EPA proposes a regulation, the substance, cost, and impact of a rule are speculative. Still,
even before EPA proposes a new ELG for power plants, the agency has launched an effort to
scrutinize state-issued CWA discharge permits for power plants as an interim measure to address
longstanding concerns that the permits need to be strengthened. In a June 2010 letter to
environmental groups, EPA committed to reviewing at least 35 CWA permits for power plants
before the end of 2012 and simultaneously provided EPA regional offices with interim guidance
to assist state and EPA permitting authorities to establish appropriate requirements for power
plant wastewater discharges.61
Since EPA has not proposed a revised steam electric power ELG rule, the agency has not
provided a Regulatory Impact Analysis or cost estimate for such a rule. EEI included an ELG rule
in the timeline shown in Figure 1, but did not analyze or project what a rule would look like, or
what its impact might be. NERC did not include an ELG rule in its analysis.
Coal Combustion Waste62
Coal combustion waste (CCW) is inorganic material that remains after pulverized coal is burned
for electricity production.63 A tremendous amount of the material is generated each year—
60 Separately, EPA also is considering regulation of coal ash disposal sites under Resource Conservation and Recovery
Act, as discussed in this report under “Coal Combustion Waste.”
61 James A. Hanlon, Director, EPA Office of Wastewater Management, “National Pollutant Discharge Elimination
System (NDES) Permitting of Wastewater Discharges from Flue Gas Desulfurization (FGD) and Coal Combustion
Residuals (CCR) Impoundments at Steam Electric Power Plants,” memorandum, June 7, 2010, on file with authors.
62 This section of the report was written by Linda Luther, Analyst in Environmental Policy.
63 In its June 2010 regulatory proposal, EPA refers to the material as coal combustion residuals. It is also commonly
referred to as coal combustion byproducts or materials. How the material is referred to generally depends on the
context in which it is being discussed. For example, coal combustion waste is generally destined for disposal, while
coal combustion byproducts or residuals may be destined for some use such as a component in gypsum wallboard or
(continued...)
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industry estimates that as much as 135 million tons were generated in 2009, making it one of the
largest waste streams generated in the United States. Disposal of CCW onsite at individual power
plants may involve decades-long accumulation of tons of dry ash (in a landfill) or wet ash slurry
(in a surface impoundment) deposited at the site.
On December 22, 2008, national attention was turned to risks associated with managing such
large volumes of waste when a breach in a surface impoundment pond at TVA’s Kingston, TN,
plant released 1.1 billion gallons of coal fly ash slurry that damaged or destroyed homes and
property. Beyond the potential for a sudden, catastrophic release from a surface impoundment, a
more common threat associated with CCW management is the leaching of contaminants likely
present in the waste, primarily heavy metals, resulting in surface or groundwater contamination.
This risk is particularly high at unlined surface impoundments which are likely in common use
today.
The Kingston release also brought attention to how the waste is managed and regulated. CCW
management is largely exempt from federal regulations and is regulated by individual states. State
requirements generally apply to two broad categories of CCW management—its disposal in
landfills, surface impoundment, or mines, and its beneficial use (e.g., as a component in concrete,
cement, or gypsum wallboard, or as structural or embankment fill). Inconsistencies and
deficiencies in state regulatory programs have been identified by EPA as one reason that national
standards to regulate CCW are needed. More recently, EPA called into question the effectiveness
of some state regulatory programs for protecting human health and the environment.
As discussed below, to establish a national standard necessary to address potential threats of
improper management of CCW to human health and the environment, on June 21, 2010, EPA
proposed two regulatory options.64
Regulatory Background
The evolution of CCW regulation began in 1978 when EPA first proposed hazardous waste
management regulations under Subtitle C of the Resource Conservation and Recovery Act
(RCRA).65 However, in 1980, Congress amended the law to exclude CCW from regulation under
Subtitle C, pending EPA’s completion of a report to Congress and regulatory determination on
whether hazardous waste regulations were warranted.66 In response, EPA published regulatory
determinations in 1993 and 2000 retaining that exemption, concluding on both occasions that
CCW did not warrant regulation as hazardous waste. However, in the 2000 determination EPA
stated that national regulations under Subtitle D (applicable to non-hazardous solid waste) were
warranted for CCW disposal in landfills and surface impoundments for reasons including new
(...continued)
cement. Regardless of what it is called, these terms refer to the same substances. Since EPA’s regulatory proposal
primarily discusses issues associated with the materials’ disposal, it is referred to here as coal combustion waste
(CCW).
64 U.S. EPA, “Hazardous and Solid Waste Management System; Identification and Listing of Special Wastes; Disposal
of Coal Combustion Residuals From Electric Utilities,” 75 Federal Register 35127-35264, June 21, 2010.
65 RCRA actually amends earlier legislation, the Solid Waste Disposal Act of 1965, but the amendments were so
comprehensive that the act is commonly referred to as RCRA rather than by its official title.
66 This exclusion was specified in Solid Waste Disposal Act Amendments of 1980 (P.L. 96-482) at 42 U.S.C.
6921(b)(3)(A)(i). The provisions are commonly referred to as the “Bevill Amendment” or the “Bevill exclusion.”
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data about potential risks to human health and the environment and concerns about the adequacy
of state regulatory programs. EPA stated that it would revise its determination that regulation
under Subtitle C was not needed if it found that a need for such regulation was warranted.
After accumulating new data regarding CCW management, in October 2009, EPA developed a
draft regulatory proposal to list the material as hazardous waste under Subtitle C of RCRA. Under
the draft proposal, EPA would establish land disposal and treatment standards for CCW. EPA
cited several reasons for determining that regulation under Subtitle C was needed based on new
data which showed that disposal in unlined landfills and surface impoundments presents
substantial risks to human health and the environment from releases of toxic constituents, that a
large amount of waste is still being disposed in units that lack necessary protections, and state
programs have not been sufficiently improved to address gaps that EPA had previously
identified.67
Current Regulatory Proposal
As a result of review by the Office of Management and Budget, EPA’s draft proposal underwent
substantial changes. The final proposal, published on June 21, 2010, stated that the determination
to revise the regulatory determination had not yet been made. It proposed two regulatory options
for consideration. Under the first option, EPA would draw on its existing authority to list a waste
as hazardous and to regulate it. The second option would keep the Subtitle C exclusion in place,
but would establish national criteria applicable to landfills and surface impoundments under
RCRA’s Subtitle D non-hazardous solid waste requirements. Under Subtitle D, EPA does not have
the authority to implement or enforce its proposed requirements. Instead, EPA would rely on
states or citizen suits to enforce the new standards. However, in support of the Subtitle D option,
EPA cited industry’s concern that labeling CCW as hazardous waste would stigmatize beneficial
uses of the material and ultimately increase the amount that must be disposed.68
The public comment period for EPA’s proposal ended on November 19, 2010. It is unclear when,
or if, EPA will ultimately promulgate a final rule. On March 3, 2011, EPA Administrator Lisa
Jackson testified that she does not anticipate a final rule to be promulgated in 2011, due to the
large number of public comments received. 69
During several congressional hearings, some Members of Congress also have expressed concern
over EPA’s ultimate decision to regulate CCW. Their concerns about potential Subtitle C
regulations relate primarily to the potential impacts those requirements may ultimately have on
coal-producing states, state regulatory agencies, energy prices, and CCW recycling opportunities.
On the other hand, concerns expressed by other Members regarding the Subtitle D option
generally relate to concerns that human health and the environment would not be sufficiently
protected given EPA’s lack of authority to enforce Subtitle D requirements.
67 For more information about EPA’s regulatory proposal, see CRS Report R41341, EPA’s Proposal to Regulate Coal
Combustion Waste Disposal: Issues for Congress, by Linda Luther.
68 Opponents of the Subtitle D option have argued the opposite point—that recycling may actually increase if disposal
becomes more costly under the Subtitle C requirements.
69 House Committee on Appropriations, Subcommittee on Interior, Environment, and Related Agencies, March 3,
2011, EPA budget hearing.
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EPA’s Regulatory Impact Analysis (RIA) estimated potential costs and benefits associated with
the 2010 regulatory proposal. The RIA estimated average annualized regulatory costs to be
approximately $1.5 billion a year under the Subtitle C option and $587 million a year under the
Subtitle D option. EPA also estimated annualized “regulatory benefits.” Under the Subtitle C
option, regulatory benefits would range widely depending on whether there would be increases in
recycling due to added costs of disposal, or decreases in recycling due to possible “stigma”
effects of regulating the material under Subtitle C.70 EPA estimated that if a decrease in beneficial
use were to occur, this could result in increased costs of $16.7 billion, while induced increases in
recycling could result in a regulatory benefit of $7.4 billion a year. Under the Subtitle D option,
the regulatory benefit is estimated to range from $85 million to $3 billion a year.71
The EEI report estimated that if the Subtitle C option were adopted, costs would be considerably
higher than projected by EPA, based largely on two costs that were not considered by EPA—costs
of retrofitting existing disposal units to meet new standards, and the costs of sending the waste to
an offsite commercial hazardous waste disposal facility. With regard to the first cost, neither of
EPA’s regulatory options would require existing landfills to be retrofitted to meet new regulatory
standards as long as they install groundwater monitoring systems and implement corrective
action, as needed, while existing surface impoundments would be required to be retrofitted.
However, based on its past experience with surface impoundment regulations, EPA assumed that
facilities would choose to close rather than retrofit. EEI assumed that some portion would retrofit.
With regard to the second cost, EEI assumes that under potential Subtitle C requirements, siting
or zoning restrictions and state or local ordinances would affect a facility’s decision to open a new
CCW landfill. However, these factors are difficult to evaluate. Electric utilities currently operate
CCW landfills on-site; no data have been presented that indicate that future landfills could not
meet EPA’s proposed location restrictions or design requirements or that additional restrictions
would prohibit or limit the potential for on-site disposal. Further, according to industry
statements, new CCW landfills are already built with liners and groundwater monitoring systems.
Thus, there is little evidence to suggest that new Subtitle C standards would differ greatly from
what has, up until now, been common industry practice.
Other Regulatory Actions Affecting Coal Power
EPA and other federal agencies (the Office of Surface Mining and Reclamation, in the
Department of the Interior; and the U.S. Army Corps of Engineers) are developing a series of
actions and regulatory proposals to reduce the harmful environmental and health impacts of
surface coal mining, including a practice called mountaintop removal mining, in Appalachia.
These actions would not affect electric power plants directly, and thus are not covered by EEI nor
NERC in their studies. Nevertheless, numerous critics have included actions by EPA, the Corps of
Engineers, and the Interior Department regarding mountaintop removal mining in Appalachia in
what they term a “War on Coal.” Some of these EPA-Corps-Interior actions are discussed in
Appendix A to this report.
70 Potential benefits to the Subtitle C option also included groundwater protection benefits (e.g., human cancer
prevention benefits) and remediation or cleanup costs avoidance after groundwater contamination or surface
impoundment breach.
71 For more detail on cost estimates, see 75 Federal Register 35134 and 35211-35220, June 21, 2010.
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The Future for Coal-Fired Power
Virtually all the analyses agree that coal will continue to play a substantial role in powering
electric generation for decades to come. EPA, for example, in the Utility MACT RIA, concluded
that coal-fired generation will be roughly the same in 2015 as it was in 2008, despite the impact
of the MACT and other rules.72 By 2030, the agency projects that 43% of the nation’s electricity
will still be powered by coal.73 (The current level is 45%.) EEI projected that coal will be
responsible for 36% to 46% of electricity generation in 2020, depending on the scenario.
There will be retirements of coal-fired capacity, however, as all of the analyses conclude. The
number of these retirements, and the role of EPA regulations in causing them, are matters of
dispute. The most extreme scenario in EEI’s analysis showed 76 GW of coal-fired capacity
retirements by 2020 (a little less than 25% of current capacity) as a result of the regulations it
analyzed. As noted in the discussion of the individual regulations, in many cases EEI’s analysis
assumed regulations far more stringent than EPA actually proposed.
The units that would retire are the least economic and/or those currently operating with minimal
pollution controls. As noted in Figure 5, there are 110 GW of coal-fired plants (about one-third of
all coal-fired capacity) that began operating between 1940 and 1969, and two-thirds of these
plants do not have scrubbers. These are the prime candidates for retirement.
72 Utility MACT RIA, p. 8-16; 2008 data are from U.S. DOE, Energy Information Administration, Electric Power
Annual 2009, April 2011, Table 2.1, available at http://www.eia.gov/cneaf/electricity/epa/epa_sum.html.
73 Utility MACT RIA, p. 8-16.
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Figure 5. Coal Plants by Age and Emission Controls
Source: Sue Tierney, “EPA Proposed Utility Air Toxics Rule –Managing Compliance in Reliable Ways,”
Congressional Staff Briefing, May 9, 2011, p. 4.
In many cases, these older plants are not base-load plants, so their significance as a percentage of
coal-fired generation is less than one might assume from adding up their nominal capacity. In a
presentation to congressional staff, Sue Tierney, a former Assistant Secretary of Energy, presented
data showing that the pre-1970 units operating without emission controls are in use only 41% of
the time.74
EPA’s modeling confirmed that the plants likely to be retired are older, smaller, and less
frequently used: the agency concludes, for example, that under the MACT rule the average unit to
be retired will be 51 years old, with an average capacity of 109 Mw (versus 278 Mw for units that
will continue operation), and has operated only 56% of the time.75
Some of these units will be replaced by new capacity, of which some will be coal-fired, but most
replacements are likely to be natural gas combined cycle units. Even before the advent of the
“train-wreck” rules, very few coal-fired plants were being built. As shown in Figure 6, since
1990, more than 80% of new capacity has been natural gas-fired. These plants are highly
efficient; they are cost-competitive with coal; and they emit no SO2, no mercury, and no other
hazardous air pollutants. Without scrubber sludge to manage, they also do not need to meet
effluent guidelines. Natural gas-fired power plants also have an advantage with regard to
greenhouse gas (GHG) emissions: for the same amount of electric generation, they emit only half
the GHGs of coal-fired units.
74 Data obtained from Sue Tierney, “EPA Proposed Utility Air Toxics Rule –Managing Compliance in Reliable Ways,”
Congressional Staff Briefing, May 9, 2011, p. 4. Hereafter, “Tierney presentation.” Additional calculation by CRS.
75 Utility MACT RIA, p. 8-17.
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In the last two years, gas has enjoyed a price advantage, as well. As one analyst notes:
Since most of America’s utilities have the ability to employ natural gas fired power plants in
lieu of coal fired power plants when natural gas is priced advantageously, utilities have been
ramping up natural gas consumption and reducing their usage of coal. With the price of
Central Appalachian (CAPP) coal currently trading at $73 per ton, up from $60 per ton for
much of last year, a recent study by Credit Suisse (CS) indicates that natural gas prices
would need to rise to approximately $6.30 per mcf [thousand cubic feet] before coal and
natural gas trade at parity for electricity generation.76
Gas is currently trading at around $4.50 per mcf, with futures contracts through 2014 generally
trading below $6.00.77
Train Wreck?
Is there a train wreck coming for coal-fired power? The answer depends on the individual facility.
Older, smaller, less efficient units already face a train wreck. In 2010, 48 of them with a
combined capacity of 12 GW were retired, according to one source.78 Another source identifies
149 coal-fired units with a combined capacity of 19.7 GW whose retirement has been announced
or implemented in the past few years.79 In recent weeks, as utilities weigh the cost of retrofitting
and operating their older units, more retirements have been announced.80
76 Bill Powers, “Natural Gas vs. Oil and Coal,” Financial Sense, February 1, 2011, at http://www.financialsense.com/
contributors/bill-powers/natural-gas-vs-oil-and-coal.
77 Commodity Futures Price Quotes for NYMEX Natural Gas, at http://futures.tradingcharts.com/marketquotes/
NG.html.
78 Sierra Club, “2010, Outlook Dimmed for Coal: Year End State of Coal Report,” Press Release, December 22, 2010,
at http://action.sierraclub.org/site/MessageViewer?em_id=192801.0.
79 See Source Watch, “Coal Plant Retirements,” at http://www.sourcewatch.org/index.php?title=
Coal_plant_retirements#Table_1:_Age_of_U.S._Coal_Plants. Of the 149 units listed, all but 15 were built before 1973.
80 American Electric Power announced in early June that it will retire 6 GW of coal-fired capacity, about one-fourth of
the capacity of its coal-fired fleet, and will retrofit an additional gigawatt to burn natural gas. TVA, in April, announced
that it will retire 18 coal-fired units, replacing them with low emission or zero-emission electricity sources, including
renewable energy, natural gas, nuclear power, and energy efficiency.
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Figure 6. Power Plant Capacity, by Type and Year It Entered Service
Source: Sue Tierney, “EPA Proposed Utility Air Toxics Rule –Managing Compliance in Reliable Ways,” Congressional Staff Briefing, May 9, 2011, p. 10. The chart is based
on EIA Form 860 data. A similar chart produced by EIA itself can be found at http://www.eia.gov/todayinenergy/detail.cfm?id=1830.
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But this does not mean that the newer (post-1970) coal-fired facilities that have invested in
pollution controls over the years will be shuttered. Most of them already comply with many of the
proposed rules, or if not, they can do so with modest modifications to their pollution control
equipment. A train wreck for this group seems unlikely.
In between the two ends of the spectrum are facilities that are efficient enough or play a
sufficiently vital role in meeting regional demand that the economics likely would justify their
retrofit. For these facilities, the key questions are whether there will be sufficient time to act, and
whether the reliability of the electric grid will be affected as they are taken off-line for
modification.
Timing and Reliability Issues
It is difficult to generalize about the timing and system reliability issues. Several utilities state that
they will have difficulty meeting the deadlines. In congressional testimony, April 15, 2011,
Thomas A. Fanning, the Chairman, President, and Chief Executive Officer of The Southern
Company, which provides electricity to 4.4 million customers in the Southeastern United States,
stated:
The reliability of the nation’s electric generating system is at risk because of the number of
new rules and regulations applicable to power plants. The stringency of these regulations, the
lack of flexibility likely to be provided within these regulations, and, above all, the
compliance schedules that will be required put reliability at risk. Accelerated plant
retirements and shutdowns triggered by the Utility MACT rule will cause reserve capacity to
plummet, increasing the likelihood and severity of service disruptions.81
In announcing the retirement of one-fourth of its coal-fired generation, June 9, 2011, American
Electric Power’s Chairman and CEO, Michael G. Morris, in a press release, stated:
We support regulations that achieve long-term environmental benefits while protecting
customers, the economy and the reliability of the electric grid, but the cumulative impacts of
the EPA’s current regulatory path have been vastly underestimated, particularly in Midwest
states dependent on coal to fuel their economies. We have worked for months to develop a
compliance plan that will mitigate the impact of these rules for our customers and preserve
jobs, but because of the unrealistic compliance timelines in the EPA proposals, we will have
to prematurely shut down nearly 25 percent of our current coal-fueled generating capacity,
cut hundreds of good power plant jobs, and invest billions of dollars in capital to retire,
retrofit and replace coal-fueled power plants.82
Others, however, cite historical experience and available indicators to argue that timing and
system reliability will not be a problem. Michael Bradley, representing the Clean Energy Group, a
coalition of electric power companies with over 200 GW of electric generating capacity,
including 105 GW of fossil-fuel fired capacity, testified that:
81 Testimony of Thomas A. Fanning, “Recent EPA Rulemakings Relating to Boilers, Cement Manufacturing Plants,
and Utilities,” Hearing, House Energy and Commerce Committee, Subcommittee on Energy and Power, April 15,
2011, p. 13.
82 “AEP Shares Plan For Compliance With Proposed EPA Regulations,” press release, June 9, 2011, at
http://www.aep.com/environmental/news/?id=1697.
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The Utility Toxics Rule provides the business certainty the electric sector needs to move
forward with capital investment decisions;
• While not perfect, the proposal is reasonable and consistent with the requirements of the
Clean Air Act;
• The electric sector is well positioned to comply; and
• The Clean Air Act provides sufficient time to comply as well as the authority to
accommodate special circumstances where additional time is necessary.83
The Institute of Clean Air Companies, which represents the pollution control industry, states that
utilities installed 60 GW of scrubbers and 20 GW of selective catalytic reduction (SCR) between
2008 and 2010. (See Figure 7.) In the early 2000s, in response to the NOx SIP Call, the industry
installed 96 GW of SCR in a five-year period while successfully maintaining system reliability.
This was a “much more capital and manpower intensive effort” than the Utility MACT will be,
according to David Foerter, the group’s Executive Director.84
83 Testimony of Michael Bradley, “Recent EPA Rulemakings Relating to Boilers, Cement Manufacturing Plants, and
Utilities,” Hearing, House Energy and Commerce Committee, Subcommittee on Energy and Power, April 15, 2011, p.
1
84 David C. Foerter, Executive Director, Institute of Clean Air Companies, “EPA’s Proposed Utility Air Toxics Rule,”
Presentation to Congressional Staff, May 9, 2011, p. 6.
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Figure 7. Cumulative SCR and Scrubber Installations, by Year
Source: David C. Foerter, Executive Director, Institute of Clean Air Companies, “EPA’s Proposed Utility Air
Toxics Rule,” Presentation to Congressional Staff, May 9, 2011.
Notes: SCR = Selective Catalytic Reduction technology to reduce NOx emissions. FGD = Flue Gas
Desulfurization, commonly referred to as a scrubber.
If necessary, as shown in Figure 6, the industry is capable of adding new generating capacity in a
short time. From 2000-2003, electric companies added over 200 GW of new capacity, far more
than any of the analyses suggest will be needed in the 2011-2017 timeframe.
A December 2010 analysis by FBR Capital Markets concluded that even the incremental
retirement of 45 GW by 2014 (which appears to be more than EPA’s rules will effect) would have
little effect on electricity reserve margins:85 “Summer reserve margins are currently 26% across
the U.S. and are likely to decline only to 24% by 2014 in a draconian scenario in which 45 GW of
generation is retired.”86 FBR offers the caveat that electricity reserve margins are a regional, not a
national matter; but its analysis of eight NERC regions found reserve margins of 16.8% to 37.8%
under its “draconian” 2014 scenario.87
Other studies suggest that proper planning can prevent a train wreck, even in worst-case
scenarios. Much depends on whether individual utilities have already begun planning for the
85 Only three of EEI’s nine scenarios resulted in that many retirements, and all three assumed regulations far more
stringent than EPA has proposed.
86 FBR Capital Markets, Coal Retirements in Perspective – Quantifying the EPA Rules, December 13, 2010, p. 18.
87 Ibid., p. 19. NERC considers 15% to be the necessary planning reserve margin. See NERC, “Reliability Indicators:
Planning Reserve Margin,” at http://www.nerc.com/page.php?cid=4%7C331%7C373.
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implementation of the rules, including lining up engineers to design modifications, and
conducting preliminary discussions with permitting authorities and grid operators regarding the
required steps. This point is stressed by analysts on all sides of the issue. For example, Sue
Tierney, after reviewing several studies, states:
The studies’ results do not mean that there will be resources gaps; they make it clear that
action needs to be taken soon
• These studies serve as a “call to action” ...
• Several are explicit in saying that they have identified resource gaps in order to signal
that action is needed.88
NERC’s study is one of those to which Tierney refers. NERC concluded that, “Regulators, system
operators, and industry participants should employ available tools to ensure Planning Reserve
Margins while forthcoming EPA regulations are implemented.”89 Perhaps more importantly, it
stated: “NERC should further assess the implications of the EPA regulations as greater certainty
or finalization emerges around industry obligations, technologies, timelines, and targets.”90 Given
that the NERC study assumed far more stringent requirements than EPA proposed for both the
Cooling Water Intake and Utility MACT rules, a NERC reassessment could be informative.
Price and Availability of Natural Gas
The EEI and NERC reports said that EPA rules would make coal-fired power more expensive so
that utilities would retire additional coal-burning units (i.e., beyond those they already plan to
retire) and replace them with alternative generation that emits fewer pollutants, leading to a drop
in coal-fired generation and equal or greater increase for natural gas. From one perspective, the
train wreck debate appears to be a coal-vs.-natural gas argument. The debate is not entirely that
simple, however, because gas-burning power plants will be subject to some of the new rules, too.
Some rules may affect coal-fired power plants disproportionately compared with other plants,
such as the cooling water intake proposal, while others may affect power plants of all types.
The primary impacts of many of the rules discussed here will be on coal-fired plants more than 40
years old that have not, until now, installed state-of-the-art pollution controls. Many of these
plants are inefficient and are being replaced by more efficient combined cycle natural gas plants.
In EEI’s analysis (and perhaps in the others that use the Integrated Planning Model91), a key
variable is the assumed price of natural gas. The price of gas in EEI’s reference case rises
somewhat compared to today’s price of about $4.50 per MMBtu, but it remains below $6.00 per
MMBtu every year from now until 2035.92 This is inexpensive gas, by the standards of recent
88 Tierney presentation, p. 9.
89 NERC report, p. VII.
90 Ibid.
91 The Integrated Planning Model, developed by ICF Inc., is used by EPA, EEI, and others to model the impacts of
environmental regulations on the electric power industry.
92 Natural gas price projections are shown on page 58 of the EEI report.
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history, as much as one-third below the price in each of the years 2004-2008. The low prices
apparently reflect recent reports that future supplies of gas are projected to be abundant.93
In the other scenarios modeled by EEI (i.e., the scenarios showing the impact of EPA’s expected
regulations), the gas price ranged from about $5.50 to $7.50 per MMBtu over the 25 years
through 2035. The higher prices presumably are the result of increased demand as some EGUs
switch from coal to gas as a compliance strategy. These prices would also be below 2004-2008
prices in most cases.94
What the model showed in most of EEI’s scenarios, then, is that, because the price of gas was
projected to remain low, coal-powered units would be retired or converted to natural gas as EPA
imposes the regulatory requirements under consideration.
Two of EEI’s scenarios, however, used different assumptions regarding gas prices: they
artificially assumed that gas costs either $1.50 or $3.00 per MMBtu more than the model’s supply
curve showed. With more expensive gas, fewer coal-powered facilities would be retired: in the
extreme ($3.00 more) case, 17 GW were retired, compared to 57-71 GW in the same case with
lower-priced gas.95
What these scenarios tell us is that utilities will look at the impending regulations and decide what
to do largely based on their assumptions regarding the cost of the alternatives—natural gas
(where it’s available) being the most often discussed, but others include conservation, wind, and
other renewable resources. If they expect the price of gas to remain low or the cost of other
alternatives to be competitive, their primary method of compliance likely will be to retire old coal
plants and switch to gas or the alternatives. If they expect the price of gas or other alternatives to
be high, they’ll invest the money in retrofitting the coal plants to reduce their emissions.
As the NERC report stated:
Unit retirement is assumed when the generic required cost of compliance with the proposed
environmental regulation exceeds the cost of replacement power.... For the purpose of this
assessment, replacement power costs were based on new natural gas generation capacity. If
the unit’s retrofit costs are less than the cost of replacement power, then the unit is marked to
be upgraded and retrofitted to meet the requirements of the potential environmental
regulation., i.e., it is not considered “economically vulnerable” for retirement.96
As utilities attempt to forecast the price of natural gas, their conclusions will be based in large
part on assumptions as to whether gas will be available in sufficient quantities to meet the
increased demands of electric power generation. Natural gas faces its own controversies, as
domestic production increasingly relies on “unconventional” sources such as shale, from which
gas is obtained by hydraulic fracturing. (For additional information on this practice, see CRS
Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Issues, by Mary Tiemann and
Adam Vann.) Nevertheless, a 2009 NERC report stated:
93 The comparison is to EIA data shown in Figure 4 above.
94 All the scenarios, including the Reference case, assume a brief price peak in 2015, with prices declining for the next
15-20 years thereafter.
95 EEI report, Table 3.1.
96 NERC report, p. 6.
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Concerns regarding the availability and deliverability of natural gas have diminished during
2009 as North American production has begun to trend upward due to a shift toward
unconventional gas production from shale, tight sands, and coal-bed methane reservoirs. In
its latest biennial assessment, the Potential Gas Committee increased U.S. natural gas
resources by nearly 45 percent to 1,836 TCF [trillion cubic feet], largely because of increases
in unconventional gas across many geographic areas. Pipeline capacity has similarly
increased, by 15 BCFD [billion cubic feet per day] in 2007 and 44 BCFD in 2008, with an
increase of 35 BCFD expected in 2009. Storage capacity has also increased substantially.97
In short, the “train wreck” facing the coal-fired electric generating industry, to the extent that it
exists, is being caused by cheap, abundant natural gas as much as by EPA regulations. As John
Rowe, Chairman and CEO of Exelon Corporation, recently stated: “These regulations will not kill
coal.... In fact, modeling done on the impacts of these rules shows that up to 50% of retirements
are due to the current economics of the plant due to natural gas and coal prices.”98
Legislation
Congress has shown a great deal of interest in the forthcoming EPA power plant rules and related
Administration activities, with both proponents and opponents of EPA action circulating “Dear
Colleague” letters and hearings held or scheduled by several House and Senate committees.
Legislation to prevent or delay EPA action has passed the House, and more legislation is
considered likely. Some recent proposals are broad in nature, targeting EPA generally or a lengthy
list of specifics, while others focus more narrowly on individual rules or actions.
One such broad bill is H.R. 2401, the Transparency in Regulatory Analysis of Impacts on the
Nation (TRAIN) Act of 2011. It would establish a panel of representatives of federal agencies to
report to Congress by August 2012 on the cumulative economic impact of a number of listed EPA
rules, guidelines, and actions concerning clean air and waste management. A House
subcommittee approved this bill on July 8. Similar legislation introduced in the Senate, S. 609,
the Comprehensive Assessment of Regulations on the Economy Act of 2011, would direct the
Department of Commerce to form a panel to review the cumulative energy and economic impacts
of specific rules proposed or finalized by EPA or expected soon. Both bills would cover rules
discussed in this report. Impetus for this type of legislation is the widely expressed concern that
when EPA analyzes impacts of individual regulations, it does not consider costs imposed by
multiple rules taking effect more or less simultaneously. Another bill, H.R. 1872 (the
Employment Protection Act of 2011) would require EPA to consider the impact on employment
levels and economic activity prior to issuing a regulation, policy statement, guidance, or other
requirement, implementing any new or substantially altered program, or issuing or denying any
clean water or other permit.
Even before the start of the 112th Congress, House Republican leaders signaled that House
committees would scrutinize EPA’s rulemaking decisions, including by withholding funding for
97 NERC, 2009 Long-Term Reliability Assessment: 2009-2018, October 2009, p. 4, available at http://www.nerc.com/
files/2009_LTRA.pdf.
98 John W. Rowe, “Energy Policy: Above All, Do No Harm,” Remarks as Prepared, American Enterprise Institute,
March 8, 2011, p. 7. Exelon is one of the largest electric and gas utility companies in the United States, serving 13
million people in Illinois and Pennsylvania.
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prospective rules and de-funding previously promulgated rules.99 This was demonstrated when
the House passed H.R. 1, a full-year continuing appropriations resolution for FY2011, in
February. As passed by the House, the bill contained more than 20 provisions restricting or
prohibiting the use of appropriated funds to implement various regulatory activities under the
EPA’s jurisdiction—including many discussed in this report.100 (On March 9, the Senate failed to
approve the House-passed bill and subsequently also did not agree to a substitute text (S.Amdt.
49) that contained different funding levels and generally omitted the EPA regulatory provisions in
the House-passed bill.) Final legislation that provided full-year appropriations for EPA (P.L. 112-
10) did not include the restrictive provisions in the House-passed bill.
Several bills concerned with specific rules discussed in this report also have been introduced.
The House approved legislation to restrict EPA authority and to repeal a dozen EPA regulatory
actions dealing with greenhouse gases (H.R. 910) on April 7. In the Senate, an amendment
identical to H.R. 910 (S.Amdt. 183) failed on a vote of 50-50.
As discussed elsewhere in this report (Appendix A), EPA’s January 2011 veto of a CWA permit
for a West Virginia surface coal mining project has been very controversial, including in
Congress, and raised questions about adequate coal supplies for power plants. In the 112th
Congress, legislation has been introduced to remove EPA’s veto authority from the CWA (H.R.
517), and a number of other bills to modify or clarify this portion of the law also have been
introduced (H.R. 457/S. 272, H.R. 468/S. 960, and H.R. 2018). A subcommittee of the House
Transportation and Infrastructure Committee held hearings on these issues in May, and on June
22, the Committee approved H.R. 2018. Several provisions in this bill would limit EPA’s
authority to provide oversight of states’ implementation of the CWA; it would allow the agency to
veto a Section 404 permit only with concurrence of the state where the subject discharge
originates.
Also in the 112th Congress, two bills have been proposed that would prohibit CCW from being
regulated under Subtitle C of RCRA—H.R. 1391 (the Recycling Coal Combustion Residuals
Accessibility Act of 2011, or the RCCRA Act) and H.R. 1405. On June 21, 2011, a House Energy
and Commerce Committee subcommittee approved H.R. 1391.101
Beyond Congress, some state legislatures also have taken interest in EPA’s regulatory activity. In
February, the American Legislative Exchange Council issued a report identifying a number of
strategies that states could use to oppose EPA’s actions: adopting resolutions, conducting
enhanced legislative review of state regulations, and enacting bills to assert state sovereignty.102
Resolutions critical of EPA’s actions have been introduced in several state legislatures this year.
99 Honorable Jerry Lewis, letter to EPA Administrator Lisa P. Jackson, November 29. 2010, on file with authors.
100 For information, see CRS Report R41698, H.R. 1 Full-Year FY2011 Continuing Resolution: Overview of
Environmental Protection Agency (EPA) Provisions, by Robert Esworthy.
101 For more information, go to the House Energy and Commerce Committee hearing web page, “Fossil Fuel
Combustion Waste Regulation,” http://republicans.energycommerce.house.gov/hearings/hearingdetail.aspx?NewsID=
8474.
102 American Legislative Exchange Council, “EPA’s Regulatory Train Wreck, Strategies for State Legislators,”
February 2011, http://www.alec.org/AM/Template.cfm?Section=EPATrainWreck&Template=/CM/
ContentDisplay.cfm&ContentID=15364. According to its website, the American Legislative Exchange Council is an
organization of conservative state lawmakers.
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Concluding Thoughts About the “Train Wreck”
Analyses
EEI, NERC, and other recent reports describe scenarios and potential impacts of EPA rules,
including projected need for additional power plant capacity or potential reliability problems, that
depend on a number of assumptions such as the stringency of the rules or expected tight
compliance deadlines, many of which differ greatly from what EPA has actually proposed or
promulgated. Also, because most of the reports try to look collectively at EPA rules, to the extent
a proposed or promulgated rule differs from some of these assumptions, it can be difficult to
separate out one rule’s projected impacts from the report’s overall conclusions about multiple
rules.
Some of the reports project impacts on power plants and electricity supply nationwide, some
project impacts on a regional basis. In reality, evaluating regulatory impacts, compliance costs,
and possible retirement decisions depends on facility-specific considerations—micro, not macro.
Utilities and states will be affected differently. Rules when actually proposed or issued may well
differ enough that investment or retirement decisions look entirely different. Technology options
available to a unit or plant depend on the specific rule, and compliance costs may be less than
projected. Even some units with high assumed control costs, or others that look to be marginal
economically, may install controls and continue to operate. Many utilities have already installed
technology needed to comply with new rules; for them, costs will be minimal: EPA said that, with
regard to the most expensive proposed rule, the Utility MACT, more than half of the coal-fired
units fall in this category. The EEI and NERC reports did not account for the fact that plants’
compliance costs may be less because of investments already made in pollution control
equipment.
Frequently overlooked in analyses of EPA regulations are the benefits to public health and the
environment that will occur, benefits that for the most part are difficult to monetize. EPA does
estimate benefits of individual rules, while acknowledging that it is challenging to quantify
benefits due to data limitations and uncertainties in approaches used to value benefits. The costs
of the rules may be large, but, in most cases, the benefits are larger, especially estimated public
health benefits. Neither the EEI nor the NERC report addresses benefits.
Although much of the current critical attention to EPA’s regulations has focused on rules affecting
power plants, especially coal-fired power plants, the rules discussed here are only part of EPA’s
statutory mandate and regulatory agenda, and there are controversies about many of these other
rules, as well, such as a MACT rule to control toxic air pollutants from commercial and industrial
boilers and several Clean Water Act rules concerning water quality standards and permits.103
Further, concerns about impacts of EPA rules have been raised by a range of individual
companies and trade associations representing regulated entities beyond the electric utility sector,
such as agriculture, chemical manufacturers, water utilities, and others.104
Several other conclusions bear repeating:
103 For additional information, see CRS Report R41561, EPA Regulations: Too Much, Too Little, or On Track?, by
James E. McCarthy and Claudia Copeland.
104 Regarding agriculture’s interest in EPA rules, see CRS Report R41622, Environmental Regulation and Agriculture,
coordinated by Megan Stubbs.
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• The studies sponsored by industry groups (EEI and NERC) were written before
EPA proposed most of the rules whose impacts they analyze, and they assumed
that the rules would impose more stringent requirements than EPA proposed in
many cases.
• Of the regulations so far proposed, the Utility MACT, which will set standards
for power plant emissions of mercury and other hazardous air pollutants, appears
to be the most expensive. EPA’s analysis concluded that it will impose annual
costs of $10 billion to $11 billion annually
• Other rules that industry expected to impose major costs now appear less likely
to do so. The Cooling Water Intake rule, for example, proposes a less costly,
more flexible regulatory option than EEI and NERC anticipated. Further, NERC
believes that few coal-fired EGUs will be affected by this rule, which will have
greater impact on older, oil-fired units. The Coal Combustion Waste Rule has
been delayed, with no deadline for promulgation.
• For coal-fired plants, the primary impacts will be on units more than 40 years old
that have not, until now, installed state-of-the art pollution controls. Many of
these plants are inefficient, and are being replaced by more efficient combined
cycle natural gas plants.
• Lower prices for natural gas and recent increases in its projected availability may
reduce the impact of the proposed rules on electric utilities and consumers,
although they may lead to more retirements of coal-fired units.
• There is a substantial amount of excess generation capacity at present, due in part
to the recession and also due to the large number of natural gas combined cycle
plants constructed in the last decade, muting reliability concerns.
Implementation
Finally, several other points regarding the timing of implementation of EPA rules are worth
underlining:
• Many proposed and “pre-proposal” rules linger for years without being
promulgated; thus, many of the EPA actions described here may not be finalized
or take effect for some time. They may also be substantially altered before they
become final (i.e., before sources of pollution actually are affected by control
requirements), as a result of the proposal and public comment process, and/or
judicial review.
• Although EPA generally announces a schedule under which it plans to propose
and promulgate rules, experience suggests that proposal and promulgation may
take longer than estimated, particularly in cases that do not have court-ordered
deadlines.
• Even court-ordered dates for proposal or promulgation may change. It is not
uncommon for EPA to request extensions of time, often due to the need to
analyze extensive comments.
• Promulgation of standards is not the end of the road. Virtually all major EPA
regulatory actions are subjected to court challenge, frequently delaying
implementation for years. As noted earlier, many of the regulatory actions
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described here are the result of courts remanding and/or vacating rules
promulgated by previous administrations.
• In many cases, EPA rules must be adopted by states to which the relevant
program has been delegated. Moreover, many states require that the legislature
review new regulations before the new rules would take effect.
• For many rules, actions by states may be more significant than what EPA does,
because the CAA, CWA, and RCRA allow states to adopt more stringent
requirements. For example, EPA’s cooling water intake proposal does not
mandate installation of costly closed-cycle cooling systems at all existing power
plants. At the same time, an EPA rule does not preclude states from imposing
such a mandate, as has occurred and is occurring in several locations (e.g., New
York, California, Delaware, and New Jersey).
• Standards for stationary sources under the air, water, and solid waste laws are
generally implemented through permits, which would be individually issued by
state permitting authorities after the standards take effect. When finalized, a
permit would generally include a compliance schedule, typically giving the
permittee several years for installation of required control equipment. Existing
sources generally will have several years following promulgation and effective
dates of standards, therefore, to comply with any standards.
In short, the road to EPA regulation is rarely a straight path. There are numerous possible causes
of delay. It would be unusual if the regulatory actions described here were all implemented on the
anticipated schedule, and even if they were, existing facilities would often have several years
before being required to comply. Unable to account for such factors, which will vary from case to
case, timelines that show dates for proposal and promulgation of EPA standards effectively
underestimate the complexities of the regulatory process and overstate the near-term impact of
many of the regulatory actions.
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Appendix A. Regulatory Actions Affecting
Mountaintop Removal Mining
EPA and other federal agencies (the Office of Surface Mining and Reclamation, in the
Department of the Interior; and the U.S. Army Corps of Engineers) are developing a series of
actions and regulatory proposals to reduce the harmful environmental and health impacts of
surface coal mining, including a practice called mountaintop removal mining, in Appalachia.
These actions would not affect electric power plants directly, and thus were not covered by EEI
nor NERC in their studies. Thus, CRS did not include these regulations in the discussion of the
“train wreck” issues in the body of this report. Nevertheless, numerous critics of EPA have
included EPA, Corps of Engineers, and Interior Department actions in what they term a “War on
Coal.” The actions, announced in a June 2009 interagency Memorandum of Understanding, are
intended to tighten regulation and strengthen environmental reviews of permit requirements under
the CWA and the Surface Mining Control and Reclamation Act (SMCRA).
Also in June 2009, EPA and the Army Corps signed a specific agreement detailing criteria that
will be used to coordinate and expedite review of pending CWA permit applications for surface
coal mining operations in Appalachia. The agencies are conducting detailed reviews of 79 permit
applications to evaluate the permits in order to limit environmental impacts of the proposed
activities. This review is proceeding slowly. In June 2010, the Army Corps suspended the use of a
particular CWA general permit for surface coal mining activities in Appalachia and proposed a
rule to prohibit its use entirely; a finalized rule, expected in 2012, would apply more stringent
CWA rules to these coal mining operations.105
In April 2010 EPA released an interim guidance memorandum that seeks to clarify the agency’s
tightened requirements for surface coal mining in Appalachia. The guidance will be applied as a
framework for EPA’s approval of all pending and future reviews of permits to dispose of coal
mining waste and other types of Appalachian surface coal mining discharges that are authorized
by the CWA. Among other items, the interim guidance sets strict numeric limits on conductivity
levels in waters affected by mining activities. Conductivity is a measure of the level of salinity in
water associated with discharges of selenium and total dissolved solids that are associated with
coal mining wastes. Based on recent scientific literature, EPA has concluded that conductivity
above certain levels in Appalachian streams presents a reasonable potential to harm stream biota.
Conductivity, and its use in assessing coal mining impacts on water quality, has become a focus
of debate. According to EPA, the 2010 interim guidance is not intended to bring a complete halt
to surface coal mining in Appalachia, but to force the industry to adopt practices that will
minimize harmful impacts. Environmental groups support the guidance document and EPA’s use
of conductivity to assess water quality impacts, but industry groups have been highly critical,
asserting that the science linking conductivity to water quality impairment is uncertain and that
acceptable numeric levels are arbitrary. Lawsuits challenging the guidance have been brought by
the States of Kentucky and West Virginia, as well as individual coal companies and trade
associations. In January 2011, a federal judge who is hearing one of the challenges denied
industry’s request to block implementation of the guidance, but also denied the government’s
105 U.S. Department of the Army, Corps of Engineers, “Suspension of Nationwide Permit 21,” 75 Federal Register
34711-34714, June 18, 2010.
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request to dismiss the case. EPA is working on revised guidance that incorporates public
comments, scientific reviews, and experience of implementing the 2010 guidance. Final guidance
had been expected by April 1, but its release has been delayed by interagency review.
In addition, in November 2009, the Department of the Interior’s Office of Surface Mining (OSM)
issued an Advance Notice of Proposed Rulemaking (ANPR) describing options to revise a
SMCRA rule, called the stream buffer zone rule, which was promulgated in December 2008.106
The Obama Administration identified the 2008 rule, which exempts so-called valley fills and
other mining waste disposal activities from requirements to protect a 100-foot buffer zone around
streams, for revision as part of the series of actions concerning surface coal mining in Appalachia.
OSM identified a broad set of regulatory options that it is considering for revisions to the 2008
rule, ranging from formally reinstating the previous rule with small conforming changes, to
requiring stricter buffer zone requirements for mountaintop mining operations on steep slopes.
OSM officials have been working on developing a new rule, with the goal of releasing a proposal
by early 2011, but none has yet emerged. In addition, EPA and OSM have pledged to strengthen
oversight of state CWA and SMCRA permitting, regulation, and enforcement.
Finally, EPA has used CWA authority to veto a permit for a surface coal mining operation in West
Virginia, after determining that the activity will have an unacceptable adverse effect on wildlife
and fishery resources. EPA’s veto has been very controversial, in part because it involves the rare
action of cancelling a permit previously issued by the Army Corps. Coal industry groups and
those representing manufacturing and other sectors have been highly critical, many saying that to
revoke an existing permit creates huge uncertainty about whether water quality permits would be
rescinded in the future, producing a ripple effect beyond the coal industry. EPA argues that the
veto, while highly unusual, is justified because the project involves unacceptable environmental
damages.
Viewed broadly, the Administration’s combined actions on surface coal mining displease both
industry and environmental advocates. The additional scrutiny of permits, more stringent
requirements, and EPA’s veto of a previously authorized project have angered the coal industry.
At the same time, while environmental groups support the veto and related actions, many favor
even tougher requirements.107
Critics assert that collectively the Administration’s activities and initiatives concerning surface
coal mining in Appalachia are needlessly delaying important projects, thus costing jobs and
hurting the nation’s energy security. While these actions do not directly affect power plants, they
have the potential of doing so indirectly, if they effectively limit or restrict coal supplies. None of
these actions are discussed in either the EEI or NERC analysis.
106 U.S. Department of the Interior, Office of Surface Mining Reclamation and Enforcement, “Stream Buffer Zone and
Related Rules; Advance notice of proposed rulemaking; notice of intent to prepare a supplemental environmental
impact statement (SEIS),” 74 Federal Register 62664-62668, November 30, 2009.
107 For additional information, see CRS Report RS21421, Mountaintop Mining: Background on Current Controversies,
by Claudia Copeland.
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Appendix B. Bibliography of Analytic Reports
Growing interest in the impact of EPA regulation on fossil-fuel power plants, especially coal-fired
plants, has generated a large number of analytic reports by policy and advocacy groups using
varying assumptions and analytic approaches that reach varying conclusions. Many of these
reports were issued prior to proposal or promulgation of a rule.
North American Electric Reliability Corporation, 2010 Special Reliability Scenario Assessment:
Resource Adequacy Impacts of Potential U.S. Environmental Regulations, October 2010,
http://www/nerc.com/files/EPA_Scenario_Final_v2.pdf.
ICF International, Potential Impacts of Environmental Regulation on the U.S. Generation Fleet,
Final Report, prepared for Edison Electric Institute, January 2011, http://www.pacificorp.com/
content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2011IRP/
EEIModelingReportFinal-28January2011.pdf.
Metin Celebi, Frank Graves, Gunjan Bethla, et al., The Brattle Group, Potential Coal Plant
Retirements Under Emerging Environmental Regulations, December 8, 2010,
http://www.brattle.com/_documents/uploadlibrary/upload898.pdf.
National Economic Research Associations, Proposed CATR + MACT, prepared for American
Coalition for Clean Coal Electricity, May 2011, http://www.americaspower.org/
NERA_CATR_MACT_29.pdf.
Dan Eggers, Kevin Cole, Yang Y. Song, and LinLin Sun, Credit Suisse, Impact of EPA Rules on
Power Markets, September 2010, http://epw.senate.gov/public/index.cfm?FuseAction=
Files.View&FileStore_id=b42de70d-b814-4410-831d-34b180846a19. Also see Dan Eggers,
Credit Suisse, Implications of EPA Policy, April 2011, http://www.fbcinc.com/EIA/presentations/
Eggers_04.26.11.pdf.
Wood Mackenzie, “Long-term Viability of Many U.S. Coal Plants at Risk,” September 10, 2010,
http://www.woodmacresearch.com/cgi-bin/corp/portal/corp/corpPressDetail.jsp?oid=2178098.
FBR Capital Markets, Coal Retirements in Perspective—Quantifying the Upcoming EPA Rules,
December 13, 2010, http://jlcny.org/site/attachments/article/388/coal1.pdf.
Hugh Wynne, Francois D. Broquin, and Saurabh Singh, Bernstein Research, Black Days Ahead
for Coal: Implications of EPA Air Emissions Regulations for Energy & Power Markets, July 21,
2010, http://grist.s3.amazonaws.com/eparegs/Bernstein%20-
%20black%20days%20ahead%20for%20coal%20-%2007%2021%2010.pdf.
There also have been a number of recent analytic rebuttals to these reports:
Michael J. Bradley, Susan F. Tierney, Christopher E. Van Atten, et al., Ensuring a Clean, Modern
Electric Generating Fleet while Maintaining Electric System Reliability, August 2010,
http://www.mjbradley.com/documents/MJBAandAnalysisGroupReliabilityReportAugust2010.pdf
and Summer 2011 Update, June 2011, http://www.mjbradley.com/documents/MJBA Reliability
Report Update June 7 2011.pdf.
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University of Massachusetts Political Economy Research Institute, James Heintz, Heidi Garrett-
Peltier, Ben Zipperrer, New Jobs – Cleaner Air, Employment Effects Under Planned Changes to
the EPA’s Air Pollution Rules, February 2011, http://www.ceres.org/resources/reports/new-jobs-
cleaner-air.
Susan F. Tierney and Charles Cicchetti, The Results in Context: A Peer Review of EEI’s
“Potential Impacts of Environmental Regulation on the U.S. Generation Fleet,” Summary
Report, May 2011, http://www.supportcleanair.com/resources/studies/file/Tierney-and-Cicchetti-
EEI-Peer-Review-Summary-May-2011.pdf.
World Resources Institute, Response to EEI’s Timeline of Environmental Regulations, November
2010, http://pdf.wri.org/factsheets/factsheet_response_to_eei_timeline.pdf.
Josh Bivens, Economic Policy Institute, A Lifesaver, Not a Job Killer, EPA’s proposed “air toxics
rule” is no threat to job growth, EPI Briefing Paper, June 14, 2011, http://w3.epi-data.org/
temp2011/BriefingPaper312 (2).pdf.
Jennifer Macedonia, Joe Kruger, Lourdes Long, and Meghan McGuinness, Bipartisan Policy
Center, Environmental Regulation and Electric System Reliability, June 13, 2011,
http://www.bipartisanpolicy.org/sites/default/files/BPC%20Electric%20System%20Reliability.pdf
Daniel J. Weiss, Valeri Vasquez, and Stewart Boss, “Mercury Falling, Many Power Plants Already
Have Equipment to Slash Mercury, Toxic Contamination,” June 21, 2011,
http://www.americanprogress.org/issues/2011/06/mercury_falling.html.
Author Contact Information
James E. McCarthy
Claudia Copeland
Specialist in Environmental Policy
Specialist in Resources and Environmental Policy
jmccarthy@crs.loc.gov, 7-7225
ccopeland@crs.loc.gov, 7-7227
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