Clean Air: New Source Review Policies and Proposals
Congressional research reportFeb 25, 2003
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Prepared for Members and Committees of Congress
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On November 22, 2002, the Environmental Protection Agency (EPA) finalized revisions to
several aspects of the Clean Air Act’s (CAA) New Source Review (NSR) requirements. At the
same time, EPA proposed rules to clarify the definition of “routine maintenance” under NSR. The
proposed and final rules have generated controversy. The Bush Administration has argued that the
new rules will reduce pollution and increase energy efficiency. In contrast, the State and
Territorial Air Pollution Program Administrators (STAPPA) and Association of Local Air
Pollution Control Officials (ALAPCO) argue that the revisions will “undermine efforts to achieve
and sustain clean, healthful air.” Nine Northeastern states filed suit against the final rules issued
by EPA on December 31, 2002 in the U.S. Court of Appeals for the D.C. Circuit, and
Pennsylvania filed a separate lawsuit on January 27, 2003; on January 30, eight states, mostly
from the Midwest and the South, filed a petition in support of the final rule.
Into the 1970s, coal-fired electric generating facilities were built with a projected useful life of
30-40 years. Over time a powerplant’s efficiency declined, until it would be replaced or put on
standby for use during emergencies. As the CAA evolved, it established stringent pollution
control requirements on newly constructed facilities, but not on older ones unless they underwent
a modification that increases emissions (or emitted pollutants that exceeded health-based air
quality standards). By the early 1980s, however, it became technically feasible to refurbish a
powerplant to preserve its efficiency, so plants could continue in regular operation.
Thus, “life extension” became more advantageous than building new facilities that would incur
capital and operating costs of CAA-required pollution controls. The crucial issue was whether life
extension triggered the “modification” provision of the CAA: In promulgating regulations in
1975, EPA had exempted certain activities from the definition of modification, including
“maintenance, repair, and replacement which the Administrator determines to be routine for a
source category....” In response, utilities began to spread out their plant rehabilitation efforts in an
attempt to fit them into their routine maintenance schedules.
If one believes that EPA’s routine maintenance exemption was limited and did not permit the
rehabilitation of existing facilities, then one would conclude that many of the industry’s
rehabilitation activities of the last 20 years go beyond what NSR allows. From this perspective,
current law requires existing sources undergoing refurbishment to meet stringent NSR standards.
This is the perspective underlying the Clinton Administration’s enforcement initiative, an
initiative for which the Bush Administration has stated its support. In contrast, if one believes that
an exemption for routine maintenance is appropriate and should be defined in terms of current
industry practices, then one would argue that NSR discourages plant owners from upgrading
facilities operating with worn-out, inefficient components, thereby foregoing opportunities to
conserve energy and to reduce emissions by installing newer, more efficient components. This
perspective that NSR discourages energy efficiency is reflected in the Bush Administration’s
proposed revisions to routine maintenance published in December 2002. This report will not be
updated.
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Background ..................................................................................................................................... 1
What Has Happened?................................................................................................................ 1
What Is the Controversy?.......................................................................................................... 3
What Is a Modification?............................................................................................................ 6
How Does Routine Maintenance Fit? ....................................................................................... 8
Emissions Impact .................................................................................................................... 12
Proposed Alternatives.................................................................................................................... 15
Reform NSR to Permit Current Utility Rehabilitation Practices: The Administration
Proposal................................................................................................................................ 15
Replace NSR with Multi-pollutant Legislation....................................................................... 18
Reform NSR to Reduce Emissions From Existing Facilities.................................................. 19
Conclusion: NSR – Ambiguous, Meaningless or Moot?............................................................... 20
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Figure 1. Trend of Power Plant Heat Rate with Age ..................................................................... 10
Figure 2. Impact of Power Plant Aging on Reliability of Fossil-Fired Units 50 to 200 Mw......... 10
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Table 1. NSR Final Rule: Summary of Major Provisions ............................................................... 3
Table 2. U.S. Coal-Fired Electric Generating Capacity Additions, 1989-2000 (net summer
capacity) ....................................................................................................................................... 4
Table 3. Coal Consumption and Coal-fired Generation, 1989-2000 ............................................... 5
Table 4. Coal-fired Generation Capacity Factors and Heat Rates: 1989-2001 (based on
net summer capacity) ................................................................................................................... 6
Table 5. EIA’s 2010 NSR Reference Cases: Emissions from Coal-fired Electric
Generating Facilities .................................................................................................................. 12
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Author Contact Information .......................................................................................................... 21
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On November 22, 2002, the Environmental Protection Agency (EPA) finalized revisions to
several aspects of the Clean Air Act’s (CAA) New Source Review (NSR) requirements. These
revisions became effective with their publication in the Federal Register on December 31, 2002.
At the same time, EPA proposed a rule to clarify the definition of “routine maintenance” under
NSR. The proposed and final rules have generated controversy. The Bush Administration has
argued that the new rules will reduce pollution and increase energy efficiency.1 In contrast, the
State and Territorial Air Pollution Program Administrators (STAPPA) and Association of Local
Air Pollution Control Officials (ALAPCO) argue that the revisions will “undermine efforts to
achieve and sustain clean, healthful air.”2 The attorneys general in nine Northeastern states filed
suit against the final rules issued by EPA on December 31, 2002 in the U.S. Court of Appeals for
the D.C. Circuit.3 Pennsylvania filed a separate lawsuit on January 27, 2003. On January 30, the
attorneys general in eight states, mostly from the Midwest and the South filed a petition in
support of the final rule.4
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This is not the first time the NSR provisions of the Clean Air Act (CAA) have engendered
controversy. Enacted as part of the 1977 CAA Amendments and modified in the 1990 CAA
Amendments, NSR is designed to ensure that newly constructed facilities, or substantially
modified existing facilities, do not result in violation of applicable air quality standards. NSR
provisions outline permitting requirements both for construction of new major pollution sources
and for modifications to existing major pollution sources. Specific requirements dictated by NSR
depend on where the facility is sited. In attainment areas – those meeting the National Ambient
Air Quality Standard (NAAQS) for a pollutant – the governing requirements are the Prevention of
Significant Deterioration (PSD) provisions of the CAA. In nonattainment areas – those not in
compliance with a NAAQS for one or more pollutant – the governing requirements are covered
by nonattainment provisions. Some facilities can be subject to a combination of both, if the area is
in attainment for some criteria pollutants,5 but not others. Meeting these permitting requirements
can be a long and complex process, depending on the specific project, the pollutants involved,
and the specific state and federal regulatory authorities involved.6 In 1996, EPA proposed changes
1
Environmental Protection Agency, New Source Review (NSR) Improvements, November 21, 2002.
STAPPA/ALAPCO, “EPA’s New Source Review Reforms Will Undermine Environmental Protection, Say
State/Local Air Pollution Control Agencies,” November 22, 2002.
3
They are: Connecticut, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and
Vermont. See: “Nine States Sue Bush Administration for Gutting Key Component of Clean Air Act,” Press release,
Department of Law, State of New York (December 31, 2002).
4
They are: Indiana, Kansas, Nebraska, North Dakota, South Carolina, South Dakota, Utah, and Virginia.
5
Pollutants for which EPA has set NAAQS are often called “criteria pollutants” after the criteria documents EPA
prepares for setting the standard. For background on NAAQS and the criteria air pollutants and how the CAA is
structured to ensure attainment of clean air, see CRS Report RL30853, Clean Air Act: A Summary of the Act and Its
Major Requirements, pp. 3-8.
6
Many of the activities under the CAA, including many requirements specifically involving NSR, either reside with or
can be and have been delegated to states (which can include territories, Indian tribal governments, and the District of
Columbia). In essentially all cases, EPA can act in lieu of states to which authorities have not been delegated, or
whenever states fail to take required actions.
2
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to NSR to streamline it.7 However, the proposals were subject to considerable controversy, and a
final rule was not issued under the Clinton Administration. These complexities and controversies,
particularly with respect to modifications of existing sources, became manifest in the November
1999 enforcement suits filed by the Justice Department for EPA, and in the responses to them.8
The Clinton Administration’s enforcement initiative raised questions within the Bush
Administration. In May 2001, Vice President Cheney’s energy task force called on the Justice
Department to review the legality of the lawsuits.9 In January 2002, the Justice Department found
the lawsuits to be supported in law and fact.10 In addition, the energy task force asked EPA to
review the impact of NSR on new utility and refinery generation capacity, energy efficiency, and
environmental protection. In June 2002, EPA reported to the President that: (1) NSR had not
significantly impeded investment in new power plants or refineries; (2) NSR had impeded
projects at existing facilities that would maintain and improve reliability, efficiency and safety;
and (3) NSR does result in significant environmental and public health benefits.11 Based on its
findings, EPA recommended several revisions to NSR.12 There were two parts to the
recommendations. The first consisted of four recommendations that would complete the 1996
Clinton Administration’s rulemaking process. The second was a recommendation to propose a
regulation to clarify the definition of “routine maintenance.”
As published in December 2002, the final rule’s provisions fall into four categories based on
EPA’s June 2002 recommendations,13 and which the EPA believes completes the rulemaking
process begun under the Clinton Administration in 199614: (1) Plantwide Applicability Limits
(PALs); (2) Clean Unit Exclusion; (3) Pollution Control and Prevention Projects; and (4)
Emissions Calculation Test Methodology. Table 1 briefly summarizes the major differences
between the regulations existing at the time of the rulemaking, the Clinton Administration’s
proposed rule; and EPA’s 2002 final rule. EPA’s final rule provides a detailed discussion of what it
proposed in 1996 and what it finalized in November.15
The second rulemaking is a proposed clarification of the definition of routine maintenance.16
Moving away somewhat from its current “case-by-case” approach to determining routine
maintenance, the revisions would carve out two categories of activities that would automatically
constitute routine maintenance under NSR. The first category, “Annual Maintenance, Repair, and
Replacement Allowance,” would provide an exemption for safety, reliability, and efficiency
7
61 Federal Register 38249-38344, July 23, 1996.
CRS Report RL30432, Air Quality and Electricity: Enforcing New Source Review, by (name redacted) and (name
redacted).
9
Report of the National Energy Policy Development Group, May 2001 (Chapter 7, p. 14)
10
United States Department of Justice, Office of Legal Policy, New Source Review: An Analysis of the Consistency of
Enforcement Actions with the Clean Air Act and Implementing Regulations, January 2002, p. vi.
11
Environmental Protection Agency, New Source Review: Report to the President (June 2002), p. 1.
12
U.S. Environmental Protection Agency, EPA Announces Steps to Increase Energy Efficiency, Encourage Emissions
Reductions (June 2002).
13
Some documents released by EPA refer to five “improvements” because they include in the Emissions Calculation
Test Methodology category two improvements: (1) baseline change; and (2) test change.
14
61 Federal Register 142 (July 23, 1996), pp. 38250-38344.
15
67 Federal Register 80185-80314 (December 31, 2002). An internet version is available at http://www.epa.gov/nsr/
nsrfinal.pdf.
16
67 Federal Register 80290-80314 (December 31, 2002).
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activities whose capital and non-capital cost fall below a specific cost threshold. The second
category, “Equipment Replacement Approach,” would provide an exemption for replacing safety,
reliability and efficiency rated components with new, functionally equivalent equipment if the
cost of the replacement components is below a specific threshold. The proposal includes several
options for implementing each of these approaches, and asks for comments on how the two
approaches should interact and whether the second approach is sufficient alone.
Table 1. NSR Final Rule: Summary of Major Provisions
Provision
Prior Existing
Regulation
1996 Clinton Proposed
Rule
2002 EPA Final Rule
Voluntary emission cap
based on most recent 2-yr.
average plus a reasonable
operating margin that is less
than the trigger for NSR
review. PALs may be
adjusted to reflect any new
requirements
If unit meets a BACT or
LAER limit set in the last 10
years, NSR would not be
triggered by changes unless
unit increases hourly
potential emissions
Emission cap based on any
consecutive 24-month
period over the past 10
years and valid for 10 years
Plantwide
Applicability Limits
none
Clean Unit Exclusion
none
Pollution Control
and Prevention
Projects (P2
projects)
none
Excludes P2 projects from
NSR unless emission
increase would contribute to
violation of NAAQS, PSD,
or air quality related values
in a Class I area. Permitting
authority responsible for air
quality determination
Emissions
Calculation Test
Methodology
(baseline and test
changes)
Actual to potential
test for all industrial
sources except
electric utilities which
have an actual to
future actual test
based on a facility’s
emissions over 24
consecutive months
within the most
recent five-year
period
Proposed options ranging
from applying the actual to
future actual test to only
electric utilities or to all
industrial sources, or
eliminating it
If unit meets a BACT or
LAER limit set since 1990,
or MACT, RACT or
undertook pollution
prevention efforts, it would
be excluded from NSR for
10-15 years
Excludes P2 projects from
NSR unless emission
increase would contribute
to violation of NAAQS, PSD
or air quality related values
in a Class I area. EPA will
provide a list of
presumptively eligible
technologies
Applies the utility’s actual to
future actual test to all
industrial sources based on a
facility’s emissions over two
consecutive years within the
most recent ten-year period
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The CAA requires a preconstruction review of, and a permit for, almost any modification of an air
polluting source or any major new source. Assuming that a state has an EPA-approved State
Implementation Plan (SIP), which spells out the state’s strategy for complying with NAAQS,
regulatory approval to construct the new source or modify the existing source must come from
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the appropriate state agency. To receive this “Permit to Construct,” the applicant must show that
the proposed source or modification will not result in, or exacerbate, violation of a NAAQS,
either locally or downwind. In addition, applicants must show that their proposal will not result in
local or downwind exceedences of increments of increased air pollution allowed under Prevention
of Significant Deterioration (PSD) regulations in areas complying with NAAQS. It is this
preconstruction review process that is called New Source Review (NSR).17
The NSR process is triggered for any new source that potentially could emit 100 tons annually (or
less in some areas) of any criteria air pollutant, and by any modification that will cause a
significant increase in annual emissions (regulatorily defined as 40 tons for SO2 and NOx18). The
specific NSR requirements for affected sources depend on whether the sources involved are
subject to the PSD or the non-attainment provisions.19 If covered by PSD, the source is required
to install Best Available Control Technology (BACT), which is determined on a case-by-case
basis, and which cannot be less stringent than the federally determined New Source Performance
Standard (NSPS) for that pollutant. If covered by non-attainment provisions, the source is
required to install Lowest Achievable Emission Rate (LAER) and obtain applicable offsets for
that particular area.20 Like BACT, LAER must not be less stringent than the federal NSPS.
Despite the breadth of coverage suggested by NSR, few permits have been issued to coal-fired
power plants over the program’s history.21 If this situation is examined from the perspective of
new construction, the lack of permits is not too surprising. Current U.S. coal-fired electric
generating capacity is about 300,000 megawatts (MW), and has remained steady at that level for
the last ten years.22 As indicated in Table 2, additions to coal-fired capacity, while greater than
retirements, have not been significant. Capacity that began operation between 1989-2000
constitutes about 3% of total current coal-fired capacity.
Fired Electric Generating Capacity Additions, 1989-2000
(net summer capacity)
Table 2. U.S. Coal-
Year
Capacity Additions (MW)
Retirements (MW)
1989
1,967
379
1990
3,063
175
1991
792
377
1992
498
254
1993
0
104
17
Some restrict the term “NSR” to the review process in a nonattainment area only; the review process in an attainment
area being called “PSD pre-construction review”. This paper will use the term to indicate both. In addition, new and
modified sources must meet New Source Performance Standards (NSPS).
18
40 CFR 52.24(f)(10) for nonattainment; 40 CFR 52.21(b)9230(i) for PSD.
19
It should be noted that a source can be affected by the PSD requirements for one pollutant, and by the nonattainment
requirements for another pollutant.
20
For details on these provisions and their requirements, see Clean Air Act, Part C – Prevention of Significant
Deterioration of Air Quality, sections 160-169; and, Part D – Plan Requirements for Nonattainment Areas, sections
171-178.
21
Environmental Protection Agency, Letter to Chairman Inhofe (March 26, 1999), p. 2.
22
Data represent net summer capacity. Energy Information Administration. Annual Energy Review 1998, DOE/EIA0384(98), July 1999. P. 219.
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Capacity Additions (MW)
Year
Retirements (MW)
1994
540
461
1995
1,036
2
1996
1,611
16
1997
0
293
1998
0
2
1999
55
192
2000
16
40
9,578
2,295
Total 1989-2000
Source: Energy Information Administration,
Inventory of Power Plants in the United States
, various years.
The dynamism in coal-fired generation is the continuing operation of existing coal-fired facilities.
As indicated by Table 3, despite the general lack of new plant construction, coal-fired electricity
generation and related coal consumption has continued to climb over the past decade. This
increase results from utility efforts to optimize performance of existing coal-fired facilities
despite their increasing age. Historically, as plants age they become less reliable and less efficient,
leading utilities to derate them and move them from baseload to cycling duties. However, as
indicated in Table 4, contrary to historical expectations, utilization of coal-fired capacity has
increased over the past decade, and the efficiency of units has not decreased.
Table 3. Coal Consumption and Coal-fired Generation, 1989-2000
Coal Consumption
(thousand short tons)
Net Generation
(billions Kwh)
1989
781,672
1,584
1990
790,244
1,591
1991
793,666
1,591
1992
805,140
1,621
1993
842,153
1,690
1994
848,796
1,691
1995
860,594
1,709
1996
907,209
1,795
1997
931,949
1,845
1998
946,295
1,874
1999
949,802
1,881
2000
994,933
1,966
2001
975,570
1,904
Year
Source: t generation, coal consumption data from Energy Information Administration, Annual Energy Review
Ne
2001, July 2002.
This suggests that the economics of plant maintenance has changed fundamentally over the past
decade or so, making it economic for utilities to spend more to maintain their coal-fired capacity
than was the case previously. The question the EPA lawsuits raise is whether these efforts to
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maintain or even to expand generation from existing coal-fired facilities – compared to the
degradation of capacity that would be expected – represent “routine maintenance” or a
“modification” of those facilities under the CAA. If such maintenance does represent a “
modification,” then the CAA would require the installation of pollution control equipment;
“routine maintenance,” on the other hand, would not trigger the requirement for new controls.
With the restructuring of the electric utility industry placing ever-greater focus on plant
economics, this issue has intensified in recent years.23
fired Generation Capacity Factors and Heat Rates: 1989-2001
(based on net summer capacity)
Table 4. Coal-
Year
Capacity Factor
Heat Rate
1989
59.1%
10,302
1990
59.1%
10,331
1991
59.1%
10,344
1992
59.8%
10,285
1993
62.2%
10,303
1994
62.0%
10,336
1995
62.7%
10,342
1996
65.4%
10,383
1997
67.2%
10,364
1998
67.7%
10,363
1999
68.1%
10,346
2000
71.0%
10,378
2001
68.7%
10,435
Source:
Net summer capacity, net generation, coal consumption data from Energy Information Administration,
Annual Energy Review 2001, July 2002.
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As noted above, there is no firm data that NSR has seriously obstructed the construction and
operation of new power plants. The controversy over NSR with respect to power generation
focuses on existing facilities and under what conditions they meet the modification trigger that
would require them to undergo NSR. As defined under the 1970 Clean Air Act, a modification is
“any physical change in, or change in the method of operation of, a stationary source which
increases the amount of any air pollutant emitted by such source or which results in the emission
of any air pollutant not previously emitted.”24 In subsequent regulations issued in 1975 with
respect to New Source Performance Standards (NSPS), EPA defined modification as any physical
or operational change that resulted in any increase in the maximum hourly emission rate
23
See: (name redacted) and (name redacted),
Electricity Restructuring: The Implications for Air Quality, CRS Report 98-615
ENR, July 16, 1999.
24
Section 111(a)(4).
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(kilograms per hour) of any controlled air pollutant.25 In addition, EPA regulations stated that any
replacement of existing components that exceeded 50% of the fixed capital costs of building a
new facility placed the plant under NSPS, regardless of any change in emissions.26 With the
advent of NAAQS non-attainment provisions (Part D), Prevention of Significant Deterioration
provisions (Part C), and NSR in 1977, a different approach to defining modification was
appropriate as the focus was shifted from enforcing NSPS emission rates to compliance with
NAAQS and PSD. In promulgating regulations for the PSD and non-attainment programs, EPA
defined “significant” increase in emissions in terms of tons per year emitted by a major source.
For sulfur dioxide and nitrogen oxides, the threshold is 40 tons per year.27 Facilities that exceed
that threshold are subject to NSR.
Enforcing these thresholds has been more difficult than their apparent clarity would suggest.
EPA’s thresholds for the NSPS program generally represent no practical constraint on life
extension efforts by utilities. Most life extension efforts improve the availability and reliability of
generating units, not their capacity to generate. Thus, their maximum hourly emission rate would
not change. Likewise, most life extension efforts cost far less than the 50% asset value threshold.
NSR review has a far more sensitive trigger – a tonnage increase in pollutant output. Because life
extension does improve availability and reliability, it is likely to increase emissions over levels
emitted before the life extension activities were undertaken. But how does one measure the
change? What are the baselines28?
These issues came to a head in the late 1980s when EPA decided to enforce NSR against facilities
undergoing life extension efforts. In 1988, the EPA ruled that a life extension project by
Wisconsin Electric Power Company (WEPCO) met the trigger for NSR because of the potential
for increased emissions from the facilities after the project compared with actual emissions from
the facilities before the project. After considerable litigation29 and congressional debate, EPA
modified this “actual to potential” emissions trigger with respect to electric utilities in 1992.30 The
new “test” to determine the applicability of NSR compares a facility’s actual emissions before the
modification with its projected actual emissions after the modification (“actual to future actual”).
Specifically, “actual emissions” equal the facility’s average emission rate during a 2-year period
out of the preceding 5 years before the proposed change. “Future actual” is the product of the
facility’s projected emission rate after the change and its projected actual utilization based on
historical and other data. These are the current NSR regulations for utility plants.
25
40 CFR 60.14(a) (1975).
40 CFR 60.15 (1975).
27
For PSD, see 40 CFR 52.21(b)(23)(i); for nonattainment, see 40 CFR 52.24(f)(10).
28
Defining the baseline has been a key issue. Every powerplant has what is called “nameplate” capacity, which
indicates its theoretical size; but the actual output is defined by its “operating capacity,” which is determined by the
engineering and operational details of the individual plant. Moreover, from an engineering perspective, the operating
capacity declines over time as a result of boiler deterioration, pipe clogging, and other predictable changes due to use.
The issue is, then, what level of capacity restored by renovations trigger NSR: only renovations that increase capacity
beyond the facility’s nameplate capacity? those that increase capacity beyond the original operating capacity? those
that increase capacity above an engineering-defined capacity that projects declines over time? Or those that increase
potential emissions above the actual emissions before the modification?
29
Wisconsin Electric Power Company v. Reilly, 893 F.2d 901 (7th Cir. 1990).
30
57 Federal Register 32314-32339 (July 21, 1992).
26
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Fundamental to the debate on NSR enforcement with respect to existing facilities is the notion of
“routine maintenance.” In promulgating implementing regulations, EPA exempted certain
activities from the definition of physical or operational change. Among those activities exempted
was: “maintenance, repair, and replacement which the Administrator determines to be routine for
a source category....”31 In addition, increases in production rates that do not involve capital
expenditures do not constitute a modification. Responding to this situation, utilities began to
spread out their life extension efforts in an attempt to make them fit into their routine
maintenance schedules.32 Indeed, the term “life extension” has fallen out of the professional
literature, replaced with terms like capital improvement, performance improvement and unit
integrity, condition assessment, life operation management, review of continued operating
requirements, and asset management.33 The commonly used term currently is rehabilitation
program.34 By spreading out the life extension efforts and integrating them into facilities’
operation and maintenance schedules, the distinction between “modification” and “routine
maintenance” is effectively blurred, and arguably, eliminated.
These “rehabilitation” practices that extend the design life of a power plant represents a change in
what had earlier been considered accepted maintenance practices: Before the early 1980s, power
plants were generally assumed to have fixed lives – 30-40 years – after which they would be
replaced or relegated to cycle or peaking duties. In its 1981 Technical Assessment Guide, The
Electric Power Research Institute (EPRI) defined a unit life as follows:
Unit life is an estimate of the book life of the plant. The maintenance costs include sufficient
funds to replace minor equipment that wears out before the unit life shown.35
In its cost analyses for coal-fired powerplants, this unit life was assumed to be 30 years.36 By its
1986 Technical Assessment Guide, the definition of unit life was the same, but the assumed unit
life for a coal-fired powerplant was 40 years.37
The flux in the notion of fixed powerplant lives was evident in the early 1980s debate on
proposed acid rain legislation. In utility analyses of anticipated cost of retrofitting their existing
powerplants with additional pollution controls, utilities split on the issue of retirement, either as a
31
40 CFR 60.14(e)(1).
As observed by Robert Smock, Editor, “Power Plant Life Extension Trend Takes New Directions,” Power
Engineering (February 1989): “There are signs that many utilities will not use the term “life extension” to describe their
spending on old power plants, even though extended life is one of the major goals of the spending program. The reason
for the aversion to the term lies in the 1970 Clean Air Act. That federal law requires all power plants constructed after
August, 1971 to restrict emissions of air pollutants such as sulfur dioxide. Plants built prior to 1971 are exempt, which
includes most of the early candidates for life extensions. The problem is that the law also says that grandfathered plants
can lose their exemption if they are “modified” or “reconstructed” in a major way and emission of proscribed pollutants
are increased.”(p. 21).
33
Robert G. Presnak and Bock H. Yee, “Life Extension: The Benefits Are Real,” Power Engineering (December
1993), pp. 25-27.
34
For a current view of managing existing facilities, see Jason Makansi, “Rehab: Get the Most from the Existing Asset
Base,” Power (June 1999), pp. 30-40.
35
Electric Power Research Institute, TAG – Technical Assessment Guide, Palo Alto: EPRI, (May 1982), p. App B-48.
36
ibid, p. App B-55.
37
Electric Power Research Institute, TAG – Technical Assessment Guide (volume 1: Electricity Supply – 1986), Palo
Alto: EPRI (December 1986), p. B-43.
32
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pollution control strategy, or as utility policy in general. For example, American Electric Power, a
leading opponent of such legislation, conducted its cost analysis with assigned specific retirement
dates for its existing powerplants ranging from 30-40 years. Indeed, it considered early retirement
to be a viable, cost effective pollution control option.38 In contrast, analyses by other utilities
assumed neither any specific retirement dates, nor early retirement as a control option.39
Up to this time, routine maintenance practices did not attempt to arrest or reverse the normal
deterioration of the powerplant’s performance over its life span. Industry aging trends with
respect to powerplant performance with standard maintenance practices (as suggested by the
EPRI definition) are well documented.40 In general, aging affects both the efficiency of the
powerplant along with its reliability and availability. Degradation of key components, such as
turbines, waterwall tubing, and reheaters, slowly reduces a powerplant’s efficiency in converting
heat to steam and steam to electricity. The result is a higher heat rate and less output. As shown in
Figure 1, “average industry maintenance practice” results in heat rates increasing by about 0.3
percent annually during the first ten years of operation, dropping to below 0.2 percent after that.41
38
See: American Electric Power, “Acid Rain Control Costs,” in Acid Rain: A Technical Inquiry, Hearings before the
Committee on Environment and Public Works, U.S. Senate, May 25 and 27, 1982, p. 736.
39
For example, see: ibid., Responses to Written Questions, pp., 748 (Southern Company Services), 756 (Public Service
of Indiana), 767 (Indianapolis Power & Light), 790 (Ohio Edison).
40
In particular, see: H. H. Heiges and H. G. Stoll, “Power Plant and Turbine-Generator Upgrading Economics,”
presented at EPRI and EEI’s Fossil Plant Life Extension Workshop, June, 1984.
41
ibid., pp. 12-2 - 12.3.
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Figure 1.Trend of Power Plant Heat Rate with Age
Figure 2. Impact of Power Plant Aging on Reliability of Fossil-Fired Units
50 to 200 Mw
Likewise, the aging of components eventually increases the forced outage rate of powerplants as
component failure becomes more frequent. As indicated in Figure 2, reliability of coal-fired
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facilities peak at between 10 and 20 years of service and then begins to deteriorate. By 35 years
of operation, a facility’s forced-outage rate has increased by 10 percentage points. In particular,
older facilities begin to have significantly longer outages as they age, in line with the failure of
major equipment, such as the turbine-generator.42
As indicated by the data presented in Table 3, these documented trends based on 1980 “average
industry maintenance practices” are not occurring. Heat rates for coal-fired facilities are
remaining relatively stable while capacity factors are increasing substantially. It is obvious that
the rehabilitation programs utilities initiated in the 1980s and continuing to the present have been
successful in dramatically reducing the aging process with respect to coal-fired facilities.
However, is this success a violation of the modification definition of NSR? If “routine
maintenance” is defined in terms of “average industry maintenance practice” at the time of the
1970 or 1977 Clean Air Act Amendments, then a strong case can be made that it is – major
components are being replaced or upgraded that would not have been under average industry
maintenance practices of that time. Yet, if “routine maintenance” is interpreted to mean industry
practices at the current time, then one can argue that rehabilitation has become routine over the
past 20 years, and thus does not represent a modification.
This is fundamental to the way one views the proposed clarifications to the definition of routine
maintenance proposed by EPA. If one believes that EPA’s routine maintenance exemption as
enunciated in the 1970s was delimited and not a license to rehabilitate existing facilities, then one
would conclude that many of the industry’s rehabilitation activities of the last 20 years go beyond
what NSR requirements allow. Thus, any argument by the current Administration that its
proposed NSR revisions would reduce emissions beyond that required under current law would
be untenable as enforcement of current law would require existing sources subject to NSR to
meet the stringent standards of either BACT or LAER. This perspective that applying NSR
requirements to rehabilitation would reduce emissions is consistent with the enforcement
initiative of the Clinton Administration, an initiative for which the Bush Administration has stated
its support.
In contrast, if one believes that an exemption for routine maintenance is appropriate and should
be defined in terms of current industry practices, then one would conclude that the potential threat
of NSR (and the installation of BACT or LAER) prevents owners from making cost-effective
improvements in the overall performance and efficiency of their existing facilities (e.g., improved
heat rates). From this perspective, NSR discourages plant owners from upgrading facilities
operating with old, worn-out, inefficient components, thereby foregoing opportunities to conserve
energy and to reduce carbon dioxide emissions by installing newer, more efficient components.
This perspective that NSR discourages energy efficiency is reflected in the Bush Administration’s
proposed revisions to routine maintenance published in December, 2002.43
This second view that rehabilitation is in fact routine also reflects the defense of many of the
utilities sued by the Justice Department under the Clinton Administration. For them, rehabilitation
programs are the norm for the industry and, therefore, should not trigger NSR. In its proposed
revisions to the definition of routine maintenance, the Bush Administration cited analyses by the
Tennessee Valley Authority (TVA) and First Energy that they would have “lost” 32% and 39% of
their coal-fired capacity respectively, if they had capped their emissions under a “narrow” routine
42
43
ibid., pp. 12-3 - 12.5.
67 Federal Register 80290-80314 (December 31, 2002).
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maintenance exclusion.44 With the decision of the Bush Administration to support revisions to
NSR, utilities subject to litigation originating under the Clinton Administration’s enforcement
initiative are using EPA’s new policy position as a defense.45
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In announcing the NSR suits in 1999, the EPA Administrator stated that “controlling the sulfur
dioxide and nitrogen oxides from these plants could lead to an 85 to 95 percent reduction
respectively in these pollutants.”46 Based on her statement, this would reduce SO2 emissions by
1.87 million tons and NOx emissions by 0.63 million tons. Also, given the widespread nature of
life extension efforts, it is reasonable to assume that further reductions would be achieved as other
utilities either installed BACT or retired their offending facilities. Thus, at first glance, it would
appear that very substantial emission reductions could be achieved by rigorous enforcement of
NSR’s regulations using the existing definition of “routine maintenance” rather than EPA
proposed new one.
The best analysis of future possibilities under current NSR regulations is by the Energy
Information Administration (EIA).47 The three relevant scenarios are: (1) reference: no
enforcement (including halting current lawsuits); (2) NSR 32: enforcement limited to the current
lawsuits; and (3) NSR All: enforcement expanded to include all coal-fired plants over 25
megawatts. The projected 2010 sulfur dioxide (SO2) and nitrogen oxides (NOx) results under
these three scenarios are presented in Table 5. As indicated, depending on one’s expectation with
respect to NSR enforcement in lieu of the EPA proposed rule on routine maintenance, the
difference in emissions could be on the order of a factor of five.
Table 5. EIA’s 2010 NSR Reference Cases: Emissions from Coal-fired Electric
Generating Facilities
Scenario
NOx Emissions
(million tons)
SO2 Emissions
(million tons)
Reference
NSR 32
NSR All
4.20
3.78
1.56
9.70
9.10
1.94
44
67 Federal Register 80302 (December 31, 2002).
For example, on January 8, 2003, Southern Indiana Gas & Electric Company (SIGECO) filed a “notice of
supplemental authority” with the U.S. District Court for the Southern District of Indiana arguing that EPA’s proposed
revisions undercuts the government’s case against it. Specifically, the company argues that its activities that invoke the
lawsuit are far smaller than those that would be allowed under the revised rule, and that language in the proposal
supports its argument that the company did not receive fair notice of the interpretation underlying the enforcement
action. On February 18, 2003, the U.S. District Court for the Southern District of Indiana rejected the claims by
SIGECO, calling testimony by SIGECO experts on the routine maintenance issue “irrelevant and unpersuasive.” This
follows a ruling on February 13, 2003 by the same Court that “EPA’s interpretation for routine maintenance is
reasonable and persuasive.”
46
Carol M. Browner, Administrator, Remarks Prepared for Delivery, Clean Air Enforcement Press Conference
(Washington, D.C.: November 3, 1999).
47
Energy Information Administration, Strategies for Reducing Multiple Emissions from Electric Power Plants with
Advanced Technology Scenarios, chapter 5: Potential Impacts of New Source Review Actions (October 2001), pp. 5763.
45
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Source:
EIA, Strategies for Reducing Multiple Emissions from Power Plants, table 20.
However, the CAA is a complex piece of legislation built up over time. In the case of SO2 any
reduction achieved under NSR would interact with reduction requirements under title IV – a SO2
reduction program designed with different premises than NSR. Specifically, title IV limits total
SO2 emissions from utilities to 8.9 million tons beginning in the year 2000, with interim
reductions required in 1995. The cap is enforced through tonnage limitations at individual
existing utility plants and by an emission offset requirement for new facilities. SO2 emissions
from most existing sources are capped at a specified emission rate times a historical (1985-1987)
average fuel consumption level. Thus the tonnage limitation is based on preset and historical data,
not regulatory limits. To implement the program, title IV created a comprehensive emissions
allowance system. An allowance is a limited authorization to emit a ton of SO2 during or after a
specified year. Issued by EPA, allowances are allocated to existing facilities in accordance with
the emission rate/fuel consumption formulas detailed in the law. Such allowances may be used at
the plant they are allocated to, or they can be traded or banked for future use or sale. The program
has been very successful with nearly 100% compliance.
This 1990 CAA Amendments program does not integrate well with the 1977 CAA Amendments
NSR program. Except that they both focus on existing facilities and SO2, they have little in
common. The NSR is concerned with modifications at existing facilities and installation of
BACT. Title IV doesn’t address whether existing facilities continue operation or not, or whether a
specific facility installs BACT or not; compliance with the cap is the determining criterion. NSR
is an enforcement mechanism to assure compliance with individual plant standards; title IV is a
program to reduce aggregate SO2 emissions by permitting utilities considerable flexibility in
determining appropriate compliance strategies.
The current SO2 NSPS, the “floor” for any BACT or LAER determination, is a percentage
reduction requirement that reduces SO2 emissions by 70%-90%, depending on the coal burned.
However, the allocations under title IV for existing coal-fired facilities is not as stringent and can
be met with low-sulfur coal. Thus, any facility that installed BACT under NSR would
“overcontrol” SO2 under title IV, and, therefore, have excess allowances available for sale or to
bank for future use. Consequently, any reductions achieved because of NSR enforcement could
be rendered moot by title IV, if the affected plant subsequently sold its SO2 reduction to some
other facility not covered by an NSR action.48 Except for any TVA reductions, the net result
would be no reductions, at least theoretically. Title IV does not provide for adjusting allowance
allocations as a result of NSR enforcement. Rather, the law explicitly bases its allowance
allocations on historical data, not on any presumption of compliance with NSPS or SIP
requirements. To avoid this “allowance trap,” either Congress would have to change the law, or
utilities would have to agree to surrender the excess allowances created by any NSR enforcement
action. Indeed, NSR settlements and agreements in principle resulting from EPA’s enforcement
initiative have included the retirement of SO2 allowances that the utilities could have used to emit
additional pollution elsewhere.49
48
The TVA Compliance Order would require retirement of allowances equal to any SO2 reductions achieved as a result
of the compliance order.
49
For example, see U.S. Environmental Protection Agency, “United States and New Jersey Announce Clean Air Act
Coal-fired Power Plant Settlement With PSEG Fossil LLC Effect Will Cut New Jersey Industrial Sulfur Dioxide
Emissions by 32%,” EPA Press Release, January 23, 2002.
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The situation with potential NOx reduction is more complex. First, there is the interaction of NSR
and the NOx NSPS. Unlike the very stringent SO2 NSPS, the NOx NSPS historically has not
reflected the cutting edge in technology development.50 Until the new standard was set in 1998,
the NOx NSPS for coal-fired facilities was 0.6/0.5 lb. of NOx per million Btu of heat input,
depending on the type of coal burned. This standard, set in 1979, could be met with fairly simple
combustion modifications or low-NOx burners, and did not require the installation of pollution
control devices such as selective catalytic reduction (SCR). Indeed, the standard did not reflect
the state of the art with respect to low-NOx burners.
In 1998, EPA promulgated a new NOx NSPS for coal-fired facilities of 0.15 lb. of NOx per
million Btu – a standard more in line with available technology. However, this new standard was
challenged in court. In September, 1999, the D.C. Court of Appeals vacated the new NOx NSPS
with respect to modified utility boilers, while later upholding the NSPS with respect to new
sources.51 By vacating the modified standard, the NSPS for modified sources returned to the
previous 1979 standard until such time as EPA proposes a revised NSPS. As a result, the floor for
determining BACT or LAER for modified coal-fired sources is unclear at the current time. If the
floor is the current modified NSPS as set in 1979, reductions achieved by NSR enforcement
would be considerably less than that suggested by some. In contrast, if the floor is the new 1998
NSPS, the reduction would be substantial. Surveying BACT determinations over the time period
1991-1995 sheds no light on what BACT might be currently: data indicate permitted emission
rates ranged from 0.15 to 0.5 lb. per million Btu.52 Thus, it is difficult at the current time to
project what any actual NOx reduction would be achieved by increased NSR enforcement.
The confusion is exacerbated by the interaction of NSR and title IV. The NOx reduction program
under title IV differs substantially from the SO2 program. Like the NSPS program, the title IV
NOx program is based on emission rates, not tonnage limitations. The difference is that the
emission rate for the title IV program is set for existing facilities to be achieved in 1995 or 2000
(depending on the facility), regardless of whether the facility is modified or not. In addition, the
rate limitation for most boilers under title IV is 0.45 to 0.5 lb. per million Btu, or more stringent
than the 1979 NOx NSPS. Thus, you have the curious situation of some existing coal-fired
facilities having emission controls since 1995 that are more stringent than the existing NSPS – a
situation that continues currently with the court action on the modified NSPS.
A third interaction is between NSR and the NOx SIP call. The NOx SIP Call (also called the
Ozone Transport Rule), requires 21 eastern and midwestern States and the District of Columbia to
reduce emissions of NOx to prevent interstate transport of ozone pollution.53 To achieve the
necessary reductions, EPA stipulates an emission budget for each of the affected states, with each
state free to decide on what controls to use to maintain emissions within those budgets. With
much of the reduction likely to come from coal-fired electric powerplants, EPA is recommending
States agree to a regional cap and trade program to implement the reduction program. The
50
(name redacted),
Nitrogen Oxides and Electric Utilities: Revising the NSPS, CRS Report 96-737 ENR (October 13,
1998).
51
Lignite Energy Council v. Environmental Protection Agency, Order No. 98-1525, D.C. Court of Appeals (September
21, 1999). In a separate opinion issued December 21, 1999, the court upheld the NSPS with respect to new sources.
52
Office of Air and Radiation, EPA, Analyzing Electric Power Generation under the CAAA (July 1996).
53
Environmental Protection Agency, Findings of Significant Contribution and Rulemaking for Certain States in the
Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone, 63 Federal
Register 57356-57538, October 27, 1998. Further litigation removed the state of Wisconsin from the list of states
affected by the rule.
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potential interaction between this program and an NSR enforcement is unclear, as the allowances
used in any NOx trading program would have a regulatory, rather than a statutory, basis.
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Alternatives to the current NSR situation focus on either energy or environmental considerations.
For example, the Administration’s proposed revisions to routine maintenance are an outgrowth of
the President’s National Energy Policy and are intended “to provide greater regulatory certainty
without sacrificing the current level of environmental protection....” The policy goal is not to
reduce emissions. As stated in the proposed rule:
What these [EPA’s] analyses indicate, however, is that regardless of which scenario is
closest to what comes to pass, none of the proposed provisions related to the RMRR [routine
maintenance, repair, replacement] exclusion will have a significant impact on emissions from
the power sector.54
The Bush Administration’s NSR focus on energy policy contrasts directly with the focus of the
Clinton Administration’s enforcement initiative where, by seeking to enforce NSR requirements,
EPA attempted to exploit an existing authority to reduce emissions. Likewise, proposed
legislation in the 107th Congress to define a modification in terms of a power plant’s age was
another attempt to use NSR as an emissions reduction program.
NSR is one approach that the Clean Air Act takes to control emissions from existing sources, but
arguably more efficient and more effective methods to ensure declining emissions from existing
sources over time have been developed since NSR was added to the CAA in 1977. For example,
title IV of the CAA, enacted in 1990, explicitly and substantially reduces SO2 and NOx emissions
from existing utility plants. In fact, title IV reduced more SO2 emissions from coal-fired electric
generating facilities in its first year of implementation (1995) than NSR has in its 20 years of
existence. The “cap and trade” program has had nearly100% compliance (indeed, substantial
over-compliance); the implicit logic of EPA’s lawsuits suggests NSR’s compliance with respect to
electric generating facilities has been near zero. The title IV program began without significant
delays (SO2 program on-time, NOx program 1 year late); the EPA lawsuits could take years to
resolve with uncertain results.
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Published in December, 2002, the Bush Administration’s proposed definition of routine
maintenance would permit current utility rehabilitation practices to continue without the threat of
triggering NSR. As suggested above, the proposed changes to the definition of routine
maintenance are focused on energy policy considerations, not environmental considerations. If
one’s baseline is current utility emissions, EPA believes, as stated above, the proposed changes
will have no significant impact on emissions.
54
67 Federal Register 80304 (December 31, 2002).
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The proposed rule suggests two approaches for determining whether a utility’s activities exceed
routine maintenance. Both approaches involve the use of a cost trigger, and EPA suggests that the
two could be used together, or the second approach could stand alone. The first category, “Annual
Maintenance, Repair, and Replacement Allowance,” would provide an exemption for safety,
reliability, and efficiency activities whose capital and non-capital cost fell below a specific cost
threshold. The second category, “Equipment Replacement Approach,” would provide an
exemption for replacing safety, reliability, and efficiency rated components with new, functionally
equivalent equipment if the cost of the replacement components is below a specific threshold.
Obviously, using a cost threshold to define routine maintenance means that the stringency of NSR
with respect to an existing source would depend substantially on the cost estimate used to set the
trigger.
However, no proposed estimates are provided in the proposed rule for an “annual, maintenance,
repair and replacement allowance.” EPA’s quantitative discussion of such estimates in the rule
consists of noting the IRS values for such items (ranging from 0.5% to 20% of invested costs,
depending on industry); and estimates contained in standard reference manuals for the chemical
process industry (ranging from 2% to 10% for that industry). From this literature review, EPA
concludes: “Based on information contained in the resources mentioned above, the appropriate
annual maintenance percentages would be in the range of 0.5% to 20%, depending on the
industry.”55 Even this broad conclusion is more precise than the actual proposal as the proposal
also states that EPA is considering whether or not to exclude from the allowance calculation costs
associated with replacing components that experience unanticipated failure or a catastrophic
failure.56
With regard to a cost trigger with respect to the second approach EPA anchors its discussion on
the 50% of the assessed value reconstruction cost trigger of the NSPS, stating:
Thus, we believe that the 50% capital replacement threshold used under the NSPS might
constitute an appropriate limitation on when identical or functionally equivalent replacement
should qualify as RMRR under the equipment replacement provision without regard to other
considerations.57
EPA does not provide any analyses to reinforce its belief that 50% is an appropriate cost trigger
for its replacement approach, and notes that “there are other considerations pointing in favor of a
threshold lower than the 50% reconstruction threshold that may be appropriate to bound the
equipment replacement provision.”58
This position by EPA appears to reflect two somewhat contrasting perceptions with respect to
NSR.
First, EPA believes that it is not reasonable for the replacement approach to exclude from NSR
activities that involve the total replacement of an existing entire process.59 However, a 50% cost
trigger would, in fact, permit such activities, at least for power plants. As CRS noted in reports
55
67 Federal Register 80298 (December 31, 2002).
67 Federal Register 80299 (December 31, 2002).
57
67 Federal Register 80301 (December 31, 2002).
58
ibid.
59
ibid.
56
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beginning in 1985, the 50% reconstruction trigger is not a serious constraint on utility
rehabilitation activities.60 Indeed, a review of EPA’s Applicability Determination Index (ADI)
database indicates no instance where the reconstruction provisions of the NSPS regulations has
been applied to an electric generating facility.61 EPA appears to recognize the potential that a 50%
cost trigger would never be invoked and, therefore, suggests a limiting principle for rehabilitation
programs based on “functional equivalence” of replaced components. Even this may have
problems, as stated by EPA:
We recognize that it may sometimes be difficult to determine where to draw the line between
an activity that should be treated as an excluded replacement activity and one that should be
viewed as a physical change that might constitute a major modification when the
replacement of equipment with identical or functionally equivalent equipment involves a
large portion of an existing unit. At the same time, we believe it is important to provide some
clear parameters for making this determination.62
Whether those parameters would be clearer than the current NSR trigger remains to be seen.
Second, while EPA believes that complete reconstruction should not be allowed, it also believes
that the breadth of exclusion permitted by any definition of routine maintenance is irrelevant in
terms of reducing powerplant emissions. In a qualitative discussion of utility behavior and the
potential emissions impact of a “narrow” definition of routine maintenance, EPA states:
...a narrow RMRR exclusion that is clearly established is not expected to achieve significant
reduction in historic emission levels, and might even lead to area wide emissions increases.
Most facilities would take lawful steps to avoid having to obtain an NSR permit that would
impose strict limitations, even when replacements would be found under this narrow
exclusion to be non-routine.63
If the breadth of definition does not affect emissions, it is not clear why it matters whether a
utility can completely reconstruct a facility. If EPA’s concerns are primarily energy policy driven
and focused on providing industry with clear parameters, a simple cost trigger without any
functional restraint is well within the rationales presented in its routine maintenance proposal.
Indeed, the Bush Administration has stated that it believes that multi-pollutant legislation would
be more effective and efficient in reducing pollutants than rigorous NSR enforcement. Thus, the
Administration “Clear Skies” proposal includes an exemption from NSR for facilities complying
with provisions contained in the bill.64
60
(name redacted), et. al.,
The Clean Air Act and Proposed Acid Rain Legislation: Can We Get There From Here? CRS
Report 85-50 (February 21, 1985), p. 46.
61
Telephone conversation with EPA, February 3, 2003.
62
67 Federal Register 80301 (December 31, 2002).
63
67 Federal Register 80302 (December 31, 2002).
64
Introduced in the 107th Congress as H.R. 5266 and S. 2815.
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If the object of the Clinton Administration’s NSR enforcement initiative was to reduce SO2
emissions from coal-fired powerplants, the most straightforward alternative would be to lower the
cap on such emissions contained in title IV. The practical effect of the 1990 SO2 cap was to
reduce SO2 emissions from existing facilities to the level required by the 1971 NSPS. The effect
on new sources was to reduce the NSPS to zero, as all emissions now have to be offset. Lowering
the existing cap by about two-thirds would achieve roughly the same emission reductions as all
existing powerplants meeting the 1978 NSPS, but utilities would have some flexibility in
achieving such reductions. Admittedly, utilities would get credit for shutdowns that they would
not get under NSR enforcement; however, the administrative and cost advantages of the
allowance system might be considered worth it. In any case, it would require new legislation,
which could be a long drawn out process.
Similarly, a new “cap and trade” program for NOx would eliminate the uncertainties involved in
the NSR enforcement debate, and, potentially, in several other EPA initiatives with respect to
NOx emissions. In that context, EPA has been strongly urging states to consider a regional cap
and trade program in implementing its NOx SIP Call, and any possible compliance with Section
126 petitions. Indeed, EPA made such a program a part of its proposed Federal Implementation
Plan (FIP) for states that do not submit adequate SIPs under the SIP Call and its compliance plan
for implementing approved Section 126 petitions. However, to implement a regionwide cap and
trade program under the NOx SIP Call for NOx would require either extraordinary cooperation
between the states affected (because of the SIP process), or new EPA authority.
The Administration apparently agrees with this position. In February 2002, the Bush
Administration announced its “Clear Skies” proposal to place emission caps on electric utility
emissions of SO2, NOx and mercury (Hg). Implemented through a tradeable allowance program
the emissions caps would be imposed in two phases: 2010 (2008 in the case of NOx) and 2018. It
was introduced as part of a complete rewrite of Title IV of the Clean Air Act on July 26, 2002, as
H.R. 5266. It was introduced in the Senate on July 29 as S. 2815. No action was taken on the
proposal in the 107th Congress.
In addition to the emission caps, H.R. 5266/S. 2815 would have substantially modified or
eliminated several provisions in the Clean Air Act with respect to electric generating facilities.
With respect to existing facilities, the bills provided an exemption from NSR (and other
provisions) for existing facilities that meet specific requirements provided in the legislation.
Replacing NSR with a cap and trade program is not without controversy. Indeed, a report by EPA
Region IX found that NSR is very compatible with a cap and trade program.66 After examining
implementation of California’s RECLAIM program from its inception in 1993 to the present, EPA
concluded:
65
For a comprehensive discussion of multi-pollutant strategies, see: CRS Report RL30878, Electricity Generation and
Air Quality: Multi-Pollutant Strategies, by (name redacted) and (name redacted); for a comparison of multi-pollutant
Air Quality: Multi-Pollutant
legislation introduced in the 107th Congress, see (name redacted) and (name redacted),
Legislation, CRS Report RL31326 (October 22, 2002).
66
U.S. Environmental Protection Agency, An Evaluation of the South Coast Air Quality Management District’s
Regional Clean Air Incentives Market – Lessons in Environmental Markets and Innovation (November, 2002).
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RECLAIM’s experience seems to demonstrate that cap and trade (CAT) can work with
Clean Air Act (CAA) New Source Review (NSR). This may be a function of the types of
sources included or the controls in place at many facilities. This lesson is contrary to the
commonly reported federal view and should be further researched.67
Others also see a conflict between NSR and multi-pollutant legislation. Multi-pollutant legislation
introduced by Senator Carper in the 107th Congress, S. 3135, included provisions modifying
NSR. Under S. 3135, NSR would have been triggered if the capital costs of replacement
components exceeded 50% of the construction costs of a new facilities (similar to current
reconstruction regulations and the Administration’s proposed second option) or if the rate of
emissions (in terms of pounds per megawatt-hour) increased. Unlike the Administration’s
regulatory proposal, this modification of NSR would occur within the context of a comprehensive
series of emissions caps on SO2, NOx, Hg, and CO2 that are laid out in the bill. The
Administration’s Clear Skies proposal does not include CO2.
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While the above proposal sees a lessening of NSR for existing facilities, either for energy policy
reasons or to reduce potential conflict with a cap and trade program, other proposals see an
aggressive definition of modification as complementing a cap and trade program. For example, in
the 107th Congress, H.R. 1256 (Waxman), and S. 556, as reported by the Senate Committee on
Environment and Public Works, contained provisions that would have required all powerplants 30
years or older to meet current NSPS requirements. Essentially, this legislation would have defined
“modification” in terms of plant age, not physical or operation change. It would be relatively easy
to implement, and, as indicated in Table 5 previously, an “all NSR” scenario would result in
substantial emission reductions.
Similar to S. 3135, the proposals introduced above modify NSR within the context of a
comprehensive series of emissions caps on SO2, NOx, and CO2, along with unit-by-unit emission
limitations on Hg. Currently, NSR for powerplants can only result in reduced emissions of SO2,
NOx, and particulate matter. There is no NAAQS or NSPS for either Hg or CO2. Thus, to control
these additional pollutants, additional control regimes would be necessary, particularly for CO2.
By combining NSR with multi-pollutant legislation, one provides a fairly clear picture as to the
direction of emission control regulation for the lifetime of a powerplant.
However, this clarity comes at the price of flexibility with respect to utilities complying with the
emissions caps. Instead of using market mechanisms, such as trading of emissions credits, to
create a cost-effective reduction in all four pollutants, the 30-year rule means that BACT or
LAER for SO2, NOx, and particulate matter would have to be installed on given plants, regardless
of what a more comprehensive compliance strategy might suggest. Thus, it is possible that
combining a stringent NSR with multi-pollutant legislation in the manner suggested by H.R. 1256
and S. 556 might increase the overall cost of compliance.
67
ibid., p. 68.
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Much of the popular debate on NSR has focused on “grandfathered” powerplants. One example
from a 1998 report by a public interest group states:
The Clean Air Act of 1970, as amended in 1977 and 1990, contains a major exemption that
allows older coal-burning power plants to emit between 4 and 10 times the amount of
pollution that new plants may emit under the Clean Air Act. In part, this colossal loophole
exists because industry lobbyists argued successfully that its older plants would soon retire,
and that therefore it would be wasteful to require expensive retrofits to control pollution from
these plants. However, over 20 years later, many of these same plants, built in the 30s, 40s,
50s and 60s, are still operating, largely without environmental controls.68
The term “grandfathered powerplant” is a much used and little understood concept employed in
debate on emissions from existing powerplants. Specifically, “grandfathered” is an ambiguous,
and, in some cases, meaningless term generally used to indicate whether a given powerplant is
covered under Section 111 of the Clean Air Act. Passed with the 1970 Clean Air Act
Amendments, Section 111 requires the EPA to promulgate regulations defining the minimum
controls necessary for new sources (including power plants) regardless of their location. Called
New Source Performance Standards (NSPS), they require major new sources constructed after
their promulgation to install the best system of continuous emission reduction which has been
adequately demonstrated according to EPA. Currently, there are NSPS regulations for
powerplants that cover three pollutants – sulfur dioxide (SO2), nitrogen oxides (NOx) , and
particulate matter. Typically, “grandfathered” refers to those plants (usually coal-fired
powerplants) that were constructed before the effective dates of those NSPS regulations and,
hence, not subject to them. NSPS regulations for powerplants were first promulgated in 1971 and
revised in 1979. The NOx NSPS regulations for powerplants were revised again in 1998. Instead
of NSPS requirements, such “grandfathered” sources must meet emission rate limits established
by a State Implementation Plan (SIP).
Three aspects of the NSPS make the term “grandfathered” at best ambiguous:
68
•
Some emissions of concern, such as carbon dioxide (CO2) and mercury (Hg) are
not criteria air pollutants, and, therefore, not covered by the NSPS for
powerplants at the current time. Hence, “grandfathered” would not apply for
these pollutants as all powerplants (indeed, all major sources of these pollutants)
are “grandfathered.”
•
EPA is required to review the NSPS every eight years, resulting in increased
stringency for covered pollutants as technology improves (and for determinations
of BACT and LAER). Therefore, what powerplants are “grandfathered” is
ambiguous as there is no set baseline. For example, the NSPS for NOx was
revised in 1998 to a stringency that only a couple of commercially operating
coal-fired powerplants met at the time; by that standard, virtually all coal-fired
powerplants are “grandfathered” with respect to NOx emissions.
United States Public Interest Research Group, Lethal Loophole, U.S. PIRG Education Fund (June, 1998), p. 3.
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Title IV of the 1990 Clean Air Act Amendments changed the regulation of
existing powerplants with respect to SO2 and NOx. In some cases, the
requirements under title IV for existing sources are more stringent than some of
the existing or previous NSPS. For example, under phase 1, some existing
“grandfathered” powerplants were required in 1995 to meet NOx standards more
stringent than then-existing NSPS NOx requirements for new powerplants.
Likewise, under phase 2 of title IV, existing “grandfathered” coal-fired
powerplants were required in 2000 to meet SO2 standards that are essentially
equivalent to (if not more stringent than) the 1971 NSPS for SO2. The term
“grandfathered” is essentially meaningless under such circumstances.
If the focus of debate about “grandfathered” powerplants is NOx emissions, then age of plant is
not a relevant consideration – fuel source is. Coal-fired facilities, regardless of age, are the
relevant focus of any effort to increase NOx controls. If the focus of debate about “grandfathered”
powerplants is SO2 emissions, then the title IV emissions cap is the relevant consideration. There,
age was a consideration in allocating emission credits; however, the relevant definition was not
based on NSPS compliance (or any other CAA compliance), but on whether the plant was
operational, under construction, or planned at the time of enactment. Indeed, the NSPS for SO2
for new powerplants is in some ways moot – all new sources must completely offset their
emissions under the cap as they receive no allocation of emission credits. The NSPS is effectively
zero net emissions. Thus, if reducing SO2 from electric generating facilities is the goal, shrinking
the current cap on SO2 is the most logical approach. Likewise, a cap on NOx emission is a logical
extension for reducing NOx emissions from electric generating facilities. EPA favors this
approach in addressing transported pollution programs in the Northeast where the agency has
proposed state-by-state emissions caps.
The WEPCO decision precipitated public debate and congressional oversight, and the Bush
Administration’s proposed revisions to NSR have done the same. Unlike previous efforts to
address NSR, the focus of the Administration’s proposed routine maintenance rule is not to
reduce pollution, but to facilitate electricity production. The proposed rule’s attempt to reduce
barriers to energy production by widening the definition of routine maintenance is not attached to
legislation to reduce any emissions effects. The Administration has introduced legislation to
reduce emissions from powerplants, but promulgation of its proposed routine maintenance rule is
not contingent on passage of that legislation. The Administration believes the linkage is not
critical as it believes that the definition of routine maintenance will have no effect on emissions.
Others may disagree.
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(name redacted)
Specialist in Energy and Environmental Policy
[redacted]@crs.loc.gov, 7-....
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