State and federal command-and-control regulation of emissions from fossil-fuel electric power generating plants.

I. INTRODUCTION

In 2001, the public was fed a steady diet of news stories concerning electrical energy shortages and escalating prices. California received the most attention after experiencing power blackouts, rationing, and staggering increases in annual electric power costs. (1) Some industry interests attempted to use the perception of electricity shortages to reduce the stringency of environmental laws. This effort could have been buttressed by the report of the President's National Energy Policy Group (NEPG), headed by Vice President Dick Cheney. (2) The group made at least fourteen recommendations that could impact environmental laws applicable to the fossil-fuel electric power industry. (3) However, shortly after the report was issued, Senator James Jeffords (I-Vt) left the Republican Party, which thereby lost control of the Senate. (4) The administration's ability to implement a change in energy or environmental policies was compromised by the split in the control of Congress and Senator Jeffords's position as the chair of the Senate Environment and Public Works Committee. (5) Nevertheless, environmental laws, especially the Clean Air Act (CAA), (6) will continue to be active battlegrounds because the imposed compliance costs can be an important component of the total cost of electric power. Since these costs are not necessarily imposed on the members of the electric power industry equally, their ability to compete in a deregulated market may be significantly affected by existing requirements and proposed changes to the air pollution control program.

This Article will examine the major CAA command-and-control provisions applicable to fossil-fuel electric power generators and will discuss the major initiatives designed to more stringently regulate this industry. It will not cover economic-based regulatory approaches involving emissions trading of sulfur dioxide (S[O.sub.2]) and nitrogen oxides (N[O.sub.x]), (7) and will provide only a brief discussion of global warming issues, which may result in carbon dioxide (C[Osub.2]) reduction requirements being imposed on electric power plants. (8)

II. BACKGROUND ON THE ELECTRIC POWER INDUSTRY

Environmental protection requirements imposed on fossil-fuel electric power generators by the United States Environmental Protection Agency (EPA) are subject to ongoing review because this is the industry most responsible for conventional air pollutant emissions and is a significant source category of hazardous air pollutants. Fossil fuels are used to generate about 68% of the electricity in the United States; coal is used to generate about 44% of the electricity. (9) In 1998, electric utilities emitted 67.2% of the nation's S[O.sub.2], 24.9% of N[O.sub.x], and about 10.6% of the small particulate (P[M.sub.10]) emissions,(l0) Moreover, sixty-seven hazardous air pollutants potentially are emitted from fossil-fueled electric power generating plants, and EPA predicts a 30% increase in these emissions by the year 2010. (11) In addition, about 40% of C[O.sub.2] from United States sources comes from electric power industry (utilities and nonutilities combined), (12) and domestic C[O.sub.2] emissions increased by 2.5% in 2000, which is a significant increase from the 1.3% average annual growth from 1990 to 2000. (13) The United States's emissions of C[O.sub.2] are responsible for an estimated 25% of the world's C[O.sub.2] emissions from fossil-fuel burning and cement manufacturing. (14) Moreover, increases in generating capacity are projected to increase C[O.sub.2] from the electricity sector by 14 to 38% by 2007 from the 1998 level. (15) In 1999, coal was used to generate 52.8% of the electricity generated in the United States; petroleum was used to produce 2.56%; and natural gas was used to produce 10.78% (16) The use of natural gas is projected to increase, coal use will increase more slowly, and petroleum use is expected to continue to decrease. (17) Most of the nation's coal-burning plants were constructed between 1950 and 1980, and these plants are the nation's most significant stationary source of air pollution. (18) New electric power plants almost always use gas-fired turbines because such plants are less expensive to construct, have a higher thermal efficiency, and produce far less pollution. This offsets the need for gas, which is more expensive than coal. (19)

In 2001, there were more than five thousand electric power planks in the United States. (20) However, the field is dominated by a small number of investor-owned and publicly-owned utilities. In 1995, investor-owned utilities accounted for more than 75% of retail electric power sales and revenues. Ten companies accounted for 32.61% of the revenue from investor-owned electric utilities, over $53 billion dollars. (21) Publicly-owned electric utilities accounted for about one-eighth of the revenue from electric power sales; nearly half of the publicly-owned generation sales came from ten utilities. (22) Because the electric power industry is such an important stationary air emissions source, and because it represents the most cost effective target for major reductions of N[O.sub.x] and S[O.sub.2] emissions, much of the CAA program for stationary sources is aimed at controlling this industry. (23)

The electric power industry is changing rapidly. Two laws--the Public Utility Regulatory Policy Act of 1978 (PURPA) (24) and the Energy Policy Act of 1992 (EPAct) (25)--started the move toward increased competition in the electric power industry. EPAct removed constraints on ownership of electric power generator facilities and encouraged competition in the wholesale electric power business. Consequently, on April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued two orders that encourage wholesale competition in the sale of electricity. FERC Order No. 888 (26) opened access to transmission networks by requiring any public utility that controls electric transmission facilities used in interstate commerce to provide transmission services to generators based on a tariff filed with FERC, and Order No. 889 (27) requires utilities to establish systems to electronically share information on the availability of transmission capacity. (28) In 2001, changes in FERC's composition moved the agency to a more aggressive position aimed at controlling market power in wholesale markets. (29)

Many state legislatures have moved to allow competition in the retail sale of electric power. As of March 2002, restructuring legislation had been enacted in. about half the states and the District of Columbia. (30) Other states have either pending public utility commission regulation or legislation to allow restructuring. (31) This deregulation movement slowed, at least temporarily, in the summer of 2000 when California residents experienced a massive increase in electric power costs with prices increasing from approximately $30 per megawatt hour to over $1000 per megawatt hour. (32) Initially, some people attributed this problem to environmental protection requirements. (33) However, the problem is a complex one driven by demand that can exceed supply. The market is influenced by an inadequate electric power transmission system, aging generating equipment with increasing maintenance needs, high natural gas prices, possible market manipulation by gas and electric companies, unseasonably warm weather, below average rain and snow that reduced hydroelectric supply in the Pacific Northwest, and improvident government decisions. (34) As these electricity supply problems became more acute in 2001, the movement toward deregulation was countered by demands for government intervention. After California's unfortunate experience, six states--Arkansas, Nevada, New Mexico, Oklahoma, Oregon, and West Virginia--that had begun deregulation placed the process on hold. (35) Other states, such as Delaware, Maryland, New Jersey, Pennsylvania, and the District of Columbia, continue to move toward deregulation but with additional government restrictions. (36)

Deregulation has been a factor in mergers of electric utilities, mergers of electric power companies with gas companies, utilities merging with non-electric businesses, and acquisition by utilities of assets in states and countries other than the utility's service area. (37) Non-utilities are emerging as a vibrant component of the electric generation industry moving from a 7% share of total electric capacity in 1992 to a 17% share in 1999. (38) This is being accomplished by new capacity additions and by acquiring divested utility assets. (39) Between 1998 and 1999, non-utilities installed more new capacity than utilities. (40) Nevertheless, reserve margins decreased from 33% in the early 1980s to 12% in 1999. (41) Non-utilities primarily use simple cycle gas turbines to provide electricity during peak load periods or use combined cycle untis. (42) To the extent that natural gas replaces coal as the fuel used for electric power generation, the environment benefits. Modern gas-fired turbines have no S[O.sub.2] or mercury emissions; they emit only about 15% of the N[O.sub.x] of a well regulated coal-burning plant, (43) Moreover, combined cycle gas-fired generators are more fuel efficient and achieve efficiencies of 50% compared to coal-fired plants that are about 34% efficient. (44) Deregulation is expected to have a profound effect on electric power production and its impact on the environment. (45) Moreover, the market may not become more competitive, but may result in fewer than a dozen companies generating most of the nation's electricity. (46) Thus, the government may seek to play a more aggressive role to protect the environment. (47)

In a regulated market, the costs of complying with environmental laws are passed directly through to the customers or are incorporated into the rate base of the utility. In the competitive market, the costs of compliance, which can be a significant portion of the costs of producing electricity, can affect a generating facilities profitability. However, market forces may limit the extent to which such costs are passed on to customers. (48) At this time, assessing the direction of the role of government in regulating the electric industry must wait for a clearer picture to emerge.

III. CLEAN AIR ACT COMMAND-AND-CONTROL PROVISIONS AFFECTING FOSSIL-FUELED ELECTRIC POWER PLANTS

A. The State Implementation Plan Program

1. Requirements of the SIP Program

To meet the National Ambient Air Quality Standards (NAAQS), CAA section 110 requires each state to develop a state implementation plan (SIP). (49) The SIP must include the elements set forth in sections ll0(a)(2)(A)-(M) and must be approved by EPA. If the SIP fails to meet the CAA's statutory and regulatory requirements, EPA's Administrator may reject the SIP and ultimately impose penalties; (50) and if necessary, she may promulgate a federal implementation plan (FIP). Since 1977, additional requirements for attainment areas and nonattainment areas have been imposed by the CAA's subchapter I, parts C and D. (51) These requirements were significantly expanded in the 1990 CAA Amendments and necessitated changes in SIPs to meet the new requirements. (52)

To comply with the SIP requirements, fossil-fuel electric power generating plants must meet the CAA requirements applicable to stationary sources, but due to the large portion of stationary source emissions attributable to the electric power industry, there are provisions in the CAA aimed primarily at this industry. (53) Moreover, because of the size of most electric power plants, the more stringent requirements imposed on major sources usually are applicable. In addition, CAA subchapter IV imposes on the electric power industry an emission cap and trading system for S[O.sub.2] (54) and coal-fired utility units are subject to emission limitations for N[O.sub.x]. (55)

Because the NAAQS for nitrogen dioxide (N[O.sub.2]) is almost never exceeded, EPA has not made much effort to control N[O.sub.2] as a criteria pollutant. All areas of the United States, including Los Angeles (the only area to record violations in the last decade), are in attainment of the annual NAAQS for NO[sub.2] of 0.053 ppm. (56) Areas that do not have air quality that meets the NAAQS must impose more stringent air pollution controls. There were 20.3 million people in the United States living in counties with P[M.sub.10] concentrations in 1999 above the NAAQS level. (57) There are no counties with violations of the S[O.sub.2] standard. (58) However, S[O.sub.2] emissions from coal-fired electric power plants are responsible for much of the increase in rural fine particulate (P[M.sub.2.5]) concentrations. (59)

The most significant criteria pollutant problem is ozone (O[sub.3]); 53.8 million people live in counties violating the O[sub.3] one-hour NAAQS. (60) Ozone nonattainment areas are subject to SIP revisions to meet CAA requirements. Moreover, the northeastern states, from northern Virginia to Maine, are subject to ozone transport region requirements. (61) Facilities located upwind of a nonattainment area for ozone that are in a "ozone transport region" may be subject to controls if the facility emits more than fifty tons per year of N[O.sub.x]. (62) Since 1990, O[sub.3] nonattainment areas require the use of stringent controls on Volatile Organic Compounds (VOC) and N[O.sub.x] sources. Moderate or worse O[sub.3] nonattainment areas require the use of reasonably available control technology (RACT) on existing sources. (63) For areas that are serious or worse, a 9% reduction of VOC or NO[sub.x] emissions for each three-year period from 1996 through the attainment date is required. (64) For extreme areas, additional N[O.sub.x] controls are required (65) CAA section 182(f) imposes on the states a duty to control emissions of N[O.sub.x] unless reductions would not contribute to the attainment of the ozone standard. (66) Compliance with subchapter IV is also required, (67) but this does not exempt a source from other CAA requirements. (68) Moreover, emission reductions made to comply with the acid rain program will not prevent states from imposing more stringent controls as part of their mandated SIP revisions and their subchapter V operating permit program. (69)

2. Pending Legislation Aimed at Electric Power Generators

EPA believes that over the next few years the electric power industry needs to achieve large reductions in emissions of S[O.sub.2] and N[O.sub.x]. (70) This is needed in the East primarily to reduce acid rain and ozone transport although regional haze problems also exist; (71) in the West, the major concerns are regional haze and pollution of pristine Class I areas, such as national parks. (72) Bipartisan legislation has been introduced in the Senate (73) and in the House (74) to reduce power plant NO[sub.x], S[O.sub.2], mercury, and CO[sub.2] emissions. (75) The four pollutant bills would cap N[O.sub.x] emissions at 25% of 1997 levels, S[O.sub.2] at 25% of levels permitted under the CAA's subchapter IV program, mercury emissions at 10% of 1999 levels, and C[O.sub.2] emissions at 1990 levels. (76) The President's National Energy Policy Group (NEPG) recommends that EPA work with Congress to propose legislation to significantly reduce and cap emissions of S[O.sub.2], N[O.sub.x], and mercury from electric power generators using a market-based program with caps on the three pollutants (77) EPA reportedly is considering a proposal to seek a 75% N[O.sub.x] reduction by 2012, an 80% S[O.sub.2] reduction by 2010, and an 83% reduction in mercury emission by 2012. (78) EPA's Administrator has opined that such legislation would make many of EPA's programs aimed at controlling emissions from electric power plants unnecessary. (79) This has encouraged the Clean Power Group (CPG) to propose emission reductions similar to or greater than those found in Senate Bill 556 (S. 556 or Jeffords BiU). (80) According to some proponents, strong new multi-pollutant legislation could remove the need for the section 126 program, the N[O.sub.x] SIP call, the regional haze program, and the new source review (NSR) program discussed below. (81) However, some of these programs are statutorily required (82) and others are subject to various court mandates. (83) Moreover, more stringent emission requirements could remove the need for emission trading pursuant to CAA subchapter IV because there would be few, if any, buyers. (84) However, EPA's analysis shows that multi-pollutant legislation may result in higher emissions than allowed under existing law. (85)

The bills before Congress led to industry groups developing alternative proposals. The Clean Power Group (CPG), a coalition of power marketing firms, proposed phasing in emission limits on N[O.sub.x], S[O.sub.2], and mercury. In exchange, it seeks to eliminate most air pollution programs, including NSR and the acid rain program. The Clean Energy Group (CEG), which represents utilities and energy distribution companies, calls for C[O.sub.2] regulation and a modified NSR program. The CEG approach would not impose NSR unless a facility re-powered by replacing its major components and increased the facility's emission rate. (86) Energy for a Clean Air Future (ECAF), a coalition of companies using coal for at least 50% of their generated electricity, favors voluntary C[O.sub.2] reductions and a cap-and-trade system for N[O.sub.x], S[O.sub.2], and mercury emissions. In return, most applicable CAA programs would be eliminated. (87) EPA is backing the three-pollutant regulatory approach that would impose national caps on emissions. The agency is supported by the Council on Environmental Quality (CEQ), but opposed by the Departments of Interior and Energy. (88) The EPA bill has more stringent N[O.sub.x] and S[O.sub.2] caps than the Jeffords Bill. (89) Western utilities are seeking a regional approach that would impose less stringent controls on electric power generating plants in the West. (90)

The electric power plant pollution control bills were delayed after the September 11, 2001 terrorist attacks on the World Trade Center and the Pentagon, but the Jeffords Bill was slated for November markup and floor action in 2002. (91) The Bush administration opposes the bill because of its costs and tendency to threaten fuel diversity by encouraging a switch from coal to natural gas. (92) All the Republicans on the Senate Environment and Public Works Committee opposed S.556 except Senator Lincoln Chafee (RRI). (93) The date for the markup of S.556 was moved to February 2002. (94) The United Mine Workers and the Teamsters Union are supporting the Bush administration's efforts to prevent C[O.sub.2] emission controls, which will complicate the largely Democratic Party's efforts to enact a four-pollutant bill. (95)

When the substantive air pollution requirements change, the states must revise their SIPs to accommodate new requirements. The CAA programs, discussed below, have led to numerous changes in SIPs, which can be expected to continue because the SIP is part of a dynamic air pollution control program. As of March 9, 2001, EPA had declared eleven states and the District of Columbia to be violating SIP requirements by failing to submit revisions required by the Ozone Transport Rule (discussed below). (96)

B. New Source Performance Standards for Coal-Fired Power Plants

1. Requirements of NSPS

CAA section 111, providing for new source performance standards (NSPS), was enacted as part of the 1970 CAA Amendments. (97) Plants built before 1971 are exempt from such requirements unless they are modified or reconstructed. (98) Because of the costs associated with meeting NSPS and NSR (discussed below), the CAA encourages the electric utilities to keep old plants operating. (99) NSPS becomes applicable when a stationary source begins construction or modification after proposed regulations are promulgated for a source category. (100) The evolution of the NSPS program has resulted in different requirements for construction or modification that has been commenced during different time periods. (101) Sources constructed prior to 1971 are not subject to federal NSPS, but requirements can be imposed by a state as part of its SIP. New fossil-fuel-fired steam generators that commenced construction after August 17, 1971 are subject to particulate matter, S[O.sub.2], and N[O.sub.x] limits. (102) On December 23, 1971, regulations were promulgated that limited coal-burning power plants to S[O.sub.2] emissions of 1.2 lbs/million (mm) Btu of heat generated. (103)

The 1977 CAA Amendments require a revised electric power plant standard. (104) In June 1979 EPA promulgated final NSPS. (105) The 1.2 lbs of S[O.sub.2] per mm Btu standard was retained. However, all sources, regardless of their emission rate, were required to reduce their potential S[O.sub.2] emissions by at least 70%. (106) For sources that emitted more than 0.6 lbs of S[O.sub.2] per mm Btu, reductions of at least 90% were required. (107) The regulation also limited particulate emissions to 0.03 lbs/mm Btu. (108) By requiring post-combustion removal of sulfur, the revisions made the burning of high-sulfur coal as economically attractive to utilities as burning low-sulfur coal. The effect of the revised regulations was to make the 1.2 lb/mm Btu limit irrelevant except for very high-sulfur coal because most coal scrubbed to meet a 90% reduction requirement results in emissions with less than 1.2 lbs of SO[sub.2] per mm Btu. (109) The NSPS for fossil-fuel-fired steam generators continues to require that S[O.sub.2] emissions not exceed 1.2 lbs/mm Btu heat input and also imposes percentage reduction requirements. (110) However, in the 1990 CAA Amendments, section 111(a)(1)(A)(ii), (111) which provided for the percentage reduction in S[O.sub.2] emissions, was removed from the statute. (112) The 1.2 lbs/mm Btu requirement continues to be applicable. (113)

The D.C. Circuit upheld the regulations. (114) EPA had the authority to push technology even though it had not demonstrated that the standard could be achieved with existing scrubber technology. (115) However, since much of the electric power generated from coal-burning plants was not subject to NSPS, the actual emissions from electric power plants greatly exceeded the NSPS. (116)

CAA section 111(a)(1) was changed in 1997 to require fossil-fuel-fired stationary sources to have "the best system of emission reduction that (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated." (117) The word "continuous," which previously had been placed before the word "emission," was removed in 1990. Removal of this word was considered necessary because it had created considerable litigation and had been interpreted to prevent the use of intermittent controls. However, CAA section 123 continues to prohibit intermittent controls. (118)

On July 9, 1997, EPA proposed revised N[O.sub.x] emission standards. (119) A final standard, promulgated on September 16, 1998, covered fossil-fuel-fired steam generating units built, modified, or reconstructed after July 9, 1997. (120) For electric utility boilers, the rule differentiated between new and modified units by changing from an input-based standard to an output-based standard expressed as an N[O.sub.x] limit of 200 nanograms per joule or 1.6 pounds per megawatt-hour of gross energy output based on a thirty day rolling average for new facilities. (121) EPA's emission "limits [were] based on the use of selective catalytic and selective noncatalytic reduction technologies," which the agency predicted would cost about $1500 per ton of N[O.sub.x] removed. (122) Existing electric utility boilers that were modified or reconstructed after July 9, 1997 were subject to input standards that limited N[O.sub.x] to 0.15 lbs/mm Btu. (123) On September 21, 1999, the D.C. Circuit vacated the modified boiler emission standards because the regulations were "seriously deficient." (124) On August 14, 2001, EPA withdrew its NSPS for new fossil-fuel-fired steam generating units constructed, modified, or reconstructed after July 9, 1997. The agency will require such electric utility boilers to meet the N[O.sub.x] standards in the NSPS issued in 1979. (125) This move is not very significant because new or modified electric generating facilities would usually be controlled by the requirements imposed by NSR.

2. Application of NSPS to Electric Power Plants

The NSPS program applies to new, modified, and reconstructed facilities. (126) In the past twenty years, few new coal-burning electric power plants have been constructed; existing coal-burning facilities have been maintained and repaired to keep them operational. The most important case concerning modifications to an electric generating facility is Wisconsin Electric Power Co. v. Reilly (WEPCO). (127) WEPCO is well-known because of its primary holding that allows electric utility steam generating units to determine whether a major modification has occurred by using the "actual-to-future-actual" emissions test. The case also provides guidance concerning what is routine maintenance, repair, or replacement. It should be emphasized, however, that for purposes of NSPS a modification requires an increase in the facility's hourly rate of emissions for any pollutant to which a standard applies (128) or "which results in the emission of any air pollutant not previously emitted." (129) For prevention of significant deterioration (PSD) NSR proposes a "major modification," requiring a significant net emissions increase in total annual emissions from a major stationary source. (130) For nitrogen oxides, for example, a significant increase is forty tons per year. (131) Thus, the issue of whether maintenance is routine and thus exempted from the modification or major modification designation only becomes important if emissions have increased for NSPS purposes or increased significantly for NSR purposes.

To determine whether work is routine requires EPA to make a case-by-case determination, (132) and EPA's determination is to be set aside only if it is arbitrary, capricious, or an abuse of discretion. (133) In making this determination, EPA must weigh the following factors: the work's 1) nature, 2) extent, 3) purpose, 4) frequency, 5) cost, and 6) other relevant factors. (134) Perhaps the most obvious WEPCO rule is that a company should not call its maintenance a "life extension" program. (135) Maintenance that extends the life of a source beyond its planned retirement date or beyond its designed useful life will probably be considered a modification.

The life expectancy of the WEPCO plants was fifty years, and they were placed into service between 1935 and 1950. Management had planned retirement dates of 1992 for two units and 1999 for three units; the renovation was designed to extend the plants' life expectancy until 2010. EPA found no electric utility had ever had a life extension project that approached the nature, scope, or extent of the WEPCO renovation. (136) The project's purpose was "to completely rehabilitate aging power generating units[,] ... restoring their original capacity and substantially extending the period of utilization." (137) EPA also considered that the air heaters were being replaced "in whole" by removing the entire unit. (138) In terms of frequency, the renovation included work that would occur only once or twice in a unit's expected life cycle, and WEPCO had never previously replaced a steam drum of comparable size. (139) The cost of the WEPCO project was at least $70.5 million, and while not large enough to be a "reconstruction" under EPA rules, the court held that EPA could consider the cost of this magnitude as one factor in determining that this project was not routine. (140) Overall, WEPCO is of limited use in determining when a repair is routine. WEPCO lost on the routine maintenance issue, and the facts were heavily weighted toward the work being a modification and not routine maintenance.

C. New Source Review

In the late 1990s, environmentalists were claiming that power plants more than twenty years old were the most significant source of air pollution from electric power plants. (141) The Southern Environmental Law Center, for example, reported that in the eight states in the Southeast United States there are about 375 power plants, but the twelve worst polluters who generate 17% of the region's electric power contribute 31% of the region's S[O.sub.2] emissions and 44% of the region's N[O.sub.x]. (142) The Tennessee Valley Authority's (TVA's) Paradise Power Plant had the most emissions in the region, and in 1995, it was responsible for about 5% of the SO[sub.2] and 8% of the N[O.sub.x] emitted by power plants in the Southeast. (143) EPA has responded to public pressure with an aggressive enforcement program based on NSR.

1. Requirements of NSR

NSPS is primarily a baseline for determining the applicable air pollution control technology for major new or modified sources. The NSR program aims to have modern pollution control technology installed in a prevention of significant deterioration (PSD) area when a major new source is constructed or when a modification of a major source increases emissions above threshold levels established by the NSR regulations. In nonattainment areas, NSR requirements are based on an approved SIP program that is usually more stringent than PSD requirements. The NSR program is administered by state or local air pollution authorities in accordance with NSR regulations. A state's NSR program can be incorporated into a SIP after approval by EPA, or the state may request delegation of the federal NSR program as it is written in the federal NSR regulations. (144)

The NSR program has two components: nonattainment NSR and PSD. The two subprograms have different requirements for major new or major modified sources. (145) In nonattainment areas, lowest achievable emission rate (LAER) is applicable; (146) in PSD areas, the best available control technology (BACT) is required for major sources. (147) In both situations the applicable requirements must be at least as stringent as NSPS. Thus, the NSR required for the construction or modification of major sources will usually impose a standard more stringent than NSPS. The technology for each industry that meets these requirements is found in EPA's BACT/LAER guidance, (148) but it is the permitting authority that specifies an emission limit that represents BACT.

NSR applies to major sources. For PSD areas, a major source threshold is the potential to emit one hundred tons per year of any air pollutant from stationary sources in twenty-eight listed categories. (149) Fossil-fuel-fired steam electric plants of more than 250 million Btu per hour heat input are a listed category. (150) For categories that are not listed, such as simple cycle combustion turbines, the threshold is 250 tons per year. (151) In nonattainment areas, the threshold for a major source ranges from one hundred tons per year down to ten tons per year depending on the severity of the area's air pollution noncompliance. (152) Emission limitations are triggered by a source's potential to emit, which is defined as a source's capacity to emit a pollutant when operating at maximum design capacity, except as constrained by practicable enforceable permit conditions that limit its potential to emit. (153) Modifications also require compliance with NSR if a major source increases emissions of a pollutant regulated under the CAA in an amount in excess of the regulatory significance level. (154) For most industries, the increase is measured by the difference between future potential emissions and past actual emissions. (155) The electric generating industry, however, gets a benefit based on the WEPCO rule. (156) This rule used an "actual-to-future-actual" test rather than a test based on potential emissions. (157) For nonattainment NSR, pollutants for which the area is in nonattainment must be offset. (158) The applicants must demonstrate through an alternative analysis that the benefits of the facility outweigh the environmental and social costs. (159) Then the project must be constructed or modified using LAER technology. (160)

In PSD areas, in addition to meeting BACT, the applicant must perform an air quality analysis that demonstrates the emissions will not cause or contribute to violations of any NAAQS or result in a significant deterioration of air quality. (161) Moreover, the applicant must show the project will not adversely affect air quality-related values, including visibility, that affect designated Class I areas, including wilderness areas and national parks. (162)

2. Application of NSR to Electric Power Plants

While these technology-based standards are stringent, electric utilities have continued operating old plants that never have been subject to NSR requirements. In 2000, pre-1980 electric power plants emitted about one-third of the nation's S[O.sub.2], N[O.sub.x], and PM pollution. (163) N[O.sub.x] limitations illustrate this issue. Older plants, which are primarily coal-fired, emit N[O.sub.x] at 100 to 630 ppm of exhaust volume. The NSR standards applicable to new gas-fired plants impose a 9 ppm emissions limitation, and some states impose a 3 ppm standard. (164) This results in new facilities having to control N[O.sub.x] at costs ranging from $2500 to over $10,000 per ton of N[O.sub.x] removed, while old facilities that could reduce N[O.sub.x] at a cost as low as $300 per ton are not required to do so. (165) Thus, more stringent control of old plants has become a priority for both enviroumentalists and EPA. (166) One way to accomplish this would be to prohibit a facility from "netting out" of the NSR program by reducing emissions from other existing equipment. California uses this approach to impose NSR requirements on modifications that increase emissions regardless of whether other emissions at the facility can be reduced. (167) Another approach would be to impose NSR if there is a modification of a discrete source, but impose NSR-based emission limits on the entire plant. This plantwide applicability of NSR requirements has some industry and state government support. (168)

The most obvious approach to subject old plants to the more stringent NSR requirements would be to phase out the provisions allowing facilities to be "grandfathered." This also would help remove a competitive advantage that grandfathered plants enjoy because they avoid costs associated with enviroumental protection that their competitors must absorb. On June 17, 2001, Texas enacted a law that ended the ability of about one-third of the state's industrial facilities to avoid NSR. Under the new law, grandfathered facilities in East Texas must be permitted by 2007, and those in other parts of the state must be permitted by 2008. (169) On August 7, 2001, Illinois enacted legislation aimed at eventually cutting emissions from older fossil-fuel-fired power plants. Under this law, the Illinois EPA is to issue findings about the need to reduce emissions from power plants by September 30, 2004. The Illinois EPA is then to propose rules and after they are proposed, the Illinois Pollution Control Board, which is the organization that actually promulgates environmental rules, is to act on the Illinois EPA proposed regulation within one year. (170) Thus, in about a decade, Illinois may more stringently control its most serious emissions sources.

3. NSR Enforcement

EPA is required, and a state may issue administrative orders or seek injunctive relief, to prevent the construction of a major emitting facility that does not meet the PSD requirements. (171) EPA also can act to prevent construction in nonattainment areas unless the source and the area's SIP meet the requirements of part D. (172) If a state agency receives approval to implement the PSD program, EPA can seek relief only if the state does not follow EPA-approved procedures or the applicant is violating the permit. (173) Some states have not opted to run the PSD permit program, leaving EPA the responsibility of reviewing and implementing PSD facility permits for major new or modified sources.

An interesting issue is the extent to which EPA can punish a facility constructed without the required PSD construction permit. On November 17, 1998, EPA released "NSR Guidance," which states that modifications will be more strictly defined and remedies will be aggressively pursued. (174) This guidance was based on the approach of "once in, always in" set out in its maximum achievable control technology (MACT) standards memorandum of May 16, 1995. (175) The NSR guidance was EPA's response to an obvious weakness in the CAA dealing with the interplay between the construction permit program and the operating permit program. EPA asserted that CAA violations subject an offending major source to NSR. EPA's position when resolving NSR enforcement actions is that, to effectuate the purpose of the NSR programs, the agency should generally, at a minimum, require the installation and operation of control technology or process changes resulting in emission reductions equivalent to BACT in PSD cases and LAER in nonattainment cases. When a case involves a source that failed to obtain a permit or limit at the time of construction, the source should not be allowed to avoid installation and operation of pollution control equipment or process changes by obtaining a "synthetic" minor limit (usually through a permit) after the fact unless compelling circumstances exist. (176)

According to EPA, when a source's actual emissions exceed the major source threshold, the source should be required to comply fully with all applicable NSR requirements, including major NSR permitting, control technology, air quality impact analysis, and offsets. As part of a settlement, EPA usually will seek a consent decree requiring a minimum level of control that ensures BACT/LAER-equivalent emission reductions. (177)

Moreover, EPA "has determined that it is no longer appropriate to allow a source to 'correct' an NSR violation by dismantling an illegal modification, unless emissions from the new or modified unit would essentially become zero (e.g., the entire process line was shutdown)." (178) Thus, a source generally cannot return to pre-violation conditions to avoid installation of control equipment or implementation of process changes.

EPA's NSR Guidance of November 17, 1998 explained (or changed) EPA's policy concerning violations of PSD requirements and identified the preferred minimum injunctive relief as the installation of BACT. The policy interprets the law so that nearly all violations of an operating permit or SIP by a major source are deemed to be PSD/NSR violations. This view transformed the NSR from a program that usually applied once to a facility and involved about 200 applications a year into a program applicable to about 22,000 existing major sources that periodically must undergo NSR review. (179)

On November 3, 1999, EPA initiated NSR enforcement actions against American Electric Power, Cinergy, Illinois Power, Southern Indiana Gas and Electric, Alabama Power, Ohio Edison, and TVA for alleged violations at thirty-six Midwestern and Southeastern electric power plants. (180) On November 29, 1999, the attorneys general of New York and Connecticut sued American Electric Power Company for alleged NSR violations at ten Midwest and Southern electric power plants. (181) The company replied that the allegations were without merit. (182) On March 1, 2000, EPA targeted an additional twelve coal-fired electric power plants owned by American Electric Power, Cinergy, and Southern Indiana Gas and Electric Company. (183) Other electric utilities have been the subject of an EPA-issued Notice of Violation or civil actions. (184) The Justice Department and EPA settled the case against the Tampa Electric Company in a consent decree on February 29, 2000. (185) In April 2000, EPA issued a notice of violation against Virginia Power Company's Mount Storm plant. (186) On November 16, 2000, EPA tentatively settled its NSR cases against Virginia Power for an estimated $1.2 billion. (187) On December 12, 2000, EPA tentatively settled with Cinergy when the defendant agreed to invest $1.4 billion in control technology. (188) In the same month, EPA sued Duke Energy Company for violations at eight power plants. (189) On January 12, 2001, EPA again filed suit against the Alabama Power Company for violations in Alabama. (190) The electric power industry is fighting NSR-based actions (191) and has accused EPA of attempting to change the NSR regulations through enforcement actions. (192) The impact of this enforcement activity initially had a profound effect on the electric power industry. (193) TVA, for example, challenged the administrative complaint, but it announced plans to spend $1.5 billion to install five scrubbers, stating that its actions were unrelated to the pending enforcement actions. Additionally, the NSR enforcement action subjects plants in states such as Mississippi and Florida to increased air pollution control requirements, though they are not subject to interstate transport control efforts. (194) In addition to the federal efforts, a number of Northeastern states have joined the federal lawsuits as co-litigants. (195) However, the incentive for utilities to negotiate began to diminish in 2001 as the industry waited for expected benefits from the Bush administration. (196)

On September 15, 2000, EPA's Environmental Appeals Board (EAB) issued an important opinion concerning when a physical change becomes a modification triggering the applicability of NSR and NSPS. (197) The case involved changes commonly performed by the industry as once- or twice-in-a-lifetime replacements. Such projects were designed to modernize plants by using advanced technology and to extend a plant's life by twenty or more years beyond its original expected life of thirty-five to forty years. In the September 15, 2000 EAB opinion that involved TVA, all of the projects were among the largest rehabilitations undertaken by TVA at coal-fired power plants and were handled by TVA's central office plant maintenance department, not the individual plant's maintenance department. Each of the projects cost from $2.6 million to $57.1 million and required approval of TVA's Board of Directors. (198) EAB applied a four-factor test to determine whether the exemption for routine maintenance, repair, and replacement should apply, where routine changes do not trigger NSR/NSPS. EAB looked at 1) the nature and extent of the change, 2) the purpose of the change, 3) the frequency of the change, and 4) the cost of the change. (199) Using these factors, EAB concluded TVA's changes were not routine, and thirteen of the fourteen projects were modifications triggering NSR and NSPS requirements. (200) In its conclusion, however, EAB rejected EPA's actual-to-potential test for determining whether there was an emissions increase meeting the NSR requirements for "significant net emissions increases." (201) Instead, it adopted an actual-to-projected-actual test. Among the remedies imposed by EAB, TVA is required to obtain NSR permits applying the requirements in effect at the time of the permit application, perform an audit of its coal-fired electric generating units, and remedy violations identified by the audit. On March 5, 2001, TVA asked the Eleventh Circuit to vacate the EAB decision upholding EPA's air pollution enforcement actions against the agency. (202)

This decision can be expected to have a significant impact on generators using coal-fired units. Approximately two-thirds of the coal-fired units more than twenty years old have been de-rated. (203) If these units could regain their lost capacity, they would provide approximately twenty thousand megawatts of increased capacity. (204) But this increase could not be accomplished without the risk that the newly online units would trigger NSR requirements. The potential for being subjected to NSR requirements also affects industry decisions concerning improving the fuel efficiency of electric power generation. For example, Detroit Edison proposed to replace and reconfigure the high-pressure section of two steam turbines at its Monroe Power Plant to upgrade energy efficiency. (205) Because this project would have substantially improved efficiency compared to the original design, EPA considered it a physical change under its NSR regulations, and a resulting significant increase in emissions would subject the units to NSR. (206)

Another example involves using combined heat and power (CHP) units to replace existing industrial boilers to provide steam to the industrial facility and electricity to the public. CHPs emit significantly fewer emissions than the existing boilers they replace, but electric power companies allege that NSR regulations prevent facilities from upgrading their plants. (207) Still another example is a proposed Duke Power project that involved the installation of inlet air foggers on combustion turbines (CTs) to increase power output during periods of high ambient temperatures. (208) Foggers allow combustion of additional fuel and, thus, greater power output at the same ambient temperature. Under NSR regulations, the project was considered a physical change and appropriate safeguards were required to ensure that the emissions did not significantly increase as a result of the change. Industry claims this decision makes it more difficult to use the foggers and increase the output of existing units. (209)

4. Political Review of EPA's NSR Enforcement

EPA's aggressive use of its NSR enforcement authority is a political issue. (210) NEPG recommends that EPA, in consultation with the Department of Energy, "review NSR regulations, including administrative interpretation and implementation, and report to the President within ninety days on the regulation's impact on investment in new utility and refinery generation capacity, energy efficiency, and environmental protection." (211) NEPG's report, however, provides no additional information concerning the effect, if any, of NSR requirements on electric power generators, nor does it indicate what, if anything, should be done to change the NSR program.

In response to the NEPG recommendation, on June 22, 2001, EPA issued its NSR 90-Day Review Background Paper, which provides information on the electricity-generating and petroleum-refining industries, but offers no conclusions or recommendations. (212) The report does, however, provide NSR cost data. For new coal-fired units in PSD areas, capital costs constitute 20% to 27% of total construction capital costs, and annual generating costs comprise 23% to 27% of total generating costs. (213) For combined-cycle units, costs are much lower--2% to 5% of capital construction costs and 5% to 14% of total annual generating costs. (214) For nonattainment areas, new coal-fired capital costs for NSR are about 24% to 27% of total construction capital costs; annual pollution control expenditures are about 27% to 31% of total annual generation costs. (215) For combined-cycle units, capital costs for NSR are 1% to 14%, and annual generating NSR costs are 5% to 17% of the total annual generating costs. (216) The Department of Justice conducted a separate review of NSR enforcement actions (217) and on January 15, 2002, concluded that EPA's NSR-based enforcement actions were consistent with the CAA. (218)

In October 2001, President Bush was considering uncoupling NSR reforms before proposing new emissions controls for electric utilities, but the administration has not agreed to a specific action. (219) On October 15, 2001, EPA announced the availability of draft guidance designed to help electricity cogenerators avoid NSR requirements. (220) EPA is now considering plantwide emission limits as an alternative to NSR. (221)

D. Control of Toxic Air Pollutants

1. Regulation of Hazardous Air Pollutants

The 684 coal-fired electric power plants in the United States emit trace amounts of sixty-seven air toxics, (222) according to a 1998 EPA report required by CAA section 112(n)(1)(A). (223) Toxic air pollutants are defined as those "pollutants known to cause or suspected of causing cancer or other serious human health effects or ecosystem damage." (224) Of the thirty-three chemicals listed for control under EPA's Urban Air Toxics Strategy, most are emitted from fossil-fuel electric generating plants. (225) According to EPA, most of the inhalation health risk comes from arsenic and chromium emissions, but the agency also is concerned about mercury and dioxins emissions. (226) For oil-fired utilities, nickel creates the greatest inhalation risk. (227) Mercury emissions are considered the most significant pollutant for multi-pathway analysis because they bioaccumulate in the food web. (228)

The CAA has an extensive regulatory program to control hazardous air pollution emissions, (229) based primarily on CAA section 112. (230) When fully implemented, emissions standards will apply to eighty-two stationary source categories. (231) National emission standards for hazardous air pollutant source categories are found at 40 C.F.R. part 63, but no regulation covering fossil-fuel electric-power generators has been promulgated.

The Emergency Planning and Community Right-to-Know Act of 1986 (232) contains reporting requirements for its Toxic Release Inventory (TRI) that can be expected to affect the political pressure to regulate electric power plant emissions of toxic pollutants. (233) In May 1997, electric power companies first became subject to TRI reporting requirements. (234) They were required to report for 1998 by July 1, 1999, and the submitted reports showed electric power plants were significant sources of some listed substances. (235) Litigation by three electric power companies to avoid TRI reporting failed when a motion for summary judgment was denied by the D.C. District Court. (236)

2. Controlling Mercury Pollution in the Electric Power Industry

Most of the recent effort aimed at the electric power industry has focused on the control of mercury. The CAA required EPA to study mercury emission from electric utility steam-generation units and report to Congress by November 15, 1994 as a prerequisite to regulation. (237) In 1998, EPA reported that coal-fired utility boilers were the largest single source of mercury emissions in the United States and accounted for one-third of the estimated 158 tons of mercury released annually. (238) Mercury from coal-fired electric utility steam-generation units was the hazardous air pollutant (HAP) of greatest concern.

In 1998, EPA agreed to submit to the D.C. Circuit Court of Appeals, by December 15, 2000, a decision as to whether the agency would regulate mercury emissions from electric utilities under the CAA. (239) EPA then issued a CAA section 114 request to the industry requesting coal data for 1999, and some units were required to supply stack test data on HAP emissions. EPA also evaluated mercury control performance. (240) Industry opposition to controls on mercury emissions was based on the absence of any cost-effective technology for controlling mercury emissions. (241) However, it has been argued that emissions could be reduced at utilities by using low-mercury coal. (242) In 1996, the Department of Energy had estimated mercury controls could be as high as $10.4 billion per year. (243) In 1997, EPA estimated that mercury control costs were $5 billion per year. (244) In 1999, EPA lowered its cost estimate to $1.9 billion per year to reduce mercury emissions from electric power plants by 65%. (245) This could be accomplished by using carbon-injection technology coupled with spray cooling and the use of fabric filters in a baghouse. Industry, however, said this technology has never been tested on a large-scale project. EPA then indicated control costs could be further reduced to between $1.68 billion and $1.87 billion annually by combining the technology with an industry wide "cap and trade" system that would allocate emissions using a tradable allowance system similar to that used for S[O.sub.2] trading. (246)

On September 6, 2000, the Northeast States for Coordinated Air Use Management (NESCAUM) issued a report concluding that the technology to dramatically reduce mercury emissions from power plants could be rapidly deployed if required by EPA. (247) The National Academy of Sciences (NAS) conducted a study of the health effects of methyl mercury and reported its findings in July 2000. (248) According to NAS, mercury from power plant emissions changes into "methyl mercury which is a highly toxic, more bioavailable form that biomagnifies in the aquatic food chain (e.g. fish)." (249) The health effect of greatest concern is created by the consumption of mercury-contaminated fish by women of childbearing age. (250) Mercury emissions from electric utilities "comprise a substantial portion of the threat ... to public health and the environment." (251) This led EPA, on December 14, 2000, to issue a Notice of Regulatory Finding pursuant to CAA section 112(n)(1)(A) "that regulation of coal- and oil-fired electric utility steam generating units for HAP is appropriate and necessary." (252) EPA found that mercury can be effectively removed from the exhaust gas stream using oxidizing agents or sorbents injected into the gas stream. Moreover, control of mercury as part of a multipollutant control program (e.g., N[O.sub.x], S[O.sub.2], and PM) reduces mercury control costs significantly. (253) While EPA considers mercury to be the HAP in need of regulation, it also considers dioxins, hydrogen chloride, and hydrogen fluoride to be additional candidates for regulatory control. (254)

On February 20, 2001, the Edison Electric Institute filed a petition with the D.C. Circuit seeking a review of EPA's determination to regulate mercury. (255) The Utility Air Regulatory Group also filed a petition with EPA to reconsider its determination, (256) and filed a separate case seeking review in the D.C. Circuit. (257) In July 2001, the U.S. Geological Survey released information that mercury released within the last few years primarily from coal-burning utilities and incinerators were the largest contributors to mercury in fish, water, and sediment. (258) EPA expects to promulgate mercury regulations by 2003, which are to be implemented by 2005. (259) On July 26, 2001, the D.C. Circuit ruled that EPA's regulatory determination, in December 2000, to control mercury emissions from coal- and oil-fired power plants was not subject to judicial review. (260) However, the Earthjustice Legal Defense Fund is suing EPA for failure to issue a variety of regulations required by CAA section 112, including MACT standards, under section 112(e), and persistent pollutants, such as mercury, under section 112(c)(6). (261) In Congress, the Senate Environment and Public Works Committee is considering a four pollutant bill to regulate mercury, S[O.sub.2], N[O.sub.x], and C[O.sub.2]. (262) The House is also considering proposed legislation. (263) The Department of Energy, however, opposes the mercury provisions. (264) At the state level, Wisconsin's Department of Natural Resources was considering regulating mercury emissions in June 2001; if this were to occur, Wisconsin would be the first state to target mercury sources, including coal-fired electric power plants. (265)

At the end of 2001, no action had been taken to regulate mercury. The discussion had turned to whether, for the purpose of developing MACT standards, coal should be categorized based on its content of elemental and non-elemental mercury and its chlorine content. Elemental mercury is harder to control, but does not settle near its emission point. Non-elemental/ionic mercury is produced by bituminous coal and settles locally. Chlorine in the coal also becomes a pollutant, but chlorine binds with mercury and makes it easier to remove the mercury. Powder River Coal, for example, burns cleaner because it has a lower chlorine content, but its elemental mercury is more difficult to remove. (266)

E. N[O.sub.x] Control Under Title IV

Electric utilities in 1980 accounted for 30% of total N[O.sub.x] emissions; in 1998 they were responsible for about one-quarter of United States N[O.sub.x] emissions. (267) Approximately 80% of electric utility N[O.sub.x] emissions come from coal-fired plants of the type regulated by section 407 of the CAA. (268)

1. The N[O.sub.x] Program

Since the 1990 CAA Amendments were enacted, there has been increased concern for controlling N[O.sub.x] emitted from fossil-fuel-fired boilers. N[O.sub.x] can be controlled using combustion controls or post-combustion controls. Combustion controls focus on the "three T's" of combustion--temperature, time, and turbulence. By reducing flame temperature, the residence time of fuel or fuel/air turbulence N[O.sub.x] formation can be minimized. (269) Controls used to prevent N[O.sub.x] formation during combustion include low-N[O.sub.x] burners (LNBs), reburning, overfire air (OFA), flue gas recirculation (FGR), and modifications to the "three T's." (270) Selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) are forms of post-combustion controls. (271) An alternative approach would be to invest in new, combined cycle natural gas power plants and to encourage cogeneration. However, existing N[O.sub.x] control policies do not encourage a transition to more fuel efficient and less polluting alternatives. (272) The 1990 CAA Amendments created a rate-based control program for N[O.sub.x] (273) that was the first generally applicable N[O.sub.x] regulation for existing electric power plants.

Using 1980 as the base year, the N[O.sub.x] provisions are designed to achieve an approximate two million ton reduction in annual N[O.sub.x] emissions by 2000. (274) The N[O.sub.x] program does not use allowances, but rather aims to reduce N[O.sub.x] emissions through improved control technology. (275) This program does impose the $2000 per ton penalty, adjusted for inflation, on excess emissions. (276)

By May 15, 1992, the Administrator was to set annual allowable emission limitations for N[O.sub.x] for each type of boiler. (277) Emission rates may not exceed 0.45 lb/mm Btu for tangentially fired boilers and 0.50 lb/mm Btu for dry bottom wall-fired boilers (other than units applying cell-burner technology). These are called Group I boilers and their emissions are considered easier to control than Group II boilers. Group II comprise wet bottom wall-fired boilers, cyclones, cell burners, and all other types of utility boilers that are not in Group I. (278) Group I or II boilers may be Phase I or Phase II boilers depending on the time they are subject to emission limitations. The time for compliance is the same as for the S[O.sub.2] control program. (279) Phase I units are subject to these requirements after January 1, 1995. (280) By January 1, 1997, EPA was to establish emission limitations for all other types of utility boilers. (281) These Phase II boilers were to comply with the applicable requirements by January 1, 2000. In addition, EPA was to promulgate revised NSPS by January 1, 1994, under CAA section 111, for N[O.sub.x] emissions from fossil-fuel-fired steam generating units from both electric utility and nonutility units. (282)

An N[O.sub.x] limitation that is less stringent may be authorized if the operator demonstrates that the applicable emissions limitation cannot be met using the requisite low N[O.sub.x] burners technology or other technology upon which the emission limitation was based. A compliance extension is also possible if the required technology is not immediately available. (283) An owner of two or more units subject to N[O.sub.x] emission limitations may comply by using the average emission rate of all the units. (284)

2. EPA's N[O.sub.x] Regulations

On October 27, 1992, EPA released two N[O.sub.x] related proposed rules. (285) On March 22, 1994, EPA published the final N[O.sub.x] rule (286) that the CAA required to be published by May 15, 1992. (287) The final rule included "overfire air" as low-N[O.sub.x] burner technology. Both tangentially fired boilers and dry bottom boilers were to use this technology by January 1, 1995, if they exceeded N[O.sub.x] emissions set by the CAA. This rule affected about 180 plants. (288) The final rule was challenged by the Alabama Power Company and the National Coal Association. The court was asked to decide whether low-N[O.sub.x] burner technology includes overfire air technology. The petitioners argued that requiring overfire air was an interpretation more stringent than intended by Congress. The D.C. Circuit, in Alabama Power Co. v. EPA, (289) agreed in its November 1994 decision, saying low-N[O.sub.x] burner technology did not include overfire air. (290) In January 1995, EPA proposed a settlement of the remaining issues in litigation including the agency's rules requiring reductions in emissions of N[O.sub.x]. (291)

On April 13, 1995, in response to the court's remand, EPA issued another final rule that revised the definition of low-N[O.sub.x] burner technology to comply with the court's decision. (292) It set emission limits for all Phase I and Phase II dry bottom wall-fired and tangentially fired boilers (Group 1) in the United States that combust coal as a primary fuel. Other changes included new requirements for compliance extensions for Phase I N[O.sub.x] emission limitations, new requirements for alternative emission limitations (AEL), and changes in the provisions concerning averaging of N[O.sub.x] emissions from two or more units. In general, the regulatory changes reduced compliance requirements, extended the compliance date, and increased compliance flexibility. The revisions were estimated to reduce N[O.sub.x] emissions by 1.54 million tons annually by the year 2000. EPA approved compliance plans on August 11, 1995, under which units must comply with the applicable emission limitations under 40 C.F.R. section 76.5 (the "standard emission limitations") or with a N[O.sub.x] averaging plan under 40 C.F.R. section 76.10. Plants in Pennsylvania, Ohio, and Wisconsin were covered. (293)

The Phase I standards applied to 265 coal-fired electric power producing units. The rate limits were met by 178 units using low-N[O.sub.x] burners. Less stringent alternative emissions limits were granted to ten units, twenty-three met the requirements without modification, and the remaining units complied using the statute's averaging provisions. (294) Emissions can be expected to rise with increased electric power production because N[O.sub.x] emissions are not capped. (295) However, for electric utilities in the East, N[O.sub.x] emissions also are subject to the controls to abate interstate air pollution transport.

On December 19, 1996, EPA promulgated a final rule for its Phase II nitrogen oxides emission reduction program. (296) This rule implemented CAA section 407(b)(2), which applies to N[O.sub.x] emissions for Group I and II boilers after January 1, 2000. The rule established N[O.sub.x] emissions limitations on a pounds per million Btu annual average basis. (297) EPA concluded that low-N[O.sub.x] burner technology was available for Group I boilers beginning in the year 2000. Therefore, EPA set an emission standard of 0.46 lb/mm Btu based on that technology for dry bottom wall-fired boilers and 0.40 lb/mm Btu for tangentially fired boilers. (298) The agency also set emission limitations for various types of Group II boilers. (299)

The revised N[O.sub.x] emission limits for Group I and II Phase II boilers were challenged by electric utilities and industry groups in the D.C. Circuit. On February 13, 1998, the court upheld the bulk of the challenged rule based on its finding that EPA had not exceeded its authority and the court's deference to the agency concerning judgments on scientific and technical matters. (300) The court, however, did remand to EPA for reconsideration or a more adequate justification on the portion of the final rule that reclassified certain retrofitted cell-burner boilers as wall-fired boilers. (301) On May 1, 1998, EPA formally removed the remanded provision from the final rule. (302) EPA then revised its regulations to treat as a cell-burner boiler any boiler constructed as a cell-burner boiler and converted to the burner configuration of a wall-fired boiler. (303) Only one boiler was expected to be affected by the revision. (304)

On January 29, 2001, American Electric Power announced plans to control N[O.sub.x] at two of its coal-fired plants in West Virginia with selective catalytic reduction but using urea that is converted to ammonia instead of ammonia. (305) On June 21, 2000, WEPCO announced it would make major reductions in air emissions from five of its coal-fired plants by using low-N[O.sub.x] burners, overfire air, SNCR, and SCR. (306) On August 17, 2000, EPA issued a notice of its preliminary draft of pending guidance on BACT for N[O.sub.x] Control on Combined Cycle Turbines. (307) SCR has been considered BACT for many natural gas combined cycle turbines, but EPA is now considering a more case-specific determination of what is BACT. (308)

3. N[O.sub.x] Program Favors Old Electric Power Plants

These technology requirements to control N[O.sub.x] result in a bias toward old dirty coal-fired plants. Old sources are subject to standards set at 0.45 to 0.50 lb/mm Btu, but new plants must meet a 0.15 lb/mm Btu standard. Some old units, however, emit at levels as high as 2.0 lbs/mm Btu. (309) Existing oil-and gas-fired plants are subject to an emission limit of 0.20 to 0.30 lb/mm Btu. (310) New gas-fired facilities are subject to state standards as low as 0.02 lb/mm Btu, which is an order of magnitude more stringent than existing oil and gas facilities and two orders of magnitude more stringent than some old units. (311) This discourages investment in new equipment. (312)

F. Tall Smokestacks

1. Use of Dispersion Techniques to Meet CAA Standards

Under the CAA of 1970, EPA permitted states to allow the use of tall stacks and other dispersion techniques in lieu of emission limitations. (313) Thus EPA's policies concerning smokestack parameters encouraged long distance transport of acid-producing chemicals emitted from stationary sources. In 1974, in Natural Resources Defense Council, Inc. v. EPA, (314) the Fifth Circuit held that Georgia's SIP, which allowed dischargers to avoid stringent emission limits by constructing high smokestacks to disperse pollutants, was inconsistent with CAA section 110(a)(2)(E). (315) In Train v. Natural Resource Defense Council, Inc. (316) one of the first air pollution cases to reach the United States Supreme Court, the Court allowed each state to select whatever mix of controls it desired and held that a state has considerable freedom to design a SIP as long as it provides for attaining the NAAQS. (317) The Court, however, was ambiguous on the use of dispersion techniques, such as tall smokestacks, and subsequently several federal appellate courts indicated a belief that CAA section 110(a)(2)(E) requires maximum reliance on emission controls before either dispersion techniques or intermittent controls may be used. (318)

On January 6, 1976, EPA promulgated guidelines on the role of tall smokestacks, allowing their use where BACT was used or where not using tall smokestacks would be economically unreasonable or technologically unsound. (319) Industry had already opted to construct tall smokestacks to avoid the need to install more effective, but more expensive, air pollution controls. In 1970, there were only two smokestacks in the United States higher than five hundred feet. (320) By 1985, there were more than 180, with 23 over 1000 feet in height. (321) Moreover, industry adopted the practice of venting more than one combustion unit to a smokestack, which increased the exhaust gas temperature and, consequently, the height of the stack plume. (322)

In 1977, Congress expressed antipathy to both the use of intermittent or supplemental control systems (323) and high smokestacks. (324) For purposes of SIP development, high smokestacks were not banned, but a new section 123 limited the height of a smokestack to a height consistent with "good engineering practice" (GEP) and prohibited crediting SIPs with benefits derived from dispersion techniques. (325) The effect was to adjust SIPs mathematically to remove benefits derived from tall smokestacks and dispersion techniques. CAA section 302(k), defining "emission limitation," excluded intermittent controls by requiring emission limits to be continuous. (326)

EPA promulgated proposed regulations to implement section 123 on January 12, 1979. (327) Stack heights for calculation of emissions could not exceed GEP, which usually meant that a smokestack could not exceed two-and-a-half-times the height of the facility. The GEP approach was initially upheld by the D.C. Circuit in Alabama Power Co. v. Costle. (328) This lawsuit challenged the GEP approach used for modeling emissions from tall stacks based on regulations promulgated on November 3, 1977. (329)

EPA issued the 1979 proposed regulations without changes as final regulations on February 8, 1982. (330) The Natural Resources Defense Council (NRDC) and the Sierra Club challenged these regulations. The D.C. Circuit held that, based on the legislative history of the CAA, Congress had limited the use of intermittent controls as well as credit for excessive stack height and dispersion techniques. (331) Three reasons were set forth:

   First, dispersion techniques do not reduce the amount of pollution ... but
   merely spread it ... to other areas.... Second, the long-range transport of
   certain pollutants was ... linked to the formation of "acid rain"....
   Third, intermittent control systems, which are dependent on synchronizing
   plant operation with weather conditions, were thought to be unreliable and
   virtually impossible to enforce. (332)

In the 1982 final regulations, the GEP height was based on a two-and-a-half-times height formula for regulated stacks constructed before January 12, 1979. (333) After January 12, 1979, a formula of height plus one-and-a-half-times the lesser of height or width was to be used for GEP calculations. (334) The court upheld some provisions of the stack height regulations, but reversed others, and remanded still other provisions to EPA for further action. (335) The end result was that the tall stacks constructed before the change in the law avoided meaningful regulation.

On July 8, 1985, EPA promulgated new final regulations for CAA section 123. (336) Seventeen years after CAA section 110 presented issues concerning the use of tall stacks to avoid air pollution controls, and more than ten years after CAA section 123 was enacted, NRDC sued again. Once again, some aspects of the regulations were remanded, although most of the rule was upheld. (337) NRDC argued that it was impermissible to build a high stack to avoid excessive concentrations of emissions at ground level caused by atmospheric downwash from nearby structures or terrain unless the source was equipped with all feasible emission controls. (338) The court held that existing or SIP-required emission rates are the baseline that can be used to support within-formula stack height increases. (339) Therefore, existing plants with greater emissions than those allowed from new sources can use the high ground level concentrations of air pollution that result from high emissions to justify increases in stack height above the height normally allotted by GEP regulations.

The court, however, did require EPA to reconsider its decision to exempt an emission source from the requirements of 1985 stack height regulations under the CAA if the company raised its smokestack heights within the limits of GEP before October 1983. (340) The court objected to this exemption because EPA did not require the parties responsible for exempted sources to show reliance on the prior regulatory policy before they increased smokestack heights. (341) As a result of this opinion, EPA had to redraft regulations affecting emission limits for S[O.sub.2] at over two hundred power plants. (342)

The use of tall smokestacks, which resulted in an increase in the adverse affects of air pollution, should never have been approved by EPA. Congress tried to curb the use of tall stacks in 1977, but a decade later the regulations were still tied up in litigation. The importance of stack heights has been reduced by the 1990 CAA Amendments, especially CAA subchapter IV. (343) Controls are now to be imposed on all sulfur emissions from electric power plants. As a result, EPA has not promulgated new regulations. (344)

2. International Air Pollution

Tall stacks led to the long distance transport of air pollutants, which has an adverse effect on Canada. CAA section 115 deals with international air pollution. (345) If the EPA Administrator finds that air pollution may reasonably be anticipated to endanger public health or welfare in a foreign country, and the Administrator determines that the foreign country has essentially the same air pollution limits as are applicable in the United States, then EPA must promulgate rules to prevent the harm. (346)

In 1985, Northeastern states and national groups sued in D.C. district court to prevent emissions that caused acid rain in Canada, basing their suit on CAA section 115. In New York v. Thomas (Thomas 1), (347) the court granted summary judgment and ordered EPA to issue SIP revision notices to force states to act to protect Canada from the effects of acid rain. (348) The D.C. Circuit upheld the lower court decision. (349) However, the district court had said EPA could make a new determination of reciprocity. (350) In October 1985, EPA's Administrator Lee M. Thomas found that reciprocity continued to exist. (351) The D.C. Circuit reversed, holding that the original findings of endangerment and reciprocity by the prior Administrator, Douglas Costle, were rules under 5 U.S.C. section 551(4) of the Administrative Procedure Act (APA), (352) and, therefore, notice and comment procedures were required to change them. (353) The D.C. Circuit required the plaintiffs to file rulemaking petitions with EPA before they could bring a lawsuit to compel EPA to reduce emissions. (354) A petition for rulemaking was filed with EPA in April 1988 and was denied in October 1988. (355) EPA based its denial on a claimed lack of knowledge as to whether U.S. emissions are causing acid rain in Canada. (356) Nine states, the province of Ontario, and environmental groups brought suit in federal court in November 1988 seeking to reverse EPA's decision.

In 1990, the D.C. Circuit once again upheld EPA's unwillingness to protect Canada, saying that EPA was not obliged to promulgate endangerment and reciprocity findings until it was able to determine specific pollution sources. (357) The court was willing to accept EPA's claim that the endangerment could not be correlated to sources of pollution. Congress, however, had no difficulty in making such a determination, and in the 1990 CAA Amendments, it required 110 specified electric power plants to reduce emissions of S[O.sub.2]. (358) Thus, the 1990 subchapter IV program with its sulfur and nitrogen oxides reduction provisions is now the most viable program for reducing both interstate and international air pollution from domestic stationary sources.

On March 13, 1991, the United States and Canada made an executive agreement to deal with acid rain. (359) Under this agreement a bilateral Air Quality Committee was established to review progress and submit periodic reports to the governments. (360) On April 7, 1997, a new agreement was signed to address transboundary air pollution, but it had no specific targets or deadlines. (361) In June 1998 the United States and Canada endorsed a timetable and strategy for addressing ground-level ozone and particulate matter. (362)

G. Interstate Air Pollution Control

1. CAA Provisions Governing Interstate Air Pollution

Since 1970, the application of the CAA's subchapter I primarily has been focused on achieving local ambient air quality standards, but there are some exceptions. (363) The 1970 CAA Amendments required the SIP to "insure that emissions of air pollutants from sources located in any air quality control region will not interfere with the attainment or maintenance of such primary or secondary standard in any portion of such region outside of such State or in any other air quality control region." (364) This provision continues, with slightly different wording, as CAA section 110(a)(2)(D), which prohibits stationary sources from emitting air pollution that prevent any other state from meeting a NAAQS or that would interfere with another state's SIP provisions conceming PSD or visibility measures. (365)

Section 110 does not enable EPA to force a particular control measure on the states. (366) CAA section 110(k)(5) allows the EPA Administrator to require the revision of any SIP that it finds inadequate to attain or maintain a NAAQS. (367) Emissions from small sources, if significant when combined with emissions from other sources in an upwind area, can be included in a section 110(k)(5) SIP call. (368) Only federal standards, not more stringent state standards, can be enforced as an interstate pollution abatement effort. (369)

Section 126 is the other CAA provision designed to prevent adverse impacts on downwind states from air pollutants traveling from upwind states. (370) EPA in the past was reluctant to use this provision, and it has not been an effective air pollution control tool, but it is now becoming important. (371) From 1977 to 1998, EPA never granted a petition filed under section 126, nor did it disapprove a SIP revision due to inadequate control of interstate air pollution transport. (372) Pennsylvania, New York, and Maine petitioned EPA pursuant to CAA section 126 alleging violation of NAAQS and impairment of visibility of their air because of S[O.sub.2] emissions released in seven midwestern states. After extensive proceedings at EPA on the three petitions and an eleven-month comment period that ended in May 1982, the three petitioning states sued seeking an order requiring EPA to rule on the petitions. (373) The D.C. district court, on October 5, 1984, required EPA to make a decision on the petitions within sixty days. (374)

On December 10, 1984, EPA published a denial of each state's petition. (375) The states then appealed, and the D.C. Circuit denied relief to the states in a decision that interpreted section 126 to make it very difficult for a state impacted by interstate transport of pollutants to use the provision. (376) For example, the court required the complaining state to show by monitoring data that violations of NAAQS occurred, but at the same time gave deference to EPA's models that showed no violation of NAAQS. The D.C. Circuit also construed section 126 to require focusing on major sources within an emitting state rather than reviewing broadly the upwind states's emissions. (377)

In the 1990 CAA Amendments, Congress modestly expanded the scope of section 126 by adding "group of stationary sources" to the sources subject to the section's requirements. (378) The scope of CAA section 110(a)(2)(D) was also expanded to prohibit air pollution that "contribute[s] significantly" to nonattainment rather than the more limited "prevent attainment" language used prior to 1990. (379) Section 126(c) provides that a major new or modified source may not violate CAA sections 110(d)(2)(D)(ii) or 126 after EPA's Administrator makes a finding that violations have or will occur. (380) States or political subdivisions may petition for such a finding, and the Administrator must act on the petition. (381)

No major new or modified source may be constructed or operated in violation of sections 126 or 110. If an existing source is to operate more than three months after the Administrator has makes a section 126(b) finding, it must comply with the emissions limitations and compliance schedule imposed by the Administrator as required by section 110(a)(2)(D)(ii); compliance may be extended for up to three years after the date of the finding if the source complies with emission limitations and compliance schedules. (382)

2. The Ozone Transport Problem

The 1990 CAA Amendments also created the Ozone Transport Commission (OTC) to coordinate the planning to reduce air pollution in the twelve northeastern states from Maine to the northern counties of Virginia plus the District of Columbia. (383) In 1994 OTC developed a Memorandum of Understanding (MOU) requiring each state to lower its emissions. All OTC states except Virginia adopted the MOU. (384) Massachusetts led the way by moving to develop a state emissions allocation and trading plan for N[O.sub.x] reduction, and officials on July 26, 1996, announced a plan to reduce N[O.sub.x] emissions 15% by 1999. The plan involved twenty-three of the state's largest utilities and created a permanent cap on N[O.sub.x] emissions. The sources were to determine how to reduce emissions in a cost-effective way using a trading mechanism that allows companies to buy or sell N[O.sub.x] allowances. (385) In 1996, New York challenged an EPA exemption from N[O.sub.x] controls given to four midwest states. (386) On March 18, 1997, NESCAUM released a report saying the northeastern states would not succeed in meeting ozone NAAQS unless Midwest sources of NO[sub.x] reduced their emissions. (387)

In the mid-1990s, the northeastern states began to aggressively push for more effective controls over the midwest states' N[O.sub.x] emissions. In 1995, the Environmental Council of States (ECOS) recommended the formation of a national work group to develop a consensus solution to the ozone transport problem. (388) This led to the creation of the Ozone Transport Assessment Group (OTAG), whose membership included EPA, thirty-seven eastern and midwest states and the District of Columbia, industry representatives, and environmental groups. OTAG developed "the most comprehensive analyses of ozone transport ever conducted." (389) This work eventually led to EPA's proposed rule (390) and final rule (a.k.a. SIP call), which requires twenty-two states and the District of Columbia to submit SIP revisions to achieve specified quantities of NO[sub.x] reduction in the eastern half of the United States. (391)

On August 14, 1997, EPA received section 126 petitions from Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, and Vermont seeking relief from N[O.sub.x] emissions allegedly coming from as far as Louisiana in the Southwest, Georgia in the Southeast, and as far west as Minnesota. (392) The petitions targeted different geographic areas in the eastern United States. All the petitions identified electric power generating plants as a source category, but they varied concerning the other industrial categories identified. Some petitions identified specific electric power plants. (393) The petitions also varied regarding the remedy requested. (394) On October 6, 1997, a group representing Midwestern electric utilities filed suit in the D.C. Circuit Court of Appeals (395) challenging EPA's authority to regulate electric power plants based on petitions filed by northeastern states under CAA section 126. (396)

The eight states petitioning EPA under section 126, on February 25, 1998, filed a complaint in the Southern District of New York to compel the agency to act. (397) EPA and the state petitioners reached a settlement agreement on the section 126 suit that was published on March 5, 1998, with a request for comments. (398) EPA published an advance notice of proposed rulemaking on April 30, 1998, that met the first milestone in the Proposed Consent Decree. (399) On October 21, 1998, EPA released its notice of proposed rulemaking (NPRM) concerning the section 126 petitions. (400) The NPRM stated that portions of the petitions were technically meritorious, but EPA proposed to act at a later date after the states had the opportunity to reply to its planned SIP call. The NPRM went on to describe the schedule and conditions that would trigger findings of applicability and the proposed requirements that would apply; it proposed to deny certain petitions, in whole or in part. (401) As part of the proposed section 126 rule, EPA proposed a federal N[O.sub.x] trading program. (402) This is a market-based system with caps on emissions from upwind states from certain sources that involves aggregating the source allocations in each state for units that are required to participate in the N[O.sub.x] trading program either as part of the section 126 remedy or as part of the FIP. (403) This "cap-and-trade" program would be used to meet the state's N[O.sub.x] emissions budget. (404)

3. EPA's "SIP Call"

On October 27, 1998, EPA promulgated a "SIP call." (405) The rule, which became effective on December 28, 1998, applies to facilities in the eastern United States. (406) The covered area includes Alabama and Georgia in the South, north to Massachusetts, and west to Wisconsin, Illinois, and Kentucky. (407) The rule subjects twenty-two states and the District of Columbia to its requirements, which makes it applicable to more states than the section 126 rule. (408) The rule requires SIP revisions to meet the requirements of section 110(a)(2)(D)(i)(I) in order to prevent, N[O.sub.x] emissions in amounts that "contribute significantly to nonattainment in, or interfere with maintenance by," a downwind state. (409) SIP revisions were to be submitted by September 30, 1999, projecting N[O.sub.x] reductions that met the N[O.sub.x] emissions budget specified in the rule. (410) EPA's SIP call did not change the N[O.sub.x] requirements under CAA subchapter IV, which continue to apply. (411) EPA subsequently proposed a FIP to be used if a state fails to revise its SIP in a manner satisfactory to the agency. (412) By early 1999, at least twenty-nine lawsuits had been filed challenging the regulation, including nine petitions from states. (413)

EPA developed an N[O.sub.x] budget for the states based on an emissions limit of 0.15 lb of N[O.sub.x] per mm Btu heat input for electric generating units (EGU) and reductions of 60% from non-EGU boilers and turbines with emissions of one or more tons per day. Stationary internal combustion engines are to reduce emissions by 90%. Cement manufacturing plants are to provide reductions of 30%. (414) The new rule required that states reduce N[O.sub.x] from electric generating units by 77% in West Virginia, 73% in Illinois, 71% in Missouri, and 70% in Ohio. (415) Seventeen of the twenty-three jurisdictions subject to the rule must reduce emissions by 50%. (416) Only the District of Columbia and Rhode Island, of the jurisdictions subject to the rule, will not have to cut emissions; they will, however, be subject to an N[O.sub.x] emissions budget. (417)

The state budgets required an overall 28% reduction in N[O.sub.x] during the ozone season, (418) which was subsequently changed to 25% as a result of an increase in the emissions inventory baseline. (419) The final rule does not mandate which sources must reduce pollution; the states must decide where the reductions are to be made. The SIP revisions were to be fully implemented by May 1, 2003. (420) However, there is a provision for a "Compliance Supplemental Pool" that provides flexibility to states to deal with excess emissions from sources that are unable to meet the compliance deadline in the 2003 and 2004 ozone seasons. (421) EPA's control strategy to meet the N[O.sub.x] reduction requirements includes using post-combustion controls (SCR and SNCR) and combustion controls such as low-N[O.sub.x] burners and overfire air. (422) On May 14, 1999, EPA promulgated revised N[O.sub.x] emission budgets for twenty-two states and the District of Columbia. (423)

In 1999, the OTC Phase II program also commenced with nine OTC states establishing an emissions cap-and-trading system for N[O.sub.x]. This program required 912 electric power generating units to reduce emissions by 55 to 65% from a 1990 baseline of 417,444 tons. (424) The sources not only complied, but reduced emissions 20% below the target. Importantly, 126 of the 142 coal-fired units achieved the reductions using operational changes without significant capital costs. (425)

On May 25, 1999, EPA announced that the section 126 permit petitions filed in 1998 were technically meritorious, but that it was deferring action on the petitions pending action by the states pursuant to its N[O.sub.x] SIP call. (426) EPA's decision to defer to its SIP call approach, backed up by a proposed FIP, (427) was based on the overlap of the sections 110 and 126 approaches and the advantages that EPA perceived would come from using the section 110 SIP call approach. The SIP call requires emission reductions from all sources, but the section 126 petitions were limited to addressing emissions from upwind sources. Moreover, if EPA granted the section 126 petitions, it must promulgate requirements for emission sources, but by using a SIP call, the states must promulgate the requirements for the sources. (428)

On May 25, 1999, the D.C. Circuit issued an order staying the N[O.sub.x] SIP call. (429) In response, EPA revised the section 126 rule on January 18, 2000, by making the findings of significant contributions, granting the relevant portions of the section 126 petitions, and delinking the section 126 findings from compliance with the N[O.sub.x] SIP call. (430) This was done because there was no longer any effective program being developed as part of the SIP call for addressing interstate pollution, but the agency's new rule contained a provision withdrawing its findings upon approval of a N[O.sub.x] SIP in accordance with the October 1998 SIP call. (431) On March 2, 2000, EPA revised the statewide emissions budgets again for the twenty-two states and the District of Columbia subject to the N[O.sub.x] SIP call. (432) On March 3, 2000, a three-judge panel of the District of Columbia Circuit largely upheld EPA's SIP call. (433) The court upheld the N[O.sub.x] SIP call for nineteen states and the District of Columbia, but vacated it for Wisconsin, Georgia, and Missouri because of an inadequate record. (434) This decision resulted in nineteen states and the District of Columbia being subject to the SIP call, but only twelve states and the District of Columbia subject to section 126 requirements. (435)

On June 24, 1999, EPA issued an interim final rule to temporarily stay the section 126 petitions until November 30, 1999. (436) The stay was intended to give EPA time to address the American Trucking Association v. EPA. (437) decision issued by the D.C. Circuit that remanded the eight-hour ozone standard. (438) The SIP call was subsequently extended to January 10, 2000, (439) and was extended again until February 17, 2000, when the revised SIP rule became effective. (440)

On April 11, 2000, EPA asked the D.C. Circuit to remove the stay and to extend the SIP submittal deadline to September 1, 2000. (441) Subsequently, six states indicated they wanted to take their case to the Supreme Court. (442) On August 9, 2000, EPA announced its receipt of a petition for rulemaking, by New York and the six New England states, pursuant to CAA section 109, to promulgate revised secondary NAAQS for N[O.sub.x], S[O.sub.2], and P[M.sub.2.5]. (443) On August 30, 2000, the D.C. Circuit again ruled on the SIP call and further delayed the implementation deadline until May 31, 2004. (444) However, several states indicated their intent to continue to use a May 1, 2003 start date; moreover, the section 126 ruling still contained a May 1, 2003 deadline. (445) Litigation over the section 126 final rules followed, and on November 13, 2000, EPA announced a proposed settlement agreement. (446)

On September 18, 2000, EPA stayed the N[O.sub.x] SIP call insofar as it related to the eight-hour ozone standard that had been rejected in American Trucking. (447) On December 26, 2000, EPA ruled that Virginia, West Virginia, Alabama, Kentucky, North Carolina, South Carolina, Tennessee, Illinois, Indiana, Michigan, Ohio, and the District of Columbia had failed to submit SIP measures as required by the SIP call. (448) The rule took effect January 25, 2001, which triggered both the CAA sanction provisions and the two-year period for EPA to promulgate a FIP. (449)

4. Appalachian Power Cases

On May 15, 2001, the D.C. Circuit once again issued an opinion on the section 126 rule in Appalachian Power Co. v. EPA (Appalachian Power l). (450) Numerous petitioners had challenged the rule as being inconsistent with the CAA, as well as being arbitrary and capricious, and technically deficient. (451) The court upheld most aspects of the rule, but remanded several parts of it to the agency for reconsideration. (452) The court upheld EPA's interpretation that CAA sections 110 and 126 are independent statutory tools to address interstate pollution transport, and therefore, EPA may deploy them either singly or in tandem. (453) The court also upheld EPA's definition of "significant contribution" under section 126 to be those emissions of N[O.sub.x] that can be controlled at a cost of no more than $2000 per ton of N[O.sub.x] removed. (454)

The court remanded for an explanation of EPA's use of the Integrated Planning Model (IPM) based on certain specific challenges. (455) However, the court said it would reverse only if the agency's conclusions were unreasonable. (456) The court upheld the section 126 rule establishing an N[O.sub.x] budget for each upwind state, capping emissions from existing, proposed, and future as-yet-unproposed sources. EPA may bar the construction or operation of major new proposed sources. (457) The court then vacated and remanded the portion of the rule concerning cogenerators because it could not determine why EPA was treating them differently than large electric generating units. (458)

On June 8, 2001, the D.C. Circuit revisited the N[O.sub.x] SIP call in the Appalachian Power II case. (459) On March 3, 2000, the court upheld the bulk of EPA's N[O.sub.x] SIP call in Michigan v. EPA. (460) Appalachian Power II involved various challenges to how EPA made its decision in the SIP call. (461) The primary issue before the court involved how EPA had devised the state N[O.sub.x] budgets. On this issue, the court held that it could not "excuse the EPA's reliance upon a methodology that generates apparently arbitrary results particularly where, as here, the agency has failed to justify its choice. (462) The court then went on to remand EPA's growth factor determinations, source definitions challenged by non-electric generators, and the state emissions budget for Missouri. (463) It rejected the other issues raised by the petitioners without explanation. (464)

On June 29, 2001, the Appalachian Power Company once again asked the D.C. Circuit for relief by seeking to delay the compliance date of May 1, 2003 for meeting N[O.sub.x] emission limits based on section 126. (465) On August 3, 2001, EPA placed new information in its docket in response to the D.C. Circuit's remand of May 15, 2001 in Appalachian Power I. (466) On August 24, 2001, the D.C. Circuit gave electric generators an indefinite extension for complying with the section 126 rule that had originally imposed the May 1, 2003 compliance date. (467) On September 21, 2001, EPA issued a final rule revising N[O.sub.x] emissions allowances under section 126. (468) On November 8, 2001, Illinois became the first midwestern state to receive EPA approval for its N[O.sub.x] reduction plan required by the agency's N[O.sub.x] SIP call. (469) On the same day, Indiana's N[O.sub.x] reduction plan also was approved. (470)

H. Visibility Protection

Visibility can be affected by plume blight that comes from specific sources. If the plume does not disperse, it can obscure or discolor the sky. Visibility also can be affected by regional haze from many sources. (471) Visibility deterioration is caused by light extinction resulting from light scattering by particulates, natural Rayleigh scattering by atmospheric gases, and by light absorption by particles and gases. (472) The major cause of visibility reduction is sulfate (S[O.sub.4]), a secondary pollutant formed in the atmosphere from sulfur oxides that are primarily released from coal-burning electric power plants. Other coal-burning processes, oil-fired electric power plants, petroleum refining, and metal smelting also contribute to emissions. (473) The second major contributor to visibility impairment is organic pollutants emitted from natural sources (bioemissions) as well as from stationary and mobile sources. (474) Carbon (soot) particles from smoke and diesel exhaust and course particles from wind-blown dust, smoke, and pollen affect visibility, too. (475) Nitrate (N[O.sub.3]) is the third largest contributor to reduced visibility. Nitrate is a secondary pollutant produced from N[O.sub.x] released from combustion sources and motor vehicles; it can react with water to produce nitric acid (HN[O.sub.3]) and also to produce nitrate salts. (476) Nitrogen in the form of ammonia (N[H.sub.3]) or ammonium (N[H.sub.4]) also contributes to visibility reduction. (477) Most visibility reduction in the eastern United States is due to S[O.sub.4] particles formed from S[O.sub.2] emitted by coal-burning electric generation plants. (478) The S[O.sub.4] contribution in the eastern United States ranges from 64% on the best days to 80% on the worst days; organic carbon (soot) contributes 12% on the best days and 9% on the worst days; and nitrate accounts for 12% on the best days and 5% on the worst days. (479) In the western United States, sulfates account for between 35% of the light extinction on the best days and 45% on the worst days; organic matter contributes 19% to 22%; crustal material contributes 16% to 20%; and nitrate contributes 12% to 15% to visibility impairment. (480) In 1993, the average visual range in most national parks in the western United States was about sixty to one hundred miles; in the eastern United States it was about twenty miles. (481) This is about one-half to two-thirds of the natural visual range in the West, but only about one-fifth of the natural visual range in the East. (482)

1. Failure of the CAA to Protect Visibility

The use of the CAA to protect park values does not fulfill expectations because a program based primarily on standards set to protect human health has little effect on the impact of air pollutants on a natural ecosystem. The health-based air pollution control program has a lesser impact on improving visibility because even small increases in emissions can have significant adverse effects. For example, an increase of one microgram of particulate concentration in the atmosphere in an area that provides a two hundred mile view can result in a decrease in visibility of 30%. Thus, visibility protection and economic development are in serious conflict. (483)

Furthermore, increment-based limitations on emissions do not adequately protect an area from visibility impairment. Particles in the 0.1 to 1.0 micron range have the greatest ability to reduce visibility, yet they are not the subject of specific legal restrictions. (484) In addition, visibility impairment is dependent on the total amount of fine particles between an observer and the subject being viewed, not the concentration in the ambient air that is the focus of the NAAQS and the increments. (485) The CAA program predicted to have the most beneficial effect on visibility improvement is the acid rain program in subchapter IV. The benefits will be greatest in the eastern United States. In the western United Sates where most Class I areas are located, the acid rain program was projected only to halve the growth in S[O.sub.2] emissions between 1993 and the year 2010. (486)

The visibility program in CAA sections 169A and B is primarily aimed at existing sources, while the PSD program that comprises the rest of subchapter I, part C is primarily aimed at new or modified major emitting facilities. (487) Major stationary sources not in operation for more than fifteen years on August 7, 1977 and that emit any air pollutant that may cause or contribute to visibility impairment are required to install and operate the Best Available Retrofit Technology (BART). (488) BART is determined by considering the source's characteristics, such as the technological and economic feasibility of control and the degree of visibility improvement that may result from control. (489) A major source is defined for visibility protection purposes as listed stationary sources with the potential to emit 250 tons or more of any pollutant. (490) Fossil-fuel-fired steam electric plants of more than 250 million Btu per hour of heat input and about twenty-five other categories are covered. (491) EPA, however, may exempt sources that have no impact on visibility. (492)

Section 169A was added to the CAA in 1977. It required the Secretary of the Interior, in consultation with federal land managers, to identify mandatory Class I areas where visibility is an important value. The EPA Administrator then was to promulgate a list of such areas and regulations to assure reasonable progress in meeting the national goals concerning visibility protection. Each state that contained, or impaired, any area with visibility values was to revise its SIP to utilize emission limits, schedules of compliance, and other measures necessary to make reasonable progress toward remedying existing or future visibility impairment. (493) EPA determined that visibility was an important value in 156 of the 158 mandatory Class I areas. (494) Two mandatory Class I areas, Rainbow Lake, Wisconsin and Bradwell Bay, Florida were not included because they had no vistas extending outside their boundaries and did not meet other criteria used to determine the importance of visual values. (495) Thirty-five states and the Virgin Islands had Class I areas listed for visibility protection that required revision of their SIPs. (496) They had to make reasonable progress toward preventing visibility impairment and protect any "integral vista," which is the view looking out from a listed Class I area. (497) Neither the Departments of Agriculture nor Interior designated integral vistas by the regulatory deadline. In 1980, EPA promulgated visibility regulations under section 169A (498) that adopted a "phased approach to visibility protection." (499) Phase I controlled "reasonably attributable" impairment from a single existing stationary facility or small group of existing stationary facilities. (500) EPA deferred addressing "regional haze" impairment because of the "scientific and technical limitations inherent in attempts to identify, measure, and control such broadscale visibility impairment. (501)

EPA's "Phase I" regulations required the thirty-five affected states and the Virgin Islands to coordinate the development of SIPs with the appropriate federal land managers, to develop programs to assess and remedy visibility impairment from new and existing sources, and to develop a long-term strategy to assure reasonable progress toward section 169A's national visibility goal. (502) States were to identify existing sources "which may reasonably be anticipated to cause or contribute" to any visibility impairment "reasonably attributable to that existing stationary facility." (503) Once a source was identified, the affected state was to take measures to attain "reasonable progress." Measures generally include the determination of emissions limitations for that source based on BART. (504) The CAA mandates guidelines be promulgated by the EPA Administrator that require emissions limitations for fossil-fuel-fired generating powerplants having a total generating capacity in excess of 750 megawatts. (505) To avoid visibility-based emission requirements, the owner or operator of the plant must demonstrate to the satisfaction of the Administrator that the plant, by itself or in combination with other sources, does not have a significant impact on the visibility of a protected mandatory Class I area. (506)

2. EPA Addresses Regional Haze

On November 24, 1987, EPA disapproved the SIPs of twenty-nine states for failing to comply with the visibility regulations. (507) By 1993, ten states (Georgia, North Carolina, Arkansas, Louisiana, Colorado, North Dakota, Utah, Wyoming, Alaska, and Oregon) revised their SIPs to meet the 1980 visibility rules. EPA promulgated FIPs for sixteen states and the remaining ten states had a combination of SIPs and FIPs. (508)

The 1990 CAA Amendments added section 169B, which required studies and provided the authority to establish visibility transport regions and visibility transport commissions to deal with interstate transport of pollutants that contribute to visibility impairment. (509) The 1990 CAA Amendments specifically required a Grand Canyon Visibility Transport Commission (GCVTC) to be established. (510) The statute required a report concerning the control of regional haze to be issued by November 15, 1994, recommending measures to be taken in clean air corridors. (511) Until the 1999 regulations were promulgated, the basic requirements continued to be the 1980 regulations found at 40 C.F.R. sections 51.300 to 51.307. (512) The regulations were limited in length and scope and basically tracked the statutory requirements. They dealt primarily with visibility impairment from identified stationary sources, not the regional haze created by the transport of pollution from many sources that impairs visibility in every direction over a large area.

In the 1980 regulations, EPA said that regional haze would be regulated in the future because technology and knowledge were not sufficiently sophisticated to allow it to monitor, model, and fully understand regional haze. (513) When EPA had not proposed regional haze regulations in 1989, Maine attempted to force EPA to act. (514) The 1980 regulations classified air pollution impairing visibility as either plume blight ("smoke, dust, colored gas plumes, or layered haze ... which obscure the sky or horizon and are relatable to a single source or a small group of sources") or regional haze, and treated the two categories separately. (515) Maine sued in federal district court, under citizen suit provisions, claiming EPA had a nondiscretionary duty to regulate. Maine lost when the court held EPA's 1980 regulation was final action and, therefore, was reviewable only in the U.S. Court of Appeals. (516) In a subsequent appeal, the First Circuit noted that a decision to postpone action constitutes a final action for the purposes of CAA section 307. (517) Because a challenge to the regulation was not brought in the D.C. Circuit within sixty days, this case was held to be an untimely challenge in a proper court. The First Circuit went on to affirm the district court's dismissal because there was no right to bring a citizen suit action in this case. (518) In response, the 1990 CAA Amendments changed the CAA's citizen suit provision in section 304(a) to authorize lawsuits to compel agency action that was unreasonably delayed, (519) and Congress ordered EPA to regulate regional haze. (520)

On October 3, 1991, EPA issued its final determination that certain visibility impairment episodes at the Grand Canyon were traceable to the Navajo Generating Station. (521) This resolved the lawsuit brought by the Environmental Defense Fund (EDF). (522) The battle over the Grand Canyon's visibility began in 1982, and it took nearly ten years to reach a negotiated settlement. It is one of the rare examples of negotiated rulemaking used successfully in an environmental controversy (523) and was the first time the 1977 law was used to protect the visibility of a national park. (524) That facility is located on the Navajo Indian Reservation and is, therefore, subject to the jurisdiction of EPA and the Navajo Nation. (525) A FIP for Arizona requiring BART was imposed on the Navajo Generating Station. (526) Generally, the CAA and its regulations require the application of BART once it has been determined that visibility, impairment is "reasonably attributable" to an existing source such as the Navajo Generating Station.

On November 13, 1991, EPA established GCVTC under the authority granted by CAA section 169B(c). (527) GCVTC was to focus on the Class I areas near the Grand Canyon in the "Golden Circle" that includes most of the national parks and wilderness areas of the Colorado Plateau. (528) It released a draft report in November 1995 entitled; Options for Improving Western Vistas. (529) The report dealt with sixteen national parks and visibility areas in the West and found that stringent controls, at a cost of over ten billion dollars per year would, at best, improve annual average visibility between 20 and 25%. Industry groups, therefore, advocated that no new efforts should be undertaken. (530)

On June 10, 1996, GCVTC adopted nine recommendations to reduce air pollution in the region. For stationary sources, sulfur levels were to be reduced at least 13% from 1990 levels by the year 2000. GCVTC favored the use of emissions trading to reduce emissions and envisioned a successor entity to continue its work (531) after it terminated in 1996. (532) GCVTC was replaced by the Western Regional Air Partnership (WRAP) that expanded the prior GCVTC membership. It is currently composed of nine western states and about 211 Indian tribes, (533) with Idaho being the most recent western state that was added. (534) The WRAP produced an annex to the GCVTC recommendations and these organizations' proposals were later incorporated into EPA's Regional Haze Rule. (535)

On July 1, 1999, EPA promulgated a final regional haze rule calling on the states to establish goals and emission reduction strategies to improve visibility in all 156 mandatory Class I national parks and wilderness areas. (536) The rule allows the nine western states to implement GCVTC's recommendations within the framework of a national regional haze program. (537) The rule encourages the states to work together in regional partnerships to reduce emissions of fine particles. (538) Congress, in the Transportation Equity Act for the 21st Century (TEA-21), (539) required a regional haze monitoring network to be developed by December 31, 1999. (540) This law supersedes CAA section 169B and establishes a new deadline for SIP submissions. EPA will designate areas between July 2004 and July 2005. (541) Areas designated nonattainment must submit SIP revisions in the July 2007 to July 2008 time frame. (542) Regional haze program requirements are set forth in 40 C.F.R. section 51.308. There are five regional planning organizations (RPOs) created by EPA to deal with regional haze issues. For example, the Mid-Atlantic Northeast Visibility Union (MANE-VU) includes twelve states from New Hampshire to Maryland, the District of Columbia, two tribal members, the St. Regis Mohawk Tribe and the Penobscot Indian Nation, appropriate federal land managers, and EPA. (543) At a minimum, SIPs must include a long-term strategy and provide for BART to be used on certain major stationary sources. (544) There are also provisions for reasonable progress targets (545) that are to return visibility to natural conditions in sixty years. (546) Fossil-fuel steam electric plants of more than 250 million Btu heat input are one of the twenty-six source categories subject to BART. (547) BART emission limitations are established on a case-by-case basis following the factors set out in the rule. (548)

On January 12, 2001, EPA announced regional haze rule proposed amendments that would guide the states in determining which utilities would be required to install the BART. (549) However, the proposed rule was subject to the Bush administration's review of rulemakings that were made in the final days of the Clinton administration. (550) After a coalition of states and industry groups asked the Bush administration to review the rule, especially the proposed retrofit requirements for power plants, the Bush administration delayed promulgating the rule. (551) This decision was opposed by New England governors. (552) On March 28, 2001, OTC announced six model rules for states to adopt to reduce NO[sub.x] and VOC emissions and a resolution to support the creation of a multistate group to coordinate regional haze reduction. Among its initiatives is one to address on-site or "distributed" electric power generation. Much of this electric power involves the use of diesel generators, which have high NO[sub.x] emissions. (553)

On July 20, 2001, EPA finally promulgated the proposed rule six months after it had been announced. (554) It required guidelines to be promulgated by EPA to be followed by the states and would require retrofits of BART at older power plants and other major sources in twenty-nine states to control regional haze. (555) In addition, EPA proposed revisions to the 1980 regulations concerning visibility impairment from specific sources. (556) BART is to consider controls more stringent than the SO[sub.2] controls imposed by NSPS. (557) The proposed rule provides guidance on six aspects of BART--identification of BART-eligible sources, identification of sources subject to BART, BART engineering analysis, cumulative visibility analysis, BART emissions limits, and the emissions trading program alternative. (558) EPA did not propose that modifications would affect a source's BART eligibility. (559) In August 2001, the 1999 regional haze rule was being challenged in the D.C. district court for allegedly exceeding EPA's authority under the CAA. (560) In October, electric utilities submitted comments to EPA claiming the agency's proposed regional haze guidelines were illegal. (561)

The Northeast States for Coordinated Air Use Management released a report on July 24, 2001 stating that BART implementation will not result in reaching visibility goals. BART does not apply to sources built prior to 1962, which exempts many midwest coal-fired plants. (562) Moreover, not all potential BART eligible sources will be covered because the statute applies only to power plants reasonably anticipated to cause or contribute to visibility impairment. (563) In August 2001, some industry members questioned the legality of the proposed regulations. (564) Moreover, EPA and the Regional Planning Organizations disagreed as to which model should be used to prepare the visibility plans required by 2008. (565) On December 12, 2001, EPA made available two draft documents concerning implementation of regional haze regulations. (566)

The main body of the PSD statute and its implementing regulations contains additional visibility protection requirements. CAA section 165(d) gives the federal land manager an affirmative duty to protect air quality related values including visibility. (567) A state is restricted in its ability to issue permits where EPA, the governor of an adjacent state, or the federal land manager notifies the permitting state that the proposed facility may contribute to a change in the air quality of a Class I area. (568)

To carry out their responsibilities under tl~e CAA, EPA's guidance requires the permitting authority to notify the federal land manager (FLM) (569) of all major facilities proposed to be sited within one hundred kilometers (sixty-two miles) of a Class I area. Additionally, if very large sources planned to be sited at a distance greater than one hundred kilometers have the potential to affect a Class I area, notification is required. (570) If the increment will be violated in the area where the project is proposed, the permit may be denied. Regardless of whether or not the increments are exceeded, as part of the PSD permit application, the applicant must perform an air quality analysis for each pollutant subject to PSD that may impact a Class I area. The applicant must use approved EPA models, and a pre-modeling protocol review by EPA is recommended. (571)

The FLM is responsible for performing an air quality related values (AQRV) effects analysis concerning the impacts on aquatic and terrestrial ecosystems on federal Class I land. (572) A finding of visibility impacts requires additional steps pursuant to 40 C.F.R. section 52.27(d). If emissions exceed the increment allowed in a Class I area, but the FLM certifies that no adverse effects on air quality related values (including visibility) of the Class I land would occur, a permit may be granted. (573) The applicant must show an absence of adverse impact where an increment violation exists. Conversely, if there is no increment violation, the FLM must demonstrate that the proposed facility will have an adverse impact. Even if the adverse impact does not exceed the increment in the Class I area, a permit may be denied. (574) The decision maker, usually the state agency, must supply a rational basis for rejecting the FLM's adverse impact determination. (575) A reviewing court uses an arbitrary and capricious standard of review in examining rejections of adverse impact determinations. (576) Should the state concur with the FLM's analysis, a permit will not be issued. (577) The regulations provide values for significant increases in ambient air concentrations over minor source baseline concentrations that trigger review. (578)Emissions are considered significant if discharged within ten kilometers of a Class I area with an ambient air impact equal to or greater than 1 MUg/m (24-hour average). (579) In addition, facilities located within one hundred kilometers of a federal Class I area are presumed to have an adverse impact on air quality related values unless the applicant proves the contrary. (580)

I. Permitting

1. Construction Permits

EPA and the states require construction permits to be obtained prior to the construction of new or modified major sources. In addition, operating permits are usually required for new and existing sources. Siting efforts include obtaining the necessary CAA permits, usually issued by the appropriate state permitting authority. (581) States enjoy some discretion concerning the exercise of their CAA authority, (582) but EPA's extensive regulatory provisions controlling both construction and operating permits limits their discretion.

The CAA considers approximately twenty thousand sources major, which potentially subjects them to CAA NSR permitting requirements. (583) About 250 facilities apply for PSD or nonattainment NSR permits each year. According to EPA, from 1997 to 2001, the average time between filing a permit application and issuance of the final permit was 7.2 months. (584) EPA currently reports a reduction in the average permitting time. (585) Since 1995, 274 PSD permits were issued for new and modified electric generating facilities, only ten of which were issued for coal-fired electric generators. (586) Average time for issuing a PSD permit for a coal-fire generating facility was ten months compared to an average of 7.5 months for gas-turbine facilities. Although the average time to receive a final permit for a turbine facility is decreasing, (587) it should be noted that EPA's calculation only considers the interval between filing a complete application and granting the final permit. The time required to develop information necessary for the application can be substantial. For example, in PSD areas, a year of modeling data may be needed. (588) Moreover, granting an EPA permit may not end the issue. A court challenge to the granting of the permit may take years to resolve. Furthermore, construction of a major source may require securing numerous permits from local, state, and federal authorities. Nevertheless, the NSR program can work. California, with tm NSR program more stringent than EPA's, issued forty-six permits for power plant construction from 1999 to mid-2001. (589)

2. Operating Permits

Prior to the 1990 CAA Amendments, the CAA did not include an operating permit program. (590) Operating permits are now required for all major sources, any other source (including an area source) subject to regulation under CAA section 111 or section 112 (hazardous air pollutants), sources required to have permits under subchapter I parts C or D, affected sources under CAA subchapter IV, and any other source designated by the Administrator. (591) CAA mandates these operating permits in addition to preconstruction permits required for new or modified major stationary sources in PSD areas and in nonattainment areas that were discussed in the NSR material in section 3(c). (592)

Operating permits may be granted for up to five years. (593) Power to veto the granting of a permit rests with EPA. (594) Once granted, compliance with the permit is a shield against certain CAA enforcement actions based on matters covered by the permit. (595) Because operating permits are subject to citizen suit challenges, the citizen suit provision exposes utilities to liability for past violations, as well as to penalties for conduct subject to prior governmental administrative sanctions. (596)

3. Acid Rain Requirements

Under subchapters IV and V of the CAA, state and local permitting authorities develop and administer acid rain programs as part of their subchapter V operating permits program. (597) Phase I permits were to be issued by EPA as provided in regulations that were due May 15, 1992; (598) however, the core regulations were not promulgated until January 11, 1993. (599) Permit requirements are found at 40 C.F.R. section 72.9. Permit applications were due February 15, 1993. (600) EPA was required to act on an application within six months of receipt. (601) After EPA's approval, states may process acid rain permit applications from sources covered by EPA's acid rain program. (602) States may impose more stringent requirements on affected units if the state requirement is articulated in a portion of the operating permit that is separate from the Acid Rain Program requirements. (603) A number of states are moving to require more stringent NO[sub.x] control. (604)

Phase II permits were to be issued by each state if its permit program was approved by EPA. (605) Most sources not covered by Phase I were required to apply for a permit by January 1, 1996. (606) States with approved programs were to issue permits by December 31, 1997. (607) If a state did not have an approved program, then applications from the sources were due by July 1, 1996, and EPA had to act on the application by January 1, 1998. (608) New sources had to submit an application two years before either January 1, 2000, or the date on which the unit begins operation. (609) Approximately seven hundred Phase II facilities had to meet the SO[sub.2] reduction requirements by January 1, 2000. (610)

The designated representative for an affected source must include a compliance plan with the application for an acid rain permit. (611) If emission limits are to be met by holding the necessary allowances, all that is required is a simple statement that allowances will be used. A unit planning to use bonuses or extensions must file a more detailed plan. (612) The plan may be revised at any time. (613)

Any unit may choose to become an affected unit under subchapter IV to be able to use its reductions to meet the legal requirements imposed on other units under the same ownership. (614) They must meet the requirements imposed by subchapter IV, but they may not transfer or bank allowances from reduced utilization or shutdown. (615) The baseline will be the emissions based on fuel consumption and operating data for the unit for the years 1985 to 1987, or if such data is not available, EPA may prescribe a baseline based on alternative data. (616) If the unit is an exempted unit, the exemption is binding on the permitting authority. (617)

4. Efforts to Expedite Permitting

At the state level, there appears to be some effort to ease the permitting burdens. For example, the Arizona Administrative Code provides for accelerated processing for sources willing to pay the costs of accelerated processing. (618) Another interesting development in Arizona is the use of certificates of environmental compatibility issued by the Arizona Corporate Commission to require companies building new gas-fired generating facilities to make power available to Arizona customers during peak demand periods rather than selling power throughout the Southwest to the highest bidder. (619) However, on June 19, 2001, Kentucky ordered a six-month moratorium on accepting new power plant applications in order to allow time for a review of the environmental impact of existing applications. (620)

The environmental law literature reports numerons proposed bills in state legislatures and regulatory changes at the state administrative agency level, but a detailed analysis of state efforts is beyond the scope of this discussion. In response to the electrical energy problems in the West, however, state legislatures in Montana, Wyoming, Utah, Oregon, Washington, and Nevada introduced or passed legislation to limit public participation in permitting and siting decisions, reduce or eliminate environmental controls on facilities, and reduce the scope and time allowed for environmental review. (622) In the East, New York enacted an expedited approval process. (622) Common concerns at the state level include the need to determine 1) the appropriate EPA guidance in the face of complex and contradictory NSR rules, 2) the appropriate role of EPA and federal land managers in state permitting, and 3) the method of how the states determine what is the best available technology and EPA's role in a state's determination. (623) Fast-track measures, however, cannot prevent environmentally-based judicial challenges. (624)

On January 17, 2001, California's Governor Davis declared an energy emergency. He subsequently issued executive orders to encourage increased production of electricity from existing facilities and to accelerate the construction of new generating capacity. (625) In addition to the normal permitting process, California provides for expedited permits, peaking power permits, and emergency permits to speed the creation of new electric generating capacity. (626) On May 22, 2001, California's governor signed legislation to reduce the time for reviewing power plant projects to require the process to be completed in 180 days. (627) In June 2001, Governor Davis eased local air rules to encourage increased power production. Plants were released from air emission limitations in return for paying mitigation fees. (628) The Governor's executive orders were subsequently challenged on June 19, 2001, with complaints filed in the U.S. District Court for the Northern District of California. (629) A consent decree was filed on October 31, 2001, that put controls on three peaking units in the San Francisco area in exchange for a payment of $20,000 per ton of NO[sub.x] generated beyond its permitted discharge. (630)

On May 18, 2001, by executive order, President George W. Bush established an interagency task force to expedite permit reviews. (631) On August 20, 2001, it was announced that the chairman of the Council on Environmental Quality would chair the interagency task force to be housed in the Department of Energy. It will be comprised of representatives from twenty federal departments and any additional representatives added by the chairman. It plans to divide its responsibilities among about eight subgroups responsible for day-to-day management to including electricity generation and electricity transmission. (632)

IV. CONCLUSION

The rapid change in the electric power industry discussed in Part II of this Article is, in part, being shaped by the CAA programs discussed above. Unfortunately, these CAA programs are not: part of an overall strategy that encompasses both environmental and energy policy considerations. The proposed four pollutant bill, which includes controls on carbon dioxide emissions, does not appear to have given adequate consideration to either costs or its effect on the use of coal to generate electricity. The new source review program still has not developed a workable definition of "repair," and the program to get old facilities to meet the emission standard of new sources is dependent on the vagaries of an enforcement program. Moreover, the Bush administration may terminate aggressive enforcement of the NSR program. Further, after more than thirty years of experience with the CAA, emissions standards are still based on the amount of fuel used rather than electricity generated, which gives a competitive advantage to dirty, inefficient coal-burning plants. Such an approach is in conflict with the recent efforts to control carbon dioxide emissions.

Interstate air pollution transport abatement involves taking steps to control sources that years earlier should have been subject to more stringent emission limits. But the SIP call and the section 126 program are both too new to be meaningfully evaluated. Visibility protection efforts will probably not be successful because the costs and lifestyle adjustments necessary for effective control are unlikely to be accepted by the public. But efforts in this direction should be commended and ultimately could be successful if the nation moved to significantly increase its electric power generation based on nuclear or renewable energy sources such as wind power.

It is clear that decisions concerning the CAA will have major ramifications in determining how electricity will be generated in the coming years. But, because of the lack of any overall energy or environmental policy, the decisions concerning how and where electricity is generated will be made by the utilities seeking to avoid risk and meet their obligations to shareholders. A significant factor in the private sector's decision-making process will be CAA requirements. At this time, the federal government has largely failed to develop an energy policy consistent with the need to protect air quality, and it has failed to develop CAA requirements that encourage efficient use of energy.

(1) Steven Pearlstein, On California Stage, a Cautionary Tale, WASH. POST, Aug. 21, 2001, at 21, 2001 at A1.

(2) NATIONAL ENERGY POLICY, REPORT OF THE NATIONAL ENERGY POLICY DEVELOPMENT GROUP, RELIABLE, AFFORDABLE, AND ENVIRONMENTALLY-SOUND ENERGY FOR AMERICA'S FUTURE (May 2001), [hereinafter NATIONAL ENERGY POLICY] available athttp://www.whitehouse.gov/energy/National-Energy-Policy.pdf. While electricity shortages were receiving a great deal of media attention, the United States added a record 51,000 megawatts of electrical capacity in 2001. Spencer Abraham, Deregulation Is Working, WASH. POST, Jan. 14, 2002, at A17.

(3) NATIONAL ENERGY POLICY, supra note 2, chs. 4, 5, 7, 8, app. 1. The energy plan is now the subject of a Natural Resource Defense Council lawsuit aimed at forcing the Department of Energy to reveal the extent to which industry helped formulate the plan. Pamela Najor, Environmental Group Sues DOE for Failing To Provide Information on Bush Energy Plan, 32 Env't Rep. (BNA) 2406 (Dec. 14, 2001).

(4) Jeffords to Chair Environment Panel, Supports New Controls for Air Pollution, Daily Env't Rep. (BNA), June 1, 2001, at A-1, WL 106 DEN A-1, 2001.

(5) Cheryl Bolen, Jeffords Switches from GOP to Independent; Senate to Reorganize Under Democrats, Daily Env't Rep. (BNA), May 25, 2001, at AA-1, WL 102 DEN AA-1, 2001; Steve Cook, Jeffords, Lieberman Urge No Delay in Implementation of NO[sub.x] Control Rule, Daily Env't Rep. (BNA), June 1, 2001, at A-1, WL 106 DEN A-1, 2001.

(6) 42 U.S.C.[subsection] 7401-7671q (2000).

(7) See Byron Swift, How Environmental Laws Work: An Analysis of the Utility Sector's Response to Regulation of Nitrogen Oxides and Sulfur Dioxide Under the Clean Air Act, 14 TUL. ENVTL. L.J. 309 (2001).

(8) One writer has described CO[sub.2] as the Achilles heel of the coal industry. The newest most efficient conventional coal-burning electric power plants emit three times as much CO[sub.2] as a natural gas plant. Old, less efficient plants emit considerably more CO[sub.2]. Jeff Goodell, Blasts from the Past, N.Y. TIMES MAG., July 22, 2001, at 31, 44. As of July 23, 2001, 178 nations have agreed to Kyoto Protocol implementation rules. Pamela Najor, Opinion Divided Over Potential Impact of Bonn Agreement on U.S. Industry, 32 Env't Rep. (BNA) 1464 (July 27, 2001). The United States has rejected the protocol, and with Congress moving forward on legislation to control CO[sub.2] domestically, U.S. companies may not have access to a worldwide emissions trading system to reduce the cost of compliance. Id.

(9) U.S. Dep't of Energy, Office of Fossil Energy, Latest EIA Coal Facts, 44 CLEAN COAL TODAY 11 (2001), available at http://www.lanl.gov/projects/cctc/newsletter/documents/Ol_spr.pdf.

(10) U.S. ENVTL. PROT. AGENCY, NATIONAL AIR QUALITY AND EMISSION TRENDS REPORT 1998, at 122, 124, 125 (2000) [hereinafter 1998 TRENDS REPORT] (percentages were calculated from data on these pages).

(11) U.S. ENVTL. PROT. AGENCY, NATIONAL AIR QUALITY AND EMISSION TRENDS REPORT 1997, at 82 (1998); see also U.S. ENVTL. PROT. AGENCY, PROFILE OF THE FOSSIL FUEL ELECTRIC POWER GENERATION INDUSTRY 58 (1997) [hereinafter PROFILE], available at http://www.epa.gov/oar/aatrnd97/chapter5.pdf.

(12) U.S. ENVTL. PROT. AGENCY, INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS AND SINKS: 1990-1999 ES-12 (2001) [hereinafter GREENHOUSE GAS EMISSIONS 1990-1999], available at http://www.epa.gov/globalwarming/publications/emissions/us2001/index.html.

(13) Michael Bologna, U.S. C[O.sub.2] Emissions Up 3.1 Percent in 2000, Total Greenhouse Gas Emissions Also Grow, Daily Env't Rep. (BNA), Nov. 13, 2001, at A-4, WL 217 DEN A-4, 2001.

(14) UNITED NATIONS PROGRAMME ET AL., WORLD RESOURCES 2000-2001, PEOPLE AND ECOSYSTEMS: THE FRAYING WEBS OF LIFE 282-83 tbl. AC.1 (2001). (15) Peter Menyasz, NAFTA Study Estimates Major Increase in CO[sub.2] Emissions from Electricity Sector, 32 Env't Rep. (BNA) 2297 (Nov. 30, 2001).

(16) U.S. DEP'T OF ENERGY, ENERGY INFORMATION AGENCY, REDUCING EMISSIONS OF SULFUR DIOXIDE, NITROGEN OXIDES, AND MERCURY FROM ELECTRIC POWER PLANTS 35 tbl.B2 (2001) [hereinafter REDUCING EMISSIONS], available at http://www.eia.doe.gov/oiaf/servicerpt/mepp/pdf/sroiaf(2001)04.pdf.

(17) Id.

(18) Byron Swift, Grandfathering, New Source Review, and N[O.sub.x]--Making Sense of a Flawed System, Daily Env't Rep. (BNA), July 14, 2000, at B-1, WL 136 DEN B-1, 2000.

(19) U.S. DEP'T OF ENERGY, ANNUAL ENERGY OUTLOOK 2000 WITH PROJECTIONS TO 2020, at 68 (2000), available at http://www.eia.doe.gov/oiaf/archive/aeo00/pdf/0383(2000).pdf.

(20) NATIONAL ENERGY POLICY, supra note 2, at 7-5. Non-utility electricity accounts for nearly 12% of the electric power generated, but it is the industry segment that produces nearly 94% of the electricity generated from non-hydroelectric renewable sources. In 2001, 239 were investor-owned utilities, 2009 publicly-owned, 10 federally-owned, and 912 cooperative electricity. Energy Info. Agency, U.S. Dep't of Energy, Overview of the Electric Power Industry, at http://www.eia.doe.gov/cneaf/electricity/page/primer.html (last visited Mar. 4, 2002). There were also 2110 nonutility power producers. Id.

(21) These companies are Southern California Edison Co., Pacific Gas and Electric Co., Commonwealth Edison Co., Texas Utilities Electric Co., Florida Power & Light Co., Consolidated Edison Co.--NY, Inc., Virginia Electric & Power Co., Georgia Power Co., Public Service Electric & Gas, and Duke Power Co. PROFILE, supra note 11, at 9. (Author note: The EIA data ranks individual companies not holding companies. If holding companies, such as American Electric Power, Southern, and Entergy were evaluated the concentration of revenue would be greater.)

(22) Id. at 8. These utilities include City of Los Angeles (CA), Salt River Project (AZ), Power Authority of State of NY, San Antonio Public Service Board (TX), City of Seattle (WA), Jacksonville Electric Authority (FL), Sacramento Municipal Utility District (CA), South Carolina Public Service Authority, City of Austin (TX), and Omaha Public Power District (NE). Id. at 10 tbl. 4.

(23) LARRY B. PARKER & JOHN E. BLODGETT, AIR QUALITY AND ELECTRICITY INITIATIVES TO INCREASE POLLUTION CONTROLS 4 (2001), available at http://www.cnie.org/nle/crsreports/air/air-34.cfm.

(24) Pub. L. No. 95-617, 92 Stat. 3117.

(25) 42 U.S.C.[subsection] 13201-13556 (2000).

(26) Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, 61 Fed. Reg. 21,540 (May 10, 1996). Public Utilities subject to Order No. 888 do not include public power systems.

(27) Open Access Same-Time Information System (Formerly Real-Time Information Networks) and Standards of Conduct, 61 Fed. Reg. 21,737 (May 10, 1996) (codified at 18 C.F.R. pt. 37 (2001)).

(28) Id. at 21,764.

(29) Deirdre Davidson, A Bolt of Regulatory Lightning: Bush's Energy Cop Surprises Industry with Ambitious Plans, LEGAL TIMES, Jan. 7, 2002, at 1.

(30) U.S. Energy Info. Admin., Dep't of Energy, Status of State Electric Industry Restructuring Activity, at http://www.eia.doe.gov/cneaf/felectricity/chg_str/tab5rev.html (last visited Mar. 16, 2002).

(31) Id.; see also Kirsten H. Engel, The Dormant Commerce Clause Threat to Market-Based Environmental Regulation: The Care of Electricity Deregulation, 26 ECOLOGY L.Q. 243, 247 n.6 (1999) (listing 16 state restructuring laws).

(32) ABA, SECTION OF ENV'T, ENERGY & RESOURCES, ENVIRONMENT, ENERGY, AND RESOURCES LAW: THE YEAR IN REVIEW 2000, at 1 (2001) [hereinafter THE YEAR IN REVIEW 2000]. For a more sinister view of deregulation and California's energy crisis, see Pearlstein, supra note 1, at A9.

(33) See Carolyn Whetzel, California: Pollution Control Rules Not Key Cause in Electric Power Crisis, State Officials Say, Daily Env't Rep. (BNA), Mar. 3, 2001, at A-2, WL 59 DEN A-2, 2001.

(34) Pearlstein, supra note 1, at A8.

(35) See Congressional Budget Office, Causes and Lessons of the California Electricity Crisis (Sept. 2001), available at http://www.cbo.gov/search.html.

(36) Pearlstein, supra note 1, at A8.

(37) LARRY PARKER & JOHN BLODGETT, ELECTRIC RESTRUCTURING: THE IMPLICATIONS FOR AIR QUALITY (2000), available at http://www.cnie.org/nle/crsreports/energy/eng-43.cfm.

(38) U.S. ENVTL. PROT. AGENCY, NSR 90-DAY REVIEW BACKGROUND PAPER 12 (June 22, 2001), available at http://www.epa.gov/air/nsr-review/nsr-review.pdf [hereinafter NSR 90-DAY REVIEW]. However, most non-utilities are owned by holding companies that include utilities.

(39) Id.

(40) Id. at 13.

(41) Id. at 15.

(42) Id. at 16.

(43) ENVT'L LAW INSTITUTE, CLEANER POWER: THE BENEFITS AND COSTS OF MOVING FROM COAL GENERATION TO MODERN TECHNOLOGIES 3 (May 2001), available at http://www.eli.org/pdf/rr01cleanerpower.pdf.

(44) Id.

(45) See generally Michael Evan Stern & Margaret M. Mlynczak Stern, A Critical Overview of the Economic and Environmental Consequences of the Deregulation of the U.S. Electric Power Industry, 4 ENVTL. LAW. 79, 101-64 (1997) (describing the theoretical justification for deregulation); William G. Rosenberg, Restructuring the Electric Utility Industry and Its Effect on the Environment, 14 PACE ENVTL. L. REV. 69, 73-76 (1996) (discussing the catastrophic effects deregulation will have on the environment).

(46) Pearlstein, supra note 1, at A9.

(47) See generally Rosenberg, supra note 45, at 77 (deregulation will provide the need for stricter regulations); Edward Smeloff, Utility Deregulation and Global Warming: The Coming Collision, 12 NAT. RESOURCES & ENV'T 280, 285 (1998) (describing the measures that policy makers must take to ensure that restructuring will decrease carbon emissions); Karen Palmer, Resources for the Future, Electric Restructuring: Shortcut or Detour on the Road Achieving Greenhouse Gas Reductions? (July 1999), available at http://www.rff.org/issue_briefs/PDF_files/ccbrf18.pdf.

(48) Robert F. Lawrence, Beware of Hidden Green Costs, LEGAL TIMES, June 14, 1999, at S36.

(49) Clean Air Act, 42 U.S.C. [section] 7410 (2000).

(50) Id. [subsection] 7410(m), 7509; Michigan Dep't of Envt'l Quality v. Browner, 230 F.3d 181, 185 (6th Cir. 2000).

(51) 42 U.S.C. [subsection] 7470-7492, 7501-7515 (2000).

(52) See generally ARNOLD W. REITZE, JR., AIR POLLUTION CONTROL LAW: COMPLIANCE AND ENFORCEMENT ch. 3 (2001).

(53) 42 U.S.C. [section] 7651(a)-(o) (2000). These sections refer to fossil-fuel-fixed combustion devices as "units." Id. [section] 7651(a)(15).

(54) Id. [section] 7651(c) (emission limitation for S[O.sub.2).

(55) Id. [section] 7651f.

(56) Attainment States Designation: California, 40 C.F.R. [section] 81.305 (2000):

(57) U.S. ENVTL. PROT. AGENCY, LATEST FINDINGS ON NATIONAL AIR QUAUTY: 1999 STATUS AND TRENDS 5 (2000) [hereinafter 1999 TRENDS REPORT].

(58)Id.

(59) Id. at 11.

(60) Id. at 5.

(61) Clean Air Act, 42 U.S.C. [subsection] 7511c, 7506a (2000). These sections give EPA the authority to establish other interstate transport regions, but to date no regions have been created. Karl James Simon, The Application and Adequacy of the Clean Air Act in Addressing Interstate Ozone Transport, 5 ENVTL. LAW. 129, 213 (1998).

(62) State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990, 57 Fed. Reg. 13,498, 13,527 (Apr. 16, 1992).

(63) 42 U.S.C. [section] 751ia(b)(2), (f) (2000). See generally Thomas O. McGarity, Missing Milestones: A Critical Look at the Clean Air Act's VOC Emissions Reduction Program in NonattainmentAreas, 18 VA. ENVTL. L.J. 41, 70-74 (1999).

(64) 42 U.S.C. [section] 7511a(c)(2)(B) (2000).

(65) Id. [section] 751Ia(e).

(66) Id. [section] 751ia(f); see New York v. EPA, 133 F.3d 987, 990-92 (7th Cir. 1998) (granting states bordering Lake Michigan an exception from normal restriction on nitrogen oxide emissions because EPA determined that reducing such levels would not contribute to the attainment of National Air Quality Standards for ozone).

(67) 42 U.S.C. [subsection] 7651-7651o (2000).

(68) Id. [section] 76511.

(69) Id.[section] 7651g(b).

(70) U.S. GEN. ACCOUNTING OFFICE, EMISSION SOURCES REGULATED BY MULTIPLE CLEAN AIR ACT PROVISIONS 12 (2000).

(71) See generally U.S. GEN. ACCOUNTING OFFICE, AIR QUALITY AND RESPIRATORY PROBLEMS IN AND NEAR THE GREAT SMOKY MOUNTAINS (2001), available at http://purl.access. gpo. gov/GPO/LPS12801.

(72) Laura Mahoney, California, Colorado Regulators Disagree on Need to Change New Source Review, Daily Env't Rep. (BNA), July 16, 2001, at A-13, WL 135 DEN A-13, 2001.

(73) S. 556, 107th Cong. (2001).

(74) H.R. 1256, 107th Cong. (2001); H.R. 1335, 107th Cong. (2001).

(75) Steve Cook, Northeast Still Suffering Severe Effects Despite Reductions in Power Plant Emissions, 32 Env't Rep. (BNA) 584, 584 (Mar. 30, 2001); Steve Cook, Schumer Sees `Best Chance in Years' To Gain Passage of N[O.sub.x] S[O.sub.2] Controls, 32 Env't Rep. (BNA) 853, 853 (May 4, 2001).

(76) Steve Cook, Bipartisan Bill Introduced to Regulate Power Plant Emissions of Four Pollutants, Daily Env't Rep. (BNA), Mar. 16, 2001, at AA-l, WL 52 DEN AA-I, 2001. A group of seven electric utilities responded with plans to seek the introduction of a bill that would reduce emissions of N[O.sub.x] and S[O.sub.2] 50% by 2008; reduce SO[sub.2] an additional 10% by 2012; reduce mercury 65% by 2008, and between 79% and 93% by 2012; and reduce C[O.sub.2] to 2000 levels by 2008, with further reduction to 1990 levels by 2012. Regina P. Cline, Seven Power Companies Draft Bill to Control Four Pollutants, Including C[O.sub.2'] Daily Env't Rep. (BNA), June 28, 2001, at A-2, WL 124 DEN A-2, 2001,; see also Steve Cook, EPA Considering Performance Standard for New Sources in Multi-Pollutant Proposal, Daily Env't Rep. (BNA), Sept. 11, 2001, at A-I, WL 175 DEN A-l, 2001 (discussing state enforcement and cap-and-trade systems).

(77) NATIONAL ENERGY POLICY, supra note 2, at 3-3.

(78) Steve Cook, Utilities Find EPA Multi-Pollutant Limits Cost Twice that of Less Ambitious Caps, Daily Env't Rep. (BNA), Sept. 14, 2001, at A-2, WL 177 DEN A-2, 2001.

(79) Whitman Calls for Quick Action in Congress on Three-Pollutant Measure, Delay on C[O.sub.2] 32 Env't Rep. (BNA) 1527, 1527 (Aug. 3, 2001).

(80) Steve Cook, Optional CO[sub.2] Reductions Included in Plan by Energy Companies to Lower Emissions, Daily Env't Rep. (BNA), Aug. 9, 2001, at A-10, WL 153 DEN A-10, 2001. CPG was formed by Calpine, Enron, Ni Source, Trigen Energy, and E1 Paso Corp. Its members primarily use natural gas to fuel their operations. Another lobby group, the Clean Energy Group, formed by several unregulated subsidiaries of electric utilities, is also lobbying for new controls. Id. Other industry groups include Energy for a Clean Air Future representing Cinergy Corp., Pennsylvania Power and Light Corp. (PPL), Reliant Energy Inc., Tampa Electric Co.,Trans Alta Corp., and Wisconsin Electric Power. The Alliance for Constructive Air Policy also includes Cinergy. See James V. Grimaldi, Energy-Industry's Links to Regulators, Administration Worry Environmentalists, WASH. POST, Sept. 10, 2001, at E13.

(81) Steve Cook, Level of Power Plant Emissions Cuts Will Determine Shape of New EPA Program, 32 Env't Rep. (BNA) 1576, 1576 (Aug. 10, 2001).

(82) See Clean Air Act, 42 U.S.C. [section] 7491 (2000) (regional haze).

(83) See discussion infra Part III. G (discussing interstate air pollution control).

(84) See generally REITZE, supra note 52, at 6 (explaining the possibilities behind stringent emission requirements).

(85) Steve Cook, Analysis of EPA Proposals for Power Plants Sees More Emissions in Multi-Pollutant Plan, 32 Env't Rep. (BNA) 2390, 2390 (Dec. 14, 2001).

(86) Competing Utility Emissions Plan May Create Congressional Hurdle, INSIDE EPA's ENVTL. POL'Y ALERT, Aug. 22, 2001, at 20, 20-21. CPG includes Ni Source, Enron, Calpine, El Paso, and Trigen. CEG includes Conectiv, Consolidated Edison, Northeast Utilities, PG&E National Energy Group, and Dempra Energy. Id.

(87) Steve Cook, More Industry Proposals Emerging on Controlling Power Plant Emissions, Daily Env't Rep. (BNA), Sept. 5, 2001, at A-8, WL 171 DEN A-8, 2001. ECAF is made up of Reliant Energy, PPL Corp., TECO Energy Inc., Trans Alta Corp., and Wisconsin Electric Power Co. Id.

(88) EPA Utility Plan Gains Support from White House Environment Panel, INSIDE EPA's ENVTL. POL'Y ALERT, Sept. 19, 2001, at 17, 17. See generally REDUCING EMISSIONS, supra note 16 (providing DOE's analysis of air pollution).

(89) Steve Cook, Industry Says EPA Multi-Pollutant Limits Cost Twice that of Less Ambitious Caps, 32 Env't Rep. (BNA) 1816, 1816 (Sept. 21, 2001).

(90) Western Utilities Seek Flexibility Under Multi-Pollutant Plan, INSIDE EPA's ENVTL. POL'Y ALERT, Sept. 19, 2001, at 15, 15-16.

(91) Steve Cook, Bill to Reduce Power Plant Emissions Slated for November Markup, Floor Action in 2002, 32 Env't Rep. (BNA) 1909 (Oct. 5, 2001).

(92) Steve Cook, Jeffords Bill Would Raise Electricity Costs Up to 50 Percent, EPA Official Tells Panel, Daily Env't Rep. (BNA), Nov. 2, 2001, at A-1, WL 211 DEN A-1, 2001.

(93) Steve Cook, Jeffords Aiming for February Markup of Four-Pollutant Bill for Power Plants, Daily Env't Rep. (BNA), Nov. 16, 2001, at A-1, WL 220 DEN A-1, 2001.

(94) Id.

(95) Unions Back Bush in Fight for Narrow Utility Emissions Reduction Bill, INSIDE EPA's ENVTL. POL'Y ALERT, Nov. 14, 2001, at 14, 14-15.

(96) PARKER & BLODGETT, supra note 37.

(97) Clean Air Act, 42 U.S.C. [section] 7411 (2000).

(98) Susanne Pagano, Texas: PUC Rule Allows Utilities to Recover Cost of Emission Control at Grandfathered Plants, 31 Env't Rep. (BNA) 1840, 1840 (Sept. 1, 2000).

(99) U.S. GEN. ACCOUNTING OFFICE, ELECTRICITY SUPPLY: OLDER PLANTS' IMPACT ON RELIABILITY AND AIR QUALITY 2 (1990).

(100) 42 U.S.C. [section] 7411(a)(2) (2000).

(101) Id. [section] 7411.

(102) 40 C.F.R. [subsection] 60.42-.44 (2001).

(103) Standards of Performance for New Stationary Sources, 36 Fed. Reg. 24,876, 24,879 (Dec. 23, 1971) (codified at 40 C.F.R. [section] 60.43 (2001)). A standard that is based on fuel inputs rewards inefficiency. The amount of fuel used, not the electricity generated, determines the emissions that are allowed.

(104) 42 U.S.C. [section] 7411(b)(6) (2000).

(105) New Stationary Sources Performance Standards; Electric Utility Steam Generating Units, 44 Fed. Reg. 33,580 (June 11, 1979) (codified at 40 C.F.R. pt. 60 (2001)).

(106) Id. at 33,580.

(107) Id.

(108) Id. at 33,581.

(109) The "[a]verage heating value of coal used to generate electricity in 1979 was 21.4 [mm]Btu per metric ton." WORLD ALMANAC AND BOOK OF FACTS 801 (Mark S. Hoffman ed., 1987). One million Btu would be produced by 103 pounds of such coal (2205 pounds of coal/21.4). Assuming very high sulfur coal (7%), this would produce 7.2 lbs of sulfur, which if reduced by 90%, as required by the regulation, results in an emission of .72 lbs of sulfur or 1.42 lbs of SO[sub.2]/mm Btu. Thus, except when burning very high sulfur coal, the 1.2 lb/mm Btu limit is not controlling.

(110) 40 C.F.R. [section] 60.43a (2001).

(111) Clean Air Act, 42 U.S.C. [section] 7411(a)(1)(A)(ii) (repealed 1990).

(112) Clean Air Act Amendments of 1990, Pub. L. No. 101-549, [section] 403(a), 104 Stat. 2399, 2631 (1990) (codified as amended at 42 U.S.C. [section] 7411(a)(1) (2000)).

(113) 42 U.S.C. [subsection] 7411(a), 7651b (2000).

(114) Sierra Club v. Costle, 657 F.2d 298, 312 (D.C. Cir. 1981).

(115) Id. at 356.

(116) See, e.g., United States v. West Penn Power Co., 460 F. Supp. 1305 (W.D. Pa. 1978).

(117) 42 U.S.C. [section] 7411(a)(1) (2000).

(118) Id. [section] 7423.

(119) Proposed Revision of Standards of Performance for Nitrogen Oxide Emissions from New Fossil-Fuel Fired Steam Generating Units; Proposed Revisions to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units, 62 Fed. Reg. 36,948 (proposed July 9, 1997) (to be codified at 40 C.F.R. pt. 60).

(120) Revision of Standards of Performance for Nitrogen Oxide Emissions from New Fossil-Fuel Fired Steam Generating Units; Revisions to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units, 63 Fed. Reg. 49,442 (Sept. 16, 1998) (codified at 40 C.F.R. pt. 60 (2001)).

(121) 40 C.F.R. [section] 60.44a (2001).

(122) Alec Zacaroli, Final Rule Sets Fuel Neutral NO[sub.x] Standard for New or Rebuilt Utility, Industrial Boilers, Daily Env't Rep. (BNA), Sept. 8, 1998, at AA-l, WL 173 DEN AA-l, 1998. On April 10, 2001, EPA issued a direct final nde modifying certain monitoring and measurement procedures. Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units, 66 Fed. Reg. 18,546 (Apr. 10, 2001) (codified at 40 C.F.R. pt. 60 (2001)).

(123) 40 C.F.R. [section] 60.44a (2001).

(124) Lignite Energy Council v. EPA, 1999 U.S. App. LEXIS 26263, at * 2 (D.C. Cir. Sept. 21,19991).

(125) Air Pollution: Responding to 1999 Ruling, EPA Withdraws Emissions Standard for Modified Boilers, Daily Env't Rep. (BNA), Aug. 14, 2001, at A-7, WL 156 DEN A-7, 2001.

(126) EPA maintains an Applicability Determination Index (ADI) that contains memoranda on applicability issues associated with NSPS, at http://www.epa.gov/oeca/eptdd/adi.htm. Modification is defined at 40 C.F.R. [section] 60.14 (2001); reconstruction is defined at 40 C.F.R. [section] 60.15 (2001).

(127) 893 F.2d 901 (7th Cir. 1990).

(128) 40 C.F.R. [section] 60.14(a) (2001).

(129) Clean Air Act, 42 U.S.C. [section] 7411(a)(4) (2000).

(130) 40 C.F.R. [section] 52.21(b)(2)(i) (2001).

(131) Id. [section] 52.21(b)(23).

(132) WEPCO, 893 F.2d at 910.

(133) Id. at 907.

(134) Id. at 910.

(135) Id. at 906.

(136) Id. at 911.

(137) Id.

(138) Id.

(139) Id. at 912.

(140) Id.

(141) S. Envtl. Law Center, Southeastern Energy News, S. RESOURCES, Jan. 1997, at 1.

(142) Id.

(143) Id.

(144) NSR 90-DAY REVIEW, supra note 38, at 2.

(145) Clean Air Act, 42 U.S.C. [subsection] 7475(a)(4), 7503(a)(2) (2000). The PSD program also requires applicants to protect air quality related values. See id. [section] 7475(d). See generally Alan P. Loeb & Tiffany J. Elliott, PSD Constxaints on Utility Planning: A Review of Recent Visibility Litigation, 34 NAT. RESOURCES J. 231 (1994) (discussing impact of PSD and visibility programs of the CAA on siting new and modifying existing utility and industrial plants).

(146) 42 U.S.C. [section] 7501(3) (2000).

(147) Id. [section] 7479(3).

(148) Envtl. Prot. Agency, New Source Review Policy and Guidelines Database, at http://www.epa.gov/region07/programs/artd/air/nsr/nsrpg.htm (last visited Feb. 15, 2002); see also Envtl. Prot. Agency, Applicability Determination Index, at http://www.epa.gov/oeca/eptdd/adi.html (last visited Feb. 15, 2002). EPA has a RACT/BACT/LAER Clearinghouse web site at http://www/epa/gov/clearinghouse (last visited Feb. 15, 2002). See EPA Requests Comments on Clean Air Database, Daily Env't Rep. (BNA), Nov. 19, 2001, at A-9, WL, 221 DEN A-9, 2001.

(149) 42 U.S.C. [section] 7479(1) (2000).

(150) 40 C.F.R. [section] 51.166(b)(1)(i)(a) (2001).

(151) NSR 90-DAY REVIEW, supra note 38, at 3.

(152) 42 U.S.C. [section] 751la(e) (2000).

(153) 40 C.F.R. [section] 51.165(a)(1)(iii) (2001).

(154) Id. [section] 51.165(a)(1)(v)(C)(8)(i). Significant is defined for several pollutants at id. [section] 51.166(b)(23).

(155) Id. [section] 51.166(b)(21).

(156) See WEPCO, 893 F.2d 901 (7th Cir. 1990). EPA later extended the WEPCO rule to steam-generating electric turbines. See EPA Relaxes Stringent Air Rules for Some Peak-Use Utility Turbines, INSIDE EPA's ENVTL. POL'Y ALERT, Aug. 22, 2001, at 21, 21-22.

(157) 40 C.F.R. [section] 51.166(b)(21)(v) (2001).

(158) 42 U.S.C. [section] 7503(c) (2000).

(159) Id. [section] 7503(a)(5).

(160) Id. [section] 7503(a)(2). In addition, all sources owned by the applicant within the state must be in compliance and public participant requirements must have been met. Id. [section] 7503(a)(3).

(161) Id. [section] 7475(a), (e).

(162) Id. [section] 7475(d); see also 40 C.F.R. [section] 51.166(b)(23)(iii) (2001).

(163) Byron Swift, Electric Utility Regulation: Grandfathering, New Source Review, and NO[sub.x]--Making Sense of a Flawed System, 31 Env't Rep. (BNA) 1538, 1538 (July 21, 2000).

(164) Id. at 1539.

(165) Id.

(166) An Environmental Law Institute report argues that fuel switching is the most efficient way to achieve pollution reduction. ENVTL. LAW INST., CLEAN POWER: THE BENEFITS AND COSTS OF MOVING FROM COAL GENERATION TO MODERN POWER TECHNOLDGIES (May 2001), available at http://www.eli.org.

(167) Mahoney, supra note 72, at A-14.

(168) Pamela Najor, Plantwide NSR Limits Offered by Industry Viewed by States as Generally Acceptable, Dally Env't Rep. (BNA), Mar. 20, 2000, at A-9, WL 54 DEN A-9, 2000.

(169) Susanne Pagano, State Closes Loophole in Air Standards, Sets Funding for Emissions Reduction Plan, Dally Env't Rep. (BNA), June 21, 2001, at A-10, WL 119 DEN A-10, 2001.

(170) Michael Bologna, Governor Signs Law Seeking to Limit Pollution from 'Grandfathered' Power Plants, 32 Env't Rep. (BNA) 1602, 1602 (Aug. 10, 2001).

(171) Clean Air Act, 42 U.S.C. [section] 7477 (2000).

(172) Id. [section] 7503(a).

(173) Solar Turbines, Inc. v. Seif, 678 F. Supp. 93, 97 (M.D. Pa. 1988).

(174) Memorandum from Eric V. Schaeffer, Director, Office of Regulatory Enforcement, Guidance on the Appropriate Injunctive Relief for Violations of Major New Source Review Requirements (Nov. 17, 1998) [hereinafter EPA's NSR Guidance], available at http://es.epa.gov/oeca/ore/aed/comp/gcomp/g5.html.

(175) Memorandum from John S. Seitz, Director, Office of Air Quality Planning and Standards, Potential to Emit for MACT Standards-Guidance on Timing Issues (May 16, 1995), available at http://www.epa.gov/ttn/oarpg/t3/memoranda/pteguid.pdf.

(176) EPA's NSR Guidance, supra note 174. A synthetic minor permit includes limits on operation and production (e.g., hours of operation) as well as limits requiring installation and operation of control technology. A violating source may not avoid the injunctive relief required by EPA's guidance by installing air pollution control equipment or making process changes that may reduce emissions to below the applicable thresholds, but not to the level possible with BACT/LAER-equivalent controls or process changes. Id.

(177) Id. EPA does not alter its current policy that the BACT or LAER determination is made at the time a source goes through NSR permit review. Thus, if a source violates NSR in 1995 (e.g., by constructing a major source without a major NSR permit) and finally applies for a permit in 1998, the 1998 NSR permit should comply with 1998 BACT or LAER technology. See, e.g., Memorandum from John S. Seitz, Director Stationary Source Compliance Division, EPA, to Air Management Division Directors (Jan. 11, 1990), available at http://www.epa.gov/ttn/nsr/psdl/p8_43.html.

(178) EPA's NSR Guidance, supra note 174.

(179) Mahoney, supra note 72, at A-13.

(180) Pamela Najor, House Panel Seeks Answers from EPA on Enforcement Actions on Electric Utilities, Daily Env't Rep. (BNA), Mar. 8, 2000, at A-l, WL 46 DEN A-1, 2000; Steve Cook, New Source Review Lawsuits Going Ahead Despite White House-Mandated Policy Review, Daily Env't Rep. (BNA), Sept. 5, 2001, at AA-1, WL 171 DEN AA-1, 2001.

(181) Pamela Najor, New York, Connecticut Sue Utility, Allege NSR Violations at 10 Plants, Daily Env't Rep. (BNA), Nov. 30, 2000, at A-12, WL 229 DEN A-10, 1999.

(182) Claims in NSR Lawsuits Lack Merit, Most Exceed Five-Year Limit, AEP Says, Daily Env't Rep. (BNA), May 11, 2000, at A-12, WL 92 DEN A-12, 2000.

(183) Pamela Najor, EPA Amends Suits Against Three Utilities to Allege CAA Violations at 12 More Plants, Daily Env't Rep. (BNA), Mar. 2, 2000, at A-9, WL, 42 DEN A-9, 2000.

(184) See, e.g., PARKER & BLODGETT, supra note 37, at 6; see also Steve Cook, Southern Company Emissions Targeted in Campaign by Environmental Groups, Daily Env't Rep. (BNA), Apr. 4, 2001, at A-8, WL 65 DEN A-8, 2001.

(185) Pamela Najor, EPA Settles with One of Seven Utilities Sued for New Source Review Violations, Daily Env't Rep. (BNA), Mar. 1, 2000, at AA-1, WL 41 DEN AA-1, 2000; see also Elliot Eder & Robin L. Juni, Has EPA Fired Up Utilities to Clear the Air?, 15 NAT. RESOURCES & ENV'T 8, 59 (2000) (describing the settlement features and anticipated results).

(186) PARKER & BLODGETT, supra note 37, at 6.

(187) Id.

(188) Id.; see also Brian Broderick, Ohio-Based Utility to Reduce Emissions at 10 Coal-Fired Plants in Air Act Settlement, 32 Env't Rep. (BNA) 10, 10 (Jan. 5, 2001).

(189) Andrew M. Ballard, Duke Power Claims EPA Is Changing Definition of 'Routine' Maintenance Unfairly, Daily Env't Rep. (BNA), Dec. 28, 2000, at A-7, WL 249 DEN A-7, 2000.

(190) Cook, supra note 180, at AA-1.

(191) See Tenn. Valley Auth. v. EPA, 278 F.3d 1184 (11th Cir. 2002).

(192) Julie R. Domike & Alec C. Zacaroli, Reinterpretation of NSR Regulations Could Have Costly Implications for Business, Daily Env't Rep. (BNA), Mar. 7, 2000, at B-1, WL 45 DEN B-1, 2000; Ballard, supra note 189, at A-7.

(193) See generally Domike & Zacaroli, supra note 192, at B-1 (describing how changes could place companies at greater enforcement risk and alter rules the industry has relied upon).

(194) Andrew M. Ballard, TVA Announces $1.5 Billion Plan to Install Five Scrubbers at Four Coal-Fired Plants, 32 Env't Rep. (BNA) 1952, 1952 (Oct. 12, 2001); see also PARKER & BLODGETT, supra note 37, at 3.

(195) Steve Cook, Utility, Refinery Lawsuits Going Ahead Despiie Bush-Mandated Policy Review, 32 Env't Rep. (BNA) 1794, 1795 (Sept. 14, 2001).

(196) Eric Pianin, Suits Against Power Firms Justified, Justice Dept. Says, WASH. POST, Jan. 16, 2002, at A17.

(197) In re Tenn. Valley Auth., No. CAA-2000-04-008, 2000 WL 1358648 (EAB Sept. 15, 2000) (final order on reconsideration).

(198) Id.

(199) Id.

(200) Id.

(201) Id.

(202) Steve Cook, TVA Asks Court to Vacate EPA Decision Upholding New Source Review Enforcement, Daily Env't Rep. (BNA), Mar. 12, 2001, at A-6, WL 48 DEN A-6, 2001.

(203) NSR 90-DAY REVIEW, supra note 38, at 28.

(204) Id.

(205) Id. at 29.

(206) Id. Draft guidance concerning cogenerators' exposure to NSR requirements is available at http://www.epa.gov/ttn/nsr.

(207) NSR 90-DAY REVIEW, supra note 38, at 29.

(208) Id.

(209) A May 2001 report by the National Coal Council (NCC) examined the effect of regulatory policy on efficiency gains at existing coal-fired power plants. NCC, INCREASED ELECTRICITY AVAILABILITY FROM COAL-FIRED GENERATION IN THE NEAR-TERM (May 2001). The report stated

   EPA has further indicated that it will treat innovative component upgrades
   that increase efficiency or reliability without increasing a unit's
   pollution producing capacity as modifications as well. EPA's current
   approach to these projects strongly discourages utilities from undertaking
   them, due to the significant permitting delay and expense involved, along
   with the retrofit of expensive emission controls that are intended for new
   facilities. This is the greatest current barrier to increased efficiency at
   existing units. To support this conclusion, NCC identified two EPA
   determinations, one involving Detroit Edison Company in May 2000 (discussed
   above), the other involving Sunflower Corporation in 1998, in which EPA
   ruled that improved, higher efficiency turbine blades could not be used to
   replace less efficient blades that had broken without invoking new source
   review and the associated costs for additional pollution controls.

Id. at 35.

(210) Pamela Najor, Inhofe, Breaux Ask Bush Administration to Suspend New Source Review Enforcement Daily Env't Rep. (BNA), Mar. 28, 2001, at AA-1, WL 60 DEN AA-1, 2001; Steve Cook, Two Senators Object to Colleagues' Request to Suspend New Source Review Enforcement, Daily Env't Rep. (BNA), Apr. 13, 2001, at A-3, WL 72 DEN A-3, 2001; Domike & Zacaroli, supra note 192, at B-1.

(211) NATIONAL ENERGY POLICY, supra note 2, at 7-18.

(212) NSR 90-DAY REVIEW, supra note 38.

(213) Id. at 19.

(214) Id.

(215) Id. at 20.

(216) Id. Combined cycle gas turbine use received EPA's approval on August 6, 2001 to use the WEPCO "actual to representative actual annual emissions" test for NSR applicability. See Letter from John S. Seitz, Director of Air Quality Planning and Standards, to Patrick M. Raher (Aug. 6, 2001), available at http://www.epa.gov/ttn/nsr/gen/cgtsd.pdf.

(217) Steve Cook, EPA to Miss Deadline for NSR Report: Finding Will Wait for Broader Pollution Plan, Daily Env't Rep. (BNA), Sept. 15, 2001, at AA-1, WL 157 DEN AA-1, 2001.

(218) U.S. DEP'T OF JUSTICE, NEW SOURCE REVIEW: AN ANALYSIS OF THE CONSISTENCY OF ENFORCEMENT ACTIONS WITH THE CLEAN AIR ACT AND IMPLEMENTING REGULATIONS 39 (2002), http://www.usdoj.gov/olp/nsrreport.pdf.

(219) White House Weighs Uncoupling NSR Reforms from Air Emissions Bill, INSIDE EPA's ENVTL. POL'Y ALERT, Oct. 31, 2001, at 18-19.

(220) Notice of Availability for Draft Guidance on Source Determinations for Combined Heat and Power Facilities Under the Clean Air Act New Source Review and Title V Programs, 62 Fed. Reg. 52,403 (Oct. 15, 2001). The draft guidance is available at http://www.epa.gov/ttn/nsr. See Steve Cook, EPA Draft Guidance Aims to Help Cogenerators Avoid New Source Review, 32 Env't Rep. (BNA) 2007 (Oct. 19, 2001).

(221) Steve Cook, New Source Review Reform May Include Plantwide Emissions Limits, Official Says, Daily Env't Rep. (BNA), Nov. 15, 2001, at A-1, WL 219 DEN A-1, 2001.

(222) Electric utility steam-generating unit is defined at Clean Air Act, 42 U.S.C. [section] 7412(a)(8) (2000).

(223) U.S. ENVTL. PROT. AGENCY, STUDY OF HAZARDOUS AIR POLLUTANTS FROM ELECTRIC UTILITY STEAM GENERATING UNITS--FINAL REPORT TO CONGRESS: VOLUME I (1998) [hereinafter FINAL REPORT].

(224) 1999 TRENDS REPORT, supra note 57, at 79.

(225) 1998 TRENDS REPORT, supra note 10, at 71.

(226) FINAL REPORT, supra note 223, at 6.

(227) Id. at 7.

(228) Id. at 16.

(229) See generally Arnold W. Reitze, Jr. & Randy Lowell, Control of Hazardous Air Pollution, 28 B.C. ENVTL. AFF. L. REV. 299 (2001) (providing synopsis of early efforts to control hazardous air pollutants and analyzing requirements and programs established by EPA).

(230) Clean Air Act, 42 U.S.C. [section] 7412 (2000) (defining and listing hazardous air pollutants).

(231) 1999 TRENDS REPORT, supra note 57, ch. 5.

(232) 42 U.S.C. [subsection] 11001-11050 (2000).

(233) Id. [section] 11023.

(234) Addition of Facilities in Certain Industry Sectors; Revised Interpretation of Otherwise Use; Toxic Release Inventory Reporting; Community Right-to-Know, 62 Fed. Reg. 23,834 (May 1, 1997).

(235) Alec Zacaroli, Utilities Should Begin Preparing Now for Release of TRI Data, Officials Say, 29 Env't Rep. (BNA) 1847, 1847 (Jan. 22, 1999).

(236) Judge Rejects Utilities' Control Argument, Upholds EPA Extension of TRI Requirements, Daily Env't Rep. (BNA), Apr. 7, 1999, at A-5, WL 66 DEN A-5, 1999.

(237) Clean Air Act, 42 U.S.C. [section] 7412(n)(1)(B) (2000).

(238) EPA Should Set Target Reduction Goals on Mercury for Utility Boilers, Report Says, Daily Env't Rep. (BNA), Mar. 20, 1998, at A-1, WL 53 DEN A-1, 1998.

(239) Pamela Najor, Agency View of Mercury Health Impact Not Likely to Change with New Utility Data, Daily Env't Rep. (BNA), Nov. 28, 2000, at A-7, WL, 229 DEN A-7, 2000.

(240) Alec Zacaroli, Utilities Told to Monitor Mercury Levels in Coal Under EPA Information Request, Daily Env't Rep. (BNA), Apr. 7, 1998, at A-1, WL 66 DEN A-1, 1998; Alec Zacaroli, Utilities Oppose Mercury Data Request, Maintain Measure Is Largely Unnecessary, Daily Env't Rep. (BNA), Nov. 17, 1998, at AA-3, WL, 221 DEN AA-3, 1998.

(241) Alec Zacaroli, EPA Decision on Mercury Emissions May Lead to Control Requirements by 2004, Daily Env't Rep. (BNA), Dec. 2, 1998, at AA-1, WL 231 DEN-AA-1, 1998.

(242) Byron Swift, A Better, Cheaper Way to Regulate Mercury, 29 Env't Rep. (BNA) 1721, 1721 (Jan. 1, 1999).

(243) Alec Zacaroli, Report Finds Cutting Mercury Emissions Would Be Less Costly than First Estimated, Daily Env't Rep. (BNA), Mar. 30, 1999, at A-1, WL 60 DEN A-1, 1999.

(244) Id.

(245) Id.

(246) Id.

(247) N.E. STATES FOR COORDINATED AIR USE MGMT., ENVIRONMENTAL REGULATION AND TECHNOLOGY INNOVATION: CONTROLLING MERCURY EMISSIONS FROM COAL-FIRED BOILERS 9 (2000).

(248) Regulatory Findings on the Emissions of Hazardous Air Pollutants from Electric Utility Steam Generating Units, 65 Fed. Reg. 79,825, 79,826 (Dec. 20, 2000). 249 Id. at 79,827.

(250) Id.

(251) Id.

(252) Id. at 79,829.

(253) Id. at 79,830.

(254) Id. at 79,827. Fifty facilities representing 0.2% of the reporting facilities in the U.S., Canada, and Mexico are responsible for about 30% of on-site hazardous releases. Of the 50, 27 are electric utilities. Peter Menyasz, U.S., Canada Make Strides in Curbing Toxic Releases, Progress Slow Elsewhere, CEC Says, 32 Env't Rep. (BNA) 1474, 1474 (July 27, 2001).

(255) Steve Cook, Emissions, Daily Env't Rep. (BNA), Feb. 22, 2001, at AA-l, WL 36 DEN AA-l, 2001 (citing Edison Elect. Inst. v. EPA, No. 01-1078 (D.C. Cir. Feb. 20, 2001)).

(256) Pamela Najor, Utilities Call Mercury Decision Unreasonable; States, Others Tell Court to Uphold EPA Rule, Daily Env't Rep. (BNA), Mar. 27, 2001, at A-5, WL 59 DEN A-5, 2001.

(257) Id. (citing Edison Elec. Inst. v. EPA, No. 01-1078 (D.C. Cir. Feb. 20, 2001)).

(258) Study Says Utilities Responsible for Mercury Contamination, INSIDE EPA'S ENVTL. POL'Y ALERT, Aug. 8, 2001, at 27, 27.

(259) U.S. DEP'T OF ENERGY, ENVIRONMENTAL BENEFITS OF CLEAN COAL TECHNOLOGIES 4 (2001).

(260) Court Rejects Utility Challenge to EPA Plans on Mercury Controls, INSIDE EPA'S CLEAN AIR REPORT, Aug. 2, 2001, at 22, 22 (referring to Util. Air Regulatory Group v. EPA (D.C. Cir. July 26, 2001)).

(261) Darren Goode, Environmentalists to Sue EPA for Missing Air Act, Agency Deadlines, INSIDE EPA'S ENVTL. POL'Y ALERT, July 25, 2001, at 11, 11-12.

(262) Pamela Najor, States Urge Action by Congress, Bush to 'Substantially' Cut Mercury Release, Daily Env't Rep. (BNA), Mar. 7, 2001, at A-7, WL 45 DEN A-7, 2001.

(263) See supra notes 73-76 and accompanying text.

(264) Steve Cook, EPA Proposal to Reduce Mercury Emissions Draws Opposition from Energy Department, 32 Env't Rep. (BNA) 1709, 1709 (Aug. 31, 2001).

(265) Wisconsin Mercury Plan Would Cover All Sources, Allow Trading, INSIDE EPA'S CLEAN AIR REPORT, June 21, 2001, at 7, 7.

(266) Environmentalists Push For Utility Toxic Control Beyond Mercury, INSIDE EPA'S ENVTL. POL'YALERT, Nov. 28, 2001, at 16, 16.

(267) 1998 TRENDS REPORT, supra note 10, at 122.

(268) Clean Air Act, 42 U.S.C. [section] 765If(b)(2) (2000).

(269) U.S. DEP'T OF ENERGY ET AL., REBURNING TECHNOLOGIES FOR THE CONTROL OF NITROGEN OXIDES EMISSIONS FROM COAL-FIRED BOILERS 9 (1999), available at http://www.lanl.gov/projects/cctc/topicalreports/documents/topical14.pdf.

(270) Id.

(271) Id. SCR has been used primarily on combined-cycle turbines, but its use is being extended to simple-cycle combustion turbines. Regina P. Cline, New Technology May Affect Process for Obtaining Permits, Consultant Says, 32 Env't Rep. (BNA) 1311 (July 6, 2001).

(272) Swift, supra note 18, at B-1.

(273) 42 U.S.C. [section] 7651f (2000).

(274) Id. [section] 7651(b).

(275) Id. [section] 7651f.

(276) Id. [section] 7651j(a), (c).

(277) Id. [section] 7651f(b)(1).

(278) See id. [section] 7651f(b)(2) (describing emission limitations for boilers).

(279) Id. [section] 7651f(a).

(280) Id. [section] 7651(b)(1).

(281) Id. [section] 7651f(b)(2).

(282) Id. [section] 7651f(c)(1).

(283) Id. [section] 765If(d).

(284) Id. [section] 7651f(e)

(285) State Implementation Plans; Nitrogen Oxides Supplement to the General Preamble for the Implementation of Title 1 of the Clean Air Act Amendments of 1990, 57 Fed. Reg. 55,620 (Nov. 25, 1992) (codified at 40 C.F.R. pt. 52 (2001)); Acid Rain Program; Nitrogen Oxides Emission Reduction Program, 57 Fed. Reg. 55,632 (Nov. 25, 1992) (codified at 40 C.F.R. pt. 76 (2001)).

(286) Acid Rain Program; Nitrogen Oxides Emission Reduction Program, 59 Fed. Reg. 13,538 (Mar. 22, 1994).

(287) 42 U.S.C. [section] 7651f(b) (2000).

(288) Power Plant Asks Appeals Court to Eliminate Overfire Technology Requirements in EPA Rule, 25 Env't Rep. (BNA) 1260 (Oct. 28, 1994).

(289) 40 F.3d 450 (D.C. Cir. 1994).

(290) Id. at 445.

(291) EPA Proposes Settlement on Core Acid Rains Rules, ENVTL. WK., Jan. 26, 1995, at 2.

(292) Acid Rain Program: Nitrogen Oxides Emission Reduction Program, 60 Fed. Reg.41, 068 (Apr. 13, 1995) (codified at 40 C. F. R. pt. 76 (2001)

(293) Acid Rain Program: Acid Rain Compliance Plans and Exemptions, 60 Fed. Reg. 41,068 (Apr. 11, 1995).

(294) Byron Swift, Command Without Control: Why Cap-and-Trade Should Replace Rate Standards for Regional Pollutants, 31 ENVTL. L. Rep. (ENVTL. L. Inst.) 10,330, 10333 (March 2001).

(295) Id.

(296) Acid Rain Program: Nitrogen Oxides Emission Reduction Program, 61 Fed. Reg. 67,112 (Dec. 19, 1996).

(297) Id. at 67,113.

(298) Id.

(299) Id. at 67,114.

(300) Appalachian Power Co. v. EPA, 135 F.3d 791,827 (D.C. Cir. 1998).

(301) Id.

(302) Acid Rain Program; Nitrogen Oxides Emission Reduction Program, Final Rule in Response to Court Order, 63 Fed. Reg. 24,116 (May 1, 1998) (codified at 40 C.F.R. pt. 63 (2001)).

(303) Acid Rain Program--Nitrogen Oxides Emission Reduction Program, Rule Revision in Response to Court Remand, 64 Fed. Reg. 55,834 (Oct. 15, 1999) (codified at 40 C.F.R. pt. 76 (2001)).

(304) Pamela Najor, EPA Revises Acid Rain Regulation for Coal-Fired Boilers Due to Court Action, Daily Env't Rep. (BNA), Oct. 18, 1999, at A-9, WL 200 DEN A-9, 1999.

(305) Steve Cook, Utility Installing NO[sub.x] Controls at Two W. Va. Plants at Cost of $230 Million, Daily Env't Rep. (BNA), Feb. 2, 2001, at A-7, WL 23 DEN A-7, 2001.

(306) Julie Cohen, Wisconsin Utility Proposes Plan To Cut S[O.sub.2] and NO[sub.x] at Five Plants, Daily Env't Rep. (BNA), July 25, 2000, at A-9, WL 143 DEN A-9, 2000.

(307) Notice of Availability for Draft Guidance on BACT for NO[sub.x] Control at Combined Cycle Turbines, 65 Fed. Reg. 50,202 (Aug. 17, 2000).

(308) See Cline, supra note 271, at 1311 (discussing technology considerations, including draft EPA guidance regarding application for SCR and related cost-benefit analysis).

(309) Swift, supra note 18, at B-1.

(310) 40 C.F.R. [subsection] 60.44, 60.44a (2001).

(311) Swift, supra note 18, at B-2.

(312) Id.

(313) Approval and Promulgation of Implementation Plans, 37 Fed. Reg. 10,842 (May 30, 1972) (codified at 40 C.F.R. pt. 52 (2001)).

(314) 489 F.2d 390 (5th Cir. 1974).

(315) Id. at 394.

(316) 421 U.S. 60 (1975).

(317) Id. at 79.

(318) Big Rivers Elec. Corp. v. EPA, 523 F.2d 16, 21 (6th Cir. 1975); Kennecott Copper Corp. v. Train, 526 F.2d 1149, 1153 (9th Cir. 1975), cert. denied, 425 U.S. 935 (1976); Mision Indus., Inc. v. EPA, 547 F.2d 123, 129 (1st Cir. 1976).

(319) Stack Height Increase Guidelines, 41 Fed. Reg. 7450 (Feb. 11, 1976).

(320) Id.

(321) Id.

(322) Id.; M. Borreli, Up, Up, andAway, AMICUSJ., Spring 1985, at 2.

(323) Intermittent controls are those used when atmospheric conditions are so poor that concentrations of air pollution build up. Intermittent controls allow less costly control because control may only be needed a few times a year, but their use requires sophisticated air monitoring capability which makes enforcement difficult for the government. See Dow Chem. Co. v. EPA, 635 F.2d 559, 560 (6th Cir. 1980) (describing Dow's supplementary control system), cert. denied, 452 U.S. 939.

(324) Id. at 562.

(325) Clean Air Act, 42 U.S.C. [section] 7423(a) (2000).

(326) In Dow Chemical Co. v. EPA, the court upheld EPA's refusal to approve a revision to Michigan's SIP on the ground that it did not include solely continuous emissions control systems. 635 F.2d at 561-62.

(327) 1977 Clean Air Act Amendments for Stack Heights, 44 Fed. Reg. 2608 (Dec. 29, 1979) (codified at 40 C.F.R. pt. 51 (2001)).

(328) 636 F.2d 323, 387 (D.C. Cir. 1979).

(329) Approval and Promulgation of State Implementation Plans, 42 Fed. Reg. 57,459, 57,460 (Oct. 31, 1977) (codified at 40 C.F.R. pt. 52 (2001)).

(330) Stack Height Regulations, 47 Fed. Reg. 5864 (Feb. 8, 1982) (codified at 40 C.F.R. pt. 51 (2001)).

(331) Sierra Club v. EPA, 719 F.2d 436, 440-41 (D.C. Cir. 1983), cert. denied, 468 U.S. 1204 (1984).

(332) Id. at 441 (internal citations omitted).

(333) Id. at 443.

(334) Id.

(335) Id. at 466-68.

(336) Stack Height Regulation, 50 Fed. Reg. 27,892 (July 8, 1985) (now at 40 C.F.R. pt. 100 (2001)).

(337) Natural Res. Def. Council, Inc. v. Thomas, 838 F.2d 1224 (D.C. Cir. 1988).

(338) Id. at 1236.

(339) Id. at 1238.

(340) Id. at 1245-46.

(341) Id.

(342) The regulations governing stack heights are part of the extensive Requirements for Preparation, Adoption, and Submittal of Implementation Plans, codified at 40 C.F.R. pt. 51 (2001). The basic requirement is that the degree of emissions limitation required of any source must not be affected by any dispersion technique, including a source's stack height that exceeds good engineering practice (GEP). 40 C.F.R. [section] 51.164 (2001) (stack height procedures). In addition to the ban on stack height that exceeds GEP, the regulations prohibit intermittent controls and improper manipulation of the exhaust gas plume. Id. [section] 51.100(hh). GEP is defined as the greater of three different measures: 1) 65 meters, 2) for sources that relied on EPA's regulatory position and had a stack in existence on January 12, 1979, the height of nearby structures, or 3) for all other sources, H + 1.5L, where H is the height of nearby structures and L is the lesser of the height or width of the nearby structures. Id. [section] 51.100(ii). A taller stack may be treated as GEP if the need for increased height is demonstrated by a fluid model or field study approved by EPA or a state or local control agency that ensures that the emissions from a stack do not result in excessive concentrations of any air pollutant. Id. [section] 51.100(ii)(3). For sources seeking credit for heights greater than the GEP formula, the ground level concentration must be at least 40% greater than that which would be experienced without downwash, wakes, or eddy effects. Id. [section] 51.100(kk)(1). The use of any intermittent control system may also be considered when establishing an emission limitation for a pollutant under a SIP. Id. [section] 51.119 (intermittent control systems). In addition, regulations promulgated in 1988 affect section 123. Stack Height Emissions Balancing; Final Policy, 53 Fed. Reg. 480 (Jan. 7, 1988) (codified at 40 C.F.R. pt. 51 (2001)). These regulations say an "affected source" that must meet more stringent emissions limitations due to stack height regulations can meet its legal requirements by securing reduction from another source within the same state or interstate air quality control region (AQCR). Id. However, to rely on this provision, the affected source must show that total emissions will be reduced 20% more than if the affected source met the emission limitations. Id. The affected source also must show that the area will attain the NAAQS and is designated as either a PSD area or is in the process of implementing an approved SIP. Id. at 481.

(343) But see Kammer Power Plant; West Virginia; Stack Height Infeasibility Analysis, 63 Fed. Reg. 44,434 (Aug. 19, 1998).

(344) Stack Heights, INSIDE EPA's CLEAN AIR REPORT, Nov. 3, 1994, at T-3.

(345) Clean Air Act, 42 U.S.C. [section] 7415 (2000).

(346) Id.

(347) 613 F. Supp. 1472 (D.D.C. 1985).

(348) Id. at 1476.

(349) Thomas v. New York (Thomas II), 802 F.2d 1443 (D.C. Cir. 1986), cert. denied, 482 U.S. 919 (1987).

(350) Thomas I, 613 F. Supp. at 1484.

(351) Thomas II, 802 F.2d at 1446.

(352) 5 U.S.C. [subsection] 551-559, 701-706, 1305, 3105, 3344, 4301, 5335, 5372, 7521 (2000).

(353) Thomas II, 802 F.2d at 1446-48.

(354) Id.

(355) Her Majesty the Queen in Right of Ontario v. EPA, 912 F.2d 1525, 1530 (D.C. Cir. 1990).

(356) Id.

(357) Id.

(358) Clean Air Act, 42 U.S.C. [section] 7651c(e)(3), tbl. A (2000).

(359) Agreement on Air Quality, Mar. 13, 1991, U.S.-Can., 30 I.L.M. 676.

(360) See International Joint Commission; Boundary Waters Treaty of 1909; An Invitation to Comment on the 1996 Progress Report of the Air Quality Committee Under the Canada-United States Air Quality Agreement, 61 Fed. Reg. 58,728 (Nov 18, 1996).

(361) Aiec Zacaroli, U.S., Canada Sign Air Pollution Pact, Fail to Commit to Specific Reductions, Daily Env't Rep. (BNA), Apr. 8, 1997, at AA-1, WL 67 DEN AA-1, 1997.

(362) UNITED STATES-CANADA, AIR QUALITY AGREEMENT 1998 PROGRESS REPORT 25 (1998), available at http://www.epa.gov/airmarkets/usca/airus98.pdf. This report also covers the progress made in reducing acid deposition.

(363) Committee on Enviromuent and Public Works, Clean Air Act Amendments of 1980, S. REP. No. 101-228, at 289 (1989).

(364) Clean Air Act Amendments of 1970, Pub. L. No. 91-604, [section] 110(a)(2)(E), 84 Stat. 1676 (1970).

(365) Clean Air Act, 42 U.S.C. [section] 7410(a)(2)(D)(i) (2000). The provision states in part that SIPs shall not

   (I) contribute significantly to nonattainment in, or interfere with
   maintenance by, any other State with respect to any such national primary
   or secondary air quality standard, or

   (II) interfere with measures required to be included in the applicable
   implementation plan for any other State under part C to prevent significant
   deterioration of air quality or to protect visibility.

Id.

(366) Virginia v. EPA, 108 F.3d 1397 (D.C. Cir. 1997), modified by 116 F.3d 499 (1998); Train v. Natural Res. Def. Council, 421 U.S. 60, 79 (1975).

(367) 42 U.S.C. [section] 7410(k)(5) (2000).

(368) New York v. EPA, 852 F.2d 574 (D.C. Cir. 1988); Air Pollution Control Dist. of Jefferson Co., Ky. v. EPA, 739 F. 2d 1071 (6th Cir. 1984).

(369) Connecticut v. EPA, 656 F.2d 902, 910 (2d Cir. 1981); see Timothy Talkington, Note, Interstate Air Pollution Abatement and the Clean Air Act Amendments of 1990: Balancing Interests, 62 U. COLO. L. REV. 957, 959-64 (1991).

(370) 42 U.S.C. [section] 7426 (2000).

(371) See, e.g., Southwestern Pa. Growth Alliance v. Browner, 121 F.3d 106 (3d Cir. 1997). One writer has chronicled EPA's reticence to use its powers under [section] 126. Vickie L. Patton, The New Air Quality Standards, Regional Haze, and Interstate Air Pollution Transport, 28 Envtl. L. Rep. (Envtl. L. Inst.) 10,155 (Apr. 1998).

(372) Patton, supra note 371, at 10,166.

(373) New York v. Ruckelshaus, 14 Envtl. L. Rep. (Envtl. L. Inst.) 20,873 (D.D.C. Oct. 5, 1984).

(374) Id.

(375) Interstate Pollution Abatement, Final Determination, 49 Fed. Reg. 48,152 (Dec. 10, 1984) (codified at 40 C.F.R. pt. 52 (2001)).

(376) New York v. EPA, 852 F.2d 574 (D.C. Cir. 1988); see also Connecticut v. EPA, 656 F.2d 902 (2d Cir. 1981); Air Pollution Control Dist. of Jefferson Co., Ky. v. EPA, 739 F.2d 1071 (6th Cir. 1984).

(377) New York v. EPA, 852 F.2d at 578.

(378) Clean Air Act Amendments of 1990, Pub. L. No. 101-549, 104 Stat. 2399, 2469 (1990).

(379) Discussion of the 1990 CAA amendments to [section] 126 and the case law concerning this section is found in Talkington, supra note 369.

(380) Clean Air Act, 42 U.S.C. [section] 7426(c) (2000).

(381) Id. [section] 7426(b).

(382) Id. [section] 7426(c).

(383) Id. [section] 7511c(a).

(384) Memorandum of Understanding Among the States of the Ozone Transport Commission on Development of a Regional Strategy Concerning the Control of Stationary Source Nitrogen Oxide Emissions (signed Sept. 27, 1994), available at http://www.sso.org/otc.

(385) Massachusetts: State, Energy Producers Agree to Reduce Nitrogen Oxide Emissions by 15 Percent, Daily Env't Rep. (BNA), July 30, 1996, at B-1 WL DEN B-1, 1996.

(386) Dennis C. Vacco & J. Jared Snyder, New York State's Legal Battle Against Upwind Pollution and Acid Rain: The Attorney General's Perspective, ENVTL. L. IN N.Y., Sept. 1998, at 129, 141.

(387) Alec Zacaroli, Study Says Fixing Northeast Ozone Problem Requires Deep Cuts in Midwestern Emissions, Dally Env't Rep. (BNA), Mar. 19, 1997, at A-5, WL DEN A-5, 1997.

(388) Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone, 63 Fed. Reg. 57,356 (Oct. 27, 1998) (codified at 40 C.F.R. pts. 51, 72, 75, 96 (2001)) [hereinafter SIP Call].

(389) Id. at 57,362. OTAG recommendations are found at Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone, 62 Fed. Reg. 60,318, 60,376, app. B (proposed Nov. 7, 1997).

(390) The proposed rule was announced October 10, 1997. See Alec Zacaroli, Proposal Calls on 22 States to Cut N[O.sub.x] Emissions by 1.6 Million Tons Per Year, 28 Env't Rep. (BNA) 1198 (Oct. 17, 1997).

(391) SIP Call, supra note 388, at 57,355.

(392) Alec Zacaroli, Petitions from Northeast States Ask EPA to Cut Emissions from Hundreds of Sources, Daily Env't Rep. (BNA), Aug. 15, 1997, at AA-1, WL 158 DEN AA-1, 1997; Eight Northeastern States Petition EPA for Direct Action on Transported Pollution, 28 Env't Rep. (BNA) 709 (Aug. 15, 1997).

(393) Finding of Significant Contribution and Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 63 Fed. Reg. 56,292 (proposed Oct. 21, 1998) (codified at 40 C.F.R. pts. 52, 97 (2001)) [hereinafter Proposed 126 Rule].

(394) See id. at 56,297 tbl. I-1 (summarizing the eight petitions).

(395) Midwest Ozone Group v. EPA, No. 97-1627 (D.C. Cir. Oct. 6, 1997).

(396) Alec Zacaroli, Air Pollution: Midwest Utility Group Sues EPA to Block Petitions by Northeast States for N[O.sub.x] Cuts, Daily Env't Rep. (BNA), Oct. 10, 1997, at A-5, WL 197 DEN A-5, 1997.

(397) Proposed 126 Rule, supra note 393, at 56,299 (citing Connecticut v. Browner, No. 98-1376 (S.D.N.Y. 1988)).

(398) Proposed Settlement Agreement; Ozone Transportation in Eastern United States; Section 126 Petitions Filed by Northeastern States, 63 Fed. Reg. 10,874 (Mar. 5, 1998).

(399) Findings of Significant Contribution and Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 63 Fed. Reg. 24,058 (Apr. 30, 1998) (codified at 40 C.F.R. pt. 52 (2001)).

(400) Proposed 126 Rule, supra note 393.

(401) Id.

(402) Id. at 56,309.

(4O3) Id.

(404) See generally Approval and Promulgation of Air Quality Implementation Plans; New Hampshire, New Hampshire-Nitrogen Oxides Budget and Allowance Trading Program, 65 Fed. Reg. 68,111 (proposed Nov. 14, 2000) (summarizing the proposed rule).

(405) SIP Call, supra note 388.

(406) James Kennedy & Martha Kessler, States May Force EPA Action on Clean Air Act Section 126 Petitions, Dally Env't Rep. (BNA), Oct. 16, 1997, at A-7, WL 200 DEN A-7, 1997.

(407) SIP Call, supra note 388, at 57,356.

(408) In addition, some states are subject to the NSR enforcement discussed above in Part IV.C. Five states--Indiana, Kentucky, North Carolina, Ohio, and West Virginia--are subject to the N[O.sub.x] SIP call, the section 126 determination and the NSR enforcement action. Florida and Mississippi have been targeted only for NSR enforcement. Connecticut, Massachusetts, Missouri, and Rhode Island are subject to the SIP call. Alabama, Georgia, Illinois, South Carolina, and Tennessee are subject to NSR enforcement action and the N[O.sub.x] SIP call. Delaware, Maryland, New Jersey, New York, Pennsylvania, and Virginia are subject to the section 126 action and the N[O.sub.x] SIP call. See LARRY B. PARKER & JOHN E. BLODGETT, AIR QUALITY AND ELECTRICITY: INITIATIVES TO INCREASE POLLUTION CONTROLS (Mar. 9, 2001), http://www.cnie.org/nle/crsreports/air/air-34.cfm.

(409) SIP Call, supra note 388, at 57,358.

(410) Id.

(411) Id. at 57,359, 57,476.

(412) Id. at 57,355.

(413) Alec Zacaroli, States Expected Not to Meet Deadline for Submitting Ozone Transport Rule Plans, Daily Env't Rep. (BNA), Jan. 13, 1999, at AA-1, WL 08 DEN AA-1, 1999.

(414) SIP Call, supra note 388, at 57,365.

(415) Id. at 57,433.

(416) Id.

(417) Id. at 57,434-35.

(418) Id. at 57,439.

(419) Technical Amendments to the Findings of Significant Contribution and Rulemaking for Certain States for Purposes of Reducing Regional Transport of Ozone, 64 Fed. Reg. 26,298, 26,299 (May 14, 1998). (codified at 40 C.F.R. pt. 51 (2001)).

(420) SIP call, supra note 388, at 57,365-66.

(421) Id. at 57,428.

(422) Id. at 57,429. A supplemental notice of proposed rulemaking, technical corrections, and notice of availability was promulgated on Mar. 3, 1999 at 64 Fed. Reg. 10,341-42.

(423) Technical Amendment to the Finding of Significant Contribution and Rulemaking for Certain States for Purposes of Reducing Regional Transport of Ozone, 64 Fed. Reg. 26,298 (May 14, 1999) (codified at 40 C.F.R. pt. 51 (2001)).

(424) Swift, supra note 294, at 10,335.

(425) Id.

(426) Findings of Significant Contribution and Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 64 Fed. Reg. 28,250 (May 25, 1999) (codified at 40 C.F.R. pt. 52 (2001)).

(427) Federal Implementation Plans to Reduce the Regional Transport of Ozone, 63 Fed. Reg. 56,394 (Oct. 21, 1998) (codified at 40 C.F.R. pts. 52, 98 (2001)).

(428) Id. at 56,296.

(429) Michigan v. EPA, No. 98-1497, 1999 U.S. App. LEXIS 38833 (D.C. Cir. May 25, 1999); see Tony Kreindler, Appeals Court Delays SIP Deadline Pending Review of Challenge to N[O.sub.x] Rule, Dally Env't Rep. (BNA), May 27, 1999, at AA-1, WL 102 DEN AA-1, 1999; Alec C. Zacaroli, Court Rulings Imperil EPA's Efforts to Clamp Down on Ozone Pollution, Daily Env't Rep. (BNA), June 21, 1999, at B-1, WL 118 DEN B-1, 1999.

(430) Findings of Significant Contribution and Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 65 Fed. Reg. 2674 (Jan. 18, 2000) (codified at 40 C.F.R. pts. 52, 97 (2001)).

(431) Id. at 2676.

(432) Technical Amendment to the Finding of Significant Contribution and Rulemaking for Certain States for Purposes of Reducing Regional Transport of Ozone, 65 Fed. Reg. 11,222 (Mar. 2, 2000) (codified at 40 C.F.R. pt. 51 (2001)).

(433) Michigan v. EPA, 213 F.3d 663, 689 (D.C. Cir. 2000); see Zacaroli, supra note 429, at B-1.

(434) Michigan v. EPA, 213 F.3d at 681-85.

(435) PARKER & BLODGETT, supra note 408.

(436) Interim Final Stay of Action on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 64 Fed. Reg. 33,956 (June 24, 1999) (codified at 40 C.F.R. pt. 52 (2001)).

(437) 175 F.3d 1027 (D.C. Cir. 1999), reh'g denied in part & granted in part, 195 F.3d4 (D.C. Cir. 1999), rev'din partsub nom., Whitman v. Am. Trucking Ass'n, 531 U.S. 457 (2001).

(438) Id. at 1057:

(439) Final Rule to Extend the Stay of Action on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 64 Fed. Reg. 67,781 (Dec. 3, 1999) (codified at 40 C.F.R. pt. 52 (2001)).

(440) Final Rule to Extend the Stay of Action on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport, 65 Fed. Reg. 2039 (Jan. 13, 2000) (codified at 40 C.F.R. pt. 52 (2001)).

(441) Pamela Najor, Court Should Not Give States Extra Time to Develop N[O.sub.x] Control Plans, EPA Says, Daily Env't Rep. (BNA), May 19, 2000, at A-1, WL 98 DEN A-1, 2000.

(442) Pamela Najor, Six States Ask Federal Appeals Court to Delay Oct. 30 Deadline for N[O.sub.x] Plans, Daily Env't Rep. (BNA), Aug. 9, 2000, at A-1, WL 154 DEN A-1, 2000.

(443) Petition for Secondary National Ambient Air Quality Standards for Nitrogen Dioxide, Sulfur Dioxide, and Fine Particulate Matter and Related Request, 65 Fed. Reg. 48,699 (Aug. 9, 2000).

(444) Michigan v. EPA, No. 98-1497, 2000 WL 1341477 (D.C. Cir. Aug. 30, 2000).

(445) Pamela Najor, Federal Court Grants More Time to Utilities to Comply with 1998 Ozone Trarcsport Rule, 31 Env't Rep. (BNA) 1922, 1922 (Sept. 15, 2000).

(446) Proposed Settlement Agreements on Regulations Under Section 126 of the Clean Air Act Reducing Regional Transport of Ozone, 65 Fed. Reg. 67,742 (Nov. 13, 2000).

(447) Stay of the Eight-Hour Portion of the Findings of Significant Contribution and Rulemaking for Purposes of Reducing Interstate Ozone Transport, 65 Fed. Reg. 56,245 (Sept. 18, 2000) (codified at 40 C.F.R. pt. 51 (2001)).

(448) Final Rule Making Findings of Failure to Submit Required State Implementation Plans for the N[O.sub.x] SIP Call, 65 Fed. Reg. 81,366 (Dec. 26, 2000) (codified at 40 C.F.R. pt. 51 (2001)).

(449) Id.

(450) 249 F.3d 1032, 1036 (D.C. Cir. 2001).

(451) Id. at 1037.

(452) Id. at 1036.

(453) Id. at 1046.

(454) Id. at 1050.

(455) Id. at 1051.

(456) Id. at 1055.

(457) Id. at 1056; see also Revisions of the Federal N[O.sub.x] Budget Trading Program, the Emissions Monitoring Provisions, the Permits Regulation Provisions and the Appeals Procedures, 66 Fed. Reg. 31,978 (proposed June 13, 2001).

(458) Appalachian Power I, 249 F.3d at 1063.

(459) Appalachian Power Co. v. EPA (Appalachian PowerII), 251 F.3d 1026 (D.C. Cir. 2001).

(460) 213 F.3d 663 (D.C. Cir. 2000).

(461) Appalachian Power II, 251 F.3d at 1026.

(462) Id. at 1035.

(463) Id.

(464) Steve Cook, Ruling Makes EPA Less Likely to Meet Deadline for N[O.sub.x] Limits, Attorney Says, Dally Env't Rep. (BNA), June 11, 2001, at AA-1, WL 112 DEN AA-1, 2001; see also Patricia McCubbin, Michigan v. EPA: Interstate Ozone Pollution and EPA's N[O.sub.x] SIP Call, 20 ST. Louis U. PUB. L. REV. 47 (2001); Patricia McCubbin, Looking to Upwind States to Reduce Interstate Ozone Pollution, 31 Envtl. L. Rep. (Envtl. L. Inst.) 11,045 (Sept. 2001) (discussing N[O.sub.x] SIP that required 23 states to reduce nitrogen emissions).

(465) Steve Cook, Utilities Seek Delay in Ozone Transport Rule While EPA Weighs Emissions Limits Changes, Daily Env't Rep. (BNA), July 3, 2001, at A-2, WL 127 DEN A-2, 2001.

(466) Availability of Documents for the Response to the Remedies in the Ozone Transport Cases Concerning the Method for Computing Growth for Electric Generating Units, 66 Fed. Reg. 40,609 (Aug. 3, 2001).

(467) Federal Appeals Court Delays Ozone Controls on Electric Utilities, INSIDE EPA's ENVTL. POL'Y ALERT, Sept. 5, 2001, at 23, 23. But see Steve Cook, EPA Considering Partial Harmonization of Deadlines for Section 126, N[O.sub.x] SIP Call, Dally Env't Rep. (BNA), Nov. 13, 2001, at A-l1 WL 217 DEN A-1, 2001.

(468) See EPA Revises Nitrogen Oxide Allowances for Non-Utility Boilers in South, Midwest, Daily Env't Rep. (BNA), Sept. 24, 2001, at A-2, WL 183 DEN A-2, 2001.

(469) Michael Bologna, Federal Agency Oks Two State Plans to Reduce Nitrogen Oxides Emissions, 32 Env't Rep. (BNA) 2216 (Nov. 16, 2001).

(470) Bebe Raupe, Indiana's N[O.sub.x] Reduction Rule Approved By EPA for Reducing Transported Pollution, Daily Env't Rep. (BNA), Nov. 14, 2001, at A-3, WL 218 DEN A-3, 2001.

(471) EPA promulgated regulations in 1980 to address visibility impairment reasonably attributable to one or a small group of sources. Regional Haze Regulations, 45 Fed. Reg. 80,084 (codified at 40 C.F.R. [section] 51.300-.307 (2001)). Regional haze was not addressed until a proposed regulation was promulgated on July 31, 1997, Regional Haze Regulations, 62 Fed. Reg. 41,138, and finalized in a regulation promulgated July 1, 1999, Regional Haze Regulations, 64 Fed. Reg. 35,713.

(472) U.S. DEP'T OF THE INTERIOR, NATIONAL PARK SERVICE, STATUS OF AIR QUALITY AND RELATED VALUES IN CLASS I NATIONAL PARKS AND MONUMENTS OF THE COLORADO PLATEAU 1-13 (1997) [hereinafter VALUES].

(473) Id. at 1-14.

(474) Alec Zacaroli, Air Quality Data Indicate Eastern Visibility Not Improving, West Making Some Progress, 29 Envtl. L Rep. (BNA) 1747, 1747 (Jan. 8, 1999).

(475) VALUES, supra note 472, at 1-15.

(476) Id. at 1-22.

(477) Id. at 1-11.

(478) Western coal is usually low in sulfur, therefore visibility impairment from other substances is more important in the West. U.S. ENVTL. PROT. AGENCY, PROTECTING VISIBILITY, AN EPA REPORT TO CONGRESS 6 (1979).

(479) Zacaroli, supra note 474, at 1747.

(480) Id. at 1748.

(481) U.S. NAT'L RESEARCH COUNCIL, PROTECTING VISIBILITY IN NATIONAL PARKS AND WILDERNESS AREAS I (1993) [hereinafter PROTECTING VISIBILITY IN NATIONAL PARKS].

(482) Id.

(483) See generally id. (discussing causes of reduction in visibility).

(484) Particles of 2.5 microns or less were the subject of regulations issued as National Ambient Air Quality Standards for Particulate Matter, 62 Fed. Reg. 38,652 (July 18, 1997). They were remanded in American Trucking Ass'n v. EPA, 175 F.3d 1027 (D.C. Cir. 1999), and Whitman v. American Trucking Ass'n, 531 U.S. 457 (2001). Small particulates also have been pollutants subject to a largely ineffectual interstate transport control effort. See generally Patton, supra note 371, at 10, 155 (discussing air quality standards since 1955).

(485) PROTECTING VISIBILITY IN NATIONAL PARKS, supra note 481, at 3.

(486) Id. at 62.

(487) Clean Air Act, 42 U.S.C. [subsection] 7472-7479 (2000).

(488) Id. [section] 7491(b)(2)(A). The program thus covers sources that commenced construction between Aug. 7, 1962 and Aug. 7, 1977.

(489) Id. [section] 7491(g)(2).

(490) Id. [section] 7491(g)(7).

(491) Id.

(492) Id. [section] 7491(c)(1).

(493) Id. [section] 7491(b)(2).

(494) National Visibility Goal for Federal Class I Areas; Identification of Mandatory Class I Federal Areas Where Visibility Is an Important Value, 44 Fed. Reg. 69,122 (Nov. 30, 1979) (codified at 40 C.F.R. pt. 81 (2001)).

(495) Id. at 69,123, 69,124.

(496) Regional Haze Regulations; Proposed Rule, 62 Fed. Reg. 41,138 (July 31, 1997) (codified at 40 C.F.R. pt. 51 (2001)).

(497) Protection of Visibility, 40 C.F.R. [section] 51.301 (2001).

(498) Visibility Protection for Federal Class I Areas, 45 Fed. Reg. 80,083, 80,084 (codified at 40 C.F.R. [section] 51.300-.307 (2001)).

(499) Id. at 80,085.

(500) Protection of Visibility, 40 C.F.R. [section] 51.301(s) (2001).

(501) See 45 Fed. Reg. at 80,085-86 (defining regional haze as "widespread, regionally homogeneous haze from a multitude of sources which impairs visibility in every direction over a large area").

(502) 40 C.F.R. [section] 51.300-.307 (2001).

(503) Id. [section] 51.302(c)(4)(i).

(504) Id. [section] 51.302(c)(2). The regulations define the term "visibility impairment" as "any humanly perceptible change in visibility (visual range, contrast, coloration) from that which would have existed under natural conditions." Id. [section] 51.301(x). The term "reasonably attributable" is defined as "attributable by visual observation or any other technique the State deems appropriate." Id. [section] 51.301(s); see also Visibility Protection for Federal Class I Areas, 45 Fed. Reg. at 80,085, 80,094 (the states or EPA, pursuant to [section] 110(c), have considerable discretion to determine how and whether impairment may be attributed to an individual source).

(505) Clean Air Act, 42 U.S.C. [section] 7491(b)(2) (2000).

(506) Id. [section] 7491(c)(2).

(507) State Implementation Plans for Visibility Long-Term Strategies, Integral Vistas, and Control Strategies, 52 Fed. Reg. 45,132, 45,133 (Nov. 24, 1987) (codified at 40 C.F.R. pts. 52, 81 (2001)).

(508) Id. at 45,132 (1987). See generally Craig N. Oren, The Protection of Parkland From Air Pollution: A Look at Current Policy, 13 HARV. ENVTL. L. REV. 313 (1989).

(509) 42 U.S.C. [section] 7492(c) (2000).

(510) Id. [section] 7492(f).

(511) Id. [section] 7492(d).

(512) Visibility Protection for Federal Class I Areas, 45 Fed. Reg. 80,083, 80,084 (Dec. 2, 1980) (codified at 40 C.F.R. pt. 51 (2001)).

(513) Id. at 80,085-86.

(514) See Maine v. Thomas, 874 F.2d 883 (1st Cir. 1989) (Maine brought suit to compel EPA to promulgate additional protections against air pollution in federal parks and wilderness areas).

(515) Id. at 885.

(516) Maine v. Thomas, 690 F. Supp. 1106 (D. Me. 1988), affd, 874 F.2d 883 (1st Cir. 1989).

(517) Maine v. Thomas, 874 F.2d at 887.

(518) Id. at 885.

(519) Clean Air Act, 42 U.S.C. [section] 7604(a) (2000).

(520) Id. [section] 7492(d)(2)(C).

(521) First-Time Regulatory Action to Reduce Power Plant Pollution by 90%, INSIDE EPA's CLEAN AIR REPORT, Sept. 26, 1991, at 22, 22.

(522) Envtl. Def. Fund v. Reilly, No. C82-6850-RPA (N.D. Cal. Apr. 20, 1984).

(523) The key to the settlement was the active participation of the concerned parties and their ability to convince industry and EPA to accept the use of an annual average. To meet a 30 day average at 70% reduction would have required the installation of back-up scrubbers at high cost. However, 90% control on an annual basis could be achieved at a much lower cost. EPA would not allow annual averaging for health protection regulations, but was willing to accept this compromise in a regulation designed to protect aesthetic values. D. Michael Rappoport & John F. Cooney, Visibility at the Grand Canyon: Regulatory Negotiations Under the Clean Air Act, 24 ARIZ. ST. L.J. 627 (1992) (providing a useful discussion of negotiated rulemaking).

(524) Utilities Agree to Clean Air at the Grand Canyon, EDF LETTER (Environmental Defense Fund, New York, N.Y.), Jan. 1, 1992, at 1.

(525) Source Specific Federal Implementation Plan for Navajo Generating Station; Navajo Nation, 64 Fed. Reg. 48,725 (proposed Oct. 8, 1999).

(526) Approval and Promulgation of Implementation Plans: Revision of Visibility FIP for Arizona, 56 Fed. Reg. 50,172 (Oct. 3, 1991).

(527) Grand Canyon Visibility Transport Commission; Meeting, 56 Fed. Reg. 57,522, 57,523 (Nov. 12, 1991). Eight western states and four Native-American Tribes were voting members. The voting members were Arizona, California, Colorado, Nevada, New Mexico, Oregon, Utah, Wyoming, the Acoma Pueblo, the Hopi Tribe, the Hualapai Tribe, the Navajo Nation, and the Columbia River Intertribal Fish Commission. There were six non-voting members, including EPA. EPA, Fact Sheet, Proposed Regional Haze Regulations For Protection of Visibility In National Parks and Wilderness Areas (July 18, 1997), at http://www.epa.gov/ttncaaal/tl/fact_sheets/hazefs.pdf; see also Vickie Patton & Bruce Polkowsky, EPA's Regional Haze Proposed: Protecting Visibility in National Parks and Wilderness Areas, 11 TUL. ENVTL. L.J. 299, 311, n. 74 (1998).

(528) 56 Fed. Reg. at 57,523.

(529) GRAND CANYON VISIBILITY TRANSP. COMM'N, OPTIONS FOR IMPROVING WESTERN VISTAS: DRAFT CONTRACTOR'S REPORT (Nov. 4, 1995).

(53O) Alex Zacaroli, Grand Canyon Visibility Report Stirs Debate on Controls Needed in West, Daily Env't Rep. (BNA), Dec. 8, 1995, at A-7, WL 1995 DEN 236 d13, 1995.

(531) Marilyn S. Kite et al., Visibility: A Critique of the National Program; A Review of the Impacts in Southwest Wyoming, 33 LAND & WATER L. REV. 3, 8 (1998).

(532) James A. Holtkamp, Coal and Air Quality: The Basics of Air Pollution Control and Emissions Trading, 47 ROCKY MTN. MIN. L. INST. [section] 21.03[6][b], at 21-13.

(533) Id. [section] 21.031[6][c], at 21-13.

(534) Facts about the Western Regional Air Partnership, at http://www.wrapair.org (last visited Feb. 6, 2002).

(535) Holtkamp, supra note 532, [section] 21.03[6][c], at 21-13.

(536) Regional Haze Regulations; Final Rule, 64 Fed. Reg. 35,713 (July 1, 1999); see also Michael T. Palmer, The Regional Haze Rule: EPA's Next Phase in Protecting Visibility Under the Clean Air Act, 7 ENVTL. LAW. 555, 559 (2001).

(537) See 64 Fed. Reg. at 35,714.

(538) Id.

(539) Pub. L. No. 105-178, 112 Stat. 107 (1998).

(540) 64 Fed. Reg. at 35,723.

(541) Id.

(542) Id.

(543) State Report Says BART Insufficient to Achieve EPA's Visibility Goals, INSIDE EPA'S CLEAN AIR REPORT, Aug. 2, 2001, at 33, 33 [hereinafter State Report Says BART Insufficient].

(544) 64 Fed. Reg. at 35,727.

(545) Id. at 35,730.

(546) Id. at 35,731.

(547) Id.

(548) Id. at 35,738.

(549) See Proposed Guidelines for Best Available Retrofit Technology (BART) Determinations Under the Regional Haze Regulations, 66 Fed. Reg. 38,108 (proposed July 20, 2001).

(550) Pamela Najor, Regional Haze Rule Needed to Address Visibility Problems, Northeast Groups Say, Daily Env't Rep. (BNA), Feb. 1, 2001, at A-1, WL 22 DEN A-1, 2001.

(551) Steve Cook, States, Industry Groups Request Review of Retrofit Requirements Under Haze Rule, Daily Env't Rep. (BNA), Feb. 12, 2001, at A-1, WL 29 DEN A-1, 2001.

(552) Steve Cook, New England Governors Ask Whitman to Publioh Haze Rule Retrofit Guidelines, Daily Env't Rep. (BNA), Mar. 13, 2001, at AA-1, WL 49 DEN AA-1, 2001.

(553) Steve Cook, More Regional Pollution Control Measures Announced by Ozone Transport Commission, Daily Env't Rep. (BNA), Mar. 29, 2001, at A-1, WL 61 DEN A-1, 2001.

(554) Proposed Guidelines for Best Available Retrofit Technology (BART) Determinations Under the Regional Haze Regulations, 66 Fed. Reg. 38,108 (proposed July 20, 2001).

(555) Id. at 38,108; Steve Cook, Northeastern States Endorse Integrating BART with Other Air Emissions Initiative, Daily Env't Rep. (BNA), July 31, 2001, at A-5, WL 146 DEN A-5, 2001. BART Guidelines will be added as Appendix Y to 40 C.F.R. pt. 51.66 Fed. Reg. at 38,109.

(556) Proposed Guidelines for Best Available Retrofit Technology (BART) Determinations Under the Regional Haze Regulations, 66 Fed. Reg. at 38,109.

(557) Id. at 38,110.

(558) Id. at 38,115.

(559) Id. at 38,119.

(560) Steve Cook, 1999 Wilderness Protection Regulation Attacked by Groups on Both Sides of Issue, 32 Env't Rep. (BNA) 1754, 1754 (Sept. 14, 2001) (citing Am. Corn Growers Ass'n v. EPA, No. 99-1348, (D.D.C. 2001)).

(561) Steve Cook, Utilities Question Haze Guidelines Legality; Environmental Coalition Calls Them 'Crucial', Daily Env't Rep. (BNA), Oct. 11, 2001, at A-2, WL 195 DEN A-2, 2001.

(562) State Report Says BART Insuflicient, supra note 543, at 33.

(563) See, e.g., Clean Air Act, 42 U.S.C. [section] 7491(c)(2) (2000) (fossil-fuel fired power plants with total design capacity of at least 750 megawatts are eligible for exemption from statutory retrofit requirements only if operators or owners demonstrate their location is sufficiently distant from any mandatory Class I federal area to not cause or contribute to significant impairment or visibility).

(564) Steve Cook, Environmental Groups Praise Guidelines on Haze; Industry Raises Legality Questions, 32 Env't Rep. (BNA) 1661, 1661 (Aug. 24, 2001). While environmentalists praised proposed guidelines for states to control power plant emissions, industry members called them "unworkable and not authorized by the Clean Air Act." Id.

(565) EPA May Scuttle National Model to Track Haze Emissions, INSIDE EPA's ENVTL. POL'Y ALERT, Sept. 5, 2001, at 19, 19-20.

(566) EPA Offers Guidance to State Agencies on Implementation of Visibility Regulations, 32 Env't Rep. 2440 (Dec. 21, 2001) (citing 66 Fed. Reg. 64,262).

(567) 42 U.S.C. [section] 7475(d)(2)(B) (2000).

(568) Id. [section] 7475(d)(2)(C)(i).

(569) Id. [section] 7475(d)(2)(A). The FLM for the National Park Service and the U.S. Fish and Wildlife Service is the Assistant Secretary of the Department of the Interior for Fish, Wildlife, and Parks. The FLM for the U.S. Forest Service is the regional forester or the forest supervisor. John Bunyak, The FLM's Role and Responsibility in New Source Review, 29 Env't Rep. (BNA) 2389, 2390 n. 1 (Apr. 2, 1999).

(570) Bunyak, supra note 569, at 2391 (citing a March 19, 1979 memorandum of the EPA's Assistant Administrator of Air, Noise, and Radiation).

(571) Id.

(572) Id. at 2393-94.

(573) 42 U.S.C. [section] 7475(d)(2)(C)(iii) (2000); 40 C.F.R. [section] 51.166(p)(4) (2001).

(574) 42 U.S.C. [section] 7475(d)(2)(C)(ii) (2000); 40 C.F.R. [section] 51.166(p)(3) (2001).

(575) State Implementation Plans for Visibility New Source Review and Monitoring Strategy, 50 Fed. Reg. 28,544, 28,549 (July 12, 1985).

(576) Opinion of EPA Environmental Appeals Board on Virginia Power Plant Permit (PSD Appeals Nos. 92-3, 92-4, 92-5; Oct. 5, 1992), 23 Env't Rep. (BNA) 1605, 1611 (1992).

(577) 42 U.S.C. [section] 7475(d)(2)(C)(ii) (2000).

(578) 40 C.F.R. [section] 52.21(p)(5) (2001).

(579) Id. [subsection] 51.166(b)(23)(iii), 52.21(b)(23)(iii); see also Donald R. van der Vaart & John C. Evans, Proposed Requirements for Class I Impacts Under New Source Review, 29 Env't Rep. (BNA) 763, 763 (1998) (analyzing current efforts to address concerns raised by permitting authorities, EPA, and FLMs regarding authority to determine a source's impact on Class I areas). Note that this article's analysis is criticized by Bunyak, supra note 569.

(580) See U.S. ENVTL. PROT. AGENCY, OFFICE OF AIR QUALITY, DRAFT NEW SOURCE REVIEW WORKSHOP MANUAL E.16-18 (1990) (describing the permit process and applicant burdens for sources located within 100 kilometers of Class I areas); 40 C.F.R. [subsection] 51.166(b)(23)(iii), 52.21(b)(23)(iii) (2001).

(581) See, e.g., Pub. Serv. Co. of Colo. v. EPA, 225 F.3d 1144 (10th Cir. 2000) (noting that the state of Colorado, not EPA, is the permitting authority for stationary emitting sources).

(582) See THE YEAR IN REVIEW 2000, supra note 32, at 178 (citing Dayton Power & Light Co. v. Jones, 748 N.E.2d 1171 (Ohio Ct. App. 2000)).

(583) NSR 90-DAY REVIEW, supra note 38, at 7.

(584) Id.

(585) Id.

(586) Id. at 9.

(587) Id.

(588) Clean Air Act, 42 U.S.C. [section] 7475(e)(2) (2000).

(589) Martha Kessler, California, Colorado Regulators Disagree on Need to Change Controversial Program, 32 Env't Rep. (BNA) 1399, 1399 (July 20, 2001).

(590) 42 U.S.C. [subsection] 7661-7661f (2000).

(591) Id. [section] 766ia(a).

(592) See generally REITZE, supra note 52, at 175-223 (discussing details of preconstruction and operating permits).

(593) 42 U.S.C. [section] 7661a(b)(5)(B) (2000).

(594) Id. [section] 766Id(b).

(595) Id. [section] 7661c(f).

(596) Id. [section] 7604(a).

(597) 40 C.F.R. [section] 72.9 (2001).

(598) 42 U.S.C. [section] 7651g(c)(3) (2000).

(599) Acid Rain Program: General Provisions and Permits, Allowance System, Continuous Emissions Monitoring, Excess Emissions and Administrative Appeals, 58 Fed. Reg. 3590. (Jan. 11,1993).

(600) 42 U.S.C. [section] 7651g(c)(1)(A) (2000)

(601) Id [section] 765g(c)(2)

(602) Acid Rain Program: Notice of State Acid Rain Programs, 60 Fed. Reg. 52,911 (Oct. 11, 1995) (listing state permitting authorities approved by EPA).

(603) 40 C.F.R. [section] 72.5 (2001)

(604) See States Boost Efforts to Impose Multi-Pollutant Emissions Controls, INSIDE EPA's ENVTL. POL'Y ALERT, May 2, 2001, at 15, 15-16 (discussing initiatives by Massachusetts, North Carolina, and Illinois to limit emissions of N[O.sub.x] and other pollutants).

(605) 42 U.S.C. [section] 7651g(d)(1) (2000)

(606) Id. [section] 7651g(d)(2)

(607) Id. [section] 7651g(d)(3)

(608) Id.

(609) Id. [section] 7651g(e). New units are defined as those commencing commercial operation on or after November 15, 1990. Id [section] 7651a(10)

(610) Many Permitting Authorities Lack Rules for Issuing Phase II Acid Rain Permits, Daily Env't Rep. (BNA), Dec. 7, 1995, at A-5, WL 1995 DEN 235 D-10, 1995.

(611) 40 C.F.R [section] 72.31 (20001).

(612) 42 U.S.C [section] 7651g(b) (2000)

(613) Id. [section} 7651g(g)

(614) Id. [section] 7651i(a) (2000). For the complete text of the Opt-In Program, see Opting Into the Acid Rain Program, 60 Fed. Reg. 17,100 (Apr. 4, 1995) (codified at 40 C.F.R. pts. 9,72-75, 77,78 (2001). See generally Christopher S. Ferguson, The Opt-In Program, 2 ENVTL. LAW 487 (1996) (discussing the intent, structure, and mechanism of the Opt-In Program).

(615) 42 U.S.C. [section] 7651i(f) (2000).

(616) Id. [section] 7651i(b).

(617) 40 C.F.R. [section] 72.6(c)(6) (2001).

(618) ARIZONA ADMIN. CODE R18-2-326 (2001).

(619) William H. Carlile, Group Drops Suit Against State Regulators After Plants Agree to Serve Demand Peaks, Daily Env't Rep. (BNA), Oct. 31, 2000, at A-11, WL 211 DEN A-11, 2000.

(620) Bebe Raupe, Kentucky Imposes Power Plant Moratorium, Will Study Utilities, Environmental Impacts, Daily Env't Rep. (BNA), July 5, 2001, at A-5, WL 128 DEN A-5, 2001.

(621) Western Lawmakers Easing Environment Controls on Power Plants, INSIDE EPA's CLEAN AIR REPORT, May 24, 2001, at 22, 22.

(622) Pataki Signs Bill Expanding Requirements for Proposed Electric Generating Facilities, Daily Env't Rep. (BNA), Nov. 20, 2001, at A-9, WL 222 DEN A-9, 2001.

(623) Pamela Najor, Six States Send Recommendations to EPA on Reforming New Source Review Permitting, Daily Env't Rep. (BNA), Mar. 14, 2001, at A-1, WL 50 DEN A-1, 2001.

(624) Environmentalists Step Up Challenges to Fast-Tracked Power Plants, INSIDE EPA's CLEAN AIR REPORT, July 19, 2001, at 25, 25-26.

(625) Cal. Energy Comm'n, Licensed, Constructed, and On Line by September 30, 2001: Update on Energy Commission's Review of Electrical Reliability Projects and Other California Peaking Projects (revised Aug. 2, 2001), available at http://38.144.192/sitingcases/peakers/backgrounder, html.

(626) Id.

(627) Carolyn Whetzel, New State Law Will Speed Reviews of Power Plants to Combat Energy Crisis, Daily Env't Rep. (BNA), May 23, 2001, at A-3, WL 100 DEN A-3, 2001.

(628) Carolyn Whetzel, Governor Relaxes Regional Air Rules, Allows Greater Power Generation in Summer, Daily Env't Rep. (BNA), June 13, 2001, at A-3, WL 114 DEN A-3, 2001.

(629) Carolyn Whetzel, Lawsuit Challenges Governor's Effort To East Pollution Limits for Power Plants, Daily Env't Rep. (BNA), June 22, 2001, at A-2, WL 120 DEN A-2, 2001.

(630) Carolyn Whetzel, San Francisco Power Plant to Pay Fine, Operate 'Peaking' Units Within Proper Limits, Daily Env't Rep. (BNA), Nov. 2, 2001, at A-13, WL 211 DEN A-13, 2001.

(631) Executive Order 13212--Actions To Expedite Energy-Related Projects, 66 Fed. Reg. 28,357, 28,357 (May 18, 2001).

(632) Stephanie Ingersoll & Steve Cook, White House Announces Plans to Set Up Interagency Group to Speed Permit Reviews, 32 Env't Rep. (BNA) 1686, 1686 (Aug. 24, 2001).

J.B. and Maurice C. Shapiro Professor of Environmental Law and Director of the LL.M. Environmental Law Program, The George Washington University; M.P.H. 1985, The Johns Hopkins University; J.D. 1962, Rutgers University; B.A. 1960, Fairleigh Dickinson University. The author wishes to thank reference librarian Ms. Germaine Leahy and legal secretary Ms. Winnie Hercules for their assistance.