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31 ELR 10330 | Environmental Law Reporter | copyright © 2001 | All rights reserved Command Without Control: Why Cap-and-Trade Should Replace Rate Standards for Regional PollutantsByron SwiftByron Swift is a Senior Attorney and Director of the Energy and Innovation Center at the Environmental Law Institute. His work addresses issues in designing environmental law to achieve high environmental quality while promoting innovation and lowering costs. He can be contacted by e-mail at swift@eli.org. An overview of nitrogen oxides and sulfur dioxide regulation of power plants in the 1990s will be published in 14 TUL. ENVTL. L.J. 1 (2000). Background research for this Article was supported in part by The Joyce Foundation and A.W. Mellon Foundation. The author thanks these foundations, and the many others who generously provided advice and data, with particular thanks to the Clean Air Markets Division of the U.S. Environmental Protection Agency, Joel Bluestein, Dallas Burtraw, Denny Ellerman, and Debra Knopman. The views expressed are of the author, and not necessarily those of the Environmental Law Institute, The Joyce Foundation, or the A.W. Mellon Foundation. I. Introduction While current environmental laws provide us with an adequate environmental protection system, they must be reformed if we hope to achieve an excellent one. This Dialogue examines regulation of nitrogen oxides (NOx) and sulfur dioxide (SO2) in the power sector over the past years, and provides a direct comparison of the rate-based methods used in both the Title IV and new source review (NSR) programs of the Clean Air Act (CAA)1 with cap-and-trade programs that have been established for both pollutants. This examination reveals the need to move away from the use of end-of-pipe rate standards and the old source/new source distinction in order to create an efficient and effective regulatory system that embraces the principles of pollution prevention and sustainable development. II. An Overview of SO2 and NOx Regulation in the Power Generation Sector A. Regulation of Existing Sources: Title IV and Ozone Transport Commission (OTC) Standards Emissions of NOx and SO2 from most existing power generation sources are regulated under Title IV of the CAA established in the CAA Amendments of 1990.2 Title IV creates two very different systems to achieve major reductions in SO2 and NOx emission from utility sources: a national emissions cap and allowance trading approach for SO2, and rate-based standards for NOx. Northeastern states comprising the Ozone Transportation Region also initiated NOx regulation in 1995 and instituted an emissions cap and allowance trading system for NOx in 1999. The results of these programs are described below. 1. Emissions Cap and Allowance Trading Program for SO2 Electric utilities are responsible for 60% of national SO2 emissions,3 and Title IV imposes a permanent cap on utility SO2 emissions at 8.95 million tons, roughly one-half the 1980 baseline.4 Title IV, unlike traditional regulation that imposes source-specific rate limits, implements an industrywide mass standard known as an emissions cap. The emissions cap and allowance trading program for the SO2 program is divided in two phases. Phase I began in 1995 and required the 263 dirtiest coal-fired electric-generating units (referred to as Table A units) to reduce their emissions to a base level of 5.7 million tons of SO2.5 Phase II implements a stricter standard in the year 2000, and requires all generating units larger than 25 megawatts to reduce their emissions to the final cap amount.6 To implement the cap, allowances equivalent to a ton of SO2 are assigned to each affected generating unit based on their generation rates from the historic base period of 1985-1987, scaled down so that the aggregate emissions equaled the target emissions cap.7 Although the annual and the bonus allowances are allocated without charge to existing sources, a limited number of allowances also are available for purchase through an annual U.S. Environmental Protection Agency (EPA) auction.8 Title IV, therefore, implements a zero new source standard, as any new generating source must purchase all its needed allowances.9 In another [31 ELR 10331] departure from traditional regulation, Title IV allows individual sources to trade their unused allowances to other sources or bank them for future use.10 Finally, Title IV incorporates an extremely strict monitoring and compliance system. Monitoring is required by continuous emissions monitoring devices (CEMS) that collect data every 15 minutes, with consolidated data reported hourly.11 The monitors must also regularly transmit data that indicates that the monitor is functioning properly. CEMS are expensive, costing almost $ 1 million per stack.12 Compliance procedures are also strict and include an automatic $ 2,000 fine per ton and forfeiture of an additional ton of reductions.13 Utilities responded to the Title IV program by reducing SO2 emissions by eight million tons, almost 50% below their 1990 emissions level and30% below the cap in Phase I.14 The most significant use of the flexibility mechanisms of Title IV was banking, or emitting below the standards and saving the allowances for later use. About 75% of total allowances created were banked,15 as a more stringent cap on all units would be imposed in 2000. Another major use of a flexibility provision was trading, which was used by 30 of the 51 firms for intra-firm averaging.16 Although trading volume increased throughout the program17 as firms became more comfortable with trading and some began to trade for arbitrage purposes, only 3 of the 51 firms used inter-firm trading to emit over their allowance allocation.18 Figure 1:1990-1999 SO2 Allocated Allowances and Emissions19 [SEE ILLUSTRATION IN ORIGINAL] A major story of Phase I compliance under the SO2 program was the low cost of compliance. This was due to the flexibility of Title IV, derived primarily from the cap approach, which allows greater flexibility than the rate-based standards, and also the ability to trade allowances.20 Initial expectations by industry in 1991 were for allowance prices of $ 300 to $ 1,000 during Phase I.21 In 1992 and 1993, the earliest signals began to show that prices would be substantially lower,22 and EPA's first auction of allowances in March 1993, revealed prices at $ 131. Allowance prices then continued in the $ 100 range until they began to climb toward $ 200 as Phase II approached.23 The lower cost of compliance was driven by cost reductions and innovation in both of the principal means of compliance—the use of low-sulfur coal and scrubbing. The widespread use of low-sulfur coal has been a major component of compliance strategy for Phase I, resulting in over seven million tons of net reductions (over one-half of net reductions).24 This use was catalyzed by the flexibility afforded by Title IV, which allowed low-sulfur coal to compete with scrubbing as a compliance method. This led to experimentation and innovation in fuel blending techniques that allowed greater than expected use of low-sulfur western coals, and greater incentives to use eastern low- and medium-sulfur coals. These innovations, together with reduction in rail costs due to competition among railroads, lowered the cost premium for low-sulfur coal and dramatically increased their use, which has been a major driving force in lowering the cost of compliance in Phase I of Title IV.25 Scrubbing was the second principal strategy to reduce SO2 in Phase I, and accounts for 3.5 million tons of emissions reductions (rising to 5.5 million tons if bonus allowances allocated to scrubbed units are counted).26 Scrubbers were installed for 27 Table A units,27 promoted in part by the bonus allowances, although several firms canceled scrubber contracts when the low prices for low-sulfur coal became apparent in the early 1990s. The cost of scrubbing also fell significantly during the compliance period, due to innovation in design and materials as well as the significantly lower need for redundancy to comply with Title IV's annual standard, in comparison to previous scrubbers that had been built to meet the new source standard. Although the Phase I cap required only a moderate SO2 reduction of around 30%,28 the cap-and-trade approach exerted continuous pressure to innovate and create lower cost reductions. The cap has prompted continuing innovation in fuel blending techniques and rail infrastructure relating to low-sulfur coal, and also in scrubbing, the cost of which has declined steadily since competition was created with low-sulfur coal.29 The ability to trade allowances has led to a fully integrated cost of sulfur in the coal market, integrating an environmental parameter into the price of coal. Finally, the monetization of environmental costs and benefits under the cap-and-trade approach has allowed the fuller integration of environmental considerations into the regular financially based decisionmaking throughout a company. Overall, the shift in Title IV away from scrubber use and toward low-sulfur coal had economic, environmental, and political consequences. The investment in rail infrastructure, innovation in fuel blending and rail transport, and competition among railroads led to low compliance costs that benefitted both the industry and ratepayers. The principal environmental benefit is the reduction and permanent cap on SO2 emissions, together with the greater political possibility of further reductions given the low cost of compliance. Other environmental benefits of the move to cleaner fuels include the benefits of pollution prevention, in avoiding the direct 1.5% energy loss and significant resource use and waste disposal consequences of scrubbing. Political consequences were also significant, and include the move from unionized coal-mining jobs in midwestern states with high-sulfur coal to western and Appalachian states with low-sulfur coal. Notwithstanding these shifts, the success of the Title IV SO2 cap-and-trade program in overachieving a strict standard at low cost has led some to include it among the most successful programs under the CAA.30 2. Title IV's Rate-Based Standards for NOx Title IV was also designed to reduce NOx emissions from utility boilers by two million tons below 1980 levels by the year 2000.31 Title IV established the first regulation of NOx faced by many existing power plants, as previously only certain states had established NOx standards for older sources in order to meet ambient standards established under Title I of the CAA.32 However, instead of using an emissions [31 ELR 10333] cap and allowance trading system, Congress required EPA to establish annual average emission limits in pounds per million British thermal unit (lb/mmBtu) for coal-fired electric utility units based on the use of "low NOx burner technology."33 The law further contained flexibility provisions, including an annualized emissions rate period and the ability of firms to average the emissions rates of units under their control.34 Phase I ofthe NOx program applied to the 265 wall-fired and tangentially fired boilers included in Table A or substitution units active on January 1, 1995, and lasted from 1996 to 1999.35 Phase II of the program started in 2000, and includes all other affected units.36 The chart below shows the emissions limits applicable to different boiler types in Phase I and Phase II of the program. For wall-fired and tangentially fired boilers, the Phase I limits represent reductions from their respective uncontrolled emissions levels of 0.95 and 0.65 lb/mmBtu.37
The reductions resulting from Phase I are shown graphically below. Overall, units lowered their average NOx emissions rates to 0.40 lb/mmBtu during Phase I, 43% below the 1990 average of 0.70 lb/mmBtu.45 This has resulted in NOx reductions of approximately 400,000 tons per year or 32% below 1990 levels, with reductions projected to rise to 2,060,000 tons per year during Phase II that starts in 2000.46 There is less of a reduction in tons than in rates because economic growth leading to higher fuel use by both Table A and substitution units. Unlike the capped SO2 program, NOx emissions would be expected to rise with increased utilization.47 Figure 2. Title IV NOx Emission Rates for Phase I Units (1990-1999)48 [SEE ILLUSTRATION IN ORIGINAL] Compliance with the NOx program can be characterized in several ways. First, the program led primarily to the simple retrofit of a known technology onto most boilers. Innovation led to cost reductions in low-NOx burner technology for two kinds of boilers, but not a third, and did not lead to continuous drivers for improvement beyond the compliance date. Second, firms made heavy use of the flexibility provisions, especially averaging—204 of the 265 affected units were included in an averaging plan.49 A third characteristic was slight overcompliance with the standard, as Table A firms emitted 11% below the standard to ensure a margin of safety.50 3. OTC Cap-and-Trade in 1999 Forced Further Reductions at Existing Plants In the 12 northeastern and Mid-Atlantic states,51 NOx emissions from large power plants have been controlled not by Title IV, but by more stringent state regulations coordinated under the OTC. The OTC was created under the CAA Amendments of 1990 to coordinate planning at a regional level to facilitate each state's efforts to reduce NOx in order to attain the national ambient air quality standard for ground level ozone. In September 1994, every northeastern and Mid-Atlantic state, except Virginia, adopted a memorandum of understanding to achieve regional reductions of NOx from power generators in three phases starting in 1995.52 In Phase I of the OTC program, states required sources to install reasonably available control technology (RACT), a standard roughly equivalent to the Title IV standards but applying one year earlier.53 Pennsylvania required sources to install low-NOx burners with separate overfire air, and other states, such as New York and New Jersey, defined rate standards that were slightly more stringent than the Title IV standards.54 Most states also allowed averaging among a firm's facilities, creating standards slightly more stringent than but similar to Title IV. In response, most sources added combustion controls such as low NOx burners and/or overfire air to their units. Phase II of the OTC program started in 1999, and nine OTC states established a NOx Budget Program involving an emissions cap and allowance trading system similar to EPA's SO2 Acid Rain Program.55 The emissions cap required 912 electricity-generating units to reduce emissions by 55-65% from their 1990 baseline of 417,444 tons.56 Despite the stringency of the standard, sources overcomplied by reducing emissions 20% below the cap level.57 Compliance levels were also very high, with only one source failing to meet its standard by one ton and, therefore, subjecting itself to an automatic fine and two-ton penalty.58 Despite initial expectations that many sources would need to use expensive end-of-pipe controls such as selective catalytic reduction (SCR) to achieve these deep reductions, the flexibility afforded by the cap-and-trade approach led to unexpected results. One such result was that 126 of the 142 affected coal-fired units achieved NOx reductions up to 30% through operational changes alone, without significant capital additions.59 The cap approach allowed compliance through a number of technologies, including gas reburn and selective noncatalytic reduction, and not only SCR. As a consequence, allowance prices, after initial volatility at the start of the program in which prices ranged from $ 3,000 to $ 7,000 per ton, have settled down to less than the $ 500 to $ 1,000 range, significantly lower than estimated.60 New plants or significant modification of existing plants are subject to a stringent federal NSR process, which requires at a minimum compliance with new source performance standards (NSPS).61 Traditional NSPS establish emissions rate standards for each power generation technology, such that more lenient standards are applied to dirtier technologies. NSPS for NOx allow coal-fired boilers to emit twice the NOx as oil-fired ones, and three times that of gas-fired ones.62 In 1998, EPA established a new, fuel-neutral NSPS of 0.15 lb/mmBtu for major modifications of existing sources, and 1.6 lb/megawatt hour (MWh) of electricity generated for new sources, the latter an innovative output-based standard that provides a benefit to efficient producers.63 However, this fuel-neutral NSPS rarely applies, as the case-by-case oriented NSR process is more stringent and, therefore, controls new plant standards. Under the NSR process, regulators establish an emissions rate standard on a case-by-case basis, again based on the power generation technology, such that more lenient standards are applied to dirtier technologies. The standard also varies geographically: sources built in areas that have attained the ambient ozone standard set by EPA must prevent significant deterioration of air quality, and install the best available control technology (BACT) for the type of plant proposed considering "energy, environmental, and economic impacts and other costs."64 New plants in nonattainment areas must meet the even more stringent lowest achievable emissions reduction (LAER) standard, which excludes consideration of cost.65 These strict standards are motivated both as a means to achieve ambient standards, and as a mechanism to spur the development and application of new technologies. 1. New Source Standards for SO2 The 1970 CAA also established a stringent NSPS for new plants, limiting SO2 emission rates to 1.2 lb/mmBtu for coal-fired plants.66 This had a dramatic effect on the industry, as emission rates from older plants were far higher, and electric utilities began to focus research and operational efforts to extending the operating life of the old "grandfathered" facilities. In the CAA Amendments of 1977, Congress created stricter NSPS by requiring new sources to meet both the 1.2 pound standard and remove either 90% of SO2 emissions from high-sulfur coal or 70% of the SO2 emissions from low-sulfur coal.67 This new standard requires utilities to install scrubbers at all new generating units, removing much of the incentive to use low-sulfur coal and favoring political interests in using eastern high-sulfur coal. However, by increasing the cost of new coal-fired plants, this requirement added to the incentives to extend the life of the older and dirtier plants, and may have further aggravated the conditions that led to acid precipitation. There are several aspects of the NSPS for SO2 that significantly restrict technology use and increase costs. First, it requires sources to make a percentage reduction in potential emissions of SO2 precluding compliance through switching to low-sulfur fuel, as no matter how low the sulfur, the standard requires a further 70-90% reduction, necessitating the [31 ELR 10336] use of an end-of-pipe technology such as scrubbing.68 Second, the standard significantly increases the cost of the scrubber, which must be overbuilt to achieve a 90% (or 70%) reduction on a continuous basis. As a consequence, the cost of an NSPS scrubber is far higher than needed to reduce sulfur, requiring significant redundancy and typically a backup scrubber module in case the first one fails. Ironically, the environment also does not benefit from the inflexible NSPS standard. Despite the costs imposed by the NSPS standard, it creates no net environmental benefits as total emissions are now governed by the emissions cap under Title IV. Nor are there significant local benefits, as sources must already comply with SO2 standards pursuant to Title I of the CAA that protect against local ambient concentrations. The continued use of the inflexible rate-based methodology under the SO2 NSPS therefore makes little sense today when there is a national emissions cap on SO2. 2. New Source Rate Standards for NOx Have Created an Uneven Regulatory Framework and Differential Business Drivers A major problem with NOx new source standards is that by differentiating between old and new plants, they create a significant bias toward old sources that only need to meet a relatively weak standard, while new clean sources face a very stringent one. This problem is exacerbated in the power sector due to long capital life and the great differences in generating technologies. Older largely coal-fired plants emit NOx at levels of 100 to over 1,000 parts per million (ppm) of exhaust volume, even though some could reduce NOx at prices as low as $ 300 a ton.69 However, new plants are virtually all gas-fired70 and far cleaner than coal plants, and the stringent NSR standards require them to reduce their already low NOx emissions to 9 ppm, or in some states 2 ppm.71 This requires investments in end-of-pipe controls that cost from $ 2,500 to over $ 10,000 per ton of NOx reductions and that can discourage investment in newer clean technologies.72 As shown in the table below, NOx regulation of power plants in the 1990s created a highly uneven regulatory framework. Because rate standards were set at differing levels for the different base technologies, they create a perverse situation in which the greater the amount of NOx emitted by a power technology, the more lenient the rate standard. The table also reveals the great disparity between the standards for old and new sources, and also how technology-by-technology standards have imposed the highest costs on the cleanest sources.
NSR also applies when plants undergo significant modifications, and EPA has filed lawsuits against eight companies asserting that their older plants should be subject to NSR because they have made major modifications. However, even if a source has undergone NSR, years or decades may elapse before the plant is subject to the standards again, during which time there is no incentive to improve. Another problem is that these standards divert research attention away from identifying and developing new, cleaner power sources, to how to achieve pollutant reductions and extend the life of older sources without triggering NSR. This leads to a fundamental lack of alignment of the objectives promoted by CAA and objectives of a sound clean energy policy. A. Problems With the Methodology of Using Rate Standards There are several key problems with the rate standards for NOx and SO2 used under Title IV and new source standards.These problems preclude their efficient or effective operation and are especially pronounced in sectors, such as power generation, with long capital life. 1. Emissions Rate Standards Do Not Force a Move Toward Cleaner Technologies One of the chief problems with emissions rate standards for NOx under both Title IV and new source standard is that they are individually set for each specific generation technology. Different standards are set depending on the kind of fuel used, and specific boiler or turbine technology used. Therefore, Title IV's Phase I NOx standards were 0.50 lb/mmBtu for wall-fired boilers, 0.45 lb/mmBtu for tangentially fired boilers, and various other boilers were completely exempt; under Phase II NOx standards vary from 0.86 to 0.40 lb/mmBtu.74 Under NSR, new gas technologies face standards at or lower than 0.05 lb/mmBtu, an order of magnitude lower than the standards for old coal plants.75 Such standards create no incentive to move from dirtier to cleaner technologies. Yet in the power sector, the fundamental answer to solving pollution problems is precisely to move to cleaner, less polluting technologies. 2. Rate Standards Apply Only at a Discrete Point in Time, Limiting Compliance Methods Another key problem with the current rate standard approach is that they require reductions only once: for new plants, at the time the plant is built or undergoes a major modification, and for existing plants, at the date Title IV applied.76 This limits compliance options to those capital or process equipment choices made at the time the plant is built or modified, and eliminates the possibility of compliance through changes in management practices, fuels, or any other operational decisions after a plant is built. This harkens back to an older view of pollution, that there is a single known technology "fix" that can be implemented once. The reality is that technology is ever-evolving, and there are numerous technologies and management practices that can reduce pollution; a good regulatory system needs to provide firms with the incentives to implement them. There are three major negative consequences of applying a rate standard at only one time, such as when a plant is built or at a certain date. The first is that such a standard provides firms with no incentive to take advantage of future technology advances. A firm does not have to implement anything more after the date it is permitted, even if a technological breakthrough means that it could inexpensively reduce pollution an additional amount. This is precisely what has happened with cyclone boilers, as after the regulatory standard was issued, the industry discovered how to cheaply reduce NOx emissions in cyclones far below the standard. However, firms had no incentive to do so, thereby allowing high-emittingboilers to continue to pour pollution into the air. The second negative consequence is that the CAA's new source standards only promote compliance through decisions about capital equipment, and not through ongoing operational or management decisions. Many NOx reduction technologies, such as gas reburn and overfire air, are incremental, and can be adjusted to achieve various rates of NOx control depending on the cost of inputs and other parameters. Indeed, the first year of application of the OTC cap-and-trade for NOx in northeastern states revealed that once a market incentive was created to reduce NOx emissions, firms found ways to lower NOx by up to 30% at existing units, and without significant capital additions.77 Achieving NOx reductions through operational changes can be highly effective, and may be essential in order to reduce NOx to very low levels. Promoting such changes requires that regulatory systems move beyond the current rate-based approach, which provide no incentives to go beyond initially established limits. A third major but longer term consequence of requiring compliance only through periodic changes in rates is its chilling effect on research and development. Since the rate standard creates no continuous driver to lower emissions, firms do not invest continuously in research and development to enhance environmental quality, because there is no compliance benefit in doing so. Instead, the periodic effort to lower the rate standards becomes a political issue, with industry battling through its lawyers to make sure the rate standard is as lenient as possible, and then to use existing technologies for compliance. As demonstrated best by the cyclone boiler situation,78 when the rate standard is then announced, [31 ELR 10338] there is a flurry of research activity on how to reach the standard at least cost, after which the research effort subsides again. 3. Emissions Rate Standards Restrict Compliance Technologies and Promote End-of-Pipe Solutions Instead of Pollution Prevention and Cleaner Processes A fundamental problem with rate standards is that by focusing on end-of-pipe rate reductions, they may restrict technology choice, and inherently favor compliance practices through end-of-pipe pollution controls instead of the other two compliance methods—cleaner inputs or fuels and cleaner processes. Both of the latter are more aligned with pollution prevention principles. The following table compares the technologies permitted under various SO2 standards, and the estimates of compliance cost using those standards. It shows that for identical pollutant reductions, more inflexible regulatory standards can significantly increase costs. A technology prescription, such as one mandating that scrubbers gain a 10 million ton reduction, is the least flexible and was estimated to cost $ 7 million.79 Equally inflexible was the 1978 NSPS because it required a rate reduction in potential emissions of 70-90%, which meant that one had to scrub no matter how clean the coal.80 Somewhat more flexible was the 1971 NSPS, with a percentage concentration rate standard that allowed the use of either a scrubber or compliance coal.81 Title IV's cap-and-trade program—passed in 1990—allows any compliance method.
The regulatory agency applying a rate standard may add to the inflexibility inherent in rate standards by favoring pollutant reductions gains through end-of-pipe controls over those achieved through pollution prevention. Over the past decade, major technological advances in natural gas turbines have reduced their uncontrolled NOx emissions from over 100 ppm to the very low 9-15 ppm range.83 This has achieved a 90% pollution reduction, yet this may not count when a regulatory body applies a standard like BACT or LAER. Some states applying these standards only recognize a 90% reduction achieved though end-of-pipe control equipment such as SCRs, and do not count what has been achieved through pollution prevention or process change.84 4. Emissions Rate Standards Create High Transaction Costs and a Culture of Conflict Between Regulators and the Regulated Industry Typical permitting processes applying new source rate-based standards under the CAA typically takes one and one-half years or longer, creating high administrative costs to governments and major opportunity costs for firms that may be siting new clean plants. Under this process, a government regulator must make a specific determination of what specific technology meets the regulatory standards or is the "best available," pitting regulators against the applicant in a series of factual issues.85 Title IV's NOx standards resulted in litigation that delayed the program one year due to a conflict between industry and regulators on the applicable technology, and the NSR process is time- and resource-intensive. However, the gain to the environment may be zero or slight if the plant is a modern gas plant, as NOx and SO2 emissions are minimal, and they would be expected to create benefits by displacing power from dirtier sources. In addition, in nonattainment areas, any resulting emissions must be offset anyway, creating no net environmental benefit from these lengthy procedures. Regulations do not have to be this way. Major environmental benefits can be achieved without transaction costs under technology-neutral approaches such as the emissions cap and allowance trading system. Both the Acid Rain Program's SO2 cap and the OTC NOx cap create major emissions reductions and a zero new source standard without any lengthy permitting procedures (transactions take less than 24 hours) or conflict between regulator and regulated. These approaches redirect business efforts away from contesting regulatory authority toward competing in the marketplace. B. Problems Relating to the Disparity in Standards Between Old and New Plants A fundamental strategy in our CAA has been to impose strict standards on new plants, while old plants are exempted or subject to lenient requirements. These new source standards are designed both to reduce ambient pollution levels, on the assumption it will be cheaper to achieve reductions at new plants instead of old plants, and as a technology-forcing mechanism to encourage the development of cleaner processes. The effectiveness of these standards is assessed below for NOx reductions, as the lack of construction of new coal plants means there are few new SO2 sources. 1. New Source Standards Have Failed to Efficiently Reduce Ambient Pollution Levels A basic assumption behind new source standards is that it will be less expensive to attain the emissions reductions needed to achieve ambient levels through new source standards. This assumption appears fundamentally flawed in the NOx case, and based on a static concept of technology change. Due to fundamental technology changes in power generation, the disparity in rate standards between old and new plants now results in perverse incentives for attaining clean energy. Today, virtually all new power plants use gas-fired turbine technology86 and are both more efficient and far cleaner than coal-fired units—even without controls. Modern gas combined cycle plants emit virtually no SO2, particulates or air toxics, and NOx emission levels are around 0.05 lb/mmBtu, well below the NSPS and 10 to 40 times lower than that of coal units.87 Therefore, as shown in the above Figure 3, there is actually an inverse relationship between the age and cleanliness of plants and the costs of added NOx reductions. Contrary to the initial supposition that it would be cheaper to achieve significant reductions at new plants versus older ones, technology change has meant that significant reductions are available only at old plants and are also far cheaper there. 2. New Source Standards Force Only Limited Kinds of Innovation The record of new source standard and forcing innovation is more complex. New source standards have led to development of new technologies, including improvements in SCR technology and innovative control technologies, such as SCONOX88 [31 ELR 10340] and XONON.89 They have also contributed to a collaborative federal-industry effort to develop cleaner and more efficient gas turbines, to which federal research also played a large role.90 However, it has also suppressed innovation. The distinction between old and new plants has led firms to continue to use highly polluting old plants, and has restrained upgrades or efficiency investments because they might trigger NSR. As a consequence, virtually all research funds spent by the principle utility research coalition, EPRI (formerly the Electric Power Research Institute), is to improve the performance of existing units, whereas most federal research funds are to develop new and cleaner technologies.91 Secondly, the process of governmental approval of specific firm technology choices has led to a situation that has virtually eliminated venture capital from the environmental technology field.92 3. NSR Creates No Net Benefits in Nonattainment Areas or Under an Emissions Cap Approach A final irony is that in a cap-and-trade situation, or in nonattainment areas where the CAA requires any new source to fully offset its emissions with matching reductions from existing sources, there are no actual environmental benefits as there are no net NOx reductions even after the very high costs imposed by NSR.93 C. Cap-and-Trade Programs Achieve a Results-Oriented Approach Fortunately, there are solutions for each of the significant problems created by NOx and SO2 rate regulations. The best and most comprehensive solution would be to replace existing standards with a stringent emission cap and allowance trading system, created on a national or regional basis, that includes all sources.94 This solution would not only be extremely effective environmentally, but also would eliminate virtually all of the problems mentioned above that are caused by the use of rate standards, because cap-and-trade programs: * create a consistent standard applicable to both old and new plants; * do not discriminate by creating different standards for different technologies; * create continuous drivers for improvement and innovation; * allow business flexibility to choose differing compliance approaches; * have effective monitoring of emissions; * achieve high levels or 100% compliance; and * minimize transaction costs and conflict. Steps are being taken to implement cap-and-trade approaches, including existing programs such as the Acid Rain Program, the OTC NOx cap-and-trade system in the Northeast, and the pending EPA state implementation plan call that would extend an NOx cap-and-trade system to at least 19 eastern states.95 In addition, "4-pollutant" bills proposed in Congress would establish stringent national cap-and-trade standards for SO2, NOx, and carbon dioxide, and address mercury reductions.96 These would eliminate the grandfathering problem and create a uniform standard applied to all covered units, while promoting compliance through pollution prevention. The major benefits of a good cap-and-trade system are that it enacts a stringent and permanent limit, which serves society's interest in pollution reductions, while allowing the widest possible breadth of compliance options, hence reducing costs. It removes government from case-by-case decisionmaking about technologies, freeing business to experiment without liability. Cap-and-trade systems eliminate all discrimination between old and new plants and between technologies because all face equal incentives to reduce.97 It performs far better than a rate-based system in regards to [31 ELR 10341] both cost and innovation, principally because government no longer needs to predict where innovation may occur as they do in a rate system. The cap-and-trade system places this burden on the regulated entities. A cap-and-trade approach also encourages greater innovation for several reasons. Perhaps the most important is that the uniform standard exerts pressure on all to innovate, as all sources are equally covered under the standard. There are no exceptions, waivers, or lower standards for certain technologies that characterize most rate systems, such as the Title IV NOx program, in contrast to the SO2 program. This maximizes the breadth of innovation and allows unexpected innovation. Second, the pressure to innovate is continuous, driven both by the lack of growth in the cap and the opportunity to market allowances. Both give firms reasons to continuously seek lower emissions, unlike rate systems where there is no incentive to go beyond the rate limit. Third, the opportunity to use allowances softens the risk of failure in experimentation, while the cap assures achievement of environmental goals. Another key benefit of cap-and-trade programs is their record of effective monitoring and near 100% compliance. In five years, the Acid Rain Program for SO2 has achieved 100% compliance every year, and in the first year of the OTC NOx cap-and-trade program, there was only one exceedance of one ton, leading to a swift and automatic penalty.98 Yet another benefit is that cap-and-trade programs minimize transaction costs. Instead of a protracted dispute between firms and government about what technology is most appropriate, firms must simply comply and be able to show the government that at year-end they have enough allowances to cover emissions. The government role changes appropriately and dramatically from choosing technologies to assuring compliance. The environmental integrity of the program is assured by the reductions made through the emissions cap, which never grows. A negative aspect that some believe may occur with cap-and-trade programs is that the trading may shift the locus of emissions, potentially causing areas of higher localized pollution levels. In reality, it is difficult to see why cap-and-trade systems should have any greater effect in this regard than rate standards, which themselves allow great local variability as they do not control plant size, siting, or utilization. In particular, this should not be of concern with a regional pollutant, or if the total reductions are sufficiently great that everyone benefits. In addition, an analysis of the first four years of the Acid Rain Program's SO2 cap-and-trade program showed that regional movements of allowances were minimal (3% of all allowances used), and that trading may even have helped cool hot spots.99 Experience with rate-based approaches for NOx and SO2 regulation in the power generation sector reveals inflexibility in their application that does not help to reach environmental benefits. Key problems include the disparities created for different technologies and between old and new plants, which creates strong economic incentives to use dirtier technologies and against the installation of new plants; their restriction of technology choice; and tendency to limit innovation to end-of-pipe controls. Emissions cap and allowance trading systems now in place for both SO2 and NOx have been able to effect a strict environmental standard while avoiding the inflexibility of rate standards, and are more aligned with pollution prevention goals. Moving from rates standards toward cap-and-trade programs appears essential to meet the goals of a clean energy policy and to attaining the multipollutant reductions benefits from switching to cleaner new power sources. 1. 42 U.S.C. §§ 7401-7671q. ELR STAT. CAA §§ 101-618. 2. Title IV of the CAA Amendments of 1990, Pub. L. No. 101-549, tit. IV, 104 Stat. 2399 (codified at 42 U.S.C. §§ 7651-7651o, ELR STAT. CAA §§ 401-416), was designed to address the problem of acidification of lands and water bodies caused by acid deposition from emissions of SO2 and NOx. Emissions of these substances also cause significant health problems in the formation of fine particulates and urban ozone, which although recognized at the time of passage of the 1990 Amendments were not emphasized. 3. U.S. EPA, NATIONAL AIR POLLUTANT EMISSION TRENDS 1990-1998 3-10 (1999) [hereinafter EMISSION TRENDS]. 4. U.S. EPA, 1999 COMPLIANCE REPORT. ACID RAIN PROGRAM 5 (2000) (EPA-430-R-00-007) [hereinafter EPA 1999 COMPLIANCE REPORT]; EMISSION TRENDS, supra note 3, at 3-12 (utility SO2 emissions recorded at 17.5 million tons in 1980). 5. The level of the Phase I cap was reached by multiplying an emission rate of 2.5 pounds of SO2 per million British thermal unit (lb/mmBtu) times utilization in the baseline years. 6. The level of the Phase II cap of 8.95 million tons was reached by multiplying an emissions rate of 1.2 lb/mmBtu SO2 times baseline utilization. The 1.2 lb/mmBtu emission rate has historical significance, as it is the rate standard that has been required for new coal-fired power plants since 1970. Because bonus allowances of 530,000 tons per year will be issued from 2000 to 2009, the cap in those years will equal 9.48 million tons. 7. In addition to these basic allowance allocations, Title IV also allocates 3.5 million bonus allowances over the first years of the program to encourage the use of scrubbers, and 300,000 bonus allowances to reward efforts to develop alternative energy sources. 42 U.S.C. § 7651c(g), ELR STAT. CAA § 404(g). 8. Id. § 7651, ELR STAT. CAA § 401. 9. Id. § 7651b(e), ELR STAT. CAA § 403(e). 10. Id. 11. EPA 1999 COMPLIANCE REPORT, supra note 4, at 17-18; see also 40 C.F.R. pt. 75 (2000). 12. A. DENNY ELLERMAN ET AL., MARKETS FOR CLEAN AIR: THE U.S. ACID RAIN PROGRAM 250 (2000) [hereinafter ELLERMAN 2000]. 13. 42 U.S.C. § 7651j, ELR STAT. CAA § 411. 14. EPA 1999 COMPLIANCE REPORT, supra note 4. In addition to the actual reductions of almost 8 million tons, 3.5 million extension allowances were allocated as bonus allowances, which together with other bonus programs created an 11.6 million allowance bank at the end of 1999. Id. 15. ENVIRONMENTAL LAW INST., ANALYSIS OF EPA 1995-1999 COMPLIANCE REPORTS (on file with author) [hereinafter ELI 1995-1999 COMPLIANCE REPORT ANALYSIS]. 16. Id. 17. EPA 1999 COMPLIANCE REPORT, supra note 4, at 11. 18. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 19. U.S. EPA. ACID RAIN COMPLIANCE REPORTS 1995-1997; EPA 1999 COMPLIANCE REPORT, supra note 4. 20. ELLERMAN 2000, supra note 12; Dallas Burtraw & Byron Swift, A New Standard of Performance: An Analysis of the Clean Air Act's Acid Rain Program, 26 ELR 10411 (Aug. 1996). 21. An industry poll showed widespread expectations of allowance prices on the order of $ 300 to $ 735 for Phase I and $ 500 to $ 1,000 for Phase II in June-July 1991, falling to $ 200 to $ 550 for Phase I and $ 300 to $ 700 for Phase II by October-November 1991. Ian M. Torrens et al., The 1990 Clean Air Act Amendments: Overview, Utility Industry Responses, and Strategic Implications, 17 ANNUAL REV. OF ENERGY & THE ENV'T 220 (1992); see also ELLERMAN 2000, supra note 12, at 232. 22. The first was a trade of 10,000 allowances from Wisconsin Power & Light to the Tennessee Valley Authority at $ 265. Matthew L. Wald, T.V.A. Buys Allowance to Emit a Chemical in Acid Rain, N.Y. TIMES, May 12, 1992,at A1; Frank Edward Allen, Tennessee Valley Authority Is Buying Pollution Rights From Wisconsin Power, WALL ST. J., May 11, 1992. The second was a trade of 25,000 allowances from ALCOA to Ohio Edison for $ 300 per allowance. Joan E. Rigdon, ALCOA Unit Arranges $ 7.5 Million Sale of Pollution Allowances to Ohio Edison, WALL ST. J., July 1, 1992. 23. EPA 1999 COMPLIANCE REPORT, supra note 4, at 10. 24. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 25. ELLERMAN 2000, supra note 12. 26. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 27. U.S. DOE, ENERGY INFORMATION ADMIN., ELECTRIC POWER ANNUAL vol. II, tbl. 30 (detailing flue gas desulfurization capacity in operation at U.S. electric utility plants as of December 1999). 28. The 1985-1987 baseline level of Phase I units is about 10 million tons, and the average Phase I cap was approximately 6.8 million tons (not counting bonus allowances), for a 33% reduction. EPA 1999 COMPLIANCE REPORT, supra note 4, at 7. 29. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 30. Id.; Burtraw & Swift, supra note 20. 31. Acid Rain Program; Nitrogen Oxides Emission Reduction Program—Phase II Final Rule, 61 Fed. Reg. 67111 (Dec. 19, 1996) [hereinafter Phase II Final Rule]. 32. Although some states established these as early as 1972, most states did not emphasize NOx reductions until scientific evidence began to indicate reducing NOx would be the most effective way to reduce urban ozone. NATIONAL RESEARCH COUNCIL, RETHINKING THE OZONE PROBLEM IN URBAN AND REGIONAL AIR POLLUTION (1991). 33. 42 U.S.C. § 7651, ELR STAT. CAA § 401. 34. Id. § 7651f, ELR STAT. CAA § 407. 35. These units, known as Group 2 boilers, include cell, cyclone, and wet-bottom boilers. Id. 36. Phase II includes both wall-fired and tangentially fired (Group 1) boilers not covered in Phase I and other types of boilers (Group 2 boilers). See Phase II Final Rule, supra note 31. Since the units included in Phase I have already made their boiler modifications, they are permanently grandfathered at the lower Phase I standards and not the more stringent Phase II standards. 42 U.S.C. § 7651f, ELR STAT. CAA § 407. 37. U.S. EPA, COMPILATION OF AIR POLLUTANT EMISSION FACTORS AP-42 (1990). 38. 42 U.S.C. § 7651f, ELR STAT. CAA § 407. 39. Alabama Power Co. v. EPA, 40 F.3d 450, 25 ELR 20166 (D.C. Cir. 1994) (vacating Phase I NOx final rule). 40. EPA1999 COMPLIANCE REPORT, supra note 4, at 10. 41. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 42. EPA 1999 COMPLIANCE REPORT, supra note 4, at 10. The process for approving these alternative emissions limits is still not complete for any unit. 43. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 44. See Phase II Final Rule, supra note 31. 45. EPA 1999 COMPLIANCE REPORT, supra note 4, at app. C-2. The range of emissions rates for the affected boilers has also been reduced, from 1990 baseline emissions ranging from 0.26 to 1.21 lb/mmBtu to a range from 0.13 to 0.81 lb/mmBtu in 1999. Id. 46. Id. at 13. 47. Id. at 13-15. 48. ELI 1995-1999 COMPLIANCE REPORT ANALYSIS, supra note 15. 49. EPA 1999 COMPLIANCE REPORT, supra note 4, at app. C-1. 50. Id. at 14. For Table A units, average emissions were 0.43 lb/mmBtu during the 4 years of the program, 11% below the average limitation of 0.49 lb per mmBtu. Emissions rates of Table A units gradually moved lower during the Phase I, from 0.45 lb/mmBtu in 1996, to 0.42 lb/mmBtu in 1999. Id. 51. The OTC comprises the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont; the northern counties of Virginia; and the District of Columbia. 52. 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 Emission (signed Sept. 27, 1994), available at http://www.sso.org/otc [hereinafter OTC MEMORANDUM OF UNDERSTANDING]. Phase I included the installation of reasonably available control technology (RACT). 53. Id. 54. Pennsylvania law defines RACT for large coal-fired units as "the installation of low NOx burners with separate overfire air." 25 PA. CODE § 129.93 (b)(1) (2000). New Jersey requires utility boilers to meet the following standards: tangentially fired: .38 lb/mmBtu; wall-fired; .45 lb/mmBtu; and cyclone .55 lb/mmBtu. 7 N.J. ADMIN. CODE § 27-19.4 (2000). New York State RACT regulations set standards for wet-bottom coal-fired tangential plants at 0.42 lbs./mmBtu, and for wall-fired at 0.45 lbs./mmBtu. N.Y. COMP. CODES R. & REGS. tit. 6, § 227-2.4 (2000). 55. OTC Memorandum of Understanding, supra note 52. Under this program, budget sources were allocated allowances by their state government. Each allowance permits a source to emit one ton of NOx during the summer period (May through September). Allowances may be bought, sold, or banked. Any person may acquire allowances and participate in the trading system. Each budget source must comply with the program by demonstrating at the end of each control period that actual emissions do not exceed the amount of allowances held for that period. However, regardless of the number of allowances a source holds, it cannot emit at levels that would violate other federal or state limits, e.g., new source performance standards (NSPS), Title IV, or NOx RACT. 56. U.S. EPA, 1999 OTC NOx BUDGET PROGRAM COMPLIANCE REPORT (Mar. 27, 2000). 57. Id. 58. Id. 59. Joel Bluestein, Energy and Environmental Analysis, Inc., OTR NOx Market: Lessons Learned (1999) (unpublished report presented at Emissions Marketing Associates in October 1999) (on file with author); GAS RESEARCH INST., LOW COST OPTIONS FOR ACHIEVING DEEP NOx REDUCTIONS (2000), available at http://www.gri.org. 60. Alternative technologies are described in the Gas Research Institute's report on Low Cost Options for Achieving Deep NOx Reductions. See GAS RESEARCH INST. supra note 59. Compliance cost is described in U.S. EPA, 1999 OTC NOx BUDGET PROGRAM COMPLIANCE REPORT, supra note 56. 61. 42 U.S.C. § 7479(3), ELR STAT. CAA § 169. 62. The initial NSPS for power plant boilers established NOx emissions limits of 0.50 to 0.80 lb/mmBtu for coal-fired boilers, 0.30 lb/mmBtu for oil-fired boilers, and 0.20 lb/mmBtu for gas-fired boilers. 40 C.F.R. pts. 60.44, 60.44a (2000). 63. Id. pt. 60.44a(d); 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, 61 Fed. Reg. 49442 (Sept. 16, 1998) (final rule). 64. 42 U.S.C. §§ 7475, 7479(3), ELR STAT. CAA §§ 165, 166(3). 65. Id. § 7503(a)(2), ELR STAT. CAA § 173(a)(2). 66. 40 C.F.R. pt. 60.44 (2000). 67. Id. pt. 60.44a. 68. In Sierra Club v. Costle, 657 F.2d 298, 11 ELR 20455 (D.C. Cir. 1981), the court affirmed that a utility could not use low-sulfur coal to create equivalent reductions. It interpreted the rate-based standard and held that: In no instance, however, can a plant reduce emissions by less than 70 percent of potential uncontrolled emissions…. There is no dispute that the 70 percent floor in the standard necessarily means that, given the present state of pollution control technology, utilities will have to employ some form of flue gas desulfurization ("FGD" or "scrubbing") technology. Id. at 316 & n.38, 11 ELR Digest at 20455. 69. See Table 2 infra. 70. U.S. DOE, ANNUAL ENERGY OUTLOOK 2000 (1999) [hereinafter DOE ANNUAL ENERGY OUTLOOK 2000]. 71. U.S. EPA, RACT/BACT/LAER CLEARINGHOUSE ANNUAL REPORT FOR 1998: A COMPILATION OF CONTROL TECHNOLOGY DETERMINATIONS (June 1998) (EPA 456/R-98-004) [hereinafter U.S. EPA CLEARINGHOUSE REPORT FOR 1998]. 72. See Table 2 infra. 73. U.S. EPA, COMPILATION OF AIR POLLUTANT EMISSION FACTORS AP-42 (1998); Phase II Final Rule, supra note 31; Joel Chalfin, General Electric Power Plant Systems, Gas Turbine Emissions (1999) (unpublished presentation) (notes on file with author); Leslie Witherspoon & Ken Smith, NOx Control Technology Options and Development Activity for Mid-Range Natural Gas Fired Turbines (1999) (unpublished presentation) (notes on file with author). 74. 40 C.F.R. pts. 76.5-76.7 (2000). 75. U.S. EPA CLEARINGHOUSE REPORT FOR 1998, supra note 71. 76. Title IV required sources affected by Phase I to make reductions by January 1, 1995, and for all other sources must make reductions by January 1, 2000. 42 U.S.C. §§ 7651c(a), 7651d(a), ELR STAT. CAA §§ 404(a), 405(a). NSR applies when a plant is built or undergoes a major modification. Id. § 7479(1)-(2), ELR STAT. CAA § 169(1)-(2). 77. GAS RESEARCH INST., supra note 59; Bluestein, supra note 59. 78. See Dave O'Connor et al., Electric Power Research Inst., The State of the Art in Cyclone Boiler NOx Reduction (1999) (unpublished presentation at EPRI-EPA-DOE Combined Utility Air Pollutant Control Symposium in Atlanta) (notes on file with author); ELECTRIC POWER RESEARCH INSTITUTE, FIRST DEMONSTRATION OF OVERFIRE AIR ON CYCLONE STEAM GENERATOR REDUCES COSTS OF NOx COMPLIANCE (1998). "The results have clearly demonstrated the technical and operational feasibility of overfire air as a commercially viable NOx control approach for cyclones. The application of the technology on five cyclone furnaces …. showed no substantial impacts from slagging, fouling, or corrosion of waterwall tubes when fueled by western coal." ELECTRIC POWER RESEARCH INST., NOx CONTROL FIELD TEST RESULTS ON COAL-FIRED CYCLONE BOILERS—CNCIG PROGRAMS (1999), available at http://www.epri.com (EPR Report No. TR-113643). 79. H.R. 3400, 98th Cong. (1983). H.R. 3400, which was known as the Waxman-Sikorski Bill and which was cosponsored by over 80 House members, would have mandated scrubbing on the 50 largest utility plants, and was estimated to cost as much as $ 7 billion annually. Paul R. Portney, Economics and the Clean Air Act, 4 J. ECON. PERSP. 173-81 (1990). See generally Dallas Burtraw, Appraisal of the SO2 Cap-and-Trade Market, in EMISSIONS TRADING 133-89 (Richard F. Kosobud ed., 2000). 80. If the law requires a percentage rate reduction in potential emissions, cleaner fuels cannot be used for compliance, as the standard requires an additional percent reduction via end-of-pipe control devices no matter how clean the fuel. See note 68 supra. This perversely may even lead businesses to use dirtier fuels, as it may be cheaper to reduce pollution by the given percentage with a dirtier fuel compared to the cleaner fuel. 81. A standard such as the 1.2 lb/mmBtu rate standard enacted in the 1971 NSPS would have permitted the use of compliance coal within this defined sulfur limit as an alternative to scrubbing, but would not have prompted the experimentation with fuel blending that led to the significantly increased use of western and mid-sulfur coals that was observed under Title IV. 82. Byron Swift, Barriers to Environmental Technology Innovation and Use, 28 ELR 10202 (Apr. 1998); Burtraw & Swift, supra note 20; ICF RESOURCES, COMPARISON OF THE ECONOMIC IMPACTS OF THE ACID RAIN PROVISIONS OF THE SENATE BILL (S. 1630) AND THE HOUSE BILL (S. 1630 [sic]) (1990); U.S. GENERAL ACCOUNTING OFFICE, AIR POLLUTION: ALLOWANCE TRADING OFFERS AN OPPORTUNITY TO REDUCE EMISSIONS AT LESS COST (1994). 83. Marvin Schorr & Joel Chalfin, General Electric Power Systems, Gas Turbine NOx Emissions Approaching Zero—Is It Worth the Price? (1999) (unpublished presentation at Air & Waste Management Association's 92d Annual Meeting, June 1999, St. Louis, Mo.) (notes on file with author); STATE & TERRITORIAL AIR POLLUTION PROGRAM ADMINISTRATORS & ASS'N OF LOCAL AIR POLLUTION OFFICIALS (STAPPA/ALAPCO), CONTROLLING NITROGEN OXIDES UNDER THE CLEAN AIR ACT: A MENU OF OPTIONS (1994). 84. MASS. REGS. CODE tit. 310, §§ 7.00, 7.02 (1999); see MASSACHUSETTS DEPARTMENT OF ENVIRONMENTAL REGULATION, CONDITIONAL COMPREHENSIVE PLAN APPROVAL OF MYSTIC STATION (2000) (requiring end-of-pipe SCR technology to reach 2 ppm in addition to dry low-NOx burner). EPA has recognized this problem and proposed a guideline that would presume BACT requirements are met if a source adopts very clean gas turbine technology without using SCR. Notice of Availability for Draft Guidance on BACT for NOx Control at Combined Cycle Turbines, 65 Fed. Reg. 50202 (Aug. 17, 2000). 85. U.S. EPA CLEARINGHOUSE REPORT FOR 1998, supra note 71. 86. Modern gas plants are cheaper to build than coal plants, and achieve 55% efficiency instead of the 34% average for coal plants. This offsets the relatively more expensive fuel cost for natural gas, and the U.S. Department of Energy (DOE) estimates that 90% of new generation between 2000 and 2020 will be gas-fired. DOE ANNUAL ENERGY OUTLOOK 2000, supra note 70, at 65, 67. 87. Because they are more efficient than coal plants, they also emit roughly one-half the carbon dioxide (CO2). See generally STATE & TERRITORIAL AIR POLLUTION PROGRAM ADMINISTRATORS & ASS'N OF LOCAL AIR POLLUTION OFFICIALS, REDUCING GREENHOUSE GASES AND AIR POLLUTION: A MENU OF HARMONIZED OPTIONS 49 (1999). 88. SCONOX is available for use with gas-fired turbines, and uses post-combustion catalysts to remove both NOx and CO from the turbine exhaust, and reduces particulates as well. SCONOX is more expensive than SCR, and entails the loss of about 1% of plant efficiency. For large units, the combined capital and operating costs add about 2 mills (0.2 cents) to the cost of a kilowatt hour, twice that of SCR. For small industrial 7 MW gas turbines, the capital cost of a SCONOX unit at over $ 2 million may exceed the cost of the turbine itself, and annual costs are $ 310,000. Together these yield an annualized cost of $ 590,000 to reduce 25 tons of NOx emissions to 2 tons, or $ 25,000 a ton (note the cost of reducing the marginal 1 ton from SCR is $ 1 million). 89. XONON is a system that combusts fuel through a chemical process that prevents the formation of NOx. 90. DOE's Advanced Turbine Systems program has the objective of developing ultra high-efficiency gas turbine systems for utilities, with an appropriation of approximately $ 30million in recent years. U.S. DOE, ENERGY INFORMATION ADMINISTRATION, FEDERAL ENERGY MARKET INTERVENTIONS: PRIMARY ENERGY 33, app. B (1999) (Report #SR/OIAF/1999-03). 91. ELECTRIC POWER RESEARCH INST., 1999 ANNUAL REPORT (2000); U.S. DOE, FISCAL YEAR 2000 BUDGET, at http://www.doe.gov. 92. According to Environmental Business International, private venture funding, which reached $ 200 million in 1990, has now sunk to less than $ 60 million in an era of major technology funding. See PROGRESSIVE POLICY INST., HOW ENVIRONMENTAL LAWS CAN DISCOURAGE POLLUTION PREVENTION: CASE STUDIES OF BARRIERS TO INNOVATION 3-4 (2000), available at http://www.dlcppi.org; see also ENVIRONMENTAL LAW INST., BARRIERS TO ENVIRONMENTAL TECHNOLOGY INNOVATION 9 (1998) (reasons include the double approval barrier to environmental technologies—governmental and firm—and the fractioning of market size into individual permitting jurisdictions). 93. This is particularly true for CO2, the principal greenhouse gas. Since CO2 is a long-lived gas that lasts for centuries once emitted, it is critical to achieve major carbon reductions in the next decade or two. The only practical way to do so is to invest heavily in efficiency and in modern gas-fired generation, which is needed to substitute for the older coal-fired power plants. Yet our NOx policies make such new investment considerably more difficult, especially for smaller units that are precisely the ones that are used for co-generation at industrial sites or to convert methane gas to power, and are counted on to achieve efficiency gains and major greenhouse gas reductions. 94. Although a system of pollution charges or fees may also provide similar benefits if the charges are set high enough, such systems have rarely been implemented in the United States. 95. Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone; Final Rule, 63 Fed. Reg. 57356 (Oct. 27, 1998) (covering 22 states and achieving similar reductions as a 0.15 lb/mmBtu rate standard). Although initially proposed for a group of 22 states, challenges to EPA's authority resulted in court orders that restricted application of the final rule to 19 states. Appalachian Power Co. v EPA, 208 F.3d 1015, 30 ELR 20560 (D.C. Cir. 2000) (limiting application to 19 states) (deadline for states to file state implementation plans extended to Oct. 31, 2000). 96. See, e.g., H.R. 25, 106th Cong. (1999) (sponsored by Rep. Sherwood Boehlert (R-N.Y.)); H.R. 2569, 106th Cong. (1999) (sponsored by Rep. Frank Pallone (D-N.J.)); and S. 1369, 106th Cong. (1999) (sponsored by Sen. James Jeffords (R-Vt.)). 97. A related aspect is that cap-and-trade systems allow for efficient and smooth reductions in pollutant levels. Title IV provides a good example, as the allowable limit was lowered between Phase I and Phase II of both programs. However, under the rate-based approach for NOx, all boilers that had complied with Phase I limits were grandfathered without having to meet the Phase II limits, whereas in the cap-and-trade approach for SO2, the cap was simply lowered, requiring all units to comply. 98. EPA 1999 COMPLIANCE REPORT, supra note 4; U.S. EPA, 1999 OTC NOx BUDGET PROGRAM COMPLIANCE REPORT, supra note 56. 99. U.S. GENERAL ACCOUNTING OFFICE, ACID RAIN: EMISSIONS TRENDS AND EFFECTS IN THE EASTERN UNITED STATES (Mar. 2000) (GAO/RCED-00-47); Byron Swift, Allowance Trading and SO2 Hot Spots—Good News From the Acid Rain Program, 31 Env't Rep. (BNA) 954 (May 12, 2000), available at http://www.epa.gov/acidrain/papers. 31 ELR 10330 | Environmental Law Reporter | copyright © 2001 | All rights reserved |