|
26 ELR 10411 | Environmental Law Reporter | copyright © 1996 | All rights reserved
Title IV's flexibility translates into several opportunities for operational modifications that save considerable money. Plants now have the flexibility to shift power to low-polluting plants for baseline loads and to switch on high-polluting plants only for incremental loads, efficiently reducing their SO2 emissions. The allowance trading program lets facilities achieve low-cost emission reductions and rely on internal power shifting among units or the allowance market for further compliance. Another important element is the reduced need for spare absorber modules. Before the 1990 Clean Air Act Amendments, scrubber systems usually included a spare module to maintain low emission rates when any one module was inoperative. As long as emission allowances are a sufficient compliance strategy, utilities can save considerable capital costs by eliminating the spare module and using allowances during periods of maintenance or unplanned outages.33 However, by far the most significant reason for lower costs has been the flexibility afforded utilities under the program to switch to low-sulphur coal as a means of compliance. This has driven competition and technology improvements in the coal and rail haul industry, which in turn have led to a dramatic reduction in the delivered cost of low-sulphur coal. A review of changes in the receipts for coal distinguished by sulphur content reveals that between 1990 and 1994 use of low-sulphur coal (defined as less than 0.6 pounds (lbs.) sulphur per million British thermal units (mmBtu)) increased by 28 percent while its price fell by 9 percent.34 Meanwhile, sales of high-sulphur coal (defined as greater than 1.67 lb. sulphur per mmBtu) fell by 18 percent, though prices fell by only 6 percent.35 Two trends explain the accelerated decline in the price of low-sulphur coal. The most important has been the reduction in the cost of rail transport of low-sulphur western coal, driven by investment and innovation in the rail industry. Many observers in the Clean Air Act debates conjectured that bottlenecks would occur in rail transport that would preclude western coal from playing a big role in compliance plans of eastern utilities. Hence, price forecasts hinged on the higher prices for low-sulfur Appalachian coal that was locally available to eastern utilities. However, these potential bottlenecks have failed to materialize. Rail transportation constitutes about 50 percent of the total cost of delivering low-sulfur coal from the West to the East. Coal transportation prices in the East are 20-26 mills per ton mile. However, competition in rail transport for western coal has caused prices to drop to an average of 10-14 mills per ton mile. During a recent bidding war to deliver Powder River Basin coal to Georgia Power Co., quoted prices fell to 6.5 mills per ton mile, allegedly even below marginal cost, in order to expand market share and justify further investments in infrastructure.36 A second explanation for declining coal prices is that the capital and other costs expected to be borne by utilities for using low-sulphur coal have failed to materialize due to the flexibility offered by Title IV. Fuel blending has become one of the major compliance strategies of utilities because it allows them to take advantage of low-sulphur fuels while avoiding capital investments that would be necessary when relying exclusively on low-sulphur fuels. In addition, a feared loss of megawatt capacity with low-sulphur coal has turned out to be low. The consequence of reduced low-sulphur coal prices, combined with the ability to exploit low-sulphur coal resulting from the flexibility of Title IV, is that in Phase I many plants that are not relying on scrubbers are arguably complying with the Acid Rain Program at virtually no cost or at a savings. A study by Resources Data International estimates that the savings to such firms may be as much as $ 158 million annually during Phase I.37 For example, the Southern Company will incur about $ 45 million in additional operating and maintenance and fuel expenses through the year 2000 for its 12 Phase I units not equipped with scrubbers, costs that are so low, spread over five years, as to be effectively neutral.38 The decline in coal prices driven by the availability of cheap, low-sulphur western coal has led some to speculate that some of the emission reductions that are occurring under Title IV would have happened anyway.39 Indeed, early emissions reductions are observable in 1993 and 1994, before Phase I took full effect.40 The trend toward early reductions suggests the possibility that the Acid Rain Program did little more than accelerate a trend that was otherwise occurring. Econometric analysis by A. Denny Ellerman and Juan-Pablo Montero has verified that, to some extent, this is the case. They conclude that Title IV should get some, but not all, of the credit for the decrease in emissions that has resulted from the increased use of western coal.41 A more meaningful assessment of Title IV's performance occurs when one compares that performance to the effect that differently structured acid rain regulation might have on the structure of coal markets. A command-and-control approach, such as that embodied in the Waxman-Sikorski bill,42 would have forestalled the development of low-sulphur western coal as a compliance option, as did the 1977 Clean Air Act Amendments affecting new sources. A slightly more flexible approach that would have implemented emission rate caps of 1.2 lbs. SO2 per mmBtu at the facility level would have precluded the blending of fuels with varying sulphur content, because such blending usually can achieve, at best, emission rates in excess of this level. This approach would also not capture savings from load shifting among units, or allowance trading. The change in regulatory structure has significantly altered utilities' compliance behavior in abating SO2 emissions. The NSPS required scrubbers to be installed in all new utility units to reduce SO2 emissions. Since the passage of Title IV in 1990, 17 facilities have ordered retrofit scrubber equipment for existing facilities, about one-half the number previously expected for Phase I of the program.43 No new scrubber has been purchased since the early days of the Acid Rain Program. Instead, utilities have chosen cheaper compliance options, particularly fuel blending and switching to low-sulphur coals. In doing so, they have been able to avoid capital intensive, irreversible investments during a period of change in the nature of economic regulation in the industry. Savings Due to Allowance Trading Activity These cost reductions have been achieved despite the lack of significant interutility allowance trading. The GAO estimated that only 2 of the 80 utilities that would benefit from trading were doing so, and one commentator has estimated that as of March 1995 only 1 percent to 3.5 percent of allowances allocated for Phase I (300,000-1,300,000) were involved in "real" interutility trades.44 Some analysts have noted this lack of interutility trading as a failure of the program.45 Many of these analysts, however, are confusing two kinds of trading programs. The closed system, or emission cap and allowance trading programs such as Title IV, fundamentally change the regulatory structure, as it gives industry the freedom to choose the method of compliance. These benefits come from the emission cap itself, as well as the trading. An open market trading system typically does not alter the command-and-control structure of a regulatory system, but allows trades to be made to improve efficiency. Their only benefit comes if trading is substantial. Title IV's trading provisions allow for further cost reductions based on the difference in different utilities' costs of reducing SO2 emissions. Illinois Power Co. is the only firm to rely heavily on allowances for Phase I compliance, and Carolina Power & Light Co. and Georgia Power are the only two firms that appear headed to do so in Phase II. EPA's Allowance Tracking System indicates that as of the end of 1995 4.3 million allowances had been transferred into utility accounts from brokers, fuel companies, and other utilities.46 These transfers have not been analyzed for the nature of the transaction. They include trades between operating companies within the same holding company, but they do appear to indicate that activity in the market is increasing. Nonetheless, utility avoidance of allowance trading as a compliance strategy has attracted widespread notice.47 One important reason trading has been lighter than many analysts originally expected is the role played by low-sulphur coal in meeting compliance requirements. The decline in rail transport costs, coupled with ample supplies of low-sulphur coal, makes it a commonly available option with comparably low marginal costs at many different facilities. Nonetheless, the GAO has identified 80 utilities in Phase I with emission reduction costs higher, and sometimes significantly higher, than current allowance prices.48 In principle, within a system of transferable emission allowances, a firm with relatively high marginal costs of emission reduction would have an incentive to take advantage of another firm's relatively low marginal costs. There are, however, several important obstacles to this allowance trading among utilities. Actions (or lack of action) by state public utility commissions (PUCs) that have created uncertainty, and aspects of standard electric utility regulation that tend to inhibit trading,49 have depressed demand and willingness to pay for allowances. First, uncertainty about the evolution of regulatory rules has inspired caution toward the market. This problem was amplified in the market's early stages by a requirement that utilities submit compliance plans to EPA for Phase I by February 15, 1993, before EPA's rules were proposed or the first allowance auction was held in March 1993.50 The Federal Energy Regulatory Commission (FERC), which regulates interstate energy transactions, provided guidance for accounting rules on allowances in March 1993,51 but FERC and state PUCs have provided little guidance on cost recovery rules. Second, and perhaps most important, those rules that have been developed erode the incentive to trade.52 For example, all states except Connecticut treat allowances as current period expenses analogous to fuel purchases, and costs (or cost savings) are passed through to ratepayers.53 This provides little incentive for the utility to reduce costs through the purchase or sale of allowances because the allowances expose the utility to risk for which there is little reward. According to most PUC cost recovery rules, gains from allowance sales are passed through to ratepayers while the risk that allowances may be needed in the future lingers. In addition, in most instances allowance costs are not recoverable until the year in which the allowance is used (interest charges on capital costs of allowances are recoverable), which discourages purchase and banking of allowances as a compliance strategy for use years into the future. Only one state commission, Georgia's PUC, has adopted a procedure that links the market price of allowances to compliance costs in providing guidance to utilities.54 The allowed rate of return, the depreciation rate, and the risk that expenses may not be recoverable in electricity rates are likely to differ among compliance strategies, favoring one strategy over another. Furthermore, typical prohibitions against shareholder earnings on capital gains (but not capital losses) imposes one-sided risk on utilities that purchase allowances.55 Utilities are often described as "risk averse," indicating that they are prone to strategies that minimize their risks rather than minimize their costs. Furthermore, all states continue to review transactions one at a time. This [26 ELR 10418] process is laborious and time-consuming and ill-suited for a utility operating in a competitive market.56 A third impediment to allowance trading has been explicit prohibitions by state legislatures on trades that might undermine local economic activity, especially coal production.57 Nearly every state with substantial Phase I compliance obligations has enacted legislation to promote the use of local coal.58 Perhaps the most aggressive attempt was an Illinois law, subsequently struck down by the courts as unconstitutional, that would have encouraged electric utilities to burn coal mined in the state by requiring installation of scrubbers as part of their Clean Air Act compliance.59 Other laws sought to achieve the same goal in more subtle ways, for instance by offering preapproval of cost recovery of investments in scrubbers. A fourth impediment to allowance trading stems from the excess supply of allowances in Phase I due to a provision of Title IV that provides an "extra" 3.5 million allowances in Phase I to facilities primarily for employing scrubbers.60 These allowances were a political concession in the 1990 legislation intended to subsidize utilities that install scrubbers. Congress sought to cushion the program's blow to states producing high-sulfur coal. The affect of this provision, coupled with PUC policies discussed previously, is to encourage scrubbing even if it is not the least-cost option for these utilities in terms of social opportunity costs. Scrubbing already in place at 24 units with 13 gigawatts of capacity account for about one-half of the projected emission reductions in Phase I.61 Scrubbing makes allowances available in Phase I, thereby increasing the supply of allowances in Phase I and depressing their price. The phased-in nature of the Acid Rain Program, which has been labeled "the most serious flaw in the allowance program,"62 may also create disincentives to allowance trading. Phase I attempts to balance conflicting goals in attempting to achieve emission reductions early, protect high-sulphur coal mining, and minimize costs. On the other hand, the phase-in has allowed the industry to learn over time and schedule investments in a way that has probably reduced costs. Phase I arguably separates utilities that would sell allowances from those that would buy them. Phase I utilities are the dirtiest existing coal plants and are expected to be a source of allowances that facilities not covered until Phase II will purchase. In addition, those Phase II facilities that can reduce emissions cheaply are allowed to opt into Phase I, further separating purchaser from seller and expanding the supply of allowances in the program's first five years. Consequently, a huge bank of allowances is amassing that will carry over to Phase II. The allowance bank is expected to reach between 7 million and 15 million tons at the beginning of Phase II in the year 2000, and is expected to last into the latter part of the next decade.63 This near-term surplus of allowances has reduced the need for allowance trading. Yet another possible disincentive is the tax treatment of allowances. Under federal tax law, the cost basis of allowances is zero, because they are allocated for free. This imposes a large tax on potential sellers of allowances, who may then seek to recoup this tax liability by selling at a price higher than most buyers are willing to pay. A solution would be to create a fair market value basis for allowances.64 In addition, many analysts have criticized EPA's allowance auction as a poorly designed institution that generates prices below those reached in bilateral trades between utilities. The auction design set forth in the statute is a discriminating price, sealed bid auction that provides strategic incentives for bidders to underbid their reservation prices.65 Each year, 2.8 percent of annual endowments of allowances to utilities are withheld for the auction with revenues returned to the original utility owners.66 Though this churns the market by forcibly executing transactions, it does so at a price level that may send a biased signal to the market about the value of allowances.67 The auction should be redesigned, as it currently contributes to the uncertainty about allowance price.68 Finally, the public has responded in unfriendly ways to announcements of trades, criticizing both sellers and buyers of allowances.69 As a consequence, there are ample hurdles to allowance trading and ample explanations why trading has been slow to develop. Innovation and Investments Prompted by the Acid Rain Program Title IV has had a significant positive effect on innovation and investment related to SO2 compliance. Any type of environmental regulation that tightens standards stimulates technological innovation to achieve emission reductions. However, the previous NSPS could only force technological change in scrubber design or other end-of-pipe solutions. Title IV appears to have stimulated innovation and investment in a broad range of compliance options, resulting in least-cost compliance. The innovation with the greatest impact on the compliance market has been a reduction in the cost of rail transport of low-sulphur coal, due to major investments in new infrastructure and to innovations that would have been impossible to predict or stimulate under the old standard. Following passage of Title IV, the rail industry implemented a number of innovations and improvements to meet increased demand for low-sulphur western coal. These include double and triple tracking, increasing size of car fleets, using new and more powerful locomotives, improving car design (e.g., using aluminum cars), and developing coal tipping technology that increases car dump speed. There has also been a dramatic increase in investment in rail infrastructure resulting from the robust competition in rail transport. These improvements have dispelled fears voiced during the debates over the 1990 Clean Air Act Amendments that bottlenecks in rail transport would preclude western coal from playing a major role in the compliance plans of eastern utilities. Innovation has also taken place in the use of existing plant and equipment. Coal-fired power plants are designed for a particular type of coal, and deviations in any of several important properties may impair plant performance or harm equipment.70 Conventional thought has been that combustion of low-sulfur sub-bituminous western coal in eastern utility cyclone boilers would be troublesome because low- sulphur coal differs from the commonly used bituminous coal in moisture content, heat content, and ash properties. Experimentation prompted by the allowance trading program has led to an improved understanding and use of the ability to blend fuels. Blending technology has been found to reduce the originally supposed detrimental effects of using low-sulphur coal. Title IV has even led to improvement in scrubber technology by subjecting it to competition, and providing market incentives for improved efficiency in scrubbing. The technology of scrubbing has evolved considerably in recent years, and new scrubbers exhibit increased efficiency through improvements such as larger modules, elimination of reheat, and increased reliability. Improvements in scrubber design and use of materials also have reduced maintenance costs and increased utilization rates.71 These improvements have reduced scrubber prices by as much as 50 percent since the late 1980s.72 Future retrofit scrubber installations in Phase II are expected to see total costs reduced by another 15 percent.73 The economic incentives in Title IV are such that increasing SO2 removal from, say, 90 percent to 95 percent can be cost-effective compared to the opportunity cost of allowances. As stated above, these efficiency improvements afforded no advantage under the NSPS before the adoption of the Acid Rain Program, as there was no regulatory or market incentive to go beyond the NSPS. Under the Acid Rain Program, however, additional reductions benefit a utility,74 as every ton of emission avoided is an allowance earned that reduces overall compliance costs. Overall, a study by Clean Air Capital Markets75 identified $ 12 billion in investment associated with Title IV by mid- 1995:$ 6 billion for development of low-sulphur coal fields, $ 3 billion for scrubbers and modifications, $ 2 billion in coal-related rail investment, and over $ 1 billion in allowance purchases. Unlike the previous standard, Title IV appears to have promoted innovation in the least-cost compliance options, which were determined by business decisions and not technology prescriptions. Allowance Prices Reflect Lower Long-Term Marginal Costs The price of an allowance for emission of one ton of SO2, originally estimated to be $ 750 by some analysts, has dropped to below $ 100. The EPA auction for allowances in March 1996, which may underestimate the current value of an allowance due to its institutional features, yielded an average price of $ 68.14 per ton for an allowance usable in the current period, and a price of $ 65.36 per ton for an allowance useable in the year 2002. Estimates of the average price of an allowance in private transactions through 1996 are below $ 100.76 There are several reasons that allowance prices are plummeting. Most encouraging among these is the emergence of low-sulphur coal as a major low-cost option for compliance in Phase I. Innovation and competition among the variety of compliance options, as outlined above, have reduced the cost of each. The low allowance price therefore indicates that the Act is working, not the opposite. Other aspects of the Acid Rain Program have reinforced the drop in prices. The availability of bonus allowances in Phase I and the ability of eligible utility plants from Phase II (substitution units) to voluntarily subject themselves to Phase I requirements in order to bank allowances for the future77 have contributed significantly to the growing surplus of allowances in the bank for future use. The consequence is an emission bank that is likely to reach about 10 million tons entering Phase II, at which time allowable emission rates at all facilities will be reduced and utilities [26 ELR 10420] are expected to begin to draw down the bank. Projections vary about how long the bank will last, but most analysts expect it to be drawn down slowly and to last at least until after the middle of the next decade. The surplus of allowances in Phase I which has contributed to low allowance prices thus far could lead to exaggerated optimism about the performance of the program. While there is abundant evidence from examining fundamental technological costs that real marginal costs have dropped sharply compared to projections, they have not dropped as much as the current price of an allowance would suggest. Economic theory suggests that the market price of an allowance should approximate the marginal cost of abatement. What explains the current difference between allowance prices and marginal costs? Although some might claim that it is time to rethink economic theory, actually it is time to better understand the structure of Title IV. An accurate estimation of abatement costs, coupled with the long-term nature of compliance options, means that the current allowance price probably reflects the discounted value of future abatement costs. Investments in scrubbers, as well as commitments to other strategies such as use of low-sulphur coal, are "lumpy" decisions that are not easily changed. Scrubbers have a high fixed cost that is largely irreversible, whereas operating costs are relatively low, and low-sulphur coal contracts typically have relatively long durations. Once these investments are in place, utilities save relatively little by increasing emissions. On the other hand, further emission reductions generate allowances that will not be used until the latter part of the next decade, at which time the allowance bank is expected to be exhausted and the current price of an allowance may approximate marginal costs. The collapse in any difference in the price of an allowance usable now and one useable five years in the future provides convincing evidence that the allowance market is working as economic theory would suggest, given the institutional features and circumstances of the Acid Rain Program. There is no scarcity premium placed on allowances useable today relative to ones useable in five years because the large allowance bank will last beyond five years. Furthermore, the present value of allowances does not reflect the marginal cost of a ton of emission reduction today but rather their expected scarcity value (marginal cost) in the long term. It is plausible to assume that the ability to expand use of low-sulphur coal will reach a limit and that the marginal costs per ton from emission reduction by the year 2010, when the bank is exhausted, will be governed by the use of scrubbers. The marginal cost of scrubbing is the cost per ton of the scrubber less the cost of the next least comprehensive option. This value is greater than the average cost per ton removed by scrubbing, often termed the "incremental cost." In the year 2010 the marginal cost may approximate $ 435 (in 1994 dollars) per ton of SO2 reduction.78 This value, discounted to the present at an interest rate of 8 percent, suggests that the present value of an allowance should be about $ 148, relatively close to recently observed allowance prices.79 The future cost of abatement may be even lower if one assumes technology improvements or other cost reductions due to the ability of low-sulphur coal suppliers to exceed expectations about price and supply performance to date, and the probable increased use of natural gas. Furthermore, increasing competition in electricity generation and potential deregulation of the industry makes large capital investments increasingly risky, which should also fuel the search for compliance options with lower capital costs. These considerations lead one to suspect that the marginal cost of abatement 10 years hence will be well below $ 275 per ton, but not as low as the current value of allowances.80 Sensitive Ecosystems and Regional Effects Sensitive Areas. Some people have argued that some sensitive areas may require greater reductions in SO2 than are required under Title IV. A prominent case in point is the Adirondacks ecosystem, which some believe can tolerate no more than 3.5 kilograms (kg) of sulphur per hectare to achieve ecosystem health, less than the reduction to 6 kg per hectare expected under Title IV.81 In addition, there is concern that increasing competition in the utility industry, and the effects of compliance with new NOx standards, may concentrate emissions in cheap but dirty coal-fired power plants in the airshed upwind of the Adirondacks.82 Rather than addressing such problems through command-and-control regulation, a subregional cap could be created for a regional airshed under Title IV. For the Adirondacks or Northeast, this would need to include parts of the Ohio River valley and northeastern states.83 Using this approach would capture the benefits of Title IV and address the problem at least cost. Effects of Trading on Sensitive Areas. Since Title IV establishes a national cap on emissions, one of the potentially troubling effects of the interutility trading element of Title IV is the possibility that trading can create regional concentrations of SO2.84 This might cause regional environmental damage in particularly sensitive areas such as the Adirondacks or central Appalachians. However, relatively little interutility trading occurred during the first year of Title IV's operation, and that which did occur has not affected sensitive areas in the Northeast. Under Title IV, regional impacts could occur if units in close geographic proximity purchased significant amounts of allowances. However, the statistical probability of this is low, and several trends actually favor trading away from these sensitive areas. Modelling by the 1990 Integrated Assessment Report of the National Acid Precipitation Assessment Program found that the opportunity to trade—compared to uniform emission reduction—could actually benefit these sensitive aquatic regions.85 Moreover, economic considerations have led analysts to predict that an increase in interutility trading would encourage midwestern utilities to sell allowances to others, especially southeastern utilities, due to their differing costs of abatement.86 Indeed, after the first full year of trading, midwestern utilities had been net sellers of allowances.87 However, since utilities are overcomplying in Phase I and creating a bank of allowances that will carry forward into Phase II, one can learn little from the level or pattern of trading to date with respect to potential regional shifts in SO2 emission patterns.88 Furthermore, any possible increase at a site resulting from trading would be overwhelmed by the approximate 50 percent reduction in overall emissions embodied in Title IV.89 In the long term, an emission cap system may do more for such sensitive regions because pollutant loads do not increase with economic growth, something that would happen with traditional command-and-control regulations. An emission cap and allowance trading program requires a strict monitoring system. Title IV's strict compliance monitoring requirements have been called the gold standard that assures the integrity of both the SO2 emissions cap and the allowance trading program. Data from 1995 show the integrity of monitoringto be high, with monitoring devices certified at all units and over 93 percent functioning accurately.90 Under Title IV, actual emissions must be measured by continuous emission monitors (CEMs) which record actual utility emissions of SO2 and other gases. Predictive emission monitors may also be permitted, and can be just as accurate, but regulatory barriers in the testing procedures have, unreasonably according to some, restricted their use.91 Title IV's compliance mechanism is open and straightforward, and together with the Act's penalty provisions, create an almost self-executing enforcement system. The statute establishes an Allowance Tracking System, which publicly records the number of allowances held in each utility account. At year end, a utility must have enough [26 ELR 10422] allowances to cover its emissions, or be fined $ 2,000 per missing allowance and have to make up its shortfall from future allowances.92 This system is much simpler than regular permitting systems, and has not only proven more effective, but has greatly reduced the time cost of permitting to the industry. Since the penalty provision is self-executing, the requirement under Title IV that a permit be issued could be eliminated altogether so long as the penalty provisions remain. One of the success stories of Title IV has been that, as a consequence of this, there has been virtually 100 percent compliance with its emission standard with little need for enforcement action.93 There has been relatively little litigation over the Acid Rain Program compared to what is expected with more traditional rate-based or technology-based standards. Four lawsuits have been filed and settled, two of which concerned the complex substitution provisions created by the program's phases.94 This relative lack of litigation is attributable to several elements of Title IV. Most significant is the nature of the cap-and-trade standard, which is relatively straightforward because the statute defines the cap and allocates allowances. An indication that the cap-and-allowance approach works smoothly relative to a traditional regulatory approach is the record of what has happened to the NOx provisions of Title IV. Title IV includes a program for NOx abatement that establishes traditional emission limitations. A bitter dispute has ensued between EPA and industry sources over these standards, with a court rejecting one set of final rules,95 and EPA promulgating another set in January 1996 under the threat of more litigation.96 In contrast, the emission cap for SO2 has been implemented in a timely fashion with a minimum of controversy.97 A significant advantage of performance regulations such as the emissions cap is that they do not require a small army of bureaucrats to review whether each point source is meeting its technology-based effluent limit. This also eliminates the costly delays businesses face when seeking permits. Title IV runs with less than 100 employees nationwide in state and federal programs. Phase I was operated by the federal government using fewer than 70 employees, a significant number of whom were needed to deal with needless complexity written into the law for substitution rules due to phasing and special bonus programs.98 Without such rules, the Acid Rain Program would have required even fewer employees to run a program with an economic compliance cost of around $ 2 billion annually. Even with these complications, the administration of Title IV costs less than $ 2 per ton to administer.99 In contrast, states are authorized under the Clean Air Act to collect a $ 25 per ton fee to support permitting and enforcement activities for running Title V air permit programs.100 Suggested Improvements to the Acid Rain Program The fundamentals of the Acid Rain Program are sound. Key provisions, including the hard emission cap, an allowance trading system, bankable allowances, and strict monitoring rules, are in place. Nevertheless, several improvements could be made to the program. The EPA auction of allowances, while an innovative idea, has a current structure that destabilizes allowance prices and should be modified. Secondly, the permit system may create unneeded complexities and is not needed given the self-executing performance and penalty provision of Title IV. Thirdly, more flexibility should be afforded in the testing procedures to approve effective emission monitoring technologies as alternatives to CEMs. Perhaps more important than these administrative reforms are reforms needed in PUCs and FERC regulatory policies that discourage allowance trading. These reforms will be important for Phase II to capture the savings needed to minimize costs. A traditional regulatory approach by PUCs does not encourage utilities to use the allowance program in a way that is in the best interests of ratepayers. Instead, utilities are likely to favor a self-sufficient compliance strategy, creating significantly higher industrywide compliance costs.101 FERC and the PUCs must become more proactive in providing a more certain regulatory environment for utilities participating in trading. Also, the regulatory environment must not discourage or discriminate against active participation in the market. It should encourage a comparison of technology options, including allowance acquisitions, in construction of utility compliance plans for Title IV. These methods should mimic the incentives of a competitive market.102 Furthermore, as new evidence is gathered by the National Acid Precipitation Assessment Program and affiliated agencies on all benefits and costs of the Acid Rain Program, including the ecological, recreation, human health, and visibility benefits, the overall level of the emissions cap at a national level or potentially at regional levels should be reconsidered.103 The Acid Rain Program's first full year of implementation has shown the program to be successful in achieving its environmental goals at compliance costs far less than those under a conventional approach. The program has demonstrated the virtues of an innovative performance-based approach to environmental regulation and shown that regulatory systems that create market-based compliance incentives can reduce costs without undermining the goal of improved environmental quality. Although technology forcing, the previous command-and-control standards perhaps focused on forcing the wrong technologies. Because they required scrubbers, the only technological innovations were in scrubber technology. Under the Acid Rain Program, dramatic technology innovations leading to lower costs have occurred in rail transport of coal and in fuel blending. In the future, they may also occur in clean coal or energy efficiency measures, depending on market forces. The Acid Rain Program has contributed importantly to lowering the costs of SO2 emission reductions in unanticipated ways. Compliance costs have fallen from an expected value of about $ 4 billion per year when the 1990 Clean Air Act Amendments were enacted to about $ 2.5 billion per year or less, and could fall to $ 1.2 billion with greater trading. Monetized benefits from the legislation were expected to be between $ 2 billion and $ 9 billion, according to one review,104 and new estimates of the health and visibility effects of the program suggest that benefits could be even greater than that.105 The apparent decrease in costs and increase in benefits, compared with values expected when the 1990 amendments were enacted, suggest that a more thorough review of costs and benefits is appropriate and that such a review could justify revising the Act to tighten the SO2 emission cap, at least on a regional basis. Despite the program's successes, some of its results, coupled with new information about benefits and costs of SO2 emission reductions, indicate limitations in accurately predicting benefits or costs associated with specific measures. Thus, rather than subjecting existing environmental programs to a rigorous cost-benefit test, as many in Congress have suggested, Congress might do better to examine existing regulatory programs to see if they can be restructured to adopt performance standards that encourage innovation by granting increased flexibility to firms in their abatement efforts. While this approach may require greater agency and industry resources directed toward monitoring activities, costs should be greatly reduced, and there likely will be additional savings in other administrative and legal costs. For example, adopting the Title IV emission cap and allowance trading approach to abatement of urban ozone precursor NOx and volatile organic compounds could improve attainment, save billions of dollars annually, and significantly reduce the cost of permitting to business and regulators alike. The conversion of technology-based or effluent-rate standards to overall performance standards may be the simplest way forward to least-cost environmental regulation.
33. The estimate of capital costs for a 488 megawatt plant with 3.2 percent sulphur would increase by one-third with a spare module. U.S. ENERGY INFO. ADMIN., supra note 12, at 92. 34. Low-sulphur western coal is plentiful and the minemouth cost was about $ 7.32 per ton in 1993 (in 1993 dollars), compared with an average central Appalachian coal price of $ 27.64 per ton. (The western coal price is the average price for Wyoming coal.) Appalachian coal on average will have medium- to high-sulphur content, but also a higher energy (Btu) content. U.S. ENERGY INFO. ADMIN., DOE/EIA-0584(93), COAL INDUSTRY ANNUAL 1993, tbl. 80 (1994). Compared to five years ago, coal prices and price projections for low-sulphur coal (1.2 lbs. SO2/mmBtu) are $ 5-7 less for central Appalachian coal and $ 0-2/ton lower for Powder River Basin (western) coal. K. WHITE ET AL., THE EMISSION ALLOWANCE MARKET AND ELECTRIC UTILITY SO2 COMPLIANCE IN A COMPETITIVE AND UNCERTAIN FUTURE 2-4 (1995). 35. U.S. ENERGY INFO. ADMIN., DOE/EIA-0064(90), COAL DATA: A REFERENCE 68 (1991), and U.S. ENERGY INFO. ADMIN., DOE/EIA- 0064(93), COAL DATA: A REFERENCE 91 (1995). A recent study by Resource Data International shows that the price of low-sulphur coal from western fields is now 12 percent less than the price of high-sulphur coal, a greater price differential than for all low-sulphur coals. RESOURCES DATA INT'L, INC., RDI's PHASE I DATABOOK—PERFORMANCE UNDER THE CLEAN AIR ACT AMENDMENTS OF 1990 (1995). 36. Burtraw, supra note 29. 37. RESOURCES DATA INT'L, INC., supra note 35; see Jeff Bailey, Electric Utilities Are Overcomplying With Clean Air Act, WALL ST. J., Nov. 15, 1995, at B8. 38. K. Boyd & W.D. Herrin, Implementation of the Southern Company Clean Air Compliance Strategy, Paper Presented at the Air & Waste Management Association Meeting on Acid Rain and Electric Utilities: Permits, Allowances, Monitoring, and Meteorology, in Tempe, Ariz. (Jan. 1995). 39. Western coal represents about 56 percent of recoverable coal reserves, and about 94 percent of western coal is low or medium sulphur, representing over 75 percent of the low- and medium-sulphur coal in the nation. Furthermore, western coal is primarily surface mined, which entails dramatically lower costs of production than does underground mining. 40. At facilities identified in Title IV for Phase I compliance, emissions of SO2 declined from 9.4 million tons in 1980 to 7.4 million tons in 1994. This reduction is nearly sufficient to achieve the targeted level for 1995, the first year of the Acid Rain Program. U.S. EPA, EPA 430/R-95-012 1995, ACID RAIN PROGRAM EMISSIONS SCORECARD 1994: SO2, NOx, HEAT INPUT, AND CO2 EMISSION TRENDS IN THE ELECTRIC UTILITY INDUSTRY (1995) (available from ELR Document Service, ELR Order No. AD-155). 41. A. DENNY ELLERMAN & JUAN-PABLO MONTERO, WHY ARE ALLOWANCE PRICES SO LOW? AN ANALYSIS OF THE SO2 EMISSIONS TRADING PROGRAM (MIT-CEEPR Working Paper No. 96-001, 1996). 42. See supra note 17. 43. Jeffrey C. Smith & Stuart M. Dalton, FGD Markets & Business in an Age of Retail Wheeling, Paper Presented at EPRI/EPA/DOE SO2 Control Symposium, Miami, Fla. (Mar. 28, 1995). 44. Kenneth Rose, Implementing an Emissions Trading Program in an Economically Regulated Industry: Lessons From the SO2 Trading Program, in MARKET-BASED ENVIRONMENTAL PROGRAMS (forthcoming 1996). 45. Indeed, one of the coauthors of this Article wrote that if a robust allowance trading market failed to emerge, the allowance trading program could conceivably raise costs compared to a command-and-control approach. Douglas R. Bohi & Dallas Burtraw, Avoiding Regulatory Gridlock in the Acid Rain Program, 10 J. POL'Y ANALYSIS & MGMT. 676 (1991). "Almost all involved agree that the rate of trading among utilities is not as high as had been expected [and] … is not nearly enough to realize the kind of financial savings originally envisioned." G. Zorpette, A Slow Start for Emissions Trading, IEEE SPECTRUM, July 1994, at 49; see also M.L. Wald, Acid-Rain Pollution Credits Are Not Enticing Utilities, N.Y. TIMES, June 5, 1995, at A11. But see Sam Hays, Emissions Trading Mythology, ENVTL. F., Jan./Feb. 1995, at 15 ("Emissions trading … pales into insignificance in the face of the massive, overriding decision … to cap [emissions]."). 46. U.S. EPA, supra note 2. 47. Kenneth Rose, Twelve Common Myths of Allowance Trading: Improving the Level of Discussion, ELEC. J., May 1995, at 64. 48. U.S. GAO, supra note 20, at 30-41; see also U.S. EPA, supra note 31 (forecasting significant price differences in utilities' costs of abatement). 49. Douglas R. Bohi & Dallas Burtraw, Utility Investment Behavior and the Emission Trading Market, RESOURCES & ENERGY, Apr. 1992, at 129; see Rose, supra note 44. 50. 42 U.S.C. § 7651g(c), ELR STAT. CAA § 408(c). 51. FERC, REVISIONS TO UNIFORM SYSTEM OF ACCOUNTS TO ACCOUNT FOR ALLOWANCES UNDER THE CLEAN AIR ACT AMENDMENTS OF 1990 AND REGULATORY-CREATED ASSETS AND LIABILITIES AND TO FORM NOS. 1, 1-F, 2, AND 2-A (1993). 52. Don Fullerton, Shaun P. McDermott, and Jonathan P. Caulkinset found that regulatory rules could more than double the cost of SO2 compliance in certain scenarios. Don Fullerton et al., Sulfur Dioxide Compliance of a Regulated Utility (University of Texas (Austin), Department of Economics mimeo, Apr. 1996); for a contrary view on whether state regulators have impeded trading, see Elizabeth M. Bailey, Allowance Trading Activity and State Regulatory Rulings: Evidence from the U.S. Acid Rain Program (Massachusetts Institute of Technology, Mar. 1996). 53. Rose, supra note 44. 54. Id. at 20. 55. Bohi & Burtraw, supra note 49; Barry D. Solomon, SO2 Allowance Trading: What Rules Apply?, PUB. UTIL. FORT., Sept. 15, 1994, at 22 (offering prescriptions for regulators to avoid these problems). 56. Rose, supra note 44. 57. James J. Winebrake et al., Estimating the Impacts of Restrictions on Utility Participation in the SO2 Allowance Market, ELEC. J., May 1995, at 50. 58. Douglas R. Bohi, Utilities and State Regulators Are Failing to Take Advantage of Emission Allowance Trading, ELEC. J., Mar. 1994, at 20; Rose, supra note 44. 59. Seventh Circuit Rejects Illinois' Attempt to Favor Use of In-State Coal By Utilities, 25 Env't Rep. (BNA) 1794 (Jan. 20, 1995); see also Indiana Coal-Use Law Unconstitutional Violates Commerce Clause, Appeals Court Says, 26 Env't Rep. (BNA) 1612 (Jan. 12, 1996). 60. 40 C.F.R. § 73.25 (1995). 61. WHITE ET AL., supra note 34, at 2-1; Smith & Dalton, supra note 43 (17 facilities have ordered retrofit scrubbers). 62. BRIAN J. MCLEAN, EPA, 95-RA120.04, LESSONS LEARNED IMPLEMENTING TITLE IV OF THE CLEAN AIR ACT 7 (1995). 63. White et al. estimate that the bank will reach 9.4 million tons in the year 2000. WHITE ET AL., supra note 34. Resource Data International estimates that the bank in the year 2000 will reach 12-15 million tons, and will be drawn down sometime between 2007 and 2010. RESOURCES DATA INT'L, INC., supra note 35. 64. WHITE ET AL., supra note 34, at 6-12; see also Michael J. Thomas, Why Taxes Don't Distort Emissions Trading, PUB. UTIL. FORT., Dec. 1, 1994, at 37; Stanley I. Garnett II, Why Taxes Do Distort Emissions Trading, PUB. UTIL. FORT., Feb. 15, 1995, at 42. A fair market value basis would also encourage donations to retire allowances, unless Congress were to limit this right. 65. T.N. Cason, Seller Incentive Properties of EPA's Emission Trading Auction, 25 J. ENVTL. ECON. & MGMT. 177 (1993); T.N. Cason, An Experimental Investigation of the Seller Incentives in EPA's Emission Trading Auction, 85 AM. ECON. REV. 905 (1995). 66. 42 U.S.C. § 7651o(b), ELR STAT. CAA § 416(b). 67. EPA's annual auction, which the 1990 amendments mandate, has been shown to provide buyers with a strategic incentive to under-represent their true willingness to pay for additional allowances. Cason, Seller Incentive Properties of EPA's Emission Trading Auction, supra note 65. Nonetheless, Ellerman and Montero argue that the auction has served a useful function in making widely known at an early date the relatively low cost of compliance and of allowances, compared with expectations before program implementation. See ELLERMAN & MONTERO, supra note 41. 68. See U.S. GAO, supra note 20, at 53. 69. D.A. SELIGMAN, AIR POLLUTION EMISSIONS TRADING: OPPORTUNITY OR SCAM? (Sierra Club 1994); Peter Passell, Paying to Pollute: A Free Market Solution That's Yet to Be Tested, N.Y. TIMES, Jan. 4, 1996, at D2. 70. Equipment likely to be affected by blending coals includes the coal handling system, the fuel preparation and firing system, the primary air system, the steam generator, and the particulate removal system. Coal blending is also likely to affect ash and waste disposal, building and structural support, and plant cleanup and maintenance. U.S. ENERGY INFO. ADMIN., supra note 12, at 14-20. 71. INSTITUTE OF CLEAN AIR COS., supra note 12. 72. U.S. GAO, supra note 20, at 28; U.S. EPA, supra note 2, at 1. 73. WHITE ET AL., supra note 34, at 2-2. 74. I.M. Torrens et al., The 1990 Clean Air Act Amendments: Overview, Utility Industry Responses, and Strategic Implications, 17 ANN. REV. ENERGY & ENV'T 211, 221-22 (1992). 75. Clean Air Capital Markets, Data Presentation (Washington, D.C. Jan. 10, 1995) (on file with authors). 76. Resources Data International predicts that 1996 prices will average in the $ 70-$ 80 range. AIR DAILY LTD., AIR DAILY, June 7, 1996. 77. See supra note 63 and accompanying text. 78. White et al. estimate a reference case with high plant utilization to have a marginal cost in the year 2010 of $ 528/ton (in 1994 dollars). They estimate a case with low plant utilization at $ 335/ton. WHITE ET AL., supra note 34. This Article chooses a midpoint for illustration because the authors of this Article expect electricity demand to grow less than White et al. estimate that it will, and the authors of this Article expect further declines in scrubber costs and fuel costs (which White et al. model in sensitivity analysis), while plant utilization at existing facilities may be as high as White et al. estimate in their reference case. 79. White et al. suggest that an 8 percent discount rate strikes an appropriate balance between conventional regulated utility discounting based on the weighted average cost of capital and higher discounting for competitive conditions with greater risk. WHITE ET AL., supra note 34. For comparison, use of an 11 percent discount rate with the original value of $ 435 would yield a present value of $ 101. One can criticize use of marginal cost because as long as some semblance of economic regulations for electric utilities remains in place, cost recovery rules will center on incremental rather than marginal cost, and this may be reflected in allowance prices. Use of an incremental cost estimate reflecting the average cost per ton removed at scrubbed facilities suggests a value of about $ 275 (in 1994 dollars) in the year 2010, yielding a present value allowance price of about $ 94, which is even closer to that observed recently. 80. A present period price of $ 90 (in 1996 dollars) for an allowance, coupled with expected exhaustion of the bank around 2007 and an interest rate of 8 percent implies a marginal cost of abatement in 2007 of $ 210 (in 1996 dollars). Resources Data International estimates the market price of allowances in the year 2010 to be $ 200, or possibly as high as $ 360. RESOURCES DATA INT'L, INC., supra note 35. 81. See, e.g., H.R. 2682, 104th Cong., 1st Sess. (1995) (a bill to amend the Clean Air Act to provide for additional reductions of SO2 for the Adirondacks, specifying a target deposition level of 3.5 kg sulphur per hectare per year). 82. One recent study by Henry Lee and Negeen Darani estimates that a "moderate" increase in plant utilization rates for coal facilities from 64 to 67 percent results in a 1.1 million ton increase in SO2 emissions, representing 11.1 percent of the goal of current U.S. policy. Henry Lee & Negeen Darani, Electricity Restructuring and the Environment 55 (Kennedy School of Government mimeo, Harvard University Nov. 22, 1995). In the context of Title IV these would have to be made up at other facilities or from the allowance bank. However, modeling of emissions by region by White et al. suggests that emissions in the Ohio Valley in the long-term (year 2010) would decrease due to higher plant utilization that would probably accompany increased competition, and the Northeast will increase its emissions. WHITE ET AL., supra note 34. Nonetheless, a more immediate effect could be felt from more liberal transmission access and long-distance transmission of electricity under a rule that FERC is proposing. Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Service by Public Utilities, 60 Fed. Reg. 17662 (Apr. 7, 1995). Comments from many intervenors on the Draft Environmental Impact Statement of the FERC Notice of Proposed Rulemaking (Docket No. RM95-8-000) have suggested that specific accommodations should be made to lessen this environmental impact. See 61 Fed. Reg. 17263 (Apr. 19, 1996). 83. The Northeast is the principal region of concern because of its location upwind from coal-fired power plants in the Ohio Valley, and because of the sensitivity to acidification in the Adirondacks ecosystem. 84. It is important to note that local health-based concerns about SO2 emissions are governed not by Title IV but by the health-based NSPSs and NAAQS. Utilities must comply with these standards separately from their obligations under Title IV, which requires additional emission reductions in order to address regional and national concerns. A proposed EPA rule for the SO2 program provides: "Sections 403(f) and 413 of the Act require that nothing in the acid rain permit … would alter any other Clean Air Act requirement, including those designed to protect National Ambient Air Quality Standards." 56 Fed. Reg. 63006 (Dec. 3, 1991). The 24-hour standard for ambient SO2 concentrations, not to be exceeded more than once per year, is 0.14 parts per million. Id. 85. U.S. NAPAP, supra note 7. This report compared a 50 percent reduction in SO2 emissions applied as a uniform percentage reduction across sources with the same reduction achieved through uniform emission rates within each state, which would imply varying percentage reductions across sources. The report found that for the uniform emission rate example, "deposition reductions at specific receptors are expected to range from slightly higher to moderately lower than the domain-wide emissions reductions," where emphasis was placed on regions with sensitive aquatic systems. Id. at 256. 86. "Midwestern utilities were considered the most likely to install scrubbers because of their low cost per ton of SO2 removal. This occurs because the cost per ton of removing SO2 is lower for a plant burning high-sulfur coal than for a plant burning low-sulfur coal. Midwestern utilities typically burn high-sulfur coal. Utilities … with higher per-ton scrubbing costs and higher projected growth in utility demand, such as the Southeast, would be net buyers of allowances." U.S. GAO, supra note 20, at 40 & n.12. 87. U.S. GAO, supra note 20, at 39. 88. Barry D. Solomon, The Geography of SO2 Allowance Trading, in ENVIRONMENTAL PROFESSIONAL (forthcoming 1996-1997). 89. The Northeast is one region that has been concerned about the effects of trading, because of its location upwind from coal-fired power plants in the Ohio Valley, and because of the sensitivity to acidification in the Adirondacks ecosystem. Using an adapted version of the Tracking and Analysis Framework sponsored by the National Acid Precipitation and Assessment Program, which employs a reduced form atmospheric transport model based on Atmospheric Statistical Trajectory Regional Air Pollution (ASTRAP), the authors of this Article calculated the change in average atmospheric concentration of SO2 and SO[4] (sulfates) in the Northeast region (New York and New England) under various scenarios in the year 2010. Changes in these concentrations can be expected to represent changes in acidic deposition in the region fairly well, although the coarse regional focus may obscure effects specific to the Adirondacks. The authors of this Article find that the Ohio Valley region is responsible for about 70 percent of the decrease in concentrations of SO2 and SO[4] in the Northeast that will ultimately result from full implementation of Title IV. The Ohio Valley's decrease in contribution to concentrations in the Northeast represents about 1.2 micrograms SO2 and 0.6 micrograms SO[4] per cubic meter as an annual average. 90. U.S. EPA, supra note 2. 91. C. Foster Knight, How Regulations Impact Innovative Environmental Technologies: A Recent Case Study, TOTAL QUALITY ENVTL. MGMT., Spring 1995, at 119. 92. 42 U.S.C. § 7651j, ELR STAT. CAA § 411. 93. Conversation with Joseph Kruger, Energy Evaluation Branch Chief, Acid Rain Division, EPA, in Washington, D.C. (June 12, 1996) [hereinafter Kruger Conversation]. In addition, there has been 100 percent compliance with the initial requirement that all utilities install CEMs by the beginning of 1995. U.S. EPA, supra note 2, at 2. 94. U.S. EPA, EPA 430-N-95-012, ACID RAIN PROGRAM UPDATE NO. 2: PARTNERSHIP FOR CLEANER AIR (1995). 95. Alabama Power Co. v. U.S. Environmental Protection Agency, 40 F.3d 450, 25 ELR 20166 (D.C. Cir. 1994). 96. 61 Fed. Reg. 1442 (Jan. 19, 1996); Stricter NOx Limits Proposed by EPA for Several Types of Utility Boilers, 26 Env't Rep. (BNA) 1787 (Jan. 26, 1996). 97. See generally MCLEAN, supra note 62 ("Comparing the experiences implementing the SO2 and NOx provisions of Title IV confirms the importance of having clear goals and consequences for delay."). 98. There are, for example, 29 separate formulas, which required separate data collection, at an administrative cost of $ 1-2 million. The substitution and compensation rules created by the two phases involving different utilities on an interconnected grid also created administrative complexity. About 15 percent of the total budget of the Acid Rain Program is devoted to creating the data and other systems required to comply with these complexities introduced by the political process. Kruger Conversation, supra note 93. 99. See MCLEAN, supra note 62, at 12. 100. 42 U.S.C. § 7661a(b)(3)(B)(1), ELR STAT. CAA § 502(b)(3)(B)(1). See generally U.S. GAO, GAO/RCED 94-68, AIR POLLUTION: PROGRESS AND PROBLEMS IN IMPLEMENTING CERTAIN ASPECTS OF THE CAAA OF 1990 (1993). The North Carolina Clean Air Act Advisory Council estimated the annual cost for the permit program to be $ 36 per ton. 101. Rose, supra note 44. 102. For some useful guidelines, see KENNETH ROSE ET AL., THE NATIONAL REGULATORY RESEARCH INSTITUTE, REGULATORY TREATMENT OF ELECTRIC UTILITY CLEAN AIR ACT COMPLIANCE STRATEGIES, COSTS, AND EMISSION ALLOWANCES (1993). 103. Recent research indicates that cumulative effects of past acid rain in some regions may require a significantly greater reduction in SO2 emissions. G.E. Likens et al., Long-Term Effects of Acid Rain: Response and Recovery of a Forest Ecosystem, 272 SCIENCE 244 (1996). 104. Paul R. Portney, Economics and the Clean Air Act, J. ECON. PERSP., Fall 1990, at 173. 105. Annual visibility benefits in the year 2010 have been estimated to be $ 2.5 billion. Chestnut et al., supra note 6. Annual health benefits in the year 2010 were estimated by one study to be about $ 40 billion. U.S. EPA, supra note 5, at S-8. This study may be criticized for employing liberal assumptions with respect to a variety of issues. A more cautious approach still yields an estimate of about $ 14.4 billion per year in the year 2010. DAVID AUSTIN ET AL., PRESENTATION BEFORE THE NAPAP PEER REVIEW OF THE TRACKING AND ANALYSIS FRAMEWORK (Draft Results 1995). 26 ELR 10411 | Environmental Law Reporter | copyright © 1996 | All rights reserved |