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Economic incentives for clean coal technology deployment
Economic incentives for clean coal technology deployment Adam Rose and Amit Mor
Clean coal technologies (CCTs) hold great promise for abating acid rain at low or zero incremental cost. They also represent a useful tactic in promoting energy security. Yet adoption of these technologies in the USA has been slow, and circumstances indicate continued inertia. The US government has a major programme to subsidize CCT demonstration projects but has done little to stimulate their adoption. This paper examines several fiscal incentives and finds their costs to be rather modest, especially in the light of the non-market benefits that widespread CCT adoption would reap. Keywords: Coal; Technology; Environment
In late 1984 the US Congress enacted the first phase of what has become known as the Clean Coal Technology (CCT) Programme. The initial programme and the several legislative supplements since are intended primarily to accelerate the demonstration of new technologies that promise cleaner coal processing, combustion or derivative fuels. Because many of these methods are also being touted as cost saving, they are seen as an ideal solution to the acid rain issue; that is, we may be able to reduce acid rain without incurring the sizable costs associated with conventional pollution control alternatives. 1 More recently, the increased combustion efficiency characteristic of many of these options has been hailed for its contribution to a 'no regrets' strategy against global warming. Although the CCT Programme has had some success, z the actual deployment of CCTs depends on more than just the demonstration of even commercial-scale operations. One crucial link is the private investment decision to adopt these new technologies. Given the track record of most electric The authors are with the Department of Mineral Economics, The Pennsylvania State University, University Park, PA 16802, USA.
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utilities and the decision making environment in which they operate, there is good reason to be pessimistic about the future utilization of CCTs. Of course, regulations mandating their use have recently been enacted as part of the 1990 Clean Air Act Amendments. 3 Still, these regulations have not been fully specified, and enforcement slippage in regulatory timetables has taken place in some prominent cases (eg CAFE standards). The purpose of this paper is to evaluate a fiscal incentive approach to enhance the likelihood of CCT adoption. Subsidies have been widely used in the energy arena, but seldom used in the environmental one. They can be justified in the case of CCTs, however, on the grounds that the market may fail to capture the broader social benefits of pollution control and of decreased reliance on foreign oil. Of course, fiscal incentives are not the only approach to the problem. Consideration should also be given to reestablishing a competitive market environment for decision makers. In the following section, we provide a brief evaluation of the CCT programme and the progress to date on technology developments. Major considerations in the deployment of CCTs are discussed in the third section, including the cases for 'levelling the playing field' and fiscal incentives. The fourth section contains a comparative analysis of several major types of subsidies applicable to CCT deployment.
The clean coal technology option An evaluation of the Clean Coal Technology Programme The official 'Clean Coal Technology' designation arose from the Congressional Omnibus Continuing Resolution of October 1984. This removed US$750 million from the Synthetic Fuels Corporation and initiated a Clean Coal Technology Reserve to provide government assistance to private sector demonstration projects in this area, with a goal of commercialization by the mid-1990s. The US Department of Energy (DOE) was asked 0301-4215/93/060668-11 ~) 1993 Butterworth-HeinemannLtd
Economic incentives for clean coal technology deployment
to evaluate the role of fiscal incentives and argued that they 'will not accelerate commercialization of these technologies and may be counter-productive to their development'. 4 The conclusion cited the perceived adequacy of free market forces and the distortionary effects of subsidies, specifically in the face of the substantial uncertainties involved. Interestingly, DOE also cited its own previous experiences, which 'have with few, if any, exceptions been unsuccessful in commercializing new fossil technologies'. 5 Finally, DOE reemphasized its intent to continue to promote basic R&D, as opposed to commercialization. Congress, however, stipulated the CTI" Programme could provide a subsidy up to and including 50% of any approved project. At the same time, procedures were established for a repayment of the subsidy from profitable projects. 6 In December 1985 Congress passed PL99-190, setting aside just under US$400 million for Round I demonstration projects. A total of 51 project proposals were submitted to DOE, of which 9 were designated for support. At the same time, there was growing pressure on the issue of acid rain, stemming from such sources as the Lewis-Davis report and the National Acid Precipitation Assessment Project report. 7 The USA faced what one DOE official termed a window of opportunity for new clean coal technologies because of ageing of existing utility boilers and the forecast of a need for significant increase in new capacity by the mid-1990s, s One option is to build entirely new facilities, but only at great expense. Another is to modernize, repower or retrofit existing facilities and thus increase their power output by replacing or enhancing current boiler installations. 9 The implication is that the cost of enhancing existing installations with CCTs might be less expensive than meeting air reduction emissions with end of pipe control methods alone, and would definitely be lower than building new standard boiler facilities with or without emission controls. Thus, more attention needed to be given to technologies that are compatible with existing utility configurations. These factors led to a revised programme known as the Innovative Clean Coal Technology Demonstration Programme (ICCT). This was a combination of the Department of Interior and Related Agency Appropriations Act of FY 1987 (PLL 99-500 and PL 99-591), and the President's US$2.5 billion (over five years) Acid Rain Initiative. Formal proposals submitted in Round II numbered 54, with 16 proposals being chosen for federal cofunding. 1° Round III of the programme carried over the emphasis on retrofitting and repowering. A pro-
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gramme opportunity notice (PON) received 48 formal proposals of which 13 were chosen for cofunding. Cofunding of chosen proposals by private industry was just under 60%, down from about 68% for Rounds I and II. After some delay, Round IV of the programme was initiated in early 1991. DOE received 33 proposals, of which 9 were chosen. More recently, the PON for Round V was postponed until July 1992.11 While the Clean Coal Technology Demonstration Programme has been an identifiable thrust in the direction of desirable technologies and has garnered numerous responses, progress has been slow, especially in light of assessments done at the outset of the programme that called for demonstrations of more than a dozen different types of technologies by the mid-1990s. By mid-1990, only five projects from Rounds I, II, and III had reached the operational stage; eight projects had been withdrawn for technical and financial reasons, and four Round I and II projects were still in the pre-award stage. By August 1992 the number of operational projects had, however, increased to 17, though the number of terminated projects had reached 13. J2 It would also appear that the approval process is not synchronized with the overall programme target dates. This process involves several pre-award stages, including planning and DOE fact finding, prenegotiations, headquarters panel review, formal negotiations, headquarters panel approval, headquarters executive board approval, DOE Secretary approval and congressional approval. Also, the timetable for the programme has been accelerated and decelerated at various times for budgetary and political reasons, thereby increasing uncertainties, to the detriment of attracting investors.
Technology development The economic performance of major CCT options (including ICCTs) is summarized in Table 1. The DOE analysis indicates that, barring unforeseen technical difficulties, energy conversion efficiency (as compared to a conventional coal fired power plant) is not adversely affected to a significant degree and, in a few cases, is actually increased. In fact, the replacement of an old plant with a new plant using any technology will probably result in greater conversion efficiency. The figures in Table 1 refer, in this instance, to comparisons between new CCTs and new conventional installations. The power output of existing plants is not affected significantly either for the conventional and retrofit categories, while the repowering technologies promise very dramatic increases in output. In addition, most of
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Economic incentives for clean coal technology deployment Table 1. Technical and economic performance of innovative clean coal technologies. Incremental cost of electricitya (mills/kWh)
Technology Conventional Coal cleaning
Efficiency
Power output
Plant life
Small increase
No change
Slight extension
2-3
Flue gas scrubber Retrofit Advanced flue-gas clean up Limestone injection burner Slagging combustor Gas reburning
Decrease
Moderate decrease
No change
9-11
Decrease Decrease Small decrease No change
Small decrease Small decrease Small decrease No change
No change No change Slight extension Slight extension
In-duct sorbent injection Advanced coal cleaning
Small decrease Small increase
Small increase No change
No change Slight extension
Coal slurry Repowering Gasification combined cycle Pressurized fluidized-bed Atmospheric fluidized-bed
Small decrease
Small decrease
No change
Moderate increase Slight increase No change
100-200% increase 50-100% increase 10-15% increase
Moderate extension Moderate extension Moderate extension
10-12 5-8 1-2 Depends on gas price 2-4 6-21 11-23 0-4 4-6 12-17
Capital cost (US$/kW)
Additional fuel cost only 180-200 175-300 80-110 50-60 10-20 40-90 Additional fuel cost only 20-50 950-1200 800-1000 700-900
Sources: US Department of Energy, Second Report to Congress on Emerging Clean Coal Technologies Capable of Retrofitting, Repowering and Modernizing Existing Facilities, Washington, DC, 1987; US Department of Energy, Clean Coal Technology Demonstration Program: Annual Report to Congress, Washington, DC, 1990. aAssumes base is conventional coal fired power plant with only particulate removal devices. For repowering technologies, capital costs are relatively high because the output, ie capacity, of the plant is increased. One mill = 0.1¢.
these options promise moderate extension to the useful life of existing facilities. The effect of the technologies on the cost of electricity is in the range of a 10-20% increase over a conventional coal fired plant for most alternatives. The range for capital cost increases is a little broader even for the conventional and retrofit alternatives, with several of the options falling far below 10%. The repowering options appear to imply very high additional capital costs, but the numbers need to be adjusted for increased capacity. Although the incremental cost of utilizing these new technologies is termed an increase in Table 1, the D O E analysis may be misleading. First, the cost of burning alternative fuels (oil and gas) may increase by more than 10-20% above coal burning costs by the mid-1990s. Recall that upward pressure on prices is greater on relatively less abundant resources and those whose prices can be influenced by political events such as the war in the Middle East. Second, it seems more reasonable to use a reference point that includes the full cost of constructing and operating a new steam-boiler facility ie it is only fair to include the cost of meeting environmental control requirements. The effect of this can be understood by subtracting the cost for a flue gas desulphurization (FGD) unit from each of the new options. Then, many of the CCTs would provide a definite cost saving, stimulate production of end products and hence stimulate the demand for coal. 670
In addition to the combustion efficiency and emission control advantages already mentioned, several general design characteristics common to many CCT options represent significant cost savings. These include modularity, shorter construction time and fuel flexibility. The first two can save from US$150250/kW of capacity, while the latter can mean as much as a l¢/kWh energy cost savings. Most of the options promise to make coal use more attractive by virtue of reducing SO2 emissions substantially: however, NOx reduction is moderate at best. 13 Aside from the well known sludge problems of FGD units, no major waste disposal problems are associated with the other technologies. In light of recent concerns about global climate change, improved combustion efficiency also offers some CO2 reduction. Among the more problematic aspects of evaluating CCTs are projections of technical readiness. Predictions of commercial availability of some major CCTs are presented in Table 2. DOE's first assessment in 1985 projected commercial readiness by the middle of this decade in most cases. However, this key date is moved back to three years on average by each new D O E assessment in 1987 and 1990. These dates are even more distant for options other than those involving repowering and retrofit; for example, Siegel and Temchin set the date as 2010-2020 for the commercial availability of magnetohydrodynamics. 14 ENERGY POLICY June 1993
Economic incentives for clean coal technology deployment Table 2. Commercial availability of clean coal technologies.
Technology Retrofit Advanced flue-gas clean up Limestone injection multistage burner Advanced combustors Gas reburning In-duct sorbent injection Chemical and microbiological coal cleaning Advanced physical coal cleaning Repowering Integrated gasification combined cycle Pressurized fluidized-bed combustion Atmospheric fluidized-bed combustion
1985 estimate year of commercialization
1987 estimate expected availability
1990 estimate first commercial plants
1990 -95 1990 -95 1986-9(} --1995 -2000 1986-90
1995 -2000 1990 -95 1990-95 1990 -95 1990-95 1990 -95 1990 -95
1995 -99 -1993 -97 1993 -96 1991-95 1997 -2001) 1993 -98
-1995 -2000 1986-90
1990 -95 1990-95 1990 -95
1997 -2004 1997 -2003 1996 -2001
Sources: US Department of Energy, Report to Congress on Emerging Clean Coal Technologies, Washington, DC, 1985; US Department of Energy, Second Report to Congress on Emerging Clean Coal Technologies Capable of Retrofi'tting, Repowering and Modernizing Existing Facilities, Washington, DC, 1987; US Department of Energy, Clean Coal Technology Demonstration Program: Annual Report to Congress, Washington, DC, 1990.
A n o t h e r way of viewing this situation is to point to the 'just around the corner' syndrome that is typical of new energy technology assessments. Most CCT assessments undertaken over the past 30 years, especially those for synfuels, have predicted nearterm availability or economic viability: yet we seem to be no closer to the target now than in the late 1950s. ~5 We should also emphasize the distinction between technical availability and economic viability and note that the D O E studies pertain primarily to the former. The D O E studies are credible in terms of technical progress, but involve a great deal of uncertainty about when or whether the CCTs will be able to compete with conventional systems in the marketplace.
Technology choice Deployment considerations Simple economics would appear to dictate that once we do turn the corner on viability, widespread use of clean coal technologies will ensue. But numerous factors indicate that just the opposite is likely to happen. One indication of this is the US experience with the atmospheric fluidized-bed combustion (AFBC) process, which has been a proven technology at small scales for two decades. As of 1990 there were only 24 coal fired A F B C plants generating electricity in the country, with a combined capacity of about 2000 MW. A F B C units burning other fuels were comparably meagre. Installations scheduled to come on line over the next few years would raise this capacity level to about 3500 MW, 16 about 1% of the US coal fired capacity. This compares with much more extensive use in other countries. The fact that the operations in other countries utilize a variety of ENERGY POLICY June 1993
fuels in addition to coal (eg wood, waste products, biomass) implies that electric utilities in the US lag in imagination and commitment to this valuable technology, that they are not in a competitive market or that they are highly risk averse. Inertia in adopting new technologies is further evidenced from another perspective. For example, the boilers in large-scale, coal fired power plants currently in use are much the same as those brought on line in the 1920s, despite the fact that hundreds of such plants were built, and conditions were ripe for experimentation during the industry's significant growth phase. Overall, very few technologies capable of improving the environmental performance of coal utilization have been developed and extensively deployed over the past 25 years. The following factors should be considered in attempting to understand the reasons for this phenomenon. First is the large capital investment, sometimes in excess of a billion dollars per unit. Premature replacement of an existing facility would take years to recoup and would appear to be especially unattractive in the era of pursuit of short-run profits. The impact of such an investment on the financial position of an electric utility might even make it unattractive in the long run. Second is the risk factor. It is likely that demonstrations at commercial scale will still not be convincing enough to many potential CCT customers. Given the complexity of their operations and technical problems associated with previous new technologies, including nuclear reactors, utilities and other customers are likely to be gun shy. It would seem that the utility industry is even wary of its own research. For example, the Electric Power Research Institute circulated findings touting the success of FBC and
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Economic incentives for clean coal technology deployment
IGCC operations, 17 but the industry dearly failed to follow suit. Third is regulatory agency attitudes, primarily those having a bearing on the risk factor. 18 It has increasingly become the case that state public service commissions would not allow nuclear plant failures to be factored into the rate base. There is the fear that failures of CCTs would meet the same fate. This has the effect of imposing the entirety of the experimentation risk on to utility shareholders, and thus acts as a disincentive to adopting new alternatives. A reversal of this practice would lead to a sharing of this risk by utility customers. Some suggest that it is justified in principle since these customers may benefit from power generation cost reduction. In practice the remedy is difficult because of the need to arrive at a reasonable risk sharing in light of such great uncertainty. More recently, there has been congressional interest in this issue in the form of the proposed Clean Coal Technology Deployment Act ($879), which sought to designate any CCT project as prudent for FERC rate making purposes, and to encourage the same designation be granted by state public utility commissions. Fourth is the uncertainty surrounding environmental regulations. A chronic fear of major manufacturers and utilities is that soon after investing in a new technology, legislation will be passed requiring that some other technology be used. Previous technology forcing approaches, such as those requiring best available control technology (BACT) and lowest achievable emission rate (LAER) policies, reinforced this concern. More recent policy debates over CO2's contribution to global warming raise the spectre of still another generation of technological replacement. More recently, Congress passed the 1990 Clean Air Act Amendments ($1630), a main feature of which is an acid rain abatement programme. The Act calls for SO2 reduction of large utility boilers in two phases, with target dates of 1995 and 2000. A novel feature is the specification of a marketable emission permit programme. The Act contains some special features that will directly affect the interests in CCTs. It provides an exemption from more stringent regulations of ongoing CCT projects and grants a four-year extension for meeting Phase II requirements for plants repowered with a CCT. The Act also requires the FERC to initiate a five-year experimental programme of regulatory incentives for CCTs. It is not clear whether these will have a significant effect on their deployment. There are still uncertainties about emission trading, special allowances for Mid-west
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utilities, special formulas for smaller and cleaner plants, and still unspecified performance standards for NOx that must be issued by 1994.19
A market approach The 'command and control' approach, typically in the form of process or performance standards, has dominated the environmental management arena in the USA and most other countries. Although most economists have favoured fiscal penalties or inducements, such as effluent charges, these instruments represent some interference with the market. Both these standards and charges approaches are seen as ways to eliminate the market failure stemming from the presence of externalities in the form of pollution. Although the enforcement power of the state would seem to assure the effectiveness of administrative decree, the internalization of the opportunity costs of pollution associated with penalties or inducements makes compliance just as likely, though in a more subtle way. Moreover, since the fiscal approach allows for greater flexibility of choice, it is inherently more efficient. An alternative approach is one that corrects a market failure by establishing or strengthening the market and then stepping back and letting supply and demand take their course. This seems to trouble many outside the economic profession because they think there is no assurance that the desired behaviour would be forthcoming. But establishing a perfectly competitive market facilitates voluntary compliance with broader objectives in the course of pursuing private profit. Many innovative arrangements, such as emissions trading, have been proposed to bring about such an outcome. 2° In the case of deployment of CCTs, an elaborate scheme may not be needed. If, in fact, these options are technically and economically sound, it may be sufficient just to improve the information flow, reduce the uncertainty regarding future environmental regulation, provide a sharing of the risk, and eliminate unfair advantages from competing alternatives. Government at various levels, equipment vendors, and trade associations can help in the transfer of information about CCTs. In addition, standardized and independent testing, as well as open inspection of demonstration and subsequent operating facilities, would help. The optimal sharing of risk between market participants is an old problem and complicated by the fact that what promotes allocative efficiency may be very inequitable. It is safe to say, however, that a continued hard stand on technological innovation in
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Economic incentives for clean coal technology deployment
relation to rate making is likely to produce less than the social optimum level of progress. Ideally, the risk burden would be spread between stockholders and customers so as to attain the optimal path, but in practice the empirical calculations are difficult. Ironically, the matter of 'unfair' advantage by competing technologies is attributable to a great extent to the subsidies in this policy area. Estimates of the value of these subsidies range from US$10 billion to nearly US$50 billion in a given year, 21 with nuclear power traditionally having been the most favoured option. The effect of these subsidies is to lower the price of some options relative to others and thus distort the choice process. Elimination of many of these subsidies was proposed in various recent tax reform proposals and is consistent with the Reagan and Bush administrations' theme of creating a level playing field for all energy options. 22 The fact that only a few of the subsidies were eliminated in the most recent round of reforms, however, indicates that actual implementation of this policy approach must overcome some powerful entrenched interests. Overall, there may be some insurmountable obstacles to creating a situation of perfect competition, meaning some subsidies or other offsetting distortions might be justified in such a second-best world. We should also note that a conventional private goods market might not be the relevant ideal, because of public good features of early operating experiences. Some subsidies might be justified for those first several facilities that incur the added cost of moving the nation up the technological learning curve. 23 Finally, we note one interesting aspect of the market solution - it does not require the deployment of CCTs to be successful. If firms opt for low sulphur coal, natural gas or some other alternative then so be it. The problem is that, in practice, it is difficult to tell whether such an outcome is due to market success or market failure.
A fiscal incentive approach Although subsidies and taxes are often viewed as two e q u i v a l e n t sides of the fiscal i n s t r u m e n t approach, 24 the extent of their application in the energy and environmental arenas is quite different. Subsidies for pollution control are a rarity, but are often used in the case of energy policy, most notably for conservationfl 5 The use of fees is just the opposite, although several noted economists have proposed an oil import tariff. 26 One of the reasons for this difference is the perceived fairness of the application of the instru-
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ment. The polluter is viewed as the perpetrator of the environmental externality, and therefore it is seen as fair to tax him. 27 A similar attitude has not won favour in terms of 'wasting' energy, although the oil import tariff case suggests that those who cost us some national or energy security are increasingly viewed as culpable by policy makers. There are both energy and environmental features inherent in the case of CCTs, and it would seem that using subsidies to ensure the deployment of these technologies could be justified on several grounds. First, although CCTs are obviously biased in favour of coal use, there are several absolute and relative (to the use of other fuels) social benefits to be gained. Increased coal use reduces the US reliance on foreign oil, cost estimates of which range from US$1 to US$30 per barrel in terms of several types of external costs. 28 Second, subsidizing CCTs may have some justification from the efficiency and equity standpoints of regional development. Many of the coal producing areas of the USA are economically depressed. Lagging regions are thought to place a drag on national growth, and 'workfare' in the form of producing coal may be preferable to conventional welfare in the form of unemployment compensation. Finally, CCTs do represent a solution to the acid rain problem which, if not costless, is at least less costly than other approaches. Moreover, most of the aspects of subsidies that have been viewed as leading to aberrant (non-optimal) behaviour do not apply in the technology specific case. From a practical standpoint, the value of CCT subsidies probably need not be very great. In this case, the subsidy need not be set equal to the marginal social benefit of acid rain reduction, but simply at a level able to overcome the inertia of the adoption decision plus any cost differential between a CCT and the least-cost alternative. As noted earlier, subsidies are rampant in the energy arena, 29 with estimates in the tens of billions of dollars per year. Estimates on the high side count 'all identifiable federal energy-related expenditures, other than market purchases of energy for own use'. 3° Estimates on the low side omit certain categories of expenditures, especially those associated with defence aspects of energy. Coal already receives a large portion of these subsidies in absolute terms and in relation to total coal and new coal energy produced. No estimates of the proportion of these subsidies attributable to CCTs can be offered at this time, but it is safe to say, given on-going research, development, and deployment of generic efforts in this area, that it is substantially larger than
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Economic incentives for clean coal technology deployment
the current US$500 million per year matching money for officially designated CCT demonstration programmes. Not all subsidies are equal in their costeffectiveness or manageability, so comparative evaluations must be undertaken to arrive at an optimal subsidy arrangement. Past success is a place to start, but new, specialized subsidy instruments might also be devised eg a variable subsidy whose value is based on the contribution of the facility to the national learning curve, or closely related to this, a subsidy that varies with the riskiness of the technology. In theory, subsidies can be fine tuned to bring about desired goals, such as the timing and magnitude of CCT deployment. Of course, there is a case against subsidies. In addition to claims that they are inferior to the market solutions, there is the claim that they do not work in practice. This argument, however, pertains to R&D, and aside from the lack of supporting evidence presented, may be less applicable to deployment, where there is less uncertainty. In addition, subsidies are viewed as price distorting, but that is the point. They are intended to correct the social valuation of a decision as almost always inaccurately reflected in a market price, as in reduced dependence on foreign oil or an improved physical environment. Finally, we note the possible displacement effect of some productive investment by subsidies for energy technology, which have been estimated at 40% of total US investment in recent years. 3~ Concerns such as this, however, can be approximated and factored into the optimal subsidy levels as social costs to be subtracted from the potentially many social benefits.
Analysis of subsidies to promote technology adoption Government can share the risk and uncertainties inherent in the adoption of new technologies by industry through the use of subsidies. The following analysis of financial incentives for CCTs takes its lead from the US Department of Energy Report by the Innovative Control Technology Advisory Panel. 32 Three major types of incentives are examined: tax breaks, soft loans and capital subsidies. All three of these incentives apply to risks associated with uncertain capital costs, since investment and debt returns are recognized expenses for taxation purposes. Still, to the extent they lower overall costs, these subsidies compensate for various types of risks.
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Fiscal incentives
Tax incentives are widely used to decrease capital costs and inherent risks. Some major examples are: accelerated depreciation, investment tax credit and property and ad valorem tax exemptions or reductions. 33 Our analysis will focus on the first two. To determine income for taxation purposes, the straight line depreciation method can be considered the baseline case. Thus, for a normal power plant with a 30 year life expectancy, the annual recognized depreciation cost is 3.333% of the installed capital cost. Accelerated depreciation allows investors to write off their investment more rapidly by deducting more of the capital cost from tax payments during the early years of the plant's operations. Thus, a doubled depreciation rate would be 6.667% annually for 15 years, and in a 10 year accelerated depreciation schedule, the capital cost would be deducted at a 10% annual rate. The investment tax credit is a direct reduction in the project's tax liability, which equals a fixed rate of capital investment (up to 15% according to current laws). The investor may use the credit either at the plant's commissioning or during the installation period. Usually, investors will use the credit as soon as they have a positive tax liability to which it can be applied. While tax incentives can reduce some of the risk associated with capital costs, they do not assist with the problem of obtaining the high levels of initial capital required for major utility installations. In addition, this incentive may cause an undesirable phenomenon of overintensive capital investment. 34 Soft loans bear interest rates lower than the market rates. They may range from moderately lower interest rate loans (1 or 2% below market rates) to interest free loans. These loans can finance part or all of the debt component of the capital investment. Although subsidized loans can provide a partial solution to the industry's capital risk, they do not directly correspond to uncertainties associated with the plant's performance. Subsidies and grants are widely used economic incentives in promoting the use of new technologies. They may be provided in various ways: per ton of pollutants removed, per installed kilowatt capacity and percentage of capital cost. Our analysis focuses on the more popular capital cost subsidy, where investors receive a grant at a fixed rate of their capital investment. This is the approach currently used to promote demonstration of various types of CCTs in the USA (see above). Capital cost subsidies also tend to promote the adoption of more capital intensive investments. As
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Economic incentives" Jor clean coal technoh~gy deployment Table 3. Impact of incentives for various CCTs on busbar prices a and percentage change b from base case (60% capacity utilization). Tax incentive
Clean coal technology
Pulverized coal with flue-gas desulphurization (PC/FGD) Atmospheric fluidized-bed combustion (AFBC) Pressurized fluidized-bed combustion (PFBC) Pressurized fluidized-bed combustion repowering Integrated gasification combined cycle (IGCC)
Soft loan interest loan
Free interest loan
Capital subsidy 25% of 50% of total total cost cost
41.2 (- 12.21 43.0 (- 12.5) 43.0 (- 13.0) 37.2 (-11.21 43.8 (- 12.9)
37.8 (-19.41 40.2 (- 19.91 39.3 (-20.4) 34.4 (-17.9) 40.0 (-20.5)
4(I.4 (-13.9) 43.0 (- 14.31 42.4 (-14.6) 36.5 (-12.91 42.9 (- 14.71
10 year
11.5%
Reduced (3%)
Base case
accelerated depreciation
investment tax credit
46.9
40.9 (-12.8) 43.6 (- 13.1) 42.8 (-13.4) 36.9 (-12.0) 43.5 (- 13.5)
50.2 49.4 41.9 50.3
44.8 (-4.5) 47.9 (-4.5) 47.1 (-4.7) 4(I.2 (-4.1) 48.0 (-4.6)
33.6 (-28.4) 35.6 (-29.0) 34.7 (-29.8) 3(I.9 (-26.3) 35.2 (-30.0)
aln mills/kWh (1 mill = 0.1el. bNumbers in parentheses.
with tax and loan incentives, these subsidies do not provide an answer to risks related to project performance. However, other types of grants and subsidies, such as a subsidy based on pollution abatement levels, do not create a capital intensive bias.
Effect of selected economic incentives The implications of selected incentives on the busbar generation cost of different CCTs are assessed below. The incentives examined include: tax incentives (10 year accelerated depreciation and 11.5% investment tax credit), soft loans (3% below market rates and interest free), and subsidies (25% and 50%). In our calculations, first the impacts of the incentives on the capital charge rates were calculated and the results applied to the selected CCTs for the calculation of the busbar costs. These were calculated under two scenarios of plant utilization: 60% capacity factor (Table 3) and 70% capacity factor (Table 4). Beginning with the case of a capacity factor of 60%, the effect of tax incentives reveals that a 10 year accelerated depreciation policy contributes
to a reduction of 12.0 to 13.5% in the busbar cost of selected technologies relative to the base case. For example, the busbar cost of pressurized fluidizedbed combustion (PFBC) repowering decreased from 41.9 mills/kWh to 36.9 mills/kWh (1 mill = 0.1¢), whereas the busbar costs of integrated gasification combined cycle (IGCC) decreased from 50.3 mills/ kWh to 43.5 mills/kWh. The impact of the 11.5% investment tax credit is more moderate. This incentive contributes to a reduction of 4.1 to 4.7% in the busbar costs of the selected technologies. The variation in the rate of cost decrease for each incentive across the various technologies is mainly due to the variation in the base case cost of the different CCTs. Soft loans can contribute to a maximum reduction in busbar costs in a range of 17.9% (PFBC repowering) to 20.5% (IGCC) in the case of free interest loans. The most effective incentive in our analysis is the 50% capital subsidy, which contributes to a reduction of up to 30% in busbar cost (IGCC). Similar relative effects are ahieved when a 70% plant capacity factor is utilized (Table 4). With this assumption, however, base case busbar costs are
Table 4. Impact of incentives for various CCTs on busbar prices a and percentage change b from base case (70% capacity utilization). Tax incentive
Clean coal technology
Pulverized coal with flue-gas desulphurization (PC/FGD) Atmospheric fluidized-bed combustion (AFBC) Pressurized fluidized-bed combustion (PFBC) Pressurized fluidized-bed combustion repowering Integrated gasification combined cycle (IGCC)
Soft loan interest loan
Free interest loan
Capital subsidy 25% of 50% of total total cost cost
38.1 (- 11.4) 4(1.5 (- 11.6) 39.6 (-12.0) 34.6 (- 10.4) 40.3 (-12.2)
35.2 (-20.5) 37.3 (- 18.6) 36.4 (-19.11 32.2 (- 16.61 37.0 (-19.41
37.4 (- 13.tl) 39.7 (- 13.3) 38.9 (-13.61 34.0 (- 12.01 39.5 (-23.5)
10 year
11.5%
Reduced (3%)
Base case
accelerated depreciation
investment tax credit
43.0
37.8 (- 12.1) 40.2 (- 12.2) 39.4 (-12.4) 34.4 (- 10.9) 40.0 (-12.9)
45.8 45.0 38.6 45.9
41.2 (-4.2) 43.9 (-4.1) 43.0 (-4.4) 37.2 (-3.6) 43.8 (-4.6)
31.6 (-26.5) 33.4 (-27.1) 32.5 (-27.8) 29.2 (-24.4) 32.9 (-28.3)
aln mills/kWh, bNumbers in parentheses.
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Economic incentives for clean coal technology deployment Table 5. Incentives required to achieve breakeven with alternative base power plants. Type of incentive Accelerated depreciation (years) Clean coal technology
Conventional
Pulverized coal with flue-gas desulphurization (PC/FGD) 10 Atmospheric fluidized-bed combustion (AFBC) 6 Pressurized fluidized-bed combustion (PFBC) 8 Pressurized fluidized-bed combustion repowering 17 Integrated gasification combined cycle (IGCC) 6
PC/FGD
Investment tax credit (%) Conventional PC/FGD
Reduced interest loan (%) Conventional PC/FGD
Capital subsidy (%) Conventional PC/FGD
-
30
-
-3
-
22
-
15
45
17
-6
-1.6
32
12
16
40
12.5
-5
-1.2
30
9
6
a
a
5
45
17
-1.6
32
a
5
-0.75 -6
12
aPFBC repowering is already lower than PC/FGD.
lower than in the 60% capacity factor scenario in a range of 3.3 mills/kWh (PFBC repower) to 4.4 mills/kWh (IGCC). The relative improvements due to various subsidy types are the same as in Table 3. Another way of analysing the potential of incentives is to determine the magnitude required to achieve the breakeven point with the busbar cost of conventional power plants. The comparison is made with regard to two types of technologies: a conventional power plant that does not contain appropriate pollution control devices and a power plant consisting of a pulverized coal combustion boiler with flue-gas desulphurization (PC/FGD). The results are presented in Table 5 and reveal that in the case of accelerated depreciation, investment write offs of 17 years (PFBC repower) to 6 years (AFBC and IGCC) are required to achieve breakeven with the conventional power plant. Conversely, more moderate accelerated depreciation rates are sufficient to reach breakeven with PC/FGD - 16 years (PFBC) and 15 years (AFBC and IGCC). Note that the busbar cost of PFBC repowering is already lower than the busbar cost of PC/FGD. Required investment tax credit rates to achieve breakeven with the conventional plant are in the range of 6% (PFBC repower) to 45% (AFBC and IGCC). The range drops to only 0-17% to achieve parity with PC/FGD. For soft loan incentives, a reduction of 0.75% (PFBC repower) to 6% (AFBC and IGCC) from an assumed market lending rate of 7% is required to achieve breakeven with a conventional plant, and a 0 to 1.6% reduction with PC/FGD. Finally, a capital subsidy of 5-32% is necessary to achieve breakeven with a conventional plant, and of 0-12% with PC/FGD. The aforementioned results are almost identical between cases of 60% and 70% plant capacity utilization factors. 676
Conclusion Our analysis suggests that widespread deployment of clean coal technologies is not likely to be forthcoming over the next two decades despite the CCT Demonstration Programme and the 1990 C A A Amendments. Numerous bureaucratic hurdles and commercialization viability questions, as well as uncertainties over specific implementation of the new environmental regulations, will slow the adoption of CCTs. Moreover, electric utility industry attitudes towards risk and the utility regulation environment are problematic in the link between demonstration and deployment. Economic incentives are one way of overcoming these problems. More scrutiny of this policy issue is needed. The US$2.5 billion CCT Programme may appear to be a sizable sum in isolation, but it needs to be compared with the social benefits it may yield. Even if we utilize the absolute lower bound benefit estimate of US$2 billion per year, the discounted present value over the relevant time horizon would be several times greater than the CCT outlayY The complication is that the CCT subsidy is not the only distortion causing fiscal incentive in this area. The crucial question is thus the effectiveness of the CCT programme relative to other fiscal incentives in helping attain the optimal level of social benefits. Another perspective on the situation is to note that the Reagan and Bush administrations' position against market interference has resulted in their putting all of their eggs in the R&D and demonstration strategy baskets. If policies to actually level the playing field are not enacted, or if it is determined that this is an unattainable goal, a deployment subsidy should be examined as a realistic alternative. This might mean shifting some future CCT funding to the deployment stage. ENERGY POLICY June 1993
Economic incentives for clean coal technology deployment
Our results indicate that the most economically viable CCT is PFBC repowering. It requires the lowest incentive rate (eg a 5% capital subsidy or less than 1% reduced loan rate) to break even with conventional technology, and does not require any incentive when compared with PC/FGD. Conversely, new PFBC installations require an extensive subsidy, and AFBC and IGCC require the highest incentive rates. Such conclusions can only be drawn under the assumption that the reference economic criterion for the selection of preferable CCTs is the minimization of the incentive required to achieve breakeven with conventional or PC/FGD technologies. In this regard, however, other economic, technology and environmental criteria should be considered, including benefits and limitation of repowering methods; maturity, reliability and efficiency of different technologies; the environmental achievements of the CCTs in pollution mitigation; and the contribution of a technology that stimulates the use of a domestically abundant fuel, thereby reducing the nation's dependence on imported oil. Preference among various incentive types may vary between investors and the government, and among investors themselves. Many investors may prefer tax incentives that will enable them to benefit from a lower tax burden, mainly in the first years following the plant's commissioning. Others may prefer capital subsidies or soft loans to lower their debt burden. The government macroeconomic policy perspective may be sensitive to the effects of the type of incentive on its budget, eg increased expenditures (capital subsidy and soft loans) versus decreased incomes (tax incentives). In addition, fiscal timing may also play a role in the decision. Whereas tax incentives imply reduced incomes in future years, capital subsidies necessitate relatively large expenditures up front. The USA has committed US$2.5 billion to the Clean Coal Technology Programme at the demonstration level. Yet follow up considerations, mainly with respect to deployment under considerations of a free market or regulatory requirements of the recent Clean Air Act Amendments, have been subjected to little economic or energy planning scrutiny. Clearly further analysis of CCT deployment prospects is warranted given the potential size of the public investment and potential social benefits.
This research was supported in part by the US Office of Technology Assessment and The Pennsylvania State University Mining and Mineral Research Institute. Some background portions of
ENERGY POLICY June 1993
this paper are taken from the senior author's (A.R.) contributions to a report to OTA, co-authored with Walter Labys and Thomas Torries. An earlier version of the paper was presented at the Annual International Meeting of the International Association for Energy Economics.
tUS Department of Energy (DOE), Clean Coal Technology Demonstration Program: Annual Report to Congress, Washington, DC, 1990. 2A. Rose, T. Torries and W. Labys, 'Clean coal technologies and future prospects for coal', Annual Review of Energy and the Environment, Vol 16, 1991, pp 59-90. 3M. Yates, 'Congress approves historic clean air legislation', Public Utilities Fortnightly, December, 1990, Vol 6, pp 53-55; N. Kete, 'The US acid rain control allowance trading system', Climate Change: Designing a Tradeable Permit System, Paris, OECD, 1992. 4US Department of Energy, Report to Congress on Emerging Clean Coal Technologies, Washington, DC, 1985, pp 1-4; US Department of Energy, Supplemental Report to Congress on Emerging Clean Coal Technologies, Washington, DC, 1985. Slbid. 6In general, the Clean Coal Technology Programme has substantial industry support. Many of the guiding principles of the programme are consistent with private industry views as expressed in a report by the National Coal Council, an advisory committee to the Secretary of Energy composed primarily of executives of companies involved in the coal cycle, including machinery manufacturers, as well as some labour leaders, public officials and scientists (see National Coal Council, Clean Coal Technology, Washington, DC, 1986). One significant difference is the greater emphasis on government risk sharing encouraged by the National Coal Council. 70. Lewis and W. Davis, Special Envoys Report on Acid Rain, Washington, DC, 1986; National Acid Precipitation Assessment Program (NAPAP), Interim Assessment: The Causes and Effects of Acidic Deposition, Washington, DC, 1987. SJ.A. Wampler, Testimony to the Committee on Energy and Natural Resources, US Senate. More than 50% of the utility boilers currently utilizing coal will be at least 25 years old by then. Annual average growth in electricity demand is project at 2.5 to 3.0% per year (see also Electric Power Research Institute 'Coal technologies for a new age', EPRI Journal, January/February, 1988) after the levelling off of the late 1970s and early 1980s. 9These terms are defined as follows in US Department of Energy, Second Report to Congress on Emerging Clean Coal Technologies Capable of Retrofitting, Repowering and Modernizing Existing Facilities, Washington, DC, 1987, p 30 - repowering: 'any technology that replaces a significant portion of the original power plant and reduces atmospheric emissions of pollutants, often while increasing capacity.' Retrofitting - 'the installation on existing facilities of devices designed primarily to reduce emissions." Modernization - 'the upgrading of an aging power plant for the purpose of extending, its useful service life in order to postpone the need for new generating capacity.' x°US Department of Energy, The New Coal Era, Report No DOE/FE-0193P, Washington, DC, 1990: US Department of Energy, op cit, Ref 1. HUS Department of Energy, Clean Coal Technology Demonstration Program: Program Update, 1991, Washington, DC, 1992. ~2US Department of Energy, Project Status Report, mimeo, Office of Fossil Energy, Washington, DC, 199[); US Department of Energy, Project Status Report, mimeo, Office of Fossil Energy, Washington, DC, 1992. I-~The emission reduction characteristics of various CCTs as specified in US Department of Energy, Report to the Secretary of Energy Concerning Commercialization Incentives, Report No DOE/EH-0083, Washington, DC, 1989, are as follows: PC/FGD, reduction rate 90% SO2, 0% NO~; AFBC 90-95% SO,, 60% NO~; PFBC 90-95°/,, SO2, 70% NO~; PFBC repower 90-95% SO2, na NO~; IGCC 92-99% SO> 92% NO,.
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Economic incentives for clean coal technology deployment 14j. Siegel and J. Temchin, 'Role of clean coal technology in electric power generating in the 21st century', in J. Tester, N.A. Ferrari and D.O. Wood with Janos M. Beer, eds, Energy and the Environment in the 21st Century, MIT Press, Cambridge, MA, 1991. lSJ.M. Griffin and H.B. Steele, Energy Economics' and Policy, 2nd edn, Academic Press, Orlando, FL, 1986. ~6R. Wolk and J. McDaniel, 'Electricity without steam: advanced technology for the new century,' presented at The Association of Edison Illuminating Companies Power Generation Meeting, Orlando, FL, 1990. 170p cit, Ref 8, EPRI. lSThere are three types of risks associated with the deployment of new technologies: capital cost, performance, and operating and maintenance cost. Capital cost risks refers to the possibility that actual capital expenditures may be higher than initially estimated. This risk is an increasing function of capital intensity of the investment. Performance and operating cost risks are associated with the possibility of technical and other problems reducing the rate of output or raising costs above original expectations. All other things equal, the risks are an inverse function of prior operating experience. 190p cit, Ref 3, Kete. 2~I'. Tietenberg, Emissions Trading: An Exercise in Reforming Pollution Policy, Resources for the Future, Washington, DC, 1985; R. Hahn, 'Economic prescriptions for environmental problems', The Journal of Economic Perspectives, Vol 3, 1989, pp 95-114. 21US Department of Energy, Selected Federal Tax and Non-Tax Subsidies for Energy Use and Production, Energy Policy Study, USGPO, Vol 6, Washington, DC, 1980; H.R. Heede, 'A preliminary assessment of federal energy subsidies in FY1984', Testimony before the House of Representatives Subcommittee on Energy Conservation and Power, Washington, DC, 20 June 1985. 22US Senate, Tax Reform Act of 1986, USGPO, Washington, DC, 1986. 23j.K. Harlan, Starting with Synfuels: Benefits, Costs, and Program Design Assessments, Ballinger, Cambridge, MA, 1982. This might involve offsetting taxes too, such as one to cover the security premium on imported oil or import taxes on subsidized foreign produced technology. 24The early literature on effluent charges and subsidies viewed them as perfectly symmetric and both capable of generating an efficient outcome. Subsequent analyses, however, indicated that subsidies were vulnerable to strategic behaviour on the part of economic agents that would lead to inefficiencies in the short run, and that even normal behaviour would render a subsidy based
678
arrangement inefficient in the long run (see G.E. Mumy, 'Longrun efficiency and property rights sharing for pollution control', Public Choice, Vol 35, 1976 pp 59-74; W.J. Baumol and W.E. Oates, The Theory of Environmental Policy, 2nd edn, PrenticeHall, Englewood Cliffs, NJ, 1987. 25A. Rose, 'Modeling energy conservation programs: an application to natural gas utilities', Energy Journal, Vol 6, 1987, pp 87-103. 26H.G. Broadman and W. Hogan, Oil Tariff Policy in an Uncertain Market, Discussion Paper 86-11, Energy and Environmental Policy Center, Harvard University, Cambridge, MA, 1987. 27Coase, one of the more prominent of the early proponents of the market solution, has pointed out that it takes two to make an externality and that the assignment of blame is arbitrary and unnecessary to an efficient outcome. Thus, the assignment of property rights under the market solution is an equity issue not an efficiency issue. Under certain circumstances, so is the choice of fees versus subsidies (see R.H. Coase, 'The problem of social cost', Journal of Law and Economics, Vol 3, 1960, p 1-44). 28D.R. Bohi and W.D. Montgomery, 'Social cost of imported oil and US import policy', Annual Review of Energy, Vol 7, 1982, pp 37-60; D. Hall, 'Preliminary estimates of cumulative private and external costs of energy', Contemporary Policy Issues, Vol 8, 1990, pp 283-307; P.K. Verleger, 'Understanding the 1990 oil crisis', Energy Journal, Vol 11, 1990, pp 15-33. 29Energy subsidies take many different forms. Heede (eg op cit, Ref 21) identifies 17 federal tax code categories and programmes and 21 federal agencies. Numerous state level subsidies are identified by Chapman (D. Chapman, 'Federal incentives affecting coal and nuclear power economics', Natural Resources Journal, Vol 22, 1982, pp 361-378). 3°0p cit, Ref 21, Heede.
31Ibid. 320p cit, Ref 13. 330p c#, Ref 29, Chapman. 34H. Averch and L. Johnson, 'Behavior of the firm under regulatory constraint', American Economic Review, Vol 52, 1962, ~ 1053-1069. ocial benefits of new energy technologies are often measured in terms of the security premium on imported oil they would displace. The premium is in turn often measured by the least-cost alternative to achieve energy security. This is widely held to be the Strategic Petroleum Reserve, whose annual cost is simply the interest cost on the stored oil: see Verleger, op cit, Ref 28. Of course, this lower bound ignores a potentially large environmental premium representing additional .social benefits that can be achieved by CCTs.
ENERGY POLICY June 1993
Clean coal technologies (CCTs) hold great promise for abating acid rain at low or zero incremental cost. They also represent a useful tactic in promoting energy security. Yet adoption of these technologies in the USA has been slow, and circumstances indicate continued inertia. The US government has a major programme to subsidize CCT demonstration projects but has done little to stimulate their adoption. This paper examines several fiscal incentives and finds their costs to be rather modest, especially in the light of the non-market benefits that widespread CCT adoption would reap. Keywords: Coal; Technology; Environment
In late 1984 the US Congress enacted the first phase of what has become known as the Clean Coal Technology (CCT) Programme. The initial programme and the several legislative supplements since are intended primarily to accelerate the demonstration of new technologies that promise cleaner coal processing, combustion or derivative fuels. Because many of these methods are also being touted as cost saving, they are seen as an ideal solution to the acid rain issue; that is, we may be able to reduce acid rain without incurring the sizable costs associated with conventional pollution control alternatives. 1 More recently, the increased combustion efficiency characteristic of many of these options has been hailed for its contribution to a 'no regrets' strategy against global warming. Although the CCT Programme has had some success, z the actual deployment of CCTs depends on more than just the demonstration of even commercial-scale operations. One crucial link is the private investment decision to adopt these new technologies. Given the track record of most electric The authors are with the Department of Mineral Economics, The Pennsylvania State University, University Park, PA 16802, USA.
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utilities and the decision making environment in which they operate, there is good reason to be pessimistic about the future utilization of CCTs. Of course, regulations mandating their use have recently been enacted as part of the 1990 Clean Air Act Amendments. 3 Still, these regulations have not been fully specified, and enforcement slippage in regulatory timetables has taken place in some prominent cases (eg CAFE standards). The purpose of this paper is to evaluate a fiscal incentive approach to enhance the likelihood of CCT adoption. Subsidies have been widely used in the energy arena, but seldom used in the environmental one. They can be justified in the case of CCTs, however, on the grounds that the market may fail to capture the broader social benefits of pollution control and of decreased reliance on foreign oil. Of course, fiscal incentives are not the only approach to the problem. Consideration should also be given to reestablishing a competitive market environment for decision makers. In the following section, we provide a brief evaluation of the CCT programme and the progress to date on technology developments. Major considerations in the deployment of CCTs are discussed in the third section, including the cases for 'levelling the playing field' and fiscal incentives. The fourth section contains a comparative analysis of several major types of subsidies applicable to CCT deployment.
The clean coal technology option An evaluation of the Clean Coal Technology Programme The official 'Clean Coal Technology' designation arose from the Congressional Omnibus Continuing Resolution of October 1984. This removed US$750 million from the Synthetic Fuels Corporation and initiated a Clean Coal Technology Reserve to provide government assistance to private sector demonstration projects in this area, with a goal of commercialization by the mid-1990s. The US Department of Energy (DOE) was asked 0301-4215/93/060668-11 ~) 1993 Butterworth-HeinemannLtd
Economic incentives for clean coal technology deployment
to evaluate the role of fiscal incentives and argued that they 'will not accelerate commercialization of these technologies and may be counter-productive to their development'. 4 The conclusion cited the perceived adequacy of free market forces and the distortionary effects of subsidies, specifically in the face of the substantial uncertainties involved. Interestingly, DOE also cited its own previous experiences, which 'have with few, if any, exceptions been unsuccessful in commercializing new fossil technologies'. 5 Finally, DOE reemphasized its intent to continue to promote basic R&D, as opposed to commercialization. Congress, however, stipulated the CTI" Programme could provide a subsidy up to and including 50% of any approved project. At the same time, procedures were established for a repayment of the subsidy from profitable projects. 6 In December 1985 Congress passed PL99-190, setting aside just under US$400 million for Round I demonstration projects. A total of 51 project proposals were submitted to DOE, of which 9 were designated for support. At the same time, there was growing pressure on the issue of acid rain, stemming from such sources as the Lewis-Davis report and the National Acid Precipitation Assessment Project report. 7 The USA faced what one DOE official termed a window of opportunity for new clean coal technologies because of ageing of existing utility boilers and the forecast of a need for significant increase in new capacity by the mid-1990s, s One option is to build entirely new facilities, but only at great expense. Another is to modernize, repower or retrofit existing facilities and thus increase their power output by replacing or enhancing current boiler installations. 9 The implication is that the cost of enhancing existing installations with CCTs might be less expensive than meeting air reduction emissions with end of pipe control methods alone, and would definitely be lower than building new standard boiler facilities with or without emission controls. Thus, more attention needed to be given to technologies that are compatible with existing utility configurations. These factors led to a revised programme known as the Innovative Clean Coal Technology Demonstration Programme (ICCT). This was a combination of the Department of Interior and Related Agency Appropriations Act of FY 1987 (PLL 99-500 and PL 99-591), and the President's US$2.5 billion (over five years) Acid Rain Initiative. Formal proposals submitted in Round II numbered 54, with 16 proposals being chosen for federal cofunding. 1° Round III of the programme carried over the emphasis on retrofitting and repowering. A pro-
ENERGY POLICY June 1993
gramme opportunity notice (PON) received 48 formal proposals of which 13 were chosen for cofunding. Cofunding of chosen proposals by private industry was just under 60%, down from about 68% for Rounds I and II. After some delay, Round IV of the programme was initiated in early 1991. DOE received 33 proposals, of which 9 were chosen. More recently, the PON for Round V was postponed until July 1992.11 While the Clean Coal Technology Demonstration Programme has been an identifiable thrust in the direction of desirable technologies and has garnered numerous responses, progress has been slow, especially in light of assessments done at the outset of the programme that called for demonstrations of more than a dozen different types of technologies by the mid-1990s. By mid-1990, only five projects from Rounds I, II, and III had reached the operational stage; eight projects had been withdrawn for technical and financial reasons, and four Round I and II projects were still in the pre-award stage. By August 1992 the number of operational projects had, however, increased to 17, though the number of terminated projects had reached 13. J2 It would also appear that the approval process is not synchronized with the overall programme target dates. This process involves several pre-award stages, including planning and DOE fact finding, prenegotiations, headquarters panel review, formal negotiations, headquarters panel approval, headquarters executive board approval, DOE Secretary approval and congressional approval. Also, the timetable for the programme has been accelerated and decelerated at various times for budgetary and political reasons, thereby increasing uncertainties, to the detriment of attracting investors.
Technology development The economic performance of major CCT options (including ICCTs) is summarized in Table 1. The DOE analysis indicates that, barring unforeseen technical difficulties, energy conversion efficiency (as compared to a conventional coal fired power plant) is not adversely affected to a significant degree and, in a few cases, is actually increased. In fact, the replacement of an old plant with a new plant using any technology will probably result in greater conversion efficiency. The figures in Table 1 refer, in this instance, to comparisons between new CCTs and new conventional installations. The power output of existing plants is not affected significantly either for the conventional and retrofit categories, while the repowering technologies promise very dramatic increases in output. In addition, most of
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Economic incentives for clean coal technology deployment Table 1. Technical and economic performance of innovative clean coal technologies. Incremental cost of electricitya (mills/kWh)
Technology Conventional Coal cleaning
Efficiency
Power output
Plant life
Small increase
No change
Slight extension
2-3
Flue gas scrubber Retrofit Advanced flue-gas clean up Limestone injection burner Slagging combustor Gas reburning
Decrease
Moderate decrease
No change
9-11
Decrease Decrease Small decrease No change
Small decrease Small decrease Small decrease No change
No change No change Slight extension Slight extension
In-duct sorbent injection Advanced coal cleaning
Small decrease Small increase
Small increase No change
No change Slight extension
Coal slurry Repowering Gasification combined cycle Pressurized fluidized-bed Atmospheric fluidized-bed
Small decrease
Small decrease
No change
Moderate increase Slight increase No change
100-200% increase 50-100% increase 10-15% increase
Moderate extension Moderate extension Moderate extension
10-12 5-8 1-2 Depends on gas price 2-4 6-21 11-23 0-4 4-6 12-17
Capital cost (US$/kW)
Additional fuel cost only 180-200 175-300 80-110 50-60 10-20 40-90 Additional fuel cost only 20-50 950-1200 800-1000 700-900
Sources: US Department of Energy, Second Report to Congress on Emerging Clean Coal Technologies Capable of Retrofitting, Repowering and Modernizing Existing Facilities, Washington, DC, 1987; US Department of Energy, Clean Coal Technology Demonstration Program: Annual Report to Congress, Washington, DC, 1990. aAssumes base is conventional coal fired power plant with only particulate removal devices. For repowering technologies, capital costs are relatively high because the output, ie capacity, of the plant is increased. One mill = 0.1¢.
these options promise moderate extension to the useful life of existing facilities. The effect of the technologies on the cost of electricity is in the range of a 10-20% increase over a conventional coal fired plant for most alternatives. The range for capital cost increases is a little broader even for the conventional and retrofit alternatives, with several of the options falling far below 10%. The repowering options appear to imply very high additional capital costs, but the numbers need to be adjusted for increased capacity. Although the incremental cost of utilizing these new technologies is termed an increase in Table 1, the D O E analysis may be misleading. First, the cost of burning alternative fuels (oil and gas) may increase by more than 10-20% above coal burning costs by the mid-1990s. Recall that upward pressure on prices is greater on relatively less abundant resources and those whose prices can be influenced by political events such as the war in the Middle East. Second, it seems more reasonable to use a reference point that includes the full cost of constructing and operating a new steam-boiler facility ie it is only fair to include the cost of meeting environmental control requirements. The effect of this can be understood by subtracting the cost for a flue gas desulphurization (FGD) unit from each of the new options. Then, many of the CCTs would provide a definite cost saving, stimulate production of end products and hence stimulate the demand for coal. 670
In addition to the combustion efficiency and emission control advantages already mentioned, several general design characteristics common to many CCT options represent significant cost savings. These include modularity, shorter construction time and fuel flexibility. The first two can save from US$150250/kW of capacity, while the latter can mean as much as a l¢/kWh energy cost savings. Most of the options promise to make coal use more attractive by virtue of reducing SO2 emissions substantially: however, NOx reduction is moderate at best. 13 Aside from the well known sludge problems of FGD units, no major waste disposal problems are associated with the other technologies. In light of recent concerns about global climate change, improved combustion efficiency also offers some CO2 reduction. Among the more problematic aspects of evaluating CCTs are projections of technical readiness. Predictions of commercial availability of some major CCTs are presented in Table 2. DOE's first assessment in 1985 projected commercial readiness by the middle of this decade in most cases. However, this key date is moved back to three years on average by each new D O E assessment in 1987 and 1990. These dates are even more distant for options other than those involving repowering and retrofit; for example, Siegel and Temchin set the date as 2010-2020 for the commercial availability of magnetohydrodynamics. 14 ENERGY POLICY June 1993
Economic incentives for clean coal technology deployment Table 2. Commercial availability of clean coal technologies.
Technology Retrofit Advanced flue-gas clean up Limestone injection multistage burner Advanced combustors Gas reburning In-duct sorbent injection Chemical and microbiological coal cleaning Advanced physical coal cleaning Repowering Integrated gasification combined cycle Pressurized fluidized-bed combustion Atmospheric fluidized-bed combustion
1985 estimate year of commercialization
1987 estimate expected availability
1990 estimate first commercial plants
1990 -95 1990 -95 1986-9(} --1995 -2000 1986-90
1995 -2000 1990 -95 1990-95 1990 -95 1990-95 1990 -95 1990 -95
1995 -99 -1993 -97 1993 -96 1991-95 1997 -2001) 1993 -98
-1995 -2000 1986-90
1990 -95 1990-95 1990 -95
1997 -2004 1997 -2003 1996 -2001
Sources: US Department of Energy, Report to Congress on Emerging Clean Coal Technologies, Washington, DC, 1985; US Department of Energy, Second Report to Congress on Emerging Clean Coal Technologies Capable of Retrofi'tting, Repowering and Modernizing Existing Facilities, Washington, DC, 1987; US Department of Energy, Clean Coal Technology Demonstration Program: Annual Report to Congress, Washington, DC, 1990.
A n o t h e r way of viewing this situation is to point to the 'just around the corner' syndrome that is typical of new energy technology assessments. Most CCT assessments undertaken over the past 30 years, especially those for synfuels, have predicted nearterm availability or economic viability: yet we seem to be no closer to the target now than in the late 1950s. ~5 We should also emphasize the distinction between technical availability and economic viability and note that the D O E studies pertain primarily to the former. The D O E studies are credible in terms of technical progress, but involve a great deal of uncertainty about when or whether the CCTs will be able to compete with conventional systems in the marketplace.
Technology choice Deployment considerations Simple economics would appear to dictate that once we do turn the corner on viability, widespread use of clean coal technologies will ensue. But numerous factors indicate that just the opposite is likely to happen. One indication of this is the US experience with the atmospheric fluidized-bed combustion (AFBC) process, which has been a proven technology at small scales for two decades. As of 1990 there were only 24 coal fired A F B C plants generating electricity in the country, with a combined capacity of about 2000 MW. A F B C units burning other fuels were comparably meagre. Installations scheduled to come on line over the next few years would raise this capacity level to about 3500 MW, 16 about 1% of the US coal fired capacity. This compares with much more extensive use in other countries. The fact that the operations in other countries utilize a variety of ENERGY POLICY June 1993
fuels in addition to coal (eg wood, waste products, biomass) implies that electric utilities in the US lag in imagination and commitment to this valuable technology, that they are not in a competitive market or that they are highly risk averse. Inertia in adopting new technologies is further evidenced from another perspective. For example, the boilers in large-scale, coal fired power plants currently in use are much the same as those brought on line in the 1920s, despite the fact that hundreds of such plants were built, and conditions were ripe for experimentation during the industry's significant growth phase. Overall, very few technologies capable of improving the environmental performance of coal utilization have been developed and extensively deployed over the past 25 years. The following factors should be considered in attempting to understand the reasons for this phenomenon. First is the large capital investment, sometimes in excess of a billion dollars per unit. Premature replacement of an existing facility would take years to recoup and would appear to be especially unattractive in the era of pursuit of short-run profits. The impact of such an investment on the financial position of an electric utility might even make it unattractive in the long run. Second is the risk factor. It is likely that demonstrations at commercial scale will still not be convincing enough to many potential CCT customers. Given the complexity of their operations and technical problems associated with previous new technologies, including nuclear reactors, utilities and other customers are likely to be gun shy. It would seem that the utility industry is even wary of its own research. For example, the Electric Power Research Institute circulated findings touting the success of FBC and
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Economic incentives for clean coal technology deployment
IGCC operations, 17 but the industry dearly failed to follow suit. Third is regulatory agency attitudes, primarily those having a bearing on the risk factor. 18 It has increasingly become the case that state public service commissions would not allow nuclear plant failures to be factored into the rate base. There is the fear that failures of CCTs would meet the same fate. This has the effect of imposing the entirety of the experimentation risk on to utility shareholders, and thus acts as a disincentive to adopting new alternatives. A reversal of this practice would lead to a sharing of this risk by utility customers. Some suggest that it is justified in principle since these customers may benefit from power generation cost reduction. In practice the remedy is difficult because of the need to arrive at a reasonable risk sharing in light of such great uncertainty. More recently, there has been congressional interest in this issue in the form of the proposed Clean Coal Technology Deployment Act ($879), which sought to designate any CCT project as prudent for FERC rate making purposes, and to encourage the same designation be granted by state public utility commissions. Fourth is the uncertainty surrounding environmental regulations. A chronic fear of major manufacturers and utilities is that soon after investing in a new technology, legislation will be passed requiring that some other technology be used. Previous technology forcing approaches, such as those requiring best available control technology (BACT) and lowest achievable emission rate (LAER) policies, reinforced this concern. More recent policy debates over CO2's contribution to global warming raise the spectre of still another generation of technological replacement. More recently, Congress passed the 1990 Clean Air Act Amendments ($1630), a main feature of which is an acid rain abatement programme. The Act calls for SO2 reduction of large utility boilers in two phases, with target dates of 1995 and 2000. A novel feature is the specification of a marketable emission permit programme. The Act contains some special features that will directly affect the interests in CCTs. It provides an exemption from more stringent regulations of ongoing CCT projects and grants a four-year extension for meeting Phase II requirements for plants repowered with a CCT. The Act also requires the FERC to initiate a five-year experimental programme of regulatory incentives for CCTs. It is not clear whether these will have a significant effect on their deployment. There are still uncertainties about emission trading, special allowances for Mid-west
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utilities, special formulas for smaller and cleaner plants, and still unspecified performance standards for NOx that must be issued by 1994.19
A market approach The 'command and control' approach, typically in the form of process or performance standards, has dominated the environmental management arena in the USA and most other countries. Although most economists have favoured fiscal penalties or inducements, such as effluent charges, these instruments represent some interference with the market. Both these standards and charges approaches are seen as ways to eliminate the market failure stemming from the presence of externalities in the form of pollution. Although the enforcement power of the state would seem to assure the effectiveness of administrative decree, the internalization of the opportunity costs of pollution associated with penalties or inducements makes compliance just as likely, though in a more subtle way. Moreover, since the fiscal approach allows for greater flexibility of choice, it is inherently more efficient. An alternative approach is one that corrects a market failure by establishing or strengthening the market and then stepping back and letting supply and demand take their course. This seems to trouble many outside the economic profession because they think there is no assurance that the desired behaviour would be forthcoming. But establishing a perfectly competitive market facilitates voluntary compliance with broader objectives in the course of pursuing private profit. Many innovative arrangements, such as emissions trading, have been proposed to bring about such an outcome. 2° In the case of deployment of CCTs, an elaborate scheme may not be needed. If, in fact, these options are technically and economically sound, it may be sufficient just to improve the information flow, reduce the uncertainty regarding future environmental regulation, provide a sharing of the risk, and eliminate unfair advantages from competing alternatives. Government at various levels, equipment vendors, and trade associations can help in the transfer of information about CCTs. In addition, standardized and independent testing, as well as open inspection of demonstration and subsequent operating facilities, would help. The optimal sharing of risk between market participants is an old problem and complicated by the fact that what promotes allocative efficiency may be very inequitable. It is safe to say, however, that a continued hard stand on technological innovation in
ENERGY POLICY June 1993
Economic incentives for clean coal technology deployment
relation to rate making is likely to produce less than the social optimum level of progress. Ideally, the risk burden would be spread between stockholders and customers so as to attain the optimal path, but in practice the empirical calculations are difficult. Ironically, the matter of 'unfair' advantage by competing technologies is attributable to a great extent to the subsidies in this policy area. Estimates of the value of these subsidies range from US$10 billion to nearly US$50 billion in a given year, 21 with nuclear power traditionally having been the most favoured option. The effect of these subsidies is to lower the price of some options relative to others and thus distort the choice process. Elimination of many of these subsidies was proposed in various recent tax reform proposals and is consistent with the Reagan and Bush administrations' theme of creating a level playing field for all energy options. 22 The fact that only a few of the subsidies were eliminated in the most recent round of reforms, however, indicates that actual implementation of this policy approach must overcome some powerful entrenched interests. Overall, there may be some insurmountable obstacles to creating a situation of perfect competition, meaning some subsidies or other offsetting distortions might be justified in such a second-best world. We should also note that a conventional private goods market might not be the relevant ideal, because of public good features of early operating experiences. Some subsidies might be justified for those first several facilities that incur the added cost of moving the nation up the technological learning curve. 23 Finally, we note one interesting aspect of the market solution - it does not require the deployment of CCTs to be successful. If firms opt for low sulphur coal, natural gas or some other alternative then so be it. The problem is that, in practice, it is difficult to tell whether such an outcome is due to market success or market failure.
A fiscal incentive approach Although subsidies and taxes are often viewed as two e q u i v a l e n t sides of the fiscal i n s t r u m e n t approach, 24 the extent of their application in the energy and environmental arenas is quite different. Subsidies for pollution control are a rarity, but are often used in the case of energy policy, most notably for conservationfl 5 The use of fees is just the opposite, although several noted economists have proposed an oil import tariff. 26 One of the reasons for this difference is the perceived fairness of the application of the instru-
ENERGY POLICY June 1993
ment. The polluter is viewed as the perpetrator of the environmental externality, and therefore it is seen as fair to tax him. 27 A similar attitude has not won favour in terms of 'wasting' energy, although the oil import tariff case suggests that those who cost us some national or energy security are increasingly viewed as culpable by policy makers. There are both energy and environmental features inherent in the case of CCTs, and it would seem that using subsidies to ensure the deployment of these technologies could be justified on several grounds. First, although CCTs are obviously biased in favour of coal use, there are several absolute and relative (to the use of other fuels) social benefits to be gained. Increased coal use reduces the US reliance on foreign oil, cost estimates of which range from US$1 to US$30 per barrel in terms of several types of external costs. 28 Second, subsidizing CCTs may have some justification from the efficiency and equity standpoints of regional development. Many of the coal producing areas of the USA are economically depressed. Lagging regions are thought to place a drag on national growth, and 'workfare' in the form of producing coal may be preferable to conventional welfare in the form of unemployment compensation. Finally, CCTs do represent a solution to the acid rain problem which, if not costless, is at least less costly than other approaches. Moreover, most of the aspects of subsidies that have been viewed as leading to aberrant (non-optimal) behaviour do not apply in the technology specific case. From a practical standpoint, the value of CCT subsidies probably need not be very great. In this case, the subsidy need not be set equal to the marginal social benefit of acid rain reduction, but simply at a level able to overcome the inertia of the adoption decision plus any cost differential between a CCT and the least-cost alternative. As noted earlier, subsidies are rampant in the energy arena, 29 with estimates in the tens of billions of dollars per year. Estimates on the high side count 'all identifiable federal energy-related expenditures, other than market purchases of energy for own use'. 3° Estimates on the low side omit certain categories of expenditures, especially those associated with defence aspects of energy. Coal already receives a large portion of these subsidies in absolute terms and in relation to total coal and new coal energy produced. No estimates of the proportion of these subsidies attributable to CCTs can be offered at this time, but it is safe to say, given on-going research, development, and deployment of generic efforts in this area, that it is substantially larger than
673
Economic incentives for clean coal technology deployment
the current US$500 million per year matching money for officially designated CCT demonstration programmes. Not all subsidies are equal in their costeffectiveness or manageability, so comparative evaluations must be undertaken to arrive at an optimal subsidy arrangement. Past success is a place to start, but new, specialized subsidy instruments might also be devised eg a variable subsidy whose value is based on the contribution of the facility to the national learning curve, or closely related to this, a subsidy that varies with the riskiness of the technology. In theory, subsidies can be fine tuned to bring about desired goals, such as the timing and magnitude of CCT deployment. Of course, there is a case against subsidies. In addition to claims that they are inferior to the market solutions, there is the claim that they do not work in practice. This argument, however, pertains to R&D, and aside from the lack of supporting evidence presented, may be less applicable to deployment, where there is less uncertainty. In addition, subsidies are viewed as price distorting, but that is the point. They are intended to correct the social valuation of a decision as almost always inaccurately reflected in a market price, as in reduced dependence on foreign oil or an improved physical environment. Finally, we note the possible displacement effect of some productive investment by subsidies for energy technology, which have been estimated at 40% of total US investment in recent years. 3~ Concerns such as this, however, can be approximated and factored into the optimal subsidy levels as social costs to be subtracted from the potentially many social benefits.
Analysis of subsidies to promote technology adoption Government can share the risk and uncertainties inherent in the adoption of new technologies by industry through the use of subsidies. The following analysis of financial incentives for CCTs takes its lead from the US Department of Energy Report by the Innovative Control Technology Advisory Panel. 32 Three major types of incentives are examined: tax breaks, soft loans and capital subsidies. All three of these incentives apply to risks associated with uncertain capital costs, since investment and debt returns are recognized expenses for taxation purposes. Still, to the extent they lower overall costs, these subsidies compensate for various types of risks.
674
Fiscal incentives
Tax incentives are widely used to decrease capital costs and inherent risks. Some major examples are: accelerated depreciation, investment tax credit and property and ad valorem tax exemptions or reductions. 33 Our analysis will focus on the first two. To determine income for taxation purposes, the straight line depreciation method can be considered the baseline case. Thus, for a normal power plant with a 30 year life expectancy, the annual recognized depreciation cost is 3.333% of the installed capital cost. Accelerated depreciation allows investors to write off their investment more rapidly by deducting more of the capital cost from tax payments during the early years of the plant's operations. Thus, a doubled depreciation rate would be 6.667% annually for 15 years, and in a 10 year accelerated depreciation schedule, the capital cost would be deducted at a 10% annual rate. The investment tax credit is a direct reduction in the project's tax liability, which equals a fixed rate of capital investment (up to 15% according to current laws). The investor may use the credit either at the plant's commissioning or during the installation period. Usually, investors will use the credit as soon as they have a positive tax liability to which it can be applied. While tax incentives can reduce some of the risk associated with capital costs, they do not assist with the problem of obtaining the high levels of initial capital required for major utility installations. In addition, this incentive may cause an undesirable phenomenon of overintensive capital investment. 34 Soft loans bear interest rates lower than the market rates. They may range from moderately lower interest rate loans (1 or 2% below market rates) to interest free loans. These loans can finance part or all of the debt component of the capital investment. Although subsidized loans can provide a partial solution to the industry's capital risk, they do not directly correspond to uncertainties associated with the plant's performance. Subsidies and grants are widely used economic incentives in promoting the use of new technologies. They may be provided in various ways: per ton of pollutants removed, per installed kilowatt capacity and percentage of capital cost. Our analysis focuses on the more popular capital cost subsidy, where investors receive a grant at a fixed rate of their capital investment. This is the approach currently used to promote demonstration of various types of CCTs in the USA (see above). Capital cost subsidies also tend to promote the adoption of more capital intensive investments. As
ENERGY POLICY June 1993
Economic incentives" Jor clean coal technoh~gy deployment Table 3. Impact of incentives for various CCTs on busbar prices a and percentage change b from base case (60% capacity utilization). Tax incentive
Clean coal technology
Pulverized coal with flue-gas desulphurization (PC/FGD) Atmospheric fluidized-bed combustion (AFBC) Pressurized fluidized-bed combustion (PFBC) Pressurized fluidized-bed combustion repowering Integrated gasification combined cycle (IGCC)
Soft loan interest loan
Free interest loan
Capital subsidy 25% of 50% of total total cost cost
41.2 (- 12.21 43.0 (- 12.5) 43.0 (- 13.0) 37.2 (-11.21 43.8 (- 12.9)
37.8 (-19.41 40.2 (- 19.91 39.3 (-20.4) 34.4 (-17.9) 40.0 (-20.5)
4(I.4 (-13.9) 43.0 (- 14.31 42.4 (-14.6) 36.5 (-12.91 42.9 (- 14.71
10 year
11.5%
Reduced (3%)
Base case
accelerated depreciation
investment tax credit
46.9
40.9 (-12.8) 43.6 (- 13.1) 42.8 (-13.4) 36.9 (-12.0) 43.5 (- 13.5)
50.2 49.4 41.9 50.3
44.8 (-4.5) 47.9 (-4.5) 47.1 (-4.7) 4(I.2 (-4.1) 48.0 (-4.6)
33.6 (-28.4) 35.6 (-29.0) 34.7 (-29.8) 3(I.9 (-26.3) 35.2 (-30.0)
aln mills/kWh (1 mill = 0.1el. bNumbers in parentheses.
with tax and loan incentives, these subsidies do not provide an answer to risks related to project performance. However, other types of grants and subsidies, such as a subsidy based on pollution abatement levels, do not create a capital intensive bias.
Effect of selected economic incentives The implications of selected incentives on the busbar generation cost of different CCTs are assessed below. The incentives examined include: tax incentives (10 year accelerated depreciation and 11.5% investment tax credit), soft loans (3% below market rates and interest free), and subsidies (25% and 50%). In our calculations, first the impacts of the incentives on the capital charge rates were calculated and the results applied to the selected CCTs for the calculation of the busbar costs. These were calculated under two scenarios of plant utilization: 60% capacity factor (Table 3) and 70% capacity factor (Table 4). Beginning with the case of a capacity factor of 60%, the effect of tax incentives reveals that a 10 year accelerated depreciation policy contributes
to a reduction of 12.0 to 13.5% in the busbar cost of selected technologies relative to the base case. For example, the busbar cost of pressurized fluidizedbed combustion (PFBC) repowering decreased from 41.9 mills/kWh to 36.9 mills/kWh (1 mill = 0.1¢), whereas the busbar costs of integrated gasification combined cycle (IGCC) decreased from 50.3 mills/ kWh to 43.5 mills/kWh. The impact of the 11.5% investment tax credit is more moderate. This incentive contributes to a reduction of 4.1 to 4.7% in the busbar costs of the selected technologies. The variation in the rate of cost decrease for each incentive across the various technologies is mainly due to the variation in the base case cost of the different CCTs. Soft loans can contribute to a maximum reduction in busbar costs in a range of 17.9% (PFBC repowering) to 20.5% (IGCC) in the case of free interest loans. The most effective incentive in our analysis is the 50% capital subsidy, which contributes to a reduction of up to 30% in busbar cost (IGCC). Similar relative effects are ahieved when a 70% plant capacity factor is utilized (Table 4). With this assumption, however, base case busbar costs are
Table 4. Impact of incentives for various CCTs on busbar prices a and percentage change b from base case (70% capacity utilization). Tax incentive
Clean coal technology
Pulverized coal with flue-gas desulphurization (PC/FGD) Atmospheric fluidized-bed combustion (AFBC) Pressurized fluidized-bed combustion (PFBC) Pressurized fluidized-bed combustion repowering Integrated gasification combined cycle (IGCC)
Soft loan interest loan
Free interest loan
Capital subsidy 25% of 50% of total total cost cost
38.1 (- 11.4) 4(1.5 (- 11.6) 39.6 (-12.0) 34.6 (- 10.4) 40.3 (-12.2)
35.2 (-20.5) 37.3 (- 18.6) 36.4 (-19.11 32.2 (- 16.61 37.0 (-19.41
37.4 (- 13.tl) 39.7 (- 13.3) 38.9 (-13.61 34.0 (- 12.01 39.5 (-23.5)
10 year
11.5%
Reduced (3%)
Base case
accelerated depreciation
investment tax credit
43.0
37.8 (- 12.1) 40.2 (- 12.2) 39.4 (-12.4) 34.4 (- 10.9) 40.0 (-12.9)
45.8 45.0 38.6 45.9
41.2 (-4.2) 43.9 (-4.1) 43.0 (-4.4) 37.2 (-3.6) 43.8 (-4.6)
31.6 (-26.5) 33.4 (-27.1) 32.5 (-27.8) 29.2 (-24.4) 32.9 (-28.3)
aln mills/kWh, bNumbers in parentheses.
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675
Economic incentives for clean coal technology deployment Table 5. Incentives required to achieve breakeven with alternative base power plants. Type of incentive Accelerated depreciation (years) Clean coal technology
Conventional
Pulverized coal with flue-gas desulphurization (PC/FGD) 10 Atmospheric fluidized-bed combustion (AFBC) 6 Pressurized fluidized-bed combustion (PFBC) 8 Pressurized fluidized-bed combustion repowering 17 Integrated gasification combined cycle (IGCC) 6
PC/FGD
Investment tax credit (%) Conventional PC/FGD
Reduced interest loan (%) Conventional PC/FGD
Capital subsidy (%) Conventional PC/FGD
-
30
-
-3
-
22
-
15
45
17
-6
-1.6
32
12
16
40
12.5
-5
-1.2
30
9
6
a
a
5
45
17
-1.6
32
a
5
-0.75 -6
12
aPFBC repowering is already lower than PC/FGD.
lower than in the 60% capacity factor scenario in a range of 3.3 mills/kWh (PFBC repower) to 4.4 mills/kWh (IGCC). The relative improvements due to various subsidy types are the same as in Table 3. Another way of analysing the potential of incentives is to determine the magnitude required to achieve the breakeven point with the busbar cost of conventional power plants. The comparison is made with regard to two types of technologies: a conventional power plant that does not contain appropriate pollution control devices and a power plant consisting of a pulverized coal combustion boiler with flue-gas desulphurization (PC/FGD). The results are presented in Table 5 and reveal that in the case of accelerated depreciation, investment write offs of 17 years (PFBC repower) to 6 years (AFBC and IGCC) are required to achieve breakeven with the conventional power plant. Conversely, more moderate accelerated depreciation rates are sufficient to reach breakeven with PC/FGD - 16 years (PFBC) and 15 years (AFBC and IGCC). Note that the busbar cost of PFBC repowering is already lower than the busbar cost of PC/FGD. Required investment tax credit rates to achieve breakeven with the conventional plant are in the range of 6% (PFBC repower) to 45% (AFBC and IGCC). The range drops to only 0-17% to achieve parity with PC/FGD. For soft loan incentives, a reduction of 0.75% (PFBC repower) to 6% (AFBC and IGCC) from an assumed market lending rate of 7% is required to achieve breakeven with a conventional plant, and a 0 to 1.6% reduction with PC/FGD. Finally, a capital subsidy of 5-32% is necessary to achieve breakeven with a conventional plant, and of 0-12% with PC/FGD. The aforementioned results are almost identical between cases of 60% and 70% plant capacity utilization factors. 676
Conclusion Our analysis suggests that widespread deployment of clean coal technologies is not likely to be forthcoming over the next two decades despite the CCT Demonstration Programme and the 1990 C A A Amendments. Numerous bureaucratic hurdles and commercialization viability questions, as well as uncertainties over specific implementation of the new environmental regulations, will slow the adoption of CCTs. Moreover, electric utility industry attitudes towards risk and the utility regulation environment are problematic in the link between demonstration and deployment. Economic incentives are one way of overcoming these problems. More scrutiny of this policy issue is needed. The US$2.5 billion CCT Programme may appear to be a sizable sum in isolation, but it needs to be compared with the social benefits it may yield. Even if we utilize the absolute lower bound benefit estimate of US$2 billion per year, the discounted present value over the relevant time horizon would be several times greater than the CCT outlayY The complication is that the CCT subsidy is not the only distortion causing fiscal incentive in this area. The crucial question is thus the effectiveness of the CCT programme relative to other fiscal incentives in helping attain the optimal level of social benefits. Another perspective on the situation is to note that the Reagan and Bush administrations' position against market interference has resulted in their putting all of their eggs in the R&D and demonstration strategy baskets. If policies to actually level the playing field are not enacted, or if it is determined that this is an unattainable goal, a deployment subsidy should be examined as a realistic alternative. This might mean shifting some future CCT funding to the deployment stage. ENERGY POLICY June 1993
Economic incentives for clean coal technology deployment
Our results indicate that the most economically viable CCT is PFBC repowering. It requires the lowest incentive rate (eg a 5% capital subsidy or less than 1% reduced loan rate) to break even with conventional technology, and does not require any incentive when compared with PC/FGD. Conversely, new PFBC installations require an extensive subsidy, and AFBC and IGCC require the highest incentive rates. Such conclusions can only be drawn under the assumption that the reference economic criterion for the selection of preferable CCTs is the minimization of the incentive required to achieve breakeven with conventional or PC/FGD technologies. In this regard, however, other economic, technology and environmental criteria should be considered, including benefits and limitation of repowering methods; maturity, reliability and efficiency of different technologies; the environmental achievements of the CCTs in pollution mitigation; and the contribution of a technology that stimulates the use of a domestically abundant fuel, thereby reducing the nation's dependence on imported oil. Preference among various incentive types may vary between investors and the government, and among investors themselves. Many investors may prefer tax incentives that will enable them to benefit from a lower tax burden, mainly in the first years following the plant's commissioning. Others may prefer capital subsidies or soft loans to lower their debt burden. The government macroeconomic policy perspective may be sensitive to the effects of the type of incentive on its budget, eg increased expenditures (capital subsidy and soft loans) versus decreased incomes (tax incentives). In addition, fiscal timing may also play a role in the decision. Whereas tax incentives imply reduced incomes in future years, capital subsidies necessitate relatively large expenditures up front. The USA has committed US$2.5 billion to the Clean Coal Technology Programme at the demonstration level. Yet follow up considerations, mainly with respect to deployment under considerations of a free market or regulatory requirements of the recent Clean Air Act Amendments, have been subjected to little economic or energy planning scrutiny. Clearly further analysis of CCT deployment prospects is warranted given the potential size of the public investment and potential social benefits.
This research was supported in part by the US Office of Technology Assessment and The Pennsylvania State University Mining and Mineral Research Institute. Some background portions of
ENERGY POLICY June 1993
this paper are taken from the senior author's (A.R.) contributions to a report to OTA, co-authored with Walter Labys and Thomas Torries. An earlier version of the paper was presented at the Annual International Meeting of the International Association for Energy Economics.
tUS Department of Energy (DOE), Clean Coal Technology Demonstration Program: Annual Report to Congress, Washington, DC, 1990. 2A. Rose, T. Torries and W. Labys, 'Clean coal technologies and future prospects for coal', Annual Review of Energy and the Environment, Vol 16, 1991, pp 59-90. 3M. Yates, 'Congress approves historic clean air legislation', Public Utilities Fortnightly, December, 1990, Vol 6, pp 53-55; N. Kete, 'The US acid rain control allowance trading system', Climate Change: Designing a Tradeable Permit System, Paris, OECD, 1992. 4US Department of Energy, Report to Congress on Emerging Clean Coal Technologies, Washington, DC, 1985, pp 1-4; US Department of Energy, Supplemental Report to Congress on Emerging Clean Coal Technologies, Washington, DC, 1985. Slbid. 6In general, the Clean Coal Technology Programme has substantial industry support. Many of the guiding principles of the programme are consistent with private industry views as expressed in a report by the National Coal Council, an advisory committee to the Secretary of Energy composed primarily of executives of companies involved in the coal cycle, including machinery manufacturers, as well as some labour leaders, public officials and scientists (see National Coal Council, Clean Coal Technology, Washington, DC, 1986). One significant difference is the greater emphasis on government risk sharing encouraged by the National Coal Council. 70. Lewis and W. Davis, Special Envoys Report on Acid Rain, Washington, DC, 1986; National Acid Precipitation Assessment Program (NAPAP), Interim Assessment: The Causes and Effects of Acidic Deposition, Washington, DC, 1987. SJ.A. Wampler, Testimony to the Committee on Energy and Natural Resources, US Senate. More than 50% of the utility boilers currently utilizing coal will be at least 25 years old by then. Annual average growth in electricity demand is project at 2.5 to 3.0% per year (see also Electric Power Research Institute 'Coal technologies for a new age', EPRI Journal, January/February, 1988) after the levelling off of the late 1970s and early 1980s. 9These terms are defined as follows in US Department of Energy, Second Report to Congress on Emerging Clean Coal Technologies Capable of Retrofitting, Repowering and Modernizing Existing Facilities, Washington, DC, 1987, p 30 - repowering: 'any technology that replaces a significant portion of the original power plant and reduces atmospheric emissions of pollutants, often while increasing capacity.' Retrofitting - 'the installation on existing facilities of devices designed primarily to reduce emissions." Modernization - 'the upgrading of an aging power plant for the purpose of extending, its useful service life in order to postpone the need for new generating capacity.' x°US Department of Energy, The New Coal Era, Report No DOE/FE-0193P, Washington, DC, 1990: US Department of Energy, op cit, Ref 1. HUS Department of Energy, Clean Coal Technology Demonstration Program: Program Update, 1991, Washington, DC, 1992. ~2US Department of Energy, Project Status Report, mimeo, Office of Fossil Energy, Washington, DC, 199[); US Department of Energy, Project Status Report, mimeo, Office of Fossil Energy, Washington, DC, 1992. I-~The emission reduction characteristics of various CCTs as specified in US Department of Energy, Report to the Secretary of Energy Concerning Commercialization Incentives, Report No DOE/EH-0083, Washington, DC, 1989, are as follows: PC/FGD, reduction rate 90% SO2, 0% NO~; AFBC 90-95% SO,, 60% NO~; PFBC 90-95°/,, SO2, 70% NO~; PFBC repower 90-95% SO2, na NO~; IGCC 92-99% SO> 92% NO,.
677
Economic incentives for clean coal technology deployment 14j. Siegel and J. Temchin, 'Role of clean coal technology in electric power generating in the 21st century', in J. Tester, N.A. Ferrari and D.O. Wood with Janos M. Beer, eds, Energy and the Environment in the 21st Century, MIT Press, Cambridge, MA, 1991. lSJ.M. Griffin and H.B. Steele, Energy Economics' and Policy, 2nd edn, Academic Press, Orlando, FL, 1986. ~6R. Wolk and J. McDaniel, 'Electricity without steam: advanced technology for the new century,' presented at The Association of Edison Illuminating Companies Power Generation Meeting, Orlando, FL, 1990. 170p cit, Ref 8, EPRI. lSThere are three types of risks associated with the deployment of new technologies: capital cost, performance, and operating and maintenance cost. Capital cost risks refers to the possibility that actual capital expenditures may be higher than initially estimated. This risk is an increasing function of capital intensity of the investment. Performance and operating cost risks are associated with the possibility of technical and other problems reducing the rate of output or raising costs above original expectations. All other things equal, the risks are an inverse function of prior operating experience. 190p cit, Ref 3, Kete. 2~I'. Tietenberg, Emissions Trading: An Exercise in Reforming Pollution Policy, Resources for the Future, Washington, DC, 1985; R. Hahn, 'Economic prescriptions for environmental problems', The Journal of Economic Perspectives, Vol 3, 1989, pp 95-114. 21US Department of Energy, Selected Federal Tax and Non-Tax Subsidies for Energy Use and Production, Energy Policy Study, USGPO, Vol 6, Washington, DC, 1980; H.R. Heede, 'A preliminary assessment of federal energy subsidies in FY1984', Testimony before the House of Representatives Subcommittee on Energy Conservation and Power, Washington, DC, 20 June 1985. 22US Senate, Tax Reform Act of 1986, USGPO, Washington, DC, 1986. 23j.K. Harlan, Starting with Synfuels: Benefits, Costs, and Program Design Assessments, Ballinger, Cambridge, MA, 1982. This might involve offsetting taxes too, such as one to cover the security premium on imported oil or import taxes on subsidized foreign produced technology. 24The early literature on effluent charges and subsidies viewed them as perfectly symmetric and both capable of generating an efficient outcome. Subsequent analyses, however, indicated that subsidies were vulnerable to strategic behaviour on the part of economic agents that would lead to inefficiencies in the short run, and that even normal behaviour would render a subsidy based
678
arrangement inefficient in the long run (see G.E. Mumy, 'Longrun efficiency and property rights sharing for pollution control', Public Choice, Vol 35, 1976 pp 59-74; W.J. Baumol and W.E. Oates, The Theory of Environmental Policy, 2nd edn, PrenticeHall, Englewood Cliffs, NJ, 1987. 25A. Rose, 'Modeling energy conservation programs: an application to natural gas utilities', Energy Journal, Vol 6, 1987, pp 87-103. 26H.G. Broadman and W. Hogan, Oil Tariff Policy in an Uncertain Market, Discussion Paper 86-11, Energy and Environmental Policy Center, Harvard University, Cambridge, MA, 1987. 27Coase, one of the more prominent of the early proponents of the market solution, has pointed out that it takes two to make an externality and that the assignment of blame is arbitrary and unnecessary to an efficient outcome. Thus, the assignment of property rights under the market solution is an equity issue not an efficiency issue. Under certain circumstances, so is the choice of fees versus subsidies (see R.H. Coase, 'The problem of social cost', Journal of Law and Economics, Vol 3, 1960, p 1-44). 28D.R. Bohi and W.D. Montgomery, 'Social cost of imported oil and US import policy', Annual Review of Energy, Vol 7, 1982, pp 37-60; D. Hall, 'Preliminary estimates of cumulative private and external costs of energy', Contemporary Policy Issues, Vol 8, 1990, pp 283-307; P.K. Verleger, 'Understanding the 1990 oil crisis', Energy Journal, Vol 11, 1990, pp 15-33. 29Energy subsidies take many different forms. Heede (eg op cit, Ref 21) identifies 17 federal tax code categories and programmes and 21 federal agencies. Numerous state level subsidies are identified by Chapman (D. Chapman, 'Federal incentives affecting coal and nuclear power economics', Natural Resources Journal, Vol 22, 1982, pp 361-378). 3°0p cit, Ref 21, Heede.
31Ibid. 320p cit, Ref 13. 330p c#, Ref 29, Chapman. 34H. Averch and L. Johnson, 'Behavior of the firm under regulatory constraint', American Economic Review, Vol 52, 1962, ~ 1053-1069. ocial benefits of new energy technologies are often measured in terms of the security premium on imported oil they would displace. The premium is in turn often measured by the least-cost alternative to achieve energy security. This is widely held to be the Strategic Petroleum Reserve, whose annual cost is simply the interest cost on the stored oil: see Verleger, op cit, Ref 28. Of course, this lower bound ignores a potentially large environmental premium representing additional .social benefits that can be achieved by CCTs.
ENERGY POLICY June 1993