No single type of financial incentive closes the cost gap between clean coal and modern conventional coal technologies.
After two decades of demonstration projects aimed at establishing the technical and economic viability of clean-coal technologies, a variety of power producers now are considering seriously their use for new commercial generating plants. The major remaining obstacle is how to obtain financing for the next few plants, with an expected cost of electricity about 15 to 20 percent higher than that produced by conventional coal facilities.
Since the use of clean-coal technologies remains a high priority for the federal government, various financial incentives have been proposed to help overcome this problem. After examining a wide range of formally and informally proposed options, however, the authors have identified a critical dilemma facing policymakers: No single type of financial incentive studied will close the cost gap between clean coal and modern, conventional-coal technologies for all three major groups of generator owners-investor-owned utilities, independent power producers, and publicly owned utilities and cooperatives.
This dilemma comes at an awkward time for owners of generation, many of whom invested heavily during the last decade (when gas prices were relatively low) in power plants fueled by natural gas.
Since 1990, more than 200 GW of new natural gas generating capacity has been placed in service, compared with only 15 GW of new coal-fired capacity. Since 2000, however, the average price of natural gas has more than doubled, and two major price spikes have occurred that set records for months at a time. As a result, many of the new gas-fired plants are not competitive: For 2004, the average capacity factor of U.S. natural-gas, combined-cycle plants was only 32 percent. And, looking toward the future, gas prices appear likely to remain high as domestic production increasingly falls behind consumption.
In addition to rising gas prices, which once again have made conventional coal-fired plants highly competitive, other considerations are driving renewed interest in coal. Foremost among these are concerns over energy security and balance-of-payment deficits related to rising imports of oil and liquefied natural gas (LNG)-imports that have been key to fueling economic growth over the past half-century. These imports likely will continue to play a key role in the future, but their benefits will be weighed against the transfer of funds to other countries, often in unstable parts of the world.
Coal remains the nation's most abundant domestic energy resource, still economically attractive even after paying to retrofit expensive, emission-control systems. Rising environmental pressures, however, have created deep uncertainty over which future coal technologies will be most economical in the long run.
Advanced Coal Technologies
Against this background, the attractiveness of advanced coal technologies is easy to understand: Plant emissions can be reduced more efficiently by eliminating pollutants before or during combustion, rather than through post-combustion treatment. Eventually, a portfolio of such "clean-coal" technologies will be needed to handle different grades of fuel and meet specific regional needs. Initially, the impetus for developing these technologies was to reduce sulfur dioxide emissions associated with acid rain, but recent concerns have focused on the potential health effects of microscopic particles and trace emissions of mercury, as well as the chance to reduce emission of greenhouse gases. Providing funds to demonstrate such technologies at commercial scale is the focus of the U.S. Department of Energy's Clean Coal Power Initiative. Meanwhile, the industry-sponsored "CoalFleet for Tomorrow" initiative is working to accelerate the commercial deployment of a portfolio of advanced coal-power systems. Our analysis of financial incentives for commercial deployment was sponsored by "CoalFleet" and EPRI.
For high-grade bituminous coals, integrated gasification combined-cycle (IGCC) plants offer significant advantages. By mixing the coal with steam and oxygen under high temperature and pressure, IGCC produces a combustible gaseous mixture called syngas, made up primarily of carbon monoxide and hydrogen. The clean-burning syngas is first consumed as fuel in a combustion turbine, then the hot exhaust from this turbine is used to produce steam that drives a steam turbine. Such a combined cycle provides very high levels of energy efficiency and the existence of a separate stream of syngas offers additional opportunities for producing hydrogen or capturing carbon dioxide. Existing IGCC systems can achieve thermal efficiencies of about 39 to 41 percent, with further advances in gas-turbine technology expected to raise this level to 45 to 50 percent. By comparison, the average efficiency of today's fleet of pulverized coal plants is about 33 percent.
For lower-ranked fuels, such as subbituminous coal or lignite, a variety of clean-coal technologies may prove to be important. For several IGCC implementations, other clean-coal technologies involving direct improvements in the combustion process currently appear to be more cost-effective. Ultra-supercritical (USC) pulverized coal (PC) plants, for example, are being developed to operate with steam temperatures and pressures high enough to achieve plant efficiencies of 45 percent. USC plants are approaching commercial maturity in Japan and parts of Europe where high fuel prices place a premium on efficiency. Projections based upon at least one IGCC process suggest that IGCC also may be competitive for the subbituminous coals. It clearly is an area of intense interest. DOE recently granted $200 million to a Southern Co. IGCC project that will use Powder River Basin coal. For large-scale plants burning very low-grade fuels, another technology, based on circulating fluidized bed combustion, may provide a high-performance, cost-effective option.
Need for Financial Incentives
Our initial analyses of possible financial incentives to stimulate deployment of commercial clean-coal power plants have focused on IGCC. Already there are four IGCC demonstration power projects built with partial government funding, as well as numerous smaller industrial coal-gasification facilities around the world, used mainly to produce chemical feedstock. In addition to having very low emissions of air pollutants such as sulfur, particulates, and mercury, IGCC also offers a carbon capture potential that could provide a useful hedge against future limitations on carbon-dioxide emissions. In this case, the syngas is mixed with steam to create relatively pure streams of hydrogen and carbon dioxide, allowing the latter to be captured and sequestered in geologic formations, rather than being released into the atmosphere as a greenhouse gas.
Despite these significant technological advantages, IGCC power plants have not yet been built without government financial assistance. The two primary factors are higher initial capital costs compared with conventional coal plants, and costs associated with technological risks that might impact the reliability and availability of IGCC plants. According to EPRI data, the capital cost of an IGCC unit, in terms of dollars per kilowatt of generating capacity, is about 14 percent higher than a comparable pulverized coal unit. This accounts for about half of the cost-of-electricity (COE) gap between the two technologies, measured in dollars per megawatt-hour of electrical energy produced.
The other half is the risk premium imposed by the financial community to finance an IGCC power plant, based on concern that the plant's capacity factor-i.e., the proportion of time it is running at full power-would be less than a conventional plant. Such concern is based in part on problems encountered at IGCC demonstration facilities, but also because experience at commercial-scale plants is still very limited. Vendors are working hard today to address those issues related to technology costs and risks, but the risk premium likely will remain until there is more commercial-scale experience. For purposes of analysis, we assume the risk premium reflects a 78 percent capacity factor for an IGCC plant over a 30-year period, compared with 88 percent if, after initial ramp up, the plant operated as designed.
Table 1 shows the resulting COE gap for three classes of owners. For all classes of owners, assured market recovery, either regulatory or through long-term power purchase agreement, is necessary to gain financing. Our cost calculations assume that these market risks have been addressed.
As indicated by the table, the COE gap differs considerably by ownership for a number of reasons. First is the debt structure and cost of capital. Based on typical industry practices, an investor-owned utility (IOU) is assumed to use corporate financing with 55 percent debt at 6.5 percent interest, compared with an independent power producer (IPP) that has 70 percent debt financing at 8 percent interest, because of the need to provide higher return on capital. Public power entities and cooperatives are assumed to use 100 percent debt financing at 4.5 percent interest, because interest on their debt is not taxable. In addition, the IOU and IPP are assumed to pay both federal and state taxes at a combined rate of 39.2 percent, while the public/co-op owners are assumed to be tax exempt. Despite their differences, all three types of potential plant owners likely would estimate a PC plant to cost significantly less than an IGCC plant.
Incentive Options
We considered eight types of federally provided financial incentives in our analysis to help close this cost gap. Not surprisingly, based on the financing and tax differences described above, the impact of specific incentives varies considerably among owner classes. Indeed, we conclude that no single incentive examined will suffice to close the COE gap for any of the three types of owners.
Loan guarantees. This is often identified as an attractive option from the government's point of view because the impact on the federal budget is minimized, since no funds actually are spent unless the borrower defaults or incurs specific types of extraordinary expenses. While some prominent studies suggest that federal loan guarantees, combined with state regulations aimed at assuring cost recovery, would be sufficient to give IGCC power plants a significant cost advantage over PC plants, our estimated benefits to the three types of owners are much less. Assuming that such guarantees lower the interest rate for IOUs by 0.5 percent and for IPPs by 0.8 percent, we estimate the COE savings would be only $1.08/MWh and $1.80/MWh, respectively-far below the amount required to close the COE gap. In addition, loan guarantees would not help public/co-op owners at all. Direct loans. This case assumes the federal government loans plant owners 80 percent of the IGCC project cost at the same interest rate as a 30-year Treasury bond, effectively reducing the rate for an IOU by 1.5 percent and for an IPP by 3 percent. Of the financing options examined, direct loans provide by far the most value to IPPs, reducing the COE gap by $6.76/MWh. Such loans could give IOUs a COE savings of $3.24/MWh and have no effect on public/co-op owners. Federal cost sharing. Our base case assumes that the federal government would share 10 percent of the cost of a new IGCC plant, with funding made available during construction and not requiring payback. This is the best option for the public/co-op sector, reducing its COE gap by $1.54/MWh. IOUs save $2.08/MWh and IPPs save $2.17/MWh. Investment-tax credit. This credit also is assumed to cover 10 percent of the plant cost, but would become available only at plant startup. Public/co-op owners would not benefit, while IOUs and IPPs would receive only marginally higher savings than in the case of cost sharing-$2.29/MWh and $2.37/MWh, respectively. Production-tax credit. Assuming a $9/MWh tax credit for the first 10 years of plant operation, this option is the most attractive for IOUs, with a COE savings of $4.24/MWh, compared with $4.23/MWh for IPPs. (Since IOUs have access to lower interest rates already, they do not benefit as much as IPPs from incentives that affect capital costs; but since they pay comparable taxes as IPPs, once plant operations begin, they receive almost exactly the same benefit from a production tax credit.) Public/co-op owners receive no benefit. Tax-exempt financing. Such financing reduces the interest rate demanded by lenders and is applied to outstanding bonds during both construction and operation. Tax-exempt financing benefits IPPs somewhat more than a production-tax credit, with COE savings of $4.85, but provides sharply lower benefits, $2.97/MWh, for IOUs and none for the already tax-exempt utilities. Accelerated depreciation. By reducing the recovery period for depreciation, this option enables a plant owner to realize the tax deduction earlier-over a 5-year period instead of 20 years-in the case analyzed. IOUs and IPPs receive approximately the same benefits, $3.14/MWh and $3.33/MWh, respectively, with no benefits for tax-exempt utilities. Availability insurance. This new concept is meant to address the technology risk component of the COE by having the government provide insurance for shortfalls below a specified availability target. This option also has the advantage of providing roughly equivalent benefits to all three owner classes, with IOUs, IPPs, and public/co-op owners achieving COE savings of $0.90/MWh, $1.02/MWh, and $0.82/MWh, respectively. Although none of these figures comes close to covering the estimated cost of technology risk, availability insurance may make a valuable contribution when combined with other incentives (as discussed below), or could be redefined to provide more value. The value of the various incentives to each type of plant owner is summarized in Table 2.
Clearly, no single incentive studied comes close to making IGCC competitive with PC for everybody, even with significant changes in base-case assumptions. However, the table does provide a basis for analyzing new individual incentive proposals or packages of incentive that could be tailored to close the COE gap for various classes of plant owners.
Combining Incentives To Close the COE Gap
Table 3 illustrates combinations of incentives that make IGCC essentially competitive with PC for one or more classes of owners. The first two apply only to taxable entities. Doubling the base-case investment tax credit from 10 to 20 percent and combining it with accelerated depreciation, for example, provides a COE savings of $7.72/MWh for IOUs and $7.06/MWh for IPPs, leaving only a small gap. Alternatively, doubling the production tax credit to $18/MWh-equal to that currently available for wind energy facilities-could give IGCC an advantage over PC for the taxable entities, with a value of $8.48/MWh for IOUs and $8.46 for IPPs.
The third package of incentives would triple the federal cost share to 30 percent without repayment and add availability insurance, providing public/co-op owners with enough value-$5.35/MWh-to make IGCC attractive compared with PC. The COE gap would not quite be closed for IOUs and IPPs (with respective savings of $6.75/MWh and $7.27/MWh) but the difference is small enough that other considerations might well determine their choice.
In the end, however, it must be remembered that any incentives such as those just discussed are intended only to get IGCC "over the hump" of initial commercial deployment. After that, the commercial attractiveness of this prototypical clean-coal technology will depend on a variety of other factors. Foremost among these will be resolution of the technical risks involved, specifically by showing that IGCC plants can achieve sufficiently high availability to compete with conventional coal plants. Initial capital costs also should decline as the infrastructure for building, maintaining, and utilizing IGCC facilities develops. Additional factors that may influence the long-term attractiveness of IGCC technology include the potential need to sequester carbon to mitigate global warming or to produce hydrogen for future fleets of fuel-cell vehicles. Because of this potential, the ultimate value of IGCC may be its importance as a hedging strategy-a way to keep using the nation's most abundant energy resource while providing options to deal with long-term environmental demands.
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