Tax Credit for Combined Heat and Power

The CCTI proposal would implement an 8-percent investment tax credit for qualified CHP systems. A qualified system must be placed in service between 2000 and 2002 and must be larger than 50 kilowatts. The proposed legislation would require that systems which currently have a tax life of 7 years or less adopt a tax life for depreciation purposes of 15 years. This requirement would reduce the effective tax credit to about 4 percent and, presumably, would exclude biomass-fired cogeneration from the pulp and paper industry. Additional conditions, which vary with system size, must also be met (Table 8).

Table 8. CCTI Requirements for Qualifying Combined Heat and Power Systems

34

*The minimum size requirement is 67 horsepower for mechanical systems. The 50-megawatt system size corresponds to 67,000 horsepower.

Source: U.S. Department of the Treasury, General Explanation of the Administration's Revenue Proposals (Washington, DC, February 1999), pp. 45-46.

The efficiency requirements ensure that qualifying systems genuinely produce both heat and power in substantial amounts. In contrast, cogeneration systems qualifying under the Public Utility Regulatory Policies Act of 1978 (PURPA) were only required to produce thermal output equal to 5 percent of useful energy output. As a result, much of the PURPA-induced cogeneration capacity added after 1978 was designed with minimal thermal output and relatively low overall efficiency. Such "nontraditional” cogeneration capacity, which represents approximately onehalf the total CHP in operation, generally provides little efficiency improvement over comparable systems (combinedcycle plants) installed by electric utilities.

The proposed tax credit for CHP systems is expected to have its primary impact on traditional cogeneration in the industrial sector, which is the focus of this analysis. There may be some impact on nontraditional or merchant plant facilities, but the CCTI system efficiency standard of 0.7 would exclude many CHP plants that are designed to maximize electrical output rather than total system efficiency. Because total system efficiency falls as the ratio of electrical output to useful thermal output increases, nontraditional CHP plants generally do not meet the system efficiency requirement to qualify for the tax credit. Traditional industrial cogeneration accounts for about 40 percent of total cogeneration capacity (Table 9). The remainder is in refining, oil and gas production, the commercial sector, and the nontraditional category.

Methodology

The effects of the proposed CHP tax credit were assessed by estimating the relationship between CHP project economics and market penetration, using a new methodology developed and implemented in the NEMS industrial module. Industrial CHP market penetration was estimated as a function of steam requirements by industry, existing CHP. CHP system costs and performance, and investment payback acceptance rates, providing a quantitative

34 This analysis did not address the likelihood of the successful demonstration and widespread adoption of black liquor gasification combined-cycle technologies, which could lead to such a large increase in self-generation that the industry would become a net seller of electricity after 2010.

Table 9. Components of Cogeneration Capacity in the Reference Case, 1999 and 2002

Source: Energy Information Administration, National Energy Modeling System run AEO99R.D033099A.

framework for evaluating the effect of policies to improve CHP economics, as well as the removal of barriers to CHP (such as high standby electricity rates imposed on CHP facilities by some electric utilities). The analysis was limited to an assessment of gas turbine CHP systems, which are well-suited for a wide range of applications and represent the predominant technology used for new CHP installations.35

The methodology was designed to determine the technical potential for CHP, evaluate its economic potential, and estimate annual capacity additions. The technical potential for CHP exists at facilities with significant thermal energy uses, generally in the form of process steam. Because steam is relatively expensive to transport, industrial CHP systems are typically sited at the facility where the thermal energy will be used. Electric power from CHP is most often applied to the facility's own uses, but it can also be supplied to the grid. Thus, the thermal needs of a facility. not necessarily its electric power needs, determine the technical potential for CHP.

The assessment of the potential for new CHP begins with an examination of the thermal requirements of industry and the amount of CHP, or cogeneration, already in place. Many of the best sites for cogeneration in the industrial sector currently are being used, and 35 to 40 percent of the steam used in the industrial sector is produced through cogeneration. Still, additional cogeneration could meet some portion of the remainder of the existing steam requirements, as well as any growth in steam requirements as industry expands. The incremental technical potential appears to be over 50 gigawatts,36 almost 40 percent of which arises in industries with relatively small thermal requirements, where the economic desirability of CHP systems is sharply reduced.

To estimate CHP growth, the potential thermal (stearn) capacity for new cogeneration was estimated under the assumption that cogeneration systems can replace or supplant existing boiler capacity to meet a portion of the steam load not already being met with CHP. The prototype CHP systems are assumed to be sized to meet a facility's average hourly steam loads (net of steam already being produced by CHP). In addition, the ratio of power to steam produced by typical cogeneration systems was used to estimate the corresponding electric generating capacity. Because the characteristics of cogeneration systems vary with size, the analysis accounted for several ranges of thermal output that candidate CHP systems would supply. The thermal requirements of each industry were divided among these thermal ranges, based on the size distribution of boiler capacity. For each thermal load range, one of five candidate CHP systems was selected as a prototype by matching the average hourly thermal requirement within the range.

35 Other analyses of CHP potential have assumed that most CHP additions will be gas-fired. See, for example, American Council for an Energy-Efficient Economy. Approaching the Kyoto Targets: Five Key Strategies for the U.S. (Washington, DC. August 1998), p. 28. 36Onsite Energy Corporation, "Basis for 60 GW of Remaining Cogeneration Potential in the Industrial Sector (May 1997).

37

The five prototype cogeneration systems were assumed to have the characteristics shown in Table 10, which were developed from information supplied by manufacturers, as well as several industry studies." Although the technical specifications are often available, the typical total costs of installed systems—about twice those for gas turbine generators—are not available. As summarized in one study: "Thus the installed cost of a gas turbine with an HRSG [heat recovery steam generator] can be estimated from the FOB price by multiplying this price by a factor of the order of 1.8-2.3.-38

Source: Energy Information Administration estimates based on information from Caterpillar, Allison Gas Turbines, and Centre for the Analysis and Dissemination of Energy Technology (CADDET): Gas-Turbine-Based CHP in Industry (1993) and Small-Scale Cogeneration (1995).

A prototype system for each thermal size range was evaluated as a discretionary investment opportunity, based on regional prices of natural gas and electricity. The evaluation estimated the payback period for a CHP investment. The payback estimates, together with the system size characteristics, were used to estimate market penetration. The total technical potential for CHP was calculated with the assumption that all the prototype systems would be installed, irrespective of economics. The economic potential, or the fraction of technical CHP potential that would be realized on the basis of relative economic attractiveness, was estimated from the payback periods. To estimate economic potential, an assumed quantitative relationship was formulated to describe the general notion that the shorter the payback period is, the greater is the likelihood that an investment will be undertaken. This assumed relationship, the "payback acceptance curve," quantifies the fraction of CHP investments that would occur for a given payback period. The midpoint on this "sliding scale" is 2.5 years, reflecting an assumption that half of all CHP technical opportunities with a payback period of 2.5 years would be adopted. For longer payback periods, a smaller fraction of the CHP opportunities would be adopted. For example, 10 percent of CHP opportunities with a 5-year payback period are assumed to be adopted. The assumed payback requirements are meant to reflect typical financial requirements, as well as some of the institutional and regulatory barriers that limit CHP market penetration. A study prepared for DOE Indicates that 21 percent of proposed cogeneration projects with a 3.3-year payback period have

The economic evaluation methodology draws heavily from two recent analyses of CHP from the Centre for the Analysis and Dissemination of Energy Technology (CADDET): Gas-Turbine-Based CHP in Industry (1993) and Small-Scale Cogeneration (1995). Some characteristics, such as heat rates of gas turbines, are based on data provided from Solar Turbines (owned by Caterpillar) and Allison Gas Turbines. *Centre for the Analysis and Dissemination of Energy Technology (CADDET), Gas-Turbine-Based CHP in Industry (1993), p. 45.

57-713 99-5

been implemented.39 The values assumed for the payback acceptance curve for industrial cogeneration are shown

in Table 11.

Table 11. Assumed Values for the CHP Investment Payback Acceptance Curve

Source: Energy Information Administration, Office of Integrated Analysis and Forecasting.

The market penetration of industrial CHP over the 2000 to 2002 period was estimated with and without the proposed 8-percent investment tax credit. The primary effect of the credit in the CCTI analysis case is to reduce the capital cost 40 of the cogeneration system, and thus the investment payback period, by 8 percent, thereby reducing a project's payback period and increasing the likelihood that the project will be undertaken. The result is higher overall economic potential and higher annual additions, as a greater share of candidate sites find CHP sufficiently attractive to invest in it. For CHP systems with a 7-year tax life, the effect of the tax credit is reduced by increasing the depreciation period that can be used for tax purposes to 15 years. For those companies with no current liability, the tax credit would have no impact.

Although a small amount of refinery CHP is projected to be induced by the tax credit, the impact is likely to be significantly attenuated by other capital demands that are being placed on the refining industry. Over the next few years, the refinery industry must make substantial capital investments to meet fuel quality and plant emissions requirements of the Clean Air Act Amendments and upcoming regulations." The most costly capital spending requirement for the industry is likely to be a restriction on the allowable sulfur content of all gasoline. The U.S. Environmental Protection Agency (EPA) has determined that reduced sulfur levels in gasoline are necessary to reduce vehicle emissions. 42 Thus, in early 1999, the EPA is expected to propose a reduction in the average allowable

*U.S. Department of Energy. Analysis of Energy-Efficiency Investment Decisions by Small and Medium-Sized Manufacturers, DOE/PO-0043 (Washington, DC, March 1996), Table 4-2. The same study reported that more than 40 percent of energy conservation projects with an immediate payback were not undertaken.

"The effective reduction in payback period is somewhat less than 8 percent. This results from the lower present value of depreciation allowances, since the depreciable basis is reduced by the amount of the credit.

41Investments should be nearing completion that will allow refineries to produce reformulated gasoline to meet reduced emissions requirements in January 2000. Capital investments may also be required to meet new standards that will reduce emissions of hazardous air pollutants (HAPS) from certain refinery units by 2002. In addition to these Federal requirements, separate gasoline requirements being adopted by States may require further investments. For instance, the State of Georgia has a requirement that the Atlanta area must use gasoline with reduced volatility and sulfur content. Upcoming rulemakings that would reduce the allowable sulfur content of gasoline and diesel are expected to require sizable investments. Further expenditures may also be required if concerns about methyl tertiary butyl ether (MTBE) contaminating water supplies lead to restrictions on its use as an oxygenate in gasoline.

U.S. Environmental protection Agency, Office of Mobile Sources, EPA Staff Paper on Gasoline Issues, EPA-420-R-98-005 (Washington, DC. May 1998).

sulfur content of gasoline to 30 parts per million (ppm)-down from the current average of 340 ppm.43 Although the exact level of sulfur reduction is unknown, refineries seem likely to shift planning and investment toward clean fuels, rather than CHP, in the face of mounting pressure from the EPA, environmentalists, and automobile manufacturers.

The oil and gas production industry is also unlikely to expand the use of CHP for enhanced oil recovery (EOR) within the 2000-2002 period. Current low crude oil prices would not support an increase in steam production from EOR development. About 20 percent of EOR capacity has been idled, and that capacity would be returned to service before new plants or additions were built. In this economic environment, an 8-percent tax credit for investment in CHP equipment is not likely to induce additional CHP for EOR steam production.

Results

In the reference case for this analysis,44 873 megawatts of new cogeneration capacity are projected to be added between 2000 and 2002 (Table 12). In the CCTI analysis case, an additional 190 megawatts of new CHP capacity is projected to be installed during the 3-year period. However, all the capacity projected to be added in the 20002002 period-1,064 megawatts-would qualify for the credit. If the average system capital cost were $1,000 per kilowatt, the total reduction in projected tax revenues would be $85 million. If capacity additions that would have occurred in the absence of the tax credit in 1999 or 2003 were moved to the 2000-2002 window, total additions

qualifying for the ITC would be 1,567 megawatts, bringing the total reduction in tax revenues to $125 million.46

Table 12. Projected Effects of the CCTI Tax Credit on Traditional Industrial Cogeneration, 2000-2002

Cumulative Capacity Additions in the Reference Case (Megawatts)
Incremental Capacity Additions in the CCTI Analysis Case (Megawatts)
Cumulative Capacity Additions in the CCTI Analysis Case (Megawatts)*
Reduction in Projected Tax Revenues (Million Dollars)

Net Carbon Reduction, 2002 (Million Metric Tons)..

873

190

1,064 to 1,567

85 to 125
0.150

*The range results from the possibility that currently planned additions will be moved from 1999 or 2003 to take advantage of the

CCTI tax credit.

Source: Energy Information Administration, National Energy Modeling System runs AE099R.D033099A and CCTITAX.D033099A.

The increased penetration of CHP is likely to reduce carbon emissions overall. Although an increase in CHP would increase total industrial fuel consumption, the resulting reduction in electricity purchases would displace fuel used by central power stations. With CHP, the incremental amount of fuel used to produce a unit of electricity is generally

Low-sulfur gasoline specifications will be implemented in NEMS when the regulations are finalized. EPA estimates that low-sulfur gasoline will cost 1 to 3 cents more per gallon. Because gasoline sulfur and automotive emissions are linked, the proposal will be issued in conjunction with the new "Tier 2" vehicle exhaust emissions standards, which would take effect between 2004 and 2007. Also expected in 1999 is a preliminary notice of proposed rulemaking that would reduce the sulfur content of diesel fuel to accommodate reductions in emissions of NO, and particulates.

"The reference case for this analysis differs slightly from the reference case used for the Annual Energy Outlook 1999. The difference reflects the revised methodology used to project cogeneration.

Note that this estimate does not include the "bunching effect" that could arise if projects that would have been undertaken without the credit in 1999 or 2003 were moved to the 2000-2002 window to take advantage of the tax credit.

By comparison, in "President Clinton's FY 2000 Climate Change Budget. p. 2, the Administration estimates that the credit will reduce tax revenues by $332 million. Assuming that the installed cost for CHP systems averages $1,000 per kilowatt, this implies that the Administration anticipates that qualifying CHP additions during the 3-year period will be 3.750 megawatts. It is not known what portion of the Administration's tax revenue reduction estimate is due to unintended beneficiaries.