Analysis of The Climate Change Technology Initiative

Report#:SR/OIAF/99-01

Introduction

The Administration's Climate Change Technology Initiative (CCTI) includes a number of proposed tax incentives that would provide tax credits for buildings, vehicles, industry, and renewable electricity generation. The purpose of the tax credits is to reduce the initial costs of more energy-efficient and renewable technologies for buildings, vehicles, and industry and provide tax incentives for the generation of electricity from renewable sources, thereby encouraging their adoption earlier than would otherwise occur. The tax credits are short-term incentives, lasting only a few years and extending no later than 2006; however, in addition to their short-term impacts, they are intended to stimulate the use of the technologies, lower costs, and establish a more mature market for them. The Administration estimates the combined revenue impact of the tax credits at $383 million in fiscal year 2000 and $3.6 billion from fiscal years 2000 through 2004.

In general, this analysis of the tax incentives used the National Energy Modeling System (NEMS),⁽⁸⁾ the Energy Information Administration (EIA) model of U.S. energy markets. To evaluate the tax credits for new energy-efficient homes, U.S. Department of Energy (DOE) building code and building simulation models were also used. The results of the analysis highlight the energy savings and reductions in carbon emissions for each of the tax credits, relative to a reference case based on the Annual Energy Outlook 1999 (AEO99),⁽⁹⁾ published in December 1998. Where possible, an estimate of the tax revenue implications is also provided and compared to the Administration estimates.

Some past tax incentives have been able to accelerate substantially the introduction of new technologies into the market. For example, natural gas production from coal seams has grown dramatically since the late 1980s, largely because of tax credits that provide an incentive for the production of high-cost gas supplies. Other tax credits have had little impact, including the current biomass tax credit and the solar tax credit, which was enacted in 1978 and expired in 1985.

Important factors in the success of tax incentives include the timing and magnitude of the credits. Compared to some earlier tax credits, including the 40-percent solar tax credit, the incentives currently proposed are of small to modest magnitude and of relatively short duration. Other factors include the definition of qualifying entities and the different incentives provided by investment and production tax credits. Investment tax credits provide a return to the investor at the time a capital investment is made, while production tax credits provide a return during the life of the credit.

It is likely that some of the technologies targeted in the CCTI would penetrate to some degree even in the absence of the proposed tax credits; however, those units would receive the tax credit as well as the marginal units that would come on line purely as a result of the credit. Estimates of the magnitude of such unintended benefits are also provided. Another unintended result of the tax credits may be a tendency on the part of purchasers to either delay or accelerate investments in order to receive the credits, an effect that cannot be quantified. An additional unintended effect of an investment tax credit is that part of the value of the credit accrues to equipment manufacturers and suppliers. The credit increases the demand for capital equipment, leading to higher equilibrium prices for the equipment. As a result, as much as 70 percent of the tax credit could be passed to equipment suppliers in the form of higher equipment prices.⁽¹⁰⁾ If this situation were to occur, the impact of a tax credit on capital equipment additions could be quite modest. This effect has not been incorporated in the analysis.

Buildings

The Clinton Administration's proposed budget for fiscal year 2000 includes a package of proposals aimed at promoting energy efficiency and improving the environment. The CCTI package would provide $2.1 billion in targeted tax incentives over 5 years for consumers who purchase energy-efficient products and energy from renewable sources for use in buildings. By offering consumers price reductions on energy-efficient products through reductions in their Federal taxes, the CCTI initiatives are intended to increase demand for the products and, thereby, increase economies of scale in the production process, reduce production and retail costs, and develop a more robust market for the products. The CCTI package also includes $273 million in investments for research, development, and deployment of clean technologies for residential and commercial buildings in fiscal year 2000 (see Chapter 3).

The proposed CCTI tax credits provide incentives for the purchase of more efficient equipment and structures by offering income tax credits for the year in which the equipment or structure was purchased. The Administration estimates reductions in tax revenues of $2.1 billion from fiscal year 2000 through fiscal year 2006 as a result of the proposed initiatives for the buildings sectors. Specific estimates include $1.5 billion in tax incentives for energy-efficient equipment, $429 million for the purchase of new energy-efficient homes, and $132 million for rooftop solar systems.

The EIA has conducted an analysis of the CCTI tax incentive proposals that have the potential to affect levels of energy use and carbon emissions in the buildings sectors. Estimates of the projected impacts were developed by comparing the results from a reference case with results from an analysis case incorporating the proposed tax initiatives. Energy consumption and energy-related carbon emissions were the only effects considered. The reference case included efficiency and price improvements expected under current policy and market conditions. The residential and commercial demand modules of NEMS were used to model the CCTI proposals that could be explicitly represented (tax credits for energy-efficient equipment in existing homes and buildings and tax credits for rooftop solar systems). An off-line analysis using DOE building simulation models and payback analyses was employed to evaluate the potential impacts of the proposed tax credits for energy-efficient new homes. Estimates were developed considering only the buildings sectors, with no analysis of possible feedback effects from other sectors of the economy.

Tax Credits for Energy-Efficient Building Equipment

Background

A two-tier tax incentive program has been proposed to accelerate the development and distribution of energy-efficient technologies, generally providing a 10-percent credit for energy-efficient equipment purchased in 2000 and 2001 and a 20-percent credit for higher efficiency equipment purchased from 2000 through 2003. For example, a small commercial business that is planning to install a new cooling system in the year 2000 could receive either a 10-percent tax credit on the purchase price of a residential-type central air conditioner with a cooling efficiency of 13.5 SEER (Seasonal Energy Efficiency Factor) or a 20-percent tax credit for a central air conditioner with a cooling efficiency of 15 SEER. The specific technologies, requirements for eligibility, and applicable credits of the tax incentive program are shown in Table 1.

The tax credit is a percentage of the purchase price not exceeding a specified price limit. The purchase prices of the technologies included in the CCTI proposal are such that, in some instances, the tax credit does not exceed the cap. Table 2 illustrates this point by providing the costs and possible tax credits for equipment of the efficiency levels specified in the proposal. Also provided in Table 2, for comparison purposes, is the cost of the equipment that just meets the current energy efficiency standards and thus would receive no tax credit.

In the NEMS residential and commercial modules, the income tax credit is represented as a direct offset to the cost of the equipment. The costs for each of the affected technologies are reduced only for the years specified in the budget language. Once the tax credit expires, it is no longer subtracted from the cost of the technology. Both the reference case and the CCTI analysis case incorporate cost declines for advanced technologies over time as producers gain experience. The size and duration of the credit in the CCTI case are not considered sufficient to alter the rate of the cost declines. The credit is also believed to be too small to affect general consumer behavior toward energy efficiency or to change the barriers to entry that exist in the marketplace. An example of this market phenomenon is the development of heat pump water heaters in the early 1980s. With the help of government and utility supports, sales of heat pump water heaters peaked at about 8,000 units in 1985. Even with continued utility support, however, the decline in real energy prices and uncertainties regarding the technology caused sales to slip to 2,000 units per year, where they have stabilized.⁽¹¹⁾ While innovative and aggressive marketing strategies by private firms and government information programs could enhance the effectiveness of the tax credits by increasing the exposure and consumer awareness of a given technology, the short lead time and limited duration of the proposed incentives make changes in consumer behavior unlikely.

It is clear from Table 2 that the tax credits offered would not significantly change the economics of the investment decision from the consumer's point of view. Historically, consumers have been unwilling to invest in energy-efficient equipment with long payback periods. Short tenancy rates, lack of information, the fact that builders (as opposed to consumers) generally purchase the energy-using equipment, and limited availability of investment funds are just some of the factors that tend to affect purchase decisions.

Most of the technologies included in the CCTI proposal currently retain very small market shares in the residential arena. Natural gas heat pump prices have been high and volatile due to low sales, which currently total under 6,000 units per year. A consortium of 120 gas utilities currently subsidizes the development of the York Triathlon gas heat pump in an effort to increase sales to a level at which economies of scale can reduce the installed cost.⁽¹²⁾ The tax credits offered for the purchase of this technology could increase sales somewhat; however, the cost--including the tax credit--is still almost double the cost of a traditional gas furnace/central air conditioner system. With energy prices expected to remain stable in real terms over time, it is unlikely that significant increases in the market penetration of gas heat pumps would occur without substantial subsidies or technological breakthroughs leading to large price reductions.

The only generating technology included in the CCTI tax incentive proposal for energy-efficient building equipment is the fuel cell. Currently, units sized for residential applications are in the prototype stage, with a projected commercialization date of 2001-2002. There is only one manufacturer of fuel cells for commercial-sized units. The current cost for a commercial-sized fuel cell is about $3,000 per kilowatt of capacity; the CCTI tax credit would reduce the cost to $2,500 per kilowatt.⁽¹³⁾ As an example, assume that a commercial business purchases a fuel cell system, the tax credit is taken, and the cost of the fuel cell is financed at 9-percent interest for 7 years. Including the fuel savings that would result from using the heat produced by the fuel cell to satisfy the company's hot water needs in place of a natural-gas-fired water heater, the fuel cell could provide electricity for around 20 to 21 cents per kilowatthour, depending on regional natural gas prices. That cost is about three times the average U.S. commercial electricity price. Thus, a much larger incentive or a dramatic drop in fuel cell costs in the next few years would be required to spur adoption of this technology.⁽¹⁴⁾

Results

The analysis results indicate that the CCTI tax incentive proposal for energy-efficient building equipment could reduce projected carbon emissions by 1.5 million metric tons (0.3 percent) and buildings energy use by 26.8 trillion British thermal units (Btu)--0.1 percent of delivered energy--in 2005. Table 3 shows the savings in the CCTI analysis case relative to the reference case. The CCTI case includes the tax credits for all the technologies listed in Table 2.

Given the small increase in the projected market share for the technologies targeted by this tax credit proposal, it follows that a significant portion of the decreased tax revenues could result from tax credits received by consumers who would have purchased the equipment with no additional incentive. For example, sales of all natural gas heat pumps would be eligible for the tax credit, and with sales currently totaling 5,500 units per year, $5.5 million could be claimed by consumers who would have purchased the equipment absent any tax credit. In the years covered by the tax credit (2000-2003), the analysis indicates that a total of 36,444 natural gas heat pumps would be purchased in the reference case,⁽¹⁵⁾ and that an additional 25,119 units would be purchased because of the tax credit in the CCTI case. In the CCTI case, the Treasury would incur a total reduction of $61.6 million in projected tax revenues related to purchases of natural gas heat pumps. Of the $61.6 million, 60 percent of the tax credits paid would go to unintended beneficiaries.

Tax Credits for Energy-Efficient New Homes

Background

The following CCTI tax credits for energy-efficient new homes are proposed:

In calendar years 2000 and 2001, a credit of $1,000 for new homes that are at least 30 percent more efficient than the International Energy Conservation Code (IECC) (same as Energy Star Home)

In calendar years 2000 through 2002, a tax credit of $1,500 for new homes that are at least 40 percent more efficient than the IECC

In calendar years 2000 through 2004, a tax credit of $2,000 for new homes that are at least 50 percent more efficient than the IECC.

The IECC eligibility standard is an update to the more commonly referenced Model Energy Code (MEC), most recently issued in 1995. Given the similarities between the two codes and the data and software availability already established for MEC95, MEC95 was used as the basis for qualifying for the tax credits. Because there is some overlap between the equipment eligible for tax credits under the CCTI energy-efficient building equipment proposal and the eligibility requirements for the credit for energy-efficient homes, only one of the credits can be claimed for a given structure.⁽¹⁶⁾ It is not clear how the energy savings would be certified to assure that the requirements of the tax credit were met.

Given the intricate interactions between building shell measures, equipment measures, building orientation and shading, and equipment sizing, it is difficult for any estimate to incorporate all the potential effects included in designing and building a home. The NEMS residential model is not a building simulation model and therefore cannot handle all the different aspects and interactions of building systems. In order to give some perspective on the magnitude and potential impacts that the CCTI tax incentive might have, an offline analysis was completed using a building simulation model (PEAR),⁽¹⁷⁾ the MECcheck software,⁽¹⁸⁾ and a cash flow/payback model. When the three models are used in concert, energy savings, code compliance, and investment information can be determined. Although the models estimate energy savings and code compliance, they do not address all issues associated with the energy efficiency aspects of new home construction. The software used for this analysis, although possibly not the state of the art, was readily available, and analysts were familiar with its use.⁽¹⁹⁾

Even with the use of very detailed building simulation models, there are several limitations of note regarding this analysis. The MECcheck and PEAR programs do not include a number of options that may affect the costs of meeting the qualifications for the tax incentives. The software does not allow for orientation properties, which allow builders to minimize sun exposure in the summer and maximize it in the winter. There is no credit for downsizing the heating and cooling equipment, which allows builders to install smaller, less costly units when a tighter building envelope is in place. There is no accounting for more efficient ventilation systems (e.g., tighter duct work), and only conventional building materials are considered. In addition, there is no unique solution for achieving an energy savings target. To the extent that some of these options can be and are used to meet the CCTI efficiency level requirements, their omission in this analysis may cause higher estimated costs of meeting the program's requirements than if the options were included.

As of the end of 1998, 16 States had adopted MEC95 or better building codes,⁽²⁰⁾ and 36 States had adopted some form of the MEC or its equivalent.⁽²¹⁾ Implementation and enforcement of the code are difficult, and construction often is not compliant. Building codes in States without mandatory codes may be set on a county-specific basis, making estimates of an "average new home" building shell difficult. A somewhat different approach to increasing the building of energy-efficient homes is to offer the tax credit to the homebuilder, as opposed to the homeowner. If the credit were offered to the builder, more energy-efficient homes would be made available to prospective buyers, because the builders would receive an incentive to construct more energy-efficient homes. Currently, builders can recoup only the incremental cost of improving energy efficiency in the sales price of the home, because they do not receive the benefits of lower energy bills. To address this issue, Rep. William Thomas (R-CA) is preparing to introduce the Energy Efficient Affordable Home Act of 1999, which would enable the builders of energy-efficient homes to receive the $2,000 tax credit.⁽²²⁾ The CCTI tax credit would be available to homeowners only; however, given the restrictions on allowable tax credits, it is not clear whether all parties interested in receiving the tax credits could claim them.

For this analysis, two prototype houses were used as typical for two climate regions: north and south. Tables 4 and 5 detail the characteristics and costs of efficiency measures for each prototype and the expected tax credit. It is assumed that each percentage level specified in the tax credit proposal relates to energy savings relative to the MEC95 code for heating and cooling only. It is further assumed that the most efficient equipment is installed as a means to meet the credit, because it is generally the cheapest option per Btu saved.

Methodology and Results

MECcheck was used to establish the characteristics of a MEC95-compliant home, which were then input into PEAR, a building simulation model developed by DOE, to establish MEC95-compliant energy consumption for heating and cooling. The characteristics were then changed to achieve the levels of energy consumption specified in the tax credit proposal. The characteristics shown in Tables 4 and 5 are the results of this process. The costs associated with the efficiency improvements were then mapped to each particular characteristic. As noted above, the solutions given in the tables above are not necessarily unique, nor are they necessarily the least-cost options for obtaining the goal of the tax credit proposal. Furthermore, there is considerable uncertainty in the estimates of the costs of meeting the CCTI efficiency requirements. It is possible that, for some specific locations, costs could be much lower than portrayed here.

To determine the attractiveness of each investment, a spreadsheet model was developed using a cash flow and payback analysis as the means to evaluate the investment. The following assumptions were used in the analysis:

Homes receiving the tax credit were assumed to be mortgaged at 7.5 percent for 30 years, with a 10-percent down payment. Thus, if the incremental costs of the energy-efficient home were $2,500, an up-front cost of $250 would occur in the down payment, and mortgage payments would increase by $191 per year.

The penetration of energy-efficient homes was assumed to be a function of the number of years it would take to achieve a positive cumulative cash flow given the estimated costs and savings and assumed mortgage provisions. The concept of number of years to positive cash flow is similar to, but distinct from, the commonly computed simple payback period.

In the reference case, Energy Star homes are built at an increasing rate, with the starting point closely tied to recent results from the program.⁽²³⁾ For the years 2000 and 2001, during which a $1,000 tax credit applies, it was assumed that Energy Star homes would receive this credit. New homes achieving the 40- and 50-percent energy savings levels were assumed to reduce the baseline of Energy Star homes, which would not be eligible for the tax credits, by 50 percent after 2001. It was assumed that 50 percent of the new homes built in the reference case would be upgraded to receive the tax credit in the CCTI case. Although this is only an assumption, the incremental savings for upgrades to shell efficiency beyond the 30-percent level generally offer rapid returns with the tax credits in place, and some conversions should be expected.

In the first 3 years of the program, only homes achieving 30- and 40-percent savings over MEC95 would be built. In the last 2 years of the program, homes achieving 50-percent savings over MEC95 would be built. This assumption represents an increase in the efficiency of homes built as the program matures.

The results are as follows:

Approximately 222,000 additional energy-efficient homes would be built in the CCTI case during the 2000-2004 period. A total of just under 300,000 homes would receive tax credits averaging nearly $1,800. The total reduction in projected tax revenues would approach $540 million.

Given the length of time that buildings remain in the housing stock, most of the benefits of energy and carbon savings would continue for 50 years or more, although such long-term savings are not illustrated here.

Energy savings for electricity and natural gas and total reductions in carbon emissions would be as shown in Table 6.

Tax Credits for Rooftop Solar Equipment

Background

The CCTI tax incentive for rooftop solar equipment is aimed at encouraging individuals and businesses to adopt systems that provide heat and electricity without producing greenhouse gases. The credit, equal to 15 percent of the investment cost, applies to rooftop photovoltaic (PV) systems and solar water heating systems located on or adjacent to a building and used exclusively for purposes other than heating swimming pools. Solar water heating systems placed in service during the 5-year period from 2000 through 2004 are eligible up to a maximum credit of $1,000. Rooftop PV systems placed in service during the 7-year period from 2000 through 2006 are eligible for the 15-percent tax credit up to a maximum of $2,000.

Currently, a 10-percent business energy tax credit (BETC) is provided to private businesses for qualifying equipment that uses solar energy to generate electricity, to heat or cool, to provide hot water for use in a structure, or to provide solar process heat. The allowable tax credit for any one year is limited to $25,000 plus 25 percent of remaining taxes after the credit is taken. Credits not allowable in one year may be taken in other tax years. Equipment that uses both solar and non-solar energy must not use more than 25 percent of its total annual energy input from non-solar sources to qualify. Passive solar systems and those owned by public utilities are not eligible. Thus, commercial taxpayers would have to choose between the present tax credit and the proposed CCTI credit for each qualifying investment. For systems that qualify for both credits, only small systems would benefit more from the 15-percent CCTI proposal because of the $1,000 and $2,000 caps. The solar technology costs and tax credits used in the analysis of the proposed CCTI tax credit for rooftop solar systems are shown in Table 7.

Tax credits have been used in the past to create a niche market for solar water heaters. In the early 1980s, shipments of medium-temperature solar thermal collectors (the type used for water heaters) peaked at just under 12 million square feet (enough for roughly 300,000 units) per year. After the Federal 40-percent residential and 15-percent business energy tax credits expired at the end of 1985, shipments fell to less than 1 million square feet per year, and they have never recovered.⁽²⁴⁾ The business energy tax credit was reinstated at 15 percent for 1986 and phased down to 10 percent by 1992, with the Energy Policy Act of 1992 (EPACT) providing a permanent extension of the BETC.

The credit reinstatement and increasing oil prices after 1986 did not seem to create a rebound of the solar industry. Today, most solar collector shipments (85 percent) are used for heating swimming pool water, which is excluded from the tax credit. In 1997, EIA estimates that roughly 460,000 households (0.5 percent) used solar water heaters to provide some of the energy required to heat the annual load of hot water.⁽²⁵⁾ Currently, about 9 percent of solar thermal collector shipments are destined for the commercial sector. Only 0.5 percent of all solar thermal collector shipments purchased by the commercial sector are for uses other than heating swimming pools, even with the existing energy tax credit available.

Residential rooftop PV systems are uncommon. Some are used for remote power generation, where connection to the electrical grid would be prohibitively expensive. PV systems are also rare in the commercial sector, used primarily for power generation and communications.⁽²⁶⁾ The 10-percent BETC is generally not enough to make PV systems economically attractive to the commercial sector, where purchased electricity is readily available. There are Federal, State, and local programs and incentives to encourage use of solar technologies. Locally, under the PV Pioneer I program, the Sacramento Municipal Utility District (SMUD) has created a small market for solar photovoltaics by installing the equipment on residential rooftops for $4 per month for 10 years. The homeowner is, however, obligated to pay SMUD's current rate for electricity. Since 1993, more than 450 homes have participated in the program. SMUD has recently launched PV Pioneer II, which allows homeowners to purchase their own PV systems and participate in net metering, generating their own electricity at no cost and paying for the electricity needed from the electrical grid. Any excess electricity generated from the PV system is sold back to the grid for future credit.⁽²⁷⁾ With energy prices expected to remain stable in real terms, it is likely that substantial subsidization or technological breakthroughs leading to large price reductions would be required to foster increased penetration of residential PV systems.

The reference case for this analysis includes the current 10-percent BETC for both solar thermal water heaters and PV systems. Installations for DOE's Million Solar Roofs (MSR) program (see Chapter 3) are also included in the reference case. The analysis does not include consideration of any State or local incentives.

Results

A negligible change from reference case results was seen when the CCTI tax incentive for rooftop solar equipment was included in the NEMS residential and commercial modules. It should be noted that many of the units completed under the MSR program could be eligible for the solar tax credit. Approximately 400,000 units--of which 66,000 are included in the reference case--are planned to be constructed under the program from 2000 through 2004, the period for which revenue impacts are estimated.⁽²⁸⁾ Any such units qualified to receive the tax credits during this interval probably would be unintended beneficiaries, because the MSR program pre-dates the CCTI tax incentives. The proposed tax credit is modest in comparison with the 40-percent residential credit available in the past. Niche markets with local incentives in place and electricity rates much higher than the national average could create a situation in which the CCTI tax incentive would make solar technologies economically attractive; however, the Census Division resolution of NEMS dilutes the ability to capture such instances.

Industry

Background

The CCTI proposal includes a new investment tax credit for the installation of combined heat and power systems (CHP) that meet specified energy efficiency targets. The reduction in capital cost resulting from the tax credit is intended to induce additional investments in CHP. For this analysis, the NEMS industrial demand module was modified to estimate the likely incremental impacts of the CHP tax credit on energy consumption and carbon emissions. Other potential benefits of the CHP tax credit (such as reduction of other pollutants) were not analyzed.

This analysis did not address district energy systems. The NEMS commercial model incorporates consumption of district energy services, but central district energy plants are not modeled explicitly in NEMS. To the extent that district energy plants are owned by governmental entities, however, an investment tax credit is likely to have little impact on expanding district energy systems.⁽²⁹⁾ There are also significant lead times for site approval, construction, and operating permits for district energy systems.⁽³⁰⁾ These lead times could cause otherwise qualifying district energy systems to miss the tax credit window.

The analysis did not include the potential effects of removing institutional barriers to CHP and merchant power plants. Elimination or reduction of barriers due to, for example, standby rates, exit fees, establishing uniform interconnection standards, or reform of environmental permitting policies could lead to a substantially larger CHP increase than is likely with the CHP investment tax credit alone. The Administration currently has in place the CHP Challenge Program, which may address some of these barriers.⁽³¹⁾ One analysis has concluded that institutional barriers to CHP systems represent a significant impediment to greater deployment of the technology.⁽³²⁾ The study estimated that addressing four types of institutional barriers could lead to an additional 50 gigawatts of CHP by 2010. The specific measures advocated were expedited permitting for CHP systems; output-based air pollution regulations; removal of a variety of "utility-driven" barriers; and establishing a standard depreciation period of 7 years for all new CHP systems.

The analysis specifically did not include any existing, ongoing programs, such as Industries of the Future, the Advanced Turbine System Program, research and development programs, or voluntary programs. The likely energy impacts of those programs are regularly assessed by DOE and are not reviewed here.⁽³³⁾

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.⁽³⁴⁾ Additional conditions, which vary with system size, must also be met (Table 8).

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 one-half the total CHP in operation, generally provides little efficiency improvement over comparable systems (combined-cycle 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 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 (steam) 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.

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.⁽³⁷⁾ 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⁾

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 been implemented.⁽³⁹⁾ The values assumed for the payback acceptance curve for industrial cogeneration are shown in Table 11.

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 of the cogeneration system, and thus the investment payback period, by 8 percent,⁽⁴⁰⁾ 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.⁽⁴¹⁾ 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 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.⁽⁴⁵⁾ However, all the capacity projected to be added in the 2000-2002 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⁾

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 lower than for central power stations. Increased CHP reduces purchased power requirements and leads to lower emissions from central-station electricity producers. Because additional natural gas is required for CHP, higher site emissions result. The net carbon reduction is the difference between the reduced central-station emissions and the increased site emissions. For presentation purposes, the net change in carbon emissions is attributed to the industrial sector. The CCTI tax incentive has the potential to reduce carbon emissions by 0.15 million metric tons per year--less than 0.1 percent of the 512 million metric tons of industrial carbon emissions projected for 2002. There may, however, be additional reductions in other pollutants that would contribute to the environmental benefits of the projects.

The results presented above could be altered significantly if a variety of institutional barriers that impede CHP projects could be reduced. For example, EPA has encouraged States to provide CHP plants with set-aside allowances in their proposed NO_x trading program.⁽⁴⁷⁾ One result of reduced institutional impediments could be a greater willingness to invest in CHP projects with longer payback periods, because the required payback period incorporates the potential for unforeseen complications and delays due to existing institutional arrangements, as well as the strictly financial aspects of a project. To assess the effects of this possibility, a sensitivity analysis was conducted assuming that a much longer (approximately doubled) payback period would be acceptable. The sensitivity analysis indicated that as much as 645 megawatts of additional new CHP capacity could be induced. In this situation, net carbon reductions of 0.5 million metric tons could occur.

The cost of the CHP tax incentive program would be higher if nontraditional cogenerators (merchant plants) were able to qualify for the credit. Nontraditional cogenerators are facilities built mainly to sell power. Because their production of useful thermal energy is typically small relative to their power output, the total system efficiency of merchant units is below the minimum threshold specified in the CCTI proposal. In NEMS, merchant facilities are treated as simple electricity power plants rather than as cogenerators; however, they could have a more significant impact if some regulatory burdens and uncertainties were reduced. For example, establishing a uniform interconnection standard could lead to more additions of merchant power plant capacity, as well as more traditional cogeneration capacity.

Because the proposed investment tax credit would expire in 2002, no additional induced change is projected after 2002. It is possible, however, that a "momentum" effect could lead to some additional inducement even after the tax credits expire (Table 13). In 2010, carbon emissions are projected to be 0.15 million metric tons (less than 0.1 percent) lower than in the reference case.

Finally, the analysis indicates that there could be a high ratio of unintended beneficiaries for this program. The projected ratio of unintended beneficiaries (capacity that would be added in the absence of the credit) to induced capacity additions is more than 4 to 1, in part because of the short time frame for the proposed credit. It takes 18 to 36 months to plan, design, and install new CHP capacity and perhaps much longer for district energy systems, and most of the facilities that would qualify for the credit would also be installed without it. Further, the proposed tax credit would shorten the payback period for investments in new CHP capacity by less than 3 months--a marginal benefit that is unlikely to affect the economic decision for most firms.

Transportation

Background

Sales of alternative-fuel vehicles (AFVs) and advanced vehicle technology (AVT) vehicles are expected to make up approximately 4 percent of all U.S. light-duty vehicle (LDV) sales in 1998.^(48),(49) More than 58 percent of those sales are alcohol flexible vehicles, which can run on any combination of alternative fuel and gasoline, and 41 percent are AFVs that use either compressed natural gas (CNG) or liquid petroleum gas (LPG). The remaining 1 percent are electric vehicles.

The electric vehicles currently available (Table 14) average 17 to 30 percent higher fuel efficiency than comparable conventional gasoline vehicles. Whereas conventional gasoline vehicles achieve only about 18 to 28 percent efficiency in combustion, electric vehicle motors have almost no loss in thermal efficiency. On the other hand, approximately 66 percent of the primary energy used to produce electricity is lost in production and transmission.

Hybrid electric vehicles are just beginning to enter the marketplace. For example, the Toyota Prius, scheduled for introduction in the U.S. market in 2000, uses a gasoline engine and regenerative braking to restore power to an electric battery that runs the vehicle motor. It has been advertised as having reached 66 miles per gallon (mpg) in the Japanese fuel efficiency test cycle, but in the U.S. Federal test procedure (FTP) cycle it has been rated at only 50 to 55 mpg.

Fuel cell vehicle technology is still in the early stages of development. Only a few test vehicles--buses in the Chicago Transit Authority fleet--have been sold, and some mechanical problems with those have been reported. Fuel cell vehicles have the potential to increase fuel economy relative to conventional gasoline vehicles by some 72 percent with gasoline as a fuel, 84 percent with methanol, and 100 percent with hydrogen.

Tax Credits for Electric, Electric Hybrid, and Fuel Cell Vehicles

The CCTI proposes the following tax initiatives for LDVs:

For qualifying electric and fuel cell vehicles, the current 10-percent tax credit, subject to a $4,000 cap, would be extended at its full level through 2006. The credit currently is scheduled to be phased down beginning in 2002 and eliminated by 2005.

For qualifying electric hybrid vehicles, graduated tax credits are proposed:

- $1,000 for each vehicle purchased after December 31, 2002, and before January 1, 2005, that is 33 percent higher in fuel efficiency than a comparable vehicle in its class

- $2,000 for each vehicle purchased after December 31, 2002, and before January 1, 2007, that is 66 percent higher in fuel efficiency than a comparable vehicle in its class

- $3,000 for each vehicle purchased after December 31, 2003, and before January 1, 2007, that is twice as high in fuel efficiency as a comparable vehicle in its class

- $4,000 for each vehicle purchased after December 31, 2003, and before January 1, 2007, that is three times as high in fuel efficiency as a comparable vehicle in its class.

In order for hybrid vehicles to qualify they must have regenerative braking and an energy storage system that will recover at least 60 percent of the energy used in braking from 70 to 0 mph.

All qualifying vehicles must meet or exceed all emissions requirements for gasoline vehicles.

Analytical Approach

The NEMS transportation module represents conventional gasoline vehicles (including direct injection gasoline technology and 58 other fuel-saving technologies), diesel turbo direct injection, alcohol (both methanol and ethanol) flexible fueled and dedicated vehicles, gaseous (both CNG and LPG) dedicated and bi-fuel vehicles, electric vehicles, electric hybrid (gasoline and diesel) vehicles, and fuel cell vehicles (methanol, hydrogen, and gasoline reformers). Each AFV/AVT technology is evaluated within each of the 12 EPA size classes for both cars and light trucks. For this analysis, the following consumer purchase criteria were evaluated:⁽⁵⁰⁾ (1) vehicle price, (2) cost of driving per mile (fuel price divided by fuel efficiency), (3) vehicle range, (4) top speed, (5) acceleration, (6) multiple fuel capability, (7) maintenance cost, (8) luggage space, and (9) fuel availability.

It was assumed that there would be no new requirements or additional costs for catalysts, engine design changes, or advanced reformulated fuels to meet EPA vehicle emissions standards. If stricter EPA standards are passed, they could lower the market penetration rates and carbon emissions reductions projected in this analysis.

The following assumptions were made in modeling the CCTI analysis case:

All electric vehicles and fuel cell vehicles were provided with a $4,000 vehicle price reduction relative to the reference case price through 2006. The date of commercial availability for fuel cell vehicles was changed from 2010 in the reference case to 2006.⁽⁵¹⁾

All electric hybrid vehicles were provided with the tax incentives specified in the CCTI proposal, based on the average fuel efficiency of a comparable gasoline vehicle in each EPA size class. Gasoline-electric hybrids were assumed to be commercially available by 2001 and diesel-electric hybrids by 2005 (both the same as in the reference case).

Results and Discussion

The results for the CCTI analysis case show an early increment in sales of electric vehicles--8,620 total sales in 2002, compared with 8,260 in the reference case. By 2010, however, the projected sales are approximately the same in the two cases at about 299,280 units (Table 15). Sales of fuel cell vehicles, which are assumed to be available at the very earliest by 2006, are projected to total approximately 870 units in 2006, rising to 4,630 in 2010 and 18,430 in 2020 in the CCTI case. Projected sales of hybrid vehicles--particularly, gasoline-electric hybrids--are significantly higher in both cases (at more than 871,000 vehicles) than are sales of either electric vehicles or fuel cell vehicles. Hybrids are anticipated to be available in U.S. markets by 2000, and the technology allows for vehicle characteristics that are similar to those of conventional gasoline vehicles--especially the most important consumer purchase criterion, vehicle price (see discussion below).⁽⁵²⁾

Total AFV/AVT sales in the CCTI case represent 6.2 percent of all LDV sales in 2010 (Table 15). Moreover, most of the projected sales also occur in the reference case. Because the proposed CCTI tax incentives would be in effect only through 2006, no significant additional accumulation of AFV/AVT vehicles is projected, even by 2010. Consequently, projected LDV fuel consumption in the CCTI case does not differ significantly from that in the reference case (Table 16). The difference in 2005 is less than 0.5 trillion Btu, consisting almost entirely of a reduction in gasoline consumption. The difference in 2010 is only 0.77 trillion Btu (0.002 percent of total transportation fuel consumption), and in 2020 it is just 0.71 trillion Btu. As a result, the reduction in projected carbon emissions from transportation energy use in the CCTI case relative to the reference case is only about 0.003 million metric tons in 2010-- representing just 0.0004 percent of total carbon emissions for the transportation sector (Table 17). In 2020, the CCTI case results in a reduction of 0.01 million metric tons of carbon.

Projected AFV/AVT vehicle sales and the corresponding reductions in Federal tax revenues in the CCTI analysis case are shown in Table 18. In 2003, the reduction in tax revenues totals just over $725 million, growing to $1.58 billion in 2005 and $1.75 billion in 2006. The total proposed allocation of Treasury funds for the CCTI tax incentives is $900 million for the years 2000 to 2004, as estimated by the Administration, compared to $1.96 billion in this analysis.

The results above suggest that the proposed CCTI tax initiatives for LDVs would not yield many additional AFV/AVT sales above those projected in the reference case. Consequently, most of the tax benefits would go toward consumer purchases that would have been made even without the proposed tax incentives (more than 98 percent of AFV/AFT sales in 2004)--because of the sales mandated by the Low Emission Vehicle Program in California, New York, and Massachusetts and those resulting from the tax incentives for electric and fuel cell vehicles in EPACT. The CCTI tax initiatives would, however, provide additional incentives for manufacturers to comply with the mandates of the Low Emission Vehicle Program. Additional benefits would result from a reduction in vehicle emissions of criteria pollutants other than carbon, because electric and fuel cell vehicles are zero emission vehicles.

Why are the projected effects of the CCTI tax incentive program for LDVs so marginal? The answer is suggested by an analysis of the barriers to AFV/AVT penetration of the U.S. LDV market. Again, the following criteria are likely to be considered by prospective purchasers: (1) vehicle price, (2) cost of driving, (3) vehicle range, (4), top speed, (5) acceleration, (6) multiple fuel capability, (7) maintenance cost, (8) luggage space, and (9) fuel availability.

The most important consideration in consumer purchase decisions is vehicle price. In the reference case, at low production volumes of approximately 2,500 vehicles per year, the price of an electric, hybrid, or fuel cell vehicle is approximately $10,000 higher than that of a comparable gasoline vehicle. And even at sales volumes approaching 25,000 units per year, the cost differential still would be about $7,000 for electric vehicles, $7,000 for hybrids, and $2,000 for fuel cell vehicles. Although the CCTI tax initiative would reduce the vehicle price, the effective reduction would amount to only about $4,000 off the reference case price of $10,000 for a compact fuel cell vehicle in 2005.^(53),(54)

In terms of driving costs, even with the lower vehicle prices at higher sales volumes, consumers may not receive sufficient payback through fuel savings to encourage AFV/AVT purchases if gasoline prices remain low.⁽⁵⁵⁾ Because 75 percent of the vehicles purchased in the United States are still on the road after 10 years, vehicle purchases generally are long-run decisions. The pattern of fuel prices over the recent past can be expected to raise doubts among consumers about the prospects for long-term increases in the future. Gasoline prices rose by 31.6 cents a gallon (in 1997 dollars) from 1973 to 1974, but by 1978 they were only 14.5 cents above 1973 levels. From 1978 to 1979, prices rose by 47.1 cents a gallon, only to fall below 1978 prices by 1983. Although consumers switched their purchasing patterns toward smaller cars and away from larger cars during the oil crises, those short-term fuel price spikes caused only short-run adjustments in vehicle purchasing patterns. Moreover, although AFV/AVT fuel economies (miles per gallon) are expected to be significantly higher than those of conventional gasoline vehicles, their driving costs per mile also are likely to remain significantly higher. As long as gasoline prices remain low, electricity will be a more expensive vehicle fuel. Hydrogen currently is more than twice as expensive as gasoline and, at any rate, is not available to the average consumer.

Vehicle range, top speed, and acceleration may also pose barriers to consumer acceptance. For example, electric vehicles can travel a maximum of one-fourth to one-sixth the distance that a conventional gasoline vehicle can travel before refueling. Top speeds generally are similar for the advanced technologies and gasoline vehicles, but all the new technologies have significant acceleration drawbacks that would require higher horsepower and larger engines to match the performance of conventional vehicles, which in turn would reduce their fuel economy.⁽⁵⁶⁾

After price, reliability or quality is often cited as the most important purchase criterion by consumers, who are wary of high maintenance costs. Unfortunately, the maintenance costs for AVT vehicles are virtually unknown. Mechanics are not currently being trained to repair and maintain the vehicles, and the availability and cost of replacement parts are uncertain. For present-day electric vehicles, which use lead-acid batteries, the batteries must be replaced approximately every 3 years at a cost of more than $10,000 for each replacement. Nickel-metal hydride batteries provide 50 percent greater vehicle ranges and last twice as long as lead-acid batteries, but they cost more than four times as much. Lithium-ion batteries can extend vehicle ranges to approximately three times those of lead-acid batteries and may not require replacement during the life of the vehicle, but their costs can be as much as 10 times that of a lead-acid battery.

Interior volume and luggage space are also of concern to potential purchasers, especially with regard to electric battery packs or fuel cell stacks, which may significantly reduce the interior volume. Electric vehicles are likely to be limited in availability to smaller vehicles, because the expense of batteries needed to power larger vehicles would be prohibitive. Two electric minivans are currently on the market (see Table 14), but their purchase price is approximately $100,000 per vehicle. Fuel cell vehicles, in contrast, may only be available in the larger size classes, because of the size and weight of the fuel cell stacks.

Finally, fuel availability is one of the most important barriers to AFV/AVT market penetration. Infrastructure problems are important issues for the production and distribution of both methanol and hydrogen fuel. Methanol refueling stations are sparsely scattered in most States, although more are available in California. Electricity is available in nearly all U.S. homes, but recharging stations are just beginning to appear. Moreover, the recharging time for most electric vehicles is between 3 and 8 hours.

In addition to the above concerns that are expected to dampen the enthusiasm of consumers for AFV/AVT purchases, emissions and environmental issues also pose significant hurdles for the new vehicle technologies. For example, electric vehicles are nearly emissions-free while in operation, but their ability to provide net emissions reductions depends on the primary energy source used to generate the electricity that fuels them. Coal-burning electricity generation provides few benefits relative to gasoline-burning vehicles. Still another environmental issue for electric vehicles is the potential impact of rapid production, elimination, and recycling of vehicle batteries on a large scale.

Emissions issues may also pose problems for diesel-electric hybrid vehicles. Advances in diesel technology have significantly reduced their noise and emissions of particulates, but high levels of nitric oxides and particulates may present significant health problems. EPA is currently revising its NO_x and particulate emissions standards as mandated by Congress under the Clean Air Act Amendments of 1990, and recent regulations passed by the California Air Resources Board are expected to eliminate diesel technologies from further consideration as solutions to higher fuel economy unless they use advanced catalysts and/or new types of low-sulfur or reformulated diesel fuel.

Advanced low-sulfur, low-benzene, and reformulated fuels in combination with advanced catalysts are currently being explored, and Fischer-Tropsch fuels (derived from refinery waste products and natural gas) also are potential candidates for use with advanced diesel technologies. Studies have shown that these advanced diesel fuels and derivatives can reduce both NO_x and particulate emissions by as much as 80 percent. At present, however, the fuels are not cost-competitive with either gasoline or diesel fuel.

Vehicle stock turnover is also very slow in the personal vehicle market, which accounts for the lack of fuel savings and carbon emissions reductions by 2010. Even 1 million vehicle sales amount to just 0.4 percent of the vehicle stock, which is projected to total some 230 million vehicles by 2010.

Renewable Electricity Generation

Background

The proposed CCTI tax initiatives include several provisions aimed at increasing the utilization of zero-carbon fuels, such as wind and biomass, in the generation of electricity. It is hoped that the programs will spur the development of zero-carbon generating technologies and lower their costs in the future. Such incentives for renewable fuels are not entirely new. EPACT (P.L. 102-486) established production incentives for new biomass and wind-powered generating facilities, but their impact has been fairly small.

EPACT provides qualifying new wind and biomass facilities with a 1.5-cent subsidy (adjusted for inflation since 1992) for each kilowatthour of electricity they produce during their first 10 years of operation. In effect, the subsidy reduces the per-kilowatthour cost of new wind plants by 20 to 25 percent and the per-kilowatthour cost of new biomass plants by 20 to 30 percent. To qualify, a new wind plant must have come on line between January 1, 1994, and June 30, 1999 (June 30, 2003, for those brought on by publicly owned entities). For qualifying biomass plants the beginning date is January 1, 1993. The program differs slightly for facilities built by private and public entities. For private companies, the subsidy is paid through a production tax credit (PTC), and biomass plants must be closed-loop facilities to qualify.⁽⁵⁷⁾ For public entities, the subsidy is paid by DOE through a renewable energy production incentive (REPI), and the definition of qualifying biomass facilities is much broader.

So far, the REPI and PTC have resulted in only limited additions of biomass and wind generating capacity. No biomass capacity has been built in response to the PTC, because technologies for closed-loop biomass are not yet commercially available. For wind, incentive programs other than the PTC appear to have contributed to the capacity builds during the EPACT PTC period (Table 19). Very little wind capacity was added during the early years of the PTC. Of the 886 megawatts⁽⁵⁸⁾ of new wind generating capacity either on line or expected before the expiration of the EPACT PTC in 1999, only 87 megawatts entered service before 1998, of which 31 megawatts are clearly associated with programs independent of the PTC. Of the remaining nearly 800 megawatts, 577 have been encouraged by other programs, principally State mandates, most of which began in 1998. For example, in Minnesota, Northern States Power is legislatively mandated to build 425 megawatts of new wind power, over 240 megawatts of which is expected to be added in 1998 and 1999. Only 223 megawatts of the capacity expected to be added over the 1998 to 1999 period appear to be coming on without a specific mandate. However, even these additions appear to have been influenced by additional factors, including testing, demonstration, and green power programs and other environmental initiatives. Further, the vast majority of the capacity, 602 megawatts, is expected to enter service in 1999, at the end of the PTC period. Some of this capacity probably would have been built in 2000 or later but is being brought on earlier to take advantage of the existing PTC.

Because so little capacity has been added, the revenue effects of the existing PTC and REPI programs are fairly limited. For wind power, PTC-related tax expenditures (tax revenues not received) through 1997 are estimated at less than $4 million, rising to $16.3 million in 1998. If the capacity expected to be added in 1999 is built before the expiration of the PTC, tax revenue reductions this year could rise to a maximum of $55.6 million. For biomass, Federal appropriations data indicate that REPI payments have been made to two biomass plants and eight landfill gas plants. REPI payments for biomass and landfill gas plants were $2.7 million in 1998.

Climate Change Technology Initiative

The CCTI extends the PTC for wind and biomass for 5 years, through June 30, 2004. In addition, the proposal would expand the types of plants qualifying for the biomass subsidy while slightly narrowing the types of plants qualifying for the wind subsidy. The definition of eligible biomass sources is broadened from only closed-loop biomass to include any solid, nonhazardous, cellulosic waste material that is segregated from other waste materials, and that is derived from the following forest-related sources: mill residues, pre-commercial thinnings, slash, and brush other than old growth timber. Also included would be pallets, crates and dunnage, trimmings, and agricultural byproducts or residues. In essence, this would expand the credit to those facilities that can use wood residues and wood wastes to generate electricity for sale to customers (self-generation does not qualify).

In addition to broadening the definition of eligible biomass, the proposal also provides a 1.0-cent PTC (adjusted for inflation from the 1999 base) for biomass that is co-fired in coal plants to produce electricity during the period July 1, 1999, through June 30, 2004. Unlike the PTC for new wind and biomass plants, the co-firing PTC does not continue for the first 10 years during which a plant co-fires but remains in effect only from 1999 through 2004. This credit would apply to all facilities that are co-firing biomass with coal, including those that are already doing so. For wind, although no final decisions have been made, it is currently believed that the repowering of existing capacity will be excluded from the PTC extension. Therefore, EIA has assumed that no additional existing wind generating capacity (beyond the 260 megawatts covered under current rulings) will receive credits for repowering.

Methodology

For this analysis, the PTC for wind and biomass was modeled in the NEMS electricity market and renewable fuels modules, with no feedback from other NEMS modules. Because the vast majority of biomass-based cogeneration is consumed on site, and therefore is not eligible for the credit, cogeneration was not considered in the analysis. In order to test the potential impacts of the CCTI, it was assumed that the PTC would be extended by 5 years, through 2004.

In the reference case for the analysis, the date of commercial availability for new biomass-fired units (expected to be integrated gasification combined-cycle facilities) was assumed to be 2005, past the period in which new units would qualify for the CCTI tax credit. A few biomass gasification demonstration units are expected to come on line over the next few years, but the technology is not expected to be commercially available until those units have gone through several years of testing. For the CCTI case, the 2005 commercial availability date was maintained, effectively limiting the facilities able to take advantage of the PTC to the expected demonstration units. Fuel inputs were also expanded to include currently available wood residues and waste in addition to dedicated energy crops, which are assumed not to be available until 2010. While it is plausible that the PTC could encourage the construction of some older, less efficient direct-fired biomass boiler units, that technology was not specifically modeled. It is believed that the relatively low efficiency of direct-fired units would make them economically unattractive.

The model was also modified in the CCTI case to allow coal plants to use biomass for a portion of their fuel if it was economical. It was assumed that a coal plant could use biomass to displace up to 4 percent of the coal it would normally use. Current research has shown that a typical coal-fired boiler can fire from 3 to 5 percent biomass without a costly retrofit. Coal plants can consume larger shares of biomass, perhaps as much as 10 to 15 percent of their fuel, if new fuel handling systems are added and boiler firing equipment is modified. Such modifications are expensive, however ($250 or more per kilowatt of capacity), and the short length of the PTC for biomass co-firing makes it unlikely that plant operators would be willing to make such investments.

An offline analysis was performed to match the availability of relatively low-cost biomass with the amount of coal capacity in a State. The maximum co-firing share allowed in any region was the minimum of the available low-cost biomass and the available coal capacity (assuming the use of 4 percent biomass) matched at the State level. Because there were States where the match was not good--large amounts of biomass but few coal plants, or many coal plants but little biomass--the maximum amount of coal that could be displaced by co-firing with biomass was determined to be 1.8 percent nationally. (For example, Oregon has a substantial amount of mill residues that could be used for co-firing in coal plants, but there is very little coal-fired capacity in the State.) Among the regions in the model, the share varied from 0 to 4 percent.

In addition, because there are factors that may constrain the development of a biomass co-firing market that are not represented in the biomass supply curves used, several other modifications were made. The biomass supply curves do not include the costs and time associated with things such as ensuring that an adequate fuel supply is available near a specific plant, testing the fuel to see if plant modifications are needed, designing and making plant modifications, applying for any licenses that are needed, and, potentially, getting air permit changes approved. In addition, because many coal plant operators are in the midst of making changes to comply with new environmental regulations and preparing for a restructured electricity market, they are reluctant to entertain other changes at this time. To reflect the impact of these factors, the co-firing shares were phased in over time, and a hurdle rate was added to the cost of biomass fuels. In the reference case, the co-firing shares were phased in between 1999 and 2015, and a hurdle rate of 1 cent per kilowatthour was assumed. In other words, for biomass fuel to be considered, it had to lower the operating costs of the plant by 1 cent per kilowatthour. In the CCTI co-firing case, the shares were phased in between 1999 and 2005, and the hurdle rate was assumed to start at 1 cent before declining to 0.1 cent by 2005. Essentially it was assumed that the availability of the biomass co-firing PTC would lead to faster development of the biomass co-firing fuel market and a reduction in the costs incurred in preparing to use the fuel.

Results

Biomass

As discussed in the methodology section, because new biomass gasification plants are not expected to be commercially available until 2005, the extension and broadening of the biomass PTC does not lead to more capacity being added solely on an economic basis (Table 20). However, the extension of the PTC may encourage additional demonstration efforts. In the reference case, 248 megawatts of testing and demonstration plants were assumed to come on line within the PTC period. In the CCTI case, an additional 30 megawatts of biomass gasification demonstration plants, bringing the total to 278 megawatts, are expected to be added from 1999 through 2004. The increase in biomass generation and reduction in carbon emissions because of the 30 additional megawatts added in the CCTI case are small. In 2010, the carbon savings amount to 0.4 million metric tons, less than 0.1 percent of total electricity carbon emissions. However, because the full 278 megawatts added are expected to take the tax credit, the tax consequences are larger. In 2010, if all the expected demonstration plants took advantage of the PTC, tax collections would be $23 million lower. Approximately 11 percent of the tax savings would go to the 30 megawatts induced by the program, and the remaining 89 percent would go to capacity expected to be built even without the program.

The results presented here hinge on the commercial availability of biomass gasification technology and the development of the needed biomass fuel supply within the PTC time frame. The near-term focus of the PTC will make this a challenge. Uncertainties regarding the development of biomass technology include availability and proximity of the biomass fuel supply; the economics, which are highly site specific; the potential of green power programs; and potential sulfur emissions, which have been reported for a Minnesota biomass plant that burns alfalfa.⁽⁵⁹⁾

The biomass co-firing provision of the CCTI has a more significant impact than the PTC for new plants; however, because the co-firing credit expires in 2004, the impact declines somewhat in the later years. In 2004, electricity generation from co-fired biomass is projected to be 18.6 billion kilowatthours in the CCTI case, about 3.4 times the reference case level (Table 21). As a result, total carbon emissions are 3 million metric tons lower in that year. The cost of the subsidy is estimated to be about $595 million in tax revenue reductions, with about 38 percent going to facilities that would have used biomass co-firing without the PTC.

It is assumed in this analysis that the PTC would encourage power plant operators and biomass fuel suppliers to overcome the hurdles that are keeping them from taking advantage of the low-cost supplies that appear to be available. For example, electricity producers might maintain their relationships with biomass fuel suppliers once the PTC has induced such purchases. A recent example of such a change is the use of low-sulfur subbituminous coal in boilers originally designed only for bituminous coal, encouraged by the sulfur emission reduction requirements of the Clean Air Act Amendments of 1990 (CAAA90). Before the CAAA90 requirements were implemented, it was believed that the plants could not burn subbituminous coal. After testing and minimal modification, however, use of subbituminous coal in such boilers expanded significantly.

For both biomass and wind (see below), the actual tax revenue losses may be less than estimated in the CCTI case even if all the projected new capacity enters service. To the extent that new generating capacity (1) is ineligible for the PTC because of minimum tax rules or other requirements effectively disallowing the benefits, (2) enters service later in its initial year or is delayed until a later year, or (3) performs below the 33-percent capacity factor assumed for new wind capacity or the 80-percent capacity factor assumed for new biomass capacity, the tax revenue reductions could be less than estimated here.

Wind

In the reference case, new wind generating capacity is expected to be built after 1999 despite the expiration of the EPACT PTC. In response to State mandates, renewable portfolio standards, and other requirements, 537 megawatts of new wind capacity is projected to be added from 2000 through 2004. No additional wind capacity is expected to be added in this period based solely on economics. Wind technology costs and performance are expected to improve, but they still are not expected to be competitive with new natural gas plants in most situations.

Extending the PTC through 2004 leads to only modest additions of new wind generating capacity beyond those projected in the reference case. In the CCTI case, U.S. wind generating capability is only 50 megawatts above reference case projections (Table 22). The minimal cost declines induced by the addition of this capacity result in little additional wind generating capacity after 2004 and only 10 megawatts more after 2010.

The tax revenue consequences of the CCTI are similarly modest for wind power when applied only to the CCTI-induced additional capacity, totaling only $2.6 million in 2005. The total tax revenue effects of the PTC extension are much greater, however, because the 537 megawatts of wind capacity expected to be added in the reference case can also take advantage of it. As a result, if all the eligible plants take advantage of the extended PTC, the cost could reach $28.9 million in 2005. Because little new wind capacity is expected to be encouraged by the extended PTC, carbon emissions are virtually unchanged, decreasing by less than 0.1 percent of electricity sector carbon emissions.

The PTC could indirectly lead to new capacity additions not captured in the results presented here. Just as the new wind plants added during the EPACT PTC time frame appear to have been encouraged by the combination of the PTC, State mandates, and other incentive programs, the combined stimulus could conceivably continue with the extension of the PTC. Without the PTC extension, the other incentive programs could be less successful. Conversely, green power programs and utility testing programs may grow if the PTC is extended. Some consumers may be willing to pay a small premium to purchase green power, including wind power, but if the PTC is not extended the premium required may exceed what they are willing to pay. Similarly, some power companies have been experimenting with new wind facilities to become familiar with the technology and test how they might use it within their systems. Their willingness to continue those efforts may grow if the PTC is extended.

Overall the impacts of the tax incentives for new wind and biomass generating technologies are expected to have very modest impacts. Their combined impact reduces carbon emissions by only 0.5 million tons (less than 0.1 percent of electricity sector carbon emissions) in 2010. In addition, they slightly reduce the costs of complying with SO₂ and O_x emission caps. While the production tax credits for these technologies do lower the costs faced by potential developers, they are not large enough to overcome the cost disadvantages they face. New gas-fired facilities (and new coal-fired facilities after 2015) are very economical, making it difficult for new wind and biomass plants to break into the market. Even though renewable technologies are improving, the falling costs and improving efficiencies of new fossil generating technologies continue to restrict their penetration in the market.

The story for biomass co-firing is somewhat different. Coal plants can burn small amounts of biomass without significant modifications. Thus, if low-cost biomass fuel can be found, collected, and delivered to the plant at reasonable costs, it may be economical. Data suggest that there is a relatively large amount of low-cost biomass available in the form of mill residues, urban wood waste, and site clearing residues. The production tax credit would be expected to encourage power plant operators or third-party developers to search out these supplies and develop collection and handling systems. In 2004, the biomass co-firing PTC is projected to lead to carbon emissions about 3 million tons (0.5 percent of total electricity sector carbon emissions) below the level projected in the reference case.

While these PTCs are not expected to spur a large increase in renewable power generation, there are other non-CCTI programs being considered that could have a bigger impact. For example, the Comprehensive Electricity Restructuring Act proposed by DOE in 1998 included a 5.5-percent renewable portfolio standard.⁽⁶⁰⁾ The AEO99 analysis of this proposal found that it could lead to an annual reduction in carbon emissions of 20 to 25 million metric tons during the 2010 to 2020 period, at a cost of about $1 per month for the average residential household.⁽⁶¹⁾

Conclusion

In general, the impacts of the proposed tax incentives in CCTI are relatively small. In 2004, the tax credits for the buildings, industrial, and transportation sectors are projected to reduce total primary energy consumption by 33.5 trillion Btu, or 0.03 percent, relative to the reference case projection of nearly 104 quadrillion Btu (Table 23). The impact in 2010 is 31.6 trillion Btu (0.03 percent). In the reference case, carbon emissions are projected to reach 1,659 million metric tons in 2004 and 1,790 million metric tons in 2010. These tax incentives lower the projected emissions by 1.9 million metric tons (0.11 percent) and 1.6 million metric tons (0.09 percent) in 2004 and 2010, respectively (Table 24). The wind and biomass generation tax incentives are projected to reduce fossil energy consumption for electricity generation by 129.8 trillion Btu in 2004 and by 71.9 trillion Btu in 2010, reducing carbon emissions by 2.9 million metric tons (0.17 percent) in 2004 and by 1.5 million metric tons (0.08 percent) in 2010.

In 2004, total carbon emissions are reduced by 4.8 million metric tons, or 0.29 percent, as a total of the individual impacts of the tax credits. The reduction reflects lower energy consumption and a shift in the mix of energy fuels. In 2010, the tax credits reduce carbon emissions by 3.1 million metric tons, or 0.17 percent of the reference case projection.

The impacts of the tax credits tend to increase from 2002 to 2004, because the more advanced technologies become available and gradually penetrate the market. Their impact is less beyond 2004 due to the buildings equipment and biomass co-firing tax credits. As the buildings equipment tax credits expire, the impact of the tax credits is reduced, because some of the new, more efficient equipment begins to be retired and is replaced by less efficient equipment. The more efficient equipment is no longer economical without the tax credit. The biomass co-firing tax credit expires in 2004, and its incremental impact is subsequently reduced. The co-firing credit is a production tax credit that leads to more generation from biomass in coal plants when it makes biomass fuel competitive with coal. Some other tax credits have a more sustained impacts as a result of earlier investments.

The investment tax credits lower the initial cost of purchasing more equipment; however, the tax credits do not appear to be of sufficient magnitude to overcome consumer reluctance to purchase more expensive equipment with long payback periods. Most consumers are willing to invest in more efficient, but more expensive, equipment only if the higher initial costs are offset by lower fuel expenditures within a period of several years. In the electricity generation sector, the production tax credits may affect some marginally competitive wind and biomass plants; however, new natural-gas-fired, combined-cycle plants generally retain an economic advantage. Also, the more flexible operation of natural-gas-fired generating facilities provides an advantage over wind generation. Higher prices for fossil fuels or higher demand growth could serve to make these technologies more economically attractive.

Tax credits of longer duration and/or higher value could also lead to more significant impacts by making the technologies more competitive. The timing and duration of the credits are critical. The CHP tax credit applies only to systems installed between 2000 and 2002. There is not much opportunity to take advantage of the credit, because 18 to 36 months are required to plan, design, and install new capacity. Biomass gasification is assumed to be commercially available in 2005, but the credit expires in 2004. Therefore, only demonstration biomass gasification plants and traditional biomass plants would receive the credit. Similarly, the fuel cell vehicle tax credit extends only through 2006, when EIA assumes that fuel cell vehicles will first become commercially available. This date was advanced from the reference case assumption of 2010 due to the tax credit.

Although tax credits have benefits in encouraging some incremental investments, there may be some unintended consequences. Some of the technologies covered by the credits would likely penetrate even without the credits, which can be seen by comparing the tax incentive case with the reference case. Those units would receive the tax credits in addition to those units added incrementally as a result of the credits. Such unintended beneficiaries may be a significant portion of the total units: as much as 98 percent for the transportation tax credits, nearly 90 percent for biomass generation, and about 80 percent for CHP. Another unintended result could be a shifting of planned investments to fall within the time period of the credits by purchasers either delaying until the credits begin or accelerating their investments.

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File last modified: April 14, 1999

URL: http://www.eia.doe.gov/oiaf/archive/climate99/tax.html

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