Incentives, Mandates, and
Government Programs for
Promoting Renewable Energy

by Mark Gielecki, Fred Mayes, and Lawrence Prete

Introduction

Over the years, incentives and mandates for renewable energy have been used to advance different energy policies, such as ensuring energy security or promoting environmentally benign energy sources. Renewable energy has beneficial attributes, such as low emissions and replenishable energy supply, that are not fully reflected in the market price. Accordingly, governments have used a variety of programs to promote renewable energy resources, technologies, and renewable-based transportation fuels. ⁽¹⁾ This paper discusses: (1) financial incentives and regulatory mandates used by Federal and State governments and Federal research and development (R&D), ^{(2), (3)} and (2) their effectiveness in promoting renewables.

A financial incentive is defined in this report as providing one or more of the following benefits:

• A transfer of economic resources by the Government to the buyer or seller of a good or service that has the effect of reducing the price paid, or, increasing the price received, respectively;



• Reducing the cost of production of the good or service; or,



• Creating or expanding a market for producers.

The intended effect of a financial incentive is to increase the production or consumption of the good or service over what it otherwise would have been without the incentive. Examples of financial incentives are: tax credits, production payments, trust funds, and low-cost loans. Research and development is included as a support program because its effect is to decrease cost, thus enhancing the commercial viability of the good(s) provided. ⁽⁴⁾

Regulatory mandates include both actions required by legislation and regulatory agencies (Federal or State). Examples of regulatory mandates are: requiring utilities to purchase power from nonutilities and requiring the incorporation of environmental impacts and other social costs in energy planning (full cost pricing). Another example is a requirement for a minimum percentage of generation from renewable energy sources (viz., a "renewable portfolio standard," or, RPS). Regulatory mandates and financial incentives can produce similar results, but regulatory mandates generally require no expenditures or loss of revenue by the Government.

It is very difficult to quantify total resource expenditures resulting from even just direct financial incentives, due to the large number of energy incentives that have been enacted over the past quarter of a century. ⁽⁵⁾ In addition, the resulting interactive effect of these incentives makes it extremely difficult to correlate the effect of any one incentive on a specific energy program or on the economy. A 1992 Energy Information Administration (EIA) report ⁽⁶⁾ estimated the annual cost for Federal energy subsidies in 1990 of between $5 billion and $10 billion. EIA recently updated certain portions of this study in order to update cost estimates for continuing subsidies and to provide cost estimates for new subsidies for primary energy sources only (i.e., excluding electricity). ⁽⁷⁾ This report estimated the value of Federal financial "interventions and subsidies" for renewable energy at $1.3 billion. Of this amount, $725 million represents the reduction in excise tax for alcohol motor fuels. ⁽⁸⁾

Whereas these EIA subsidy reports discussed the scope of Federal energy subsidies and attempted to measure the cost of all energy subsidies, this article differs from those studies in three ways. First, this article focuses on regulatory and legislative mandates, as well as, financial incentives and Federal R&D for renewable energy, including renewable transportation fuels. Federal R&D is included because its cost to the government is well measured by the Federal budget process, and R&D is integral to lowering costs and/or reducing the time it takes for renewable technologies to become commercially viable. Second, this article does not measure the total cost of incentives, though it does provide some measures related to incentive costs. Finally, this article provides an assessment of the aggregate impact of the various programs for promoting renewable energy.

Generally speaking, Government policies have goals, while incentives, mandates, and Government programs in support of those policies have more specifically stated objectives. One gauge of the effectiveness of these measures can be the progress made toward meeting objectives. The following criteria are used to evaluate the incentives, mandates, and programs discussed in this article:

• Growth in electric generating capacity using renewable resources
• Growth in electricity generation by renewable resources
• Growth in the production of ethanol fuels
• Reduction in cost of the renewable technology/or cost competitiveness in the market
• Cost to consumers
• Market sustainability of the renewable technologies.

Sustainability of the renewable technology in a competitive market is an ultimate long-term goal.

Federal Incentives, Mandates, and
Programs for Renewable Energy

In response to energy security concerns of the mid-1970s, President Carter signed into law the National Energy Act of 1978 (NEA), a compendium of five bills that sought to decrease the Nation's dependence on foreign oil and increase domestic energy conservation and efficiency. A major regulatory mandate that has encouraged renewable energy, the Public Utility Regulatory Policies Act of 1978 (PURPA), was established as a result of the NEA. Most of the remaining Federal renewable energy legislation enacted since the late 1970s are financial.

Regulatory Mandates

Public Utility Regulatory Policies Act of 1978

PURPA was the most significant section of the National Energy Act in fostering the development of facilities to generate electricity from renewable energy sources. ⁽⁹⁾ However, with the electric power industry challenging its legality and implementation issues, the broad application of PURPA did not occur until after the legality of PURPA was upheld in 1981. PURPA opened the door to competition in the U.S. electricity supply market by requiring utilities to buy electricity from qualifying facilities (QFs). QFs are defined as nonutility facilities that produce electric power using cogeneration technology, or power plants no greater than 80 megawatts of capacity ⁽¹⁰⁾ that use renewable energy sources. There is no size restriction for cogeneration plants; however, at least 5 percent of the energy output from a qualifying cogeneration facility must be dedicated to "useful" thermal applications.

Under PURPA, utilities are required to purchase electricity from QFs at the utilities' "avoided cost." ⁽¹¹⁾ The Federal government, in formulating regulations, often delegates implementation to the States. This occurred with PURPA, as the Federal Energy Regulatory Commission (FERC) delegated the authority for the determination of avoided cost to the States. In several States including California, avoided cost purchase contracts were very favorable to non-utility generators. For example, between 1982 and 1988, Standard Offer 4 (SO4) contracts written in California allowed QFs to sell renewable energy under 15-to-30 year terms. The contract guarantees fixed payment rates (based on forecasted short-run avoided costs) for up to 10 years if the QF has signed a contract for at least 20 years. After the 10 ^th year, energy prices moved to the short-run avoided cost of the purchasing utility. The 10-year provisions were tied to forecasts of increases in oil and gas prices, and were the basis for the fixed payments for the first ten years of the contracts. The forecasts were much higher than prices actually turned out to be. Therefore, a price and revenue drop occurred in the eleventh year when the fixed contract energy prices converted to variable prices (based on short-term avoided cost), greatly lessening the economic viability of affected projects.

Financial Incentives

The major Federal legislation on financial incentives for renewable energy and renewable transportation fuels has been structured as tax credits and  production incentive payments. (See Tables 1 and 2 for a summary of major Federal provisions that affect renewable energy and renewable-based transportation fuels, respectively.) For renewable energy, tax credits for purchases of renewable energy equipment were aimed at both the residential and business sectors. Accelerated depreciation of renewable energy equipment and production incentives were aimed at investors. From 1978 through 1998, similar types of tax credits have been in existence. Over time, the various laws have usually expanded the technologies covered, increased the credit amount, or extended the time period.

Two new types of financial incentives were introduced as part of the Energy Policy Act of 1992 (EPACT)--a production tax credit (PTC) and a renewable energy production incentive (REPI). The PTC is a 1.5 cents-per- kilowatthour (kWh) payment, payable for 10 years, to private investors as well as to investor-owned electric utilities for electricity from wind and closed-loop biomass facilities. The REPI provides a 1.5 cents-per- kWh incentive, subject to annual congressional appropriations, for generation from biomass (except municipal solid waste), geothermal (except dry steam), wind and solar from tax-exempt publicly owned utilities, local and county governments, and rural cooperatives.

For renewable transportation fuels, tax credits and tax exemptions are used to promote the use of renewable fuels, with the goal of displacing petroleum use in the transportation sector. There are four ⁽¹²⁾ Federal tax subsidies for the production and use of alcohol transportation fuels: (1) a 5.4-cents-per-gallon excise tax exemption, ⁽¹³⁾ (2) a 54-cents-per-gallon blender's tax credit, ⁽¹⁴⁾ (3) a 10-cents-per-gallon small ethanol production tax credit, ⁽¹⁵⁾ and (4) the alternative fuels production tax.

Table 1. Timeline - Major Tax Provisions Affecting Renewable Energy
1978	Energy Tax Act of 1978 (ETA) (P.L.95-618) Residential energy (income) tax credits for solar and wind energy equipment expenditures: 30 percent of the first $2,000 and 20 percent of the next $8,000. Business energy tax credit: 10 percent for investments in solar, wind, geothermal, and ocean thermal technologies; (in addition to standard 10 percent investment tax credit available on all types of equipment, except for property which also served as structural components, such as some types of solar collectors, e.g., roof panels). In sum, investors were eligible to receive income tax credits of up to 25 percent of the cost of the technology. Percentage depletion for geothermal deposits: depletion allowance rate of 22 percent for 1978-1980 and 15 percent after 1983.
1980	Crude Oil Windfall Profits Tax Act of 1980 (WPT) (P.L.96-223) Increased the ETA residential energy tax credits for solar, wind, and geothermal technologies from 30 percent to 40 percent of the first $10,000 in expenditures. Increased the ETA business energy tax credit for solar, wind, geothermal, and ocean thermal technologies from 10 percent to 15 percent, and extended the credits from December 1982 to December 1985. Expanded and liberalized the tax credit for equipment that either converted biomass into a synthetic fuel, burned the synthetic fuel, or used the biomass as a fuel. Allowed tax-exempt interest on industrial development bonds for the development of solid waste to energy (WTE) producing facilities, for hydroelectric facilities, and for facilities for producing renewable energy.
1981	Economic Recovery Tax Act of 1981 (ERTA) (P.L.97-34) Allowed accelerated depreciation of capital (five years for most renewable energy-related equipment), known as the Accelerated Cost Recovery System (ACRS); public utility property was not eligible. Provided for a 25 percent tax credit against the income tax for incremental expenditures on research and development (R&D).
1982	Tax Equity and Fiscal Responsibility Act of 1982 (TEFRA) (P.L.97-248) Canceled further accelerations in ACRS mandated by ERTA, and provided for a basis adjustment provision which reduced the cost basis for purposes of ACRS by the full amount of any regular tax credits, energy tax credit, rehabilitation tax credit.
1982-1985	Termination of Energy Tax Credits In December 1982, the 1978 ETA energy tax credits terminated for the following categories of non-renewable energy property: alternative energy property such as synfuels equipment and recycling equipment; equipment for producing gas from geopressurized brine; shale oil equipment; and cogeneration equipment. The remaining energy tax credits, extended by the WPT, terminated on December 31, 1985.
1986	Tax Reform Act of 1986 (P.L.99-514) Repealed the standard 10 percent investment tax credit. Eliminated the tax-free status of municipal solid waste (MSW) powerplants (WTE) financed with industrial development bonds, reduced accelerated depreciation, and eliminated the 10 percent tax credit (P.L.96-223). Extended the WPT business energy tax credit for solar property through 1988 at the rates of 15 percent for 1986, 12 percent for 1987, and 10 percent for 1988; for geothermal property through 1988 at the rates of 15 percent for 1986, and 10 percent for 1987 and 1988; for ocean thermal property through 1988 at the rate of 15 percent; and for biomass property through 1987 at the rates of 15 percent for 1986, and 10 percent for 1987. (The business energy tax credit for wind systems was not extended and, consequently, expired on December 31, 1985.) Public utility property became eligible for accelerated depreciation.
1992	Energy Policy Act of 1992 (EPACT) (P.L.102-486) Established a permanent 10 percent business energy tax credit for investments in solar and geothermal equipment. Established a 10-year, 1.5 cents per kilowatthour (kWh) production tax credit (PTC) for privately owned as well as investor-owned wind projects and biomass plants using dedicated crops (closed-loop) brought on-line between 1994 and 1993, respectively, and June 30, 1999. Instituted the Renewable Energy Production Incentive (REPI), which provides 1.5 cents per kWh incentive, subject to annual congressional appropriations (section 1212), for generation from biomass (except municipal solid waste), geothermal (except dry steam), wind and solar from tax exempt publicly owned utilities and rural cooperatives. Indefinitely extended the 10 percent business energy tax credit for solar and geothermal projects.
1999	Tax Relief Extension Act of 1999 (P.L. 106-170) Extends and modifies the production tax credit (PTC in EPACT) for electricity produced by wind and closed-loop biomass facilities. The tax credit is expanded to include poultry waste facilities, including those that are government-owned . All three types of facilities are qualified if placed in service before January 1, 2002. Poultry waste facilities must have been in service after 1999. A nonrefundable tax credit of 20 percent is available for incremental research expenses paid or incurred in a trade or business.
Notes: The residential energy credit provided a credit (offset) against tax due for a portion of taxpayer expenditures for energy conservation and renewable energy sources. The general business credit is a limited nonrefundable credit (offset) against income tax that is claimed after all other nonrefundable credits.

Table 2. Timeline - Major Tax Provisions Affecting Renewable Transportation Fuels
1978	Energy Tax Act of 1978 (ETA) (P.L.95-618) Excise tax exemption through 1984 for alcohol fuels (methanol and ethanol): exemption of 4 cents per gallon (the full value of the excise tax at that time) of the Federal excise tax on "gasohol" (gasoline or other motor fuels that were at least 10 percent alcohol (methanol and ethanol))
1980	Crude Oil Windfall Profits Tax Act of 1980 (WPT) (P.L.96-223) Extended the gasohol excise tax exemption from October 1, 1984, to December 31, 1992. Introduced the alternative fuels production tax credit. The credit of $3 per barrel equivalent is indexed to inflation using 1979 as the base year, and is applicable only if the real price of oil is bellow $27.50 per barrel. The credit is available for fuel produced and sold from facilities placed in service between 1979 and 1990. The fuel must be sold before 2001. Introduced the alcohol fuel blenders' tax credit; available to the blender in the case of blended fuels and to the user or retail seller in the case of straight alcohol fuels. This credit of 40 cents per gallon for alcohol of at least 190 proof and 45 cents per gallon for alcohol of at least 150 proof but less that 190 proof was available through December 31, 1992. Extended the ETA gasohol excise tax exemption through 1992. Tax-exempt interest on industrial development bonds for the development of alcohol fuels produced from biomass, solid waste to energy producing facilities, for hydroelectric facilities, and for facilities for producing renewable energy.
1982	Surface Transportation Assistance Act (STA) (P.L. 97-424) Raised the gasoline excise tax from 4 cents per gallon to 9 cents per gallon, and increased the ETA gasohol excise tax exemption from 4 cents per gallon to 5 cents per gallon. Provided a full excise tax exemption of 9 cents per gallon for "neat" alcohol fuels (fuels having an 85 percent or higher alcohol content).
1984	Deficit Reduction Act of 1984 (P.L.98-369) The STA excise tax exemption for gasohol was raised from 5 cents per gallon to 6 cents per gallon. Provided a new exemption of 4.5 cents per gallon for alcohol fuels derived from natural gas. The alcohol fuels "blenders" credit was increased from 40 cents to 60 cents per gallon of blend for 190 proof alcohol. The duty on alcohol imported for use as a fuel was increased from 50 cents to 60 cents per gallon
1986	Tax Reform Act of 1986 (P.L.99-514) Reduced the tax exemption for "neat" alcohol fuels (at least 85 percent alcohol) from 9 cents to 6 cents per gallon. Permitted alcohol imported from certain Caribbean countries to enter free of the 60 cents per gallon duty. Repealed the tax-exempt financing provision for alcohol-producing facilities.
1990	Omnibus Budget Reconciliation Act of 1990 (P.L. 101-508) Allows ethanol producers a 10 cent per gallon tax credit for up to 15 million gallons of ethanol produced annually. Reduced the STA gasohol excise tax exemption to 5.4 cents per gallon.
1992	Energy Policy Act of 1992 (EPACT) (P.L. 102-486) Provides: (1) a tax credit (variable by gross vehicle weight) for dedicated alcohol-fueled vehicles; (2) a limited tax credit for alcohol dual-fueled vehicles; and (3) a tax deduction for alcohol fuel dispensing equipment.
1998	Energy Conservation Reauthorization Act of 1998 (ECRA) (P.L. 105-388) Amended EPACT to include a credit program for biodiesel use by establishing Biodiesel Fuel Use Credits. An EPACT-covered fleet can receive one credit for each 450 gallons of neat (100 percent) biodiesel purchased for use in vehicles weighing in excess of 8500 lbs (gross vehicle weight (GVW)). One credit is equivalent to one alternative fueled vehicle (AFV) acquisition. To qualify for the credit, the biodiesel must be used in biodiesel blends containing at least 20 percent biodiesel (B20) by volume. If B20 is used, 2,250 gallons must be purchased to receive one credit. Transportation Equity Act for the 21st Century (TEA-21) (P.L. 105-178) Maintains, through 2000, the 5.4 cent per gallon (of gasoline) excise tax exemption for fuel ethanol set by the Omnibus Budget Reconciliation Act of 1990 (P.L. 101-508). Extends the benefits through September 30, 2007, and December 31, 2007, but cuts the ethanol excise tax exemption to 5.3, 5.2, and 5.1 cents for 2001-2002, 2003-2004, and 2005-2007, respectively, and the income tax credits by equivalent amounts. The exemption is eliminated entirely in 2008.

However, only the partial exemption from motor fuels excise tax is used to any extent. It is important to note that there are important financial incentive issues in the form of tax equity regarding all of the "alternate transportation fuels." However, only the alcohol fuels are renewable, so this paper is confined to those. The primary incentive is the ethanol excise tax exemption.

Research and Development

Government research and development (R&D), especially applied research, is considered a support program because, when successful, it reduces the capital and/or operating costs of new products or processes. Research and development comprises three components: basic research (original investigation in some area but with no specific commercial objective), applied research (investigation with a specific commercial objective in mind), and development (translating scientific discovery into commercial products or processes). ⁽¹⁶⁾

Figure 1. R&D Funding for Selected Renewable Energy Technologies (1999 Dollars)

The Department of Energy (DOE) applied research program for renewable energy is accomplished through the use of partnership programs. These programs, in which the Department acts primarily as a facilitator, have been a prominent part of renewables R&D funding since the mid-1980s. There are two funding components to this type of program: cost-sharing and in-kind contributions. Cost sharing refers to project funding contributions by all parties involved in the project. In-kind contributions refer primarily to, on the company side, the payment of salaries and the use of equipment and resources during the course of work on the project, and on the government side, the use of capital equipment, such as scientific and engineering equipment and facilities at DOE's national laboratories. (In the past, such programs have included a payback feature where the contractor repaid the government its original investment once the project became commercial and profitable.) In partnering programs, the Department also works with the ultimate product consumer to determine desired product characteristics and feeds this information back to its partner(s). For R&D projects, the private sector cost share is 20 percent. By comparison, demonstration projects require at least a 50 percent cost share by private firms. Figure 1 shows renewable energy R&D funding over time in 1999 dollars.

The DOE has consistently supported solar (including solar thermal, passive solar, and photovoltaic) R&D efforts at a higher level than other renewables. However, major new Presidential biofuels energy initiatives during the past 2 years have increased 1999 DOE R&D spending for biomass energy systems (including both electric and transportation applications) by 64 percent over its 1997 level. In 1999, more than 35 percent of biomass energy system R&D was directed toward ethanol. ⁽¹⁷⁾ Major areas being investigated are: advanced fermentation organisms, advanced cellulase (enzyme) development, integrating the various stages of cellulose to ethanol production, and support for cellulose to ethanol demonstration production facilities. ⁽¹⁸⁾ The principal method for achieving production increases is via leveraged partnerships with private ethanol producers.

Other Federal agencies have also contributed to renewable energy R&D efforts. The National Aeronautics and Space Administration (NASA) works on fuel cell research (in conjunction with DOE), solar energy applications in underdeveloped countries, and conducts modest studies on microwave energy from solar panels which would orbit the earth. The Department of Agriculture (USDA) has the Alternative Agricultural Research and Commercialization Corporation, a venture capital firm for alternate energy sources. USDA also joins effort with the Environmental Protection Agency to capture methane from lagoons to supply heat and power.

State Incentives, Mandates, and
Programs for Renewable Energy

Electric industry restructuring is the major issue affecting renewable energy at the State levels. In a few States, electric industry restructuring legislation supports renewable energy with financial incentives through funds from surcharges on electricity sales or renewable portfolio standards. ⁽¹⁹⁾ Most States provide for net metering. ⁽²⁰⁾ Even prior to electric restructuring legislation, many States had financial incentives for renewable energy. (A DOE-sponsored North Carolina State University website provides summary information, updated periodically, on State-level financial incentives, and regulatory programs and policies for renewable energy.) ⁽²¹⁾

State financial incentives include personal income tax credits and deductions for the purchase of various renewable-based technologies or alternative fuel vehicles; corporate income tax credits, exemptions, and deductions for investments in renewable technologies; sales tax exemptions on renewable equipment purchases; variable property tax exemptions on the value added by the renewable energy system; renewable technology and demonstration project grants; and special loan programs for renewable energy investments.

Some State incentives for renewable energy technologies overlap the Energy Policy Act of 1992 (EPACT) Production Tax Credit (PTC). When State and Federal incentives overlap, the PTC may or may not be reduced, depending on Internal Revenue Service rulings. In California, for example, wind projects canget renewable resource funds without jeopardizing eligibility for the PTC. In other cases, the PTC is reduced by the amount of the State incentive. ⁽²²⁾

While some ethanol-producing States do not subsidize ethanol, others offer tax incentives for gasoline blended with ethanol and for ethanol production, which vary from $0.10 to $0.40 per gallon.

California

Because of its long history of promoting renewable energy and the dominant position which the State holds in renewable energy production, ⁽²³⁾ this report examines renewable energy incentives promulgated by California. From about 1980 through 1983, California had a 25-percent tax credit for wind energy systems. Combined with Federal tax credits, the effective tax credit for wind plants during that time was nearly 50 percent. It is therefore hardly surprising that wind energy capacity  in California grew from 176 MW in 1982 to 1,015 MW in 1985. California also strongly supported renewables beginning in 1982 via pricing terms of the Standard Offer 4 contract mentioned earlier, which utilities were required to sign with qualifying facilities.

With the move toward deregulation and restructuring of the electric power industry, the California General Assembly passed a law in 1996, which on March 31, 1998, opened electricity markets to retail competition. Although California had previously been aggressive in promoting renewable energy, Assembly Bill (AB) 1890 enacted an entirely different approach. It established a new statewide renewables policy by providing $540 million collected from the State's three largest investor-owned utilities over 4 years starting in 1998 to support existing, new, and emerging renewable technologies to make the transition to a competitive market. The bill also allocates an additional $62.5 million for energy projects deemed to be in the "public interest."

After the California Energy Commission submitted its recommendations to the Legislature for allocating and distributing these funds ($540 million) in March 1997, the General Assembly enacted Senate Bill 90, which created a Renewable Resource Trust Fund containing four accounts: Existing Renewable Resources Account ($243 million), New Renewable Resources Account ($162 million), Emerging Renewable Resources Account ($54 million), and Customer-side Renewable Resources Account ($81million).

The program has a competitive bidding mechanism to reward the most cost-effective projects with a productionincentive for existing and new technologies. ⁽²⁴⁾ The funds are distributed by program type as follows:

• Existing technologies: funds are distributed differentially among three technology tiers (groupings) through a cents per kilowatthour production incentive, with a cap of 1.5 cents per kWh. Funds for existing technologies may decrease annually from January 1, 1998, to January 1, 2002, to increase funds for the development of new renewable technologies.



• New technologies: funds are distributed through a production incentive based on a competitive solicitation process, with a cap of 1.5 cents per kWh, to be paid over a 5-year period after a project begins generating electricity. The funds may increase annually from January 1, 1998, to January 1, 2002.



• Emerging technologies: funds are provided through rebates, buy-downs, or equivalent incentives to purchasers, lessees, lessors, or sellers of eligible electricity generation systems.



• Customer-side account: funds determined by dividing available funds by eligible renewable generation with a 1.5-cents-per-kWh cap, and for industrial customers a limit of $1,000 in rebates. The size of this account is fixed, so that as customer demand increases, the payment decreases; it is presently 1.0 cent per kWh.

By early July 1998, the new technologies auction received 56 bids representing nearly 600 megawatts of new renewable energy resources. All of the bids received amounted to a total of $182 million in incentive payments, $20 million more than the $162 million allocated in the renewable energy program for new generation. Bids were used to ensure a competitive, market-based, environment using a performance-based criterion. They were submitted on a cents per kWh basis for electricity production, not to exceed 1.5 cents. The renewable resource technologies determined eligible to receive funding at an average incentive of 1.2 cents per kWh include: wind, approximately 300 megawatts (also eligible for the PTC); geothermal, 157 megawatts; landfill gas, 70 megawatts; biomass, 12 megawatts; digester gas, 1 megawatt; and small hydro, 1 megawatt. The combined impact of all incentives (State and Federal) has assisted in bringing 290 MW of new or repowered wind capacity online in 1999. ⁽²⁵⁾ Thus, the incentives used in California have been successful in meeting the objective of increasing the number of renewable projects in the State.

A major characteristic responsible for this success is the incentive program's competitive bidding mechanism to reward the most cost-effective projects, using a production incentive rather than an investment tax credit.

Public Interest Energy Research Program (PIER) - Assembly Bill 1890 also requires that a minimum of $62.5 million in funds, collected annually from investor-owned utility ratepayers, be used for "public interest" energy research development and demonstration (RD&D) efforts that would not be provided adequately by either a competitive or regulated market. Senate Bill 90 required that the PIER portfolio include the following areas: renewable energy technologies; environmentally preferred advanced generation; energy-related environmental enhancements; end-use energy efficiency; andstrategic energy research.

Effectiveness of Incentives,
Mandates, and Government Programs

How effective have renewable energy incentives, mandates, and Federal and State programs been? It is virtually impossible to quantify the effect of any single action, because of the interdependence of many of the renewable energy programs in effect at any one time. Even the effects of straightforward incentives such as the Renewable Energy Production Incentives (REPI) are difficult to determine, because it is not known how much renewable generation would have been produced in the absence of REPI. Further, REPI itself may not have been sufficient to induce the renewable generation eligible for REPI payments, but rather a combination of REPI and other Federal and State incentives. Following is a discussion of the effectiveness of four Federal renewable energy support programs--PURPA, REPI, the Federal ethanol incentive program, and R&D funding. The characteristics of these programs and an assessment of whether they have proven effective in achieving the desired results are discussed.

PURPA

This assessment of the effectiveness of PURPA is actually an assessment of PURPA in combination with various tax incentives in place between 1978 and 1998. PURPA established a new class of generator, qualifying facilities (QF), that afforded cogenerators and certain renewable generators the opportunity to sell electricity to electric utilities at the utility's avoided cost rates. These facilities were also granted tax benefits described in Table 1, which lowered their overall costs.

PURPA's QF status applied to existing as well as new projects. Together, by year-end 1998, existing and new projects totaled 12,658 megawatts of  QF renewable capacity (Table 3). Of this, two-thirds (8,219 megawatts) of QF capacity was biomass. Some of these biomass QFs, however, were not "new" facilities, but rather had gone into commercial operation prior to PURPA. ⁽²⁶⁾ PURPA enabled these facilities to connect to the grid, if they chose to become QFs, and sell any generation beyond their own use at avoided cost rates.

Table 3. Nonutility Qualifying Facilities Using Renewable Resources as of December 31, 1998
Fuel Source	Nameplate Capacity (megawatts)	Gross Generation (thousand megawatthours)
Biomass	8,219	45,032
Geothermal	1,449	9,882
Hydroelectrica	1,263	5,756
Wind	1,373	2,568
Solar Thermal	340	876
Photovoltaic	14	11
Total Renewable QF	12,658	64,126
Total QF, All Sources	60,384	327,977
Total Nonutility, All Sources	98,085	421,364
aConventional; excludes pumped storage.    Notes: Totals may not equal sum of components due to independent rounding.    Source: Form EIA-860B, "Annual Electric Generator Report - Nonutility."

As stated in the Introduction, two of the criteria for evaluating the effectiveness of incentives and mandates such as PURPA are renewable capacity and generation growth. The EIA began collecting data from nonutility companies in 1989 (Table 4), 11 years after the passage of PURPA. However,  between 1989 and 1998, renewable capacity increased by 11.9 percent. At the national level, non-hydroelectric renewable generating capacity rose by 4,426 MW; the increase in hydroelectric capacity was 5,703 MW. Renewable generation rose by 22 percent (Table 5). Most of the increase in electricity generation from renewable energy is in the utility hydropower sector, including net imports. Nearly all of the increase in biomass, geothermal, solar, and wind generation occurred between 1989 and 1993. Non-hydro renewable generation, excluding imports, actually declined by more than 5 percent between 1993 and 1998, due primarily to California replacing Standard Offer 4 contract "avoided cost" provisions with competitive bidding mechanisms, and declining production at The Geysers geothermal plant. Also, in 1992, New York amended its Six-Cent Rule, which established a 6-cents-per-kilowatthour floor on avoided costs for projects less than 80 MW in size, such that it was not applicable to any future power purchase agreements. ⁽²⁷⁾

Table 4. U.S. Electric Power Sector Net Summer Capability, 1989-1998 (Megawatts)
Source	1989	1990	1991	1992	1993	1994	1995	1996	1997	1998
Hydroelectrica	74,587	73,964	76,179	74,773	77,405	78,042	78,563	76,437	79,788	79,573
Geothermal	2,603	2,669	2,632	2,910	2,978	3,006	2,968	2,893	2,853	2,917
Biomass	7,840	8,796	9,627	9,701	10,045	10,465	10,280	10,557	10,535	10,266
Solar/PV	264	339	323	339	340	333	333	333	334	365
Wind	1,697	1,911	1,975	1,823	1,813	1,745	1,731	1,678	1,579	1,698
Total Renewables	86,990	87,679	90,736	89,547	92,582	93,591	93,874	91,897	95,090	94,819
Non Renewables	637,275	647,241	649,741	657,016	662,373	670,423	675,643	683,975	683,412	681,065
Total	724,265	734,920	740,477	746,563	754,955	764,014	769,517	775,872	778,502	775,884
aConventional; excludes pumped storage.    Notes: Biomass capability does not include capability of plants where the Btu of the biomass consumed represents less than 50 percent of the Btu consumed from all energy sources. Totals may not equal sum of components due to independent rounding.    Sources: Energy Information Administration, Form EIA-860A, "Annual Electric Generator Report - Utility" and predecessor forms, and estimated data using Form EIA-860B, "Annual Electric Generator Report - Nonutility," and predecessor form.

Table 5. Electricity Generation From Renewable Energy by Energy Source, 1989-1998 (Thousand Kilowatthours)

Data on renewable capacity in California were available for years prior to 1989. These data, for 1980 through 1996 (Table 6), more clearly show the growth in renewable capacity owned by nonutilities since the passage of PURPA. Renewable-based nonutility capacity (excluding cogeneration) rose from 187 megawatts in 1980 to 3,777 megawatts (excluding small hydropower and cogeneration plants) in 1996.

Table 6. California Nonutility Power Plants Installed Capacity, 1980-1996  (Megawatts)
Year	Cogenerationa	Waste-to-Energyb	Geothermal	Small Hydro	Solar	Wind	Total
1980	227	14	0	0	0	173	414
1981	261	14	0	0	0	176	451
1982	412	32	0	48	1	176	669
1983	658	46	9	59	8	227	1,007
1984	893	79	96	67	27	496	1,658
1985	1,444	140	178	107	57	1,015	2,941
1986	1,788	275	188	144	122	1,235	3,752
1987	3,063	396	319	176	155	1,366	5,475
1988	3,662	513	587	229	221	1,378	6,590
1989	4,942	783	806	298	301	1,382	8,512
1990	5,315	878	870	321	381	1,647	9,412
1991	5,838	883	813	330	374	1,698	9,936
1992	5,684	804	831	371	408	1,729	9,827
1993	5,778	845	863	370	373	1,797	10,026
1994	5,857	795	863	410	373	1,629	9,927
1995	6,280	709	846	349	368	1,630	10,182
1996	6,177	823	885	362	360	1,709	10,316
aIncludes gas-fired facilities and biomass co-firing and cogeneration.    bWaste-to-Energy includes wood and wood waste, municipal solid waste, landfill gas, and other biomass. However, biomass co-firing and cogeneration capacity is included under cogeneration.   Source: California Energy Commission, Draft Final Report, California Historical Energy Statistics, January 1998, Publication Number: P300-98-001.    Notes: Data exlude facilities rated less than 5 megawatts. Some data in this table are inconsistent with national data in Table 4 due to different sources, categories, and coverage. Also, these data represent installed capacity, while the data in Table 4 represent net summer capability.

Most of the growth had occurred by 1990. Between 1990 and 1993, California nonutility renewable capacity (excluding small hydropower and  cogeneration plants) increased just 3 percent to 3,878 megawatts, and between 1993 and 1995, capacity actually dropped to 3,553 megawatts; generation followed a similar pattern. The principal reasons for this decline were the lower PURPA "avoided costs" when the long-term energy payment provisions of the contracts (usually 10-years), mostly signed in the early 1980s, expired. Natural gas prices in nominal dollars paid by electric utilities in California declines from a high of $6.77 per million Btu in 1982 to between $2.50 to $3.00 in 1986 through 1993. By 1995, the price declined further to $2.22. ⁽²⁸⁾ This, along with the repeal of the standard investment tax credits in 1986, caused some wind, biomass, and solar facilities to reduce output or cease operation. ⁽²⁹⁾ Also, there was a substantial slowdown in the construction of new capacity. This slowdown transpired despite substantial decreases in short-run average costs of renewables because the operation costs were not reduced enough to be competitive in the market conditions of the mid-to-late 1990s. ⁽³⁰⁾

Another criterion in evaluating the effectiveness of PURPA, in addition to expansion of renewable energy capacity and generation, is the cost competitiveness of the renewable facilities in the market. Utility wholesale power purchases from other utilities, which are more often made on a mutually agreeable economic basis between utilities and may be regarded as reflecting "wholesale" prices, averaged 3.53 cents per kWh nationwide in 1995. ⁽³¹⁾ Although EIA has not attempted to estimate the cost of PURPA directly, ⁽³²⁾ it has examined the prices that utilities paid in 1995 to purchase power from nonutilities and, in particular, PURPA QF nonutilities using renewable resources. ⁽³³⁾ The average price utilities paid all nonutilities was 6.31 cents per kWh nationwide, considerably higher than the average wholesale price. Higher still was the price utilities paid nonutilities for renewable-based electricity. Utilities paid an average of 8.78 cents per kWh for power generated from renewable sources, compared with 5.49 cents per kWh for power from non-renewable sources. ⁽³⁴⁾ Utilities paid an average of 9.05 cents per kWh for nearly 42,800 million kWh of power from renewable QFs in 1995, compared with just 5.17 cents per kWh for 3,300 million kWh of power from non-QF renewables. This difference was even more extreme in California, where the renewable QF/non-QF purchased power costs were 12.79 and 3.33 cents per kWh, respectively. ⁽³⁵⁾ All non-QF purchases of renewable energy, however, were from hydropower facilities, ⁽³⁶⁾ the lowest cost renewable resource-and the lowest cost of all electricity resources. ⁽³⁷⁾ In analyzing these data, the reader should bear in mind that by 1995, many of the original PURPA power purchase contracts between utilities and nonutilities had expired. Therefore, the data reflect a mixture of the original avoided cost contracts and newer contracts. ⁽³⁸⁾

Renewable-based generation costs would obviously have compared much more favorably with other generation costs during 2000, when California experienced severe electricity and natural gas shortages. Natural gas prices--the primary basis for determining alternative generation cost--rose sharply during 2000. Through September, the average cost of gas delivered to electric utilities in California increased to $4.32 per million Btu as compared to $2.68 for deliveries through September 1999. ⁽³⁹⁾

Renewable Energy Production Incentive (REPI)

Initial payments under the Energy Policy Act of 1992 (EPACT) Renewable Energy Production Incentive (REPI, summarized in Table 1), for Fiscal Year (FY) 1994 totaled $693,120 and were distributed among four State-owned and three city-owned facilities which generated 42 million kWh of electricity from seven facilities (Table 7). One used wind, two used solar photovoltaics (PV), and four used methane from landfills. ⁽⁴⁰⁾ By FY 1998, net generation eligible for REPI payment had reached 529 million kWh from 19 facilities. Interesting points to note about the REPI program are: (1) The number of facilities has remained relatively stable since FY 1996; (2) The number of solar/PV facilities has been quite modest, except for a one-time increase in FY 1996 which did not result in a sizable increase in REPI-eligible generation; and (3) The greatest increase in both eligible facilities and generation occurred in two areas, landfill methane and wood waste, which are often excluded (along with municipal solid waste) from actual and proposed renewable energy incentives; and (4) only tax-exempt facilities are eligible.

Table 7. Renewable Energy Production Incentive (REPI) Disbursements
Fiscal Year	Facilities	Energy Source	Net Generation (million kWh)	Nominal Payments (thousand dollars)
1994
	2	Solar PV		8
	1	Wind		93
	4	Landfill Methane		592
Total	7		42	693
1995
	4	Solar PV		15
	2	Wind		205
	5	Landfill Methane		2,178
Total	11		153	2,398
1996
	9	Solar PV		28
	3	Wind		205
	5	Landfill Methane		1,879
	1	Biomass Digester Gas		417
Total	18		177	2,529
1997	2	Solar PV		31
	3	Wind		123
	8	Landfill Methane		1,212
	1	Biomass Digester Gas		265
	1	Wood Waste		1,222
Total	15		458	2,853
1998
	3	Solar PV		91
	5	Wind		31
	9	Landfill Methane		1,716
	1	Biomass Digester Gas		359
	1	Wood Waste		1,803
Total	19		529	4,000
Source: http://www.eren.doe.gov/power/repi.html (October 22, 1999).

It is important to note that while the generation eligible for REPI payments increased more than twelvefold, the number of facilities receiving REPI support increased only threefold, and that increase occurred during the first 3 years of the program. This could have occurred because the 1.5 cents per kWh has not been sufficient to encourage much additional construction, though it may be a factor in maintaining production from economically marginal wind farms, or, more likely, because of the uncertainty associated with year-to-year congressional appropriations, or both. For existing biomass generators, whose variable costs per kWh are generally higher than those for wind generators, the 1.5-cents-per-kWh credit is much less likely to support continued operation of marginal plants.

Federal Ethanol Incentive Program

Prior to the Federal ethanol subsidy program, begun in 1979, ⁽⁴¹⁾ the United States produced virtually no fuel ethanol. In the first year of the subsidy program, the United States produced 10 million gallons. Production increased rapidly, to 175 million gallons  in 1981, 870 million gallons in 1990, 1.4 billion gallons in 1998, and 1.5 billion gallons in 1999. ⁽⁴²⁾ Virtually all production is in the Midwest, and fuel ethanol stocks are sizable only in the Midwest and Gulf Coast regions.

To determine what production of ethanol would be without the subsidies, it is necessary to analyze ethanol's three distinct purposes as an additive to gasoline. Originally, it was used to extend gasoline supplies as "gasohol," a mixture of 10 percent ethanol and 90 percent gasoline. As such, it was necessary for ethanol to compete economically with gasoline, necessitating the 54-cent-per gallon subsidy of corn-based ethanol. Ethanol also is used to raise the octane level of gasoline--its octane rating is 133. Beginning in the late 1970s, the use of lead, the only major octane enhancer used until then, was phased down. Both MTBE ⁽⁴³⁾ and ethanol were used.

For octane-enhancing purposes, MTBE has a clear economic advantage over ethanol. More recently, ethanol and MTBE have been added to gasoline as an oxygenate to reduce harmful emissions. The incremental cost per gallon of MTBE-based gasoline (which receives no subsidy) is 2 to 3 cents per gallon. Using a 7.7 percent blend of ethanol, the value of the ethanol subsidy alone in a gallon of gasoline would be 4.1 cents. The total incremental cost per gallon of ethanol-based gasoline is 4.4 cents. ⁽⁴⁴⁾ While MTBE has an economic advantage per gallon of additive, ethanol has a higher oxygen content than MTBE. Thus, only about half the volume of ethanol is required to produce the same oxygen level in gasoline as if MTBE is used. This allows ethanol, typically more expensive than MTBE per unit of product, to compete favorably with MTBE for the wintertime oxygenate market. ⁽⁴⁵⁾ However, recent EPA "Tier 2" requirements for summer time reformulated gasoline made it necessary to increase the ethanol content to 13 percent in 1999. Clearly, increasing the ethanol content of gasoline in the near term increases its cost vis-a-vis MTBE-based gasoline.

It is also important to note that ethanol's one-third share of the oxygenate market is concentrated in the Midwest where most of the corn is grown. Many States in the Midwest have sizable ethanol support programs. ⁽⁴⁶⁾

The use of MTBE in some parts of the country may have less to do with economics than with the cost of transporting ethanol far from where it is produced. Ethanol is "splash blended" at gasoline distribution tank farms because it cannot be transported via pipeline.

Assessments of repealing the Federal ethanol subsidies differ widely, from no industry ⁽⁴⁷⁾ to the continuance of the market