Introduction

Restructuring of the U.S. electric power industry has refocused attention on renewable energy and the policies that affect it. Renewable energy sources include water, wind, solar, geothermal, and some combustible materials, such as landfill gas, municipal solid waste (MSW), and other forms of biomass. Public policies favoring renewable energy are nothing new. Policies including tax and financial incentives and guaranteed purchase power contracts, among others, have supported the development of renewable energy in the past. Such policies have sought to develop a sustainable energy future, reduce dependence on foreign oil, and reduce the environmental impacts of fossil-fueled electricity generation. These ends were deemed to be more important than the fact that alternative fuels cost more than fossil fuel sources of energy.

The advent of competition in electricity markets necessitates a reevaluation of renewable energy policies. Concerns about the use of renewable energy sources in a competitive environment can be outlined as follows. Competition in the electric power industry will encourage utilities to become more efficient and reduce costs in order to lower electricity prices. There will be a premium on short-term cost minimization. In this environment, renewable energy sources will be challenged to continue to penetrate electric power markets because they are generally higher-cost options for producing electricity. Proponents of renewable energy thus fear that renewables may be an inadvertent casualty in the transition to a competitive market. This chapter reviews the reasons for the historical interest in renewable electric power in the United States; the Federal and State plans to support renewables; the various mechanisms being implemented or discussed to provide that support; and issues specific to individual renewable energy resources and technologies.

Overview

The electric power industry and its regulators were unprepared for the social, political, and economic upheavals that followed the oil embargo of 1973. The tripling of oil prices precipitated a need for numerous rate increases by electric utilities because oil was being used to fuel many power plants. In the wake of the oil embargo, the goal of national energy policy was to foster an adequate supply of energy at reasonable costs. As a result, interest in renewable energy rose sharply during the 1970s. A strategy to achieve that goal was to promote a balanced and mixed energy resource system. The development of renewable energy—which reduces dependence on fossil fuels, does not need to be imported, and generally produces fewer and less toxic pollutants than fossil fuels—became a national priority.

The oil embargo of 1973 was a catalyst for the proposal and adoption of the National Energy Act of 1978, a compendium of statutes aimed at restructuring the U.S. energy sector. One objective of the Act was to reduce the Nation's dependence on foreign oil and its vulnerability to interruptions in oil supply through the development of renewable and alternative energy sources.

The most significant statute in the National Energy Act for the development of commercial markets for renewable energy was passed into law as the Public Utility Regulatory Policies Act of 1978 (PURPA). Among other things, PURPA encouraged the development of "nonutility" cogeneration and small-scale renewable-fueled electric power plants designated as "qualifying facilities."¹⁶⁰ Under PURPA, utilities were required to purchase electricity from certain qualifying facilities at the utilities' avoided costs, that is, the cost to the utility if it had generated or otherwise purchased the power. Some avoided cost purchase contracts, particularly in California, were very favorable to renewable technologies.

A second major factor influencing the development of renewables was State policies promoting renewable energy. California, in particular, promoted renewable energy strongly in the 1980s with renewable energy tax credits. By the late 1980s, however, California's renewable tax credits for wind energy had ended, and competition and pricing policies had begun to evolve in the electric utility industry. "Competitive bidding" became the predominant approach to defining avoided costs. By the end of the decade, with declining natural gas prices setting the value of avoided costs, renewable facilities had difficulty competing in electricity markets on the basis of price alone.

To spur renewable energy development, the Federal Government provided several tax incentives. By 1982, most renewable energy projects were eligible for a 10-percent investment tax credit, a 15-percent business renewable energy investment tax credit, a 40-percent residential tax credit for renewables, and a 5-year accelerated depreciation schedule. Taking advantage of these incentive packages, private industry responded by pioneering new renewable energy technologies and applications. In terms of Federal research and development budget appropriations, funding for renewables increased dramatically from fiscal year (FY) 1974 through FY 1979, stabilized for 2 years, dropped precipitously in FY 1982, then decreased further each year until rebounding in FY 1991. Funding increased to $391 million in FY 1995 before dropping to $268 million in FY 1996 and $244 million in FY1997. The appropriation for FY 1998 is $272 million.¹⁶¹ This pattern of inconsistent funding, as well as the on-again, off-again availability of some incentives, has created an uncertain investment environment for renewables.

The Renewable Electricity Marketplace

Electric utility and nonutility power producers generated 446 billion kilowatthours in 1997, 13 percent of their total generation,¹⁶² from renewable energy sources (Table 11). Including net imports, total available electricity from renewable resources was 467 billion kilowatthours.

Water from conventional hydroelectric power plants¹⁶³ is the major renewable energy source for electricity production in the United States. Conventional hydroelectric plants produced 360 billion kilowatthours of electricity (including exports), about 10 percent of total U.S. generation (81 percent of renewable generation), in 1997. Other renewables accounted for an additional 86 billion kilowatthours, or 2 percent of total U.S. electricity generation for the year. Excluding conventional hydroelectricity, biomass is the largest renewable source of electricity (75 percent), followed by geothermal (19 percent). Wind and solar account for the remainder (6 percent).

Of the 86 billion kilowatthours domestically generated from nonhydroelectric renewable energy sources,¹⁶⁴ nonutility power producers accounted for 91 percent and electric utilities 9 percent. Electric utilities have historically devoted few resources to nonhydroelectric renewable energy sources. This is because, in general, these facilities are small in size and more expensive per unit of output than large central generating stations. Federal and State incentives have, however, resulted in the development of some nonhydroelectric renewable power plants by electric utilities. In California, with State incentives and favorable climate conditions, electric utilities have developed geothermal, solar, and wind facilities.

Manufacturing processes and legislative incentives favor the production of electricity from renewable sources by nonutility power producers. A nonutility power producer includes a corporation, person, agency, authority, or other legal entity that owns generating capacity, but, unlike electric utilities, is without a franchised service area or an obligation to serve retail customers. Nonutility power producers include qualifying facilities (cogenerators and small power producers) under PURPA, exempt wholesale generators¹⁶⁵ under the Energy Policy Act of 1992 (EPACT), other commercial and industrial establishments that may generate electric power for their own use and buy backup or sell excess power to electric utilities, and independent power producers built solely to supply and sell power to electric utilities.

Table 11. Electricity Generation from Renewable Energy by Energy Source, 1993-1997
(Million Kilowatthours)

The major technology used in nonutility generation is cogeneration—the combined production of electric power and another form of useful energy (heat or steam). Many nonutility power producers use waste energy streams (principally heat) to produce electricity, and some manufacturing processes may produce renewable waste (e.g., sawdust) that can be burned to produce energy.

The distinction between the utility and nonutility sectors assumes additional significance under some restructuring proposals, notably in California. Under many plans, a firm must generate some high percentage (usually over 50) of its electricity from renewable sources to be classified as a "green power" provider. Such requirements will tend to limit utility ownership of renewable generating facilities and push future nonhydroelectric renewable development into the nonutility sector.

Most renewable energy systems (except perhaps for biomass) are not constrained by the same types of fuel supply infrastructure considerations as fossil-fueled power generating units. The constraints that renewable power systems face are related to geographic availability factors associated with particular wind, biomass, geothermal, and hydroelectric resources. To a great extent, renewable generating facilities are very region- and site-specific, which, depending on the circumstances, can be either a drawback or a significant advantage. Until recently, most nonutility renewable energy power generators and other nonutility generators have sold their power directly to local utilities, or used it on site, avoiding the need for nationwide transmission access. With deregulation opening access to electricity transmission, transmission pricing can affect the development of renewable power generating facilities.

Utility Generation

Electric utilities generated 338 billion kilowatthours from renewable resources in 1996 and 349 billion kilowatthours from renewable resources in 1997 (Table 11). Nearly 98 percent of utility generation came from conventional hydroelectric facilities in both 1996 and 1997. Access to water power by utilities in Washington made that State the leading producer of renewable energy, accounting for 29 percent of all renewable electricity produced in 1996 (Table 12).¹⁶⁶ Washington also leads the Nation in utility power produced from wood and wood waste. Electric utilities in Illinois, Connecticut, and Minnesota generated, respectively, 87 percent, 45 percent, and 31 percent of their renewable- based electricity from municipal solid waste and landfill gas. Virtually all utility geothermal energy comes from California.

In 1996, 14 percent of utility renewable generation nationwide occurred in California. (California's share of nonutility renewable electricity was even larger—over 23 percent (Table 13).) State policies promoting renewable energy have also influenced the development of renewables. California, for example, promoted renewable energy strongly in the 1980's with renewable tax credits. The combined effect of resource availability and energy policy makes California the second-largest producer of renewable electricity generation.¹⁶⁷

Utilities in Oregon, which also has sizable water power resources, produced the third-largest amount of electricity from renewables—13 percent. Besides New York at 8 percent and Montana at 4.1 percent, no other State contributed more than 4 percent of total utility renewable generation.

Nonutility Production

Nonutility generators produced almost 86 billion kilowatthours of electricity in 1995 and 89 billion kilowatthours in 1996 (Table 13). Almost 17 billion kilowatthours (19 percent) of electricity was produced from conventional hydroelectric facilities in both 1995 and 1996. More than 42 percent of nonutility renewable electricity generation is produced from wood and wood waste.

Nonutilities in California produce by far the largest share of electricity, 23 percent. Nonutility renewable generation (outside California) is more evenly spread than is utility renewable generation. One reason is that nonutility plants are usually smaller than utility plants, having been built in many instances to service a single facility (e.g., pulp and paper manufacturing plants). Thus, many more resource locations—particularly for biomass and hydropower—are available. After California, the States with the most nonutility electricity generation from renewables in 1996 were Florida, Maine, Alabama, New York and Louisiana.

Table 12. Renewable Electric Utility Net Generation by State, 1996 (Million Kilowatthours)

Table 13. Nonutility Gross Generation from Renewables by State, 1996 (Million Kilowatthours)

Federal Approaches to Supporting Renewables

Various electric power restructuring bills have been proposed in the U.S. Congress. All the proposals contain sections designed to promote the development of renewable energy. The Clinton Administration has also recently presented a proposal, the "Comprehensive Electricity Competition Plan," as a blueprint for electric power restructuring. This plan and four legislative proposals are summarized below. The legislative proposals discussed were drafted prior to the Administration's plan and were chosen for discussion because they include provisions which have attracted considerable interest.

Administration's Comprehensive Electricity Competition Plan

The Administration's "Comprehensive Electricity Competition Plan" was released in March 1998. The components of the plan were designed to work together to provide the economic benefits of competition in a manner that is fair to all consumers and to enhance the environmental performance of the electric power industry. The plan has five basic objectives: (1) to encourage States to implement retail competition (i.e., end users may choose their electricity provider); (2) to protect consumers by facilitating competitive markets; (3) to assure access to and reliability of the transmission system; (4) to promote and preserve public benefits; and (5) to amend existing Federal statutes to clarify Federal and State authority.

The Administration's plan, with the objective of promoting and preserving public benefits, proposes policy mechanisms, such as a renewable portfolio standard, public benefit funding, and net metering, to promote the development of renewables. The terms renewable portfolio standard, public benefit fund, and net metering are defined and discussed below.

Renewable Portfolio Standard

A renewable portfolio standard (RPS) is a market-based strategy to ensure that renewable energy constitutes a certain percentage of total energy generation or consumption. An RPS could require electricity generators or sellers to cover a percentage of their electricity generation or sales, respectively, with generation from renewable technologies. It guarantees that a minimum percentage of generation comes from renewable sources. Under the Administration's proposal, the initial RPS requirement, based on electricity sales, would be set close to the existing ratio of renewable generation to total retail electricity sales, with an intermediate increase in 2005, followed by an increase to 5.5 percent in 2010. (In 1997, nonhydroelectric renewable generation represented 2 percent of total generation.) Retail sellers could meet the RPS requirement either by generating sufficient renewable electricity to meet the ratio, or by purchasing tradeable renewable electricity credits that would be created and tracked. The RPS would employ market prices through credit trading and spread the cost of supporting renewable generation more evenly across the retail electricity market than does PURPA's "must buy" provision (Section 210), which would be repealed under the Administration's plan. The RPS could be subject to a price cap.¹⁶⁸

Public Benefit Fund

The Administration's plan supports the creation of a $3 billion Public Benefit Fund (PBF) to provide matching funds to States for low-income assistance, energy efficiency programs, consumer education, and the development and demonstration of energy technologies, particularly renewables. The PBF would be a 15-year program, funded through a generation or transmission interconnection fee on all electricity.¹⁶⁹ Since transmission will be regulated, the charge should be nonbypassable to ensure that all customers pay the charge and the charge is competitively neutral. The charge can be based on energy, demand, or a combination of both. In the Administration's plan, the charge would be capped at 0.1 cent (1 mill) per kilowatthour. States would have the option to seek funds and allocate the funds among public purposes. The States would compete for the funds on the basis of cost-effective proposals.

Net Metering

Net metering refers to the concept that a facility is permitted to sell any excess power it generates over its load requirement back to the electrical grid to offset consumption. (A more detailed discussion of net metering is provided later in this chapter.) Under the Administration's plan, all consumers would be eligible for net metering, and all distribution service providers would be required to assure the availability of interconnection. This provision would apply only to very small (up to 20 kilowatts) renewable energy projects and would be subject to a price cap determined at the State level.

Finally, in competitive markets, many different suppliers will offer a diverse menu of energy products and services with different pricing and billing plans. Under the Administration's proposal, consumers will have the option of choosing suppliers on the basis of their generation mix, including paying a premium for "green power" (renewable generation). To ensure consumers that they are purchasing green power, the Secretary of Energy would be authorized to implement a rulemaking to require all electricity suppliers to disclose reliable and easy-to-read information on prices, generation sources, and other information to enable consumers to make informed choices among various offers.

Senate Bill 237 (The Bumpers Proposal)

Section 110 of Title One of Senate Bill 237 has a requirement for a certain amount of renewable energy generation. Starting in 2003, 5 percent of total retail electricity sold must come from a renewable energy source (including partial credit for hydroelectricity). The amount increases to 9 percent in 2008 and 12 percent in 2013. Thereafter, the requirement remains constant until 2019, when it ends. Retail electric suppliers may satisfy the requirement by earning renewable energy credits under the National Renewable Energy Trading Program, depending on the type of renewable energy source used. Credits will be issued by the Federal Energy Regulatory Commission (FERC) to any facility using renewable resources for generation or for any power purchased by the facility from a generator using renewables. One half of one credit can be earned by any large hydroelectric facility that generates and then sells one unit of energy. One credit can be earned by any facility that generates and sells electricity from a renewable energy source other than hydro at a facility built before the enactment of the Act. Two credits can be earned by any facility built after the enactment of the Act that generates and sells electricity from a renewable energy source other than hydroelectric.

Senate Bill 687 (The Jeffords Proposal)

Section 5 of Senate Bill 687 instructs the Secretary of Energy to establish a National Electric System Public Benefits Board to fund programs related to renewable energy sources, universal electric service, affordable electric service, energy conservation or efficiency, or research and development in any of these areas. The money for the National Electric System Public Benefits Fund will be financed from transmission wire charges imposed by FERC and will be distributed to the States by the Board. States must provide matching funds. The Board will recommend eligibility criteria for disbursements from the Fund and will determine the amount needed every year for the fund. FERC will impose a nonbypassable, competitively neutral wires charge paid directly to the fund by the operator of the wire. The charge will be applied to all electricity carried through the wire, measured from the busbar at a generation facility, which has an impact on interstate commerce.

Section 6 of the bill provides a renewable energy portfolio standard imposed on any nonhydroelectric facility that generates electricity for sale. Starting in the year 2000, 2.5 percent of total electricity generated by all (nonhydropower) electricity generators must be generated from renewables. Renewable energy sources include wind, organic waste (excluding incinerated municipal solid waste), biomass, geothermal, solar thermal, and photovoltaics. The required renewables portfolio schedule after the year 2000 increases by approximately 1 percent a year until the year 2020 up to a total of 20 percent, which is the target level for beyond that time period. The bill also provides for renewable energy credits, to be issued by the Federal Energy Regulatory Commission (FERC) beginning in 2001. One credit will be given for each megawatthour of electricity sold by a facility in the preceding calendar year that was generated from a renewable energy source. Credits can be traded and used in lieu of generation to meet the generation requirement of the renewables portfolio standard.

House of Representatives Bill 655 (The Schaefer Proposal)

House of Representatives Bill 655 calls for a minimum renewable generation requirement (Section 113) by December 31, 2000. It directs the FERC to establish a program to issue renewable energy credits to electricity generators, providing for their sale and exchange. It would require each generator (excluding hydroelectric facilities) selling electric energy to submit such credits to FERC in an amount equal to the required annual percentage of the total renewable electric energy it generated in the preceding year. PURPA would be amended so that it would no longer apply to any electric utility whose customers are able to purchase retail services from any offeror on a competitively neutral and nondiscriminatory basis.

House of Representatives Bill 1359 (The DeFazio Proposal)

The intent of House of Representatives Bill 1359 is to amend PURPA to establish a means to support programs for energy efficiency, renewable energy, and universal and affordable service for electric customers. It would establish a National Electric System Public Benefits Fund, to be administered by the National Electric System Public Benefits Board, which would provide matching funds to States for the support of eligible public purpose programs. This program would not supersede other programs that support renewable energy.

State Approaches to Supporting Renewables

Much of the regulatory initiative to bring competition to the electricity industry is occurring at the State level. As at the Federal level, most States have formulated policy measures to preserve or promote renewables in a restructured electric power market. The States have been considering a number of regulatory mechanisms to promote renewable energy development, including a system benefits charge (SBC) or "wires charge," RPS, net metering, and green pricing (voluntary).

The SBC would be a fee that would be paid by users of distribution lines, either generators or consumers. It would be included in the cost of electricity to all consumers. Revenues from the charge could be pooled for use in a number of ways to fund the development of selected renewable energy projects.

By design, both the SBC and the RPS would be competitively neutral with respect to fuels and technology, and would put in place a minimum public obligation to support the development of renewable energy. Used singly or in combination, they will have differential effects on renewable energy development. The SBC provides for a regulatory agency with the latitude to promote specific renewable technologies or projects.

Given that the SBC is collected on a regular basis from wires usage, it would provide consistent support to renewables. By providing this consistent support, it would also have the effect of making the cost of capital lower for this type of project development. The biggest drawback of the SBC is the administrative cost and difficulty of decisionmaking. The RPS, on the other hand, does not have these administrative obstacles because the market is used to determine which projects are developed. The renewable portfolio standard would encourage the lowest cost, highest efficiency projects to be developed. There is, however, a risk of neglecting the development of those renewable technologies that have a longer development horizon. As of February 9, 1998, 6 States had enacted RPS provisions, 5 States had enacted SBC provisions, and 26 States had some form of green pricing program legislation (discussed below).

Net Metering

As mentioned above, net metering is an arrangement that permits users generating power to sell any electricity in excess of requirements back to the grid to offset consumption.¹⁷⁰ How excess energy (if any) from facilities under net metering is treated, and what rates are paid, are what differentiate State net metering policies. Some State initiatives require the utility to pay retail rates instead of avoided cost rates for the excess energy. States may apply certain capacity restrictions and, in some cases, fuel restrictions on facilities that qualify for net metering.

Most net metering programs are available to customer-owned small generating facilities only, and some programs further restrict the eligibility to renewable energy technologies. Net metering can increase the economic value of small renewable energy technologies for customers by allowing them to use the grid to bank their energy, producing electricity at one time and consuming it at another. This form of energy exchange is especially useful for such renewable energy technologies as wind turbines and photovoltaics, which transmit electricity to the grid intermittently (when the wind is blowing or the sun is shining) and, at other times, are consumers of electricity from the grid.

Green Pricing/Marketing

Green pricing or green marketing is an approach States have used to maintain or increase demand for renewable electricity. In green marketing programs, electricity suppliers offer consumers electricity produced from environmentally preferred resources consisting largely of renewable energy. Consumers who voluntarily choose to purchase their electricity under a green marketing program pay a premium above their normal electricity bills. This premium is then applied toward the additional costs incurred by electricity suppliers to develop and maintain a renewable power project that might otherwise not be cost-effective.

Initially,¹⁷¹ the goal of green marketing was to provide customer-driven mechanisms for enabling the development of additional renewable energy power projects. Although the concept of green marketing originated in a regulated environment, a number of utilities and nonutilities are looking at green pricing programs as a way to differentiate their product in a more competitive market. Market research conducted to date suggests that there is a willingness among consumers to pay more for power from renewable energy up to a certain point.¹⁷² Assuming that this remains true in the future, regardless of what shape the restructured electric industry takes, green marketing programs are likely to continue evolving as viable competitive strategies that electricity suppliers can use to aggregate customer groups, reach specific market segments, and retain existing customers.

As of March 1998, there were 17 State level green pricing programs in operation, 5 in active development, 7 that were pending formulation based on utility market research, and 4 in the planning stage. A current list of green pricing programs can be found at http://www.eren.doe.gov/greenpower/summary.html. This web site is maintained and regularly updated by the Department of Energy's Office of Energy Efficiency and Renewable Energy.

The case of green marketing is illustrative of the types of issues associated with this strategy. With hundreds of nonutility "electric service providers" planning to offer electricity in the California market, fierce competition will likely produce a variety of claims about the electricity being offered. In order for customers to make informed choices, they must understand what really distinguishes one supplier from another. A criterion that some customers say they will use is the extent to which generation is environmentally acceptable. For most such customers, this means renewable sources.

Unfortunately, pilot programs in New England illuminated the potential for "green fraud," when some suppliers allegedly offered their customers electricity that they labeled as green but that in fact was no different from any other electricity in the New England Pool. To prevent such abuses in the future, legislatures, regulators, and private organizations have proposed measures to give electricity customers valid information on the renewable content of their electricity. To provide customers data on their suppliers, California's Assembly Bill (AB) 1305 legislation, enacted in 1997, requires all electric service providers annually to state the source of their electricity.¹⁷³ Categories include coal, large hydroelectric (greater than 30 megawatts), natural gas, nuclear, other, and eligible renewables (biomass and waste, geothermal, small hydroelectric, solar, and wind). In Illinois, the new Environmental Disclosure Law¹⁷⁴ requires every "electric utility and alternative retail electric supplier" to provide customers quarterly the known sources of electricity by fuel type, with corresponding emissions information.

To provide further assistance to customers in evaluating how "green" their electricity is, the non-profit Center for Resource Solutions in San Francisco will certify with its "Green-e Brand" that approved electric service providers:¹⁷⁵

• Obtain at least 50 percent of total energy from "eligible renewable resource facilities" through performance obligation contracts
• Utilize fossil resources in the nonrenewable component of the electricity product that have equal or lower air emissions (for SO_x, NO_x, and CO₂) than the fossil portion of an equal amount of system power (from California's Power Exchange). Generate air emissions from waste renewable fuels, to the extent they are utilized, at a rate as low as or lower than would be generated by alternative waste disposal methods
• Refrain from using nuclear power beyond that contained in system power purchased for the eligible electricity product's portfolio.

The success of green marketing programs is related to the extent that consumers would choose to pay higher rates for renewable-based electricity.¹⁷⁶ Green marketing amounts to product differentiation, with the result that the demand for renewable-based electricity would have its own supply and demand functions. Absent system benefits charges (SBC) and renewable portfolio standards (RPS) in a competitive market, renewable electricity product differentiation is even more critical because it (ostensibly) increases the demand for renewable energy. However, some believe that in a competitive marketplace, both an RPS or SBC and green marketing are necessary and serve to complement each other.¹⁷⁷

Current Economics

Renewable technologies are generally characterized by relatively high capital costs and low operation and maintenance costs. These characteristics make them attractive in the long run, but less so in a competitive setting where the premium is on near-term cost minimization. Renewable generating technologies continue to make advances, thereby increasing their efficiency and lowering cost; however, outside of some niche market applications, they still are not economically competitive with conventional sources of power.

One of the ways in which capital costs decrease is through "learning by doing." That is, as the number of units of a product are built, manufacturers learn more efficient production techniques and costs thereby decline. In the case of renewables, this can occur whether a company builds for the domestic market or for export. With American firms competing for foreign markets, costs are likely to decline further domestically. Capital costs and operations and maintenance (O&M) costs also decline through "economies of scale," that is, up to a certain (optimal) plant or project size.

Levelized Costs of Renewable Electric Technologies

When determining the fuel source to use in constructing a new generating plant, "levelized" cost is usually used to determine which technology and energy source will be least cost. Levelized costing considers all capital, fuel, and operating and maintenance costs. In levelized costing, capital costs are amortized over the expected power output for the life of the plant.¹⁷⁸

EIA estimates the levelized costs of all generating technologies using its National Energy Modeling System, (NEMS). Tables 14 through 17 show decision year 2000 cost and performance information, based on NEMS, for fossil and renewable technologies for the major regions of the country best suited for renewables.

Although geothermal energy appears to be the least costly of the technologies compared in the California-Southern Nevada power area (CNV) (Table 14), there is very limited capacity available for development at 37.6 mills per kilowatthour. Wind power offers a 10-percent cost advantage over natural gas combustion turbine technology. However, wind technology is intermittent and therefore cannot be fully credited for firm capacity. The levelized cost of biomass power is about double that of wind and gas combustion turbines. The biomass power cost, however, does not include any credit for waste disposal costs that might be otherwise incurred.

In the Northwest (NWP) and the Southwest, except California (RA), the cost comparison is much the same, except that biomass is about one-fourth less expensive than in California.¹⁷⁹ In most of Texas (ERCOT), however, natural gas combustion turbines are 10 mills per kilowatthour cheaper than the next cheapest technology, wind power. Biomass in eastern Texas produces power for approximately the same cost as in NWP and RA.

It is worth reiterating that site-specific conditions are critical to the economic feasibility of renewable electric generating plants. NEMS does not assess generating plant feasibility on a site-specific basis.

A number of state public utility commissions (including Rhode Island and Massachusetts) have also studied levelized/life-cycle costs of renewables.¹⁸⁰

Table 14. Cost and Performance Characteristics for Combustion Turbine and Renewable Generating Technologies, California-Southern Nevada (CNV)

Table 15. Cost and Performance Characteristics for Combustion Turbine and Renewable Generating Technologies, Southwest (RA)

Table 16. Cost and Performance Characteristics for Combustion Turbine Technologies and Renewable Generating Technologies, Northwest (NWP)

Table 17. Cost and Performance Characteristics for Combustion Turbine and Renewable Generating Technologies, Electric Reliability Council of Texas (ERCOT)

Transmission Issues for Renewable Energy Technologies

The tariffs.¹⁸¹ for transmission access and services are coming under review as the electric power industry evolves from a regulated to a competitive environment. The structure of the transmission tariff will determine the allocation of transmission costs to the users of the transmission system, and ultimately, to the respective consumers. The structure of the transmission tariff can impact the prices of transmission for different generation technologies and energy sources, which could affect the economics of these technologies.

The transmission tariff is designed to recover both the marginal and fixed costs of the transmission system. The marginal cost of transmission for completing any given power transfer, including losses, ancillary services (i.e., capacity reserves), and any congestion cost, is typically a small fraction of the embedded cost included in transmission tariffs. The transmission tariff also sets prices well above the marginal cost to recover the fixed cost of the transmission system. The methodology used to recover fixed costs (in excess of marginal cost) can impact the price of electricity, thereby potentially affecting competition among generation suppliers. For example, certain transmission tariffs could result in a distant generation supplier paying "pancaked" transmission rates¹⁸² to several transmission providers, the sum of which greatly exceeds the marginal cost of transmission.

The most common type of transmission tariff is postage stamp pricing. A postage stamp rate is a fixed charge per unit of energy transmitted within a particular zone, irrespective of the distance that the energy travels. Other transmission tariffs include megawatt-mile and congestion pricing. Megawatt-mile rates explicitly reflect the cost of transmission based on both the quantity of power flow and the distance between the receipt and delivery points. Congestion pricing is used to allocate the available transmission capacity by increasing the price to users of the transmission lines as maximum transmission capacity is reached.

Currently, transmission tariffs are based on contract path pricing. A contract path rate is one that follows a fictional transmission path agreed upon by transaction participants. However, contract path pricing does not reflect actual power flows through the transmission grid, including loop and parallel path flows. Flow-based pricing schemes can be used as an alternative to contract path pricing.

Tariffs that include charges for firm (take-or-pay) transmission capacity or transmission distance will increase the cost of transmission for generating units having low capacity factors (e.g., due to intermittency of operation, as with wind-powered facilities) or with increasing transmission distance (e.g., remotely located facilities, as with biomass powered facilities). Under these tariffs, technologies utilizing certain renewable energy technologies having inherently low capacity factors, large distance from load centers, and intermittent operation will incur relatively higher transmission costs than other technologies.

Historically, renewable energy technologies have received Federal and State incentives to make them more price-competitive with fossil-fueled technologies. In competitive markets, advocates of renewable energy resources, in addition to promoting incentives (e.g., renewable portfolio standards), are also promoting green pricing programs where consumers pay a premium for electricity from renewables. How competitive renewable technologies ultimately become will depend on the cost of renewable technologies to produce electricity, including transmission prices, incentives that mandate consumption or reduce the cost of renewable generation, and the price elasticity of consumers' demand for green power. High prices for transmission services, added to the cost of renewable generation, could reduce the demand for renewables even with green pricing programs. However, a transmission tariff that results in high transmission prices in certain geographic areas may create an opportunity in those areas for distributed generation by using renewable technologies to compete with central station power plants.

Distributed Generation

During the early development of the electric power industry, electricity was provided using distributed generation, sometimes called distributed resources, where generation occurs near or at the site of electricity demand. Although distributed generation has been replaced by large central-station power plants—made possible by the development of an adequate, reliable, and efficient transmission system—it may be staging a comeback under deregulation.

Generation will be priced competitively under deregulation, but transmission and distribution (T&D) will continue to be regulated. T&D regulation is undergoing substantial changes, with transmission owners required to open access to transmission lines, and the transmission services undergoing a transition to "unbundling" of services and prices. Under unbundled services, transmission owners must provide a clear and specific tariff for a variety of transmission access services (e.g., point-to-point vs. network related, interruptible vs. noninterruptible charges) and a variety of dispatching and power management services (e.g., capacity reserves, voltage control, and administration). Distributed generation may have opportunities in niche markets to be competitive with the cost of electricity from central stations, which includes cost of transmission (including losses and ancillary reserves), operating power substations, and distribution lines and equipment for delivery to end users.

T&D costs can vary greatly among locations with the unbundling of rates. T&D costs may be relatively low for customers receiving power from plants close to major transmission lines or substations. For customers located far away from main transmission lines, or in constrained areas of the grid, T&D costs may be a multiple of the average costs. Distributed generation may prove to be attractive in areas where it can defer T&D investment or where it can improve reliability to the consumer. Small-scale renewable generation technologies that have seen significant cost reductions and improvements in operating characteristics may be competitive and provide benefits (e.g., environmentally friendly, minimum land use) not available from large central generating stations. In the future, fuel cells, wind turbines, solar panels, and some biomass technologies may meet these criteria.

Renewable Energy Resources

Each of the renewable resources and technologies is different with regard to resource location, markets, and infrastructure. Therefore, each may be differentially affected by deregulation. This section discusses the possible effects of competitive markets on each of the renewable sources.

Biomass¹⁸³

Biomass produced 75 percent of nonhydroelectric renewable electricity in 1997, with wood comprising the largest component of biomass energy. Clearly, the success of any restructuring provision attempting to increase substantially renewable-based electricity in the near term will require more generation from biomass sources. A major issue in this section is the availability of additional biomass resources, especially wood and wood waste, which are the principal biomass products used to produce electricity. Their use is greatest in the forest products industry, which consumes about 85 percent of all wood and wood waste used for energy and is the second-largest consumer of electricity in the industrial sector (Figure 23).¹⁸⁴ Electric utilities have historically relied on fossil fuels and consumed very little biomass. Of the more than 500 U.S. biomass power production facilities (with total capability near 10 gigawatts), fewer than 20 are owned or operated by electric utilities.

Figure 23. The Largest Electricity-Consuming Industries and Their Generation, 1994 (Million Kilowatthours) (Click graph to view full size)

Although many people envision substantial increases in biomass power for the future with "energy crop" plantations forming a primary supply base,¹⁸⁶ this is not feasible in the near term. Presently, "closed-loop" (i.e., sustainably supplied) biomass power projects are at the research and demonstration phase.¹⁸⁷ This reemphasizes the fact that significant near-term increases in biomass-produced power will need to come from sectors currently producing power from biomass.

If the principal source of biomass for power is waste streams, then industrial company biomass generation beyond current levels will require changes in basic industrial operating conditions which generate those waste streams. That is, the synergy referred to above must be maintained. A decision by an industrial company to increase electricity generation would be based on (1) how increasing generation would affect industrial operations, i.e., existing processes and products; (2) anticipated costs and supply implications for additional primary biomass fuel; and (3) the cost of self-generated versus purchased electricity.

One industrial operating condition which could change is the character of the biomass fuel used. If primary fuel (e.g., dedicated crops and trees) rather than waste-based fuel were used to support increased generation, fuel costs would change. Another is that increased industrial biomass generation could require alteration or addition of fuel storage, material handling, and generating equipment (e.g., for cofiring retrofits). Third, increased demand would be placed on the fuel supply infrastructure. While some biomass fuel resources are owned by industrial companies,¹⁸⁸ in other cases companies purchase from private or government landowners. The availability of additional biomass fuel from noncaptive suppliers is thus uncertain. Hence, prices paid for electricity would have to be sufficiently high to motivate forest product generators to become net sellers beyond current levels for there to be a significant impact on U.S. biomass-generated electricity from the industrial sector.

It is generally perceived that, absent mandatory incentives to promote and preserve public benefits (e.g., RPS, wire use charges), electricity restructuring will exert competitive market pressures that will (on a macro scale) tend to reduce, rather than increase, the price of electricity. It is, therefore, not reasonable to anticipate a substantial increase in industrial output of biomass electricity solely due to market restructuring. Even with a mandatory RPS, it is unclear that the cost of new biomass power would be less than for other renewables—particularly wind—in the near term.

The effect, on the other hand, of green power marketing programs, voluntary or State-mandated, is an altogether different matter. During the past year, there has been a steadily increasing demand for renewable-based electricity as a result of retail marketing programs and State production mandates and incentives. Whether or not demand for green power is beginning to outstrip initial supply, there is clear evidence of new interest and participation by both forest products and energy companies, and public attitude and corporate image play no small role in this change. Utilization of additional primary biomass resources, such as timber, for energy may be constrained somewhat in the short term by available generating capacity. The potential of the wood resource base for energy use is large, however, under qualified conditions.

One major qualification is that noneconomic factors, such as public perceptions regarding land use, will play a major role in how much of the wood resource base may be used for energy. There may be a conjunction at the present time, however, between public attitude toward use of timber resources for energy and the potential of biomass-based power.

A recent analysis of the press by the Forest Service indicated that 75 percent of the stories on the subject expressed a favorable attitude and growing acceptance that forest ecosystem management is necessary. In recent decades, cutting practices on timberland have been a contentious public issue. Thinning of forest understorey¹⁸⁹ is a component of this issue. The study noted that attitudes have shifted regarding the thinning of understorey since the lives of over a dozen firefighters were claimed a few years ago in their attempt to control a raging forest fire. While understorey wood is of limited commercial use otherwise, it is a good source of hogged fuel (woodchips). Slash (tops, stumps, and limbs) left over from general timber harvesting are related in nature. It is now perceived that balanced ecological practice leaves sections of slash and understorey for support of habitat and natural reforestation but removes part to reduce the risk of fire and allow remaining healthier trees to grow larger than they would otherwise.

Use of understorey, slash, poor quality timber, and mill wastes for energy may now even represent an opportunity for some companies to "hit a home run." If these products are replanted with new biomass, use of these forest wastes for energy is a sustainable practice and a strategy for mediation and sequestration of carbon. A primary motive for forest product companies to thin understory and remove slash is to replace this poor quality biomass with more commercially viable trees. This may be not only a profitable but also an ecologically popular practice if biodiversity can be maintained. It may now become possible for companies simultaneously to acquire both a "green" corporate ecological image in their resource operations and a "green energy" image in their production operations.¹⁹⁰

Although the increased availability of understorey for fuel would represent an increase in the biomass resource base, any sizable short- to mid-term increase in commercially viable resources is not feasible. Trees require 20 to 40 years to reach full maturity, and while crops such as switchgrass and alfalfa can be grown quickly, the infrastructure for utilizing them for energy is limited, as mentioned previously. Thus, in evaluating the potential for large increases in renewable-based electricity generation from a resource point of view, the conclusion is the same as previously—heavy reliance upon the existing biomass resource base and the generating capability of the Forest Products Industry.

In addition to the potential for traditional forest product companies to participate in the green power phenomenon, one must evaluate the degree of success which nontraditional participants in the national fiber market will experience. The principal nontraditional participant would likely be an electric utility considering cofiring biomass with coal. Scenarios for large increases in biomass-based power usually assume that some fraction of this electricity will come from cofiring. About 15 percent of a cofiring fuel mix can be biomass in theory. In practice, workable proportions may be closer to 5 percent. At the utility sector level, this scenario might imply that a big increase in biomass electricity subsumes participation by many buyers making relatively small, scheduled fiber purchases.

The viability of the utility cofiring scenario, at first glimpse, does not appear favorable. Forest product industries are usually located in close proximity to timber resources. In contrast, utility generating facilities are located according to a number of considerations: water availability, land acquisition capability and costs, environmental and safety issues, transmission and distribution costs, and proximity to population centers, among others. These considerations often do not put utility plants within an economically feasible range (generally 50 miles) of biomass resources; the amount of wood required to satisfy only 5 percent of fuel requirements is far too small to transport wood in a manner similar to that of coal. Thus, some utilities that might wish to cofire wood are faced with difficulties accessing fuel resources in a cost-effective manner.

Finally, a major limitation on the use of wood for energy within the Forest Product Industry is the fact that wood has a higher value for its primary end uses (e.g., paper, packaging, structural components, insulating materials, panels, composite materials, chemical feedstocks, mulch, animal bedding, sanitary products, components for automobiles, etc.) than for fuel. Using more wood for fuel would place upward pressure on the cost of primary products, unless additional forest resources are available near current costs.

The reality is, however, that there are many constrictions on the supply of forest resources. For many years, harvests outstripped timber production, and while supply has recovered somewhat in recent decades, significant pressures on supply sometimes develop. Also, the amount of cutting allowed on Federal lands has fallen drastically in recent years, largely for ecological reasons. Additionally, forest product companies enjoy long- established fiber supply relationships, contract arrangements, and sometimes own or lease timberland directly. Therefore, utilities and nontraditional generators would appear to be at a disadvantage with respect to obtaining significant additional wood supply.

About 50 percent of the national timber resource base is privately owned, however, with millions of acres in noncommercial hands. Some of it cannot be accessed by virtue of such factors as aesthetic considerations and buffer value, but a large quantity can. Buyers can contract directly with private landowners to harvest poor commercial quality trees or to thin understorey. Frequently, however, such activities are conducted by brokers who deal with all wood grades. Also, independent consulting foresters represent both individuals and groups of landowners and provide the reforestation knowledge and services that would be handled by the staff of large forest product companies and corporate timberland owners. Therefore, an infrastructure is already in place that can be used to advantage by nontraditional wood generators.

As mentioned earlier, large diversified forest product companies sometimes own "captive" timber resources. However, many of these companies are still not self- sufficient in fiber supply. Businesses that fall into the partly or wholly fiber-dependent category can be expected to oppose any changes in markets that introduce new demand and price pressures on the timber supply. Businesses that have excess timber reserves can be expected to favor increased biomass-based power output. In this respect, the market conditions for wood supply facing any nontraditional wood generator are dependent on local conditions and ownership characteristics.

These are some of the obstacles and opportunities which confront new biomass electricity generation. The structure of the Forest Products Industry reflects that, although there are only 500 to 1,000 very large corporate businesses, there are nearly 40,000 smaller businesses involved in forestry, logging, and sawmilling. Biomass-based power could develop into a huge new market for some of these businesses—eventually. From a national perspective, the potential opportunities of increased biomass electricity generation are great. Winners include small business, rural development, national energy security, and climate goals. In the immediate future, however, any substantial increases in power from biomass will come from the large Forest Products Industry firms, whose use of biomass for power is linked to their overall production of major products.

Geothermal

Producing electricity from geothermal resources involves a mature technology. The time from which a site is confirmed as having the potential (i.e., with sufficient water at temperatures high enough to drive turbine blades using a binary or flash system) to the time a facility can produce electricity is short—less than 3 years. However, due to the remote locations of geothermal resources, the cost of transmission may make the venture more expensive than a facility that does not need miles of transmission lines. Constructing transmission lines requires extensive environmental permits, the acquisition of which may stretch out for years before a permit is granted. Currently, two potential areas of geothermal resources are known to remain without a facility, both in Northern California. However, only one-third of the potential capacity estimated in 1992 is currently built.

The Northwest region has an abundant supply of electricity, most of it coming from the Bonneville Power Administration (BPA). The BPA recently backed out of contractual arrangements to purchase geothermal electricity from Northern California for this very reason. It is possible, however, that if consumer demand for "green energy" is sufficient, geothermal energy will be among the resources used.

Solar

The solar industry, especially the photovoltaics (PV) segment, has reduced product prices substantially in recent years. The industry has made major progress in all areas of performance, reliability, and costs, as well as consumer acceptance. For many years, State and Federal governments, as well as environmentalists and utilities, have strongly supported the use of solar energy—especially in the U.S. Department of Energy's research and development budget. However, attaining competitiveness with conventional fuels has been slowed by factors that affect the viability of all¹⁹¹ renewables, including declining though still relatively high capital costs for solar operations, the decline in the price of natural gas, the surplus of coal-fired energy, and the planned deregulation of electricity. In most cases, solar energy systems currently are not economical for grid-interactive applications.

As generation becomes deregulated, the solar energy industry will have to emphasize its niche market applications and newly derived opportunities (subscription to renewable energy power supplies, net metering, rooftop PV systems, and portfolio standards) in order to continue its technological and cost-reducing developments. Solar energy can fill many niche applications because of its unique characteristics of generally low maintenance costs, modularity, portability, and adaptability.

Distinct market niches with differing promise emerge in distributed generation, depending on market structure. Solar energy is consistent with the concept of the distributed utility. At present, utilities are the major market niche for distributed generation. They use distributed generation at substations to place generation closer to areas with new high load demand and, thereby, to minimize infrastructure costs associated with the con-struction of new transmission lines and generation facilities. The Hedge substation plant, for example, was completed by the Sacramento Municipal Utility District in 1995 for transmission and distribution support. It consists of four PV systems, totaling 527 kilowatts. In addition, distributed generation units are small and, as full retail access becomes a reality, smaller generators (from 2 megawatts up to 50 megawatts capacity) are likely to be in demand. Solar/PV stations fit well into this structure.

Currently, rooftop PV systems are benefitting from net metering. Under some net metering proposals, the customer's PV system offsets the retail electric rates rather than wholesale avoided costs, a plus to the consumer. Rooftop PV systems also have no-cost land for siting. The Sacramento Municipal Utility District is planning the installation of 1,000 such rooftop systems in its district. About 15 States, including California and all of the New England States, allow homeowners essentially to become small-scale solar power plants, running their electric meters backward and sending power back to their utilities when they generate more than they use (net metering). In a separate initiative, on June 26, 1997, in his speech before the United Nations Session on Environment and Development, President Clinton announced a national plan to install PV rooftop systems in 1 million homes by the year 2010.

Under most restructuring proposals, however, new grid-connected rooftop PV installations with net metering are unlikely because competitive pressures will eliminate mechanisms supporting higher cost generation. Utilities under restructuring, for example, will no longer be in the role of making low-interest loans for the rooftop equipment. On the other hand, the use of rooftop installations in remote areas to avoid construction of distribution lines should be economically viable. Also, solar energy is treated very favorably in many of the States that have passed renewable portfolio standards. For example, New York has set-asides totaling $750,000 per year for renewable projects; in 1996, 90 percent went to PV projects.

Wind

The greatest advantage of wind power is its potential for large-scale, though intermittent, electricity generation without emissions of any kind.¹⁹² In addition, over the years, wind energy's production cost has benefitted from improvements in technology and better reliability.¹⁹³ Wind power plants can be built in small, modular units (less than a megawatt each) within a relatively short time frame (2 years), so they offer power suppliers greater flexibility than plants that can be built only in large sizes and over longer periods of time. As noted below, this would be an advantage only in deregulated markets where major transmission investments are unnecessary.

About 1,700 MW of wind capacity operate in the United States, most of which is located in California because of utility incentives offered there in the 1980s.¹⁹⁴ This pattern is shifting, however, as other States develop wind power plants with a variety of local initiatives. Wind power facilities are now operating or under construction in Minnesota, Texas, Colorado, Iowa, Vermont, Hawaii, Wyoming, Michigan, New York, Montana, North Dakota, Oregon, and Wisconsin.

Analysis indicates that good wind resource areas with accessibility to nearby transmission lines do exist,¹⁹⁵ although it is perhaps more common that wind resources are located some distance from adequate transmission lines.¹⁹⁶ Larger wind developments (several hundred megawatts) are more likely to be able to justify investments in transmission.

Fixed, investment-related charges are the largest component of wind-based electricity costs. Improved designs with greater capacity per turbine have reduced investment costs to a quarter of what they were a decade ago, so that the cost per kilowatt of installed capacity is currently around $1,000 (1996 dollars).¹⁹⁷ Wind power plants incur no fuel costs, however, and their maintenance costs have also declined with improved designs.¹⁹⁸

At good sites, electricity generation from wind power now costs around 4 cents per kilowatthour (levelized) including the EPACT credit.¹⁹⁹ This is still higher than the cost anticipated from combined-cycle, natural gas-fired plants with present gas prices. If natural gas prices rise much, however, wind power will become competitive in selected markets.

Due to the intermittent nature of wind, a wind power plant's economic feasibility strongly depends on the amount of energy it produces. Capacity factor²⁰⁰ serves as the most common measure of a wind turbine's productivity. Estimates of capacity factors in 1997 ranged from 26 percent to 36 percent.²⁰¹

In the United States, wind power has a lower delivered cost than other new nonhydroelectric renewable electricity resources. Virtually all exploitable and economical hydroelectric sites have already been developed. Therefore, if the electricity supply industry moves toward a higher renewable fraction, wind power can be expected to play a significant role. While wind power has no air emissions, it does have other impacts on the environment. These are visual obstruction, bird kills, and noise pollution. Mitigation measures are frequently taken to resolve these problems.

Another major issue regarding wind intermittency is that wind power can offer energy, but not on-demand capacity. Even at the best sites, there are times when the wind does not blow sufficiently and no electricity is generated. Existing hydroelectric power offers the greatest complementarity with new wind power facilities in that it provides capacity but only limited energy. As the market is deregulated and becomes more competitive, ownership of dispatchable resources together with wind will be of greater value than either alone.

Related to intermittence is wind's unpredictable nature. Weather forecasting has improved markedly over the past several decades, so wind power plant operators can predict, to some extent, what their output will be by the hour. But that ability is imperfect at best. In the past, unpredictability was not as important because a large vertically integrated utility—particularly one with excess capacity—was able to dispatch whatever was needed at the time it was needed. As that capability is dispersed to competitors in the new deregulated industry, the problem will be exacerbated by market rules that require operators to bid into the exchange at least 24 hours in advance. Therefore, wind power plants will be at a disadvantage unless they are allied with suppliers offering appropriate levels of firm capacity.

Conclusion

The continued use of renewable-based electricity faces strong challenges in a competitive electricity market. Renewable energy sources, while relatively benign environmentally, are generally higher cost options for generating electricity. In order to maintain renewables as a generating option, a number of strategies have been put in place or proposed. One or more of these mechanisms—renewable portfolio standard (RPS), system benefits charge (SBC), public benefit fund (PBF), net metering, green marketing—are generally part of Federal and State proposals to support renewables while their costs continue to decline.

Endnotes

160. Essentially, PURPA defines two groups of "qualifying facilities": (1) "small power producers" with rated capacity less than 80 megawatts that obtain at least 75 percent of input energy from renewable sources and (2) renewable-based cogenerators. Utilities may not own more than 50 percent of a qualifying facility.

161. U.S. Department of Energy, Office of Budget, DOE History Tables.

162. Total generation for 1997 is estimated to be 3,533 billion kilowatthours. Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(98/03) (Washington, DC, March 1998), Table 7.1 states that renewables' share of total generation in 1997 was unusually high due to record high hydroelectric generation.

163. Pumped storage plants are not considered renewable since energy is consumed to pump the water to the upper reservoir.

164. Excluding electricity imported by utilities.

165. An exempt wholesale generator (EWG) is a nonutility electricity generator that is not a qualifying facility under the Public Utility Regulatory Policies Act of 1978 (PURPA). EWGs were created by the Energy Policy Act of 1992 (EPACT), and made exempt from provisions of the Public Utility Holding Company Act of 1935 (PUHCA). The exemption of EWGs from PUHCA regulations eliminated a major barrier for utility-affiliated and nonaffiliated power producers who want to compete to build new non-rate-based power plants.

166. State-level data for 1997 were not available when this report was published.

167. In California, qualifying facilities (QFs) typically enter pre-approved contracts called Standard Offer Contracts with utility companies. These contracts vary by the difference between short- and long-term costs based on the utility costs they displace. Short-term avoided costs are generally calculated to reflect the costs that would have been incurred to supply the energy otherwise. These costs are based on the utility's marginal generating costs, varying with the fuel in use and seasonal demand. Long-term avoided costs are designed, in addition to reflecting marginal costs, to include the costs of a resource (capital cost) that the utility would have constructed in lieu of the QF resource.

168. A price cap is a value set on a credit that would be sold by the government to limit the price they would be traded for. The cap, in effect, limits the cost of renewable electricity to consumers. Monies collected by the government from the sales of credits could be used to support renewable technologies.

169. The terms used to describe such a charge include public benefit charge, access charge, wires charge, systems benefit charge, and universal service charge. Although these terms differ, the concept is the same.

170. Net metering, in effect, measures the difference between the total generation of a facility and the electricity consumed by the facility with a single meter that can read electricity flows in and out of a facility. Hence, the meter will record the net energy received by the facility or, if the facility generated more than it consumed, the energy delivered to the grid.

171. Green marketing programs were first introduced by companies like Detroit Edison, Gainesville Regional Utilities, Sacramento Municipal Utility District, Public Service of Colorado, and Traverse City Light and Power.

172. B.Fahrar and A. Houston, "Willingness to Pay for Electricity from Renewable Energy," Proceedings of the 1996 ACEEE Summer Study on Energy Efficiency in Buildings (August 25-31, 1996), pp. 2-6. However, a clearer indication of what people will actually pay can be determined by undertaking local-area market research. Only 10 percent of the respondents in one such local area survey indicate they would participate in a specific green pricing program. In fact, several local-area market research studies indicate that at the program's inception, only 1 percent will actually sign up.

173. While over 100 nonutilities initially announced plans to service the California market, only 27 nonutilities had formally filed to offer electricity as of April 1, 1998.

174. ILCS 5/16-127 (new) -- Public Act 90-561.

175. Power marketers participating in the Green-e Branding Program as of November 1, 1997, were Edison Source, Foresight Energy, PacifiCorp, Enron Energy Services, Green Mountain Energy Resources, Electric Clearinghouse, Bonneville Power Administration/Environmental Resources Trust, and the Sacramento Municipal Utility District. Planning to enter the market by mid- to late 1998 were PG&E Energy Services and Cleen 'n Green.

176. It should be noted that the premium paid by consumers for green power would be used to increase the amount of renewable-based electricity available on their system, or, powerpool. It is not a direct purchase of renewable-based electricity from supplier to consumer.

177. Actually, green pricing creates an increased risk in a competitive market that, should consumer preferences turn away from renewables, less renewable electricity might be demanded than if the utility under the existing "rate of return" rate making scheme rolled a small amount of higher-cost renewable-based electricity into its overall rates.

178. In general, "levelized cost" is the present value of the total cost of building and operating a generating plant over its economic life, converted to equal annual payments. In the context of this report, levelized costs are the calculated average busbar costs per kilowatthour of generating electricity over the plant lifetime, including overnight capital costs per kilowatt, fixed operations and maintenance (O&M costs per kilowatt, variable O&M per kilowatthour, and fuel costs per kilowatthour, using a specified discount rate.

179. The regions used in this chapter are based on EIA NEMS model Electricity Market Module regions as shown on p. xiv of Energy Information Administration, Electricity Prices in a Competitive Environment, DOE/EIA-0614 (Washington, DC, August 1997). These regions are synonymous with the NERC regions and subregions.

180. C.T. Donovan Associates, Inc., Scoping Study of Renewable Electric Resources for Rhode Island and Massachusetts, Volume 2: Life Cycle Cost Analysis (Burlington, VT, November 1997).

181. Tariff is a set of schedules filed with the regulatory authority specifying lawful rates, charges, rules, and conditions under which service is provided.

182. "Pancaked" transmission rates refer to paying multiple rates on top of one another. For example, if postage stamp transmission rate, schedules are in effect, then a firm which had transmission facilities outside a single "zone" would have to pay for crossing into another "zone"; hence, the term "pancaked."

183. Biomass includes wood, wood waste (e.g., black liquor from paper pulping operations), municipal solid waste, manufacturing wastes, ethanol, and "other biomass" (e.g., used tires, utility poles, and various combustible gases which are byproducts of manufacturing.)

184. Based on sector analysis of data in Energy Information Administration, Manufacturing Consumption of Energy, 1994, DOE/EIA-0512(97) (Washington, DC, December 1997), Table A43.

185. These are usually wood waste streams but can be from a wide variety of sources, such as rice hulls or bagasse from sugar harvesting.

186. "Energy crops" are any crops grown and dedicated for energy production, with the intent that the generating facility can be "sustainably supplied" by these crops.

187. For example, a 75-megawatt generating plant, which will be fueled by a sustainable alfalfa supply grown by regional farmers, is being built in Minnesota.

188. The ownership of resources by an entity using that resource is known as "captive ownership."

189. Understorey is composed of the noncommercial timber and scrub vegetation growing amid commercial-grade timber.

190. Some companies go a step further and now offer the retail pubic "green tagged" building products, reflecting that they have been manufactured by use of sustainable and environmentally responsible practices.

191. R&D expenditures for solar energy activities (solar thermal and photovoltaic) account for about 31 percent of the DOE proposed FY 98 R&D budget. See U.S. Department of Energy, Solar and Renewable Resources Technologies Program, GAO/RCED-97-188 (Washington, DC, July 1997) Table 1.

192. D.L. Elliot and M.N. Schwartz, "Wind Energy Potential in the United States," National Renewable Energy Laboratory (Golden, CO, 1997), Figure 3. See Web site www.nrel.gov/wind/potential.html.

193. "Wind Industry Criteria for Restructuring the Electric Industry" in American Wind Energy Association, AWEA Compilation on Electric Industry Restructuring (Washington, D C, Spring 1997)

194. Energy Information Administration, Electric Power Annual 1996, Volume II, DOE/EIA-0348(96)/2 (Washington, DC, December 1997).

195. See National Renewable Energy Laboratory, U.S. Wind Reserves Accessible to Transmission Lines, Review Draft (Golden CO, August 1994).

196. J. P. Doherty, Energy Information Administration, "U. S. Wind Energy Potential: The Effect of the Proximity of Wind Resources to Transmission Lines," Monthly Energy Review DOE/EIA-0035(95/02) (Washington, DC, February 1995), pp. vii-xiv.

197. Energy Information Administration, Annual Energy Outlook 1998, DOE/EIA-0383(98) (Washington, DC, December 1997), p. 217.

198. Energy Information Administration, Renewable Energy Annual 1996,DOE/EIA-0603(96) (Washington, DC, March 1997), p. 47.

199. By comparison, the American Wind Energy Association estimates the cost at 3 cents per kilowatthour. See "Renewables in a Competitive Environment," in American Wind Energy Association, AWEA Compilation on Electric Industry Restructuring (Washington, DC, Spring 1997).

200. Capacity factor is the ratio of the electrical energy produced by a generating unit for the period of time considered to the electrical energy that could have been produced at continuous full-power operation during the same period.

201. Electric Power Research Institute and the U.S. Department of Energy, Renewable Energy Technology Characterizations, EPRI TR-10946 (Palo Alto, CA, December 1997), pp. 6-12.