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wind energy policy, transmission & regulation The Mechanics of a Renewables Portfolio Standard Applied at the Federal LevelNancy Rader, Policy
Advisor
[1]The Renewables Portfolio Standard (RPS) is market-based policy for increasing the amount of renewable energy serving our country. It requires all generators or retail sellers of power[2] to demonstrate, through ownership of tradable "renewable energy credits," that they have supported the generation of a certain amount of renewable power. Because the RPS applies equally to all competing electricity providers, it is competitively-neutral. The regulatory role is limited to certifying credits, verifying that generators possess the required number of credits at the end of each year, and imposing a significant penalty for non-compliance on those that fall short. This penalty is sufficiently large to ensure full compliance. A primary advantage of the RPS as compared to the "system benefits charge" method for promoting the commercial development of renewables is that it does not require the centralized collection and dissemination of funds or require state agencies to make decisions about winners and losers. The market makes all decisions regarding which renewable plants to build, where, and for what price. The bottom line is results: the generation of renewable power by a date certain. We can expect the market to deliver these results at the lowest possible cost. Definition of "Renewable energy"This term refers to natural energy resources that are inexhaustible: wind, solar, geothermal, biomass, and hydropower.[3] However, for the purpose of qualifying for benefits under the RPS, "renewable energy" can be defined in the policy process to include only those renewable resources that the nation wishes to particularly encourage. Encouragement is most appropriate for those resources and technologies that currently produce an insignificant amount of total U.S. electricity generation, but which have great potential to provide a significant share of the nation's power within the next decade and beyond. Fitting that description would be wind, solar, geothermal and biomass. To accommodate hybrid facilities that were developed under PURPA rules, the definition could allow for the use of up to 25% fossil fuels on an annual basis. Either all of the output could qualify as renewables, or the output could be pro-rated to reflect only the proportion which was fueled by renewable resources. In the latter case, the fossil fuel percentage limit could be increased. Renewable Energy Credits, or "RECs"Renewable Energy Credits ("RECs") are central to the RPS. A REC is a tradable certificate of proof that one kWh of electricity has been generated by a renewable-fueled source and sold to an end-user in the state. RECs are denominated in kilowatt-hours (kWh) and are a separate product from the power itself. Each credit is proof of actual generation and sale of renewable electricity—not merely proof of capacity. The RPS boils down to a requirement that every generator possess a number of RECs equivalent to a determined percentage of its total annual kWh generation (or sales). For example, if the RPS is set at 5%, and a generator sells 100,000 kWhs in a given year, then it would need to possess 5,000 RECs at the end of that year. The sale of RECs is the mechanism by which revenues are transferred from generators to the most competitive renewable energy generators to maintain their economic viability. Its purposes are to provide a means of demonstrating compliance with the portfolio standard, and to provide a cost-reducing alternative to complying with the standard compared to reliance solely on renewable power generation. The RECs are owned by the renewables generator and may be bundled for sale along with its power, or RECs and power may be sold separately into their respective markets at prevailing market prices. The trading of RECs also creates a competitive market for renewable power since renewable energy generators will compete to lower the cost of their power generation, and therefore the price of their RECs, to assure that both their power and their RECs are purchased. Likewise, generators can purchase RECs when they purchase renewable power (a "package" of RECs and power), or they can purchase RECs separately—either directly from a renewables generator or from the REC market. Thus, generators can decide whether to build a renewable energy facility, purchase renewable power bundled with RECs, or buy credits separately. Generators also make all decisions relating to the type of renewable energy to acquire, the price paid, the contract terms offered, and whether to enter into long-term REC and/or renewable power purchase contracts or to purchase these commodities on the spot market. The REC system provides compliance flexibility and avoids the need to "track electrons." The REC concept is patterned after the SO2 credit-trading program under the federal Clean Air Act and the emission-reduction credit trading program of the South Coast Air Quality Management District's Regional Clean Air Incentives Market (RECLAIM) Program in Southern California. The efficiency and cost-savings accomplished under these market-based programs have surprised the world. SO2 allowances that were predicted to cost $600/ton or more under regulation-as-usual have fallen to just $85/ton under the market-based trading system. Under the RECLAIM program, in addition to bilateral trading, a semi-annual "Clean Air Auction" is sponsored by the New York-based brokerage firm of Cantor Fitzgerald, which also recently opened a web site for environmental credit traders, enabling them to make immediate exchanges. Similar automated markets would develop under the RPS's credit trading system. Cost-Reducing Dynamic of the RPSThere are several ways in which the RPS assures least-cost achievement of the nation's renewable energy goals. Cost savings are first achieved because the certainty and stability of the RPS policy will enable long-term contracts and financing for the renewable power industry, which will, in turn, lower renewable power costs. Least-cost compliance is encouraged through the compliance flexibility provided to generators, who can compare the cost of owning a renewables facility to the cost of a REC/renewable power purchase package and to secondary-market RECs. Finally, since generators will be looking to improve their competitive position in the market, and since all must meet the standard, each generator will have an interest in driving down the cost of renewables, perhaps by lending their own financial resources to a renewables project, by seeking out least-cost renewables applications, or by entering into long-term purchasing commitments. This fosters a "competitive dynamic" that is not achieved with policies that involve direct subsidies to renewable generators without involving the rest of the electric industry. Cost ContainmentEnough is known about the range of possible market conditions and the cost of renewables to predict within reasonable bounds the estimated cost of an RPS at different percentage-requirement levels. Ordinarily, there are no conditions under which standards (e.g., building codes, safety requirements, etc.) can be avoided. This is because loopholes could be created that might undermine the standard, and because it complicates enforcement. However, an RPS policy can be designed to include a simple system of cost containment that avoids these complications. Here's how it works:
The maximum possible cost of the RPS would be the number of RECs required under the standard (under various assumptions for growth in total kWh sales) multiplied by the cap price. This method was carefully devised to avoid undermining the market for RECs. If the cap price is sufficiently in excess of the expected market price, it will preserve a vigorous market for renewables. It will also preserve marginal-cost competition for credits because renewable energy generators will compete to sell their credits both below and above the cap price. This will serve to keep the price of RECs as low as possible. This cost cap mechanism may never be used, however, since the market can be expected to deliver renewables well below the cap price. Expected CostsThe expected cost of the RPS is significantly lower than the maximum set by the cost cap. The expected cost can be estimated by comparing the marginal cost of electricity sold in the state to the marginal cost of the renewable power that is needed to satisfy the standard. The difference, multiplied by the total amount of renewables required, is the expected cost. This type of analysis was performed to determine the cost of a nationwide RPS set at 2% in 2000, 3% in 2005, and 4% in 2010. The study found that an RPS set at these levels could be achieved at a very modest cost. In its first year, it would likely cost nothing at all. In the year 2010, it would probably cost only three hundredths of one cent per kilowatt-hour, adding about 16 cents per month to the average (500 kWh/month) residential electric bill.[4] According to the same analysts, a 10% RPS in the year 2010 would add approximately $1.30 on a typical monthly household bill.[5] These are direct costs that do not take into account the fact that market prices for power do not reflect the full costs of traditional resources or the full benefits of renewable resources, including fuel diversity, environmental benefits, and domestic economic benefits. In addition to these immediate benefits, the RPS will create a renewable energy infrastructure that will enable the country to respond quickly to potential shocks to energy markets. If fuel prices should rise and/or additional environmental protection regulations (e.g., a carbon tax) should materialize, the RPS will result in substantial additional direct-cost savings. When renewables become competitive with conventional electricity sources on a direct-cost basis, the RPS self-sunsets. That is, as the cost of conventionally fueled power rises and the cost of renewable power declines, RECs will have less and less value. When the value stabilizes at virtually nothing, the RPS will no longer be needed. It is important not to sunset the program before this point, since costs can be reduced substantially if the standard is expected to be in place until renewables are fully competitive. A stable RPS will enable long-term contracts and lower-cost financing. Without long-term policy stability, the cost of renewable energy projects could increase by 25-50% as a result of increased financing costs.[6] Percentage RequirementAn RPS is best designed to preserve the existing level of renewable energy serving the nation and then to gradually increase the percentage requirement to achieve greater diversity over time. A yearly increase in the standard would create the best conditions for renewable energy suppliers since it would prevent "boom and bust" cycles that might be caused by large percentage increases that occur every five years or so. A constant, predictable market will also foster lower costs since renewable energy industries will not have to go through cycles of layoffs and rehiring, losing human resources and institutional memory along the way. If the RPS is set to take effect within a short time after its adoption, it should begin at a level that is slightly less than the amount of energy which can be delivered by the existing renewable energy generators in order to create competition among those generators at the outset. If the policy becomes effective far enough in the future to allow new renewable facilities to come on line, giving generators the ability to bargain effectively for REC purchases from existing facilities and/or to obtain RECs from new facilities, the standard can be set at existing or higher levels. Given the relatively short lead-time required for renewable energy facility development, two years would provide plenty of advance time. Reporting and ComplianceReporting is straightforward, involving two separate procedures at the administering agency: (1) renewable producers voluntarily certify their kilowatt-hour output and apply for an equivalent number of RECs; (2) generators comply with the standard by demonstrating ownership of a sufficient number of RECs in relation to electricity generation (or sales). With regard to the first, renewable-resource generators report and certify the number of RECs created as a result of their generation. Proof of sale of renewable power in the U.S. is required. With regard to the second, generators document and report their total generation in kilowatt-hours (kWhs) for the previous year and ownership of a sufficient number of RECs. At the end of the year, the administering agency simply compares the generators' reports with the renewable producers' reports, in much the same manner as the Federal IRS compares taxpayer reports of income with the 1099 forms filed by the payers of that income. Alternatively, the accounting could be handled through an electronic system as follows. (i) Renewable Facility Producer A generates credits (by generating renewable power) which are posted by the administering agency (or its private agent) into an electronic account for that producer, and so forth for all producers. (ii) Generator Z purchases RECs from Producer A. Both sign a form requesting the administering agency to transfer the purchased number of RECs from Owner A's account into Generator Z's account. (iii) At the end of the annual reporting period, the agency informs all generators of their REC account status and asks them to document their total kWh generation. At the end of a three-month true-up period, the required number of RECs are removed from each generator's account and retired. (iv) For generators who have insufficient credits in their accounts, the agency imposes the appropriate penalty. TOPPenalties and EnforcementFor generators that fall short of the required number of credits at the end of the reporting period, an automatic penalty for non-compliance is assessed. The amount of the penalty is three times what it would have cost to purchase each REC that the generator should have acquired. This penalty is estimated to be about 3¢ to 5cents¢ per RE--C—high enough to encourage full compliance, yet not so high as to encourage litigation. The high penalty level is intended to make the policy self-enforcing by avoiding the need to resort to costly administrative and enforcement measures. It is modeled after the federal SO2 allowance trading program, under which an automatic $2,000/ton penalty (indexed to inflation) is imposed for each excess ton of SO2 produced. SO2 credits are trading currently at about $100 each, though costs were originally projected to fall between $500 and $1500. Because of the high penalty associated with noncompliance under the SO2 allowance program, which took effect in 1995, the EPA did not take a single enforcement action in the policy's first effective year. Another similar program is NEPOOL's capacity reserve requirement, under which each participant is fined $105/kW-year for capacity shortfalls. This is well in excess of compliance costs, and has successfully deterred non- compliance (though the fine has been assessed and paid on several occasions). The RPS penalty is different than the cost cap, because it far exceeds expected costs. The cost cap is intended to protect those who make a good-faith effort to comply and cannot find RECs below the cap price. The penalty is to ensure that everyone makes that good faith effort so that an active credit market is created and to ensure that generators are engaged in thinking about how to generate renewables (or incorporate them into their resource portfolio) at least cost, instead of seeking ways out of the program. Though few penalties are expected to be collected, in the event that a few penalties are incurred, penalty funds could be allocated to support renewables R&D, including the commercialization of emerging renewable energy technologies. The Attorney General could handle seriously delinquent accounts and criminal behavior. Flexibility ProvisionsA number of provisions are built into the RPS concept to provide compliance flexibility:
It is necessary to exclude large hydropower from the RPS for several reasons. Though hydro brings public benefits in terms of avoiding the air emissions and wastes associated with conventional power plants, hydro is technologically mature, is fully commercialized (representing a significant share of the electricity market), and has limited development potential. Most importantly, including hydro in the RPS would create several intractable practical problems: (a) output from the large base of Canadian hydro projects could potentially be rerouted into the U.S. market and "flood" that market, depressing prices to levels too low to support non-hydro renewables; (b) the large year-to-year fluctuations in hydro output would make it difficult to meet a fixed standard each year and at the same time provide a predictable market for renewables; and (c) many hydro facilities have more than one use and have been built with the aid of large government subsidies. Therefore, it may be difficult to avoid cross-subsidizing irrigation, recreation, flood control, etc., through payments to hydro via the RPS. Including hydro projects under some size limit (no more than 30 MW) may help to keep in operation those projects that will have difficulty competing in the market (especially those with high environmental mitigation costs). Encouraging a Diversity of Renewables— The RPS in its simplest form is a strategy for diversifying the electric supply with the lowest-cost renewable power available, as judged through market competition. Its primary purpose is not aimed directly at technology commercialization, though it will certainly encourage private investment in technology advancement. A diversity of renewable resources will be encouraged because generators and investors are likely to seek out the most cost-effective technologies and technology applications, thereby taking advantage of the most cost-effective applications of each resource (i.e., the low-cost end of the supply curve for each resource). Because the cost of many renewable technologies, e.g., wind, geothermal, landfill gas and some solid-fuel biomass and some solar thermal facilities, are in the same competitive range, the market is likely to result in a diversity of resources and technologies. The market can also be expected to seek out cost-effective niche applications of renewables, such as distributed applications of photovoltaics. Higher-cost technologies can be encouraged through commercialization programs (e.g., those funded by system benefits charges), which can work along side the RPS. Because the RPS creates a market for renewables, it will help to close the gap between the cost of pre-commercial technologies and the renewables-market price. As a result, technology commercialization program dollars can go farther as a result of the RPS. Self-generationSurplus renewables generation that is metered and sold at retail from customer-owned, grid-connected renewable facilities could be eligible for RECs. If a simple method is available to measure the power produced by these systems that is consumed on-site, that generation could also qualify for RECs. Though off-grid renewable self-generation applications could qualify for RECs, there are two reasons for not including them: (1) most off- grid self-generation applications are already competitive as compared to T&D line extensions; and (2) off-grid applications are not metered or sold at retail, and thus verification of production would be difficult. If policy-makers nevertheless want to encourage off-grid renewables, procedures could be developed to estimate production, though verification could entail high transactions costs. Allocating RECs from Existing FacilitiesAn RPS policy creates a new, unanticipated source of income for existing renewable energy facilities. If those facilities are operating under an existing contract, RECs can be allocated by policy-makers to either party. In most circumstances, the RECs should be allocated to the plant owner, since it took the initial investment risk and may now need the REC income to maintain operations. Indeed, one of the objectives of the RPS is to preserve the existing level of renewables generation, and that is achieved most efficiently if REC revenues flow to the generator. In addition, only the generation facility knows what it needs to operate, and therefore it is in the best position to bargain for the sale of its RECs in the market. Finally, allocating RECs to the other party to the contract, the power purchaser, could create a "tilted playing field" with regard to contract buy-out negotiations. However, there are countervailing reasons that justify allocating RECs to the power purchaser and transferring RECs to the generator only after it exits its contract. Chiefly, this would create an incentive for generators to exit PURPA contracts, facilitating movement toward a "clean slate" in the new competitive markets. One caution is that this could create a market advantage for utilities that would possess a significant fraction of total RECs at no added cost. A remedy to this situation would be to require RECs to be auctioned off by a designated marketing agent and apply the proceeds to reduce stranded costs, thus benefitting ratepayers. The RPS and Green MarketingThe RPS will create a stronger customer market for renewables. By developing a base of renewables and creating a healthy renewable energy industry, individual consumers are more likely to have the opportunity to support renewables through their choice of suppliers in the market. More fundamentally, the RPS addresses the "free rider" problem associated with all markets that deal in goods that have large benefits to society but which don't accrue specifically to the purchasing consumer.[7] The RPS will create a renewable energy industry that is strong enough to engage in green marketing, which will entail high transaction costs in reaching prospective customers. Finally, the RPS will help to reduce the cost of renewables, which will make them more attractive to consumers. Footnotes 1. This summary is based on the concept developed in 1995-6 by the American Wind Energy Association and the Union of Concerned Scientists. Many people made important contributions to the development of the policy as described here, including Nancy Rader, Brent Haddad and Richard Rosen. This summary draws largely from the first detailed proposal of the RPS, which was formally submitted to the California Public Utilities Commission in August 1996 by AWEA, the California Biomass Energy Alliance, the Geothermal Energy Association, and the Solar Thermal Electric Alliance. 2. At the federal level, the RPS can be applied to either generators or retail suppliers. From here forward, this paper will refer only to generators. (To avoid potential state/federal jurisdictional conflicts, states must apply the RPS to retail sellers. See Scott Hempling and Nancy Rader, "State Implementation of Renewables Portfolio Standards: A Review of Federal Law Issues." January 1996.) 3. See below for a discussion of issues relating to hydropower. 4. This analysis was performed for the Union of Concerned Scientists by the Tellus Institute using the Department of Energy's National Energy Modeling System. 5. Stephen Bernow, "Analysis of Renewable Portfolio Standards," June 1997. 6. Ryan Wiser and Steven Pickle, Financing Investments in Renewable Energy: The Role of Policy Design and Restructuring. Lawrence Berkeley National Laboratory. March 1997. 7. For a discussion of this issue, see Nancy A. Rader and Richard B. Norgaard, "Efficiency and Sustainability in Restructured Electricity Markets: The Renewables Portfolio Standard," The Electricity Journal. July 1996.
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