 Government policies that mandate grid-connected renewable energy are used to accelerate market deployment for renewable energy systems and equipment. Several justifications exist in support of these policies. First, by accelerating market deployment, the technologies will more quickly achieve cost reductions from learning and economies of production, and this will speed up the date by which they be economically competitive without these promotional policies. Second, countries with such policies are very likely to grow strong industries to provide renewable energy systems and equipment that can quickly capture export markets as their technologies become more competitive in other markets.
Three categories of policies are discussed: Price Mandates, where renewable energy generators are paid fixed prices for the electricity they provide to the grid, Market Share Mandates, where all electricity providers must obtain a specific market share quantity of renewable energy generation, and Competitive Bidding, where set quantities of renewable energy generation are purchased on the basis of open competitive solicitations.
The effectiveness of any set of government policies depends on how well they are designed and whether or not they are enforced. The use of a particular policy type does not guarantee success. In addition, the policies need to be appropriate to the types of technologies, projects and applications they are trying to promote. See a Comparison of Market Mandates. Furthermore, each country has unique circumstances and must design and enact its own set of policies based on needs, competing interests and available resources. See Requirements for a Successful Policy. All these mandated market policies need to address who will pay for the incremental financial costs between renewable energy and conventional energy sources. In general, there are four principle approaches: 1) the most common approach is that incremental costs are passed on to consumers and shared among the entire population or customer base by an additional per kilowatt-hour (kWh) charge; 2) incremental costs are covered by public funds such as system benefit charges in the US; 3) incremental costs are covered by a carbon tax on fossil fuel consumption, for example, in the UK; and 4) incremental costs are covered through a Green Fund from government budget and donor support, for example, in Mexico. 
Price Mandates Price-setting policies reduce cost and pricing related barriers by establishing favorable price regimes for renewable energy relative to other sources of power generation. The quantity of investment obtained under such regimes is unspecified, but prices are known in advance. With price-setting policies it is not possible to know in advance how much generation or capacity will result or, indeed, if the share of renewable energy generation will increase over the long-term. However, tariffs can be adjusted up or down to encourage more or less investment in renewable energy in order to bring installations in line with desired targets. The two main price-setting policies seen to-date are the PURPA legislation in the United States and “electricity feed-in laws” in Europe. Under a price setting policy, electric utilities are obligated to allow renewable energy plants to connect to the electric grid, and they must purchase any electricity generated with renewable resources. Net metering laws permit consumers to install small renewable systems at their homes or businesses and then to sell their excess electricity into the grid, which must purchase the power at retail market prices. Net metering is a limited form of feed-in tariff. PURPA PURPA (The U.S. Public Utilities Regulatory Act of 1978) required utilities to interconnect with and buy energy from “qualifying facilities,” including renewable energy plants, at incremental or avoided costs of production. In California, the implementation of PURPA involved the use of standardized long-term contracts with fixed (and, in some cases, increasing) payments for all or part of the contract term. The costs of the contracts were covered through higher electric rates for consumers. The time length of the contracts (15 to 30 years for wind projects), combined with fixed energy prices for much of that time, assured producers of a market for their product and finally gave them something they could take to the bank to obtain financing. PURPA was fundamental to the birth of the renewable energy business in the US, and during the 1980s California became the world’s leader in renewable energy use. However, by the 1990s energy prices had not risen as originally expected and a large number of natural-gas fired independent power plants came on-line in California. Power surpluses emerged, wholesale power prices declined, and declining standard offer rates led to reduced competitiveness of renewable energy and a significant slowdown in construction of new capacity. Electricity Feed-In-Law Under an electricity feed-in-law, electric utilities are obligated to allow renewable energy plants to connect to the electric grid, and they must purchase any electricity generated with renewable resources at fixed, minimum prices. These prices are generally set higher than the regular market price, and payments are usually guaranteed over a specified period of time. Tariffs may have a direct relationship with cost or price, or may be chosen instead to spur investment in renewable energy. The early pricing laws adopted in Europe (Denmark and Germany) guaranteed producers a minimum share of the retail electricity rate—at least 85 percent in Denmark, and 90 percent in Germany. These laws were revised in the late 1990s, and today most pricing laws provide a fixed payment for renewable electricity that varies by technology type, plant size, and occasionally by location (e.g., wind energy), and is generally based on the costs of generation. Payments guaranteed to new projects decline annually, and are adjusted every two years. The tariffs last for 20 years from date of project installation. German electric utilities now qualify for these payments as well. The costs of higher payments to renewable energy producers are covered by an additional per kilowatt-hour (kWh) charge on consumers. In most countries, the charge is levied on all customers according to their level of use. In the early pricing laws, only some utility customers were required to purchase green electricity, but these features caused inequities and were changed (e.g., Germany in 2000). In a few cases, taxpayers share in the cost, such as in Denmark through a combination of feed-in rates and reimbursement of a carbon tax. Laws similar to Germany’s Pricing Law (DOC) have been enacted in Spain, and several other European countries, including France, Austria, Portugal, and Greece, in addition to South Korea. Recently, both Brazil and China have enacted legislation that combines pricing laws and mandated capacity targets. To date, those countries that have experienced the most significant market growth and have created the strongest domestic industries have had price-setting laws. For example, in Germany, wind power purchase prices were highly favorable, amounting to about DM 0.17/kWh (US 10 cents/kWh), and applied over the entire life of the plant. As a result, total wind power installed went from near zero in the early 1990s to over 8500 MW by 2001, making Germany the global leader in renewable energy investment. Similarly, a combination of feed-in tariffs, production subsidies of DK 0.10/kWh, and a strong domestic market helped the Danish wind industry maintain a 50% market share of global wind turbine production for a number of years. At the same time, it is important to note that pricing laws have not succeeded in every country that has enacted them. In order to succeed, tariffs must be high enough to cover costs and encourage development of particular technologies; they also must be guaranteed for a time period long enough to assure investors of a high enough rate of return. The success of pricing laws is also determined by factors such as charges for access to the electric grid, limits set on qualifying capacity, and the ease of permitting and siting (as influenced by the existence and specifics of national or regional standards). For developing countries, the critical concern regarding feed-in laws is that the price for renewables may be set too high and the cost to the country will be greater than it would have be under a more market-based incentive. On the other hand, markets are apt to be particularly sensitive to the need for relatively uncomplicated access to the electric grid and low transaction costs. Pricing laws allow for ease of entry into the marketplace and tend to favor smaller companies and incremental investment, making them particularly suited to developing countries, where power markets are often small and dispersed. As in the industrial world, it is critical to focus on models of development that are viable, sustainable, and replicable, and that emphasize local participation and ownership. Net Metering A limited form of feed-in tariff, “net metering,” permits consumers to install small renewable systems at their homes or businesses and then to sell their excess electricity into the grid. This excess electricity must be purchased at retail market prices by the utility. In some cases, producers are paid for every kilowatt hour (kWh) they feed into the grid; in other cases they receive credit only to the point where their production equals their consumption. This policy option has been adopted in Japan, Thailand, Canada, and at least 38 U.S. states, including Texas and California. It is of benefit to electricity providers as well as system owners, particularly in the case of PV, because excess power generated during peaking times can improve system load factors and offset the need for new peak load generating plants. Net metering differs from the access and pricing laws in Europe primarily in scale and implementation. Success in attracting new renewable energy investments and capacity depends on limits set on participation (capacity caps, number of customers, or share of peak demand); on the price paid, if any, for net excess generation; on the existence of grid connection standards; and on enforcement mechanisms. Without other financial incentives, net metering is not enough advance market penetration. Neither California nor Texas saw much benefit from net metering for wind power, let alone for more costly renewables like solar PV, until other incentives were added to the mix. However, net metering might have a greater impact if private generators were to receive time-of-use rates for the electricity they put into the grid—particularly in the case of solar PV, which generate electricity at peak demand times when the value of their power is highest. Net metering can be (and often is) used simultaneously with quantity mandates.
Market Share Mandates Market share policies mandate that a certain percentage or absolute quantity of generation to be supplied from renewable energy, at unspecified prices. The government sets a target and lets the market determine the price. Typically, governments mandate that a minimum share of generating capacity or electricity generation come from renewable sources. The share required often increases gradually over time, with a specific final target and end-date. The mandate can be placed on producers, distributors or consumers, but is generally placed on the distributors if they are distinct from generators. The Renewable Portfolio Standard (RPS) is a quantity mandate policy. The RPS is a policy measure that legally established a target for the minimum amount of capacity or generation that must come from renewable energy sources according to a specific schedule leading to a target amount at some future date. The types of renewable resources or technologies that can be used to meet the target are specified and defined as qualifying resources. In addition, fees are usually established for non-compliance. Solar, wind and geothermal technologies are generally included as qualifying resources, but some forms of biomass (municipal wastes) or hydropower above a specific size may be excluded. Some RPS legislation even includes energy efficiency. All these accepted technologies compete equally for supply contracts, and developers negotiate for the price and contract terms they will accept. In a few cases, specific targets are established by technology type so that, for example, solar PV does not have to compete against wind. At the end of each target period, electricity suppliers must demonstrate that they have met their target market share through the ownership or purchase of qualifying renewable energy sources. In most cases, they can also purchase renewable energy credits on the open market to meet a portion of their requirement. Fees for non-compliance are usually set at levels that will encourage the electricity suppliers to meet the targets. As of the end of 2005, twenty U.S. states, covering more than 35 percent of the U.S. electricity demand, have mandated quotas through RPS laws. Market share policies are now in use in several other countries as well, including Japan, the United Kingdom, Italy and Australia. With an RPS, as with the price-setting policies, the additional costs of higher payments to renewable energy producers are paid through a special tax on electricity or by a higher rate charged to all electricity consumers. Because RPS laws establish specific targets for renewable energy, there is certainty regarding the future share of the market, and this provides producers and manufacturers with a predictable, steadily-growing market. One concern regarding market share policies is that the speed with which technologies are introduced is based on a political decision that might be largely unrelated to technical progress and the efficiency of using renewable energy. However, as with pricing laws, many of the problems associated with market share laws can be overcome with careful system design. In any event, many economists prefer quantity-forcing policies because they allow the market to set prices. On the other hand, some analysts believe that the lower purchase prices common under bidding or RPS systems result in lower levels of installed capacity. In fact, pricing laws have consistently proved most successful at promoting the growth of renewable electricity capacity and generation. While more than 45 countries installed wind capacity during the 1990s, just three, with pricing laws (Germany, Denmark, and Spain) accounted for more than 59 percent of total additions for the period 1991 through 2001.
Competitive Bidding A variety of renewable energy policies have been implemented on the basis of open competitive solicitations. Typically, these competitive bidding policies specify a target amount of generating capacity or share of electricity generation to be achieved. Several rounds of bidding are usually scheduled, and the solicitations may group technologies with similar cost and performance characteristics to achieve a broader final mix of technologies. Project developers submit bids for contracts, and if they are successful can begin to develop their project. In some countries, competitive bidding has been used to implement concession programs. Concessions are a tool that has long been used by governments to control development of natural resources, such as oil & gas fields, forests, metals and other minerals. The concept for promotion of grid-connected renewable energy development is similar and most often used for wind resources. In a few notable cases, governments have used concession approaches to promote the development of grid-connected renewable energy systems. European government bodies have been giving out wind farm concessions since the late 1990s. The concessions have been either allocated through a competitive bidding process or through the evaluation of applications according to specific criteria and conditions. For example, the Norwegian Water Resources and Energy Directorate (NVE) announced in 1997 the first concession for wind farm. By October 2004, NVE has given concessions to 1025 MW of wind power, out of which 270 MW have been installed. Up until that time, more than 40 applications had been received and have been evaluated according to a bidding process. Other European examples illustrate how the concept has been broadly applied. Belgium granted an area concession for the construction and the management of its first 300 MW off-shore wind farm in 2003. Portugal's energy directorate recently granted concessions for 2000 MW of wind farms, and Greek regulator recently gave a "positive recommendation" for 360 MW of wind farm concessions. Elsewhere, Brazil has approved 729 MW of wind farm concessions. The UK’s NFFO program encouraged project developers to bid below cost in order to capture contracts, with the result that successful bidders were unable to meet the terms of the bid or ended up insolvent, and the project is never built. The UK abandoned the NFFO approach after the fourth round of bidding in 1997. The Chinese wind concession programs intended to bring down and reveal the cost of wind farms in China. However, the bid prices are too low to make the projects financially viable, and sent a wrong signal to the government who is developing a feed-in tariff policy based on these bid prices. Eight developers have been selected through three rounds of bidding since 2002, but none have been developed. Ireland and California have been more successful with competitive bidding approaches by applying very stringent criteria for pre-qualifying bidders. Because the quality level of the full set of bidders is at a similar level, the bidders can make more realistic bids without fear of losing to a low-quality bidder. In addition, the bid process is designed to set the tariff at the second-lowest bid price. Non-Fossil Fuel Obligation (NFFO) The UK’s Non-Fossil Fuel Obligation (NFFO) was an early example of this type of policy. The policy arose as a consequence of utility privatization, and it introduced an obligation on the regional power companies to purchase a certain percentage of their electricity from non-fossil fuels. The program provided a premium payment for renewable energy derived from a surcharge on utility bills across the consumer base, and it was designed to use a series of competitive tenders within defined technology categories to get a steady convergence between the price paid for renewable energy bids and the market price. A total of four rounds of NFFO tenders were implemented and winning bidders were awarded contracts to generate electricity at their contracted capacity for up to 15 years (only 8 years in the first 2 tender rounds). Starting in NFFO-2, all suppliers were paid the bid prices for the most expensive contracted project in each band (the “strike price”). Thus, some suppliers got more than they bid; and some suppliers intentionally underbid knowing they would get the strike price. This approach resulted in awards to some poorly conceived projects, and a high number of winning bidders were unable to come to financial closure. Out of 3,271 MW of awarded contracts in the NFFO, only 821 MW have been installed – success rate of 25%. Also, the lack of penalties for non-performance resulted in lengthy development periods. As a result, the UK abandoned the NFFO approach after the fourth round of bidding in 1997. Under NFFO there was a dramatic decrease in the supply prices for wind, where the average bid price fell by 31% between 3rd and 4th tenders, making it close to conventional costs. The decline was due to longer contract periods, technology improvements, and a decline in the cost of financing. However, much of this cost reduction is attributed to development activity in Europe in response to feed law support, and critics say that the NFFO merely squeezed profitability in the U.K. A problem under NFFO was that the periodic approach to tenders created intervals with relatively heavy activity interspersed with periods of inactivity. This created a stop-start situation that was difficult for sponsors and project developers to manage effectively and resulted in high administrative costs. The Irish Alternative Energy Requirement (AER) is outwardly similar to the British NFFO, with five tenders launched since 1994. One result of the AER is renewable energy prices that are among the lowest in Europe. The key difference with the AER program was a process of applying very stringent criteria for pre-qualifying bidders. Because the quality level of the full set of bidders is at a similar level, the bidders can make more realistic bids without fear of losing to a low-quality bidder. Specifically, the bid applications are first examined on a qualitative basis and thereafter are ranked according to their tendered electricity selling price. By placing an emphasis on the more mature technologies and projects, this program promoted cost effectiveness in the sourcing of renewable energy. California Renewable Energy Incentive Program The California Energy Commission (CEC) is currently operating a renewable energy incentive program based on competitive bidding for electricity production-based tariff support. As a component of California utility deregulation in 1996, legislation was created that gave the State authority to administer funds totaling approximately $540 million collected from a small consumer surcharge (system benefit charge) collected through the investor owned utilities. The legislation was intended to maintain and protect existing in-state renewable energy capacity, provided support for new renewable energy capacity development, and create incentives to stimulate further penetration of emerging renewable energy technologies. To date, the CEC has implemented sets of solicitations. The New Generation support activity, which has committed a total of $241 million over three auctions and the New Technologies account, which has committed $162 million over 3 auctions in 4 years. The CEC solicitations use a reverse auction approach – asking bidders to propose a per kilowatt-hour incentive for a specified amount of power production. The production-based incentives can be paid monthly over at most a 5-year period. Bids are ranked-ordered from the lowest to the highest until the available funds are depleted or all bids have been accepted. There is a cap of 1.5 cents per kWh as an upper limit on bids, and no project can receive more than 25% of total funds available. In learning from the NFFO experience, the California process has both an incentive for early project implementation and penalties for project delays. Projects that come on line before their target date are eligible for up to a 10% bonus on top of original incentive bid, but in no case can the total incentive with bonus be more than 1.5 cents. There are a range of incremental delay points that result in 10% reductions in the bidder’s incentive payment. By one year after the target date, incentive payment is reduced 50%; and beyond that it is reduced to zero. The solicitation rules help to assure efficient allocation of the incentive funding and avoid both overestimation of the renewable energy production, which would tie up funds unnecessarily; and underestimation, which would lead to insufficient funds in the program. Under-estimation of generation is discouraged by limiting incentive payments to no more than the proposed amount of generation - i.e., extra generation will not receive the incentive payment. Over-estimates are discouraged through reasonableness checks and penalties. If the actual generation averages less than 85% of estimated generation over the first 3 years, the incentive payments are reduced by 25% for remaining 2 years. Also, to avoid front-loading, incentive payments in each of first three years are limited to 25% of project’s total award fund. The CEC elected to let technologies compete within a common pool, and unlike the NFFO program, did not ‘band’ technologies to differentiate among different costs and operating characteristics. It operates a separate grant program (using another portion of the system benefit charge funds) for emerging renewable technologies, such as solar PV. The CEC solicitation program is currently in flux with California RPS legislation and the CEC program extension being passed at the same time. It currently appears that under the RPS, the utilities will actually conduct their own solicitations under the aegis of the California Public Utilities Commission (CPUC) to meet to their RPS targets. The utility will not pay the bid price, but a 'market price' set by the CPUC. Funding from the CEC program (i.e. the system benefit charge fund) will then be used as "supplemental energy payments" to cover the difference between what new renewable projects bid into the utility solicitations and the benchmark set by the CPUC and CEC. The challenge in this emerging system will be in determining the benchmark or market price that the utility must pay. The higher this is the more resistance there will be by the utilities. A lower benchmark will increase the costs incurred by the system benefit charge fund and could exhaust the fund without reaching the RPS target. China Wind Concession Bidding The advantages and disadvantages of concessions bidding can be illustrated by the effort of the Chinese government to develop the country’s wind potential through a wind concessions program implemented through a competitive bidding process. After years of high wind electricity tariffs, the Chinese government hoped that introducing competitive bidding for wind farm development would drive down and reveal the cost of wind farm in China. The primary goal of the wind concession program is to steadily ramp up new wind power capacity at the lowest possible cost while maintaining control over development decisions. Additional program goals include promoting the technology transfer of advanced wind energy technology, and increasing local manufacturing of wind energy systems and technology components. Under the Wind Power Concession program, the National Development and Reform Commission (NDRC) invited international and domestic investors to develop 100 MW wind farms on a potential wind site. Winning bidders are granted approval to develop the selected project site, a PPA for the first 30,000 hours of the project operation, guaranteed grid interconnection, financial support for grid extension and access roads, and preferential tax and loan conditions by the central government. This backing of the central government creates a comparatively lower-risk investment environment for wind farm developers in China. The first round of bidding requested that proposed projects use turbines over 600 kW in capacity that consist of over 50 percent local content. In October 2003, two companies were selected through the first round of competitive bidding to develop the initial large-scale wind concession projects. However, the winning bid prices were below the long-run marginal costs, and significantly lower than any previous wind farm price in China. The selected developers experienced difficulties in obtaining financing, and these initial two projects have not yet been developed. There was an effort made in the second round of bidding to adjust the market to this experience, and three developers were selected (with slightly higher prices than the first round). However, it appears that bid prices are still be too low to be financially viable, and none of these projects have been developed. An additional complication of the second round of bidding is that requirement for local content was raised to 70 percent. Today, the concession has caused a major concern to the wind industry in China. These bid prices are too low to make these projects financially viable. But it sent a wrong signal to the government, who is developing a feed-in tariff policy under the newly passed Renewable Energy Law based on these bid prices. This has seriously affected other wind projects under development. In addition, the number of companies attempting to bid for the concession projects actually fell from the first round of concessions to the second round—contrary to expectations that the number of participants would increase with the program’s increased visibility and the “success” of the first two concessions. Furthermore, the selection of concession sites and the decision for the bid prices are not based on well-measure wind resources. A reported twenty additional wind farm concession sites are in the current program pipeline.
Comparison of Market Mandates The arguments in favor of price setting policies are that to date, they have been most successful at developing renewable energy markets and domestic industries, and achieving the associated social, economic, environmental, and security benefits. They are flexible and can be designed to account for differences in technologies and in the marketplace. They encourage steady growth of small- and medium-scale producers, involve low transaction costs, facilitate financing, and provide easy entry for new players into the market. The principle arguments against price setting policies are that the tariff is difficult to set, particularly at the beginning when the true costs of renewable energy systems are unknown. In addition, the overpayments that have regularly occurred in static feed-in tariff systems result in economic inefficiency and unnecessarily high prices that consumers pay for renewable power. Furthermore, requirements for domestic production can involve restraints on renewable energy trade. The arguments in favor of quantity setting policies (both RPS and competitive bidding) are that they promote the least-cost projects, i.e., the cheapest resources are used first, which brings down early costs of the policy. They provide certainty regarding future market share for renewable energy, but this is often not true in practice as planned project do not materialize. They are perceived as being more compatible with open or traditional power markets and are more likely to fully integrate renewable energy into electricity supply infrastructure. They also facilitate the establishment of a renewable energy credit trading system. The principle arguments against quantity setting policies (especially competitive bidding approaches) are that they produce high risks and low rewards for equipment suppliers and project developers, which slows innovation. Price fluctuations in “thin” markets can create instability and gaming in the quest for contracts. Large, centralized merchant plants tend to be favored to the disadvantage of small investors. Development tends to get concentrated in areas with the best resources, causing possible opposition to projects and missing many of the benefits associated with renewable energy (jobs, economic development in rural areas, reductions in local pollution). Targets set the upper limit for development as there are no incentives to install more than the mandated level. They tend to create cycles of stop-and-go development. They can be complex to design, administer and enforce. They have high transaction costs, and they lack flexibility (are difficult to fine-tune or adjust in the short-term if situations change.) To date, price-setting policies (feed-in laws) have been responsible for most of the additions in renewable electricity capacity and generation, while driving down costs through technology advancement and economies of scale, and developing domestic industries. The record of quantity-setting policies is more uneven thus far. Competitive bidding approaches have exhibited a tendency toward boom and bust markets because of the tight competition that can be created. Many RPS policies have only been implemented recently, so their effectiveness is not yet fully known. It is important to recognize that both price-setting systems and quantity-setting policies ensure the right of the electricity suppliers to recover the incremental cost from consumers and for electricity generators to be able to connect to the grid. But pricing systems with periodical adjustments have provided increased predictability and consistency in markets, which in turn have encouraged banks and other financial institutions to provide the capital required for investment.
Requirements for successful policy The specific requirements of successful price-setting or quantity-setting policies are defined below1 . What is most important for both approaches is political stability, and long-term, credible, enforceable and consistent policies. Additional requirements for successful implementation include standards, education and stakeholder involvement. Price setting laws should: Ensure periodical and wise adjustments of the premium over system avoided cost to eliminate excess rent payments by the state to private generators/suppliers – incremental adjustments built into law Establish tariffs according to technology (and location) with input from research institutes and renewable energy industries Provide tariffs for all potential developers, including utilities Ensure that tariffs are high enough to cover costs and encourage development Guarantee tariffs for long enough time period to ensure high enough rate of return Ensure that costs are shared equally across country or region Eliminate barriers to grid connection.
Quantity setting laws should: Apply to a large segment of the market Include specific purchase obligations and end-dates Establish adequate penalties for non-compliance, and enforcement Set different bands by technology type (e.g. a carve-out for solar PV) Require long-term contracts to reduce uncertainty for project developers Establish tradable certificates with minimum and maximum prices Avoid a time gap between one quota and the next (for competitive bidding).
Paying for the incremental cost of renewable energy Renewable energy policies require incentives to realize the quantities of renewable energy that are justifiable on the basis of the local and global environmental externalities, because these values are not recognized in the market place. Many of these incentives result in higher payments to renewable energy producers compared to market prices. Others may result in lower costs or tax burdens. Irrespective of whether a price-setting or a quantity-setting policy is adopted, the critical issue is that cost be spread out over full customer or population base. In most countries, the additional costs of higher payments to renewable energy producers are allowed to pass through to the consumers. In some countries, the incremental costs are paid through an additional per kilowatt-hour (kWh) charge on consumers, such as the system benefit charges in the US. In a few cases, taxpayers share in the cost, such as in Denmark through a combination of feed-in rates and reimbursement of a carbon tax. In Mexico, a Green Fund supported by government budget and GEF resources is set up to pay for the incremental costs.
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