What is the best choice of regulatory instruments/tools for Renewable Energy promotion based on efficiency and effectiveness of reaching policy targets (FiT versus Green Certificates versus Central Procurement and others)?

[Response by Sanford Berg, November 2012]



In their review of RE policy instruments used around the world, including in six representative developing and transition economies, Elizondo and Barroso (2011) identify the following lessons:

  1. A tailor-made approach is necessary (reflecting the local market and institutional setting).
  2. Policy sequencing is critical for policy effectiveness (since legal/regulatory frameworks for interconnection and siting must be established before implementing RE policies).
  3. Policies that successfully lead to the scale-up of renewable energy may not necessarily be efficient (so the benefits and costs of programs must be carefully identified).
  4. Policy interaction and compatibility need to be considered because complex interactions among programs and unintended effects can reduce the net benefits of RE programs.
  5. Policy and regulatory design is a dynamic process; for example, Feed-in Tariff policies have required successive adjustments in various countries.
  6. RE policy performance (effectiveness/efficiency) depends on a number of key factors including financial sustainability, adequate infrastructure, and clear interconnection rules.

The NARUC Handbook identifies a number of regulatory instruments incentivizing a range of renewable energy projects:

  1. Feed-in Tariffs: tariff-based incentives that result in favorable tariff rates, ensuring that investors are guaranteed income that covers costs and additional return on capital sufficient to motivate investment (which can be uniform or differential across technologies);
  2. Net Metering: a system whereby electricity produced in excess of the customer’s load is sold back to the interconnecting utility, generally at the retail electricity rates;
  3. Renewable Portfolio Standards (RPS), including Quota systems (and penalties for non-compliance), and Green Credits (or tradable Renewable Energy Certificates (RECs);
  4. Central Procurement via Energy Auctions (Tendering), by which investors compete for a project through a competitive bidding system initiated by a government department or agency;
  5. Power purchase agreements, which are contracts between a seller and a buyer: these may differ depending on the type of generation technology;
  6. Direct investment support, including loan guarantees and tax incentives: although regulators would generally not have control over such funds, the agency might be given the responsibility for monitoring the cost-effectiveness of such programs;
  7. Other Incentives for RE development:
    1. Direct research and development grants and use of targeted funds
    2. Assistance in resource mapping
    3. Encouraging the voluntary sector
    4. Making green look good
    5. Trade restrictions

RE instruments can be classified as price-based (FiTs) or quantity-based (RPS). Experience suggests that FiTs are effective at reducing investor risk (compared with RPS or quota instruments). However, there is some evidence that quota mechanisms (an RPS-REC scheme) can be less expensive than price-based instruments like FiTs (which involve high subsidy rates for less mature RE technologies). RPS-REC programs promote competition among technologies, which gives an advantage to more mature (and less expensive) technologies. Central Procurement or Purchased Power Agreements represent mechanisms for acquiring energy from renewables. As of 2011, green house-cap-and-trade frameworks and carbon taxes were not part of any developing country’s portfolio of policies promoting RE (Elizondo and Barroso, 2011)

Many of these initiatives involve distributed generation, so access to the grid, power quality, and other issues need to be addressed by regulators in the design of the instruments. The strengths and limitations of the RE instruments are noted below, along with a description of the role of the regulator in implementing each policy option. Note that Elizondo and Barroso (2011) provide a Glossary of terms and recent renewable energy experience in selected developing countries. In addition, the REToolkit is a comprehensive resource for renewable energy development, describing grid, mini-grid, and stand-alone systems. The legal and regulatory barriers to independent power producers include lack of transmission access, lack of incentives for regulated utilities, unfavorable pricing rules, and excessive permitting requirements and siting restrictions. Energy sector regulators can address each of these issues in the context of specific programs (described in detail in the REToolkit)


1. Feed-in Tariffs (FiTs)

According to the NARUC Handbook (p. 39), “The most important components of Feed-in Tariffs (the details of which vary across jurisdictions to meet country-specific needs) are:

  1. A fixed price set in law, regulation or decision (or, in the more advanced markets, a premium tariff structure which is the market price with a fixed added amount).
  2. The fixed price level is often different across technologies (e.g., hydropower commands a different price than solar).
  3. In some developed feed-in tariff frameworks, stepped tariff designs (e.g., differentiation within same technology based on site, plant size or conditions that affect the yield). A way to encourage early investment is to stagger new feed-in tariffs so that they decrease annually; this technique motivates entities to install renewable energy technologies in the current year – rather than waiting until the price of RE systems decreases – while accounting for developments in technology.
  4. Process and period for tariff revision, limiting the amount of time that a feed-in tariff applies. This gives adequate comfort to investors but also ensures that incentives are in effect only as needed, and offers a process for reconsideration if expected market integration is not yet reached and/or incentives remain necessary.
  5. Long Duration [Contract Length]. Most variants and best practice hold that the price should be guaranteed for a specific period of time reflecting the cost of investment, usually around 20 years (according to the Pierce Atwood Report).
  6. Purchase obligations, requiring that a utility or a transmission company, distributor or supplier purchase the RE-generated power at a rate determined by public authorities. In most cases, regulatory measures are applied to impose an obligation on electricity utilities to pay the (independent) power producer a price as specified by the government.”

Role of the Regulator: Regulatory oversight of FiT programs is essential, whether the price is based on a pre-determined number (and with some maximum capacity), an auction/bidding process, or avoided cost. In each case, the regulator monitors activities to ensure abuses do not arise. The avoided social cost of additional fossil-fuel generation includes local environmental externality costs (or, more broadly—but more difficult to compute—the global externality). How these external costs are factored into program evaluation is partly dependent on the enabling legislation (or executive order). Two issues warrant particular attention:

  1. Differential FiTs: Tariffs that are dependent on the particular technology are problematic, since they can greatly increase the cost of obtaining RE. Nations may have a comparative advantage in applying a particular technology, so it is unclear why very expensive technologies should be encouraged when they are so costly. Furthermore, the main beneficiaries of (for example) wind energy FiT might be wind turbine manufacturers based in developed countries.
    Case: Tanzania has adopted a technology-neutral FiT, thus avoiding extremely high cost technologies.
  2. Flexibility: One of the most important lessons learned from the FiT experience (and more broadly preferential tariffs for renewable energy) is that sufficient flexibility must be built into the rules to ensure that prices adapt to changes in the market, while still offering the security that investors need. A good regulator strives to get this balance right.

2. Net Metering

Net Metering is generally applicable to consumers who own relatively small renewable facilities. The system owner (of a solar or wind facility) receives a credit on her electricity bill. Unlike the case a FiT, the owner is generally paid the retail price for excess electricity produced by the (home or small commercial) customer. Since most electricity meters can run in both directions, the meter serves as a mechanism for reducing bills and (possibly) making money for the small customer. To reduce transactions costs, the savings might be rolled over to the next month. Net metering could apply variable pricing for (more expensive) Time of Use meters.

Role of the Regulator: So long as enabling legislation encourages or requires net metering, the energy regulator will need to oversee the system and evaluate its effectiveness in meeting RE objectives. According to the REToolkit (p. 65): “Success in attracting new renewable energy investments and capacity depends on:

  1. Limits set on participation (capacity caps, number of customers, or share of peak demand);
  2. the price paid, if any, for net excess generation;
  3. the existence of grid connection standards; and
  4. enforcement mechanisms”

Thus, regulatory rules for each of these elements are essential for the effective application of this mechanism. Net metering can be used in conjunction with quantity mandates to meet aggregate renewable energy targets.


3. Renewable Portfolio Standards (RPS)

RPS is market-based, so it suitable in situations where there are many buyers (distributors) and suppliers (generators using technologies based on renewable energy). In addition, private sector participation can be encouraged—which brings more financial capital into the industry. Voluntary RPS systems have been announced in a number of jurisdictions, but without clear incentives to participate, distribution utilities tend to be unwilling to purchase high cost electricity. A quota or purchase obligation (with penalties for missing the target) can be based on a percentage of the total actual load or on a specific level of kWH (which raises costs if demand is lower than expected). Typically, distribution companies (or final suppliers/retailers) are the entities mandated to meet the standard, with a penalty for non-compliance (or an associated buy-out price per MWh for shortfalls).

  1. Certificates for renewables can be provided by a government agency that certifies the MWh produced by a qualified generator. The buyer (distribution utility) then pays the price for the RE, and gains certification for its purchase. A single (electronic) registry keeps track of the certificates. The registry can also serve as a trading platform to reduce transactions cost and to enable other stakeholders to purchase certificates to encourage RE development (see auctions, below). In extreme circumstances, the responsible agency could issue waivers, but the circumstances should be clearly specified in advance so the target does not become a “soft (politically-driven) constraint”.
  2. Co-existence and evolution of support mechanisms: there is evidence that countries with FiT have moved to RPS and certificates.
  3. Funds from penalties can be applied to RE or EE programs if the enabling legislation allows. To mitigate potential price volatility for the certificates, there can be a virtual price cap (i.e. non-compliance fee) and a floor.
  4. Limitations of RPS: If solar PV is the dominant technology, then RPS may not the preferred instrument. Based on international experience, small solar PV may be best supported via FiT.

Role of the Regulator: So long as enabling legislation establishes RPS, the energy regulator will need to oversee the system and evaluate its effectiveness in meeting RE objectives. Generally, some other agency is responsible for certifying the generators and handling the certification system.


4. Energy Auctions

Energy auctions must be well designed. There are a “number of methods for determining sales price. Interested parties place bids and the highest bidder obtains the item if the bid is greater than the reservation price (minimum acceptable bid). Alternatively, there can be an auction for a subsidy to provide a service (say, to a high cost, un-served geographic area); in such cases, the lowest bid wins the subsidy. There are a number of different types of auctions with a variety of characteristics, including Dutch auctions and second price auctions.” (BoKIR Glossary) The rationales behind auctions are numerous:

  1. Efficiency: If the number of bidders to provide renewable energy is enough, those with the lowest cost will win the contracts. Rather than setting low reserve prices, those operating the auction should seek to expand the number of bidders.
  2. Use of Information: Those with information (producers) make bidding decisions based on their experience and (well-informed) expectations.
  3. Price Discovery: Auctions can be used to discover the price that potential investors in a particular technology (like solar) would require. For example, Brazil held reverse auctions for wind energy in 2011, leading to prices as low as $60 per MWh; the auction yielded a total of 2.9 giga-watts (GW) of energy.
  4. Transparency: Auctions can be designed to be transparent, technology neutral, and simple. Investor’s perceptions regarding the fairness of the process are crucial for the auction’s success.
  5. Contract Design: The product (kWH) being acquired can be clearly defined. Well-designed contracts specify the rights and obligations of all parties. Safeguards against non-performance can be utilized, including warranties.

Role of the Regulator: The sector regulator may not be the agency holding the auction, but since the costs will affect the final prices paid by consumers, the regulator should monitor the process to ensure that best practice is adopted. An inadequate number of bidders or tacit collusion can yield high prices for purchasers. Strategic behavior among bidders can lead to high prices. In addition, the sector regulator should ensure that risk allocation issues are addressed in the resulting contracts. Risk is difficult to handle since the winner is often in a strong position to renegotiate the terms and conditions of the contract. Because of the winner’s curse and other issues associated with auctions, various formats have been suggested to ameliorate potential problems. However, complicated formats should be avoided in the early stages of RE acquisition. The ESMAP Report by Bessant-Jones et. al. provide a thorough overview of bidding and other risk assessment issues.


5. Power Purchase Agreements (PPAs)

PPAs have been widely utilized to obtain RE capacity and MWh. The agreement should be based on an auction or bidding process to ensure least-cost acquisition of the electricity generated using renewable energy. Bessant-Jones et. al. (2008) propose a Benchmarking methodology in an ESMAP Report, including attention to examines legal infrastructure, solicitation for bids (and the importance of competition), power sales enhancements (like renewable set-asides or net metering), and tariff design (tariff floors, capacity tariffs, or renewable premiums).

Role of the Regulator: The potential roles of the regulator include ensuring the transparency of bidding processes, licensing facilities, arbitrating disputes, evaluating the prudency of contracts (without engaging in retrospective regulation), and setting the terms and conditions for interconnection. The legal infrastructure, bid solicitation procedures, power sales enhancements, and tariff design are discussed in detail elsewhere. Bessant-Jones et. al. (p.4) identify possible approaches to regulatory reviews of Power Purchase Contracts, and include examples from developing countries:


  1. Assist in negotiating PPAs
  2. Before or after the fact regulatory approval of PPAs
  3. Standardized/model PPA
  4. Mandated (competitive) Procurement guidelines


  1. Administratively specify a maximum price
  2. Tie maximum price to competitive power sales
  3. Benchmarking of overall power purchase costs of distribution companies
  4. Benchmarking of individual PPAs

The NARUC Handbook (p. 43) presents other considerations for regulators: “Procurements should be offered in stages, so that while PPAs are useful to provide security, the purchase and sale process should be staggered to allow for market changes and not to tie up the market in one or even a few large deals. As RE technologies mature, they will become more efficient and less costly. Utilities should stage their Request for Proposal (RFP) process to take advantage of these future efficiencies. Similar to staged procurements, competitive processes such as auctions can be used to ensure that efficiencies are wrung from project developers. The RFP process must be transparent and fair to all stakeholders. This will allow competition to flourish and give customers greater access to choice. As part of this transparency, the tendering framework should incorporate considerations for how to open competition to smaller, less established entities/project developers.” Clearly, the sector regulator has a number of actions that can promote cost-effective PPAs.


6. Direct Investment Support

Subsidizing RE production is one way to promote new capacity, but if the source of funds is uncertain or unsustainable, the initiative is unlikely to be successful. For example, a particular fund might be viewed as an ad hoc source of funding that may not be sustainable. In addition, various tax incentives have been utilized to promote RE. The NARUC Handbook (p. 32) lists the four policies as promoting RE investments, with a two others from the REToolkits:

  1. Property and sales tax incentives
  2. Production and investment tax credits (via rebates, exemptions on royalties, tax credits, accelerated depreciation)
  3. Grant or rebate programs for RE developers and owners
  4. Loan guarantee programs
  5. Trade restrictions (quotas, trade embargoes, and technical restrictions represent another form of subsidy, though these can violate international trade agreements)
  6. Government procurement (of infrastructure or specific technologies for government facilities)

Role of the Regulator: These policies are generally outside regulatory purview. Of course, reports on the effectiveness of these programs can help policy-makers improve tax incentives.


7. Other Incentives

Other incentives fall into at least four categories:

  1. Direct research and development grants and use of targeted funds: Local universities train those who will be managing and operating RE initiatives. Colleges of Business and Engineering are in a good position to provide research that can improve prospects.
  2. Assistance in resource mapping: Thermal, hydro, solar, and wind all have geographic elements. Specialists in those fields (from universities or consulting firms) can be utilized to provide a factual basis for decision-makers. Managers need data on the features of the resource; policy-makers need information on the implications of over-use or on potential unintended consequences.
  3. Encouraging the voluntary sector: Non-governmental organizations can be useful allies in the development of RE strategies, especially when there are small projects affecting local communities.
  4. Making green look good: Public relations cannot make a bad project look good, but it can be necessary for siting and other issues, where community acceptance is crucial. Without a public consensus behind renewables, those benefitting from current institutional arrangements can block RE initiatives. The sector regulator can hold regional workshops that promote public participation and educate the citizenry.

Role of the Regulator: The sector regulator plays a somewhat tangential role in these initiatives. More specialized agencies will fund technical research or engage in resource mapping. Ultimately, the commercial viability of RE programs depends on factors other than “voluntary” organizations or actions, but a supporting regulatory framework can make a difference.


Seven types of RE programs have been surveyed. They can be used in combination and scaled up as particular initiatives prove cost-effective. The programs fall into four main categories:

  • Price Based Incentives: FiTs (and net metering),
  • Quantity Based Incentives or Quota Obligations: Renewable Portfolio Standards/Renewable Energy Certificates, and Competitive Procurement (auctions)
  • Fiscal and Financial Incentives: Tax credits, government subsidies and loan guarantees
  • Voluntary Measures

Readers are advised to see Elizondo and Barroso (2011) who present a Table (Appendix 3) that compares the investment risks, effectiveness/efficiency, and complexity of price and quantity-based RE instruments. One role of the sector regulator is to promote transparency and stakeholder participation, so the risks are clearly understood and mitigated where possible. Each of the program types has different features: securing financing, predicting revenue streams, devising incentives for cost containment, and designing contracts.

At a minimum, regulators are encouraged to seek least-cost technologies to limit the impact on customer bills. Lessons from other countries should be researched. For example, Sargsyan, et. al (2011) draw lessons from experiences in India. Finally, the policy instruments need to be well developed and carefully utilized. Systematic review of policy impacts is necessary if cost-effective programs are to be expanded and weak programs pruned from the nation’s RE policy portfolio. Regulators can play a particularly valuable role in the evaluating RE programs.



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