At least 18 US states are considering, or are reported to be considering, adopting feed-in-tariffs (FiTs) to stimulate renewable energy development. While many states have renewable portfolio standards (RPS) in place, some legislators must feel that their state’s RPS do not provide sufficient incentive for targeted renewable energy development.
A renewable portfolio standard is a state policy that requires power providers to obtain a minimum percentage of their power from renewable energy resources by a certain date. As of September 2010, 31 states and the District of Columbia have passed mandatory RPS programs, with six additional states approving conditional or non-mandatory renewable energy goals. Wide disparity exists in state RPS requirements, including what qualifies as a renewable resource, what specific target must be met and by when, and whether there are special set-asides or similar preferences for currently favored renewable sources (e.g., the solar preference in Nevada and the wind preference in Illinois).
Enter FiTs, widely regarded as a successful stimulus to renewable energy development in Europe. However, FiTs face significant legal impediments in the United States because of their potential to raise wholesale power prices of renewable energy, risking preemption by federal law under the Supremacy Clause of the US Constitution. In addition, to the extent that FiTs require or otherwise prefer in-state renewable resources, they risk violating the Constitution’s Commerce Clause. Notably, in-state RPS restrictions and similar protectionist policies such as local “multipliers” have raised Commerce Clause concerns with some state RPS.
Despite these significant legal barriers to states’ FiT policies, solutions do exist. Through careful legal structuring, states can encourage renewable energy development through FiTs without running afoul of federal law limitations. In our view, using existing federal law (or established exemptions), a European-style FiT is certainly feasible as a legal matter and, we believe, still reasonably practical. For example, by permitting a utility to levy special tariffs for the purpose of making supplemental payments to the renewable energy supplier, states may be able to avoid the constitutional issues that prevent them from directly imposing a FiT. Based on the successful European FiT experience, the ability of states to effectively implement FiTs will play a central role in expanding renewable energy development in the United States.
Constitutional Limits on RPS...
Not only have state RPS programs apparently failed to stimulate renewable energy production as desired, they have also spawned litigation under the Commerce Clause of the US Constitution. Many sta te RPS programs contain mayer brown 12 protectionist provisions favoring in-state over out-of state facilities. These may include outright bans of out-of-state production or bonuses for in-state production, in the form of incentive multipliers or set-asides. For example, New Jersey requires that its suppliers and providers procure at least 2,518 GWh from in-state solar generators during “energy year” 2021, and 5,316 GWh during “energy year” 2026 and each year thereafter. Under New Mexico law, when all else is equal, preference must be given to renewable energy generated in New Mexico. Ohio law requires that at least 50 percent of the renewable energy requirement be met by in-state facilities. Similar protectionist measures can be found in the RPS laws of many other states as well. While significant variation exists across state RPS requirements, the law is quite clear: programs that favor in state producers are unconstitutional per se.
The Commerce Clause grants Congress the power to regulate interstate commerce. An important corollary of that power is that states generally may not pass protectionist laws that discriminate against interstate commerce. The US Supreme Court has long struck down facially discriminatory state laws by applying a “virtually per se rule of invalidity,” as stated in Wyoming v. Oklahoma1. For such a law to survive, the enacting state must show that it had no other means to protect a unique local interest than to facially discriminate against interstate commerce, a test that is almost impossible to meet. Even where state and local laws are not facially discriminatory, they still may be unconstitutional if their burden on interstate commerce clearly exceeds local benefits.
Wyoming v. Oklahoma offers an example of a constitutional challenge to state economic protectionism in the energy sphere. In that case, the state of Oklahoma enacted a law that required all electricity generators to purchase at least 10 percent of their coal from in-state coal mines. The Supreme Court found that the law unconstitutionally discriminated against out-of-state coal, for no strong reason other than protectionism. It made no difference that Oklahoma’s statute affected only a “small portion” of the Oklahoma coal market; the Court explained that Commerce Clause invalidated state and local laws that provide any type of facial economic protectionism. Cases like Wyoming raise serious doubts as to the constitutionality of many states’ RPS programs.
As expected, states’ RPS restrictions have spawned legal challenges. In TransCanada Power Marketing Ltd. v. Bowles,2 TransCanada sued a number of officials in Massachusetts seeking a declaration that the Massachusetts RPS program was unconstitutional insofar as TransCanada’s out of state renewable resources were not eligible. While these parties are reported to have settled their dispute, TransCanada promises to be just the first of many battles against facially protectionist state RPS measures.
The Supreme Court has recognized (in FERC v. Mississippi3) that the market for energy production is one of the most “basic element[s] of interstate commerce.” In another electric power case (Ark. Elec. Coop. v. Ark. Pub. Serv. Comm’n4), the Court has also stated that “uncontrolled regulation by the States can patently interfere with broader national interests.” In light of comments such as these, as well as the Court’s recognition that renewable energy generated out-of-state is virtually identical to renewable energy generated in-state, states will be hard-pressed to justify their facially discriminatory RPS measures.
...And on FiTs
In addition to the Commerce Clause restrictions on state protectionism, state FiT programs face limitations under the Supremacy Clause of the US Constitution. Every “wholesale” energy sale in interstate commerce, which can include sales that take place entirely within a state if the interstate transmission grid is used, implicates federal law, and requires either compliance or exemption. To the extent that a FiT applies to such sales, technically the FiT obligations are imposed on the purchaser rather than the seller; however, whether this is effective to avoid the otherwise applicable federal law remains uncertain.
The Federal Power Act (FPA) governs the transmission and sale for resale (i.e., “wholesale”) of power in interstate commerce. The FPA makes it unlawful to make a sale at wholesale without a contract, and without US Federal Energy Regulatory Commission (FERC) approval of that wholesale contract (which can include FERC approval of a tariff authorizing the seller to make sales for resale at market-based rates, rather than pursuant to individually approved contracts). This effectively means that a state FiT cannot lawfully force a utility to purchase power at a state-set price. As a result, any FiT imposed under the FPA could not be an unconditional obligation to purchase the renewable energy produced. Instead, the purchase price would remain subject to approval by FERC, using a “just and reasonable” and not “unduly discriminatory” standard as defined by Sections 205 and 206 of the FPA.
One exemption from the FPA is under the Public Utility Regulatory Policies Act of 1978 (PURPA), which allows renewable energy producers to make certain sales of power to utilities without FERC approval. To be eligible, however, a facility must receive FERC certification as a “qualifying facility” (QF), which is limited to a subset of renewable energy technologies and project sizes, and the sale must be pursuant to a state program implementing PURPA. In addition, the price to be paid by the utility cannot exceed the utility’s avoided cost.
Because of the QF exemption from FPA compliance, PURPA would appear to be a viable FiT implementation structure. But it is far from perfect. Most wind farms and large-scale solar projects are too large to meet the requirements of a qualifying facility, so a state FiT would have to target individual users and small renewable producers. Additionally, a utility’s avoided cost is most likely still well below the price necessary to provide adequate compensation to the renewable energy producer. While the first issue will not disappear, short of an amendment to PURPA, it makes the second issue, sufficient compensation to the producer, critically important. Qualifying facilities (and their developers/investors) will only participate in the FiT if they receive compensation adequate to cover costs and earn a reasonable return on their related investment.
This means that states must find a way to supplement avoided costs. Doing so will allow US FiTs to stimulate renewable energy production, as they have done in Europe. A review of the situation in California, which has become the battleground for deciding the constitutionality of state FiT programs, illustrates how difficult and complex such a process can be.
Recent California FiT Challenges
Introduced at the end of 2008, California’s FiT pays $0.096 per kilowatt hour (kWh) for combined heat and power generating facilities of 20 megawatts (MW) or less installed in 2010. This price is based on the Market Price Referent (MPR), set at the avoided cost of a natural gas-fired plant and includes a greenhouse gas adder to reflect the anticipated cost of carbon mitigation. Specifically, the MPR assumes that the opportunity cost for wholesale power mirrors the hypothetical cost of operating a base-load combined-cycle gas turbine (CCGT) unit over a 10-, 15-, 20- or 25-year period. The MPR also incorporates the likely future cost of greenhouse gas emissions control efforts, such as a carbon tax. The MPR is also used under the state’s accelerated RPS, adopted in 2006.
Because the total FiT ends up above avoided costs, the three major retail utilities, Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric, filed a complaint with FERC in May 2010, alleging the FiT amounts to unconstitutional state regulation of interstate power at wholesale. In their complaint, they based their claims on previous FERC rejections of state pricing above avoided costs inside of PURPA and made the policy argument that inconsistent pricing across states could impose a significant burden on investor-owned utilities, giving rise to prohibitively high wholesale renewable energy prices that destroy their competitive advantage.
Newly elected Governor Jerry Brown, who was then the California Attorney General, responded to the complaints by claiming that California is not setting rates for the wholesale generator. Instead, he asserted, it is establishing a price that utilities must offer to generators in order to comply with state law; the generator retains discretion to sell (or not) at the offered rate. A January 2010 report by the National Renewable Energy Lab (NERL) lent support to Brown’s position, claiming that a state FiT would not violate the FPA if designed as the utility’s offer to buy at a state-specified price. The NREL based its conclusion on FERC’s 1997 ruling in Midwest Power Systems, Inc.5 In that case, FERC held that Iowa’s 6-cent FiT (versus a 1.5-cent avoided-cost rate) was pre-empted as unlawful because it fell outside of PURPA.
Yet while California took care to ensure that its FiT would fall outside of PURPA, it is unclear whether this is indeed the case. Most of the generation facilities meeting the state’s efficiency standard could be QFs under the PURPA standard in any event, meaning there may not be federal preemption. But California doesn’t require eligible generators to obtain QF status, so it can disclaim any intent to act under PURPA.
Brown also defended the FiT under the state’s police power, as a public health and safety law. As a result, he asserted, it should be presumed lawful and not preempted absent a clear and manifest purpose by Congress. According to Brown, due to the impending threat of global warming, PURPA and FERC should be interpreted liberally to give states flexibility in avoided-cost rate setting to accommodate important state environmental objectives. And, because the California MPR has been deemed to be de facto reasonable in the context of the RPS, the same standard should carry over to a FiT.
But FERC was not persuaded by Brown or the California Public Utilities Commission (CPUC), the California agency responsible for implementing the FiT. In a July 15, 2010, order, it found that certain CPUC decisions are preempted by federal law, except in limited circumstances. While California was relying on the fact that its FiT controlled power purchases, not power sales, FERC elevated substance over form, holding that the California FiT attempted to establish wholesale prices above the avoided cost of the purchasing utility. As FERC has exclusive authority to regulate wholesale power sales, it held the California FiT to be preempted under the Supremacy Clause of the US Constitution. This means the FiT must comply with the FPA and PURPA, which requires that eligible facilities are QFs and the established “offer” price does not exceed avoided cost. This victory for the retail utilities has broad implications for other California FiT programs and for all states that currently have, or are considering, FiTs.
Based on the FERC order, states must now find an alternative method for setting total payments, or equivalent feed-in tariffs, above avoided costs, to avoid triggering federal preemption under the FPA. We believe this can effectively be done under PURPA by providing supplemental payment mechanisms to generators of power rather than directly addressing the price of power, which as we have seen is problematic. Such supplemental payments mechanisms are generally outside of FERC’s jurisdiction and might take the form of: (i) renewable energy credits/certificates, which generators would sell to purchasers needing to comply with RPS or other state-law mandates; (ii) subsidies/cash grants directly to generators from states; (iii) utility tax credits for purchasers of renewable energy equivalent to the amount of the additional payment required for the renewable source, effectively offsetting the economic impact of such additional charge or (iv) standard offer contracts implemented through state RPS, with sellers either exempt from FPA rate requirements or authorized to charge market-based rates. These payments legally “top-up” the avoided cost, so that the total tariff received by generators can more closely reflect the cost of generation. The German FiT program is widely viewed as one of the most successful in Europe, in terms of stimulating renewable energy production.
The German FiT program includes a top-up payment that comes from a pool known as the Systems Benefit Charge, collected from ratepayers. In contrast to the Swiss program, where the pool is fixed and collected in advance, the German pool is flexible and applied to ratepayers after the fact. So, as more renewable energy production is added to the system, the pool expands and charges ratepayers proportionally (including a reasonable return on investment).
A similar program adopted in the United States would not only give states legal cover under PURPA, but, as long as the top-up payments are made to utilities to offset higher purchase prices (rather than being made to generators directly), would also help shift the investment risk of renewable energy, as a public good, to the utility ratepayers. Utilities would then be faced with identifying the optimal method of financing these additional costs. We believe that, in particular, stranded-cost securitization could then be used to finance renewable energy development, by monetizing the FiT charges and transferring the production risk to the capital markets, with low transaction costs and capital markets efficiencies.
States to Proceed with Caution on FiTs
Feed-in-tariffs can be used by states to stimulate renewable energy development where RPS alone have fallen short. Currently, 10 states are contemplating the adoption of above-wholesale-cost FiTs for state-regulated investor-owned utilities; we believe that they should continue doing so if they desire realistically to encourage greater renewable energy generation. Yet the legal obstacles require great care in structuring the FiT. While a state FiT cannot exceed avoided costs, supplementary payments under PURPA can be used legally to avoid federal preemption, encouraging desired levels of generation while allowing developers and investors to earn a reasonable profit.
Although the supplemental payment approach should help avoid federal preemption, there is still the lingering problem that US energy law treats renewables as a supplement to the existing utility system. While states could attempt to level the playing field through uncapped FiTs, thus allowing for a diversity of energy sources, federal energy law continues to be a major hindrance, as most wind farms and large-scale solar projects are too large to be considered qualifying facilities under PURPA. This explains why California has seen no significant increase in in-state renewable energy production, while foreign countries with FiTs, where there are no size restrictions, have seen demand for renewables surge in recent years.
But California and other states can use supplemental payments under PURPA to provide push aggregate prices above avoided costs, providing incentives for producers, while sidestepping the FPA. Eliminating any uncertainty that surrounds state implementation of FiTs through supplemental payments will allow the United States to follow Europe’s lead and see a major expansion in renewable energy production.
|1. 502 U.S. 437, 454 (1992).|
|2. Case No. 4:10-cv-40070 (D. Mass.).|
|3. 456 U.S. 742, 757 (1982).|
|4. 461 U.S. 375, 377 (1983).|
|5. Docket EL95-51, 78 FERC ¶61067|