by Cortney Madea and Richard Lehfeldt, Dickstein Shapiro LLP
Historically, the United States has relied on financing techniques to promote renewables development, including solar renewable energy credits, power purchase agreements, rebates, net metering and tax credits.
Recently, however, a few states and cities have adopted feed-in tariffs for renewable energy, specifically solar power. Feed-in tariffs are an established method for spurring development of renewable and other nontraditional power resources and often are identified as the financing technique that gave Europe an early lead in renewable energy development.
Feed-in tariffs provide a developer with a guaranteed connection to the grid, a long-term contract to sell the power and a fixed price that will allow the producer to recover costs and earn a profit. Germany, for example, has had feed-in tariffs since 1991 and is the world leader in solar development with about 10 GW of photovoltaic (PV) power installed. By contrast, the total U.S. solar capacity from PV and concentrating solar power is about 2 GW.
A recent Deutsche Bank research report stated that feed-in tariffs, compared with renewable energy incentive schemes, are particularly attractive and low-risk from an investor’s view. This assessment is supported by U.S feed-in tariff experience. In 2009, Gainesville, Fla., became the first U.S. city to offer higher payments for solar power through a feed-in tariff. The program was subscribed fully within a year of its establishment.
California, Oregon and Vermont have solar feed-in tariffs, and other states have initiated tariff development. Vermont provided 25-year contracts for solar power with prices based on production cost, together with a rate of return equal to what a Vermont utility receives. The program had a 12.5 MW solar cap and was fully subscribed on the program’s first day. A feed-in tariff is an effective way to encourage or guarantee renewable resource development.
In a July 15 order, the Federal Energy Regulatory Commission (FERC) for the first time addressed a state-approved feed-in tariff and held that a state’s ability to establish such a tariff rate is constrained by FERC’s preemptive authority (in most circumstances) to set wholesale rates for power sales in interstate commerce. The FERC order addressed a California Public Utility Commission (CPUC) feed-in tariff that required investor-owned utilities (IOUs) to purchase power from combined heat and power generators at rates set by the CPUC. Ruling on competing petitions filed by the CPUC and a group of three California IOUs, FERC found that the Federal Power Act (FPA) largely preempts the CPUC from specifying wholesale rates in interstate commerce.
The commission clarified that the CPUC decisions would not be preempted if the generators are qualifying facilities, which are exempt under the Public Utility Regulatory Policies Act (PURPA) from the wholesale rate provisions of the FPA, and the rate set by the CPUC does not exceed the purchasing utility’s avoided cost. Limiting the application of state feed-in tariffs to qualifying facilities would exclude solar projects larger than 80 MW from state feed-in tariff programs. By restricting purchase rates to the purchasing utility’s avoided costs, FERC limited the incentives that may be included in the feed-in tariff rates.
The FERC order might not be a death knell for U.S. feed-in tariff programs that are just beginning to show promise. The order carves out renewable feed-in tariffs for qualifying facilities that do not exceed the utility’s avoided cost.
Second, the order addresses only the state’s ability to set a wholesale rate; it specifically leaves open a state’s authority to order its utilities “to purchase capacity and energy from certain resources.”
That invitation at least implies that a state could set up, for example, a reverse auction mechanism seeking a certain number of megawatts of solar power and allow the market to establish the appropriate market-clearing price, thereby avoiding the situation in the CPUC order where the state commission set the wholesale rate.
Third, the state could establish a nonwholesale rate source of compensation for a renewable developer that would make up the gap between the facility’s avoided cost and the pricing necessary to develop these projects. Such sources could include tax incentives, retail rate adders or renewable credits from a public benefit trust fund.
FERC’s CPUC order restates hornbook law about the commission’s plenary authority to set wholesale rates and is the opening volley in a longer federal-state dialogue about how to bring alternative power resources into operation.
Twenty-nine states and the District of Columbia have established mandatory renewable portfolio standards (RPS) for their jurisdictional utilities. The U.S. Congress came close to making RPS a federal mandate last year. The sitting FERC commissioners, notwithstanding the FERC order, vigorously support renewable integration initiatives.
We should expect FERC to embrace different paths to the same objective in states’ future attempts to establish feed-in tariffs.
Cortney Madea is an associate in Dickstein Shapiro LLP’s energy practice. Reach her at 202-420-3302 or email@example.com.
Richard Lehfeldt is a partner in Dickstein Shapiro LLP’s energy practice. Reach him at 202-420-2215 or firstname.lastname@example.org.