In an order issued Oct. 21, 2010, the Federal Energy Regulatory Commission (FERC) provided clarification as to how a state might be able to structure a “feed-in tariff” requirement. Generally, a feed-in tariff requires electric distribution companies to purchase the power produced by a specific resource class, usually renewable, under government-established rates designed to encourage the use of such power resources.

Some states have shown an interest in mandating feed-in tariffs for their electric utilities to encourage the use of renewable power resources. However, the federal government’s exclusive jurisdiction over the prices for wholesale power sales has stymied the states’ efforts in this regard. FERC has now offered guidance as to how states may achieve some of their objectives.


FERC’s order had its genesis in a California state law that established a feed-in tariff requirement for power from certain cogeneration facilities of 20 megawatts (MW) or less, with the California Public Utilities Commission (CPUC) charged with establishing the rate. The CPUC asked FERC for a declaration that this program was not pre-empted by federal law, but the three major investor-owned utilities in California asked FERC to declare that the program was pre-empted.

The CPUC argued that it was not setting a price for wholesale power sales, but was only requiring the utilities under its jurisdiction to offer to purchase power from eligible cogenerators at the price set by the CPUC. In an order issued July 15, 2010, FERC rejected the CPUC’s argument that it was only setting an offering price.

FERC held that the program amounted to impermissible wholesale price-setting, which is solely within the jurisdiction of FERC. However, FERC stated that the CPUC program might pass muster if it was set up pursuant to the Public Utility Regulatory Policies Act (PURPA), under which a state is authorized to require utilities to purchase power from “qualifying facilities” (QFs) at state-established rates that are no higher than the utilities’ “avoided costs.”

In response to FERC’s July 15 order, the CPUC asked FERC for clarification regarding the flexibility it had to establish “avoided costs” for specific power resources that it wished to encourage. In earlier FERC precedent, it had been unclear whether different “avoided costs” could be established for different resources.

FERC’s clarification

In its Oct. 21 order, FERC provided the requested clarification. FERC, emphasizing that states had wide latitude in establishing avoided costs, held that a “multi-tiered avoided cost rate structure” was consistent with PURPA. FERC reasoned that where a state requires a utility to procure a certain percentage of energy from generators with certain characteristics, those types of generators “constitute the sources that are relevant to the determination of the utility’s avoided cost for that procurement requirement.”

FERC also clarified that the state may also include in its avoided cost calculation the costs of transmission upgrades that would be avoided by purchasing power from closer resources. Additionally, FERC noted that a state is free to reward favored resources through other mechanisms outside of the avoided cost rate, such as the creation of renewable energy credits.

Continued limitations under PURPA

FERC’s Oct. 21 order was a clear effort to give the states more leeway with respect to feed-in tariffs, and is more state friendly than FERC’s July 15 order. However, that leeway is still limited by necessary compliance with PURPA.

This limitation has three implications.

  1. The only resources that could be beneficiaries of such a feed-in tariff would be those that meet FERC’s definition of a QF, which encompasses certain cogeneration, renewable, geothermal, biomass, waste, and geothermal resources.
  2. Although the state will have a fair amount of discretion, the rate established for the tariff must have a demonstrable relationship to the costs a utility would avoid for that class of resources.
  3. This PURPA-type feed-in tariff may only be used where utilities remain under an obligation to purchase from QFs.

The Energy Policy Act of 2005 allowed utilities to end their mandatory purchase obligation under specific circumstances if the QFs in their area had access to competitive markets for their power. A number of utilities located within Regional Transmission Organizations with day-ahead markets have been relieved of their mandatory purchase obligation for QFs above 20 MW in size.

Generally, there is a rebuttable presumption that QFs of 20 MW and smaller would remain subject to the mandatory purchase requirement even if the market criteria were met. Accordingly, most QFs of 20 MW and under would be potentially subject to a PURPA-type feed-in tariff, and larger QFs would be potentially subject if their utilities have not been relieved of the purchase obligation.

Because FERC granted the CPUC the clarifications it requested, FERC did not address the CPUC’s alternative request for rehearing that argued that FERC was wrong in holding that feed-in tariffs outside of PURPA were pre-empted by federal law. Accordingly, this fundamental jurisdictional issue is not yet ripe for judicial review. For now, unless Congress enacts feed-in tariff legislation, feed-in tariffs in the United States will have to conform to the PURPA model as defined by FERC in this case.