FERC Ruling Changes Course and Assists Renewables

Karlynn Cory's picture

Throw everything you know about utility avoided rate calculations overboard. OK—not everything, but federal regulators clarified that states can support renewable projects using production-based incentives [including feed-in tariffs (FITs)] even if they are set above traditional utility “avoided costs.” 

In October 2010, the Federal Energy Regulatory Commission (FERC) overturned a long-standing precedent that had “severely restricted states’ ability to set rates…that [were] favorable to renewables,” according to the Law Office of Carolyn Elefant [1]. And while it was challenged in November, FERC clarified in January that payments to U.S. renewable generators can now be differentiated based on renewable energy (RE) technology (and perhaps other ways), making the payment structure closer to European renewable policy design.A large ship saling at sea, Credit: ┼╗eglarz, Wikimedia Commons

What’s the Big Deal with Differentiated Avoided Costs?

Utility avoided costs are complex – much like sailing a tall ship.  The issue at hand is how to calculate what utilities pay qualifying facilities (QFs)—including renewable generators and combined heat and power (CHP) plants. Under the Public Utility Regulatory Policies Act (PURPA), QFs can be paid no more than the utility’s avoided cost, or the “incremental cost of alternative energy” [2].  Under PURPA, FERC delegated to state utility regulators the authority to set prices paid to QFs, as long as the payment level is not greater than the utility’s avoided cost.  (Note that utility avoided cost is not a limitation in Hawaii, Alaska, or for ERCOT—the electrical interconnect in Texas. See [3] for more detail.)

Past FERC orders and rulings have long been interpreted to mean that the utility avoided cost (distinct for each utility) was the cheapest available marginal power available.  This utility avoided cost was typically estimated as a natural gas combined cycle (NGCC) unit. But payments based on NGCCs are not sufficient to support new renewable project economics in most of the United States.  Therefore, FERC’s avoided cost interpretation under PURPA (i.e., the cheapest available marginal power) limited the ability of states to support renewables through production-based incentives like FITs.

Therefore, instead of relying on PURPA, states adopted renewable portfolio standard (RPS) policies. RPS policies are established under state law (not PURPA), and they specify the amount of eligible renewables required while allowing the market to set the price.  Because the state does not establish the price paid to renewable projects and allows utilities to negotiate with market players, the contracts are viewed as acceptable to FERC.

But What Changed?

On October 21, 2010, FERC issued an historic order in a California FIT docket. Where FERC surprised everyone is by “overruling SoCal Edison’s broader language on this issue” [2] (i.e., the existing precedent) in a significant reinterpretation of utility avoided cost methodology. 

This unexpected ruling has three main components. First, if a state has a renewable requirement under PURPA authority (I don’t believe any do right now), avoided costs are no longer solely based on the one and only least expensive generation unit. FERC stated that “[If] a state required a utility to purchase 10 percent of its energy needs from renewable resources, then a natural-gas fired unit…would not be relevant to determining avoided costs for that segment of the utility’s energy needs” [2]. In other words, in states that decide to create a new renewables requirement under PURPA, renewable generation can have an avoided cost that is distinct from the general system mix. It is important to note that RPS policies are mandates under state law (not under PURPA), which means the FERC ruling would not apply directly.

Second, avoided costs can be differentiated—although it is unclear to what degree.  When asked for clarification in the California case, FERC stated, “[We] find the concept of a multi-tiered avoided cost rate structure can be consistent with the avoided cost rate requirements set forth in PURPA and our regulations.” They clarified that “[Avoided] cost rates may also ‘differentiate among [QFs] using various technologies on the basis of the supply characteristics of the different technologies’” [2]. This clarification was spelled out to include five factors in determining the price calculation: (1) a utility’s system costs, (2) contract duration, (3) QF availability during daily or system peaks, (4) whether the utility avoids costs from the daily or system peaks, and (5) costs or savings of line losses [2]. Therefore, it appears that there can be multiple avoided costs (perhaps for technology, too) if certain conditions are met. These conditions will require qualified lawyers to interpret this language, or it may be clarified in future dockets, if the matter is brought before FERC.

Finally, adders that can be calculated and justified can also be incorporated in the avoided cost estimate, including the avoided transmission and distribution costs. FERC stated that if a QF helps the purchasing utility avoid “expected costs of upgrades to the distribution or transmission system…such an ‘adder’ or ‘bonus’… [is] consistent with PURPA” and thus can be included. Importantly, FERC explained that environmental externalities cannot be included as an avoided cost adder unless it is a “real cost” (e.g., a carbon tax) [2].

Utilities were just as surprised as anyone by FERC’s order. In fact, on November 22, 2010, the Edison Electric Institute (EEI) and the three California investor-owned utilities petitioned FERC to “withdraw the avoided cost provisions of the...order” [4].  FERC denied the petition on January 20, 2011 [5].

The sustained ruling appears to indicate that states can set renewable avoided cost rates under PURPA that are distinct from conventional utility avoided costs.  And while it is not entirely clear, perhaps renewable avoided costs could be further differentiated by technology, length of contract, daily and system peaks, and/or avoided transmission and distribution costs.  The law firm of Dewey & LeBoeuf states, “The Clarification, therefore, grants California great flexibility in developing and executing a statewide renewable energy policy,” although “[it] is unclear…how thinly California will be permitted to slice its definitions” [6]. Thus, it appears that FIT payments can be differentiated (to some degree), making them similar to those used in Europe. And while this is part of a California FIT docket, the FERC ruling would apply outside of California and perhaps could be applied outside of FIT policies (as long as PURPA is the basis for RE policy). 

The FERC order applies to QFs that are smaller than 20 MW, even if utilities applied for an exemption from PURPA. The Energy Policy Act (EPAct) of 2005 authorized FERC to exempt electric utilities from the PURPA requirement if (1) they meet specific requirements and (2) they apply to FERC for such an exemption. However, “FERC…has clarified that the utility [exempt from PURPA] is still obligated to purchase from QFs with a capacity of 20 MW or less” [3].

It is not surprising, then, that California utilities are taking action. According to Carolyn Elefant, the California utilities worked with CPUC to develop a settlement (filed March 18, 2011), which includes several components. First, the three California utilities filed an application with FERC to secure the EPAct 2005 exemption—to terminate PURPA QF purchase obligations for QFs greater than 20 MW in size [7]. Second, the settlement also clarifies that the utilities and regulators will work together “to establish a new QF/CHP program and to make available additional power purchase agreement (PPA) options for QFs 20 MWs and smaller.” Elefant further explained that it isn’t clear if FERC will accept the settlement since there are “an awful lot” of QFs that would be impacted [8]. It appears that about 20 entities submit to intervene, some in support of the settlement and some protesting it [9].

So—What is Next?

Overall, this FERC order is seen as a positive ruling by the RE community.  FERC’s reinterpretation of existing precedent appears to provide a clear path for using PURPA to create differentiated avoided costs for renewables. In addition, even if a utility is exempt from PURPA, it still has an obligation to provide avoided cost payments to QFs less than 20 MW.

There are several questions that remain in my mind (I’d love to hear your comments!):

  • •    Is there a limit to the number of avoided cost rates that can be created?  For example, can avoided cost differentiation occur based on technology (geothermal separate from wind)? Size of the project? Physical location of installation (e.g., rooftop or ground-mounted PV)?
  • •    Most state RPSs were established outside of PURPA (under state law—such that this FERC order). Will any of these states adopt FIT policies (under PURPA) to help support new renewable project development?


[1]  Elefant, Carolyn, “FERC’s New ‘Un-FIT’ Ruling May Allow Favorable Pricing for Marine Renewables.” Law Offices of Carolyn Elefant, blog entry by Carolyn Elefant on November 1, 2010. http://lawofficesofcarolynelefant.com/renewablesoffshore/?p=646. Accessed June 1, 2011. 

[2] Federal Energy Regulatory Commission (FERC). “Order Granting Clarification and Dismissing Rehearing.” 133 FERC ¶ 61,059, Docket EL10-64-001 (California Public Utility Commission) and Docket EL10-66-001 (Southern California Edison, Pacific Gas and Electric Company, and San Diego Gas & Electric Company), Issued October 21, 2010.
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=12468361. Accessed June 1, 2011.

[3] Hempling, Scott; Elefant, Carolyn; Cory, Karlynn; and Porter, Kevin. Renewable Energy Prices in State-level Feed-in Tariffs: Federal Law Constraints and Possible Solutions. NREL/TP-6A20-47408. Golden, CO: National Renewable Energy Laboratory, January 2010.  http://www.nrel.gov/docs/fy10osti/47408.pdf. Accessed June 1, 2011.

[4] Edison Electric Institute. “Request for Rehearing of the Edison Electric Institute before the Federal Energy Regulatory Commission.” Docket EL10-64-001 (California Public Utility Commission) and Docket EL10-66-001 (Southern California Edison, Pacific Gas and Electric Company, and San Diego Gas & Electric Company), November 22, 2010. http://www.eei.org/whatwedo/PublicPolicyAdvocacy/TFB%20Documents/101122ComerFercAvoidedCosts.pdf. Accessed June 1, 2011.

[5] FERC. “Order Denying Rehearing.” 134 FERC ¶ 61,044, Docket EL10-64-001 (California Public Utility Commission) and Docket EL10-66-001 (Southern California Edison, Pacific Gas and Electric Company, and San Diego Gas & Electric Company), Issued January 20, 2011. http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=12539290. Accessed June 1, 2011.

[6] Dewey & LeBoeuf. “FERC’s Clarification of California Feed-in Tariff Order Opens the Door for Higher Prices for Some Renewable Generation but May Have Unexpected Consequences.” Client Alert, October 28, 2010. http://www.deweyleboeuf.com/~/media/Files/clientalerts/2010/FERCsClarificationofCaliforniaFeedInTariff.ashx. Accessed June 1, 2011.

[7] Pacific Gas and Electric Company; San Diego Gas & Electric Company; Southern California Edison Company. “Application of [said utilities] to Terminate PURPA Purchase Obligation for Qualifying Facilities Greater than 20 MW.” Docket No. QM11-2-000,  March 18, 2011. http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12590995. Accessed June 1, 2011.