For the last few years, several local and state governments, reflecting local policies, have adopted so-called “feed-in tariffs” (FIT) to promote development of dispersed, small scale renewable generation through incentive pricing. Most FITs are intended to stimulate development of small scale solar or renewable energy facilities, i.e. rooftop and small commercial scale, as compared with large, utility scale generation. On July 15, 2010, the Federal Energy Regulatory Commission (FERC) issued a narrowly written decision in California Public Utilities Commission, 132 FERC ¶61,047, (FIT Order) restating that Part II of the Federal Power Act (FPA) and Section 210 of the Public Utilities Regulatory Policy Act of 1978 (PURPA 210), not state (or local) legislation, govern the price that local utilities may pay under FITs for electric energy from small scale, highly efficient combined heat and power (CHP) systems (cogenerators). That decision almost certainly extends to FITs governing solar and comparable small scale renewables. Immediately following the decision, the National Association of Regulatory Utility Commissioners adopted a resolution seeking Congressional nullification of the decision. [1] At the time of this writing, the likelihood of Congressional action in the near future is dim; leaving the stark questions whether and how the states are going to resolve their differences over feed-in tariff pricing. Will that discussion be confrontational or cooperative?
While the immediate focus of the FERC FIT Order and ensuing debate is whether federal or state law establishes the standards to determine the price to be paid under an FIT, the underlying policy questions are: (i) who should decide the appropriate level of incentive to pay for such renewables; (ii) whether electricity consumers or the public at large, ultimately should pay for those incentives; and (iii) how much regulatory compliance should be required of the FIT-designated generators themselves? Should the incentive premium above average system costs be included in the purchasing utility’s revenue requirement or should the premium be paid by state funds?
FERC asserts that sales from FIT-qualified generators to local utilities are subject to its jurisdiction because they occur in interstate commerce and the local utility then resells that electricity to its retail customers. Since 1935, jurisdiction over the rates for those sales have been subject to the FERC’s exclusive jurisdiction under FPA Sections 201, 205 and 206, with certain exceptions. One major objective of such jurisdiction is to protect consumers by applying uniform standards for determining the costs of wholesale electricity. By contrast, FITs and their authorizing statutes reflect local acceptance of the fact that a price exceeding the average cost of conventional generation is needed to make the installation of dispersed residential and commercial small scale solar and other renewable generation financially feasible. Can those local policy decisions be accommodated within a dual state-federal regulatory framework? Assuming that Congress will not enact a national renewable energy policy in the foreseeable future, the FERC’s FIT Order will either serve as a framework for a state-federal regulatory accommodation on acceptable renewable incentives or be used as yet another wedge to add to the burgeoning tensions between state and federal regulators involving energy facility/resource issues.
This article suggests that coordinated application of state and federal statutes may be achievable to satisfactorily implement FITs. First, it will briefly describe feed-in tariffs from a regulatory perspective. Next, it will discuss the issues presented to the FERC and their resolution in the FERC’s FIT Order. This article will conclude with suggested topics of discussion by the FERC and all stakeholders that might enable implementation of FITs with a minimum of federal “intrusion.” The federal regulatory compliance obligations of FIT generators, an issue only obliquely addressed in the FIT Order, will be included in this discussion because it is integral to FERC jurisdiction over sales for resale under FPA Part II. While FITs sometimes are used in conjunction with utility scale renewable and efficient generation, for purposes of simplifying the discussion, this article will assume that FITs refer primarily to small scale, e.g. under 3 MW, renewable resources and CHPs of under 20 MW.
Distributed Renewable Generation and FITs
The right of states to determine the types of generating resources encouraged within their boundaries has long been federal policy expressed in the FPA and in precedent. For more than a decade, many states have enacted renewable portfolio standards (RPS) that require retail load serving utilities in their state to obtain specified percentages of their energy supply from renewable resources.[2] Fulfilling an RPS requirement that may require load serving utilities to obtain as much as a third of their energy supply from renewable generation within ten to fifteen years necessarily promotes the development of “utility-scale” projects.
Feed-in tariffs, by contrast, represent a determination that small scale, renewable and highly efficient conventional generation at load sites are a necessary complement to RPS requirements. Such requirements meet the state goal of promoting a sustainable energy supply and reducing greenhouse gas emissions. Whereas larger scale renewable generation, often with large footprints, must be undertaken with the expectation of meeting the myriad challenges of developing utility scale generation, the premise of FITs is that as many of the contracting and regulatory approval hurdles as possible must be eliminated in order to facilitate dispersed deployment of FIT-qualified generation. That premise underlies the following working, (and somewhat aspirational), definition of a state-level feed-in tariff included in a report prepared for DOE’s National Renewable Energy Laboratory:
a publicly available, legal document, promulgated by a state utility regulatory commission or through legislation, which obligates an electric distribution utility to purchase electricity from an eligible renewable energy seller at specified prices (set sufficiently high to attract to the state the types and quantities of renewable energy desired by the state) for a specified duration; and which, conversely, entitles the seller to sell to the utility, at those prices for that duration, without the seller needing to obtain additional regulatory permission.[3]
Under that definition, the two key elements of a FIT are (1) the obligation of distribution utilities to purchase the output from FIT-qualified generators at a specified price, and (2) the establishment of that price at a level reflecting the cost of comparable renewable/efficient generators, rather than the utility’s average supply cost. U.S. localities have noted that in Germany and other European countries, such tariffs have promoted widespread deployment of solar photovoltaic panels on rooftops through the payment of a generous incentive rate.[4] Apart from California, only a few U.S. localities such as Gainesville, Florida (for its municipal electric distribution utility)[5] and the State of Vermont[6] have adopted FITs, and those are tailored to renewable generating facilities of less than 20 MW.
Summary of the FERC FIT Order
The FERC’s FIT Order arises from competing requests to the FERC by the California Public Utilities Commission (CPUC) and California’s three major investor-owned utilities (IOU) respectively seeking confirmation or rejection of the CPUC’s decision requiring each IOU to offer a standard-form ten-year power purchase contract, including a CPUC-approved price, for the purchase of energy produced by CHPs with a total generating capacity of less than 20 MW.[7] The CPUC decision implemented California statute AB 1613, which is limited to CHPs. AB 1613 is part of suite of statutes requiring FITs for various forms of renewable generation, as well as other measures aimed at reducing greenhouse gases. The CPUC’s petition contended that those contracts, which are themselves the feed-in tariffs, were compatible with FERC’s jurisdiction under Part II of the FPA and Section 210 of PURPA (PURPA 210). The CPUC’s contention was premised on the principle that the states alone have jurisdiction over their utilities’ resource portfolios, and the FPA does not preempt California from implementing AB 1613 because the CPUC requires only that such utilities make an offer to buy power. In contrast, the IOUs’ petition contended that the two federal statutes preempt AB 1613’s feed-in tariff program
FERC conceded that states may require utilities to purchase capacity and energy from specified resources. It also held under existing precedent that the AB 1613 feed-in tariff program was not preempted to the extent it constitutes the state’s implementation of PURPA 210 with the proviso that (1) those CHP generators eligible for contracts with the purchaser utilities must have or obtain qualifying facility (QF) status under PURPA 210 and the FERC’s implementing regulations; and (2) the rates the purchaser utilities are required to offer to CHP/QFs may not exceed the utilities’ respective avoided costs. FERC explicitly rejected the arguments of the CPUC and many supporting intervenors that environmental considerations gave California complete jurisdiction over FITs. It ruled that such factors have no bearing on FERC’s exclusive jurisdiction over wholesale rates. FERC was unswayed by assertions that state estimates of environmental costs and benefits, e.g. reduction of carbon emissions, could be included in state avoided cost determinations for purchases from QFs. It reaffirmed that QF purchase rates may not exceed the purchasing utility’s avoided cost as determined by the kinds of quantifiable information permitted under PURPA section 210 and the Commission’s QF regulations. Noting a lack of record evidence, the FERC FIT Order did not otherwise rule on the level of the CPUC-required purchase rate nor further address the jurisdictional status of renewable generation sellers.
The Policy Dilemma Presented by the FIT Rate “Premium”
The FERC’s FIT Order did not create a new policy dilemma; it simply reminded California and the states that the states’ rights to establish policy concerning electric generation resource selection does not include power to impose prices under state law where sales of electricity for resale and any form of interstate transmission are involved. The framework under FPA Sections 201, 205 and 206 both establishes FERC’s exclusive right to set, or at least limit, the price to be paid by utilities under FITs, and to accept or reject each such sale because each seller, i.e. each rooftop generator, that sells to a distribution utility is itself a “public utility” subject to its jurisdiction under the FPA (unless the generator is a publicly-owned entity exempt from FERC’s rate jurisdiction under FPA 201(f)).
States and localities that have adopted FITs understandably are frustrated by the federal jurisdictional limitations on their policy reach. Nevertheless, when the essence of the concern is viewed apart from the renewable energy context, the issue of whether states should be permitted to establish the costs of electricity sold in interstate commerce and, potentially, export the cost of individual state initiatives to electricity consumers in neighboring states is similar to the controversies that led to the Supreme Court’s seminal Attleboro precedent[8], the enactment of both Part II of the FPA in 1935, and PURPA 210 in 1978, and the seminal cases since then. The real issue for FIT promoters is whether it is more appropriate for state or federal authorities to decide whether customers of the distribution electric utility should pay the state-authorized FIT premium above the “cost-based” or “market based” rate when such a premium is needed to facilitate dispersed renewable development.
The assumption that FITs require incentive rates rests on two factors. First, the installed capital costs of most renewable generation technologies as measured on a per-kilowatt (kW) basis substantially exceeding the comparable costs of conventional generation that now compose a substantial portion of the existing base load generation fleet. Second, despite the negligible variable cost of renewable generation, the intermittency of many types of renewable generation means that fewer kilowatt-hours will be generated per kilowatt of installed capacity than is characteristic of the existing base load fleet. This means that the average cost of renewable energy per kW of installed capacity is higher than the average costs for most load serving distribution utilities. CHPs do not suffer from the problem of intermittent generation. Because CHPs have higher capital costs than less efficient cogenerators as well as somewhat greater variable costs than renewables, they, too need a premium rate.
By contrast, the long recognized purpose of rate regulation is to establish electric utility rates that are fair to BOTH consumers and generators. In 1978, Congress faced the tension between the imperative of rate regulation and the desire to promote development of renewable and cogeneration (more efficient) facilities by enacting the avoided cost concept in PURPA 210. The basic assumption linking consumer and generator interest embodied in the avoided cost concept is that every kilowatt-hour that a utility purchases from a qualifying facility (QF) is the utility’s marginal requirement and the premium is capped at the purchasing utility’s “avoided cost,” i.e. the cost the utility would incur for the next increment of capacity or energy obtained to meet its incremental energy requirement.[9] Avoided cost, therefore, is not determined by reference to the needs of a particular type of generating resource, as is the case in many FITs, but rather at the intersection of the marginal energy and capacity requirement and the costs of energy or capacity needed to meet that requirement. The costs included in the avoided cost determination, therefore, had to be observable, as the FERC later confirmed in Southern California Edison Co.[10] and Connecticut Light and Power Co,[11], and reasserted in the FIT order.[12] The rate incentive is the amount by which the avoided cost exceeds the utility’s average system supply cost.
The PURPA 210 rate concept is, therefore, an evolution of the FPA Part II “just and reasonable” framework of rate regulation. Unlike FPA Sections 205 and 206 which designate FERC as the sole arbiter of rates, PURPA 210 provides for shared state-federal implementation that may yet serve FIT purposes. Under PURPA 210 FERC established the rules for determining which generators qualified as QFs and the formula the states must use to determine the avoided cost rates for each distribution utility they regulate.[13] FERC retained the obligation to determine which entities qualified as QFs, while the states were empowered to determine the appropriate rates, terms and conditions under PURPA, i.e. “implemented the requirements of Section 210 of PURPA” as the FERC describes the regime. Thus, within the limits on the avoided cost rate levels inherent in the FERC’s PURPA regulation and subsequent decisions in individual enforcement cases, the states were left with the responsibility of determining the “premium” that utilities and, ultimately, ratepayers would pay for the more efficient, environmentally preferable generation that was to be encouraged.
The one significant difference between PURPA 210 and an FIT that must be considered in applying the shared federal-state regulatory implementation model relates to the scale of the generation qualifying for a rate premium. The avoided cost concept assumes that utilities would purchase energy from QFs to meet system requirements rather than constructing their own large scale generating facilities. To a large extent, purchases by utilities from QFs were to replace purchases by utilities from other utilities at rates that otherwise would be regulated by FERC under the just and reasonable standard of FPA Sections 205 and 206.
FITs, by contrast, are intended to promote the development of small scale renewable and efficient distributed generation located near consumers’ loads. FIT-qualifying generation of this scale may be considered as much of a load displacement rather than a utility supply dimension. If such generation is used solely to meet end-user load, no FERC-regulated sale at wholesale would be involved. Since FERC’s jurisdiction over sales of electricity is limited to sales for resale in interstate commerce, the purely retail sale from generation to load would be regulated by the states under state law. This difference suggests that strict application of the existing PURPA 210 avoided cost model to resolve the question whether state or federal regulators should have the final say over the level of the FIT rate “premium” is not quite satisfactory. Under the existing statutory and regulatory structure confirmed in the California FIT decision, what are the opportunities for federal state collaboration on pricing the FIT premium and approving FIT transactions?
Potential FERC Initiatives to Facilitate State Pricing of the FIT Premium Consistent With Federal Statutory Standards
There appear to be two aspects of the current federal regulatory structure that interfere with complete state formulation and implementation of FITs. The first is rate regulation under either FPA Sections 205 and 206 or PURPA 210. This is the framework confirmed by the FERC’s FIT Order.
The second is that since generators qualifying for FIT treatment are public utilities under the FPA, they must file their rates, terms and conditions of service with the FERC under FPA Part II unless they fit within the QF exemptions under PURPA 210 and the FERC’s implementing regulations. This is not an issue for FIT QFs with a net power production capability of 1 MW or less. Those FIT generators that qualify as QFs under PURPA 210 with a net power production capability exceeding 1 MW must make a filing with FERC to confirm that they meet the QF standards in the FERC’s regulations[14] and either self certify or file an application with the FERC to confirm such status.[15] QFs using renewable sources with a net power production capacity of less than 20 MW (or higher in the case of geothermal sources) are exempt from various provisions of the FPA[16] and the Public Utility Holding Company Act of 2005.[17] These requirements were not addressed by the FERC’s FIT decision, however, if the FERC actively enforces them, they may present potentially larger obstacles to FIT implementation than the rate issues because the home and small business owners that are expected to deploy FIT generators are not likely to be in a position to understand or bear the transaction costs of compliance.
Another factor common to both issues is the treatment of FIT generators that do not qualify as QFs. If each state were to define eligible FIT generators in a way that would also qualify them as QFs, the scope of concerns to be worked through with respect to both rate setting and utility filing would be simplified. States might consider requesting the FERC to clarify how and whether CHPs may qualify as qualifying cogeneration facilities.
The context of the FERC FIT Order suggests that if all FIT generators qualify as QFs, the most expeditious inquiry might be whether state commissions and FERC can agree on the factors that would be used to establish the FIT “premium” and on a safe harbor procedure for states to implement those factors within the PURPA 210 framework in a way that also conforms with applicable state FIT authorizing statutes. The CPUC stated in its August 16, 2010 request to FERC for clarification or rehearing of the FIT Order that it is willing to undertake precisely that approach if the FERC clarifies the necessary ground rules.[18]
Moreover, states should think creatively about how to define avoided costs of utilities purchasing energy from QF/FIT-qualifying generators. For instance, those states that have adopted RPS requirements may well be able to defend setting the PURPA 210 avoided cost at the average cost of a new renewable resource rather than conventional generation because the marginal capacity or energy may well be required to come from renewable resources. Similarly, to the extent that forthcoming regulations from the United States Environmental Protection Agency to curb greenhouse gas emissions under the federal Clean Air Act impose new costs on conventional generation, such costs may well be factored into the avoided cost calculation.
Finally, state commissions and FERC should also address the potential for procedural short cuts that ameliorate the burden of FPA and PURPA 210 filing requirements on individual FIT generators. One general approach might be for FERC to create categories of filings that rely explicitly on state determinations of FIT generator qualification if those qualification standards match those under PURPA 210. FERC might consider exercising its authority under FPA Section 209(b) to convene either bilateral or joint consultations with state commissions to address these issues.
Conclusion
The FERC’s FIT Order undoubtedly is irritating to states and stakeholders desiring to promote sustainable electricity generation in the absence of Congressional action. Nevertheless, the FIT Order is a reminder that the enduring consumer protection concerns inherent in the FPA and PURPA 210 ought to be observed while enlisting the population at large in the effort to control greenhouse gas emissions. The FERC FIT decision sharpens the focus on those issues and may provide a catalyst for productive state-federal collaboration rather than another wedge between them.
Endnotes:
[1] Resolution Supporting State Authority to Adopt and Promote Feed-in-Tariff Mechanisms for
Renewable and Other Generation Technologies, National Association of Regulatory Utility Commissioners (July 21, 2010), available online at: http://www.naruc.org/Resolutions/Resolution%20Supporting%20State%20Authority%20to%20Adopt%20and%20Promote%20FiTs.pdf
[2] See http://apps1.eere.energy.gov/states/maps/renewable_portfolio_states.cfm for an interactive map detailing the RPS requirements by state.
[3] Renewable Energy Prices in State-Level Feed-In Tariffs: Federal Law Constraints and Possible Solutions, Hempling, Elefant, Cory and Porter, NREL/TP-6A2-47408, January 2010 (hereinafter “NREL FIT Report”) at pp. iv-v. As will be demonstrated infra, the aspirational aspect of this definition is that current law does not permit avoiding the need “to obtain additional regulatory permission(s).”
[4] See, e.g., A Policymaker’s Guide to Feed-in Tariff Policy Design, Couture, Cory, et al. NREL/TP-6A2-44849, July 2010
[5] Gainesville City Ord., Appendix A, Utilities § (1)(i)(1)(C)
[6] 30 V.S.A § 8005.
[7] 132 FERC ¶61,047 (Docket Nos. EL10-64-000 and EL10-66-000, issued July 15, 2010).
[8] Public Util. Comm’n v. Attleboro Steam Co., 273 U.S. 83 (1927).
[9] It is beyond the scope of this article to describe the PURPA 210 regime. The NREL FIT Report provides a concise description of this framework as applied to FITs at pp. 5-13 and Appendix A.
[10] Southern California Edison Co., 70 FERC ¶61,215 (1995)
[11] Connecticut Light and Power Co., 70 FERC ¶61,012 (1995)
[12] The current promoters of FITs should not feel singled out by the FERC FIT decision. At the time that PURPA was adopted and implemented, several states attempted to improve on the concept with their own alternative energy facility bills that set rates under state authority above the levels of avoided cost under PURPA 210 and the FERC’s implementing regulations at 18 C.F.R. §292.304. The Commission struck down the rates at which public utilities were required to purchase the energy from such generators to the extent that they exceeded federally determined avoided cost rates. Midwest Power Systems, Inc. 78 FERC ¶61,067 (1997).
[13] This article will not discuss the parallel structure by which public power entities, i.e. “non regulated utilities” under PURPA 210, complied with the PURPA 210 requirements because those entities are often likely to be exempted from state FIT initiatives, as was the case in California and are not regulated directly by FERC.
[14] 18 C.F.R. §292.203 (effective June 1, 2010).
[15] 18 C.F.R. §292.207 (eff. March 1, 2010).
[16] 18 C.F.R. §292.601.
[17] 18 C.F.R. §292.602
[18] Request for Clarification Or, In The Alternative, Request For Rehearing Of The Public Utilities Commission Of The State Of California, filed in FERC Docket Nos. EL10-64-000 and EL10-66-000.