By a two-to-one majority, the Federal Energy Regulatory Commission (FERC) voted on September 19, 2019 to propose revisions to its regulations under the Public Utility Regulatory Policies Act of 1978 (PURPA) to provide states with additional flexibility in establishing avoided cost rates that utilities are required to pay to cogeneration and small renewable energy generating facilities.1 In the Notice of Proposed Rulemaking (NOPR) approved in this decision, FERC also proposes certain other changes to its regulations implementing PURPA.
PURPA was enacted in the aftermath of the energy crises of the 1970s as part of an effort to promote conservation and improved efficiency in the electric generation sector and reduce the amount of oil and natural gas used for electric generation. Under the authority of PURPA, FERC issued regulations that required electric utilities to (i) allow “qualifying cogeneration facilities” and “qualifying small power production facilities” (referred to as qualifying facilities or QFs) to interconnect to their electric transmission and distribution facilities, (ii) sell electric energy to QFs, and (iii) purchase electric energy and capacity from QFs at “avoided cost” rates. In general, cogeneration QFs are projects of any size that make use of excess heat either from industrial operations to generate electric energy or from generating electric energy to support an industrial process. Small power production QFs generally are projects with a capacity of 80 MW or less that use renewable energy sources (principally wind, solar, geothermal, or biomass) to generate electric energy. Many PURPA requirements are implemented by the states, subject to compliance with regulations issued by FERC. There are variations between states as to how they implement the requirements of PURPA and FERC’s regulations.
PURPA was an important first step in providing the legal framework for the development of the independent power generating industry in the United States. Other federal statutes and FERC regulations adopted after PURPA—as well as legislation in many states—have significantly expanded the market for non-utility electric generation and led to development of vibrant wholesale and retail electric markets in many parts of the United States. However, some states—particularly in the Southeast and much of the Western United States (other than California)—have largely maintained the traditional model of vertically integrated electric utilities and provided only limited opportunities for non-utility electric generation to participate in the market. It is particularly in these states where PURPA plays an important role for utility-scale independent generation.
Many utilities and state regulators have sought relief from FERC’s current regulations—especially the requirements that utilities must purchase energy and capacity from QFs at the utilities’ avoided costs (i.e., the “cost to the electric utility of the electric energy which, but for the purchase from [the QF], such utility would generate or purchase from another source”2). In proceedings seeking input on proposals for PURPA reform, FERC heard concerns that the current method for calculating avoided cost rates led to contract rates that were higher than market rates.3
In the NOPR, FERC discussed several key reasons why the current PURPA regulations should be changed:
- Domestic natural gas supplies are more plentiful than at the time when PURPA was enacted.
- US electric markets have been transformed to provide for open access to transmission networks and vibrant, competitive wholesale electric markets where independent electric generators (including those using renewable resources) can sell their output.
- Federal and state programs now provide various incentives for development of alternative resources, including renewable resources.4
The key proposals included in the NOPR are as follows:
- Revisions to avoided cost regulations:
- States would have the flexibility to require that the energy rates in contracts with QFs vary with changes in the purchasing electric utility’s avoided costs at the time the energy is delivered (instead of being fixed in advance for the term of the contract). The NOPR justifies this proposal, in part, by noting that concerns about fixing contract prices over the long term have led some state utility commissions to limit—or consider limiting—the term of QF contracts to as little as one to three years (a trend that many QF developers have opposed).5 Independent power producers are likely to be concerned about whether they can obtain financing for projects with offtake contracts that are at prices essentially the same as the prices the producer would receive if it were selling into the merchant market. FERC recognizes this concern and suggests that the QFs could also enter into financial hedges, such as contracts for differences, to establish a fixed price.6
- To the extent states allow QFs to enter into contracts at a fixed rate, the states would have additional flexibility to have those rates determined based on projected energy prices during the delivery term of the contract. For example, prices could be set based on forward energy price curves as of the time the contract is entered into.7 This proposal may raise questions about what would be an appropriate, publicly available source for such price projections.
- States could set “as-available” rates for QF sales (to the extent the contract does not have a fixed price) based on market prices. For example, for electric utilities located in organized electric markets,8 this would be the locational marginal price (LMP) established in that market. In other areas, the market price could be established at a liquid market hub (such as the Mid-Columbia (Mid-C) hub in the Pacific Northwest or the Palo Verde Hub in the Southwest), and FERC proposes certain factors that could be considered to determine whether the prices at the market hub are competitive and reflect the utility’s avoided costs. Alternatively, a competitive price could be calculated based on natural gas price indices and heat rates (because combined cycle, natural gas-fired, electric generating units often set the marginal price for electric energy in many markets).9 It can be expected that many parties will raise issues about whether the prices at certain market hubs are appropriate measures of the utilities’ avoided costs on a consistent basis (instead of just being used for certain balancing transactions). Parties also may raise questions about whether basing avoided costs on the marginal cost of production from combined cycle plants adequately considers other relevant factors, such as the supply/demand balance at any particular time and transmission congestion.
- States also would be able to allow utilities to determine QF contact rates for capacity and energy through competitive solicitation processes. FERC proposes that such solicitations must be transparent and non-discriminatory and suggests some minimum requirements including: transparency; availability to all interested, qualified bidders; being conducted at regular intervals; independent administration; and oversight by a state utility commission or nonregulated electric utility.10 QF developers can be expected to suggest many additional requirements for such solicitations.11
- Revisions to utility purchase requirement:
- States that have retail choice programs could reduce the obligations of electric utilities to purchase energy from QFs to the extent those utilities’ supply obligations have been reduced. For example, to the extent that utilities retain a provider of last resort obligation and procure supplies to serve those obligations through solicitations with a particular term (e.g., one year), the utilities would only be required to enter into purchase contracts with QFs with the same term.12
- FERC would expand the scope of the regulation that allows utilities operating in certain competitive wholesale markets13 to avoid the requirement to purchase the output of QFs to cover small power production QFs that have a capacity between 1 MW and 20 MW. This regulation currently exempts utilities operating in such markets from the requirement to purchase the output from QFs that are larger than 20 MW, but there is a rebuttable presumption that QFs with a capacity of 20 MW or less do not have non-discriminatory access to such competitive electric markets. Unless this presumption is rebutted (which has occurred only rarely), utilities are required to purchase from all QFs with a capacity of 20 MW or less at avoided cost rates. Under the proposal, the exemption from the requirement to purchase would apply to all small power production QFs with a capacity greater than 1 MW; the rebuttable presumption would only apply to small power production QFs with a capacity of 1 MW or less.14 If adopted by FERC, this proposal would virtually eliminate the ability of utility-scale renewable energy projects to require utilities to enter into power purchase agreements with small power production QFs in these markets and would place smaller (between 1 and 20 MW) renewable energy projects on an even footing with larger projects. As is the case currently for their larger counterparts, these small utility-scale projects may have difficulty obtaining financing based solely on their ability to sell at merchant prices into wholesale RTO or ISO markets and may need to find utilities or corporate or financial entities who are willing—without being required to do so under PURPA—to enter into physical or financial contracts to establish a fixed price for the project output.
- FERC would require QFs to demonstrate commercial viability and a financial commitment to construct the facility before the QF is legally entitled to require an electric utility to enter into a contract at avoided cost rates. FERC’s current PURPA regulations entitle a QF to have the avoided cost calculation made at the time that the utility has a legally enforceable obligation (LEO) to enter into a contract with a QF, but the regulations do not specify what is required to demonstrate an LEO. Under the NOPR, the PURPA regulations would be amended to require the QF to “demonstrate that a proposed project is commercially viable and the QF has a financial commitment to construct the proposed project pursuant to objective, reasonable, state-determined criteria in order to be eligible for an LEO.” The proposal does not prescribe the criteria to be established by the states but provides examples such as “(1) obtaining site control adequate to commence construction of the project at the proposed location; (2) filing an interconnection application with the appropriate entity; (3) securing local permitting and zoning; or (4) other similar, objective, reasonable criteria.”15 The plain words of the proposal (to require that the QF demonstrate commercial viability and a financial commitment) sound stricter than what is implied by the example criteria listed above. It does not appear that FERC intends that the proposal would require any type of financial analysis to demonstrate commercial viability or a formal commitment from a financing party to fund the construction. Additional clarification in the regulatory language may be needed to prevent states from erecting unreasonable barriers to establishment of an LEO
- Revision to QF size determination:
- FERC would revise the current one-mile rule under which the size of facilities seeking qualification as a small power production QF (the size of which is limited to 80 MW) is determined by including any facilities with affiliated ownership located within one mile of the facilities seeking qualification. This is intended to prevent parties from circumventing the 80-MW size limitation by dividing a larger single facility into multiple smaller, closely located facilities. Under the proposal, facilities located between 1 and 10 miles of each other would be initially presumed to be separate facilities, but that presumption could be rebutted by evidence presented by a protesting party or the Commission.16 If this proposal is adopted, QFs seeking financing may need to file with FERC their self-certification forms earlier in the development process, because financing parties may be reluctant to provide funding until the time for filing any protests has expired without any protest having been filed (or any such protests have been denied by a FERC order that has become final and non-appealable).
- Procedural changes:
- QFs would need to present certain additional information in their certification applications, in particular related to the location of and ownership of their facilities. This would assist in determining whether the rebuttable presumption for facilities located within between 1 to 10 miles of each other has been met.17 While FERC proposes to use an affiliation standard for such purposes that excludes certain passive equity interests, the disclosures required on the forms used for certification and self-certification applications have traditionally been interpreted to require a broader standard for inclusion of upstream owners (including equity owners that would not be considered to be “affiliates” under this standard). Unless the filing standards are changed, parties may need to provide additional information in the “Miscellaneous” section of their QF filings to explain why certain passive owners should not be treated as affiliates for purposes of determining whether facilities located within 1 to 10 miles of each other are a single facility for QF purposes.
- Any party would be able to protest a QF self-certification application (within 30 days after filing of the application) without having to file a petition for declaratory order (and paying the associated filing fee). FERC proposes to continue its current policy under which self-certifications are effective upon filing and remain effective during the pendency of any ruling on a protest, unless and until the self-certification is revoked. Under the proposal, FERC would rule upon protests within 90 days but the timeframe could be extended in certain circumstances.18 Considered together with the proposal to revise the one-mile rule, as discussed above, this may require QFs to make their self-certification filings earlier in the development process so that their financing will not be delayed during the pendency of the time for filing a protest or for resolving any protest that has been filed.
As noted above, the NOPR was approved by a two-to-one majority. Chairman Neil Chatterjee and Commissioner Bernard McNamee voted in favor of the full NOPR, while Commissioner Richard Glick dissented in part. In his dissent, Commissioner Glick disagreed, in particular, with the proposal to eliminate the requirement for utilities to enter into power purchase contracts with QFs at fixed rates for the duration of the contracts, claiming that doing so will make it much harder—or impossible—for QFs to obtain financing and will not adequately protect QFs from discriminatory rates. He also objects to the proposal to determine that LMPs are per se reasonable measures of as-available avoided costs for energy and the proposals for use of certain other measures of competitive market prices. Commissioner Glick argues these proposals will place QFs on an uneven playing field compared to vertically integrated utilities that in many cases are virtually guaranteed full cost recovery for their electric generation investments. Finally, Commissioner Glick opposes changing the current rebuttable presumption that small power production QFs of 20 MW or smaller do not have non-discriminatory access to competitive wholesale markets in RTO or ISO markets; he argues that there is no evidence to support reducing this threshold to 1 MW.
In general, Commissioner Glick expresses the view that certain changes of the type proposed in the NOPR should be addressed by Congress and not by FERC. And he argues that many of the statistics presented in the NOPR as reasons to reform the PURPA rules—such as the growth of independent generation and renewable energy projects—show that PURPA has been successful in encouraging competition rather than showing that many PURPA requirements are no longer necessary. Moreover, he notes that many of these statistics show success in areas of the country where highly developed RTO or ISO markets exist but do not show that PURPA is no longer necessary in parts of the country with less competitive markets.
As noted above, comments on the NOPR will be due within 60 days of publication in the Federal Register. Given the active participation of many different parties in the proceedings leading up to the issuance of this NOPR and its importance for independent generators, renewable energy advocates, consumer advocates, electric utilities, and state utility regulators, it can be expected that FERC will receive vigorous and varied comments in response to the NOPR. Once FERC has had the opportunity to review the comments, it will be able to issue a final rule (or perhaps a further revised proposed rule).
It should be noted that the composition of the Commission is likely to change significantly before any final rule is issued, because there currently are two open positions on the Commission. The Commission generally includes five members (each of whom is appointed by the President and confirmed by the Senate), with no more than three commissioners of the same political party. The Commission now includes two commissioners from the Republican Party (Chairman Chatterjee and Commissioner McNamee) and one from the Democratic Party (Commissioner Glick). Accordingly, one of the open positions could be filled from the Republican Party and the other open slot likely would be filled by a nominee from the Democratic Party. Given the likelihood that up to two additional commissioners will be added before FERC acts on a final rule, the two commissioners who made up a majority of the Commission when it issued the NOPR would no longer constitute a majority without being joined by at least one additional commissioner.