07.22.2020
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Updates
For the first time in 15 years, the Federal Energy Regulatory Commission (FERC) significantly revamped key aspects of its regulations implementing the Public Utility Regulatory Policies Act of 1978 (PURPA).[1] The 490-page final rule adopts many changes that electric utilities have long been seeking. It grants more flexibility for states to adopt variable rates for purchases of energy from qualifying facilities (QFs) and allows greater reliance on competitive pricing and calculations based on liquid trading hubs or indices to dictate avoided cost rates, potentially even outside organized wholesale markets run by regional transmission organizations or independent system operators (RTO/ISOs). FERC also addressed the contentious topic of forming legally enforceable obligations (LEOs), giving states more latitude to require that QFs demonstrate commercial viability and a financial commitment to construct their projects before an LEO can be formed, but stopping short of addressing certain issues, such as the states’ ability to severely limit QF contract terms. FERC also significantly revised the qualification requirements for small power production facilities (SPPs) and expanded electric utilities’ ability to terminate their purchase obligations altogether by lowering the rebuttable presumption of nondiscriminatory access to wholesale markets for SPPs (but not for cogeneration QFs) from 20 MW to 5 MW. FERC also adopted a few clarifications that should be beneficial to QFs, but overall Order No. 872 is a significant win for utilities.
That said, the magnitude of the impact from Order No. 872 on QF development will vary by state and by electric utility, as FERC continues to leave many crucial decisions and details up to the individual states. Notably, FERC also limited application of Order No. 872 to new contracts or entitlements with electric utilities and new QF certifications and recertifications making substantive changes to an existing QF, noting that FERC does not intend to “permit disturbance” of existing QF contractual arrangements or certifications.
Order No. 872 will be effective 120 days after publication in the Federal Register, which remains pending as of this writing. Rehearing requests are due August 17, 2020.
An overview of PURPA and detailed discussion of FERC’s changes to (1) Avoided Cost & Electric Utility QF Purchases, (2) Establishing LEOs, (3) Presumptions Regarding Non-Discriminatory Access to Wholesale Markets, and (4) Qualification of SPPs are provided below.
PURPA Overview
PURPA was enacted in 1978 with the goal of reducing the United States’ dependence on oil and natural gas by encouraging development of generating resources that used alternative fuels and cogeneration facilities that more efficiently combined production of heat and power. PURPA is somewhat unique in that it requires both federal and state action to implement. Specifically, Section 210(a) requires FERC to “prescribe, and from time to time thereafter revise, such rules as [the Commission] determines necessary to encourage cogeneration and small power production,”[2] including rules that require electric utilities to sell electricity to, and purchase electricity from, QFs. But Section 210(f) requires each state regulatory commission and nonregulated electric utility[3] to implement FERC’s rules.
FERC first promulgated its regulations under PURPA in 1980, and those regulations have largely remained untouched over the last 40 years. At that time, FERC concluded that QFs faced three crucial roadblocks: (1) electric utilities were not required to purchase QFs’ electric output at a non-discriminatory rate, (2) electric utilities sometimes charged discriminatorily high rates for backup services, and (3) QFs ran the risk of being subject to burdensome state and federal regulation as utilities.[4] Moreover, at that time FERC had not yet adopted open-access transmission principles, and it was extremely difficult for QFs to compete with vertically integrated utilities that controlled transmission access. To combat these obstacles, among other things FERC’s PURPA regulations directed electric utilities to provide energy to QFs on a non-discriminatory basis and at just and reasonable rates, required electric utilities to interconnect with QFs, and set rates for sales by QFs to electric utilities equal to the “avoided cost” of the purchasing electric utility. Determination of appropriate avoided cost rates for each electric utility was left up to individual states.
In 2005, the U.S. Congress amended PURPA to add Section 210(m), which provides for termination of the requirement that an electric utility enter into a new obligation or contract to purchase from a QF if the QF has nondiscriminatory access to certain kinds of markets. FERC implemented this statutory amendment in 2006 in Order No. 688, which was the last major overhaul of FERC’s PURPA regulations before Order No. 872.
Avoided Cost and Electric Utility QF Purchases
PURPA requires that rates for QF output sold to electric utilities must (1) be just and reasonable to the electric consumers of the electric utility and in the public interest, (2) not discriminate against QFs, and (3) not exceed the incremental “cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small power producer, such utility would generate or purchase from another source.”[5] FERC’s regulations refer to this incremental cost as the electric utility’s “avoided cost.”
FERC’s regulations[6] provide QFs two options to “put” power to an electric utility. First, the QF can sell energy when it is available, in which case the rate is calculated at the time of delivery (an “as-available” rate). Second, the QF can elect to sell its output over a specified term pursuant to an LEO which may be, but does not have to be, a signed contract. If the QF elects a LEO, FERC’s regulations allow the QF a further choice to be paid either (1) the purchasing electric utility’s avoided cost calculated at the time of delivery, or (2) the purchasing electric utility’s avoided cost calculated and fixed at the time the LEO is incurred.
Order No. 872 marks a significant change to FERC’s PURPA regulations by explicitly giving states “flexibility” to adopt variable avoided cost rates for QF energy and use competitive pricing to determine QF energy and capacity rates going forward. FERC was careful not to mandate that these measures be used, however, so it remains a state-by-state decision as to how a particular electric utility’s avoided cost rates will be determined. For example, FERC opened the door to:
- States requiring that energy rates (but not capacity rates) under LEOs vary in accordance with changes in the purchasing electric utility’s as-available avoided costs at the time the energy is delivered. If adopted by a state, a QF would lose its ability to elect to have its energy rate be fixed at the time the LEO was entered into, though it would continue to be entitled to a fixed capacity rate for the term of the LEO. This is a significant departure from court precedents interpreting a QF’s right to elect a fixed rate set at the start of an LEO.
- States setting “as-available” rates based on the locational marginal price (LMP) in an organized wholesale electric market, such as MISO, PJM, ISO-NE, NYISO, ERCOT, CAISO, and SPP. FERC adopted a rebuttable presumption that such LMP represents the as-available avoided costs of the electric utility located in such market. FERC left it to the states to determine which LMP is most representative of the avoided cost of the particular electric utility, including the question whether to use a “delivery node” LMP associated with the utility’s load or a “generator node” LMP where the QF is located.
Importantly for electric utilities in the West, FERC also concluded that LMPs in the CAISO’s Western Energy Imbalance Market (EIM) “may presumptively be used as a measure of as-available energy avoided costs for utilities able to participate in the Western EIM market.”[7]
With respect to electric utilities located outside of the organized electric markets noted above, FERC gave states flexibility to set QF energy rates at competitive prices from liquid market hubs or calculated from a formula based on natural gas price indices and heat rates, provided that the states first determine that such prices represent the purchasing electric utilities’ avoided costs.
- States setting both energy and capacity avoided cost rates pursuant to a competitive solicitation process conducted pursuant to transparent and non-discriminatory procedures consistent with FERC’s Allegheny standard and certain specified criteria that focus on openness and transparency.[8] FERC further clarified that if an electric utility acquires all of its capacity through such a competitive solicitation (i.e., it does not add capacity through self-build or other power purchase opportunities outside the solicitation), the competitive solicitation could be the exclusive mechanism for determining QF avoided capacity costs. Moreover, if a QF fails to win an award through such a competitive solicitation, the state could set its avoided capacity cost rate at zero (on the rationale that the utility has no capacity needs to fulfill outside the competitive solicitation).
The competitive solicitation could be an attractive option for a state looking to streamline its QF rate-setting process, since many states are familiar with designing competitive solicitations for resource planning purposes. Moreover, it may open the door for electric utilities to file with FERC to terminate their mandatory purchase obligations altogether for some QFs, as explained further below.
Taken as a whole, the flexibility envisioned by Order No. 872 may lead some states to allow a great deal more variability in QF avoided cost rates, a result that QFs have long fought against. While FERC recognized that QFs often rely on long-term fixed price contracts for financing, it concluded that other mechanisms—such as fixed avoided cost capacity prices and financial instruments used to hedge energy commodity prices—would ensure QFs remain financeable in the event a state decides to adopt variable avoided cost rates for QF energy.
FERC took steps to clarify that QFs must “demonstrate commercial viability and a financial commitment to construct” a facility “pursuant to objective and reasonable state-determined criteria” before the QF is entitled to create a LEO. Examples of such criteria provided by FERC include (1) taking meaningful steps to obtain site control adequate to commence construction of the project at the proposed location, (2) filing an interconnection application with the appropriate entity, and (3) requiring that the QF show that it has submitted all applications, including filing fees, to obtain all necessary local permitting and zoning approvals (though FERC stopped short of requiring that QFs had received such approvals). FERC was clear that these criteria were designed to “limit the number of unviable QFs obtaining LEOs and unnecessarily burdening utilities that currently have to plan for QFs that obtain a LEO very early in the process but ultimately are never developed.”[9]
FERC continued to find that states have flexibility as to what constitutes an acceptable showing of commercial viability and financial commitment. While FERC suggested Order No. 872 would create greater certainty for QFs and utilities alike, it still leaves much for states to resolve in this regard. Conditions that states have placed on the creation of an LEO have led to some of the most contentious cases brought to FERC and the courts under PURPA, and that does not appear likely to stop as a result of Order No. 872.[10] For example, FERC did not directly address to what extent states may dictate severely abbreviated QF contract terms (for example, in some cases, states have sought to limit terms to two years).
Presumptions Regarding Non-Discriminatory Access to Wholesale Markets
FERC’s regulations implementing Section 210(m) of PURPA contain a rebuttable presumption that QFs with a net capacity at or below 20 MW do not have nondiscriminatory access to such markets such that electric utilities could not terminate their obligation to purchase from such QFs unless the presumption was rebutted. Order No. 872 updated this rebuttable presumption solely for SPPs (not cogeneration QFs) by reducing the net capacity threshold from 20 MW to 5 MW, significantly shrinking the number of SPP QFs that qualify for this rebuttable presumption.
FERC concluded that electric utilities that had already successfully filed with FERC to terminate their purchase obligation for QFs over the 20 MW threshold will need to file again to terminate the mandatory purchase obligation for SPPs between 5 MW and 20 MW. As many electric utilities in RTO/ISO markets previously filed to terminate their mandatory purchase obligations for QFs over the 20 MW threshold, it is likely there will be a flurry of such filings after Order No. 872 goes into effect.
Importantly, FERC opened the door to termination of the mandatory purchase obligation for electric utilities outside an RTO/ISO. Specifically, FERC will consider on a case-by-case basis proposals to terminate the purchase obligation based on competitive solicitations or liquid market hubs. FERC also suggested that it would consider on a case-by-case basis whether a “properly run RFP or competitive acquisition process” may also justify termination of the mandatory purchase obligation. This may encourage electric utilities (and states) to use competitive RFPs meeting FERC requirements not only to set QF avoided capacity costs but also to justify termination of their mandatory purchase obligations altogether for SPPs over 5 MW.
Currently, FERC’s regulations require that all affiliate facilities that use the same energy source and are located on the same site must be aggregated to determine whether such SPPs meet the 80 MW limitation on SPP size. Until now, FERC has applied a “one-mile rule” to determine whether affiliated facilities are on the same site, aggregating facilities within a one-mile radius of one another. Many utilities have maintained that some QF developers game the SPP size limitations by building extremely large wind or solar facilities in excess of 80 MW that are close together but configured in such a way as to circumvent the one-mile rule.
In Order No. 872, FERC revised its one-mile rule to three presumptions: if an SPP is located one mile or less from any affiliated SPPs that use the same energy resource, it will be irrebuttably presumed to be at the same site as those affiliated SPPs. Conversely, if an SPP is located ten miles or more from any affiliated SPPs that use the same energy resource, it will be irrebuttably presumed to be at a separate site from those affiliated SPPs. If, however, an SPP is located more than one mile but fewer than ten miles from any affiliated SPPs that use the same energy resource, it will be rebuttably presumed to be at a separate site from those affiliated SPPs.
FERC also enhanced electric utilities’ and states’ ability to rebut the presumption and demonstrate that affiliated SPPs using the same energy source more than one mile but fewer than 10 miles apart are at the same site. Instead of filing a petition for declaratory order (and incurring associated filing fees), interested stakeholders can challenge an initial self-certification, or self-recertification making substantive changes[11] to an existing self-certification, by filing a protest. The protest must “specify facts that make a prima facie demonstration that the facility described in the certification (both self-certification and application for Commission certification) or recertification (both self-recertification and application for Commission recertification) does not satisfy the requirements for QF status”—a general allegation is insufficient.
FERC specified a variety of physical and ownership characteristics[12] it could consider in deciding whether affiliated SPPs are located at the same site. Further, FERC clarified that distances must be measured by the distance between the nearest “electrical generating equipment”[13] of each facility, measuring from the edge of the electrical generating equipment closest to the affiliate SPPs’ nearest electrical generating equipment.[14] FERC also made related clarifications and changes to the Form 556 for self-certification of QF status.
These changes will make it considerably easier for electric utilities and others to challenge SPP self-certifications where QF developers seek to develop wind or solar resources in close proximity to one another. Developers seeking to qualify their projects as SPPs will need to carefully consider common structures such as shared interconnection facilities that reduce the cost of developing rich renewable resources in remote locations, but may, when combined with other factors, provide utilities an opportunity to challenge SPP status. Moreover, these changes will require investment funds and other entities that acquire voting equity stakes in QF portfolios to do more careful diligence regarding the location of SPPs they already own and those owned by target companies, since the SPPs will need to self-recertify upon closing due to the new affiliation, and utilities could use the opportunity to challenge continued QF status.
However, FERC did clarify that self-certifications will continue to be effective upon filing and will remain in effect even after a protest is filed, until such time as FERC issues an order revoking certification. FERC also laid out a procedural process for addressing protests, stating that it would issue an order within 90 days of the filing of a protest, subject to extension if FERC determines it requires additional information. FERC may also toll the period by an additional 60 days. Absent FERC action within the allotted time, a protest will be deemed denied, which provides some certainty for SPPs.
Endnotes
[1] Qualifying Facility Rates and Requirements, Order No. 872, 172 FERC ¶ 61,041 (2020) (Order No. 872).
[2] U.S.C. 824a-3(a).
[3] This update follows FERC’s convention of referring to state regulatory commission and nonregulated electric utilities tasked with implementing PURPA collectively as “states.”
[4] Order No. 69, FERC Stats. & Regs. ¶ 30,128 (1980).
[5]16 U.S.C. 824a-3(d).
[6] 18 CFR § 292.304(d)(1) and 18 CFR § 292.304(d)(2).
[7] Order No. 872 at P 177.
[8] Order No. 872 at P 60 (citing Allegheny Energy Supply Co., LLC, 108 FERC ¶ 61,082, at P 18 (2004)) (Allegheny). Under the Allegheny standard, a competitive solicitation process is transparent and non-discriminatory if it meets four principles: (1) transparency, a requirement that the solicitation process be open and fair; (2) definition, a requirement that the product, or products, sought through the competitive solicitation be precisely defined; (3) evaluation, a requirement that the evaluation criteria be standardized and applied equally to all bids and bidders; and (4) oversight, a requirement that an independent third party design the solicitation, administer bidding, and evaluate bids prior to selection.
[9] Order No. 872 at P 688.
[10] FERC continued to adhere to prior precedents finding that LEOs could not be conditioned on the existence of an executed interconnection agreement or power purchase agreement, the filing of a formal complaint by the QF with the state, the ability to supply firm power, or the ability to deliver power in 90 days. Order No. 872 at P 34.
[11] FERC stated that “substantive changes” may include, as examples, a change in electrical generating equipment that increases power production capacity by the greater of 1 MW or 5% of the previously certified capacity of the QF, or a change in ownership in which an owner increases its equity interest by at least 10% from the equity interest previously reported. Order No. 872 at P 550.
[12] Order No. 872 at P 509 (“(1) physical characteristics, including such common characteristics as: infrastructure, property ownership, property leases, control facilities, access and easements, interconnection agreements, interconnection facilities up to the point of interconnection to the distribution or transmission system, collector systems or facilities, points of interconnection, motive force or fuel source, off-take arrangements, connections to the electrical grid, evidence of shared control systems, common permitting and land leasing, and shared step-up transformers; and (2) ownership/other characteristics, including such characteristics as whether the facilities in question are: owned or controlled by the same person(s) or affiliated persons(s), operated and maintained by the same or affiliated entity(ies), selling to the same electric utility, using common debt or equity financing, constructed by the same entity within 12 months, managing a power sales agreement executed within 12 months of a similar and affiliated small power production qualifying facility in the same location, placed into service within 12 months of an affiliated small power production QF project’s commercial operation date as specified in the power sales agreement, or sharing engineering or procurement contracts.”).
[13] Defined to be “all boilers, heat recovery steam generators, prime movers (any mechanical equipment driving an electric generator), electrical generators, photovoltaic solar panels, inverters, fuel cell equipment and/or other primary power generation equipment used in the facility, excluding equipment for gathering energy to be used in the facility.” Order No. 872 at P 521.
[14] Order No. 872 at PP 522-23 (“Thus, we clarify that for a solar facility, the measurement should be from the edge of the small power production facility seeking QF status’ solar panel or inverter that is closest to the edge of the nearest “electrical generating equipment” of that affiliated small power production QF. For a wind facility, the measurement should similarly be from the edge of the small power production facility seeking QF status’ wind turbine or inverter closest to the edge of the nearest “electrical generating equipment” of the affiliated small power production QF. For a wind facility, we clarify that the relevant point for measuring distance of an individual wind turbine is the tower (not the projection of the blade’s wingspans onto the ground).")
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