Last week, FERC issued Order No. 872-A, its “further guidance order” on the PURPA Reform Final Rule. Appeals of Order No. 872 are pending at the Ninth Circuit, with the first appeal being held in abeyance until no later than early January 2021. Given the relatively few changes to the Final Rule, this order may close the relevant docket at FERC, for now. Whether some portions of the Final Rule will be remanded or even vacated is difficult to predict at this early stage, and may well depend on the judicial panel. Of the clarifications issued, only one was particularly significant – the affirmation of CARE v. CPUC on tiered avoided cost rates. Both that clarification and the few other changes and clarifications indicate that the degree to which the Final Rule will alter the PURPA landscape is largely dependent on state and FERC implementation of the new policies and regulations adopted. The clarifications/modifications adopted by FERC are discussed below.

Tiered Avoided Costs. FERC affirmed its current policy that a state with procurement mandates could set avoided costs by looking only at resources that could fulfill such mandate, where a purchasing utility had not yet much such mandate. This practice, known as “tiered avoided cost” pricing, which the Ninth Circuit had made mandatory within its boundaries, had been called into question by the Final Rule’s indication that any competitive solicitation used to set an avoided cost price having to be open to all resources, not only a subset of resources. This clarification provides states substantial authority to subsidize all sorts of QF-eligible resources, by adopting procurement mandates and setting avoided cost rates based only on the costs of resources that can meet such mandates. For example, a state requirement to purchase a certain number of MW from under 2 MW solar facilities could result in an avoided cost rate that is double, triple, even quadruple market prices of utility-scale solar. Such a naked subsidy would raise retail rates accordingly, but nothing prevents a state from adopting such a mandate. States that oppose such subsidies, i.e., that are more focused on the retail customer rate impacts of PURPA, simply will not adopt them.

Perhaps what was most unusual about the clarification was FERC’s statement that it could not “overrule” a decision of a Court of Appeals. The Ninth Circuit was merely interpreting a FERC policy set in FERC orders; it was not interpreting PURPA itself. Indeed, the court’s interpretation arguably conflicts with the plain meaning of the statute. If FERC has adopted a regulation stating all resources had to be considered in setting avoided cost, it could have mooted the Ninth Circuit decision, as the Ninth Circuit relied on specific words in a FERC order. If a FERC regulation that required all-source avoided cost rates were being interpreted, the outcome of the case would have almost certainly been different.

Variable Energy Cost Rates. Under the Final Rule, as clarified, states have complete discretion as to whether to require utilities to offer PURPA contracts with a fixed or variable energy rate; or the state can leave the decision to the utility. Thus, FERC’s clarification in Order No. 872-A – that a state may only use variable rates to set avoided energy costs if the utility has fulfilled its obligations to disclose avoided cost data under 18 CFR 292.302 – is only meaningful if a state allows the variable energy cost option in the first place. FERC found that “in the context of a state selecting a variable energy rate that can change over the term of a QF contract, ensuring that QFs have access to such avoided cost data encourages QF development.” (If such data shows that the avoided costs are quite low for a given utility, that data access will not be very encouraging!) Presumably, utilities eager to avoid fixed-cost energy rates will be amenable to providing such data.

Role of Independent Entities in Competitive Solicitations. FERC ruled that if a competitive solicitation is used to set an avoided cost rate, it should be “administered and scored” by an independent entity, thus clarifying the role of the independent entity that had to have “oversight” under Order No. 872. Again, given that states decide in the first instance whether to even allow competitive solicitations to set avoided costs, the actual impact of this clarification is unknown. It was clear under Order No. 872 that there would be very strict limitations imposed on utilities permitted to use competitive solicitations, such that the clarification is not at all surprising.

Need to Recertify and Rebuttable Presumption of Separate Sites. One of the major concerns of upstream owners of affiliated QFs that are spaced just outside the 1-mile limit is that their projects would lose their QF certifications. This aspect of Order No. 872 may be one that has fairly significant impacts on certain sets of QFs, i.e., affiliated, larger small power production facilities that have used the one-mile rule to their advantage whose contracts are now “out-of-the-market” and/or unnecessary to meet renewable mandates. A Petition for a Declaratory Order (PDO) seeking de-certification apparently can be filed at any time against affiliated QFs within 10 miles of one another based on Paragraph 275, such that QFs that used the one-mile rule previously could be de-certified by a buyer willing to pay the PDO filing fee. Given this risk, the relief that FERC gave on re-certification described below may not be very effective, if the PDO filing fee is a small fraction of out-of-market costs.

In Order No. 872-A, FERC lessened the burden on QFs that had to re-certify, an event that allows protestors 30 days for “free” protests. Specifically, a small power production QF does not need to re-certify and reflect changes in Section 8a of its Form 556 due to a change in the information it has previously reported regarding its affiliated small power production QFs that are more than one mile but less than 10 miles from its electrical generating equipment, unless that change by the affiliated QF also impacts any other entries on the evaluating small power production QF’s Form No. 556. As a result, if for example, if an upstream owner has five closely-located QFs and one project re-certifies, includes a substantive change, and reports for the first time its four other QF affiliates within 10 miles, the other four QFs would not have to re-certify. If a protest is submitted as to the one QF, FERC will have a fair amount of discretion in determining whether it should be de-decertified, but it does not appear such a protest would impact the remaining affiliated QFs. A (or perhaps four) PDO(s) would need to be filed as to the other four QFs.

Perhaps the most likely reason to re-certify is a change in upstream ownership and it remains entirely unclear if this change will be considered substantive, such that certification can be protested free of charge, as FERC did not opine on this issue as at least one entity requested.

Additionally, FERC clarified that if a hydroelectric generating facility is more than a mile apart (but less than 10 miles apart) from an affiliated facility, yet on the same impoundment (an unlikely scenario), the rebuttable presumption would be that they are at separate sites.

PURPA 210(m) Rebuttable Presumption. The final clarifications issued all related to the implementation of Section 210(m). FERC clarified that one factor for rebutting the presumption of access to markets – “a predominant purpose other than selling electricity” – could be argued by behind-the-meter DERs and would be considered by FERC. Given that this reference was presumably to retail behind the meter DERs, few DERs behind retail meters are 5 MW in the first place and thus the impact of this change should be minimal. FERC fixed a clerical error such that the list of factors that small power production facilities between 5 MW and 20 MW can point to in seeking to rebut the presumption that they have access would be include in its regulations that apply to ISO-NE, MISO, NYISO, PJM, and ERCOT. Finally, FERC clarified that in measuring the size of 5 MW to 20 MW small power production facilities, that it would look primarily at the net certified capacity of each QF and that while it would not be bound by the new ten-mile rule, it could consider the new ten-mile rule. This final clarification is perhaps the most important. Developers that plan to have a high concentration of DERs in one area or to lease rooftop PV may have to consider the risk that such projects will not be certified or, if existing, might be de-certified. The DER Aggregation Final Rule, however, may obviate the need for individual DERs in an aggregation to have QF status in some regions.