In Post I, we explore the three “big” issues that the Final Rule highlights at Paragraphs 13-20 – the (potential) reduction of the 20 MW cap to a 5 MW cap for renewables as to the must-purchase obligation on utilities in organized markets; changes to the one-mile rule; and, the holding that for QFs selecting that a price be fixed at the time of its legally enforceable obligation (LEO), the energy price need no longer be fixed over the contract term. As discussed below, the impact of cap reduction to 5 MW may turn heavily on future case law, and may not prove highly significant if FERC finds specific barriers to participation. LSEs are going to need to carefully make their cases for a cap reduction in responding to protests, particularly if a change in Administration occurs before their new petitions are filed. As to the one-mile rule, this change may prove more significant due to the frequency with which the same FERC test is used for other purposes. Finally, the “new” rule on states being permitted to adopt non-fixed energy prices in otherwise fixed-rate contracts is not particularly new at all.

Must-Purchase Mandate Reduction to 5 MW for Renewables (18 C.F.R. §292.309). The Final Rule changed the NOPR’s proposal, increasing the size of QFs (from 1 MW to 5 MW), from which LSEs can be exempted from having to purchase. This change was a relatively minor concession and provided FERC an opportunity to better support the 5 MW number selected. The most burning question is how the factors identified as useful in overcoming the rebuttable presumption that 5 MW or larger QFs have market access (and the factors left unidentified) will be applied in practice. FERC held that in determining whether the presumption is rebutted, it will look at “(1) specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates; (2) the unique circumstances impacting the time/length of interconnection studies/queue to process small power QF interconnection requests; (3) a lack of affiliation with entities that participate in RTO/ISO markets; (4) a predominant purpose other than selling electricity which would warrant the small power QF being treated similarly to cogenerators (e.g., municipal solid waste facilities, biogas facilities, run-of-river hydro facilities, and non-powered dams); (5) the QF has certain operational characteristics that effectively prevent the qualifying facility’s participation in a market; and (6) the QF lacks access to markets due to transmission constraints, including that it is located in an area where persistent transmission constraints in effect cause the QF not to have access to markets outside a persistently congested area to sell the QF output or capacity.” It further held that this “is not intended to be an exhaustive list of the factors that a QF could rely upon in seeking to rebut the presumption.  These factors, among other indicia of lack of nondiscriminatory access, will be assessed by the Commission on a case-by-case basis in considering a claim that the presumption of nondiscriminatory access to the defined markets should be considered rebutted for a specific QF.” Given it is an election year, the timing of petitions and just who is applying such factors may prove important.

The interpretation of factor (1) as applied to a QF that is not affiliated with a significant market player will be critical in determining the impact of this rule change. The key issues may be: 1) whether LSEs can demonstrate that a QF can readily hire any number of market participants/scheduling coordinators or consultants that can market QF power; and 2) how FERC treats the expense of hiring such expertise in considering whether it creates a true barrier to participation. That is, will FERC consider the hiring of someone who can navigate an RTO tariff and provide 24/7 scheduling service a normal cost of business, or treat the expense as a barrier? Factor (2) may spur the need for those LSEs in RTOs that do not perform any distribution interconnections to reconsider the need for the LSE to adopt FERC-jurisdictional distribution interconnection procedures.

As discussed below, the cap reduction, when combined with the one-mile rule changes, may make the cap reduction somewhat more significant.

One-Mile Rule (18 C.F.R. § 292.204(a)(2)). The revised one-mile rule will provide that: “there is an irrebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located one mile or less from the facility for which qualification or recertification is sought are located at the same site as the facility for which qualification or recertification is sought” and that “facilities for which qualification or recertification is filed on or after [the effective date] there is an irrebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located 10 miles or more from the facility for which qualification or recertification is sought are located at separate sites from the facility for which qualification or recertification is sought.” As a result, 1-10 miles becomes a gray zone where an LSE can rebut the presumption that multiple small power production (SPP) facilities are in fact separate facilities.

Only FERC can decide if an entity claiming to be a small power production is 80 MW or smaller under the one-mile rule, and the only recent litigated case on the subject, while very significant, involves whether storage co-located with renewables (and charged from renewables) impacts how to measure the 80 MW. The Final Rule refuses to address this crucial and hotly-debated issue, stating “the role of battery storage in QFs, including with regard to the distance between QFs, is beyond the scope in this proceeding.” Virtually all reported cases on the one-mile rule at both FERC and the states in the last decade involve not the 80 MW issue but whether and how the one-mile rule is used for other purposes: 1) measuring QF size for the determining whether multiple QFs together are 20 MW or under for purpose of the must-purchase obligation (and eventually 5 MW for many LSEs); 2) whether multiple QFs meet a state maximum size for a (favorable) standard contract; 3) whether the 1 MW and smaller rule for those QFs that need not self-certify is met; and 4) exemptions from certain FPA and PUHCA provisions for QFs of a certain size.

As to the first issue, FERC explained in Order No. 688 that, for purposes of evaluating whether QFs 20 MW or smaller do not have nondiscriminatory access, it would look at all relevant factors relating to size, including, but not limited to, ownership, proximity of facilities, and whether facilities share a point of interconnection, but it would not be bound by the absolute language of the one-mile rule set forth in 18 C.F.R. § 292.204(a). In the Final Rule, FERC confirms this position. As to the second issue, FERC has no authority to dictate how a state measures QF size for eligibility for standard contracts, and while the FERC rule often is applied by the states, it can be ignored. As to the third issue, FERC confirmed in the Final Rule it would apply the test in 18 C.F.R. § 292.204(a)(2) to determine if multiple QFs reach the 1 MW threshold. As to the fourth issue, because current certifications will not be disturbed sua sponte, existing QFs may enjoy such exemptions for some time.

It is highly difficult to discern, without rigorous analysis, how many existing projects would today fall within the gray area of being 1-10 miles apart, such that how the rule change will impact existing future siting practices, as compared to today’s practices, is unclear. Also, developers may still be able to place multiple projects within 10 miles by ensuring different ownership of the completed projects.

Although projects in the gray area may have to recertify due to substantive changes (“Substantive changes that may be subject to a protest may include, for example, a change in electrical generating equipment that increases power production capacity by the greater of 1 MW or 5 percent 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”), FERC indicated that protestors “must demonstrate changed circumstances from the facts on which the Commission acted on the certification filing that call into question the continued validity of the earlier certification.” Thus, those QFs in the gray area today appear to be “safe.”

The true of impact of this change may prove significant where the 292.204(a)(2) test is used by the states to determine eligibility for certain QF programs aimed at small QFs and by FERC in applying it to maximum size thresholds for the must-purchase obligation and exemptions. Developers of new small QFs in particular may have to be much more cautious about siting to retain eligibility for certain state and federal benefits. The Final Rule also may burden lessors of small PV systems who, as a precaution, would feel obliged to look at a ten mile radius in self-certifying QFs that they own.

Energy Pricing Options for Contracts/LEOs Fixed at Time of the Obligation (18 C.F.R. § 292.304(d)). The permitting of a variable (or formula) energy price in a otherwise fixed rate contract while perhaps facially significant, really only is a significant change as to those few states that always had variable energy prices, but had to abandon them due to federal court litigation. Certainly, more states that never allowed variable or formula pricing may now permit it, but nothing stopped them from adopting such rates before court decisions issued in only the last five years. It was well-known that both California and most New England states had either formula or Locational Marginal Prices (LMPs)-based energy rates in place for over a decade. FERC never itself challenged these rates. The California, Massachusetts, and Connecticut state commissions, however all were compelled by litigation to look at the issue of adopting fixed energy rates after two federal circuit courts found this pricing illegal. Only California actually adopted (in the very last few months) a standard fixed energy price standard contract as a result of the litigation. Massachusetts and Connecticut may well return to LMPs for energy, which appears to remain an option under 18 C.F.R. § 292.304((d)(2), although the rebuttable presumption that such price represents avoided cost does not clearly apply to QFs choosing a LEO/contract over “as available” only status.

As noted, more states may be encouraged by LSEs and ratepayer advocates to move to non-fixed energy pricing but the impact of this move in 2020 is highly different in 2020 than in 1978-79. When PURPA was adopted, virtually all forecasts were of ever increasing energy prices. Today, if a state had to lock in a price for energy, the environment is far different and states would be hesitant to make the same types of decisions and allow for the same contract terms as they did in the 1980s, as the first QFs came on line. For example, California’s brand new standard fixed rate contract has a maximum term of twelve years, far fewer than when California originally implemented PURPA.