Order No. 872 spends an inordinate number of pages discussing the wholly optional use by a state of Locational Marginal Prices (LMPs) for those QFs selling only as available energy in an RTO market. 18 C.F.R. § 292.304(b)(6). The reason this fuss is somewhat surprising is that most QFs (excluding net metered QFs) enter into contracts for sales of capacity and energy, such that the practice of making no capacity commitment at all, involves a somewhat limited subset of QFs. Moreover, as FERC points out, the use of LMP for such resources has been fairly common, despite FERC’s prior admonishment against it. Feeling some heat, FERC did roll back its proposal somewhat, making use of LMP subject to challenge.

Although such “as-available only” sales may be more common in regions where several LSEs lack any energy and capacity needs (i.e., parts of New England and the Mid-Atlantic), where LSEs they merely deliver products procured for their load by third-parties, the same regions generally have bolstered small, renewable QFs by various other programs that include fixed-price contracts or opening net metering to larger (i.e., 1-2 MW) QFs.

Much of the fuss seems to be coming from entities, such as California cogenerators, the California commission, and Southeast PIOs, that have confused the proposal with the proposal to allow energy prices to vary in fixed rate contracts. Indeed, FERC finds some comments confusing in that stakeholders seem to be complaining about LMP being insufficient without a fixed capacity price when “as available” sellers are not required to be compensated for any product but energy under revised 18 C.F.R. § 292.304(d)(1)(i).

One very significant set of cases seems to have been overturned in Order No. 872, although more clarity could have been provided and a regulation is needed to make any reversal binding on the courts.

In 2010, in CPUC, FERC reversed 15 years of precedent and found that an avoided cost rate could be based on a subset of resources, as opposed to all resources. FERC, speaking permissively, said that a state with a renewable portfolio standard (RPS) may set an avoided cost rate foe renewables if the utility had not yet met the mandate. In short, the concept the tiered avoided costs was born. Several years later, the Ninth Circuit interpreted this permissive wording as mandatory, holding that if an RPS existed and a QF could meet that need, the avoided cost rate has to be based on only renewables. Continue Reading PURPA Final Rule Post III – Were the Ninth Circuit’s CARE v. CPUC and FERC’s CPUC Decisions Overturned?

Because LSEs must still offer fixed capacity prices under Order No. 872, and given the trend in decreasing prices for renewables, the Final Rule’s impacts on LEO formation may actual be fairly significant, particularly in states viewed as hostile to QFs. In the Final Rule, FERC adopted a “minimum standard” for LEOs, amending its regulations to provide that: “A qualifying facility must demonstrate commercial viability and financial commitment to construct its facility pursuant to criteria determined by the state regulatory authority or nonregulated electric utility as a prerequisite to a qualifying facility obtaining a legally enforceable obligation. Such criteria must be objective and reasonable.” 18 C.F.R. § 292.304(d)(3).

FERC provided examples of factors a state could reasonably require a QF to demonstrate: (1) taking meaningful steps to obtain site control adequate to commence construction of the project at the proposed location and (2) filing an interconnection application with the appropriate entity. A state could also require that the QF show that it has submitted all applications, including filing fees, to obtain all necessary local permitting and zoning approvals. FERC also ruled that obtaining a PPA or financing cannot be required. Also not permitted are requirements that: a utility execute an interconnection agreement (or likely any agreement at all); a QF file a formal complaint with the state commission; the QF being capable of supplying firm power; and, the QF being able to deliver power in 90 days. Continue Reading PURPA Final Rule Post II – LEOs, the Texas Lion Has Been Tamed and Other Impacts

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. Continue Reading PURPA Final Rule Post I – Which of FERC’s Resolutions of the “Big Three Issues” Is Most Significant?

Order No. 872 probably deviated more in favor of QFs, from the highly controversial NOPR that spawned it, than some expected. Nonetheless, it still will trigger a deluge of rehearing requests largely from environmental, public policy, and QF interests. The degree to which load serving entities (LSEs) and some states, including Texas in particular, push back against some of their losses will be interesting to watch. Depending on November’s election results, we may see a very quick rehearing order or a slow rehearing process, by which time some state commissions likely will have revamped their PURPA programs. Almost certainly, precautionary petitions for review will be filed as soon as the inevitable tolling order is dry, in light of Allegheny. In any case, how Order No. 872 is implemented by the states (“states” includes local regulatory authorities) and FERC will play an important role in determining how significant the Final Rule will prove to be. In an initial series of posts, this blog explores several Order No. 872 topics. These posts are intended as commentary, not summaries.

On July 10, 2020, the D.C. Circuit issued its opinion on various Petitioners’ appeals of Order No. 841. As predicted, the Court denied Petitioners’ claim that FERC lacks the authority to prohibit States from barring electric storage resources (ESRs) located on utility distribution systems from participating in wholesale power markets. Given the EPSA Supreme Court decision involved the sale of a product – demand response – that is not even FERC-jurisdictional, this case – involving sales by ESRs of clearly FERC-jurisdictional products – made the decision a slam dunk. Indeed, Petitioners would be hard-pressed to obtain either a rehearing en banc or a writ of certiorari.

The D.C. Circuit applied a test found in EPSA in rejecting most of the Petitioners’ claims. The court examined: 1) whether the challenged practice at issue – FERC’s prohibition of State-imposed distributed ESRs participation bans – directly affects wholesale rates; 2) whether FERC had regulated State-regulated facilities; and, 3) whether the court’s determinations would conflict with the FPA’s core purposes of curbing prices and enhancing reliability in the wholesale electricity market. The first and third prongs were so easily met that the court barely touched on them. The court found “swiftly” as to the first prong that FERC’s prohibition of State-imposed participation bans directly affects wholesale rates. Indeed, it noted that “If ‘directly affecting’ wholesale rates were a target, this program hits the bullseye.” As to the third prong, the court found that the “challenged Orders do nothing more than regulate matters concerning federal transactions – and reiterate ordinary principles of federal preemption – they do not facially exceed FERC’s jurisdiction under the Act. Our decision today does not foreclose judicial review should conflict arise between a particular state law or policy and FERC’s authority to regulate the participation of ESRs in the federal markets.”

As to the second prong, the court relied heavily on the Supremacy Clause of the Constitution to reject claims that States can close off access to wholesale markets. The court explained that “because FERC has the exclusive authority to determine who may participate in the wholesale markets, the Supremacy Clause – not Order No. 841 – requires that States not interfere.” Continue Reading The Lesson of the Appeal of Order No. 841 – Be Careful What You Ask For

In a July 2, 2020 Order, FERC declined to answer a question in a Petition for Declaratory Order (PDO) concerning whether a set of off-system QFs could deliver power to a utility at a Point of Delivery (POD) that was constrained. This question is important because if answered affirmatively, it could result in the utility’s ratepayers having to pay upgrade costs to ensure that all firm transmission service reservations can be accommodated in addition to paying for power from a QF at an avoided cost rate. In the Blue Marmots case, the QFs sought two findings from FERC:

to declare that transmission congestion on the purchasing utility’s system does not relieve the electric utility of its mandatory obligation to purchase from a QF under PURPA, where all other predicates to the creation of a LEO have been established.

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… to declare that the Commission’s direction in section 292.306 of the Commission’s regulations that QFs are obligated to pay such interconnection costs as are assessed by state regulatory authorities extends only to the physical interconnection between the QF and the utility system to which it is directly interconnected, not to other aspects of transmission service over which the Commission retains authority.

The first request was probably unnecessary, as the PURPA purchase obligation is relatively absolute in FERC’s view. The only issue is one of price, i.e., who has to pay to relieve the congestion; the answer to the second question thus may determine whether the QF chooses to sell to this utility. The QF still can sell, if the deciding body decides it must the pay to relieve congestion; it remains the QF’s choice. It is the second issue thus that is far more relevant and has not been addressed by FERC. And, it still has not. Continue Reading FERC Declines to Answer Question of Impact of Off-System QFs Choosing Constrained Points of Delivery

Although there were tempting things to write about in last few months, client considerations meant not writing about certain “hot” topics such as net metering. The Order No. 841 oral argument at the D.C. Circuit, however, demanded an article. The only challenge to Order No. 841 involved distributed storage and its participation in wholesale markets. The oral argument already has been summarized by many and although a close call on whether the case will be dismissed for lack of injury or upheld on the “affects” clause, a victory for distributed storage is fairly likely. The oral argument proved to be interesting not so much for the future of Order No. 841, but for the future of FERC regulation of wholesale distribution service, a service that it has regulated for decades. It seems no one involved in the oral argument remembered that the D.C. Circuit once stated: “FERC’s assertion of jurisdiction over all wholesale transmissions, regardless of the nature of the facility, is clearly within the scope of its statutory authority.” That is, TAPS v. FERC gave FERC a seal of approval to regulate “wholesale distribution service,” as it is a form of transmission service in interstate commerce. FERC counsel’s decision not to mention this decision was puzzling and whether FERC will return to embracing it, if a DER Aggregation Final Rule is issued, will be interesting to watch. Continue Reading Order No. 841 Oral Argument Analysis: Has Everyone Forgotten TAPS v. FERC?

About a decade ago, FERC opened the door to state commissions setting different avoided cost rates and adopting different standard contracts for different types of QFs. Although the ultimate legality of so-called “tiered avoided cost pricing” remains to be tested in court, a decision from the United States Court for the District of Idaho teaches an important lesson in how state commissions should and should not issue rulings categorizing QFs as fitting within a particular tier, if such tiers exist. In Franklin Energy Storage, the court decided that a state commission order finding that a particular type of QF was only eligible for the avoided cost rate and contract for solar and wind facilities was in error because the state commission actually was ruling on whether the facilities were or were not QFs. Despite the fact that all the parties to the case agreed that QF status was a matter exclusively within FERC’s jurisdiction, as supported by the IEP v. CPUC precedent, the court still read the Idaho commission’s action as a ruling on the merits of QF status.

The QFs at issue consisted of battery storage devices that would receive 100% of their energy input from a combination of renewable energy sources such as wind, solar, biogas, biomass. The purchasing utility obtained an order from the Idaho commission that that storage facility QFs such as the plaintiffs’ were subject to the same treatment and rates as wind and solar QFs rather than the treatment of “other QFs.” The plaintiffs challenged this order, which would have resulted in less favorable contracts. The court found that the Idaho Commissioners made their own determination of QF status, despite their concession that only FERC could make such determination. It appears that it was the specific wording of the Idaho commission’s order that caused this result. Continue Reading A Lesson for State Commissions In Classifying QFs

In the last year, two decisions from judges sitting on the bench of the United States Court for the District of New Mexico have opined that PURPA claims made by plaintiffs were “as applied” rather than “implementation” claims and thus could not be heard in federal court. The first decision, in Great Divide I, was a close call and provided an in-depth discussion of the “as applied” versus “implementation” precedent. There, had the case been pled more broadly, as an attack on the legally enforceable obligation (“LEO”) standard established by the New Mexico commission, the court said it would have heard the case on its merits. Indeed, the issue of whether a LEO standard meets PURPA’s requirements had been heard recently by the Montana federal court system. The Great Divide I court invited a better-styled complaint, indicating the complaint could be transformed into an implementation claim.

The plaintiffs filed such an amended complaint, and the court did review the merits of the case, issuing an order on the merits in Great Divide II (2019 WL 5847060) last November. The court found that the New Mexico LEO standard did not violate PURPA, especially given FERC’s silence on appropriate prerequisites which gave the New Mexico Commissioners “the wiggle room” to implement a prerequisite. This decision has been appealed and may be mooted by FERC’s PURPA Final Rule. Now, the newest decision from New Mexico District Court – Vote Solar, – indicates that at least one judge in New Mexico would not have entertained any attempt by the Great Divide I plaintiffs to replead their case. Continue Reading A New Mexico Federal District Court Tries to Slam Shut the PURPA “Implementation” Claims Window