One would think the issue of jurisdiction over interconnections to distribution facilities of resources selling wholesale power could not get more complex. Order No. 2222 proves that it could. Specifically, QF interconnections to distribution, an area where jurisdiction previously had been relatively clear, has been muddled a bit. For decades, FERC has claimed that it has jurisdiction over the interconnection of QFs connected to the distribution systems of FERC-jurisdictional utilities unless the QF was only selling (or could only sell) to the utility to which it was connected and the sales were under PURPA. Order No. 2222 perhaps continues this policy. Perhaps not. FERC stated: “This final rule also does not revise the Commission’s jurisdictional approach to the interconnections of QFs that participate in distributed energy resource aggregations.[fn]  [fn]See Order No. 2003, 104 FERC ¶ 61,103 at PP 813-815; Order No. 2006, 111 FERC ¶ 61,220 at PP 516-518; Order No. 845, 163 FERC ¶ 61,043.” The problem with the sentence is there is not really an “approach” for QFs “that participate in distributed energy resource aggregations.” The citations are instead to an approach that applies to QFs participating directly in wholesale markets. That said, the case for FERC jurisdiction appears more compelling than the case against FERC jurisdiction, absent further clarification. Continue Reading Order No. 2222 – FERC Sows Some Confusion as to Interconnection Jurisdiction for QFs that Are Exclusively DER Aggregation Participants

Order No. 2222 goes to great length explaining why DER aggregators selling power are public utilities making FERC-jurisdictional sales under FPA Section 205. FERC holds “to the extent that a distributed energy resource aggregator’s transaction in RTO/ISO markets entails the injection of electric energy onto the grid and a sale of that energy for resale in wholesale electric markets, we find that the Commission has jurisdiction over such wholesale sales.” And, “to the extent a distributed energy resource aggregator makes sales of electric energy into RTO/ISO markets, it will be considered a public utility subject to the Commission’s jurisdiction.” This holding is no surprise. FERC has said for decades that sales by DERs at wholesale are FERC-jurisdictional. (The focus of this article is DERs not subject to an exemption under FPA Section 201(f).) A decade ago the Commission stated in CPUC:

We deny SMUD’s request that the Commission clarify that distribution-level facilities and distribution-level feed-in tariffs do not implicate Commission jurisdiction. The FPA grants the Commission exclusive jurisdiction to regulate sales for resale of electric energy and transmission in interstate commerce by public utilities. The Commission’s FPA authority to regulate sales for resale of electric energy and transmission in interstate commerce by public utilities is not dependent on the location of generation or transmission facilities, but rather on the definition of, as particularly relevant here, wholesale sales contained in the FPA.

FERC states it is “only exercising jurisdiction in this final rule over the sales by distributed energy resource aggregators into the RTO/ISO markets. Hence, an individual distributed energy resource’s participation in a distributed energy resource aggregation would not cause that individual resource to become subject to requirements applicable to Commission-jurisdictional public utilities.” But, it never explains why such participants are not subject to FPA Section 205. The mystery presented is why the DER participants in an aggregation that sell FERC-jurisdictional products (i.e., largely products other than demand response) are not subject to FERC jurisdiction and regulation. An explanation would better serve the public. Continue Reading The Great Order No. 2222 Mystery: Why Aren’t DERs that Participate in Aggregations Subject to Public Utility Requirements?

In the long-awaited Broadview Order, FERC reinforced PURPA’s statutory limit for small power production qualifying facilities (SPP QFs) to a “power production capacity” of not more than 80 MW. SPP QFs can not evade this statutory limit by restraining the ability of much large facilities to actually “send out” more than 80 MW through the use of limited inverters.  The Commission attempted to dodge the question that the industry was actually awaiting, regarding how storage charged from an SPP QF should be counted with regard to the 80 MW limit, stating that it “did not need to address whether the associated battery storage system is a separate facility or whether and how the battery storage system should be considered in determining the facility’s power production capacity.” Instead, the ruling was based on the 160 MW of solar capacity at the site. But, the ruling provided no indication that if the facility had consisted of 80 MW of solar and 80 MW of battery storage that the outcome would not have been identical.

The order is prospective and does not affect SPP QFs that have self-certified or have been granted Commission certification prior to September 1, 2020. Until December 31, 2020, the effective date of Order No. 872, any challenge to a Form 556 filing for an over 80 MW SPP QF would have to be through a Petition for Declaratory Order, rather than a protest. Continue Reading The Commission Takes a Narrow View of Broadview

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.


… 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