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In Order No. 2003, FERC adopted a very clear policy – that if a vertically-integrated transmission provider charged its OATT customers for reactive power from its own generating fleet under OATT Schedule 2, it had to allow other generators in its BAA (f/k/a control area) to be compensated for reactive power as well. This meant merchant and public power (non-jurisdictional) generators could file seek reactive compensation, regardless of the transmission provider’s need for additional reactive power. Implementation of the policy was not quite so simple because not all transmission providers were vertically-integrated. RTOs/ISOs had to make their own decisions as to whether generators would be compensated for reactive power. Some RTOs/ISOs decided any generator could obtain compensation (e.g., PJM); some decided no generator could (e.g., CAISO). In any case, the question arises what does eligibility for reactive power compensation have to do with a PURPA and DER blog? The subject is relevant because FERC has yet to provide clear answers in all cases as to QF and DER eligibility for reactive compensation.
Continue Reading Reactive Power Sales: QFs and Distributed Energy Resources

In the past few months there have been a few events that merit a word, but few true surprises. It has become clear that there will be significant delays in the implementation of DER aggregation in some ISO/RTO regions. The complexities of aggregation are numerous and it appears that various regions will adopt a variety of approaches. Perhaps one of the most crucial topics will be the maximum size of a single DER in an aggregation, which may vary widely among regions. One minor surprise of the last few months may be the ease with which utilities seeking relief from the PURPA must-purchase obligation from 5 MW – 20 MW small power production facilities have been obtaining such relief. The relief has come easily due to a near total lack of protests of filing seeking relief.

As to specific DER/PURPA matters that have occurred at FERC over the last few months:
Continue Reading Catching Up on Recent DER/PURPA Events at FERC

Readers of this blog may know that Allco can be a thorn in the side of utilities with PURPA purchasing obligations. Allco is often successful in ensuring the rights of QFs under PURPA in district and appellate court cases. Sometimes, however, its positions inadvertantly benefit purchasing utilities, as its challenges have led to rulings that states cannot mandate the price of wholesale power unless acting under PURPA in the (non-ERCOT) continental United States. Indeed, in challenging a Connecticut statute that facially appeared to require utilities to pay a state-set price for wholesale power, Allco lost its case (Allco v. Klee), but its failure only was due to the fact that the court interpreted the Connecticut statute as not mandating the utilities to purchase power at the state-set price. The Second Circuit found that that while the state could “direct utilities to “enter into” contracts with specific bidders, that there was not sufficient evidence that “utilities will be ‘compelled … to accept specific bids.” This ruling would certainly provide grounds for a utility to reject a purchase contract with the price set by the state outside of PURPA’s avoided cost regime.

A recent dismissal of one of Allco’s challenges, although correctly decided by a Vermont district court on purely procedural grounds, should be of considerable interest to Vermont ratepayers, ISO-New England, and FERC in light of the position on the limits on FERC jurisdiction espoused by the Vermont Public Utility Commission (Vermont PUC). Indeed, it would be of immense interest to the industry in the unlikely event that the merits of the Vermont PUC’s stance against FERC jurisdiction, had been the grounds for the dismissal of the case. But, that position – that Vermont’s “Standard Offer Program” is “clearly” outside the jurisdiction of FERC because wholesale sales under the program are made in intrastate commerce – was not addressed on the merits.
Continue Reading The Vermont PUC Takes a Stance Against FERC Jurisdiction Over Wholesale Power Sales From Distributed Resources

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?

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

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?

The DERs Aggregation rulemaking (now FERC Docket No. RM18-9) was initiated back in 2016 and was the subject of a 2018 Technical Conference. Now, FERC has posed to the six ISOs/RTOs an identical set of data requests regarding DERs that focus primarily on how interconnection service and distribution service would be provided to DERs. The data requests illustrate an issue discussed in a recent blog post about Order No. 2003 and FERC’s decision there to: 1) eliminate the bright line between its jurisdiction and state jurisdiction over interconnection service and replace it with a blurrier jurisdictional line that is referred to as the “first-use test” or “already subject to an OATT test”; and 2) retain the bright line between its jurisdiction and state jurisdiction over interconnection service when the seller is a qualifying facility (QF) that can sell to third parties. FERC’s questions reflect how complicated this policy is to implement (particularly as a non-QF may become a QF, thus shifting jurisdiction). The questions also indicate how difficult to even determine the role, if any, ISOs and RTOs take in DER interconnections by reviewing their filed tariffs. Taking FERC’s jurisdictional policies and ISO/RTO policies on whether to participate in the DERs interconnection process and applying them to an aggregation that may be comprised of QFs, non-QFs, demand response participants, and storage DERs raises a host of questions that many ISOs, RTOs, and Distribution Owners likely have not even considered. These questions may get those conversations started.

The answers to the questions will probably reveal several interesting things about how much, or how little, any particular ISO or RTO knows about interconnection processes for DERs. Some predictions of what FERC may learn from some of its questions are made below. These are only predictions. For brevity, the data requests are not repeated here.
Continue Reading FERC’s ISO/RTO DERs Data Requests – What Do They Tell Us and What Will the Answers Likely Tell FERC

The jurisdictional discussion in Order No. 841-A was lengthy. It could have been very short.

This blog today takes a personal turn as I relate the tale of FERC’s jurisdiction over energy storage resources (ESRs) connecting to a public utility’s distribution system to sell wholesale power. There is only reason that the tale is long…

Yesterday, FERC issued an order on a Petition for Declaratory order from Sunrun, asking that FERC waive the QF certification filing requirements for separately-interconnected, individual residential rooftop solar PV systems and related equipment with maximum net power production of 20 kW or less that Sunrun provides financing for but which the homeowner has an option to purchase, where such 20 kW or less systems may aggregate to over 1 MW within a one-mile radius; and that in a Form No. 556 submitted for a cluster of rooftop PV systems that exceeds 20 kW, the Commission waive the requirement in Item 8a of Form No. 556 to include information regarding the facilities covered by the first requested waiver (i.e., 20 kW or less facilities), even if they are within one mile of the cluster that exceeds 20 kW that is being certified).

Although the Petition garnered minimal opposition, largely in the form of requests to delay action until (anticipated) PURPA reform occurred, FERC chose to act. FERC granted both waivers, agreeing with prior statements that solar generation facilities installed at residences or other relatively small electric consumers such as retail stores, hospitals, or schools do not present a compelling need for QF registration. The burden of such filings was considered to be too great in light of the lack of benefits. The second waiver was granted for similar reasons, as the fact that new client homeowners are added frequently and existing client homeowners may at any time exercise their option to purchase their 20-or-less kW PV systems would create a major burden on entities with business models such as Sunrun.
Continue Reading FERC’s Sunrun Order Should Surprise No One, But May Lead to More Interesting Cases

On April 1, 2019, FERC issued deficiency letters to all the ISOs/RTOs that submitted Order No. 841 (Storage Rule) compliance filings: CAISO, ISO-NE, MISO, NYISO, and PJM. Generally such letters ask the RTOs and ISOs to explain in much greater detail how their tariff provisions permit energy storage resources (ESRs) to participate in their markets. It appears that FERC wants each requirement imposed by Order No. 841 to be discussed in the specific context of ESRs, such that if a tariff provision does not specify that ESRs are covered or subject to a provision, the ISO or RTO must explain why the provision nonetheless applies to ESRs. There are only a handful of Order No. 841 compliance deficiency letter issues relevant to distribution-connected ESRs (i.e., a form of DER). The most interesting question actually arguably is relevant to both distributed ESRs and transmission-connected ESRs, although in one deficiency letter (MISO) the question was asked only as to distributed-ESRs. That question is: How is the ISO/RTO is going to prevent ESRs from paying twice for “charging for later discharge” energy? It will be interesting to see what “prevention methods” FERC finds adequate.

Under Order No. 841, FERC found that an ESR should pay the wholesale market price (the nodal LMP in particular) for charging energy used for later discharge in the wholesale market. FERC was not “persuaded by commenters who argue that developing metering practices that distinguish between wholesale and retail activity is impractically complex.” Even though FERC expects that wholesale and retail loads typically can be distinguished, it did recognize that, particularly for distributed DERs with retail load, the task may be too complex. In Paragraph 321 of Order No. 841, FERC stated: “we require each RTO/ISO to prevent resources using the participation model for electric storage resources from paying twice for the same charging energy. To the extent that the host distribution utility is unable – due to a lack of the necessary metering infrastructure and accounting practices – or unwilling to net out any energy purchases associated with a resource using the participation model for electric storage resources’ wholesale charging activities from the host customer’s retail bill, the RTO/ISO would be prevented from charging that resource using the participation model for electric storage resources electric wholesale rates for the charging energy for which it is already paying retail rates.”

This paragraph gives ISOs and RTOs an “out” if a distributed ESR is located within a distribution utility that will not net out wholesale purchases from the retail bill. In such cases, the RTO/ISO should not bill the ESR at wholesale for its charging energy. Indeed, where load is not distinguished, answering FERC’s deficiency letter question may be quite simple. Several ISOs/RTOs explained on compliance that they would not assess a wholesale charge unless the retail and wholesale loads could be distinguished:

  • MISO Tariff Attachment HHH, Section 6 states “To the extent the [ESR] is paying retail rates for energy associated with wholesale charging activities, the [ESR] shall complete Appendix 3 to this agreement in order for MISO to exclude settlement at wholesale prices for the same charging energy.”
  • The CAISO provided ESRs several options, including one where the CAISO does not charge such ESRs for their charging because the distribution utility already has done so at a retail rate.

The difficult and interesting question is what happens if the ISO/RTO has a method for distinguishing wholesale and retail load.
Continue Reading Order No. 841 (Storage Final Rule) Deficiency Letters – The Double Charging Issue