Recently, the D.C. Circuit upheld FERC’s decision granting Broadview Solar’s application to become a QF in SEIA v. FERC. In doing so, the appeals court solidified FERC’s “send-out” capacity approach for determining QF status. The underlying case, Broadview, has been the subject of several prior blog posts, as the underlying FERC decisions
Dalreed Solar – FERC Declines to Provide Additional Clarity as to QF Re-Certification “Substantive Changes” that Trigger Protest Rights, But Engages in a Same-Site Analysis
In Order No. 872, FERC provided PURPA purchasers and other interested parties the opportunity to protest QF re-certifications if a “substantive change” was being made, although the Final Rule was less than perfectly clear as to what constituted a substantive change. FERC stated in Order No. 872-A that substantive changes that may be subject to a protest could include “a change in electrical generating equipment that increases power production capacity by the greater of 1 MW or five 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.” In response to a concern that the “substantive change” standard was vague, FERC responded that it intended to make a case-by-case determinations on what changes are substantive.
In Dalreed Solar, FERC declined an opportunity to expand its identification of examples of substantive changes. In the re-certification at issue, Dalreed Solar changed its net power production capacity from 20 MW to 40 MW, an obvious slam dunk of “substance,” although due to an earlier re-certification of its original proposed project from 40 MW to 20 MW, Dalreed Solar had a non-frivolous claim that the change was not substantive. FERC readily dismissed this argument and indicated that the proper comparison was between the last re-certification and the current one. Given that it ruled on this MW change as sufficient, FERC then declined to rule on whether other changes were substantive.
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Magnolia Solar, LLC – What Does it Mean to Have a LEO, If a Self-Regulating Purchaser Is Permitted to Limit the Term Length of a PURPA PPA?
In its PURPA Reform Final Rule (Order No. 872), FERC mentioned the fact that the Idaho PUC had reduced the term of PURPA PPAs to two years (albeit there would be a perpetual new contractual obligation to purchase every two years). The Idaho PUC did so “based on its concern about fixed QF rates, and that the ability to require variable energy rates could lead to longer contract terms.” In fact, FERC mentioned this fact several times in Order No. 872, seemingly hoping that the PURPA reforms adopted would convince the Idaho PUC to permit longer terms for PURPA PPAs. FERC, however, never commenced an enforcement action against the Idaho PUC or opined in dicta that its two-year PPA term maximum was illegal. These facts render the recent dicta adopted in Magnolia Solar, LLC v. South Carolina Public Service Authority largely inscrutable.
There, Magnolia filed a petition for enforcement against Santee Cooper claiming that Santee Cooper was violating FERC’s PURPA regulations regarding a QF’s ability to form a legally enforceable obligation (LEO). Although FERC declined to initiate an enforcement action, FERC found that a LEO had been formed based on the facts: (1) Magnolia informed Santee Cooper that it was ready to “initiate next steps … for offtake/power sales” and Santee Cooper responded with a shell PPA; (2) the parties had discussions on numerous contractual terms and Magnolia moved forward on many critical steps for the project (i.e., lease agreements, zoning, required reports and studies, interconnection request, Form No. 556, obtaining financing); and (3) Santee Cooper provided a five-year avoided cost rate in a draft PPA and then Magnolia revised the draft for a 20-year avoided cost rate and submitted it to Santee Cooper.
The record was clear, however, that Santee Cooper would not negotiate PPA with a term of any greater length than five years. It had argued that there was no LEO because Magnolia refused to commit to any PPA with a term of only five years. Certainly, if the Idaho PUC can limit a PURPA PPA term to two years and face no FERC action in federal court, Santee Cooper, in its regulatory role, also should be allowed to limit PURPA PPAs to five years without any concern FERC would bring an enforcement action. Otherwise, FERC arguably would be acting discriminatorily. Thus, the import of the dicta in Magnolia Solar regarding the LEO seems somewhat meaningless.
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FERC QF Self-Recertifications and the “By the Same-Day Policy”
FERC finally answered a question that has long needed answering – when does a QF self-recertification need to be refiled? I.e., is there a grace period before such filing is due after a material fact has changed? The short answer is that there is no grace period at all. And, Staff views anything beyond 30 days after a material change occurs as meriting a self-report.
The PURPA regulation found at 18 C.F.R. Section 292.207(f)(1)(i) states that “[i]f a qualifying facility fails to conform with any material facts or representations presented by the cogenerator or small power producer in its submittals to the Commission, the notice of self-certification or Commission order certifying the qualifying status of the facility may no longer be relied upon. At that point, if the facility continues to conform to the Commission’s qualifying criteria under this part, the cogenerator or small power producer may file either a notice of self-recertification of qualifying status pursuant to the requirements of paragraph (a) of this section, or an application for Commission recertification pursuant to the requirements of paragraph (b) of this section, as appropriate.” Many in the industry assumed that, as with other changes and reporting requirements (e.g., notices of succession; changes in status; Order No. 860 submissions), that there must be some reasonable deadline (i.e., 30-days) after the change occurs before the self-recertification is “due.” But, Irradiant Partners, LP clarifies that FERC expects material changes to be submitted by the day of the change in the fact. (Because Form 556, Line 1l allows a filer to indicate the date a change will take effect, changes can be filed earlier.) FERC did not take issue with the fact that Staff advised Irradiant that if it was filing a self-recertification later than 30 days after a change in material facts or representations, it should self-report such filing(s) to the Office of Enforcement.
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Order No. 860: QFs and Distributed Energy Resources
Who Needs to Submit a Baseline: As November 2, 2021 looms (and is far scarier than Halloween), owners of QFs and DERs may be thinking, “what me worry?” But the looming due date for Order No. 860 baseline submissions can impact some QFs and some DERs. Although it is perhaps almost too late for those subject to, but unaware of their obligations to, make timely Order No. 860 submissions, steps can be taken now by those QFs and DERs with market based-rate (MBR) authority.
For a variety of reasons, some QFs have MBR authority: they may no longer sell under PURPA and are too large to be exempt from FPA Section 205 regulation; they may have MBR authority as a safety measure in case they fall out of QF compliance; they may be concerned about losing QF status due to changes in the 1-mile rule; among other reasons. As to DERs, while many DERs are renewables and sized to be exempt from FPA Section 205 regulation and thus Order No. 860, some DERs, such as in front of the meter, stand-alone storage, will be “Sellers” with Order No. 860 obligations. Determining if a QF or DER has an Order No. 860 obligation is simple, does the entity that owns/controls the asset have an MBR Tariff on file? If yes, an Order No. 860 baseline obligation exists, even if the entity has never made a sale subject to FPA Section 205 regulation. FERC keeps a list of entities with MBR on this page (look at right side of page for link to “Electric Utilities With Approved Market-Based Rate Authority (Includes Contact Information)”).
For those QFs/DERs who belatedly realize that they have an Order No. 860 obligation, if they cannot gather the data required by Order No. 860 and learn how to submit it in a matter of two weeks, an extension request may be an option. Some QFs, particularly those whose sales are all exempt under 18 C.F.R. Section 292.601, may want to reconsider whether they need MBR authority at all and seek to cancel their MBR Tariffs effective on or before November 1, 2021. Although, such Seller may be technically out of compliance with Order No. 860, as long as the Commission grants the cancellation date, FERC may choose not to demand compliance between November 2nd and the effective date of the cancellation. (This option applies to anyone with an unnecessary or unused MBR Tariff.) Other Order No. 860 issues relating to QFs and DERs are discussed below.
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Reactive Power Sales: QFs and Distributed Energy Resources
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.
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Vermont Supreme Court Gets It Right (Maybe) on Alternative PURPA Programs
In a case involving Allco, a frequent plaintiff in state and federal PURPA litigation, a state’s adoption of an alternative PURPA program was challenged. Vermont is a state with multiple PURPA programs, a situation FERC has held is perfectly reasonable. Parsing the existing FERC holdings on multiple programs, having two different PURPA programs is acceptable…
Catching Up on Recent DER/PURPA Events at FERC
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:…
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In Broadview “Rehearing” Order, FERC Channels Emily Litella: “Never Mind”
FERC’s decision in Broadview Solar, LLC (discussed here) couldn’t even make it to its first birthday before FERC said “never mind,” that such decision was a mistake. Reversing the reasoning of its earlier order, FERC held in its order addressing arguments on rehearing that a 160 MW solar facility with a 50 MW battery could qualify as a small power production qualifying facility (SPP QF), so long as the facility’s “net output to the electric utility (i.e., at the point of interconnection), taking into account all components necessary to produce electric energy in a form useful to an interconnected entity,” was 80 MW or less. The Commission’s rationale largely mirrored the arguments put forth in dissent to the original order by then-Commissioner, now-Chairman, Glick. But the rehearing order still did not address important considerations in evaluating compliance with PURPA’s 80 MW limit, and (like the original order) drew a dissent. It is doubtful that the new order will be the last we hear on this issue, although any load serving entity challenging the new order (or the policy, if and when applied to them in an analogous order), will need an appellate panel of strict statutory constructionists.
Continue Reading In Broadview “Rehearing” Order, FERC Channels Emily Litella: “Never Mind”
The Vermont PUC Takes a Stance Against FERC Jurisdiction Over Wholesale Power Sales From Distributed Resources
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