A Proposed Decision issued by Administrative Law Judges Debbie Chiv and Kelly A. Hyme of the Public Utilities Commission of California rejects a fundamental tenet of many community renewable (CR) programs. That tenet is that wholesale power sales can be “erased’ by couching cash payments to CR generators as “bill credits.” Although FERC has made clear that net energy metering (NEM) programs can eliminate the existence of wholesale power sales, the Proposed Decision rejected arguments that a proposed CR program was similar to a NEM program. The ALJs accepted the argument that “the use of the term ‘credit’, when there is no retail bill being offset by the credit, and the proposed banking of credits, when there is no subscriber to receive the credits, is not net energy metering.” As a result of finding that the proposed CR program (using a net value billing tariff approach (NVBT)) could not be squeezed into the NEM concept, the Proposed Decision held that, as with any compelled wholesale power purchase at a state-set rate, PURPA would apply.

Assuming the Proposed Decision remains largely intact, it has no immediate impact on existing CR programs. (It may send some CR generators scurrying for QF status.) CR programs can and do work, if CR generators are paid a reasonable price that does not create unacceptable cost shifts. Nonetheless, the CR industry may try to convince FERC to greatly expand the concept of NEM if the Proposed Decision stands. FERC should not bite. CR programs and PURPA have co-existed for well over a decade and can continue to do so as discussed below.Continue Reading Community Renewable Generators: Wholesale Power Sales Versus Net Energy Metering

As noted in the most recent blog post, a challenge by Allco Finance Limited (Allco) to the Massachusetts Department of Public Utilities’ (DPU) and the Massachusetts Department of Energy Resources’ (DOER) (Massachusetts Agencies) implementation of Massachusetts’ seven-year old legislation – An Act to Promote Energy Diversity – has no obvious connection to PURPA, yet was submitted as a PURPA Petition for Enforcement (PFE) under PURPA Section 210(h)(2)(B). A Petition for Declaratory Order (PDO) arguably would have been a better, albeit costlier, choice. The few responses to the PFE shed a small amount of light on the relevancy of PURPA issue, but spread a brighter light on the need for state actors to retain FERC counsel before drafting and implementing laws concerning the sale for resale of electricity and transmission of electricity in interstate commerce.Continue Reading Is PURPA Relevant to Non-PUPRA State Procurement Mandates? Presumably Not, But There Is a Lesson To Be Learned From the Recent Allco Challenge

The easiest means for a state to provide a subsidy to a preferred generation/resource type or class is to mandate purchases from that class at state-mandated rates. The typical reaction of a FERC attorney to such a claim should be, well that approach is simply illegal; states cannot compel utility purchases outside the bounds of PURPA. Indeed, in the last fifteen years, FERC has said so at least twice – when state -mandated purchase programs were challenged by California’s investor owned utilities and the New England Ratepayers Association. FERC resolutely held that mandated purchases were limited to purchases from QFs under PURPA at avoided cost rates. The Supreme Court rejected a (somewhat) less obvious means for states to mandate subsidized wholesale purchases in Hughes v. Talen. But, these cases do not mean that state programs that mandate purchases outside of the PURPA avoided cost construct have been eliminated, even where organized wholesale markets exist. Many such programs still exist, in any number of forms, including net metering programs that pay cash at the end of a time period at above an avoided cost rate and virtually all community solar programs. Most such programs are never challenged, but there is one entity willing to take on some state-mandated purchase programs that fall outside of PURPA, as evidenced by the latest challenge by Allco Finance Limited (Allco), this time to a Massachusetts program.

The Allco petition should be no surprise, as Allco has for over a decade led both the fight against state commissions compelling utilities to pay QF resources above PURPA avoided cost rates and compelling utilities to pay non-QF resources state-mandated rates. Although Allco’s success has been somewhat limited as discussed below, the outsized role Allco has played is not surprising. There are very few utilities willing to challenge a state regulator or legislature that requires the utility to buy from either a QF at above an avoided cost rate or from a non-QF, pursuant to a state-mandated price or process. As a result, some state-mandated programs can morph into a voluntary purchase programs, that are nearly impossible to challenge on legal grounds. One might expect that if a state program were too generous and caused ratepayers to pay unmerited subsidies, that consumer advocates would challenge such programs. However, traditional consumer advocates are often state actors themselves (i.e., independent offices of the state commission, state Attorneys General, etc.), also hesitant to challenge to state action. The result is that Allco has been the primary thorn in the side of state legislatures and commissions, representing neither consumer or utility interests, but the interests of QFs that are ineligible for the programs or are failed bidders in programs.Continue Reading Mandatory and Not So Mandatory Wholesale Purchases at State-Set Rates:  Allco Leans In

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

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.
Continue Reading 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 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.
Continue Reading 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?

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.
Continue Reading FERC QF Self-Recertifications and the “By the Same-Day Policy”

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.
Continue Reading Order No. 860: 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.
Continue Reading Reactive Power Sales: QFs and Distributed Energy Resources

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