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”

Tuning into a replay of the March 8, 2022 SEIA v. FERC oral argument on FERC’s PURPA reform rule – Order No. 872 – resulted in a somewhat unexpected lesson on the National Environmental Policy Act (NEPA), including NEPA standing, and remedies. About two-thirds of the argument focused on whether an Environmental Assessment (EA) was necessary or too speculative, whether the Public Interest Organizations (PIOs) had standing to raise NEPA issues, and whether the most appropriate remedy for a NEPA violation was vacatur of the Final Rule or remand (leaving the Final Rule in place).

Before delving into the NEPA issues, much of the other one-third of the oral argument was spent discussing the issue of the right of a state commission to eliminate a QF’s option of selecting a fixed energy rate with the rate set at time of the legally enforceable obligation. SEIA’s primary contention was that FERC reversed a long-standing policy by finding in Order No. 872 that a single PURPA contract that over its life exceeded actual avoided cost, rather than balancing out over time, was a violation of PURPA itself. SEIA may have scored a point in arguing that given such a policy was adopted, the Final Rule could not have left it to the states to determine whether or not energy costs could be fixed or variable, as that act in itself would have itself been arbitrary. That said, it is quite difficult to find in Order No. 872 any definitive holding or finding that an individual contract violates PURPA if it over-estimates avoided cost over its lifetime, let alone, that FERC adopted a remedy to address this possible result. Continue Reading The Future of PURPA Reform Under Order No. 872: Did the Oral Argument Provide Any Clues?

Part 2 of post on Order No. 2222 deficiency letters issued to the NYISO and CAISO.

Locational Requirements. NYISO DER Aggregations must be at a single NYISO-identified Transmission Node that will be as large as possible while accounting for the efficiency of the NYISO-administered markets and the reliability of the system. FERC wants to understand the process for identifying such nodes in detail. Future filers can expect that any locational limitation must be fully developed and described in detail, particularly if the process is located in a business practice manual (BPM) rather than the tariff.

Distribution Factors and Bidding Parameters. CAISO has a requirement relating to DER Aggregations providing net response at its Pricing Node (PNode) and distribution factors in a Master File which governs various bid components. Here, the Commission questions focused on process rather than whether the substance of the requirement was questionable.

Information and Data Requirements. The CAISO has requirements largely located in a BPM related to the detailed information needed about each DER in an Aggregation. FERC’s extensive questioning on the subject included many “whys” such data requirements existed. It was a bit unclear whether FERC’s concern was the location of the requirements (a BPM) or the nature of the information, which seemed to be the type of information any ISO would require so that it could properly account for and model  DER Aggregation. FERC also asked about the Aggregator’s CAISO Scheduling Coordinator’s need to retain auditable data and comparability. Here, the concern seemed less about the requirement than whether it was similar to other Scheduling Coordinator data retention requirements.

Metering and Telemetry System Requirements. Both NYISO and CAISO were asked about the metering and telemetry requirements imposed on DER Aggregators. FERC was most interested in relationship between the Distribution Utility’s role in meter data collection process and other details as to how data will be collected, including whether direct measurement would always be required. Given that a Distribution Utility’s role in metering may vary quite widely based on factors such as the nature of the DER, whether it has load behind its retail meter, its interconnection obligations, and whether the state oversees metering, the question on the role of the Distribution Utility in metering may be very difficult for an ISO to answer. At least the NYISO and CAISO, as single-state ISOs, have a more narrow task than future filers that may be dealing with a dozen or more states with differing state commission rules applying to the regulated Distribution Utilities as well as an even larger number of unregulated Distribution Utilities. FERC’s main concern may be duplicative metering. The Commission also seems interested in why various size thresholds exist. Where size thresholds exist, explanation is key even if the threshold is quite longstanding.

Coordination Between the ISO, Aggregator, and Distribution Utility. FERC’s questions to both ISOs on the role of the main players appear largely rooted in its concern that Distribution Utilities will thwart DER Aggregation. Although Order No. 2222 provides Distribution Utilities review rights over DER Aggregations as to safety and reliability as to the distribution system, FERC expects the ISOs to define such rights in some detail, a role that an ISO may be loathe to take on given a lack of familiarity with distribution systems generally. The Commission seems particularly concerned that single DER additions to Aggregations may cause lengthy re-evaluations. Resolving disputes also was a common concern. Future filers will likely have to spill extensive ink on such processes that may not yet be well developed due to a lack of experience; i.e., Distribution Utilities may not yet know what issues may even arise, but ISOs will need to try and address any potential issues.

Ongoing Operational Coordination. As to ongoing operations, FERC is concerned about information flow between the Distribution Utility and ISO as well as protocols and procedures used when a Distribution Utility overrides an ISO dispatch, as presumably will be its right under the Distribution Utility’s interconnection agreement with each DER. Transparency is an issue as to such coordination and communication. Once again, the devil is in the details, which may be difficult to describe, particularly by ISOs that have not had any experience with DER Aggregations.

Role of Relevant Electric Retail Regulatory Authorities. FERC permits voluntary regulating authority participation in the coordination and participation of DERs and both ISOs were questioned in detail about various roles that these authorities ay play. These questions are difficult given that an ISO may dealing with dozens of authorities, some of which will play varying roles. FERC is asking specific questions as to what each authority plans to do, a question that is seemingly only answerable by the regulating authority itself, assuming the regulating authority even intends to address the issue before a DER Aggregation exists. It is not clear that future filers can do more than identify what a regulatory authority may possibly do, as each regulatory authority may have varying authority itself. Certainly, how regulatory authorities participated in any stakeholder process should be described to demonstrate that their voices are being heard.

Modifications to List of Resources. NYISO was questioned about the required list of DERs in each Aggregation and updates to the list. As noted above, processes involving changes relating to a single DER in an Aggregation are of keen interest presumably due to concerns over delays. FERC does not expect actions, such as the deletion of a single DER from an Aggregation, to trigger a lengthy review process.

Summary. The Deficiency Letters have given future filers (and protestors) a road map as to what it expects in a satisfactory filing. The concern raised by the letters is that FERC is seeking some information an ISO simply may not now nor ever possess. Multiple “compliance filing” rounds are thus to be expected to answer FERC’s questions to its satisfaction. Given FERC’s lack of jurisdiction over regulatory authorities and many Distribution Utilities, the ISOs bear a heavy compliance burden to describe the roles of entities they do not control.

Two ISOs, CAISO and NYISO, filed their Order No. 2222 compliance filings in July, as they had largely already had DER aggregation programs even before the effective date of the Final Rule. Their filings garnered relatively few protests, which is not surprising as they only made minor modifications to their existing programs. But, their filings also garnered quite lengthy deficiency letters (NYISO and CAISO), which inform us as to FERC’s primary concerns with Order No. 2222 compliance and will prove instructive as to the other ISOs still working on their compliance efforts. This two-part post examines the letters and FERC’s concerns. As the letters somewhat mirror one another on topics, the examination follows the order of the letters’ inquiries.

Interconnection. Only NYISO was questioned on its interconnection proposal in that it did not address DERs connecting to the Transmission System. This question is odd because DERs are defined as being connected to distribution, rendering the purpose of the question unclear unless referring to distribution facilities already used by wholesale customers. That said, such facilities are still distribution facilities and not transmission.

Small Utility Opt-In. Only CAISO was asked about its process for small utilities to opt-in and/or what happens if they later decide to opt out. The questions largely relate to process or omissions of process for opting-in and out. That said, the Commission is re-examining these issues in any event, such that future changes may be required. Future filers should be comprehensive in explaining all processes related to small utility opt-in/out processes.

Definition of DER. The Commission was concerned as to both ISOs as to whether their DER definitions were broad enough to encompass any resource and whether they could identify any resources that would not be eligible to participate. (Presumably the Commission meant whether any resource could participate in a DER Aggregation if it met the minimum/maximum size threshold and was connected to distribution, as all non-DER resources are ineligible and some DER resources are too large). The questions posed are somewhat difficult to answer as they seem to be addressing unknown future types of resources, but in any case, future filers should clearly indicate any excluded resources.

Participation Model. As to the CAISO, the Commission wondered whether a heterogenous DER Aggregation that never injected energy over a certain interval could be reclassified as demand response. There appears to be no reason for such an reclassification, as long as the injectable resource remains ready to inject, nor would Order No. 222 indicate such an action is appropriate. The NYISO received many questions on the participation subject, as the Commission was concerned with NYISO’s separation of heterogenous and homogenous DER Aggregations as well as its rules for addressing DER Aggregations comprised of solely Intermittent Power Resources and the impacts of these categories. The NYISO had expressed concerns over DER Aggregations made up solely of Intermittent Power Resources, as to the risks such DER Aggregations were taking in not being able to meet certain operational requirements. The Commission sought to understand why such risks did not apply to DER Aggregations made up of largely solar DERs. Presumably, the risks for any DER Aggregation that cannot perform 24/7 are similar; the clear lesson is that if an ISO (which term includes an RTO) is going to comment on such risks, it should explain the risks.

Also as to the NYISO, FERC was concerned with how NYISO would perform analysis to enforce its requirement that DER Aggregations that seek to qualify as Installed Capacity Suppliers needing Capacity Resource Interconnection Service (CRIS) for each of their injecting DERs. Although the NYISO indicated that the process would be comparable as to any other resource, FERC requested an overview of the process. Future filers should be careful if indicating a process already exists, to cite to specific sections of their Tariffs that would be applied to DERs or DER Aggregations.

The NYISO was questioned about DER Aggregations seeking to sell Ancillary Services, as the NYISO requires that all DERs in such an Aggregation be able to abide by various reliability standards. FERC questioned whether this requirement was necessary if the DER Aggregation as a whole can meet its obligations. This may be an issue that relates only to NYISO, but indicates that any limits on DER Aggregation participation in any market should be well-supported and explained.

Types of Technologies. NYISO was questioned about the exclusion of a fairly broad array of resource types that participate in its markets under other models/programs. It may have been unclear to FERC that some of these resources can be in a DER Aggregation, if they do not participate under another model/program. Again, participation restrictions should be explained.

CAISO drew questions about its varying programs for demand response resources inside and outside of a DER Aggregation, particularly as it relates to the net benefits test of Order No. 845. Although the CAISO explained there is no mechanism for CAISO to apply the net benefits test to only a portion of a DER Aggregation, the Commission had many follow-up question presumably to affirm the veracity of and technical support for the CAISO position. The takeaway would be once again very detailed explanations of any limitations on DER Aggregation participation.

Double Counting of Services. The questions surrounding double-counting largely relate to who is doing the verifying and exactly how it will be done. This area is quite complex given the dueling jurisdictions, innumerable possible retail programs; it may require multiple filings to sufficiently clarify such rules.

Minimum and Maximize Size/Capacity Requirements of Aggregation. The Commission seemingly caught a discrepancy in the CAISO Tariff as to the size minimum for storage devices providing ancillary services. Another concern was the cap on the size of a DER in an Aggregation in CAISO of 1 MW, which is based on CAISO’s view that DERs above such size can and should be subject to all CAISO Tariff requirements. This issue perhaps reflects a potential substantive dispute between the CAISO and FERC over managing DERs generally, which management is simplified if DERs are not aggregated.

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 as long as two conditions are met: 1) there is one PURPA program that is fully compliant with PURPA and available to any QF (including a program that merely consists of a utility negotiating QF contracts on an individual basis) and 2) the additional program does not require purchasing utilities to involuntarily pay a price above avoided cost.

The Vermont PUC (VtPUC) has adopted what is referred to as Rule 4.100, which is effectively a “program” that applies to all contracts and obligations formed pursuant to the VtPUC’s PURPA-implementing authority, except standard-offer contracts formed pursuant to 30 V.S.A. § 8005a, and merely requires distribution utilities to purchase the generation output of QFs under an administratively-determined avoided cost rate. Basically, under Rule 4.100, any QF can obtain a PURPA contract at a “generic” avoided cost. The VtPUC has adopted a “standard offer contract” program as well that has evolved through the years. In its current iteration, the program has a capacity cap, varying technology requirements, and the VtPUC calculates avoided costs to serve as price caps for each technology category. In addition, the VtPUC is authorized to use a market-based mechanism, “such as a reverse auction or other procurement tool” to fill the capacity for each category of renewable energy and set the avoided cost on a market basis for a category.

Before the VtPUC and again on appeal, Allco argued that the market-based mechanism violated federal law because it compels wholesale sales of electricity in violation of PURPA where the reverse-auction based prices are less than the avoided costs as defined by PURPA. This very argument is rather odd in that PURPA never compels sales, it compels purchases. It also is odd in that the very point of the VtPUC standard offer contract and auction was to pay a technology-specific avoided cost above the avoided cost rate available under Rule 4.100. In any case, the VtPUC defended its alternative program on the grounds that its market-based pricing mechanism complied with PURPA because Vermont also offers a PURPA-compliant alternative to the standard-offer program under Rule 4.100. The VtPUC also argued, according to the court that Rule 4.100 “satisfies the requirements of PURPA, so the standard-offer program is not constrained by the PURPA restrictions on pricing.” The last statement is troubling in that any PURPA program is constrained by PURPA restrictions on pricing, if challenged by the compelled purchaser. That is, if the market-based mechanism was in fact resulting in a price above avoided-cost, a purchasing utility could successfully challenge the mechanism, recognizing that proving to a court that a price is “above avoided cost” can be quite challenging.

On appeal, the court discussed FERC precedent (or FERC dicta) as well as the Winding Creek line of cases at length, and concluded (correctly), that “assuming Rule 4.100 fully satisfies Vermont’s obligations under PURPA to give QFs an opportunity to sell power on a must-take basis at avoided-cost rates” an alternative PURPA program was permitted. The court’s holding that states “in rolling out its regulations implementing PURPA, FERC suggested that PURPA contemplates that states may establish auxiliary programs to promote the goals of PURPA in addition to their core programs implementing PURPA, and that those programs may depart from some of the parameters PURPA requires of the state’s core program implementing PURPA” is not particularly troubling. What is troubling, however, is the court stating “FERC interpreted PURPA to authorize states to establish or maintain additional programs compelling electric utilities to purchase electricity from QFs at rates other than the avoided-cost rates defined by PURPA.” (Emphasis added.) This statement is troubling in that it implies states may compel purchases at above avoided cost rates.

But, then the court said the VtPUC was not suggesting an avoided cost cap could be ignored. “The PUC has concluded that the standard-offer program, which offers some QFs the opportunity to secure contracts to sell new capacity at prices that exceed generic avoided-cost rates, but are capped by technology-specific avoided costs, is such a program authorized by PURPA as a complement to Rule 4.100.” This statement indicates that the VtPUC understands that it can have tiered, technology-specific avoided cost prices that are above an “all-resource” avoided cost price, rather than merely having a second PURPA program that is not constrained by avoided cost at all. Such a position reflects FERC’s rulings in Order No. 872.

The problem with the decision is that the court continues on, once again forgetting to mention this avoided cost constraint, ruling that:

Consistent with FERC’s own interpretation of PURPA, we accept the PUC’s conclusion that if Rule 4.100 satisfies the requirements of PURPA, its use of a market-based mechanism in the standard-offer program is authorized by PURPA, provided that its standard-offer pricing is otherwise “just and reasonable to the electric consumers of the electric utility and in the public interest, and … [does] not discriminate against [QFs].

(Emphasis added.) This sentence muddies the entire decision because it does not include the caveat that the market-based mechanism in the standard-offer program cannot compel a utility to pay above an avoided cost rate. There may well be two (or more) very different avoided cost rates, and the utility may be compelled to pay the higher of the two, but the higher rate is still constrained by PURPA and concept of avoided cost.

In sum, the case does not appear to be too worrisome in that the alternate PURPA program under review plainly was intended to result in a higher, technology-specific, but still avoided-cost, rate. Having multiple avoided costs is not problematic under FERC’s regulations allowing for tiered, technology-specific avoided cost rates. (Whether tiered, technology-specific avoided cost rates are lawful under PURPA is an issue no utility has chosen to raise to a court.) More careful wording, however, would have been helpful.


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