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

It has been more than a month since FERC proposed eliminating the state opt-out with regard to retail customer participation in demand response programs in organized wholesale markets. In its NOPR, Participation of Aggregators of Retail Demand Response Customers in Markets Operated by Regional Transmission Organizations and Independent System Operators, FERC proposed elimination of the state opt-out. In the concurrently issued Order No. 2222-A, FERC set aside its earlier finding that the participation of demand response in distributed energy resource aggregations is subject to the opt-out and opt-in requirements of Order Nos. 719 and 719-A. Those states that had opted out are none too pleased, as evidenced by NARUC’s rehearing request filed in response to Order No. 2222-A. The NOPR certainly will draw objections. In contrast, demand response supporters have sought clarification of Order No. 2222-A to ensure that “double counting” does not occur when a DER demand response resource is compensated for acting as a provider of a service, whether procured on a forward-looking basis or in real-time, and reduces an end-use customer’s load on the bulk power system, resulting in retail savings for the customer. These entities seek assurance that a behind-the-meter DER providing wholesale demand response service through serving is own on-site load be compensated at full LMP under Order No. 745.

FERC will certainly defend its change in position based on its view that “the terms of wholesale market participation are a matter under exclusive Commission jurisdiction,” such that its orders “do not infringe upon or otherwise diminish state authority.” It would appear that Order No. 2222-A and the effectively pre-ordained outcome of the new NOPR, would be the death knell of the state opt-out. The question raised here is, does it have to be? Continue Reading The Death of the Demand Response Opt-Out?

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”

This post updates the most recent post regarding initial state and federal proceedings that were initiated in light of Order No. 872.

Post-Order No. 872 Requests for Relief from the PURPA Purchase Mandate

Given the paucity of actual or potential QFs in the relevant service areas of ETEC and NTEC, and thus an absence of protests, these entities, who led the pack in submitting the first QM filing under Order No. 872, rather quickly obtained the requested relief. Since their filing, a few more applications have been submitted and certainly more are expected soon. Not surprisingly, many of the earliest filers had relatively few existing or queued potential QFs. No protest has been filed in any QM docket to date. Continue Reading Order No. 872-Related FERC and State Proceedings Initiated in Its Initial Months of Effectiveness

Now that Order No. 872 has been effective for a few weeks, the first few proceedings that will inform its implementation have commenced. More such proceedings will certainly be initiated in next few months. Continue Reading Order No. 872-Related FERC and State Proceedings Initiated in Its Initial Weeks of Effectiveness

Last week, FERC issued Order No. 872-A, its “further guidance order” on the PURPA Reform Final Rule. Appeals of Order No. 872 are pending at the Ninth Circuit, with the first appeal being held in abeyance until no later than early January 2021. Given the relatively few changes to the Final Rule, this order may close the relevant docket at FERC, for now. Whether some portions of the Final Rule will be remanded or even vacated is difficult to predict at this early stage, and may well depend on the judicial panel. Of the clarifications issued, only one was particularly significant – the affirmation of CARE v. CPUC on tiered avoided cost rates. Both that clarification and the few other changes and clarifications indicate that the degree to which the Final Rule will alter the PURPA landscape is largely dependent on state and FERC implementation of the new policies and regulations adopted. The clarifications/modifications adopted by FERC are discussed below. Continue Reading FERC’s PURPA Reform Rule: Order No. 872-A’s Few Clarifications and Modifications Continue to Indicate that FERC and the States Will Have Significant Discretion in Implementing PURPA

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

The glowing reviews and legal/trade press headlines would have one believe that DER Aggregation under Order No. 2222 will soon transform the electric industry, as DERs too small to participate directly in RTO/ISO markets will flock to third-party DER Aggregators who will sell wholesale services to organized markets. Will DER owners leap at the chance to participate in wholesale markets? The near-term answer lies in footnote 95 of Order No. 2222, leaving net metering (NEM) untouched and the (Solar Power World) map below. The map shows us four RTO/ISO states (NY, MI, IN, IL) where DERs cannot participate in “traditional” NEM, i.e., where the meter runs backward or excess power over the billing period is compensated at the retail rate). Depending on NEM compensation in such states, perhaps DER Aggregation is a meaningful option. There is a direct connection between DER participation in an aggregation and the economics of traditional (full retail compensation) NEM, the subject of NERA’s Petition for Declaratory Order. That connection has been ignored by most articles extolling Order No. 2222. (Disclaimer: Steptoe represented the New England Ratepayers Association in filing its PDO in Docket EL20-42.) The true potential of Order No. 2222 is unlikely to be met unless FERC changes the colors on the map below by asserting its full jurisdiction over wholesale power sales, whether those sales are made under PURPA’s exemption for sales from small QFs or FPA Section 205.

Continue Reading The Best Description of Order No. 2222? “Landmark” “Transformative” Ground-Breaking” “Barrier-Busting” “Competition-Boosting” “Game-Changing” “Bold” or “None of the Above Due to Traditional Net Metering”?