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

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

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”

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

In the long-awaited Broadview Order, FERC reinforced PURPA’s statutory limit for small power production qualifying facilities (SPP QFs) to a “power production capacity” of not more than 80 MW. SPP QFs can not evade this statutory limit by restraining the ability of much large facilities to actually “send out” more than 80 MW through the use of limited inverters.  The Commission attempted to dodge the question that the industry was actually awaiting, regarding how storage charged from an SPP QF should be counted with regard to the 80 MW limit, stating that it “did not need to address whether the associated battery storage system is a separate facility or whether and how the battery storage system should be considered in determining the facility’s power production capacity.” Instead, the ruling was based on the 160 MW of solar capacity at the site. But, the ruling provided no indication that if the facility had consisted of 80 MW of solar and 80 MW of battery storage that the outcome would not have been identical.

The order is prospective and does not affect SPP QFs that have self-certified or have been granted Commission certification prior to September 1, 2020. Until December 31, 2020, the effective date of Order No. 872, any challenge to a Form 556 filing for an over 80 MW SPP QF would have to be through a Petition for Declaratory Order, rather than a protest.
Continue Reading The Commission Takes a Narrow View of Broadview

In a July 2, 2020 Order, FERC declined to answer a question in a Petition for Declaratory Order (PDO) concerning whether a set of off-system QFs could deliver power to a utility at a Point of Delivery (POD) that was constrained. This question is important because if answered affirmatively, it could result in the utility’s ratepayers having to pay upgrade costs to ensure that all firm transmission service reservations can be accommodated in addition to paying for power from a QF at an avoided cost rate. In the Blue Marmots case, the QFs sought two findings from FERC:

to declare that transmission congestion on the purchasing utility’s system does not relieve the electric utility of its mandatory obligation to purchase from a QF under PURPA, where all other predicates to the creation of a LEO have been established.

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… to declare that the Commission’s direction in section 292.306 of the Commission’s regulations that QFs are obligated to pay such interconnection costs as are assessed by state regulatory authorities extends only to the physical interconnection between the QF and the utility system to which it is directly interconnected, not to other aspects of transmission service over which the Commission retains authority.

The first request was probably unnecessary, as the PURPA purchase obligation is relatively absolute in FERC’s view. The only issue is one of price, i.e., who has to pay to relieve the congestion; the answer to the second question thus may determine whether the QF chooses to sell to this utility. The QF still can sell, if the deciding body decides it must the pay to relieve congestion; it remains the QF’s choice. It is the second issue thus that is far more relevant and has not been addressed by FERC. And, it still has not.
Continue Reading FERC Declines to Answer Question of Impact of Off-System QFs Choosing Constrained Points of Delivery