In light of the pending FERC PURPA NOPR, some states have stayed or delayed ruling on pending cases involving PURPA contracts and avoided cost rate, particularly where a standard contract or rate is involved. In two states, however, December 9, 2019 saw significant decisions on PURPA contracts and rates. Although too detailed to fully recap here, the orders reflect the fact that PURPA rates and contracts raise innumerable and complex issues, particularly when utilities claim renewable QFs cause integration costs and developers of hybrid (paired) QFs seek compensation associated with the benefits of adding battery storage to renewable QFs. On January 3, 2020, however, one of the orders, was altered on reconsideration, as arguments that the rates adopted were too low were found to be persuasive.

In Caithness Beaver Creek, LLC, which is pending reconsideration, the Montana PSC -re-examined numerous policies on avoided costs and other issues such as contract length after Caithness and NorthWestern could not negotiate a PURPA contract. Perhaps the most interesting ruling came on the methodology for calculating an avoided cost for energy, as the Montana PSC found good cause to depart from its prior methodology. As the current FERC PURPA regulations still require a fixed price for energy, the Montana PSC decided to adopt a forecasted rate based on hourly modeling and marginal costs to serve load so that avoided energy costs would equate to the running cost of NorthWestern’s highest-cost resource needed to serve load in each hour: $0 if load is served with must-take or intermittent resources with no variable costs (solar, wind, hydro); the variable costs of the marginal generating resource if load is served with NorthWestern-dispatched generation; or the market price if load is served by market energy purchases. Continue Reading Not All States Are Awaiting a FERC Final Rule In Re-Examining PURPA Rates and Contracts (Updated)

PURPA presents interesting issues regarding how state commissions may deal with “transmission costs” caused by qualifying facilities (QFs), particularly when QFs are wheeling to a utility to which they are not interconnected. FERC previously has stated that a QF only has to deliver power to a point of interconnection with the purchasing utility in Pioneer Wind Park I. But in the same case, FERC also stated that “implicit in the Commission’s regulations, transmission or distribution costs directly related to installation and maintenance of the physical facilities necessary to permit interconnected operations may be accounted for in the determination of avoided costs if they have not been separately assessed as interconnection costs.” This statement, while located in a footnote, should not be overlooked. Several years ago, the Montana Public Service Commission affirmed its importance in Decision 7560a, ruling that transmission service upgrade costs associated with the a QF project may be accounted for in the determination of avoided costs, but then found the utility at issue had to provided adequate evidence of transmission costs. Continue Reading Transmission Costs and Congestion: Relationship to Avoided Costs

Admittedly, it is odd for a PURPA blog to take a month to publish on the PURPA NOPR. But, it took some thought to determine what the NOPR really means to the industry. (The author’s 10-day October vacation had nothing to do with the delay.) In any case, this blog is not for the purpose of summarizing the NOPR; plenty of summaries abound across the internet. The purpose of this posting is to consider what will be the impact of the Final Rule, assuming that it changes very little from the NOPR. Despite the two primary reactions – extensive hand-wringing and substantial glee – the impacts likely will not be very profound, nor does the NOPR diverge from any Congressional mandate reflected in PURPA.

Prior to discussing the potential impacts of PURPA reform, we briefly examine the legality of FERC’s actions. We must start with the premise that Congress did not enact PURPA to encourage QFs. That oft-repeated mantra is false. Congress enacted PURPA to encourage those QFs that could sell power while being paid an avoided cost rate. And, we also must remember that in 2005, Congress indicated QFs with access to certain markets no longer needed to be supported by the PURPA purchase mandate. Congress did not say anything about 20 MW QFs, 1 MW QFs, or any other size QFs. Congress never said a thing in PURPA about avoided cost rates being fixed, formulaic, market-based, or taking any other particular form. Finally, PURPA is silent on legally enforceable obligations (LEOs) establishing a date for fixing the avoided costs rate, for the simple reason PURPA never required a fixed rate to begin with. In short, the NOPR does not appear to violate Congress’ intent; rather, it changes FERC’s implementation of PURPA, which of course could be changed back by a future Commission.

With that background, the discussion below explains why some of the key NOPR proposals are not all that impactful. Some proposals simply address court precedent with which FERC disagrees. Other changes, if adopted, may have little impact, as states adopt programs that effectively undo the changes proposed. Continue Reading PURPA NOPR: Why All the Fuss?

Without having seen the new PURPA NOPR, two reforms discussed at the September 19 Open Meeting appear to be the most significant. First, is the ability of states to permit a floating (i.e., formula) energy rates in contracts, such as tying the energy price to market rates. If adopted, this change would reverse the various court decisions that have held that under FERC’s existing regulations, a rate set at the time of a legally enforceable obligation must be fixed as to both the capacity and energy component. This change may well serve its intended purpose, making states more willing to permit longer-term PURPA contracts in an era where wholesale power prices are unlikely to rise significantly due to fuel price volatility. Second, the reduction in the size of small power production facilities (i.e., renewables) from which utilities that have obtained a purchase exemption under PURPA Section 210(m) from 20 MW to 1 MW is very significant to many ISO/RTO utilities. The up-to-20 MW purchase requirement, among other things, interfered with rational integrated resource planning by compelling purchases from often sophisticated generators that can readily participate in markets.


The DERs Aggregation rulemaking (now FERC Docket No. RM18-9) was initiated back in 2016 and was the subject of a 2018 Technical Conference. Now, FERC has posed to the six ISOs/RTOs an identical set of data requests regarding DERs that focus primarily on how interconnection service and distribution service would be provided to DERs. The data requests illustrate an issue discussed in a recent blog post about Order No. 2003 and FERC’s decision there to: 1) eliminate the bright line between its jurisdiction and state jurisdiction over interconnection service and replace it with a blurrier jurisdictional line that is referred to as the “first-use test” or “already subject to an OATT test”; and 2) retain the bright line between its jurisdiction and state jurisdiction over interconnection service when the seller is a qualifying facility (QF) that can sell to third parties. FERC’s questions reflect how complicated this policy is to implement (particularly as a non-QF may become a QF, thus shifting jurisdiction). The questions also indicate how difficult to even determine the role, if any, ISOs and RTOs take in DER interconnections by reviewing their filed tariffs. Taking FERC’s jurisdictional policies and ISO/RTO policies on whether to participate in the DERs interconnection process and applying them to an aggregation that may be comprised of QFs, non-QFs, demand response participants, and storage DERs raises a host of questions that many ISOs, RTOs, and Distribution Owners likely have not even considered. These questions may get those conversations started.

The answers to the questions will probably reveal several interesting things about how much, or how little, any particular ISO or RTO knows about interconnection processes for DERs. Some predictions of what FERC may learn from some of its questions are made below. These are only predictions. For brevity, the data requests are not repeated here. Continue Reading FERC’s ISO/RTO DERs Data Requests – What Do They Tell Us and What Will the Answers Likely Tell FERC

It is somewhat common for a utility to determine not to challenge a new rule on power purchases issued by its state commission that is clearly in violation of PURPA or the FPA. This reluctance is understandable and often rests on a political decision: fighting a state commission over an issue may have a greater downside than upside with regard to the continuing relationship between the utility and its regulators. Utilities also sometimes ignore the illegality of new state laws requiring them to purchase energy from certain sources or at certain rates. Developers are less inclined to defer to state legislatures or regulators and often will challenge laws or state commission orders that appear facially unlawful. But, as such challenges can be costly, some preemptable state laws and regulations in some cases go unchallenged. Allowing such laws and regulations to remain in place can lead to unforeseen impacts and expenses for purchasing utilities and developers alike. Continue Reading Preemptable State Laws and Regulations: The Failure to Challenge Can Have Adverse Impacts

In 2017, a California federal district held in Winding Creek v. CPUC that the California Public Utilities Commission (CPUC) had two PURPA problems: 1) its capped PURPA program entitled “Re-MAT” did not adopt an avoided-cost price because of its adjustment mechanism scheme; and 2) the CPUC’s standard PURPA contract (Standard Contract) failed to properly implement PURPA because the contract had only one, not two, pricing options. As a result, the court found that the cap on the Re-MAT program was improper. The district court found that the Standard Contract would need to provide a fixed price at the time of contracting and at delivery to satisfy FERC’s PURPA regulations. The district court also held that it was not its job to fix the Re-MAT pricing problem by setting an avoided cost price or requiring the purchasing utility to provide a contract at the “unadjusted” price demanded by the QF. Both sides appealed.

Yesterday, the Ninth Circuit ruled that the district court was correct as to all its findings. Perhaps of most importance, the Ninth Circuit concluded that a formula rate could not satisfy the requirement of 18 C.F.R. § 292.304(d)(2)(ii) of a price set at the time of contracting (i.e., when a legally enforceable obligation (LEO) is formed). It stated, that the “Standard Contract provides only one formula for calculating avoided cost, and that formula relies on variables that are unknown at the time of contracting.” Indeed, it found this “infirmity is plain from the face of the regulations, so we do not defer to FERC’s unreasoned conclusion to the contrary.” Continue Reading Ninth Circuit Affirms Winding Creek: Formula Rates Do Not Satisfy Price Set at Time of LEO

Several moths ago FERC issued an Intent Not to Act on New Mexico Public Regulation Commission’s (NMPRC) LEO standard, which (seemingly) was challenged by a QF’s (Great Divide) Petition for Enforcement under PURPA. The NMPRC had adopted a very strict LEO standard, that required that QFs must be ready to interconnect and deliver energy before any legally enforceable obligation may be created to purchase the power at avoided cost rates. Great Divide turned to federal district court for relief, as one might expect. There was an expectation that this case could provide some important guidance as to the current chasm between many purchasing utilities and the QF industry as to at what point of time a LEO should be found to have been established.

Instead, what the industry received was a lengthy order dissecting whether Great Divide had truly brought an implementation claim as opposed to an “as applied” claim. The court (2019 WL 2144829) found that Great Divide brought an “as applied” claim largely because Great Divide was challenging an NMPRC order finding it had no LEO rather than the rule (Rule 570) on which such order was based and/or the NMPRC’s interpretation of that rule. Continue Reading District Court Order Provides PURPA Guidance – On “As Applied” Versus Implementation Claims

On June 3, 2019, the US. Court of Appeals for the Ninth Circuit issued a Memorandum Opinion (i.e., not for publication), that reinforced the scope of the role of the district and appellate courts in cases brought under the juridical review scheme of PURPA. In the case below, the plaintiff QFs (Plaintiffs) had succeeded in convincing FERC (in a declaratory order ruling) that the Montana Public Service Commission’s (MPSC) legally enforceable obligation (LEO) standard violated PURPA and that the QFs were entitled to declaratory relief. The QF plaintiffs went to district court to obtain confirmation and an order that the LEO standard that the MPSC had applied was illegal. Before the district court could rule, however, the MPSC set a new LEO standard that it placed into effect prospectively. Nonetheless, the district court provided declaratory relief that the prior LEO standard was unlawful. Both the Plaintiffs and MPSC appealed.

The district court had left all interested parties (including with purchasing utility, Northwestern Energy) with no guidance as to what LEO standard should apply to the Plaintiffs and other QFs that were denied contracts under the illegal LEO standard. The QFs wanted guidance, the MPSC wanted the entire matter found moot. The Ninth Circuit agreed with the MPSC, holding that the district court erred in concluding it could reach the merits of Plaintiffs’ request for declaratory relief. The court found that the request for declaratory relief was moot, given that the MPSC regulation under challenge had been changed before the district court issued its ruling. Continue Reading Ninth Circuit Reinforces the Appropriate Role of Courts in PURPA Implementation Claims

The jurisdictional discussion in Order No. 841-A was lengthy. It could have been very short.

This blog today takes a personal turn as I relate the tale of FERC’s jurisdiction over energy storage resources (ESRs) connecting to a public utility’s distribution system to sell wholesale power. There is only reason that the tale is long (like this blog entry) – Order No. 2003.

In the bundled era, no one seemed to give much thought to the fact that FERC, and the FPC before that, regulated both the interconnection of and delivery of power to load-serving entities (LSEs), i.e., wholesale customers, connected to a public utility’s local distribution facilities. With unbundling and full open access on the horizon, however, FERC reiterated its policy in Tex-La:

“We do not agree with TU that the local distribution exception to our jurisdiction under section 201(b)(1) of the FPA precludes us from ordering under section 211 the transmission services requested by Tex-La. Section 211(a) of the FPA authorizes the Commission to require a transmitting utility: ‘to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) to the applicant.’ Ordering ‘transmission services’ to the wholesale customer in this proceeding, whether or not that service consequently involves some use of facilities that may not be purely ‘transmission’ facilities, is doing no more than what we are authorized to do by the statute. It is not an assertion of jurisdiction over specific facilities, but rather is an assertion of authority to order specific services.”

With open access, the relatively few distributed energy resource (DERs) that were not QFs selling only to their host utility were typically interconnected pursuant to FERC jurisdiction.

In a case arising shortly after open access, involving interconnection service, but not delivery service for a new LSE, FERC, relying on Federal Power Act Section 210, made clear that when the FPA said that FERC could compel to electric utilities to interconnect to the “transmission facilities of any electric utility” Congress really meant “transmission or distribution facilities.” FERC explained in Laguna:

“PG&E has provided no persuasive rationale for us to read ‘transmission facilities’ in [S]ection 210 in a way that would vitiate the very purpose of the provision, i.e., the ability of an eligible applicant to obtain interconnection to a utility’s transmission grid. Under PG&E’s argument, the Commission would lack jurisdiction to order an interconnection any time nominally local distribution facilities arguably are involved. We do not believe that Congress intended for wholesale customers such as Laguna to be ineligible for an interconnection under [S]ection 210, based merely on the label attached to facilities to which they interconnect.”

Laguna stands for the simple proposition that if one electric utility asks another electric utility to interconnect, FPA Section 210 allows FERC to order that interconnection. An ESR (or any DER), that will sell electric energy presumably is an electric utility. Is the tale over? No. (Although perhaps it is over if an ESR is willing to seek interconnection service under FPA Section 210.)

In 2000, in Tennessee Power Company, FERC clarified that interconnection is a critical component of open access transmission service. In the very same year, the D.C. Circuit affirmed FERC’s assertion of jurisdiction of any wholesale transmission service (including distribution facilities), in Order No. 888, holding in TAPS v. FERC that “FERC’s assertion of jurisdiction over all wholesale transmissions, regardless of the nature of the facility, is clearly within the scope of its statutory authority.” A bright line had been set as to retail and wholesale usage of distribution. If interconnection service is transmission service and FERC has jurisdiction over all wholesale transmission service, even if it occurs on local distribution facilities, does that not mean (putting PURPA aside) that FERC has exclusive jurisdiction over: 1) interconnections to public utilities of entities buying and selling power at wholesale; and 2) the delivery of wholesale energy to or from such wholesale entities? Now, the tale must be over. Sorry, no.

How did DERs (including distributed ESRs) interconnection jurisdiction get so complicated after Tex-La, Laguna, Tennessee Power, and TAPS? Indeed, such jurisdiction got so complicated for a wholesale ESR, FERC is now saying in Order No. 841-A that “Order No. 841 did not mandate that electric storage resources must have access to the distribution system” and “Order No. 841 does not modify states’ authority to regulate the distribution system, including the terms of access.” The dissent goes further.

The tale might have ended had FERC adopted its Order No. 2003 NOPR position in Order No. 2003. In the NOPR, FERC embraced the bright line it had established in Order No. 888 and cases like those cited above, stating that it is “clear that the FPA grants federal jurisdiction over transmission by a public utility in interstate commerce and when public utilities make sales for resale in interstate commerce. Within this jurisdiction, we propose that the NOPR IA and IP will apply only when a generator interconnects to the Transmission Provider’s transmission system or makes wholesale sales in interstate commerce at either the transmission or distribution voltage level.” FERC was prepared to continue to exercise the jurisdiction it had exercised for years over interconnections of wholesale sellers (and more commonly wholesale buyers) to distribution facilities. Many states got angry. FERC blinked. Order No. 2003 was issued.

There, FERC found that some lower-voltage facilities are “local distribution” facilities not under its jurisdiction, but that some distribution facilities are used for jurisdictional service such as carrying power to or from a wholesale power customer and are included in a public utility’s OATT. Order No. 2003 was thus found to apply “to interconnections to the facilities of a public utility’s Transmission System that, at the time the interconnection is requested, may be used either to transmit electric energy in interstate commerce or to sell electric energy at wholesale in interstate commerce pursuant to a Commission-filed OATT.” The “first-use” test. The Commission also addressed QF interconnections in Order No. 2003, but did not mention that its first-use test would not apply to those QFs connected to distribution with the ability to sell to third parties, as it later would. Although the first-use test remains, the foundation on which it rested (that FERC only has authority to order interconnections to “already-used” distribution facilities), had already been abolished before the ink dried on Order No. 2003.

In Order No. 2003, FERC stated that it would exercise exclusive jurisdiction over the rates, terms, and conditions of Commission-jurisdictional service provided over “dual use distribution facilities.” But in a separate case, winding its way on appeal in the midst of the Order No. 2003 rulemaking, FERC argued that once any entity made a wholesale use of a local distribution facility, such now dual-use facility became exclusively FERC-jurisdictional. All service over dual-use distribution was FERC-jurisdictional according to FERC such that various “pieces” of each utility’s distribution system would not be subject to state jurisdiction when used by retail customers. Interestingly, this broad taking of jurisdiction from the states was challenged only by two utilities, and no states. A D.C. Circuit panel heard the Detroit Edison appeal and disagreed with FERC. The court explained that a local distribution facility used by a wholesale customer remained subject to state jurisdiction for retail purposes but that when a local distribution facility is used in a wholesale transaction, FERC has jurisdiction over that transaction pursuant to its wholesale jurisdiction under FPA § 201(b)(1). In other words, the D.C. Circuit supported a simple and clear bright line between state and federal jurisdiction over local distribution facilities. Wholesale uses belong to FERC; retail uses belong to the state. There were not in fact two “flavors” of distribution facilities each subject to the exclusive jurisdiction of either FERC or the state. FERC would have to address this new bright line on rehearing of Order No. 2003, as the case was issued too late for any commenters to use it to support FERC’s NOPR claim of jurisdiction over all wholesale DERs interconnections.

Now, those (very few) who objected to FERC’s change in position from the NOPR’s wholesale/retail test to Order No. 2003’s first-use test had strong ammunition. Well, they thought they did. One lawyer, whose name I refuse to disclose because I (oops!) failed to change FERC’s view in three separate clarification/rehearing requests, tried to use Detroit Edison to reinstate a simple bright line test. In Order No. 2003-C, FERC issued its final rejection of its NOPR claim of jurisdiction over all wholesale generator interconnections to distribution systems, explaining that asserting such jurisdiction “would allow a potential wholesale seller to cause the involuntary conversion of a facility previously used exclusively for state-jurisdictional interconnections and delivery, and subject to the exclusive jurisdiction of the state, into a facility also subject to the Commission’s interconnection jurisdiction – a result that we believe crosses the jurisdictional line established by Congress in the FPA.” (FERC expressed no concern about QFs selling to third parties and new wholesale loads causing the exact same conversion.) Had FERC instead ruled in Order No. 2003 that interconnection service was an element of transmission service and FERC has exclusive jurisdiction over all wholesale transmission even on distribution facilities, I personally believe that a court of appeals would have upheld that ruling. The selling of wholesale generator interconnection service certainly sounds like a wholesale transaction under the logic of Detroit Edison. But, FERC would not accept this position.

In short, by adopting the first-use test in Order No. 2003, FERC voluntarily narrowed its jurisdiction over wholesale usages of distribution facilities, at least as to generation interconnections. In contrast, FERC never seemed to relinquish jurisdiction over either wholesale load interconnections or any delivery service that requires the use of distribution facilities.

The entire jurisdictional portion of Order No. 841-A, thus, could not rest on cases such as Tex-La, TAPS, Detroit Edison, etc., that stand for the proposition of exclusive FERC jurisdiction over all wholesale distribution transactions (including generator interconnections) without reversing Order No. 2003’s exclusion as to some generator interconnections. In contrast, those cases, although not cited, are implicit once FERC starts discussing rates for wholesale delivery service that ESRs may have to pay to charge. The distribution delivery transaction remains exclusively FERC-jurisdictional after Order No. 2003. In Order No. 841-A, FERC stated that it “would consider any proposal to establish a rate for providing wholesale distribution service to an electric storage resource for its charging (whether a facility-specific rate, a wholesale distribution service rate that applies to all or some subset of electric storage resources, a generally applicable wholesale distribution service tariff, or any other rate mechanism) on a case-by-case basis in light of the record evidence.”

Order No. 2003 did not address FERC’s unquestioned exclusive jurisdiction over wholesale load interconnections. This point raises one final question and perhaps could have changed this tale’s ending if it had been raised in the Order No. 841 rulemaking: Just as an ESR needs an interconnection to discharge (and sell) energy, it needs an interconnection to buy the very wholesale power that Order No. 841 said it was entitled to buy. That is, an ESR is, in part, a wholesale load. Granted, an ESR may need only one physical interconnection, but rather than tying itself in knots over jurisdiction through cases such as EPSA and the “affects and relates to” clause of the FPA, a FERC ruling that the interconnection of a wholesale load to a public utility is a FERC-jurisdictional service would have been an easy way for FERC to find the interconnection jurisdiction it ceded away in Order No. 2003 as to ESRs. When one views ESRs as wholesale loads, the notion that FERC lacks authority over their interconnection to any distribution facility is implausible. The tale could have had a very different ending as to DERs that are ESRs had they been treated like LSEs.

But for now, the DERs interconnection jurisdiction tale ends with Order No. 2003. Its first-use test remains the law (except for those third-party selling QFs, some of which may well already have added storage or may add storage, and those DERs that may turn to FPA Section 210 given Laguna).

None of the discussion above is meant to undermine the argument that ESRs located on distribution systems can and likely will raise reliability, security, operational, cost causation, and myriad other difficult issues and challenges for utilities given sufficient penetration levels. Nor does the discussion above judge whether states or FERC are in a better position to address such issues. FERC likely could assert jurisdiction over wholesale interconnections and still permit a state to opt out. Rather, the discussion above is intended to point out that FERC’s distribution interconnection jurisdiction has ebbed and flowed over time. I have been lucky to have been both a frequent participant and intimate observer in these distribution interconnection jurisdiction skirmishes for over two decades. It appears such opportunities are not going away.

This blog article reflects only the personal viewpoint of its author, Jennifer Key.