On July 10, 2020, the D.C. Circuit issued its opinion on various Petitioners’ appeals of Order No. 841. As predicted, the Court denied Petitioners’ claim that FERC lacks the authority to prohibit States from barring electric storage resources (ESRs) located on utility distribution systems from participating in wholesale power markets. Given the EPSA Supreme Court decision involved the sale of a product – demand response – that is not even FERC-jurisdictional, this case – involving sales by ESRs of clearly FERC-jurisdictional products – made the decision a slam dunk. Indeed, Petitioners would be hard-pressed to obtain either a rehearing en banc or a writ of certiorari.

The D.C. Circuit applied a test found in EPSA in rejecting most of the Petitioners’ claims. The court examined: 1) whether the challenged practice at issue – FERC’s prohibition of State-imposed distributed ESRs participation bans – directly affects wholesale rates; 2) whether FERC had regulated State-regulated facilities; and, 3) whether the court’s determinations would conflict with the FPA’s core purposes of curbing prices and enhancing reliability in the wholesale electricity market. The first and third prongs were so easily met that the court barely touched on them. The court found “swiftly” as to the first prong that FERC’s prohibition of State-imposed participation bans directly affects wholesale rates. Indeed, it noted that “If ‘directly affecting’ wholesale rates were a target, this program hits the bullseye.” As to the third prong, the court found that the “challenged Orders do nothing more than regulate matters concerning federal transactions – and reiterate ordinary principles of federal preemption – they do not facially exceed FERC’s jurisdiction under the Act. Our decision today does not foreclose judicial review should conflict arise between a particular state law or policy and FERC’s authority to regulate the participation of ESRs in the federal markets.”

As to the second prong, the court relied heavily on the Supremacy Clause of the Constitution to reject claims that States can close off access to wholesale markets. The court explained that “because FERC has the exclusive authority to determine who may participate in the wholesale markets, the Supremacy Clause – not Order No. 841 – requires that States not interfere.” Continue Reading The Lesson of the Appeal of Order No. 841 – Be Careful What You Ask For

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

Although there were tempting things to write about in last few months, client considerations meant not writing about certain “hot” topics such as net metering. The Order No. 841 oral argument at the D.C. Circuit, however, demanded an article. The only challenge to Order No. 841 involved distributed storage and its participation in wholesale markets. The oral argument already has been summarized by many and although a close call on whether the case will be dismissed for lack of injury or upheld on the “affects” clause, a victory for distributed storage is fairly likely. The oral argument proved to be interesting not so much for the future of Order No. 841, but for the future of FERC regulation of wholesale distribution service, a service that it has regulated for decades. It seems no one involved in the oral argument remembered that the D.C. Circuit once stated: “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.” That is, TAPS v. FERC gave FERC a seal of approval to regulate “wholesale distribution service,” as it is a form of transmission service in interstate commerce. FERC counsel’s decision not to mention this decision was puzzling and whether FERC will return to embracing it, if a DER Aggregation Final Rule is issued, will be interesting to watch. Continue Reading Order No. 841 Oral Argument Analysis: Has Everyone Forgotten TAPS v. FERC?

About a decade ago, FERC opened the door to state commissions setting different avoided cost rates and adopting different standard contracts for different types of QFs. Although the ultimate legality of so-called “tiered avoided cost pricing” remains to be tested in court, a decision from the United States Court for the District of Idaho teaches an important lesson in how state commissions should and should not issue rulings categorizing QFs as fitting within a particular tier, if such tiers exist. In Franklin Energy Storage, the court decided that a state commission order finding that a particular type of QF was only eligible for the avoided cost rate and contract for solar and wind facilities was in error because the state commission actually was ruling on whether the facilities were or were not QFs. Despite the fact that all the parties to the case agreed that QF status was a matter exclusively within FERC’s jurisdiction, as supported by the IEP v. CPUC precedent, the court still read the Idaho commission’s action as a ruling on the merits of QF status.

The QFs at issue consisted of battery storage devices that would receive 100% of their energy input from a combination of renewable energy sources such as wind, solar, biogas, biomass. The purchasing utility obtained an order from the Idaho commission that that storage facility QFs such as the plaintiffs’ were subject to the same treatment and rates as wind and solar QFs rather than the treatment of “other QFs.” The plaintiffs challenged this order, which would have resulted in less favorable contracts. The court found that the Idaho Commissioners made their own determination of QF status, despite their concession that only FERC could make such determination. It appears that it was the specific wording of the Idaho commission’s order that caused this result. Continue Reading A Lesson for State Commissions In Classifying QFs

In the last year, two decisions from judges sitting on the bench of the United States Court for the District of New Mexico have opined that PURPA claims made by plaintiffs were “as applied” rather than “implementation” claims and thus could not be heard in federal court. The first decision, in Great Divide I, was a close call and provided an in-depth discussion of the “as applied” versus “implementation” precedent. There, had the case been pled more broadly, as an attack on the legally enforceable obligation (“LEO”) standard established by the New Mexico commission, the court said it would have heard the case on its merits. Indeed, the issue of whether a LEO standard meets PURPA’s requirements had been heard recently by the Montana federal court system. The Great Divide I court invited a better-styled complaint, indicating the complaint could be transformed into an implementation claim.

The plaintiffs filed such an amended complaint, and the court did review the merits of the case, issuing an order on the merits in Great Divide II (2019 WL 5847060) last November. The court found that the New Mexico LEO standard did not violate PURPA, especially given FERC’s silence on appropriate prerequisites which gave the New Mexico Commissioners “the wiggle room” to implement a prerequisite. This decision has been appealed and may be mooted by FERC’s PURPA Final Rule. Now, the newest decision from New Mexico District Court – Vote Solar, – indicates that at least one judge in New Mexico would not have entertained any attempt by the Great Divide I plaintiffs to replead their case. Continue Reading A New Mexico Federal District Court Tries to Slam Shut the PURPA “Implementation” Claims Window

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