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

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