A PURPA complaint before the Michigan PSC, accessible through the article Michigan Utility Under Fire For Alleged PURPA Violations, teaches a good lesson about words. The QF complainant (Greenwood Solar) stated that a utility (DTE): 1) has an obligation to buy capacity even if unneeded; and 2) needs to obtain a waiver from FERC in order to be absolved of the requirement to buy capacity. Indeed, in a fairly recent case cited by Greenwood Solar, FERC reiterated its regulation that specifically requires that a utility purchase any energy and capacity made available by a QF. PURPA regulations state that energy and capacity purchases are mandatory, but for the exemption for purchases from over 20 MW QFs that most utilities in organized markets have obtained. The complaint alleges that respondent DTE insisted that it had no obligation to purchase unneeded capacity from a QF. A close reading of FERC’s exact words on the topic supports Greenwood Solar’s contention that an obligation to purchase capacity exists, despite any need. Although this policy appears counterintuitive, the policy is logical when coupled with other words issued by FERC – that a utility that lacks a need for capacity may lawfully fulfill its purchase obligation by offering a QF a price for capacity of $0.00/MW. Continue Reading Words with Enemies – PURPA and the Capacity Purchase Obligation
In our series of posts on the need for PURPA reform targeted at the Allco decision, we identified Congress as one avenue of reform. Although the Congressional path to success may be arduous, the journey has begun. On May 3, 2018, Senators John Barrasso (R-WY) and James Risch (R-ID) introduced the “Updating Purchase Obligations to Deploy Affordable Resources to Energy Markets Under PURPA Act” (“UPDATE PURPA Act”). Although the UPDATE PURPA Act is quite broad in scope and will undoubtedly prove controversial, unlike Rep. Walberg’s (R-MI) PURPA Modernization Act of 2017, the new bill directly addresses 18 C.F.R. Section 292.304(d)(2)(ii) (as to renewable (small power production) qualifying facilities (QFs)) by requiring that Section 292.304(d)(2) be amended to provide that “a legally enforceable obligation for the delivery of electric energy or capacity from a qualifying small power production facility shall not require any electric utility to purchase energy or capacity from a qualifying small power production facility at a rate that exceeds the incremental cost of the electric utility of alternative electric energy or capacity, as calculated at the time of delivery.” In short, the bill effectively eliminates the requirement for a utility to pay for energy and capacity at a price other than the price at the time of delivery, eliminating the price risk for both buyers and sellers alike inherent in long-term contracts.
Given that the more modest reforms of the PURPA Modernization Act of 2017 have not been enacted (well over a year after introduction), FERC could speed the journey to “fix” Allco, by introducing a rulemaking that clarifies that rates set at the time of a legally-enforceable obligation can be formula rates. Even if such relief is later superseded by more comprehensive PURPA reform, this reform should be adopted sooner rather than later to stem litigation. Certainly, broader reform by FERC would be welcome by the utility industry, but reform of 18 C.F.R. Section 292.304(d)(2)(ii) is a priority reform. Continue Reading Some in Congress Are Ready to Address Allco – Are the FERC Commissioners Willing to Join Them?
After holding its two-day Technical Conference on DERs, FERC issued two Requests for Comments on April 27, 2019 in existing Docket No. RM18-9 and new Docket No. AD18-10. FERC divided the existing rulemaking docket into two parts, separating the topic of DER Aggregation in ISOs and RTOs from the topic of DER Technical Considerations for the Bulk Power System. Also, FERC added “new” questions to the seven existing sets of questions asked before the conference. The docket split and new questions provide some new insights that should be considered in drafting comments, which are due June 26, 2018. Specifically:
- We can discern from the opening of an AD docket that is not limited to ISOs/RTOs that FERC is interested in ensuring DERs are taken into account by all Transmission Providers in modeling, planning, supporting, and operating the bulk power system.
- We can discern from new questions on planning and models that FERC may be seeking to assert some sort jurisdiction over distribution system planning on the grounds that DERs impact bulk power systems and that transmission planning must be (somewhat) integrated with distribution planning.
- We can discern from new questions about the need for DER data that more information about the importance of 1) individual DER size and 2) overall DER penetration levels should be provided to FERC.
- We can discern from the new questions about aggregating behind single versus multiple nodes that pricing issues may be difficult to resolve and may need to vary by ISO/RTO.
- We can discern from the new questions about utility distribution companies (UDC) that the myriad issues they face as relates to DERs, including ensuring distribution system safety and reliability, ensuring retail ratepayers are not adversely financially impacted, and dealing with state retail customer privacy laws, need to be identified and addressed in an appropriate fashion. The UDCs will need to identify those issues of concern, given their own particular situations.
- We can discern from the new question about participation in the CAISO DER program, that FERC needs more information on the relationship between each UDC/state retail net metering program and the impacts of such programs on the likelihood and type of DER participation in wholesale markets.
Based on the two-day FERC Technical Conference on DERs, where varying opinions were presented on a variety of technical and operational issues relating to DERs and DER aggregation, the following are overarching takeaways that the Commission and its Staff should consider before taking the next step on DERs’ and/or DER aggregations’ participation in wholesale markets.
- Identify where/whether need exists. The need for ISO/RTO rules for DER aggregations or DER participation in wholesale markets may vary widely, especially as a preference for participation in “the retail market” (e.g., net metering; distribution system support; distribution facility deferral) may result in very little DER participation in wholesale markets, even where market penetration of DERs is significant.
- The UDC rules this domain. The role of the Utility Distribution Company (UDC) in wholesale market participation will be significant. The notion that a DER aggregator would interface only with the ISO/RTO, although supported by DER aggregators at the conference, appeared to be a non-starter for UDCs and ISOs/RTOs. The message that the UDC or a Distribution System Operator ultimately had to have operational control over the distribution system was clear.
- Plug and play is not here today. The readiness for significant DER penetration varies widely from UDC to UDC and any FERC rule must take this into account, particularly as state commissions are the entities ultimately authorizing UDC “spend” on distribution system modernization.
- Jurisdictional, regulatory, and legal issues must be resolved first, not as an afterthought. Technical/operational issues cannot be fully divorced from jurisdictional, regulatory, and legal issues. Establishing rules and policies should precede any discussion of technical implementation, but have been largely ignored to date (and purposefully omitted from the Technical Conference). Examples: 1) is it practical for DERs that do not have or cannot obtain qualifying facility (QF) status to sell into wholesale markets (whether directly or through a DER aggregator) under the existing regulatory system (requiring quarterly EQR filings and maintaining market-based rate eTariffs)?; 2) Currently, QFs selling to the market must take FERC-jurisdictional interconnection service under existing FERC policy; if aggregators are considering aggregating entire neighborhoods of PV owners (which are QFs as a matter of law if under 1 MW), is this approach to interconnection practical? When and how are such issues going to be addressed?
- Multi-use applications will take time to address. Compensation and cost recovery relating to DERs offering both FERC- and state-jurisdictional services and/or taking FERC- and state-jurisdictional services raise implementation issues that are very complex. Although they are solvable issues, significant time and effort is required to solve them, particularly at the state commission level.
Those persons that believe that the Federal Power Act left exclusive jurisdiction over local distribution facilities (and everything that occurs on such facilities) to the states have been told that they are wrong. The courts have told them they are wrong. FERC has told them they are wrong. Yet, whenever FERC mentions the distribution system, state regulators and others object vociferously that FERC is intruding into state-jurisdictional matters. Indeed, the Commission’s Final Rule on Storage, which assumes that many if not most storage devices will be connected to distribution, actually raises no meaningful jurisdictional issues that have not already been addressed by the courts. Nonetheless, several rehearings raising jurisdictional issues related to storage devices located on the distribution system were filed in response.
Successful appeals are unlikely on jurisdictional grounds, assuming FERC does not appease the states as it has on other occasions, such as with regards to non-QF interconnections to distribution. NARUC and some utilities have objected to certain aspects of the Final Rule that permit participation by storage resources interconnected to distribution in wholesale markets. FERC jurisdiction over all wholesale sales in interstate commerce is well-established. And, FERC jurisdiction over the usage of a distribution system to engage in wholesale market transactions rests on FERC precedent more than two decades old. FERC jurisdiction over wholesale distribution service was affirmed in New York v. FERC, and Detroit Edison Co. v. FERC. Continue Reading Untangling Jurisdiction Issues for DERs
The finding in the Allco decision – that 18 C.F.R. Section 292.304(d)(2)(ii) does not permit a utility to impose a formula rate on a QF (see Part I) – should and can readily be eliminated, even if the decision has had only a limited impact to date, as discussed in Part II of this series.
The strongest fix would come from Congress, but whether or not Congress takes action, FERC is free to re-write its regulations to specifically state that a formula rate does meet the requirement. Indeed, FERC is free to eliminate the regulation altogether, as the regulation (in its current form) is not mandated by Congress’ PURPA legislation. All PURPA requires is that the rate for purchases be at avoided cost. A rulemaking on this subject is certainly a possible course of action, whether initiated by state commissions, utilities, or FERC itself. Calls for reform already have been submitted to FERC, and there is little reason for FERC to ignore such calls.
The Allco court’s prohibition on the use of formula rates to satisfy 18 C.F.R. § 292.304(d)(2)(ii), discussed in Part 1 of this series, has not yet had a widespread impact. As long as a state commission permits the utilities that it regulates to negotiate fixed-price (non-formulaic) contracts, the Allco decision should not have a meaningful impact, absent a utility absolutely refusing to entertain any non-formula rate. Only where a state policy, rule, or regulation prohibits a non-formula rate (or a utility refuses to negotiate a fixed rate), is litigation at FERC and the courts likely to ensue. Our expectation is that some additional litigation, attacking the use of formula rates in QF contracts, will continue to occur absent a change in the FERC regulation.
In response to the Massachusetts District Court finding that its PURPA rules were unlawful in the Allco case, the Massachusetts Department of Public Utilities (DPU) opened a new rulemaking docket in March 2017 (DPU 17-54). The DPU solicited comments on proposals for complying with the court’s order in Allco. Comments were received, but no action has yet been taken by the DPU in the docket. Thus, even in Massachusetts, the ultimate impact of Allco is uncertain.
FERC’s PURPA regulations contain a rather serious anachronism. In this three-part series, we identify the problem, as reflected in a federal district court decision (Part I); discuss its impacts to date, which have remained relatively minimal (Part II); and explore whether FERC-led PURPA reform is coming and/or what states can do without federal help (Part III).
FERC’s PURPA regulations state that a qualifying facility (QF) is entitled to a contract (i.e., a legally enforceable obligation) that provides it the option of selling energy or capacity at a rate based on a purchasing utility’s avoided cost calculated at the time of delivery, or the avoided cost calculated at the time the obligation is incurred. The meaning of the latter subsection – “avoided costs calculated at the time the obligation is incurred” – was addressed by a Massachusetts federal district court in 2016 (affirmed by the First Circuit in 2017). The court indicated that a formula rate did not constitute an avoided cost calculated at the time the obligation is incurred as required by the regulation. Such ruling means that QFs (at least in the First Circuit) are entitled to an absolutely fixed price per MWh for their energy. In an era of markets, competition, FERC’s own preference for formula rates, and reduced fuel price fluctuation risk, this view is anachronistic.
Some state net energy metering (NEM) programs cause cost shifts to a degree that perhaps was never intended by FERC. Sun Edison LLC, and MidAmerican Energy Co., remain the seminal cases on how FERC determines whether a wholesale sale of energy has occurred under a state’s NEM program. As explained below, many state commissions may be implementing MidAmerican and SunEdison in a manner contrary to what FERC intended when it decided those cases.
FERC has jurisdiction over all wholesale sales (i.e., sales for resale), although, due to PURPA and its implementing regulations, rates for certain wholesale sales by qualifying facilities (QFs) are set pursuant to state oversight. Arguably, then, any time a NEM customer sells power back to a utility, who would then re-sell it to another customer, such sale would be a FERC-jurisdictional sale or a sale under PURPA, depending on the eligibility rules for NEM customers’ resources. However, in SunEdison and MidAmerican, the Commission held that there may be, over the course of a billing period, either a net sale from the NEM customer to the utility, or a net purchase by the NEM customer from the utility. In both cases, FERC ruled that where there is a net sale to a utility at the end of the billing period, the sale is considered to be wholesale. In short, in these cases, FERC delegated its jurisdiction to determine when a wholesale sale occurred to the states, but indicated that it would defer to the states’ billing period. Because eligibility for NEM programs are typically limited to renewable resources well under 1 MW that are automatically QFs, the state may only mandate a utility to pay an avoided cost rate for such sale, consistent with PURPA.