PURPA NOPR: Why All the Fuss?

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. Fixed Capacity and Floating Energy A/C Rates for QFs with LEOs For many years, FERC has implicitly and explicitly permitted several state commissions to adopt PURPA pricing rules under which energy prices were formulaic in nature – the CPUC’s short-run avoided cost rate for energy and New England states commissions’ adoption of locational marginal cost pricing for energy (LMP). The decision in the NOPR to explicitly permit floating or formula energy prices does not undermine PURPA, for the simple reason PURPA never said such prices had to be fixed. Rather, the decision, if adopted, reverses decisions disallowing such rates in at least two key regions Allco (First Circuit) and Winding Creek (Ninth Circuit). Both cases indicated FERC’s existing regulations must be interpreted to mean a price set at the time of a LEO had to be fixed and that a formula rate was not a fixed rate. The NOPR proposes to return the status quo before these two cases. Several of the state commissions impacted by the two court decisions have been moving somewhat slowly to replace their existing floating rate PURPA programs and may choose to await the outcome of this rulemaking before abandoning their existing programs. Other states may continue to encourage QFs by retaining fixed energy rates in an era of generally declining costs. This proposed change, if adopted, may have fairly minor impacts. LMP, Market Hub, Combined Cycle, and Other Options for QFs Selling As-Available Energy Again, states have been relatively free to set prices for as-available energy, and several New England states had been using LMP for many years. In 2016, the New England Small Hydro Coalition was complaining to FERC that “Connecticut, New Hampshire and Massachusetts, have determined that the avoided cost rate is the hourly real-time LMP.” The various options that the NOPR sets forth as acceptable are nothing new. What is actually notable about the NOPR’s proposed flexibility to set QF rates for as available energy for utilities outside RTOs and ISOs is the lack of any discussion of CARE v. CPUC. There, the Ninth Circuit held that “[w]here a utility uses energy from a QF to meet the utility’s [renewable portfolio standards] obligations, the relevant comparable energy sources are other renewable energy providers, not all energy sources that the utility might technically be capable of buying energy from.” This ruling covers a very significant portion of the country not in RTOs and ISOs, and many states that have renewable portfolio standards. The fact that FERC did not address the order directly (by overturning it or reflecting it in its regulations) is surprising. RFPs for Setting A/C Rates The notion of using RFPs for setting avoided cost rates and to determine if capacity is actually needed is not a new concept as the NOPR makes clear. There are simply right and wrong ways to go about issuing and implementing such RFPs and the NOPR proposes to codify what is or is not permissible. The One-Mile Rule It is unclear from the NOPR whether the one-mile rule will remain, or whether it will effectively become a ten-mile rule. The answer to that depends on how the rebuttable presumption is enforced. Interpreting how to measure a mile (or ten miles) is mere tweaking on the edges, and the interpretation proposed is logical. This issue is more pressing for non-ISO/RTO utilities, but they are often located in states where sufficient land exists for developers to spread QFs out by ten miles, if necessary. The much more interesting aspect of the one-mile rule is its impact combined with the proposed 1 MW rule for eliminating the renewable QF purchase mandate and the leasing model some companies that install solar PVs use. If a solar company leases thousands of PV systems in a new neighborhood, could this impact the ability of the residents to obtain compensation for “excess” (i.e., excess at the end of a set period such as a year or the end of the resident’s retail account) net metered energy under PURPA? The Commission may treat the retail customer that owns the PV’s output, but not the PV system, as a separate entity from the lessor and leave such state programs alone. This is an issue that may have to be litigated. The Presumption of Market Access for > 1 MW Renewable QFs Almost certainly, the proposal to reduce the PURPA 210(m) presumption of market access from 20 MW to 1 MW for renewable QFs will be among the most controversial aspects of the NOPR. Claims of a lack of sophistication of smaller QFs arguably are undermined by the rapidity with which and number of such QFs that swoop into generation queues when a stale avoided cost rate for small QFs is spotted. The differing treatment of cogeneration, based on the fact “owners of cogeneration facilities might not be as familiar with energy markets and the technical requirements for such sales” is unsupported. That said, whether cogeneration, the installation of which has remained fairly flat for years, “picks up steam” remains to be seen, as many states with utilities subject to the 20 MW rule for cogeneration purchases are trying to eliminate fossil fuel use altogether. Indeed, there likely will be a lawsuit in the next decade or so as to whether a state can refuse to site any cogenerator on the grounds that it burns fossil fuel. My bet is New York or California will be the locus of this litigation. As to the concern expressed by some that, if adopted, the 1 MW limit will be the death of small renewable QFs, a funeral may be premature. States may and have adopt procurement requirements that oblige regulated utilities to purchase from renewables sized between 1-20 MW or take other similar measures, as long as they do not compel purchases at a state-set price. States can penalize utilities for not meeting procurement targets. Indeed, in California, most QFs between 3-20 MWs are not selling power pursuant to PURPA, but pursuant to the Renewable Auction Mechanism (“RAM”). The RAM has changed over the years, but is an example of how a state can ensure purchases from smaller renewables without invoking PURPA, even if FERC adopts the NOPR proposal. Whether such policy is beneficial for ratepayers, as compared to renewable solicitations comparing delivered prices across all sizes of QFs, is matter that can be debated, but for those states that see value in small renewables, the NOPR, if adopted, is not a death knell. The “access to markets” for 1 MW to 20 MW renewable QFs may actually result in case-by-case FERC litigation regarding the ease of obtaining FERC-jurisdictional interconnection and wholesale distribution service from particular utilities as to distribution-located QFs. (There is no reason to expect 1 MW to 20 MW renewables will not obtain QFs status even if the purchase mandate is eliminated; they will do so to avoid rate regulation.) The California utilities’ two-decade old wholesale distribution (including interconnection) tariffs may well situate them for such litigation. Utilities in ISOs or RTOs that view such QF interconnections as subject to ISO/RTO interconnection procedures because they are FERC-jurisdictional, also may be in a better position than other utilities, although distribution owners in such ISOs/RTOs will still have to offer wholesale distribution service as to such QFs. The LEO Standard Proposal Whether the NOPR’s proposal on the LEO standard is pro-utility or pro-QF is entirely dependent on the current state of affairs in a particular state, assuming a state has adopted a LEO standard to begin with. Rather obviously, FERC is seeking to overturn Power Resource Group, Inc., v. Public Utility Commission of Texas, allowing ERCOT to require a QF to be 90 days from operation to establish a LEO, and its New Mexico imitation. In a few states, the new standard will be a win for QFs, in many states it will likely leave the status quo in place, and in a few states, it may benefit utilities. That said, unless a state decides to retain fixed energy prices, the date of a LEO loses much of its importance. The Retail Load Reduction Proposal One of the most intriguing aspects of the NOPR is its proposal to provide that the PURPA purchase obligation may be reduced to the extent the purchasing electric utility’s supply obligation has been reduced by a state retail choice program. How such provision would be implemented by the states is quite unclear as there is little guidance in the NOPR. Arguably, in states where retail load is served wholly through competitive bidding, a utility may no longer have any PURPA obligation at all. Thus, this provision, may have quite profound implications for those (very few) states where state-run procurement schemes are in place for retail load and the utility has ceased the provision of energy to load. If this proposal is adopted, it likely will prove quite controversial. In states with community choice aggregators (CCA), it could eliminate significant quantities of QF purchases, unless the states adopt and apply resource procurement targets to CCAs that largely replace PURPA programs. An appellate court challenge to this provision also seems likely. Conclusion In sum, if the NOPR is adopted, the impacts may not be as profound as feared or as desired. The reality is that PURPA has not been the primary driver of either renewables or cogeneration for at least a decade or more. The NOPR’s statement that since 2005 QFs have made up only 10 to 20 percent of all renewable resource capacity in service in the United States shows that state policies and economics have and will play a much more important role than PURPA in shaping the resource mix of the future.