In the past few months there have been a few events that merit a word, but few true surprises. It has become clear that there will be significant delays in the implementation of DER aggregation in some ISO/RTO regions. The complexities of aggregation are numerous and it appears that various regions will adopt a variety of approaches. Perhaps one of the most crucial topics will be the maximum size of a single DER in an aggregation, which may vary widely among regions. One minor surprise of the last few months may be the ease with which utilities seeking relief from the PURPA must-purchase obligation from 5 MW – 20 MW small power production facilities have been obtaining such relief. The relief has come easily due to a near total lack of protests of filing seeking relief.
As to specific DER/PURPA matters that have occurred at FERC over the last few months:
Broadview (Second Rehearing). Having reversed course on March 19, 2021 by setting its September 2020 Order, FERC upheld its “what’s old is new again” position in the second Broadview rehearing order. FERC determined that its “send out” approach to measuring a small power production facility, which had been in effect prior to the September 2020 Order, should be retained. On rehearing, FERC was addressing once again how to measure the power production capacity of a novel facility whose generating subcomponents (e.g., solar panels) had a nameplate capacity of greater than 80 MW, but that was physically incapable of producing more than 80 MW for sale to the interconnected electric utility at any one point in time and chose to measure “the maximum output that the facility as a whole can produce for the electric utility after accounting for all the constituent parts that make up the facility, which in this case includes the inverters.” This measurement issue ultimately is one for the courts to decide. That said, Congress should step in and determine whether batteries (and other storage systems) can or cannot be included in determining the “power production capacity” of a facility because, they do not “produce” power but simply store it for delivery at a later time. It is not clear that Congress ever contemplated storage in setting the 80 MW maximum size for small power production QFs and thus this question is much tougher for a court to answer. Given the Broadview facts, the reviewing court can ignore this issue on appeal given that the solar generating facilities were over 80 MW. But, the notion that storage should not count at all would mean that a facility could “send out” more than 80 MW at an moment and this approach may have to be addressed by FERC as well.
Order No. 2222-B. In Order No. 2222-B, FERC reversed, or at least slowed its course, on the heated opt-out issue, setting aside the decision in Order No. 2222-A to decline to extend the opt-out requirement of Order No. 719 to demand response resources participating in heterogeneous DER aggregations. Demand resources in states that have opted out, will have to await and see if the Commission reverses course on the Order No. 719 opt-out altogether in the notice of inquiry proceeding (Docket No. RM21-14), a result urged by Commissioner Chatterjee. FERC was provided several bases for reversing itself by parties – lack of jurisdiction, lack or adequate notice, and lack of reasoned decision-making in departing from existing policy. The Commission chose to justify its reversal based largely on a lack of notice to impacted parties may not have anticipated that this proceeding would call into question the prohibitions in Order No. 719. FERC indicated a desire for an opportunity for all interested views to be heard and considered. FERC reaffirmed its claim of jurisdiction, noting that “EPSA held that the Commission’s regulation of demand response participation in wholesale markets is a practice that directly affects wholesale rates.” That said, such justification is weakened by the fact that “practices” that directly “affect” wholesale rates, such as demand response, can be subject to state regulation and the “affects” clause may be limited in such cases. Using the “affects” clause to regulate “practices” that were intentionally left by Congress for the states or another federal agency to regulate is somewhat concerning. If for example, FERC were to argue that local gas distribution company rates affected wholesale electric market prices would it be permitted to use the “affects” clause to alter state-set rates, practices, or policies of LDCs – certainly not. If a state has legal authority to regulate demand response, the difference in these examples is difficult to discern. Indeed, FERC’s view of its role in demand response seems to rest heavily on the concept of negative (wholesale) generation being a “product” over which it has jurisdiction under the FPA. Negative generation should be called by its proper name – “load.”
Alabama Retail Rates for QF-owning Retail Customers. Given that FERC itself has almost never enforced PURPA, its intent not to act order in Docket No. EL21-64 came as no surprise. There, Alabama retail customers that owned QFs complained that the Alabama PSC (APSC) had adopted a retail rate rider in violation of PURPA. The rider includes certain charges that allowed Alabama Power Company to recover the fixed costs associated with its generation, transmission, and distribution infrastructure required to provide partial requirements customers with reliable power when their own (PURPA) generation is not operating. The complaining parties argued that the rider: 1) was not based on accurate data showing a difference in cost to serve customers who have adopted on-site solar; 2) included charges based on lost revenues rather than on cost-of-service principles; 3) applied a different pricing policy to QFs than non-QFs with similar load patterns for collecting demand costs common to the rate class from customer; 4) charged for non-requested back-up services; and 5) relied upon unreasonable and unsupported assumptions regarding forced outages of customer-sited systems. The APSC defended its approval of the rider on the grounds that it prevents undue discrimination by remedying the subsidization of customers with interconnected on-site generation (partial requirements customers) by full requirements retail customers. As indicated by the concurrence, at least two Commissioners believed the rider might violate PURPA and highlighted perceived weaknesses in the APSC’s technical defense of the rider.
The issues raised are directly analogous to the net metering conundrum now being addressed by some states. If full retail net metering reaches a saturation point such that it is no longer sustainable, how should retail customers with behind-the-meter generation be compensated? If a state has both net metering for smaller QFs and allows real-time netting for larger QFs, perhaps it is easiest to replace all such programs with a buy-all/sell-all regime under PURPA. Such a regime may still result in a protracted fight over avoided cost rates for the sell-all side, but dual programs (monthly net metering for customers with small QFs and real time netting for those with larger QFs) results in a multitude of fights – over net metering compensation, avoided cost compensation, and back-up/standby rates for QFs. Buy-all/sell-all regimes for all retail customers condense the many possible and quite acrimonious issues to a single issue – setting avoided cost rates. And, that is an area in which states have fairly broad discretion.