FERC has issued its third and fourth orders on initial compliance attempts with Order No. 2222, covering PJM and ISO-NE. Many of the holdings reflected compliance policies similar to those adopted in the prior NYISO and CAISO orders (summarized previously Part 1, Part 2, Part 3, Part 4). This analysis thus will focus on unique findings, new precedent, and otherwise noteworthy matters.

PJM Compliance Filing Order

Double-Counting. It is remarkable that FERC made two unremarkable findings with regard to net energy metering (NEM) programs under which DER owners are compensated at the full retail rate. First, FERC found that such DERs cannot participate in PJM’s capacity market (largely due to the must-offer energy requirement, but perhaps also recognizing that they would be compensated twice for capacity under such a full retail NEM program). Second, FERC acknowledged that DER owners in full retail NEM programs actually are compensated for ancillary services that they do not even provide and that paying them for ancillary services, assuming they could provide them, would be double counting. The point that DER owners in full retail NEM programs could not possibly earn wholesale compensation in energy, capacity, or ancillary services markets that was not double compensation is a point electric distribution companies (EDCs) have made for years, but this is the first time that FERC has expressed a clear understanding that NEM participants already may be compensated for a large range of products, let alone acknowledged that participants are compensated regardless of whether or not they actually provide such services. Although further clarity will result on compliance, the decision reflects a breakthrough of sorts, as previously FERC refused to explicitly acknowledge that NEM customers in California might be receiving compensation for ancillary services. The fact that the Pennsylvania PUC expressed concern over double counting as to ancillary services in particular perhaps swayed FERC into recognizing the level of compensation offered by some NEM programs. (Of course, it is this level of NEM compensation that largely renders Order No. 2222 meaningless as to some DERs.)

EDC Review. The PJM decision also was notable as to the ferocity with which FERC rejected the notion of giving EDCs more than 60 days to review DER Aggregations, unless the RTO/ISO itself indicates exceptions may be necessary. Although PJM’s pre-registration process was not rejected, the role of the EDC in that process must be reformed and its clear that such process cannot include any EDC review, given PJM’s 60-day EDC review period that is part of the registration process.

Locational Requirements. FERC appeared disbelieving of PJM’s justifications for a single node approach for energy market participation and has sought a change or a better explanation. Given that several other RTOs/ISOs are seeking only single node aggregation, this issue likely will get more attention.

ISO-NE Compliance Filing Order

BTM DERs Metering and Double Counting. The proposed treatment of behind-the-meter (BTM) DERs drew quite a bit of attention from FERC, which found that ISO-NE’s proposal to require measurement of BTM DERs at the retail delivery point, unless the Assigned Meter Reader can accommodate submetering or parallel metering of the DER was not just and reasonable, as it created barriers to entry. Protesters had asserted that measurement at the RDP is a barrier to participation for BTM DERs because it obfuscates actual DER performance for purposes of wholesale market participation and that parallel metering is impractical and costly. ISO-NE argued that metering at the RDP, parallel metering, or submetering combined with reconstitution comprise the universe of metering options of which ISO-NE is currently aware that address double counting. In her concurrence, Commissioner Clements observed that “one comes away with the impression that developing a workable participation framework for behind-the-meter DER is nearly impossible.”

A closer examination of the issue, as relates to customers with on-site BTM DERs and retail load that are not participating in a demand response-only DER Aggregation, reveals that the ISO-NE is assuming that a BTM DER is participating in the wholesale market with its gross, rather than net, production. For example, in its pleadings, the ISO-NE made the point that paying behind-the-meter generator based on its directly submetered output while also billing the customer based on its lower RDP (i.e., retail) meter reading would result in double counting. This fact was the main reason behind ISO-NE’s metering proposal. But there is no double counting at all, if the BTM DER serves its on-site retail load first, and then sells its net output to the DER Aggregator. And, the BTM DER owner likely would ensure that the DER Aggregator can only dispatch the BTM DER to sell its net output. The ISO-NE instead assumes a BTM DER would choose to not serve its on-site retail load before selling any power to the wholesale market, an economically irrational decision unless wholesale market prices reach up the $100s/MWh. That is, BTM DERs are typically installed to reduce on-site load, with net energy (or other services) being sold at wholesale. The notion of a BTM DER selling its gross energy is illogical in nearly every hour of the year. (A BTM DER could be connected to an EDC that mandates a “buy-all, sell-all” structure (an unusual, but not unheard of approach that disallows all netting), but in that case, the proper metering would already exist.)

One question raised by FERC is why did other RTOs/ISOs seem not to have the same issue? There is no evidence that the issue of a BTM DER choosing to sell its gross production would not be a major problem in every other ISO/RTO (again, ignoring demand response BTM DERs). Rather, no other ISO/RTO has assumed the BTM DER is selling gross output, so the issue has not arisen. No one has needed to develop a framework for gross sales because presumably no one would take the economically illogical step of turning over control of their gross energy production to a DER Aggregator, if in nearly all hours, the retail price of electricity exceeds the wholesale price of any market service. Indeed, CAISO has had DER Aggregation for years, but due to net metering, where BTM DERs of all sizes may net, the DER Aggregation program is basically uneconomical for BTM DERs. In NYISO, BTM DERs would presumably sell their net output to the DER Aggregator, avoiding this issue. (And, there is evidence that the New York EDCs expect BTM DERs to choose this net option.)

In sum, the ISO-NE should be able to accommodate BTM DERs that own generators selling only net production, as is typical. If a BTM DER truly intended to sell on a gross basis, the ISO-NE is correct that the metering, billing, and accounting are all quite difficult absent an EDC that already prohibits all netting and meters accordingly. Of particular concern, if FERC believes that BTM DER owners should be able to switch between selling net production at wholesale to selling gross production at wholesale (i.e., selling gross when wholesale prices rise to the $100s-$1000s/MWh), such an approach inevitably would require either resource-intensive manual workarounds and/or expensive (and yet-to-be-developed) metering. Only if the BTM DER bore all such costs, would such approach be equitable to other retail customers. Perhaps ISO-NE explaining to FERC that BTM DERs that are netting on-site retail load can be accommodated could largely solve the perceived problem.

Although the above discussion does not apply to BTM DERs in the form of demand response, Order No. 745 seemingly already addressed the relevant issue. Under Order No. 745, in circumstances in which the net benefits test is satisfied, paying the LMP to BTM DERs participating as demand response resources, without reflecting the savings load realized from not having to purchase electricity, does not reflect a double payment, according to FERC. In contrast, under Order No. 2222, If the BTM DER resource participates as another type of DER (i.e., not as a demand response DER in an aggregation of only demand response DERs), the requirements in Order No. 745 would not apply. In the case of a heterogeneous aggregation, the same problem discussed above admittedly exists because the load served is not entitled to a highly significant benefit of Order No. 745. But, that fact merely raises the issue of why would a demand response DER participate in a heterogeneous DER Aggregation when far more favorable compensation is available through a homogeneous demand response DER Aggregation?

Clements’ Concurrence (ISO-NE)

Clements’ view is that participation of BTM DERs in ISO-NE markets is being completely stymied and reliability is threatened by the issue discussed above – an issue that may very well be non-existent. She mentions Massachusetts and other New England states having aggressive DER goals. One question raised by her dissent is whether Order No. 2222 is actually needed to meet these goals or whether these goals already are being met outside of Order No. 2222. According to the EPA’s State Energy and Environment Guide to Action: Interconnection and Net Metering, issued in 2022, Massachusetts “is a national leader in net metering policy and in the amount of total net metered energy sold back to the utility, which in 2020 was 717 GWh.” According to the EPA, this was “approximately 28 percent of all net metered energy sold back in the United States (EIA 2020).” Moreover, the ISO-NE adopted a new policy allowing small generators to serve as wholesale load reducers by not participating in the wholesale market. Commissioner Clements’ dissent ignores that Order No. 2222 is not the only way to encourage DERs. Indeed, many BTM DERs have state-mandated options that both provide more compensation and eliminate any middleman, and thus are more encouraging of BTM DERs than Order No. 2222. For now.

Christie’s Dissents

Commissioner Christie voted against both orders, despite voting for the CAISO and NYISO compliance orders. (One possible reason that he failed to dissent earlier is that CAISO and NYISO had adopted DER Aggregation voluntarily prior to Order No. 2222 being issued.) Commissioner Christie pointed out in his dissents that the problems and complexities of complying with Order No. 2222 are extreme and the costs enormous. His conclusion in the PJM order is that Order No. 2222 will haunt the RTOs and RERRAs, the reliability of the grid, and the pocketbooks of consumers for a very long time. Although legal/regulatory implementation costs are high, if states continue to use NEM, PURPA programs that ask EDCs to voluntarily pay above avoided cost rates, and other programs that provide more value to energy-producing DERs than the wholesale market, Order No. 2222 will be largely irrelevant. Costs may not be as high as feared if participation is largely non-existent. That said, there is a limit to the degree to which states can use such types of programs before cost shifting renders them unworkable and they are reformed so that DER owners are relegated to earning compensation that more accurately values the services they provide. (As noted, the Pennsylvania PUC quite unabashedly admitted that it pays DERs not only for energy, but for the transmission, capacity, ancillary services and distribution components of retail rates as compensation for the energy produced.) Once state-mandated DER compensation is more accurate, participation in the wholesale market through DER aggregation may become more appealing. But even smaller state subsidies, such as compensating NEM customers for excess energy under a value of solar program, may continue to pay well more than the wholesale market price, less a cut for a DER Aggregator.

One leaves the newest compliance orders with the impression that a fulsome understanding of the direct connections between state DER programs (including NEM), Order No. 745 demand response aggregation programs, and Order No. 2222 aggregations and how, whether, or why a DER may choose among such options does not yet exist. Given that there may be as many different such connections as there are states with at least one ISO/RTO member, renders obtaining such an understanding difficult. Such direct connection also may result in retail customers paying Order No. 2222 implementation costs when Order No. 2222 DER Aggregations will not be an option that is economically logical for DER owners.