• Slow Down/Permit Flexibility on Timing. Several of the RTOs/ISOs provide FERC reasons why it needs to slow down its desire to have DER aggregation processes in place. The reasons range from the mere time it will take to implement such processes in a well-thought out manner with the right technology (which technology may not be readily available today) (NYISO, MISO, ISO-NE) to the fact that the demand for participation through aggregation is just not there (MISO, ISO-NE). Although the CAISO already has an aggregation process in place, it is not being used, and while blame for that is debatable, this fact supports the general theme that time is not of the essence. PJM’s comments indicate that it is fairly well-prepared for DER aggregation in light of existing DER participation, but also indicate that many questions need to be answered before it and its stakeholders can implement a workable program. ISO-NE does not believe adequate tools exist yet for implementation. MISO believes DER integration and aggregation needs to be accomplished over a time period that is consistent with other reform efforts that may have a higher priority.

• Eligibility Should Be Left to RTOs/ISOs. The notion that any size or type of DER could participate in the wholesale market through an aggregator is not accepted by the RTOs/ISOs. NYISO, for example, envisions that only dispatchable DERs be permitted to participate. PJM prefers to limit DER participation to non-load curtailment DERs, given that demand response programs serve such entities. PJM would largely limit the size of DERs in an aggregation to 100 kW. CAISO’s existing rule (DERs in an aggregation limited to 1 MW) is intended to largely limit aggregation to DERs who cannot participate directly in the market. Similarly RTOs/ISOs prefer DER aggregations be limited in size (PJM 1 MW, CAISO 20 MW) for a variety of reasons. The RTOs/ISOs have a clear message: a Final Rule should set no minimum or maximum size requirement and permit eligibility rules (dispatchability, metering/communications requirements) should be set by the RTO/ISO.

• The Distribution Owners’ (“DO”) Role. All the commenting RTOs/ISOs recognize the role of the DO as crucial to the DER aggregation process whether commercially, operationally, or both. Indeed, RTOs/ISOs generally appear to consider such role much broader in scope and substance than the Commission’s questions imply. The CAISO recognizes that DOs must have procedures in place for reliable operations and describes a need for “deep coordination.” One of ISO-NE’s main concerns is whether DOs will have time to react to RTO/ISO dispatches. PJM recognizes the need for DOs to be the gatekeepers for dealing with double-compensation issues and observes that they have a role related to coordinated registration and interconnection. NYISO acknowledges greater coordination will be needed between it and DOs and it wants DOs to review all DERs in an aggregation as to reliability issues. MISO calls for careful collaboration with the DOs. The PJM Independent Market Monitor (“PJM IMM”) supports maximum coordination.

• Dual-Use Issues Must Be Addressed. One reason for the need for FERC to permit flexibility in timing is the complexities involved where DERs may be participating in both state-jurisdictional compensation programs and a DER aggregation. Developing rules and policies, on a state-by state-basis, for the non-single state ISOs, will take significant effort as this is an area in which both jurisdictional and practical issues arise. The CAISO observes that a DER may only want to be available at certain times to its aggregator. NYISO acknowledges that it will need to be aware of any dual uses by a DER in an aggregation. One of the primary issues recognized by many of the RTOs/ISOs is who has final dispatch control over a DER providing services both to a DO and an RTO/ISO.

• Single Node Versus Multiple Node Aggregation – An RTO/ISO Decision. The issue of whether aggregations must be comprised of resources behind a single node or multiple nodes likely will depend on existing market structures and thus flexibility is needed. The PJM IMM’s strong objection to a multi-nodal concept is notable, given that PJM itself sees multi-nodal aggregation as possible, although its presents tough issues. The CAISO has developed its own “sub-LAP Aggregation Point” approach. NYISO similarly is working on its own approach using a single unique point identifiers, which is not multi-nodal.

Commentary: The ISOs/RTOs have made a strong case for significant flexibility in developing an aggregation program and in the timing of when such a program is needed. Perhaps one of the most salient observations about the RTO/ISO community’s comments was the Southwest Power Pool’s apparent decision not to file comments. This omission seems to indicate that, as ISO-NE observes, there may not be significant interest in DER aggregation in some regions. The lack of interest in higher-cost regions (e.g., ISO-NE) can be explained by the fact that demand response and net metering may be better options for small DERs, and larger DERs have other avenues for (at least) market compensation as a result of the Storage Final Rule or under PURPA. In lower-cost regions (e.g., SPP/MISO), lack of interest can be explained by a lack of DER penetration. The CAISO alleges the DOs’ interconnection processes as one reason, among others, that DER aggregation is not occurring today, without mentioning as other reasons for the lack of interest the facts that California’s net metering law has no size limitation (and provides compensation at the retail rate) and that the existing demand response aggregation program also provides significant compensation. Several of the issues that the RTOs/ISOs raise may be contested by DOs. For example, PJM assumes that a NEM customer has reserves to sell to the wholesale market; a DO may contest that its compensation to a NEM customer entitles it to sell such reserves. Stakeholder processes will have to deal with such contentious issues.