On February 7, 2024, at the request of the U.S. Department of Energy (DOE), NAESB held a kick-off meeting for the development of a standard model contract to facilitate purchases by distribution owners of “distribution services” from DER aggregators. The idea is for NAESB to develop a standard contract that could be used by distribution owners nationally to allow DER aggregators to sell them distribution services. Unlike Order No. 2222, which mandated participation in ISO/RTO markets by DER Aggregators, whether a distribution owner must purchase services (and which services) from DER Aggregators is a decision that each state commission and local regulatory authority would make on its own. And, each such regulatory body can of course develop its own contracts. Distribution owners could voluntarily opt to use the standard contract for programs as well.

The NAESB standard contract is not designed for sales of demand response, which is logical, given that many distribution owners already have demand response programs in place. Rather, according to a NAESB agenda document, the covered distribution services would include Distribution Capacity, Voltage-Reactive Power, Reliability, Resilience, Energy, and Power Quality. At the kickoff meeting, the fact that sales of energy to distribution owners (i.e., load serving entities) by DER Aggregators would be FERC-jurisdictional and thus energy did not seem to belong in a contract for the sale of state-jurisdictional services was discussed. Energy likely will not be included in the final standard contract, although efforts by some to narrow FERC’s existing jurisdiction over wholesale sales were mentioned.

This NAESB effort, even though it would result in a product that may or may not gain any traction nationally, raises issues similar to Order No. 2222.

One issue discussed at the kickoff meeting was that the NAESB standard aggregation contract should ensure that a DER Aggregator for state-jurisdictional services is not prohibited from serving as a DER Aggregator, presumably for the same DERs, for FERC-jurisdictional services, under Order No. 2222. Although ISO/RTO Order No. 2222 aggregation programs assume that the ISO/RTO will have dispatch control over the DER Aggregator, how exactly a DER Aggregator could be required to follow orders from the ISO/RTO and a distribution owner appears to be an issue outside the scope of the NAESB project. It is unclear how the NAESB standard contract will address dual participation if such dual participation would run afoul of the requirements of participation in an Order No. 2222 aggregation (i.e., by allowing distribution owner dispatch). That said, given that FERC-jurisdictional DER aggregation is quite rare in areas where it is already an available business model (CAISO/NYISO), this is a dilemma that may never need to be solved.

The kickoff meeting did not address the need for the standard contract, as it appears such decision already had been made. But it remains unclear why DERs would be willing to forego existing state programs for a DER aggregation. Participating, for example, in full net metering is far more lucrative, presumably, than selling “distribution services” to a DER aggregator. There may be states willing to permit net metered customers to earn additional revenues, but distribution owners may balk at the cost and argue double compensation is occurring, just as they have in Order No. 2222 proceedings. Moreover, there is a trend in net metering (and other DER programs) to not net kWh but to pay (in credits) a “stack of values” to DER participants, which stack typically includes the equivalent of resiliency or reliability services, as well as future distribution deferral.

Given the vast array of existing state-jurisdictional programs for DERs with many, many different approaches to compensation, NAESB’s task becomes all the more challenging. Depending on what state program, if any, a DER already participates in, likely will govern what, if any, additional “distribution services” it may sell through a DER Aggregator. A one-size fits all contract will not work if DER eligibility for compensation depends on what compensation each DER already is earning. Disputes almost certainly will emerge over double compensation.

Another issue not addressed at the kickoff meeting is that some existing state programs under which DERs are paid to defer distribution capacity additions, compensation often reflects the full cost of the DER (and its operation), such that the value of the sale of energy or other products produced by the DER flows to ratepayers because the DER already has had its cost of service covered by such ratepayers. A state that takes such approach with DERs in an aggregation, would need to prohibit that DER from receiving any additional revenues that do not accrue to the ratepayers that paid for the DER. How the standard contract would address this issue should be considered, but again, compensation schemes could vary widely from state to state.

If a state commission adopts the ultimate NAESB standard contract product for use by regulated distribution owners, careful consideration will be required as to eligibility for compensation, as well as reasonable compensation levels. Utilities also should consider whether they should be seeking changes or clarifications to existing DER programs in order to prohibit DER aggregation that would result in additional compensation for products and services already reflected in existing compensation. Appropriate compensation for DERs, and the impacts of such compensation on ratepayers, remains a controversial topic and will for years to come, given the differentials among states in DER penetration. The Minnesota commission’s recent vote to reduce solar garden compensation reflects this fact.