It has been more than a month since FERC proposed eliminating the state opt-out with regard to retail customer participation in demand response programs in organized wholesale markets. In its NOPR, Participation of Aggregators of Retail Demand Response Customers in Markets Operated by Regional Transmission Organizations and Independent System Operators, FERC proposed elimination of the state opt-out. In the concurrently issued Order No. 2222-A, FERC set aside its earlier finding that the participation of demand response in distributed energy resource aggregations is subject to the opt-out and opt-in requirements of Order Nos. 719 and 719-A. Those states that had opted out are none too pleased, as evidenced by NARUC’s rehearing request filed in response to Order No. 2222-A. The NOPR certainly will draw objections. In contrast, demand response supporters have sought clarification of Order No. 2222-A to ensure that “double counting” does not occur when a DER demand response resource is compensated for acting as a provider of a service, whether procured on a forward-looking basis or in real-time, and reduces an end-use customer’s load on the bulk power system, resulting in retail savings for the customer. These entities seek assurance that a behind-the-meter DER providing wholesale demand response service through serving is own on-site load be compensated at full LMP under Order No. 745.

FERC will certainly defend its change in position based on its view that “the terms of wholesale market participation are a matter under exclusive Commission jurisdiction,” such that its orders “do not infringe upon or otherwise diminish state authority.” It would appear that Order No. 2222-A and the effectively pre-ordained outcome of the new NOPR, would be the death knell of the state opt-out. The question raised here is, does it have to be?

Let’s examine what FERC has said about providers of demand response service. In 2010, FERC told us in Energy Connect that “where an entity is only engaged in the provision of demand response services, and makes no sales of electric energy for resale, that entity would not own or operate facilities that are subject to the Commission’s jurisdiction and would not be a public utility that is required to have a rate on file with the Commission.” So sellers of demand response are not FERC-regulated, even if they sell into wholesale markets. The “product” demand response quite noticeably is not a reportable product on Electric Quarterly Reports, so the sale of product itself is not FERC-jurisdictional. In Demand Response Supporters, FERC noted that use of behind-the-meter generation to facilitate demand response is distinguishable from sales from generation in front of the meter into a wholesale market subject to the Commission’s jurisdiction. These positions seem to leave the states room to regulate both the sellers and the product they sell to retail customers.

Although it is clear that FERC has indicated that any state or local restrictions on wholesale market participation, even if contained in the terms of retail service, would interfere with the Commission’s statutory obligation to ensure that wholesale electricity markets produce just and reasonable rates, there are perhaps actions states can take that allow for participation but remain wholly inside the bounds of state jurisdiction. The question is what can a state commission regulate, if it cannot regulate which resources may participate in the wholesale market? For example, can a state regulate the economics of participation, as long as it allows participation?

One thing that a state can regulate is retail rates. And, just because a retail customer is paid for demand response through a FERC-jurisdictional market should not impact a state’s ability to consider this participation in setting retail rates for the customer. For example, a state can find that a retail customer that participates in a demand response program by agreeing to reduce demand and that fails to reduce demand must be placed on a retail rate schedule that compensates the load serving entity more robustly for having to serve unexpected load. A retail customer that is reducing demand through on-site generation may have to pay back-up rates that appropriately reflect the cost to the utility of back-up service. (If such on-site generation is a QF, the ability of a state commission to assess rates for retail back-up services may be constrained by PURPA. The Alabama PSC recently has been accused of violating PURPA based on its approval of new rates for such service.) Also, a state can assess retail customers “departing load” charges based on prior consumption patterns before joining a demand-response program; such a charge may be justified on several grounds, including avoiding cost-shifting. One gray area is state regulation of third-party aggregators of demand response, as state laws may be unclear as to what types of services render an entity a public utility for purposes of state jurisdiction. Additionally, consumer protection may provide another regulatory option. Also, the product such aggregators sell at retail could perhaps be found to be subject to state regulation.

In sum, states that truly oppose demand response participation by retail customers may still may have some arrows in their quivers. Few states may use such arrows, but if some do, interesting jurisdictional skirmishes may arise.