Trending Topics in Electricity Today: The Value of Demand Response

After the D.C. Circuit Court’s invalidation of FERC Order 745, how can we pay for demand response?

Demand response” happens when electricity customers change consumption patterns in response to the needs of the power grid. Electricity customers can provide a substantial amount of demand response to grid operators without a noticeable effect on their electricity service — for example, by adjusting the set-point of an industrial freezer or a home hot water heater by a degree or two. Aggregate those adjustments over enough customers, and the total becomes a major resource that can be used to manage the grid’s variability in the short-term, to absorb renewable energy generation during times of high output and low load, and to avoid “overbuilding” the system in the longer-term by cutting down peak demand.

In 2011, in response to the clear value of demand response, FERC issued Order 745 to place it on par with generation in electric energy markets. FERC’s order stated that grid operators should compensate demand response resources that provide a “net benefit” at the “locational marginal price” of generation in the same area. This gave the electricity markets access to a new cost-effective resource and contributed to the development of demand response in capacity and ancillary services markets. Increased access to low-cost demand response proved extremely valuable; for example, when PJM qualified demand response to participate in its capacity market, prices dropped 85 percent in one year.

But this past May, a 2-1 majority on the D.C. Circuit Court vacated FERC Order 745, declaring that FERC lacks the jurisdiction to compensate retail customers for reducing consumption. While the Court did not dispute the benefits of demand response for electricity prices, nor its ability to provide the same type of service as generation, the Court found that Order 745’s compensation mechanism interfered with the “retail market” relationship that is exclusively under the purview of states. FERC petitioned for “en banc” review, aiming to get the case in front of the full 11-person panel of judges, but that petition was rejected in September. It is unclear whether the U.S. Supreme Court will review the case.

Leaving things somewhat ambiguous, the Court declined to explain which entities, if any, may continue to participate in a market for demand response. The ruling makes it clear that FERC itself may not circumvent state jurisdiction over retail markets by ordering ISOs/RTOs to directly pay customers for demand response; instead, only states can set compensation levels for customers who provide demand response. This finding is grounded on the Court’s holding that demand response is solely a “retail product,” an assertion the dissenting judge contested. The ruling also leaves open the question of whether ISOs/RTOs may voluntarily accommodate the sale of demand response on the wholesale market in the case that it is entirely outside the jurisdiction of FERC.

So, what can be done to enable demand response to continue to provide reliability, affordability, and environmental benefits to consumers? Scott Hempling, an attorney and expert on FERC jurisdiction, outlined several potential actions that states or ISOs/RTOs may be able to take now to support demand response despite the ruling:

  1. States can call on utilities to become retail load managers without any resale into the wholesale market. (Note that this likely leaves substantial value on the table.)
  2. States can call on utilities or third parties to act as aggregators of demand response and resell to the wholesale market. (The ruling is somewhat ambiguous on whether or not this is possible.)
  3. With state approval, the wholesale market operator can independently open and operate a market for demand response outside of FERC jurisdiction. (This is not unprecedented, as Renewable Energy Credit markets are not FERC jurisdictional.)

Because of the lingering questions about the scope of the D.C. Circuit Court’s ruling, some of these suggestions are likely to be the subject of further litigation. However, they provide examples of proactive ways to keep paying demand response providers for the value they deliver. In addition to considering the proposed schemes outlined above, states can also initiate stakeholder discussions about how to address demand response in light of the Court’s ruling, bringing together the regional wholesale market operator with the utilities, demand response aggregators, customers, and regulators.

What have states and RTOs done to preserve demand response after the D.C. Circuit ruling?

New York’s Public Service Commission (NY PSC) and PJM have both taken proactive steps to preserve demand response in spite of the ruling. Here’s what they’ve done:

New York
New York’s “Reforming the Energy Vision” proceeding (described in a previous blog post) recognizes that distributed energy resource optimization is essential to ensuring just and reasonable rates. New York’s vision would transform utilities into “Distribution System Platform” (DSP) providers, encouraging them to look across all options — including demand response — to optimize the distribution system. With a DSP at the core, there are vast opportunities for demand response to meet local grid needs outside of FERC jurisdiction.


To start, the DSP will compensate demand response for the value it provides on the local distribution grid. The question remains how the DSP can monetize excess demand response (and other distribution-level resources, for that matter) aggregated within its footprint. Although it’s unlikely FERC will ever be able to set a price for demand response, the NYISO could consider compensating utilities—rather than directly compensating customers—for bids that shift regional load to when and where it is needed most, although this could still be invalid if ISOs/RTOs are disallowed from purchasing demand response at all under the ruling. This framework has yet to be litigated and the D.C. Circuit leaves room for either interpretation. New York’s regulators may also consider creating a separate, non-FERC-jurisdictional marketplace for demand response wherein utilities can trade excess demand response capabilities with one another. In any case, the NY PSC is being proactive about reforming its approach to demand response and is opening a stakeholder process in response to the D.C. Circuit ruling that includes the NYISO, utilities, and state regulators. (See New York’s Straw Proposal, page 63.)

PJM Interconnection is the country’s largest existing consumer of demand response, and thus the most exposed to the D.C. Circuit ruling. Earlier this month, PJM published a white paper outlining its proposal to maintain a market for demand response while acknowledging the limitations of its procurement strategy under the Court’s invalidation of Order 745. PJM’s proposal is admittedly cautious and keen to avoid risking litigation, but the RTO does provide some concrete steps for other wholesale market operators that may be considering their options.

PJM proposes that it will stop compensating demand response via locational marginal prices (LMPs), effectively removing its status as equal to generation. Instead, PJM proposes that it will credit load-serving entities (LSEs) for demand response by reducing their capacity obligations under reliability rules. This shifts the burden of procuring demand response to state-regulated utilities, avoiding the issues raised in the D.C. Circuit’s ruling. Because PJM is no longer compensating customers directly for demand response, they are no longer regulating retail markets. It is important to note, however, that LSEs are unlikely to be motivated to bring demand response online, and may even be incentivized not to pursue demand response if they own generation assets.

This reduction in reserve capacity obligations would reduce the total amount of capacity required on the bulk system, lowering procurement costs for utilities and their customers, without interfering directly with retail rates. PJM’s proposal also removes demand response from the capacity market, but PJM asserts that the ancillary services market (traditionally exclusively under wholesale market control) is likely unaffected by the D.C. Circuit ruling.

The extent to which PJM’s new procurement scheme will reduce costs is unclear. Navigant found that removing demand response from PJM’s capacity market would cause prices to triple. Scott Hempling and others have suggested that FERC could make the case that exclusion of cost-effective demand response cannot result in “just and reasonable” wholesale rates, and could even order wholesale operators to accept demand response bids from wholesale purchasers (e.g. distribution utilities) rather than retail customers. Given that such a case could be made, PJM’s proposal may be considered conservative, but it does provide one framework for ensuring some amount demand response has the chance to stay on the system.

It remains to be seen how exactly the issue of demand response compensation will play out, but one thing remains abundantly clear: demand response provides value to the grid, we just need to rethink how we pay for it.

This blog was written by Michael O’Boyle, Sonia Aggarwal, and the experts of America’s Power Plan. Thank you to Allison Clements, Jon Wellinghoff, Katherine Hamilton, and Scott Hempling for their input on this piece. The authors are responsible for its final content.

The original version of this piece is available here.

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Sonia is the Director of America's Power Plan, a project of more than 150 top energy experts from academia, industry, and non-profits who have come together to address the challenges associated with our nation's power sector and help inform policy-makers about proper solutions for the future. Sonia is also Director of Strategy at Energy Innovation: Policy and Technology LLC, an energy and environmental policy firm that delivers high-quality research and analysis to decision-makers to make informed choices on energy policy. Her work at Energy Innovation spans wholesale power market structures, utility business models, grid operations, innovation policy, and quantification of policy impact.

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