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A Buyer's Market
Getting the most from demand response—despite a flawed FERC rule.
On March 15 the Federal Energy Regulatory Commission (FERC) issued the long-awaited and controversial rule on demand response (DR) compensation—Order 745.1 As anticipated, the rule held that “comparable” treatment for DR resources with generation requires that they receive the same compensation, the locational marginal price (LMP). The justification cited was this syllogism: that if decreased demand had the same effect on power markets as increased supply, and if supply is paid LMP, then demand response should be paid LMP.
By contrast, several regional market organizations, PUCs and independent economists held that fair economic compensation requires subtracting the retail rate (G) to account for the benefit that load already receives by not paying for energy it doesn’t consume. In this view, full LMP compensation discriminates against real-time pricing customers, whose only benefit from curtailing is avoiding payment of LMP. Accordingly, (LMP – G) compensation equalizes treatment with real-time pricing customers while full LMP compensation distorts markets and creates opportunities to game the system.
These concerns are legitimate. However, with some care it actually might be possible to implement full LMP compensation for demand response without distorting markets.
Over the objection of nearly all commenters, the order requires a net benefits test limiting the hours in which DR bids would be accepted. This test would ensure that total compensation to DR providers never exceeds the benefits enjoyed by load from reducing LMPs, by restricting DR events to the highest peak hours of a year. Demand responders asserted their service was nothing at all like traditional utility peak-shaving, while generators and independent commenters asserted the test was an artifact of the excess compensation proposed, but that with the economically correct compensation (LMP – G), no restrictions on hours would be required. Grid operators expressed concern that implementing the test added a significant administrative burden. Sensitive to this issue, the rule simplified implementation by allowing regional markets to set a monthly trigger price for DR events.
The New England Conference of Public Utility Commissioners (NECPUC) had advocated limiting hours using a benefits test because compensation at full LMP creates a “missing money” problem. As the cost of “negawatts” is borne by load consuming a reduced quantity of megawatts, without a limit on hours more could be paid to demand responders than saved by load through reduced LMPs. Furthermore, with DR allowed during all hours at full LMP compensation, a customer can game the system by shifting load from one shoulder hour to another without creating a system benefit.
Applying such a test for New England, NECPUC estimated that in 2008, DR would be restricted to the highestpriced 8 percent of annual hours. With the decline in power markets since then, this condition has occurred far less often, so many DR aggregators have been signing up customers to receive free money—capacity payments customers collect with the expectation they rarely will be called. By contrast, generators have incurred substantial fixed costs whose recovery is impaired