Utility CEOs debate the merits of a retail surcharge to fund clean-tech R&D.
Encore for Negawatts?
Congress renews PURPA’s call for conservation and load management, but the world has changed since the 1970s.
and regional spot-energy markets, rather than limiting their expansion.
In fact, experts and policymakers from across the country seem to hint that FERC’s most radical step also might be the most logical. That step would bring the granularity of RTO wholesale generation markets down to the retail level. Such a change would introduce fully nodal and locational marginal pricing (LMP) to individual loads, instead of averaged over zones, as is done today in New York, New England, and PJM.
There are exceptions, of course. Several years ago, FERC ordered PJM to comply with tariff provisions allowing any wholesale customer with an hourly interval meter data to elect full nodal LMP pricing at retail. (See Occidential Power Services, Inc. v. PJM Interconnection, LLC, Sept. 15, 2003, 104 FERC ¶61,289.) Also, ISO New England is moving ahead with “special case nodal pricing,” whereby certain individual customer loads can qualify to receive non-averaged LMP prices at retail. (See, ISO-NE Compliance Filing, June 30, 2005, FERC Docket No. ER02-2330-37.)
The most radical idea, however, comes from the Midwest Independent System Operator (MISO), which plans a so-called energy-only market (no capacity market or credits) where customers eventually would pay scarcity prices without caps. MISO argues that if you want customers to temper their demand in response to price, you must first offer a price in a range high enough that the slope of the demand curve moves off the vertical and acquires a real, measurable price elasticity. With prices in that range, a further increase will compel a reduction in electric use—not out of homage to an administrative program, but out of natural consumer behavior.
Are Congress and FERC ready for that?
Programs and Potential
Lacking any standard terminology—questioning even FERC’s use of terms within its survey questionnaire—the power industry has found it difficult to provide FERC with a clear and concise characterization of existing DR plans.
At the regional level, there are some programs, such the New York ISO’s EDRP (Emergency Demand-Response Program), that are clearly keyed to reliability and system capability, even though curtailments may be voluntary, and thus might well qualify as a plan deserving of federal regulatory oversight. The EDRP kicks in when reserves fall low, and pays the higher of $500/MWh or the zonal real-time LMP price for demand reductions. (Compensation is paid to LSEs—load-serving entities—but more likely to aggregators known as “curtailment service providers,” or CSPs).
Others, such as NY-ISO’s DADRP (Day-Ahead Demand Response Program), which allow LSEs or customers to submit decremental bids in the regional day-ahead spot market, are seen as “price-responsive” programs, or as “economic” in nature. Such programs, arguably, should remain hands-off at Congress and FERC.
Lastly, consider programs such as PJM’s ALM (Active Load Management), or NY-ISO’s ICAP/SCR (Installed Capacity Special Case Resources). These plans are designed not to reduce peak demand, but instead to procure generating capacity of a quality that might otherwise qualify as a resource under a regional ICAP, UCAP, or LICAP plan. An example might be a large C&I customer with self-generating capability, who agrees to curtail consumption so that its plant