The latest dispute over PJM’s bidding rules has raised the level of uncertainty in organized electricity markets. Efforts at reform have created a market structure so jumbled that it can’t produce...
Encore for Negawatts?
Congress renews PURPA’s call for conservation and load management, but the world has changed since the 1970s.
capacity (lying behind the meter) can be released to the market. Thus, these programs are linked to resource adequacy, but the payments appear indistinguishable to the return on capital that a merchant generator earns for market-based power sales.
Detailed counts of program enrollments, curtailments (number, size, dollar value), and DR reductions in demand peaks and contribution to resource requirements for the regional grids can be found in the most current of one of the regular reports on demand response that RTOs and ISOs submit periodically to FERC:
- New York ISO . See Sixth Biannual Compliance Report on Demand Response, filed Dec. 15, 2005, FERC Docket No. ER01-3001.
- ISO New England . See Semi-Annual Status Report of Load Response Programs, filed Dec. 29, 2005, FERC Docket No. ER03-345-006. See also, Independent Assessment of Demand Response Programs (by RLW Analytics, LLC, and Neenan Associates, LLC), filed Dec. 30, 2005, FERC Docket No. ER02-2330-40.
The Silicon Valley Leadership Group (SVLG) founded in 1978 by David Packard of Hewlett-Packard, claims that demand response typically can provide demand reductions of 3 to 5 percent of annual peak load, for periods of up to 100 hours or so per year. Thus, as SVLG points out (and also Dan Delurey, of the Demand Response and Advanced Metering Coalition, or DRAM), demand response typically produces only a small reduction in total energy usage. That is because demand interruptions usually account for less than 1 percent of total annual hours. (The PJM market monitoring unit says DR for the region throughout 2003-04 produced an overall price impact of only about $1/MWh.)
Data from the U.S. Energy Information Administration (Form 861), as cited by the American Public Power Association, shows a total peak load reduction in the United States of 9,300 MW in 2003, versus 979,586 MW in total nameplate capacity. MISO estimates a total regional DR potential of about 5,000 to 10,000 MW. PJM says its ALM program (giving capacity credit against the ICAP obligation) could reliably provide up to 7.5 percent of the region’s summer peak.
Planning and Certification
What role should DR and load-reduction programs play in regional capacity planning, or in meeting state-sponsored resource adequacy requirements (RAR), especially since many DR programs envision interruptions that are purely voluntary on the part of load?
Nearly three years ago, the California PUC set target goals for demand reduction from DR programs and instructed electric utilities on how to integrate those DR goals into their resource-procurement plans. The goal for 2005 was 3 percent of annual peak system demand, increasing to 4 percent for 2006, and 5 percent in 2007. (See CPUC Decision 03-06-032, June 5, 2003.)
As of a year ago, however, the PUC had noted that the state’s three major electric utilities, Southern California Edison, Pacific Gas and Electric Co., and San Diego Gas & Electric, each appeared to be running short of achieving those DR goals. In the PUC’s words, all three “question the achievability and cost-effectiveness of the DR [megawatt] goals, noting that there may be more cost-effective alternatives to meet their loads.”
The PUC acknowledged that