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Water Heaters to teh Rescue: Demand Bidding in Electric Reserve Markets

With just a few changes in reliability rules, regulators could call on consumer loads to boost power reserves for outages and contingencies.
Fortnightly Magazine - September 1 2003
  1. Participation. ISOs, distribution utilities, and state energy offices and regulators should encourage loads to provide contingency reserves and to participate in the ISO markets for these reserve services. To stimulate such participation, the ISO should work with load-serving entities and other load aggregators to combine many small loads. Such aggregation should improve greatly the economics of load participation in these markets.
    The ISO could, based on the prior recommendation, work with the load aggregators to develop metering and communication requirements that meet the ISO's legitimate reliability needs and accommodate the needs of the load aggregators and individual retail customers. In addition, ISOs and load-serving entities (LSEs) should educate customers on bulk-power reliability issues, the importance of contingency reserves, and the role that demand resources can play in cost-effectively providing these reserves. Finally, ISOs might establish pilot programs to demonstrate the market barriers, benefits, and costs of using large and small loads to provide contingency reserves. Such programs could involve a few large industrial loads and an aggregation of residential loads (perhaps through a utility's existing direct-load-control program).
  2. Design Protocols for Load Aggregation. The ISOs should, working with LSEs and others, design load-research protocols that could be used when reserves are provided by aggregations of many small loads and which could substitute for the traditional performance measurement used for generators. Such protocols would measure the load-reductions of various types of loads under different conditions (time of day, day of the week, and season) and develop methods to forecast expected load reductions from different types of loads participating in contingency-reserve markets.

These recommendations, while required to accommodate demand-side resources in participating in markets for contingency reserves, need not imply preferential treatment for any one class of resources. Rather, rules should be modified simply to incorporate a broad consideration of economic costs and benefits.

  1. U.S. Federal Energy Regulatory Commission, Notice of Proposed Rulemaking: Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, Docket No. RM01-12-000, Washington, D.C., July 31, 2002.
  2. North American Electric Reliability Council, "Policy 1 Generation Control and Performance," NERC Operating Manual, Princeton, N.J., Nov. 21, 2002.
  3. Although NERC requires recovery from a major disturbance within 15 minutes, the control-area operators require the resources providing contingency reserves to respond fully within 10 minutes. The extra five minutes often are needed by the operators to decide whether a major contingency has occurred and, if so, how best to respond.
  4. Until November 2002, NERC's Policy 1 was prescriptive. NERC required that, with some exceptions, at least 50 percent of the 10-minute reserves be spinning. Perhaps more important, NERC restricted spinning reserve to "unloaded generation that is synchronized and ready to serve additional demand." Clearly, this statement excluded customer loads from providing this valuable ancillary service. NERC's new Policy 1 permits contingency reserves to be "supplied from generation, controllable load resources, or coordinated adjustments to Interchange Schedules," a very important change for demand resources.
  5. Northeast Power Coordinating Council, "Operating Reserve Criteria," Document A-06, New York, N.Y., Nov. 14, 2002.
  6. U.S. Federal Energy Regulatory Commission, ISO New England Inc., Order Accepting for Filing