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Price Spike Redux: A Market Emerged, Remarkably Rational

Fortnightly Magazine - February 1 1999

of rolling blackouts. Through it all, however, the lights stayed on.

Before and During: The Runup in Prices

Early in 1998, the North American Electric Reliability Council's summer forecast noted that the margin of generation available to meet peak summer loads in the Midwest was becoming quite thin. NERC was particularly concerned about systems under the East Central Area Reliability Coordination Agreement (ECAR, covering Ohio, Indiana, Lower Michigan, and adjacent areas) and the Mid-America Interconnected Network (MAIN, covering most of Illinois, Wisconsin, and adjacent areas). Ontario Hydro's unexpected shutdown of several nuclear plants heightened the anxiety because parallel flows along its lines also could affect reliability.

Summer arrived early in the Midwest, with some generators out of service for scheduled maintenance in June, prior to planned peak use in July and August. Adding scheduled and unscheduled outages, American Electric Power entered the days of the spikes with more than 20 percent of its capacity out. The company estimated the probability of these outages at 1.5 percent, and that of such extreme heat at 0.3 percent. The rest of ECAR and MAIN suffered from more outages than usual, aggravated by the loss of important transmission due to storms.

On-peak power prices began to rise above $100 per megawatt-hour as the week of June 22 began, and they reached $250/MWh to $400/MWh for delivery on June 24. Around that date, Federal Energy Sales, a small marketer, was alleged to have defaulted on some call options it had written to deliver power at $50/MWh. Utilities and marketers that had counted on deliveries from FES (or others dealing with that company) found themselves thrown unexpectedly into the short-term market. That market became less accessible as storms and loading restrictions cut available transmission and transactions.

Prices rose to the thousands of dollars per megawatt-hour throughout the Midwest and the Southeast, where producers were exporting power northward. As the week of June 22 ended and more normal conditions prevailed, prices returned to their pre-spike levels, generally less than $50/MWh, throughout the entire Eastern Interconnection. July's spikes were a less extreme replay of June's, due again to record loads and unexpected outages but without defaults.


Was There a Market?

In regions like New England and California, bulk power markets have functioned and grown for decades. Even before California's restructuring, some of its utilities regularly obtained more than half of their power from independent producers and utilities beyond the state's borders. In the Midwest and Southeast, greater self-reliance by utilities has been the rule. Operating units of some large holding company systems trade substantial amounts of power among themselves, but most utilities in those areas obtain relatively little of their requirements from outsiders. Last summer, however, some midwestern utilities had to go to market for power to augment their production. Prices responded by climbing to four-digit levels.

Did a functioning market emerge in the Midwest?

A market is often defined by convergence of prices to a common value, net of costs of transportation. Convergence may be stymied when trading is too thin, because of the high cost of arranging