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Price Spike Redux: A Market Emerged, Remarkably Rational

Fortnightly Magazine - February 1 1999

22, the same as in the preceding and following weeks.

Figure 2 shows the results of a confidential survey of Midwestern marketers by Tabors Caramanis and Associates (TCA) of Cambridge, Mass.fn2 It shows hourly variation in the highest and lowest reported prices per MWh of short-term power over June 24 and 25. Both high and low prices peak in the midday hours and bottom late at night, consistent with (but certainly not proving) efficiency in the allocation of generation. The gap between high and low reported prices is substantial. It may reflect both the difficulties of shopping in this type of market and the uncertainty that comes with an unprecedented situation. Utilities must make commitments to meet demand in upcoming hours, and currently available transmission paths may become unavailable if not claimed quickly.

Power purchased at spike prices was a small fraction of total power use during the critical days. To estimate the amounts transacted, TCA combined volume data from its survey with reports filed by marketers at FERC for June 24 and 25. Of 92 Midwestern transactions that took place at prices exceeding $100/MWh, 61 were for volumes of 200 or fewer MWh, mostly to flow for two hours or less. These figures are not exhaustive (reports to FERC are sometimes incomplete), but if provisionally accepted they show that high-price power flowed at an average of 695 megawatts per hour over the Midwest on June 24 and 25.

Since peak 1997 summer demand in the region was 168,000 MW, unless the data are wildly incomplete they show how unimportant spike-priced power actually was in the overall picture. That power went to satisfy the last increments of demand and was purchased in the most extreme of market conditions. With most utility-owned generation committed to serve at regulated retail rates, spike prices had a minor impact on overall power costs and the bills of most customers.

Transmission: TLR Rules Significant

Prior to last summer, a utility experiencing line-loading problems generally redispatched its system to meet the problem as economically as possible. A utility undertaking redispatch could adversely affect nearby systems as a byproduct of its operations by increasing their line loadings. Last summer, FERC permitted utilities in the Eastern Interconnection to use new TLR procedures proposed by NERC, whose members are largely transmission-owning utilities. The new procedures deal with overloading on a region-wide basis, and can require that transactions far from the affected area be curtailed on the basis of non-economic criteria.

On June 24 and 25 three separate invocations of TLR drastically curtailed power flows over the East and Southeast. A June 25 overload of 30 MW between Minnesota and Wisconsin ultimately led to curtailment of at least 1,900 MW of transactions throughout the Midwest. Generation outages had clearly strained the transmission system, but curtailments of this volume and scope were unprecedented.

Figure 3 plots aggregate weekly volume data (daily data are unavailable) against a weighted weekly index of prices over the Eastern Interconnection. At a time of heavy demand due to weather and generation outages, we would expect the volume of