Electric Competition Moves On
The recent months have brought a flurry of activity in a number of states:
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transactions or obtaining information about alternatives. Economists have not yet agreed on a numerical criterion for concluding that two regions lie within the same market, particularly when each is affected by a similar set of external forces. When analyzing the price spikes, a graph of daily power prices in different regions would be dominated by a handful of observations of four-digit prices, obscuring inter-regional linkages that might have occurred during times when prices were at more normal levels.
It is easier to see the similarity of price movements among regions by plotting their natural logarithms, as we do in figure 1 for daily index prices between June 1 and Aug. 7, as published by Power Markets Week. Logarithms facilitate comparison of proportions, since a 30-percent range on a spike day is the same vertical distance as a 30-percent range on a normal day. The individual blue lines show deliveries of on-peak power into various Midwestern and Southeastern regions and utility territories. They include ECAR, MAIN, the Southeastern Electric Reliability Council (SERC), the Florida-Georgia border (FLA/GA), Tennessee Valley Authority (TVA), Southwest Power Pool (SPP), and Entergy Corporation. They move together so closely that individual labeling is virtually impossible. The percentage range of prices among the regions differs little between spike days and more ordinary ones.
Negotiated prices for bulk power and substantial available transmission capacity link the Midwest and Southeast into a single trading area. Prices in nearby regions that transact only small volumes with the Midwest and South behave quite differently, as shown by the white lines in figure 1. Those regions include (1) the Mid-Continent Area Power Pool (MAPP) in the upper Midwest, which has little transmission capacity into ECAR and MAIN; (2) the Electricity Reliability Council of Texas (ERCOT), an electrically isolated area that can only export small amounts of power; and (3) the Pennsylvania-New Jersey-Maryland Interconnection (PJM), a centrally dispatched pool into which utilities must offer power at cost-based prices; and (4) the New England Power Pool, at a greater distance to the Northeast.
Hour by Hour:
Spikes Thinly Traded
The demand for electrical energy fluctuates predictably during a normal day, reaching its peak(s) in the late afternoon or evening, and its bottom in the predawn hours. In the absence of such constraints as minimum load conditions, generators with high avoidable costs only will be efficient to dispatch during hours of high demand. If production is determined by market bids, high-cost plants will offer their power only during peak hours, when the market-clearing price is high enough to cover their incremental costs. A utility that generates most of its own power will usually face market prices for supplementary or economy purchases that also vary predictably during the day. If prices do not follow load in this way, the market will be operating inefficiently, producing its hourly requirements at higher cost than necessary.
During the June spike days, the variation of hourly prices was consistent with economic efficiency in generation. Power Markets Week reported off-peak power prices in ECAR in the $12/MWh to $14/MWh range throughout the week of June