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Money, Power and Trade: What You Never Knew About the Western Energy Crisis

Fortnightly Magazine - May 1 2001

As Figure 2 demonstrates, WSCC hydro generation is dominated by Columbia River water flow. Generation from other hydro systems, such as the Colorado and Sierra facilities, comes in relatively small amounts, often correlated to conditions along the Columbia.

Columbia water flows are now projected to be 54 percent of normal for the coming year. That is uncharted territory for the western power market (1977 was the year of the last major drought).

Because droughts are infrequent, their occurrence plays havoc with the economics of alternative power supplies. During good water years many of the region's oil and gas generators will lie idle or generate at prices not much higher than marginal cost. That means that capital costs will have to be recovered primarily during a period of drought. That, in turn, implies a spot market with many years of low-priced power, punctuated by episodes of extremely high prices. %n7%n

Following a string of high water years, supplies in 2000 were modest, with natural water flow lower than normal. In order to refill the reservoirs, generation had to be curtailed. During the critical months of June, July, August, and September, WSCC hydroelectric generation was an average of over 6,000 MW per hour less than the previous year (em roughly the output of seven to 10 nuclear reactors. %n8%n The drop in hydro supply occurred just when California and the Southwest were experiencing peak demand. Since California typically imports electric energy from the Pacific Northwest and the desert Southwest, the combination of lower hydro supplies and peak southwest cooling demand meant that existing oil and gas generators inside the state had to be driven at exceptionally high rates. In California, overall power output increased 13 percent, as the state's oil and gas generators were forced to displace imports that had been available in previous years. %n9%n For the months of June through September of 2000, natural gas generation in western U.S. states increased 62 percent from 1999. %n10%n The consequence of the unprecedented increase in thermal generation output was a shortage of natural gas delivery infrastructure, a draw down of gas inventories, and a rapid depletion of emissions credits, which drove marginal production costs and prices to historic highs.

October brought cooler weather and loads dropped. However, due to the intensity of use in summer months, California's oil and gas generators were in poor repair and many were down for maintenance, or were short on emissions credits. Likewise, nuclear and coal units scheduled maintenance or fuel replenishment during the normally low-demand shoulder season.

California's utilities and ratepayers might have slipped through the net, were it not for Murphy's Law and mercurial Mother Nature. Winter in the Pacific Northwest, which is usually awash in rain, sleet, and snow, saw unusually dry weather, coupled with a severe early-December cold spell. The mere threat of the Arctic Front and its impact on gas inventories was enough to panic the market. In December the region experienced record price spikes, as illustrated in Figure 3. And, since that period, bilateral prices in the Pacific Northwest (Mid-Columbia, Wash.) have been