When Électricité de France stepped in to buy Constellation Energy’s nuclear assets and help the company avoid bankruptcy, the Maryland Public Service Commission conditioned the sale on a set of...
Money, Power and Trade: What You Never Knew About the Western Energy Crisis
the highest in the region, reflecting an increasingly serious water shortage, compared to the Southwest (Palo Verde, Ariz.).
The consequences of the December price spikes were immediate and serious. California's two largest utilities were forced to buy large volumes of power at prices that they could not pass on to consumers. Southern California Edison (SCE) and Pacific Gas & Electric (PG&E) already were weakened from the summer spikes, and the new round of price increases rang alarm bells on every trading floor in the region. As a consequence suppliers began to question whether they would ever be paid. %n11%n On Dec. 13, the "dirty 13" bluntly refused to sell to the California Independent System Operator (ISO), which provoked a stage 2 emergency and threatened blackouts and chaos over the Christmas holidays. A day later on Dec. 14, the secretary of energy, under the auspices of the Federal Power Act, ordered power suppliers to continue sending energy to California. The secretary's action was followed on Dec. 15 by an order issued from the Federal Energy Regulatory Commission (FERC) that aimed to temper California markets by introducing so-called "soft price caps." %n12%n
The combination of cold weather and federal action took its toll. Hydroelectric generation in the Pacific Northwest increased in order to meet local load and supplement California supplies. The consequence was a rapid drafting of reservoirs, increasing the risk that the expected low runoff in May, June, and July would not be adequate for them to refill the pools. The power crisis was exacerbated in December by a record-setting cold spell in the South, Midwest, and Atlantic states, which severely strained natural gas inventories and delivery systems across North America, and particularly in California.
As the WSCC entered the shoulder season in February and March, the sense of crisis and urgency abated for a short period. Snow levels in the Sierra Nevada range improved to near normal, but precipitation in the mountains feeding the Columbia River drainage remained near record lows. Snow levels in the Cascade Mountains of Oregon and Washington are the second-lowest on record. Thus, there is increasing concern about the ability of the region's generation resources to meet summer peaks. For this reason, spot prices remain high and forward prices for the summer have risen significantly. The problem is exacerbated by the fact that California is unprepared to cope with high load levels, its interruptible load program in turmoil since late 2000. Virtually none of the long-term contracts entered into by the California Department of Water Resources will begin delivering power until late in 2001 or 2002. The cost for California to procure power on the spot market from June through September will likely total no less than $2 billion per month. If the summer is hot or if qualifying co-generation and small power facilities (QFs) are allowed to charge spot prices, this figure could approach $4 billion. Even with the 3 cents per kilowatt-hour rate hike of March 26, funds appear inadequate to meet such expenses. The state controller has forecast that the cost of power purchases by