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

Fortnightly Magazine - May 1 2001

markets stemmed from their earlier experience with gas markets.

Back during the 1980s and early 1990s, long-term gas prices usually stood much higher than spot prices, because the industry had vastly overbuilt production and transportation facilities. Also, as the volume of spot gas trading grew, the market matured, liquidity blossomed, and spot transactions proved reliable. Spot gas prices would spike, but only for short periods in response to pipeline outages or unusual weather. No one questions that California's reliance on spot gas markets for over a decade was beneficial to its industry and utilities. However, that success offered no similar guarantee for the power industry, where markets remained immature and where spare capacity depended on an unpredictable hydro supply. In addition, the gas market transition from bundled services for retail customers to unbundled supply occurred over a 10-year period, starting with the largest and most sophisticated customers.

In thermal electricity systems, the power prices tend to go to extremes (em prices spike to extraordinary levels when load reaches system capacity, or else fall down more or less to the cost of fuel when demand abates. Hydro systems can work in a very different way, however.

With hydropower, usually there is more than enough capacity to meet peak demand. However, the system can be "energy" constrained. The energy constraint arises because natural stream flow plus the water stored in reservoirs may not prove adequate to meet the load over an annual cycle. In a market setting, that means that the alternative cost of generating power today depends on the value foregone of generating some time in the future. There are, of course, all kinds of other constraints (em fisheries management, shipping, irrigation, recreation, etc. Nonetheless, hydro systems ought not to produce pricing extremes except in the most extreme high demand/ low supply situations. In theory, if water (rather than capacity) is short, both off-peak and on-peak prices will rise, until the current price is more or less equal to the net present value of expected prices in the future. In this case, however, expectations for load and replacement energy are critical, because precipitation for future water periods is unknown.

Since market disturbances began in May 2000, the western power market has been acting like an energy-constrained hydro system. Prices often peaked in response to capacity constraints, but did not return to fuel costs plus a small margin. Instead off-peak prices have remained high, acting as if the system had an energy constraint. In fact, it often has. The fundamental increase in demand described earlier and drop in hydro generation together have meant that oil and gas peaking units have had to increase utilization far beyond expectations. These units, however, depend on the availability of fuel, storage capacity, and the pipeline delivery infrastructure. These constraints frequently limit the total number of hours, or proportion of time, a unit may generate. Most generators contract in advance for a given volume of gas, and arrange storage based on expected utilization. Sometimes they may simply not be able to exceed their planned level of utilization. At other