Boom and Bust? Understanding the Power Plant Construction Cycle
fixed cost obligations. If the market clears at higher prices, however, a smaller CTC would be required. In this article, I envision that market prices would clear somewhat higher in the first few years after adoption of a capacity payment. When the utilities earn increased revenues selling to the PX, regulators would lower the CTC. Using the example of the three large utilities, the PX charges could increase by around $4 billion over the next five years. The stranded costs of these utilities are around $26 billion to $30 billion, substantially greater than the $4 billion. It seems that capacity payments would not penalize California's retail consumers in the short term.
Now, what about the long term? Could capacity payments lead to higher retail bills after the CTC charges are phased out? The California PUC expects CTCs to be completed by the year 2002, so one might ask if the retail consumer would experience higher bills after the year 2002. But the short-term impacts of capacity payments are largely eliminated by the year 2002. By the start of 2003, for example, the total PX price is almost identical in model simulations (Ford 1999).
1 Selected models used in the United Kingdom, in California, and in the Northwest are reviewed in the detailed version of this article (Ford 1999).
2 The observation on capacity markets appears in (CERA 1997). According to Rose (1995), "much has been written about the changing market for economy electric energy. In contrast, prices for wholesale electric generating capacity appear to be hidden."
3 The constant capacity payment was used here to confine the analysis within the reach of a highly aggregated model, which simulates the average annual price of energy. The constant payment was also adopted because of my instinctive aversion to adopting variable capacity payments as a supplement to variable payments for energy. My aversion is based, in part, on the findings by Bunn and Larsen (1992). They used computer simulation to demonstrate the destabilizing effect of the variable price for capacity originally used in the United Kingdom.
But setting a price for capacity is only one of several approaches to encourage investment in adequate generating capacity. A second approach would impose an obligation for installed capacity. This approach has been used by ISOs in New England, New York and Pennsylvania-New Jersey. According to Singh and Jacobs (1999), the capacity requirement approach "really boils down to administratively determined capacity payments."
A third approach relies on market prices as the primary signals for long-term investment while assigning short-term responsibility to the ISO. This is the approach in California where the ISO payments for ancillary services (AS) can be substantial. Sing and Jacobs (1999) report that California's AS costs "have been the highest observed thus far." Grix (2000) reports that AS payments amounted to 5.6 percent of total market energy costs in 1999. The value of AS payments can be important to investors, especially if their plant is to be equipped with automatic generation control. The value of AS payments is demonstrated by Deb (2000) using a multi-product, multi-area