Perhaps the only political prediction bound to come true this year is that the words ôelectric restructuringö will reverberate in nearly every stateÆs legislative chamber.
With the implementation of the Energy Policy Act and the FERC's Orders 888 and 889, competition has been introduced into wholesale power markets. It is limited in scope, however, as utilities are still able to recover their fixed generation costs and embedded cost of capital from their captive retail markets. This limited competition impedes progress towards the development of a more efficient generation system in the U.S. and provides only modest benefits to retail customers.
Currently, generators compete only in wholesale markets and not in retail power markets. This restriction has created a temporary, bifurcated market. Utilities are guaranteed recovery of their fixed costs from ratepayers in the retail market. Similarly, nonutility power producers who signed contracts in the late 1980s or early 1990s get full recovery of their costs from long-term, fixed-price contracts with utilities. Competition, therefore, occurs only on the margin in the wholesale market, with the price of electricity determined by the short-term marginal cost. Even in bidding for new capacity contracts, the price seldom reflects the full value of capacity because utilities with excess capacity already recover fixed costs from captive customers.
An analysis of the economics governing current pricing in the Western Systems Coordinating Council provides a good example of this bifurcated market. In the table below, the hypothetical operating profit of four plants located close to the Palo Verde trading hub are shown. Hourly unit-level generation from RDI's POWERdat database was summed to the plant level and used to calculate on- and off-peak plant output. The daily Dow Jones Palo Verde Electricity Index was used to estimate hourly revenue for day-ahead firm power during on- and off-peak periods. The fuel cost and total cash cost (operation and maintenance expenses) were estimated using RDI's proprietary cost model. The operating profit is the difference between the average revenue and the plant's cash cost. Our analysis assumes that these power plants would collect all of their revenues by selling into the wholesale power market.
As shown in the table, based on our estimation of revenue obtained from the wholesale market, these plants were running at a loss for the first three quarters of 1996. In fact, these four plants have an apparent negative operating profit during 29 of 36 months. The weighted average revenue, represented by the Palo Verde cash price, was $16.11/MWh whereas the average total cash cost was $21.14/MWh.
Why would a utility sell so much power at a loss? In reality, it does not. The utility is able to recoup much of its theoretical loss from its captive ratepayers. On the wholesale market, the utility is willing to sell from these plants at the marginal production cost. Any amount above incremental production cost generates more profits for the utility. Due to minimum-take provisions on coal contracts or two-tiered pricing schemes, the marginal production cost at these plants is lower than even the average fuel cost, resulting in the low power market prices at the Palo Verde hub. The utility's main goal becomes reduction in marginal generation costs to gain more sales on the wholesale market, rather