development, location in the transmission network, environmental effects, and operational flexibility, as well as price. Since it is difficult to compare all of these attributes with a common metric, it is inevitable that qualitative judgment will play a role in the evaluation process.

Competitive bidding brought product differentiation to the independent power market. One important dimension for this involved operational flexibility. The PURPA obligation to purchase QF power meant that all such production was “must take” in nature. A number of factors, however, led to increasing operational problems on power systems, especially during “off-peak” period. The fundamental problems is an excess of inflexible generation at these times, relative to demand (Le, et al., 1991). Thus, the demand for more flexible operation became great, and utilities began to require this in their requests for bids. Analytic problems associated with bid evaluation in this setting are described in Kahn et al. (1992).

One of the principal motivations for competitive bidding is to lower the cost of power. Although evidence is fragmentary, there is reason to believe that prices are coming down. Table 8, from Comnes, Belden, and Kahn (1995), shows for a small sample of projects that prices are getting lower over time. These data are not without ambiguity, and require some discussion. Further, there are a variety of non-price terms which affect the overall value of the projects. The non-price terms involve either operational flexibilities or contractual performance requirements. Broadly speaking, the more recent projects offer the utilities more operating freedom and stricter contract terms. Kahn (1991) gives an account of the trend toward stricter contract terms. A brief explanation of the Table 8 data should make clear the extent to which clear conclusions are possible.

The data given in Table 8 is denominated in levelized nominal 1994$ over the contract term which is at least 20 years in length. This sample represents roughly one sixth of the private power projects that entered service during the 1990-93 period, but most of that was based on standard offer contracts. This sample represents at least half of the projects acquired by some kind of competitive process. Within this sample, the coal-fired projects are an average 2.49B/kWh, or 35%, more expensive than the gas-fired projects. In quantity terms, gas clearly dominates the market.

Broadly speaking, the coal-fired projects represent avoided cost expectations that were higher than subsequent developments proved to be justified. The dominance of gas fired generation was due both to falling commodity costs for fuel and the rapid introduction of highly efficient combined cycle technology based on advanced combustion turbines. This technology has relatively modest capital costs and thermal efficiencies that exceed 45% (Beck, 1993).

These data are not conclusive. The number of cases reviewed is small. The productivity gains reflected in Table 8 may be generic to the industry, rather than due to the superior performance of the private producers. Even if this latter hypothesis is correct, however, some of the stimulus for these gains can be attributed to competitive pressure.

Private power production offers incentives for technical innovation that are absent from rate of return regulation. Under the fixed price formulas contained in private power contracts, any