Given a chance to make a positive change in California’s wholesale generation market, the California Public Utilities Commission (CPUC) in December opted instead to maintain the state’s existing “hybrid” market model. That decision will further restrict meaningful opportunities for independent power producers (IPPs) and increase the likelihood that future generation will consist of utility ratebase projects.
The CPUC presented its decision as an interim measure that supports development of a competitive market that will stimulate private investment in new generation without the need for long-term power-purchase agreements. However, promoting new utility ratebase generation is the antithesis of a “merchant model” and, notwithstanding the CPUC’s reasoning, will likely inhibit the emergence of a competitive market.
Still ignoring the problems
As previously discussed in this column, institutional advantages favor utility generation over IPP resources and make the benefits that hybrid markets supposedly offer, at best, illusory (POWER, March 2006). An administrative law judge’s proposed decision recognized this inherent flaw in the California hybrid model and, if adopted, would have prohibited utility-owned projects from participating in utility resource solicitations. But the CPUC commissioners dismissed this recommendation in favor of protective measures. In particular, a (currently undefined) “code of conduct” prevents the sharing of information between utility personnel responsible for developing utility bids and utility personnel responsible for selecting winning bids.
Restrictions on the sharing of information presuppose that utilities actually develop and construct “utility generation” and do not address fundamental problems of a hybrid market. Recent utility-owned generation projects in California have consisted of facilities added to the utility’s ratebase that were developed and bid into resource solicitations by third parties—circumstances the “code of conduct” would not affect. However, the financial incentive for a utility to select a “turnkey” project over a competing IPP power-purchase agreement in a resource solicitation is the same as for projects developed by the utility: an incremental addition to the utility’s ratebase and the attendant ability for shareholders to earn a cost-plus “return” for 30 years or more.
The absence of a rational and transparent methodology for comparing utility-owned generation and IPP power-purchase agreements on an apples-to-apples basis means that the hybrid model provides a utility with ample opportunity to favor projects promising ratebase recovery, irrespective of the cost consequences to customers.
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