Competition in power generation fosters technical innovation, cleaner power plants, and downward pressure on prices. Before the 1980s, such competition was almost nonexistent: vertically integrated utilities built and operated the vast majority of U.S. plants with oversight by state regulators. The Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 1992 were enacted partially to make generation markets competitive. By the late 1990s, most new capacity was being developed by independent power producers (IPPs).
The ascendancy of IPPs, however, was short-lived. Their decline was precipitated by political reactions to the California energy crisis and the Enron scandals, and by Wall Street’s retreat from financing plants based on the assumption that "if we build it (capacity), they will come (and buy it)." These failures, wrongly blamed on the independent generator model, and an emerging consensus that the U.S. needs more power supply and lower retail prices, have fueled a policy debate on whether our generation needs are better served by independent generators and competitive markets or by state-regulated vertically integrated monopolies.
One alternative approach that has been advanced is the "hybrid" market model, in which IPPs and utilities (directly or through an affiliate) "compete" to build new generation. Proponents of hybrid markets assert they would assure anxious regulators that capacity needs will be met in timely fashion, protect investors with guaranteed revenue streams supported by regulated rates, and preserve some semblance of competition.
Worst of both worlds
Although promoted as the "best of both worlds," the benefits of hybrid markets are illusory. Hybrid markets are inherently flawed because they trust a monopsony (a single buyer) to "objectively" choose a supplier from among its own and third-party power projects—an unrealistic expectation. Moreover, embedded in the hybrid model are institutional advantages that almost always result in the purchasing utility designating its own project as winner of the supposed competition. These built-in advantages, divorced from actual superiority, include those that follow.
Subjective determinations of need. The purchasing utility determines its need for incremental generation. Not surprisingly, in many cases to date, purchasing utilities have found "no need" for the new capacity proposed by an IPP but identify a "ready market" for the capacity the utility envisions building.
One-sided costs of delays. IPPs cannot obtain financing for a power project without a signed power purchase agreement (PPA), including a commitment that the plant be on-line by a date certain. Any delay in the awarding or regulatory approval of a PPA subjects the independent generator to financial risk. That risk raises the IPP’s costs and thus the floor of its bid price, making the project less competitive. Utilities’ access to balance sheet financing and their general control over the timing of the execution of PPAs effectively insulates their projects from the risks of such delays.
Discriminatory credit requirements. The unreasonable credit requirements that utilities increasingly impose on IPPs (POWER, November/December 2005, p. 28) also serve to increase the independents’ costs and bid prices. In contrast, credit support for utility generation essentially adds no cost for the bidding utility, as its obligations are secured by expected ratepayer revenues.
Skewed cost comparisons. Regulators do not fairly compare IPP and utility generation costs. For instance, the utility’s purchase price for power from IPP projects is fixed, with the developers assuming all of the risks related to delays and cost overruns. For utility projects, ratepayers—rather than the utility—typically bear these risks and therefore the projects’ ultimate costs. Utility bid prices generally do not reflect this greater risk to ratepayers. Utilities also "impute" financing costs when evaluating PPAs with IPPs, but they do not similarly segregate their financing costs in rate-based project bids.
Unequal regulatory costs. Increasingly, state regulators impose oversight on IPPs that were previously subject only to jurisdiction by the Federal Energy Regulatory Commission. IPPs can recover their regulatory compliance costs only through power sales, again increasing their minimum bids. In contrast, because utility rates generally provide for recovery of regulatory compliance costs, utilities need not account for these costs in their project bids.
In most cases, the hybrid market model guarantees the choice of a utility project over the competing IPP project. The unbalanced playing field portends the demise of the U.S. independent generator and the resurrection of generation markets monopolized by the local distribution utility.
The recent wave of new "utility" projects in California and the corresponding dearth of PPAs awarded to IPPs make clear that the deciding factor for "competitive success" in the hybrid market is utility market power. Most of these projects (such as the Mountainview project in Southern California) were developed by IPPs that were forced to sell them—often at fire-sale prices—when the incumbent utility refused to purchase their production or delayed signing a PPA. Regulators and consumer groups have short-sightedly applauded the supposed efficacy of the hybrid market model. But the near-term "benefits" perceived actually sacrifice true innovation and economic and environmental benefits.
In his "house divided" speech of 1858, Abraham Lincoln proclaimed: "I believe this government cannot endure permanently half slave and half free." Similarly, competitive generation markets cannot endure as half-utility, half-IPP.
Steven F. Greenwald
Christopher A. Hilen