The one-day-in-10-years criterion might have lost its usefulness in today’s energy markets. The criterion is highly conservative when used in calculating reserve margins for reliability. Can the...
Pay-as-Bid vs. Uniform Pricing
Discriminatory auctions promote strategic bidding and market manipulation.
in new generation facilities. More important, pay-as-bid auctions inadvertently may discourage investments in baseload and some renewable generation technologies. Under pay-as-bid auctions, technologies with low variable costs likely will shade their bids below their true expectation of the market price to reduce the risk they inadvertently bid above the eventual clearing price. Because low-cost plants earn large margins when they are selected to produce power, these plants face a greater opportunity cost if their bids inadvertently are above the eventual clearing price. By shading bids, however, expected financial returns to investments in these technologies are reduced, which biases the mix of investments toward shoulder and peak generation technologies—such as natural gas-fired combined cycle and combustion turbines. Such a shift would increase the long-run cost of electricity generation and, as a result, likely would lead to corresponding increases in prices.
The design of wholesale RTO electricity markets continues to evolve. These changes are motivated by the continued desire for more reliable and efficient electricity production, as well as for more affordable electricity. Changes in wholesale market design to a pay-as-bid approach are unlikely to reduce prices, and may make matters worse by potentially leading to price increases, creating dispatch inefficiencies and decreasing incentives for baseload facilities.
Indeed, there is a risk that needed efforts and resources to improve facility siting, promote demand response, encourage and determine appropriate forward contracting, and refine capacity market design—to address the missing-money problem—might become diverted by an effort to switch to an auction format that does not address any of these needs.
1. EIA, January 2007, Monthly Energy Review.
2. See, for example, Burkhart, Lori A., “Regulator’s Forum: Restructuring Rollback, Public Utilities Fortnightly, November 2007.
3. The so-called organized wholesale markets are those that rely principally on centralized energy spot markets.
4. Laffer, Arthur B. and Patrick N. Giordano, “Exelon Rex, Will power deregulation in Illinois benefit consumers or utilities?” Wall Street Journal, Dec. 1, 2005.
5. See, for example, Morin, Roger A., New Regulatory Finance, Public Utilities Reports, Inc., 2006, p. 1, including reference to Bonbright, James, Principles of Public Utility Rates, New York: Columbia University Press, 1966, p. 3.
6. Dispatchable resources—whether from available generating units or demand-side resources—are the tools available to the dispatcher to meet electricity demand at least-cost at any point in time. For simplicity, in the rest of this paper we discuss the dispatch of power plants, while recognizing that many of these same discussion points apply to the dispatch of certain demand-side resources and even of certain controllable direct-current transmission facilities capable of making certain remote generation available for dispatch to a system.
7. Note that Figure 1 is only intended to provide insight into the orientation—but not necessary the relative magnitude—of economic efficiency under alternative regulatory/market models.
8. Capacity markets that are part of some organized wholesale markets provide investors with some fixed payments outside of energy and ancillary services markets, although the levels of and financial risks associated with such revenue streams differ substantially from those provided by regulated returns on investments in rate base.