1 Also cited as contributing factors are the lack of long-term contracting, operating problems in the ISO and power exchange (PX) markets, and suggestions that owners of generation took advantage of the supply shortage and the design of California's wholesale power markets to exercise market power to drive prices higher.
2 San Diego Gas and Electric has recently proposed to install hourly meters and offer hourly prices to all commercial and industrial customers greater than 100 kW in size. Former California PUC President Daniel Fessler has recently recommended a demand-side bidding program to pay large users to reduce load in time of supply shortage ("What About California?", Remarks at 14th Annual Utility M&A Symposium, Jan. 29, 2001), one of the options discussed below. See also the comments of Enron Corp. CEO Kenneth Lay to the effect that "[P]rice signals need to be allowed...for people to understand there is a shortage." ("Energy exec: Public needs a costly lesson," , Feb. 4, 2001.)
3 The ISO has developed three new interruptible programs for 2001, one of which will credit customers at pre-set energy prices for reducing load during notified periods, as described below.
4 Just prior to approval of the state's long-term power contracting measure, a group of regulatory and energy economists issued a "manifesto on the California Electricity Crisis," through the Institute of Management, Innovation, and Organization at the University of California, Berkeley, which offered several recommendations. These included an immediate rate increase on the portion of the load not covered by generation still owned by the major utilities (to begin providing revenue to cover market prices), freedom for distribution companies to arrange long-term contracts, retail competition and pricing flexibility, and a review of market power issues. They warned against the state over-committing to long-term contracts or taking over utilities' generation and distribution facilities.
5 The band of prices in the $100 to $200/MWh range at low load levels occurred late in August following large natural gas price increases that have continued to the present.
6 Steven L. Puller, "Pricing and Firm Conduct in California's Deregulated Electricity Market," PWP-080, University of California Energy Institute, Nov. 2000.
7 PJM Interconnection State of the Market Report 1999, Market Monitoring Unit, June 2000.
8 The PJM Interconnection State of the Market Report 1999 estimated that during one high-price summer episode a load reduction of 1,000 MW would have reduced the market price by $200/MWh from the high of $850/MWh, while a reduction of 2,000 MW would have reduced the price by $400.
9 See S. D. Braithwait. and M. O'Sheasy, "Customer Response to Market PricesHow Much Can You Expect When You Need it Most?," EPRI International Energy Pricing Conference, July 2000.
10 Load-weighted average elasticities in different scenarios ranged from 0.07 to 0.135, where an elasticity of 0.1, for example, indicates that a 100 percent price increase in a given hour will generate approximately a 10 percent load reduction. We applied hourly pricing only to medium and large commercial and industrial customers, and assumed market shares that ranged from a low of 10 percent of commercial and 25 percent of industrial loads, to a high of 50 percent of both types of loads.
11 For a detailed discussion, see K. Eakin and A. Faruqui, "Pricing Retail Electricity: Making Money Selling a Commodity," in , edited by Ahmad Faruqui and Kelly Eakin, Kluwer Academic Publishing, 2000.
12 The current financial crisis of PG&E and Southern California Edison serves as an extreme example of the risk of offering a fixed price (at a level set by regulation for a multi-year period) in the face of uncertain wholesale prices.
13 See S. D. Braithwait, "Residential TOU Price Response in the Presence of Interactive Communication Equipment," Chapter 20 in , edited by A. Faruqui and K. Eakin, Kluwer Academic Publishers, 2000.
14 See "An Application of Coincident Peak Pricing to Seattle City Light", EPRI, 2001, forthcoming.
15 Witness the extremely high losses that interruptible customers have faced in California.
16 Interruptible programs have been offered for two different purposes. One is for reliability reasons, to provide load relief only during rare periods of low system reliability. The other is for economic reasons, to reduce utilities' need to purchase high-cost power. Suppliers and system operators may wish to maintain some load on emergency interruption programs to help in times of reliability problems. However, interruptions for economic reasons are an inefficient way to match demand and supply. A more effective approach is to inform customers of the cost of power, and let each of them decide how much to consume at those prices.
17 See Eric Hirst and Brendan Kirby, "Retail-Load Participation in Competitive Wholesale Electricity Markets," prepared for EEI and Project for Sustainable FERC Energy Policy, December 2000.
18 The single preset payment may be overly inflexible, leading to underpayments or overpayments, unless interruptions are limited to periods of wholesale prices within a relatively narrow range. It will also limit the magnitude of potential demand response during the most severe conditions.
19 See Braithwait (2000), op. cit.
20 For further discussion, see David Glyer, "You Can Run but You Can't Hide: Why Fixed-Price Products May Reflect Market Prices, and What You Should Do About It," EPRI International Energy Pricing Conference, July 2000.
21 Some have apparently swung to the opposite extreme of suggesting that all customers should face hourly prices. We believe that it would be difficult to justify the cost of the metering and other requirements relative to the benefits obtained. Furthermore, it would violate one of the tenets of deregulationgreater customer choice. Finally, as shown in this study, the demand response of only a portion of the total load is needed to produce substantial wholesale price reductions.
22 An amendment to the recent state legislative measure authorizing the state to enter long-term power contracts restricts future rate increases to apply only to usage 130 percent above an average baseline level. This one-sided feature will limit customers' incentive to conserve energy, because they receive credits only at low capped rates, rather than higher market prices.