This paper first describes those features of the electricity supply industry that make a prospective market monitoring process essential to a well-functioning wholesale market. Some of these features are shared with the securities industry, although the technology of electricity production and delivery make a reliable transmission network a necessary condition for an efficient wholesale market. These features of the electricity supply industry also make antitrust or competition law alone an inadequate foundation for an electricity market monitoring process. This paper provides examples of both the successes and failures of market monitoring from several international markets. More than ten years of experience with the electricity industry re-structuring process has demonstrated that market failures are more likely and substantially more harmful to consumers than other market failures because of how electricity is produced and delivered and the crucial role it plays in the modern economy. Wholesale market meltdowns of varying magnitudes and durations have occurred in electricity markets around the world, and many of them could have been prevented if a prospective market monitoring process backed by the prevailing regulatory authority had been in place at the start of the market.

This paper describes the lessons that should be learned about electricity market design and regulating energy markets from the California electricity crisis. A necessary first step in determining the lessons learned from the California electricity crisis is a diagnosis of its causes. This requires a clear understanding of the federal and state regulatory infrastructure that governs the US electricity supply industry. I then discuss the conditions in the western US electricity supply industry that enabled the California crisis to occur. The paper then describes the important regulatory decisions by FERC that allowed what was a very solvable problem develop into a full-fledged economic disaster during the latter part of 2000. As part of this discussion of FERC's response to the events of the summer of 2000, I will also dispel a number of the myths that circulated around this same time about the causes and consequences of the California electricity crisis. I will also discuss the actions taken at the state and federal level that ultimately stabilized the California electricity market. This is followed by a discussion of what I believe are the major lessons for electricity market design that should be learned from the California crisis. The paper concludes with recommendations for how FERC should change the way it carries out its statutory mandate to set just and reasonable wholesale prices and how state PUCs should revise their retail market policies to prevent a future California crisis. In this discussion, I describe a worst-case scenario for how another California electricity crisis could occur if these recommendations are not followed.

This paper measures the unilateral incentive each of the five largest electricity suppliers in the California had to exercise market power in the state's wholesale market during the five month period June 1 to September 30 of 1998, 1999 and 2000. Using the actual bids submitted to the California Independent System Operator's (CAISO) real-time energy market, I compute the hourly price elasticity of the ex post residual demand curve faced by each supplier evaluated at the market-clearing price for that hour. The inverse of this hourly ex post residual demand elasticity quantifies the extent to which that supplier is able to raise the hourly real-time energy price above its marginal cost of supplying the last megawatt-hour (MWh) it sells in the CAISO's real-time energy market. I use the average hourly value of the inverse of the firm-level residual demand elasticity over the four month sample period of each year as a summary measure of the extent of unilateral market power possessed by each supplier. For each firm, this measure of unilateral market power is significantly higher in 2000 relative to the corresponding firm-level values in 1998 and 1999. For each of the five firms, this measure is slightly higher in 1998 than 1999. The firm-level results presented below are consistent with the view that the enormous increase in the amount market power exercised in the California market beginning in June of 2000 documented in Borenstein, Bushnell and Wolak (2002) was due to a substantial increase in the amount of unilateral market power possessed each of the five large suppliers in California.

This paper analyzes the results of a critical peak pricing (CPP) experiment involving 123 residential customers of the City of Anaheim Public Utilities (APU) over the period June 1, 2005 to October 14, 2005. Using a nonparametric condition mean estimation framework that allows for customer-specific fixed effects and day-of-sample fixed effects, I find that customers in the treatment group consumed an average of 12 percent less electricity during the peak hours of the day on CPP days than customers in the control group. There is also evidence that this reduction in consumption for customers in the treatment group relative to customers in the control group is larger on higher temperature CPP days. The impact of CPP events is confined to the peak periods of CPP days. Mean electricity consumption by customers in the treatment group is not significantly different from that of customers in the control group during the peak or off-peak periods of the day before or day after a CPP event. Much of the estimated consumption reduction of treatment consumers relative to control group consumers during peak periods of CPP days is due to reductions from a higher level of consumption by treatment group customers in non-CPP days. The consumption reductions paid rebates during CPP days are almost 7 times the reduction in consumption due to CPP events predicted by the treatment effects estimate, which provides strong evidence of an overly generous method for setting the reference level for peak period consumption relative to which customers are issued refunds during CPP days. The paper closes with a discussion of the challenges associated with implementing a CPP rate with a rebate mechanism as the default rate for residential customers.

Regulators of electricity markets around the world continue to struggle with the problem of incentivizing generators whose output, due to their location in the grid, has no viable substitutes. Such generators possess 'local' market power. Since these generators also compete in broader regional markets, the actions taken to exploit their local market power can also effect market outcomes over larger areas. In California, a contract structure known as the reliability must-run (RMR) contract was developed to address the problem of local market power. However, the contract form that was in place during 1998 created serious incentive problems. We find that, during the months of June through September 1998, RMR contracts had the effect of raising overall supply bid prices from most producers, thereby leading to higher energy prices in the California regional market.

This paper analyzes the extent to which the conditions in the emissions permit market for oxides of nitrogen (NOx) operated by the South Coast Air Quality Management District (SCAQMD) in the Los Angeles metropolitan area interacted with competitive conditions in the California electricity market to enhance the ability of electricity suppliers with some or all of their generation units located in SCAQMD to exercise unilateral market power. We present evidence consistent with the view that NOx emissions permits were a convenient vehicle for enhancing the ability of suppliers to exercise unilateral market power in the California electricity market. We find that generation unit owners with some of their plants located in the SCAQMD paid statistically significantly higher prices for 2000 and 2001 NOx emissions permits than other participants in the SCAQMD emissions market, despite the fact the prices they paid for 1998 and 1999 vintage permits were no different from other SCAQMD participants. We then present evidence consistent with the view that wholesale electricity suppliers did not operate and bid their generation units requiring NOx emissions permits in a manner consistent with higher emission permit prices being a cause of increased production costs. Taken together, this evidence suggests that NOx emission permit prices during 2000 and 2001 were primarily used by these generation unit owners to cost-justify higher bids into the California electricity market that would set higher prices for all electricity they produced.

The traditional approach to demand response of paying for a customer’s electricity consumption reductions relative to an administratively set baseline is currently being advocated by the Federal Energy Regulatory Commission (FERC) as a way to foster the participation of final consumers in formal wholesale markets. Although these efforts may lead to greater participation of final consumers in traditional demand response programs, they are likely to work against the ultimate goal of increasing the benefits that electricity consumers realize from formal wholesale electricity markets, because traditional demand response programs are likely to provide a less reliable product than generation resources. The moral hazard and adverse selection problems that reduce the reliability of the product provided by traditional demand response resources can be addressed by treating consumers and producers of electricity symmetrically in the wholesale market. Several suggestions are made for how this would be accomplished in both the energy and ancillary services markets. A specific application of this general approach to the California wholesale electricity market is also provided.

Effective competition in wholesale electricity markets is the cornerstone of the deregulation of the electricity generation industry. We examine the degree of competition in the California wholesale electricity market during June-November 1998 by comparing the market prices with estimates of the prices that would have resulted if all firms were price takers. We find that there were significant departures from competitive pricing and that it was most pronounced during the highest demand periods. Overall, this raised the cost of power purchases by about 22% above the competitive level. We also explain why the prices observed cannot be attributed to competitive peak-load pricing.

We present a method for decomposing wholesale electricity payments into production costs, inframarginal competitive rents, and payments resulting from the exercise of market power. The method also parses actual variable costs into the minimum variable costs necessary to meet demand and increased production costs caused by market power and other market inefficiencies. Using data from June 1998 to October 2000 in California, we find significant departures from competitive pricing, particularly during the high-demand summer months. Electricity expenditures in the state's restructured wholesale market rose from $2.04 billion in summer 1999 to $8.98 billion in summer 2000. We find that 21% of this increase was due to increased production costs, 20% was due to increased competitive rents, and the remaining 59% was attributable to increased market power.