Lester Baxter

Strategies to address transition costs in a restructuring electricity industry

This paper discusses the potential financial consequences, or transition costs, of transforming electricity generation from a regulated to a competitive market in the US. Industry-wide estimates suggest potential monetary losses could exceed

Transition costs: Estimation, sensitivities, and recovery

100 billion as a result of the move to competition. The paper discusses the most prominent strategies suggested to address these potential losses. For each strategy, the paper identifies the parties most likely to bear the financial consequences. Most strategies do nothing to reduce the total costs to society, but instead shift costs from one set of economic actors to another. The exceptions are those strategies that result in economic-efficiency gains, which can then be used to offset the transition costs. Most of the strategies examined require the cooperation of several parties, including regulators, to be implemented successfully.

Understanding net lost revenue adjustment mechanisms and their effects on utility finances

Abstract The pro-competitive, deregulatory forces sweeping the electricity industry could cost electric-utility shareholders

Net lost revenue adjustment (NLRA) mechanisms for utility DSM programs

100–200 billion in transition costs. These potential losses reflect the difference between regulated prices for electricity generation and the prices that might occur in a fully competitive power market. This paper discusses alternative ways to calculate transition costs, focusing on differences between aggregate (top-down) vs. disaggregate (bottom-up) methods to calculate these losses. The paper also discusses the relative importance of different factors that determine transition-cost amounts and the strategies that utilities and their regulators can use to address these potential losses.

Estimating transition costs: assessing the options

Abstract Net lost revenue adjustment (NLRA) mechanisms are the most prevalent policy used in the USA to permit utilities to recover lost revenue from demand-side management (DSM) programs. The tendency for net lost revenue to accumulate over time and for NLRA mechanisms to increase utility rates is a concern for regulators and utilities. Their concern is heightened by the competitive pressures facing energy utilities. This paper discusses the concept of lost revenue, describes the three different NLRA mechanisms used by states, and examines the effects of these mechanisms on utility finances. Our results indicate that all three NLRA mechanisms restore the net revenue lost through DSM program operation. We found that the prospective surcharge mechanism exposes the utility to less variation in cash flow as a result of net lost revenue. Increasing the accuracy of the net lost revenue forecast reduces the volatility in monthly cash flow. All three mechanisms result in higher rates and, when the amortization periods are similar, have similar effects on rates. The primary difference between the mechanisms is in the timing of these rate effects. We anticipate that NLRA mechanisms will change in response to customer and industry needs. Changes to NLRA mechanisms may include net lost revenue recovery caps, partial revenue recovery, and time limits for recovery.

Federal options for low-income electricity policy

We examine the experiences that states and utilities are having the NLRA approach. Contrary to concerns raised by some industry analysts, our results indicate the NLRA is a feasible approach to the lost-revenue disincentive. Seven of the 10 states we studied report no substantial problems with their approach. We observed several conditions linked to effective NLRA implementation and, for those states reporting problems, conditions linked to implementation difficulties. Finally, observed changes in utility-investment behavior occur afer implementation of DSM rate reforms, which include deployment of NLRA mechanisms. We find that utilities in states with lost revenue recovery invest more than twice as much in DSM as do utilities in other states.

The effects of various factors on estimates of electric-utility transition costs

Abstract When considering alternatives for measuring stranded costs—market-based or administrative, ex ante or ex post — there are many issues to consider. Regulators should weigh these issues when assessing specific estimation approaches.

Carbon dioxide emissions from the U.S. electricity sector

Protection of low-income consumers remains an important public policy concern in a restructuring electricity industry. Policies are needed to ensure that low-income households have enough affordable electricity to protect their health and safety, and that they are not victimized by unscrupulous suppliers. In this paper, the author presents three broad federal roles in setting low-income electricity policy, and discuss three more specific policy areas: universal service, electricity assistance, and health and safety. He discusses the key policy issues that arise when considering these potential federal initiatives and draw upon reviews of proposed low-income policies from restructuring proposals in eight states--California, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, Vermont, and Wisconsin.

Who should pay transition costs

Abstract Estimates of transition costs for U.S. investor-owned utilities vary widely, with many falling in the range of

Methods to estimate electric-utility transition costs

100 to