Steven Stoft

How high are option values in energy-efficiency investments?

High implicit discount rates in consumers energy-efficiency investments have long been a source of controversy. In several recent papers, Hassett and Metcalf argue that the uncertainty and irreversibility attendant to such investments, and the resulting option value, account for this anomalously high implicit discounting. Using their model and data, we show that, to the contrary, their analysis falls well short of providing an explanation of this pattern.

Technical efficiency, production functions and conservation supply curves

In a recent paper Huntington lays some of the groundwork for more meaningful discussions between economists and technologists on the apparent underinvestment in energy efficiency. In a discussion illustrated by a production function, he points out that the technical efficiency of economic actors should be treated as an empirical question. Huntingtons groundwork can be further extended by observing that there is a close relationship between production functions and conservation supply curves, an analytical tool routinely used by technologists. Here we show that a conservation supply curve can be obtained from a production function by a simple transformation.

DSM shareholder incentives: recent designs and economic theory

U.S. utility DSM shareholder incentives represent a unique form of targeted incentive regulation designed to motivate utilities to achieve specific energy-efficiency objectives. Through a review of recent DSM shareholder incentive designs and earnings for 10 U.S. utilities, we conclude that the mechanisms could be improved by harnessing their incentive powers more deliberately to ensure better alignment of regulatory objectives and utility financial self-interest. Better alignment reduces adversarial confrontation and eliminates the need for regulatory micro-management. We make five specific recommendations: (1) apply shared-savings incentives to DSM resource programs (2) use markup incentives for individual programs only when net benefits are difficult to measure, but are known to be positive (3) set expected incentive payments based on covering a utility’s ‘hidden costs,’ which include some transitional management and risk-adjusted opportunity costs (4) use higher marginal incentives rates than are currently found in practice, but limit total incentive payments by adding a fixed charge (5) mitigate risks to regulators and utilities by lowering marginal incentive rates at high and low performance levels. As regulators and utilities contemplate new forms of regulation for a restructured electricity industry, the lessons from the U.S. experience with DSM shareholder incentives are readily generalizable: Be explicit about the regulatory objective when considering multiple objectives, look broadly at alternatives that have the potential to meet these objectives without compromising the incentive properties of the mechanisms.

The theory and practice of decoupling utility revenues from sales

Decoupling has emerged in the US as an important regulatory strategy for insulating utility revenues from sales fluctuations. Breaking the link between revenues and sales, it is argued, is an important prerequisite for transforming utilities from sellers of an energy commodity to providers of energy services. We characterize the cost and regulatory conditions that underlie these arguments and, thereby, provide guidance on the applicability of decoupling to other regulated utilities. We describe how decoupling works in practice and then, using historic information on utility costs, examine the cost-tracking assumptions inherent in traditional rate-making and current decoupling approaches. Finally, we report on the actual rate impacts of decoupling examining the three US utilities with the longest history of decoupling.

Transmission Pricing and Renewables: Issues, Options, and Recommendations

Open access to the transmission system, if provided at reasonable costs, should open new electricity markets for high-quality renewable resources that are located far from load centers. Several factors will affect the cost of transmission service, including the type of transmission pricing system implemented and the specific attributes of renewable energy. One crucial variable in the transmission cost equation is a generator`s capacity factor. This factor is important for intermittent renewables such as wind and solar, because it can increase transmission costs several fold due to the traditional use of take-or-pay, capacity-based transmission access charges. This report argues that such a charge is demonstrably unfair to renewable generators. It puts them at an economic disadvantage that will lead to an undersupply of renewable energy compared with the least-cost mix of generation technologies. The authors argue that congestion charges must first be separated from the access charges that cover the fixed cost of the network before one can design an efficient tariff. They then show that, in a competitive market with a separate charge for congestion, a take-or-pay capacity-based access charge used to cover system fixed costs cannot be justified on the basis of peak-load pricing. An energy-based access charge, on the other hand, is fair to intermittent generators as well as to the usual spectrum of peak and base-load technologies. This report also reviews other specific characteristics of renewables that can affect the cost of transmission, and evaluates the potential impact on renewables of several transmission pricing schemes, including postage-stamp rates, megawatt-mile pricing, congestion pricing, and the Federal Energy Regulatory Commission`s {open_quotes}point-to-point{close_quotes} transmission tariffs.

The effect of the transmission grid on market power

If competition could extend without hindrance through the entire extent of an electrically connected power grid, the US would have just two electricity markets, each with a uniform price. These markets would be competitive indeed. Unfortunately, losses and congestion present barriers to competition and thereby provide the likelihood of significantly increased market power. This paper begins the analysis of congestion as it affects the physical extent of markets and thereby affects the degree of market power. This is new territory; very little has previously been written in this area. Although the theoretical developments reported here rely on complex economic analysis, and although the market behaviors described are extremely subtle, several broad generalizations relevant to policy analysis can be made. From these generalizations one major policy conclusion can be drawn: In an unregulated market it will be socially beneficial to build a grid that is more robust than what is optimal in a regulated environment. Unused capacity may be needed. For a line to support full competition it may need to have a capacity that is much greater than the flow that will take place on it under full competition. Markets do not have sharp boundaries. Even with only one line the two busses may be in different regions, the same region, or partially in each other`s region. Increasing capacity is more effective on a small line. If connecting two busses with a very strong line will reduce market power, then the first MW of connecting capacity will have the most impact and each additional MW will have less. A congested line will cut a market into two non-competing regions. In each region the generators will markup according to the elasticity of the demand in only their region. A generator may reduce output in order to congest a line and increase its market power.

Organization of bulk power markets: A concept paper

The electricity industry in the US today is at a crossroads. The restructuring debate going on in most regions has made it clear that the traditional model of vertically integrated firms serving defined franchise areas and regulated by state commissions may not be the pattern for the future. The demands of large customers seeking direct access to power markets, the entry of new participants, and proposed reforms of the regulatory process all signify a momentum for fundamental change in the organization of the industry. This paper addresses electricity restructuring from the perspective of bulk power markets. The authors focus attention on the organization of electricity trade and the various ways it has been and might be conducted. Their approach concentrates on conceptual models and empirical case studies, not on specific proposals made by particular utilities or commissions. They review literature in economics and power system engineering that is relevant to the major questions. The objective is to provide conceptual background to industry participants, e.g. utility staff, regulatory staff, new entrants, who are working on specific proposals. While they formulate many questions, they do not provide definitive answers on most issues. They attempt to put the industry restructuring dialogue in a neutral setting, translating the language of economists for engineers and vice versa. Towards this end they begin with a review of the basic economic institutions in the US bulk power markets and a summary of the engineering practices that dominate trade today.

Impact of power purchases from non-utilities on the utility cost of capital

Abstract The bond rating agencies in the USA have asserted that long-term power purchase contracts between non-utility generators and utilities are the equivalent of debt to the utilities, and therefore raise the cost of capital to the purchaser. Non-utility generators claim that these contracts reduce risk to the utilities. This debate is reflected in the 1992 Energy Policy Act. This paper investigates this controversy from the perspective of the equity markets. Using a CAPM framework, various specifications of the cost of equity capital are estimated, to shed light on this question. No evidence is found for the hypothesis that non-utility generation contracts raise the cost of capital. There does appear to be a slight increase in this cost for those utilities seeking to build their own generation capacity as opposed to purchasing it from non-utility suppliers.

Evaluation of front loading in auctions for wholesale power

Abstract Bidders in auctions for long-term wholesale power contracts may offer prices that exceed value in the short run, even if they are attractive in the long run. Such prices are called ‘front-loaded’. Some multi-attribute bid evaluation schemes penalize front-loading bids. The rationale for penalties is the buyers risk that long-run benefits will not materialize due to premature termination of the contract. We propose a framework to analyse the economics of front-loaded bids. Our method exploits the intuition that front-loading is a loan from buyer to seller. We separate this loan from the bidders price stream. The default risk of these loans is embodied in an interest rate greater than the utilitys normal discount rate. Several proposed bid evaluation systems are analysed from this perspective.

Coal gasification in a deintegrated electricity industry

Abstract This paper examines coal gasification in the context of a regulated utility purchasing power from an independent power producer (IPP). It outlines various contractual approaches that might be used to achieve coordination between the profit motive of the IPP and the desirability of limiting the potential escalation of natural gas prices through a backstop technology. These approaches are formulated as options. A numerical method to value the gasification option is presented. The option value is found to be significant (although uncertain). The transactions costs associated with writing contracts to incorporate the option value are substantial. Vertical integration may handle these issues more easily.