Edward Kahn

Market power in California electricity markets

Abstract As the electricity industry in California undergoes a process of fundamental restructuring, important new products and markets will be created while others will lose significance. In this paper, we undertake an initial survey of the products and markets that will be prominent in the emerging new electricity industry. We describe approaches to analyzing the prospects for, and the impacts of, market power abuse in these various product markets. The key product markets that are discussed include those for spot electrical energy, for pool-based and physical power contracts, and for reliability services such as load balancing and spinning reserve. Structural measures of market power, such as the Hirschman-Herfindahl Index (HHI), have certain general shortcomings that are exacerbated when applied to restructured electricity markets. Fortunately, the direct estimation of competitive equilibria, such as a Cournot oligopoly equilibrium, appears to be more feasible for this industry than is generally the case.

Accuracy of the Edgeworth Approximation for Lolp Calculations in Small Power Systems

Because they speed numerical calculations and exhibit functional dependences, Edgeworth-type series are increasingly used to approximate and calculate LOLPs. They are usually sufficiently accurate for large power systems (> 15 000 MW), but can be very inaccurate for small systems or those with low forced outage rates. This is because the approximating Edgeworth-type series are appropriate only for continuous probability densities, while discrete lattice-type density functions describe a typical power systemss probability properties. This paper investigates these inaccuracies for small systems (< 5000 MW), working out specific examples in a numerical approach and examining underlying functional dependences in an analytic approach.

The production tax credit for wind turbine powerplants is an ineffective incentive

Abstract The US Energy Policy Act (EPAct) of 1992 created a production tax credit of 1.5¢/kWh available for 10 years to promote certain renewable energy technologies, including wind turbines. This paper argues that the impact of the wind turbine production tax credit will be minimal. The argument depends entirely on the nature of the project finance structure used by the private power industry for wind turbine development. We show that tax credits can only be absorbed by equity investors if there is a large fraction of equity in the project capital structure. This raises the financing cost of wind turbine projects compared to conventional power technology, which relies on a large fraction of low cost debt. If the tax credit were paid as a cash subsidy, the capital structure could be shifted to low cost debt and financing costs could be significantly reduced.

Auction Markets for Dispatchable Power: How to Score the Bids

Competitive bidding for electric generating capacity is becoming based on economic dispatch rather than the PURPA “must-take” norm. Incorporating economic dispatch into bidding requires different price scoring procedures. The “avoided cost” of a dispatchable project is determined by the energy price offered. Price scoring methods based on a “percentage of avoided cost” approach are uneconomically biased against baseload projects, because they neglect the duration effects of their dispatch. This bias is illustrated in a simple model of economic dispatch. A number of utilities use the “percentage of avoided cost” method for dispatchable capacity. They can correct the bias by using a net benefits per kW measure of economic value.

A Regional Approach to Market Monitoring in the West

Market monitoring involves the systematic analysis of prices and behavior in wholesale power markets to determine when and whether potentially anti-competitive behavior is occurring. Regional Transmission Organizations (RTOs) typically have a market monitoring function. Because the West does not have active RTOs outside of California, it does not have the market monitoring that RTOs have. In addition, because the West outside of California does not have RTOs that perform centralized unit commitment and dispatch, the rich data that are typically available to market monitors in RTO markets are not available in the West outside of California. This paper examines the feasibility of market monitoring in the West outside of California given readily available data. We develop simple econometric models of wholesale power prices in the West that might be used for market monitoring. In addition, we examine whether production cost simulations that have been developed for long-run planning might be useful for market monitoring. We find that simple econometric models go a long ways towards explaining wholesale power prices in the West and might be used to identify potentially anomalous prices. In contrast, we find that the simulated prices from a specific set of production cost simulations exhibit characteristics that are sufficiently different from observed prices that we question their usefulness for explaining price formation in the West and hence their usefulness as a market monitoring tool.

Comparative assessment of the demand-side management plans of four New York utilities

This study provides a comparative assessment of the initial long-term demand-side management (DSM) plans of four New York utilities. Several quantitative and qualitative indicators are developed to assess the impact of DSM programs. For example, by the year 2000, the four New York utilities project that DSM programs could produce savings representing between 15 and 60% of their projected peak-load growth for that period. However, there is no consensus among the utilities about the appropriate methods for evaluating programs or deciding on implementation. We suggest criteria against which utility DSM plans should be assessed and apply this approach to the four utilities. We also identify the most important data and analysis needs for improving future DSM plans: improved stock characterization, explicit treatment of independent power production in the resource mix, a comprehensive assessment of the achievable potential for DSM options for all end uses and sectors, research on customer response and other information relevant to DSM options (load shape impacts, incentives required to achieve certain penetration rates), and consistent avoided cost projections.

Impact of tax reform on renewable energy and cogeneration projects

Abstract This study examines the sensitivity of renewable energy and cogeneration project returns to proposed changes in the federal tax code, specifically to reforms proposed in 1985 by President Reagan. We examine six different technologies by defining typical configurations. Project cash flows are projected over a twelve year horizon, and the investors internal rate of return (IRR) is calculated. We calculate changes in IRR as various proposed tax changes are assumed to take effect. We find that capital intensive projects, such as geothermal and small hydro, suffer most from proposed tax code changes. Conversely, the least capital intensive projects, cogeneration, fare best.

The effect of conservation programmes on electric utility earnings : Results of two case studies

Abstract This paper develops methods to measure the impact of conservation programmes on electric utility earnings. The methods are applied to two case studies. Detroit Edison represents a case where impacts are unfavourable. This utility has ‘excess capacity’ which is only made worse by conservation. Pacific Gas and Electric represents a case where conservation helps defer the need for new capacity. Even in this case, programmes targeted at summer peak demand are more beneficial than those which save baseload energy. Conditions determining the earnings impact of conservation are complex, involving regulatory factors that are specific to individual utilities.

Regulatory options for solar incentives offered by public utilities

Utilities are being called upon to accelerate the adoption of residential solar energy systems by providing financial incentives. The form such incentives may take and their cost vary widely. The principal alternative mechanisms are reviewed: 1.(1) bill credits or cash payments,2.(2) interest subsidies and favorable loan terms, and3.(3) direct utility investment programs. The relative costs of these mechanisms to the rate payer and the consumer are compared. There are tests of appropriate cost to be applied by the regulators evaluating utility solar incentives. These tests will be reviewed and their application discussed. All solar incentive cost tests require estimates of the marginal cost of energy that utilities can avoid if customers adopt solar energy or reduce consumption. Noneconomic factors influencing the choice of utility solar incentive program are discussed. The principal issues are consumer protection/quality assurance, competitive impact on the solar vendors, and income distribution effects.

Electric utility conservation programs and the decision to abandon partially completed supply projects

Electric utility conservation programs are examined in the context of a decision to terminate partially completed supply projects, using the case of Philadelphia Electric Companys Limerick generating station. A cost-effectiveness criterion is developed for such utility programs. Methodology for determining the cost of various loan and grant programs is outlined, and particular programs are evaluated. It is found that 1.(1) utility financial incentives for end-use conservation are usually cost-effective;2.(2) in the case study,conservation programs could replace one of the two units under construction;3.(3) except for the lowest cost-programs, conservation competes with continued construction.