Stan Hadley

Generation Adequacy: Who Decides?

Abstract While market-based methods for generation expansion are the preferred long-term approach, there is currently too much uncertainty regarding how consumers and suppliers will respond to spot price signals. Therefore, policymakers should encourage demand-side experiments and investments to ensure that, when prices rise, customers will be able to respond.

Transition costs: Estimation, sensitivities, and recovery

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

The DSM sky hasn't fallen yet

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.

Designing True-up Mechanisms to Recover Transition Costs

Abstract Reports of the death of DSM at the hands of restructing are greatly exaggerated. Data that utilities have submitted to EIA show that DSM is alive and well, although the pace of program increases is slowing.

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

Abstract Cost-recovery and true-up mechanisms may be the last unresolved transition-costs dilemma facing state policymakers. Two mechanisms that allow for a 100 percent adjustment for changes in exogenous factors are a good place to start.

How integrated resource planning for US electric utilities affects shareholder interests

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

Effects of Electric Utility Demand-Side Management Programs on Electricity Prices

100 to

Who should pay transition costs

200 billion. These potential losses exist because some utility-owned power plants, long-term power-purchase contracts and fuel-supply contracts, regulatory assets, and expenses for public-policy programs have book values that exceed their expected market values under competition. This paper quantifies the sensitivity of transition-cost estimates to various factors that lead to these above-market-value estimates. We created a hypothetical utility with a substantial transition-cost problem. Between 1996 and 2000, the portion of retail load that ‘leaves’ the utility increased from 8 to 42%. We analyzed the consequences of this retail wheeling from two perspectives: utility shareholders (in which case customers face the same rates with or without wheeling) or remaining retail customers (in which case utility shareholders earn the same return on equity with or without wheeling). The key variables that most affect losses include the year that wheeling begins, wholesale prices (or, equivalently, utility marginal production costs), the percentage of customers that wheel, fixed production costs, regulatory assets, and capacity-related charges for ancillary services.

Methods to estimate electric-utility transition costs

Abstract Integrated resource planning (IRP) seeks to identify the mix of resources that can best meet the future energy-service needs of customers. These resources include new sources, types, and owners of power plants plus demand-side management (DSM) programs. However, little explicit attention is given to utility shareholders in the typical resource-planning proceeding. Because of the complexity of state regulatory practices and tax policies, it seems unlikely that different resources that provide comparable services to customers will yield comparable returns to shareholders. This study examines a typical US investor-owned utilitys financial operations and performance using a spreadsheet model we developed for this project. The model simulates an electric utilitys financial operations, and produces an annual income statement, balance sheet, and cash-flow statement. We calculated the net present value of realized (cash) return on equity as the primary factor used to represent shareholder interests. We examined shareholder returns for these resources as functions of public utility commission regulation, taxes, and the utilitys operating environment. Given the increasingly competitive nature of electricity markets, we examined shareholder returns for these resources in an environment where the utility competes with other suppliers solely on the basis of electricity price.

An Assessment of the Economics of Future Electric Power Generation Options and the Implications for Fusion

As competition in the US electricity industry grows, utilities (and others) worry more about the increases in electricity prices that demand-side management (DSM) programs often cause. Therefore, several utilities have reduced the scope of their DSM programs or focused these programs more on customer service and less on improving energy efficiency. This study uses the Oak Ridge Financial Model (ORFIN) to calculate the rate impacts of DSM. These simulations suggest that DSM programs, although they reduce electric bills, often increase electricity prices. However, utilities can run DSM programs that cut prices. Reducing DSM-program costs, focusing programs on those areas where large transmission and distribution investments can be deferred, timing DSM programs to match avoided costs, and shifting more of the utilitys fixed costs to the monthly customer charge will cut DSM-induced price increases.