Timothy D. Mount

Transmission Expansion Planning Using Contingency Criteria

This paper proposes a methodology for choosing the best transmission expansion plan considering various types of security (operating reliability) criteria. The proposed method minimizes the total cost that includes the investment cost of transmission as well as the operating cost and standby cost of generators. The purpose of the study is development of new methodology for solving transmission system expansion planning problem subject to contingency criteria which are essentially extensions of the (N-1) contingency criterion. The transmission expansion problem uses an integer programming framework, and the optimal strategy is determined using a branch and bound method that utilizes a network flow approach and the maximum flow-minimum cut set theorem. The characteristics of the proposed method are illustrated by applying it to a five-bus system and a 21-bus system. The results of these case studies demonstrate that the proposed method provides a practical way to find an optimal plan for power system expansion planning.

Market power and price volatility in restructured markets for electricity

Abstract The restructured market for electricity in the UK has experienced a systematic pattern of price spikes associated with the use of market power by the two dominant generators. Partly in response to this problem, the share of capacity owned by any individual generator after restructuring was limited in Victoria, Australia. As a result, a much more competitive market resulted with prices substantially lower than they were under regulation. Nevertheless, an erratic pattern of price spikes exists and the price volatility is a potential problem for customers. This paper argues that the use of a uniform price auction (UPA) for electricity markets exacerbates price volatility. A discriminatory price auction (DPA) is proposed as a better alternative that would reduce the responsiveness of price to errors in forecasting total load.

Locational pricing and scheduling for an integrated energy-reserve market

It is well known that given a network that can become constrained on voltage or real power flows, reserves must also be spatially located in order to handle all credible contingencies. However, to date, there is no credible science-based method for assigning and pricing reserves in this way. Presented in this paper is a new scheduling algorithm incorporating constraints imposed by grid security considerations, which include one base case (intact system) and a list of possible contingencies (line-out, unit-lost, and load-growth) of the system. By following a cost-minimizing co-optimization procedure, both power and reserve are allocated spatially for the combined energy and reserve markets. With the Lagrange multipliers (dual variables) obtained, the scheduling algorithm also reveals the locational shadow prices for the reserve and energy requirements. Unlike other pricing and scheduling methods in use, which are usually ad-hoc and are based on engineering judgment and experience, this proposed formulation is likely to perform better in restructured markets when market power is a potential problem. An illustrative example of a modified IEEE 30-bus system is used to introduce concepts and present results.

Location-based scheduling and pricing for energy and reserves: a responsive reserve market proposal

It is well known that given a network that can become constrained on voltage or real power flows, reserves must also be spatially located in order to handle all credible contingencies. However, to date, there is no credible science-based method for assigning and pricing reserves in this way. Presented in this paper is a responsive-reserve scheduling algorithm incorporating constraints imposed by grid security considerations, which include one base case (intact system) and a list of credible contingencies (line out, unit lost, and load growth) of the system. By following a cost-minimizing co-optimization procedure, both power and reserves are allocated spatially for the combined energy and reserve markets. With the Lagrange multipliers obtained, the scheduling algorithm also reveals the locational shadow prices for the reserve and energy requirements. Unlike other pricing and scheduling methods in use, which are usually ad hoc and are based on engineering judgment and experience, this proposed formulation is likely to perform better in restructured markets when market power is a potential problem. An illustrative example of a modified IEEE 30-bus system is used to introduce concepts and present results.

Industrialization, urbanization and land use in China

Rapid industrial development and urbanization transfer more and more land away from agricultural production and affect the patterns of land use intensity. This paper analyzes the determinants of land use by modeling arable land and sown area separately. An inverse U-shaped relationship between land use intensity and industrialization is explored both theoretically and empirically. The findings highlight the conflict between the two policy goals of industrialization and grain self-sufficiency in the end. Several policy recommendations are offered to reconcile the conflict.

Transmission System Planning-The Old World Meets The New

Transmission systems in the United States and around the world have become more difficult to plan under deregulation. Uncertainties in generation type, location, and pricing coupled with market mechanisms that encourage transfers not designed for in the legacy transmission system have made the transmission planners life difficult. This paper describes the planning process under regulation, some of the issues encountered during the present transition to a deregulated industry, and some of the open questions that need to be addressed in the United States.

Welfare effects of improving end-use efficiency: Theory and application to residential electricity demand

Abstract This paper applies the money metric approximation to the Hicksian equivalent variation and the generalized logit model of consumer demand to the analysis of the welfare effects of end-use efficiency improvements in various electricity conservation options. The results are compared with the standard cost-effectiveness criterion based on the net present value of energy conservation investments. If the assumptions implicit in the use of this criterion hold, namely, zero end-use price and income elasticities, the net present value of an investment will be the same as the money equivalent of the net welfare change calculated by the money metric. However, the standard net present value becomes less accurate as a measure of welfare change as the end-use price and income elasticities differ significantly from zero. The money metric welfare change measure is theoretically more accurate. It is also more general since it encompasses cases where the above assumptions of the net present value criterion do not hold, i.e, net present value is a special case of the money metric.

A uniform price auction with locational price adjustments for competitive electricity markets

Competitive electricity markets which rely on centralized dispatch require a mechanism to solicit offers from competing generators. Ideally, such an auction mechanism provides incentives to submit offers equal to the marginal cost of generation for each generator. Economic theory suggests that the Uniform Price auction is an appropriate institution. However, an efficient implementation of this auction in an electricity context requires that the offers used in the auction reflect the appropriate locational price adjustments for transmission losses and congestion. This paper describes a uniform price auction that incorporates locational price adjustments on a Web-based platform suitable for experimentation. Preliminary results show dramatically different price and revenue results when compared with a simple continuous Discriminative auction.

Electricity demand growth and the energy crisis

The research reported by D. Chapman, T. Tyrrell, and T. Mount [Science 178, 703 (1972)] was sponsored by the National Science Foundation Program of Research Applied to National Needs.

Identification of load pockets and market power in electric power systems

In this paper, we present a spectral method for the identification of load pockets and the application of practical techniques for the measurement of market power. Market power is a serious concern in electric energy markets, especially in the area of a load pocket. Common definitions for market power, which rely on a comparison between market prices and a so-called competitive price, are difficult to use in practice because the competitive price is not known when the market is not competitive. The competitive price cannot be computed from data naturally available to the market. Our technique focuses on the identification of participants with the ability to increase revenues by increasing prices, an ability not present in a competitive market. We then propose measures for quantifying the extent to which market power is being exercised. These measures can be computed from data available to the market; they are practical. We present results from a 30 bus, 6 generator system, which illustrates that generators in a load pocket have and can exploit joint market power.