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Notes - A Comparison of Original Costs and Trended Original Cost Ratemaking Methods

Robert E. Anderson and David E. Mead

Year: 1983
Volume: Volume 4
Number: Number 2
DOI: 10.5547/ISSN0195-6574-EJ-Vol4-No2-11
No Abstract









Competitive Bidding In Electricity Markets: A Survey

Richard P. Rozek

Year: 1989
Volume: Volume 10
Number: Number 4
DOI: 10.5547/ISSN0195-6574-EJ-Vol10-No4-8
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Abstract:
A number of states as well as the Federal Energy Regulatory Commission have been considering whether traditional regulatory regimes in electricity and natural gas markets should be replaced with competitive bidding systems. This shift is designed to yield a more efficient allocation of energy resources within the existing legal framework The paper examines both the theoretical basis and empirical evidence on bidding processes in light of the characteristics of energy markets, especially electricity markets. It then discusses the extent to which one can draw policy conclusions about designing specific bidding processes for these markets. It concludes that given the underlying complexity of the products involved, the optimal system for procuring power should include a mix of bidding negotiation and utility construction.



Marginal Capacity Costs of Electricity Distribution and Demand for Distributed Generation

Chi-Keung Woo, Debra Lloyd-Zannetti, Ren Orans, Brian Horii and Grayson Heffner

Year: 1995
Volume: Volume16
Number: Number 2
DOI: 10.5547/ISSN0195-6574-EJ-Vol16-No2-6
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Abstract:
Marginal costs of electricity vary by time and location. Past researchers attributed these variations to factors related to electricity generation, transmission and distribution. Past authors, however, did not fully analyze the large variations in marginal distribution capacity costs (MDCC) by area and time. Thus, the objectives of this paper are as follows: (1) to show that large MDCC variations exist within a utility's service territory; (2) to demonstrate inter-utility variations in MDCC; and (3) to demonstrate the usefulness of these costs in determining demand for distributed generation (DG).



An Institutional Design for an Electricity Contract Market with Central Dispatch

Hung-po Chao and Stephen Peck

Year: 1997
Volume: Volume18
Number: Number 1
DOI: 10.5547/ISSN0195-6574-EJ-Vol18-No1-4
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Abstract:
In Chao and Peck (1996), we introduced a new approach to the design of an efficient electricity market that incorporates externalities due to loop flows. This approach enables an innovative flow-based bidding scheme for pricing transmission services. In the short term, due to some technological constraints, a hybrid institutional structure that encompasses a decentralized contract market (via the system operator) is necessary for implementation. In this paper, we present an incentive scheme that fosters efficiency and reliability within such art institutional structure. An essential ingredient is that the system operator provides all electricity traders choices of priority insurance against interruptions. We show how this scheme will ensure the integrity of the electrical contract market and provide the system operator incentives to maintain system reliability in all efficient manner in real-time dispatch.



Implementation of Priority Insurance in Power Exchange Markets

Robert Wilson

Year: 1997
Volume: Volume18
Number: Number 1
DOI: 10.5547/ISSN0195-6574-EJ-Vol18-No1-5
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Abstract:
Traders in a power exchange can use insurance to hedge against losses from curtailment by the system operator. If the system operator is liable for these reimbursements then its incentives encourage efficient real-time dispatch. This paper reviews the details of implementing such a scheme when third-party insurers offer insurance in an auxiliary competitive market, or the power exchange operates as a mutual insurance association of the traders. Because higher reimbursements entail higher service priorities, the actuarial premium for pure insurance must be accompanied by a surcharge for service priority. The amount of this surcharge can be inferred from the price of pure insurance. The Appendix shows that omission of this surcharge distorts traders' incentives in the power exchange.







Customer Retention in a Competitive Power Market: Analysis of a 'Double-Bounded Plus Follow-Ups' Questionnaire

Yongxin Cai, Iraj Deilami and Kenneth Train

Year: 1998
Volume: Volume19
Number: Number 2
DOI: 10.5547/ISSN0195-6574-EJ-Vol19-No2-12
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Abstract:
A model is developed and estimated that forecasts the share of an electric utility's customers who would switch to a competitor under various price discounts and service attributes (reliability, renewable power, energy conservation assistance, and customer service.) The method builds upon previous double-bounded dichotomous choice procedures, extended to account for the multi-attribute nature of electric power service.



Simulating the Operation of Markets for Bulk-Power Ancillary Services

Eric Hirst and Brendan Kirby

Year: 1998
Volume: Volume19
Number: Number 3
DOI: 10.5547/ISSN0195-6574-EJ-Vol19-No3-3
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Abstract:
The U.S. Federal Energy Regulatory Commission (FERC) requires electric utilities to offer six ancillary services. Most of the tariffs filed with FERC price these services on the basis of traditional cost-of-service (embedded) costs, Because most of these services are provided by generating units, however, it should be possible to create competitive markets for them. This paper describes, the structure of, and results from, a spreadsheet model that simulates markets for seven services: losses, regulation, spinning reserve, supplemental reserve, load following, energy imbalance, and voltage support. The model also analyzes, system control, although this service will continue to be provided solely by the system operator under cost-based prices. Developing this computer model demonstrated the likely complexity of markets for energy and ancillary services. This complexity arises because these markets are highly interdependent. For example, the cost of regulation (the frequent change in generator outputs to track the minute-to-minute fluctuations in system load) depends strongly on which units, are already being dispatched to provide energy and losses, their variable costs, and their operating levels relative to their maximum and minimum loading points.



The "Regulatory Compact" and Implicit Contracts: Should Stranded Costs be Recoverable?

James Boyd

Year: 1998
Volume: Volume19
Number: Number 3
DOI: 10.5547/ISSN0195-6574-EJ-Vol19-No3-4
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Abstract:
Progress toward electricity market deregulation has brought controversy over whether or not utilities are entitled to compensation for "stranded costs", i.e., costs utilities will not be able to recover due to the advent of competition in their markets. This paper uses a legal and economic analysis of contracts to address the desirability of utility cost recovery. First, underlying principles of law are reviewed to determine whether or not there is a legal presumption of recovery. Then, the analysis considers whether or not an implicit "regulatory compact" between utilities and regulators follows from principles in the economic analysis of law, particularly theories of efficient breach and implicit contracts. The paper concludes that recovery should occur in only a proscribed set of circumstances and that, when called for, compensation should be partial, rather than full.




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