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Electric Mergers: Transmission Pricing, Market Size, and Effects on Competition

Fortnightly Magazine - June 1 1996

companies of generation assets in markets remote from the geographic markets in which they now operate.12 The merger of the future, therefore, will likely involve the acquisition of generation assets in distinct geographic markets (em for example, a generating utility in New England acquiring a generating company in the Southeast.13 Once the new blueprint for the industry is better established as a model for policymaking, regulators may well condition the merger of vertically integrated utilities in the same region upon a requirement to divest the vertical components into separate transmission, distribution, and generation companies, and upon a further requirement that the generation company divest a significant portion of its generating assets.14 t


Carmen D. Legato is a partner and head of the energy practice of the law firm White & Case in Washington, DC, and a member of its worldwide Energy & Project Finance Group. He also counsels a number of stakeholders on the restructuring of the electric utility industry. Mr. Legato played a pivotal role in the restructuring of the natural gas industry, arguing the landmark Maryland People's Counsel and AGD cases that resulted in FERC's issuance of Order 436, and in 1986 he predicted the commoditization of the natural gas market in Drawing The Line on Regulation, The Harvard Study For The Future of Natural Gas. He is a former law clerk to the Hon. William J. Brennan, Jr., Associate Justice Supreme Court of the U.S. (1977 Term). Mr. Legato is grateful for the valuable assistance of Lisa A. Cottle, an associate at White & Case, in preparing this article.

1. Horizontal Merger Guidelines of 1992 (Merger Guidelines), Department of Justice and the Federal Trade Commission, 4 Trade Reg. Rep. (CCH) (pp 13,104 (1992).

2. A postage-stamp rate establishes a single price for delivery between any points of supply and delivery on the transmission system, regardless of mileage.

3. This range was calculated using the rates for point-to-point transmission service filed with the FERC by Duke ($15.89/Kw/year), Southern ($21.72/Kw/year), and Santee Cooper ($22.48/Kw/year). Assuming a load factor of 50 to 75 percent and a total cost of delivered power to a distribution utility of between 4 and 5 cent/Kwh, the cost of transmission will be between 4.8 and 12.8 percent of the total cost of delivered power. Although these rates are subject to investigation and possible reduction by the FERC, such reductions would only marginally reduce the transmission cost as a percentage of the delivered cost of power.

4. This range was calculated in the same manner as the percentages for utilities in VACAR. The selected utilities within MAIN filed proposed transmission rates between $12.04/Kw-year and $19.20/Kw-year. Applying these rates, transmission costs will be 3.7 to 11 percent of the total cost of delivered power.

5. Note, however, that the conclusion regarding transmission costs does not necessarily apply to services like load-following or reserve requirements that are called upon infrequently. Because the additional transmission costs might not be incurred often (assuming a secondary market for transmission), their effect on total cost is less, and the affected area from which