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Transmission Asset Sales: Running the Regulatory Gauntlet

There are many considerations and obstacles to overcome before transmission assets can be bought or sold.
Fortnightly Magazine - May 15 2003

divestiture includes, after the identification of the power lines, substations, and other assets likely to be divested, a calculation of the past and projected earnings attributable to these assets. At the same time, the utility must examine its credit agreements, loan agreements, and other financial instruments to determine whether there are any significant impediments to a sale. This review should also determine if the sales proceeds must be dedicated to the payoff or retirement of any specific obligations.

As part of the planning process, the utility also must consider basic organizational issues. Once the separate entity is set up, the interdependent relationships among the transmission entity, generation, and local distribution do not end. In order for regulators and company managements to be comfortable, arrangements-usually written contracts-should be in place to govern transactions between these disaggregated entities for the near and intermediate terms.

Once a utility decides to move forward, a first step is typically the transfer of assets and personnel to an affiliate and the negotiation of a number of contracts with the new affiliate. Stand-alone salary and benefit programs have to be designed for the employees of the new entity to ensure that its management will truly be independent of the divesting electric company. Transmission assets have to be identified with specificity and transferred. 12 Key contracts to be performed on transmission lines by the distribution utility should be negotiated and signed to cover operation and maintenance, construction, and administrative services. Such contracts also should address right-of-way ownership and expansion rights, 13 interconnection agreements, transmission agreements, membership in the RTO, and assumption by the ITC of agreements made by its predecessor.

While these all could be negotiated in the first instance between the divesting electric company and the independent transmission company, the more practical approach-the one taken by all sellers thus far-has been to work with an affiliate to structure the basic framework of the new transmission entity, with refinements as part of the negotiation process with the purchaser of the new entity (i.e., a stock sale, not an asset sale).

  1. The number of companies announcing a desire to raise capital and improve their capital structures is legion. See, e.g., American Electric Power, news release dated Jan. 24, 2003, http://www.aep.com/investors/financialreleases/default.asp?dbcommand=DisplayRelease&ID=986&;Section=Financial&colorControl=on. Few have publicly identified transmission as a non-core assets suitable for divesture.
  2. See, e.g., Illinois Public Utilities Act §16-111(g), 220 ILCS 5/16-111(g).
  3. The Pennsylvania Public Utility Commission has strongly supported standard market design. See, e.g., press release dated Jan. 13, 2003, http://puc.paonline.com/press_releases/Press_Releases. asp?UtilityCode=EL&UtilityName=Electric&PR_ID=956&View=PressRelease , Comments filed Jan. 10, 2003, Docket No. RM 01-12.
  4. See, e.g., http://biz.yahoo.com/p/electupriu.html.
  5. The FERC's assertion over all transmission rates other than those bundled with retail sales was upheld in New York v. FERC, 535 U. S. 1 (2002), in an opinion that contains dicta to support FERC jurisdiction over all transmission, including services bundled with retail sales.
  6. See Uniform System of Accounts for Utilities Subject to the Federal Power Act, Electric Plant Instruction 2; 18 CFR 298; Montana Power v. FERC, 599 F.2d 295, 300 (9th Cir. 1979); Niagara Falls Power Co. v. FPC, 137 F.2d