The transmission superhighway still needs major investments. Rate incentives were working -- until FERC started backing away from them. FERC should assert its authority more aggressively to...
A Brief History of Rate Base: Necessary Foundation or Regulatory Misfit?
Regulators today must define earnings for energy retailers virtually bereft of fixed assets.
Electric Power Co. (PEPCO). PEPCO proposed and the PSCDC approved, a margin component to the administrative charge that was “designed to compensate PEPCO for any regulatory and market risk it assumes as the administrator of SOS.” In approving the margin component, the PSCDC stated, “the margin proposed here by PEPCO is akin to the return on equity that utilities earn in traditional rate cases. Its purpose is to compensate PEPCO for the risks associated with serving as the SOS provider. In contrast, PEPCO’s cash working capital and capital investment costs are direct costs that will increase as a result of PEPCO’s obligation to serve as SOS provider. As such, these costs are incremental in nature and recover- able through SOS rates.” In Enmax Energy Corp., Decision 2006-001 2005 Regulated Rate Tariff non-Energy, (Jan. 13, 2006), the Alberta Energy and Utilities Board approved a non-energy margin of 6 percent on forecasted non-energy charges and an energy margin of 1 percent, for a notional composite margin of about 1.6 percent.
2. See San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Services Into Markets Operated by the California Independent System Operator and the California Power Exchange, Order of Clarification, 112 FERC ¶61,249 (Sept. 2, 2005) FERC stated that its intent was to “establish a weighted cost of capital return percentage as a substitute for a rate-of-return established by traditional discounted cash flow.” Thus, the commission substituted a 10 percent rate of return for a more traditional rate-of-return percentage calculated with a discounted-cash-flow analysis. This 10 percent return was then to be applied to the company’s long-term investment in plant or cash pre- payments (cash equivalents). In an earlier decision in AEP Power Mar- keting, Inc. et al., Conference on Supply Margin Assessment, Order on Rehearing, 108 FERC ¶61,026 (July 8, 2004), the commission found that in the limited instance of power sales of one week or less, it was “just and reasonable to price sales of power at the applicant’s incremental cost plus a 10 percent adder.” Here, the 10 percent adder was used as a “backstop” if an applicant chose not to propose its own mitigation. The commission concluded that “incremental costs plus 10 percent represents a conservative proxy for a reasonable margin available in a competitive market.” However, in the California refund case, the commission specifically stated that its reference to the AEP case was done to support the 10 percent as a reasonable return percentage. In that case, the 10 percent was applied, as we noted, to long-term investment in plant or cash prepayments, and not to incremental costs as was done in the AEP case.
3. 169 U.S. 466 (1898).
4. 320 U.S. 591 (1944).
5. Volume I, p. 37.
6. Volume I, p. 41.
7. Volume I, p. 41, footnote 51.
8. Bonbright, James C., Albert L. Danielsen, David R. Kamerschen, Principles of Public Utility Rates , Public Utility Reports, Inc., Arlington, Virginia. 1988 (First Printing 1961), p. 217.
9. Bonbright, p. 212.
10. Bonbright, p. 218.
11. Bonbright, pp. 219-220.