Power suppliers need flexibility in securing supply arrangements and should be allowed to use risk management tools, including long-term contracts, other hedging tools and, if need be, ownership of generation, against the backdrop of state-level efforts to craft and successfully implement retail electricity restructuring plans, said the Edison Electric Insititute (EEI) in recent comments filed with the Federal Trade Commission.

“As most observers have recognized, one of the major flaws of the California model was the requirement that the utilities, having divested most of their fossil generation, purchase everything from the spot market, without the benefit of risk hedges, either from long-term contracts with generators or ownership of power plants,” EEI said. This design flaw in turn placed utilities in a “price squeeze” every time the spot wholesale price exceeded the retail price caps, according to EEI.

As the number of price spikes increased, EEI continued, utilities “found themselves careening toward insolvency with billions of dollars of costs that could not be recovered from customers.” The association of power companies found the state erred in restricting utilities’ use of market tools, adding that mandatory divestiture of generation is “not likely to be a good idea.”

EEI made its comments in response to a late February announcement by the FTC that it would look into “possible jurisdictional limitations” on states’ authority to design successful retail power competition (see NGI, March 5). The FTC plans to issue a report that discusses the advantages and disadvantages associated with different approaches to specific electric restructuring issues, as well as identifies what additional federal legislative or regulatory actions may be needed.

EEI emphasized the point that effective hedging requires regulatory certainty in order to prevent “post-hoc allowances.” By way of example, EEI noted that at first California utilities were prohibited from using risk management techniques. However, once risk management measures were allowed, utilities were worried that any money saved by risk management would be passed onto customers, while any risk management that lost money would be absorbed by shareholders. “With such lose-lose options, a utility’s incentives to hedge risks is minimal,” EEI asserted.

Meanwhile, the National Rural Electric Cooperative Association (NRECA) took a slightly different approach than EEI in its comments, responding to specific questions posed by the FTC as part of its probe.

Among other things, the FTC asked for comment on what factors or measures it should examine in viewing the success of a state’s electricity competition program and how those measures should be evaluated.

In response, NRECA said that the two overriding criteria the commission should examine are price and quality of service. NRECA went on to say that a state’s retail electricity competition program should only be labeled a “success” if it is conclusively shown that the program has resulted in lower prices to consumers through competition, and not as a result of temporary, state-mandated rate cuts. Also, NRECA said that consumers should be receiving the equivalent or better service in terms of reliability.

The FTC also sought comment on the benefits or drawbacks of the different approaches to handling the supplier of last resort obligation for customers who do not choose a new supplier. More specifically, the agency ask if a provider of last resort is necessary.

NRECA responded that provider of last resort service is “absolutely necessary,” not only for customers who do not choose a new supplier, but also for customers who have no choice of supplier because no supplier has chosen to serve them. “Because electricity is an essential public service, the buck must stop somewhere; that is, there must be an entity that has the ultimate obligation to provide generation service to consumers at a reasonable rate,” the association added.

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