But does anyone know the real price of power?

You've read the headlines from Maine - how regulators asked for bids for competitive electricity but got prices higher than the old regulated rate.

But it gets worse. The more open the market, the higher the bid.

Central Maine Power and Bangor Hydro-Electric operate within ISO New England, which now is open for competition. Yet according to the Maine Public Utilities Commission, the bids from suppliers offering to serve those two utilities came in higher than bids for Maine Public Service Co., in the Maritimes control area in Canada. That market is not yet open. New Brunswick Power is the dominant utility there. What gives?

"We would not expect significantly higher prices for the CMP and BHE areas," said the PUC. "It is possible that the immaturity of the ISO-NE markets, the changing nature of the market rules, the extremely high spot market prices at certain times over recent months, and uncertainty regarding transmission pricing and other matters in the region may all be contributing factors."

Maybe it was bad timing. As the PUC noted, other states in New England were soliciting offers at the same time, "possibly impacting the bids in Maine."

Nearby, in Connecticut, regulators mulled the opposite problem. Should they accept a low-priced bid if there is no competitive bidding? In late July, United Illuminating Co. had reached a tentative settlement whereby Enron would furnish power for those UI customers electing to take the standard offer instead of choosing a competitive supplier. That settlement offered a residential generation service charge (GSC) of 4.05 cents per kilowatt-hour, which met the 10 percent cut mandated by Connecticut law. Moreover, under the four-year deal, UI customers would bear no risk of future price changes in fuel or wholesale energy.

But the state attorney general wasn't happy. The Enron/UI settlement had not emerged from competitive bidding. Was it the lowest available? The AG argued, "If GSC rates are not reflective of the market price, then they are likely to either stifle competition or impose [an] unnecessary stranded cost burden upon consumers after 2003." The PUC also weighed in: "UI and Enron do not necessarily have conflicting positions on some issues included in the agreement."

So which is it: Price or process?

In Maine the PUC accepted two bids for MPS (including a bid of 4.29 cents for residential generation), but rejected the bids for CMP and BHE. Instead, it announced a new solicitation that would allow suppliers to combine their offers with bids on the output of a utility's non-divested generation assets. The PUC set no price ceiling, but warned bidders that it had "a strong inclination" to accept only those bid prices offered at or below the winning MPS levels. (Docket No. 99-111, Oct. 25, 1999.)

Back in Connecticut, the PUC set standard offer rates for United Illuminating in a decision issued Oct. 1, but asked the parties to rework their deal, which they did on Oct. 15, according to UI spokeswoman Myra Stanley. When contacted on Oct. 28, PUC rep Beryl Lyons said the commission had not yet acted on the new plan (or even decided whether to hold new hearings). But she predicted that the PUC might issue a schedule for the case during the first week in November. (Docket No. 99-03-35, Oct. 1, 1999.)

THE PRICE OF POWER DEPENDS ON THE PRODUCT. It also depends on how you do the math. When regulators design a standard offer for default service for customers who elect not to switch, should they start with the bundled regulated price and then back off all the various unrelated items, such as transmission, distribution, marketing and account costs, system benefits charges, stranded cost securitization and so forth, yielding a residual credit for the energy? It seems simpler at first just to calculate the cost of generation, but that raises the question, What costs belong in the generation function? Consider these issues, which highlight areas of possible confusion in comparing rules from state to state involving distribution tariffs, standard offers and shopping credits:

* Old vs. New Cost. Use data from the last rate case to fix costs for distribution tariff, or require new cost study?

* Supply from Affiliates. Allow parent utility to buy power from subsidiary for standard offer portfolio?

* Incentives. Equate shopping credit to actual cost of power, or add artificial incentives?

* Retailing Costs. Inflate shopping credit to reflect the cost of marketing incurred by competitive suppliers?

* Churn Rate. Add allowance costs associated with frequent customer migration between standard and competitive offers?

* Gaming. Require seasonal shopping credits (peak and off-peak) to dissuade customers from gaming the system with frequent switching?

Connecticut has developed a 30-year electricity market price forecast for New England, pegging energy at 3.205 cents per kilowatt-hour in year 2000. (See News Digest, Sept. 1, 1999, p. 20.) It then defines "wholesale cost" as "market price" grossed-up to reflect load factor, line losses, ancillary services and other items. In the UI case, it noted that Enron had set up its generation charge (same as the shopping credit) to reflect a "higher level of migratory risk" to offset high churn rates for customer accounts, but questioned whether to allow that, given that on Sept. 9, out of concern for "gaming" behavior, the PUC had imposed a 12-month moratorium on customer switching.

In another recent order, the Massachusetts commission rejected a schedule of shopping credits proposed by Western Massachusetts Electric as too low (3.4 cents in 2000, 3.8 cents in 2001, 4.2 cents in 2002). It told WME to recalculate its standard offer generation rate at the "wholesale supply price" identified through the standard offer solicitation, but without any apparent gross-up to reflect ordinary marketing costs incurred by competitive suppliers.

In Ohio, which passed an electric restructuring law just this summer, the PUC staff proposed rules on Sept. 30 asking utilities to file periodic reports including methods to adjust shopping credits. Such adjustments would be used to ensure that migration rates meet the state mandate for 20 percent of customers in each class to have switched to competitive retailers by the end of 2003. That implies no mathematical relationship between generation costs and the shopping credit set by the PUC.

WHAT WOULD A SELF-GENERATOR CHARGE TO SELL BACK TO THE GRID? Would that rate offer a clue on how to price competitive energy? I posed that question to Bill Shanner, at Celerity Energy in Fort Collins, Colo., an engineer who develops and installs distributed generation resources for power customers.

"Try to go to the Chicago Board of Trade and sell a bushel of corn. You can't do it. It ignores the transactional cost. By analogy, you can't expect to get a market price for a block of power smaller than what they are trading on the power exchange."

Shanner believes the economics are "all fouled up," and says that tariffs don't begin to reveal all the factors that affect electricity prices. He continues, "The people who need the energy the most - who will use it to make money - actually pay the least. You've got to factor in the effect of outages on productivity and yield. Capacity is worth a lot more than energy."

Shanner sees little hope for competition to be achieved through regulatory policymaking. "You don't want to be the guy who stands up in the utility church and says there is no god."

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