Let me tell a story. A consultant I know works as the lead negotiator for a Native American tribe that sells fuel to electric generating plants. On occasion he visits the reservation to discuss business plans with the tribe, exploring various scenarios for utility restructuring.

Recently, this consultant said he found himself in the ceremonial council lodge, instructing tribal leaders on decision trees and discounted cash flows. When he finished, the younger members conferred briefly in their native language. Then they turned to the eldest member of the tribe, sitting quietly in a corner. The elder stood, spoke a few words, and sat again.

After a polite pause, the consultant asked, "What did he say?"

The answer came back. "The elder does not understand your figures, but he says he has seen a vision (em that you will help us prosper. And so, we accept your plan."

My consultant friend holds great respect for the traditions of Native Americans. He recounts this story only to show the astonishing range of issues involved in utility restructuring.

Later, the consultant repeated his story to a lawyer working with him on another case. The lawyer thought for a moment: "That sounds just like the jury system," he said.

Savings Prove Illusive

Writing last month in the Wall Street Journal, Benjamin Holden reported that electric customers in California won't likely see that entire 10-percent rate cut promised last year in the state's landmark deregulation law. ("Electricity Savings to Be Short-Circuited," Sept. 24, p. A2.) Says Holden, "[M]any experts estimate rate cuts for medium-size customers, such as grocery stores or office buildings, at no more than seven percent."

Hey, 7 percent ain't so bad. That figure falls in line with estimates by the Illinois Commerce Commission in its report on proposed state Senate Bill 55.

The ICC report (which levels a scathing attack at the senate bill), predicts savings (net present value) for Illinois' four major electric utilities over the 1998-2008 transition period: Commonwealth Edison (9.2 percent), Illinois Power (10.6 percent), Central Illinois Public Service Co. (4.5 percent), and Central Illinois Light (4.2 percent). Commercial customers might save only 2.8 percent, statewide. The ICC projects rates for ComEd and IP "will remain above the current Midwest average [Illinois excluded] for much, if not all, of the transition period."

Few customers, said the commission, will find it advantageous to switch suppliers. In Illinois, the bill would also impose a transition cost surcharge (different from the "instrument funding charge" to cover securitization bonds). Customers switching suppliers would receive a credit against transition charges, known as the "mitigation factor," to mimic savings achieved from alternative suppliers.

The bill sets the initial mitigation factor at 6 percent for residential customers, worth only about 0.5 cents per kilowatt-hour, assuming a residential rate of 8.4 cents per kWh. When all is said and done, notes the ICC, there's little incentive to switch: "While some customers may achieve more savings than allowed by the mitigation factor, through their ability to 'beat the market,' other customers may find that transition charges to the incumbent utility, regardless of the price of power on the open market, are such that the possible gain from switching suppliers is minimal or nonexistent." (Text on ICC's Internet site: www.state.il.libdocs/sb55.)

The situation appears no different on the gas side. In a speech earlier this year, James Hoecker of the Federal Energy Regulatory Commission drew attention to a failure of trickle-down economics in natural gas. I didn't hear the speech, but I read a summary prepared by Consolidated Natural Gas Co. (See, FERC Docket No. PL97-1-000, Issues and Priorities for the Natural Gas Industry.) According to CNG, Hoecker said that while the city gate price of natural gas in California fell from $2.90 to $1.99 per Mcf from 1990 to 1995, the cost to residential customers actually rose (em from $5.99/Mcf to $6.64/Mcf.

On a nationwide basis, says CNG, wellhead costs have declined by 9 percent over the same period, while residential gas prices have increased by 4.5 percent. The company muses on what it all means:

"These and similar price trends may have led Commissioner Hoecker in his speech to suggest that the reason for these trends is that a seamless, competitive gas delivery system has not yet been achieved."

Unbundling Seen Problematic

In its recent position paper, The Future of the Natural Gas Industry, released Sept. 4, the staff of the New York Public Service Commission recommended new strategies for local distribution companies. First of all, "LDCs should exit the merchant function to establish a fully competitive commodity market." (Text: www.dps.state.ny.us/fileroom/doc2990.t.)

Many LDCs would agree. But wait a minute. Once evicted from the merchant business, LDCs will become more like gas pipelines, who were forced out of commodity markets by the FERC in Order 636. And guess what? The pipelines now want back in. They say they need to rebundle commodity and capacity services to stay in business, compete against the "gray market" and capture the "value" of their assets.

Everywhere in energy, regulators are having difficulty unbundling production from pipes and wires. For them it's a matter of survival. Their jurisdiction extends only over transmission, so they must keep it separate from production, or be out of a job.

In electricity, it's an old saw that generation can substitute for transmission, like energy for mass. The most creative proposals for pricing and allocating transmission involve nodal and zonal schemes that analyze differentials in commodity prices. That's what a lot of the debate is about in restructuring power pools (em how to maintain a transparent commodity market that stays independent from transmission constraints.

Now consider this oddity. On Aug. 1 (Decision 97-08-058), the California Public Utilities Commission denied authority to Pacific Gas & Electric Co. to use derivatives (futures, options and swaps) to manage price risk for electricity. Why? PUC rules say that PG&E must buy and sell power through the state-regulated power exchange. But with derivatives, the PUC says, "PG&E could be put in the position of having to take or make delivery of electricity outside of the PX if it is unable to find a buyer for such an instrument before the maturity of the contract. ... We find that taking physical delivery under a derivatives transition would be in violation of the mandatory buy-sell requirement."

In short, when utilities invest in long-term capacity in transport markets, the value of the position is linked directly to commodity prices. To balance risk, utilities must straddle commodity and capacity markets.

The Williams Cos. put it bluntly: "Pipelines should be allowed to rebundle services without regulatory impediments."

Editor

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