With benefits unclear, PUCs will "go slow."

California, New Hampshire, Massachusetts, Nevada, Pennsylvania, Rhode Island, and Vermont have given customers the right to choose their electric providers.

Other states are considering similar legislation.

In Congress, U.S. representatives Schaefer (R-Colo.), Markey (D-Mass.), DeLay (R-Tex.), and U.S. Sen. Bumpers (D-Ark.) and others have slapped bills on the table that would give choice to electric customers on a national scale. In a recent article, The Wall Street Journal confirmed evidence of looming competition: "The rapidly unfolding deregulation and consolidation of the utility industry is spawning a profusion of takeover deals among retail, wholesale, regional and national power providers." (Mar. 20, 1997).

Yet, despite all this hubbub, competition is less likely today than it was a year ago.

Two factors underlie this paradox. First, any government that contemplates competition will face the near insurmountable task of dealing with the stranded costs and benefits that will follow. Second, these costs and benefits are likely grossly understated or simply unrecognized.

What assets and benefits will lie stranded? How should the write-offs be accomplished? Who should pay? These problems will pit electric customers (em business, residential and commercial (em against their utilities, and even against each other.

Moreover, the costs and benefits of competition will spread unevenly across the country, making some states winners while others lose out. Customers will not gain from competition until we can answer "what," "how" and "who."

The Numbers Are Daunting

Stranded costs, representing the uneconomic generation assets of electric utilities (i.e., generation assets valued below their book value because of their high capital and/or operating costs), are estimated at between $100 billion and $550 billion. Moody's Investors Service, for example, estimates stranded costs for all electric utilities to exceed $100 billion. Others have put the total as high as $550 billion, which exceeds the $500-billion bailout of the savings and loan industry.

In some states, however, the electric utilities (and consumers) enjoy low-cost production. This enviable position gives them the opposite problem (em how to deal with stranded benefits. In these states, generation assets are valued above book value because of their low capital and/or operating costs. Because state public service commissions set rates based on book value, the surplus in value becomes stranded just as certainly as a surplus in cost. Benefits are stranded in the sense that local electric utilities are required to provide the lowest-cost electric service in their territories, even though there are potential open-market opportunities at higher prices than the prices set by the state commissions.

The precise value of these costs and benefits is crucial, but unknown. It will likely fall to the Federal Energy Regulatory Commission and the state public utility commissions to come up with estimates, since it appears safe to say that no legislation authorizing customer choice will include actual calculations of who pays, who gets paid, how much, when and for how long.

How will regulators respond?

Decisions at the FERC and the PUCs will hinge on such data as the estimates of the values of generation assets within a given region. Significantly, such estimates also depend on forecasts of capital and operating costs, broken down by hour over a number of years. The mathematics are daunting. Relatively small changes in fuel cost estimates, the assumed lives of existing plants, the costs and number of new plants in a competitive market, and expected constraints on the transmission system will exert a significant impact on such forecasts. Forecasting is further complicated by the assumption that competition will begin at some unknown date in the future (em in the year 2000, for example, or perhaps 2002 or later. That hundreds of generators will compete with each other within certain regions of the country must also be assumed, adding more complexity. In short, any estimate of future market prices for electricity, which determines whether existing generating assets are worth more or less than their book values, must anticipate the future costs of building and operating hundreds of generation plants in assumed competitive markets in assumed regions of the country beginning at some assumed date. To say that the "devil is in the details" portends of considerable understatement.

Coincidentally, while state regulators may know the "devil" from their years of battling with customers and utilities, they are not likely to know the "details."

Electric utilities in the various states are currently estimating the value of their generating assets. Wall Street firms and credit rating agencies are gathering their own estimates. So, too, are the FERC, and the staffs of the PUCs and the nationwide army of utility management consultants. Meanwhile, no consensus data base exists that might help regulators even to begin to guess at where electricity prices might end up. With no good handle on the numbers, they cannot predict the extent of stranded costs and stranded benefits, if any, in their respective jurisdictions. And without a "warm and fuzzy" feeling about stranded costs and stranded benefits, they will not know the potential impact of their decisions on customers and utilities. All this will translate into a "go slow" approach, particularly among the state PUCs, which hold jurisdiction over 90 percent of all generating assets.

And the Target is Moving

Now comes the real dilemma. After forging policy to fit the assumptions, regulators and lawmakers must then sit back and watch as the market responds, undoing even the best-laid plans.

To allow utilities in their jurisdictions to write off their stranded costs, regulators in high-cost states likely will be forced to boost customer bills beyond the nominal regulated rate. This added charge could nullify the expectations of customer choice. A customer could end up paying the same total charges, no matter who provides the electricity, once the transition surcharge is added to the bill.

For example, a customer who pays 6 cents per kilowatt-hour before deregulation, and can purchase electricity after deregulation from any one of several competing utilities, including his local utility, at 5 cents per kWh, will find no incentive to switch to another provider if a 1-cent per kWh stranded costs charge is tacked onto his bill. The customer enjoys the power of choice, but why bother?

In fact, because stranded costs are expected to represent accelerated write-offs of uneconomic assets, the customer could end up paying the 5-cent competitive price plus a stranded costs charge of more than 1 cent. This scenario would make his present, regulated rates more attractive than any choice in a competitive market (at least in the short run). Customers will see little incentive to shop around if they are going to end up paying roughly the same or higher prices for electric service regardless of provider.

Making competition work in low-cost states will prove equally problematic. After all, it takes a willing buyer and a willing seller to make a market. Legislatures in California, New Hampshire, Massachusetts, Nevada, Pennsylvania, Rhode Island and Vermont took the plunge because their electric rates substantially exceeded the national average. Presumably, lawmakers in these states expect their rates to fall. But other states, like Kentucky, Tennessee, Utah, Virginia and Wyoming remain cautious about embracing competition. Their utilities already provide low-cost power. Their customers are enjoying stranded benefits in real time. While a competitive market may reduce overall prices in the long run, it certainly is not clear that states with low-cost utilities will come out ahead in either the short- or long-term. To do so, the national equilibrium for electric rates must stay equal to or fall below the current average rates in low-cost states. %n*%n

Of course, low-cost utilities are poised to play in the open market. But that doesn't guarantee a workable transition.

With rates in some regions of the country more than double those in other areas, market opportunities loom large for low-cost utilities. To illustrate, a price difference of 1 cent per kWh would mean tens of millions of dollars in annual revenue to a low-cost energy provider (em even to one of medium size. Low-cost utilities may view these disparities as revenue opportunities, but regulators in low-cost states see the possibility that competitive prices might boost rates to local consumers (em their constituents. Clearly, they are not likely to foster competition to lower national prices if there is a good chance that their efforts might raise local electric rates.

Why Hurry?

How should policy makers react to the deregulation momentum? Do they get on board and make multi-billion dollar decisions based on "loosey-goosey" estimates from "black boxes," or do they take a "wait and see" approach?

Here's my guess. In high-cost states, the powers that be will make a "black box" decision. Meanwhile, in low-cost states, the decision will be to "wait and see" what works. And, with enough of these "wait-and-see" decisions, as I expect there will be, the electric deregulation movement will surely stall (though it may not die completely).

Edward L. Flippen is a partner in the law firm of Mays & Valentine LLP. He has lectured on public utilities at the University of Virginia School of Law and on economic regulation at the T. C. Williams School of Law, University of Richmond and at the Marshall-Wythe School of Law, College of William and Mary. He is lecturing on economic regulation at the Washington & Lee University School of Law this fall. A version of this piece was published in the April issue of European Financial Services.

*Electric rates to industrial firms served by IOUs average below 4 cents per kWh in Idaho, Iowa, Kentucky, Oklahoma, Oregon, Tennessee, Texas, Utah, Virginia, West Virginia, Wisconsin and Wyoming. They average above 6 cents per kWh in California, Connecticut, Maine, New York and Vermont, and above 8 cents per kWh in Hawaii, Massachusetts, New Hampshire, New Jersey and Rhode Island.

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