With Watts to Burn, Utilities Foresee Plants by Outsiders, Conservation

Louisiana, a rural state of bayous and backwaters, overflows with electricity.

Power pours from the Waterford 3 nuclear power plant outside New Orleans, which generates 1,151 megawatts of electricity. Fifty miles up river, the River Bend nuclear plant adds 934 megawatts. On the Mississippi shore, the giant Grand Gulf reactor hums with 1,250 megawatts.

The plants are among 10 facilities built over the past decade to provide Louisiana with electricity. In that time, almost 40% of the nation’s present generating capacity came on line.

But while the watts were piling up, growth in demand for electricity was falling in the South and the rest of the country. With few exceptions, power grids throughout the United States today can produce electricity well beyond customers’ needs.

Basic laws of supply and demand would indicate cheaper electric rates. But the special equations of the utility industry instead mean higher bills, billions of dollars higher, according to one estimate.

This has prompted loud protests from consumer groups and tough rulings by state regulators. It has also created a new, wary attitude, and profound change, among the nation’s utilities.

Utility officials and regulators see a future where power stations will be built and operated by engineering firms and venture capitalists, putting wholesale electricity up for bid. Utilities of the future may manage power demands through conservation rather than construction.

The U.S. Energy Information Administration estimates that the nation’s utilities last year could generate 707,000 megawatts of electricity, while customers used only 496,000. The difference is well over the 20% safety margin considered necessary to fill unexpected demands created by heat waves, cold snaps or idle generating plants.

The size of that difference varies by territory. The region that includes Louisiana, Arkansas, Oklahoma, Kansas and parts of Mississippi, Texas and Missouri has 29% more capacity than is used. The West is awash with power, by 32%; in the Midwest, capacity is 26% over need.

Within regions, utilities have even higher margins. Middle South Utilities, with customers in Missouri, Arkansas, Louisiana and Mississippi, has a 32% margin. Public Service Co. of Indiana, the state’s largest electric utility, today generates enough power to meet its needs well into the 1990s.

Only New England and parts of the Mid-Atlantic region have supplies close to current demand.

In most cases, ratepayers must carry the cost of the multibillion-dollar plants, whether or not all the power is needed.

“Consumers are paying for capacity that is not just excess, but expensive excess,” said Paul Markowitz, a utility analyst for the Energy Conservation Coalition, an alliance of 20 national consumer and environmental groups.

The group, after studying the utility industry, asserted that excess capacity has cost ratepayers nearly $16 billion nationwide.

Overcapacity and accompanying problems follow the industry’s unprecedented success in the years after World War II, when demand for electricity grew by a steady 7% annually.

“That sort of growth means a doubling of demand every 10 years; over 26 years, there was a sixfold increase,” said Charles Komanoff, a New York-based energy consultant who has worked with regulators in 20 states.

Komanoff said that utilities then fell into what the industry calls “the benign cycle.”

“There were economies of scale as they built bigger plants and as transmission lines got bigger and cheaper per unit,” he said. “There was this wonderful phenomenon: Price (rates) went down, demand went up and price went down some more.”

Then came the 1970s.

The 1973 embargo by oil-producing nations tripled the cost of oil, at that time the source of 17% of the nation’s electrical power. The costs of gas and coal used to power generating stations also jumped. Environmental concerns about huge power plants and fears about nuclear power added delays and costs to new construction.

The benign cycle of steady growth ended. Demand fell, to an annual increase of 2% today. The sudden drop caught many utilities with new plants, often large nuclear facilities, on the drawing boards or under construction.

Commonly, the utilities continued the projects, confident that demand for new power would return.

“You had utility managements caught in the middle of building major plants with billions of dollars already invested,” said Mary Kenkel, spokeswoman for the Edison Electric Institute, an association of investor-owned utilities. “You saw managers saying, ‘Should I abandon the plant and the billion-dollar investment?’ ”

Later, the legacy of the energy crunch added to the power surplus. The Public Utility Regulatory Policies Act of 1978 requires utilities to buy power from “co-generators,” such as plants that generate electricity as a byproduct of making something else.

The idea was to save oil, but the reality was that some utilities ended up buying electricity from former paying customers, sometimes under long-term contracts whose rates were based on the high fuel costs of the last decade.

Michael Peevey is executive vice president of Southern California Edison, which buys 8% of its power from co-generators. Peevey said his company could generate that power more cheaply, or buy surplus electricity from Arizona or Pacific Northwest utilities at a lower rate.

“Our estimate is that our customers paid $200 million more this year than they had to,” he said.

Some utilities have tried to sell off excess electricity at wholesale rates. Dozens of Western companies have offered their surplus to California utilities, with few takers. Companies in the Midwest look to New England for customers, but it is unlikely that expensive power lines needed to carry the electricity will ever be constructed.

“How do you convince communities in Pennsylvania and New Jersey to accept transmission lines that offer them no benefits?” said William Sheperdson, a spokesman for the New England Power Pool, a consortium of 95 New England utilities.

While some say the utilities are to blame for their embarrassment of riches because management failed to see the changing times, those within the industry say such accusations are unfair.

“The utilities revised their forecasts downward and further downward,” said David Nevius, vice president of the North American Electric Reliability Council, a utility-supported research group. “Back in 1976, utilities were projecting that 798,000 megawatts would be needed by 1985. What actually was in service was 622,000 megawatts.”

But Alan Nogee, a utility analyst who wrote the energy coalition’s study, said decisions by state regulators permitting utilities to pass on costs of new plants to ratepayers did little to discourage unneeded construction.

“The fact that 90% of total cost of excess capacity has been passed on to ratepayers provides perverse incentive to continue to overbuild,” he said.

State officials now look harder at new power plants as they come on line. Regulatory commissions often prohibit utilities from charging customers the full cost of new plants if their need is questioned.

When the Wolf Creek nuclear plant came on line in 1985, Kansas regulators ruled that nearly half the plant’s capacity wasn’t needed and eliminated that capacity from the rate base. The decision cost owner utilities hundreds of millions of dollars.

“By bringing Wolf Creek on line, the companies had excess capacity beyond their needs,” said Keith Henley, chairman of the Kansas State Corporation Commission. “The commissioners did not want them to receive a return on an investment that was considered an excess.”

Such rulings are having a chilling effect on utilities’ plans to build new plants. Instead, non-utility companies are stepping in to fill future needs.

Encouraged by proposed Federal Energy Regulatory Commission rules that would free them of some regulatory constraints, companies like Bechtel Group Inc. and General Electric are looking to build small generating facilities that would sell wholesale power to local utilities.

“The utilities face a lot of problems, including the regulatory atmosphere, when it comes to building new generating facilities. We feel if it’s a well-developed project, we are in a better position than the utility,” said Al Donner, a spokesman for Bechtel, which has such projects in California, New Mexico, Pennsylvania and Massachusetts.

Instead of construction, utilities are looking to conservation, or “load management,” to trim future demand. Utilities across the country offer customers incentives to use more energy-efficient appliances or to limit electricity use in high-peak hours.

“Load management means we can defer major building of new capacity until 1994,” said Tom Welle, a spokesman for Potomac Electric Power Co., based in Washington, D.C.

But these changes worry some industry officials. Some think the utilities’ reluctance to build additional generating capacity and their increasing reliance on other sources for power may prove costly if economic ground rules change as suddenly as they did in the 1970s.

“It may be fine if demand doesn’t grow faster than predicted,” said Nevius of the Electric Reliability Council. “But if it does, it’s going to be much more difficult for utilities to play catch-up. People worry about the cost of overcapacity. The costs of unreliability, of not having enough electricity, are far higher.”