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Generating capital: utilities look to rest of the century

The Cleveland Electric Illuminating Company has decided to let its customers share some of the financial burdens and rewards of the electric utility business.

In mid-June, 450,000 residential customers of Cleveland Electric received a letter and brochure inviting them to buy stock in their local utility. There was also a post card customers could send back if they wanted a prospectus and stock-purchase form. So far, says Edgar H. Maugans, the utility's vice-president for finance, about 65,000 post cards have been returned.

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The idea of asking ordinary customers to be stockholders is not new, but it is being looked at more often these days as another way to raise money. And for this industry, raising the enormous amounts of money it will need in the rest of the century is proving about as difficult as finding a permanent, safe place for nuclear waste.

To meet all its construction, financing, and other capital needs for the next 17 years, it is estimated the electric utilities will need to raise some $1 trillion. But that process is being severely challenged by cuts in the public's electric consumption, a regulatory climate that has been growing chillier as utilities have asked for larger and more frequent rate increases, and stock and bond markets that are becoming increasingly wary of what was once considered a safe investment.

This wariness was increased Monday when Chemical Bank, trustee for the holders of $2.25 billion in bonds issued by the Washington Public Power Supply System (WPPSS, or ''Whoops'') of Richland, Wash., declared the utility in default, creating the largest municipal bond failure in United States history.

For the near term, the municipal bond market, which had expected the default, showed little reaction. But in the long run, if institutional and individual bondholders can get little, if any, of their money back, and after all the lawsuits are filed, the effects of the default may be more deeply felt.

''It certainly doesn't do the investment market for nuclear power any good,'' stated James N. Bumpus, vice-president for finance of the Public Service Company of Colorado, a utility that has only one nuclear plant. A major reason for the WPPSS default was the fact that five nuclear plants were started based on inflated estimates of electric demand in the Northwest.

It also won't do the market for municipal bonds any good, particularly those issued by electric utilities. In the past 10 years the firms that rate municipal bonds, led by Moody's Investors Service and Standard & Poor's, have downgraded more utility bonds than they have upgraded. In 1972 there were 15 annual net upgradings by S&P; by 1981, there were 20 net downgradings. Investors demand higher interest rates on these lower-rated bonds. This makes it more expensive for utilities to raise money, another expense they have to take out of shareholders' dividends, pass along to ratepayers, or both.

The state regulators, for their part, have been reluctant to let this or many other expenses be added to customers' bills. Until last year, state regulators were not allowing utilities an adequate rate of return, says Jerry Pfeffer, executive director of NPS Energy Management Inc., a Washington, D.C., consulting firm that advises both utilities and state regulators, though not on the same cases.

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Mr. Pfeffer says that ''1982 had been a better year for utilities'' in the regulatory arena. There seemed to be a recognition among state public utility commissions that utilities had been hit by the recession, too, and needed some relief. He noted that ''1974 to 1982 were the worst years on record in terms of utilities' financial performance.'' Even though utilities were hard hit by high interest rates, escalating fuel prices, overall inflation, and declining use of electricity, ''the response of the public utility commissions was grossly inadequate.''

The regulators did begin to recognize some of these problems last year and granted larger rate increases, Mr. Pfeffer points out, but the trend has begun to reverse this year. In the first quarter, for example, utilities were granted rate of $2.8 billion in the last quarter of last year. Actual earnings dropped 8 .4 percent in this year's first quarter, compared with the first quarter of '82.

''Some regulators are waffling now,'' observes Richard L. Rosenthal, chairman of Citizens Utilities Company, a holding company that owns electric, telephone, natural gas, and water utilities in 10 states from Vermont to California and Hawaii. ''They're trying to ride both sides of the fence. That can be bad if the fence has pickets.

''There's some tendency on the part of the utility commissions to think, 'Well, the industry has recovered and we don't have to be concerned anymore.' Well, things are better than they were a couple of years ago, but we're not there yet.''

Mr. Rosenthal says regulators should realize that ''the investment requirements over the next 10 years are going to be enormous.'' In a study completed last month by the US Department of Energy, it was estimated that the industry would need to invest $1 trillion in the 17 years between now and 2000. Nearly three-fourths, or $700 billion, of this would go for new generating capacity. Assuming an annual inflation rate of 5 percent, the $1 trillion figure nearly doubles, to $1.8 trillion.

Actually, says the US report, based on investment levels in the 1970s that may not be such a difficult achievement if the regulatory climate and bond and stock markets remain friendly. In the last decade, utilities invested an average of $42 billion (in 1982 dollars) a year in generating, transmission, and distribution equipment. That works out to nearly $700 billion for the rest of this century.

There are, however, questions of just how much additional capacity the industry will need. A phenomenon known as ''rate shock'' may put a damper on that. In general, state regulators have allowed very little of the construction costs to be added to customers' bills while construction is still in progress. This system, known as construction work in progress, or CWIP, would permit a utility to pay some of the bills for plant construction during the building process. But with several plant projects, particularly nuclear plants, being canceled in recent years, regulators are reluctant to allow much CWIP.

Utility executives say this means that most or all of a plant's construction costs (which could run more than $2 billion) cannot be added on to bills until after the facility is operating. This could result in sharply higher rates, even if those costs were phased in over several years. And those higher rates could result in more cuts in the use of electricity, something economists call ''price elasticity.''

''As expensive power plants come on line in the next few years, you're going to see a lot more price elasticity,'' says Judith Warrick, first vice-president of Dean Witter Reynolds Inc., the brokerage unit of Sears, Roebock & Co. This could throw off current estimates of the number of power plants that have to be paid for.

For a while, at least, this could work to the utilities' advantage. A decline in construction costs, added to a leveling off of fuel prices, should cut the industry's expenses during the balance of the decade, says David Knox, a research analyst at T.J. Holt & Co., an investment advisory firm in Westport, Conn. This slowdown in construction activity in the next few years, he believes, will mean that utilities will need fewer and smaller rate increases.

One uncertainty in all this, particularly for utilities in the East, Mr. Knox says, is the effect of proposed legislation in Congress to control acid rain, supposedly caused in part by power plants that burn high-sulfur coal. The utility industry has estimated that changes demanded by the legislation could increase electric rates by 4 to 53 percent. That's one reason Knox's list of eight recommended utilities for stock purchase includes none in the East; all are in the South or West.

''We've avoided utilities that might be affected by acid rain legislation,'' he says. ''We figure it will affect 31 states east of the Mississippi or adjacent to it.''

His list includes Arizona Public Service, Florida Power & Light, Hawaiian Electric, Idaho Power, Montana Power, Public Service of New Mexico, Texas Utilities, and Utah Power & Light.

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