Back in 1965, a region-wide power outage darkened the entire Northeast and suddenly the U.S. electricity industry discovered it had a reliability problem. A scant eight years later, two mideast oil embargoes (1973, 1978) again demonstrated U.S. electric system vulnerability, but this time to oil supply shocks. It took 20 years of elevated capital spending—during a period of high inflation and high interest rates, the Vietnam war, nascent environmentalism, and social and political turmoil—to fix the utility system’s problems of reliability and resource adequacy. Today, the U.S. electricity industry faces new challenges: inadequate infrastructure in the face of climate change, the associated decline in grid reliability, and the need to decarbonize power generation while addressing higher demand for electricity. Like the electric utility industry in the mid-1960s, today’s industry probably faces another two decades of high capital spending to rectify current grid problems and deficiencies.
Utility capital spending programs, which we expect to increase substantially, will rely heavily on the capital markets for both new debt and equity. The interest expense associated with this significant expected debt issuance will depend in large part on industry credit worthiness. Let’s briefly focus on two measures of financial strength that go together: corporate bond ratings and pretax operating income coverage of interest costs. Companies with relatively low bond ratings and weak interest coverage ratios pay more for capital and may not be able to access adequate amounts at all during periods of financial market stress. Just as individuals with poor credit scores expect to pay more for loans. Electric companies, which are heavily leveraged, need access to capital all the time. They cannot shelve critical projects at will, like other types of corporations, without endangering service and the reliability of their networks. In the twenty years prior to 1965, during which both interest rates and consumer prices rose, the electricity industry expanded service and steadily reduced its prices. During this so-called “golden age” for the electric utility industry, sales and profits increased while power prices declined due to the benefits of power plant economies of scale. In 1965, 96% of US electric utility bonds had strong investment grade bond ratings of single A ( A+, A and A-) or higher. Not only were the industry and its securities investment grade, but they were among the highest levels of investment grade credits available. Pretax operating income covered interest expenses by 5.4 times.
But by 1985, after twenty years of heavy capital spending, only 74% of the industry’s bonds carried single A or higher debt ratings, and interest coverage had fallen to 2.4 times. Several companies, during those 20 years, went bankrupt and many had to cut or omit their common stock dividends in order to survive. The utility industry blundered through a massive construction effort while state regulators, unused to a new regime of higher power prices, moved too slowly to permit the industry to fully recover new, higher levels of expense. (For details, see our book, America's Electric Utilities: Past, Present and Future, ninth edition). The industry ceased to be a proverbial riskless investment vehicle for so called widows and orphans. Even monopoly electric companies got into financial difficulty.
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Fast forwarding to the present, by 2021 only 25% of investor-owned electric utility industry bonds had debt ratings of single A or better and pretax interest coverage stood at 2.7 times. Thus the utility industry begins this next big capital expansion from a far weaker credit position than when it launched its post 1965 effort. The financial bottom is a lot closer than before.
In 2021, the investor-owned utilities belonging to the industry’s trade association, the Edison Electric Institute (EEI), spent about $135 billion for capital expenditures, of which roughly $25 billion went for gas utility operations and another $10 billion for miscellaneous purposes. EEI members make up over 70% of the US electric industry.
In 2022, EEI members plan to spend $155 billion in total, thereby increasing net plant (a proxy for rate base) by 7%. Let’s say that kilowatt hour sales increase from about 1% (current long term projection) to 3% (bounce back from COVID recession), inflation is 5%, fuel prices remain stable, and bond interest rates hover around 5%. How can a company maintain return on investment when its assets (net plant) must increase by 7% and sales only 1-3 %? Cut expenses and risk service interruptions or raise prices? Electric companies would obviously prefer the latter course. But without meaningful price increases, we calculate interest coverage falls further to a meager 2.1-2.2 times. Not good for maintaining credit quality. To maintain adequate interest coverage ratios, the average EEI member would have to raise prices 3-4%. Rough numbers, maybe, but we think they’re in the ballpark.
However, to modernize the US electric grid over two decades the electric industry must spend far more, possibly $285 billion a year for EEI’s members. (We have explained these numbers elsewhere.) That projected level of spending would increase net plant by 14% in 2022. So, the utility business problem remains. How to maintain investor returns if sales rise 1-3%o while the investment base rises 14%? Electric companies may have to raise prices by 8-10% to maintain coverages at 2021 levels, which are anything but robust incidentally. (Annual percentage price increases would fall over time as the rate base grows and as fuel costs decline thanks to decarbonization.)
Now let’s factor in the impacts of the recently passed Inflation Reduction Act (IRA) which may provide some financial relief to the industry. It offers tax credits and subsidies over 10 years. The total IRA subsidies equal about 10% of the rate hikes needed over a decade to maintain interest coverages at 2021 levels. Frontloading of the IRA subsidies or phase-in of the new rate base could reduce consumer pain in the early years when the price increases might be highest. Regulators have done this before.
So, taking the necessarily higher projected capital spending (for replacement, growth, and decarbonization), expenditure costs per customer would raise real US electricity prices by maybe 5% per year, from which we deduct 1% for IRA subsidies and another 1% benefit from phasing out fossil fuel costs, to produce real price increases of about 3% per year. But, that is not the full story. Power prices will rise with or without decarbonization. The electric industry has to replace a considerable amount of aging utility plant while at the same time adding new facilities to accommodate anticipated sales growth from the electrify everything trend.
Our estimates for a 10-20 year period indicate that the real price of electricity, with a full decarbonization, will rise by a single digit percentage per year. A previous analysis indicated that electric utility modernization without decarbonization will also produce real price increases in the single digit range. Keep in mind that the electric bill makes up roughly 2% of the average family budget and regulators have the means to shift costs so the greatest burden need not fall on those least able to pay. (Handing out a $500 electricity voucher to every person under the poverty line and charging the expense to electricity consumers would raise the average electric bill by less than 5%. Regulators do not, of course, hand out money, but they can rearrange financial burdens to ease the burden on those in need.)
But here is the catch. If we get an inadvertent replay of 1980s’ regulatory policy, this could throttle the reconstruction of the public electric grid by keeping electricity prices below those necessary to finance an adequate capital program. Why? Because regulators often fear the adverse political consequences of rapidly rising prices. In other words, in some states it may be politically safer to permit the electricity infrastructure to deteriorate in order to keep electric bills down. If that happens we would expect new suppliers, private users, and possibly even municipal utilities (where consumers are willing or able to foot the bills) to step in to fill these gaps. Microgrids, private sources of power generation and expanded municipal services are all likely. If public utility infrastructure, largely investor-owned, deteriorates, energy equity issues will arise. This means that those financially well off will continue to enjoy reliable electricity service through their own often considerable investment while the rest of the population has to rely on an under-financed, deteriorating public grid. This is truly a third world type of scenario.
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To sum up:
- The U.S. electricity grid needs to substantially step up its capital spending to meet accumulating challenges, some long ignored.
- The electric industry can still finance these higher costs in the old fashioned way, by charging consumers as it goes along.
- Whatever happens, prices will rise in real terms.
- Letting the grid deteriorate will have uneven social as well as economic consequences. (We used to believe this was not even remotely an option. We are no longer as certain.)
We don’t know how to account for the U.S. electricity industry’s slow motion embrace of new growth objectives that should reinvigorate an otherwise sluggish, low growth industry. Timidity, politics, short termism, culture, climate denial, insufficient commitment to science and technology, or just plain lack of vision? We cannot blame an inability to finance the transition for this slow walking. The electric industry can ultimately raise all the capital it needs using tried and true techniques—if it finally gets moving.
By Leonard Hyman and William Tilles for Oilprice.com
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