Implications of the Next Capital Spending Spree

Implications of the Next Capital Spending Spree

April 01, 2007 | By Keith Martin in Washington, DC

Capital spending by US power companies is cyclical. US utilities are about to embark on a huge capital spending spree. The last such surge in new investment was during the period 1965 to 1985. The surge will have consequences for both the regulated and unregulated sides of the US power business. Hugh Wynne, a senior utility analyst with independent research house Sanford Bernstein & Co., held a call in late February to discuss the possible consequences. The following is an edited transcript.

We are talking today about potential retirements of US fossil-fuel power plants over the next 10 years and the implications for unregulated generators, on the one hand, and regulated generators, on the other.

To cut straight to the conclusions, on the unregulated side of the business, aging power plants and the need to comply with increasingly-stringent emissions controls will require a level of capital expenditures that is a threat to unregulated coal-fired generators. The capital spending required to replace existing plants and to install required emissions controls will not only deplete distributable cash flow, but the future depreciation and interest expense tied to such spending will also erode ongoing earnings power. We believe that Reliant, Dynegy and NRG are at most risk among the unregulated merchants.

There is a positive effect on the regulated side of the business. The upswing in capital spending to replace plants and install emissions controls could bring about a material acceleration in rate base growth and, therefore, in the growth of regulated earnings. We are particularly heartened by that in view of the very wide gap between the cost of equity to regulated utilities, which we estimate to be less than 8% currently, and the returns on equity that the utilities are permitted to earn on their incremental investments, which range from 10% to 13%. That type of margin over the cost of capital, when applied to investments of the scale that we are talking about, should add materially to shareholder value.

Large utilities that combine attractive returns on equity with rapid rate base growth include Xcel, Southern Company, Entergy, American Electric Power and Duke. [Editor’s note: Mr. Wynne owns Duke and TXU stock and has a “market-perform rating” on both. The parent company of Sanford Bernstein & Co., AllianceBernstein L.P., owns 1% of the common stock of American Electric Power.] Smaller utilities faced with these types of investment programs and attractive regulatory regimes have become targets in the recent past for private equity investors. We believe they will remain such targets in the future.

Past Lessons

The last time there was a major upswing in capital investment of this magnitude among regulated utilities was during the period 1965 to 1985.

There are risks associated with an upswing of capital investment on this scale. Two factors that caused erosion in utility stock prices during the last upswing are unlikely to be repeated today. They are accelerating inflation and rising long-term bond yields. However, other factors that led investors to sour on utilities the last time clearly persist. They include the threats to credit quality deriving from such large capital expenditures, the potential for construction delays and cost overruns, and resistance among regulators to the rate increases required to recover such large capital expenditures.

During the past three decades, coal-fired power plants have been retired at about 50 years of age. If the same rule holds going forward, then 195,000 megawatts of generating capacity is likely to be retired over the next 10 years. That is a little under a fifth of the current installed generating capacity of the United States and a little under a fourth of the generating capacity using fossil fuels.

A relatively conservative estimate of the cost to replace this generating capacity is $180 billion.

The implications for regulated utilities should be broadly positive. Forty- and 50-year-old power plants in the rate base of a regulated utility contribute very little to earnings. Investing in a new coal-fired power plant at an average cost of $1,500 a kilowatt, or installing emissions controls for sulfur dioxide, nitrogen oxide and mercury at a combined cost of $400 a kilowatt, represents a material opportunity to increase rate base and, with it, regulated earnings.

Consequences for Merchant Generators

The implications are much more negative for a merchant generator.

An aging coal-fired power plant can be robustly profitable, with an operating cost of about $20 a megawatt hour given the cost today of coal. That type of plant can generate a very robust gross margin when it is in a market where gas-fired power plants set the price of power and may sustain the plant at levels of $50 a megawatt hour or higher.

Older power plants are largely or fully depreciated, meaning there is little depreciation expense to charge against this gross margin. Book earnings at these older facilities are high. Cash flow is also high because the owners tend to avoid outlays for emissions controls for as long as they can and minimize capital outlays for capacity upgrades.

The need to replace an aging power plant implies not only a drain on distributable cash flow for merchant generators, but also an erosion of earnings power in the future as replacement costs start to register on income statements. Investors would be wise to monitor the age of power plants of merchant generators. We were surprised when we sat down and estimated it. For example, Reliant generates more than a third of its power from plants within five years of normal retirement age. The figure for Dynegy is a quarter. For NRG, it is a fifth.

It is not only the replacement of existing power plants that these companies have to worry about, but also compliance with the “clean air interstate rule” that will require heavy environmental spending on emissions controls for sulfur dioxide, nitrogen oxide and mercury through 2015. The cost of complying with the new emissions limits can be substantial for the major unregulated generators, particularly when the amount of spending is considered in relation to the EBITDA, or earnings before interest, taxes, depreciation and amortization, of some of the major unregulated generators.

This spending has implications for electricity prices. Prices must be high enough to recover not only the operating cost, but also the capital invested in building a new power plant before new plants will be built.

We estimate that the long-run marginal price of power must be at least $50 an mWh for the cost of a new coal-fired plant to be recovered, and it runs as high as $70 an mWh in the case of a combined-cycle gas-fired plant assuming $8 gas.

In the gas-fired markets of Texas and New England, New York and the mid-Atlantic states, power prices last year were at levels that seem to justify investment in new power plants. The risk to generators in these regions is the possibility that electricity prices will fall due to falling gas prices or installation of lower-cost sources of power from renewable or coal-fired sources.

One need only look at the experience of merchant generators who built combined-cycle gas-fired power plants in the late 1990s and the early years of this decade to see the risk that investors run due to major changes in economic assumptions.

What is interesting is the failure of power prices in the midwest in 2006 to compensate generators for construction of new facilities. This suggests that plants reaching retirement age in that part of the country may not be economical to replace.

Regulated Opportunities

Moving to the regulated side of the business, the best way to predict earnings growth is to track total invested capital.  This reflects the regulatory paradigm in this country that a monopoly utility is required to provide electricity service, but it is allowed to recover its cost of doing so, including a return on net investment. There is a 90% correlation between invested capital and aggregate earnings of regulated utilities as a group.

When it comes to estimating future growth in invested capital, there is about a 90% correlation between such growth and megawatt hours of electricity sales.

However, if you plot both electricity sales and invested capital, you will see relatively long periods of time when total capital investment by regulated utilities was either materially below or materially above the trend line for electricity sales. This reflects an inherent cyclicality to capital spending by utilities. This cyclicality is evident even just in the last 10 years. Capital spending was less than $20 billion in 1996. It swung to more than $60 billion in 2001 before settling back to a range of $40 or $45 billion currently.

This suggests the utility industry as a whole swung from being cash-flow positive to cash-flow negative and is back to cash-flow positive.

Looking forward, we think the industry is entering another cycle of huge capital spending driven by the need to replace aging fossil fuel plants. A large number of regulated utilities are expecting rate base growth over the next 10 years of between 75% and 125% as a result of the need to replace these aging generating units.

The need to comply with emissions controls will also drive future capital spending. For the largest coal-fired generators in the country, we foresee capital outlays equivalent to 10% to 20% of current rate base in order to comply with the clean air interstate rule by the 2015 deadline.

The surge in expected capital expenditures comes at a very propitious time for utilities because it is a time when the cost of equity to the industry is probably less than 8%, but when the return on equity allowed by regulators is some 225 to 500 basis points higher, or between 10.25% and 13%.

The gap suggests the opportunity to invest substantial capital at returns well in excess of cost and, therefore, substantial present value to the existing shareholders of regulated utilities.

In selecting potential investments in utilities, there is merit in focusing on regions of the country where capacity is likely to be constrained over the next decade. In regions where capacity is abundant, regulators will be tempted to deny requests by regulated utilities to replace existing plant and suggest that they contract for power instead from underutilized wholesale generators. The markets where there is potential for significant capacity shortfalls are Florida, the Great Plains states, the area from northeastern Illinois through the rust belt to Pennsylvania, New Jersey and Maryland. These are markets where utilities are most likely to receive regulatory approval for capacity additions.

The nature of the capacity that utilities in the Great Plains states and rust belt are proposing to build is interesting. These are regions with relatively abundant supplies of coal. The bulk of the planned capacity additions are coal-fired power plants. The benefit to the utilities proposing such plants is a coal-fired power plant costs about $1,500 a kilowatt to build, which is three times more expensive than a gas plant with a capital cost of about $500 a kilowatt. The implication for the utilities in this region is rate base growth will be more substantial than it might be in regions that historically have favored gas, such as Florida or the western states.

These growth opportunities have not gone unnoticed by private equity funds. There have been a series of completed or proposed transactions in the sector, including the acquisition of PacifiCorp by MidAmerican, the proposed acquisition of Duquesne by Macquarie and the proposed acquisition of Northwestern Energy by Babcock & Brown. In each case, an entity backed by private equity sought to take control of a rapidly-growing regulated utility.

There is an opportunity to put substantial amounts of capital to work at rates of return that are well in excess of cost. Indeed, if you read Warren Buffet’s letter to shareholders explaining the motivation behind his acquisition of PacifiCorp, he frames it very much in these terms.

Over the next 10 years, capital spending to replace aging power plants and comply with the clean air interstate rule will accelerate growth in rate base and drive regulated earnings higher. The wide gap between the returns on equity allowed to utilities and their cost of equity, which is 225 to 500 basis points, means the large amounts of capital spending expected should permit utilities to add very materially to shareholder value. Among the large utilities, Xcel, Southern Company, Entergy, American Electric Power and Duke stand to benefit the most, but interesting opportunities may arise among smaller utilities as a result of the interest of private equity investors in this sector.


During the period 1965 to 1985, utility rate bases expanded by 10% a year for almost 20 years.

That was also a period when utility stocks deteriorated markedly against the S&P 500.

Particularly during the early part of the last capital expenditure boom — from 1965 to 1972 — the price-to-earnings ratio and price-to-book value of utilities trailed the S&P 500 average. During this period, there was a sharp deterioration in both of these valuation metrics.

The primary reason this occurred was declining real electricity rates as accelerating inflation was met with regulatory lag. The regulators were slow to adjust rates upward to recover increases in fuel and other costs that utilities were incurring. The declining real price of electricity was reflected in falling returns on equity. Thus, the utility industry was placed at a competitive disadvantage relative to long-term investments. This was a period when long-term Treasury yields in particular were rising rapidly and, as a result, investors bid utilities down to levels that reflected the returns available on alternative, lower-risk instruments. Another factor behind the decline in stock prices was the financial situation of the utilities deteriorated markedly as construction outlays mounted. Another factor was the business risk of the industry became materially worse over this period, reflecting both cost overruns and completion delays in the construction programs, particularly on nuclear power plants, and also regulatory opposition to the rate increases that utilities required to recover their investments in new plants.

Accelerating inflation contributed to a 14% decline in real electricity prices between 1965 and 1972. As a result, the average return of equity of utilities fell from 10.9% in 1965 to 9.4% in 1972. During the same period, yields on 10-year Treasury bonds rose from 4.3% to 6.2%. Investors began to bid down the average price-to-book value ratio of utilities from a level well in excess of 2.0 in 1965 to just 1.0 in 1972.

It was also a period of deteriorating credit quality for utilities. The combination of declining real revenues and increased construction outlays drove the industry’s average debt-to-capital ratio from 51% in 1965 to 55% in 1972. Because this was a period of rapidly rising interest rates, the industry’s average earnings-to-interest coverage ratio fell from 4.5 in 1965 to 2.6 in 1972. Lenders began to demand higher returns on utility loans. Utility credit spreads over Treasuries rose from about 30 basis points in 1965 to 130 basis points in 1972.

Similarly, equity investors began to demand much higher prospective returns to compensate them for the increased financial and business risk of the industry. Price-to-earnings ratios fell from 20 in 1965, equivalent to an earnings yield of 5%, to 11% in 1972, equivalent to an earnings yield of 9%.

The markedly deteriorating business risk of the utility industry reached its nadir around 1984 or 1985 when utilities were trading between 5 1/2 and 6 1/2 times earnings, a 35% discount to the S&P 500.

History has taught us that there is risk associated with major capital expenditure cycles of the kind we are about to enter. It is important to assess which problems in the last cycle are likely to repeat. Some past problems are unlikely to repeat today. They are rapidly accelerating inflation and rapidly rising long-term bond deals. On the other hand, investors have to remain on the lookout for other risks associated with large capex programs that we think are much more difficult to avoid, and those include deteriorating credit quality, cost overruns and construction delays, and regulatory resistance to rate increases. Investors seeking to capitalize on the benefits of the expected increase in capital spending must monitor individual utilities to make sure that these risks don’t materialize.