How is the financial crisis affecting the power sector? In short, in a big way. The electric power industry is second only to financial services in terms of reliance on credit markets and is second only to railroads in capital intensity. Of course, the huge fixed-cost structure of the power industry stems from the need to invest billions of dollars each year in generation, transmission, and distribution assets.
For the past decade, the power industry enjoyed broad access to plentiful and cheap capital from an assortment of investors, including banks, mutual funds, pension funds, insurance companies, hedge funds, and credit default obligations. But the credit crisis has virtually dried up capital or made it extremely expensive, especially for the merchant-power sector. Even after the current crisis resolves, structural changes on Wall Street that require lower debt levels (de-leveraging) and maintenance of tighter capital costs likely will permanently increase the yield spreads and debt costs for the industry.
Should the power industry adapt its approach to capital markets in this environment? The answer, of course, is yes.
An independent analysis of both the utility sector and the competitive or merchant-generation sector differentiates their financing risks and demonstrates the qualitative differences. The analyses, while providing a novel application of the discounted-cash-flow (DCF) model, concludes that multiple frameworks are necessary to establish a power company’s or project’s current cost of capital, especially under volatile capital market conditions. Finally, the analyses reveals that in today’s capital markets, it is critical to balance or combine the alternative approaches to the cost of capital in order to develop a long-term view.
The U.S. utility industry uses corporate financing to fund capital expenditures and other needs in all segments of the power industry. Debt funding is structured with recourse to the corporate issuer, and thus is included in the balance sheet of the company. Utilities generally have enjoyed favorable debt financing terms, because they have relatively stable and predictable cash flows. The credit ratings of utilities have drifted down from A and A- in recent years to BBB and BBB+, but they’re still investment grade. As a result it’s still feasible for utilities to finance capital requirements based on their credit-worthiness, particularly if multiple companies join forces. Also, in recent years there have been relatively few huge capital investments (e.g., in new coal or nuclear projects) that would require massive spending on individual projects. Even so, utility capital spending has been high and is projected to remain high, as utilities invest in large transmission, smart metering, energy efficiency and environmental upgrades.
By contrast, the U.S. merchant-pow-er sector is focused largely on unregulated wholesale generation plants, although there are a handful of merchant transmission projects and companies in the U.S. market. Examples of merchant- power generators active in the United States include Dynegy, Mirant, NRG, Reliant, and Calpine; these companies can be considered pure-plays for this sector, because they all have a predominant focus on deregulated power generation; a significant exposure to merchant power risk; a wide range of customers; a U.S. base with significant geographic diversification; and significant economies of scale in both operations and fixed costs because of the size of their generation portfolio. (NRG recently expanded beyond this pure-play description by acquiring the Texas retail operations of Reliant Energy.)
All of these merchant-power companies are rated below investment grade or in the high-yield class. Merchant projects traditionally have been project financed and carry market risk, as their cash flows may be exposed to the vagaries of spot-power prices unless they have power-purchase agreements that mitigate such risk. Although most project finance deals involve leveraged loans from commercial lenders, the debt costs for merchants generally approaches the returns on publicly traded high-yield bonds. Financing on a pure merchant basis currently is extremely difficult and power-purchase agreements are now a pre-requisite rather than a unique selling point. Recent examples of major project-financed generation plants include Caithness Energy and Noble Environmental Power.
Many companies in the merchant-power business aren’t pure plays. For example, companies usually considered utilities, such as Constellation Energy, have substantial merchant generation as well as regulated utility assets, and companies generally thought of as merchants, such as AES, own regulated utilities. For those companies, it makes sense to look at a blending of the methodologies and approaches. However, in carrying out valuations, the financial community tends to regard the fundamental risk profiles of such firms as one type or another, rather than both.
In this regard, it’s important to understand the recent history of the leveraged loan and high-yield bond market. The high-yield bond market grew rapidly throughout the 1990s and well into 2007—starting at $200 million in 1995 and expanding to $1 billion by mid-2007. Such bonds were used for financing leveraged buyouts and exits from bankruptcy, and they fueled the explosive growth of the sector in 2005 and 2006. For example, Mirant emerged from bankruptcy in 2006 and 2008 through the issuance of high-yield bonds, while Calpine’s exit financing in 2008 was privately placed.
But things changed rapidly, particularly for merchant companies. Credit dramatically tightened in 2008 and early 2009 after a period of stable and relatively low bond spreads (see Figure 1). The spread is an important indicator that shows the amount that companies pay for capital over a benchmark such as the Treasury bonds or LIBOR. Until late 2008, one of the reasons for the narrow spreads, low cost of debt, and rapid increase in debt placement in the power industry was securitization, the packaging of groups of investments into a pool and then sold as a single security. In the mortgage market, securitization enabled the redistribution of substantial credit risk from originating banks to non-bank investors, and the power industry witnessed a similar dynamic through the collateralization of leveraged loan and high-yield debt instruments. In the 2000s, the widespread use of securitized instruments such as credit default swaps and collateralized loan obligations in the power industry spread out the credit risks among a much larger and diversified group of investors, leading to reduced spreads.
Both utilities and merchants enjoyed this confluence of favorable conditions for both project and corporate financing for an extended period of time. Unfortunately, the party couldn’t last forever.
The seeds of success contained the potential for disaster. In specific, the explosion of debt that provided a windfall for power companies—by adding low-cost debt to their capital structures and allowing them to substitute debt for equity—eventually led to levels of leverage that couldn’t be adequately serviced through their cash flows. This is particularly true for merchants. Utilities, on the other hand, remained regulated, and generated sufficiently stable cash flows to service their debt obligations.1 After investing in many non-utility industry or overseas operations in the 1990s and early 2000s, most utilities went back to basics. Since then, their steadier approach has allowed them to retain significantly easier access to capital, as their credit ratings didn’t suffer as much and their spreads have remained much narrower than they did for merchants. Additionally, because utilities are viewed as a defensive sector, they’ve enjoyed ready access to capital—albeit at a higher price. The market’s general flight to quality channeled investment dollars toward utility securities, just as it did Treasuries.
As widely reported, the credit crisis in the U.S. (and global) financial markets largely was due to the exposure of banks and investors to sub-prime mortgages originated by banks and sold to investors as mortgage-backed securities. Financial institutions, primarily investment banks, were the key investors in these mortgage-backed securities and other structured products. These institutions issued large amounts of debt in the mid-2000s to fund their purchases. When housing prices started to decline, the financial institutions faced large losses on their investments.
No industrial sector—including power—has been immune to the current credit crisis, even if utilities have been less affected than merchants. The loss positions of the banks and overleveraging obviously have impacted their ability to provide financing and infrastructure project financing in the power sector, in general.
The significance of this change for the power industry is that the credit crisis has caused de-leveraging (i.e., less debt and more need for equity) and has led to a scarcity of capital for the sector. This scarcity has been reflected in the increasing yields (interest rates) of high-yield bonds (see Figure 2). Since July 2008 the yield on a non-investment grade “B” bond (the line labeled “Merchants 10 Year”) has risen from 9.5 percent to 12 percent, after reaching a high of 16 percent at the onset of the crisis. The spread has increased by 250 basis points (bps), a significant market change in such a short period. Initially, the increased spreads were slightly offset by lower Treasury bond rates, but recently the spreads have reduced partly because of higher Treasury bond rates. In fact, recently Treasury bonds are trading close to what they were in July 2008. The bottom line, though, is that non-investment-grade utilities and merchant players still need to pay appreciably more for money now versus a year ago.
Even investment-grade utilities have not been spared the pinch of higher interest rates and spreads, and consumers may be affected as a result. Utility bond yields (the red line in the upper part of Figure 2) increased from 6 percent in July 2008 to 6.75 percent today, after reaching a high of 8.5 percent, while utility spreads (the lower part of Figure 2) have increased by up to 75 bps. Over the last three months, the current yields and spreads have reduced considerably from their November 2008 peaks but remain materially higher than historical averages.
It’s important to understand the increasing utility yields in the context of the regulator’s allowed rates of return on equity. At the onset of the credit crisis, credit-rating agencies and utility executives expressed concern that the increasing debt costs were approaching the authorized equity rate of returns (ROE), and that the current levels of ROE in many jurisdictions were inadequate compensation to investors who perceived a significantly higher level of risks. Their concern was that the need for higher equity compensation could lead to utility requests for higher authorized equity returns, regulatory uncertainty, and correspondingly higher consumer rates. Recently, however, due to declining debt costs, these concerns have been allayed, but this issue could return if capital markets become volatile once again.
Empirical frameworks show how the quantitative cost of capital to the power sector has been impacted due to the current credit crisis. Two well-known and often-cited approaches to determining that cost are the capital asset pricing model (CAPM) and the discounted cash flow methodology (DCF). These models can be used to further demonstrate the clear differences between regulated and merchant entities.
The CAPM relies on historically traded stock prices for capturing equity risk, and given that, typically uses a five-year estimation period, to mitigate the impacts of recent stock price volatility. DCF also provides an alternative view of the cost of equity. Both approaches have drawbacks, so using a combination of these two methods is a reasonable solution.
The five independent power providers (IPPs) mentioned previously provide a reasonable set of comparable companies for the merchant class. For utilities, the Edison Electric Institute’s (EEI) regulated class of utilities2 provides a readily comparable set of companies. Those in the EEI class have 80 percent or more of their assets in markets with a regulated rate-of-return market structure, allowing analysts to assess market risks at the low end of the spectrum.
By comparison, merchants are on a higher future trajectory for the cost of capital, compared to utilities. However, this must be verified by determining the two groups’ weighted average cost of capital (WACC), including the two principal components of WACC—the expected return on debt (cost of debt) and the expected return on equity (cost of equity).
• CAPM Methodology: The CAPM approach determines the cost of equity of a firm, and suggests that the expected returns increase linearly with a security’s risks. The risks are measured in the form of equity beta, which is the change in the price of a stock compared to change in the appropriate stock market index, such as the S&P index or the NYSE Composite Index. Beta is a measure of the company’s market risk (both business risks and financial risks) and is directly observed from the historically-traded stock prices of the firm in relation to the broader market. A beta of 1.0 signifies that stock is as risky as the market. The expected return on equity is a forward-looking approach, so accordingly forward-looking beta estimates include a factor called the “Blume adjustment,” which assumes that over time, betas tend to move towards the average market beta, which is 1.0.
The general methodological approach is relatively standard. First, equity beta estimates for each of the comparable companies are developed. The equity betas are then un-levered to strip out the financial risk and calculate the pure business risk of the firm. This is accomplished by using an approach called the “Hamada equation,” with an adjustment for the riskiness of debt for the merchant sector. The un-levered or asset beta are then unlevered at the target debt-to-equity ratio to determine the re-levered equity beta of the comparable merchant class of companies. As a final step, the CAPM is used to develop the expected equity returns.
In addition to these adjustments from the risk-free rates and the expected market-risk premium, it’s important to consider a size premium, since the CAPM doesn’t capture the difference in market risk between smaller and larger firms, particularly for merchants. With the recent crisis, the average size of merchants has fallen to roughly $3.5 billion to $4 billion in market capitalization. Research conducted by the Center of Research in Security Prices (CRSP) at the University of Chicago indicates that even after adjusting for the market risks of small stocks, they outperform large stocks.3 Hence, the addition of a size premium to the CAPM cost of equity is reasonable. This adjustment is in the range of 60 to 100 bps and is based on size premium studies conducted by the CRSP.
• DCF Methodology: The main principle behind this methodology is that when investors price assets, they’re implicitly indicating their expected return. Thus, a reduction in stock prices would mean increased expected equity returns. Recent historical averages of the market prices of equity in conjunction with expected cash flows have been used to yield an estimate of the cost of equity.
For utilities, the expected cash flows come in the form of dividends. A two-stage dividend discount model is chosen for both periods of interest—the pre-crisis period and recent post-crisis period. The first stage is modeled as explicit cash flow for a number of years and accounts for growth phase (low growth or high growth based on economic outlook), while the second-stage model assumes stable long-term growth in perpetuity.
For the merchants, a free cash flow to equity (FCFE) model is used, as these companies have scant payout history and the retained earnings are either used to finance growth opportunities or used for stock buyback to enhance shareholder value. The methodology also uses a two-stage model for the merchants. As the earnings of these merchant companies are highly cyclical, the net income is normalized by taking an average over the last five years. Also it’s important to consider the historical growth in addition to the analysts’ consensus earnings forecast as analysts typically ignore cyclicality, which means that these forecasts typically show an upward sloping trend, regardless of whether the companies were at the peak or trough of the cycle.
Just like the cost of equity, the cost of debt is a forward-looking concept, in that it takes the future prospects of the firm into account. Yet, unlike the cost of equity, the expected return on debt can be directly observed in the market. The current yield to maturity (or yield) on the applicable debt best approximates the cost of debt. The cost of debt is the expected return on the bond issued by the security, and tends to be the same as the yield to maturity (also called the promised return) for investment-grade bonds. But for high-yield bonds, because of default risk, the expected returns on high-yield bonds (or highly leveraged debt) undoubtedly are lower than the promised returns. Thus, for a power company (whether utility or merchant) with a significant probability of default, the use of the promised yield could significantly overstate both the cost of debt and the WACC. In extreme cases, the use of the promised yield as the cost of debt even could result in the estimated cost of debt exceeding the cost of equity. This unusual situation is very nearly the case given the current state of the financial markets and its impact on the cost of debt for some firms.
Hence for highly-leveraged bonds, a correction needs to be made to the observed yields to determine the expected return on debt. One possibility is to apply standard asset pricing models like the CAPM to risky debt through estimation of a debt beta. Studies have reported debt betas in the range of 0.3 to 0.5. With a historical market-risk premium of 6.5 percent,4 the risk premium (or default component) could be in the range of 195 bps to 325 bps. But there are several issues, such as debt maturity, debt retirements and re-financings that complicate this calculation and affect the availability of a consistent price series to estimate a debt beta from a bond price series.
As an alternative to these approaches, an approach based on the “Merton model”5 has been adopted. This approach strips the default loss component from the promised yield to maturity. This is superior to the other approaches because by doing so, one need not rely on a consistent debt-price series that might not be readily available. For example, in the current market environment, the current yield to maturities for B-rated debt is in the vicinity of 12 percent. However, as explained above, due to lack of consistency, it would be inappropriate to use this as the cost of debt. The Merton model estimates the default component to be close to 2.5 to 3 percent, which indicates a true cost of debt in the 9 to 9.5 percent range.
Once the cost of equity and the cost of debt have been determined, calculating the after-tax WACC is a simple exercise. Figure 3 summarizes the results of the utility and the merchant class analysis, using both the DCF and the CAPM methodologies. Note that these numbers are purely illustrative and based on best efforts to create cost-of-capital estimates using empirical data.
The analysis projects an increase of 1 percent or less in the cost of capital using the CAPM for both utilities and merchants. The DCF model estimates a higher change—more than 1 percent for utilities and a greater than 3 percent change for merchants. Most of the change in the cost of capital (especially in the DCF case for merchants) is driven by cost-of-equity changes, although changes in debt costs also are a significant contributing factor.
As the results indicate, the CAPM methodology is relatively less responsive to fluctuations in market capitalizations over a limited historical period due to its reliance on longer-term historical data and other offsetting risk parameters. On the other hand, the DCF methodology, by construct, is highly responsive to the changes in stock prices and market capitalizations and provides a more dynamic estimate of change in cost of capital due to recent market fluctuations. The significantly greater change in the cost of capital for merchants as compared to utilities is partly explained by the relative drop in stock prices, with the decrease in stock prices for the merchants far exceeding the drop for utilities.
Neither model is perfect—DCF focuses highly, perhaps too much, on the near term, while the CAPM might over-emphasize the long term and might not take current conditions sufficiently into account. Hence, using an average of the two approaches is more prudent and might provide a better sense for relative changes in the cost of capital. Also, while the CAPM approach frequently is used for both utilities and merchants, the DCF approach seldom is used for merchants, though it is commonly applied to utilities. Given the current volatility of the credit and the equity markets, it’s critical to consider the appropriate approach to establishing a long-term view of the cost of capital.
The credit markets clearly are in a state of substantial flux, and the availability and cost of capital—to utilities, merchants and others—will depend on how quickly credit can start flowing again. The public-private partnerships structures recently announced by President Obama and Treasury Secretary Tim Geithner are intended to enable troubled banks to off-load toxic assets from their balance sheets through equity participation from the federal reserve and private banks in conjunction with leverage from the Federal Deposit Insurance Corporation (FDIC). The clear intent is to lower the overall riskiness of financial markets and hence the cost of capital, though it’s unclear whether private banks, including private-equity firms, actively will participate in this risk-sharing arrangement with the federal government. The flow-through effect of these changes on the power sector notably will affect both utilities and merchants.
Whatever the timing of the market restoration, it’s clear that structural and regulatory shifts will place more onerous guidelines for capital ratios on the banking industry, and restrict the use of securitization structures and off-balance sheet transactions. In the meantime, both utilities and merchants still have a high need for capital to finance large infrastructure projects. Banking and capital market changes likely will cause a permanent upward shift in the long-term cost of capital for the power sector. In this context, the CAPM and DCF models must be recognized for what they are: models that attempt to capture the financial outlook for a firm and determine its cost of money. By applying these models judiciously, perhaps in combination, and in new ways, utilities and merchant companies can determine the best approach and the best timing for the complex task of raising capital when they need it.
1. Even though utilities in some states were less regulated than in other states, they all have reasonably stable cash flows to service their debt obligations as many generate revenues through sales to affiliates.
2. See EEI Publication, 2008 Financial Review.
3. Source: Ibbotson SBBI, 2009 Valuation Yearbook. One explanation of this phenomenon from a trading standpoint is that small firms are not very liquid (have high liquidity betas) and not frequently traded by hedge funds and other financial players, and hence there is an illiquidity premium that should be added to the cost of equity. Another explanation is that smaller firms generally are perceived to be riskier and have fewer resources to fall back on in a crisis than large ones (though large firms often fail as well).
4. Ibbotson SBBI, 2009 Valuation Yearbook.
5. Based on “Estimating the Cost of Risky Debt,” by Cooper and Davydenko, Journal of Applied Corporate Finance, Volume 19, Number 3, Summer 2007.