During the depths of the sub-prime lending crisis, when lenders and investors seemed on the verge of panicking, MidAmerican Energy went to market.
Specifically, in late August 2007, the Iowa-based utility holding company issued $1 billion of unsecured 30-year senior bonds, with a 6.5 percent coupon rate and a “BBB+” rating from Fitch. The flotation wasn’t just successful; it was oversubscribed.
“We saw significant demand beyond the billion dollars,” says Joe Sauvage, managing director and co-head of Lehman Brothers’ global power group, which served as MidAmerican’s bookrunner. “For the right transactions with the right structure, there is significant appetite—at the right market moment.”
In some situations, utility securities actually might benefit from volatile financial markets, as nervous investors and lenders seek a relative safe haven for their money. And few investments appear safer today than U.S. electric and gas utilities. Utility-stock valuations remain within sight of historic high levels, with price-to-earnings (PE) multiples exceeding 14-to-1. Balance sheets are strong, with most utilities having completed refinancing of their highest-cost debt obligations in the last few years. And dividend payouts are holding steady, even rising in some cases, as companies reward investors after a long period of relative austerity.
From a more pessimistic point of view, however, the industry’s financial health arguably has nowhere to go but downward in the months and years to come.
Utility companies are bringing monumental capital-expenditure plans before rate regulators just as they’re dealing with a barrage of rising costs—for fuel and other commodities, as well as labor, pension-fund obligations, and interest payments. Additionally, with the threat of greenhouse-gas (GHG) regulation looming in the 2009 to 2013 time frame, utilities are facing unpredictable environmental-compliance costs.
Many utility companies and their investors expect regulators will support utilities’ capital requirements with progressive rate structures, including accelerated rate-recovery for cap-ex spending. But as costs escalate, utilities’ rate demands seem certain to test the limits of regulators’ support.
“This dynamic will lead to regulatory strains,” says John Young, CFO of Exelon Corp. “Companies will have to be very creditworthy to deal with all these issues that come at them, and state regulators will be the arbitrator.”
To better understand the forces affecting utilities’ access to capital markets, Public Utilities Fortnightly recently interviewed a group of 10 energy-finance luminaries:
William Rogers, Senior Vice President, CFO & Treasurer, Sierra Pacific Resources/Nevada Power;
John Young, Executive Vice President & CFO, Exelon Corp.;
James Hempstead, Vice President & Senior Credit Officer, Moody’s;
Richard Cortright, Managing Director, Standard & Poor’s;
Jeff Bodington, Principal, Bodington & Co.;
Robert Petrosino, Director of Credit Research, Barclays Capital;
Joe Sauvage, Managing Director, Lehman Brothers;
David Nastro, Managing Director, Morgan Stanley;
Leonard Hyman, Senior Consultant, RJ Rudden Associates; and
Stephen Maloney, Senior Consultant, Towers Perrin.
Fortnightly: How is the subprime meltdown affecting utilities’ access to capital markets?
Nastro: We see three main catalysts prompting increased volatility. First is subprime contagion. Some rumors suggest the subprime meltdown will cost as much as $150 billion. Second are failed LBO financings. The short-term pipeline is teed up with $400 billion at this point. Third is concern about liquidity. Central banks are providing liquidity support, but problems are lingering, especially in the A2/P2 commercial-paper market.
And then there’s the general concern, is there another shoe that has yet to fall?
Cortright: Everyone is waiting for the other shoe to drop.
Liquidity is definitely strained. Bankers are taking a good deal longer to find investors, but they are finding them. Companies are paying up a bit, repricing the exposures they have to contend with.
On the short term, commercial paper side, the A3 market is just gone. There’s nothing there. The A1 market is moving along basically uninterrupted, and the A2 market, where the bulk of issuers are, is seeing something of a slowdown.
Hempstead: I don’t know how long liquidity and credit concerns will take to work themselves out. But at the moment, we have a stable rating outlook for utilities. For the last five years the credit metrics for this sector have been good. They’re not as good today as we might have expected five years ago, but they are good.
Fortnightly: What does market volatility mean for independent power and below-investment-grade projects?
Bodington: It’s putting downward pressure on valuations. What’s underway is a classic flight to quality. We’re seeing an increase in spreads. Risky deals have to earn a higher rate of return compared to high-quality deals, and some of the riskier deals won’t get done at all, until their sponsors can cure some of the defects.
The real irony is the highest-quality assets might get even more aggressive. Their valuation actually will go up, because risk-averse buyers will say, “I’ve got a lot of money to spend and I don’t want to buy any risky assets, so I’m going to compete even harder to buy into the good deals.”
Maloney: The phrase “flight to quality” can translate into a flight to deeper pockets. On the merchant-power side of the business, if you have a bigger balance sheet, you are more able to handle risks. It means fewer entrepreneurs coming into the market and more market concentration, heading in the direction of market power.
Cortright: As disrupted as the markets are right now, they are looking for simplicity and certainty. There are special challenges on the unregulated side. To get financing they must have long-term contracts in place, and it adds an element of complexity.
Fortnightly: What lessons should utilities take away from the subprime meltdown?
Maloney: There’s a lesson to be learned here in risk management. It often takes a bad day in the market to show how bad the models are. You need to use a very structured process and constantly validate your models against market fundamentals.
Rogers: My personal view is the current market environment reinforces the prudence of staying ahead of your capital formation needs. Make sure you understand the difference between liquidity facilities and permanent capital.
Nastro: The old axiom about financing when the markets are open is critically important. Those who get in early with long-dated paper will be the winners at the end of the day.
Sauvage: Being ready to issue is of great value. This means having regulatory filings, board authorizations, and security filings current, so the issuer can move quickly to take advantage of market opportunities.
The utility sector is entering a heavy investment cycle, and we expect net assets will more than double in the foreseeable future. Utilities will be in the market very frequently, and depending on market conditions and issuance volume in the sector, first-movers often have an advantage in securing financing.
Fortnightly: How do the industry’s cap-ex plans affect the overall financial picture for utilities? How will the buildout affect share values and creditworthiness?
Sauvage: Many companies will be investing more money than they have in net-asset value currently. The sector likely will be cash-flow negative, before dividends, and obviously more negative after dividends.
Also, you have a combination of robust commodity prices, increased infrastructure investments, and somewhat higher borrowing costs. That means pressure on utility rates.
Rogers: We certainly agree the industry is likely to be negative free cash flow. Capital expenditures will exceed cash flow, so we will be depending on the markets for capital formation.
I think it means raising capital sooner rather than later is prudent, because if you run the risk of just-in-time capital formation, or if you get behind, you may need to accept very expensive capital, whether equity or debt.
Nastro: Utilities are being a lot more creative in funding their capital-expenditure plans. Given their significant capital needs, they are positioning themselves to lower their cost of capital and mitigate regulatory risk.
A lot of companies in the sector are asking whether they should go it alone with a large project in a single jurisdiction, or whether they should consider partnering with others to diversify the risk. In the same vein, some companies are considering ways to take projects off balance sheet and off credit. They’re asking whether there’s a way to use a financial partner or private-equity investor to reduce overall cost of capital. We’ve seen several new joint ventures form, such as RBS and Sempra, Constellation and EdF, and DTE and GE.
Petrosino: Capital investments in a regulated business are a good thing from the point of view of all stakeholders. The important question is how it will be financed. If the capital spend is financed in concert with current capitalization, it should benefit all stakeholders—even regulators who don’t want to see over-earnings from an over-levered balance sheet. But if it stresses the balance sheet, credit ratings could come under pressure.
Cortright: The weaker your credit, the more susceptible you are to bumps in the economy. And the implications of a non-supportive rate decision will have more impact than they would otherwise.
Young: The infrastructure of this country, whether ports, highways, or railroads, are competing for capital. To the extent regulators treat utilities fairly, they will have good access to that capital. The reverse could be true in other places.
Fortnightly: What’s the outlook for regulatory risk, as utilities open rate cases to finance large construction plans? How are capital markets pricing regulatory risk?
Sauvage: If you look at the regulated utilities, medium PE multiples are at 14.5x. That’s down from where they were, because most utility stock prices are about 10 percent off their 12-month highs. But it’s still a robust multiple on a historic basis.
At those equity value levels, I think the markets are assuming constructive ongoing regulatory relations.
Maloney: We’re seeing a trend toward more sophistication in regulatory policy. The current credit crisis is encouraging regulators to back off from micromanaging and to look at things from more of a macro perspective.
Young: Regulatory lag for a wires-only business is very significant, with capital expenses being such a significant multiple of depreciation. Regulatory lag will cause lower overall creditworthiness.
Utilities will be borrowing for years to come, and borrowing at the right price is good for customers. Regulatory processes that aren’t in synch with that reality will have to get caught up.
When regulators see the same issues time and again, they will come to the realization that utilities need forward-looking rate relief. It’s an evolution, and won’t happen overnight.
Rogers: In our state [Nevada], we have an integrated resource planning (IRP) process that occurs on a triennial basis, with amendments as needed. Through that IRP process, the regulators deem an investment to be prudent on a prospective basis. We rely on that, but just because it’s deemed prudent doesn’t mean we can spend at will. We have to perform on our execution of the spending program.
There could be backlash in states where they have a huge stair-step move in rates, and no pre-prudency process. It’s important for commissions to smooth out the rate impact to customers.
Hempstead: For states that really need certain infrastructure, the regulators and politicians are working in a constructive manner with utility companies to help them get these investments made. Generally speaking, we’ve seen some legislation—in South Carolina, for example—that is very favorable toward utility capital investments.
But it’s the tail-end risks we’re trying to address. With some large-scale projects, the risks are so far out, who knows what will happen? When the costs hit rates, there will be a different political environment, rate environment, and fuel-cost environment.
Hyman: The first risk is that a lot of utilities and regulators haven’t done a lot of rate cases in a long time. You have a lot of people wandering around, feeling their way.
Next you have the risk of going in for all these things at once, and you have a lot of infrastructure spending that wasn’t planned. For large capital expenditures you have uncertainty about how regulators will deal with it. It’s back to rate base exposure, without enough thought about the problems of rate base exposure. The risk is there and I don’t know why anyone would be optimistic.
Cortright: Commissioners are political animals and are subject to a whole host of different and opposing constituencies. Even the most supportive commissions will come under increasing pressure. At some point regulators will be looking for ways to restrain the increasing cost to consumers.
I think the burden of proof on utilities will get heavier and heavier. Pension obligations, medical liability, all that stuff will be put under a microscope. So certainly the more fully fleshed out and transparent a utility’s big capital-expenditure programs are, the better.
Fortnightly: How is the risk of GHG regulation affecting the financial picture for utilities and power generators? How are capital markets pricing GHG exposure?
Petrosino: That’s the multi-billion dollar question right now.
In regions where coal is setting the price of electricity, the cost of electricity will go up. But in the Northeast or Mid-Atlantic, where gas generation is more on the margin and nuclear comprises a sizeable share of baseload capacity, coal-fired power plants might lose margin because the cost of carbon may not be fully reflected in the price of electricity.
Young: Because of political realities, the financial impacts of carbon removal likely will be mitigated through safety valves and other approaches, and state regulators will feel pressure to mitigate them further. If that happens, and you price carbon at $12 a ton but the cost to remove it is really $50 a ton, then you’ve discounted the cost to the public. You won’t get much carbon removal.
Hempstead: We don’t know where the legislation is going. It’s reasonable to assume the regulations will treat you in a fair manner, and allow you to recover the costs. But it’s a big unknown, because we’re still in very early days.
Rogers: Given the timeline to build a plant that is likely to be affected by GHG issues, companies will be deferring those investment decisions until there is more clarity.
Hyman: I attend a lot of meetings on Wall Street, and until recently I rarely heard anyone say much about carbon. It’s almost as if we know it’s there, but we won’t take it seriously until it’s three months away.
Cortright: It’s impossible to make judgment calls right now. All we know is costs will be going up, but we don’t know how much, when, or how those costs will be spread around the industry. The focus is on coal burners in the Midwest and South. Will they take it on the chin? It’s an important question to answer.
Bodington: The old strategy for many companies was to get as much coal-fired capacity as possible, sell cheap power, and become heroes. GHG regulation has turned those heroes into potentially big losers. Fasten your seat belt if you’re in a coal-driven territory.
Nastro: While legislation isn’t expected until 2009, at the earliest, investors are beginning to quantify the impact of GHG and highlight, in broad strokes, the winners and losers from policy changes. We think the market increasingly will differentiate between companies that have an implied cost versus a benefit [such as coal versus nuclear].
The public markets have been slower to reach a consensus about GHG costs, but certainly strategic buyers in private markets already are making bets. Goldman Sachs sold the Horizon Wind portfolio to Energias de Portugal for a record $1,950/kW of installed capacity. That’s in indication of how far the market has moved, in terms of pricing a clean portfolio.
Fortnightly: Many utilities are working to implement time-of-use metering and conservation programs. Are utility investors concerned about how these changes might affect utility business models?
Petrosino: Management teams are talking about it, regulators are talking about it, and conferences are focusing on new rate structures and decoupling. It’s a significant change, and investors still view it as a “show-me” proposition. It’s more of a risk than an opportunity—particularly on the conservation side.
Innovative rate structures will happen because conservation, efficiency and renewable energy are important for the industry. It doesn’t make sense for a utility to build a 500-MW plant it could avoid through other measures, particularly in a world of carbon taxes. But rate structures need to provide incentives so the utility gets paid in a way that is similar to building the plant.
A lot of education needs to happen among consumers. For too long, consumers have been compla- cent about the cost of electricity. They accept rising gasoline costs, but they think they should be able to leave the lights on and it shouldn’t cost them any more than it did in the past.
Hyman: Clearly we need some sort of time-of-use (TOU) pricing so companies don’t put in a lot of equipment and assets that wouldn’t be needed if people knew what the real costs were. There’s no doubt smart-metering technology can make an enormous difference. It’s the difference between blundering along or making plans that are sensitive to customer needs. But I’m not sure the regulators are willing to let go and actually let this happen.
Sauvage: If those investments are made, they will take pressure off other parts of the company’s cost structure. That in itself has value, because you want stable rates or relatively predictable increases. Regulators will realize that, and the companies that are investing in these technologies will work in partnership with regulators. They will find paradigms that provide the right incentive for what everybody understands is the right economic and environmental outcome.
Maloney: You will see more innovation in tariff provisions, eventually working toward TOU pricing. And if the shifts are persistent, it could have some surprising effects.
Fortnightly: Given all the changes that are occurring in the industry—not to mention the changes that already have occurred—are utilities still the right investment for widows and orphans? What do you see happening with dividend trends?
Rogers: This is a great topic for the industry right now, because there are a myriad of opinions about it.
Our company just declared a dividend at the end of July, for the first time in about five-and-a-half years. Because of our high organic growth rate and our capital-investment needs, it seems to us our payout ratio should look more like the S&P 500’s average, rather than the typical utility. In other words, we’re targeting about 35 percent versus the industry average 65 percent.
We’re not alone in this. CMS Energy reinstated its dividend this year, and Allegheny Energy announced it is looking hard at it too.
Some people think you have to keep the yield high and payout ratio high to attract equity capital. But we’ve been to the point where our financial structure was stretched, and we’re not anxious to return there.
Young: A big question is whether the dividend tax cut will go away in the next administration. If it does, the value of utilities will be hurt and capital costs will go up. That will be bad for customers and investors alike.
But generally speaking, it comes to this: What do you define as a utility?
The utility sector 20 years ago was more homogeneous than it is today. Utilities were regulated companies. But today Exelon is a utility, and 80 percent of our income comes from unregulated businesses. Our nuclear-generation business is tightly linked to the price of electricity, which is linked to natural gas and other commodities. There’s a lot of volatility in that business, and that’s linked to share value. But we also have two regulated transmission and distribution companies, and their earnings stream is a lot more predictable.
We believe the value-return policy needs to be aligned with the earnings profile, capital structure, and risk inherent in the company’s business. The industry is not going back to a homogeneous dividend policy as long as the group is not homogeneous (see “Return of the Pure Play Utility,” p. 44).
Petrosino: In recent years, many utilities were valued more on growth than on dividends. We’ve seen this with PE-multiple expansion for the group, but dividend growth continues to be a selling point. As the equity markets change, it could swing back to utilities being valued more on dividends, especially as investors age and Baby Boomers look for dividends rather than growth. They’ll see utilities as a space to put their assets to work.
Hyman: Dividends are very important for utilities. They make up almost half of the profits shareholders earn. If anything, utilities ought to make sure the dividend goes up. They haven’t done a super job of investing money, and investors would prefer to have it paid to them instead of spent on wild ventures.
Hempstead: From a credit perspective, dividends are viewed as a fixed obligation. To the extent your annual dividend affects your retained earnings, you have less money to reinvest in your system. But if you are spending a lot of money on new generation or grid infrastructure, you are constantly talking to your regulators about rate relief. That increases your regulatory risk and business risks, which means you need higher credit metrics for a given rating category.
Cortright: Utilities have been buying back stock and increasing their dividends. Many are doing that because in the early part of the decade they had such a focus on recovering the strength of their balance sheets, now they’re returning to focus on the equity side.
But realistically, this industry is going into a buildout mode, and those sorts of practices will have to slow down—unless they are OK with threats to their credit quality. Companies need strong balance sheets as they go into these very stressful periods.
Sauvage: Historically utilities have under-earned during big cap-ex buildout phases.
I’d expect payout ratios to edge up a little bit, depending on cap-ex plans and regulatory treatment. A lot of the capital going in at this stage—advanced metering and other grid infrastructure—should get into the rate base more quickly than long-term generation investment. This is particularly true for companies that are going in for rate cases frequently.
Maloney: Utilities no longer own all parts of the value chain. They are service providers of last resort, and more procurement is coming outside of cost-of-service regulation. Look at how technology has evolved and how uncertainties in demand have shifted. Given this risk, is this the same stock you tried to sell to widows and orphans 30 years ago?
Arguably utilities should be getting higher returns for the capital employed. Regulatory policy has a very important effect on what utilities do and the risks they face. That’s even truer today than it was before. At the end of the day they are facing greater risks, but simply adjusting the dividend may not be sufficient to deal with those risks.
Nastro: At this point in the capital-investment cycle, there’s a natural tension between credit quality and equity returns.
And the cap-ex bubble is not yet reflected in valuations, as can be seen in the limited differentiation between the highest and lowest PE-ratios in the sector. Utilities are expected to need $60 billion in external capital between now and the end of 2010. We’re at the front end of a period of rate-case filings. Historically, regulatory pressure has compressed returns on equity.
Eventually the market will start to differentiate between winners and losers based on regulatory environment. States that use performance-based rate-making, provide incentives for infrastructure growth, and favor settlement over litigation will provide a more attractive regulatory backdrop to attract needed capital.