Utilities are enjoying some of the best financing terms anybody’s ever seen. Is the party winding down?
Utilities today enjoy the lowest all-in financing costs in recent memory. In August 2012, for example, Georgia Power sold $400 million in three-year senior secured notes with a 0.75-percent coupon. At that rate, investors buying those bonds will lose more to inflation than they’ll earn from the bonds—and yet demand for Georgia Power’s paper was so strong the company issued $50 million more debt than it had initially planned.
Indeed, Wall Street for the past couple of years has been throwing a party in honor of power and utility companies. The celebration includes utility stocks, which for a large portion of the past two years have outperformed the broader markets. Few utilities have issued new equity recently, but for those who have, Wall Street rolled out the red carpet.
Some signs, however, indicate the party might be winding down.
For one thing, regulatory commissions in many states are asking tough questions about returns on equity (ROE). The average allowed ROE has been declining for some years, but it’s still in the 10-percent range—even as utility stocks are trading higher than many have for the past decade. Low financing costs combined with high ROEs make for some uncomfortable conversations when utilities appear before regulators to seek rate recovery for capital expenditures.
That discomfort will increase when natural gas prices start rising off today’s rock-bottom $3/MMBtu. Low commodity prices effectively have shielded customers from the effects of rate increases, but the current prices are widely considered unsustainable.
At the same time, utilities face the end of bonus-depreciation policies that have made capital expenditures more affordable for the past two years. As part of the American Recovery and Reinvestment Act of 2009, bonus depreciation provided a 100-percent deduction for property acquired until the end of 2011, and 50 percent in 2012. That allowed utilities to finance a large portion of their capex directly from cash flow, rather than taking on debt or issuing new equity. The end of bonus depreciation might drive many utilities to issue new stock, which will dilute share values.
That’s always a necessary evil, but it comes at an inopportune time. Specifically, dividend tax rates are set to rise dramatically next year, if Congress doesn’t renew the tax cuts it implemented in the early years of the George W. Bush administration. Higher dividend taxes could translate into lower market valuations for utility stocks—compounding the dilutive effect of issuing new equity.
But even if dividend taxes don’t spike—or if a tax hike ultimately has a minor effect on utilities, as some analysts suggest it would (see Frontlines, p.4)—other factors in the market might signal an end to the current cheap-money Bacchanal. Namely, the new Basel III international banking standards are pressuring banks to rein-in loan tenors and increase fees. The European monetary crisis continues to loom over the global economic outlook. And so does the possibility that the U.S. Congress will remain deadlocked in a partisan budget debate, prompting the federal government to impose $109 billion in automatic spending cuts that could break the current fragile recovery and push the economy into full-blown recession.
Of course, even in a recession, utility companies enjoy relatively easy access and favorable terms in the capital markets. But the array of risks now facing the markets brings a measure of sobriety to the finance party. To get a sense of how these risks look from Wall Street, Fortnightly spoke with:
• Mike Haggerty, Bill Hunter, and Ryan Wobbrock, Moody’s
• David Nastro, Morgan Stanley
• Josh Olazabal, PIMCO
• Frank Napolitano, RBC Capital Markets
• John Whitlock, Standard & Poor’s
• Brian Tate, Wells Fargo Securities.
Money to Spend
Fortnightly: How have the capital markets evolved in the past year, in terms of access, spreads, and terms for power and utility issuers?
Tate, Wells Fargo: On the debt side, market conditions are as close to perfect as they’ve ever been from a utility-issuer perspective. In 2012, we’re seeing supply [of utility debt securities] on track to be up somewhere around 15 percent over 2011 levels. Utility credit spreads have normalized and cash flows into bonds have been consistent. But there’s a lot of cash to be invested, and not enough supply. Utility bond yields are below the 10-year average. With these attractive debt market conditions, utilities are proactively analyzing their debt portfolios and looking for reasons to issue debt.
In the bank market, liquidity is a popular boardroom topic. There’s good liquidity and strong bank demand for utility assets. Five-year credit facilities are commonplace, but Basel III changes and European debt concerns could pressure tenor and pricing.
Whitlock, Standard & Poor’s: Some factors affecting favorable access to capital markets are continued stability in cash flow and low volatility. A lot of that has to do with recovery mechanisms that smooth out cash flow, such as purchased fuel adjustments and other riders that bring cash certainty for utilities. Regulatory outcomes across the sector have been constructive this year, with timely recovery of costs.
On the secured first mortgage bonds that many electrics have issued in the past year, spreads are really tight, and that implies high confidence in receiving repayment of principal if something were to go wrong in the utility’s capital structure. Regulated utilities in general have a variety of investors seeking to hold their debt, and utilities do a good job of laddering their maturities. Many utilities have increased the size and tenor of their facilities this year, compared to previous years.
Olazabal, PIMCO: We all know what’s driving the low interest-rate environment: continued sluggishness in the economy. The Federal Reserve is driving a very favorable environment for interest rates. A couple of things affect the utility industry on top of that. In an uncertain environment, investors are moving toward high-quality investments overall. You don’t get much higher quality than utility opco [operating company] or holdco [holding company] bonds, where the underlying entities are strong. So utility bonds have been bid up, and yields are at 2 or 3 percent right now. That’s pretty low, but investors are focused on relative value. With their regulated cash flows, utilities are very strong compared to what else is out there.
Fortnightly: How long can these low interest rates and tight spreads continue?
Olazabal: I think we’re in a steady state for the most part. If we play forward what we think will happen, it’s more of the same—sluggishness in the economy, a lack of hiring, and continued pressure on the Fed to keep interest rates low. There’s a sense that this can’t go on forever, but it will take a while for things to change.
Nastro, Morgan Stanley: In our economists’ view, if Congress fails to act [and resolve the budget crisis], we’ll likely see a decline back into recession in 2013. The vitriol in Washington brings general uncertainty about the ability to find a consensus and avoid the fiscal cliff. The European sovereign debt crisis also is a pressing concern, weighing on the financial markets. Given this backdrop, the broad consensus is that interest rates will likely stay lower for longer, with a slight rise over 12 to 18 months.
Fortnightly: How is the situation different for companies with more exposure to merchant risks?
Whitlock: Access has been good for the higher-rated entities. One thing that investors have looked at is the effect of low natural gas prices, countered to some extent by hedging programs at some companies, and regulated utility operations that contribute to stable cash flow. These are the Exelons and PSEGs of the world. The integrated merchants will perform better than independent power producers because they have plants that will dispatch more on the curve.
For speculative-grade entities, credit quality has deteriorated some. They’re exposed to spot commodity prices and they avoid hedging because they’re searching for higher profits. Low prices obviously hurt them. The pure merchant companies, such as GenOn and Energy Futures Holdings (EFH), are strongly affected by the forward price curve. A company like EFH has refinancing risk with maturities coming in, and it depends on coal, which isn’t stacking up well against gas.
Olazabal: There’s a bifurcation in the market. Over the last three to five years, a lot of longer-term investors, especially institutional investors, have gone underweight on utility holdcos and gencos, on the belief that as long as you have a surplus of gas and suppressed power prices, there’s a big downside risk to holdcos and gencos. There’s a widespread belief now that gas and power prices are stabilizing, and there’s light at the end of the tunnel for gencos and the holdcos that own them. We have seen a good deal of tightening [in spreads] on those bonds. However, even when they stabilize, some companies will have 12 or 18 months of hedges that need to be re-marked, with pressure on earnings as a result. So it’s too early to tell if it’s correct, but there’s a sense that we’re close to the bottom in the merchant markets.
Haggerty, Moody’s: Merchant power companies have had no trouble accessing the capital markets, but they need a recovery in power prices. At this point they’re hunkering down, trying to conserve liquidity and hang in there until power prices increase.
Fortnightly: What’s happening in the project finance market? How are non-recourse power and gas deals getting funded?
Nastro: We’ve seen a pullback in the traditional bank market, and the capital markets have stepped up to fill the void. The traditional project finance bank market is significantly weaker and has become more fragmented. Pricing has increased and tenors have contracted, largely because of Basel III requirements and bank credit downgrades. The Eurozone banking crisis has caused many European banks to reduce their lending activity significantly, and in some cases to exit the project finance business entirely. Fewer banks are providing capital, and generally are lending only to core relationship clients.
Given this backdrop, the capital markets have filled the need. Demand for structured credit is robust. In the structured bond market, we’ve seen the majority of U.S.-based projects’ debt trading in the 5.5 to 6.5-percent range. For comparison, yields of BBB-minus rated corporate bonds are around 4.5 percent. The capital markets have been very receptive to alternatives like project bonds that offer incremental yield.
Fortnightly: For regulated utilities, what are the implications of low gas and power prices? Is it only a positive story, as prices have helped keep customers’ bills low?
Olazabal: There’s much more attention being paid to how various commodities affect utilities, even fully regulated ones. You see this at all the industry meetings and in conversations with management teams. They’re paying more attention to the impact of shale gas, and how this transformational, paradigm shift affects where you’re putting your generation investment—what type you’re going to build, what gets retired, and when.
Five years ago, all the talk was about coal and potentially IGCC and a nuclear renaissance. That’s been stopped in its tracks, not because of any consensus about the right way to go, but what’s happened on the gas side. You now have an industry that’s driven much more by broader commodity trends. The days of building a generating portfolio on a 20-year plan are over.
Napolitano, RBC Capital Markets: We’re seeing the next evolutionary stage, the re-gasification of the industry to meet the implied goals of 2001-era deregulation.
If you look back at the market modeling performed by experts in the space around 2001, you’ll see they forecast a change in the supply stack. It included the retirement of nuclear and coal plants, and continued building of combined-cycle gas-fired plants, with really no renewables in the mix. Ten years later, what do we have? Life-extensions associated with nuclear, and very few shutdowns. The court’s CSAPR decision leaves the issue uncertain, but you still see economic shutdowns of coal plants driven by regulations and also by the lack of power price support. You see all these renewable plants coming on the grid, wind and solar predominately, and people are talking about gas-fired plants again.
The new gas-fired plants can be built on a regional basis, to replace retiring coal plants. But in other cases it will be easier to build localized generation rather than plants that require multi-state transmission lines—some of which are being canceled. Some projects in PJM recently were canceled after five or six years of planning. [Editor’s note: PJM’s board at the end of August removed the $1.2 billion Mid-Atlantic Power Pathway (MAPP) and $2.1 billion Potomac-Appalachian Transmission Highline (PATH) projects from its planning queue.]
Fortnightly: What do you see as the outlook for renewables in this environment? There’s a lot of uncertainty about federal incentives, but still strong public support for renewables.
Napolitano: The question is, are we at the end of the renewable renaissance? As we head into the election and look at the pancaking of costs—and the lack of economic recovery, which would let people focus less on expenses and more on revenues—it’s getting harder to find support for renewables. Post-Solyndra, it’s a question of whether any federal subsidy, either direct or indirect, will be available for future tranches of renewable construction.
Fortnightly: During the Bush administration some states increased their RPS goals and pursued climate-change policies, partly in reaction to federal inaction. Might that happen again?
Napolitano: No state is in a healthy situation to make up the difference. In fact, as the economy continues performing weaker than planned, states might start to question their RPS goals and timelines. If we start to see states compromising on those goals, and if you take away the revenue contracts, there’s no hope of building new projects. The whole thing will come to a halt. Already some U.S. manufacturers are scaling back production lines and laying off workers, and globally we’re seeing bankruptcies among manufacturers of equipment.
This could become an environment where the strong simply eat the weak in the renewable space. Prime assets will be those that are up and running and are past the early period when the tax-attribution portion mattered most. These plants will have true operating cash flow and a contract with 15-plus years remaining. The buyers could be power companies, pension funds, or perhaps public market investors, through IPO vehicles. Also European and Canadian companies still see the U.S. as a good strategic market, and they could harvest those renewable assets. There’s good reason to believe there will be a lot of M&A activity around contracted renewable assets in 2013.
Olazabal: Institutional investors are asking if [the roll back of renewable incentives] means there’s an opportunity in the market. Even if wind goes away, there’s a lot of interesting action in solar. There’s definitely a hunger among fixed-income investors. They haven’t had access to these types of projects before, and many large institutional investors are very focused on environmental and social issues. They’d love to see more of those types of deals.
Counterparties are trying to figure out what they’ll look like. It’s a nascent market now, but a couple of big solar project bond deals have been relatively well received. It’s like the heyday of the independent power industry, when institutional investors were getting comfortable with the idea of standalone non-recourse projects, and what they meant in terms of due diligence, offtaker risks, and EPC contracting. Who will be the Bechtel or Fluor of the solar industry? Nobody knows yet, but they’ll bring a track record of getting projects done, and that will make investors more comfortable. It’s exciting; a business model is emerging.
Fortnightly: What’s the equity market outlook for power and utility companies?
Tate: The outlook vacillates, contingent on what will happen with the overall economy. Utility stocks have been a safe haven, outperforming during market volatility and underperforming during market advances. As the U.S. economic recovery picks up steam, we could see non-traditional utility investors exiting the sector as inflation kicks in. Rising interest rates and unknown dividend tax policies could be a headwind for utility stocks.
Nastro: Utility valuations are close to their 10-year highs, but we haven’t seen a significant amount of equity issuance from the sector. That’s because utilities largely took advantage of bonus depreciation. Now, as the sun likely sets on bonus depreciation, we expect to see more equity issuance from the sector as we go into 2013. Utilities have a significant amount of capex planned in the near term, and bonus depreciation is not a funding strategy.
If there’s a complete rollback on dividend taxes to pre-Bush rates, the rate would return to 39.5 percent. If you fully load that with the health-care surtax, the top dividend tax rate would be 43.4 percent. Should that scenario play out, we may see a potential compression in PE [price-to-earnings] multiples of 1 to 1.5 percent for many utility companies.
Companies now are asking the question: given where prices are today, given the potential headwinds in the macro economy, and given robust capital needs, should we consider pre-funding our 2013 and 2014 equity needs? (See “Pay it Forward.”)
Fortnightly: Utilities are in the middle of a wave of capital spending, at a time of weak demand and low power prices. Is that putting pressure on balance sheets?
Hunter, Moody’s: Actually C&I demand has increased moderately. It’s not back to where it was pre-recession, but it has increased. There has been a notable weakness in residential demand, but it’s hard to figure out how much of that is due to mild weather and conservation, and how much is due to the weak economy. However, despite middling demand and low power prices, overall we expect the industry will get reasonably timely recovery. The regulatory compact is still intact.
Haggerty, Moody’s: Low interest rates and low fuel costs help a lot. But it depends on what the capex is for and what mechanisms are in place at the state level. Capex has been coming for a while, in fits and starts. CSAPR has been delayed, and that’s given some utilities more time to comply. The other area is transmission capex, which generally benefits from reasonably high ROEs, because it’s mostly FERC regulated. But in selective circumstances, when a small utility is building a big generating asset, there will be some pressure on rates. An example is Mississippi Power, which is a relatively small operating utility building an IGCC plant. That will put pressure on rates in the neighborhood of 30 percent or higher.
Capex needs are more of an issue for unregulated companies. There’s no way for them to cover environmental capex, especially when power prices are low.
Olazabal: One thing that fixed-income investors are really focused on is environmental regulations—what shape they’ll take as they develop. CSAPR has been pushed out or removed, but we still face mercury regulations. The standards aren’t likely to get lighter from here. Depending on the outcome of the elections, maybe things won’t be as severe, but I don’t think many people realistically envision a return to a more lenient emissions environment. So the question is how much capital will be required? What will be the impact on the generation fleet? Are companies able to handle the incremental financing need? What’s the impact on the credit profile?
Whitlock: One thing we’re looking at harder in 2013—unless something happens between now and the end of the year, it looks like bonus depreciation will end. It’s been a great source of funds for companies, so they don’t have to issue large amounts of new debt. We might see a period of creeping leverage, which could affect credit quality. I think it’s too early to see where we’re headed with that, and whether utilities will balance out their debt with coverage from cash flow. The key thing is how quickly utilities can recover cash from their new investments, to generate free cash flow.
Fortnightly: Approved returns on equity (ROE) are coming under pressure. Some analysts suggest utilities’ approved ROEs could fall by between 25 and 75 basis points in the next round of rate cases. What do you see happening in approved ROEs, and what are the implications?
Olazabal: Downward pressure on allowed ROE is to be expected in this declined interest rate environment. The spread on allowed ROE is close to or near historic highs, and I think commissions are reacting naturally with some reductions. To date those reductions seem moderate and reasonable. Most utilities can handle a reduction without much material effect on the credit profile.
Nastro: Low fuel prices have largely offset customer rate increases, so regulators haven’t pushed down ROEs as fast as they might otherwise in a historically low U.S. Treasury environment. There’s a significant amount of capex that needs to go into rates, and there likely will be customer push-back. As more utilities head into rate cases, the questions will involve how well they can defend existing ROEs and manage the regulatory process. Given the macro environment, the numbers are likely to come down.
Tate: The thing to watch is rising interest rates. Interest rates can increase rapidly, and they have in the past. But rate cases involve long-term decisions. If you receive a lower ROE based on assumed capital costs, and you find yourself in a rapidly rising interest rate environment, it could pressure your returns.
Fortnightly: What’s the outlook for M&A—both for corporate mergers and also asset sales?
Nastro: We still see catalysts in place for increased strategic activity—drivers such as scale and scope, earnings growth, diversification and rebalancing the business mix, as well as succession planning.
Napolitano: When rate cases are open, it’s not a good time to announce mergers. Given the nature of rate cases that need to be filed in the next year or the next three years, you won’t see a lot of mergers of equals. You will, however, see sales of properties that aren’t core to the seller’s multi-state strategy. Live auctions on the street today include assets where a company is looking to get out of a state, or doesn’t feel it needs to be in the distribution business any longer.
Also we’ve seen a lot of internal succession planning, and a new crop of CEOs stepping in. It’s not typical for a new CEO to engage in M&A. Instead you’ll see them getting a couple of years of track record, and figuring out where they want to put their stamp on the company.
The next wave of mergers might be driven by growth rates in different economic regions. If a certain region is growing faster and you have trouble dealing with that growth, you might need a bailout partner or a big brother. And if you’re achieving higher valuation than your peers, acquiring a smaller company in a growing region might position you for growth as the economy catches up to the region.
On the unregulated side, I see lots of potential for consolidation in a very fragmented sector. The NRG-GenOn merger is an example of companies going for greater scale, putting assets under a strong management team, and managing a larger portfolio. Some companies are testing the market for valuation on fossil power plants and portfolios. Hybrid companies are thinking of changing strategies and focusing on rate-base cash flows.
Fortnightly: Won’t low power prices slow down asset sales?
Napolitano: Buyers who are going to take that risk will build in a risk-reward balance. But I don’t think it will shake out that clearly. We’re in a permanent state of uncertainty, which means that one has to use common sense. In vertically integrated markets like the Midwest, the Pacific Northwest, and the Southeast, utilities have the opportunity to acquire former independent power plants, where the PPA has run off and there’s no option for the owner but to re-contract. In those cases, assets will be sold for very low prices.
Nastro: We continue to see interest from strategic as well as financial players in buying generating assets. There haven’t been a lot of gas-fired plants with long-term PPAs on the market over the last couple of years, and that scarcity has pushed many investors to look at merchant assets more than in the past. We see interest from strategic buyers who are betting on a recovery. If you look at recent valuations, buyers are putting higher valuations on near-term cash flows than would be implied by forward curves. Those assets are being valued more highly by private buyers, who are willing to weather the market and ride out the recovery.
Also, the market is rewarding execution of a clear strategic vision by sellers who look to focus on their core business. Regulated companies continue to trade at a premium to hybrid companies, which encourages companies to reconsider divesting non-core or underperforming assets. In divestitures over the last 24 months, we’ve seen the sellers’ stock price outperform. Two years ago Pepco sold its Conectiv generating assets, and the subsequent expansion in Pepco’s P/E multiple more than offset the earnings dilution associated with the divestiture. More recently Dominion announced that it was considering divesting three merchant assets, and the company’s stock price responded favorably.
Fortnightly: Some large mergers have been completed or moved forward in the past year. What lessons can we learn from these deals?
Wobbrock, Moody’s: One lesson might be to offer up a pound of flesh from the beginning. For example, in acquiring Central Vermont Public Service, Gaz Métro offered significant customer savings, and it seemed to understand how to approach the commission and interveners. Another example is Fortis acquiring Central Hudson Gas & Electric. They proposed a plan to the commission, and it remains to be seen whether the commission thinks what they offered is enough or whether they’ll want more.
Hunter: It’s no surprise that states are taking their pound of flesh. They want to extract benefits for ratepayers before they’ll approve transactions, and companies go into deals expecting that to happen. The surprises in the latest round of mergers, however, have come from FERC, which has been more stringent in its market power determinations than had been expected. That was a surprise particularly for the Duke-Progress merger but also to a lesser extent for Exelon-Constellation. They thought selling the plant portfolio in Maryland would be sufficient, but FERC put more strictures on it and imposed a time frame that made it more expensive.
The same factors, as far as we can tell, shouldn’t necessarily be a deterrent for other mergers. For GenOn and NRG, for example, the two companies operate in very disparate geographies. There’s some overlap in New York but none in PJM, where FERC’s market power concerns primarily focused.
Nastro: It’s difficult to extrapolate a trend from just a few data points. The Duke-Progress and Exelon-Constellation situations were case-specific, but FERC is being more assertive and that’s more of a consideration now when contemplating a merger. However, states continue to be receptive to M&A as a way to mitigate potential rate increases. That’s an important reason why we’ve seen a more constructive regulatory environment at the state level.
Companies are stressing the strategic value of the combination, the benefits of balance-sheet strength and credit quality, so acquisition premiums have come down. Credit quality continues to be emphasized with the majority of corporate deals being stock transactions without incremental leverage.
Tate: In the big picture, the volume of announced utility M&A has slowed in 2012. There were over $40 billion in announced utility transactions in 2011, and in 2012 the number is significantly lower. But having said that, there’s a lot of active M&A dialogue occurring behind the scenes. Key drivers are the desire for increased scale, a greater focus on regulated operations, and enhanced growth opportunities. Financial scale has gained importance in recent M&A deals, rather than operating synergies.
Also, over the last couple of years we’ve seen a couple of trends emerging. First, Canadian utilities have shown significant interest in acquiring U.S. utilities. Since 2010, 10 of 25 deals have involved Canadian buyers. This is driven by attractive acquisition opportunities, but also there’s a valuation arbitrage; Canadian publicly traded utilities trade at premiums compared to their peers in the United States, so they can pay a higher premium and a deal can still be accretive. And allowed ROEs for U.S. utilities are frequently 100 to 150 basis points higher than they are for Canadian utilities.
The other trend is a move toward larger regulated operations and lower business risk. These drivers are pushing smaller utilities to consider consolidation. And overlying all of this, the capital markets remain open, providing attractive acquisition capital.