The Big Build will test the industry’s access to Wall Street.
Bob Ford is Americas power and utilities sector leader at Ernst & Young Americas Power & Utilities Center in Washington D.C. Email him at email@example.com. Joseph Fontana is global utilities and power industry leader, transaction advisory services at Ernst & Young. Email him at firstname.lastname@example.org. Patrick Cass is the leader of the energy and utility industry for Ernst & Young’s North Central United States Region. Email him at email@example.com.
The U.S. power and gas industries are—in common with the rest of the world—witnessing the most revolutionary period of change since the first utility systems were built. The era of easily available, affordable energy rapidly is ending and our society is realizing that our energy infrastructure is severely inadequate to supply the energy demands of the future. The major issue facing the sector today is how to fund and deliver this new climate-friendly infrastructure, which is currently estimated will cost almost $2 trillion 1 between now and 2030.
To be successful, the energy stakeholders in the United States must collaborate to bring affordable power to everyone. A successful end result will require creative financing structures and techniques; tax incentives; enabling legislation for new nuclear facilities, renewable and environmental requirements; and new grid technologies to lower and shape the system load, improve reliability and deliver more of the power produced.
In recent years, U.S. utilities have deferred major infrastructure investments because many of them were locked into multi-year tariff freezes and were working off so-called excess capacity. Some companies cut back discretionary capital spending, choosing to focus resources instead on reducing debt and restoring their financial strength. However, the years since 2005 have seen a period of accelerated investment in capital expenditures (cap-ex). Influential factors encouraging higher investment in infrastructure spending have included policy concerns about energy reliability and diversity of sources; the introduction of tighter environmental rules; and of course the heavy strain of aging generation, transmission and distribution systems.
This leaves utility CEOs facing major questions that affect the long term, but need answers today:
• Where is the money going to come from for the increased infrastructure—and are utilities’ balance sheets strong enough to finance these massive investments?
• How can management teams be sure they are making the right investment decisions?
• What are the financial implications—especially in terms of impact on revenues?
• How are they to fill the critical people skills gaps facing the industry?
So where will the capital come from to fund this big infrastructure buildout, and what are the barriers to ensuring recovery of costs?
Despite the current U.S. credit crunch, the general consensus is that capital still is (and will continue to be) available. Well-prepared utilities with strong balance sheets shouldn’t face major problems in finding banks to lend them money, or in raising cash through traditional routes like mortgage bonds and equity offerings. However, many companies that are less financially fit will experience a more challenging time raising capital and can expect higher financing costs.
Risks and Returns
There is plenty of room for funding from newer sources. For example, $302 billion of private equity capital flowed into U.S. funds in 2007.2 Hedge funds raised $194.5 billion,3 and in the two years from 2006-07, U.S. infrastructure funds rose by $150 billion.4 A good proportion of this money could make its way into the utilities industry, which still is highly attractive to investors due to its relatively low risks and stable returns.
The question of which investments will prove most attractive really depends on the individual buyer’s risk-and-return profile. An infrastructure fund, for example, will be drawn to buy rate-regulated utilities, and probably will prefer to invest in states with a track record of consistent, predictable and transparent regulation.5 But while infrastructure funds likely will be content with the dividend yield that regulated utilities will generate, PE buyers may seek to leverage any such investment to generate greater returns, or exit. Alternatively, PE buyers might avoid regulated utilities altogether in favor of buying generation, which provides the opportunity—particularly in the country’s liquid markets6—to earn hefty returns. Others (such as ITC Holdings) may be attracted to invest in transmission because of the FERC incentives available. There also could be potential for sovereign wealth funds to invest in infrastructure, although they will face close scrutiny and are likely to be disappointed if the asset they want to buy is considered strategic.
The entry of these alternative buyers has created an opportunity for utilities to sell those businesses that compete for capital with their core, strategic businesses. What also is likely to occur is an increase in divestments to raise the cash for vital new infrastructure spending.7 Some smaller utilities may be forced to merge or combine to ensure adequate critical mass so they can afford necessary investments.
Return on Investment?
One fundamental question all utility investors want answered favorably is: “Will the regulator allow us to recover the cost of our investments in future years?” Recent disappointing rate cases might give some cause for concern. For example, PNM Resources just received a very unsatisfactory decision slashing its permitted return on equity. This happened before it even started building new infrastructure. When the company begins building in earnest, it will mean further pressure on rates.
Regulatory battles like this can be demoralizing and can prompt company executives to think twice before investing. It’s no wonder that infrastructure funds seek out opportunities in states where they trust they will be allowed to earn steady, regulated returns—as in Macquarie’s recent proposed acquisition of Puget Energy.
However, even if the regulator gives investors serious reasons to pause, realistically at some point further delay is impossible and the money must be spent. Otherwise, the lights go off. Regulators realize this too. Although they may act aggressively on pricing in favor of customers, they know it’s ultimately in the best interest of the consumer to have consistent, fair regulation, because inconsistency adds delay, which in turn impacts both investment and supply reliability. It will be worth watching whether the reliability of power increases in states where the regulators prove most consistent in their approach to pricing.
While one key question concerns sources of financing, the other big issue is finding enough people to deliver the program. It will take a huge, skilled workforce to build the new infrastructure we need now, and operate and maintain it into the future. While there are plenty of options for raising money, the answer to the people issue is more complex.
A pervasive talent shortage has been growing quietly. It began with the need to control operating costs, and was exacerbated by the fact that the last major buildout of the U.S. utility system ended in the 1980s. This skills shortage is now a serious threat. For example, around half of the electricity utility workforce could become eligible for retirement within a decade8—and businesses are not even attracting enough people to replace these retirees, let alone account for expected growth. The shortage is appearing across the board: from nuclear engineers to experienced plant operators, from geophysicists and geologists to construction project managers, from senior management teams to field workers.
We may even have reached the point where future energy supplies—including the type of infrastructure we build—could be dictated by the sheer unavailability of skills. If, for example, there is a 15-year time lag to get sufficient numbers of people through the necessary nuclear engineering training, utilities might decide not to build nuclear, but meet demand other ways.
The obvious result is that attracting talent will become increasingly costly and competitive, and that training expenses necessarily will rise. The more proactive companies are tackling the problem at the root level, for example developing relationships with high schools to boost interest in the careers they can offer and to attract people into industry training programs. Power and utility companies also are reaching out to energy service companies and outsourcers for a greater proportion of their generation and T&D construction and maintenance, and this trend is widely expected to accelerate as the workforce challenges grow more severe.
Another influential factor is the question of whether critical infrastructure components actually are available to buy. As is evident from International Energy Agency (IEA) forecasts, the United States is competing with the rest of the world for the same resources.
Heavy worldwide demand is putting massive pressure on the whole supply chain, resulting in higher prices for raw materials like uranium, and long waiting lists for manufactured components like turbines. At present, for example, there is only one heavy metal forger in the world (located in Japan) that can build the necessary steel pressure vessels for nuclear plants. How will the suppliers cope with demand from the United States, let alone the rest of the world? Of course, prices will rise.
Fueled by massive demand from developing economies such as China and India, prices for vital commodities like steel and cement also have risen. It’s the same dynamic that’s driving the price of oil higher. This factor also, inevitably, pushes up the price of infrastructure building programs. The $1.6 trillion figure for infrastructure construction likely will prove an underestimate. Next year’s IEA schedule of forecast investment for the coming decade could be very much higher due to these skyrocketing raw-material costs.
What can we expect in the future? Realistically, it’s possible we could see some demand destruction, either because of rising prices or slowing economies, or both—but if so, this is likely to be a temporary dip rather than an extended trend. Long term, the assumption is that world economies will continue to grow, and growing demand will keep prices up.
The current uncertainty about forthcoming environmental regulation on carbon emissions puts power and utility companies on shifting ground in terms of business planning and investment decision-making.
In the run up to November’s election, the key political parties all have said they believe in some form of carbon control. If the Democrats win, broadly speaking, most Americans believe there probably will be a quicker response and attempt to instigate more stringent regulations than if the Republicans win. We will have to wait until after the November election to see what will be the concrete effects on the industry as a whole, and on investment in particular.
State by state, the current picture is patchy. One major movement has been the introduction of renewable portfolio standards (RPS), which currently are in place in 26 states plus the District of Columbia,9 and require utilities to supply a certain (in some cases sizeable) percentage of power from renewable sources. Some tax credits and other incentives are available to help create this new renewable supply, but the ultimate effect has to be an increase in the cost of power, simply because renewable power sources like wind are more expensive on a kWh basis than are coal or a combined-cycle plant.
We are still guessing about the price of carbon, and waiting to see what the federal government will do about carbon regulations. Ten Northeastern and mid-Atlantic states plan to implement the Regional Greenhouse Gas Initiative, or RGGI. Effective starting next year, this will put a cap-and-trade program in place around carbon, with customers ultimately bearing the cost. The real cost of carbon will become evident to customers for the first time.
How they react, and whether the system is effective or not, will depend on how the system is put into action—and at what level RGGI sets the cap. California is set to implement a similar program.
The big issues for the politicians are what tolerance exists among consumers (i.e., voters) as a whole to soak up price increases, and what will be the societal effects? After all, there is more at stake than a clean environment. In the midWest, where manufacturers need to be competitive on a worldwide basis, industrial electricity customers are currently paying around 5 cents per kilowatt hour for their electricity. What happens to those manufacturers if the price of carbon pushes electricity up and suddenly the economics of manufacturing in the Midwest don’t make sense any more? As to the effects on residential customers, figures from the Lieberman-Warner Climate Change Bill estimate the cost of carbon could reach $54 to $64 per metric tonne in 2020, rising to $227 to $271 in 2030. This could dramatically drive up the cost of residential power: There is potential for political mayhem.
Standard & Poor’s (S&P) recently took the view10 that the market could absorb the cost of carbon if it is done gradually, but that it would be disastrous for utilities if it is instigated aggressively and too quickly. We have to hope that this warning is heeded and that the approach taken by those responsible will be prudent, rather than zealous.
Clean Coal Lives
For two years, the proposed $1.8 billion FutureGen project, a single plant to test various coal types with gasification technology and permanent carbon capture and storage (CCS), was favored by the U.S. DOE. Recently, amid concerns over massively escalating costs, the DOE has reconfigured the project: The money now will be split into smaller packets to help utilities with the cost of CCS at plants still to be built. As this change of plan will delay commercialization of CCS technology by four years, investors might think this implies that the DOE’s belief in coal and CCS has waned. So is there a future for investing in clean coal? The answer is: probably. Private enterprises still are investing in carbon sequestration.11 Without up-front government funding, clean coal could be further over the horizon, but there is no reason to believe the technology won’t happen.
In the meantime, some lawmakers in Congress are working on a bill that would ban construction of any coal plants unless carbon controls are in place. However, there is a major energy conundrum here. If you don’t want coal, you need nuclear to meet demand, and there is also considerable debate about the desirability of nuclear.
Looking at the market as a whole, it is clear that the wave of consolidations that some pundits predicted would occur over the past five years has not materialized. That is not wholly surprising, given that the regulators have shown a determined and aggressive tendency to refuse any transactions they felt didn’t provide sufficient benefits to customers.
However, just because this may have put merger plans on hold for some companies, it doesn’t mean consolidation won’t proceed in the future. And while this may affect certain companies’ freedom to invest, consolidation is only one avenue to raising cash. There still are many alternatives to explore: Aspiring investors also will be considering selling off non-core assets to raise cash; going to the debt markets; raising structured finance; or entering into joint ventures with alternative capital providers.
The United States urgently needs this growth in infrastructure to secure its energy future, and well-delineated projects with a clear business case should have access to adequate funding. However, there are challenges: A shortage of skilled people; uncertainty about environmental regulation; and of course, regulatory barriers to gaining a solid return on investment.
Investors will be wary of repeating past investment cycles, in which some of the companies with the most aggressive spending programs suffered erosion in financial conditions. S&P foresees some risk on the basis of the industry’s previous experience in buildouts. It’s possible that a track record of rate freezes or prudency disallowances could make some utilities or states less attractive for investment than others. Investors will be carrying out careful due diligence to clarify whether there’s a reasonable chance of future recovery of costs. Utilities themselves will need to manage the process meticulously to avoid the risk of prudency write-offs, putting strict controls in place to manage the buildout and ensuring they have the regulator’s sign-off at each step of the development process.
1. IEA, World Energy Outlook 2006.
2. Dow Jones Private Equity Analyst newsletter, January 2008.
3. Hedge Fund Research Report, January 2008.
4. Crédit Suisse, ExNet M&A conference, January 2008.
5. e.g., this was the reasoning behind Macquarie’s investment in Puget Energy in Washington.
6. e.g., PJM, NY ISO, ERCOT, CAISO and NE-ISO.
7. e.g., PNM Resources recently announced plans to sell off its gas business to focus on electricity; and ConEd announced the sale of its unregulated generation to focus on its distribution business.
8. Estimate from Paul Bowers, president of Southern Company Generation, to the Senate Committee on Energy and Natural Resources. Reported by Electric Power Daily.
7. November 2007.
9. Four other states have voluntary regimes.
10. The Race for Green:How Renewable Portfolio Standards Could Affect U.S. Utility Credit Quality, Standard & Poor’s, March 10, 2008.
11. Including LS Power, which has just initiated a research study on the subject with the University of Texas at Austin.