If Hollywood were scripting the power industry story for 2011, it would be a sequel to 2010—more of the same, but just not quite as good. Natural gas gets top billing and the accolades, wind power drops to a supporting role, and new nuclear answers the casting call but has yet to get a speaking part. Coal is like Mel Gibson—a talented Oscar winner unlikely to get another leading role. In this, our fifth annual industry forecast report, the story may be familiar, but the price of admission is going way up.
Dull. Boring. Yawn-inducing. Soporific. Bland. More of the same. Welcome to the world of energy, 2011.
For a change, the coming year in energy, at least in the U.S., looks like a year of few surprises and no real excitement. Compared with previous years, 2011 could shape up to be business as usual, and a breather after 2010 is probably welcome.
Looking back, 2010 was filled with spills, thrills, and chills. A mammoth deepwater drilling rig in the Gulf of Mexico blew up and spewed out millions of gallons of crude, occupying the front pages of U.S. newspapers and providing endless footage for TV broadcasts for a third of the year. Climate legislation—threatening game-changing impacts on the generation of electricity, particularly for coal—crashed and burned in the U.S. Senate amid cheers from many in the industry and jeers from environmentalists. The U.S. nuclear renaissance again promised to make an appearance, and Uncle Sam dropped an $8.3 billion loan guarantee on a proposed two-unit project, but nuclear exited the year with a whimper.
Electricity Demand Rebounds
So what’s ahead? Let’s start with demand for electricity, the major driver of business decisions about generation, including whether to build new plants, retire old ones, or change the mix of technologies used to make power. The dominant factors in electric demand are the state of the U.S. economy and the weather. The “Great Recession” is still being felt, and annual economic growth is likely to be around 2% for 2011, according to many estimates.
As for the weather, last summer was unusually hot (following an unusually cool summer 2009), which drove increased use of air conditioning, causing the U.S. Energy Information Administration (EIA) in its November 2010 Short Term Energy Outlook to raise its 2010 yearly electricity forecast to a 4.7% increase, up from 4% in August. Assuming that temperatures in 2011 will return to normal, the EIA is forecasting electric demand growth for the year to drop to –0.1%, down from a modest 0.4% predicted in August (Figure 1).
|1. Electricity consumption grows. Total U.S. electricity consumption grew in 2010 after two straight years of decreases. Electricity consumption in 2011 is predicted by the Energy Information Administration (EIA) to be approximately the same as in 2010. Source: EIA, Short-Term Energy Outlook, November 2010|
Long-term EIA assessments predict that 2011 will be the last year of about zero growth in electricity generation; future predictions trend back to 1% through 2035 (Figure 2). The North American Electric Reliability Corp. (NERC) 2010 Long-Term Reliability Assessment released in October is consistent with the EIA predictions that summer peak demand will grow by 1.34% per year and annual net generation will grow by 1.57% through 2019. That means no bubbling economy to spur electric demand. Another concern: NERC recently concluded that the Environmental Protection Agency’s (EPA’s) preoccupation with regulating coal-fired power plants will likely reduce the reliability of the nation’s grid (see the NERC sidebar).
|2. Slow future growth. The EIA predicts that electricity growth, though stagnant in 2011, will resume long-term growth of about 1.5% per year. The data are based on a three-year moving average. Source: EIA, Short-Term Energy Outlook, November 2010|
The slow-as-Venezuelan crude economy influenced energy use across all sectors. Lawrence Livermore National Laboratory (LLNL) in September reported that total U.S. energy consumption in 2009 (the latest year for which data are available) was 94.6 quadrillion Btu, down from 99 quads in 2008. “Energy use tends to follow the level of economic activity, and that level declined last year. At the same time, higher efficiency appliances and vehicles reduced energy use even further,” said A.J. Simon, an LLNL energy systems analyst who develops the energy flow charts using data provided by the Department of Energy’s (DOE’s) Energy Information Administration. “As a result, people and businesses are using less energy in general.” Simon elaborated: “Simply said, people are doing less stuff. Therefore, they’re burning less fuel.”
Coal Remains Number One
The generating story for 2011 starts with coal, the fuel that just won’t quit. During 2010, green forces again tried, and failed, to commit energy regicide, but Old King Coal again survived. It’s dirty to burn, it’s hard to handle, its extraction disrupts the earth. But coal packs a wallop in terms of energy density, and it is relatively cheap, meaning that coal is still the dominant fuel for baseload generation of power. This year shapes up as offering no reason for coal plants already in operation or in the construction pipeline to disappear wholesale, although some retirements and plant cancellations are likely, due to specific business conditions (Figure 3).
|3. Coal use remains flat. Coal consumption will remain flat in 2011, according to EIA predictions. Data are presented as a percent change from the previous year. Source: EIA, Short-Term Energy Outlook, November 2010|
Look for coal to continue its hegemony well beyond 2011. Few new projects are likely to be announced this year or next, but a large group of projects are under way. Most are likely to get finished and enter service. A year ago, the DOE’s National Energy Technology Laboratory (NETL) southwest of Pittsburgh updated 2002 and 2007 reports on coal-generating plants with conclusions drawn from its extensive plant database. The key finding of last year’s NETL report was the growing gap between announced projects and commissioned plant capacity. The NETL report, “Tracking New Coal-Fired Power Plants” (available on the NETL website) noted: “Actual plant capacity, commissioned since 2000, has been far less than new capacity announced.” The 2002 report showed over 36,000 MW of new coal-fired capacity scheduled to be installed by 2007. Only about 4,500 MW actually got commissioned.
This trend continued last year and is likely to continue in 2011 and 2012, according to NETL’s Erik Shuster, who wrote the NETL reports. Shuster told POWER in an interview that he expects fewer announcements of new projects in the next couple of years, driven by uncertainty about the economy and the political environment. There will also be some retirements, such as the one announced last year by the Tennessee Valley Authority, which is retiring nine elderly units. But that leaves “tons of plants” still in the works, says Shuster.
According to NETL’s 2010 report, 22 plants (13,755 MW of coal-fired generation) were under construction in January, down from 28 plants (2,500 MW) in January 2009, with one plant (320 MW) “near construction,” down from seven plants (2,500 MW) in 2009. Eight plants (3,280 MW) in January 2010 were in NETL’s “permitted” category, compared to 13 plants (7,000 MW) in January 2009. NETL defines “permitted” as “Two or more permits approved or fuel or power contracts have been negotiated.”
The Sierra Club maintains a useful database on its website of coal-fired projects, which generally agrees with data in the NETL compilation. In its latest update, the Sierra Club’s tracking shows 44 projects that it defines as active, 11 as “upcoming,” and 25 as “uncertain.” The organization claims “victory!” for 133 cancelled plants, although many of those projects died without the opposition of environmental groups.
So coal looks solid for the next couple of years. But there is an eerie resemblance between the current coal project pipeline and what we saw in the late 1970s and 1980s with nuclear plants: It’s a pipeline in the process of emptying. The EIA’s Annual Energy Outlook also points to this phenomenon, showing a gradual but significant market share decline for coal-fired electricity by the middle of this decade, rebounding a bit by 2035. The EIA says, “With slow growth in electricity demand, little new coal-fired capacity is added, and the coal share falls from 48 percent in 2008 to 44 percent in 2035.”
Gas Enjoys a Big Rebound
Coal’s long-term decline, by EIA’s reckoning, will be more than matched by growth in gas-fired generation. The early 1990s’ “dash for gas,” which collapsed as domestic supplies shrunk and prices rose, is back. This time it’s riding the wave of new technologies for tapping the enormous resources previously trapped inside shale deposits. Washington energy lawyer Andrew Weissman said recently, “We now have the ability to develop a resource we didn’t have before, and it’s vast. It can be developed at lower costs than sources we were relying on just 24 months ago.”
Weissman added that, because of the nature of the gas deposits and current technology, “we can expand natural gas supplies very rapidly.” The ease and low cost of tapping gas in shale takes the volatility out of gas prices, which was one of the vexing features of this fuel in the past. “We had a cold winter,” said Weissman, “and that uses a lot of gas, and one of the hottest summers ever. Despite that gas prices stayed near the lowest level in a decade,” some $3 to $4 per million Btu (mmBtu).
The EIA’s most recent Short-Term Energy Outlook, released on November 9, reported that natural gas working inventories were about the same as last year’s record-setting levels. Also, the average natural gas spot price at the Henry Hub was $4.35 per mmBtu, an increase of $0.40 over 2009. The EIA projects that the Henry Hub spot price will average $4.31 per mmBtu in 2011 (Figure 4).
|4. Natural gas prices hold steady. The EIA predicts a slight upward movement in natural gas prices during 2011. Source: EIA, Short-Term Energy Outlook, November 2010|
During the first half of 2010, Industrial Info Resources (IIR) was tracking a total of nearly 9,000 MW of new gas-fired generating capacity that had a scheduled 2010 kickoff date, as reported in the September issue of POWER. That sum included about 3,800 MW that was actually under construction as of July, another 2,700 MW that was in the engineering phase, and about 2,400 MW that was planned. And 2010 wasn’t even a banner year for gas. Noted IRR, “Beyond 2010, there is a healthy book of gas-fired generation construction slated for kick-off over the next few years. Industrial Info is tracking 44,500 MW of U.S. gas-fired power plant construction scheduled to begin between 2011 and 2015. Not all of these projects will move forward, of course, but the sheer volume of planned power projects is another sign that gas-fired power development has a bright future.”
Last summer, a Massachusetts Institute of Technology (MIT) group completed the third of a series of examinations of energy sources, scoping out the prospects for gas. The MIT group, which earlier pondered coal (2007) and nuclear (2003), found that “Unconventional gas, and particularly shale gas, will make an important contribution to future U.S. energy supply and carbon dioxide (CO2) emission reduction efforts.”
The report added, “Assessments of the recoverable volumes of shale gas in the U.S. have increased dramatically over the past five years. The current mean projection of the recoverable shale gas resource is approximately 650 trillion cubic feet, with low and high projections of 420 Tcf and 870 Tcf, respectively. Of the mean projection, approximately 400 Tcf could be economically developed with a gas price at or below $6/mmBtu at the wellhead.” Figure 5 illustrates the EIA projections for natural gas consumption in 2011; much of the growth reflects gas’s use for generating electricity.
|5. Natural gas usage grew. The growth in U.S. natural gas usage in 2010 was principally caused by an increase in its use as a power generation fuel. With electricity use growth expected to be flat in 2011, natural gas usage growth will also remain flat. Source: EIA, Short-Term Energy Outlook, November 2010|
Some environmentalists have raised objections to the hydraulic fracturing technique for releasing gas from shale deposits, citing possible damage to water supplies. The MIT report commented, “The environmental impacts of shale development are manageable but challenging. The largest challenges lie in the area of water management, particularly the effective disposal of fracture fluids. Concerns with this issue are particularly acute in those regions that have not previously experienced large-scale oil and gas development.” The report advised, “It is essential that both large and small companies follow industry best practices, that water supply and disposal are coordinated on a regional basis, and that improved methods are developed for recycling of returned facture fluids.”
Gas is a growing global resource. The New York Times last fall reported major gas field discoveries off the coast of Israel. The newspaper reported, “Last year, the United States Geological Survey estimated that more than 120 trillion cubic feet of recoverable gas reserves lie beneath the waters of the Eastern Mediterranean, most of it within Israeli territory. Several months after the report, another field of 8.7 trillion cubic feet was found off Israel and a second, twice that size, was detected and is thought to have a 50 percent chance of proving out.”
The discoveries could transform energy-poor Israel, dependent on imported coal for electric power, into a self-sufficient nation. Einat Wilf, a member of the Israeli parliament, told the newspaper, “This is a huge deal that could change the geo-strategy of the region and Israel’s resources for years to come.”
Technology developments could also contribute to the continued rise of gas-fired generation around the world. The DOE’s Office of Fossil Energy announced in an August 25 Techline update that it has developed a technology for freezing natural gas into a solid, providing an alternative to conventional technology for transporting gas. Typically, moving gas involves compression (compressed natural gas, CNG) and pipelines or liquefaction (LNG) and ocean shipping. The new technology, developed by NETL, can rapidly form methane hydrate, an ice crystal that traps methane molecules within its crystalline structure. The DOE notes, “Gas hydrates retain large amounts of methane—one cubic meter of solid hydrate can produce 164 cubic meters of methane.”
NETL researchers have refined a nozzle that allows the proper mix of water and gas to produce a solid, “snow-like” mass that they say “will require less refrigeration, less pressure, and less time than either LNG or CNG production.” The DOE says that “about a third of the world’s natural gas is ‘stranded,’ or exists in remote locations where transportation costs are too great to enable utilization.” Methane hydrates are also plentiful in high-pressure, low-temperature oceans and in Arctic permafrost, the department says.
Although the future of gas is bright, a perceptible rise in gas generation won’t happen overnight, observes the EIA: “The natural gas share of generation, at 21 percent in 2008, rose in 2009 when natural gas prices fell.” It notes that, “Over the next few years, with slow growth in electricity demand, completion of coal plants under construction, and addition of new renewable capacity, the gas share falls, before trending up to 21 percent in 2035. The near- to mid-term downturn in natural gas generation might be dampened if new policies made coal use for electricity generation less attractive, or if growth in renewable generation were slower than projected.”
Wind Enters the Doldrums
That comment about wind may prove prescient. Last year was miserable for the wind industry, the most significant of the modern renewables. According to the most recent industry figures provided by the American Wind Energy Association (AWEA), new wind projects, and wind equipment manufacturing, were plunging in 2010. AWEA said that the third quarter of the year saw only 395 MW of new capacity, the lowest since 2007, in an industry that has been characterized by robust growth in the past. AWEA said that wind installations through the third quarter “stood at 1,634 MW, down 72 percent versus 2009, and the lowest level since 2006.” Manufacturing investment also continued to lag below 2008 and 2009, according to AWEA.
AWEA said that it did not expect the rest of 2010 to show a turnaround. “AWEA projects that 2010 installations will likely be 25–45% below 2009 installations, depending on policy developments,” said the wind industry trade group. AWEA projected a “dramatic drop in the project development pipeline,” observing somewhat wistfully that “there is no demand beyond the present ‘coasting momentum.’”
The wind lobby also lamented that, in the first half of the year, “the U.S. has installed more coal and natural gas power plants than wind and other clean, renewable energy sources. By contrast, during the previous two years, wind roughly matched new natural gas, and together the two sources accounted for about 90% of all new annual generating capacity installed over the past five years.”
In fact, data from the EIA and other third-party sources show that wind accounted for 39% of new installed capacity in 2009, versus 13% from coal; in the first nine months of 2010, however, the ratio flipped, and wind accounted for only 14%, versus 39% from coal, according to AWEA. Going forward, the EIA’s base case finds new wind and other renewable energy plants will contribute on par with gas and nuclear plant construction through 2020 and be dwarfed by gas plant construction through 2035 (Figure 6). The EIA base case also predicts that the installed capacity of wind and coal will remain flat for the next two decades (Figure 7).
|6. Most new capacity will be fired by natural gas or renewables. According to the EIA, “Decisions to add capacity and the choice of fuel type depend on a number of factors. With growing electricity demand and the expected retirement of 45 GWs of existing capacity, 250 GWs of new generating capacity (including end-use [combined heat and power]) will be needed between 2009 and 2035. Natural-gas-fired plants account for 46% of capacity additions . . . with 37% for renewables, 12% for coal-fired plants, and 3% for nuclear.” Source: EIA|
|7. Wind picks up rapidly, then stalls. According to the EIA, “Wind power dominates renewable capacity growth in the near term . . . [and] increases rapidly from 2008 to 2013 in response to the Federal [production tax credit, PTC] for wind, [American Recovery and Reinvestment Act, ARRA] funding, and State [renewable portfolio standard, RPS] legislation. Growth in renewable capacity slows dramatically after 2014 because of the expiration of the Federal PTC for wind and the completion of projects expected to be supported by ARRA funding. The growth before 2013 is adequate to meet State RPS-mandated renewable requirements through about 2030.” The propitious drop in the number of wind projects in 2010 is not apparent in the results of this EIA base case model. Source: EIA|
Energy journalist Bill Sweet reported in IEEE Spectrum last fall, “A more sober mood has settled over the wind industry this year. In the United States, where 10 gigawatts of capacity was added in 2009, up a record-setting 20 percent from the previous year, new turbine installations this year are expected to be closer to 6 GW…. On August 18, the top Danish wind manufacturer Vestas saw the value of its shares drop 20 percent, after a second straight quarterly loss and issuance of a profit warning. Because of several adverse trends, some of the countries that have pushed wind most aggressively may be approaching a saturation point where further turbine investment would be counter-productive.”
The problems with its industry and the solutions, says the wind lobby, are found in Washington. “Without stable policy, without demand and new power purchase agreements, and without new turbine orders, the industry is sputtering out,” says AWEA. “However, passage of a strong national [renewable energy standard] will boost demand and fire up the industry’s economic engines.” CEO Denise Bode added, “Strong federal policy supporting the U.S. wind energy industry has never been more important. We have a historic opportunity to build a major new manufacturing industry. Without strong, supportive policy like an RES to spur demand, investment, and jobs, manufacturing facilities will go idle and lay off workers if Congress doesn’t act now.”
Bode spoke before Congress adjourned for the August recess, and Congress didn’t act on energy legislation. Given the politics now on the ground, it looks as if the wind industry is going to have to suck it up and hunker down for some time (for decades, if the EIA predictions are on the mark). Many political pundits are confident that energy legislation, particularly a national renewable energy standard, won’t see the light of day in the new 112th Congress. As the history of wind turbine installations demonstrates, it is a boom-and-bust business. In the short term, it looks like a bust.
While the wind industry is gloomy, the EIA, taking a longer and more dispassionate view, is somewhat more optimistic about electricity from renewable generating technologies. The information agency predicts: “Nonhydroelectric renewable generation accounts for 41 percent of the growth in total electricity generation from 2008 to 2035, supported by extension of Federal tax credits, State requirements for renewable electricity generation,” and federal loan guarantee programs. “Wind power and biomass provide the largest share of the growth. Generation from wind power increases from 1.3 percent of total generation in 2008 to 4.1 percent in 2035. Generation from biomass, both in the electric power sector and from end-use cogeneration, grows from 0.9 percent of total generation in 2008 to 5.5 percent in 2035. A large portion of the increase in biomass generation comes from increased co-firing—a process in which biomass is mixed with coal in existing coal-fired plants, displacing some of the coal that would otherwise be burned.”
Nuclear Continues to Tread Water
If wind’s problems can only be solved in Washington, that part of the industry should beware of what has befallen another sector that has long depended on active government assistance for its future: nuclear power. That future—the “nuclear renaissance”—looks no closer in 2011 than it did five years ago.
Is it time to drop the term “renaissance” in favor of a more realistic descriptor? The term first surfaced in 2001 and gained currency during the debate over the Energy Policy Act of 2005, which established federal policies, including loan guarantees, aimed at jump-starting new nuclear plant construction. Some 10 years later, the term has lost its meaning and its implications for a large and imminent rebound in nuclear power projects. Is there really a second act for nuclear power in the U.S.? The question remains as open as it has been for the past 20 years.
The U.S. Nuclear Regulatory Commission (NRC) tracks current plans for new nuclear plants. The current NRC list shows 17 projects that have applied for agency licenses since 2007, spread among 15 developers—both utilities and merchant generators—representing 26 new units. According to the NRC, the agency received no new applications in 2010, and it predicts, without providing any detail, that it will receive applications for five new units in 2011. None of the plants in the NRC pipeline, or expected to be in the licensing process anytime soon, will be generating commercial quantities of power prior to 2018, at the earliest.
The key economic characteristics of nuclear plants have always been high capital costs and very low fuel costs. So the business decision about whether to build nuclear plants involves balancing the upfront and embedded costs (plus the difficulty of financing and recovering those costs) with future low operating costs.
One of the factors that sunk the first round of nuclear plant construction—nuclear 1.0—was the “stagflation” of the mid-1970s. Low economic growth coupled with extremely high inflation and interest rates clobbered big, long-term investments. The Seabrook nuclear plant in New Hampshire, for example, faced annual interest rates of 25% for the final chunk of borrowed cash needed to finish construction. It takes a long time to build a nuclear plant, even in the best of circumstances, so investors face a serious delay in return on investment. In retrospect, it is not much of a surprise that no new plants in the U.S. were ordered after 1974.
Today, long-term interest rates are exceptionally low, in the range of 3% to 4%, which would seem to ease financing woes for large projects such as nuclear power plants. But that’s not the case, nor was it in 2005, when Congress was forced to step in with $18 billion in authority for nuclear loan guarantees, administered by the DOE. Congress put up the loan money because many financiers remained spooked by the 1970s and 1980s, when nuclear projects collapsed across the country, leaving lenders holding bags of bad debt. Today, despite moves by the Federal Reserve to stimulate the economy by offering free money, Wall Street remains skeptical. The needed investments in nuclear plants are so large that, for many utilities, they would be bet-the-company risks. Hence, federal loan guarantees.
According to the Nuclear Energy Institute (NEI), the lobbying group for the nuclear power industry, “Nuclear energy projects are very large compared to electric utility companies. The largest electric utility has a market value of approximately $30 billion, but most are much smaller. New nuclear power plants are large, low-carbon electric production facilities that are expected to cost $6 billion to $8 billion each (2008 dollars). The relatively small electric power companies do not have the financing capability or financial strength to finance nuclear power projects absent project partners and limited investment incentives. The loan guarantee program helps offset the disparity in scale between the electric utilities and these large nuclear plant projects.”
Congress put up $18 billion in the 2005 law. However, the Bush administration, which had lobbied for the fund, was unable to allocate any of the money to proposed projects. Only in the second year of the Obama administration, in 2010, was the DOE able to give thumbs up to an $8.3 billion loan guarantee, conditioned on licensing from the NRC, to Southern Co. for a two-unit project at the existing Vogtle plant. At this writing, the loan guarantee had not resulted in a commitment from investors to finance the $10 billion project.
In large part, the problem has been a steady escalation in the estimated capital costs for all new power generation projects, but particularly nuclear projects, since 2005. Originally, the program’s designers thought $18 billion was enough to finance 80% of the capital costs of half a dozen new units, jump-starting the market and convincing Wall Street that these would be wise, profitable investments. No one knows what the costs of a new nuclear unit will be, which is one reason Wall Street is sitting on its wallets rather than opening them. According to a recent analysis by Mark Cooper for the Vermont Law School’s Institute for Energy and the Environment, “The current projected costs of reactors in the U.S. are literally all over the map, with the 2008–2009 cost estimates clustering in the $4,000 to $6,000/kW range, with estimates going as high as $10,000/kW.” Standard & Poor’s puts the average at $7.5 billion (see “The Skyrocketing Price of New Power Generation”).
Another factor militating against nuclear is low and stable natural gas prices. Standard & Poor’s (S&P) last fall noted that, except for the four contenders for a second DOE loan guarantee (likely the last from the $18 billion pot), all the pending nuclear projects have started ramping down work. Even one of the finalists, Baltimore-based Constellation Energy, is putting its Calvert Cliffs project in Maryland into slow motion. S&P said that with gas prices in the $4 to $5 range, new nuclear plants make little economic sense. “Capital costs of $6,000 to $6,500 per kilowatt, which appear to be a reasonable estimate of the construction costs for nuclear plants in the U.S., would require gas prices of $7.60 to $8.20 per MMBtu [for nuclear to be cost-competitive,]” says the S&P report.
An NEI “fact sheet” purporting to demonstrate that Wall Street is salivating to invest in new nuclear plants quotes positive remarks from Fitch Ratings, Merrill Lynch, Prudential, and Moody’s Investors Service. All are dated from 2004 to 2006. It’s unlikely that the NEI could demonstrate evidence of such enthusiasm today.
With no new U.S. plants under construction—or, to be honest, even shovel-ready—one way to gauge whether the promises of the nuclear industry for version 2.0 hold water is to look abroad. In Finland, TVO, the state utility, is supervising the building of the 1,600-MW Olkiluoto nuclear plant, featuring AREVA’s EPR reactor. The project has a €570 million loan guarantee from the French government. In late June, AREVA installed the reactor pressure vessel and said the plant should be in service at the end of 2012. The website Power-Technology.com reported last summer, “The project has been delayed by three years and is now expected to be operational by the end of 2012, resulting in a loss of $2.8 billion.”
AREVA has also had problems with its EPR project at Flamanville in Normandy, which is being built for Électricité de France (EDF). Former EDF chief Francois Roussely has cast doubts on the EPR, writing, “The credibility of both the EPR model and the ability of the French nuclear industry for success in new construction have been seriously undermined by the difficulties encountered on the Olkiluoto site in Finland and at Flamanville.” The project schedule has slipped by two years and projected costs have escalated by 25%, to $6.4 billion.
EDF plans to build four new reactors in Britain and to have the first unit in service by 2018. Charles Hendry, the UK minister of state for energy, said new reactors are likely to come in at $9.3 billion per unit.
Some nuclear power advocates argue that Wall Street investors are short-sighted and uninterested in the needs of society. Rod Adams, a former Navy nuclear submarine engineering officer and proprietor of the Atomic Insights blog, commented recently, “Perhaps part of the reason for the stark difference in decision outcomes between Georgia and Wall Street is that the people making the Vogtle decision realize that money is just a tool. They also recognize that financial performance is only one of many measures of the value of an activity.”
Presumably, recognizing the social value of nuclear power is what Congress did in 2005, and what the Obama administration reaffirmed in requesting, futilely, another $36 billion in nuclear loan guarantees in its fiscal 2011 proposed budget. That effort appears not to have worked, as we’re still waiting for a nuclear renaissance.
The EIA’s projections anticipate a rather anemic nuclear rebound. The agency says it expects nuclear generating capacity to increase from 100.6 GW in 2008 to 112.9 GW in 2035. The 2035 figure consists of 4 GW in upgrades at existing plants and 8.4 GW in new capacity, or only six new units. “All existing nuclear units continue to operate through 2035,” says EIA. The forecast assumes that the owners of the existing units “will apply for, and receive, operating license renewals, including in some cases a second 20-year extension after they reach 60 years of operation.”
The Return of Industry M&A
Finally, here’s another trend from 2010 that looks robust for 2011: energy merger and acquisition (M&A) activity. Late last summer, New York Times business columnist Andrew Ross Sorkin commented, “August is shaping up to be the busiest month for M&A in recent memory…. The animal spirits of corporate America appear to have awakened, with business leaders feeling bold again even as the economy remains sluggish.” Sorkin’s comment encompassed all of corporate America. But what he said also applies directly to energy mergers and acquisitions.
In August, Blackstone Group, a private equity firm, inked a deal to buy Dynegy Inc., one of the original players in the independent generating business of the 1980s, in a deal worth about $4.7 billion. Blackstone, at the same time, agreed to sell 3,884 MW of Dynegy’s generating fleet in California and Maine to NRG Energy for $1.36 billion. Earlier in the year, Mirant Corp., another nonutility generator, agreed to buy RRI Energy, formerly the power plant operating business of Reliant Energy in Houston, for $1.6 billion. RRI has 14,581 MW of generation and Mirant, a 1990s spinoff of Southern Co., has 10,000 MW in capacity.
There also has been lots of M&A activity in the renewable energy sector, as the wind and solar businesses are seeing a major shakeout and concentration, likely to continue in 2011. Last September, for example, Exelon Corp. bought John Deere Renewables for about $860 million, picking up 735 MW of nameplate wind capacity that is operating and another 230 MW under development. Hot M&A activity in renewables makes sense, noted Energy Business Daily, which suggested that “more mergers and acquisitions will occur as businesses try to consolidate the large number of start-up companies in the market.”
In mid-September, NRG continued its merger surge, buying Green Mountain Energy, a retail electricity marketer, for $350 million in cash. Green Mountain, with major markets in Texas and New York, was one of the first retail electricity firms in the U.S. to emerge during the market restructuring period. Texas billionaire Sam Wyly founded the firm, which has no connection to Green Mountain Power, an investor-owned Vermont electric utility.
In 2008, at the height of the credit crunch that marked the onset of the “Great Recession,” the consulting firm Accenture suggested that one likely energy market scenario was that large firms with lots of cash would look at smaller, promising firms struggling to finance growth as promising acquisitions. That has come to pass.
For 2011, lack of credit appears to be less of a problem. Money is available at interest rates that have not been lower in the memory of most people now in business. Successful firms are piling up cash. The need to find a place for all that corporate gelt —estimated at $2 trillion $3 trillion—and easy credit now appear to be M&A drivers. Cash-rich companies are looking at ways to boost the bottom line and use up their reserves before their investors demand the money. Robert Profusek of the Jones Day law firm says, “Shareholders are telling companies, either do something with all the cash or give it back to me. If you can’t grow, how do you support your multiple? You do a deal.”
The buzz over gas is also likely to contribute to greater M&A activity, said the New York Times: “This latest wave of consolidation comes with new enthusiasm for natural gas production, especially in the United States, where new technology has significantly expanded the nation’s reserves. The huge potential of new gas fields has driven most mergers in the North American energy sector in recent months, with more to come this year , according to bankers and analysts.”
“In this industry, where you’re in the business of increasing your reserves, there are two ways to do so—to drill or to acquire,” Christopher W. Sheehan, director for M&A research at IHS Herold told Times reporter Jad Mouawad. “There is an intense competition for access to resources through mergers.”
The American philosopher and sage Yogi Berra allegedly said, “It’s tough to make predictions, especially about the future.” (See the sidebar on the previous page for a report card on some of our 2010 industry predictions.) Who could have predicted the mess that mired BP in the Gulf of Mexico last year? Or the worst coal mine disaster in 50 years? Or a major gas pipeline explosion in a suburb south of San Francisco? Educated guessing is the best one can do, and that leads to this prediction for 2011: Much of the same. Or, to use another Yogi-ism, “déjà vu all over again.” Not surprisingly, that’s what we said last year.
— Kennedy Maize is a POWER contributing editor. Dr. Robert Peltier, PE is POWER’s editor-in-chief.