The Fallout
With 9,300 confirmed dead and 13,800 still missing, the devastating earthquake and tsunami that hit Japan on March 11 will go down as one of the worst natural disasters in recent memory. The death toll from the earthquake and subsequent tsunami that struck Sendai will likely approach four times that of the earthquake that rocked Kobe in 1995.
Japan is one of the world’s most beautiful countries, and its citizens have donated generously to other countries afflicted by natural disasters. The world’s third-largest economy, Japan also ranks as among the most efficient and well-organized countries on Earth; the Japanese will recover from this devastating blow and rebuild. For those interested in contributing to the relief effort, the American Red Cross is accepting donations.
Every natural disaster also carries economic consequences; in this case, the devastation in Japan has also shaken up the energy sector.
As we noted in the Flash Alert Japan’s Earthquake and Nuclear Power, the popular media’s sensationalist coverage of reactor cooling problems at Fukushima vastly exaggerated the risks of radiation exposure and a devastating nuclear accident. Little wonder that investors went into panic mode, dumping shares of uranium mining firms and utilities that operate nuclear power plants.
That being said, emergency at Fukushima will weigh on the nuclear power industry, particularly in Germany. But claims that the world will abandon nuclear power–not to mention the selloff in related stocks–are vastly overdone.
Meanwhile, the media has provided little analysis of the implications of the Sendai quake for other forms of energy. In this issue, we’ll examine the impact of the Fukushima incident on nuclear energy, renewable power, natural gas, coal and oil. We’ll also outline our top plays in these industries.
In This IssueThe Stories
The tragic events in Japan sent panic rippling through global equities markets. Names related to nuclear power were particularly hard hit, reflecting concerns about whether the burgeoning nuclear renaissance would lose steam in a post-Fukushima world. As with prior crises, investors who keep a level head and focus on identifying likely winners will fare the best. See Calm Trumps Panic.
Claims that alternative-energy technologies will benefit from renewed questions about the safety of nuclear power are shortsighted. The recent experience in Germany perfectly illustrates why solar and wind power aren’t viable alternatives. See German Inefficiency.
Although the emergency at the Fukushima nuclear power complex could have negative repercussions for the atomic energy industries in Japan and Germany, the nuclear renaissance should continue to fuel growth in key emerging markets. See Nuclear Spring or Nuclear Winter?
With global LNG markets beginning to tighten, companies with exposure to these international markets should fare well in both the near and long term. See Going Liquid.
Want to know which stocks to buy now? Check out the Fresh Money Buys list. See Fresh Money Buys.
The Stocks
First Solar (NSDQ FSLR)–Sell Short > 110
Toshiba Corp (Japan: 6502, OTC: TOSBF)–Buy in Energy Watch List
Shaw Group (NYSE: SHAW)–Buy in Energy Watch List
Cameco Corp (TSX: CCO, NYSE: CCJ)–Buy in Uranium Field Bet and Fresh Money Buy List
Uranium One (TSX: UUU)–Buy in Uranium Field Bet
Paladin Energy (ASX: PDN)–Buy in Uranium Field Bet
Chevron Corp (NYSE: CVX)–Buy < 105
BG Group (LSE: BG, OTC: BRGYY)–Buy < GBp1,650
Teekay LNG Partners LP (NYSE: TGP)–Buy < 41
Suncor Energy (TSX: SU, NYSE: SU)–Buy < USD48
Cameron International Corp (NYSE: CAM)–Buy < 60
Petroleum Geo-Services (OTC: PGSVY)–Buy
Core Laboratories
Peabody Energy Corp (NYSE: BTU)–Buy < 72.50
International Coal (NYSE: ICO)–Buy < 11
Nearly two weeks have passed since the Sendai earthquake and a week and a half since we issued the Flash Alert Japan’s Earthquake and Nuclear Power. Subscribers have asked whether my assessment of the situation has changed in the interim. It hasn’t.
The similarities between the media’s coverage of the Macondo oil spill in the Gulf of Mexico and recent reporting on the partial meltdown at the Fukushima nuclear power facility are striking.
In both instance, many media outlets raised the alarm about potential environmental risks and the long-term impact of the accident on each industry’s prospects. A year ago, names leveraged to deepwater drilling sold off dramatically while the out-of-control Macondo well continued to gush. Meanwhile, the experts argued incessantly over the well’s flow rate, and some predicted that BP wouldn’t be able to stanch the stream of oil until the field ran dry.
We offered the following commentary in the May 5, 2010, issue, Opportunity amid Crisis:
With only modest changes, the same paragraphs could apply the Fukushima accident.[T]his lack of general understanding and detail offers myriad opportunities to investors; sensationalist headlines tend to produce panic–in this case, stocks associated in any capacity with the Macondo well have taken a hit. Companies involved in this disaster fall into three categories: Those with real liability risk; those with some risk exposure but whose stocks have sold off indiscriminately; and some that likely will benefit significantly from the disaster and coming regulatory changes.
With fear in the driver’s seat, it’s time to look for investment opportunities emerging from the Horizon disaster. To determine the winners and losers, we’ll need to analyze what happened, the companies involved and what’s likely to happen going forward.
The stocks profiled in the May 5, 2010, issue included Wildcatters Portfolio holdings Cameron International Corp (NYSE: CAM) and Schlumberger (NYSE: SLB), as well as Wildcatters Portfolio holding Seadrill (NYSE: SDRL) and Anadarko Petroleum Corp (NYSE: APC). We also attached a sell rating to Diamond Offshore Drilling (NYSE DO).
On average, the four buy-rated stocks profiled in Opportunity amid Crisis are up 45.5 percent, compared to a 34.2 percent gain for the S&P 500 Energy Index and 12.9 percent return posted by the S&P 500. Sell-rated Diamond Offshore Drilling has underperformed, gaining just 3.6 percent over the same period.
As BP (NYSE: BP) began to bring the Macondo well under control, the news coverage shifted to other topics, and investors began to realize that the deepwater drilling industry was far from dead. Investors who didn’t fall prey to the prevailing panic and focused instead on identifying the likely winners and losers hit a home run.
Although the earthquake was far more devastating in terms of lives lost, the same basic principle applies: Investors who panic tend to make bad decisions, while those who take the time to evaluate the longer-term implications stand to make considerable returns on their investments.
The first untold story is that Japan was hit by one of the strongest earthquakes and largest tsunamis ever measured; within this context, the country’s nuclear reactors held up extraordinarily well. According to the Japan Atomic Industrial Forum, the Fukushima Dai-Ichi plant experienced ground acceleration of 507 centimeters per second squared, significantly above the design’s reference value. The tsunami that hit the facility was about 14.7 meters (46 feet) tall, considerably higher than the plant’s seawall was designed to withstand.
Despite these extraordinary events, all operating reactors at the site automatically shut down as designed when the earthquake hit. Shutting down a nuclear plant involves inserting control rods into the core to stop the nuclear reaction. This process isn’t like flipping a switch; some elements produced in the core of the reactor continue to degrade and produce residual heat that takes time to dissipate. But the main fission reactions halted before the plants lost power or were hit by a tsunami.
This is one of many key distinctions between the Fukushima incident and the 1986 Chernobyl disaster in the Ukraine. In the latter case, the control rods weren’t properly inserted into the core, allowing the fission reaction to spin out of control as the reactor melted down.
Second, although the suppression pools under the reactors were damaged, the primary containment vessels at all six of these reactors appear to have survived.
The term “meltdown” evokes images of a total disaster. But what happened at the Fukushima Dai-Ichi reactor wasn’t an explosion reminiscent of an atomic bomb, nor is radiation forming a toxic cloud that hovers over the plant. When the core melts down, the shell around the reactor prevents this radiation from escaping. During the Three Mile Island incident in 1979, the core melted down almost completely, but the amount of radiation released from the plant was negligible; the containment vessel worked as designed.
This is another key distinction from Chernobyl, which lacked a containment vessel capable of preventing the most dangerous radioactive material from spewing into the atmosphere.
Unlike the Soviets back in 1986, Japanese authorities responded swiftly and with great caution to the Fukushima meltdown. Whereas the Soviets denied Western reports of a disaster at Chernobyl, the Japanese have kept the local and international media apprised of the situation and evacuated a large swatch around the plant that could have been exposed to elevated radiation levels.
The Soviets also reportedly told emergency workers that responded to the disaster that their helicopters and trucks would shield them from the radiation. A recent UN report suggests that less than 50 people died because of radiation exposure from Chernobyl. Most of these victims were emergency plant workers with acute radiation poisoning. In contrast, Japan continues to monitor the exposure of Fukushima workers carefully.
Moreover, the contamination reported thus far has been minimal, especially beyond the immediate vicinity of the plant. According to a March 22 report from the US Dept of Energy, the team it sent to monitor radiation in the area has found few major risks. These workers are monitoring radiation both from the air and ground stations.
All measurements in the radiological study were below 0.03 millerem per hour, a low level when you consider that the average American receives 620 millirem of radiation exposure per year. The Nuclear Regulatory Commission’s (NRC) limit for a nuclear plant worker in the US is 5,000 millerem per year. The majority of the elevated readings were within 25 miles of the Daiichi facility.
For days, there was no measureable increase in radiation in the US. Today, in Sacramento Calif., radiation reached a detectable level, albeit thousands of times below unhealthy levels. The radioactive plume that many feared would reach US shores hasn’t materialized.
Food and water contamination in Japan has prompted the government to recommend that locals avoid spinach and other leafy vegetables produced near the plant. At the same time, it’s estimated that an individual would need to consume 3 pounds of contaminated spinach every day for more than a year to approach radiation levels that would be of minor concern. Much of the pollution that has been detected is Iodine-131 (I-131), which has a half-life of just over 8 eight days. That risk will dissipate quickly.
Japanese officials, unlike their counterparts who dealt with Chernobyl, have distributed potassium iodide tablets to individuals at risk of I-131 exposure in an effort to reduce the potential incidence of thyroid cancer.
That’s not to suggest that the meltdown isn’t without health and environmental repercussions. The presence of Cesium-137 is cause for concern. With a half-life of 30 years, Cesium-137 accounts for much of the lingering radiation in the region around Chernobyl. But all indications are that the exposure in this case will be orders of magnitude lower than at Chernobyl.
Again, the goal of this discussion isn’t to downplay the risks but rather to put them into perspective; the crisis at Fukushima was never going to be a second Chernobyl, though the media’s initial reporting on the meltdowns lent that impression.
The worst of the panic appears to be over. Workers have cooled the cores significantly with seawater and refilled spent fuel pools located in the reactor buildings. Radiation levels have retreated from their high, and workers are hooking up the plants to external power sources and repairing cooling systems. The market is beginning to realize its initial panic was overdone: The Nikkei Index has regained more than half of its losses, while shares of uranium miners have rallied a bit from their fear-induced lows.
Investors must focus on three key questions: What the aftermath of the disaster means for the Japanese economy, what it means for nuclear power and the implications for other energy commodities.
Historically, the local economy takes an immediate hit in the wake of a natural disaster. For example, power shortages have forced Japanese factories to scale back output. Ultimately, rebuilding efforts more than offset this initial swoon. To that end, Japan’s political parties have united behind a plan to repair afflicted regions and restore lost capacity. Any near-term economic headwinds should be offset in the back half of the year by the rebuilding effort.
Here’s our take on how events in Japan will affect various energy-related industries.
- The purported boost that alternative energy technologies will receive in a post-Fukushima world has been vastly overplayed. These stocks will still suffer from the same challenges that were in play before the disaster
- The nuclear renaissance should continue to pick up steam, despite the negative press from Fukushima. At this juncture, the world needs nuclear power to meet growing electricity demand worldwide. Events in Japan may prompt some modest delays in the construction of new capacity, but aside from the special case of Germany, the global fleet of nuclear reactors should continue to expand, particularly in energy-hungry emerging markets. Volatility will afflict shares of uranium miners for another one to three months, but some names will emerge as long-term winners. Companies involved in the construction advanced reactors will enjoy additional upside.
- In the near term, natural gas and liquefied natural gas (LNG) producers will receive a welcome bump. Electricity shortfalls from closed nuclear power capacity will force Japan to import more LNG. The same is true of Europe. The overhang of LNG supply from the global recession was already on the wane; these trends will further tighten international LNG markets.
- Producers of thermal coal and oil will also benefit from the need to find substitutes for Japan’s offline nuclear capacity.
The previous issue of The Energy Strategist included a brief explanation of why variable energy sources such as solar and wind power are poor alternatives to coal- and gas-fired plants that provide baseload power.
Less than a week later, in a knee-jerk reaction to the Japanese nuclear accident at Fukushima, shortsighted investors bid up solar and wind power-related stocks on the belief these energy sources would thrive amid a temporary slowdown in the construction of nuclear capacity.
During the weekend after the quake, the Western media was quick to air the views of anti-nuclear activists who regarded the situation at Fukushima as a told-you-so moment. Those who oppose nuclear power took full advantage of their best opportunity to question the safety of atomic energy since the Chernobyl disaster.
At the same time, investors also focused on earlier developments in Germany. Late last year the government announced the temporary shutdown of seven of the country’s 17 nuclear facilities and the suspension of an unpopular plan to extend the operations of these plants by as much as 14 years. Germany is now on track to close all of its nuclear power plants by 2022, replacing atomic energy–which generates almost one-third of the country’s electricity–with renewable energy sources.
Against this backdrop, it’s worth assessing the success of Germany’s alternative energy programs.
The media tends to laud Germany’s focus on renewable energy, while often suggesting that the US and other nation should follow the country’s lead in adopting an aggressive policy to promote “green” energy. But Germany’s policies to promote renewable energy inflict substantial costs on electricity producers, while the move to shutter its nuclear power plants endangers the country’s long-term economic competitiveness.
A story that appeared in the January issue of Bloomberg Markets illustrates these points. This article relayed the experience of Tommy Clever, a 39-year old environmental consultant who lives in Berlin. We’re told that Clever has installed enough solar panels on his home to generate enough power to run his washing machine and other basic appliances–at least on days when the sun is shining. But Clever’s real motivation isn’t self-sufficiency: He receives EUR0.51 (USD0.73) per kilowatt-hour for any electricity he sells to the German electricity grid. That rate is about 10 times the wholesale power cost, but it’s mandated and guaranteed by the German government under the country’s feed-in tariff (FiT) structure.
FiTs are special rates given to any business or individual generating power from renewable energy. New installations of renewable energy capacity lock in these above-average power rates for a period of 20 years. Changes in future FiT rates have no impact on projects that have already been completed and put into service. In other words, regardless of the price of natural gas, oil and coal, Clever and others like him will earn a safe, government-guaranteed return on their investment.
According to Bloomberg Markets reporter Jeremy van Loon, Clever earns an annualized return of around 9 percent on his investment. With yields on traditional safety-first investments such as bank certificates of deposits and high-quality corporate and government bonds near multi-decade lows, a 9 percent government-guaranteed return on your investment is almost too good to be true.
Germany’s generous subsidies have prompted a massive build-out in renewable energy capacity. The country boasts the world’s largest installed base of solar power and the third-largest installed base of wind power, behind the US and China. The growth rate has been nothing short of parabolic.
Source: Energy Information Administration
Germany’s non-hydroelectric power capacity has grown considerably since the country launched the FiT structure in 1991. The current law, known as Erneuerbare-Energien-Gesetz (EEG), or Renewable Energy Act, came into effect in April 2000 and has been revised and renewed a few times since. This inflection point is clearly visible in the graph.
But investors must distinguish between the terms capacity and generation. Capacity refers to the maximum potential output of a given power plant; generation refers to the actual amount of power that a plant produces. Coal-fired and nuclear power plants can operate at close to 100 percent of their rated capacity for prolonged periods, making them excellent sources of baseload power, or capacity that satisfies a country’s continuous energy demand. Baseload generation is typically supplemented by “peaking power,” additional capacity that’s called upon during periods of high demand.
In contrast, solar and wind power generate electricity on an intermittent basis, with output hinging on weather conditions. This precludes these popular renewable energy sources from serving as a replacement for baseload generation, while the unpredictability of solar and wind power also limits their effectiveness as a source of peaking power.
Although the EEG has increased Germany’s wind and solar power capacity, the regime appears far less successful when you consider the proportion of electricity that non-hydroelectric renewable energy sources generate. In 2008 non-hydroelectric renewable energy capacity represented about one-third of Germany’s total capacity but generated less than 12 percent of the nation’s total power. But the inclusion of biomass energy skews this figure. Electricity generated from wind power accounted for 6.5 percent of the country’s energy mix, while solar, tidal and wave power contributed a paltry 0.7 percent.
Nevertheless, some pundits focus on the growth in the percentage of Germany’s electricity that’s generated by wind and solar power, a trend that’s depicted in the graph below.
Source: Energy Information Administration
This sliver of Germany’s power generation has become inordinately expensive. These costs are ultimately passed on to the consumer as an additional tariff on their monthly electricity bills.
The graph below tracks these fees on an annual basis. Note that the figures depicted in this graphic aren’t cumulative, instead representing the annual charge that’s passed along to ratepayers to fund the EEG subsidies. As new renewable power installations are guaranteed high FiT rates for 20 years, these charges would persist even if Germany halted all wind and solar power installations immediately.
Source: German Federal Ministry for the Environment, Nature Conservation and Nuclear Safety, RWE AG
In 2006 German ratepayers forked over about EUR5.81 billion in fees. Despite a weak economy and declining demand for electricity, this charge had jumped to almost EUR10 billion.
FiTs for solar power are higher than for winder power, so much of the uptick in Germany’s renewable energy capacity has focused on photovoltaic panels. Because of this trend, EEG fees are expected to reach EUR21 billion in 2012. A spate of complaints from wind-power operators about the excess of high-cost solar installations has begun to sour the German public’s moods toward renewable energy.
At present, EEG rates are bearable. Taxes and fees account for about 40 percent of the price German consumers pay for electricity, but the EEG fee amounts to about EUR0.0353 per kilowatt-hour (kwh), or 15 percent of the per kwh cost of power to an average German ratepayer. In 2007 EEG fees only amounted to about 5 percent of the costs of power for your average German ratepayer. But check out this table of retail electricity rates in EU countries, the 10 US states with the most expensive rates and the 10 US states with the cheapest rates.
Source: Energy EU
In the Shadows: The Need for Conventional Reserves
But not everyone regards the cost of alternative energy as a deal breaker. Some consumers are willing to accept higher retail electricity prices in exchange for developing renewable energy sources. This argument usually rests on one of two premises: Renewable energy doesn’t need to be imported and doesn’t produce pollution.
Unfortunately, neither argument holds water. Adding renewable energy capacity doesn’t reduce a country’s demand for fossil fuels to the extent that one might imagine. And depending on the power sources they replace, renewable energy capacity can actually increase emissions of carbon dioxide (CO2) and a range of other pollutants.
Integrating renewable energy sources into the electric grid is a challenge, as the inevitable spikes and lulls in solar and wind power generation must be offset with natural gas and other flexible power sources that can be fired up to ensure that the supply of electricity meets demand.
The UK’s and EU’s largest wind power installation, Whitelee Windfarm, comprises 140 wind turbines that stand 70 meters tall (230 feet) and sport wind-turbine blades of 40 meters (130 feet) in diameter. The rated maximum capacity of each wind turbine is 2,300 kilowatts (kw), so the farm’s total installed capacity is 322,000 kw, or 322 megawatts (MW). Located just outside Glasgow, Whitelee Windfarm takes advantage of the same Scottish winds that wreaked havoc with my golf game 17 years ago at the famed Old Course in St. Andrews.
Source: European Wind Energy Association
This map depicts average wind speeds about 50 meters (150 feet) above the ground. The blue-shaded regions on this map offer the best theoretical wind resources; Scotland, including the Whitelee Wind Farm, offers some of Europe’s best wind conditions for generating energy.
The geographic advantages of the Whitelee Windfarm, make it an ideal case for evaluating the practicality of wind power. Let’s start with this graph of the installation’s average load factor, or the ratio of power generation relative to its capacity. For example, a 100 MW plant that produces 75 MW of electricity in a given month would have a 75 percent load factor.
Source: Renewable Energy Foundation
Over the past two years, the highest average monthly load factor observed at Whitelee Windfarm was just shy of 40 percent. In other words, the entire facility produced just about 122 MW on average that month. To put that into perspective, the smallest the smallest coal-fired power plants in the developed world boast a maximum capacity of 400 to 500 MW and can operate at this level as long as the operator keeps feeding them coal.
The power generated at Whitelee Windfarm also varies dramatically depending on the month; in its worst 30-day period, the installation operated at a load factor of 13 percent, generating less than 41 MW of electricity. On a daily basis, these fluctuations are even more pronounced.
Weather patterns also don’t match consumer behavior; for example, Whitelee Windfarm posted its weakest monthly load factor in February 2010, a month where UK power demand ticked up because of the harsh winter. And consumers aren’t likely to reduce their electricity consumption when the wind dies down.
To offset the inherent variability of facilities like Whitelee, utilities install shadow capacity that can feed power to the grid when wind generation fails to meet demand. In the UK, spare capacity would likely consist of natural gas-fired power plants.
The amount of spare capacity required depends on how windy it is outside and the total amount of variable power capacity that’s installed. A small amount of renewable power isn’t difficult to integrate with a modern electricity grid; the peaks and lulls in power output are easy to offset with existing gas-fired plants. However, the greater the percentage of renewable energy capacity, the more of a challenge this become.
Despite the UK’s outstanding wind resources, a 2007 study by the country’s major electricity transmission grid operator, National Grid (NYSE: NGG), didn’t offer much encouragement.
Source: National Grid, Renewable Energy and the Grid: The Challenge of Variability
This table tracks how much power capacity the UK would need under three scenarios: a 2 percent, 5 percent and 20 percent share for wind power in the national generation mix. In all three instances, National Grid assumed that the UK consumes 400 terawatt-hours.
If wind power were to account for 2 percent of electricity generation, the UK would need about 69 gigawatts (GW) of total capacity: 0.5 GW of wind capacity, 59 GW of conventional capacity (nuclear, coal and gas) and about 9.5 GW of shadow capacity. In total, the UK would need 68.5 GW of conventional power for baseload generation and reserve capacity.
If we bump wind power’s contribution up to 5 percent, the 7.5 GW of installed wind power capacity would reduce the need for conventional capacity to about 57 GW. But this expansion to wind power capacity would also necessitate 14.5 GW of reserve capacity, increasing the requisite natural gas-fired plants to 71.5 MW.
If wind power accounted for 20 percent of UK electricity generation, the country would require an additional 30 GW of shadow capacity. To worsen matters, much of this shadow capacity would consist of plants that are less efficient in converting natural gas into power.
In short, wind power increases demand for natural gas-fired shadow capacity and can increase emissions at times.Nuclear Spring or Nuclear Winter?
The shortcomings of wind and solar power serve as a powerful reminder that the alternative energy industry has yet to produce a viable replacement for nuclear energy and other sources of baseload capacity. For those concerned about emissions of sulfur dioxide, nitrous oxide or carbon dioxide, nuclear power is the best option.
Many governments and policymakers recognize renewable energy’s flaws. German Chancellor Angela Merkel, who has sought to address some of the more egregious shortfalls of her country’s energy policy, falls squarely into this camp.
In recent years, German utilities such as RWE (Germany: RWE, OTC: RWEOY) and grid operator E.ON (Germany: EOAN, OTC: EONGY) have warned that the country lacks the shadow capacity to support further growth in wind and solar power. At the current growth rate, this wind and solar power capacity would outstrip existing shadow capacity by mid-decade. Germany’s grid is already rumored to be unstable and to have teetered on the brink of collapse during periods of high demand.
Although Germany’s powerful Green movement dismisses these warnings as the product of greedy utility operators, Merkel acknowledges that these concerns are real. Merkel likely also realizes that as Germany cuts back on public spending to rein in its deficit, rising energy prices or a widespread power outage would hurt German consumers and businesses. Accordingly, the government has amended EEG to reduce the FiT rates for renewable energy projects–especially solar power–on two occasions in 2010. These efforts seek to make the installation of renewable capacity less economically attractive for those only seeking to cash in.
That’s bad news for stocks such as First Solar (NSDQ FSLR) that sell solar panels to Germany and other EU countries. Aggressive investors seeking to hedge substantial exposure to energy stocks should consider selling First Solar short above 110.
Merkel’s government also agreed to extend the operating lives of Germany’s 17 nuclear reactors.
Source: World Nuclear Association
Under the terms of a 2001 agreement, Germany’s 17 nuclear plants–accounting for about one-third of the nation’s power–were due to be shut down and decommissioned by 2022. Germany’s Green Party has been extremely vocal about its long-standing opposition to nuclear power. The Greens owe much of their popularity to the Chernobyl disaster in nearby Ukraine.
Under the terms of the compromise deal reached in late 2010, the German government was prepared to extend the operating lives of all 17 of its plants. For example, the Neckarwesthein-2 reactor due to close in 2022 would operate for an additional 14 years. Such a move would provide utilities with additional time to address near-term reserve capacity issues.
The incident at Fukushima has thrown all of this out of the window. Extending the operations of the nation’s nuclear reactors wasn’t a popular decision, and Merkel faces local elections at the end of March. In response, the chancellor instead has announced the immediate shutdown of the seven German nuclear power plants commissioned before the end of 1980. The announcement eliminates 7 GW of capacity. The shutdown will last for at least three months, and the government has indicated that it’s questionable whether the plants will operate again.
In addition, Merkel’s coalition government has suspended the planned operating extensions for all plants. This turn of events will put additional pressure on the country’s already stressed electric grid. There are few realistic choices for replacing that 7 GW of baseload capacity in the near term, not to mention the loss of 20 GW of capacity over the coming 11 years.
Japan’s nuclear power industry will also be affected. The six reactors at the Fukushima site likely will never be restarted. In addition, the country will shut down almost 10 GW worth of nuclear capacity located in regions hit by the quake. Some of these facilities could also be permanently shuttered if the damage is extensive.
But even if these capacity reductions aren’t permanent, the Japanese will need to subject all quake-impacted reactors to rigorous safety inspections. History suggests that Japan won’t rush to bring these reactors back online.
Source: Energy Information Administration
This graph tracks Japan’s historical electricity generation from nuclear power facilities and conventional thermal power pants. Japan’s three primary sources of thermal capacity are coal, natural gas and petroleum products.
The country temporarily shut down some of its nuclear power capacity in 2002 and 2007 to subject these plants to lengthy safety inspections. As you can see, nuclear power generation dipped in 2002-03 and 2007-08. In both cases, it took at least 24 months for that capacity to be brought back online, and this round of safety inspections likely will be more rigorous.
Also note that when nuclear generation fell in 2002-03, electricity generated by thermal power plants compensated for this shortfall. A similar pattern occurred in 2007-08, when reduced nuclear power capacity led to a 10-year high in thermal plant output.
Beyond Japan and Germany, it’s a bit early to make definitive forecasts about the repercussions of the Fukushima incident on the global nuclear power industry. But fears that developments in Japan will spark a backlash reminiscent to the aftermath of the Chernobyl incident are overblown. In 1986 the world abruptly stopped building new reactors.
Source: Bloomberg
There are a few key differences what transpired in 1986 and today’s environment. First, although nuclear power capacity stopped growing in the mid-1980s, electricity generation from atomic energy continued to rise.
Utilities have become better and more efficient at running plants, allowing them to achieve much higher load factors. In 1990 the average load factor for US plants was just 66 percent; today, the average US reactor operates at a load factor of more than 90 percent. The nation’s 25 most efficient reactors all boast load factors that are greater than 98 percent.
Even as the US has added little to capacity after Three Mile Island and Chernobyl, the amount of electricity generated by nuclear power continued to rise. Part of the reason no new plants were constructed was that it was far cheaper to produce more power from existing plants. But the high load factors mean that the US and other countries can’t add increase generation without constructing new nuclear power plants.
Second, the late 1980s and 1990s marked a period of historically low commodity prices. With oil, natural gas and coal prices all at depressed levels, global utilities could easily generate cheap power without the substantial up-front capital costs and regulatory headaches involved in building a new nuclear facility.
Third, emissions were less of an issue during that period. In the 1990s, electric utilities in developed nations installed scrubbers to address emissions of sulfur dioxide, particulate matter and other pollutants on coal-fired facilities. But CO2 output didn’t a major issue until the mid- to late 1990s. Removing carbon dioxide from coal plant emissions is difficult and expensive; the technology exists, but it’s largely unproven on a commercial scale.
Europe has introduced a plan to reduce CO2 emissions, the US Environmental Protection Agency has threatened to regulate CO2 and China has targets for reducing the carbon intensity of its power industry. Atomic energy remains the only CO2-free source of power generation that can be implemented on a large scale; without maintaining and adding to the global fleet of nuclear reactors, none of these countries is likely to hit these emission-reduction targets.
Finally, emerging markets continue to fuel rapidly growing demand for electricity. Countries such as China and India are desperate to secure a diverse mix of energy resources to support economic development. These nations don’t have the luxury of abandoning nuclear power because of three weeks of dire headlines about Japan’s crippled reactors.
President Obama’s support for nuclear power and decision to expand loan guarantees for new reactors surprised many in his party, particularly. US Energy Secretary Steven Chu also remains a proponent for expanding the country’s nuclear power capacity. This response contrasts with the administration’s aggressive rhetoric BP and oil drilling in the wake of last year’s Macondo spill.
As my friend and colleague Roger Conrad observed last week in Japan’s Nuclear Crisis and America’s Natural Gas, some US nuclear power plants that have been the subject of scrutiny and public opposition for some time. A handful of facilities may come under local political pressure, but that’s more a function of being located in states with a long history of anti-nuclear power sentiment.
Public opinion polls indicate that support has waned in the aftermath of the emergency at the Fukushima nuclear power complex. A Rasmussen Poll conducted on March 17 found that 40 percent of respondents were in favor of nuclear power and 38 percent opposed atomic energy, down from 49 percent support in February 2010, when President Obama announced his proposal to expand loan guarantees for new reactors.
After the past three weeks of media coverage scared some US consumers into buying potassium iodide pills, it’s no surprise that public sentiment toward nuclear power has soured somewhat. But remember that public opinion on deepwater drilling gradually improved as the shock of the spill wore off and energy prices headed higher. .
As I explained at great length in Oiling Up and Going Nuclear, China, India, Russia and other developing markets continue to spearhead the nuclear renaissance. China and India announced that they’ll examine their aggressive build-out plans in light of the disaster in Japan. This is a logical response, but these reevaluations are unlikely to alter the country’s plans–rapidly growing demand for power forecloses that option. Some Chinese officials have already said their commitment to nuclear won’t waver.
Moreover, China’s plans focus on Westinghouse’s AP1000 reactor, a fourth-generation design that includes safety features that would have limited the environmental damage from the second-generation reactor at Fukushima.
The reactor at Fukushima shut down properly in response to the earthquake; however, the failure of the electric grid and the reactor’s back-up generators led to the loss of cooling power and a partial meltdown. Consider this excerpt from Westinghouse’s description of the AP1000 design:
The AP1000™ pressurized water reactor works on the simple concept that, in the event of a design-basis accident (such as a coolant pipe break), the plant is designed to achieve and maintain safe shutdown condition without any operator action and without the need for ac power or pumps. Instead of relying on active components such as diesel generators and pumps, the AP1000 relies on the natural forces of gravity, natural circulation and compressed gases to keep the core and containment from overheating. However, many active components are included in the AP1000, but are designated as non safety-related.
Multiple levels of defense for accident mitigation are provided, resulting in extremely low core-damage probabilities while minimizing occurrences of containment flooding, pressurization and heat-up.
The AP1000 meets the U.S. NRC deterministic-safety and probabilistic-risk criteria with large margins. Results of the Probabilistic Risk Assessment (PRA) show a very low core damage frequency (CDF) that is 1/100 of the CDF of currently operating plants and 1/20 of the maximum CDF deemed acceptable for new, advanced reactor designs.
In other words, if the Fukushima reactors were AP1000s, the plants would have been designed shut down when the earthquake struck and cool down the cores with without external power supply.
If anything, recent events make the case for an aggressive transition away from older reactors, to today’s sophisticated designs, an argument that China will likely advance. The disaster would seem to militate against exclusively running reactors based on designs that are 40 years old.
Investors interested in gaining exposure to this shift toward modern reactors should consider the two companies most intimately involved with the AP1000 design, Toshiba Corp (Japan: 6502, OTC: TOSBF) and Shaw Group (NYSE: SHAW).
Toshiba is the majority owner of Westinghouse, the designer of the AP1000. The stock sold off dramatically in the wake of the Sendai earthquake; the over-the-counter shares tumbled from $6.50 to less than $4 as investors panicked. Although Toshiba Corp isn’t a pure play on nuclear power, the stock should benefit from the AP1000 design’s rising profile and an eventual recovery in the Japanese equity market.
Shaw Group owns 20 percent of Westinghouse and performs engineering and construction work related to the AP 1000 design. In addition, the firm is involved in similar work related to other types of industrial facilities such as gas-fired plants and refineries. Shaw Group stands to benefit both from its exposure to the AP1000 and other Japan reconstruction work.
Both Toshiba Corp and Shaw Group rate a buy in the Energy Watch List for now, though both could graduate to the model Portfolios in time.
Investors interested in playing the overreaction to the nuclear story should also consider Fresh Money Buy list recommendation Cameco Corp (TSX: CCO, NYSE: CCJ), the world’s largest pure-play uranium mining outfit. The previous issue of The Energy Strategist, Oiling Up and Going Nuclear, featured an in-depth discussion of this company and its growth prospects. Buy Cameco Corp up to 42.
Meanwhile, Uranium One (TSX: UUU) and Paladin Energy (ASX: PDN)–two smaller names that entail more risk–remain buys in the Uranium Field Bet. (See Oiling Up and Going Nuclear for additional details.)
Going Liquid
With Japan and Germany likely to suffer capacity shortfalls because of reduced nuclear power generation, both nations will need to ramp up exposure to other sources of electricity. Although Japan will likely renew its commitment to nuclear once it scrutinizes reactors potentially damaged in the earthquake and tsunami, political opposition in Germany may cut nuclear power’s future short.
Even if Germany shutters all of its operating reactors, the country will still receive some electricity generated by nuclear power; the country will likely import more electricity from neighboring France a nation that gets 80 percent of its power from nuclear reactors. Russia is also building 40 nuclear power plants to handle its own domestic electricity needs, freeing the country to export more natural gas to Germany and European nations.
Nonetheless, the biggest winner in the near term is natural gas and, in particular, the market for LNG. Natural gas accounts for about15 percent of Germany’s electricity mix and 26 percent of Japan’s generation portfolio. Both nations have expanded their fleet of gas-fired power plants in recent years.
Germany generates about 46 percent of its power from coal, supported by significant domestic coal supplies. Although the country will fully utilize its coal-fired capacity in the near term–especially as utilities cope with the plan to phase out nuclear reactors–the country’s limits on CO2 emissions and popular opposition to new coal-fired plants limit potential growth. Natural gas-fired plants are the only viable source of baseload power.
In Japan, coal-fired power plants generate about 30 percent of the country’s electricity, while nuclear power chips in 30 percent and petroleum products contribute 10 percent. With much of its nuclear power capacity off-line, Japan needs substitutes. The country’s coal plants already function at almost full capacity, and the nation’s aging oil-fired facilities primarily serve to augment base supply during peak use. Japan will likely lean on these plants to compensate for its reduced nuclear power production. Most analysts expect Japanese oil demand to rise by 100,000 to 200,000 barrels per day once these plants are running.
However, natural gas is the logical longer-term solution. Already the world’s leading LNG importer, Japan has invested heavily in building out its natural gas-fired capacity.
Unlike oil, natural gas continues to trade in regional markets, largely because of transportation constraints. For example, the insular US natural gas market consumes most of its domestic production. But in recent years, US investors have grown increasingly aware of opportunities in international LNG markets.
With all the fervor surrounding the US shale gas revolution–it’s not every day that a country transitions so quickly from a growing importer of natural gas to one with an oversupply–it’s easy to overlook the international implications of this domestic supply glut, particularly on the global market for liquefied natural gas (LNG).
Disconcerted by the breakdown between domestic natural gas prices and drilling activity, North American commentators tend to regard international LNG markets as a potential outlet for production from the continent’s prolific shale gas fields.
What is LNG? When natural gas is cooled to minus 260 degrees Fahrenheit at a liquefaction facility, it condenses into a liquid that’s roughly 1/600th its original size. In this form, large amounts of natural gas can be safely transported overseas in specially designed ships. Re-gasification terminals warm the LNG to return it to its gaseous state before pipelines transmit the product to end users.
This technology is far from a recent innovation; the energy industry has relied on this technology for over 50 years. In fact, the Kenai LNG plant owned by ConocoPhillips (NYSE: COP) and Marathon Oil Corp (NYSE: MRO) has operated since 1969 and remains the sole US export terminal.
Three recently proposed liquefaction terminals have captured the imaginations of many investors.
US-based producers EOG Resources (NYSE: EOG) and Apache Corp (NYSE: APA) are behind the Kitimat LNG joint venture, an export facility sited in Bish Cove, British Columbia that would supply Asian markets with natural gas sourced from the partners’ operations in the Horn River Basin.
In 2009 the duo announced a memorandum of understanding (MOU) with Korea Gas Corp (Seoul: 036460) whereby the world’s largest LNG importer would purchase up to 40 percent of Kitimat’s output. The agreement also included an option for Korea Gas to buy an equity stake in the project.
The initial plan calls for a facility capable of processing 5 million metric tons per annum (mmtpa), though capacity could eventually double in size if warranted. The partnership recently filed with Canada’s National Energy Board for a 20-year permit to export up to 10 mmtpa of LNG per year and expects to bring the facility onstream in 2015.
The two other proposed exports terminals would be built on the US Gulf Coast. In June 2010 Cheniere Energy Partners LP (AMEX: CQP) proposed adding liquefaction capacity to its Sabine Pass LNG receiving terminal in Cameron’s Parish, La. The sourced gas would come from a number of prolific fields in the region, including the Permian Basin and the Barnett, Haynesville, Eagle Ford, Woodford and Bossier Shale plays.
Initially, the company would add two liquefactions trains, each capable of producing 3.5 mmtpa of LNG. In the event of strong demand from customers, Cheniere would consider installing two additional trains. Thus far, executives from independent gas producers Encana Corp (TSX: ECA, NYSE: ECA) and Chesapeake Energy Corp (NYSE: CHK) have voiced their support for the project. Cheniere also recently announced MOUs with Morgan Stanley (NYSE: MS), Spain’s Gas Natural (Madrid: GAS) and ENN Energy (Hong Kong: 2688) for some of the planned export capacity.
On Sept. 7, 2010, the Dept of Energy approved Cheniere’s request to export about 803 billion cubic feet (bcf) of natural gas annually over the next 30 years to nations with which the US has a free trade agreement. This was only the first regulatory hurdle. That same day Cheniere filed a second proposal to export 803 bcf annually to World Trade Organization (WTO) members and non-WTO countries.
On July 26, 2010, Cheniere also initiated the process to gain approval from the Federal Energy Regulatory Commission (FERC) for the siting, construction and operation of its proposed liquefaction facilities.
Freeport LNG and Macquarie Energy, the North American energy trading and marketing arm of Australian financial giant Macquarie Group (ASX: MQG), in late November announced that they would develop export capabilities at the terminal in Brazoria County, Texas. The proposed expansion would cost about USD2 billion and would be able to export 1.4 bcf per day by 2015.
Freeport, the owner and operator of the LNG facility, will submit requests to the Dept of Energy for an export license and to FERC for the project itself.
Meanwhile, some of these facilities have applied for and received a license to re-export gas. That means that volumes of LNG imported can be stored temporarily and then shipped elsewhere. This is a welcome diversification for US LNG terminals, but is a far cry from allowing these terminals to actually export US gas.
No LNG export facilities are likely to be built in the Lower 48 for at last another five years.
Interest in these projects underscores the gradual transition of natural gas from a regional fuel to a (somewhat) global commodity and growing demand in emerging-market Asia. But these proposals aren’t the only international ramifications of the US shale gas revolution; not only has output from unconventional fields flooded the domestic market, but this oversupply also indirectly flooded global markets with excess LNG.
Earlier this decade most analysts projected that US LNG imports would increase steadily, offsetting lower domestic production. Back in 2003 there were at least two dozen proposals to build new re-gasification terminals. But US LNG imports never reached the 812 bcf per year that the Energy Information Administration projected in its Annual Energy Outlook 2004 and have fallen off a cliff after peaking in 2007.
Source: Energy Information Administration
This decline in US imports, coupled with the demand destruction that occurred during the great recession, flooded the market with low-priced LNG. Much of this gas has found its way to European markets such as Spain, Belgium and the UK, which this year became the fourth-largest LNG importer. This influx has prompted some Continental countries to reduce purchases of pipeline gas to the lowest levels allowed by contract, replacing these volumes with lower-priced LNG.
The European gas markets are a different animal. In Germany and many other European countries, utilities sign long-term gas supply contracts with Gazprom (Russia: GAZP, OTC: OGZPY) for access to pipeline gas. These “take-or-pay” contracts feature prices indexed to crude oil prices. European utilities must accept delivery of a contracted volume of gas or pay a penalty; with European gas markets well supplied in recent years, these penalties have grown significantly.
Natural gas prices in many markets have been depressed relative to oil in recent years. But European countries burdened with oil-based, fixed-rate contracts with Russia have paid prices far above the prevailing rate on the spot market. Even worse, with oil prices on the rise, natural gas prices in the contracts could jump to between USD13 and USD15 per million British thermal units (BTU) from USD8 in late 2010. Meanwhile, natural gas continues to hover around $4.50 per million BTUs in the US.
European utilities have lobbied Gazprom hard to amend the pricing structure. To date, the Russian giant has refused most of these requests, with support from the government. These long-term, oil-indexed deals aren’t the only option for European utilities. Germany and other EU countries can also buy gas from producers in the North Sea or import LNG via terminals around Europe. Prices for LNG in Europe are currently above those in the US. UK gas prices are a good proxy for prices for European LNG cargoes, at least directionally.
Source: Bloomberg
This graph depicts the 12-month strip price–the average of the next 12 months of futures prices– for US natural gas that trades on the New York Mercantile Exchange. Currently, US natural gas currently goes for $4.73 per million BTUs, up from about $4.20 at the end of February 2011.
The graph also features the 12-month Intercontinental Exchange strip prices for gas. These prices are quoted in terms of British pence per therm (10 therms = 1 million BTUs). I converted the ICE futures prices to the US standard; current prices are about $11 per million BTUs, compared to $9 per million BTUs at the end of February. This spike in UK gas prices stems from Germany and other European nations relying more heavily on natural gas as a power source.
The global LNG market has been oversupplied for three main reasons. First, the US was expected to become a major importer of LNG, but US shale gas means that the nation should be well-supplied for years to come. Gas that would have gone to the US was dumped into Asian and European markets, overwhelming demand and depressing prices.
Second, over the past few years there has been a surge in new LNG liquefaction projects in the Middle East, Africa and Asia. All that new supply overwhelmed demand and pushed prices down. There’s more LNG supply to come, particularly in Australia, but the rate of supply growth is set to slow markedly in 2011-2013.
Finally, demand was hit hard by the 2007-09 recession both in Europe and Asia. But European demand is bouncing back, and European utilities are increasingly accepting as little gas as possible under their contracts with Russia. Increasingly, these utilities are purchasing volumes on the spot market or importing more LNG. To the extent that Germany’s nuclear shutdowns drives gas demand, the country is likely to favor relatively inexpensive LNG supplies.Even more impressive, rising demand for LNG in–where else–emerging markets has also helped to absorb excess supply and should continue to drive demand over the long term.
For example, the Chinese government’s long-term plans call for natural gas to account for 10 percent of the country’s energy mix, one-third of which will be imported via pipelines or LNG.
Natural gas has been growing in popularity in China, particularly in power-generation facilities located near major cities. Concerns about air quality mean that many of the high-rise residences constructed during China’s recent housing boom are equipped for piped gas. Further migration to urban areas will only increase demand.
LNG imports will be part of the solution. In December 2010 Chinese LNG imports topped 1,000 metric tons, five times their December 2008 level and a new all-time high.
China’s first re-gasification terminal opened in Guangdong province in 2006, and the country currently boasts three import facilities. But that capacity is slated to expand substantially over the next decade. Check out the table below.
Chinese energy companies also continue to invest in projects overseas that will ensure a steady supply of natural gas.
For example, CNOOC (Hong Kong: 0883, NYSE: CEO) on Dec. 8, 2010, agreed to pay AUD50 billion for a 50 percent stake in Exoma Energy’s (ASX: EXE) five exploration blocks in Queensland’s Galilee Basin. Once the deal gains regulatory approval, the resulting coal seam gas will contribute to CNOOC’s LNG supply.
India’s lack of energy resources represents another opportunity for LNG producers, primarily in Australia and Qatar. The country’s Ministry of Petroleum and Natural Gas expects LNG imports to increase from 33 million cubic meters (mcm) per day to 162 mcm per day by fiscal year 2029-30. Over this period the government expects natural gas to grow to 20 percent of India’s energy mix from 9 percent. LNG imports could easily exceed estimates if expected pipeline imports don’t materialize–a distinct possibility–or domestic production falls short of expected production.
Two LNG terminals currently operate in India, Petronet LNG’s (Bombay: 532522) 10 mtpa facility at Dahej and Royal Dutch Shell’s (LSE: RDSA, NYSE: RDS.A) 3.6 mtpa installation at Hazira. Petronet LNG plans to add 2.5 mtpa of additional capacity. Ratnagiri Gas and Power’s 5 mtpa plant in Dabhol remains under construction, though 1mtpa of capacity could come online before the project is completed. Two additional LNG import terminals are in the early stages of planning.
In 2009, Japan imported 85.90 billion cubic meters of LNG, more than twice the level of the world’s second-largest importer, South Korea. Japan produces virtually no gas domestically and imports no gas by pipeline; the nation’s supply depends entirely on LNG imports. Some analysts estimate that the uptick in Japan’s LNG consumption in the wake of the country’s nuclear power disaster will eliminate more than one-quarter of the current supply overhang.
The LNG supply-demand balance was already tightening at the end of 2010, but the Sendai earthquake and Germany’s renewed anti-nuclear push will accelerate this trend. Investors should focus on names with meaningful exposure to international LNG markets.
For safety-first investors, Proven Reserves Portfolio holding Chevron Corp (NYSE: CVX) represents a good all-around play on LNG. Although the stock isn’t a pure-play on LNG by any stretch of the imagination, the company has a number of projects due to come onstream over the next couple of years, including the massive Gorgon LNG project in Australia. In addition, Chevron is one of the only integrated oil companies in the world with a real opportunity to significantly grow its production over the next decade.
We also like Chevron’s plans to shed its underperforming refineries and focus on its core exploration and production business. Chevron rates a buy under 105.
UK-based energy giant BG Group (LSE: BG, OTC: BRGYY) stands to benefit in the near term, as Japan–already one of the world’s leading importers of LNG–seeks to offset nuclear power capacity damaged by the recent earthquake and tsunami. Producers that have the flexibility to divert LNG cargoes from markets with less-remunerative pricing dynamics stand to reap the rewards of a substantial pricing premium, on top of already attractive, oil-indexed prices. In 2010, for example, Japan paid an average of USD11.02 per million British thermal units of natural gas–far higher than the prices paid by countries with ample access to pipeline gas.
During BG’s conference call to discuss its 2010 results and annual strategy update, CFO Ashley Almanza emphasized how the firm’s uncontracted supply enabled it to take advantage of record LNG demand in Japan and South Korea, a product of the economic recovery and favorable weather conditions during the winter and summer months:
Let’s take a look at LNG. During 2010, we saw demand recovery especially in Asia. And this was coupled with good weather-related demand during the course of the year. In these conditions, we are able to use our flexible supply chain and our market knowledge to divert cargos to high value markets. As a result, we posted operating profit of $2.2 billion in our shipping and marketing business.
Although BG doesn’t disclose what percentage of its LNG output hasn’t been sold under contract, in 2010 the company shipped 215 LNG cargoes on the spot market, 55 of which were destined for the US, the market of last resort. The company may remain mum on its uncontracted supply, but last year’s results suggest the company has the scope to allocate additional cargoes to Japan.
Over the longer term, the disaster in Japan and damage to the Fukushima nuclear power complex could impede further expansion of the country’s nuclear capacity, forcing the nation to increase its reliance on imported LNG.
In the wake of any crisis, investors invariably scramble to identify investment opportunities–either names that will benefit from resolving the disaster or names that were oversold in the ensuing panic. Provided that investors remain calm and closely scrutinize these opportunities, an overwrought market furnishes ample opportunity for future profits. For example, investors who purchased stocks leveraged to deepwater exploration and production (E&P) after the Macondo oil spill–a strategy we outlined in Opportunity amid Crisis–enjoyed substantial returns.
But BG’s growth story doesn’t hinge entirely on developments in Japan. BG operates three business segments–LNG, exploration and production (E&P) and transmission and distribution (T&D)–each of which offers exposure to a number of near- and long-term catalysts.
Source: Bloomberg
The firm’s LNG operations, which include liquefaction and re-gasification assets as well as the purchase, shipment, marketing and sale of LNG, accounted for roughly 35 percent of the company’s 2010 revenue. This makes LNG BG’s second-largest operating segment, but we’ll begin our analysis here, as much of the recent scuttlebutt has focused on this business line’s growth prospects.
LNG
BG’s LNG operations and assets span the globe and, in many instances, complement its E&P efforts:
- A 50 percent stake in the Dragon LNG import terminal in Wales, with a 20-year arrangement that will receive up 2.2 million tons per annum (mtpa) of LNG from BG. The company uses this capacity when UK prices are attractive relative to other markets.
- An interest in two 3.6 mtpa liquefaction trains at Idku, Egypt, which BG supplies with natural gas from the West Delta Deep Marine concession. The company also purchases the output from the second train for its flexible LNG portfolio.
- A 14.25 percent ownership in the Olokola LNG project, a 6.3 mtpa liquefaction plant on the southwest coast of Nigeria that’s slated to come onstream in 2012.Three to four years ago, BG also inked a number of long-term supply deals with Nigerian LNG for up to 6.25 mtpa of LNG, supplies
- An ownership stake in Atlantic LNG’s four liquefaction trains in Trinidad & Tobago. Three of these trains are fully integrated operations for BG that include production and liquefaction of natural gas as well as the export of the subsequent LNG.
- A 22-year agreement, signed in 2001, to utilize 100 percent of the capacity at the Lake Charles re-gasification terminal on the US Gulf Coast, securing access to the world’s most liquid gas market. This agreement ensures that any uncontracted LNG volumes that can’t be placed with its international customer base at least can be sold into the US market at prevailing prices.
- A 40 percent stake in GNL Quintero, which owns the 2.5 mtpa LNG import facility on Quintero Bay, Chile. BG has a 21-year agreement to supply 1.7 mtpa of LNG from its portfolio. At peak capacity, the terminal will be able to supply about 40 percent of Chile’s current demand for natural gas.
How do these disparate assets work within BG’s business model? The company’s diversified supply portfolio includes volumes from its equity interests in liquefaction terminals in Egypt and Trinidad & Tobago as well as LNG purchased from third-party producers. (Thus far, the civil unrest in Egypt hasn’t disrupted BG’s natural gas operations. Accounting for 35 percent of Egypt’s natural gas industry, BG is integral to the country’s energy economy; regardless of the political outcome in Egypt, the company’s assets are unlikely to be at risk.) In 2010 12.7 mtpa of the company’s LNG supply was sold under long-term contracts.
BG’s LNG trading and shipping divisions work together to market, sell and deliver LNG volumes to customers worldwide on both a short- and long-term basis. In addition to marketing its own contracted LNG, the firm also buys volumes on regional spot markets and resells this gas to take advantage of regional pricing discrepancies.
Thus far, BG has sold LNG volumes to 40 countries, including inaugural deliveries to Canada, Chile, the Dominican Republic, Kuwait and Portugal in 2009-10. BG has also purchased LNG from 11 of the 18 producing countries. The map below demonstrates the scope of the company’s LNG trading operations.
Source: BG Group
To support these trading activities, the company’s shipping arm boasts a fleet of owned and contracted ships. Last year, the company added four carriers capable of transporting up to 170,000 cubic meters of LNG.
Over the long term, BG’s extensive global operations should enable the firm to benefit from a global LNG market where demand growth outstrips constrained supply. As we mentioned earlier in today’s issue, European markets upped their imports in 2010. Nations such as Spain, Belgium and the UK absorbed much of the LNG supply overhang that persisted after the global recession weakened demand and the ongoing shale gas revolution transformed the US market into an outlet of last resort.
LNG figures to become an increasingly important part of the Continent’s energy mix. Supply constraints, the planned decommissioning of nuclear reactors in Germany and a desire to limit reliance on Russian natural gas should prompt EU nations to build out the necessary cross-border pipeline and support infrastructure.
But the Asia-Pacific region–where long-term, oil-indexed contracts are the norm–represents the most exciting growth opportunity for BG. Management underscored this point during its Feb. 8 conference call to discuss the company’s 2010 results and outlook, noting that the use of oil for heating purposes provides ample opportunity for fuel substitution. High economic growth in Asian emerging markets should continue to drive robust demand among industrial, commercial and residential consumer segments.
Natural gas currently accounts for only 4 percent of China’s energy mix, but BG estimates that an increase of 1 percent in gas penetration adds 25 billion cubic meters per year to Chinese gas demand. That’s equivalent to the total output from four liquefaction trains at BG’s massive Queensland Curtis LNG (QCLNG) Project in Australia. Management also noted that if gas penetration in China were to approach the levels in India–still low by global standards–Chinese gas demand would increase by roughly 150 billion cubic meters per year, or about 1.5 times Qatar’s LNG production capacity. For those wondering about this seemingly obscure comparison, Qatar is the world’s leading producer of LNG.
Although the US experience and a lack of historical precedent has prompted many analysts to err on the side of conservatism when forecasting Chinese LNG demand, Marin Houston, BG’s Executive Director and Executive Vice President and Managing Director of Americas & Global LNG, has a decidedly bold take on what the next 10 years will bring. During the company’s Feb. 8 conference call, Houston stated: “[F]orecasters generally underestimate Chinese demand by a significant margin.” BG expects Chinese LNG demand to increase at a compound annual growth rate of 10.3 percent over the next 10 years, largely based on the rapid growth in contracted volumes announced over the past three years.
Based on this forecast for Chinese LNG demand growth and the likelihood of new markets coming online, global demand will likely eclipse the current consensus projection of 350 mtpa in 2020. At present, only 280 mtpa of liquefaction facilities are in operation or have been sanctioned for construction. With its low-cost supply base and global operations, BG is well-positioned to benefit over the long term from a tightening LNG market.
The QCLNG project will be a big part of BG’s long-term growth story. In its first stage, the facilities will consist of two liquefaction trains that have a total capacity of 8.5 mtpa, though the site will be able to accommodate two additional trains. BG made its final investment decision on the project in October 2010 and has inked long-term supply contracts for roughly 10 mtpa of LNG. Management continues to evaluate the potential of adding a third train to meet demand. The company’s substantial coal-bed methane gas fields will supply the facility.
Cost overruns and delays are always a concern on projects of this scale, particularly with wage inflation in the Australian labor market. Yesterday, BG halted construction on a 540-kilometer pipeline connecting the gas field to the LNG facility because the project failed to meet certain environmental requirements. Management stated that this temporary setback won’t prevent the facility from producing its first LNG volumes in 2014.
Outside of Australia, BG is evaluating the potential to deploy floating liquefaction facilities to capitalize on the estimated 14 trillion cubic feet of natural gas resources discovered in the company’s concessions offshore Brazil. Management indicated that it expects to conclude this analysis at some point in 2011.
BG’s global LNG business will benefit in the short term from an uptick in Japanese demand, but the firm’s efforts to increase its exposure to oil-indexed, Asia-Pacific markets should pay off over the long haul. Management forecasts that once QCLNG comes online, 75 percent of the firm’s LNG sales will be based on oil prices.
E&P
BG’s E&P division includes operations in the UK and Norwegian portions of the North Sea as well as stakes in emerging plays offshore Thailand, India, China and Tanzania. But the crown jewel of the company’s E&P operations are its interests in six blocks offshore Brazil, in the highly prospective Santos Basin.
Source: BG Group
The consortia involved in these blocks have moved quickly from discovery to commercial production. Only four years after discovering the massive Tupi, BG and its partners, Wildcatters Portfolio holding Petrobras (NYSE: PBR A) and Galp Energia (Portfugal: GALP), deployed the first floating production, storage and offloading (FPSO) unit in the field. Capable of producing up to 100,000 barrels of oil per day, this inaugural FPSO will be joined in the Santos Basin by 12 additional units over the coming years. In 2013 Tupi will receive its second FPSO and Guara will receive its first. The following year will bring a second FPSO to Guara and a single FPSO to Cernambi. From 2015 to 2017, BG and its partners will deploy eight additional FPSOs across Tupi, Cernambi, Iara and Carioca. Management estimates that over the next seven years BG’s annual Brazilian production capacity will expand by roughly 300,000 barrels of oil equivalent per day.
Expanding production, coupled with resource upgrades and new discoveries offshore Brazil, should provide plenty of catalysts for BG’s shares over the next few years. In the near term, drilling activity offshore China and Tanzania could provide further upside.
T&D
Without delving into too much detail, BG’s transmission and distribution operations are concentrated in Brazil and India, two emerging markets where demand for natural gas-fired power plants will continue to grow as their economies expand.
With a number of near-term catalysts likely to buoy the stock and exposure to attractive long-term growth trends, BG Group–a new addition to the Wildcatters Portfolio–rates a buy under GBp1,650 on the London Stock Exchange or USD133 in the over-the-counter market.
My favorite yield-oriented play is LNG tanker operator Teekay LNG Partners LP (NYSE: TGP). The company reported fourth-quarter distributable cash flow (DCF) of $39.3 million, up 17 percent from a year ago. The firm also increased its quarterly cash distribution from $0.60 to $0.63 per unit. On average, Teekay LNG has increased its payout at an annualized rate of about 6 percent over the past three years.
Some investors are scared of tanker stocks because of volatile day rates in the spot market, which can vary wildly based on near-term supply and demand conditions. But Teekay LNG’s fleet is booked under long-term contracts at fixed rates that guarantee the firm’s cash flows over time.
Teekay LNG is the world’s third-largest independent operator of these tankers. Although LNG prices are low, Teekay’s business remains steady. The partnership leases carriers to producers on 15- to 20-year deals that serve specific LNG projects. These massive, multibillion-dollar LNG projects continue to go ahead despite low gas prices; the major integrated producers and national oil companies that fund such endeavors are willing to look beyond short-term weakness to long-term growth in demand for the fuel. Regardless of those business dynamics, Teekay LNG collects a fixed fee for leasing the ships it owns.
The MLP also owns a fleet of conventional tankers and liquefied petroleum gas (LPG) carriers that transport propane and other natural gas liquids (NGL). I have written about NGLs on numerous occasions in this publication. By way of review, natural gas is composed primarily of methane, a hydrocarbon consisting of one carbon atom bound to four hydrogen atoms (CH4). But raw natural gas produced from wells isn’t homogenous; methane typically occurs with a variety of heavier hydrocarbons (NGLs) such as ethane (C2H6), propane (C3H8) and butane (C4H10). Crude oil, water vapor, carbon dioxide, nitrogen and sulfur also mix with raw natural gas.
The components of this mélange vary from field to field. Some regions produce dry natural gas, or gas that consists primarily of methane with little NGL content. In contrast, “wet” fields such as the Eagle Ford of Texas and the Marcellus Shale in Appalachia also contain large quantities of NGLs.
NGLs may not receive as much media attention as crude oil or natural gas, but they’re vital energy commodities. Ethane and propane are commonly employed as petrochemical feedstock. Ethane is used to make ethylene, while propane is used to manufacture propylene–chemicals that form the building blocks of various plastics. Oil refineries also use NGLs to boost the octane rating of gasoline.
The beauty of this business is that global demand for NGLs is high and the US has NGLs in large supply thanks to plays like the Eagle Ford. These trends support demand for LPG carriers.
In 2010 Teekay LNG’s DCF covered its distribution a mere 1.03 times; although we prefer a higher margin of distribution coverage, this ratio should improve as new projects come online. Meanwhile, stability of its cash flows makes it unlikely that the firm’s payout is at risk.
Teekay LNG historically has grown through acquisitions. Last year the MLP purchased three vessels from its parent and general partner, Teekay Corp (NYSE: TK), for $160 million. The firm’s most recent acquisition was a 50 percent interest in two LNG carriers that are booked under long-term charter contracts. One of these tankers also has the ability to re-gasify liquefied natural gas. This vessel would allow a country without fixed LNG import capacity to import gas for injection into its pipeline network.
In 2011 Teekay LNG will receive an additional LPG carrier and two carriers capable of carrying both LNG and LPG. All of these ships are currently contracted under 15-year agreements that begin once they arrive from the shipyard.
In February, the company was offered a deal to buy a one-third interest in four LNG carriers that would be delivered to Teekay Corp in late 2011 and early 2012. These carriers are all scheduled to be leased under a long-term charter to serve an LNG project in Angola. The MLP is expected to announce more details in its first-quarter conference call.
As demand for LNG rises globally, Teekay LNG should have more opportunities to acquire or build tankers and lease those ships under long-term contracts at generous day-rates. And Teekay recently entered the business for floating storage and re-gasification units (FSRU). FSRUs are LNG tankers than can accept volumes from other ships re-gasify the LNG and inject it into a company’s pipeline network. FSRUs replace fixed onshore LNG import terminals.
If countries such as Japan and Germany up their LNG import, Teekay’s FSRU units could provide a convenient, mobile alternative to cost-prohibitive onshore terminals.
Shares of Teekay LNG have appreciated because of the company’s exposure to attractive end markets and the potential for further distribution growth. Teekay LNG Partners LP now rates a buy under 41.
We last reviewed compressor manufacturer Dresser-Rand (NYSE: DRC) in the Dec. 1, 2010 issue, 10 Takeover Picks for 2011. Although the stock has gained roughly 35 percent in the interim, the company remains a potential acquisition target.
Energy companies account for 90 percent of Dresser-Rand’s sales; its compressors are used in virtually every aspect of oil and gas production, refining and transmission. The company’s compressors also feature prominently in the liquefaction terminals that transform natural gas into LNG. Although the LNG end market represents a small portion of the company’s overall revenue, this segment should continue to grow.
The refining industry accounts for about one-third of Dresser-Rand’s total sales. Refiners can earn higher profits by processing cheaper heavy, sour grades of crude into gasoline and diesel. (See the March 8, 2011 issue of The Energy Strategist Weekly, Energy Investing: Strong Prospects for Petroleum Refining.) refining such grades of crude requires more advanced equipment, including more powerful compressors.
As for growth opportunities, Dresser-Rand is developing a floating liquefaction business as part of a strategic relationship with Samsung Heavy Industries (South Korea: 010150) and Samsung Techwin (South Korea: 012450). Floating liquefaction facilities would allow companies to produce gas from smaller, more remote fields and liquefy that gas without building a massive onshore LNH export facility. A floating LNG terminal may also be one way for US gas producers to export more of their gas to gas-hungry foreign markets as LNG.
Dresser-Rand has also recently announced the acquisition of Guascor Group, a Spanish manufacturer of specialized diesel engines used in the energy business. It’s a logical fit for Dresser, and management expects the deal to be immediately accretive to earnings. Buy Dresser-Rand under 55.
The stocks recommended in the three model Portfolios represent my favorite picks. The three Portfolios are designed to target different levels of risk: Proven Reserves is the most conservative the Wildcatters names entail a bit more volatility; and Gushers are the riskier plays but have the most potential upside.
I realize that this long list of stocks can be confusing; subscribers often ask what they should buy now or where they should start. To answer that question, I’ve compiled a list of 18 Fresh Money Buys that includes 16 names and two hedges.
I’ve classified each recommendation by risk level–high, low or moderate–and included a brief rationale for buying each stock. Conservative investors should focus the majority of their assets in low- and moderate-risk plays, while aggressive investors should layer in exposure to my riskier and higher-potential plays. Hedges are appropriate for investors looking to offset exposure to energy stocks.
Also note that stocks that exceed my buy target for more than two consecutive issues will either be removed from the list or the buy target will be increased.
Source: The Energy Strategist
This issue has focused on the implications of the emergency at the Fukushima nuclear power complex for the renewable and atomic energy industries, as well as firms with exposure to international LNG markets. Two other industries also stand to benefit: oil and coal producers.
With Japan likely to increase output from its aging oil-fired power plants in the near term, this should boost global oil demand slightly. Meanwhile, the slow-motion civil war in Libya continues to keep almost 1.5 million barrels per day of oil production from the market. Forces loyal to Qaddafi no longer have the upper hand after the allied bombing campaign, while opposition fighters don’t appear capable of routing their opponents. Oil-levered stocks should do well as long as this stalemate persists.
Against this backdrop, here are updated prices for some of my top picks in the Fresh Money Buys Portfolio:
- Oil sands producer Suncor Energy (TSX, NYSE: SU) is now a buy under 48;
- Deepwater equipment giant Cameron International Corp (NYSE: CAM) rates a buy under 60;
- Seismic services firm Petroleum Geo-Services (OTC: PGSVY), a huge beneficiary of a surging spending on exploration, is now a buy under USD17.50; and
- Core testing service Core Laboratories (NYSE: CLB) rates a buy under 105.
Finally, coal accounts for about half the world’s electricity generation and about 80 percent in China and 70 percent in India. It’s dirty and often maligned, but it’s real baseload generation and doesn’t have the inherent grid integration drawbacks of solar and wind power.
Ironically, environmental groups trying to force countries like Germany to shut down nuclear power are inadvertently guaranteeing those same nations will use ever-larger quantities of coal. Coal prices were already on the rise before Fukushima because of the supply disruptions caused by flooding in Australia and rising demand. This latest incident has super-charged the upside.
To reflect these bullish developments, Peabody Energy Corp (NYSE: BTU) now rates a buy up to 72.50 and in International Coal (NYSE: ICO) to 11.
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