ODAC Newsletter - 10 April 2009
Welcome to the ODAC Newsletter, a weekly roundup from the Oil Depletion Analysis Centre, the UK registered charity dedicated to raising awareness of peak oil.
These days any news that is not-as-bad-as-expected counts as good news. On this basis, oil prices jumped back up above $50/barrel on Thursday following reports from the EIA that US oil stockpiles had only increased by 1.65 million barrels rather than the 6.94 million reported by the American Petroleum Institute the previous day.
With the oil price roughly half the average price in 2008, the oil majors are now beginning to squeeze oilfield service companies, demanding lower prices and cutting back on investment. The global rig count is now at its lowest since April 2006, and this slump in activity threatens to worsen the likely price spike whenever demand growth returns.
The outlook for renewables investment is just as alarming, despite much talk of a new green era. According to New Energy Finance, global funding for renewables in the first quarter of 2009 was down 53% against Q1 2008. The British Wind Energy Association said this week that without government support 2020 renewables targets will not be met. The industry has been hit by a triple-whammy of tight finance, falling energy prices and rising component costs because of the weak pound.
While the UK is struggling to meet its renewable targets and to fill the looming power gap, there are already plans afoot for new uses of electricity. Both Gordon Brown and Boris Johnson this week announced their intentions to lead the UK in an electric car revolution. Here at last is a policy which can be sold as ‘green’ without fear of losing a significant numbers of votes. Whether it can make a significant difference in time for either peak oil or climate change however is another matter.
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Crude oil rose for a second day after a government report showed a smaller gain in U.S. inventories than the industry indicated a day earlier.
Supplies increased by 1.65 million barrels to 361.1 million last week, the highest since July 1993, the Energy Department said yesterday. The industry-funded American Petroleum Institute said April 7 stockpiles jumped by 6.94 million barrels to the highest since 1990. The two reports have moved in the same direction 75 percent of the time over the last four years.
“The fact that the Energy Department did not show as big a stock build made the market stronger,” said Christopher Bellew, senior broker at Bache Commodities in London. “Buyers had waited for the data expecting lower prices, and once it came out, people were suddenly buying at the same time.”
Crude oil for May delivery rose as much as $2.08, or 4.2 percent, to $51.46 a barrel on the New York Mercantile Exchange. It was at $51.11 a barrel at 9:45 a.m. in London. Prices are up 15 percent this year.
“We should continue to see this push-pull between the reality of weak demand and high inventories, and the hope that things are getting better,” said Anthony Nunan, an assistant general manager for risk management at Mitsubishi Corp. in Tokyo. The unexpected decline in distillate fuels also helped prices, he said.
Distillates, a category that includes heating oil and diesel, fell 3.35 million barrels to 140.8 million, according to the Energy Department. Gasoline stockpiles rose 656,000 barrels to 217.4 million in the week ended April 3.
Total daily fuel demand averaged over the past four weeks was 18.9 million barrels, down 4.4 percent from a year earlier, the report showed. It was the lowest consumption for a four-week period since October.
Global oil demand falls to an annual low during the second quarter as refineries close to perform maintenance after winter in the Northern Hemisphere.
Stockpiles at Cushing, Oklahoma, where New York-traded West Texas Intermediate crude oil is delivered, fell 878,000 barrels to 29.98 million last week, the lowest since the week ended Dec. 26. Supplies in the week ended Feb. 6 were the highest since at least April 2004, when the Energy Department began keeping records for the location.
The Cushing supplies are still above their average of 20.5 million barrels over the past five years. The excess in inventories has weighed on the May Nymex oil contract, which trades at a discount to the June future, a situation known as contango. The difference between the two is now at $2.48 a barrel, up from 69 cents a barrel a month ago.
Brent crude oil for May settlement rose as much as $1.89, or 3.7 percent, to $53.48 a barrel on London’s ICE Futures Europe exchange.
Brent is now trading at a premium of more than $2 a barrel to the West Texas Intermediate contract in New York, swinging from a discount of 43 cents on March 31.
“It makes sense that Brent is strengthening above WTI,” Mitsubishi’s Nunan said. “The U.S. is terrible right now. The overall demand is down and crude inventories are way too high.”
BP Plc, Total SA and Royal Dutch Shell Plc are asking oilfield service companies to cut project costs by up to 40 percent as the industry battles its worst slump since the mid-1970s.
Executives at contractors including Technip SA, CGGVeritas and Saipem SpA said Europe’s biggest oil companies are pressing for discounts. In response, they say they reduced the number of drilling rigs in operation by more than 25 percent and next will take oilfield vessels out of service, threatening jobs.
Projects in the Canadian oil sands, where reserves are hard to access, and marginal shallow-water fields are being trimmed, slashing the world drilling-rig total to a three-year low. The 64 percent plunge in oil from its July peak to close to $50 a barrel is deterring new investment and leaves the services industry, worth more than $60 billion, vulnerable as the order backlog shrinks.
“The pressure is much higher” than last year to make cuts, Thierry Pilenko, chief executive officer of Technip, Europe’s second-largest oilfield services provider, said in an interview at a Paris oil conference last week. “Total are talking about 20 percent, BP are talking about 40 percent, going back to the cost environment of 2004. That is much more difficult.”
The global rig count fell for five straight months, declining 7.4 percent in February to the lowest since April 2006, according to data published by Baker Hughes Inc. Operating rigs decreased 28 percent from 3,557 in September, the biggest drop since the last recession in 2001 and 2002.
“We have some oil companies asking for renegotiation of existing contracts,” said Thierry Le Roux, chief operating officer of CGGVeritas, the world’s biggest seismic surveyor, in an interview. “Total is very vocal about it, and BP is very pushy.”
Oil service companies supply rigs, design production vessels, lay pipes and build refineries. Seismic surveyors such as Paris-based CGGVeritas gather and sell data about possible petroleum reservoirs under the sea floor in areas like the Gulf of Mexico, the North Sea and Brazil.
The market for engineering, construction and offshore oilfield equipment rose 22 percent last year, according to the French Institute of Petroleum, while the market for seismic services rose 10 percent. That contributed to cost inflation.
The CEOs of Shell, BP and Petroleo Brasileiro SA have all indicated tougher times lie ahead for contractors. Petrobras CEO Jose Sergio Gabrielli said in February he doesn’t want to “kill our suppliers, but we plan to squeeze them a lot.” Jeroen van der Veer, Shell’s CEO, and Tony Hayward, BP’s CEO, have both said they aim to cut project costs.
Total is renegotiating with contractors to drive down pricing and maintain upstream investments, Yves-Louis Darricarrere, the French company’s head of exploration and production, said April 2. “Costs will as a rule come down,” he told the International Oil Summit in Paris.
Total spokeswoman Phenelope Semavoine said reducing expenditure on projects is a priority and declined to give a specific target.
“We have conversations with contractors to explain that since the oil price has dropped by $100 since last year, then we would expect to see that reflected in contractors’ costs,” said Robert Wine, a London-based spokesman at BP.
“I never thought construction costs would go up by a factor of two within four years,” Shell’s Van der Veer said April 2, adding that “if they come down, it is good news as well.” Shell’s press department in The Hague declined to comment further.
Repsol YPF SA Chief Operating Officer Miguel Martinez said last week Spain’s largest oil company is renegotiating existing contracts to cut costs by 5 percent, and aims to trim 10 percent on future agreements.
“It’s the same signal from all of them,” said Gudmund Halle Isfeldt, an Oslo-based analyst at DnB NOR ASA. “If the suppliers are listening to the signals, then they will renegotiate and reduce the costs.”
Technip gained 29 percent in Paris trading this year, making it the seventh-best performer of the 40-company Dow Jones Stoxx Oil & Gas Index, after losing 60 percent last year. Saipem gained 18 percent, rebounding from a 57 percent plunge in 2008.
Paul Andriessen, an analyst at Fortis Bank in Amsterdam, said pricing pressure will need as much as 18 months to take full effect, adding oil companies are unlikely to achieve all the savings they seek, since the supply of services is declining while demand remains.
Technip forecast in February that sales this year would be 6.1 billion euros to 6.4 billion euros ($8.2 billion to $8.6 billion) at current exchange rates, down from 7.5 billion euros last year. It also predicted there wouldn’t be any “very large” subsea contracts this year, while there would be several large downstream contracts in the Middle East.
Fourth-quarter 2008 sales of Paris-based Technip fell to 1.9 billion euros from 2.1 billion euros, while orders shrank to 1.2 billion euros from 2.1 billion euros.
Saipem, Europe’s biggest oil services company by market value, has been bolstered by a record order backlog of 19.1 billion euros at the end of last year, following a 20 percent increase in sales for 2008 to 2.83 billion euros. That’s still not enough to insulate the Milan-based company.
“We have also some pressure from our clients to reduce costs, and I think there is room for efficiency improvements,” Saipem CEO Pietro Franco Tali said in an interview.
Tali said lower procurement costs on items such as steel could be passed along to clients without hurting margins, and he doesn’t expect a “dramatic” impact. “In terms of prices, we will be able to negotiate with our clients,” he said.
Cost-cutting by European companies is part of a global trend. Schlumberger Ltd., based in Houston and the world’s largest oil-services provider, posted a 17 percent fourth- quarter profit drop in January as exploration spending decreased. Halliburton Co., the second-biggest service provider, in January said pricing pressure will continue this year while Baker Hughes said the outlook for 2009 has “continued to deteriorate.”
That pressure is being passed down the chain.
“We’re doing to our supply base what our customers are doing to us, which is to drive cost out of the system,” Tim Probert, executive vice president for strategy and corporate development at Houston-based Halliburton, told the Paris conference. “We expect a lower-cost supply chain will give us significant benefits in 2009 and 2010. There have been some redundancies, particularly in North America.”
The credit crunch will keep U.S. oil and gas producers from ramping up exploration they do through drillers such as Nabors Industries Ltd., setting the stage for shortages and surging prices when demand recovers.
Chesapeake Energy Corp. and Carrizo Oil & Gas Inc. are among producers spending no more than their cash flow after a collapse in credit markets drove up debt costs. That means they won’t hire the likes of Nabors and Rowan Cos. to drill more wells in anticipation of higher prices. Producers cut capital budgets 17 percent this year after demand slowed and prices plunged, according to Tristone Capital Inc.
“Quite frankly, they don’t have the credit, which exacerbates the problem that their revenue stream is far below the cost structure,” said Jud Bailey, an analyst at Jefferies & Co. in Houston. “They’re not jumping on lower service costs simply because they can’t. They’re literally stepping away from anything they’re not contractually obligated to.”
The result may be a “slingshot” effect as spending cuts leave a supply shortage once demand returns, Bailey said. The number of active drilling rigs worldwide has fallen 35 percent from the 23-year high reached in September, according to Baker Hughes Inc. The U.S. rig count has plunged by almost half.
Houston-based Rowan, a drilling contractor that also builds rigs, said clients are delaying or canceling projects as they wait for service costs to follow oil and natural-gas prices lower. “Our customers are being quite vocal about wanting to reset their costs of operations in this currently low commodity- price environment,” Chief Executive Officer Matt Ralls told investors on a Feb. 26 conference call.
Rowan has lost 70 percent of its market value in the past year. Nabors, based in Bermuda and run from offices in Houston, has tumbled 68 percent. Most of Rowan’s rigs drill on land or in waters less than 1,000 feet (305 meters) deep.
Nabors, the world’s largest onshore oil and gas driller, expects “substantially lower” earnings from land-based rigs through the first half of this year, CEO Gene Isenberg said in a Feb. 25 statement. Of the 273 onshore rigs Nabors had working in the U.S. in October, more than 150 are now sitting idle.
Drilling originally stalled after a collapse in oil and gas prices from last year’s historic highs, said Dennis Smith, corporate development director at Nabors. U.S. crude-oil futures are down almost $100 a barrel from the record set in July.
“The credit crunch might exacerbate it to some extent, especially the smaller guys that have no access to capital now from the conventional debt markets,” Smith said. “Generally people that are investment grade are still able to borrow, but they’re just being very prudent because nobody knows for sure where their cash flow is going to be.”
Deepwater drillers such as Transocean Inc. and Noble Corp. have fared better as producers go forward with large projects under contracts committing them to pay rig rents of more than $500,000 a day in some cases.
The credit crunch sets the current drilling slump apart from the slowdowns of 1997-1998 and 2001-2002, said James Wicklund, chief investment officer at Carlson Capital LP in Dallas. Exploration and production companies have more to consider than waiting for costs to come down, he said.
“The problem is instead of just waiting them out, they don’t have the credit markets to rely on this time to re- accelerate their drilling,” Wicklund said. “Before it was like, ‘OK, I’m going to wait until you drop prices by 20 percent, then I’m going to swoop.’ This time, the E&P companies have to live within cash flow.”
Houston-based Noble Energy Inc. is one of those producers looking for service costs to drop before resuming some projects. Chief Executive Officer Charles Davidson said he also needs to avoid contributing to a U.S. gas glut.
Borrowed to Grow
“It’s probably not the best time to be accelerating gas production,” Davidson said in a March 23 interview.
Just about all producers will be affected by the lack of available credit, regardless of how much debt they hold, said Subash Chandra, an analyst at Jefferies & Co. in New York.
“You’ll find over the last several years, pretty much everyone has borrowed to grow,” Chandra said. “Our industry on average has spent 130 percent of cash flow for a couple years in a row now. It’s kind of standard procedure.”
Schlumberger Ltd., the world’s biggest oilfield contractor, said a more prolonged slowdown in exploration and production spending will mean sharper price gains when the slump ends.
“The longer the period of lower spending, the more dramatic the falloff in production capacity will be and the steeper the recovery in oil prices once demand recovers,” CEO Andrew Gould said March 23 at a conference in New Orleans.
Oil Seen Rising
Larry Dickerson, CEO at Houston-based Diamond Offshore Drilling Inc., said he thinks global economic growth will be “substantial” coming out of the financial crisis, partly because of the industrialization of China and India.
“I think all the factors are certainly there to look at higher demand, and that’s going to be reflected in the price of oil,” Dickerson said in an interview.
Jen Snyder, head of North American gas research at consulting firm Wood Mackenzie Ltd., said she expects gas demand to recover at a slower pace than the economy because of new coal-fueled power plants opening in 2010 and 2011.
Even as service costs come down, making more projects look profitable on paper, some producers are too starved for cash or credit to ramp up drilling, said Wicklund of Carlson Capital.
“This is like all of a sudden, the price of Porsches has come down, but you lost your job,” Wicklund said. “It’s like, ‘Oh, well that’s great that service or Porsche costs have come down, but I still can’t afford it.’”
Ed Crooks, energy editor, examined the controversial idea put forward by Professor James Hamilton of the University of California, San Diego, that the US recession was caused by the oil shock of 2007-08.
Prof Hamilton says it is "a conclusion that I don't fully believe myself".
But his work ( http://bit.ly/EG3pj) raises the important question of whether the role of oil in the US and global downturn has been underestimated.
It also deals a blow to the comforting idea, promulgated by the International Monetary Fund among others, that the demand-led oil price rise of the 2000s would be more economically benign than the supply-led shocks of 1973 and 1979.
Of course, there were many other problems in the US economy last year - not least the housing crash. But house prices started to fall in 2006 and the economy continued to grow. In Prof Hamilton's model, if the oil price was taken out of the equation, the economy would have grown throughout last year.
His paper argues: "The evidence to me is persuasive that, had there been no oil shock, we would have described the US economy in fourth-quarter 2007 to third-quarter 2008 as growing slowly, but not in a recession."
Other economic models do not come up with such a powerful role for oil. But, given the central importance of events such as the steep fall in vehicle sales, the general slowdown in consumer spending and the plunge in consumer sentiment in the first half of 2008 - all of which are strongly influenced by petrol prices - it does not seem implausible to think that the cost of oil was a critical factor in the downturn.
However, in case anyone was tempted to think of the oil price as yesterday's problem, Prof Hamilton has a warning for the future.
"Some degree of significant oil price appreciation during 2007-08 was an inevitable consequence of booming demand and stagnant production . . . If growth in the newly industrialised countries resumes at its former pace, it would not be too many more years before we find ourselves back in the kind of calculus that was the driving factor behind the problem in the first place."
Last autumn's sudden collapse in commodity prices left a lot of China bulls with egg on their faces. Didn't China's insatiable demand for stuff, driven by a long-term process of urbanisation and rising incomes, guarantee the good times would roll for another two or three decades?
For the past seven years, commodity prices were essentially considered a simple function of Chinese demand. As the world's top consumer of commodities, China was thanked (and blamed) for heralding a new era of inflated raw material prices. After the commodities crash, this theory appears in tatters.
Indeed, over the next two or three years China is likely to play only a small role in setting global commodity prices: even if Chinese demand recovers, markets will be overwhelmed by shrivelling demand everywhere else.
But after the rest of the world stabilises and excess production capacity is absorbed - somewhere between 2010 and 2013 - China will again emerge as the key driver of global demand. Assuming that Beijing maintains economic and social stability, the pace and scale of industrial and urban development in China should drag up commodity prices.
The pace of urbanisation in China is unprecedented. In 1980 a paltry 20 per cent of Chinese citizens lived in urban areas, a figure associated with the poorest countries on earth. By 2030, when more than 1bn Chinese citizens will live in towns and cities, that figure will reach 70 per cent - higher than in Japan or Italy today.
As China's growth and urbanisation continues for another couple of decades, Chinese demand for commodities will rise substantially - especially hard commodities used for building houses and roads.
China has only just reached the most commodity-intensive stage of urbanisation, with metal intensity four times higher than in developed countries and twice as high as in other developing countries, according to the World Bank.
Global commodity markets have tanked and Chinese demand has stuttered. But the hungry dragon is not yet sated - he's just pausing between courses.
Canadian environmental groups on Wednesday accused Royal Dutch Shell, Europe’s biggest energy group, of reneging on its promise to reduce greenhouse gas emissions at its oil sands project in Alberta.
Pembina and EcoJustice said the company had won approval in 2004 and 2006 to extend its Athabasca oil sands project by promising to reduce emissions. Pembina yesterday presented the Alberta Energy Resources Conservation Board and government of Canada with a sworn affidavit stating Shell had set its Canadian oil projects the goal of becoming “less carbon dioxide-intensive than the most likely alternative, which is imported crude”.
Pembina said Shell had yet to set precise targets as to how it would achieve this. The environmental group estimated Shell’s promise was the equivalent of pledging to cut greenhouse gas emissions by 900,000 tonnes, or of taking 200,000 cars off the road.
Simon Dyer, Pembina’s oil sands director, said Canadian regulators would not have approved Shell’s Jackpine mine and Muskeg River mine expansion – a 100,000 barrel-a-day project – had it not made that promise. “The approvals are no longer valid given [that] Shell got them on the [understanding] these commitments would be followed through on.”
Shell has begun work but is not yet producing bitumen.
John Abbott, Shell Canada’s executive vice-president, said Shell had taken early voluntary action, making its ventures the least greenhouse gas intense of all mineable oil sands projects.
He indicated Shell was shifting from voluntary targets. “Alberta’s current regulations and the emerging Canadian policies recognise that the need to reduce emissions is too important to rely on voluntary commitments and, along with the rest of the industry, we are now focused on meeting these new regulatory targets.”
Pembina’s accusation not only risks a delay at Shell’s Athabasca oil sands projects but also another setback to its environmental credentials. Last month it pulled out of investing in solar and wind energy.
You could, perhaps, call it the "military-ecological complex". For the world's most powerful armies are going green, trying to kickstart an environmental-technological revolution in civvy street in the process. Nearly half a century after the outgoing US president, former general Dwight Eisenhower, warned that a proliferating "military-industrial complex" threatened to drive the world towards destruction, defence establishments are beginning to try to help to save it instead. And they have found that green initiatives can preserve lives on the battlefield too.
The Pentagon – which gave the world the gas-guzzling, 68 ton M1 Abrams tank, which does just over half a mile to the gallon – is leading the charge. But Britain's own Ministry of Defence, responsible for 70 per cent of all the government's carbon dioxide emissions, is not far behind. And the prestigious Royal United Services Institute is to hold a conference this year on what other Nato countries are doing.
The US military – the country's largest single energy consumer – has embarked on a drive to save fuel, and thus lives. Half of its wartime casualties are sustained by convoys, which are mostly carrying fuel and are a favoured target for enemies. It estimates that every 1 per cent of fuel saved means 6,444 soldiers do not have to travel in a vulnerable convoy.
One simple innovation – insulating tents in Iraq and Afghanistan with a layer of hard foam, reducing the need to heat and cool them – has saved 100,000 gallons of fuel a day. The Pentagon aims to get a quarter of its energy from renewable sources by 2025. It is to buy 4,000 electric cars (the world's largest single order) for use on its bases, and is developing hybrid armoured vehicles for the battlefield.
It has saved fuel by cutting the weight of aircraft – removing floor mats, redundant tools, loading thick manuals on to laptops, and using lighter paint – and within seven years plans to fly them on a 50/50 blend of ordinary fuel and biofuel, probably made from algae.
Five weeksago the MoD identified "reducing dependency on fossil fuels" as a main object of its research. It has already reduced carbon dioxide emissions from its buildings by 10 per cent this decade. All RAF planes, apart from the Battle of Britain Memorial flight and a few training aircraft, have been certified to fly entirely on biofuels, when they are available, and researchers are looking into solar-powered unmanned attack aircraft.
Scientists hope that the massive spending power of the military will spin off environmental technologies into civilian life, as jet engines, microchips, and global positioning systems did in the past. "We can be a test bed for a lot of things that normally would not seem to make powerful economic sense," said the US Assistant Army Secretary, Keith Eastin.
The people of Milford Haven are accustomed to big ships. Oil tankers have been shuttling in and out of this harbour on the Welsh coast since the 1960s, when Esso built the first of several refineries that have made it a hub of Britain’s oil industry.
So the crew of the supertanker from Qatar that docked here two weeks ago could be forgiven for thinking their arrival would pass without fuss. It didn’t. The 315-metre Tembek was greeted by the wail of sirens sounded by protesters worried about its explosive cargo. Before it docked, several thousand leaflets had been posted to nearby homes giving instructions on what to do in case of an accident with the ship’s contents.
Instead of oil, the Tembek was loaded with gas, super-chilled to liquid form and enough to heat all the UK’s 26m homes for eight hours. It was the first shipment of liquefied natural gas (LNG) to arrive at a new terminal in Wales. The $2 billion (£1.35 billion) facility, called South Hook, was specially built at Milford Haven to receive supertankers and turn their liquid cargo back into gas onshore before pumping it into the national gas network.
For supporters it was a momentous occasion, the culmination of a seven-year, £13 billion project to open a vital new supply line bringing gas from the Gulf into British homes. At full pelt, two shipments will arrive every week, providing up to a fifth of the UK’s gas.
But South Hook, the biggest LNG terminal in Europe, clearly means different things to different people. Conceived by Qatar’s state gas company Qatar Gas, it is just one part of a hugely ambitious programme to convert the tiny emirate into the primary gas supplier to the world. For the British government, it lies at the heart of its efforts to reshape our gas supplies to counteract the depletion of North Sea fields. The Queen will christen South Hook at a ceremony with the Qatari ruler next month.
For detractors, it is a disaster waiting to happen. Safe Haven, a local pressure group, has fought the building of South Hook every step of the way. It warns that an accident with the Tembek, or other LNG tankers, could release an explosive cloud of gas and devastate the town of 13,000.
Ted Sangster, chief executive of the Milford Haven Port Authority, dismisses such claims saying they “verge on the irresponsible”.
“As the manager of the port we have undertaken risk assessments, scenario-testing and planning to define the way in which we handle these ships. We have given 137 presentations to the public and interest groups,” he said. “We are the biggest port for tankers carrying oil and gas products in Britain. It’s safe.”
What is certain is that nobody has ever attempted anything on this scale before. The North field off Qatar’s coast is the single largest gas reservoir in the world. Onshore, at the sprawling Ras Laffan petrochem-ical complex that it feeds, more than 28,000 workers are building four huge new LNG processing facilities, known as “trains”.
One, called Qatar Gas 2, which will be officially commissioned today by the emir, will produce the gas for Wales. Nearly a kilometre long, the Qatar Gas 2 train is a complex chain of industrial plants, including an electricity plant capable of powering a small city. It runs a series of proces-sors to purify, dry and compress gas that enters the system impure and hot and exits as a clean, ultra-cold liquid that is then put on ships.
Qatar Gas 2, which is backed by Exxon Mobil and Total, cost $13.2 billion. Three other trains, which rely on other big oil partners such as Royal Dutch Shell and Conoco Phillips, are also nearing completion. Temporary cities have been set up in the desert for the thousands of labourers, transported to and from the site by more than 250 buses.
Then there are the ships. Depending on the gas price, shipping gas halfway round the world can be economically questionable. Nonethe-less, Qatar Gas designed two new tankers, the larger of which, the Q-Max, is 80% bigger than a traditional LNG tanker and costs $285m. The Q-Flex, such as the Tembek, is slightly smaller but can be accepted at more ports. Qatar Gas has ordered 45 ships, built in Korea, to cart Ras Laffan gas around the world – 14 of them are set aside for South Hook. Its sister company, Ras Gas, has ordered a similar number.
By the end of next year, when all the new “mega-trains” are up and running, Qatar, already the world’s biggest LNG exporter, will have doubled its annual capacity to 77m tonnes. Even at that rate, Faisal Al-Suwaidi, chief executive of Qatar Gas, said there will be enough gas to go round for quite some time. “Even when we reach 77m tonnes a year, we will have enough gas for about 100 years minimum,” he said.
His timing, however, couldn’t be worse. Gas prices have plummeted as the global economic slowdown has taken hold. At the same time, several big new LNG projects, including the Sakhalin in Russia and a larger project in Yemen, are beginning production, creating a sudden glut of supply when demand is falling.
“I would be lying if I said I wasn’t worried about the short-term outlook, but longer term the world will need this gas,” said Al-Suwaidi.
In Britain, the picture has changed dramatically. Later this year BG will open its Dragon terminal, also at Milford Haven, which will have a similar capacity to South Hook. National Grid spent £1 billion to build a huge, 316km pipeline through Wales to hook up the terminals to the national gas network.
Taken with the Isle of Grain terminal, which opened in 2005, by the end of this year nearly half of Britain’s gas needs could arrive by ship. As North Sea production declines – and worries about the reliability of Russia as Europe’s gas supplier persist – this increases the security of supply.
There are caveats, however. For one, about a third of the North gas field lies beneath Iran’s territorial waters. It is unclear how long it will be happy for its smaller neighbour to suck gas from the shared reserves. Second, capacity does not guarantee delivery. There is no contracted minimum for UK delivery. Cargoes go to the highest bidder, so last year many LNG cargoes were diverted to the likes of Japan and South Korea, which have negligible domestic supplies and were willing to pay over the odds to meet their needs.
Peter Osbaldstone at Wood Mackenzie, the research firm, said: “We have the capacity to meet our requirements, but there is no guarantee the molecules will be delivered.”
Al-Suwaidi downplayed that possibility. “This idea that you can show up when you want and go away when you want doesn’t work in LNG. To divert one cargo is something like two weeks of work for lawyers.” And there are not many other places for the gas to go, he added. Only half a dozen ports in the world, South Hook among them, are equipped to receive a Q-Max tanker.
Of course, for the likes of Safe Haven, they would rather never see a Q-Max sail into the Milford Haven harbour. Al-Suwaidi says he understands the concerns but says Qatar Gas has taken every possible precaution. The ships are doubled hulled and the five onshore storage tanks are also reinforced with more than a metre of concrete and steel.
“I understand that when we show up with these huge machines it will cause concern. So there have been some delays and it has cost us money, time and lawyers. But we are not mad,” he said with a chuckle. “We like your democracies.”
One of the dafter top-of-the-market pronouncements was Gazprom chief Alexei Miller’s forecast in June last year that oil prices would top $250 a barrel this year. It was in Mr Miller’s interests to talk up crude prices: European gas tariffs are linked to them, with a six- to nine-month time lag. And hubris was perhaps inevitable; Gazprom, with a market capitalisation of $330bn, was then the world’s third-largest company. But pride comes before a fall. Today, worth under $90bn, Gazprom is ranked 37th.
The share price slide looks excessive – owing more to investors’ fears of “Russia risk” than fundamentals – with Gazprom trading on less than 5 times prospective 2010 earnings. But the outlook has also changed significantly. Gazprom’s deputy chief executive told the board last week that gas exports to Europe – accounting for 60 per cent of revenues – were expected to plunge 22 per cent from 179bn cubic metres in 2008 to 140bn cu m this year. The average selling price was forecast to fall from $400 per 1,000 cu m to $260. Reflecting the shrinking demand, Gazprom’s gas output fell by a quarter, year-on-year, in March.
The projected annual volume fall partly reflects Gazprom’s January foot-shooting antics, when gas to Europe was shut off for 13 days because of a price squabble with Ukraine. But the recession could depress gas demand for industry and power in Europe not only in 2009 but for years to come. IHS Global Insight, a forecaster, originally estimated 2012 demand in 23 European countries at 686bn cu m. Under a mild recession scenario, it now forecasts demand at 626bn cu m; a more severe downturn could cut that to 610bn cu m.
Falling exports make a cut to Gazprom’s planned $27bn investment programme for 2009 highly likely. That could delay new supplies from costly projects such as the Yamal Peninsula, vital to meeting Europe’s longer-term energy needs. For its part, Gazprom insists it will have enough gas to go round. But this – not Mr Miller’s latest bluster last week that Gazprom might send more gas elsewhere in liquefied form, after the European Union cosied up to Ukraine – is the real concern for Europe.
National Grid, the owner of Britain's electricity transmission network, hopes to grab more than $100million (£67million) of the billions of dollars in stimulus funds set aside by President Obama for green energy projects.
The company is working with the Massachusetts state government on a bid for $57million in funding to help it to pay for a smart grid pilot launched last week. National Grid, the second-biggest energy supplier in America, is also talking to New York about a similar-sized pilot that could be funded with stimulus cash. Mr Obama has won plaudits around the world for his focus on climate change. He plans to spend $11billion of the $787billion economic stimulus package announced in February on creating a modern electricity grid that makes the most of renewable energy sources.
As much as $4.5billion will be spent on developing smart grids, which give customers better information on the energy their homes use and more control over their power usage.
Congress's attention is focused on the issue of green energy after Henry Waxman and Edward Markey, both Democrat congressmen, last week launched more than 600 pages of draft legislation outlining a big part of the President's energy strategy.
Steve Holliday, National Grid's chief executive, told The Times:
“We've got a Government there now and a President that's determined to live up to his own commitments on climate change adaptation.”
National Grid does half of its business in the United States after growing through a series of takeovers over the past ten years. The company plans to spend $57million on the smart grid pilot involving 15,000 customers in Worcester, Massachusetts. It hopes to have some or all of the cost covered by federal funds, which, if granted, would allow it to enlarge the pilot. More details are expected in the coming months of a similar pilot it is discussing for Syracuse, New York.
National Grid is also talking to Michael Bloomberg, the Mayor of New York, about a project to swap the city's ageing oil heaters for gas, with the possibility of funding from the stimulus package.
Mr Holliday added: “Each time you take an oil burner out of a normal home, it's equivalent to taking four four-wheel drive vehicles off the road. It should be a no-brainer, it has a huge impact on the environment and air quality.” The company carried out a record 60,000 oil-for-gas conversions last year after consumers were stung by record oil prices. This year, however, there are fears that numbers will drop as household incomes are pinched by the recession.
National Grid's success in America is closely tied to customers' energy efficiency. America's power systems tend to be older than those in Britain but state energy regulators are reluctant to allow suppliers to raise bills to provide cash for upgrading the systems.
Mr Holliday said that if National Grid convinced customers to use less energy, energy costs could rise slightly but household bills would remain flat. This would free up money for the company to invest in the systems.
National Grid plans to spend $500million a year within three years on promoting energy efficiency in America. It spent $170million last year alone on fitting insulation to customers' homes and businesses.
Beneath a shimmering Finnish sky, thousands of workers are toiling below a forest of bright red cranes. Stepping through a hatch between a two-metre thick concrete containment wall, Kathe Sarparanta enters a vast, roofless chamber lined with reinforced steel. “This is the heart of the reactor – the fuel rods will be right there,” said Ms Sarparanta, an employee of TVO, the Finnish utility, raising her voice above a steady din of hammering and drilling. “The temperature inside will reach 1,000 degrees centigrade.”
Here at Olkiluoto, a sprawling construction site on the thickly wooded shores of western Finland, the world’s most powerful nuclear reactor is taking shape.
This remote corner of Scandinavia, where wolves prowl the forests, may seem an unlikely starting point for a study of Britain’s looming energy crunch, but the prototype reactor that is being built here by Areva, the French nuclear energy group – the first to be ordered in Western Europe since 1986 – has profound implications for the UK.
With supplies of North Sea gas rapidly running out, the Government will announce next week a provisional list of sites for new nuclear plants, each of which will churn out enough electricity to power nearly two million homes for 60 years. By 2015, it is hoped that at least eight will be under construction, with the first – probably at Hinkley Point in Somerset – slated to enter service in 2017.
These plans, which are already well advanced, form the boldest part of a drive to plug a yawning gap in Britain’s energy supplies. But a host of challenges await before the new plants can begin supplying electricity to homes and businesses.
Dieter Helm, Professor of Energy Policy at Oxford University and a former government adviser, said: “The Government is more and more desperate for nuclear power. It provides one of the only ways that we can achieve serious reductions in carbon emissions while increasing the security of Britain’s energy supplies.”
Back in 1996, the existing fleet of nuclear stations, most of which were built in the Seventies and Eighties, generated 30 per cent of the UK’s electricity. With ageing plants gradually being retired from service, that figure has slumped to 16 per cent. If no new reactors are built, by 2023 it will have dropped to 3 per cent, with only one operational reactor left, at Sizewell B in Suffolk, according to John Hall, an independent analyst who has advised some of Britain’s biggest companies on energy since 1973.
The energy crunch is being compounded by the fact that nine of the biggest conventional coal and oil-fired power stations, which together represent 15 per cent of UK generating capacity, must close in 2015 to comply with European Union emissions rules. Despite the Government’s talk of a green energy revolution driven by wind and wave power, virtually all of this lost electrical capacity is being replaced with more fossil fuels, chiefly gas-fired power stations.
Official figures show that the share of Britain’s electricity produced by burning gas has risen from 2 per cent in 1992 to 35 per cent today. This is happening amid pressure to cut carbon emissions and as Britain’s domestic supplies of North Sea gas are running out, boosting our dependency on imports from Russia, Algeria and Qatar.
“Without these new reactors, we really are out in the cold, dark night,” Mr Hall said. “There is simply nowhere else to go. If we want to have a carbon-free economy, then we have to go new nuclear.”
Renewable energy still supplies about 5 per cent of Britain’s electricity, the bulk of it from old hydroelectric schemes. Although the figure is rising, wind energy generated only 1 per cent of UK electricity supplies in 2007. Even by the most optimistic forecasts, renewables are likely to contribute only 20 to 30 per cent by 2020. Because wind is an intermittent energy source, baseload power from nuclear or gas-fired plants will be needed as back-up.
Mr Hall added: “In any case, even that level is simply not enough as we are going to be facing a real supply crunch from 2012 onwards.”
Keith Parker, chief executive of the Nuclear Industry Association, has waited a long time for this day. For years, new-build nuclear was dismissed as a policy amounting to electoral suicide, but since the Government decided last year to support it, ministers have pulled out all the stops, he says. A new unit within government has been hard at work, aiming to bolster Britain’s nuclear regulator and clear other obstacles. But replacing the present fleet of reactors will not be easy – or cheap.
E.ON, the German energy group that will be one of the main players in the British programme – alongside RWE (also German-owned), EDF, of France, Iberdrola, of Spain and possibly Centrica, the British supplier – estimates that each new reactor will cost between €4 billion (£3.6 billion) and €5 billion. That excludes the cost of the decommissioning and waste, a thorny issue in Britain.
The challenge of financing these new nuclear plants has been amplified by the credit crunch and the collapse in the price of coal, oil, gas and carbon emissions, all of which have shifted the economics of nuclear power.
“We have been here before,” Professor Helm said. He pointed out that in 1981, with crude prices soaring in the aftermath of the Iranian Revolution, David Howell, then Energy Secretary, announced the construction of ten new nuclear power stations in the UK. A new reactor was planned to open every year for a decade.
In fact, only one was ever built – Sizewell B – and the ambitious plan sank without a trace as oil prices fell back in the wake of Saudi Arabia’s decision to flood the market with cheap crude.
It is not merely opposition from the antinuclear lobby and the glacial pace of Britain’s planning system that mean it is likely to be 2013 before the first concrete is poured. “Building nuclear reactors is a risky investment and we are in the middle of a recession, so this is a big ask for investors. The risk is that these companies could opt to build far cheaper gas plants,” Professor Helm said. “They would be ready in just two years.”
Of course, the Government is striving to keep the programme on track – but back at Olkiluoto, where construction on the prototype is three years behind schedule, it is easy to see why investors might be hesitant.
“It’s an enormous job,” admits Jounen Silvennoinen, project manager for TVO, which is paying a fixed price of €3 billion to Areva for the new plant, even though costs have soared to €4.5 billion. “The plant was due to start [this month]. But the detailed design work [to withstand a direct hit by a commercial airliner, among other things] has taken much longer than planned.”
New-build nuclear: the Government’s timetable
April 15 Government publishes a list of proposed sites for new reactors
April (ongoing) State-owned nuclear sites are auctioned to utility companies
2009-11 Britain's nuclear safety watchdog, the Nuclear Installations Inspectorate (NII), carries out design assessments of proposed designs for new reactors
2010 The planning process for individual sites starts. This should take 18 months, thanks to a new Planning Act
2011 Power companies are granted licences to build and operate a specific type of reactor on a particular site. The process for each site will take a year
2012-13 Work begins on site for the first reactors, probably at Hinkley Point in Somerset and alongside Sizewell B in Suffolk, left
2017-18 The first of the new nuclear power stations start generating electricity
A controversial nuclear recycling plant, approved by the Government despite warnings over its economic viability and reliance on unproven technology, has racked up costs of more than £1bn and is still not working properly.
Backers of the plant at Sellafield, which promised to turn toxic waste into a useable fuel that could be sold worldwide, had claimed the plant would make a profit of more than £200m in its lifetime, producing 120 tonnes of recycled fuel a year. But after an investigation by The Independent, the Government admitted technical problems and a dearth in orders has meant it has produced just 6.3 tonnes of fuel since opening in 2001.
With construction and commissioning costs of more than £600m, the facility, known as the Mox plant because of the mixed oxides (Mox) fuel it is designed to produce, has cost more than £1.2bn, confirming its status as the nuclear industry's most embarrassing white elephant and one of the greatest failures in British industrial history, losing the taxpayer £90m a year. Green campaigners and opposition MPs are now calling for the plant to be closed immediately, and a minister who fought its construction at the time has called for a public inquiry into how the plant was ever given the go-ahead.
The revelations are a blow to the Government as it plans to lead Britain into a "nuclear renaissance", pinning its hopes on nuclear technology to help meet its ambitious targets on reducing carbon emissions by 80 per cent by 2050. A spokesman for the Department of Energy and Climate Change said the performance of the plant was "clearly disappointing".
The Government had tried to keep details of the plant's losses private. The Nuclear Decommissioning Authority (NDA), the publicly funded body which owns the plant, initally refused to release details of the losses, citing confidentiality agreements in commercial contracts. But in a table published by the Government on the day of the G20 summit, the embarrassing extent of the plant's losses was finally disclosed.
Michael Meacher, who tried to block approval for the plant as Environment minister, said: "This waste of taxpayer's money is unforgivable. The construction of the plant was resisted for years. But that was overridden by Tony Blair on the basis of assurances from the nuclear industry that the Mox plant would be cost-effective and a market for its fuel would develop.
"These claims have proved illusory. But even the most pessimistic judgement never predicted that the first decade of its operations would fritter away two-thirds of a billion pounds on generating no more than 4 per cent of its target production. There should be a public inquiry into this scandal and those responsible should be held to account."
Speculation has now grown that Ed Miliband, the Climate Change Secretary, is preparing to bite the bullet and close the plant, which has faced five public consultations, legal challenges and safety concerns. The NDA admits the future of the plant is "under review".
Opposition MPs slammed the performance of the facility. "The Mox plant at Sellafield has proved to be a costly white elephant and a black hole for taxpayers' money," said Simon Hughes, the climate change spokesman for the Liberal Democrats. "This is a prime example of Labour's misguided and hugely expensive continuing love affair with nuclear power. Building a new generation of nuclear power stations is throwing billions of pounds of good money after bad. They are never built on time or on budget and they will not solve the UK's energy needs."
The plant has had an unhappy history. As soon as it was proposed in the 1990s, Greenpeace raised concerns about the safety of reprocessing used uranium and plutonium, and then transporting the weapons-grade material to customers around the world. Scientists, economists and MPs also questioned the financial viability of the project. Though the Government approved the plant on the basis that it would return a profit of about £216m over its lifetime, that figure did not take into account the £500m construction costs.
The plant was dealt a further blow in 1999, when The Independent revealed that workers at Sellafield had falsified quality-control data on Mox fuel. Unsurprisingly, customers in Japan, the country that the Government believed would provide the bulk of orders for the fuel produced by its new plant, lost confidence. It left a gaping hole in the Mox plant's order book which has never been filled.
Since it opened in 2001, the plant's complex recycling procedure has also been dogged by breakdowns and on-going difficulties. At present, production problems are being experienced in making "fuel assemblies", the final stage of production in making the fuel. Despite the problems, the Government refused to acknowledge difficulties at the plant. Even after serious issues had emerged by 2004, it still argued that the economic and environmental case for the plant was as "strong as ever". Campaigners believe the final bill for the plant will be even higher by the time it is closed, because decommissioning the facility will also cost millions. "This is a staggering waste of taxpayers' money, and we doubt that these will be the full costs of this sorry saga," said Nathan Argent, head of Greenpeace's energy solutions unit.
"Just imagine what the renewable sector could have done with a subsidy like that. The spectacular failure of the Mox plant is just another reminder of why the nuclear industry has become notorious for making wildly misleading financial claims.
"For years, we urged the Government to treat the industry's predictions with the scepticism they deserved, but our pleas fell on deaf ears. Once again the same tired old lines about sparkling new equipment are wrapped in make-believe financial forecasts, and ministers are swallowing it hook, line and sinker."
Without government assistance the UK will not meet its renewable energy targets, according to a stark warning from the wind industry.
Falling power prices, frozen finance markets and a weak pound are combining to put the brakes on wind farm developments needed to meet the deadline for 15 per cent of all energy – or about a third of electricity – to be from green sources by 2020.
Some £10bn-worth of wind installations are all ready to start being built. But unless the Government can tweak the investment case, they will not make it off the drawing board in time, says the British Wind Energy Association (BWEA).
"The 2020 targets will be in jeopardy if the current economic conditions continue," said Adam Bruce, the chairman of the BWEA. "The issue is how we deal with the short-term fall-out after the collapse of Lehman Brothers and the fall of sterling against the euro. The answer is that government has to be prepared to take short-term measures."
The problem is not that developers do not want to build. Almost 3.5 gigawatts (GW) of wind power is already in operation, another 9GW is in the pipeline, and a further 8GW is awaiting planning consent. But twice as much again is needed in the next decade, and progress is stalling.
In the onshore market – despite record growth of 425 megawatts since October – the number of new applications is at its lowest level since 2002 as developers struggle to raise finance. Offshore, the business case is even trickier. Equipment is bigger, more expensive and harder to install. With power prices falling, but the strong euro pushing component prices through the roof, Lincs and the London Array are just two of the growing list of plans put on hold.
Solutions to the impasse were included in a BWEA budget proposal submitted to the Treasury yesterday. Given the current claims on the public purse, the majority do not include direct subsidies. One possibility is that, for a premium, the government underwrites a floor price in the Power Purchase Agreements between generators and utilities to woo wary banks spooked by the falling electricity price. Alternatively, a "good" bank could be created specifically to provide lending for infrastructure programmes.
For offshore, the cost of building a grid connection – which can be as much as a fifth of a project's price tag – could be spread out across the whole generating sector rather than borne by the individual developer.
Equally, offshore wind could be allocated a higher number of Renewables Obligation Certificates, the credits which can be sold on to electricity suppliers to prove their green sourcing.
The prize for the successful creation of a major offshore industry is not only environmental. The Prime Minister told The Independent this week that "green industry" will be central to the UK's economic recovery. Europe's potential offshore wind market is huge if the UK's nascent supply chain can steal a march on continental rivals. But a fall-off in momentum in the current crop of projects, and knock-on delays to the massive 25GW of offshore capacity to be licensed later this year, will put paid to such ambitions.
A spokesman for Centrica said: "We are at a key point for the industry. If a lot of projects are not pushed through because of the economics, then quite quickly the UK's renewables supply chain, which is already weak, will be lost to more attractive markets like the US and Germany."
Government plans to make Britain a global leader in green energy are set to be rescued by the European taxpayer.
The Times has learnt that the European Investment Bank (EIB) is in talks with developers about a financial rescue package for the £3 billion London Array scheme, which is located in the Thames Estuary. Planned to be the world’s largest offshore wind farm, it is a project that has strong personal backing from the Prime Minister.
Gordon Brown wants part of the renewable energy scheme finished before the 2012 Olympics.
The UK desperately needs London Array to fulfil its ambitious target of generating 35 per cent of electricity from renewable sources by 2020.
Pleas for cash to the EIB, the long-term lending bank of the European Union, are a last-ditch attempt to save the project, which has suffered from a number of high-profile companies pulling out and fears over its funding.
The developers have limited the amount they are prepared to fund and, as a result of the credit crunch, banks are reluctant to lend on such large projects.
Even the entry of the EIB may not safeguard the future of the plan to build up to 341 giant offshore windmills generating sufficient electricity to power 750,000 homes.
A spokeswoman for the EIB declined to comment on specific projects but confirmed: “We are committed to funding offshore wind projects in the UK and are currently in discussions with a number of project promoters.”
The London Array project has been struggling since last May when Shell, the oil company, withdrew its support, citing spiralling costs.
Its two other backers, E.ON, the German power group, and Dong Energy, a Danish company, have pressed ahead. Last October it was announced that Masdar, a $15 billion (£10 billion) renewable energy fund controlled by the Government of Abu Dhabi, was acquiring Shell’s former stake.
The EIB, founded in 1958, has helped to finance many of Europe’s big postwar infrastructure projects. One of its core aims is to support sustainable development and it has recently committed to investing at least €800 million (£720 million) a year in renewable energy.
The bank has already funded a string of solar energy projects in Spain and France, as well as Greater Gabbard, another UK offshore wind project, to be built off the Suffolk coast.
The involvement of the EIB, with a capital base of €232 billion, will be welcomed by the UK Government and by the renewable energy industry, which is still reeling from the impact of the credit crunch and the collapse in the price of oil and carbon emissions.
While the EIB is not permitted to lend more than half the total cost of the project, its provisional offer of funding, which could still be withdrawn, is thought to run into several hundred million euros.
A final decision on London Array, which was first mooted in 2001, is expected this summer.
Paul Golby, the chief executive of E.ON UK, told The Times that the plunging value of the pound had also undermined the economics of the London Array project by forcing up the price of imported turbine equipment by more than 20 per cent.
A string of companies have cut their investments in the sector in recent months, including Shell and BP.
Iberdrola Renovables, the Spanish company that is the world’s largest wind farm developer, announced recently that it was slashing its investment programme in renewable energy from €3.8 billion in 2008 to €2 billion in 2009.
35%-40% the amount of electricity generation the UK is committed to supplying from renewable energy by 2020
1% the level of electricity supplied by the UK’s wind turbines in 2007
£100bn Estimated cost of building renewable energy schemes necessary to meet 2020 targets
53% Fall in global investment in clean energy between March 2008 and the same month this year
The Obama administration wants to reduce oil consumption, increase renewable energy supplies and cut carbon dioxide emissions in the most ambitious transformation of energy policy in a generation.
Most of the investments by oil companies go to traditional fossil-fuel resources, including carbon- intensive energy sources like tar sands, above, and natural gas from shale.
But the world’s oil giants are not convinced that it will work. Even as Washington goes into a frenzy over energy, many of the oil companies are staying on the sidelines, balking at investing in new technologies favored by the president, or even straying from commitments they had already made.
Royal Dutch Shell said last month that it would freeze its research and investments in wind, solar and hydrogen power, and focus its alternative energy efforts on biofuels. The company had already sold much of its solar business and pulled out of a project last year to build the largest offshore wind farm, near London.
BP, a company that has spent nine years saying it was moving “beyond petroleum,” has been getting back to petroleum since 2007, paring back its renewable program. And American oil companies, which all along have been more skeptical of alternative energy than their European counterparts, are studiously ignoring the new messages coming from Washington.
“In my view, nothing has really changed,” Rex W. Tillerson, the chief executive of Exxon Mobil, said after the election of President Obama.
“We don’t oppose alternative energy sources and the development of those. But to hang the future of the country’s energy on those alternatives alone belies reality of their size and scale.”
The administration wants to spend $150 billion over the next decade to create what it calls “a clean energy future.” Its plan would aim to diversify the nation’s energy sources by encouraging more renewables, and it would reduce oil consumption and cut carbon emissions from fossil fuels.
The oil companies have frequently run advertisements expressing their interest in new forms of energy, but their actual investments have belied the marketing claims. The great bulk of their investments goes to traditional petroleum resources, including carbon-intensive energy sources like tar sands and natural gas from shale, while alternative investments account for a tiny fraction of their spending. So far, that has changed little under the Obama administration.
“The scale of their alternative investments is so mind-numbingly small that it’s hard to find them,” said Nathanael Greene, a senior policy analyst at the Natural Resources Defense Council. “These companies don’t feel they have to be on the leading edge of this stuff.”
Perhaps not surprisingly, most investments in alternative sources of energy are coming from pockets other than those of the oil companies.
In the last 15 years, the top five oil companies have spent around $5 billion to develop sources of renewable energy, according to Michael Eckhart, president of the American Council on Renewable Energy, an industry trade group. This represents only 10 percent of the roughly $50 billion funneled into the clean-energy sector by venture capital funds and corporate investors during that period, he said.
“Big Oil does not consider renewable energy to be a mainstream business,” Mr. Eckhart said. “It’s a side business for them.”
Shell, for example, said it spent $1.7 billion since 2004 on alternative projects. That amount is dwarfed by the $87 billion it spent over the same period on its oil and gas projects around the world. This year, the company’s overall capital spending is set at $31 billion, most of it for the development of fossil fuels.
Industry executives contend that comparing investments in oil and gas projects with their research efforts in the renewable field is misleading. They say that while renewable fuels are needed, they are still at an early stage of development, and petroleum will remain the dominant source of energy for decades.
In its long-term forecast, Exxon says that by 2050, hydrocarbons — including oil, gas, and coal — will account for 80 percent of the world’s energy supplies, about the same as today.
“Renewable energy is very real,” David J. O’Reilly, the chief executive of Chevron, said in a speech in New York last November. “We need it. It will be an essential part of the future I envision. But it’s not realistic to suppose we can replace conventional energy in a timeframe that some suggest.”
Chevron has spent about $3.2 billion since 2002 on “renewable and alternative energy and energy efficiency services,” according to Alexander Yelland, a spokesman. It plans to spend $2.7 billion in the three years through 2011 on a variety of projects, including a business that helps improve energy efficiency for companies and government agencies, he said.
Despite Washington’s newfound green enthusiasm, industry executives argue that replacing any significant part of the fossil fuel business will take decades, at best. Just to keep up with growth in demand for conventional sources of energy, producers will need to invest more than $1 trillion each year from now to 2030, according to the International Energy Agency.
“Many of these companies see the world is changing,” said Daniel Yergin, the chairman of Cambridge Energy Research Associates and a historian of the industry. “But the challenge for a very large company is to get critical scale. People tend to forget the scale of the energy business.”
The world consumes about 85 million barrels of oil a day. The United States alone would require six times its arable land — and 75 percent of the world’s cultivated land — to supply its needs with ethanol made from corn, according to calculations by Vaclav Smil, an energy expert at the University of Manitoba.
More realistic, and modest, targets are proving tough to reach. Congress’s ethanol mandate, which requires oil companies to use 36 billion gallons of ethanol by 2020, cannot be achieved, experts say, without major technological advances that are still years away.
To increase supplies, most companies are looking to tar sands in Canada or converting coal or natural gas into liquid fuels, technologies that emit far more carbon dioxide than conventional oil does.
Shell, a major investor in Alberta in Canada, says that traditional oil supplies will not be enough to meet the growth in the world’s energy needs over the next half-century. In 2007, BP invested in Canadian tar sands, prompting criticism that it was “recarbonizing” itself.
John M. Deutch, a professor at the Massachusetts Institute of Technology and a former director of central intelligence, said there was little point in criticizing oil companies without first establishing federal rules that set a price on carbon dioxide emissions. Once that happens, he said, companies will adapt their strategies.
“What role will oil companies play in the future in alternatives to conventional hydrocarbon? The correct answer is nobody knows,” Mr. Deutch said. “The important thing is for the government to establish a carbon policy. You can be absolutely confident that oil companies will pursue that, as will any other companies.”
One area where companies are increasingly focused is the development of liquid fuels from plants. BP said it would soon build a demonstration plant in Florida for a type of ethanol made from plant material; Shell has worked with several firms since 2002 to develop ethanol from nonfood crops. Last year, it signed agreements with six companies, including one in Brazil, and decided to drop its other renewable efforts to focus solely on biofuels.
“Biofuels feels closest to our core business,” said Darci Sinclair, a company spokeswoman.
Other areas also hold significant promise for the industry, like technologies to capture carbon dioxide emissions and store them underground, and energy-efficiency programs, especially in the transportation sector. Exxon, long the most skeptical of the oil companies toward alternative energy investments, is working on long-term programs to improve fuel economy and reduce emissions.
In the end, many analysts say they believe that oil companies are waiting for a winning technology to emerge. Alan Shaw, the chief executive of Codexis, a biotechnology company in Silicon Valley that works with Shell, said oil companies were not blind to the new political reality but they were also in the business of making a profit.
“Don’t lose heart with Big Oil,” Mr. Shaw said. “They aren’t at a point where they are ready to invest yet, but they are getting there. I think in the next 10 years, they will invest hundreds of times more than they have in the past 10 years.”
The good news: A wonder metal that fires your phone, iPod and shiny new electric car is so clean it may save the planet. The bad news: More than half of the world's lithium is beneath this Bolivian desert...and getting it is so dirty it inspired the latest Bond plot.
Darkness falls across the Andes, turning the distant snow caps from blinding white to nothingness in the blink of an eye. From the east, the night races across the bleak Altiplano towards us, as the temperature plummets to below zero, leaving the windswept emptiness of the planet's largest salt plain in a vast cold shadow.
Above our heads, the sky changes to a hazy and then a deep blue hue, revealing the clearest view of the Milky Way to be found anywhere on Earth.
When Neil Armstrong and Buzz Aldrin became the first men to walk on the Moon, on July 20, 1969, one of the first sights they encountered from space was the wilderness where we stand. As the Earth turned they were captivated by a vast patch of white across the lower South American continent, which they instantly took to be glacial but was in fact southern Bolivia's Salar De Uyuni, a little-known but expansive desert of cactus, rainwater lagoons and ten billion tons of salt covering nearly 5,000 square miles.
Since then the salt plain has remained a largely forgotten corner of one of the most remote and inaccessible plateaus in the world; a destination for bewildered travellers heading to the Chilean border the long way from the Bolivian capital, La Paz.
It is a unique, surreal landscape - an empty white plain that stretches as far as you can see. During the rainy season a dramatic optical illusion occurs, when water lying on the surface of the salt table acutely mirrors the blue sky.
But this landscape is under threat. Energy economists in London, New York and the Middle East predict that this unlikely windblown patch of salt could, over the next two decades, become the next Saudi Arabia.
Like the Persian Gulf before it in the Twenties, Salar De Uyuni, or more specifically the vast quantities of lithium beneath its Northern Ireland-sized salt table, could be the answer to the transport problems of the 21st century.
Abandoning the cranking handle at the front of a vintage Mercedes flatbed truck, a local Aymara Indianwoman urges her family out of the warm comfort of the cab. She hunches up her ankle-length lace skirt and digs her heavy boots into the salty ground beneath her feet. The engine is dead.
She is joined by other indigenous women, salt miners, from a second broken-down vehicle. In their delicately balanced bowler hats, their babies nestled against their backs in colourful woven shawls, the women look like an overdressed scrum as they position themselves behind the truck.
While they take the strain, the drunken patriarch of the family sits in the driver's seat. He is happily chewing on charque de llama, dried llama meat, and laughing as the vehicle splutters into life. Everyone cheers. They won't have to sleep out in the cold tonight.
As the truck leaves us alone in the centre of the salt-pan there is only silence and the stellar night sky. Nobody lives here in the heart of the flats. There is no vegetation, for a start. The salt poisons any water on the surface. Along the plateau there is no sign of industry or development - only rows of brown mud huts, their musty rooms filled with reclusive Indian families with sun-blackened skin, who have lived here for generations.
But on the fringes of the salt plain, a Bolivian government plant is slowly taking shape. It is a mine with small-scale ambitions to extract the precious brine that bubbles below the salt crust on which we are perched. When first pumped from the ground, the brine looks like dirty slush.
But when left beneath the desert sun, the water will slowly evaporate, leaving a yellowy mineral bath that could easily be mistaken for thick olive oil: lithium, the lightest of all metals found on Earth and the hidden power behind our modern technological life.
Lithium may sound unfamiliar, but international demand for the mineral has gone through the roof. Today, the third element on the periodic table is the power in most mobile phones, all iPods, BlackBerrys and handheld computers.
The Mobira Senator, launched in 1982 by Nokia, consisted of a small handset connected to a brick-like nickel-based battery pack with a hefty handle on top - a crucial feature, since the whole thing weighed 22lb. Today, a typical mobile phone weighs a hundredth of this.
This reduction has been achieved largely through the advent of the lithium-ion rechargeable battery - it is lighter and able to hold a higher charge for longer than other batteries.
Between 2003 and 2007, the battery industry doubled its consumption of lithium carbonate, the most common ingredient in lithium-based products. Today's electric vehicles are powered by nickel-metal hydride batteries, but the cars' performance is limited. Lithium, however, will allow the next generation of electric cars to go a lot further.
With bated breath the American automobile industry awaits the Chevrolet Volt, a plug-in hybrid car expected to debut in 2010. The car will use a lithium-ion battery alongside a 1.4-litre petrol engine. Mercedes plans to roll out a hybrid version of its S-Class sedan later this year, and will similarly rely on lithium-ion technology for superior mileage.
Tesla Motors of San Carlos, California, has already delivered the Roadster, an all-electric two-seater sports car. The same rechargeable lithium-ion batteries, which helped to make the super-slim mobile-phone revolution possible in the past decade, are now set to power the electrification of the car.
'Since a vehicle battery requires 100 times as much lithium carbonate as its laptop equivalent, the green-car revolution could make lithium one of the planet's most strategic commodities,' says Mary Ann Wright of Johnson Controls-Saft, a lithium-ion battery producer.
But there is simply nowhere near enough currently mined to fuel the world's 900 million cars. According to William Tahil, research director with technology consultancy Meridian International Research, 'to make just 60 million plug-in hybrid vehicles a year containing a small lithium-ion battery would require 420,000 tons of lithium carbonate - or six times the current global production annually.
'But in reality, you want a decent-sized battery, so it's more likely you'd have to increase global production tenfold. And this excludes the demand for lithium in portable electronics.'
The sudden insatiable demand is spurring a race to find new sources of the third element. Mining companies are now scouring the globe's remotest corners, including the wilds of northern Tibet, where the Chinese have uncovered new reserves, as well as these remote salt plains of South America. Chile, currently the world's largest supplier of the element, has estimated reserves of three million tons.
This is dwarfed, however, by the potential lithium in Bolivia. The US Geological Survey claims at least 5.4 million tons of lithium could be extracted in Salar De Uyuni, while another report puts it as high as nine million tons.
If the electric car is ever to become a mass-market product, the lithium beneath my feet is going to have to be mined. But the Western companies desperate to get at these reserves face significant hurdles.
To get at the lithium below the white crust will cause irreparable damage to this landscape. In Salar De Uyuni, in particular, the lithium is highly diluted across the plains, so very extensive extraction operations would have to be deployed across huge swathes of the region.
The process would also put incredible pressure on water supplies. For local populations, life could easily start to mirror the scene from last year's James Bond film, Quantum Of Solace, in which wells dry up after water is stolen by the film's baddie, and villagers are forced to join collectives to buy their share. Far from being outlandish, the film may prove particularly pertinent as local South American populations find themselves having to buy water after big mining companies suck the land dry.
However, the more immediate problem facing potential lithium prospectors is Bolivia's stridently anti-Western president, Evo Morales...contd.
Secretary of the Interior Ken Salazar is optimistic about the potential of wind power to help wean the U.S. from dependence on foreign oil.
"The idea that wind energy has the potential to replace most of our coal-burning power today is a very real possibility," he said. "It is not technology that is pie-in-the sky; it is here and now," Salazar said, according to an AP report, at a meeting in Atlantic City, N.J., Monday.
Salazar is hosting four regional public meetings in April to discuss the future of offshore energy development on the nation's Outer Continental Shelf on the East Coast.
At the Atlantic City forum, he presented (PDF) estimates from the National Renewable Energy Laboratory that said wind has a gross resource of 463 gigawatts of power in the mid-Atlantic area alone. The current U.S. total production of electricity from coal is 366 gigawatts, according to the Energy Information Administration.
However, a large portion of the potential wind power is located out in deep waters. The laboratory assumes that about 40 percent of wind potential could actually be developed, totaling 185 gigawatts, or enough to power about 53.3 million average U.S. homes.
European countries, including Denmark and the U.K., have installed offshore wind parks. But so far not one offshore wind park has been built in the United States. Cape Wind in the Nantucket Sound hopes to be the first, but it is still fighting for approval.
A member of the American Coal Council, for example, told the Associated Press he thinks Salazar is too optimistic with his offshore wind estimates, and questions what will happen on days the wind is not strong enough.
The offshore energy development on the Outer Continental Shelf could also include controversial offshore oil drilling, a popular topic last year when gas prices hovered around $4 per gallon. A moratorium on offshore oil drilling has expired and Salazar also presented a potential for new energy there.
After more than 50 years of exploration and development, 70 percent of total resources are yet to be discovered, he estimates. More than half of this potential exists in areas of the Outer Continental Shelf outside the central and western Gulf of Mexico.
But the seismic data, upon which these estimates are based, is often more than 25 years old, and Salazar said in a press release that department scientists discovered huge information gaps about the location and extent of offshore oil and gas resources.
President Barack Obama and Congress must now decide whether to allow drilling off the East Coast.
Salazar continued his tour with a similar forum Wednesday in New Orleans, where oil and gas industry representatives expressed concern about the Obama Administration promotion of renewables. They claim that green energy cannot possibly provide all U.S. energy needs in the coming years--if ever. Offshore oil drilling is a must, they maintain.
"All areas of the Outer Continental Shelf should be open without delay for oil and natural gas development," Sara Banaszak, senior economist at the American Petroleum Institute, said in a press statement.
Business leaders have delivered a surprise attack on the government's environmental policy, arguing that ministers are not doing enough to cut global warming emissions or make sure the UK does not run out of power.
The CBI says billions of pounds of necessary investment will move to the US and China unless the government takes "urgent action".
It comes amid widespread disappointment that the G20 heads of state failed to come up with any real push on green issues as part of a $1.1tn (£743bn) financial aid package for the global economy.
The warning from the CBI follows a series of announcements by major energy companies, including Shell, BP and Centrica, that they would axe or reconsider investment in "low carbon" energy such as wind and solar power and carbon capture for coal-fired power stations.
Richard Lambert, the CBI's director general, said "politics and policy", not the recession, were delaying investment in the UK. He said the government's policies were on the "right path", but companies were "jittery" about investing in the UK because of delays with planning permission, poor National Grid connections, slow funding for new technology, and uncertainty over long-term carbon prices.
The government needs "to get on with it," said Lambert, ahead of today's launch of a new strategy for the energy industry. "If they don't, the risk is that the private capital needed will not come here in the volumes required."
Further evidence of the growing crisis of confidence in the green energy sector is exposed today by a survey which revealed that more than three quarters of Britain's green energy companies were now facing enormous financial difficulties gaining vital access to loans and investment money - a finding that has seriously shaken the industry's parent body.
Out of 39 member companies that responded to a poll by the Renewable Energy Association (REA), 32 said they were suffering from a shortage of cashflow and other problems, while only six said they were not affected at all.
Philip Wolfe, the director general of the REA, said the survey highlighted the need for immediate action by ministers. "Given all the rhetoric on the Green New Deal and Green Tech, it is astonishing that the renewables industry has received no dedicated support - even in areas that don't cost extra money," he said.
"As so little has been done, the last opportunity comes in this month's budget. Other countries have already committed huge stimulus monies to their renewables industries while we have nothing, so the UK industry is now at a serious competitive disadvantage."
Lambert said: "It's a bit of an edgy moment. If we're going to go to where we want to get to by 2020, we need to be moving pretty aggressively on policy."
The CBI's new strategy, one of four "road maps" to a low-carbon economy published today, will call for immediate and short-term actions, including clear planning guidance to fast-track investment in offshore wind farms and nuclear power stations and an upgraded National Grid. Ministers also need to make a quick decision about a promised trial of carbon capture and storage, and fund at least one other, says the business group.
The Department for Energy and Climate Change said there were "clear signals that there's an appetite for investment in nuclear energy" and this month it had increased the incentive for offshore wind power by 50%.
"The government has been working to ensure that the short, medium and long-term environment for energy investment remains healthy in Britain and that any barriers identified are swiftly removed," the department said.
Gordon Brown has promised an environmentally friendly Budget later this month to kick start a "green recovery" – including the mass introduction of electric cars on Britain's roads.
In an exclusive interview with The Independent, the Prime Minister trailed measures to make Britain "a world leader" in producing and exporting electric cars, hybrid petrol-electric vehicles and lighter cars using less petrol. Alistair Darling, the Chancellor, will announce in his Budget that trials for electric cars in two or three cities will begin next year. Councils will be invited to bid to become Britain's first "green cities". The Government will open talks with power companies to ensure the vehicles can have their batteries recharged at a national network of power points at the roadside.
Mr Darling will also set a target of creating 400,000 jobs in "green industries" over the next five years.
Other green measures to be outlined by the Government shortly include relaxing planning rules to allow the building of more wind farms to ensure Britain hits its target to generate 15 per cent of its energy from renewable sources by 2020. "Smart meters" will eventually be installed in every home so people can see how much energy they use. Ministers also want to develop a "clean coal" industry by approving an experiment with carbon capture and storage.
In his first newspaper interview since last week's G20 summit, Mr Brown kept open the option of a limited further fiscal stimulus in the Budget. But with public borrowing in the current financial year likely to rise from the forecast £118bn to around £150bn, he hinted that the Chancellor might have to announce more tax rises for the medium term to balance the nation's books.
"It is not just what we do to give real help now, but about setting a path for the future as well. We always take into account what we need and what is best future for the fiscal position," he said.
Pledging a raft of measures to ensure Britain emerges from the recession as a "low carbon" economy, the Prime Minister said the country could increase its output of environmental goods and services by 50 per cent to £1.5bn in the next few years.
"This is a major part of our plan for recovery in the Budget," he said. He added that the Government would provide incentives to help the car industry become a market leader across the world for electric and hybrid cars. Yesterday, the plans received a boost when the European Investment Bank approved a £340m loan to Jaguar Land Rover to develop "green" vehicles, with a further £373m to be split between Nissan's plants in Sunderland and Spain.
Mr Brown said he would consider buying a fleet of electric cars for ministers to set an example. To help Britain's struggling car industry, he said the Government was considering a "scrappage" scheme under which motorists would get up to £2,000 for trading in a polluting older car for a cleaner new vehicle.
"A different type of economy will emerge in the recovery – if we are prepared to invest in the future," he said. "Britain has a very strong and successful future ahead of us. We are leading in a number of key sectors."
The jobs of the future would come from a "green revolution" and an expansion in sectors such as pharmaceuticals, health care, education, the creative industries, information technology, bioscience and advanced manufacturing. Despite fears of a much smaller financial sector, he insisted that London would still be "one of the most attractive places to do business from".
Mr Brown said the push would enjoy widespread public support. "This is a job creator, a quality of life improver and an environment-enhancing measure," he said. "We want to harness a desire among people to be part of this. A better Britain means building a greener Britain."
Mr Brown struck an upbeat note about the United Nations-led talks on a new climate change treaty, to be held in Copenhagen in December. Despite fears that President Obama might not be ready to sign up by then, Mr Brown insisted: "He is determined to move the environmental agenda forward."
He added: "We have been brought down by a global banking crisis. We in Britain are capable and well placed – with our natural strength and our enterprising past and present, to be able to meet all these challenges in the future."
Motorists would get at least £2,000 towards the cost of buying an electric car under government moves to revolutionise driving in cities.
In an interview with The Independent yesterday, Gordon Brown said that this month's Budget would pave the way for the mass introduction of electric cars. But ministers acknowledge many drivers will need a cash incentive to be convinced to abandon petrol-run vehicles.
Boris Johnson, the Mayor of London, also said yesterday that he planned to create 25,000 electric car charging spaces in the city over the next six years. He hopes that 100,000 electric cars and vans could be using the city's streets.
The proposed government grant of £2,000 would reduce the cost of a small electric car to about £7,000. Drivers could recoup the sale price in savings in little more than two years as an average electric vehicle saves about £3,000 a year in motoring costs. The handouts would be modelled on the solar-panel grants scheme for homeowners.
The plans, to be set out in an ultra-low carbon car strategy this month, are designed to kick-start driver demand which British manufacturers could meet. They could be in place by 2011.
Mr Johnson's proposals to revolutionise motoring in London were set out in a letter to Mr Brown yesterday. The Mayor pressed for charging points to be installed on main roads and in workplaces, retail centres, car parks and railway stations by 2015. He proposes that 20 per cent of all new parking spaces be equipped with such points.
He promised to convert at least 1,000 London Authority vehicles to electric by 2015 and repeated a guarantee that electric vehicles would be exempt from the central London congestion charge. Mr Johnson called for the £60m cost of his plans to be met jointly by the Greater London Authority, the Government and the private sector.
"This package of measures would be unprecedented in Europe and would make London the electric car capital," he said. "By taking these steps, we will not only create green-collar jobs, but also smooth the way for less polluting transport choices which will improve our air quality, reduce traffic noise and contribute significantly to my carbon emissions reduction target."
The Conservatives say creating a network of charging points is essential to encourage motorists to change their habits. They propose giving electricity companies incentives to set up such points using decarbonised electricity.
Philip Gomm, from the RAC Foundation, said: "The Prime Minister's comments must be welcomed by anyone interested in providing sustainable transport for individuals into the future.
"But while government backing for alternative technology like electric vehicles is good news, this is still a vision for tomorrow and not today. The short-term answer must include further refinement of existing technology."
THE price of permits to emit carbon dioxide should be at least £85, about eight times the present price, if they are to meet their goal of getting big polluters to cut emissions, according to a government-sponsored study.
The findings, which will be published later this year by Chris Hope of Cambridge University’s Judge Business School, will shock industry at a time when pollution permits under Europe’s Emissions Trading Scheme (ETS) are trading at about £11 per ton.
The government commissioned Hope to assess the effectiveness of the ETS, the system under which companies are set limits on the amount of carbon dioxide they can emit. Those that exceed their limits must buy permits from others who have come in below their quota.
Hope is expected to say that the ETS is deeply flawed and that carbon permits should cost at least £85. He will suggest that a “green tax” on top of the carbon price may be necessary.
Oil giants pull out
BIG OIL picked up the pace of its withdrawal from renewable energy last week when BP revealed that it was closing two solar-panel plants in Spain and part of another in America.
The cutbacks, which will result in 620 job losses, come only weeks after BP announced a 30% spending cut across the company, including at its renewables arm. Earlier this year it decided not to invest in the British wind-power industry.
Shell has made the same decision and sold out of its wind interests. Last month the company also said it was pulling out of solar and hydrogen technologies.
The oil giants have been rethinking their operations since the oil price plunged from $145 a barrel to $50.
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