Feb. 18 (Bloomberg) — Shell Canada Ltd. Chief Executive Officer Clive Mather says oil from his Athabasca project, where tar sands are boiled to produce crude, can cost twice as much as drilling in the North Sea. And it’s worth every cent, he says.
“If we had access to unlimited conventional oil, I guess the interest in Athabasca would diminish quite quickly, but that isn’t the case,” Mather said in a Feb. 3 interview in London. “This is high-cost oil, there’s no question about that. At current prices, it’s still very good business.”
A 15-year decline in oil reserves is spurring companies such as Royal Dutch/Shell Group, Exxon Mobil Corp. and ChevronTexaco Corp. to spend $76 billion in the next decade to boost supplies of oil from tar sands and diesel fuel from Qatari natural gas. Oil executives say they have no choice but to try alternatives to drilling because there is not much more crude to be found in their current fields.
“We’re damn close” to the peak in conventional oil production, Boone Pickens, who oversees more than $1 billion in energy-related investments at his Dallas hedge fund firm, said in an interview in New York Feb. 16. “I think we’re there.” Suncor Energy Inc., the world’s second-biggest oil-sands miner, is his largest holding.
Companies will produce 10.1 million barrels of oil a day by 2030 from projects in Canada and Qatar, more than Saudi Arabia does today, according to forecasts by the International Energy Agency in Paris. That’s 8 percent of the world’s total.
Shell is spending $13.70 per barrel at its Athabasca project in Canada, higher than drilling projects, said Mather. Oil executives say that crude prices near $45 a barrel more than offset the extra cost. Crude for March delivery today was little changed, trading at $47.68 a barrel on the New York Mercantile Exchange at 9:30 a.m. London time.
The oil industry needs to spend $3 trillion by 2030, or $105 billion a year, to meet an expected surge in demand, the IEA estimates.
“Pressure on supply will become sufficient for more money to be put into non-conventional oil,” said Peter Odell, an oil politics and economics professor emeritus at the Erasmus University in Rotterdam. “This is a natural development of a resource base from the lowest cost to the highest cost.”
Exxon Mobil, BP Plc, Shell, ChevronTexaco and Total SA, the five largest publicly traded oil companies, last year reported net income of about $85 billion, equal to the economic output of Venezuela, a nation of 25 million people and the third-largest member of the Organization of Petroleum Exporting Countries.
Falling Reserves, Returns
Oil-sand mining projects offer a rate of return of 13.6 percent, less than half the 33.4 percent at a deepwater Gulf of Mexico field such as BP’s Mad Dog project, said Scott Mitchell, an analyst at energy consultant Wood Mackenzie in Edinburgh. West Africa’s deep waters offer an 18.2 percent return, he said. The estimates are based on an average price of $21 per barrel.
Shell and BP, Europe’s two largest oil companies, this month reported oil and gas reserves declined in 2004, based on U.S. rules. It was the first drop in more than six years for London- based BP, whose only investment in non-conventional oil sources is in Venezuelan heavy crude. BP acquired the stake when it bought the Veba Oel German oil-refining business from E.ON AG.
Shell Reserve Slump
Shell, based in London and The Hague, reported Feb. 3 that reserves fell in 2004 because it found enough oil to replace just 15 percent to 25 percent of what the company pumped. BP replaced 89 percent of production, the company said Feb. 8.
BP forecasts it can expand oil and gas output by 5 percent a year using existing deposits and doesn’t need to turn to non- conventional projects. BP’s growth comes from Russia, where it spent $7.7 billion on the TNK-BP joint venture.
“To renew our exploration business, we only need to rely on the exploration for and development of primarily conventional oil and gas resources,” Chief Executive John Browne said on a Feb. 8 conference call.
Oil futures show crude prices will stay close to $40 a barrel until 2011 because of rising demand, spurring investment in projects once considered to be marginal. Futures contracts are a promise to deliver a commodity at a specified price at an agreed- upon date in the future.
Canada’s tar sands may get $48 billion of investment by 2012, according to Canada’s National Energy Board, double the amount spent in the decade ending in 2003. As part of that, Imperial Oil Ltd., controlled by Exxon, said in November it may pay $6.5 billion to double its capacity to produce oil from tar sands.
For investors, oil sands have been a better bet than the best- known oil companies. Canadian Oil Sands Trust, which invests only in the Albertan mining projects, is up 67 percent in the past year. BP shares during that time are up 34 percent in London and Exxon Mobil, based in Irving, Texas, gained 39 percent in New York.
Current spending plans show Canada’s oil sands may produce 2 million barrels a day by 2015, more than Iraq today, crude worth $29.2 billion of revenue a year at oil prices of $40 a barrel.
Qatar may receive more than $28 billion of investment, to cause a 22-fold surge in the amount of fuels produced from natural gas, based on IEA estimates. Only two gas-to-liquids projects exist now, in Malaysia and South Africa, representing 35,000 barrels of daily production. The Qatari ventures are for a total of almost 800,000 barrels a day in 2011, according to the IEA. The fuels may be worth $15.5 billion a year in revenue, based on today’s diesel prices.
Shell will spend as much as $6 billion in Qatar to produce diesel fuel in 2009, according to project director Andrew Brown. Projects announced by Exxon, ConocoPhillips, Marathon Oil Corp., ChevronTexaco and Sasol Ltd. will cost another $22.3 billion.
The potential for non-conventional oils may exceed the IEA forecasts. Should oil reserves be lower than expected, non- conventional oil production may be 37 million barrels a day in 2030, or 39 percent of global demand, the IEA said in an alternative to its most likely scenario in the 2004 World Energy Outlook, released in October.
Ignoring oil sands and the potential to make fuels from natural gas “is a mistake,” said Ian Henderson, who manages $680 million at the JP Morgan Fleming Natural Resources Fund in London. “It’s taken millions and millions of years for hydrocarbons to form, and we are running out of them.”
Henderson owns shares of Canadian Natural Resources Ltd. and Petro-Canada, a partner in Syncrude Canada Ltd., the world’s largest oil-sands mining business. Both companies are based in Calgary. His investment fund is up 30 percent in the past year, compared with a 20 percent gain in the FTSE 350 Mining Index.
Making Canada’s oil sands viable would ease demand for crude from Saudi Arabia and other suppliers, Odell said. Alberta’s oil sands deposits contain 174.5 billion barrels of reserves, according to the Alberta Energy and Utilities Board. That total is two-thirds of Saudi Arabia’s proven reserves of 262 billion barrels.
Alberta’s oil sands cover an area larger than the state of Florida, and about two tons have to be dug up, heated and processed to make a single 42-gallon barrel of oil. Suncor Energy spends C$12 ($9.62) to C$12.50 to mine and upgrade a barrel of oil. Saudi Arabia pumps a barrel of oil for about $2.
Devon Energy Corp. President John Richels, a Canadian and a lawyer by training, remembers the first time he held a handful of the oil-encrusted sand, in the early 1990s. He said he had a hard time believing the sticky mixture could be turned into smooth- flowing crude. Devon, based in Oklahoma City, is now investing C$527 million in the Jackfish oil sands project in Alberta.
“They’re not particularly high-return projects,” he said in an interview. “We see the same kinds of returns, though, in other parts of the world.” And given the lack of exploration and political risk, the projects pay off, he said.
Failures are costly. A blaze at Suncor Energy in Alberta slashed output by about half, and full production won’t resume for months. The lost output is worth $4.4 million a day at $40 a barrel. The company expects insurance to cover most of its losses.
“There are operating risks,” Suncor Chief Financial Officer Ken Alley said in an interview. “It’s not unlike the refining industry where you operate with hydrocarbons, at high pressure and high temperature, and that is a risk that you design facilities to protect against. Nevertheless there is a level of residual risk.”
Oil sands projects of Shell and Suncor failed to meet their budgets and deadlines, the companies said, the result of competition for equipment and labor.
Syncrude Canada’s project to boost capacity by 100,000 barrels a day to about 350,000 is expected to cost $6 billion by mid-2006, almost double a 2001 forecast of $3.14 billion, according to Canadian Oil Sands Trust, lead partner in the venture. Developments by Shell Canada, 78 percent-owned by Shell, and Suncor cost as much as 70 percent more than planned, the companies reported.
“The problem is the consistent, continual and predictable cost overruns,” Pickens said. “That can’t keep happening, I don’t think, but still those overruns are a concern.”
Exploiting Venezuela’s heavy oil may double the reserves of non-conventional sources. Paris-based Total SA, Europe’s third- largest oil company, and Statoil ASA, the biggest in Norway, are among those exploiting Venezuela’s heavy oil deposits, reserves that may equal another 100 billion barrels to 270 billion, according to the U.S. Energy Department. The country already is processing 500,000 barrels a day of heavy crude.
In Qatar, the plants use a basic technology invented in the 1920s and exploited by the Nazis during World War II to make oil products from coal when embargoes cut off crude oil imports. The technology was also used in South Africa during Apartheid.
The gas-to-liquids process is wasteful, with about 45 percent of the natural gas lost in conversion, the IEA estimated.
The process consumes 10,000 cubic feet of gas to make one barrel of fuel, according to Malcolm Wells, a spokesman for Sasol Chevron Ltd., a joint venture between San Ramon, California-based ChevronTexaco and South Africa’s Sasol, which is spending at least $6 billion on building plants in Qatar.
At that rate, the amount of gas used for seven barrels of diesel is equal to what is burned in the average American household in an entire year.
Project costs are escalating because of higher steel prices and increasing demand for equipment. Shell’s gas-to-liquids plant will cost as much as $6 billion, 20 percent more than initially forecast, the company said.
BP just closed its gas-to-liquids pilot plant in the U.S. and is planning instead to sell natural gas to use in power plants, said Robert Wine, a BP spokesman in London.
Gas-to-liquids “isn’t a cheap industry to get into,” said Wells at Sasol Chevron. “It requires massive investment into infrastructure and huge sources of gas.”
Qatar has the world’s third-largest natural gas reserves, after Russia and Iran. Another 12 plants to make fuels from natural gas are in various stages of planning, in Nigeria, Iran, Egypt, Australia, Venezuela, Brazil and elsewhere, according to Paris-based Technip SA, Europe’s largest oil-services company.
A lack of information about proven oil reserves complicates assessing when supply from the world’s conventional oil fields will peak, the IEA said in its world energy outlook. The agency estimated it will occur sometime between 2013 and 2037.
“Oil won’t last forever,” said Manouchehr Takin, a senior analyst at the Centre for Global Energy Studies in London, a consulting company founded by former Saudi oil minister Sheikh Zaki Yamani.