ChevronTexaco has had more success in the Green Canyon region, 100 miles south of Louisiana. There in 2002 it drilled Tahiti (58 percent owned with partners EnCana and Shell), which has an estimated 500 million barrels of oil and is slated to come on line in 2007. Last year came Tonga, which was drilled in 5,000 feet of water but set a vertical depth record of 31,800 feet. Like Tahiti, its drilling involved piercing an 11,000-foot layer of sedimentary salt.
The world's deepest producing field, in 7,000 feet of water, is a Shell/BP project called Na Kika that uses a 20,000-ton semisubmersible floating platform loosely tethered to the seafloor that's strong enough to hold the weight of 1.5 miles of pipe and the river of oil running through it.
Try to go any deeper, like ill-fated Toledo, and you encounter another problem. “We know how to drill it, but we don't know how to produce it yet,” says North American exploration head Raymond Wilcox. No worries, says his overseas counterpart at ChevronTexaco, George Kirkland. “If we find a 1-billion-barrel field in 10,000 feet of water, we'll move quickly to get any technological gaps filled to make that happen,” he insists. “I don't think we're that far off.”
A different technical challenge arises in Newfoundland, where ChevronTexaco and its partners paid $500 million for exploration rights to the Orphan Basin region, in the heart of iceberg alley. There it hopes to find at least half a billion barrels of oil, enough to build a platform like ExxonMobil's nearby Hibernia, which can withstand a jostle from a million-ton iceberg. Built in 1997 with 1.2 million tons of concrete and ballast, Hibernia (ChevronTexaco owns 27 percent) sits on some 700 million barrels, producing 150,000 barrels a day.
Why go to all the trouble? Over the last two years 65 percent of all new reserves worldwide were found in deep water (depths of 1,200 feet or more). This year such projects will supply some 1.3 billion barrels, or 5 percent of global oil demand. That will double by 2010, according to a Wood Mackenzie study.
The busiest deepwater region is now in West Africa off the coasts of Nigeria, Angola and Equatorial Guinea. There ChevronTexaco expects to spend some $3.4 billion in the next three years to begin developing fields with more than 1 billion barrels of oil. Among them is the Agbami project, which sits in 4,800 feet of water on 800 million barrels. ChevronTexaco has a majority stake in this field and expects maximum production to hit 250,000 barrels a day soon after startup in 2007.
Russia and its onetime republics pump 13 percent of the world's oil, 9 million barrels a day, second to Saudi Arabia. While this oil-soaked region has 77 billion barrels of proven reserves, most of this vast landmass is unexplored.
A big reason is political risk. But with huge potential paybacks, most Western oil companies badly want in. BP signed a $6 billion production deal last year with Tyumen Oil Co., or TNK, resulting in a 14 percent jump in the British oil giant's second-quarter production levels. Recently, ConocoPhillips held the inside track on picking up the Russian government's 8 percent stake in Lukoil for $1.3 billion or more.
ChevronTexaco, though it has an excellent position in neighboring Kazakhstan, has come up dry in Moscow. A year ago the company was in the running to buy what was rumored to be a 25 percent stake in Yukos for some $4 billion. Such a deal would have put to rest concerns about ChevronTexaco's short-term production growth. Then came the arrest of billionaire Mikhail Khodorkovsky on a charge of tax fraud. That iced O'Reilly's interest in a deal, compounding an already frustrating year. Months earlier he was thwarted when Moscow revoked ChevronTexaco's right to share in the production of the vast Sakhalin-3 field on the island north of Japan.
O'Reilly hasn't given up. A native of Dublin who started as an engineer at Chevron 36 years ago, he has learned patience. “Russia is one of the places we'd like to have a presence,” he says. He traveled to Moscow in early July to meet with the Russian oil minister to discuss a sizable investment over some years. “The long term in Russia looks great, but Yukos puts a lot of fear in me,” says George Kirkland, ChevronTexaco's head of overseas exploration. “I don't like that. When will it be a reasonable place to be from a risk perspective? I can't answer that question.” He may have to soon. The Russian government recently hired investment bank Dresdner Kleinwort Wasserstein to value the natural gas operations of Yukos with an eye toward putting them up for auction. The Kremlin's recent consolidation of Gazprom and Rosneft into the world's largest energy company will also lure Western investment. (Chevron recently announced an agreement with Gazprom on exploration and exporting projects.)
At least there is plenty going on next door. The Tengiz field in Kazakhstan holds 6 billion to 9 billion barrels of recoverable oil. To get at them, Chevron had to engage in a game of political football, first negotiating with the Soviets in the late 1980s, then, after the fall of the U.S.S.R., with the Nazarbayev government. Since inking a deal in 1993 the company, a 50 percent owner of TengizChevroil, and its partners have spent more than $10 billion on drilling and infrastructure. In the early days transporting the crude to markets cost $6 a barrel and required thousands of railcars. Now its 280,000 barrel-a-day production of crude moves at $3 a barrel through the 900-mile Caspian pipeline to the Russian Black Sea port of Novorossiysk. ChevronTexaco has a 15 percent interest in the pipeline, which will undergo a $2 billion expansion to double its capacity to 1.2 million barrels a day. That should be enough to handle production from an even bigger Kazakh field, Kashagan, which is slated to come on line in 2008.
Transport hasn't been the only problem. Because Tengiz oil is so high in corrosive sulfur compounds, it must be partially refined before going through the pipeline. The sulfur, 5 million tons of it so far, is collected in Atyrau in 25-foot-high slabs with footprints the size of football fields. The city is also host to the world's largest gas-stimulation project in development: 240 million cubic feet of Tengiz natural gas is injected daily into the reservoirs to loosen up oil and boost well pressure. As a result, by 2008 Tengiz production should reach some 800,000 barrel/day (350,000 barrel/day net to ChevronTexaco) — enough to meet 1 percent of global oil demand.
Higher prices at the pump have also made extraction from oil sands and heavy oil feasible. ChevronTexaco's primary projects are in Canada and Venezuela, where it thinks there are 2 trillion barrels or more worth of such “unconventional oil” reserves — an amount greater than the world's remaining reserves of conventional crude.
Alberta, Canada is site of the world's largest extraction operations from oil sands, heavy earth laden with bitumen, a hydrocarbon-rich mineral. ChevronTexaco has a 20 percent interest in the $4 billion Athabasca mine, a Shell-managed project that generates 134,000 barrels of oil a day. At the enormous oil sand strip mine, shovel cranes drop 100-ton loads of sand into 400-ton dump trucks. Extracting the bitumen from the clay and sand and upgrading it into crude oil — by breaking its big hydrocarbon molecules into smaller, less viscous ones — is an expensive, energy-intensive process that consumes 650 cubic feet of natural gas for every barrel. Even after spreading infrastructure costs over an enormous scale and running operations around the clock, a barrel of synthetic crude from oil sands costs $10 or so to produce, compared with $3 for a barrel from the Middle East. Added demands from such operations will stretch Alberta's ability to provide enough natural gas — necessitating new sources of energy.
Heavy oil requires different processing. In Venezuela ChevronTexaco has a 30 percent stake in the Hamaca project, situated in the 30-billion-barrel Orinoco heavy-oil belt. The stuff comes out in a foamy mousse that can be pumped but must be blended before it can be marketed. In August work was completed on Hamaca's upgrader plant, which will allow production to ramp up to 190,000 barrels a day. Cost per barrel: $13. So far ChevronTexaco and its partners have put more than $3.8 billion into Hamaca. Payback will come slowly; fields in the area are expected to keep producing for more than 30 years. The politically fickle Venezuela has 78 billion barrels of proven reserves of conventional oil and another 260 billion barrels of heavy oil.
As the easy oil runs out, the big boys have turned to plentiful natural gas. For BP and ExxonMobil, methane already accounts for 45 percent of hydrocarbon production and within perhaps a decade will surpass oil. With just 27 percent of its production from gas, ChevronTexaco is a laggard. The problem with gas is the difficulty of moving it across the ocean. That calls for a tanker that can handle liquefied natural gas, and a port whose neighbors can tolerate the sight of these ships.
For resource-hungry countries like Japan, Taiwan and South Korea, 95 percent of the gas is LNG. The U.S. gets 2 percent that way. Just four receiving terminals are in operation here. Public fears of harborside LNG fireballs have already derailed a half-dozen of the more than 20 receiving terminals proposed for the U.S. John Cogan, head of the LNG practice at Houston law firm Akin, Gump & Strauss, predicts that five terminals will be built in the next decade, "most likely in Louisiana and Texas, where people are comfortable with the idea of energy infrastructure."
We'll need a lot more than that. After decades of predicted supply shortfalls that never came, the U.S. is now unable to meet demand, and imports 18 percent of the 24 trillion cubic feet consumed a year. With domestic fields showing production declines the last two years despite an increase in wells drilled, that supply gap will only grow. Public resistance to receiving terminals helps keep gas prices high — $6 per million Btu, triple what they were in 1999. This gets O'Reilly exercised. “We need to provide permits for LNG import terminals,” he says. Without them the resulting high price of natural gas, he says, will doom entire industries — aluminum, fertilizers, chemicals.
How does ChevronTexaco get round the angry neighbors? By heading 40 miles south of Louisiana into the Gulf of Mexico, where it gained approval to build the $600 million Port Pelican terminal. Tankers will disgorge LNG there into 6.9-billion-cubic-feet storage tanks that regasify and shoot 1.6 billion cubic feet a day via pipeline to Louisiana's Henry Hub, from which 13 large pipelines spoke out. Port Pelican could take its first shipments as early as 2007. A second proposal for a terminal on Mexico's Baja peninsula is a long shot for now.
ChevronTexaco produces 4.3 billion cubic feet of gas a day (equal to 720,000 barrels of oil). Half is from the U.S., but the brightest prospects lie elsewhere. As in a gas-to-liquids project at the world's biggest field (900 trillion cubic feet) in Qatar. Off the northwest coast of Australia lies the Gorgon field, where the company holds a controlling stake. Gorgon is thought to contain 10.9 tcf of gas (equivalent to 1.8 billion barrels of oil); nearby are fields holding another 30 tcf. Over the next decade ChevronTexaco plans to spend $11 billion to tap Gorgon and neighboring fields.
Gorgon's riches were discovered 24 years ago but never developed because there was no ready market. The price of gas wasn't high enough to pay for the LNG tankers. Now it is. China last year signed a $25 billion contract with a group developing a second Australian gas field (in which ChevronTexaco has a 17 percent stake) to take 150 billion cubic feet of LNG a year for 20 years.
“Five years ago no one ever thought of taking Gorgon LNG to North America,” says John Gass, the aptly named president of ChevronTexaco's global gas division. These days he's drawing up plans to do just that.
It's preposterous to say that the world is running out of energy. It is only running out of cheap energy. There's plenty of the expensive stuff.