Oil Producers Curb Megaproject Ambitions to Focus on U.S. ShaleBy
Rising complexity making biggest crude developments harder
Failure rates soaring when companies can least afford it
Big U.S. oil companies are starting to think small.
A stubborn 16-month crude rout with no end in sight is driving the largest U.S. oil producers away from costly, high-risk megaprojects long touted as the industry’s future and toward safer shale operations that generate the cash needed to satisfy anxious investors.
Exxon Mobil Corp., Royal Dutch Shell Plc, Chevron Corp., ConocoPhillips and Hess Corp. have all either delayed or abandoned projects that range from the deep seas of the Gulf of Mexico to Canada’s oil sands and the U.S. Arctic. At the same time, Exxon and Chevron both announced plans to substantially increase U.S. crude production, largely as a result of their shale operations.
“What makes more sense in this environment: drill a $100 million well in the deepwater Gulf that might come up empty, or poke lots of holes in west Texas where you already know there’s oil for a few million apiece?” said Michael Webber, deputy director of the University of Texas Energy Institute.
Explorers are expected to slash spending on deepwater wells by 20 percent to 25 percent next year, compared with a 3 percent to 8 percent overall reduction on all types of fields, according to Barclays Plc analysts including J. David Anderson. The type of giant reservoirs that require megaproject treatment are now found in only the roughest, deepest and coldest parts of the world.
One example: An equipment failure forced Chevron to put its $5.1 billion Big Foot development, a deepwater Gulf of Mexico project that was supposed to begin pumping crude this year, on hold until at least 2018. The San Ramon, California-based company hasn’t said whether the delay will bloat the price tag, which already had risen 28 percent from a 2010 estimate of $4 billion.
International producers are failing to deliver 80 percent of megaprojects on time and on budget, compared with about 50 percent in 2005, said Neeraj Nandurdikar, oil and gas director at Independent Project Analysis Inc.
“It’s really bad for megaprojects now,” said Joseph Triepke, managing director at Oilpro.com and a former analyst at Citadel LLC’s Surveyor Capital unit. “When oil was $90 or $100 a barrel, there was a lot of wiggle room to make a return. But at $45 oil, there’s no wiggle room. Enormous projects can’t go over or be late.”
West Texas Intermediate for December delivery rose 53 cents to $46.59 a barrel Friday on the New York Mercantile Exchange.
Exxon and Chevron may update investors on their biggest ventures when they report third-quarter results on Friday. “Chevron is taking actions responsive to the current price environment,” said Kurt Glaubitz, a company spokesman. “We are getting our cost structure down and actively managing to a smaller capital program.” An Exxon spokesman declined to comment.
ConocoPhillips, the third-biggest U.S. oil producer, canceled plans in July to search the deep Gulf of Mexico this year. Terminating a long-term rig lease may cost the Houston-based company as much as $400 million.
Other megaproject disappointments include Exxon’s Kearl oil-sands development in western Canada, where logistical challenges and harsh weather repeatedly delayed the $12.7 billion project before its opening in 2013. Plans to increase output again by 2020 have been shelved indefinitely. At Chevron’s gas-export project in Gorgon, the largest construction undertaking in Australia’s history, rising labor costs helped bloat the price tag by about 20 percent to $54 billion.
The shale drilling boom led to a supply glut that deflated prices by more than half since 2014 and shale remains one of the most economic options for producers. For Exxon and Chevron, that’s meant rededicating their spending to a region they’d mostly ignored for the half century before the shale boom while they pursued giant overseas discoveries.
Exxon has more than tripled the number of rigs it has drilling shale formations around the U.S. since buying XTO Energy for $35 billion in June 2010, Jack Williams, the senior vice president in charge of Exxon’s wells, said during a March meeting with analysts in New York. Exxon plans to double U.S. shale production in the next three years.
For Chevron, shale wells are forecast to contribute the equivalent of 160,000 barrels of daily oil output in the next two years, the company said in a March presentation to analysts. Despite the fall in crude markets, Chevron Chairman and CEO John Watson has so far stuck to his goal of boosting worldwide output 20 percent to 3.1 million barrels a day by the end of 2017, in large part because of shale.
Only 10 percent of non-shale discoveries this year will be profitable, down from 40 percent in 2010, said Julie Wilson, a senior exploration analyst at Wood Mackenzie. Cost overruns have afflicted 64 percent of oil and gas megaprojects and 73 percent of them have faced delays, according to an Ernst & Young LLP survey of 365 developments.
“Projects are getting bigger and bigger and they are failing more often,” said Howard Duhon, systems engineering manager at Gibson Applied Technology and Engineering Inc., which advises major oil companies on how to design deepwater projects. Equipment is more complex and project teams are three or four times bigger, and “it’s not clear we’re getting any better results,” he said.
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