At a time when Russia is saber-rattling and the Middle East is in turmoil, a welcome geopolitical trifecta could be in the making. The United States is poised to surpass Saudi Arabia and Russia as the world’s top oil producer. Canada’s oil sands have vaulted the country to energy superpower status. Mexico is embarking on a historic constitutional energy overhaul that its president promises will propel the country’s economy.
And there is no shortage of cheerleaders. “The North American production outlook is incredibly bright,” said Jason Bordoff, a former senior energy adviser in President Obama’s White House. “Everything we see on the ground suggests reasons to be optimistic.”
But as bright as the future may appear, energy executives and other experts say it is time for a reality check before declaring energy independence for the United States and its continent. Gushing oil and gas give North America hopes of becoming what some call “Saudi America,” but fossil fuels development is always contentious for its environmental costs. The Keystone XL pipeline, intended to connect Canada’s oil sands to American refineries, has been tangled in politics and regulatory concerns for years. Grass-roots environmental movements have stopped natural gas drilling in New York State and Quebec, and they threaten the expansion of oil company operations, pipelines and port terminals in the Western United States and Canada.
Bigger challenges face Mexico, still a fading producer for United States demand. Even as Mexico is pressing ahead with constitutional changes that promise to open exploration and production to international oil companies for the first time since the 1930s, the fine print of the legislation to carry this out is still in doubt, while raging drug violence continues to worry investors.
Perhaps most important, the economics of oil and natural gas extraction on the continent are challenging: Deepwater Gulf of Mexico oil drilling, oil sands extraction and shale drilling are all expensive and require high petroleum prices that are far from assured. Most of the easy-to-drill oil is gone. But should North America produce too much oil too quickly, and exports surge from Iraq (which is already happening) and Iran (should talks with the West over its nuclear program succeed), global oil prices could soften considerably.
There is also the possibility that the pace of shale drilling in places like Argentina, China and Russia, which have so far lagged North America, could take off, producing sizable new sources of oil and gas on the world market. As unlikely as it may seem, a price collapse, like the one that happened to domestically produced natural gas after 2008, is something every oil executive fears.
History has a way of throwing surprises at the energy patch. After the Arab oil embargoes raised oil prices in the 1970s, few foresaw the sudden collapse of oil prices just a few years later that drove Mexico and parts of Texas into an economic tailspin. Just a decade ago, companies spent tens of billions of dollars on natural gas import terminals that turned out to be useless when an unexpected boom in shale drilling led to a glut of domestic gas. Now those terminals are being converted for export at a cost of many billions of dollars more.
“There’s reason for optimism,” said Mark Finley, BP’s general manager for global energy markets and United States economics, speaking of North America’s oil and gas prospects, “but we cannot take it for granted.”
The big wild card is Mexico, whose energy fortunes have been tied to the United States ever since the late 1970s, when the country discovered great riches offshore. Over the next couple of decades, United States refiners retooled to process heavy oil from Mexico and Venezuela, but over the last decade or so production in both countries has plummeted. In the case of Mexico, oil exports to the United States have declined from 1.7 million barrels a day in 2006 to one million barrels a day in recent months.
The problem for Mexico is a sclerotic national oil company, Petróleos Mexicanos, commonly known as Pemex, which has had a monopoly on production and gasoline sales since the 1930s. Known more for corruption than expertise, the company has been forced for decades to hand over its revenue to the government while underinvesting in known oil and gas fields.
President Enrique Peña Nieto has proposed to end the monopoly by allowing foreign private oil companies to explore and produce in Mexico and share in the profits. Energy experts hope Mexico can finally exploit its riches in the deep waters of the Gulf of Mexico and in the oil- and gas-rich shale fields that cross from the United States border. Most experts say that the deep water gulf offers the most promising results over the next five to 10 years, since international oil companies have so much experience drilling in waters adjacent to Mexican waters, and Mexican wells could be hooked up to gulf pipelines that already exist.
The words coming out of Mexico are positive. “Mexican society wants change,” Pemex’s director general, Emilio Lozoya Austin, told energy executives in March at the IHS Energy Ceraweek conference in Houston. “There is room for any kind of company to come and invest.”
Citi Research estimated last year that Mexico could have 29 billion barrels of oil and gas reserves in the gulf, and an additional 13 billion barrels of recoverable oil shale reserves. Experts say production could increase by 25 percent by 2024 to nearly four million barrels a day, potentially vaulting Mexico to the fifth or sixth position among the biggest oil-producing countries.
The United States would stand to be the big beneficiary from a Mexican bonanza, both in terms of having an extraordinary new resource on its border and from added trade with a richer neighboring partner. But foreign oil executives remain cautious.
“The positive news in Mexico will help supplies in North America,” Ryan Lance, the ConocoPhillips chief executive, told a recent Rice University energy conference. But he expressed uncertainty about how effectively Mexico would change its energy laws to attract foreign investment, asking, “Are they going to put regulations in place that will make them competitive internationally?” He did not answer his own question.
Industry executives express many concerns. They wonder how thoroughly Pemex will share its rich trove of seismic data and whether they will have to take Pemex on as a partner on projects they would rather explore on their own or with other companies. They wonder if government regulators will enforce the new energy laws fairly and if the court system will fairly adjudicate disputes between oil companies, especially where Pemex is involved.
“You can go ahead and draft all the regulations that you wish, but if those regulations are not enforced, they are totally worthless,” said Jorge R. Piñon, former president of Amoco Latin America. “We need rule of law, governance and transparency.”
The rule of law has always been in short supply in Mexico, and American oil executives express concern about deploying money and manpower south of the border as long as there is so much drug gang violence.
“They are making some promising signals,” said Chris Faulkner, chief executive of Breitling Energy, an independent oil and gas producer, “but that doesn’t mean I’m rushing down there with an armored car.”
Only a decade ago Canada’s oil sands were little more than an afterthought in the energy world, with oil prices just beginning to drive high enough to make mining in the subarctic boreal forest economically viable. But while Mexico has been in decline as an oil producer in recent years, Canadian production has soared.
The biggest oil find in the world last year occurred in deep waters off the coast of Newfoundland. And the oil sands in Western Canada represent one of the top three oil reserves in the world, after Venezuela’s and Saudi Arabia’s. According to the Canadian Association of Petroleum Producers, Canada will increase its oil production from 3.2 million barrels a day in 2012 to 4.9 million barrels a day in 2020 to 6.7 million barrels a day in 2030.
But many energy executives and experts doubt that Canada will reach its full potential because of the costs of extracting the oil sands, high royalty and tax payments and environmental concerns. The latter have jeopardized Obama administration acceptance of the Keystone XL pipeline, which would connect the resource to United States refineries on the Gulf Coast.
The Keystone pipeline, if eventually approved, could bring 800,000 barrels a day south to the United States. But several other pipelines will need to be built if producers are going to scale up to industry targets, and pipeline companies face opposition in Canada as well as in the United States. Rail transport can replace some pipelines, but at a higher cost.
The lack of transport has stranded the oil sands from markets, making the oil cheaper to buy than almost any other crude on the continent. That might not be a major problem if the oil sands were less expensive to produce, but they tend to be more expensive, whether mined or steamed out of the ground.
“It’s tough to make a buck,” said Bill Maloney, executive vice president for North American exploration and production at Statoil, the Norwegian state oil company, a major producer in Canada. “Without infrastructure, why should that change?”
Executives say that the “easy barrels” have already been exploited and that more complex projects are driving up costs. There are shortages of skilled labor and competition for materials, problems made all the more complicated by the need to transport equipment and otherwise operate in a frigid sub-Arctic climate. Rising costs have already put a damper on development of natural gas export terminals in British Columbia.
Reaction in the industry to the challenges has been mixed. Capital spending in the oil sands is still rising this year, driven by investments from Exxon Mobil, Canadian Natural Resources, Suncor, ConocoPhillips and Cenovus Energy. But others are slowing their commitments. This February, Royal Dutch Shell halted work on its Pierre River mine in Alberta, which was to produce 200,000 barrels a day, and more project delays are considered probable.
Christophe de Margerie, chief executive of Total, the French oil giant and a major oil sands producer, said that only seven years ago most oil sands projects could break even with an oil price of $65 to $70, but higher taxes, royalties, regulations and labor costs had driven the break-even price to $90 to $95 a barrel — just a few dollars lower than the current price.
“The Alberta government increased taxes and royalties at the same time we were faced with this tremendous inflation in costs,” Mr. Margerie said. “And we told them, ’Careful, you are going to kill the beast even before it is alive.’ “
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The United States has been the jewel of global petroleum in recent years, increasing its oil production by more than 50 percent since 2008, and most energy analysts say they believe the good fortunes are sustainable for at least another decade. Natural gas production has been so plentiful that the price of the commodity has plunged, giving consumers and manufacturing industries a financial break, while gas import terminals are being turned around to export. The country has already replaced almost all imports of high-quality African oil with the booming production of the Texas and North Dakota shale oil fields.
The outlook for energy security would even be better if expectations of increasing Mexican and Canadian supplies came to pass. Talk of energy independence has become conventional wisdom, with the Energy Department reporting that the percentage of imported oil and petroleum products the United States consumes dropped to 40 percent in 2012, from 60 percent in 2005.
But the department warns that while the imported share should drop to 25 percent in 2016, it will rise again, to about 32 percent in 2040, as domestic production from shale fields begins to decline in 2022. Some oil executives say that the government is not optimistic enough and that technological improvements will continue to allow their companies to increase production at a profit. But few think that is a sure thing, and they list a number of concerns, most of which appear to be improbable — but not impossible.
There have already been problems. BP’s Deepwater Horizon rig disaster four years ago slowed development in the Gulf of Mexico, a critical component of domestic oil and gas production. Shell Oil’s attempts to explore in the Arctic waters off Alaska were undercut by a series of embarrassing accidents. Oil companies are fighting off challenges across Texas and the West by environmentalists opposed to fracking or trying to protect endangered species whose habitat includes oil fields.
In Colorado last year, three municipalities banned or suspended hydraulic fracturing in their communities, and environmentalists want to put broader restrictions on the statewide ballot in the fall. And in gas-rich Pennsylvania, the State Supreme Court recently ruled that local communities could limit drilling with zoning regulations.
One concern is that an oil glut could develop in the middle of the country that could depress prices so much it would be difficult for producers to justify sustaining production. Refineries on the Gulf of Mexico are not designed to process large quantities of “sweet” lighter oil from the new shale fields, and the oil could be left stranded — unless Washington reverses the current ban on most domestic oil exports, or refineries find it profitable enough to retool their plants to refine lighter oil.
Other concerns, outlined in a recent presentation by the consulting firm Wood Mackenzie, include the possibility of a global drop in oil prices; the failure of drilling technology to expand extraction from core shale areas to more marginal, peripheral parts of the fields; stiffer rail transport standards; and bans on hydraulic fracturing. The firm concluded that those risks were unlikely to undercut the United States boom, but oil executives still express some wariness.
“If there is more aggressive regulation, a ban on trade,” Mr. Finley, BP’s analyst, cautioned, “it’s just important to recognize and appreciate the range of factors that have led to this boom and not take them for granted.”
But the biggest concern is the oil price, which has a history of gyrating in unexpected ways. Just a couple of years after the natural gas drilling boom took off, the ensuing glut caused prices to drop so sharply from 2009 to 2012 that producers were forced to stop drilling in several shale fields until prices partly recovered this year.
“Industry took the rig count down, production down and investment down,” Mr. Maloney, the Statoil executive, recalled. “So why couldn’t the same thing happen with oil?”
Industry executives note that the typical oil shale well needs a price of roughly $50 a barrel to break even, given the expense of drilling horizontally and hydraulic fracturing.
“Bankers don’t want to see oil near $65,” said Mr. Faulkner, the chief executive of Breitling Energy, an active shale driller in Oklahoma and Texas. “Capital would dry up quickly like it did for gas.”
In September, Royal Dutch Shell announced its intention to sell 100,000 acres it had leased in the Eagle Ford shale field of South Texas because of out-of-control costs. An analyst at the Oxford Institute for Energy Studies has estimated asset write-downs approaching $35 billion in recent years among 15 of the main operators in the shale gas and oil fields, a tiny percentage of the total investment but a sign that shale field development is sensitive to market shifts and drilling disappointments.
What makes shale drilling particularly challenging is that wells produce most of their oil and gas in the first years of production, requiring more and more drilling in lower-quality zones of the fields.
“If W.T.I. prices come down hard,” said Lawrence J. Goldstein, a director of the Energy Policy Research Foundation, referring to West Texas Intermediate, the American benchmark crude, “investment will fall off, and you need constant investment for production just to stand still.” He added: “I am very optimistic, but only if we continue to invest.”
Article Author: Clifford Krauss, New York Times