U.S. shale boom seen casting long shadow over global energy landscape

HOUSTON -- The United States is in the early stages of a boom in domestic oil production, sparked by the same innovations in drilling technologies that tapped shale to spur a 20 percent spike in natural gas output.

Shale oil production is already booming in western North Dakota where light crude production from the Bakken Shale formation is transforming the state economy. And there are signs it will spread in Texas, eastern Ohio and parts of northeastern Colorado and even Michigan. In all, experts say, 20 U.S. shale formations could be tapped for crude.

As hundreds of thousands of domestic barrels of crude supplant imports, government experts and financial analysts are trying to comprehend the implications of shale oil on tax receipts, the value of the dollar and the trade deficit. But even the industry itself is unsure of how big the boom could be.

"When you find out the answer to that question, you give me a call," joked Jon Pepper, vice president of corporate communications at Hess Corp.

The United States last year pumped 5.5 million barrels a day of crude oil and imported 9.2 million barrels a day, giving imports roughly 63 percent of market share compared to 37 percent for domestic production, according to the federal Energy Information Administration.


But the mix could look substantially different by year's end. IHS Cambridge Energy Research Associates (IHS CERA) estimates that crude imports will fall to 47 percent of the U.S. energy mix, replaced by new domestic output and ethanol. And Daniel Yergin, the firm's chairman, predicts the United States could be pumping almost 3 million barrels of crude per day by 2020 from tight shale formations -- depending on regulators and market conditions (Greenwire, Nov. 1).

A huge question for energy experts is how shale oil might be priced on the global market. The rush of Bakken oil into the New York Mercantile Exchange's pricing point at Cushing, Okla., has pushed prices of benchmark West Texas Intermediate (WTI) crude to as much as $30 below Europe's Brent crude benchmark in recent months.

"Going back, we were awash in oil, or so it seemed," said Pete Donovan of Vantage Trading. The introduction of shale oil, he said, "has taken some of that fear factor out of the domestic barrel, where that fear factor is a little more prevalent in the Brent market specifically."

In other words, traders know that while Cushing is flush with oil, North Sea Brent crude production is in decline.

The Bakken oil push seemed to echo shale gas' effect on the global natural gas market -- effectively disconnecting North American gas prices from the rest of the world. Energy market specialists doubt that will happen to crude, but they admit the WTI-Brent gap has raised big questions (Greenwire, Oct. 17).

The shift in crude markets could threaten WTI's role as the nation's crude pricing benchmark, say analysts at Platts, an energy and metals market information and pricing company. Talk is growing of a "Houston blend" crude supplanting WTI as the means to track daily fluctuations in the price of a barrel of crude.

Environmentalists, meanwhile, are worried that a tight-oil boom might lower petroleum prices and take the steam out of a U.S. push to get drivers into electric vehicles. What happens will depend on demand trends in emerging economies since both government and industry experts agree that U.S. crude demand is likely to stay flat due to shifting demographics and work patterns and the rising efficiency of automobiles.

"For us, the bottom line is it's a fossil fuel and it generates a lot of pollution," said Amy Mall, who tracks the shale gas and oil industries for the Natural Resources Defense Council (NRDC). "Even if there is more of it than we used to think there is, it's still going to run out and it's still going to create a lot of environmental problems."

'Looking for numbers'

Bullish estimates see Bakken production reaching 500,000 barrels of crude a day by the end of the year. Some forecasts see production going to 1.2 million barrels a day by 2015, a jump of almost 18 percent in total domestic crude production over EIA's 2010 numbers -- and that is from just one field.

The Bakken is the big story today, but producers at South Texas' Eagle Ford Shale are catching up fast. Eagle Ford is projected to reach outputs of 200,000 barrels a day by year's end, likely growing to 420,000 barrels a day by 2015.

Put those estimates together, and it appears that domestic production could grow by a little over 22 percent by 2015 over EIA's 2010 figures, from the Eagle Ford and Bakken plays. That is without possible output in Colorado's share of the Niobrara formation or from the Utica Shale in Ohio, and it does not take into account new finds in the deep waters of the Gulf of Mexico where drilling is restarting after the 2010 Deepwater Horizon spill.

For instance, Hess recently inked a $600 million deal with Consol Energy Inc. for access to shale acreage in Ohio. The company does not know yet how much oil access it bought, Hess spokesman Pepper said, but the company believes it to be substantial. Other companies are spending billions of dollars more buying up stakes in future shale plays.

In fact, the booming Bakken could be a factor in the industry's push to build the Keystone XL pipeline to carry Canadian heavy bitumen liquids from Alberta's oil sands region to refineries in the Gulf Coast.

Alan Brady, IHS's head of refining research, said supplies from North Dakota and Ohio could eliminate the demand for hard-to-refine diluted bitumen in the Midwest, leaving only Houston and the Gulf Coast as customers.

"The mid-continent, the Midwest, that's the primary market right now for the oil sands material," Brady said. "But our analysis shows that if you got all this light, sweet crude coming out of the Bakken and other parts of the region, it's kind of hard to justify an investment to your refinery to upgrade it."

Trade groups, more cautious in production estimates, say they have no idea how much will actually come online or how quickly. Neither the American Petroleum Institute (API) nor the Independent Petroleum Association of America (IPAA) would say how many new wells they expect will be drilled in these new fields in the coming years, but both agree it will be substantial. Last year, more than half of all new oil and gas wells drilled in the world were in the United States as the domestic drill rate grew by almost 30 percent over 2009 levels.

"We're still looking for numbers on this question," IPAA spokesman Jeff Eshelman said. "There should be a lot more drilling in the next five years due to increased reserve projections. Ohio and New York, for example, have yet to be pervasively drilled, and industry activity is ramping up, buying land, etc."

Wall Street's bold predictions

Major oil producing Western states, excluding Texas, will probably pump much more crude than they do today, the trade group Western Energy Alliance (WEA) says.

"We are projecting 1.3 million barrels of oil per day by 2020 from the six producing Western states, although we don't include the Permian Basin in eastern New Mexico," said Kathleen Sgamma, WEA's director of government and public affairs. "If we redo those projections in a couple of years we would expect these figures to go up as the Niobrara matures."

WEA is probably underestimating the potential, she said. But the group wants to be cautious as it argues that restrictions on drilling tight oil formations on federal land could diminish industry hopes of greater activity.

"The Bakken wouldn't be the Bakken -- the big oil boom it is today -- if it were on public land, there's no question in my mind," Sgamma said. "We're lucky that the Bakken, and the Niobrara for the most part, are on private and state land."

Many on Wall Street are not as conservative in their production estimates.

Standard & Poor's energy analyst Lawrence Wilkinson told reporters earlier this year that U.S. crude production will likely expand by 20 percent just from drilling in the Bakken. Coupled with output from other tight geologic formations and the Gulf of Mexico, Big Oil seems on track to meeting or beating President Obama's goal of slashing oil imports by a third over a decade.

And Goldman Sachs raised eyebrows when it recently declared that the United States could likely become again the world's top crude producer by 2017, edging perennial front-runners Russia and Saudi Arabia.

The United States won't rid itself of the need to import crude oil entirely, most agree, but industry insiders say it is conceivable the country could one day supply all its needs domestically and from its neighbors in the Western Hemisphere. In a recent analysis, the consulting firm Wood Mackenzie said it is even possible the United States could one day attain all its crude oil needs from just North America.

High-end estimates suggest U.S. crude production could increase by as much as a third in the next eight to 10 years, slashing the trade deficit by as much as $85.7 billion, based on 2010 prices and trade figures, about equal to the nation's advanced technology trade deficit.

Boosting U.S. production by 30 percent "is extremely doable," said Greg Salerno, marketing director at the energy information firm Hart Energy.


The shale oil bounty is due to technological breakthroughs in the oil and gas industry.

Most credit George Mitchell, the billionaire who founded Mitchell Energy in 1946 and struck it rich in Texas' natural gas fields.

Starting in the late 1980s, Mitchell devoted 12 years to squeezing more gas out of a seemingly spent well in the Barnett Shale of North Texas. He eventually succeeded through perfecting approaches to hydraulic fracturing, a technique that industry experts say dates to the 1940s but has become much more prominent in recent years.

As Mitchell spent millions of dollars perfecting hydraulic fracturing, horizontal drilling technology improved in the offshore oil and gas industry, thanks to advances in locating and directing drill bits. Mitchell eventually sold out to Devon Energy in 2001, which has been benefiting greatly since -- this week Devon reported its liquids production expanded by 17 percent in the third quarter.

Through hydraulic fracturing, or fracking, a mixture of 98 percent water and other chemical lubricants, often many millions of gallons, is injected at high pressure deep underground. The water mix is used both to break apart rock formations, but also to carry sand "proppant" to keep it open. Geologic pressure wants to immediately close cracks once the pumps are shut off, so sand particles keep them open, allowing the hydrocarbon molecules to flow around them.

Mitchell fracked his first exploration well three times with positive results, enticing more gas out of the well each time than was originally thought possible. After Devon took over, it tried a fourth time using of a more lightweight proppant, which can be carried deeper and farther into the fissures. That led to gas output exceeding in five years what Mitchell managed to get out in the prior 12 years from three different fracking experiments.

By 2003 both fracking and horizontal drilling were largely ready for mainstream use. It did not take long for the industry to marry the two technologies.

Production from fracked oil and gas wells decline sooner and further than conventional wells, officials admit. But conventional drilling and pumping has only managed to extract somewhere between 25 and 35 percent of the oil typically found in underground formations, though some operators have done better. Fracking is now opening up the rest to the industry.

And determining the precise lifetime of any well is difficult, because companies can keep coming back to it to restimulate the bore hole, fracking again or even trying new approaches, like injecting carbon dioxide or steam, techniques that are extending the lifespan of Texas's famous oil patch in Permian Basin around Odessa and Midland.

"How long is a piece of string?" said Salerno at Hart Energy. "A lot of it depends on the formation, a lot of it depends on the completion technique, and a lot of it depends on the placement of the well bore. There are a lot of variables here."

U.S. as oil exporter?

The thing most holding back producers in the United States these days is infrastructure for transporting crude.

ConocoPhillips executives, who aim to boost that company's Bakken, Eagle Ford and Permian Basin output from 100,000 barrels of oil equivalent (70 percent crude oil) to 250,000 barrels a day by 2013, complained mostly of a lack of trucking and rail capacity to get the oil out in a recent call with analysts.

Companies are trying to alleviate this. Last week Enbridge Energy Partners announced a $90 million "Bakken Access Plan" to expand storage and transport capacity to help move 100,000 more barrels per day out of North Dakota.

Some are even speculating the United States could export crude, just as natural gas producers are laying plans for LNG export trains to sell shale gas to Europe.

That is a tall order though, Platts analyst Esa Ramasamy warns. At a recent forum in New York City, Ramasamy noted that exporting oil from anywhere in the United States except Alaska is virtually illegal today -- only 50,000 barrels per day can be sold and only after providing the Commerce Department with a compelling reason why no customers can be found in the United States, still the world's most voracious consumer of crude.

It would take federal legislation to change that. But that is not an entirely inconceivable scenario, he said, especially as Eagle Ford production ramps up, and so close to major Gulf Coast ports.

"The U.S. is becoming a large exporter of gasoline," Ramasamy said. "Pressure is mounting to get [crude] out of the U.S."

Of more immediate concern to oil and gas companies and environmentalists alike is the battle over how to regulate the booming industry.

WEA's Sgamma said the status quo is just fine.

"Oil and gas has been regulated by the states for almost a century now," Sgamma argued. "The federal government does not have that experience."

But NRDC's Mall said the industry is already growing too fast in North Dakota for regulators to catch up. Evidence from there and the Eagle Ford, where Texas officials have already assigned a special task force just to monitor those developments, is proof that the federal government needs to play a much greater role in protecting lands and groundwater from the inevitable accidents and spills that will come in this new oil rush, she said.

"The states clearly have not done a good job, that's why we have reports of contamination from natural gas production around the country, and we could very well see those types of complaints from oil also," Mall said. "Even the North Dakota regulators are on the record as saying that they can't keep up with it, that there are spills that they just can't attend to."

Still, much of this anticipated drilling and production may never come to pass, Salerno cautioned. Though the billions of dollars being spent on land and leases suggest very few expect it, the domestic oil industry has experienced booms and busts before, and some global calamity or regulatory backlash could pull the current momentum to a screeching halt.

"It's always been a cyclical industry," Salerno said.

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