HOUSTON/NEW YORK (Reuters) - For the past three years, the boom in the U.S. shale oil industry has outstripped all expectations. Production surged far faster than any forecasts; drillers raced to secure space in new pipelines to get their crude to market.
Now, at the periphery, that may be changing - at least for a while.
News from two of the country’s less developed shale plays in Colorado and Ohio last week offer a reality check for the wave of euphoria that has washed across the industry. The stumbles mark a break from the past few years, when nearly every new project was an overnight success and output grew and grew.
On Thursday, Ohio, home to the Utica shale, finally released annual data on 2012 production that showed the state pumped less than 700,000 barrels of oil from its shale wells -- barely enough to fill a small oil tanker. North Dakota’s Bakken shale pumps more than that every day. Even state officials said it the result was “lower than initially estimated.”
The day before, NuStar Energy LP had said it would shelve a plan to reverse a pair of underused refined products pipelines to ship crude from Colorado’s Niobrara shale oil play to Texas. It failed, twice, to garner enough commitments from potential customers to justify investing in the conversion.
Neither development was a surprise to industry experts, and both were likely affected by extenuating circumstances.
A growing preference for rail shipments likely dimmed interest in long-term commitments to use NuStar’s pipeline. Ohio’s shale may yet offer up large volumes of liquid gas and condensate, if drillers can find new ways to coax it out.
Yet taken together they offered a sign that the flush of enthusiasm and rush of investment that piled into shale fields from one coast to the other has hit a curve.
While the basic technologies of hydraulic fracturing and horizontal drilling was enough to coax an unexpected gusher of oil from shale rock in many regions, these more challenging seams may require incremental innovation to unlock.
“This is all about technology,” said Sandy Fielden, an analyst at RBN Energy in Austin, Texas.
“The bottom line is that this stuff is down there, it’s just figuring out the sweet spot of where to get it and the right conditions to get it out.”
For now, few are questioning the notion that the booming Bakken and Eagle Ford and Permian Basin in Texas will keep growing, driving domestic oil production beyond its highest in two decades and shrinking America’s reliance on imports.
But the breakneck pace of the past three years was unlikely to last forever.
“The companies have established their acreage positions, they have established sweet spots, but there are still a number of really enormous challenges in understanding how to most efficient and effective ways to maximize production in the long run,” Pete Stark, senior research director at IHS.
“We’re in the start of the second inning in a nine-inning ball game as far as know-how.”
Niobrara and Utica are not the first shale plays to disappoint investors. Michigan’s Collingswood enjoyed a mini-boom for a few months in 2010; California’s huge Monterey shale has thwarted drillers for years.
Yet the scale of the let-down is remarkable.
Just two years ago, Chesapeake Energy’s former CEO Aubrey McClendon put the Utica on the map, proclaiming it could hold a $500-billion bounty and that it would be the “biggest thing to hit Ohio since the plow”. Oil companies including Total spent billions of dollars buying drilling rights. State geologists estimated that it could hold between 1.3 billion and 5.5 billion barrels of oil reserves, a vast sum.
“The Utica has failed so far to live up to its hype,” said Ed Morse, managing director of commodity research at Citigroup.
According to Reuters calculations, the average oil production per well per days the well was active, was 80 barrels per day - about one-tenth what it is in North Dakota.
Jonathan Garrett at Wood Mackenzie in Houston says the Utica may yet prove to be a successful natural gas development, with close proximity to the East Coast demand center. But with natural gas trading at a low $4 per million British thermal units for the foreseeable future, that is not the outcome drillers had hoped for a few years ago.
In Colorado, where oil production has risen by less than 100,000 bpd since serious development began on the Niobrara several years ago, NuStar’s biggest problem was likely competition -- from other pipelines and railways.
SemGroup Corp is building a 527-mile (848-km) crude pipeline to move oil from Colorado to the U.S. crude futures hub in Cushing, Oklahoma, by the first half of 2014, and already has twice expanded its capacity. Plains All American Pipeline LP is expanding and building new rail capacity in Colorado to haul oil out by train later this year.
Those projects combined will be able to move 230,000 bpd, on top of 30,000 to 40,000 bpd of Niobrara crude that already goes to Suncor Energy’s 93,000 bpd refinery in Commerce City, Colorado.
“We’re at a point now where we’re going to see some of these lower-quality projects weeded out,” said Bradley Olsen, director of midstream research at Tudor Pickering Holt & Co in Houston.
That surpasses current output in the play’s so-called sweet spots - the Denver-Julesburg (DJ) and Powder River Basin (PRB) - which reached 170,000 bpd as of January this year, according to energy consultancy Bentek. The consultancy projects output to rise to 235,000 bpd by the end of 2013.
The option to ship crude by rail is attractive to oil producers who are uncertain how long their wells may keep pumping out crude. Rail terminals are less expensive to build, can start up faster and do not require long-term contracts sought to justify the cost of building or converting pipelines.
Refiners also like being able to pick up the cheapest oil at the moment from one of dozens of rail terminals rather than be tied to a certain type of crude for five or 10 years.
“It could come from Niobrara. It could come from Bakken. It could come from West Texas. And that’s one of the nice things about rail systems -- there’s flexibility to move those cars around to market to provide the greatest opportunities,” Alon Energy USA Chief Executive Paul Eisman said this month.
Reporting by Kristen Hays; Editing by Marguerita Choy