In recent years, North Dakota’s Bakken formation was synonymous with boom times. Crude production grew 10 times over, unemployment fell to a national low, and the state budget more than doubled as North Dakota’s coffers grew fat on severance and sales tax income.
But with crude prices down more than 70 percent at their recent bottom, some of the drillers who fueled the boom are pulling back from the Bakken.
Several exploration and production companies are no longer completing wells in North Dakota and are now turning to more efficient assets in other states. Analysts say the decision comes down to a number of factors, from the geology of the Bakken to incremental costs that producers once overlooked but can no longer ignore.
Continental Resources, the company that put the Bakken on the map, said last month that it had stopped completing wells in the formation, and Whiting Petroleum announced it would stop fracking there by April. Last October, Occidental Petroleum sold all of its Bakken assets to private equity firm Lime Rock Resources.
Hydraulic fracturing, or fracking, is the process of breaking up shale rocks by bombarding them with water, minerals and chemicals at high pressure. The process can account for up to two-thirds of the cost of a well.
To be sure, it has long been drillers’ prerogative to look beyond their existing acreage, said David Tameron, analyst at Wells Fargo Securities. “It’s in their DNA. They have to look at greener pastures elsewhere, even if they’re sitting on the best black soil,” he told CNBC.
But he said there is one overriding concern about the Bakken: that the formation’s core areas are being drilled into terminal decline as producers seek to squeeze every last ounce of efficiency from their assets.
Indeed, the drilling and fracking that is continuing in the Bakken is largely concentrated in three counties in the northwest corner of North Dakota, IHS data shows.
This “severe high grading” impacts employment because drillers are preventing production from falling off dramatically despite completing fewer wells, said IHS analyst Raoul LeBlanc.
For crews to return to Bakken oilfields in significant numbers, oil prices need to rebound to the level at which it becomes economic to produce marginal wells, he said. Either that, or drillers need to be forced to plumb noncore acreage as their best wells dry up.
“When people say we’re going to be drilling here for decades, that may be true, but we’re not going to be drilling great stuff for decades,” he said.
Crude must fetch $50 to $60 a barrel in order for drillers to ramp up Bakken production, said North Dakota budget analyst Allen Knudson, citing the state’s consultations with advisors.
Exploration and production companies in the Bakken, like elsewhere in the United States, have built up a large inventory of drilled but uncompleted wells. These DUCs are essentially half-finished wells that can be fracked once prices recover enough to warrant bringing them online.
In the meantime, drillers face hurdles in the Bakken that were once negligible, but now take a bite out of thin margins. For one, the tax regime in North Dakota is more onerous than in Texas, analysts said.
The Bakken is also a relatively remote and young play, so producers face higher costs of bringing oil to market than drillers in Texas, which benefits from its proximity to Gulf refineries and expansive infrastructure. Much Bakken crude is still shipped by rail.
The cost of getting Bakken crude to market varies depending on the destination, but the differential is roughly $8 a barrel.
“It was kind of an afterthought at $90 a barrel. Whether it was 10 or 12 bucks, big deal,” Brian Velie, analyst at Capital One Securities told CNBC. “Those eight dollars are far more important than they were a year ago.”
RBC Capital Markets warned in a note this week that competition from international Brent brought in by boat and a lack of storage space could essentially trap Bakken barrels in the Midwest.
More productive, but not most productive
Bakken producers have wrung more production from their rigs in recent years, but drillers in Texas’ Permian and Eagle Ford formations have outpaced those gains, CNBC analysis of Energy Information Administration data shows.
In the Permian, drillers typically have five or six different zones where the lateral leg of a horizontal drill can land. Bakken formations usually have just two or three landing zones. That means Permian producers get more bites at the apple, making their assets potentially more efficient.
WPX Energy is one driller that appears to be betting on its assets beyond the Bakken, said Simmons & Co. analyst Pearce Hammond.
WPX entered the Permian Basin last year through its $2.7 billion acquisition of privately held RKI Exploration & Production. Soon after, WPI announced it would increase its rig count in the Permian from four to six. Meanwhile, it plans to operate just one rig in the North Dakota’s Fort Berthold Indian Reservation this year.
“The Permian is going to be taking on increased importance for WPX, but we still very much like the Williston,” said WPX communications manager Kelly Swan, referring to the larger basin that contains the Bakken.
For 2016, WPX plans to spend $175 million to $225 million in the Permian, $100 million to $125 million in the Bakken, and $75 million to $90 million in New Mexico’s San Juan Basin. The spending plan reflects WPX’s preference for a diverse portfolio, Swan said.
Hammond said he also expects Continental Resources to gravitate toward more economic wells in its Anadarko Basin acreage in