Shale operators storing oil underground, waiting for price recovery


HOUSTON (Bloomberg) -- Oil companies, expecting prices to rebound after the biggest drop in six years, have come up with an alternative to storing their crude in tanks: They’re keeping it in the ground.

It’s a new twist on an old oil-trading technique, known as a contango storage play, in which a trader buys cheap crude in an oversupplied market and saves it to lock in profits at higher future prices. Operators, who have spent millions drilling holes through petroleum-rich shale rock are just waiting for prices to go up before turning on the spigot.

From North Dakota to Texas, there are more than 3,000 wells that have been drilled but not tapped, based on estimates from Wood Mackenzie and RBC Capital Markets. Waiting gives producers, such as Apache and EOG Resources, a better chance of receiving a higher price. It could also delay a recovery by attracting more supply, every time prices rise.

“Effectively, the rock is the storage,” Troy Cook, an analyst with the Energy Information Administration in Washington D.C., said by phone. “If you can afford to hang on to it, you could certainly choose to wait until the price goes up.”


The backlog of unfraced wells -- call it a fraclog -- is one reason that U.S. crude output is poised to climb, even as companies have idled more than a third of the rigs that were drilling for oil in October. About 85% of U.S. wells aren’t being completed right now, Continental Resources, Chief Executive Officer Harold Hamm said in a March 2 interview.

“If you shut off all drilling, and just went to pure completions, you’re still talking about a half a year of production growth,” Harold York, vice president of integrated energy research at consulting company Wood Mackenzie, said Thursday by phone.

In North Dakota, home to the prolific Bakken shale formation, the number of unfraced wells ballooned in November, as companies slowed crews to avoid releasing the initial flood of oil into a low-price environment, Lynn Helms, the state’s oil and gas director, said in January.

Apache, the third-largest leaseholder in the Permian basin, has deferred completions to trim costs, as well as try to bring its oil to market when prices are higher, Chief Executive Officer John Christmann said Feb. 12 on a conference call with investors.

Anadarko Petroleum expects to have as many as 440 uncompleted wells by the end of the year. EOG started the year with about 200 uncompleted wells and plans to let that inventory build in the first half of the year, CEO Bill Thomas said on a Feb. 25 conference call. Canadian Natural Resources Ltd., the largest heavy oil producer in Canada, has 161 uncompleted wells.

“Most of these wells, they’re high-rate wells that decline fairly rapidly, so it makes sense to hold off until prices stabilize,” Steve Laut, the company’s Calgary-based president, said in a phone interview March 5. “That’s where most of the value is going to be, in that first production period.”

Producers are pulling back after crude prices fell by more than half since June, as the rapid growth in output -- driven in large part by the U.S. shale drillers -- outpaced new demand from developing countries like China and India.

Delaying completions could also, paradoxically, extend the very oil slump companies are trying to wish away. If drillers respond to price increases by finishing more wells and adding new crude supply, it would delay the conditions needed for a rebound.

Adding Value

The U.S. produced 9.32 MMbopd of crude the week of Feb. 27, the highest level in weekly EIA data going back to 1983. Output will average 9.3 MMbopd this year, up 7.8% from 2014, the agency predicted Feb. 10. Oil inventories, at 444.4 MMbbl, are at the highest level since 1930.

Initial Production

A well should take no longer than three months to complete, depending on the time it takes to hire contractors, set up equipment and fracture, according to Charles Kemp, senior consultant at Dallas-based energy consulting company Baker & O’Brien Inc. James Cron, an independent petroleum engineer in Flaxton, North Dakota, pegged it at anywhere from one to three months.

Initial production from a new well ranges from 750 to 1,000 bopd, based on estimates compiled by Bloomberg Intelligence. That means the fraclog could represent as much as 3 MMbopd of new output, at least at the outset.

“It’s one of the reasons this is going to be an extended process,” said Mike Wittner, head of oilresearch at Societe Generale in New York. “The bigger the fraclog is, the more it’s going to slow the rebound. It means production is going to come back that much more quickly, and it’ll drag on any recovery.”

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