Pending Dakota Access oil pipe shutdown could mean extended well shut-ins

Houston — A recent US appeals court judge's order to shut the 570,000 b/d Dakota Access oil pipeline for a year starting next month could result in extended curtailments of shut-in wells in the North Dakota/Montana play, analysts said July 7.

A lack of adequate pipeline takeaway, combined with the need to scramble other modes of oil transportation, most likely rail car availability and crews, may result in keeping Bakken wells idled in May and June due to depressed oil demand and low crude prices from the coronavirus pandemic, hibernating a little longer, investment bank UBS analyst Shneur Gershuni said in an investor note.

"Shutting down the DAPL pipeline ... will increase the cost of getting Bakken production to markets as DAPL was one of the lowest, if not the lowest, cost avenues to market," Gershuni said. "The lower netback from higher transportation costs to producers ... could stall or slow the return of production ramp for the basin" in the coming months.

Analysts say upstream producers are looking at rail to the East Coast as an alternative for both existing and shut-in Bakken production, but that could add substantially to transportation costs.

"Some operators are saying the cost is $10/b-$14/b for rail versus $4/b-5/b for pipeline," Biju Perincheril, an analyst for Susquehanna Financial Group, said. "That would put pressure on in-basin differentials and will make the economics very challenging at current WTI prices."

"So restoration of Bakken curtailments could be delayed if DAPL is shut down," Perincheril said.

Rail can accommodate DAPL volumes

Crude by rail out of the Bakken averaged around 300,000 b/d in the last six months, according to Jean Ann Salisbury of researcher firm Bernstein. But analysts said there is room to accommodate substantially more than that, likely the full amount of DAPL volumes.

DAPL operator Energy Transfer has pledged to appeal the shutdown order by US District Court for the District of Columbia Judge James Boasberg of Gulf Coast-linked pipeline capacity from the Bakken Shale basin. The pipeline is slated to shut down Aug. 5.

Oil production in North Dakota – from which more than 95% of the basin's crude output comes – averaged about 925,000-970,000 b/d in mid-June versus about 1.45 million b/d pre-pandemic owing to the pandemic-related output shut-ins.

Operators continue to bring back US production shut-in from the Bakken and other plays during April through June as WTI prices this month have risen just above $40/b, although the forward curve for WTI is only predicting levels around the mid-$41s/b a year from now.

But that is higher than the teens, $20s/b and $30/bs where WTI had plunged in April through June. Still, the added $5/b-$10//b cost of rail to get Bakken crude to markets, may tamp down enthusiasm for bringing back shut-in production, analysts said. The Bakken's internal rate of return in June was minimal, at about 10.5%.

The court order to shut down DAPL pipeline may create still other "material headwinds" for Bakken oil output in the near and medium term, investment bank Tudor Pickering Holt said.

"If the appeal process is unsuccessful, we would expect a number of producers with multi-basin exposure to shut down drilling and completion[s] heading into Q4 2020 and focus on shifting capital towards the Midcontinent, Permian Basin, and Eagle Ford for next year," TPH said in a July 7 investor note.

Could shift capital to other basins

The Bakken has been the slowest to return volumes to service of the major oil basins, the bank said. And if basin crude price differentials were to widen toward rail economics and the court order is not changed, "we would expect upstream operators with multi-basin assets to shift capital allocation toward the Eagle Ford, Midcontinent, and Permian [Basin]," TPH said in a July 7 investor note.

The Eagle Ford Shale is sited in South Texas, the Midcontinent plays are generally in Oklahoma and the Permian Basin is in West Texas/New Mexico.

The DAPL shutdown may crimp some producers more than others, since the rig count has severely plummeted in the last four months – just 10 rigs were operating in the Bakken for the week ended July 1, from 53 in mid-March.

But "some upstream operators were planning to get back to work in second-half 2020, depending [upon] this highly capital efficient resource to stabilize crude declines in 2021," TPH added.

Another consequence of delayed output restoration in the Bakken is that US associated gas volumes may stand to increase, as the Bakken tends to be one of the lower gas/oil ratio domestic plays, while areas like the SCOOP/STACK, Eagle Ford, and Delaware basin can carry a healthy amount of gas with each oil well.

Producers with the highest percentage of oil volumes coming from the Bakken include Continental Resources, ConocoPhillips, Marathon Oil, Oasis Petroleum and WPX Energy, analysts say.

While Bakken-WTI differentials widened "somewhat" on July 7, a significant amount of Bakken production remains shut-in and the current court appeals process means the market may not fully reflect a more "draconian" outcome until early August, TPH added.

"Combined with alternative pipeline capacity, readily available basin infrastructure falls short of existing production and would require ramping rail volumes or a resurgence of northbound flows on Enbridge's Line 26 (capacity roughly 145,000 b/d) which competes with existing ex-Hardisty Mainline volumes," TPH said.

So in some cases, "the most viable option to manage constrained infrastructure would likely be a continuation of production curtailments," it said.