The Fuse

Bakken Production Erodes as Industry Looks Elsewhere

by Nick Cunningham | May 03, 2021

North Dakota’s Bakken shale played a major role in the growth of oil and gas production, particularly in the 2010s, prior to the explosive growth of the Permian.

But the Bakken has struggled with high costs and stagnant production. While oil prices have climbed and drilling activity has rebounded in the Permian to some extent, the Bakken does not appear situated for a similar recovery.

Bakken production remains down

North Dakota was hit hard from the market meltdown last year, with several hundred thousand barrels per day immediately shut in following the slump in prices. “Every operator was shutting in everything,” North Dakota Director of Mineral Resources Lynn Helms said last year. “We just saw a tremendous decline.” Production plunged by roughly 30 percent.

“Every operator was shutting in everything.”

Some of that production came back online after the initial (and most severe) lockdowns subsided. But not only has output remained below pre-pandemic levels, but production began sliding again in recent months. According to the EIA’s April Drilling Productivity Report, the Bakken is expected to lose another 12,000 barrels per day in May, from April’s levels. That puts production at about 1.1 million barrels per day (Mbd), down from a 2019 high of 1.5 Mbd.

The rig count in the Permian has steadily climbed since hitting a low point last August at 117, rebounding to 226 as of April 23. But the Williston basin, which includes the Bakken, has gone from 9 to 15 rigs over the same time period. That is down from over 50 rigs on the eve of the pandemic. Drillers are just not coming back. As the shale industry consolidates, the Permian basin is capturing a larger and larger share of capital and activity, leaving other shale formations in the lurch.

Already, some major companies are packing up and leaving. Norway’s Equinor just completed the sale of its Bakken assets for $900 million, after paying $4.7 billion for them several years ago. “We should not have made these investments,” Equinor Chief Executive Officer Anders Opedal told Bloomberg in February. The high price tag paid for them nearly a decade ago was made because “higher oil prices were expected in the future, a high consumption of oil was expected.”

Opedal added: “The Bakken does not compete…We have chosen to sell the Bakken to reinvest that money into other parts of our portfolio, where we get a higher return.”

The outlook is not entirely negative. Hess says that it might add another rig back into the field in North Dakota if oil prices remain relatively high. Continental Resources also said that it would step up activity in the Bakken.

Bakken sees other headwinds

The Bakken is an environmental disaster, with a worse track record than other U.S. shale formations. According to a recent report from Rystad Energy, Scope 1 emissions intensity (only looking at upstream operations) shows that the Bakken emits 20.7 kilograms of CO2 per barrel of oil equivalent, roughly three times as much as a comparable unit from Appalachia, and twice that of the Permian.

A decade ago, North Dakota was flaring 36 percent of the gas it produced.

The culprit is flaring. A decade ago, at its worst, North Dakota was flaring 36 percent of the gas it produced. That recently declined to 6 percent, which is a new low, but is still dramatically higher than the U.S. average of 1.3 percent.

In fact, North Dakota has flared and vented almost as much as gas in absolute terms as the Permian basin, despite producing only a quarter of what the Permian produces.

As climate concerns continues to intensify, which will affect the access and cost of capital, the Bakken could see increased scrutiny.

Meanwhile, another threat looms – the case of the Dakota Access pipeline is not over. The Biden administration declined to take a position on the project in a court appearance on April 9, allowing it to continue to operate. The pipeline’s permit was vacated last year by the court, even as the project has remained online despite lacking that approval.

The Army Corps could shut it down, but has declined so far. On April 26, the federal judge went back to the Army Corps, requesting an update on when the Corps plans on finishing an environmental impact statement. He gave the government until May 3, after which the judge himself could rule on whether or not the pipeline should be shut down.

Either way, the legal saga will probably drag on. But if Dakota Access loses consecutive rulings, potentially up to the Supreme Court, the pipeline could be shut down.

If that were to occur, the 570,000 barrels per day (b/d) that moves on the four-year-old pipeline would have to find alternatives routes. That means shipping by rail, which adds costs and will likely push regional prices down.

But because production itself is down, the loss of Dakota Access may not cause severe bottlenecks. “The industry had a lot of time to consider alternate routes,” Colton Bean, midstream analyst for Tudor, Pickering, Holt & Co., told S&P Global Platts in early April. “Is it going to be a disaster scenario? No. It’s more of a cap on growth than a big impact on existing production.”

Platts says that roughly 200,000 b/d could find a home on existing pipelines, another 200,000 b/d could move by rail, and another 100,000 b/d could move by truck.

The shutdown of the pipeline could add costs, another blow for a shale basin that is already struggling. Platts says the loss of the pipeline would result in a $7-per-barrel discount for Bakken crude relative to WTI at Cushing.

In the short run, with rig counts so low, production could continue to erode slowly, with or without Dakota Access.

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