After 25 Years, E&Ps Sustain Bakken Oil’s Long Plateau

Chris

Mathews

Hart Energy

Tue, 06/03/2025 - 06:00 PM

It was 25 years ago, in a nondescript corner of eastern Montana, that wildcatters unlocked the recipe that would turn the U.S. into the world’s top oil producer.

On May 26, 2000, the first stimulated horizontal oil well was landed targeting the middle Bakken Formation in Montana’s Elm Coulee Field.

The independent-fueled “shale revolution” that followed shocked the OPEC cartel, the oil supermajors, Wall Street experts—and even the independents themselves.

But in the mid-1990s, producing shale oil wasn’t yet economic.

At that point, U.S. oil production had been in decline for nearly two decades. By 2000, the nation’s production had declined to levels not seen since the 1950s, before the post-World War II boom in domestic output, according to U.S. Energy Information Administration (EIA) data.

Conventional onshore opportunities were largely considered exhausted. The big majors had picked up and were exploring offshore and internationally. It was a commonly held belief that the U.S. would be the world’s largest energy importer for the foreseeable future.

Still, the independents persisted.

Producers like Burlington Resources and Continental Resources had been landing horizontals in Montana and North Dakota. The two companies were the leading producers in the Cedar Hills Field, mainly targeting the thin, tight Red River B dolomite.

Harold Hamm, Continental’s founder and chairman, told Oil and Gas Investor that the Red River B reservoir was only around 14 ft thick.

“But it proved that, in those thin-bed reservoirs, horizontal drilling worked,” Hamm said. “We charged our geological team here and said, ‘Guys, go find the next one.’”

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Born in the Bakken

Burning tree state

Until 2000, the Bakken Formation was little more than a geological afterthought, a last resort, a “bailout zone” for producers trying to salvage sunk costs when deeper targets came up dry.

The shale was too tight, the technology too limited and the economics too shaky. Mitchell Energy & Development’s eventual breakthrough in shale was promising for gas development; oil was a different story.

“I think T. Boone Pickens had made a statement that getting natural gas from shale was one thing, but getting oil from shale was quite another,” Hamm said.

But in 2000, one well in Richland County, Montana, quietly rewrote the story.

Burning Tree State 36-2H, operated by Lyco Energy and completed by Halliburton, was the first fracked horizontal well landed in the middle Bakken. Its IP rate—196 bbl from a modest 1,700-ft lateral—might seem minor by today’s standards. At the time, it was revolutionary.

Williston producers had been drilling into the Bakken, and straight through it for deeper targets, for decades. Burlington Resources, for example, targeted the upper Bakken Shale without fracking. But the results were inconsistent.

The Bakken Formation was essentially declared dead in 1996 by the North Dakota Geological Survey.

That same year, in Montana’s Mustang Field, prospector Dick Findley and operator Bob Robinson were drilling to test the deeper Nisku bench. When it failed to produce, they bailed out in the Bakken to recoup what they could, as the story goes in "The American Shales” by Nissa Darbonne, Hart Energy’s executive editor-at-large.

The well, Albin FLB 2-33, ended up landing in the middle Bakken zone because of shows seen on a mud log, according to the North Dakota Geologic Survey. After being completed with a water-sand frac, the well flowed; Findley and Robinson made their money back.

But Albin kept flowing and flowing steadily for months. The two recalled wondering: Just how big could the middle Bakken be? The prospect needed a name, so Findley called it “Sleeping Giant.”

Over the next few years, the two wildcatters, joined by Lyco Corp. founder Bobby Lyle, quietly reentered 10 legacy verticals across the 40-mile trend. The data confirmed what they suspected: the middle Bakken could be tapped across a wide swath of eastern Montana, but it would need horizontal wells and fracs.

In need of capital, Lyle reached out to Halliburton, then chaired by future U.S. Vice President Dick Cheney.

Halliburton agreed to back one test well. After waiting for prices to recover, the team moved forward in Richland County in 2000.

Engineers aimed the bit at a 10- to 15-ft-thick sweet spot just beneath the upper Bakken Shale. The first lateral was cut short due to torque concerns, but even before it was fracked, the well began to flow.

Then, the frac job was completed. The upper Bakken Shale acted as a natural barrier, with fractures propagating into the dolomite and stopping clean at the shale boundary.

History had been made, but healthy skepticism remained. Neighbors like Headington Oil and Continental Resources watched closely.

In 2001, Lyco drilled nine more Bakken horizontals, each a success. It went 10-for-10 again in 2002.

Soon, Continental and Headington joined in. By 2004, the Elm Coulee Field, as it was named, had rapidly climbed to become the fifth-largest oil-producing field in Montana.

Hamm said he and Continental started applying techniques from Elm Coulee into North Dakota around 2003.

But Burning Tree State was the spark. The Bakken, once written off, was now the cornerstone of U.S. shale oil, and it started with one modest lateral in Montana.

Modern Bakken

After a quarter-century of continuous development, the Bakken continues to produce.

It’s not the growth engine it once was. The Eagle Ford and the Permian Basin have competed for capital since the Bakken horizontal boom started.

But the Bakken continues to play a key role in Lower 48 oil output. It ranked second in onshore oil output behind the Permian in 2024, averaging 1.23 MMbbl/d.

North Dakota has produced more than 6.6 Bbbl of crude since 1981, according to EIA data. Production has averaged over 1 MMbbl/d since 2014.

Montana has produced just over 1 Bbbl over that span.

North Dakota Montana Field Production Chart — *(Source: U.S. Energy Information Administration)*

But there are valid questions about the Bakken’s longevity. Bakken oil production is forecast to decline to 1.21 MMbbl/d in 2025 and to 1.17 MMbbl/d in 2026, per EIA data.

Continental’s Hamm agreed that the Bakken isn’t the driver of production growth it once was.

“If you look at the Bakken, it looks pretty flat,” he told Hart Energy after Election Day in November. “Maybe flat to down.”

Experts and operators say the modern Bakken story is about drilling efficiencies, inventory preservation, longer laterals and recompletions on antiquated wells.

4-mile Bakken wells

Operators have come a long way since Burning Tree’s 1,700-ft lateral. At least three Williston producers have reported drilling 4-mile laterals in North Dakota this year.

Public E&Ps Hess Corp. and Chord Energy told investors they’d each drilled 4-mile Bakken wells in February.

Hess claimed it drilled the first 4-milers in the Bakken. The two 4-mile wells run parallel, north to south, in the Beaver Lodge Field northeast of Williston, North Dakota. Nabors Industries operated the drilling rig.

Hess also drilled a 2-mile observation well outfitted with fiber and pressure gauges to study recoveries and depletion from the wells over time.

Chord Energy is going longer than anyone in the Bakken.

Chord, formed through the 2022 merger of Whiting Petroleum and Oasis Petroleum, turned its first 4-mile Bakken well to sales in the first quarter.

The well exceeded a total depth (TD) of 30,400 ft., Chord COO Darrin Henke told analysts.

The original 4-mile project was successful on several fronts, including coming in $1 million below budget, Chord CEO Danny Brown said during the company’s first-quarter earnings call.

Danny Brown Chord Energy — Danny Brown, CEO, Chord Energy

“Production over the first couple of months for the well has been encouraging, but we really need to get past the flat period and initial decline to get a better sense of the ultimate productivity and recovery,” Brown said.

Chord’s 4-mile wells are expected to recover 90% to 100% more EUR for 40% to 60% more capital.

“On a breakeven basis, 4-mile laterals are expected to be anywhere from [$8/bbl to $12/bbl] lower than 2-mile wells,” Henke said.

Chord drilled two more 4-mile laterals over the spring. Drilling times came in faster than expected, and the wells will be completed later this year.

The first foray into 4-mile laterals gave Chord confidence to move forward with planning seven more spuds this year.

For now, 3-mile wells are becoming the standard. Chord plans to turn in line 130 to 150 gross wells this year, 40% of which will be 3-mile laterals.

Continental has also drilled a 4-mile well in the Bakken, Hamm said.

Consolidation

The independent- and wildcatter-fueled landgrab in the Bakken is over. Today, publics and majors dominate the core of the basin.

The Bakken is already one of the most consolidated basins in the Lower 48, according to a 2024 analysis by investment firm Kimmeridge. The top five Bakken producers account for around 70% of the basin’s total output.

While Permian M&A has dominated headlines, the market has seen a flurry of Bakken M&A in recent years.

The creation of Chord from Whiting and Oasis brought together two major Williston operators. Their massive, combined land position is what’s allowing for the longer 3-to 4-mile laterals to get drilled.

Last year, Chord got bigger with a $4 billion acquisition of Enerplus. Enerplus was an early believer in the Bakken. In 2005, it inked a $421 million deal to acquire Lyco, including the trailblazing assets from the Sleeping Giant field in Richland County, Montana.

Devon Energy is also betting on the Bakken. Devon closed a $5 billion acquisition of EnCap Investments-backed Grayson Mill Energy in September.

The acquisition transformed Devon’s Williston Basin business with the addition of more than 300,000 net acres, 500 undrilled gross locations and 300 refrac candidates.

The $17.1 billion merger between ConocoPhillips and Marathon Oil consolidated huge portions of the Williston. ConocoPhillips also touted the potential for Bakken refracs when announcing the deal.

ConocoPhillips’ Bakken production averaged 212,000 boe/d in the first quarter, up 120% year over year.

There’s still more dealmaking to come. Exxon Mobil is reportedly exploring the sale of some of its Williston assets.

And there’s still Chevron’s pending acquisition of Hess Corp., including Hess’ large Bakken footprint. But Chevron’s acquisition of Hess is mostly for upside offshore Guyana.

Hess is in a dispute with Exxon Mobil about interests in an E&P partnership offshore Guyana. Hess, Exxon and stakeholder CNOOC are in arbitration over the contract language. A hearing was scheduled to begin in late May.

Whether the deal closes, and whether Chevron decides to keep the Bakken assets, are matters still up in the air.

Private Bakken E&Ps

Despite the huge amount of Bakken consolidation, there’s still room for private players to operate in the basin.

Petro-Hunt, a private E&P held by members of the Hunt family, is still going in the Bakken.

The Hunts have been in the Williston Basin for decades. Petro-Hunt traces its roots back to the wildcatter H.L. Hunt, pioneer of the East Texas Oil Field, and his son William Herbert (W.H.) Hunt.

Hunt interests began picking up leases in the Williston in the 1950s. W.H. Hunt drilled his first well in North Dakota in the ’50s, according to Petro-Hunt COO Marshall T. Hunt, W.H.’s grandson and H.L.’s great grandson.

Today, around 80% of the company’s production still comes from the Williston, Marshall Hunt said. That sometimes comes as a surprise to people who assumed Petro-Hunt had fully exited the basin.

Marshall Hunt Petr-Hunt — Marshall T. Hunt, CEO, Petro-Hunt

In 2012, Petro-Hunt sold acreage and 26,000 boe/d of production to public Halcón Resources Corp. for $1.45 billion.

“But we did retain a large portion of our production, as well as an even larger portion of our net acres to continue to operate,” Hunt said.

The company expanded its position in 2018 by acquiring 119,000 net acres and 246 wells from SM Energy. SM generated net proceeds of about $161 million.

Petro-Hunt has quietly remained one of the more active private E&Ps in the Bakken. The company continued to run one rig and one frac crew before and through the COVID-19 pandemic.

Before the Halcón sale, Petro-Hunt was operating 15 rigs in the Williston. That figure fell to eight after the sale.

But like other Bakken producers, Petro-Hunt is seeing benefits from D&C efficiencies in the basin. The efficiency of one drilling rig is about the equivalent of three to four rigs a decade ago, Hunt said.

Petro-Hunt plans to continue under the one-rig, one-crew cadence going forward. The company’s rig was active in Mountrail County, North Dakota, as of early May, according to state data.

Hunt Oil, owned by a different branch of the Hunt family, also remains active in the Bakken. Hunt Oil was drilling in Mountrail County as of late April.

Other private E&Ps are developing the Williston:

• Continental had four rigs active;

• Phoenix Energy had three rigs active in Divide and Williams counties; and

• Silver Hill Energy Operating, Slawson Exploration, Kraken Operating, KODA Resources and Zavanna LLC each had one rig active.

Active Rigs in Bakken by Operator — *(Source: North Dakota Department of Mineral Resources)*

D&C efficiencies

The Bakken is less about exploring for new oil today. The oil’s already been discovered. Now, it’s about optimizing costs to produce it.

Consolidation and drilling efficiencies are aimed at lowering the cost of supply per barrel.

Devon is reporting new efficiencies after closing the Grayson Mill acquisition last year.

“Drilling pace actually is up an additional 19% to the plan and drill costs are down now 15%,” said Tom Hellman, Devon’s senior vice president of E&P operations, in the company’s first-quarter earnings call.

Devon has fully switched to simul-frac and “did a complete relook at the completion design” for its Bakken wells. The company switched to a finer, 100-mesh proppant which it’s self-sourcing, rather than buying third-party.

“So, there were substantial savings on the completion side, as well,” Hellman said.

Chord is seeing material benefits from its longer wells. The company aims for 80% of its future program to be 3-mile laterals.

Beyond the boost in EURs and cost savings, longer laterals allow Chord to develop lower-quality locations in a cost-effective way.

There are portions on the outskirts of the basin where it was tougher for Chord to deploy capital than in the basin’s core, Brown said. Longer laterals allow those locations to get developed faster.

“As we move into 4-miles, I think some of those start to fall in to where they do offer very attractive rates of returns associated with development out there,” Brown said.

That’s bringing acreage that wasn’t considered sub-$60/bbl WTI inventory into that sub-$60 category today, said Michael Lou, Chord’s chief strategy and commercial officer.

Refracs are another growing story for the Bakken. The basin is home to thousands of legacy wells completed with antiquated designs and technologies.

Operators hope to breathe new life into old wells using new recompletions, where it makes sense.

Petro-Hunt has performed a handful of refracs in the Bakken, Hunt said.

“A lot of the wells that were drilled in the early 2000s or pre-2015 are going to be good candidates for refracs at some point,” he said. “You also need to make sure the economics justify the cost of the refrac itself.”

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