Executives representing three top Williston Basin E&Ps came to Hart Energy’s recent DUG Rockies conference to praise the Bakken/Three Forks play and bury—or at least kick some dirt toward—the Permian Basin. Oasis Petroleum Inc., Hess Corp. and Whiting Petroleum Corp.—collectively producing about a quarter of North Dakota’s crude oil—recounted the afflictions and tests the Bakken has weathered: steep differentials, related pipeline constraints and flagging interest from the oil and gas universe during the downturn.

Now those same weaknesses have turned to strengths. Differentials increasingly favor Bakken Clearbrook crude over West Texas Intermediate (WTI) Midland spot prices. Pipelines, particularly the Dakota Access, have opened flows east, west and south. The play is once again on the M&A frontlines—in 2017 about $5 billion transacted there—and operations are generating free cash flow.

Barry Biggs, Hess’ vice president of onshore, said Bakken operators have essentially regrouped during a particularly crushing halftime. “This idea that we’re anywhere near the end of the ball game in North Dakota needs to be debunked,’ he said. Biggs said that the region’s geology is well known and HBP, and the challenge will be in continuing to optimize the Bakken while finding additional room to grow.

However, Hess and North Dakota operators will meet their challenges “without all of the hair” that faces Permian E&Ps. “While there is need to build out additional infrastructure [in the Bakken], it is going to be incremental relative to what the Permian is going to have to do to meet the capacities required to get [oil] out of the basin,” he said.

The Bakken is set to be a key driver of U.S. production growth, with output in 2018 expected to exceed 1.23 million barrels of oil equivalent per day (MMboe/d). Producers may eclipse North Dakota’s previous high of just under 1.23 MMboe/d set in December 2014.

Brad Holly, Whiting’s president and CEO, said the Bakken core can compete with any U.S. basin. New completion techniques have driven performance, with 100% increases in EURs and higher well IPs.

“If you take the labels of the basins off the wells, you’ll see some of the best wells drilled in this country are in North Dakota and the Bakken,” he said.

Holly said a recent analyst report about the Scoop/Stack play noted that once major basins go on decline, they never recover. “The Bakken is not that story,” he said. “You can clearly see that the Bakken went on a pretty steep decline in the last downturn but has certainly recovered and production is moving north again.”

Whiting has also seen a 25% reduction in cash costs since 2014. In part, that’s due to the easing of differentials that have long hammered North Dakota. In March 2017, Bakken and Midland crude differentials flipped. “The big spike in the fourth quarter was the lowest differentials we’ve ever seen in the Bakken,” he said. At times, Bakken oil traded at a $2 to $3 premium. In March, as WTI prices continued to rise, Midland crude prices were stung by a $6 differential due to takeaway constraints.

“With the recent blowout of WTI you can see there’s a substantial difference today between Bakken differentials and Permian differentials that goes straight to the bottom line of economics,” he said.

Whiting and other companies have also kept costs down because of a more restrained approach to activity. North Dakota averaged 155 rigs in January 2015, according to the Baker Hughes rig count. Two years into the downturn, rig activity had fallen 78%, with just 34 operating in January 2017.

“The Bakken is actually in exactly the same place it was at the start of 2016,” Holly said.

In contrast, rig counts are up 59% in Texas and 46% in Oklahoma. “It certainly drove costs up, certainly drove inflation, supply, labor costs, everything like that. So, we’re watching this very carefully.”

Whiting cemented lower costs with contracts to service providers, but also as a way to prevent frack crews from defecting to the Permian or Powder River basins.

“North Dakota is fairly isolated. It takes a lot of money to move equipment to North Dakota and to move out,” he said. “If we lose them to the Permian, Powder River or anywhere else, it’s hard to get them back.”

Holly said Whiting is committed to the Bakken for the long term and giving service providers a steady program “gives them the confidence to stay.”

Cracking the code

Bakken operators acknowledge they face a challenge in finding new inventory. But as Jay Knaebel, Oasis’ vice president for reservoir engineering, said, the company has 585 core locations in the Williston and an additional 467 extended core locations. Overall, the company’s Williston Basin core and extended core offers 1,400 gross drilling locations, all of which break even at oil prices of $45 oil.

The Bakken has been good for Oasis Petroleum. Founded in 2007 as a Bakken pure play by a management team of former Burlington Resources alumni, Oasis went public with just over 3,000 boe/d in Bakken production in 2010. Current production exceeds 75,000 boe/d. The company’s Bakken holdings have grown to more than 500,000 net acres, including more than 1,000 net locations that can generate positive economics at oil prices below $45.

Oasis remained a Bakken pure play until 2017 when the company acquired 22,000 acres in the Permian Basin along the Winkler/Loving/Ward county lines. Still, the Bakken remains the primary focus for Oasis and is serving a laboratory for innovation where rapidly advancing learnings from full field development can be transferred to future development in the Permian Basin.

Oasis will spend $800 million in 2018 to fund 15% to 20% growth in the Bakken on a four or five-rig program targeting 100 wells annually, and a one or two-rig, 16 to 20 well program, in the Delaware Basin. The effort will be funded out of free cash flow from the E&P division. Oasis has been free cash-flow positive for the last three years and was one of the first E&Ps to embrace the new Wall Street mantra of living within cash flow. Separately, Oasis will divest upward of $500 million in noncore Bakken acreage by mid-year 2018, boosting balance sheet liquidity above $1 billion.

Oasis utilizes an integrated business model that incorporates stimulation services from two company-owned stimulation fleets and, more recently, a separately operated midstream gas processing and takeaway division—Oasis Midstream Partners LP—that enables the company to grow, even in a services-constrained market.

Knaebel credited vertical integration as a significant factor in well cost reduction. Oasis Well Services division’s two stimulation fleets are generating a threefold EBITDA return on capital invested while serving as a hedge against service cost inflation. Adoption of next generation enhanced stimulation techniques is improving individual well performance while simultaneously reducing well costs, turning more acreage into Tier 1 classification. Oasis just upgraded its Painted Woods acreage in western North Dakota from “core extended” to “core,” which means wells are profitable at $40 oil or better.

“We’re feeling really confident about Painted Woods,” Knaebel said. “As a result, our core inventory actually grew this year to 585 net locations. In total, in the core and the extended core, we have over 1,400 gross drilling [Bakken] locations and all of those have breakeven oil prices of $45 or better.”

The Painted Woods upgrade follows the implementation of new completion techniques and targeted well spacing that have the net effect of bringing production forward. Oasis uses a “concurrent development” philosophy in which the company performs all its infield activity within a given DSU (drilling spacing unit) at the same time. That includes using two to three rigs to drill wells in each DSU and completing wells simultaneously so that the entire DSU is brought on as one project.

One example includes its Johnsrud unit in McKenzie County, which was the first Oasis DSU brought online to fuel its midstream processing plant. The 2015 project involved 15 wells and peaked at 14,000 barrels per day (bbl/d). Since then, Oasis has repeated this practice across additional DSUs and plans to export the concept to its Delaware Basin acreage.

The company’s move to full field development has reduced well costs by $4 million, half through efficiency gains. Since 2010, Oasis has completed 800 wells averaging 10,000 feet of lateral in multiple zones. According to Knaebel, Oasis ranks second among eight Bakken peers with finding and development costs at $10.40/bbl and ranks second in margin per barrel among 12 Bakken peers at $35.07. Oasis features 75% IRRs in the Bakken.

Oasis launched its midstream processing division a couple years ago, which was recently reconstituted as an MLP for the IPO in 2017. Oasis plans to process 320 million cubic feet per day (cf/d) by year-end 2018.

“Oasis is in the Bakken for the long term,” Knaebel said. “We consider it home base, and we consider it has world class inventory.”

Out of the penalty box

Since he joined Whiting in mid-2017, Holly said, the Williston Basin’s activity and economics have been rebounding; now, oil and gas companies must focus equally on how to recapture the investment community’s interest.

Holly said there are compelling reasons to back the Bakken. Operators’ enhanced completions there have driven performance to nearly a 100% improvement in EURs and IPs, he said. EURs have risen from 500,000 to 600,000 boe to more than 1 MMboe since 2013.

“The Bakken core has some of the best wells in the U.S. It generates strong free cash flow,” he said. He referenced public data showing that since 2008, wells that have at least a 700-bbl IP for 30 days, drilled for $6- to $8 million per well, have generated a 50% to 60% rate of return. This is in the four-county Bakken core.

Further, it’s a “true oil play,” he said. Just as important, the play no longer has to sing the differential blues. The days when it was penalized by its remote location and insufficient pipeline takeaway are no more. “With Dakota Access pipeline and other pipes out of the Bakken, it’s now very competitive with the rest of the sources in the U.S. It’s changed the game for the Bakken.”

Other positives: less competition for services in the Bakken than in more fast-growing plays and basins, and a “collaborative and reasonable” regulatory climate. “It’s a stable platform,” he said.

Additional oil takeaway capacity has arrived and should be sufficient for some time. “In February, production in the basin was 1.2 MMbbl/d, and the current rail takeaway is 1.5 MMbbl and for pipelines, 1.4 MMbbl/d.” Operators can send their production to the West, East and Gulf coasts.

Natural gas is another story. Here, production is also rising, to a new all-time high of 1.2 Bcf/d in February, so the industry needs additional plants. Holly said some $3 billion in midstream infrastructure projects has been announced for completion in the next 18 months. “Oil is not decreasing, we’re just generating more gas along with it,” Holly said.

Bakken spot oil prices trailed WTI spot prices until mid 2017; changes are a result of takeaway added in the Bakken but not yet adequate in West Texas.

The Bakken’s more measured growth has insulated it from the significant spikes in service costs already experienced in Texas and Oklahoma, he said. To preserve economics, Whiting “went long” with its service providers, Holly said, so it’s not anticipating price increases this year. This factor is helping to drive outperformance.

Whiting’s harvest

Whiting’s biggest challenges include the need to expand inventory. Wells since 2008 producing at least 700 bbl/d are all in the four-county area where it and others currently focus. “The real goal of Bakken operators is to try to expand this,” he said.

“We see oil in place that is significant and is recoverable outside the current boundaries of the field, so we are looking at how to use completion technology to get at that effectively.”

Takeaway issues mean that Whiting’s rigs are spread out, with one in Mountrail County, one in Williams, and two in McKenzie. “If you bunch, you’ll have a problem of takeaway. Whiting’s well performance is over a wide geographic area which makes us feel good about our play.”

The company plans to drill 80 net wells this year out of its inventory of 1,100 Tier 1 wells and 1,500 Tier 2 wells. A cautious approach is warranted, as interference is a challenge. “You can’t get overly aggressive with DSUs or spacing,” he said.

South of the river, Whiting is closely watching the performance of new wells for signs of interference against its 1 MMbbl type curve. These new wells were tracking a 1 MMbbl type curve for 50 days, and then with effective stimulations moved north of that. After a year, they were producing about 16% higher than that type curve.

North of the Missouri River, in Williams County, production from new wells trailed that type curve initially but at 100 days was besting it and gaining ground, posting about 10% over the type curve after a year.

In Parshall Field, which may have been over drilled initially, Holly noted, eight to 10 wells were put down per DSU. Sanish Field, on the other hand, “has more oil in place than anywhere else in the Bakken and had two to four wells per DSU. We’re doing true infield drilling here, adding wells among existing wells.”

Over two years, the oiliest area there trailed the 100 MMbbl type curve, but at 200 days it gained ground, taking 400 days to cross the type curve. Cumulative production for the wells after two years is about 150,000 bbl and tracking above the type curve. Further, the company is seeing significant increases in production when restimulating parent wells in addition to the child wells.

Whiting is modeling and rightsizing every completion, mining data and using high-end models on every fracture design. Holly offered an example of five wells in the same DSU from 2012, where 3 million pounds of sand had resulted in a cumulative 35,000 bbl of oil after one year. In 2015, Whiting went back in and pumped 7.5 million pounds of sand, boosting the cumulative amount to more than 300,000 bbl. Holly emphasized, however, that increasing the amount to 7.5 million pounds didn’t result in more barrels. Instead, the company concluded, it was losing that sand to nonproductive horizons.

Thus, it’s important to right size the completions in the Bakken, and it’s also critical to keep the frack in the Middle Bakken zone. Go higher, into the Lodgepole, and the water cut soars.

Whiting was overlevered in past years, Holly said, so it is working to reduce debt, cut costs (it’s achieved a 25% cost reduction over a four-year period), and capture the benefits of rising oil prices and improving differentials to generate cash flow.

“As oil prices go up, our goal is double-digit growth while returning cash to investors,” he said. “In fourth-quarter 2017, we generated $100 million in cash flow back to our business. We’re enjoying $68 oil, but we need to get costs to where if we get into the $50s again, we can generate an investment scenario.”

Whiting has a strong hedge position to protect its capex program. “We are hedged so we could commit to services; we are long on rigs, long on completion crews, and we also locked in steel prices before the tariffs. Working with others, we’re trying to keep the services we have in North Dakota, because if they are lost to the Permian or elsewhere, they’re hard to get back.

“We have a long-dated view in the Bakken; we plan to be there for decades.”

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