Bakken Continues Decline While Operators Remain Strong

The Bakken Shale is alive and still kicking, but production continues to slow.

While oil production and rigs continue to decline in the Williston Basin of North Dakota, some companies, such as QEP Resources Inc. (NYSE: QEP) have shown impressive results in the play. At the same time, the backlog of drilled, but uncompleted (DUC) wells in the state continues to loom—which could generate financial headaches at current commodity prices.

Oil production in North Dakota declined 1% in February by 14,100 barrels a day (bbl/d), to 1.18 MMbbl/d. That was the second month in a row that production fell, which is uncommon, said Lynn Helms, director of North Dakota’s Department of Mineral Resources (NDIC).

The last time production fell in consecutive months was four years ago, Helms said.

“At that time it was because of incredible winter weather,” he said.

Gas production was flat in February at 1.47 billion cubic feet per day, which Helms linked to the increased gas capture rates from new anti-flaring regulations.

The rig count in the Williston Basin has fallen rapidly to 91 in February from a high of 218 in May 2012, which surprised Helms.

“Going into this thing in December, operators were telling us that they were going to ladder their rigs down as contracts expired,” he said. “That’s what we had built our plans around.”

Helms said oil price continues to be the driver behind slowed production, with operators reporting postponed completion work to avoid high initial oil production at very low prices and to NDIC gas capture goals.

However, Helms found as operators were faced with weak crude prices at the beginning of the year, a few started to buy out contracts and lay down rigs.

Completion count in the basin continues to be tepid. At the end of February, about 900 wells were waiting on completion—a month-over-month increase of 75 wells.

The state is quickly approaching the anticipated June number of 1,000 or more DUC wells, which Helm anticipates will lead to a surge in production that may test the oil storage capacity this summer.

At an $8 million per well cost, the industry would require about $11 billion of capital, which is well below operating cash flows in a $50/bbl world, said Tudor, Pickering, Holt & Co. in a report.

“When including basis differentials, interest expense and corporate overhead, we believe most Bakken E&Ps are now realizing netbacks of about $15 per barrel produced,” the firm said.

Tudor said roughly 1.2 MMbbl/d of basin level production would indicate $6.5 billion of cash flow, which is barely enough to fund opening up of the 900 DUC wells in backlog as of February.

Helms said EOG Resources Inc. (NYSE: EOG) probably has the largest inventory in the state, with a significant number of wells in Parshall Field.

“They’ve been doing a lot of increased density drilling there,” he said. “Those are tremendously productive wells so they are able to drill a lot of wells and maintain production and still bank a lot for future price increase.”

Helms suggested 110-120 completions are needed each month to hold production flat, equating to about 1,400 wells for the year.

Battle For The Bakken Throne

Within the past year, QEP Resources’ well results have smoked all other operators in the play, said Tim Rezvan, senior research analyst, Sterne Agee, in a report.

QEP has about 116,000 total net acres in the South Antelope and Fort Berthold Reservation areas of the Williston Basin. The company has about 143 million barrels of oil equivalent (MMboe) of proved reserves in the basin.

In its March presentation, QEP said it had five rigs operating in the basin, all on pad drilling, as of year-end 2014. The company's average net production in the play for fourth-quarter 2014 was 54,000 boe/d.

In terms of overall size and production, Continental Resources Inc. (NYSE: CLR) and Whiting Petroleum Corp. (NYSE: WLL) are still top dogs.

Continental reported production in the North Dakota Bakken of 115,137 boe/d in the fourth quarter of 2014. The company has 1.17 million net acres leased. Whiting, after its recent merger with Kodiak Oil & Gas Corp., produced of 100,870 boe/d in the fourth quarter of 2014. The company has 811,737 net acres in the basin.

But QEP has shown it can coax volumes out of the Bakken like no other, Rezvan said.

Sterne Agee released a summary of findings from data it pulled on 2,142 Bakken/Three Forks wells that began producing in North Dakota and Montana in 2014 and January 2015.

Among operators who had brought three or more wells online in a month, QEP’s results were first or second best for seven of the 13 months studied, Rezvan said.

“We were somewhat surprised by the consistency and productivity of QEP’s ’14 and early ’15 spuds,” he said.

Wells online six months had average production of 762 boe/d, while wells online 13 months had average production of 347 boe/d. Of the 66 wells, the company brought on from January-July 2014, 56 were drilled in McKenzie County.

In contrast, Bakken-focused Oasis Petroleum Inc.’s (NYSE: OAS) wells were largely in the lower half of Sterne Agee’s rankings in the basin.

“2014 was a difficult year for Oasis,” he said. “Well productivity problems contributed to light production versus guidance over the first three quarters of 2014 and exacerbated the oil-driven sell-off in shares.”

Oasis holds about 506,000 net acres concentrated in the core of the Williston Basin in the East Nesson and West Williston areas. The company has about 272 MMboe of proved reserves, as of year-end 2014.

Rezvan said the company’s drilling program this year will look strikingly different from 2014, when activity skewed toward Three Forks delineation drilling outside the basin’s core.

The company said it plans to complete 79 gross (63.3 net) operated and 2.6 net nonoperated wells in 2015. It will target an average daily production for the year between 45,000-49,000 boe/d.

“We expect activity this year to focus on delineated acreage in the company’s prime real estate—it’s about 180,000 net acres in Indian Hills [McKenzie County] and South Cottonwood [Mountrail County], two of the three most productive counties in the basin.”

Rezvan said investors should expect operators in 2015 to concentrate in the defined “sweet spot” of the play—eastern McKenzie County, western Mountrail County and northern Dunn County.

“We remain cautious of drilling on the Montana side of the play, as well as Williams County, northern/eastern Mountrail County, and southern Dunn County,” he said.

Sterne Agee estimates 2015 full-cycle costs may approach $40/bbl on core acreage, which supports current drilling initiatives.

Contact the author, Emily Moser, at emoser@hartenergy.com.