Is Bakken Upside Capped?

December 20th, 2017 |

The recent announcement of Oasis Petroleum’s Delaware Basin acquisition marks another major Bakken producer re-positioning to focus its growth capital outside the Williston Basin.  What do these shifts signal about the future of the Williston Basin?  By choosing to look for growth elsewhere, Oasis answered two related questions: how it plans to increase its inventory of ‘premium’ well locations as well as where the company views its best opportunity for low-cost production growth. Because one of the largest Bakken pure plays chose this route, does it mean that Bakken upside is capped?

One concern mentioned by Bakken naysayers is that ‘premium’ inventory is running low, particularly compared to the opportunity set in other basins. BTU developed a new, well inventory model using the actual location of previously drilled wells, along with spacing, lateral and drainage assumptions to calculate remaining locations in each major shale basin, as featured in the most recent E&P Positioning Report. The chart below shows the remaining locations in the Bakken by breakeven band compared to BTU’s forecast for well completions in the basin. In addition to having less than 250 remaining locations that breakeven below $30/bbl wellhead, more than 70% of locations that breakeven below $50 will be exhausted over the next five years.

This is in contrast to the Permian Basin, where stacked pay greatly increases the number of potential locations. While the Bakken is a vast geographical area, well economics significantly deteriorate outside the core of the play in McKenzie, Mountrail, Dunn and Williams counties. If we limited the remaining locations to just these counties, the potential wells that breakeven below $50 would only drop by 1%. However, the core is home to only 80% of the potential locations that breakeven above $50.

In addition to lack of potential well locations, the progression of breakeven improvement in the core of the Bakken hasn’t kept pace with other prolific basins since oil prices crashed, as shown by the chart below. In 2013, the average breakeven for a Bakken well was $58.45/bbl, compared to $61.81/bbl in the Delaware Basin and $71.40/bbl in the Midland Basin. So far in 2017, the Central Williston has a higher wellhead breakeven than either of those regions, at $38.52.

One reason for the smaller improvement in well economics in the Bakken relates to the innovation in well design that took place across shale basins since 2014. While numerous factors helped lower breakevens over the past few years, one of the most significant was the implementation of longer lateral lengths. In the Bakken, laterals have averaged around 10,000 ft since 2014. This early innovation gave Bakken wells somewhat of a head start in relation to breakevens. As other basins have begun to reap the benefits of longer laterals, Bakken economics haven’t been able to keep pace.

While these factors will certainly limit Bakken upside, the basin isn’t going anywhere. North Dakota remains the second largest oil producing state in the US and the Bakken has a large amount of DUCs to work off throughout 2018. However, the Bakken might be starting its transition to a cash cow that will be used to fund activity in other more promising regions. After all, the positive cash flow that Oasis expects to generate there in 2018 will be funneled south to subsidize the cash outspend in West Texas, as the company explained to investors in its recent Delaware acquisition call.

To see how BTU Analytics views oil production growth in the Bakken, Permian and other regions, check out our Upstream Outlook today. In addition, to see how the U.S. fits into the global energy landscape, register for our annual What Lies Ahead Conference before prices increase.

Author: Matt Hagerty

Matt Hagerty is an Energy Analyst at BTU Analytics, leading the publication of BTU’s Oil Market Outlook, where he forecasts crude pricing and global crude balances, as well as the E&P Positioning Report, where he models well-level economics and undrilled inventory across 11 major shale plays. He also is or was previously responsible for overseeing oil and gas production forecasts out of Texas, the Williston Basin, Rockies and Louisiana. Prior to joining BTU, he was an energy research associate at Bloomberg Intelligence. Matt holds a B.S. in Finance from Tulane University.