Where next for the Bakken?
Producers are making the North Dakota tight oil play an attractive place to drill again, but it will struggle to compete with the Permian
The Bakken, a vast shale formation under the plains of North Dakota where the US tight oil business took off less than a decade ago, has fallen into the shadows of the more productive Permian and Eagle Ford basins. Oil production in the Bakken has stagnated at around 1m barrels a day since mid-2016. Some analysts say output will never get back to its late-2015 peak, when it topped 1.2m b/d. Amid the stalled production and hotter growth prospects elsewhere, investors have fled Bakken-focused drillers.
However, there are signs that the Bakken's top producers are starting to make the economics of drilling the play more enticing. Rystad, a consultancy, pegs the wellhead breakeven for top operators—those with substantial positions in the core of the play—at around $38 a barrel. An analysis from Jefferies, the investment bank, came up with similar figures. It put the breakeven for the core of the Bakken at $39/b, although that rises sharply to nearly $55/b in the non-core areas, where wells are less productive. The Three Forks shale, which lies beneath the better-known Bakken formation and was touted by many operators as the answer to the Permian's stacked shale potential, is costlier. Both core and non-core areas of the Three Forks break even at around $54/b.
The Bakken is still lagging the Permian, the world's premier shale play, but is competitive with the Eagle Ford, another early-era tight oil province. The Jefferies analysis puts breakevens for most areas of the Permian at less than $35/b and at $41/b for the oil-rich section of the Eagle Ford. The spot WTI benchmark averaged $49.40/b through the first 10 months of this year—although North Dakota's light sweet crudes have traded at a significant discount to WTI because of infrastructure bottlenecks.
Two key trends have driven the Bakken's improved economics of late. Producers are using more intense frack jobs—pumping more sand and proppant into each well, an innovation from other shale plays brought to the Bakken to squeeze more oil from each well. They've also focused drilling on just the most productive areas of the Bakken.
Shale's development has been continuously improved over the years because drillers have constantly tinkered with their well-drilling and completion formulas, looking for the optimal recipe. In the early stages of the Bakken's development, producers sought to make wells more productive by adding evermore stages to their frack jobs. That's still happening. Hess, for instance, has increased the average frack stages at its Bakken wells from 41 in the first quarter of 2016 to 60 in the third quarter of this year. More recently, however, companies have shifted focus to "bigger" frack jobs, pumping more sand into the wells to crack open more of the shale. Up until mid-2016, producers pumped an average of around 4.5m pounds of sand into each Bakken well. Since then, that figure has jumped to 9m pounds and more in many cases.
It's paying off. Thirty-day initial production (IP) rates, a key metric for shale wells, have jumped for the Bakken's top producers. Continental Resources, the Bakken's largest producer, has seen its average IP rates jump by 50% to 1,500 barrels of oil equivalent a day this year, up from around 1,000 boe/d in 2016. ConocoPhillips also saw its wells' performance jump 50%, from 800 boe/d to 1,200 boe/d. Hess, Whiting and Marathon, all major Bakken producers, have seen similar improvements.
Although the long-term performance of the wells is still unclear, data collected by Jefferies show that late-2016 and early-2017 wells are about 50% more productive over a six-month period than wells drilled in 2014 and 2015. Companies expect to recover around 1.25m boe over the course of the well's life thanks to the bigger frack jobs, compared to half that from wells drilled with the recipes of a couple of years ago.
The bigger frack jobs come at the cost of more expensive wells. Hess' average well cost jumped in the third quarter of this year to $5.8m, up from $4.7m per well a year earlier. Most of that increase has come from completion costs—where the cost of added sand would come in. Completion costs for its wells rose by two-thirds from a year earlier to $3.1m in the third quarter of this year. Continental Resources put its average Bakken well cost at $6m last year for wells that would produce 0.9m barrels over its lifetime. It now pegs that cost at $7.5m for a well that can produce 1.1m boe. Whiting says its bigger wells will cost $7m-$7.6m.
However, the added production from each well is more than made up for from the extra oil produced. Figures from the North Dakota Pipeline Authority earlier this year lay out the dynamic: at a $40 wellhead price, a $6.5m well barely clears an acceptable rate of return with an IP rate of around 850 b/d—which is where many wells were in 2016. However, that return jumps to around 50% when the same well adds $1.5m in costs (to $7.5m), but produces 1,200 b/d, which is the situation a number of operators find themselves in.
Another tailwind for Bakken producers' finances is the improved infrastructure situation around the basin. When output from the Bakken surged between 2012 and 2014 it caused severe transportation bottlenecks. Producers scrambled for ways to move their crude out of the basin, turning to costlier rail and trucking arrangements. Through much of 2013 and 2014, more than 60% of Bakken production was loaded onto railcars and ferried by train to refineries around the country. That glut saw North Dakota's crude prices trade at steep discounts to WTI and Brent. At its worst, in 2012, Bakken crude traded at a $20/b discount to WTI and a whopping $40/b discount to Brent, with the average discount to WTI over that time at around $10/b-a major drag on Bakken producer revenues.
That has all changed with an intensive pipeline buildout, capped by the completion this year of the huge 0.525m-b/d Dakota Access Pipeline (DAPL), which was the focus of intense protests in 2016. The completion of DAPL benefits producers in two ways. First, it means that the Bakken now has far more pipeline capacity at just over 1.5m b/d than current production, which has eased the supply glut. Rail transport has all but halted, with less than 10% of Bakken crude moving around by train. As a result, the differential to WTI should now more closely reflect pipeline transportation costs—bringing the average differential down from around $10/b in the years before DAPL to around $6/b in the years to come.
$38/b - Breakeven in the core of the Bakken
The second benefit to producers is that DAPL provides a cheaper pipeline tariff to the Gulf Coast, a key market for refining and exports. As analysts at Bernstein point out, the previous pipeline route to the Gulf Coast required hopping on several lines at a total tariff of between $7.56/b to $11.83/b. For those that have committed take-or-pay contracts, DAPL ferries crude to the Gulf Coast for about a third less, at between $5.61/b and $6.63/b. Combined, these infrastructure improvements will bring in hundreds of millions of dollars a year in more revenue for top Bakken producers. They also open up new markets: in October, Continental Resources announced it would be exporting 1m barrels of Bakken light crude to China via the Gulf Coast.
While there are reasons for Bakken producers to be more cheerful these days, the basin is likely past its heyday. The Bakken was a pioneer tight oil play, and it will likely be the first to move towards the fields' inevitable decline. There are only so many wells that can be drilled in the core of the play and producers are quickly burning through their inventory of potential well sites. Jefferies, the investment bank, estimates there are somewhere between 4,700 and 5,500 undeveloped locations left in the Bakken's core, compared to 2,000 that have been drilled since 2014. At 2016's pace of development, when 924 wells were completed, that leaves around 11 years of inventory left, says Jefferies, though that timeframe could shorten or lengthen depending on the pace of activity. The relatively small inventory of drill sites is part of the reason Bakken-focused producers have seen their share prices suffer. It will also make it difficult for midstream companies to make major new infrastructure investments around the Bakken.
There are also limits to the strategy of employing ever-larger fracks. Some producers, in fact, think they've already reached the limits of how much benefit they can get from the bigger frack jobs. "I think we're at what we see as optimum right now on sand loading," Whiting's head of exploration and production Rick Ross told analysts in October.
Source: EIA, Petroleum Economist