No play in North America was hit as hard by the downturn in crude prices that began more than a year ago than the Bakken. In the past 18 months, prices in the region have fallen in half from the upper $80 per barrel (bbl) range to well under $40 per bbl.

Though prices are expected to improve in the years ahead, a full recovery to 2014 prices may not occur until the beginning of the next decade.

An unfortunate irony is that the remoteness of the Bakken from demand centers and hubs is what previously made it so attractive to midstream development, but is now a reason for slower activity on all fronts. Current economics do not support increasing already high production levels, which further delays the midstream buildout of the region.

This still leaves rail as the primary mode of transportation. While an attractive option in the first half of this decade, the increased costs associated with crude-by-rail (CBR) transportation make it less attractive with current market conditions.

First off, last back on

“The heyday of tremendous growth in crude, associated gas and liquids production in the region has been put on hold for the time being with production activity leveling off as some of the producers have had financial troubles,” Greg Haas, director, integrated oil and gas research at Stratas Advisors, told Midstream Business.

Haas said that the Bakken has always been challenged by its location, but overall global demand for crude had been strong enough to support the additional costs associated with its production and transportation.

“It’s unfortunate that on top of low prices, the Bakken was already one of the more challenged plays and yet it’s one of the more prodigious oil plays. It’s so remote from the demand centers and unconnected in large measure by pipelines that producers are on the forefront of being hit by oil prices and substantially lower netbacks compared with other plays,” Haas continued.

This decline in activity obviously feeds into the midstream, which has resulted in several projects being delayed. These include Enable Midstream Partners LP postponing the completion of Phase 2 of its Nesson crude gathering system to the second quarter, two quarters later than originally planned; as well as the delay by one quarter of the White Cliffs Pipeline expansion project developed by Noble Energy Inc., Plains All American Pipeline LP, Western Gas Partners LP and Rose Rock Midstream LP.

Of course, the biggest project delay/cancellation in the region is TransCanada Corp.’s Keystone XL Pipeline, which was rejected by the Obama administration in November. However, TransCanada fi led suit in U.S. federal court in early January seeking to overturn the rejection of the $3.1 billion project under provisions of the North American Free Trade Agreement.

Outside of this seemingly forced cancellation, project terminations have been few and far between in the Bakken. Though a construction boom isn’t likely, neither is a total shutdown in midstream development.

“It might be five years before we see the type of construction we saw in the previous five years. ‘Lower for longer’ has been a phrase used to describe WTI [West Texas Intermediate] prices, and I would say the same holds true for the midstream in the Bakken with fewer project announcements for a lengthier period of time than if prices were still in the $60 to $80 per bbl range,” Haas said.

The play has been one of the top crude basins in the world, but the decrease in crude prices and new flaring regulations in North Dakota are resulting in the Bakken seeing an uptick in gas project activity and production, including new processing and gathering capacity.

“We could see the Bakken convert from the premier North American oil play to more of a mixed play because of the decline in oil-directed drilling

as well as the requirements to capture more natural gas. In addition, as shale fields age there has been a general indication that they tend to get gasier. As drilling slows, more of the oil in the Bakken will stay in the ground. Over the years this will result in an increase in gas produced in the Bakken from existing wells,” Haas said.

Train in vain

Though Bakken producers have managed to lower drilling costs and maintain production in the midst of the current price downturn, the differentials are not nearly as strong as other plays because of the transportation costs in the play.

Indeed, production out of the Bakken increased in 2015 from the previous year despite all of the capital expenditures declining throughout the year. However, the Bakken is not an inexpensive play in which to operate and production is expected to decline in 2016. This will lead to fewer new project announcements this year, according to Haas.

Limited pipeline capacity in the region requires greater CBR transportation usage compared to other parts of the country. This requires producers to factor in lower netbacks into their drilling and capital management plans than what they could get with increased pipeline capacity.

There are several attractive pipeline projects moving forward to add capacity in the region, which will reduce CBR utilization. This will likely mean that the heyday for rail in the Bakken will end as it will have to compete for fewer barrels with cheaper pipelines.

This isn’t to say that CBR is going away anytime soon as it will still work to provide incremental transportation service along with greater flexibility compared to pipeline capacity. “The facilities will still be there and will be good options for future deliverability, but we’re unlikely to see it approach the utilization rates that we experienced just a few years ago,” Haas said.

While drilling economics may have improved and caused production to rise, the industry’s capability to handle all of this production did not grow at the same rate. This is especially true in crude markets where U.S. refineries were running at high rates with no spare capacity available to take in these additional volumes.

The domestic ban on crude exports was not lifted until the end of 2015, which meant that with no export markets available and no new refining capacity available a great deal of this crude production went into storage. This has caused storage levels to grow to more than 130 million bbl above the five-year average.

Produce, produce

“The prime directive of publicly traded E&P oil companies is ‘produce, produce, produce at all costs.’ As long as the capital markets continue to fund that prime directive, they’re going to do it,” Haas said, noting that this large storage overhang took about a year to build and could take another full year to work off given a slowdown in production.

Stay or go?

The lifting of the export ban is undoubtedly a positive for the industry, but it will not be a cure-all for its ills. The ability to export is now available, but the question remains: Which markets desire U.S. crude, especially with Brent trading at about a $2 discount to WTI?

“We have a year’s worth of crude storage built up, but we can’t simply export it away at these prices. The U.S. needs the WTI-Brent differential to be $4 or $5 in favor of WTI. The fundamentals aren’t good for 2016 and the further away from the refineries and export terminals a play is, the more it will struggle,” Haas said.

One way in which companies will seek to maintain production at a lower cost will be by completing more drilled but uncompleted (DUC) wells in 2016. These wells can be completed for half the price of a new well and have the added benefit of maintaining the geology and keeping the formations intact, according to Haas.

“There is a reason for pushing ahead with completions since you don’t want to turn oil wells on and off too often. You can damage the formation and ruin the economics by having to refrac, which would defeat the purpose of the initial completion,” he said.

No matter if this production comes from new wells or DUCs, it will need to be moved out of the region to several markets. Through both pipe and rail, production will be moved north to Canada, south to the Gulf Coast, as well as to the East and West coasts.

Each of these markets present challenges for Bakken production.

The most significant is that despite an increase, pipeline capacity is still limited and this will drive up the transportation costs by still depending on rail more than other plays.

Moving north could be somewhat problematic as Enbridge Inc. is reversing its Line 9 Pipeline to transport heavily discounted Western Canadian crude to the U.S., which would reduce the capacity to ship Bakken volumes to Canada.

The White Cliffs Pipeline will help to offset this loss of capacity, but won’t have quite the same impact that was expected when the project was first announced. Rather than provide additional capacity, it is now more of a one-for-one swap with the Line 9 reversal. Volumes shipped on the White Cliffs system will reach the Cushing, Okla., hub and be able to move to the Gulf Coast for export.

Refiners on the East and West coasts also have decisions to make on whether or not to rail in Bakken production, which could be more expensive than imported crude. Until more pipeline capacity is built, the prospects for the Bakken are dimming compared to the past few years.

Moving abroad

The U.S. began to export domestically produced crude oil for the first time in 40 years just before the start of the new year when NuStar Energy LP exported crude leased by ConocoPhillips from the Eagle Ford Shale, reportedly to a European refinery, via a contract with Vitol. Shortly afterward, Enterprise Products Partners LP sent the first U.S. crude exports from its terminal along the Houston Ship Channel to an undisclosed market through another Vitol contract.

As of press time, no Bakken volumes have been exported and though some volumes may make their way out of the country in 2016, it certainly won’t be a large market this year. “There is little rush to export higher-cost U.S. crude to lower-cost countries,” Haas said.

Long term, Bakken crude should be able to find homes in international markets due to its higher quality compared to WTI and Brent, according to Kenneth Medlock, senior director of the Center for Energy Studies at Rice University’s Baker Institute for Public Policy.

“Development in the Bakken and Eagle Ford shales has driven the bulk of the increase in domestic crude oil production to date, and the crude oils coming from those locations are generally lighter and sweeter than WTI and Brent. In an unconstrained market setting, this would normally equate to those crude oils pricing at a premium when delivered to market,” he said in a March 2015 report that found the export ban constrained domestic markets even in a low-price environment.

“In fact, in a low-price environment the need to address the export ban is heightened, as it could eliminate the current price discount thereby supporting profit margins and upstream activity,” Medlock added.

Still attractive

There are still positives coming out of the Bakken. Crestwood Equity Partners LP reported that the COLT Hub in Epping, N.D., experienced solid results in third-quarter 2015 despite lower crude prices, tighter spreads and declining North Dakota production.

“COLT continues to be the leading CBR facility in the Bakken by volume, with about 25% of that market. While total North Dakota CBR volumes were down from their 2013 high, CBR still held up well against pipelines in the quarter, transporting 47% of total Bakken crude despite very narrow WTI to Brent to Alaskan North Slope arbs,” Bob Phillips, chairman, president and CEO of Crestwood, said during a conference call to discuss third-quarter earnings.

Phillips stated that Bakken crude is still attractive to coastal refiners due to favorable refined product crack spreads. During the conference call, he said he anticipated that these spreads will widen as prices increase in 2016.

CBR usage may not reach previous highs, but it will remain attractive. “I remain convinced that COLT’s unique access to supplies in the Bakken and our superior storage and customer service position will enable us to maintain our leadership in the Bakken CBR market,” Phillips said.

While speaking at the Jefferies Energy Conference in Houston in November, Phillips noted that North Dakota was still producing more than 1 million bbl/d of crude. CBR is transporting about 465,000 bbl/d of this figure with the COLT Hub having take-or-pay contracts for 149,000 bbl/d.

“We don’t have to outrun the lion, we just have to outrun the next guy. We’re well-positioned to continue to be the best CBR facility to serve customers on the East and West coasts,” Phillips said.

While the Bakken may have had a quieter 2015 in the transaction arena than other plays around the country, one loud deal announced was Hess Corp.’s sale of 50% of its Bakken midstream assets to Global Infrastructure Partners for $2.7 billion. The resulting joint venture (JV), Hess Infrastructure Partners, is expected to generate about $300 million in earnings in fiscal year 2016 with capex spending of up to $350 million.

This deal was designed to use the attractiveness of midstream assets to help a producer, Hess, improve its liquidity in this downturn in crude prices by selling an interest in midstream assets.

“We’re going to use the proceeds from this transaction to preserve the strength of our balance sheet in the lower commodity price environment, provide additional financial flexibility for future growth opportunities and continue to repurchase stock on a disciplined basis,” John Rielly, CFO, Hess Corp., said during a call to discuss the deal.

The JV includes the Tioga natural gas processing plant, the largest such facility in the Bakken with inlet processing capacity of up to 250 million cubic feet per day (MMcf/d) and NGL extraction capacity of up to 60,000 bbl/d. The company is considering a project to debottleneck the region by increasing the facility’s processing capacity to 300 MMcf/d.

Hess Infrastructure Partners also includes the Bakken’s third-largest rail terminal, the Tioga terminal, which is capable of loading two unit trains per day for a maximum capacity of 140,000 bbl/d of crude and 30,000 bbl/d of NGL.

The facility currently has an export capacity of 54,000 bbl/d through nine crude oil train sets delivering volumes to the East, West and Gulf coasts. The JV also includes 550 new rail cars that are currently under construction and will be fully compliant with new DOT standards.

There were further positives from the Bakken from Tesoro Logistics GP LLC., which reported that volumes out of the Bakken were up 30% in 2015 on its gathering systems. This growth was attributed to the strategies and projects the company executed and primes Tesoro for future growth.

“The High Plains Pipeline is well positioned around the core of the Bakken where production and drilling continues to take place. We have the opportunity to expand some key segments of that pipeline and really pick up crude oil that is in that market now [in other transportation modes],” Phil Anderson, president, Tesoro Logistics GP, said during the company’s analyst day in December.

Tesoro anticipates playing catch-up with production by further expanding its gathering infrastructure in the region as these systems lagged behind the drilling in the Bakken, Anderson said. Tesoro Corp. placed a further bet on the Bakken through the acquisition of Great Northern Midstream, which includes the 97-mile BakkenLink crude oil pipeline, a 28-mile gathering system in the region, a 154,000 bbl/d rail loading and 657,000 bbl storage facility in Fryburg, N.D.

Given this level of investment along with crude demand forecasts on a global basis, it is safe to say that the Bakken will prove to be a strong play for the long term even with short-term pains. “The Bakken is at the back of the line as far as which plays are going to come back online sooner. It had several good years and it may experience several more difficult years,” Haas said.

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