Killing the $2.6 billion Sandpiper Pipeline Project could help bring about a supply-and-demand balance in the Bakken Shale by 2020, analysts from East Daley Capital Advisors Inc. told Hart Energy.
The project is in doubt following the Aug. 2 announcement that Enbridge Energy Partners (EEP) and Marathon Petroleum Corp. (MPC) would scrap their JV for the 450,000 barrel per day (bbl/d) Sandpiper in favor of an investment stake in the Bakken Pipeline System, which includes the 470,000 bbl/d Dakota Access Pipeline.
The proposed 24-in. and 30-in. Sandpiper would stretch 661 miles from near Tioga, N.D., to Superior, Wis., and is intended to ship Bakken crude to refineries in the Midwest and Canada. The project is slated to create 3,000 construction jobs.
Enbridge, developer of the Sandpiper, has said it would make a decision on whether to build the pipeline sometime in the third quarter, but in East Daley’s eyes, the pipeline likely won’t be built.
“Given the current forward curve, we don’t think it makes sense to continue with Sandpiper,” Justin Carlson, vice president and managing director for research at East Daley, told Hart Energy. “It was only about 70% committed when Marathon went over to Dakota Access, so they probably are even less committed now. I think it’s a tough road for Sandpiper to continue at this point.”
But Carlson views the unfolding events as a positive for the region.
“The (Bakken Pipeline System) merger is a sign of a well-functioning market,” he said. “The Bakken was overextending on pipeline capacity, given the downturn in commodity prices. By merging, the industry has rightsized for the market’s needs.”
The balance won’t come about yet, though. With Dakota Access scheduled to begin operations by year-end 2016, pipeline capacity in the Bakken will exceed the play’s output, Matt Lewis, East Daley’s director of equity research, told Hart Energy.
But not all production will move into pipelines because many producers are still locked into contracts to move their crude by rail, Lewis said. However, between now and the expected supply-and-demand equilibrium in 2019-2020, midstream operators will be, for the most part, protected by take-or-pay contracts.
Contracts can be a nervous subject since a bankruptcy judge allowed Sabine Oil and Gas Corp. to reject agreements in Texas. Because so many E&Ps are in distress while commodity prices remain low, many contracts are being renegotiated in a “blend and extend” format, Lewis said. That means that the rate of moving crude is reduced but the contract period is prolonged, which also works well for midstream companies.
And when finding capital is tough going for many in the upstream these, a struggling E&P can find itself with a sweet deal.
“What we’ve seen is that the midstream company, when they do a blend and extend with an E&P, they’re making a loan,” Jim Simpson, East Daley’s CEO, told Hart Energy. “They’re letting the E&P companies off the hook. It’s a way for an E&P company to finance using a midstream investor.”
Understanding the financial stress of E&Ps is a critical research component for East Daley, which focuses on crunching data to explain midstream risk to its clients in the hedge fund and debt fund space.
“To the extent that [E&Ps] are distressed, we will factor in a renegotiation that may not be good for the midstream,” Carlson said. “And if you know you have a contract on a system, that’s definitely something you need to put into your risk analysis.”
The Bakken’s rig count sets it apart from most unconventional plays in this downcycle—it’s rising.
“We’ve seen something that’s been unique in the second half of the year,” he said. “A lot of these companies have done new guidance for the rig count and in a lot of cases they’ve added rigs.”
While crude prices are considerably higher than the low point in February, the WTI price has not been able to climb into the $60/bbl range. Still, East Daley finds that the economics work.
Labor is much cheaper in the region now than it was a year ago when the rig count was in the 70s, Carlson said. With the count in the 30s, there many excess rigs that can be rented at much lower rates.
Another reason may be tied to strategy.
“Our thesis is those producers could have locked in forward prices at the high-$50s [in the second quarter] with derivatives, those prices on forward curves and decided, hey, at $55, we can actually produce in the Bakken and make money,” Carlson said.
Whether the rig count can stay up depends on the price of West Texas Intermediate. East Daley believes that prices in the high $40s and low $50s will sustain producers in the core of the core of the Bakken.
“The Dakota Access coming online will help netbacks for these companies,” he said. “These companies that are railing now are paying probably quite a bit more than what they’ll be paying if they have space reserved on Dakota Access Pipeline, so that helps the economics as well.”
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