Where does Bakken oil go? Increasingly, producers and end-users are working to send it to the U.S. Northeast to refiners that have been marginalized—some even shuttered—by Brent-priced waterborne crude that costs $25 or more than U.S. onshore sourced feedstock.

“We are talking to rail companies at this time about that potential in the future,” says Eric Le Dain, senior vice president, strategic planning, reserves and marketing, for Enerplus Corp. The Calgary-based E&P is making some 12,500 gross barrels of oil equivalent per day from its Bakken acreage in North Dakota with a projection to exit 2012 at 15,000 per day. It makes another 6,000 per day from the Bakken in Montana.

Sam Margolin, vice president and refining analyst for Dahlman Rose & Co., anticipates more Bakken oil, which is currently being consumed in the U.S. Midwest and on the Gulf Coast, will find its way to the East Coast as well as the West Coast.

“Bakken production is expected to grow much more, so off-take outside of the Midwest refining market is necessary,” Margolin says. “The Midwest has pretty much reached its maximum capacity of utilizing that crude.”

While EOG Resources Inc. and other producers are aggressively railing it to the Gulf Coast, new oil supply from nearer sources—the Eagle Ford, Permian Basin and Oklahoma—plus new Canadian oil-sands crude may make some Bakken oil less competitive due to transportation costs.

Neal Walters, partner, Americas, in consulting firm A.T. Kearney’s energy practice, says, “Once the pipeline infrastructure resolves the glut issue at Cushing and allows some of the Midcontinent and Canadian crudes to get to more markets, that West Texas Intermediate (WTI)/Brent differential will head closer to historical levels.”

The Bakken story began in 2004, when Continental Resources Inc. drilled the first successful horizontal in the formation. Today, the play is making some 700,000 barrels a day, elevating North Dakota recently to the No. 2 oil-producing state in the nation behind Texas and ahead of Alaska and California.

Continental alone was making 74,000 barrels per day in the second quarter of 2012. Stephen Bradley, Continental’s vice president, oil marketing, told Bentek Energy symposium attendees in Houston this spring, “We will see North Dakota production continue unabated unless the price collapses.” Differentials to WTI that Continental had seen in the first half of 2012 ranged from -$4 in January to -$30 in February to about -$1 in May. As differentials swing wildly, “somebody gets burned a lot,” he said.

Differentials have improved in the second half of this year, however, says Enerplus’ Le Dain. The company gained its Bakken position in 2005 via a prescient acquisition of Texas-based wildcatter Bobby Lyle’s Lyco Energy Corp. Enerplus currently ships its Bakken oil via rail to the Gulf Coast, on Enbridge Inc.’s North Dakota system to Clearbrook, Minnesota, and on the Butte system to Guernsey, Wyoming, which serves that refining region and points east.

In the first quarter, Enerplus’ Bakken differentials in the field were some $15 below WTI. That began to improve in the spring, and further in the third quarter. “In fact, in October, the differential was mostly removed. But it is widening again in December contracts,” Le Dain says.

Margolin says Bakken production—among that of the Lower 48—has had the most volatile differential patterns. “Bakken prices sort of move all over the place relative to WTI. I think that suggests it doesn’t really have a natural offtake center. It is figuring out its market as we go.”

And, the Gulf Coast might not be the best market for all Bakken output in the future. “The Bakken has benefited during the past 12 to 18 months from having good access to the Gulf Coast, but there is a lot of crude migrating there now, so the Bakken is potentially going to be less competitive,” Margolin says.

Other coasts

So where to? Two new markets may help narrow the gaps: the East Coast and the West Coast. Some Bakken crude is making its way to the Northeast—where all of the U.S. PADD 1 refining capacity is concentrated currently—via rail to Maine and then barged south.

But, that’s expensive, Margolin notes. “What Carlyle Group is doing at Philadelphia is building a lot of its own infrastructure to directly receive those shipments, so they don’t have to use third-party barges and which dramatically increases the volume a single plant can bring in from the Bakken.”

In that deal, The Carlyle Group LP has purchased Sunoco Inc.’s Philadelphia refinery— the largest on the East Coast at 330,000 barrels a day—with an aim of making it newly economic by bringing in Bakken crude and using new Appalachian natural gas and gas liquids. Delta Air Lines Inc. is having some success with getting Bakken oil to its newly acquired Trainer, Pennsylvania, refinery, Margolin adds, but the company isn’t reporting much about the operations. “It’s a bit of a black box at this point.”

Plains All American LP has developed a rail terminal at a former refining complex in Yorktown, Virginia, to ship Bakken oil received via rail to other East Coast refineries.

Brad Olsen, vice president, equity research, for Tudor, Pickering, Holt & Co. Securities Inc. (TPH), noted in early November that some 3 million barrels a day of onshore-priced oil is beginning to arrive on the Gulf Coast via new pipe. “To a lesser extent,” he adds, “the onshore advantage will also spread to the East and West coasts as refineries there increase their ability to receive Bakken and other onshore crudes.”

Margolin says that driving the East and West coasts as additional important off-take centers for Bakken oil in the future is that Gulf Coast refiners aren’t equipped to handle light, sweet oil exclusively. For East Coast refiners, a disadvantage they created in strategy in the past century may be an advantage today: Southern refiners upgraded to handle more heavy oil sourced from Latin America; meanwhile, East Coast refiners are already able to handle all the Bakken-sourced light, sweet they can get.

On the West Coast, where imports have grown over the years as Alaskan and Californian production have declined, refiners are accustomed to the slate of low-,medium- and heavy-gravity oil. Refiner Tesoro Corp. is looking at railing Bakken oil all the way to southern California, where it plans to buy BP Plc’s 266,000-barrel-per-day Carson refinery.

“That rail distance is expensive, but Tesoro is talking about it,” Margolin says. It is already getting some 30,000 barrels a day to its Anacortes, Washington, facility via rail with plans to expand this to 60,000 a day.
Also, BP Plc plans to import Bakken oil to its Cherry Point, Washington, refinery.

Margolin says, “It’s not as expensive to get it to the Pacific Northwest as Southern California. Tesoro will only have to pay $8.50 a barrel for transport, which is cheaper than what it costs to get it to the East Coast. The Bakken is closer to the West Coast. It’s just a straight shot west to Seattle.”

TPH managing director and head of integrated oil research Robert Kessler notes that Tesoro’s plan for Carson, California, is to use less Alaskan oil and more distressed Lower 48 oil. It estimates rail costs from the Bakken to southern California are some $12.50 per barrel. Alaskan oil transportation also costs some $12.50 a barrel. At Tesoro’s Anacortes, Washington, refinery, the $60-million bill for adding the 60,000-barrel-per-day rail terminal for Bakken crude is expected to pay for itself in two quarters, he adds.

“Long term, Tesoro expects—and so do we—Bakken prices to have strong differentials and be priced based on LLS (Louisiana Light Sweet) and rail prices to the Gulf Coast,” Kessler says.

Producers take note, however: Kessler says the current wait for new rail cars is some 18 months.

Refining markets

Is enough East Coast demand still in place? The TPH research team noted this spring that some 50% of Northeast refining capacity had closed or was closing. Since then, Carlyle Group bought the Philadelphia complex that will continue operations and Delta Air Lines bought the Trainer facility.

Margolin says, “I don’t expect significantly more closures, at least the way the market is currently.” To sum up the destruction in the PADD 1 refining complex, it imported 1.6 million barrels of crude oil a day in mid-2007. This year, it is importing 1 million a day.

A.T. Kearney’s Walters says the decline is seen all along the Eastern Atlantic Basin. “There were two world-scale refineries in the Caribbean—one in Aruba and one in the Virgin Islands, totaling more than 700,000 barrels of daily capacity—that are mothballed. They are just not economically viable at today’s waterborne crude price.”

Far north along the eastern Atlantic Basin, Royal Dutch Shell and BP have each applied for permits to import Bakken and other Lower 48 oil to Canadian Maritimes refineries. While exporting U.S.-produced oil requires federal approval, Margolin says that receiving permission to export it to Canada is not difficult. “Canada has a lot of refining capacity and some of the product gets exported back to the U.S., so the regulatory authorities don’t feel as though exporting crude to Canada is a restriction in domestic supply.”

Walters, who is based in Toronto, says that further relief in pressure on new supply to the Gulf Coast will be opening an outlet for Canadian oil-sands production to the Pacific Basin, accessing the West Coast refining complex and, possibly, Asia.

“Keystone XL by itself won’t be enough to secure markets for all the incremental oil-sands crude. There is potential for another 2- to 3 million barrels a day coming onstream in the next decade,” he says.

To him, modern North American oil dynamics are not entirely a surprise. “The potential for the oil sands and the oil-shale revolution was well known five years ago. But I think the extent of how massive and fundamental the revolution is has brought change that has caught many, if not most, of the industry pundits a bit by surprise.”

Margolin notes that expectations of dwindling world oil supply had been powering oil prices until a few years ago. Today, instead, North Sea, West African, North African and other barrels that had a ready market in the U.S. are seeking other homes, such as Asia.

“There is some concern among producers that the world oil price can go lower from here,” Margolin says. “The kind of price environment that we saw in 2007 and 2008 when ‘peak oil’ really sort of controlled the price-action valve is probably not coming back for a while.”

Meanwhile, for getting more Bakken production to markets, it’s going to be rail, he adds. “It is the cheapest and easiest to scale up. It’s difficult to get a pipeline of the size that is needed commissioned and built relative to simply adding terminal capacity. The railroads are already there.”

Walters concludes that the East and West coasts offer the most favorable price economics to Bakken producers today, and something has to give in the U.S. Midwest refining market. Traditionally, feedstock has come to it from the Gulf Coast and from western Canada. “The challenge refiners are going to face is on the demand side. Between the advent of biofuels, now the potential to go to 15% ethanol and the fairly dramatic increase in fuel economy, it is pretty much going to hold domestic gasoline demand flat.

“That is regardless of how quickly Bakken and other shale-based crudes come online.”

Regarding the East Coast refining corridor, Margolin makes one more note: Oil shipments to the U.S. Northeast were expected in the past decade to decline because refining capacity would be replaced by cheaper refined-product supplies from overseas. What has turned the global oil market on its head is that North American oil production is experiencing growth. So, “we always expected to import less crude, but the fact that we’re not importing product either is what has been the big surprise.”