One of the biggest notable successes of the U.S. shale boom has been the ability of large amounts of domestic supply to back out crude imports from West Africa. This victory is now being tempered. U.S. East Coast refineries have increased the volumes they are taking from West African producers, largely because of tighter spreads between international benchmark Brent and Bakken prices, which are altering the economics of railing crude from the Midwest.
U.S. East Coast refineries have increased the volumes they are taking from West African producers, largely because of tighter spreads between international benchmark Brent and Bakken prices.
The volumes being shipped to the U.S. are relatively small, but could be a sign of things to come. As producers have grappled with low prices for over a year and production is slowly but surely tapering off, the U.S.’ dependence on West Africa will likely rise. U.S. refineries imported more than .25 million barrels per day during three of the last four months, versus just .12 mbd in January.
It was understood by many market observers that imports from West Africa couldn’t compete in the U.S. market with American tight oil. In 2010, just before the shale boom really took off, the U.S. imported some 1.53 mbd from West African producers. Angola and Nigeria sent the largest chunk to the U.S., with Congo (Brazzaville), Equatorial Guinea, and Gabon making up the rest. Imports are unlikely to reach that level again in the near term, but refiners on the East Coast are gearing up to take more from overseas.
Oil produced in West African countries is light, sweet crude, comparable in quality to U.S. shale. Because of these similarities, as well as the price discounts of American crude, imports from West Africa were the first to be backed out by East Coast refineries. But the cost of railing crude from the Midwest to refineries along the Atlantic coast is expensive and requires wide spreads between Bakken crudes and Brent, which West African grades are priced off of. The problem is that Bakken grades—which cost at least $10-$15 per barrel to rail to market—need to trade well below Brent to give East Coast refiners enough economic incentive to pay for rail shipments from the Bakken, which stretches through North Dakota, Montana and a small part of South Dakota.
Although crude in the Bakken still trades under West Texas Intermediate (WTI), which is roughly $3 under Brent, the economics simply aren’t as attractive for East Coast refiners who enjoyed Bakken-Brent spreads averaging around $20-$30, or even higher, from 2011-14. The spread between the two has narrowed considerably and will continue to be volatile. Over the summer, Bakken at trading at Clearbrook, Minnesota was at one point near parity with WTI, effectively wiping out any incentive to rail to the East Coast. Now, with the Bakken-Brent spread fluctuating around $15 and Brent-WTI at just $3, volumes from the Bakken are having a hard time competing with imports.
Now, refineries in Philadelphia, New Jersey and Delaware can buy from West African sellers, who have cut differentials to make their crudes more attractive in the oversupplied Atlantic basin. Nigeria is having a hard time selling its crude for December and still has 10 million barrels available for November, while exports from Angola are poised to reach a six-month high of 1.82 mbd for December, notes Barclays in a recent research note. Nigeria’s largest crude, Qua Iboe, is valued at just 40 cents above Brent, one of the lowest levels in years, a reflection of how desperate West African producers are to find buyers.
Reuters reported last week that refiners with assets on the East Coast, such as PBF, Philadelphia Energy Solutions and Delta Airline’s Monroe Energy, are preparing to increase crude imports next year, reversing the trend of railing more barrels from the Bakken. Output from the Bakken is the only crude from the shale boom that can help refineries on the East Coast. Any crude from shale fields in the Eagle Ford or Permian, for instance, is sent to Gulf Coast refineries. So, once Bakken crude becomes less economical or output falls, East Coast refineries have to look to foreign suppliers. Besides crudes from West Africa, refiners on the East Coast have recently imported volumes from Azerbaijan, Norway, Chad, Mexico, Iraq, Canada, and Colombia, based on Energy Information Administration (EIA) data.
Output set to decline
While output in the Bakken has held up relatively well, it is set for a dramatic decline, making East Coast refineries further dependent on imports. The wealth produced from North Dakota’s oil boom has spawned overnight millionaires driving Ferraris, some of the lowest unemployment rates in the country in the years following the 2008 recession, and a bad ABC soap opera called Blood & Oil starring Don Johnson. The show is doing so poorly that it probably won’t see a second season, but if it is renewed, the plot will have to shift from dealing with wealth and abundance to break-even prices, access to capital markets, cost-cutting measures, OPEC’s “free-market” policy, and the narrow WTI-Brent spread.
While output in the Bakken has held up relatively well, it is set for a dramatic decline, making East Coast refineries further dependent on imports.
In a report published last week, Oxford Institute for Energy Studies predicted that Bakken output will “decline considerably” in the coming months. Production has been able to hold steady for the past year or so in North Dakota near the 1.2 mbd level as a result of higher initial production per well and lower break-even prices from cost-cutting and improved efficiency. But even though output has been mostly stable, it is on the decline, indicating that the massive drop in the rig count, which has fallen by 134 since last September in North Dakota, is finally starting to impact production levels.
Output is mainly in the core acreage areas, while activity outside the core has been very small. This indicates that fewer new wells are being drilled.
Output is mainly in the core acreage areas, while activity outside the core has been very small. This indicates that fewer new wells are being drilled. The number of permits being filed is also on the decline, signaling lower production in the future. Moreover, the authors of the Oxford Institute report note that more than two-thirds of the production in the Bakken is held by just 10 companies, some of which have global assets. “Their internal strategies, exposure across the U.S. and internationally, access to capital, and overall liquidity all factor into activity levels in the Bakken,” the report says. “Many of these operators plan on maintaining roughly the same rig count as they have right now, however this could easily change as oil prices remain in the $40 range.”
Although there are differences between the Bakken and other shale plays in the U.S., such as the Permian and the Eagle Ford, the outlook is starting to shift throughout the whole sector. The Oxford Institute study concludes: “Low oil prices will not kill the US shale industry, but they may put it into hibernation. Further rock analysis and technological advances need to be made in order to move the industry forward and reduce costs. Severe CAPEX cuts will reduce these advances in the near term.”