Earlier this decade, East Coast refineries found it cost-effective to ramp down their crude imports and turn to the price-advantaged U.S. shale oil they could rail in from the pipeline-constrained Bakken or send up by tanker from the crude-saturated Gulf Coast. Things changed, though. New southbound crude pipelines out of the Bakken came online, the ban on most crude exports was lifted — providing a new outlet for Texas crude production — and the economic rationale for railing or shipping in domestic crude to PADD 1 refineries withered. Now, things have changed again. Most important perhaps, is that the price spread between WTI and Brent has widened, and once more it can make financial sense for these refineries to revert to crude-by-rail out of the Bakken and to shipping in crude on Jones Act tankers from Corpus Christi and other Gulf Coast ports. Today, we discuss these recent trends, what’s driving them, and how long they might last.
The nexus of East Coast refineries’ crude supply, including CBR from North Dakota (PADD 2) to PADD 1 refineries, and shipments of Eagle Ford, Permian and other light, sweet crude from the Gulf Coast to PADD 1, has been a frequent topic in the RBN blogosphere — especially in the early years of the Shale Era. As we said in While CBR Gently Weeps, Bakken production growth in the early 2010s far outpaced the addition of new pipeline capacity, and building rail-loading terminals represented a logical, near-term fix. For one thing, these terminals could be constructed quickly and at relatively modest cost; for another, using the rails gave shippers destination flexibility (allowing oil to be moved to wherever the netbacks were highest). The East Coast turned out to be a logical market — refineries there were set up to process light, sweet crude, the vast majority of which they imported from West Africa and other foreign sources, generally at prices tied to the Brent benchmark. If the delivered cost of price-discounted Bakken crude (including the cost of transportation by rail) was lower than the cost of imported crude — and it was — why not rail in more Bakken crude and back off on the volumes being imported?
Similarly, production in the Eagle Ford, the Permian and other shale/tight oil plays near the Gulf Coast was rising fast in the first half of the 2010s, but there was only so much light, sweet crude that the complex refineries in Texas and Louisiana could absorb — generally speaking, these facilities were configured to refine a heavier, more sour crude slate. There was a ban on most U.S. crude exports through 2015, though, and burgeoning supplies of West Texas Intermediate (WTI) crudes (at Cushing) had driven down the WTI price in relation to Brent, so why not ship price-discounted light, sweet crude from Corpus Christi and other Gulf Coast ports to refineries in the Mid-Atlantic region? Again, Jones Act tankers provided the favorable economics.
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