In the three months since the U.S. lifted its 40-year ban on crude oil exports, a curious thing has happened. Rather than flooding global markets, U.S. crude shipments to foreign buyers have stalled. At the same time, imports into the U.S. jumped to a three-year high in what looks to be a reversal of a yearslong decline in the amount of foreign crude brought into the American market.
As of March 25, the four-week average of imports was running at 7.9 million barrels a day, 9.8 percent higher than the year before. “That’s not a one-week blip,” says Tim Evans, an energy analyst at Citi Futures. “We’re seeing a consistent pattern.”
U.S. producers, who reaped the benefits of the shale revolution, no longer enjoy a steep price advantage over foreign rivals in selling to domestic refiners. Production has fallen by about 600,000 barrels a day from its peak of 9.6 million in 2015. Now refineries are buying foreign oil to replace the lost U.S. output—and, along with traders, are storing much of the less-expensive imported oil to sell when prices rise.
During the early years of the U.S. shale boom, the millions of barrels of light, sweet crude had one big problem: no affordable access to refiners on the coasts of Texas and Louisiana. To tap into the cheaper oil pooling in Oklahoma, pipelines that used to bring imported oil up from the Gulf were reversed to take shale oil down to the coast. Refiners in Philadelphia and New Jersey also began buying North Dakota crude instead of foreign oil, moving it by train across the country. By October 2014, U.S. imports had fallen by about 40 percent from a high in 2006.
Analysts say that West Texas Intermediate crude has to be $3 to $5 cheaper than imported oil to pay for those pipeline and transportation costs. From 2011 to 2014, U.S. oil was on average $12.61 cheaper than equivalent foreign oil. The discount slowly narrowed as pipeline projects were completed and U.S. crude began to flow more freely from the middle of the country down to the Gulf Coast. A week before the Senate approved lifting the export ban on Dec. 18, WTI traded around $3 below Brent. Over the next month, the discount disappeared, and, for the first time in six years, WTI traded at a premium to Brent for a few days in January. WTI is now less than a dollar cheaper than foreign barrels available on the Gulf Coast.
So refineries along the coasts are choosing to buy imports instead of WTI. One of the biggest winners is Nigeria, which is regaining lost market share. Imports from Nigeria surged to 559,000 barrels a day in mid-March, compared with an average of 52,000 for all of 2015. Refiners are also taking more heavy oil from Mexico and Venezuela. Not only is it about $9 a barrel cheaper than WTI, it’s also what U.S. refineries prefer to handle.
The irony of the shale boom, and all the light crude it unlocked, is that it came just as U.S. refiners were spending billions to process heavy oil. “In theory, there was always going to be a linkage between freeing up U.S. barrels and replacing them with foreign crude that U.S. refiners are better suited to run,” says Kevin Book, managing director at ClearView Energy Partners.
For some of the weakest U.S. producers with the highest costs, lifting the ban didn’t matter because they can’t compete on the global market, says Abudi Zein, co-founder of ClipperData, which uses customs data and ship-tracking information to estimate global oil flows. For U.S. producers with the highest costs, “they’ll never be able to export because all of a sudden they’re competing with Saudi Arabia and Iraq.”
The U.S. is hoarding a lot of the imported oil. As of March 25, U.S. commercial crude inventories hit 534 million barrels. That’s near the all-time high in 1929, when U.S. commercial storage hit 545 million barrels, as huge oil finds coincided with the beginning of the Great Depression.
Today, with oil so cheap, producers and traders are opting to wait for prices to rise instead of selling, especially with the futures market signaling that oil prices will rise. Traders can lock in those prices by taking out a contract for delivery a few months down the road. A barrel of WTI for delivery in October is about $3.50 higher than the current price of about $39. That premium has dipped in recent months, but it’s still enough to pay for insurance and storage costs—with money left over.
“Putting away oil is one of the few risk-free plays in the world right now,” says Philip Verleger, an energy consultant and former director of the office of energy policy at the Department of the Treasury. Fears of a lack of storage space for oil haven’t come true. As of September 2015, the U.S. had 551 million barrels of working oil-storage capacity, 50 million more than it did two years before, according to government figures. Genscape, an oil-market-surveillance company, estimates that in the Midwest and the area along the Gulf Coast, the pace of construction has increased since September to about 574,000 barrels of new storage—big enough to hold a 747—a week.
The construction has helped keep leasing costs relatively low, says Ernie Barsamian, a principal at The Tank Tiger, a tank-storage broker. Average prices for a one-year lease of a storage tank run about 60¢ to 70¢ per barrel a month, he says. Barsamian estimates it costs about $40 to $50 a barrel to build a storage tank and that companies that own them can make their money back in five years or so.
As long as futures prices remain higher than current ones, the incentive will remain to pump oil and store it. That leaves the U.S. stuck in a strange pattern where “the higher inventories go, the more downward pressure that puts on near-term prices, which only increases the incentive to store it,” says Citi Futures’ Evans. The only way to break that cycle is for interest rates to rise, says Verleger, which would increase the financing costs to build storage tanks. “As long as money is cheap, it’ll make sense to build storage tanks in the U.S.”
The bottom line: U.S. oil production has fallen by about 600,000 barrels a day since peaking in 2015, and imports have filled the gap.