By 2014, the U.S. will import just 6 million barrels of crude oil per day, or roughly a third of what it uses, according to a recent forecast from the federal Energy Information Administration. That’s less than half the amount of 2006, when imports accounted for 60 percent of total U.S. oil consumption.
America’s domestic oil boom is revamping decades’ worth of established trading patterns. As the U.S. continues to ramp up production—which grew at the fastest pace ever last year—the imports that do continue coming into the U.S. will depend as much on what type of oil it is as on how far it must travel. For those reasons, Canada will remain America’s biggest oil supplier. Not only is Canada close, and can pipe its oil over the border, but its heavy, sour crude is exactly what U.S. refiners want.
Before the shale fracturing boom hit a few years ago, it seemed that the future belonged to heavy, sour crude like the stuff in western Canada’s oil sands, while the light, sweet variety would become increasingly dear. U.S. refiners spent billions installing new coking equipment to increase their ability to process this gunky, sulfury type of oil into gasoline. The irony is that by the time many of these projects were completed, the U.S. was suddenly awash in light, sweet crude gushing out of shale formations in North Dakota, Texas, Pennsylvania, and elsewhere. There are now more than 50 million barrels of oil—most of it the light, sweet kind—stuck in the storage facilities outside Cushing, Okla.
So now those refineries that upgraded are somewhat trapped. If they buy light, sweet oil, they’ve wasted their investment. “I think those refineries will be reluctant to eat the cost of those new coker units they’ve installed,” says Tim Evans, an energy analyst at Citigroup (C). The best way for them to get a return on that investment, he says, is to process heavy, sour crude, which has better margins since it still costs less than the light, sweet stuff. Thus, despite the abundance of high-quality crude, available locally, demand for heavy, sour oil from abroad will remain high in the years to come.
A new study from energy research firm IHS CERA (IHS) predicts that the U.S. will remain the primary market for oil sands. That’s good news for Canada, and (for now) Mexico and Venezuela. I say for now because if TransCanada’s (TRP) Keystone XL pipeline gets approved, Canada will be pushing 1.5 million barrels a day of heavy, sour crude to the Gulf Coast by 2015. Suddenly oil from Mexico, Saudi Arabia, and Venezuela will be competing against the cheaper Canadian product. “The Gulf Coast market’s not big enough to take new Canadian crude and maintain current imports,” says Edward Morse, head of commodities research at Citigroup Global Markets, and a noted oil forecaster. “Something has to give.”
This also means a steep drop in oil from Africa, mainly from OPEC’s biggest West African members, Nigeria and Angola. Since July 2010, the U.S. has cut its Nigerian imports by half, from more than 1 million barrels a day, to 543,000 as of October 2012, the most recent data available through the EIA. Imports from Angola have dipped below 200,000 daily barrels, from an average of 513,000 in 2008. “By the second quarter of this year, we will stop importing West African light, sweet crude into the Gulf,” Morse predicts.
Those barrels will have to find another home, more than likely India, China, Europe, and Korea. Displacing them from the U.S. market will probably lower prices overall as producers see greater market competition. Morse believes that $90 will be the new ceiling for oil prices, rather than the floor it’s been in recent years, a transition he anticipates will be “highly disruptive.”
As the U.S. continues to boost crude oil production, global oil trade routes will change more in the next decade than they have in a very long time.
