America's Oil Boom: Shape Up or Ship Out

America's newfound natural-gas bounty has already sparked arguments over whether or not to export it. Soon, it will be oil's turn.

The International Energy Agency reckons the U.S. could become a net oil exporter around 2030. It is a tantalizing prospect. But crude-oil exports will make headlines well before 2030. Try next year.

U.S. crude-oil exports are heavily restricted. Refined products such as gasoline can be shipped abroad more easily—indeed, the U.S. became a net exporter of these last year for the first time since 1949. Refiners have been selling increasing amounts in foreign markets as domestic demand has sagged amid economic sluggishness and renewed energy-conservation efforts.

Pressure to export crude oil won't grow because the U.S. will suddenly no longer need imports. The Department of Energy expects net imports to meet 39% of domestic oil consumption in 2013. Rather, it is a matter of logistics.

The rapid increase in onshore U.S. oil output in states such as North Dakota, as well as rising Canadian oil-sands output, has created a glut in the Midwest. As a result, domestic grades sell for less than international benchmarks such as Brent. West Texas Intermediate, or WTI, trades at about $87 a barrel, $22 or 20% below Brent. Grades from further inland often command even less.

While refiners, pipeline operators and rail companies are investing to get these cheaper crudes toward markets like the East Coast, the current logistical setup still favors the Gulf of Mexico coast. This region is home to almost half of U.S. refining capacity. Gulf Coast refineries are running flat out already. Moreover, many are set up for a world in which the U.S. imported lots of heavy, high-sulfur crude oil, whereas much of the output from expanding onshore fields is light and low-sulfur or "sweet."

Just under 800,000 barrels a day of light, sweet crude is currently imported to the Gulf Coast for processing, according to analysts at Raymond James. As onshore output of oil increases, these light, sweet imports will be replaced by domestic barrels. Raymond James estimates this will happen by the second half of 2013.

Gulf Coast refiners will tweak their plants to let them use more domestic light, sweet crude. But a growing surplus of these barrels in the Midwest with few easy options to get to market looks unavoidable.

So expect a push by exploration and production companies to ease export restrictions on oil in the same way they are pushing for natural gas. Gas accounts for about two-thirds of the E&P sector's output. But profits—and stock-price performance—hew more to oil.

Equally, expect the other part of the industry, refiners, to resist. Just as petrochemical firms such as Dow Chemical profit from the glut of domestic gas, refiners able to process cheap domestic crude are enjoying a windfall. Looked at on a rolling three-month average, the premium for gasoline sold in the Gulf Coast region over WTI is around $28 a barrel, close to its highest ever.

That margin could be a political liability. It is easy to envisage export-ban supporters arguing it is unjust to sell domestic crude overseas while Americans pay high gasoline prices. But as that margin shows, the benefits of cheaper crude flow first to refiners. Since gasoline produced on the Gulf Coast can be sold anywhere, Americans must compete for it—that is, pay up. Changing that would actually require raising barriers to refined-product exports, protectionism that neither the world nor refiners would welcome.

Whether such nuance can be squeezed into a political sound bite is another matter. But all politicians, drivers and investors should consider this: If E&P companies find themselves forced to sell oil at persistently lower prices because of logistical and trade constraints, they will eventually curb their output. At that point, the IEA's projections go out the window, and everyone pays more.
Liam Denning