Moored at Valero Energy Corp.’s dock in south Texas, the Liberian-flagged Afra Willow is unloading 300,000 barrels of imported, semi-processed crude oil to the company’s Bill Greehey refinery, where it will be further refined into gasoline, diesel and petrochemicals.
On the same dock, Valero is building a terminal to export light crude from Texas’s surging Eagle Ford field to the company’s refinery near Quebec City. Nearby, it is building two crude-processing units that will allow it to handle more light, Eagle Ford oil at the Corpus Christi plant.
Valero has long counted on imports from Russia and the Middle East to feed its Corpus Christi refinery. But America’s long reliance on imported oil is quickly fading as domestic output soars, and booming tight, light oil production in Texas is forcing major rethinking in the massive Gulf Coast petroleum market.
The U.S. oil surge has already reduced to a trickle imports of light oil to the Gulf Coast. Now the resurgence in American production is creating challenges for Canadian producers – not only on the Gulf Coast, but in their traditional markets in the Midwest and even in eastern markets where the Canadian industry is hoping to gain new customers through TransCanada Inc.’s proposed Energy East pipeline.
Western Canadian producers, eager to boost output and spark lacklustre share prices, have been desperate to expand their access to new markets, where prices are higher. But the competition within North America will only intensify, making it more important than ever that the industry can reach foreign markets through new pipelines to the west and east coasts.
The flood of tight, light oil production into the continental market is expected to drive a widening discount between North America and international prices, creating new problems for Canadian producers. While many refiners will still want oil sands bitumen to feed refineries specially configured to process heavy crude, the U.S. surge still poses risks for Canada, particularly since a U.S. ban on oil exports to countries other than Canada means virtually all of its crude production remains in the country.
“We sell into the U.S. market,” said Jackie Forrest, Calgary-based director of global oil for the consultancy IHS Inc. “So if the prices of light sweet crude come down, then in order to keep heavy crude still being demanded by those refiners, our prices will have to come down too.
“So the implication is, as long as the U.S. continues to have the export ban, Canadian producers will have lower prices than they otherwise would have.”
Based in San Antonio, Tex., Valero is the largest independent refiner in the United States and has pivoted away from a heavy oil strategy to take advantage of the new light oil supply.
Half a decade ago, Valero and other refiners in the United States expected to see a decline in the availability of light oil on global markets and an increasing reliance on heavier grades from Canada’s oil sands, Venezuela and Saudi Arabia. They made multibillion-dollar investments in the cokers that are required to process the heaviest grades of crude.
But all that has changed. This year alone, the company will spend more than $400-million (U.S.) to expand its capacity to process light crude, and $865-million on logistics like rail and shipping terminals to make sure its refineries can have access to growing quantities of domestic light crude but also increased supplies of Canadian oil sands bitumen for the plants that are configured to process it.
At its 265,000-barrel-a-day (b/d) plant in Levis, Que., the company expects to end its dependence on offshore supplies by next year. It plans to barge oil down the St. Lawrence River from Montreal once Enbridge Inc. completes the reversal of its Line 9; it will be able to ship 50,000 b/d from Corpus Christi to Quebec, and it has expanded its rail capacity to 55,000 b/d.
But its major work involves retooling two of its biggest Texas refineries.
“As far as the big single investments, we are building new crude units at the Houston and Corpus Christi locations, and that is specifically to process more light crude at those locations, Valero spokesman Bill Day said. The company expects to nearly double its capacity to refine light oil in just a couple of years to 1.4 million barrels a day.
The sprawling plant at Corpus Christi processes 325,000 barrels a day of crude and semi-processed feedstock in what the company bills as “one of the world’s most sophisticated and technologically advanced refineries.” While the Bill Greehey refinery – and the industry as a whole – saw some tough times in the middle of the last decade when margins collapsed, it is now riding the wave of the American energy renaissance.
North American refiners are benefiting from the shale gas revolution that drove down the price of natural gas, giving them a significant cost advantage over their global competitors. Now, the boom has spread to oil, and not just in North Dakota’s Bakken but in Texas fields like the Permian Basin and the Eagle Ford. That has created a continuing discount – now at $5 a barrel – between domestic crude and international supply.
“The big deal with the Eagle Ford is price, and it’s right in our backyard,” said Dennis Payne, plant manager at the Bill Greehey refinery. “This plant was built to run on heavy [oil], about as heavy as heavy can be.” But its new crude units will allow it to process 70,000 barrels a day of light oil.
Texas’s production has more than doubled in four years – from 950,000 barrels a day in 2009 to 1.96 million barrels last year, the highest since 1987. And it could easily double again by 2020, Barry Smitherman, head of the Railroad Commission of Texas which regulates the industry, recently told an industry conference in Houston. However, the pace of production growth depends on a number of factors, including technical challenges in extraction, domestic oil prices, the fate of the export ban, and the path of interest rates which could drive up costs in a capital-intensive business.
Despite the surge in light supply, Valero remains a vocal supporter of the Keystone XL pipeline and other projects that will bring more Canadian heavy crude to the Gulf Coast. “Even if you are processing all the light oil you can, there’s still going to be some demand for heavy crude,” Mr. Day said.
There is 2.4 million barrels a day of heavy oil processing capacity in the region, thanks to all that investment in cokers. And with declining Mexican and Venezuelan production, the refiners are keen to secure access to more Canadian crude.
“There is still some healthy demand for the heavy stuff down in the Gulf,“ said Tony Starkey, an analyst at Bentek Energy, a unit of McGraw Hill Financial Inc. “The refiners can only tune themselves so much to run this light stuff before they start hitting capacity constraints and more significant capital expenditures will be needed to run the light.”
Meanwhile, the tight, light oil is trapped in North America by government fiat – a four-decade-old ban on crude exports that only allows exemptions for U.S. free-trade partners such as Canada. Backed by some powerful members of Congress, U.S. crude producers are pushing for Washington to end the ban. But no one expects that to happen quickly and companies like Valero are arguing the government should move slowly.
One issue they cite is the Jones Act, which requires shippers between U.S. ports to use American-flagged, American-built and American-crewed vessels. That maritime law makes it considerably cheaper to ship crude from Texas to Quebec than to Philadelphia or the New York harbour. Valero says the cost of shipping crude to the U.S. East Coast by Jones Act vessel is $5 a barrel, compared to $2 on a foreign vessel to Eastern Canada.
IHS’s Ms. Forrest said there are some potential “relief valves” for the building supply of crude from North Dakota and Texas and other states. With expanding rail, barge and shipping capacity, the U.S. crude will replace imports of imported light oil in the eastern U.S. and Canada, as well as the west coast. At the same time, Gulf Coast refiners are adding as much as 700,000 b/d of refining capacity to handle the light crude. There is also a push to build “crude splitters” – prerefining processing units that allow producers to evade the export ban.
Still, Canadian producers face a continental market that will be awash in crude unless or until the Americans end their prohibition on exports. As a result, both oil sands companies and light oil producers in Western Canada are going to have to find new markets overseas, said Patricia Mohr, energy economist at the Bank of Nova Scotia.
“It’s just another reason to want to build some export pipelines,” Ms. Mohr said. Canadian producers “really need more to get their production into bigger markets in Asia Pacific, given the rapid development of U.S. light, tight oil.”