U.S. sanctions on Venezuela have American refiners scrambling to find new sources for the dense crude oil they need to make fuel, but Canadian producers are finding the opportunity too expensive to exploit.
The U.S.’s northern neighbor, the world’s fourth-largest oil producer, would be a natural candidate to make up for the loss of Venezuelan supply. But much of Canada’s heavy crude is landlocked because of a shortage of pipeline capacity. Canadian producers have been getting around the pipeline bottlenecks by using trains to carry more crude to the U.S., moving an average of more than 320,000 barrels into the U.S. daily as of November, according to the Energy Information Administration. But recent data suggest Canada-to-U.S. rail shipments—which cost more than moving oil through pipelines—are now decreasing sharply because they aren’t economically viable at current oil prices.
The lack of transport options means Canadian producers can’t easily meet the needs of refineries on the U.S. Gulf Coast now cut off from Venezuelan crude.
“For them to really capitalize on the market gap that is left with Venezuela is extremely difficult,” said Clara McGrail, an energy consultant for FTI Consulting Inc.
While U.S. oil production is at record highs, hitting 11.9 million barrels a day in November, according to the EIA, America still imported on average about 7.9 million barrels of oil daily that month, of which roughly 500,000 barrels a day came from Venezuela.
The U.S., which mostly produces light crude, needs the heavier varieties of oil found in places such as Venezuela, Canada and Saudi Arabia because many domestic refineries are designed to process a mix of oils. U.S. sanctions have threatened the supply of heavy crude, making that type of oil more expensive.
That hurts refiners and could eventually cause U.S. fuel prices to rise for everything from gasoline to diesel to jet fuel, though high gasoline inventories likely will blunt the impact on consumers. Gasoline and diesel prices have increased by less than 1% since the U.S. announced the sanctions on Venezuela last month, according to the EIA.
Moving crude to the U.S. was an attractive prospect last fall, when heavy crude was selling locally in Canada for more than $50 a barrel below U.S. benchmark prices because of the pipeline constraints. However, the province of Alberta, fearful that low local prices would destabilize local producers, invoked rarely used legislative powers to curtail oil production in December to rein in growing crude inventories. While the curtailment propped up the price of Canadian crude, it also reduced the economic incentive to send crude to the U.S. by rail by narrowing the price disparity.
Transporting a barrel from Canada to the U.S. Gulf Coast costs about $20 by rail, compared with about $12.50 by pipeline, according to energy investment bank Tudor, Pickering, Holt & Co. That shipping cost exceeds the current difference between U.S. and Canadian benchmark crude prices, which was at $10.70 a barrel Wednesday afternoon, according to RBC Capital Markets.
Imperial Oil, a Canadian oil sands producer controlled by Exxon Mobil Corp., cut its rail shipments this month. The company now expects shipments from its Edmonton rail loading facility to stop entirely in February. In December, it averaged 168,000 barrels a day.
Richard Kruger, Imperial’s chief executive, said Alberta’s market intervention had caused prices to jump too high, making train shipping uneconomical. In comments to analysts, he called the curtailment order “ill-informed.”
A spokesman for Alberta’s energy department noted that the province recently eased the curtailment and left open the possibility of further easing, adding, “While we’re not out of the woods yet, this temporary measure is working.”
Suncor Energy Inc. also has canceled plans to ship more than 20,000 barrels a day in recent weeks, while Canadian National Railway Co., one of Canada’s two large train operators, has had to idle trains because of lack of demand, people familiar with the matter said. A Suncor spokeswoman declined to comment, but Chief Executive Steve Williams told investors last week that Canadian producers are finding it difficult to justify moving crude by rail because Canadian oil has become more expensive.
“A lot of the rail movements are stopping, or have stopped,” Mr. Williams said. But, he added, “demand is increasing.”
Not all producers are cutting train shipments. Calgary-based Cenovus Energy Inc. plans to increase its rail exports from roughly 20,000 barrels a day to 100,000 by year end, said CEO Alex Pourbaix. He is counting on Canadian oil selling at a bigger discount to U.S. benchmarks later this year. “We’ll be in the money in the second half of the year,” he said.
Marathon Petroleum Corp., the largest U.S. refiner by capacity, imported a small amount of Venezuelan crude last year. Last week, it told investors that it had moved away from using the country’s oil, with replacement supplies coming primarily from the Middle East and elsewhere in Latin America.
Refiner Phillips 66 told investors Friday that it sees limits to how much heavy crude Canada can provide because of the cost of transporting crude by rail.
“We are seeing a reduced utilization of rail as we come into February,” said Jeff Dietert, a vice president. “Those economics are closed.”
Recent data reveals the dropoff in crude-by-rail shipments. Storage terminals in Western Canada loaded an average of 156,000 barrels per day onto trains for the week ended Feb. 1, according to research firm Genscape Inc., less than half the average for the week ending Jan. 11.
Oil train shipments could rebound if Alberta further eases production cuts, which likely would send Canadian crude prices lower and prompt companies to transport more crude by rail.
Even then, however, analysts said it is unlikely Canada would be able to quickly ramp up exports to the U.S. because of constraints such as securing enough additional railcars.
“It’s not clear Canada will be able to take advantage,” said Michael Tran, global energy analyst with RBC Capital Markets.