Alberta heavy crude oil trading for a premium at the US Gulf Coast?

US Gulf Coast demand for Canadian heavy crude is growing because of declining supply from Venezuela, Mexico, Iran

Our thesis is that Canadian heavy oil is not a discounted product, it’s a stranded product. Those are two very different things. The reality is that there is a very large market for Canadian heavy oil and just because the product sells at a discount does not mean that it’s not wanted. – Nick Lupick

Nick Lupick, Altacorp.

Subscribers to Altacorp Capital’s research newsletter were probably surprised to discover in the Oct. 23 edition that contrary to popular opinion, some of Western Canada’s heavy crude oil production is actually trading at a premium, not a huge discount. Analyst Nick Lupick tells Energi News that investors should be rethinking global demand for Alberta’s heavy crude oil, forecast to account for almost all of the Canadian supply growth for the next decade or two.

“Most producers in Western Canada are going to be price takers. They’re going to sell their barrels in Hardisty or Edmonton to a marketer and then the marketer from there will allot their production on the pipelines or sell it to other refineries” mostly in the US Midwest, says Lupick.

“But, it is not outlandish to think that heavy oil can trade at a premium to light.”

In fact, Western Canadian Select grades finding their way to the US Gulf Coast have traded at a premium to WTI in Houston at various times during the first half of 2018 while crude sold in Edmonton suffered differentials as high as $65 at one point.

According to Lupick, there are two over-arching factors at play.

One, the continual decline of heavy crude production from Canadian competitors like Venezuela, Iran, and Mexico.

“US imports of crude oil from Venezuela have hovered around 500,000 b/d over the past year, though the rise in WCS blend prices in the US Gulf Coast leads to our conviction that refineries are demanding Canadian crudes to replace barrels from other heavy oil producing nations in decline such as Venezuela,” Lupick wrote in his research note.

Venezuela production, which not that long ago cranked out 3 million b/d, has dropped by 1.1 million b/d since 2015 and is now down to 1.2 million b/d. Some analysts think supply could dip as low as 750,000 b/d next year.

President Donald Trump’s economic sanctions against Iran have already taken barrels of heavy crude out of the market and more will likely follow after the official start of the trade restrictions that only began Monday.

Canadian heavy crude oil has never been more in demand in US markets.

Two, the ability of producers to get their heavy product to market because of constraints in the Canadian pipeline system.

Big companies with the financial clout to enter into 20-year “take or pay” contracts with shippers – like Suncor or Husky Energy – are able to sell barrels not needed in their American refineries into the Gulf Coast market.

Other large operators, like Cenovus, ship more by rail and are ramping up their rail capacity. Lupick calculates that the discount to ship by rail from Alberta to the Gulf Coast is about $20 to $25 a barrel, whereas shipping by pipeline costs around $15.

How much Canadian heavy crude is finding its way to Texas and Louisiana refineries is a bit tricky, according to Kevin Birn, IHS MarkIt director for the Oil Sands Dialogue.

Kevin Birn, IHS MarkIt.

We think an excess of 800,000 barrels a day and rising are currently making their way down to the Gulf Coast,” he said in an interview.

That’s a much higher number than the US Energy Information Administration reports. The discrepancy is caused by a quirk in how the EIA tracks crude oil shipments, says Birn.

“Cushing, Oklahoma is a major trading hub in the United States. The Gulf Coast is in a different reporting region than Cushing. We think significant volumes of Canadian heavy that go through Cushing show up as internal American transfers,” he said.

But who owns that crude?

Lupick ticks off heavy oil producers and their publicly known shipping comitments various pipelines, making the point that a significant amount of capacity is owned by US refiners that buy the crude in Alberta at the severe discount, rather than Canadian companies owning the oil until it hits the Gulf Coast market, thus capturing the premium.

The upshot is that until Canadian pipeline capacity grows, the WCS/WTI differential will be high for those producers without shipping capacity or the ability to add new rail, like Cenovus, which in Sept. contracted with CNR and CP for three years to send 100,000 b/d by rail to the US.

Calgary-based Enbridge expects the $9 billion, 390,000 b/d Line 3 upgrade to be in service by mid-2019 and other system upgrades to add 375,000 b/d to 500,000 b/d sometime in 2020 or the year after.

“Canadian heavy oil is not an unwanted product, that is the number one thing that we have to hammer home,” concludes Lupick.

“That in the global marketplace, this is in short supply and it’s a shame that Canada has not been able to get the infrastructure in place to gain global market share and prices.”

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