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Canadian Oil Just Wants to Get the Hell Out of Canada: Gadfly


November 15, 2017

(Bloomberg Gadfly) — Canada’s oil means no disrespect — it is after all, Canadian — but it would just like to get the hell out of Canada.
The question is: Can it?

I wrote here last week about logistical bottlenecks playing havoc with U.S. oil pricing. But Canada takes this to a new level.
Most of the country’s oil comes from Alberta. Heavier, higher in sulfur and far from the American refineries on the Gulf Coast optimized to take it, Western Canada Select crude oil tends to trade at a discount to West Texas Intermediate.

It also trades at a discount to Mexican Maya crude, which is similarly tough to refine but much closer to the Gulf. In general, therefore, the discount of WCS versus Maya usually reflects the extra cost of piping those Canadian barrels south, roughly $7 to $10 a barrel. Recently, though, the spread has blown out: This partly reflects some of those U.S. bottlenecks I mentioned. Meanwhile, production of heavy oil from Mexico — and another regional supplier, Venezuela — has been declining, and Saudi Arabia has been withholding barrels.

But the bigger issue is that Alberta’s production is outpacing its pipelines. And the problem will get worse before it gets better: Futures imply average spreads of about $17 a barrel over the next two years.

Western Canada produced 3.9 million barrels a day in 2016, and that’s set to reach almost 4.8 million a day in 2022, according to the Canadian Association of Petroleum Producers. That growth is front-loaded, too: Local refineries can process about 525,000 barrels a day , and a new one starting up next year should run roughly another 40,000 a day. With about 3.3 million barrels a day of effective pipeline export capacity , that leaves about 330,000 barrels a day looking for a way out this year. That jumps to more than 600,000 a day next year and almost 700,000 a day by 2019.

 

MNP Oilfield Services
MNP Oilfield Services

 

Number of Canadian Oil Barrels That Will Be Seeking An Exit By 2019

700,00 Per Day

Oil that can’t secure space on a pipe has to go by rail instead, which costs more like $13-$18 a barrel to get to the Gulf Coast. Hence the widening spreads in futures prices (and lower margins for producers).

Three new pipelines are proposed. But getting pipelines built isn’t straightforward these days — one of the three is that Keystone XL project you might have heard about over the past decade. Even assuming they clear all their regulatory hurdles, secure customers and go smoothly, extra capacity wouldn’t begin to show up until the second half of 2019:

For the next two years, at least, therefore, pricing will be a headwind for producers in western Canada, though not all equally. Imperial Oil Ltd. and Cenovus Energy Inc. are more exposed because they refine less of their own heavy oil production compared to, say, Canadian Natural Resources Ltd. and Suncor Energy Inc.

On the flip-side, Canadian National Railway Co. and some of its peers should benefit as more barrels switch to rail:
U.S. refiners able to process Canadian barrels looking for a home could also benefit from cheaper raw materials (similar to what happened with Midwestern crude before the U.S. export ban was lifted in late 2015). HollyFrontier Corp. and Phillips 66 should capture some of the discount on Canadian oil for themselves.

Looking beyond 2019, though, it’s worth remembering there’s no guarantee all these pipelines get built. Besides regulatory hurdles, if they all show up, western Canada would flip quickly from a pipeline shortage to a surplus.

TransCanada Corp. told investors last week that if regulators in Nebraska give the go-ahead later this month, it has clients ready to support the Keystone XL project. Despite the apparent surplus this would entail, Canadian oil producers may well value an extra option. Two other pipeline proposals have died already — including TransCanada’s own Energy East proposal — and there’s no guarantee Kinder Morgan Canada Ltd.’s Trans Mountain expansion gets built. Spare capacity could also accommodate potential new oil-sands projects down the road.

That last point still looks like a stretch, though. Besides the uncertainty around medium-term oil markets right now, heavy barrels like those from Alberta face a particular problem from 2020 onward. That’s when tighter regulations for marine fuel kick in. Analysts at Tudor, Pickering, Holt & Co., a boutique energy bank, estimate this could result in at least 1.75 million barrels a day of high-sulfur fuel oil effectively flowing back onto the market as ships switch to cleaner options. Those barrels would compete closely with western Canada’s output; another headwind to pricing.

For all the puts and takes, two things are clear over the next few years. First, Albertan producers that also refine their output can weather the dislocations better. Second, it’s a good time own the exits.

This column does not necessarily reflect the opinion of Bloomberg LP and its owners.



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