Will Canada Cap Its Oil Production?

A normal person’s November is mostly associated with Thanksgiving, preparation for Christmas and New Year, perhaps enjoying the last days of Indian summer for those lucky enough to live in warmer places. A Canadian oilman’s November is a month brimming with dread and horror about what is to come next. When the Western Canadian Select outright price hit 14 USD per barrel on November 14, it marked the lowest point since Argus started assessing the crude in 2006. Similarly bituminous grades with a higher TAN number plummeted even lower – for instance, the Access Western Blend has hit a single-digit number that same day at 9 USD per barrel. As producers experience serious difficulties to keep production afloat against highly adverse conditions, the only genuinely burning question is - when will all this stop?

Let’s start with a bit of crude basics. Western Canadian Select is a blend of roughly 25 crude streams, combining heavily bituminous, sweet synthetic and condensate streams. Its API gravity level oscillates between 19 and 22 degrees, whilst Sulphur content amounts to 3-3.5 percent. It is also quite acidic – even though its total acid number (TAN) never surpasses 1 mgKOH/g, it is only thanks to blending heavily acidic streams with sweeter ones so as to deliberately keep it that way. But do not think that the Canadian plight has hit only bituminous crudes – Syncrude Sweet Premium (SSP), which is a 32-33 degree API and 0.2 percent Sulphur crude stream, has fallen to an outright price of 26 USD per barrel, roughly 30 US Dollars below the WTI CMA index.

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Source: OilPrice data.

The root cause of Canada’s problems is the massive discrepancy between the amount of oil Canada produces and its transportation system capacity, resulting in year-long bottlenecks and throughput capacity apportionments. This deadlock is mostly a result of political processes, ranging from environmental groups’ lobbying to Canada’s and the United States’ somewhat difficult reckoning with its treatment of Aborigine rights – hence, radical shifts for the better are unlikely. Keystone XL, which would take Canada’s oil sands from Hardisty, Alberta to Steele City, Nebraska, is a fitting example of the difficulty to resolve the impasse. In discussion for ten years already, the construction has still not begun – first it was President Obama’s vetoing the project despite U.S. Congress approval, now, against the background of a supportive Republican administration, it is stalled following a decision by a Montana federal judge, claiming crucial climate change-related issues were disregarded in President Trump’s executive order to allow Keystone XL.

The $9.3 billion Trans Mountain Expansion pipeline project might be another possible solution to ease the overproduction issue – however, it, too, was delayed, this time as a result of a federal appeals court that stated indigenous groups were not consulted appropriately during the designing phase of the pipeline, coupled with the usual bouquet of environmental concerns. Now, Canada’s National Energy Board has to redraw its project review and issue a new consultation with a deadline of February 22, 2019. With voices saying the deadline is too tight to conduct appropriate analysis, you can be sure there will be additional delays in the pipeline’s implementation. Thus, more than 1.4 mbpd potential throughput capacity (Keystone XL would have added 830kbpd, Trans Mountain Expansion 590kbpd) is locked in the administrative morass of court rulings and governments decisions overriding it.

The scariest element in the Canadian price plunge is that it takes place against robustly increasing production volumes. Oil sands projects have typically longer life spans than the conventional ones (i.e. their production plateaus usually last for 20-30 years) and once they are onstream, operators feel comfortable if WCS prices are 30 USD per barrel or above. This resilience is why production keeps on increasing despite the lack of greenfield development in Western Canada since 2014-2015 when oil prices crashed. In fact, the only green light given to a greenfield SAGD project (steam assisted gravity drainage) took place in early November this year – i.e. in the worst possible time – when Imperial Oil, quite counterintuitively, announced it would go ahead with the 75kbpd Aspen project.

However now, as we have established, prices for Western Canadian crudes have fallen below their breakeven levels (within the interval of 25-30 USD per barrel for already operating projects). This is not the first time for this to happen – early 2016 WCS prices dropped above 20 USD per barrel, too. On the other hand, at that time WTI hovered around 30 USD per barrel, whilst now it moves between 55-60 USD per barrel. In 2016 producers reacted swiftly, they have cut roughly 100kbpd of production for 4-5 months until prices rebounded back above 30 USD per barrel. They are doing the same now, too, albeit to a bigger extent – according to current estimates, producers have pledged to reduce output by some 130-140 kbpd so far.

Cenovus and CNRL took the biggest cut pledge so far, both eliminating some 50kbpd of oil sands production by December, however almost all noteworthy producers have curtailed their production or postponed the attainment of output peaks. The quandary is also contributing to the contraction of companies present. Several small companies have been weeded out and many others simply bought up – a quatrumvirate of sorts has emerged in the likes of Suncor Energy, Imperial Oil, CNRL and Cenovus. If two years ago they accounted “only” for 60 percent of production, by 2020 they should already take up 75 percent of the market. The latest move in this direction was Husky Energy’s hostile takeover bid with regard to MEG Energy, one of the major producers of the now-single-digit Access Western Blend crude.

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Source: National Energy Board, Oilprice data.

What next, you ask? More of the same, most probably. Western Canada is heading into winter season, which is the high season for production – the only way to survive under current circumstances is to curb supply. With only one major pipeline project coming up in 2019 – the 0.37 mbpd Line 3 extension, which will be put in operation in H2 2019. The Keystone XL and Trans Mountain Extension project will not come onstream at least before 2022, thus guaranteeing a rough few years for Western Canada producers. Rail will be a partial solution to the problem – it is expected that up to 0.4-0.45 mbpd of crude might be moved via rail in 2019, due to an expansion at the Hardisty rail terminal and greater availability of railcars. Yet this is not enough – the additional 0.2 mbpd rail transportation capacity is only sufficient to balance out the Western Canadian system under the current conditions, in case production edges up (and it will, albeit to a much lesser degree than heretofore) it goes back to oversupply again.

Operators will try their best to avoid shutting down production as in situ production sites it would require the ‘rewarming’ of the oil sands’ steam chamber, which takes some time, costs money and in wintertime might even damage the reservoir. Yet with inventories in Alberta already unprecedentedly high – more than 90 percent of the province’s storage is taken – there is simply no more space to store the crude. To add insult to injury, the impending IMO 2020-induced blow on sour crudes will even fortify the pressure on Western Canadian prices. Thus, Western Canada will have to live with the ungracious label of having the world’s cheapest crude for next couple of months (or years?).