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The Canadian OPEC: Are Alberta’s Output Cuts Sustainable?


Alberta Premier Rachel Notley has moved to the ranks of Saudi Crown Prince Mohammad bin Salman and Russian President Vladimir Putin by dictating production cuts, targeted at the short-term removal of a dangerous supply glut that has sent Western Canadian grades plummeting, some of them to single-digit territory. The plan has largely worked – as opposed to the autumnal months of 2018, it is not the Canadian grades’ price but the WTI-WCS differential that is now single-digit. Yet uncertainties are creeping up over the long-term sustainability of Alberta’s production cuts and oil producers have been increasingly vocal in demanding clear legal guarantees that the December 02 decision is not to repeat itself further on.

The markets reacted to the production cuts immediately. If during the week prior to the announcement of the curtailments the Western Canadian Select (WCS) - WTI CMA differential averaged -32 USD per barrel, it skyrocketed to -11 USD per barrel within four-five working days and has remained more or less at the same level since. The gaping hole between WCS priced in Hardisty and WCS Cushing has narrowed significantly. If on November 30, the last working day before the December 02 announcement, it amounted to -23 USD per barrel, by January 11 it edged up to as close as -3 USD per barrel, only to ease off to the current level of -6-7 USD per barrel (see Graph 1). One might even say that the actual developments have surpassed Canadian expectations in many ways.

Graph 1. Western Canadian Select in Hardisty and Cushing in October-January 2019.

(Click to enlarge)

Source: OilPrice data.

Compared to the OPEC/OPEC+ deal, where production cuts were self-imposed commitments to reduce production from a fixed baseline month (October 2016 in case of the first Vienna agreement, October 2018 in case of the latest), the Alberta output curtailments are more complex in their nature. In their first variant, each producer was to be assessed based on the average of the top 6 of 12 months of oil output between November 2017 and October 2018 – i.e. if one had a project that was hiking production and happened to start in late 2017, further capacity ramp-up might be jeopardized by the Alberta cuts. Cognizant of the above variant’s weaknesses, the Alberta authorities have modified their approach, saying the operators will be assessed from the best one of 12 months. Moreover, the Alberta authorities stated that any operator would be subject to cutting to a maximum limit of 16 percent compared to October 2018 output.

Depending on who you talk to, the news that the Alberta authorities have committed to a stringent production cut regime has both boosted market sentiment about Canadian crudes and staggered oil sands producers with stupefaction. In fact, the market rally evidenced after Rachel Notley’s announcement was more robust than it should have been – as it turned out, the volume of the announced production cuts was smaller than the actual volume of curtailments. The Alberta authorities were intent on mandating a temporary oil cut of 325kbpd, to be eased during the year (and subject to monthly reevaluation, if need be). Yet if one is to follow through with the given methodology, the actual cuts are rather in the 350-360kbpd interval (the max. 16 percent curtailment appear to be an indirect acknowledgement of this discrepancy).

The ensuing price rally has exceeded the province’s expectations – Alberta premier Rachel Notley stated they were aiming for an at least 4 USD per barrel improvement in the WTI-WCS spread, which at that time amounted to 37 USD per barrel. By the end of December the differential hovered around 20 USD per barrel, in the first week of January it amounted to 17-18 USD per barrel and, somewhat unexpectedly, moved up to 10-12 USD per barrel in the second week of January 2019. Such a development was by no means intentional. The thing is that the logistics cost of moving Alberta crude to the US Gulf Coast oscillates in the 15-20 USD per barrel and any WTI-WCS spread below that level effectively erases the economic viability of transportation and renders it extremely unremunerative.

In practice, the narrowing of the spread did not result in any decrease in rail tank car transportation amid a steeply backwardated pricing environment. Oil-by-rail volumes have generally surged this year (see Graph 2), surging to 327kbpd (the last month for which the NEB has issued official statistics so far) from the January level of 145kbpd, all this against a modestly increasing production. The Notley administration has stated it would buy 120kbpd worth of rail tank cars (roughly 7 000 in number), with some 15kbpd to be put into operation in 2019 and the rest by August 2020. Time-wise this coincides with the construction timing of the 390kbpd Enbridge Line 3, to be finished by Q4 2019. This means any production cuts are most likely to be eliminated by 2020 and might be even relaxed in the summer, if production numbers after mining turnarounds in the spring do not turn out to be a surprise.

Graph 2. Oil-by-rail volumes vs Alberta Oil Production in 2017-2018.

(Click to enlarge)

Source: National Energy Board.

Despite the price recovery, Canadian oil producers – most notably Canadian Natural Resources, Suncor and Imperial Oil – have indicated reduced or flat spending for the upcoming year. For much of the Canadian oil sands, the price rally did almost nothing to fortify the company’s stock market standing, mostly sending it to outright stagnation. Since further developments on the production cut still feel like terra incognita, smaller companies come up with more original ideas – ranging from the production of bitumen pucks (easily movable as does not require tank cars) to new bitumen upgrading technologies. The authorities of Alberta province have long sought to agree on a new facility that would serve a dual purpose – reduce the volume of diluent needed in the pipelines and be easier marketable for less sophisticated refineries – and indeed did openly endorse a 77kbpd site near Edmonton. We will see how that works given how cumbersome the commissioning of the $10 billion Sturgeon refinery was.

In the plethora of potential solutions suggested by the political class, one rarely hears that Canada should aim for other market outlets. Currently, the general narrative revolves around the Enbridge Line 3 being commissioned before the year-end of 2019 and, coupled with new rail tank cars, easing the pressure on producers in Alberta. Yet a more practical solution would be to prepare the groundwork for a pipeline that would ship Canada’s crude to its Pacific Ocean coast, making it available for Asian buyers. As of today, there is only one market for Canadian crude – the American one (in Oct 2018 Canada accounted for half of US imports), making producers really dependent on what US refiners are up to. For instance, any US maintenance season is bound to increase Alberta’s crude stocks by default.

Graph 3. Canadian Crude Exports to the United States in 2017-2018 (mbpd).

(Click to enlarge)

Source: Energy Information Administration.

It certainly took a great deal of courage from the Notley administration to mandate production cuts several months before the provincial elections. And managing those curtailments is by no means a very difficult balancing act against a very challenging market – before the production cuts were announced, the massive WTI-WCS discount has allegedly cost Canada some $80 million a day. Buying additional rail tank cars and pushing forward for more refining capacity and sophistication is acceptable in the short term but does not really solve any long-term problems that producers face. Canada needs more pipelines but needs them primarily to diversify its crude export opportunities away from the United States.

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