The introduction of mandatory production cuts by Alberta’s government that commenced on 1 January 2019 and cut oil output by 325,000 barrels daily have buoyed Canadian crude prices. After being announced in early December 2018, the discount applied to Western Canadian Select (WCS) and Edmonton Par declined significantly. This was a boon for the energy patch as price differentials to the North American benchmark West Texas Intermediate (WTI) fell from record highs to multi-year lows.
While some oil sands companies, notably Cenovus Energy Inc. (TSX: CVE)(NYSE: CVE) and Canadian Natural Resources Ltd. lobbied for government enforced production cuts, others opposed them. A key dissident was and still is Canada’s largest integrated energy company Suncor Energy Inc. (TSX: SU)(NYSE: SU). Its management believes that pricing and production levels should be left to market forces rather than government meddling.
Despite the cuts significantly boosting the price of Western Canadian Select (WCS) and Edmonton Par, they haven’t remedied the underlying issues that caused Canadian oil prices to collapse to record lows. They have also triggered serious unintended consequences for the oil sands.
Infrastructure bottlenecks remain unresolved
The primary driver of the wide price differential between Canadian crude benchmarks and WTI is the lack of pipeline exit capacity that’s preventing Canadian oil production, especially heavy oil, from reaching crucial U.S. refining markets. And this, in combination with growing domestic oil production, was responsible for a localized supply glut as inventories hit record highs, causing the differential between Canadian benchmark prices and WTI to widen significantly.
Even record crude by rail shipments, which, according to the National Energy Board peaked at 330,402 barrels daily in November 2018, were unable to alleviate the surplus. The only long-term solution is for Canada to significantly expand its pipeline infrastructure, but that’s being hindered by regulatory, environmental, community and financial hurdles. The accepted view among analysts is that it will take five years or longer for any material additions to the domestic pipeline network to occur.
Additional measures being considered by Edmonton include pushing for greater investment in crude by rail infrastructure and bolstering refining capacity in Western Canada, won’t address the core problem without substantially boosting pipeline capacity localized supply gluts and deep discounts for Canadian crude remain serious threats.
Even Enbridge Inc.’s Line 3 Expansion, a critical short-term solution for reducing pipeline bottlenecks, is facing considerable opposition. If the project is blocked in Minnesota, then the production cuts would have to stay in place for longer, which would be detrimental for the oil sands.
Production cuts have their own fallout
An unintended consequence of the mandatory production cuts is that they have worked too well. Canadian oil price differentials to WTI have narrowed so significantly that according to Suncor CEO Steve Williams, it’s becoming increasingly uneconomic to ship Canadian crude by rail to the U.S. That has sparked a sharp decline in the volume of shipments. Preliminary data from Canada’s two largest rail operators, Canadian National and Canadian Pacific show declining loads of petroleum products.
Meanwhile, Imperial Oil Ltd. (TSX: IMO)(NYSE:IMO), which, like Suncor, was opposed to the cuts, is planning to cease crude by rail shipments and dial down investment in the oil sands.
Aside from a philosophical view on markets being able to operate without excessive government intervention, it’s easy to understand their opposition. The wide spread between WCS and WTI was highly profitable for Suncor and Imperial’s downstream operations. Both possess substantial refining capacity, with Suncor’s refineries capable of processing over 60% of its oil sands production and Imperial’s more than 90% of all crude it produces.
The deep discount applied to WCS meant that the cost of feedstock for their refineries fell significantly, yet they still benefited from premium pricing for the processed petroleum products produced because of higher WTI. That gives them a distinct financial advantage over Cenovus and Canadian Natural Resources, which because of their appreciably lower refining capacity, are far more dependent on energy markets to sell the oil they produce.
Substantially narrower margins also make WCS a less attractive feedstock for U.S. refineries due to the higher costs associated with processing heavy crude. Higher Canadian oil prices will push refineries, especially those on the U.S. Gulf Coast, to look to other sources of cheaper heavy oil such as Mexico and Colombia while others are reconfiguring their operations to process the lighter sweeter crude that has flooded North American energy markets because of the shale oil boom.
In response to this fallout, Edmonton has announced that it has shaved 75,000 barrels daily of its February and March 2019 targets, which is intended to push prices lower, making it profitable to ship Canadian crude by rail, as this is the only means of alleviating existing transportation bottlenecks.
What does it mean for the oil sands?
Alberta’s production cuts have essentially kicked the can further down the road rather than addressing the core issue triggering the deep-discounts applied to Canadian heavy oil, the lack of pipeline capacity. While they buoyed prices, they have also upset the market mechanism, making it less economic to ship and process Canadian heavy oil and reducing its appeal to refiners as well as potentially creating additional unanticipated bottlenecks. This, along with their temporary nature, means that they haven’t improved the long-term outlook for oil sands operators, which lack significant refining capacity like Cenovus.
