Surging discounts for Canadian oil reignite talk of the bitumen bubble
February 2018 | EXPERT BRIEFING | SECTOR ANALYSIS
The bearish sentiment that plagued global oil prices for years was pushed aside as 2017 came to a close. Primary crude oil benchmark prices enjoyed meaningful gains during this time, including West Texas Intermediate (WTI), the most commonly referenced US crude oil benchmark, which is trading north of $60 for the first time since early 2015. The sustained price recovery can be attributed to many factors, starting with the OPEC-led production restraints and more recently the threat of supply disruptions associated with rising geopolitical tensions within and among many oil-rich nations.
But not all oil producers are rejoicing at the recent gains. In particular, producers of Canadian heavy oil are helplessly watching from afar as the benchmark for Western Canadian heavy oil, Western Canadian Select (WCS), is trading at a significant discount to other crude oil benchmarks. The differential between WCS and WTI soared to nearly US$30 in December, marking the biggest gap in over four years. The sustained price weakness of WCS carries serious implications for producers’ bottom lines and, by extension, the Canadian governments that rely on oil revenues to fund their budgets. To put things in perspective, energy analysts estimate that a $25 per-barrel discount equates to a $20m loss per day for producers of Western Canadian oil.
It is important to understand that WCS typically trades at a discount to WTI. WCS represents a heavy (19-22 API), sour (high sulfur content) crude oil blend, consisting mostly of bitumen, whereas WTI is both lighter and sweeter. The latter requires less energy to process into refined oil products like gasoline, which, in turn, yields a higher price as the lower inputs required up-front make it a more attractive commodity. WCS was developed in 2014 by four major heavy oil producers – the current entities being Suncor Energy Inc., Cenovus Energy Inc., Canadian Natural Resources Limited and Repsol Oil & Gas Canada Inc. – in order to ease the marketing and distribution complications concomitant with having to cater to varying crudes of differing qualities and grades. Other heavy oil producers produce and market their own blend of heavy oil, the price of which is strongly correlated to the price of WCS. The physical chemistry of the WCS and WTI blends, however, only accounts for a portion of the discount. Logistical constraints, in particular a lack of pipeline capacity, are currently exacerbating the price deterioration of WCS.
The inability to build new pipelines has become a chronic and well-documented issue for the oil & gas industry in Canada. The most recent proposed pipeline to fall by the wayside was Energy East, a project backed by TransCanada that would have transported up to 1.1 mbp/d of crude oil from Western Canada to refineries and port terminals in New Brunswick. TransCanada chose to scrap the project altogether in October amid increasing regulatory uncertainty, a common theme for non-renewable energy projects in Canada. As it stands, there are currently three major pipeline proposals on the table that would take more oil out of Alberta – TransCanada’s Keystone XL pipeline, Enbridge Inc.’s Line 3 replacement programme and Kinder Morgan’s trans-mountain pipeline expansion. Each of these projects will need to overcome its own hurdles, and even if the projects do go forward they are not expected to come online anytime soon.
In the meantime, the existing pipeline infrastructure simply will not be able to keep up with the increasing supply from Alberta’s oil sands. The effects of this will only become more apparent as additional supply comes online from major projects that were sanctioned prior to the global oil price crash in 2014. Take, for example, Suncor’s $17bn Fort Hills mine (194,000 bp/d) or Canadian Natural Resource’s Horizon oil sands expansion project (80,000 bp/d). These projects represent only a portion of the $90bn that has been invested in the oil sands since 2013, total production from which is expected to grow by nearly 620,000 bp/d over the next four years. Without the equivalent transportation capacity growth, the increased supply will continue to exert downward pressure on producers and ultimately on Canadian crude oil benchmarks like WCS.
Recent complications with existing pipeline infrastructure have only compounded the problems for producers in Western Canada. TransCanada’s 590,000 bp/d Keystone pipeline was suspended for nearly two weeks in November due to a 5000-gallon leak in South Dakota. The pipeline is now operating again but at a 20 percent reduced pressure threshold as environmental regulators investigate the leak. Enbridge also made two announcements in Q4 calling for extra rationing of space in its Mainline network, which is a significant carrier of Canadian crude exports to the US. The rationing was a necessary result of unplanned outages in the western portion of the network. These complications contributed to the record high inventory levels of Canadian oil in early December (31.82 million barrels).
Producers are attempting to remedy the supply glut by transporting their oil via rail. Higher costs associated with this method of transportation typically make it a relatively unattractive alternative, but the market conditions leave producers with little choice. To make matters worse, rail companies that would normally be eager to take on oil business are currently experiencing their own issues, including three derailments in the last two months of 2017. This has created a backlog of orders for rail companies, which are already struggling to uphold commitments to ship other commodities. Executives from rail companies have also expressed a reluctance to prioritise the surging oil business over other customers given that the heavy reliance to ship oil via rail will only persist as long as pipeline capacity is limited.
One piece of good news for heavy oil producers is the long-awaited opening of the $9.5bn Sturgeon Refinery near Edmonton, the first refinery to be built in Canada in more than 30 years. The refinery, owned by North West Refining and Canadian Natural Resources, is currently producing 20,000 bp/d of diesel and is expected to reach 80,000 bp/d by summer. The argument to refine more oil in Alberta has perhaps never carried more weight as producers are earning significantly more money on every barrel sent to the Sturgeon Refinery. Refining in Alberta also allows producers to make better use of existing pipelines as more oil can be sent with less blending agents.
Even with the additional refining capacity coming online, the fact of the matter remains that oil from Western Canada will continue to receive steep discounts in the short term while domestic production continues to grow without additional pipeline capacity. Thus the infamous ‘bitumen bubble’ lives on for the time being.
Fraser Wayne is an associate at Burnet, Duckworth & Palmer, LLP. He can be contacted on +1 (403) 260 0381 or by email: email@example.com.
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