The Canadian oil and gas sector has been squeezed over the last few years due to low commodity prices. Luckily, we are a resilient bunch. We’ve been able to cut costs, and with global crude demand growth on a positive trajectory, it would appear the worst is behind us.
In a Take Control – Volume 1: Alberta’s Imminent Pipeline Capacity Dilemma, I referred to the Canadian Association of Petroleum Producers’ (CAPP) annual Crude Oil Forecast, Markets and Transportation report, wherein it projected Western Canadian crude oil production will grow to 5.4MMbopd by 2030, driven by a 53% increase in oil sands production from today’s rates. Further, if we were to remain operating at status quo, we would continue to export the majority of our oil as raw bitumen.
But what if there isn’t anyone around who wants to buy that additional production?
It’s certainly an interesting question to ask, and it’s a relevant question because not all crudes oil are made equal.
Alberta bitumen is dense and it is known for its high sulfur, high metals content. In order to process heavy sour crudes such as ours, refineries need to be configured with highly capital intensive equipment such as cokers and ebullated bed hydrocrackers. If a refinery processes our crude, they demand we take deep discounts on our sales price to make up for the expensive equipment and operating costs.
Fortunately, many Gulf Coast refineries have been configured to accept heavy crudes. Back when players such as Valero, Exxon, Marathon, and Motiva built their refineries, they did so under the assumption of running cheap heavy crude feedstocks originating from places such as Venezuela, Mexico, and Saudi Arabia.
It is worth noting that despite having ample light oil supply from the current shale oil boom in Texas, many of the existing Gulf Coast refineries continue to process heavy crudes simply due to the sheer cost associated with reconfiguring their operations. Any future reconfiguration would be a heavily weighed decision.
Unfortunately, while global crude demand is forecast to increase to nearly 100MMbopd in the next year, there is limited evidence to suggest that future refining capacity will be built to handle more of our heavy feedstock. Canada currently accounts for only 4% of the global crude supply, and it may be difficult for refiners to justify building new, expensive heavy oil processing facilities, given the rise of light shale oil. This places Alberta at the mercy of foreign refiners, particularly as we plan to continue to grow our oil sands production.
In addition, we are now observing a troubling trend that may exacerbate our problem. Political and economic instability in Venezuela has ravaged its oil industry and has severely impacted the country’s ability to export heavy crude to a number of Gulf Coast refineries. According to Reuters, Venezuela’s crude output has fallen by nearly 750Mbopd since 2012, and this has forced refiners to react. In response, Valero and Marathon have both announced plans to adjust their feedstocks to lighter blends as they try to soften the impact from the supply disruption.
We should recognize that adding additional pipeline capacity alone does not address the underlying issue of having limited heavy oil processing capacity worldwide. We also need to be cognizant that refiners down south are not afforded the luxury of waiting a few years for new pipelines to be built in order for Canadian crude to fill the Venezuelan void. They are making decisions today.
So what do we do?
As Canadians, we need to be proactive and start thinking about how we can overcome the issue where a limited number of foreign refineries might dictate our ability to scale up in the market.
For starters, we need to begin assessing ways in which we can develop a product in-province that could be fed to any refinery, regardless of configuration. In doing so, we could also open our oil export potential to the entire world.
The good news is that there are many innovators in Alberta already working on the solution.