redtea/E+ via Getty Images

redtea/E+ via Getty Images

One of the most important issues that Canadian oil exploration companies have to deal with - at least those that produce heavier, sour grades - are price differentials. The fact that Western Canadian Select ("WCS") trades at a discount to West Texas Intermediate ("WTI") is not a revelation to most investors in oil and gas. While it is a less valuable grade of crude oil as far as refined product yield, most in the industry acknowledge that the spread is a construct of pipeline capacity. In other words, if Canada ever solved the issue of cross-border capacity, the spread between WCS and WTI would narrow tremendously. So now that Canada does have some additional capacity online via the Line 3 Replacement Project, why on earth are differentials (and futures) worse now than several months ago before this project was completed?

Canada has been short pipeline supply compared to its production profile for decades at this point. Legal and regulatory challenges have been persistent, either projects long since abandoned or those that are more fresh in the memory of the country: see the struggles of Keystone XL and the Trans Mountain Expansion as recent examples. Nonetheless, many expected the differential between WCS and WTI to shrink recently. On October 1, Enbridge (ENB) finally brought the Line 3 Replacement Project online. This investment has had more than its fair share of legal quagmires and I'm sure long-time CEO of Enbridge Al Monaco has pulled out a lot of hair getting it across the finish line. End of the day though, when the Canadian midstream giant replaced more than 1,000 miles of aged pipeline that was laid many years ago, it subsequently increased cross-border capacity by 370,000 barrels per day.

Front month differentials contracted significantly into the in-service date of the Line 3 Replacement, with the market expecting differentials to shrink to around $12.00 per barrel going forward: a pretty fair figure representing the tariff on the Enbridge Mainline ($7.00 - 10.00 per barrel depending on destination) plus the difference in product yield value. However, as shown below, the futures curve has worsened now, back to around the recent historical average between 2015 and 2019.

Interestingly, the spread blew out into year end. While it has since recovered somewhat, I think the drivers of that have indicated to the market that they should be careful about assuming whether forward differentials will contract from here. There were a number of factors that contributed to that obvious dip. Number one, flooding along the route of Trans Mountain Pipeline - which connects Alberta to the Canadian West Coast - led to a temporary shut down. Not really reported by the market, Trans Mountain had informed customers that it intended to run at below normal operating rates through January and just only recently has moved back to normalized. This stranded a lot of barrels, contributing to a lot of the inventory build that has been present in Canada.

What was perhaps more meaningful though was that in the latter parts of 2021, Midwestern and Gulf Coast refinery utilization rates fell due to both planned and unplanned downtime. The vast majority of heavy crude oil exported to the United States are consumed along this corridor. Canadian production also usually falls in the winter months, as oil sands projects are throttled back for maintenance and just from the impact of frigid temperatures. Higher production and lower demand have, of course, also contributed to increased inventories alongside Trans Mountain issues.

EIA Refinery Utilization (PADD 3) (EIA)

EIA Refinery Utilization (PADD 3) (EIA)

EIA Refinery Utilization (PADD 2) (EIA)

EIA Refinery Utilization (PADD 2) (EIA)

Meanwhile, Canadian producers have not expressed similar reservations on boosting production compared to their United States onshore shale peers. While public United States shale firms guiding to production increases in 2022 are currently rare (e.g., EOG Resources (EOG)), it is more normal in Canada. Suncor Energy (SU), Cenovus Energy (CVE), Canadian Natural Resources (CNQ), and many others have all guided for mid single-digit increases in production in 2022. This all adds up. Canadian oil production is already above the high watermark established just prior to the pandemic. Meanwhile, the United States will not see its production levels eclipse the levels set in early 2020 until the middle to end of 2023.

While many of the above issues are transitory, these things tend to repeat themselves. High inventories and a willingness for Canadian drillers shows that at least north of the border, the industry is content to continuously push itself back into a situation of pipeline scarcity. Unfortunately, it seems like that for 2022 and 2023, the WCS - WTI spread will be wider than what it was before the Line 3 Replacement Project was brought online. This might change with Trans Mountain Expansion, but consistent delays there make that a 2024 story at this point - if not later. Investors in Canadian E&Ps with exposure to WCS benchmarks likely just have to resign themselves to disappointing price realizations. That doesn't make them bad buys necessarily, but it's a headache that I had hoped the Canadians might have been able to improve. Meanwhile, United States refiners (particularly in the Midwest) will continue to benefit.

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I have a decade of experience in both the investment advisory and investment banking spaces, with stints in portfolio management, residential mortgage-backed securities, derivatives, and internal audit at various firms. Today, I am a full-time investor and "independent analyst for hire" here on Seeking Alpha.

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