A lot of emphasis is placed on analyzing and attempting to generate forecasts for the price differential between Canada’s heavy oil benchmark of Western Canada Select (WCS) and that of the North American light oil benchmark, West Texas Intermediate (WTI).
Although WCS almost exclusively trades at a price discount to WTI, the magnitude of this price difference is often used as a guidepost for the fortunes of Canada’s oil producers and production, about 80 per cent of which is heavy oil. The smaller is the discount of WCS to WTI, the better the pricing fortunes for heavy oil, with the opposite, a larger discount, signalling the fortunes are not quite as rosy. Of course, much also depends on the absolute price of WCS, but the magnitude and direction of the price differential often shadows broader oil market sentiment, especially for Canadian heavy crude oil.
In Part 1 of this analysis, we outlined a number of geopolitical events that emerged in 2022 and have driven the WCS price discount to WTI to a four year low around US$27/bbl during October. The two prominent factors that we highlighted were releases of crude oil from the U.S. Strategic Petroleum Reserve (SPR) that got underway on a large scale in May this year, a majority of which have been medium sour barrels; and the heavy discounting by Russia of its flagship Urals medium sour crude, a crude stream that competes with WCS on the world stage.
With both of these developments deriving, at least in part, from the war between Russia and the Ukraine, continued heavy discounting of Russian barrels is expected for most of 2023, while releases from the SPR will be running until at least December. Should President Biden continue to see fit that the SPR should be used to downwardly influence crude oil prices and, by extension, retail gasoline prices in the U.S., more SPR releases could be forthcoming in 2023. By our assessment, these geopolitical influences will carry a strong weighting on WCS crude oil price formation for at least the first half of 2023.
In this second and concluding analysis, we turn to what are typically more traditional fundamental drivers of the WCS-WTI price differential. The most frequently cited of these drivers has been the availability of pipeline export capacity from Western Canada, typically measured by the degree of apportionment on the Enbridge Mainline which transports 3.3 MMb/d (million barrels per day) of western Canadian crude, mostly heavy oil, to the U.S. Midwest and Ontario/Quebec. Traditionally, the higher degree of apportionment, the more restricted is available pipeline capacity, forcing larger discounts for heavy oil as producers compete to get barrels into the pipeline.
In the past two years, this relationship has broken down. High apportionment levels occurred throughout a good portion of 2021 (blue columns in chart below, left hand scale), but the price discount remained in a fairly stable and tight range between US$10 and US$14/bbl (red line, right hand scale). Strong refining demand in Canada and the U.S., combined with (then) U.S. domestic production that was struggling to grow, created a sustained strong bid for Canadian heavy oil barrels, despite the high levels of apportionment.
Since the Enbridge Line 3 Replacement (L3R) project officially entered service in October 2021 bringing about 370 Mb/d of incremental capacity, apportionment has been essentially at zero or the single digit range in recent months (black dashed oval). As such, there appears to be have been little to no pipeline congestion, and little to no reason for discounting of Canadian barrels related to pipeline availability since late last year.
In terms of heavy oil production, the majority flows from Alberta in the form of non-upgraded bitumen and which has been hitting record highs in recent months. However, RBN expects that annual average growth to be modest in 2022 (+80 Mb/d) and 2023 (+50 Mb/d). This kind of growth, combined with small gains expected for other light and medium crude, are unlikely to exhaust remaining spare capacity on the Enbridge Mainline, meaning continuance of low or no apportionment for the remainder of this year and the balance of 2023. As such, we do not expect export pipeline availability to be a serious issue and more likely to be a reason for the price differential to remain more narrow (smaller discount) than wider.
If Canadian heavy oil production and the ability to get that to market do not appear to be facing any serious impediments, it might be the downstream refining markets where issues could play a role in creating wider price discounts. Two recent refinery events have affected pricing and have forced WCS to a deeper discount (red dashed oval in chart below) compounding the Russian and SPR influences mentioned earlier.
First, a fire at the BP-Cenovus 160 Mb/d Toledo, Ohio refinery on September 20 occurred just a short time after the conclusion of a multi-month refurbishment. Right around this time, BP’s massive 450 Mb/d Whiting refinery in Indiana closed some on-site oil processing units for scheduled maintenance and which is expected to last until at least mid-November. Toledo was importing roughly 90 Mb/d of Canadian heavy oil prior to its refurbishment, while Whiting was importing about 300 Mb/d of Canadian heavy, of which about one-third has been suspended due to the downtime at part of the refinery. These are events which can affect both the short-term (Whiting) and longer term — Toledo is not expected to return to service until early neat year — leaving large gaps in refinery demand for Canadian heavy oil in the Midwest. Understandably, the price differential widened (larger discount) on this news and has not recovered to any great degree since.
More indirect influences on the near-term pricing differential have come from a more unusual source: low water levels on the Mississippi River, which are not expected to recover until later this year. Given that this important waterway is used to transport some refined products by barge from the Midwest to the Gulf Coast, restricted barge use has been backing up products in the Midwest, forcing some curtailment of Midwest refinery activity and demand for Canadian heavy oil.
Layering in our expectation that U.S. Midwest refineries, even after allowing for the extended outage at the Toledo refinery, will not run quite as hard in 2023 as they did in 2022 on the view that U.S. refined product demand will remain relatively stagnant, similar to what has been the situation for gasoline demand this year. As such, softer demand is expected for Canadian heavy crude oil next year in what is one of its most crucial markets.
One final big-ticket item for our price differential outlook concerns crude oil inventory levels. Crude levels in the Midwest outside of the Cushing Hub are well within the five-year range (left hand chart below), while those in the Gulf Coast (right hand chart) are closer to the top end of its five-year range. As both of these regions can often be a waystation for Canadian heavy oil, comfortable inventory levels in these regions suggest not much need to increase Canadian imports and inventories to higher levels in the near future, especially if refinery run rates may pull back modestly.
Pulling together all of these elements from the above discussion, as well as the geopolitical factors that we mentioned in Part 1, brings us to our outlook for the WCS-WTI price differential. Given the rather wide differential to date in 4Q22, we see it averaging US$28.50/bbl (blue columns and text in chart below).
Over the following four quarters, we do expect the differential to stay wider than what was seen through 2021 and early 2022, but still narrowing from US$23/bbl in 1Q23 to US$16/bbl by 4Q23. This outlook is not too different from the current forward curve (red columns and text), except that we believe the differential could begin to narrow quickly by the time we reach 4Q23 when the Trans Mountain Pipeline expansion (TMX) and its incremental 590 Mb/d of capacity is expected to enter service. Prior to that, we see the above factors, as well as the (hoped for) final sales from the SPR late this year and likely sustained heavy discounting of Russian Urals crude oil for most of 2023, as tending to hold the price differential wider than might otherwise be the case.
It may well be the case that when TMX enters service that it helps to generate an even more rapid narrowing of the price differential and places it on a more permanent path to levels not too dissimilar from the US$10 to $14/bbl range seen throughout most of 2021. The additional export capacity that TMX brings to Canadian barrels to reach Asian markets could usher in what we think will be a lengthy period of excess pipeline export capacity stretching perhaps into 2025 or 2026. As such, Canadian heavy oil will have diverse options spread across Asian markets, no longer subject to a sole dependency on exports to the U.S., where, as we have described above, refinery upsets and uneven inventory levels can quickly have negative impacts on the price of Canadian heavy oil. Even future SPR releases, if there are any, should have less of a price impact than has been the case this year once TMX is in service.
Are there market developments that could potentially narrow the price differential more quickly? There are several aside from the aforementioned low apportionment expectation for the Enbridge Mainline. Foremost would be a conclusive end to sales of crude from the SPR. Should no further releases take place, although President Biden has hinted otherwise, this would certainly help to reduce competitive influences on WCS in the Gulf Coast. Indeed, should a buyback of barrels for the SPR get underway in 2023, this would effectively neutralize a portion of medium sour barrels in the Gulf Coast that might otherwise compete with WCS.
A second item is that exports from Canada of crude oil by rail are expected to remain elevated as there are more terminals now in operation than one year ago using minimum fixed volume contracts. Given recent rail export volumes in the range of 150 Mb/d, even before the differential widened in September and October, exports at these levels or higher will keep incremental barrels off the pipelines and reduce the chances of pipeline export capacity being exhausted before the start up of TMX.
Finally, all the major export pipelines leaving Canada continue to search for efficiencies that could increase effective capacity. An example is TC Energy’s Keystone pipeline which will see an increase in effective capacity to 720 Mb/d from 640 Mb/d for the months of November and December this year by experimenting with drag reducing agents. This will likely be a prelude to a more permanent effective capacity increase next year, providing more flexibility for heavy oil leaving Canada for the US.
On a combination of fundamental drivers such as refinery activity and inventory levels, combined with the geopolitical situation playing a bigger role over the next year, the outlook for the WCS-WTI price differential appears not as rosy as it was in 2021 and early 2022. However, should price levels for benchmark WTI hold in the US$80 to US$100/bbl level as some market pundits think possible, the price differential outlook we are contemplating still yields healthy price levels for WCS in the US$55 to $75/bbl range.
We see this as a positive run up to when TMX enters service late next year, a time when the very fabric of the Canadian crude oil market — and the Canadian economy — will be permanently changed for the better.