Updated March 2018
The price of WCS averaged an estimated US$38.97/bbl in 2017, as shown in Figure 1.5 [Tableau]. WCS trades at a discount to West Texas Intermediate (WTI) because heavier sour crudes are more costly to process and most WCS is transported to refinery hubs located outside of Alberta, increasing transportation costs. WCS is priced at Hardisty, Alberta, which is landlocked, so producers must use pipelines and railways to move WCS to refineries outside of the province. However, without sufficient pipeline infrastructure, producers will incur higher costs to ship their crude by rail. Following recent pipeline expansions in the United States over the last five years, the price differential between WCS and WTI narrowed from an average of US$25.04/bbl in 2013 to an average of US$13.75/bbl in 2016 and an estimated US$11.98/bbl in 2017.
The price of WCS averaged US$37.34/bbl in the first quarter of 2017, up from US$34.97/bbl in the fourth quarter of 2016, as production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and several oil-producing countries curtailed production of heavy and medium crudes, increasing demand for heavy crudes and narrowing the price differential between heavy and light crudes.
The price of WCS decreased to US$35.68/bbl in March due to early refinery maintenance in the United States and a resultant decrease in demand for Canadian heavy crude. However, in late March, diluent supply became tight because of an explosion at Syncrude Canada’s (Syncrude’s) upgrader. As a result, several oil sands projects had to reduce their production of heavy oil until diluent supply was restored. The decrease in heavy oil supply narrowed the heavy-light price differential, strengthening the price of WCS. The effect on the price was significant because U.S. refinery runs were higher than in previous years, increasing demand for Canadian heavy crude.
The price of WCS averaged US$37.16/bbl in the second quarter of 2017, with the price differential between WCS and WTI narrowing from US$14.28/bbl in April to below US$10.00/bbl in May and June. The price of WCS strengthened in May as a result of several factors: some in situ projects shut down for maintenance, tightening supply; U.S. refinery runs continued to reach record levels; and oil imports from Venezuela and Mexico declined. A decline in the price of WCS after the oil sands projects came back on line in June was moderated by the start-up of the Dakota Access Pipeline, which helped ease infrastructure constraints.
The price of WCS increased in the third quarter of 2017, averaging US$38.27/bbl. The price differential between WCS and WTI remained narrow despite a strong hurricane season that shut in pipelines and refineries and closed marine ports. The price of WCS started to increase in July due to debottlenecking projects by Enbridge Inc. (Enbridge) that increased heavy oil takeaway capacity. The price of WCS continued to increase in August, averaging US$38.50/bbl, and the WCS-WTI price differential fell to below US$10.00/bbl as a result of high demand from U.S. refineries at the beginning of the month before Hurricane Harvey [Tableau] impacted infrastructure. However, the negative effect on prices was short-lived because the Seaway and Marketlink pipelines to the coast resumed service in early September and refineries restarted. The price of WCS increased by 4 per cent in September, averaging US$39.93/bbl, as refinery demand for WCS received a boost because tankers from other heavy oil suppliers were delayed by closures of ports, which were slower to reopen, resulting in the WCS-WTI price differential remaining under US$10.00/bbl in September.
The price of WCS increased in the fourth quarter of 2017, averaging an estimated US$43.13/bbl. This increase was partially in response to Enbridge receiving approval from the U.S. government in October to ship more crude through the Alberta Clipper pipeline, increasing cross-border flows. The price of WCS was furthered strengthened by a November announcement by OPEC that global production cuts would be extended until the end of 2018 and also by concerns over supply disruptions, which kept global oil prices elevated. However, despite the increase in the price of WCS, the WCS-WTI price differential widened in the fourth quarter as production started at Canadian Natural Resources Limited’s Horizon Phase 3 and Suncor Energy Inc.’s Fort Hills projects, adding to concerns over pipeline constraints as additional volumes come on line. In addition, the Keystone pipeline went off line in November, decreasing demand for WCS because access to refineries in the United States was reduced. The price differential continued to widen in December with continued restrictions on the Keystone pipeline, resulting in a large oil inventory in western Canada and pipeline apportionments.
As shown in Figure 1.5 [Tableau], the price of WCS is projected to increase to US$39.50/bbl in 2018 and to continue to strengthen through the forecast period, averaging US$64.47/bbl by 2027, with a range of US$46.37/bbl to US$82.57/bbl.
In the near term, the differential between WCS and WTI is expected to be volatile, but average US$13.50/bbl in 2018 as the short-term effects of the outage at the Syncrude upgrader diminish, oil sands production increases, and the large oil inventory in western Canada due to the Keystone pipeline outage draws down. The differential is expected to remain below historical values because the cuts to global production primarily affect heavy and medium crude production and sufficient transportation capacity is available to western Canadian producers. Further, demand for heavier Canadian crudes is anticipated to increase as Canadian exports maintain their competitive advantage in the U.S. mid-continent and continue to displace Mexican and Venezuelan imports in the U.S. Gulf Coast (USGC).
The U.S. mid-continent (Petroleum Administration for Defense Districts [PADD] 2) receives on average about 98 per cent of its imports from Canada due to its close proximity to Canada and the existing infrastructure to transport oil from Canadian producers. More Canadian oil has been making its way to the USGC (PADD 3), with about 10–13 per cent of Canadian crude reaching the USGC in 2017. Traditionally, PADD 3 has received heavy crude imports from Mexico and Latin America, which have similar qualities to WCS. Mexico used to be a major supplier of crude to the United States; however, in recent years, the share of Mexican Maya crude exports to the USGC has been declining. Venezuelan imports are also decreasing due to declining production, as well as sanctions imposed by the United States in August preventing the Venezuelan government and its state-owned petroleum company from issuing new debt and equity. While U.S. production has increased, most of the production growth has come from shale plays such as the Permian and Eagle Ford. These shale plays produce light grades that are attractive to global refineries but are not as desirable for USGC refineries, which are set up to process heavier crudes. Given that these refineries are able to process western Canadian heavy crudes, there is an opportunity for heavy Canadian crude to displace the heavier Latin American crudes as Canadian supply is secure and competitively priced.
Beyond the near term, the WCS-WTI price differential is expected to average US$14.00/bbl in 2019 and continue to widen to US$16.00/bbl in 2020 as the global production cuts end, oil sands production increases, new sulphur regulations increase refining costs, and Alberta producers face pipeline constraints. It is anticipated that one of the proposed export pipeline projects will be constructed; however, the price differential is expected to reach US$20.00/bbl in 2024 and remain at that level for the rest of the forecast period as the full impact of the new International Maritime Organization (IMO) sulphur regulations come into effect. The IMO set a January 1, 2020, implementation date for a reduction in the global sulphur limit to 0.5 per cent mass on mass from the current 3.5 per cent.
Once the sulphur regulations come into effect, ship owners have three main compliance options: install scrubbers, convert to liquefied natural gas (LNG) fuel, or use low-sulphur fuel. Using low-sulphur fuel is the most economical choice because installing scrubbers or converting to LNG fuel is capital intensive and time consuming. For this reason, most ship owners are likely to use low-sulphur fuel in order to comply with the new regulations, increasing the demand on refineries to produce greater quantities.
As the main demand centres for WCS are refineries in PADD 2 and PADD 3, which consist of complex refineries capable of processing heavier sour crudes, it is likely that they will not have to undergo significant costly conversions to supply the low-sulphur fuel. In addition, because PADD 2 is landlocked and its refineries produce little residual fuel in their refining mix, the new regulations are unlikely to significantly affect activities in PADD 2. PADD 3 refineries, situated on the USGC, produce a higher percentage of residual fuel in their refining mix; however, given that these refineries are able to process sour crudes, they are well positioned to take advantage of the price premium for low-sulphur fuel. Enforcement of the new regulations will be challenging because it will require cooperation between federal governments, flag states, maritime organizations, and other stakeholders to monitor and enforce the regulations. For these reasons, the full effect of the new IMO rules on the price of WCS is delayed in the forecast until after 2020.
The high and low price scenarios in Figure 1.5 [Tableau] represent the near-term and long-term volatility of the price of WCS. In the high price scenario, the market balances sooner in the forecast through expected significant cuts in medium and heavy crudes, which strengthen demand for WCS, and construction of export pipelines, which reduces infrastructure constraints. In the low price scenario, compliance with the OPEC-led production cuts is forecast to be low, resulting in a resurgence of global production, including medium and heavy crudes. This scenario also assumes that Alberta production will surpass infrastructure capacity early in the forecast period and that no pipelines will be built over the forecast period, leaving producers reliant on more costly rail transportation to export their oil.
For information on how the WCS price is derived, see the Methodology section.