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Updated June 2020

Figure 1.4 shows both the historical and forecast price of Western Canadian Select (WCS).

Summary

The price of WCS crude oil in 2019 increased by 15 per cent and averaged US$44.28 per barrel (bbl).

Over the forecast period, the base price of WCS is projected to decrease to US$19.00/bbl in 2020, improving to US$33.25/bbl in 2021 and US$55.92/bbl by 2029. The low- and high-price cases consider similar factors as those in the West Texas Intermediate (WTI) forecast. The low-price case forecasts an average of US$15.20/bbl in 2020, US$26.60/bbl in 2020, and US$41.94/bbl in 2029. The high-price case averages US$22.80/bbl in 2020, US$39.90/bbl in 2021, and US$69.90/bbl by 2029.

The price trajectory of WCS is expected to follow similar projections as those of WTI but remains relatively lower due to quality differences, transportation costs, and other regional factors. Additional factors considered for the alternative price cases can be found further down in the Low- and High-Price Cases section of this page.

In 2019

Price differentials: After finishing 2018 with a backlog of oil production and a bout of historically depressed prices in Alberta, the WCS price benchmark increased in 2019, supported by the provincial government's implementation of its curtailment rules. A number of market factors had weighed on the price of WCS in 2018, including the extended restrictions on TC Energy's Keystone pipeline, apportionment on the Enbridge Mainline, refinery outages in key markets, and other logistical issues that prevented oil from being moved by rail to export markets.

With the curtailment program addressing the surplus of oil sands production and volumes in storage, and key refining capacity being restored, prices improved into 2019. The differential remained under US$13.00/bbl for most of the year until TC Energy's Keystone experienced another unplanned outage in October 2019. Although service was restored in November, the pipeline continued to have lower operating pressures and effective throughput capacity as a result. In response to the outage, differentials briefly rose to more than US$22.00/bbl before service was restored.

Despite the challenges of getting Alberta's oil out of the province, suppliers able to reach markets were able to capitalize on opportunities in 2019. Alberta's heavy oil was able to backfill declining U.S. imports from Venezuela and Mexico. In addition, Canadian integrated companies with downstream assets and market access based on pipeline commitments and rail agreements were in a position to take advantage of low-cost feedstock and realize premiums on refined petroleum products.

Production limits: The many adverse pressures throughout 2018 ultimately took their toll on WCS, with prices averaging US$5.97/bbl in December. As shown in Figure 1.5, the Government of Alberta's curtailment program took effect in January 2019 and bolstered prices by ensuring production did not exceed available takeaway capacity. As a result, the price of WCS was able to average US$44.28/bbl through 2019. This represents an increase of 15 per cent compared to the average of US$38.46/bbl realized in 2018.

With continued near-term uncertainty regarding the start up of pipelines and rail service, the Government of Alberta extended its curtailment program to December 2020. Further, the province also made amendments to conditions for operators subject to the restrictions, including total production capabilities (increasing from 10 000 barrels per day [bbl/d] to 20 000 bbl/d), exemptions for conventional oil producers, and users of rail able to export beyond their base monthly production allotments.

Crude-by-rail: Even though crude-by-rail increased into 2019, narrow differentials proved to be challenging to producers when considering the transportation economics. As a result of the differentials faced in 2019, several large producers with access to rail let those facilities run idle. Although eastern Canada experienced propane shortages with CN Rail's week-long strike in November, there was little material effect on pricing for heavy oil. Even as the curtailment program maintains production quotas to stabilize prices, producers with long-term rail contracts and facilities are expected to increase rail volumes with sufficient price differentials.

In addition to the curtailment rules, the government announced plans in November 2018 to purchase 120 000 bbl/d in rail contracts to support prices and exports. However, it has since sought to offload these contracts to the private sector. Further details have yet to emerge on which companies will assume the contracts, how much they will cost, and how differentials will ultimately be affected. In addition, the province also cancelled programs in October 2019 that would support partial upgrading and explore new heavy oil refineries in Alberta, citing financial risks to taxpayers.

Forecast for 2020 to 2029

Price differentials: In 2020, the price differential between WCS and WTI is projected to widen, averaging more than US$14.00/bbl until 2022. Differentials are expected to widen due to the curtailment program relaxing and the return to more market-based clearing mechanisms. Any potential outages, such as refinery turnarounds, would again weigh on the price of WCS. With pipeline capacity expansions and optimization programs expected to be effective by 2023, lower transportation costs are expected to translate to narrower differentials of around US$13.00/bbl throughout the rest of the forecast.

Market access: The differential between WCS and WTI is not anticipated to narrow further until additional export capacity comes online, either through increased lower-cost rail or pipeline capacity additions. The completions of the Express pipeline expansion to serve Rocky Mountain region, referred to as the Petroleum Administration for Defense District (PADD) 4, Enbridge Inc.'s Line 3 Replacement programs in Canada and the U.S., and Enbridge Inc.'s Mainline optimization, are expected to support a narrower price differential into 2020. Pending construction, legal, and regulatory hurdles, Canada's Trans Mountain Expansion and TC Energy's Keystone XL will support additional heavy oil egress after 2022, allowing WCS producers additional flexibility to market to the U.S. West Coast (PADD 5), Gulf Coast (PADD 3), and even Asia.

Sulphur limits: The forecast considers the effects of the International Maritime Organization's (IMO's) sulphur regulations coming into effect on January 1, 2020. The IMO standards will reduce the sulphur limit for bunker fuels used in shipping to 0.5 per cent from 3.5 per cent. The International Energy Agency (IEA) estimates that more than 3.5 million bbl/d of high-sulphur fuel oil (HSFO) demanded in 2019 will largely be replaced with marine gas oil and very-low-sulphur fuel oil into 2020.

The IMO standards were expected to negatively affect global heavy sour crude oil prices because of an expected reduction in the demand for high-sulphur bunker fuels. Emission mitigation measures such as the installation of sulphur scrubbers allow ships to continue to burn HSFO, but refiners adapted the production and stockpiling of refined products to meet market demand over time. While the WCS-WTI price differential is projected to widen in 2020 to US$14.00/bbl, Alberta's exposure to the IMO standards is expected to be offset by reduced heavy oil supplies to imported to the U.S., especially from South America.

Because virtually all of Alberta's oil exports are destined for the U.S., WCS is typically supplied to complex refineries capable of handling heavy oil as well as eliminating sulphur and other impurities. Significant investments in these facilities enable the refiners to draw on heavier and lower-cost feedstock. WCS is expected to have further limited exposure to the sulphur content limit for bunker fuels because a majority of Alberta's oil is destined for markets in the U.S. Midwest. Refineries in this region primarily produce gasoline and distillate fuel oils for on-highway transportation instead of marine use, such as heating oil and diesel.

Compared to the Midwest, refineries on the U.S. Gulf Coast (USGC) produce higher volumes of residual fuel oils, which are typically used for marine vessels and power generation. However, decreased heavy oil imports from Venezuela and Mexico to the USGC suggests there will be sufficient heavy oil refining capacity for Alberta's exports in the region. By the time additional pipeline capacity is projected to come online, it is expected that refiners will have reconfigured to meet market demand under the IMO standards, having a muted effect on WCS prices longer term.

U.S. Gulf Coast demand: Imports of heavy oil from Venezuela and Mexico into the U.S. Gulf Coast are expected to continue to decrease over the forecast period, which Alberta's producers will continue to take advantage of, strengthening demand for WCS crude. While U.S. oil 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 of oil that are attractive to global refineries but are not as desirable for all U.S. Gulf Coast refineries, which are set up to process heavier feedstock. Given this, there is an opportunity for heavy Canadian crude to displace the heavier Latin American crudes as Canadian supply is secure and competitively priced.

By the end of the forecast period, the differential between WCS and WTI is forecast to narrow to US$13.00/bbl as Alberta ends its curtailment program as transportation capacity becomes increasingly available, U.S. refineries increasingly draw on Alberta supplies over international sources, and new marketing opportunities emerge for exports.

Low- and High-Price Cases

The low- and high-price cases represent the near-term and long-term volatility of the price of WCS. The following are a list of scenario considerations in the price cases.

Low-price case:

  • Differentials go unmanaged as the curtailment program ends after 2020, resulting in a surplus of oil production.
  • Production vastly exceeds storage and takeaway capacity as rail and export pipeline additions are either delayed or cancelled.
  • With inadequate volumes of low-sulphur refined products available globally, the IMO sulphur regulations have a greater-than-expected negative effect on the price of WCS.

High-price case:

  • Alberta is able to increasingly compete internationally to realize higher prices.
  • Capacity restrictions in both pipeline and rail are alleviated and reduce differentials.
  • The effect of the IMO's sulphur regulations on WCS prices will be minimal.

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