Crude Bitumen Demand


Updated March 2018

Upgraded & Nonupgraded Bitumen

Figure S3.10

  • In 2017, the four operating refineries in Alberta, with a total capacity of 73.5 thousand cubic metres per day (103 m3/d)─462.5 thousand barrels per day (103 bbl/d)─processed an estimated 50.1 103 m3/d (315.3 103 bbl/d) of upgraded bitumen and 2.7 103 m3/d (17.0 103 bbl/d) of nonupgraded bitumen.
  • As shown in Figure S3.10 [Tableau], total estimated Alberta demand for upgraded and nonupgraded bitumen was 59.5 103 m3/d (374.4 10bbl/d) in 2017, which is a 7.6 per cent increase from 2016. The increase was primarily due to recovery from the Fort McMurray wildfires.
  • Alberta demand for upgraded and nonupgraded bitumen is forecast to increase to 72.9 103 m3/d (458.8 103 bbl/d) by 2027.
  • On average over the forecast period, upgraded bitumen will account for about 82.0 per cent of total Alberta marketable bitumen demand, with nonupgraded bitumen accounting for the remainder.
  • In 2017, removals of upgraded bitumen and nonupgraded bitumen were estimated to be 103.0 103 m3/d (648.2 103 bbl/d) and 247.2 103 m3/d (1.6 million [106] bbl/d), respectively. Upgraded bitumen exports increased 7.3 per cent from 2016 due to production increases from upgraders outpacing provincial refinery demand.
  • Removals of upgraded bitumen from Alberta are expected to increase by 28.3 per cent to 132.1 103 m3/d (831.3 103 bbl/d) between 2017 and 2027, while removals of nonupgraded bitumen are expected to increase 54.0 per cent to 380.8 103 m3/d (2.4 106 bbl/d) over the same period.
  • Beyond the addition of the North West Redwater Partnership Sturgeon refinery (Sturgeon refinery) and an amended application to redesign the Value Creation Inc. (VCI) Heartland Upgrader project, there will be limited growth in Alberta demand for raw bitumen over the forecast period. Removals of nonupgraded bitumen are expected to increase over the forecast period.

The first phase of the Sturgeon refinery is projected to begin commercial operations in early 2018 and will be capable of handling up to 7.9 103 m3/d (50.0 103 bbl/d) of raw bitumen. This phase is designed to produce about 6.4 103 m3/d (40.3 103 bbl/d) of ultra-low sulphur diesel, 4.5 103 m3/d (28.3 103 bbl/d) of diluent and naphtha, 1.4 103 m3/d (8.8 103 bbl/d) of low-sulphur vacuum gas oil, and 0.5 103 m3/d (3.1 103 bbl/d) of butane and propane. While second and third phases are planned, each with identical capacity to the first phase, their development depends on the first phase being commercially viable.

VCI previously received approval for its three-phase Heartland Upgrader project, also known as the Value Chain Solutions Heartland Complex (VCS-H). VCS-H would produce a sour synthetic medium crude oil using its Accelerated DeContamination (ADC) and Clean Oil Cracking (COC) processes. VCI has submitted an amendment application to replace the second of the three phases with two Clean Oil Refining (CORe) units to produce diesel, hydrotreated naphtha, and premium synthetic crude oil supplied from its COC stream, known as Clean Oil La Fit (COLF). Under an alternative development scenario, the second phase would be able to process product from VCI’s own offsite in situ projects. A reduction in the number of phases will reduce the diluted bitumen throughput capacity of VCS-H from 41.4 103 m3/d (260.5 103 bbl/d) to 27.6 103 m3/d (173.6 103 bbl/d). Subject to regulatory approval, VCI plans to begin construction of the first phase of VCS-H in 2018 and operation in 2021, with construction of the remaining phase and refining infrastructure scheduled to follow thereafter subject to market conditions.

Husky Energy’s (Husky’s) asphalt refinery located in Lloydminster, Alberta, processes heavy oil used in producing road asphalts. The refinery also produces condensate and refined petroleum products that are processed at Husky’s adjacent upgrader located in Lloydminster, Saskatchewan. To handle its growing production from heavy oil and thermal assets, Husky considered doubling the capacity of its 4.8 103 m3/d (30.0 103 bbl/d) refinery for a cost of up to Cdn$900 million. However, the company has deferred that financial decision past 2020 following the acquisition of a 7.9 103 m3/d (50.0 103 bbl/d) heavy oil refinery in Wisconsin, which it purchased in August 2017 for about Cdn$550 million.

Currently, Alberta’s crude bitumen removals are primarily sent to the United States via pipeline and rail. Information on the province’s petroleum pipelines and rail terminals can be found in the Transportation and Facilities section. While Alberta’s bitumen exports currently meet U.S. refinery demand, light oil production in U.S. supply basins may result in a loss of U.S. refinery capacity available to process Alberta’s upgraded (lighter) bitumen.

Heavy oil refineries located in the U.S. Midwest and Gulf Coast areas could potentially convert their processing capabilities to lighter feedstocks, which would significantly reduce refining opportunities for Alberta’s nonupgraded bitumen. However, complex refineries, which are predominant in these regions and capable of handling nonupgraded bitumen, typically have multibillion dollar capital costs and favour discounted crude supplies, suggesting long-term demand for Alberta’s bitumen exports will persist. Previous challenges to investment in Mexican heavy oil exports and international sanctions against Venezuela during 2017 resulted in Alberta’s bitumen being viewed as a competitive and secure source of oil.