Updated June 2021
Production from existing facilities and supply from future projects are considered in Table S3.5. Production from future mining projects considers the cost of engineering, materials, and the skilled labour needed to expand existing projects and build new ones. Other factors considered include the forecast for oil prices.
We assess projects that have been approved or applied for based on their likelihood of meeting their on stream date and production capacity. This involves weighing the risks of each project. Some projects, although considered, will ultimately not be included in the ten-year forecast due to the high level of uncertainty about whether they will come on stream in the next decade.
In Situ Bitumen
Similar to surface mining, the supply forecast of in situ bitumen includes production from existing projects, expansions to existing projects, and new projects. All approved and applied for projects have been considered, as listed in Table S3.6. The forecast assumes that all existing projects will continue producing at normal production levels over the forecast period.
Projects considered for the forecast are assessed for the likelihood of meeting the on-stream date and stated production capacity. This involves weighing the risks of each project. Some projects, although considered, will ultimately not be included in the ten-year forecast due to the high level of uncertainty about whether they will come on stream in the next decade.
In projecting primary bitumen production, the AER combines expected production from currently active wells and new wells placed on production. The number of new wells placed on production and their average initial productivity and decline rates are the main determining factors in projecting production volumes. Similar to the crude oil well methodology, an economic model is used to determine the number of primary wells placed on production which forms the basis of the forecast.
The production forecast for future crude bitumen projects accounts for the past performance of similar schemes (including production and energy demand intensities), project modifications, the forecast of crude oil and natural gas prices, light crude and bitumen price differentials, and the ability of North American markets to absorb increased volumes. The production forecast does not consider future export pipeline capacity since the AER does not have authority over approving pipelines that cross provincial or international borders. Factors that may affect the pace of development, such as the availability of labour and equipment, were considered in the forecast.
Table S3.7 lists all future projects considered in the forecast. The AER considers the cost of engineering, materials and the amount of skilled labour required to expand existing projects and build new ones. Other key factors are assessed, such as crude oil price forecasts, the price differential between light crude oil and bitumen, the length of the construction period, and the market penetration of new upgraded volumes, all of which will affect project timing.
The bitumen demand forecast largely considers upgrading and refining capacity. Alberta demand includes newly proposed and approved expansion projects. Marketable production in excess of Alberta demand is assumed to be exported to other markets. Markets traditionally served by Alberta’s bitumen are assessed for opportunities and limitations, including maintenance schedules, transportation constraints, and competing supplies of crude oil.
Supply costs are the minimum constant dollar price required to recover all capital expenditures, operating costs, royalties, and taxes, as well as to earn a specified return on investment. After accounting for transportation costs and exchange rates, bitumen supply cost calculations enable projects to be compared to other crude oil benchmarks. This price can also be compared with current market prices to assess whether a project or resource is economically attractive.
Reference projects in our supply cost estimates include in situ steam-assisted gravy drainage (SAGD) (with and without cogeneration) and standalone mining (with cogeneration). While each real-life project is unique in its location and in the quality of its reserves, our supply cost analyses rely on a range of project specifications, including capital and operating cost information gathered from applications and company plans.
Mining projects with onsite upgrading facilities were not considered as currently no such projects have been proposed in Alberta. SAGD capital costs cover a wide range of values, with the lower range representing additional expansion phases where portions of the infrastructure are already in place, and the upper range representing capital costs for greenfield projects.
A major component of operating costs is natural gas purchased for fuel and feedstock. The supply costs analysis uses the forecast for the AECO-C gas price over a project’s 30- to 40-year life. For 2020 and beyond, our analysis assumes a nominal discount rate of 10 per cent.
Carbon costs assumptions for new oil sands projects are in alignment with the Government of Alberta’s Technology Innovation and Emissions Reduction (TIER) fund credit amount for 2020 to 2022, which is in line with current federal legislation. In March 2021, the Supreme Court of Canada ruled that the federal government has the ability to impose a minimum standard on carbon pricing across the country. At the time this analysis was being completed, higher carbon prices were yet to be legislated. Meanwhile, the provincial government may use different policy and regulatory instruments to minimize potential competitiveness impacts of higher carbon prices on industry. As such, carbon prices were assumed to remain at 2022 levels over the remainder of the forecast.
All 2020 data is as reported by industry until the end of December and does not capture any subsequent amendments. We used crude bitumen production volumes submitted in Petrinex.