Updated May 2022
Energy prices play a key role when deciding on energy development or assessing remaining reserves. Prices are determined by supply and demand, which are both influenced by economic activity, seasonal temperatures, and market access.
Crude Oil Prices
West Texas Intermediate (WTI)
North American crude oil prices are based on the price of WTI crude oil at Cushing, Oklahoma, which is the underlying physical commodity market for the New York Mercantile Exchange (NYMEX) for light crude oil contracts.
The near-term forecast for WTI prices are based on the current and expected U.S. and global supply and demand balance within the next three years. Thereafter, prices reflect inflation rates and other factors, such as longer-term global and North American supply and demand trends.
WTI is considered a light, sweet crude oil and has an American Petroleum Institute (API) gravity of 40 degrees and sulphur content of less than 0.5 per cent.
Canadian Light Sweet (CLS)
The forecast for the CLS crude oil price at Edmonton, Alberta, is derived from WTI prices at Cushing. The price of CLS typically follows similar trajectories as WTI and is adjusted by several regional factors, including transportation costs from Edmonton to Cushing and the U.S./Canadian dollar exchange rate. The combination of these forecasts and factors are used to develop the light sweet crude oil price forecast in Canadian dollars.
Western Canadian Select (WCS)
The WCS crude oil price forecast is derived from WTI prices at Cushing. The WCS benchmark represents a blend of different bitumen types. The price is based on several factors, including oil sands supply and inventories, demand from U.S. refineries capable of handling heavy oil, transportation costs and availability from Hardisty, Alberta, to Cushing, the U.S./Canadian dollar exchange rate forecast, and quality differentials (e.g., sulphur content, density).
WCS is considered a heavy, sour crude oil and has an API gravity of 20.5 to 21.5 degrees and a sulphur content of 3.0 to 3.5 per cent. The physical quality distinction between WCS and WTI is relevant as heavy and sour crude oils trade at a discount to the light and sweet ones.
Natural Gas Prices
Henry Hub, located in Erath, Louisiana, has traditionally been the primary trading hub for natural gas in North America and is the underlying commodity market for spot and futures prices on the NYMEX.
The Henry Hub price forecast for near term is derived from current data on existing and expected economic activity in the natural gas sector, continental supply and demand, and exports of North American natural gas from liquefied natural gas terminals. This data is collected from various Canadian and U.S. government agencies, market and industry reports, and company information.
The long-term forecast considers additional economic factors, including inflation, uncertainties surrounding continental supply and demand, government policies, and project completion schedules.
The AECO-C price from the Natural Gas Exchange (NGX) is the Alberta reference price derived from the U.S. Henry Hub price forecast, accounting for transportation differentials, regional demand, and the U.S./Canadian dollar exchange rate.
Base price: The most likely price path given what is currently known and expected.
Low- and high-price cases: The low- and high-price cases reflect underlying uncertainties inherent in the base price forecast. This is reflected in the short term by implied volatility, estimated using historical prices. Long-term volatility is assumed to grow over time due to rising uncertainty.
Volatility measures how much prices move over time, expressed as a percentage difference of the price of the commodity on a day-to-day basis. Because price is a function of supply and demand, volatility results from the underlying supply and demand characteristics of the market.
Both the low- and high- price cases represent the 90th percentile confidence intervals, subject to historical volatility. These intervals grow overtime to account for increasing uncertainty.
U.S./Canadian Exchange Rate Forecast
Because physical commodities are traded internationally, prices are influenced by the exchange rate between the currencies of the trading partners. Since the U.S. dollar serves as the underlying currency for commodity markets, the focus is on the U.S./Canadian dollar exchange rate.
The exchange rate forecast is an input into the crude oil and natural gas forecast models for projecting Canadian commodity prices. The exchange rate assumptions are based on an evaluation of Canadian economic indicators, such as gross domestic product, inflation rates, residential and commercial investment, as well as an evaluation of current trade and oil price forecasts.
The capital expenditure forecasts for oil sands and conventional oil and gas are based on the production forecasts for natural gas, crude oil, and crude bitumen set out in this report. The AER estimates them separately and then combines them for the total oil and gas capital expenditures.
Historical statistics are from the Canadian Association of Petroleum Producers (CAPP) Statistical Handbook, with 2021 value being an estimate until actual capital expenditures are reported by all companies.
Oil and Natural Gas
The oil and natural gas capital expenditure forecast are the sum of capital spending on oil and gas drilling and completion, land, gas plants development, field equipment, geoscience, and enhanced oil recovery. Drilling and completion cost assumptions are based on the Petroleum Services Association of Canada's cost study. The AER's meterage data is used to determine a drilling cost per metre by fluid status (oil or gas) and well type. The forecast number of wells placed on production is used to determine the capital expenditures for drilling and completions. Wells are classified by fluid status and well type.
Land sales and gas plant expenditures are based on publicly available information, including industry budgets and presentations.
Expenditures for field equipment, geophysics, and enhanced oil recovery are based on historical trends and are consistent with forecasts and assumptions used in this report.
The oil sands capital expenditure forecast is based on the forecast for new projects and the forecast for sustaining capital expenditures for existing projects.
Capital spending requirements for new projects are broken down into in situ thermal, primary, mining, and upgrading project types. Capital cost assumptions for each project type, including both the capital outlay allocation over time and the construction timelines, are based on publicly available information.
The capital expenditure forecast for new projects includes projects applied for, approved, or under construction and may incorporate some announced projects. These projects have been assessed for the likelihood of meeting the on‑stream date and anticipated expenditures.
Sustaining capital expenditures are capital spent by a business to maintain and repair fixed assets and exclude expenses for operations. The AER calculated these expenditures by taking the industry average estimate of sustaining costs per barrel and applying it to the crude bitumen production forecast.
The capital expenditure forecast for emerging resources is based on public announcements for hydrogen, helium, and geothermal projects, including projected capacity additions as described in the emerging resources forecast.