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Updated June 2021

 

Energy prices play a key role when making any decision on energy development or when assessing remaining reserves. Prices are determined by supply and demand, both of which are 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 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 a 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 a number of 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, and its price is based on a number of factors such as: oil sands supply and inventories; refinery demand in key U.S. markets 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. It is important to make the physical quality distinction between WCS and WTI, as heavy and sour crude oils naturally trade at a discount to light and sweet ones.

Natural Gas Prices

Henry Hub

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 (LNG) terminals. This data is collected from various Canadian and U.S. government agencies, market and industry reports, and company information.

The longer-term forecast considers additional economic factors, such as inflation, and considers uncertainties surrounding continental supply and demand, government policies, and project completion schedules.

AECO-C

The AECO-C price from the Natural Gas Exchange (NGX) is the Alberta reference price and is derived from the U.S. Henry Hub price forecast, taking into account transportation differentials, regional demand, and the U.S./Canadian dollar exchange rate.

Price Cases

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, derived from the futures markets, and in the long term by historical price fluctuation, as derived from actual realized prices.

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. As price is a function of supply and demand, volatility results from the underlying supply and demand characteristics of the market.

The short-term high- and low-price cases reflect the implied volatility over a period of two to three years, reflecting current market conditions.

The long-term low and high price scenarios reflect historical price trends. The range of the low and high bands is a measure of uncertainty about how the market expects prices to trade.

U.S./Canadian Exchange Rate Forecast

As 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.

Capital Expenditures

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 2020 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 off of publicly available information, including industry budgets and presentations.

Expenditures for field equipment, geology and geophysics, and enhanced oil recovery are based on historical trends and are consistent with forecasts and assumptions used in this report.

Oil Sands

The oil sands capital expenditure forecast is based on the forecast for new projects and the forecast for sustaining capital expenditures for existing projects.

New 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 list of new projects in the oil sands capital expenditure forecast 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

Sustaining capital expenditures are capital spent by a business to maintain and repair fixed assets and do not include 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.