Updated March 2018
All values for 2017 have been estimated using data reported by industry up until the end of August 2017. Full-year estimates for 2017 were derived using these data, adjusting for seasonality.
The AER defines supply cost as the minimum constant dollar price required to recover all capital costs, operating costs, royalties, and taxes, as well as to earn a specified return on investment. The supply cost calculation determines a dollar value required per unit of production. The supply costs are based on representative wells in each Petroleum Services Association of Canada (PSAC) area. Supply costs for different geological plays and PSAC areas vary significantly because of differing production rates, well types, drilling and operating costs, royalties, and other factors. Therefore, the results may not be reflective of wells that differ from the representative well profiles used in the analysis.
The following data were used to derive a supply cost estimate for the average horizontal, vertical, and directional well in each PSAC area: formation, initial productivity, production decline rates, vertical depth drilled and total measured depth of the well, gas composition, shrinkage, capital costs, operating costs, royalties, taxes, and a 10 per cent nominal rate of return. The supply costs are not risked (i.e., assumes a 100 per cent success rate) and are estimated as wellhead costs, which are reported in Canadian dollars.
The crude oil supply model was revised in 2015 to forecast well activity and production in more detail. Forecasts are now available by PSAC area, crude oil density, and well type.
The AER does not separately estimate or report “tight” oil production, that is,oil found in low‑permeability rock, such as sandstone, siltstone, shale, and carbonates. It is often difficult or impossible to separate the tight portion of the reserve or tight oil production from a conventional reservoir; therefore, any unconventional tight oil volumes are included within the AER’s conventional crude oil reserves and production reporting.
The AER uses crude oil production volumes submitted to Petrinex by producers. Petrinex is a secure, centralized information network used to exchange petroleum-related information.
In projecting conventional crude oil production, the AER combines for each year expected production from pre-existing producing wells and new wells placed on production in that year, shown in Table S4.2 [HTML]. The number of new wells placed on production and their average initial productivity and decline rates are the main determining factors used in projecting production volumes. The AER uses a model that also considers prices, royalties, taxes, capital costs, and other costs. The model calculates a net present value for representative wells for all years within the forecast period, with the calculated net present value forming the basis of the forecast. The forecast considers limiting factors such as current and future capital market conditions and remaining reserves.
Table S4.3 [HTML] shows the forecast initial productivity rates, calculated using historical three-year average rates for conventional wells by PSAC area. Decline rates, shown in Table S4.4 [HTML], vary depending on factors such as the age, type, and geological locations of the wells. The AER also takes into account its estimates of the remaining established and yet-to-be established reserves of crude oil in the province.
The Alberta conventional crude oil demand forecast is based on historical refinery throughput, anticipated new refineries, and expansions to current refinery capacity. Removals are equal to the difference between Alberta production and Alberta demand. The AER uses historical utilization rates when forecasting refinery throughput in Alberta.