Updated June 2020
This section discusses the production forecast methodologies for natural gas, which includes the three AER well type classifications of gas:
- CBM is methane found in coal seams, both as adsorbed gas and free gas.
- Shale gas is natural gas locked in fine-grained, organic-rich rock.
- Tight gas refers to natural gas found in low-permeability rock, such as sandstone, siltstone, and carbonates.
Although tight-gas volumes have been included in the AER's natural gas reserves and production reporting, it is often difficult or impossible to separate the tight portion of the reserves or production of a conventional reservoir.
Supply Costs
A supply cost, or "breakeven" price, is the minimum constant dollar price needed for an operator to recover all capital expenditures, operating costs, royalties, and taxes, as well as to earn a specified return on investment. It is expressed as a dollar value required per unit of production.
PSAC Areas
The supply costs estimate for an average horizontal or vertical/directional well in each Petroleum Services Association of Canada (PSAC) area includes
- initial productivities
- production decline rates
- vertical drilled depths and total measured depths
- gas composition
- shrinkage
- capital costs
- operating costs
- royalties and taxes
- a 10 per cent nominal rate of return
Assumptions
Not risked: The supply cost estimates are not risked (i.e., assumes a 100 per cent success rate).
Prices: Supply costs are estimated at plant-gate prices, which are reported in Canadian dollars (Cdn$).
Fluid Type: The representative wells in the Foothills, Foothills Front, Central, and Northwestern regions of Alberta (PSAC Areas 1, 2, 5, and 7) and the representative wells for shale wells are assumed to produce wet gas.
Marketable Natural Gas
Marketable gas is gas that remains after raw gas is processed (to remove nonhydrocarbons and heavier natural gas liquids) and meets specifications for use as a fuel. Marketable natural gas volumes are referred to as either the actual metered volume with the combined heating value of the hydrocarbon components present in the gas (i.e., "as is" gas) or the volume at standard conditions of 37.4 megajoules per cubic metre (MJ/m3). The average heat content of produced natural gas leaving a field plant is estimated to be 39.2 MJ/m3. This compares with a heat content of about 37.0 MJ/m3 for CBM.
Marketable natural gas production volumes for gas are calculated based on production data from the section on supply and disposition of marketable gas in ST3: Alberta Energy Resource Industries Monthly Statistics.
Table S5.7 shows the calculation for Alberta natural gas volumes.
CBM and Shale Gas Wells
Natural gas production from CBM and shale gas wells is determined separately. As shale and CBM producing wells are re-evaluated based on new information, historical annual values can change. Removals are equal to the difference between Alberta production and Alberta demand. However, removals must satisfy natural gas permitting conditions.
Production Forecast
We consider the following three components when forecasting marketable natural gas production:
- expected production from existing producing gas wells
- expected production from new gas wells placed on production
- gas production from oil wells
We also take into account estimates of the remaining established and yet-to-be established reserves of natural gas in Alberta. Gas production from oil and gas wells is forecast separately from shale and CBM wells. All projections are combined for a total forecast for Alberta. Continual reclassification of CBM and shale wells placed on production results in revisions to historical data and, therefore, changes to annual forecasts.
The natural gas production forecast includes marketable gas values, the gas that remains after the raw gas is processed to remove nonhydrocarbons, and heavier natural gas liquids that meet specification for use as a fuel.
Well Productivity
Table S5.8 shows the forecast of initial average productivity for new gas (by PSAC area), shale, and CBM wells. Decline rates for gas production from existing gas wells vary depending on factors such as the age, type, and geological locations of the wells. These numbers form the basis of the average well productivity over time and are paired with the number of producing wells to forecast production.
Main Factors in Predicting Volumes
To project natural gas volumes, we rely on data from the associated decline rates (Table S5.9 [insert new HTML link for Table S5.9][HTML]). Prices, royalties, taxes, capital costs, and other costs are also considered.
Royalty Estimations
We use the Modernized Royalty Framework to estimate royalties. A net present value for representative wells for all years of the forecast period is calculated, with the calculated net present value forming the basis of the forecast. Limiting factors, such as current and future capital market conditions and remaining reserves, are also considered.
Data
The AER uses natural gas production volumes submitted by industry to Petrinex. Petrinex is a secure, centralized information network used to exchange petroleum-related information. All 2019 data is as reported by industry up until the end of December and does not capture any subsequent amendments.