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Updated June 2023


Marketable Natural Gas

Marketable gas is natural gas that remains after raw gas is processed (to remove nonhydrocarbons and heavier natural gas liquids) and meets the 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 39.5 MJ/m3, compared with coalbed methane (CBM) at about 37.0 MJ/m3.

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 marketable Alberta natural gas volumes for 2021 and 2022.

the marketable Alberta natural gas volumes for 2021 and 2022
Coalbed Methane and Shale Gas

Natural gas production from CBM and shale gas wells is determined separately. Shale gas and CBM-producing wells are re-evaluated based on new information because historical annual values can change.

Production Forecast

The AER includes three well-type classifications for natural gas production:

  • CBM: methane found in coal seams as adsorbed or free gas.
  • Shale gas: natural gas locked in fine-grained, organic-rich rock.
  • Conventional and tight gas: tight gas refers to natural gas found in low-permeability rocks such as sandstone, siltstone, and carbonates.

Although tight-gas volumes are included in the AER’s natural gas reserves and production reporting, it is difficult (sometimes impossible) to separate the tight portion of the reserves or production in a conventional reservoir.

Our forecasts for marketable natural gas production consider

  • expected production from existing producing gas wells,
  • expected production from new gas wells placed on production,
  • gas production from oil wells, and
  • prices, royalties, taxes, capital costs, and other costs.

Our forecasts also account for estimates of the remaining established and yet-to-be-established reserves of natural gas in Alberta. We use the Modernized Royalty Framework to estimate royalties.

A net present value is calculated for representative wells for all years of the forecast and forms the basis of the forecast. Limiting factors, such as current and future capital market conditions and remaining reserves, are also considered.

Gas production is forecast separately for conventional and tight, shale, and CBM wells. All projections are combined for a total marketable gas production forecast for Alberta. Continual reclassification of CBM and shale wells placed on production results in revisions to historical data and changes to annual forecasts.

Initial Productivity Rates

Table S5.8 shows the forecast of initial average productivity for new natural gas (by Petroleum Services Association of Canada (PSAC) area), shale, and CBM 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. Initial productivity rates are expected to decline in most areas except for Foothills Front (including shale) and horizontal wells in Central Alberta area.

the forecast of initial average productivity for new natural gas
Main Factors in Predicting Volumes

We rely on data from the associated decline rates (Table S5.9) to project natural gas volumes. Decline rates for gas production from gas wells vary depending on a well's age, type, and geological location.

Forecast production decline rates for new Alberta natural gas wells

Demand Forecast

The demand forecast for Alberta is based on a sector-by-sector analysis of past, present, and future drivers of natural gas use. For example, forecasts for sectors such as oil sands and electricity generation depend on other forecasts, such as crude bitumen production, total electricity demand, and growth in renewable electricity generation.
Gas removals are equal to the difference between Alberta marketable gas production and Alberta demand. Removals are assumed to satisfy natural gas permitting conditions.

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 and earn a specified return on investment. It is expressed as a dollar value required per unit of production.

The supply cost estimate for an average horizontal or vertical/directional well in each PSAC area includes the following parameters:

  • initial productivities
  • production decline rates
  • drilled vertical depths and total measured depths
  • gas composition
  • shrinkage
  • capital costs
  • operating costs
  • royalties and taxes
  • prices of by-products such as natural gas liquids and sulphur
  • a 10 per cent nominal rate of return

The supply cost estimates are not risked (i.e., assume a 100 per cent success rate) and are estimated at plant-gate prices and reported in Canadian dollars. Representative wells in the Foothills, Foothills Front, Central, and Northwestern areas of Alberta (PSAC areas 1, 2, 5, and 7) and the representative wells for shale wells are assumed to produce wet gas.


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 2022 data are as reported by industry up until the end of December 2022 and does not capture any subsequent amendments.