Although not a new concept, carbon taxes have become a hot topic around the globe, ever-growing in the last decade.  Canada is no different. At home, Canadians are paying carbon taxes on several different services, from fueling vehicles to heating our homes. The same can be said for industrial emitters. They pay carbon tax based on historical emission rates as well as emission reduction targets set by government legislation.

Why? According to the Government of Canada:

A price on carbon pollution is an essential part of Canada’s plan to fight climate change and grow the economy. It is one of the most efficient ways to reduce greenhouse gas emissions and stimulate investments in clean innovation. It creates incentives for individuals, households, and businesses to choose cleaner options.

Alberta has implemented carbon taxes for large emitters since 2007 and many in situ projects are part of the program. In situ projects combust natural gas to generate steam, which is then injected into the underground reservoir to heat and mobilize bitumen. During the natural gas combustion process, carbon dioxide and other greenhouse gases are generated and released into the atmosphere. These emissions are measured and a carbon tax is applied to them.

Over the last 4 years, there have been many changes and updates to legislation at the federal and provincial level. Canada is looking to achieve emissions neutrality by 2050 and a price on carbon is part of our government’s solution to this complicated problem. In this blog, we will discuss the impact of carbon price legislation on in situ projects.



  • Effective January 2020, replacing the Alberta Carbon Competitiveness Incentive Regulation (CCIR). Granted federal equivalency in December 2019.
  • Mandatory for large emitters (over 100,000 tonne CO2/year) but small emitters can apply to opt-in. If a facility does not opt-in, they will pay carbon tax based on federal legislation.
  • In situ projects with 4,000 bbl/day of bitumen production and steam-oil ratio (SOR) of 3 would emit over 100,000 tonne CO2 each year.
  • For large emitters, project facility emissions history is used to determine a facility specific benchmark (tonne CO2/m3 bitumen), 10% reduction in year one (2020) followed by 11% in year two (2021) and 12 % in year three (2022), until the project reaches the industry high performance benchmark (HPB).
  • New projects (first 2 years) are exempted from compliance. Facility specific benchmarks are based on year two to year four emission rates. Benchmarks tighten each year, until it reaches the industry high performance benchmark.
  • For Alberta in situ projects, the HPB is 0.2974 tonne CO2/m3 bitumen. Based on a typical emission rate of 0.14933 tonne CO2/m3 steam, this equates to a steam-oil ratio (SOR) of approximately 2.0.


Carbon price has the biggest impact on carbon tax. The federal government plans to increase the carbon tax to $170/tonne by 2030. In the immediate future (2022), the carbon tax will sit at $50/tonne. The Alberta TIER program is currently following the federal carbon pricing model.

The industry has been reducing operating costs since the 2014 oil price crash and many in situ operators have achieved operating costs below $12/bbl of bitumen. With a carbon price of $50/tonne CO2 by 2022, a project with SOR of 2.5 would pay $0.60/bbl of bitumen production in 2030 but it would be $2/bbl of bitumen production with $170/tonne CO2. This is a 17% increase to $12/bbl of operating costs. A SOR of 2.5 is relatively low in the industry; projects with a higher SOR will see further increase in carbon tax.

The following graph shows the impact of carbon pricing and project SOR on carbon tax. The following graph assumes constant project SOR throughout the life of a project:


With a SOR of 4 and $170/tonne CO2 carbon tax, a project that is starting in 2021 will pay carbon taxes of approximately $5/bbl of bitumen by 2040. The additional $5/bbl of bitumen operating cost would impact in situ project economically but it is relatively minor when compared to the swing in oil prices over the last 5 years. For in situ projects, oil price is the biggest driver in project economics due to large upfront facility capital investment and longer payout periods. If a project has announced that it is now uneconomic due to $170/tonne CO2 carbon tax, that project was likely already marginal, even without carbon tax, since a $5/bbl decrease in oil price is not uncommon.

The introduction of higher carbon tax is not the main reason why Alberta has not seen any new in situ projects being built. But it does introduce uncertainties to the industry with the constant influx of legislation and changing carbon price. GLJ continues to monitor federal and provincial legislation for updates, and is running a series of carbon tax sensitivities to better understand the impact of a higher, future carbon tax on project economics.


  • Include carbon tax in all economic calculations to understand the impact. GLJ has included carbon tax calculation and forecast for all in situ projects based on existing legislation. For non in situ projects, carbon tax can also be a concern.
  • Optimize operations and embrace new technologies to reduce project SOR. There are a wide variety of emerging technologies in different stages of development such as solvent, electrical heating and more.
  • Consider a cogeneration facility to obtain carbon credit from electricity generation while generating steam.
  • Consider CO2 sequestration where COis injected into underground reservoirs for storage to reduce emissions into the atmosphere.
  • Purchase credits from other projects based on the federal Greenhouse Gas Offset Credit System Regulations.
  • Utilize and optimize existing technologies that have been proven to reduce project SOR such as natural gas (NCG) injection while reducing steam injection and drilling infill wells.
  • Review company project development timing. Carbon benchmarks tighten each year; it could be beneficial to focus capital on one project to speed up development, rather than spending capitals on multiple projects.
  • Review and adjust company development areas. Consider separating large projects into several smaller in situ projects, since each will have its own benchmark that will tighten within different timeframes. If a company has a large volume of land, with over 30 years of undeveloped reserves, it’s reasonable to have 2 separate projects to obtain a more favorable benchmark for the development starting after 2035.
Published On: April 27, 2021Categories: Carbon


  • Angie Wong

    Angie has over twelve years of experience in the oil and gas industry and joined GLJ in 2014. She has a strong foundation in development, operation and evaluation of thermal in situ projects across Western Canada. She has also evaluated various EOR projects, conventional and unconventional assets. More recently her focus has been on changes in Canada Greenhouse Gas legislation and the impact on project economics.