Home Environmental Climate-Related Risks and Air Emissions

We take steps to minimize our impact on land and habitat, air and water, actively seeking ways to both mitigate and further reduce our environmental footprint.

We provide environmental expertise, standards, systems and oversight, through teams deployed in all areas of our operations. Our structure incorporates elements such as technical standards capability, with technical authority and a continuous improvement team.

Climate-Related Risks and Air Emissions


  • Target of reducing Scope 1 GHG emissions intensity by 25% by 2025, from our 2015 level
  • Aspire to achieve net zero emissions by 2050
  • Scope 1 GHG emissions intensity of 37.44 tonnes of CO2e/mboe


  • Maintain ongoing management and governance of climate-related risks, with the goal of reducing greenhouse gas emissions and other air pollutants through the development and application of new technology and energy efficiency measures.
  • Target to reduce Scope 1 GHG emissions intensity by 25% by 2025.

Our operations generate greenhouse gases and other air emissions. We recognize these emissions can affect local air quality and contribute to climate change. Our emissions are generated by combustion equipment, venting to atmosphere, the flaring of waste gases, and fugitive emissions.

Air emissions management programs collect the data needed to meet regulatory requirements, manage risk and explore opportunities to economically improve emissions performance and minimize the impact on our neighbours. This is supported by our Environmental Performance Reporting System, which provides transparency and consistency of data.

Our carbon management approach and metrics are detailed in annual submissions to the CDP Climate Change Program. In 2019 we maintained our grade of B, which exceeds the North American average and is based on our disclosure of: governance, risks and opportunities, business strategy, targets and performance, emissions methodology, emissions data, emissions breakdown, energy, additional metrics, verification, carbon pricing and engagement. In 2019 our CDP response was reviewed by members of the executive team and signed by the Chief Operating Officer.

Our air emissions-related initiatives include:

  • Public disclosure of air emissions
  • Fugitive emissions management
  • Methane conservation projects
  • Evaluating and testing CO2 capture technology
  • Carbon capture at our Lloydminster Ethanol Plant for use at CO2 enhanced oil recovery locations
  • Generation of carbon offsets through beyond compliance emission reductions at our Tucker Thermal Project and early action on methane emissions reduction at our assets in Western Canada
  • Contributing to joint industry air emissions management initiatives and research, such as through the Petroleum Technology Alliance of Canada
  • Improvement of shared data related to air emissions
  • Engaging with regulators to provide feedback on proposed regulations at local, regional and corporate levels

Emissions Targets

We have set a target to reduce our Scope 1 greenhouse gas emissions intensity by 25% by 2025, from our 2015 level and aspire to achieve net zero emissions by 2050. Achieving our 2025 target is a start while we continue to invest in new technologies and carbon offsets that will bring us closer to this 2050 goal.

Climate Change and Greenhouse Gas Emissions

We recognize the social, environmental and economic risks posed by climate change as outlined in the Intergovernmental Panel on Climate Change (IPCC) Special Report on Global Warming of 1.5 degrees Celsius. The risks and opportunities inherent to a lower global emissions pathway are built into our Enterprise Risk Management process.

Husky believes there is a significant role for government to provide incentives and direct support in the development and commercialization of technologies that reduce industry emissions. Revenues generated through carbon policy and regulation should be made available to support industry research, including the development and deployment of innovative practices and technology that improve efficiency and reduce carbon emissions. Emission reduction regulations should apply a price on carbon and we support the development of a market for environmental attributes such as emissions offset credits.

We monitor changing expectations related to carbon and climate performance and disclosure, including the Task Force on Climate-related Financial Disclosures and the Sustainability Accounting Standards Board.

Through both voluntary and mandatory reporting mechanisms, we demonstrate our management of ESG risks, including climate change.

We continuously engage with our investors and other stakeholders about their expectations related to climate change disclosure, to understand and address their priorities.

Husky follows the Greenhouse Gas Protocol for Scope 1 and 2 GHG estimation methodology, adjusted using IPIECA guidance where relevant. Under new regulatory reporting requirements, more than 60% of our 2019 Scope 1 emissions will be assured by a third party, to a reasonable level. The rest of the 2019 Scope 1 emissions are subject to independent limited assurance. All Scope 2 emissions and our total energy use receive independent limited assurance. Due to COVID-19 restrictions, assurance over selected performance indicators will be performed and published later in 2020.

Scope 1 and 2 GHG Emissions Performance

Our 2019 Scope 1 GHG emissions decreased almost 700,000 tonnes of CO2e compared to 2018, due to natural declines in conventional oil production, the shutdown of the Lima Refinery to tie-in the crude oil flexibility project, sale of the Prince George Refinery, operations at the Superior Refinery remaining suspended due to a 2018 fire and the shut- in of the SeaRose floating production, storage and offloading vessel for part of the year.

Our Scope 1 GHG emissions intensity in 2019 was 37.44 tonnes of CO2e/mboe.*

Scope 2 GHG emissions, consisting of emissions from purchased electricity and steam, decreased 65% in 2019, or more than 100,000 tonnes, primarily due to the need for less electricity. This is due to natural declines in conventional oil production, operations at the Superior Refinery remaining suspended due to a 2018 fire, Alberta government- mandated production curtailment that led to reduced production at the Sunrise Energy Project, a turnaround at the Rainbow Lake Gas Plant and the shut in of a Saskatchewan thermal project, which is being decommissioned.

Carbon Offsets

Under Alberta’s Carbon Competitiveness Incentive Regulation in 2019, the Tucker Thermal Project will use both emission performance credits generated in previous years and emission offset credits to reduce total compliance costs. These credits were earned by reducing Tucker’s GHG emissions below regulatory requirements.

Renewable and Low Carbon Production

Renewable energy is a growing part of the global energy mix and we assess opportunities to use renewable energy where it makes economic and operational sense. Almost 30 years ago Husky helped pioneer ethanol production for use in ethanol-blended gasoline. We currently operate two ethanol plants, in Minnedosa, Manitoba and Lloydminster, Saskatchewan. With total production of up to 300 million litres per year, we are Western Canada’s largest manufacturer and marketer of fuel-grade ethanol.

Carbon Capture and Storage

At the Lloydminster ethanol plant, we capture up to 250 tonnes a day of carbon dioxide (CO2) to aid in enhanced oil recovery, which involves CO2 being injected into reservoirs to increase oil production. From 2012 to 2019, 531,000 tonnes of CO2 were captured. The use of this technology allows us to produce some of the lowest carbon intensity ethanol in Canada.

We continue to evaluate additional carbon capture technologies, including at our Pikes Peak South thermal project where we have been testing Svante technology that captures CO2 from a once-through steam generator. We started in 2015 with a 0.5 tonne-per-day pilot and in 2019 commissioned a 30 tonne-per-day system. We believe these technologies have the potential to reduce carbon capture costs and reduce the carbon intensity of bitumen production.

Options to reduce GHG emissions from our upstream and downstream operations are compiled and evaluated using a Marginal Abatement Cost Curve (MACC). The MACC catalogues the size of emissions reduction possible and return on investment for various options. This allows us to prioritize resources and achieve reductions at the most efficient cost per tonne of CO2e. The MACC also helps different areas of the Company share information about emissions reduction options.

We prepared a carbon management plan for our Sunrise facility in 2017. The annually renewed carbon management plan helps us engage with our joint venture partner on options to improve emissions performance. In 2020 carbon management plans were added to the annual performance contracts of operational Executive Vice Presidents and Senior Vice Presidents, which will be used to update and track progress against our carbon target.


Husky supports provincial regulations requiring the reduction of methane emissions from oil and gas operations in Alberta and Saskatchewan by 45% by 2025. These regulations came into effect on January 1, 2020 and provide new methodologies on how to report fuel, flare and vent volumes, which will result in a change in our reported venting emissions for 2020.

Initiatives to reduce methane emissions include the conversion of pneumatic devices, gas conservation and incineration technology. To further enhance our ability to manage and reduce methane emissions, we are gathering equipment data from our upstream operations in Western Canada. As of June 2020 our Methane Reduction Retrofit Compliance Plan in Alberta covers most of our operations. This data is critical to determine how to effectively reduce methane from our operations and meet the intent of the new regulations. We have visited more than 3,200 locations, with more than one million data points confirmed, and have continued to gather data in 2020.

Gas Conservation

We are redesigning our CHOPS operations to use multiple horizontal wells from a central location, instead of scattered vertical wells. This results in the associated gas from many wells produced to a single location where it is more easily conserved, resulting in less venting and flaring.

Criteria Air Contaminants/Hazardous Air Pollutants

We measure, monitor and report emissions of criteria air contaminants through regulations outlined in the Canadian Environmental Protection Act, under Environment and Climate Change Canada, and hazardous air pollutants through regulations outlined under the U.S. Environmental Protection Agency. This allows us to evaluate and manage emissions at the corporate and individual facility level, forecast emissions associated with future operations and achieve regulatory compliance.

Environment and Climate Change Canada’s Multi-Sector Air Pollutant Regulations (MSAPR) require us to meet NOx limits within our inventory of stationary engines and heaters. Large stationary engines and heaters installed after 2017 must meet low NOx performance requirements and our MSAPR program will ensure that we meet the regulatory timeline of 2025.

Our facilities are designed to meet the ambient air quality objectives in Alberta and Saskatchewan for NOx, SO2 and particulate matter. Our continuous emissions monitoring systems monitor NOx at Sunrise and Tucker and SO2at the Lloydminster Upgrader, to ensure we do not exceed regulatory requirements.

In 2019 there was a reduction of between 10% and 15% in all criteria air contaminants, primarily due to the changing operating conditions.

The sulphur recovery unit installed at the Rush Lake thermal project in mid-2018 is reducing our sulphur emissions, responsible for more than 60% of the 2019 over 2018 decrease. Due to the sale of the Prince George Refinery in 2019, those emissions were not reported, offset by increased sulphur emissions at two of our Saskatchewan thermal projects.

Total NOx emissions decreased by 14% in 2019, due primarily to the shut-in of the SeaRose FPSO for part of the year, less drilling in the Atlantic region and the shutdown of the Lima Refinery to tie-in the crude oil flexibility project.

The 10% decrease in 2019 VOCs is primarily due to the sale of the Prince George Refinery and operations at the Superior Refinery remaining suspended. The 15% decrease in 2.5 micron Particulate Matter over 2018 is due to the shut in of the SeaRose FPSO for part of the year and operations at the Superior Refinery remaining suspended.

Fugitive Emissions Management Program

We have two programs to manage fugitive emissions, the Fugitive Emissions Management Program (FEMP) for upstream and midstream facilities, and the Leak Detection and Repair (LDAR) program for downstream facilities. Fugitive emissions, including methane and VOCs, are gas and vapour leaks from valves, piping connections, pumps and compressor seals, and other piping system components which occur as part of the normal operation of a facility or plant.

These programs detect and ensure timely repair of fugitive emissions from equipment. FEMP and the LDAR program improve safety through early detection and repair of emission sources, reducing exposure to potentially hazardous gases, reducing GHG emissions and VOCs, improving overall air quality, increasing operational efficiency and conserving marketable gas.

Several techniques are used to detect leaking components, including specialized infrared cameras that provide a view of normally inaccessible locations such as tank seals and overhead piping from a distance, organic vapour analyzers to detect airborne hydrocarbons, and ultrasonic leak detection. Vapour analyzers and ultrasonic measurements can be used to quantify equipment leaks. A third-party database is used to track all survey results and implement corrective actions.

In 2019 our Canadian upstream and midstream facilities followed the Canadian Association of Petroleum Producers (CAPP) Best Management Practice for Fugitive Emissions, conducting surveys quarterly at all large gathering and processing facilities and at least once a year at others.

Our downstream facilities conduct ongoing LDAR monitoring. Within our Canadian downstream facilities we monitor almost 54,000 components and have more than 200,000 data points since the inception of the LDAR program in 2011. We monitor about 125,000 components at the Lima Refinery and approximately 70,000 at the Superior Refinery. Improvements in our LDAR program have resulted in a leak rate of 0.12% for Canadian downstream facilities, consistent with our Lima operations which are subject to more frequent testing requirements.

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