Canada Gazette, Part I, Volume 157, Number 50: Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)
December 16, 2023
Statutory authority
Canadian Environmental Protection Act, 1999
Sponsoring departments
Department of the Environment
Department of Health
REGULATORY IMPACT ANALYSIS STATEMENT
(This statement is not part of the Regulations.)
Executive summary
Issues: Greenhouse gases (GHGs), including methane, are a major contributor to climate change. The 2023 National Inventory Report notes that in 2021, the oil and gas sector was responsible for 28% of Canada’s GHG emissions, accounting for 189 megatonnes (Mt) of carbon dioxide equivalent (CO2e). This makes the sector the largest GHG emitter in Canada. This sector was also the largest source of methane emissions in 2021; about 20% of the sector GHG emissions are methane. Current measures that were designed to achieve a reduction of 40–45% below 2012 levels by 2025 will not be sufficient to meet Canada’s new methane commitment to achieve at least a 75% reduction in oil and gas sector methane emissions by 2030, relative to 2012 levels.
Description: The proposed Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [hereinafter referred to as the proposed Amendments] would build on the existing Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the Regulations] to reduce upstream oil and gas methane emissions through the introduction of emission standards and work practices to inspect sites and make repairs. The proposed Amendments would also introduce a new performance-based compliance option designed to focus on emissions outcomes, rather than prescribing a specific pathway to compliance. The proposal would build on the existing regulatory requirements, and would apply to upstream, midstream, and transmission facilities in Canada’s onshore oil and gas sector.
Rationale: In March 2022, the Government published Canada’s 2030 Emissions Reduction Plan (PDF) (ERP), providing a roadmap to reach its climate commitments, such as reducing national GHG emissions by 40 to 45% below 2005 levels by 2030 under the Paris Agreement, and achieving net-zero emissions by 2050. As noted in the ERP, Canada is part of the Global Methane Pledge, which aims to reduce global anthropogenic methane emissions across all sectors by at least 30% by 2030, relative to 2020. Furthermore, Canada was the first country to commit to further reduce methane emissions from oil and gas operations, by at least 75% by 2030, relative to 2012.
Cost-benefit statement: From 2027 to 2040, the proposed Amendments are estimated to have incremental costs of $15.4 billion, while the cumulative greenhouse gas emission reductions are estimated to be 217 Mt of CO2e, valued at $27.8 billion in terms of the estimated social benefit of avoided global damages from climate change. The monetized net benefits of the proposed Amendments are thus estimated to be $12.4 billion and are estimated to be achieved at an average cost of $71 per tonne of CO2e over the time frame of the analysis.
Issues
Greenhouse gases (GHGs) are a major contributor to climate change. The 2023 National Inventory Report (NIR) notes that in 2021, the oil and gas sector was responsible for 28% of Canada’s GHG emissions, accounting for 189 Mt CO2e. This makes the sector the largest GHG emitter in Canada. This sector was also the largest source of methane (CH4) emissions in 2021, accounting for about 40% of Canada’s methane emissions. Current measures that were designed to achieve a reduction of 40–45% below 2012 levels by 2025 will not be sufficient to meet Canada’s new methane commitment to achieve at least a 75% reduction in oil and gas sector methane emissions by 2030, relative to 2012 levels.
Background
Methane is the main component of natural gas, and it is included in the list of toxic substances (item No. 66) under Part 2 of Schedule 1 to CEPA. Oil and gas facilities are the largest industrial emitters of methane in Canada. Most of the methane emissions from this sector are from upstream activities: the production and field processing of light and heavy crude oils, bitumen, natural gas and natural gas liquids. The majority of methane emissions from the oil and gas sector are released as a result of emissions from either fugitive (unintentional release) or venting (intentional release) sources.
Methane is a short-lived climate pollutant that has a relatively short lifespan in the atmosphere compared to CO2 and other longer-lived GHGs. It has a global warming potential 84 times that of CO2 over a 20-year period and at least 25 times that of CO2 over a 100-year period. Due to its potency and short lifespan, reducing methane emissions has the potential to bring significant near-term climate benefits.
The Government of Canada is committed to taking action on climate change. In December 2015, Canada and its international partners reached the Paris Agreement, an accord intended to fight climate change and limit the global average temperature rise to well below two degrees Celsius (2 °C) and to pursue efforts to limit the temperature increase to 1.5 °C above pre-industrial levels. As part of its commitment under the Paris Agreement, Canada pledged to reduce national GHG emissions by 30% by 2030.
The Pan-Canadian Framework on Clean Growth and Climate Change, published in 2016, was developed with the provinces and territories and in consultation with Indigenous peoples — to meet Canada’s emissions reduction targets, grow the economy, and build resilience to a changing climate. This plan set the development of federal methane regulations in motion.
In April 2018, the Regulations were finalized under the Canadian Environmental Protection Act, 1999 (CEPA). The objective of the Regulations was to reduce methane emissions from the oil and gas sector by 40–45% below 2012 levels by 2025. Requirements pertaining to fugitive emissions, well completions and compressor maintenance came into force in January 2020, while remaining requirements pertaining to general venting, pneumatic devices and new compressors came into force in January 2023.
Provinces also advanced new regulatory requirements to manage methane emissions in the oil and gas sector. The provinces of Alberta and British Columbia amended existing regulations in 2018, while Saskatchewan published new regulations in 2019. The provinces further amended their regulations in early 2020 to better align them with the federal Regulations as applied in their respective jurisdictions. By the end of 2020, the Government recognized the provincial methane regulations as meeting equivalent emissions-reduction outcomes to the federal Regulations. Therefore, the Regulations do not apply in the jurisdictions of Alberta, British Columbia and Saskatchewan. The Saskatchewan equivalency agreement ends on December 31, 2024, the British Columbia equivalency agreement ends on March 25, 2025, and the Alberta equivalency agreement ends on October 26, 2025.
In 2021, at the 26th Conference of the Parties to the United Nations Framework Convention on Climate Change, Canada joined 110 countries in endorsing the Global Methane Pledge, which committed countries to take economy-wide action to reduce methane emissions by 30% by 2030. As part of its endorsement, Canada was the first country to target a reduction in methane emissions in the oil and gas sector of at least 75% below 2012 levels by 2030. This initiative builds on previous commitments made to achieve a reduction of 40–45% by 2025. In December of the same year, a federal review report titled Review of Canada’s methane regulations for upstream oil and gas sector was published, and it concluded that Canada is on track to meet its 2025 target for methane reductions from the oil and gas sector.
The 2030 Emissions Reduction Plan, developed under the Canadian Net-Zero Emissions Accountability Act, was published on March 29, 2022, describing actions that are already driving significant emission reductions as well as proposed measures that will deliver the economy-wide emission reductions needed to meet Canada’s international commitments on climate action. The plan noted that the Government continues to work to reduce oil and gas methane emissions by at least 75% below 2012 levels by 2030 while supporting clean technologies to further decarbonize the sector. Concurrently, the Government of Canada published a discussion paper to solicit views on how to strengthen the Regulations. The responses to that consultation process informed the path forward. In September of the same year, the Department released Faster and Further: Canada’s Methane Strategy, outlining the challenges and opportunities faced in this sector in implementing mitigating measures to reduce the largest sources of methane emissions, and reiterating the commitment to strengthen methane regulations to achieve at least a 75% reduction of oil and gas methane emissions below 2012 levels by 2030, and publish proposed amendments to the Regulations in 2023.
Objective
The proposed Amendments are intended to contribute to a reduction of methane emissions in the upstream oil and gas sector by at least 75% below 2012 levels by 2030. This action would reduce Canadian GHG emissions, contributing to Canada’s international commitments to combat climate change. In addition, as methane is a short-lived climate pollutant with significant near-term climate impacts, these reductions would contribute to slowing the rate of near-term global warming.
Description
The proposed Amendments would expand the current coverage and stringency levels of the Regulations.
The proposal builds on the existing regulatory requirements, introducing a focus on maximizing emission reductions, ensuring all practical actions are in place by 2030, and would apply to onshore upstream, midstream, and transmission oil and gas facilities. It would expand fugitive emissions management and other requirements to manage emissions from equipment. The proposed Amendments would also introduce a performance-based compliance option designed to focus on emissions outcomes, rather than prescribing a specific action for compliance.
Regulatory approach
Venting emissions
The proposed measures would prohibit the venting of natural gas to the environment, with exemptions. It would address operational venting activity, as well as temporary venting (which takes place during or in preparation for maintenance).
- The proposed Amendments would prohibit operators from intentionally venting hydrocarbon gas into the atmosphere. All pressurized equipment, e.g. pneumatic devices, product tanks, separators, dehydrators, and compressors would need to be physically connected to conservation or destruction equipment.
- Operators would be allowed to vent hydrocarbon gas during planned equipment maintenance or temporary depressurization when measures are taken to minimize venting of hydrocarbon gas to the atmosphere.
Exceptions: Safety, poor gas quality, prevention of prolonged interruption of gas supply to the public.
As of 2027, facilities increasing gas production would be required to design and operate systems to eliminate venting. All facilities in the sector would be subject to the new requirements in 2030.
Emissions associated with combustion of hydrocarbon gas
The proposed measures would require operators to manage emissions during the combustion of hydrocarbon gas.
- Hydrocarbon gas destruction equipment
- Combustion systems utilized to comply with the proposed Amendments would have to achieve a minimum carbon conversion efficiency of 98%. The system would be required to operate with a pilot flame, automatic ignition device, and flame failure detection system.
- Exceptions: Catalytic oxidation systems (efficiency of at least 85%) could be utilized for small gas volumes, not to exceed 60 m3 per day.
- Flaring
- Flaring of hydrocarbon gases, other than to avoid serious risk to human health or safety arising from an emergency, would have to be supported by an engineering study that concludes that the use of the hydrocarbon gas to produce useful heat or energy is not feasible in the circumstances.
- As of 2027, facilities increasing gas production would be required to design and operate systems to limit emissions during combustion and to eliminate routine flaring where feasible. All facilities in the sector would be subject to the new requirements in 2030.
Fugitive emissions
The proposed measures would target emissions that are unintentional, i.e. fugitive emissions.
The proposed Amendments would introduce a risk-based approach to the application of the fugitive emissions management program. Facilities that are more likely to emit methane (Type 1 facilities) would need to maintain a quarterly inspection schedule, whereas facilities less likely to emit methane (Type 2 facilities) would need to maintain an annual inspection schedule. All facilities would also need to undertake screening inspections, and at least one annual inspection by an auditor. All comprehensive inspections would need to be conducted using instruments with a standard minimum detection limit of 500 ppm. Upon detection of emissions, whether as a result of an inspection or otherwise, repairs would need to be made within a repair timeline that is dependent on the emission rate (i.e. higher emissions would need to be addressed quickly — within 24 hours or 7 days — whereas lower emissions, less than 1 kg/hr, can be scheduled for repair over several months).
Requirements for instruments that may be used in comprehensive inspections would incorporate by reference analytical methods developed by the United States Environmental Protection Agency (EPA) and set out in the United States Code of Federal Regulations, in order to provide a consistent North American approach when using these instruments. For example, EPA Method 21 is a specific analytical method used to detect leaks from equipment in industrial facilities. It has been a key tool in EPA regulations aimed at reducing air pollution and protecting public health since the 1970s.
The related proposed measures would come into force on January 1, 2027, for all facilities, as these changes can be implemented without any modifications to facility infrastructure.
Performance-based approach
This proposed measure would set out an alternative approach for compliance with the Regulations that relies on the installation of continuous monitoring systems for the facility’s potential methane emission sources. Upon detection of methane emissions, a mitigation response must be initiated according to timelines dictated by the emission rate. When detected emissions exceed a management trigger of 10 kg/hr, an event analysis would also need to be conducted as part of mitigation actions. This compliance pathway is an alternative to the requirements described for venting and fugitive emissions.
This related proposed Amendments would come into force on January 1, 2027, and be an available compliance option for all facilities.
Removing application to offshore facilities
The proposed Amendments would remove specific compliance requirements for the offshore sector in the existing Regulations. This change would avoid duplication with regulations proposed by Natural Resources Canada for the Frontier and Offshore Regulatory Renewal Initiative, which would include specific measures to deal with methane emissions in the offshore sector.
Administrative amendments to the Regulations
The proposed Amendments would make several housekeeping changes to the Regulations. Definitions no longer relevant to the amended regulatory text would be repealed: completion, design bleed rate, flowback, gas-to-oil ratio, hydraulic fracturing, pneumatic controller and pneumatic pump. The reference to the list of toxic substances in Schedule 1 to the Canadian Environmental Protection Act, 1999 has been updated. In addition, the concept of health and safety as it applies in various parts would be made consistent across all parts of the Regulations.
Regulatory development
Consultation
The Department of the Environment (the Department) has consulted with provincial and territorial governments, Indigenous partners, representatives from industry and environmental non-governmental organizations (ENGOs), academics and experts, other government departments, international partners, and the public. Since March 2022, the Department has received 140 submissions in response to two publications, held over 80 meetings, and hosted three public webinars.
The publication of a discussion paper in March 2022 initiated formal public consultations on how to achieve Canada’s strengthened oil and gas methane emissions target of at least a 75% reduction by 2030 relative to 2012 levels. The discussion paper presented, at a high level, potential additional actions that could be implemented by expanding the scope and stringency of the Regulations through regulatory amendments. Building on the initial feedback received, a Proposed Regulatory Framework (the Framework) was published in November 2022. The Framework presented and sought input on a more detailed source-by-source approach to managing methane releases by expanding the scope and stringency of the Regulations. Under the Framework, requirements would apply to a wider set of sources, most exclusions would be eliminated, and many individual sources of methane emissions would be driven toward zero emissions. The Department continued to indicate an openness to including performance-based elements in the regulatory amendments.
Industry comments
The Department engaged in many discussions with industry associations such as the Canadian Association of Petroleum Producers, Explorers and Producers Association of Canada, the Canadian Gas Association, and with individual oil and gas companies. This stakeholder group expressed general support for the intent to work toward the Government’s target of at least a 75% reduction in methane emissions by 2030, but expressed concern about potential cost, lack of flexibility in the Framework, and strict application of specific standards without regard to safe operation of facilities.
Companies were concerned about costs and technical feasibility challenges, often due to regional, subsector and facility characteristics. Some stakeholders sought certain flexibilities, for example allowing existing facilities more time to come into full compliance, to address the uneven distribution of costs and technical feasibility challenges across the oil and gas sector. The Department also received significant support regarding the implementation of a performance-based approach, which is generally understood to be the assignment of an emissions target without specific direction as to how it would be achieved.
Several companies acknowledged that their corporate sustainability goals align with significant methane emission reductions in their internal climate policies, and two major companies indicated their aim for zero methane emissions by 2030.
The Department acknowledges that there is heterogeneity across the oil and gas sector. To account for this, the proposed Amendments would introduce staggered dates for the coming into force of regulatory measures, starting in 2027, with full sector compliance by 2030. This implementation approach spreads compliance costs across several years, and allows some facilities to delay investments for compliance purposes, or, in some cases, would allow late life-cycle production sites to avoid new capital investments.
A performance-based approach is also being proposed as an option for regulated sites. This approach would be enabled by an opt-in program that allows for the use of a continuous monitoring system to monitor for emissions, track problems and structure emissions management. This approach would allow emission reduction targets to be met while allowing individual facilities the flexibility to minimize costs based on their unique needs.
Some industry comments suggested adjusting compliance timelines for leak detection and repair for small facilities, and delaying requirements for capturing gas from pipeline blowdowns and/or for deploying certain clean technologies.
Balancing the need to maximize emissions reductions with concerns about feasibility for small or remote facilities, the proposed Amendments follow a risk-based approach to fugitive inspections that concentrates on facilities with equipment that represents the greatest potential for emissions. This approach focuses more inspection activity where it would be most effective at reducing emissions.
Some industry representatives noted that Canada’s offshore facilities face different compliance costs and technical challenges than onshore facilities.
The Department also heard that residential distribution networks present a challenge for regulation, largely due to the expansive nature of distribution infrastructure and high marginal cost of abatement. Moreover, the Department heard that ensuring the reliability of distribution networks is critical. Measures to reduce methane emissions from the distribution of natural gas in Canada’s municipal areas will be considered by the Department outside of the proposed Amendments.
Industry also raised concerns about alignment with other instruments, including federal and provincial requirements. Industry noted that reducing methane emissions from stationary engines could have implications for investment decisions to comply with the federal Multi-Sector Air Pollutant Regulations (MSAPR).
The Department is collaborating internally and with other government departments to ensure various federal policies affecting the oil and gas sector are complementary. The Department also continues to share information with the U.S. EPA and monitor U.S. progress in developing their own strengthened regulations. With regard to regulating methane emissions from stationary engines, the Department intends to explore addressing stationary engines, regarding air pollutant and GHG emission impacts, through amendments to MSAPR at a later date.
Industry also emphasized the importance of ensuring flexibilities for safe operations are incorporated into any regulatory requirements. The Department heard that flaring events and some emergency venting may be required in certain cases for safe facility operation.
To address concerns about safety, the proposed Amendments include explicit exceptions when safe operations would be compromised, especially in response to unplanned events.
Industry also requested financial assistance for clean technology implementation and emissions monitoring and reporting. The Government of Canada supported methane emission reduction through the Emissions Reduction Fund, as part of Canada’s COVID-19 economic response plan. This proposal does not anticipate any specific new funding program.
Environmental non-governmental organizations
A number of bilateral and joint discussions were held with environmental non-governmental organizations (ENGOs), including key organizations engaged on methane policy, such as the Pembina Institute, Environmental Defence Fund, and the David Suzuki Foundation. ENGOs expressed support for the stringent measures described in the Framework. To ensure the integrity of the performance-based approach, ENGOs noted that high quality, verifiable methane emissions performance data would be critical.
The Department is maintaining the overall direction of a source-by-source approach that will drive as many emissions sources as possible toward zero. The proposed performance-based option is also included as an alternative pathway for compliance. This approach would be enabled by an opt-in facility emissions monitoring program using a continuous emission detection system that would structure emissions management.
In parallel to advancing strengthened regulations, the Department will continue to monitor and support measurement work to better understand methane emissions. The Department will also continue to support Natural Resources Canada to develop a Methane Centre of Excellence, which will further ensure that emissions inventories are informed by the most recent measurement research.
Balancing the need to maximize emissions reductions with concerns about feasibility for certain facilities, the proposed Amendments take a risk-based approach to emission inspections that concentrates on facilities with equipment that represents the greatest potential for emissions. The proposed Amendments also include a new annual inspection, requiring third-party inspections for fugitive emissions.
Provinces and territories
The Department focused engagement activities with the major oil and gas-producing provinces of British Columbia, Alberta, and Saskatchewan. Each of these provinces regulates oil and gas methane emissions through provincial regulations. The federal government has recognized these provincial regulations as equivalent under CEPA and has stood down the application of federal regulations for periods of five years in these provinces.
Provinces noted that their plans to reduce methane emissions exist concurrently with federal targets, and that alignment of approaches would be important going forward. Provinces highlighted the unique regional characteristics of their oil and gas sectors, with some expressing interest in exploring the renewal of equivalency agreements.
Some provinces voiced specific concerns and questions regarding federal modelling. In response, the Department held a public technical briefing in June 2023 to share information about the Department’s modelling approach and data sources and has also welcomed discussions on this topic in bilateral meetings.
Provinces also expressed interest in performance-based compliance options. They indicated that a balance between prescriptive regulations and performance-based approaches may be required.
The proposed Amendments incorporate the source-by-source approach to reducing methane emissions outlined in the Framework. The proposed Amendments also introduce an annual independent inspection requirement and include a performance-based option as an alternative pathway for compliance.
Provinces also stressed the importance of reliability for distribution networks to ensure that natural gas remains available for heating during the winter.
The Department has considered safety concerns and has included new flexibilities to ensure safety and system integrity is considered in the design of the proposed Amendments, especially in response to unplanned events.
The Department is not covering natural gas distribution infrastructure in these regulatory amendments, but will explore a tailored approach for the distribution subsector outside of the current proposal.
Indigenous organizations
Indigenous organizations were broadly supportive of addressing methane through technical regulations, with some pointing out potential co-benefits in reducing air pollution.
There were, however, questions about how the approach would address certain emissions sources, including non-point-source emissions from broader areas such as exposed mine faces and ponds.
The Department notes that while the current approach focuses on upstream and midstream facilities, area sources have been excluded due to limited technological opportunities for mitigation. However, fugitive methane emissions from area sources are now captured by recent amendments to the Output-Based Pricing System Regulations (OBPS Regulations).
Some comments called for more transparency with respect to local emissions data and indicated an interest in collaboration, noting that local First Nations could play a role in methane leak detection.
The Department continues to support and engage in emission monitoring, measurement, reporting, and verification work undertaken by federal science organizations, academic research groups and provincial regulators, to better understand methane emissions, and will continue to engage Indigenous organizations as this work advances.
Modern treaty obligations and Indigenous engagement and consultation
As required by the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, an assessment of modern treaty implications was conducted on the proposal. The assessment examined the geographic scope and subject matter of the proposed Amendments in relation to modern treaties in effect. The assessment did not identify any modern treaty obligations.
Instrument choice
To meet Canada’s 2030 methane emissions reduction target, a range of policy options were identified. The process for evaluating the instrument choice focused on options that could effectively abate methane emissions from the upstream oil and gas sector. Consideration was given to three options: increase the scope of the Output-Based Priced System (OBPS), include methane emissions reduction into the proposed oil and gas emissions cap (the Cap) or amend the Regulations (the proposed Amendments).
Canada’s approach to carbon pricing gives provinces and territories the flexibility to implement carbon pricing systems that meet minimum national stringency standards (the benchmark) or choose the federal carbon pricing system. The federal carbon pricing system for industry, the OBPS, currently applies in Manitoba, Prince Edward Island, Yukon, and Nunavut. Facilities covered under the OBPS are in sectors determined to be at risk of carbon leakage and competitiveness impacts from carbon pricing. They are required to provide compensation by paying the carbon price or remitting eligible compliance units for every tonne of emissions above an emissions limit. Facilities that emit below their emissions limit are issued surplus credits that they can sell or bank for future use. Their emission limits are calculated as a function of production volumes and performance standards set on the basis of emissions per unit of output (output-based standards). This creates a price incentive for covered facilities to reduce their GHG emissions. The OBPS was not considered an effective tool to meet Canada’s 2030 methane emissions reduction target because it does not apply nationally and as an economy-wide pricing system, it targets the lowest-cost reductions across the economy and is not designed to assure a specific level of emissions reductions from any one sector or activity. In addition, due to the heterogeneity of the facilities in the upstream oil and gas industry, it was not considered feasible to establish an output-based standard for each type of facility covered by the proposed Amendments.
In July 2022, the Government released a discussion paper outlining two potential options to implement the commitment to cap and cut oil and gas sector emissions (the Cap). Both options outlined in the paper take a flexible market approach to implementing the Cap. The paper proposed that all GHGs, including methane, be covered by the Cap. Details of the Cap are under development; however, although a carbon markets approach would provide an incentive to reduce methane emissions, it would provide facilities with flexibility as to which emission reductions to pursue and, therefore, this approach would not assure that Canada’s 2030 methane emissions reduction target would be achieved.
Given the flexible nature of carbon pricing in the options proposed for the Cap, specific methane emission reductions are not guaranteed. A regulatory approach is complementary to the price on carbon pollution in that it forces specific activity relating to this particular GHG source, while it would contribute to meeting the emissions reduction objectives of the Cap. Emissions pricing policies create a broad incentive across the economy to use less energy and improve efficiency, while the proposed Amendments target methane emissions. For these reasons, the proposed Amendments were selected as the appropriate instrument to meet Canada’s 2030 methane emissions reduction target.
Only specific regulations implementing work practices and equipment or site emission standards can ensure that Canada meets its methane commitments. The proposed Amendments would allow Canada to build on its existing regulatory infrastructure to advance an efficient regulatory instrument, with policy elements aligned with those of other jurisdictions, such as the United States.
Regulatory analysis
From 2027 to 2040, the proposed Amendments are estimated to have incremental costs of $15.4 billion, while the cumulative GHG reductions are estimated to be 217 Mt of CO2e, valued at $27.8 billion in terms of the estimated social benefits of avoided global damages. The monetized net benefits of the proposed Amendments are thus estimated to be $12.4 billion and are estimated to be achieved at an average cost of $71 per tonne over the time frame of the analysis.
Analytical framework
To estimate the impact of the proposed Amendments, an analysis was conducted that quantifies three categories of incremental benefits: reductions in GHG emissions (CH4 and CO2), reductions in volatile organic compound (VOC) emissions, and energy savings in the form of conserved natural gas. The analysis then monetizes two main categories of incremental impacts: the costs of compliance (including administration) and the benefits of GHG emission reductions. Impacts attributable to the Regulations are analyzed over 14 years (2027 to 2040), which covers the period after the proposed Amendments come into force (2027), then apply fully across the sector (2030) and then extend to 2040 to illustrate the costs and benefits that would accrue over time as a result of the proposed Amendments.
All dollar figures are presented in 2022 Canadian prices (Can$). Prior year prices were inflated using a gross domestic product (GDP) deflator.footnote 1 Where sources used American prices (US$), they were converted to Canadian dollars using 2022 purchasing power parity.footnote 2 Present value terms have been discounted at 2% annually, which is the near-term Ramsey discount rate now utilized by the Government of Canada when monetizing GHG reductions (more information on this approach is presented in the benefits subsection). The same discount rate has been applied across both costs and benefits to provide analytical consistency, and 2024 was selected as the “present” year for discounting, as it is assumed to be when the proposed Amendments would be registered as final regulations.
The incremental impacts are derived by comparing a baseline scenario of existing measures to a regulatory scenario that reflects key aspects of the proposed Amendments. The baseline scenario represents the continuation of current federal requirements to limit methane emissions from oil and gas sector operations. While provincial regulators also impose requirements to limit methane emissions in each of Canada’s major oil-producing provinces, and currently have equivalency agreements with the federal government, these agreements are set to expire before the proposed Amendments come into force. Thus, only the existing federal methane requirements are represented in the baseline scenario.
Analysis of regulatory coverage and compliance
To estimate the incremental benefits and costs of the proposed Amendments, the analysis considered who would be affected (regulatory coverage) and how they would most likely respond (their compliance strategies), as described below.
Regulatory coverage
The proposed Amendments would target emissions from the upstream oil and gas sector by implementing facility and equipment level requirements. Facility level requirements would include a prohibition on venting hydrocarbon gas to the atmosphere, with exceptions, replacing previous emission limits on facility production venting. Fugitive emission requirements would be strengthened, applying at more facilities, with more frequent emission surveys, including an independent measurement each year.
Currently, some facilities are expected to already meet the compliance requirements of the proposed Amendments due to current provincial measures or voluntary action. Facilities that would need to take incremental action to comply with the proposed Amendments are considered affected facilities. The cost-benefit analysis focuses on affected facilities when estimating incremental impacts of the proposed Amendments. To estimate affected facilities in the oil and gas sector, Petrinex (Petroleum Information Network) upstream oil and gas facility counts for Alberta and Saskatchewan were used and forecasted using the production forecasts of crude oil and natural gas from the Canada Energy Regulator (CER).
Regulatory compliance
The proposed Amendments set requirements to manage methane emission sources, but do not prescribe unique actions or technologies to comply with the requirements. However, for modelling purposes, assumptions have been made regarding specific compliance actions to estimate costs and benefits. The compliance actions assumed to be adopted by the upstream oil and gas industry to meet the new requirements for each source, as related to venting and fugitive emissions, are described below. The Amendments introduce a compliance option to utilize a continuous monitoring system to track emissions and structure emissions management. To meet the requirements of the continuous monitoring system provisions, all potential methane sources would need to be managed to source-based standards. The development of this compliance option is based on technology. To simplify the cost-benefit analysis, affected facilities are assumed to take the same compliance actions under both compliance options.
Costs of compliance
Facilities affected by the proposed Amendments are expected to incur incremental capital and operating costs to comply with the new requirements. Some administrative effort by the industry would also be required to demonstrate compliance with the proposed Amendments.
The proposed Amendments introduce various compliance flexibilities and a phased approach to the application of the newer, more stringent requirements to address potential financial and competitiveness issues. The proposed Amendments set out different requirements based on the size and type of equipment at sites, allow options for site monitoring requirements, and phase in the application of requirements for certain facilities.
The proposed Amendments introduce additional compliance requirements starting in 2027. The new requirements for fugitive emission management would come into force in 2027 for all facilities. For the remaining requirements, the compliance action is assumed to start in 2027 for facilities that begin operation in or after 2027, or in a later year if the combined volume of hydrocarbon gas produced or received increases. These are referred to as “new” facilities for the purpose of the following analysis. These facilities are therefore assumed to require capital costs in that same year. For the purposes of this analysis, facilities that were producing or processing gas before 2027 with continued production or processing volume declines are referred to as “existing” facilities. These facilities would be required to start complying in 2030 and are assumed to incur capital costs in that same year.
Operating costs are assumed to begin in the year capital cost are incurred and continue annually until the end of the analytical period. To estimate capital and operating costs, the analysis uses information from a variety of sources, including reports by Process Ecology (2023),footnote 3 Delphi (2017),footnote 4 ICF (2015),footnote 5 Natural Gas Star(2011),footnote 6 and Natural Gas Star (2006).footnote 7
Venting
At oil production facilities, natural gas is sometimes produced as a by-product that is released (vented) to the atmosphere as a waste rather than captured and sold as a product, especially for sites where gas gathering infrastructure is not accessible. Such gas, which is mostly composed of methane, can be captured and routed to a combustion device to lower emissions (CO2 has a lower contribution to global warming than methane), or ideally used as a fuel or sold by building new infrastructure.
Under the proposed Amendments, facilities would be expected to either destroy or conserve gas. The Department estimates that roughly 5 700 facilities would conserve gas, while an estimated 50 700 facilities would opt to destroy it. Facilities that conserve gas are assumed to do so by installing a vapour recovery unit (VRU), and roughly 600 of these facilities are assumed to also complete a pipeline tie-in. Facilities that opt to destroy the gas are assumed to do so through optimizing their flares, installing a combustor, or installing an oxidizer. The technology utilized for destruction is dependent on the expected gas volume, and it is estimated that 29 800 facilities would optimize their flares, 3 800 facilities would install a combustor and 17 100 facilities would install an oxidizer.
Capital costs for facilities conserving gas are estimated to average $84,900 per facility to purchase and install a VRU and roughly $1.1 million to complete a pipeline tie-in. For facilities opting to destroy gas, capital costs are estimated to be $6,600 to purchase and install a flare ignition system, $52,000 to purchase and install a combustor and $36,500 to purchase and install an oxidizer. Of the total number of affected facilities from 2027 to 2040, approximately 48% (existing facilities) will bear a capital cost in 2030 and an associated ongoing operating cost. The remaining 52% of affected facilities (new facilities) will have a capital expense each year (2027 to 2040), as well as an associated ongoing operating cost. This will occur at a rate of approximately 4% of total affected facilities per year.
Annual operating costs are estimated to range from $3,900 per facility per year for the VRU, to $38,870 per pipeline tie-in, as shown in Table 1 below.
It is estimated that the venting and flaring requirements would result in a total present value cost to industry of $3.3 billion between 2027 and 2040.
| Compliance action | Capital costs (dollars) |
Annual operating costs (dollars) |
Number of affected facilities table b1 note a | Total present value costs 2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| VRU | 84,900 | 3,900 | 5 700 | 574 |
| Pipeline tie-in | 1,137,700 | 38,870 | 600 | 743 |
| Flare ignition system | 6,600 | n/a | 29 800 | 169 |
| Combustors | 52,000 | 15,140 | 3 800 | 580 |
| Oxidizers | 36,500 | 5,420 | 17 100 | 1,204 |
| Total | n/a | n/a | 56 400 table b1 note b | 3,270 |
Table b1 note(s)
|
||||
Figures may not add up to totals due to rounding.
Note: Costs derived from Natural Gas Star (2006),footnote 7 Delphi (2017),footnote 4 and Process Ecology report (2023).
Blowdowns (venting)
During maintenance activities, or for certain operational reasons, natural gas may be released to the atmosphere in a short-duration event to allow safe access to equipment. This is referred to as a blowdown. This gas could, instead, be routed to existing on-site gas capture systems, or combusted with portable equipment.
The effect of the proposed Amendments would be that regulated facilities would redesign their blowdown systems, capture and route gas to portable combustors, and install equipment for blowdown gas capture and conservation. Facilities that need to redesign their blowdown systems and alter emergency shutdown practices are expected to bear a cost of $8,800 per compressor. It is also estimated that about 1 700 facilities would be required to capture blowdown gas in transmission stations, at a cost of approximately $85,000 per device. These systems are assumed not to require operating costs.
The Department estimates that, to comply with the new requirements, 4 300 compressors would have to capture blowdown gas and route to a new combustor, which is estimated to cost about $72,300, with an additional $600 in annual operating costs, per device. It is estimated that existing facilities and compressors, representing approximately 55% of the total affected count, would have a capital cost in 2030 with an ongoing operating expense. The remaining 45% representing new facilities and compressors at about 3% per year would have capital costs from 2027 to 2040, and have an associated ongoing operating expense.
It is estimated that the new requirements that would affect blowdowns practices would result in a total present cost to industry of $437 million between 2027 and 2040.
| Compliance action | Capital costs (dollars) |
Annual operating costs (dollars) |
Number of affected devices table b2 note a | Total present value costs
2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| Redesign blowdown systems | 8,800 | n/a | 4 300 | 32 |
| Capture and route gas to portable combustor | 72,300 | 600 | 4 300 | 277 |
| Install blowdown gas capture and conservation equipment | 85,000 | n/a | 1 700 | 128 |
| Total | n/a | n/a | 10 300 | 437 |
Table b2 note(s)
|
||||
Note: Costs derived from the Process Ecology report (2023).
Figures may not add up to totals due to rounding.
Well liquids unloading (venting)
Gas production can become constrained at wells as liquids build up in the underground production piping. To restore production rates, wells can be “unloaded” by allowing pressure release at ground level — a special type of blowdown event referred to as well liquids unloading. Gas that would be released during this event could be captured and used or routed to a combustion device.
The Department estimates that there are approximately 25 100 wells in Canada that would perform well liquids unloading at varying frequencies and venting volumes between 2027 and 2040. It is expected that, of the wells performing liquids unloading without a plunger lift, 11 500 would need to install a plunger lift to reduce emissions at a cost of $38,600 per well. The remaining wells, with greater vented volume or where a plunger lift is already installed, would be expected to destroy the gas by installing a destruction device that costs $57,000 per well. There would be no associated operating expense with either technology. Of the total number of affected wells from 2027 to 2040, approximately 50% (existing wells) would bear a capital cost in 2030 and an associated ongoing operating cost. The remaining 50% of affected wells (new), at a rate of about 4% per year, will have a capital expense each year from 2027 to 2040 and an associated ongoing operating expense.
The avoidance of emissions during well liquids unloading is estimated to result in present value costs to industry of $1 billion between 2027 and 2040.
| Compliance action | Capital costs (dollars) |
Annual operating costs (dollars) |
Number of affected wells table b3 note a | Total present value costs 2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| Install plunger lift systems in gas wells | 38,600 | n/a | 11 500 | 378 |
| Reduce liquids unloading venting with flaring, incineration, or destruction device | 57,000 | n/a | 13 600 | 660 |
| Total | n/a | n/a | 25 100 | 1,038 |
Table b3 note(s)
|
||||
Note: Costs derived from the Process Ecology report (2023) and Natural Gas Star (2011).footnote 8
Figures may not add up to total due to rounding.
Pneumatic instruments and pumps (venting)
Industry can use natural gas pressure to drive pumps and instruments needed at oil and gas sites. This gas is often released to the atmosphere through these devices. Such emissions can be eliminated by replacing this equipment with electric systems, or by using air or an inert gas to drive them.
The proposed Amendments would require the use of non-emitting pumps and instruments in some facilities, beginning in 2027, and with application to all facilities by 2030. A total of 261 300 pneumatic devices including 55 100 pumps and 206 200 instruments are considered within the time frame of the analysis, from 2027 to 2040. It is estimated that existing facilities, representing approximately 53% of the total affected devices, would bear a capital cost in 2030 with an associated ongoing operating cost. The remaining 47%, representing new facilities, would bear a capital cost from 2027 to 2040 with an associated ongoing operating cost. It is assumed that the average capital cost would be $9,500 for pumps and $10,100 for instrument replacements. The annual operating costs are estimated to be roughly $1,000 for each new pump and instrument replacement. The analysis for total present value costs includes all capital and operating expenditures from 2027 to 2040 and also considers the decrease in operating costs as facilities that invested capital costs in 2030 reach end of life.
It is estimated that the transition to non-emitting pneumatic instruments and pumps would result in a total present value cost to industry of $4.1 billion between 2027 and 2040.
| Compliance action | Capital costs (dollars) |
Annual operating costs (dollars) |
Number of affected devices table 4 note a | Total present value costs 2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| Replace pneumatic pumps with electric pumps (solar and onsite power) | 9,500 | 1,000 | 55 100 | 835 |
| Replace pneumatic instruments with non-emitting solutions such as electrified or air-driven instruments | 10,100 | 1,000 | 206 200 | 3,251 |
| Total | n/a | n/a | 261 300 | 4,086 |
Table 4 note(s)
|
||||
Note: Costs derived from the Process Ecology report (2023).
Figures may not add up to total due to rounding.
Compressor seals and vents (venting)
Compressors usually release small amounts of natural gas through mechanical systems inherent to the design of this high-pressure equipment. Design or maintenance problems can lead to significant emissions. The piping in these systems can be modified to route this gas to fuel, sales or combustion equipment.
In order to comply with the proposed Amendments, regulated facilities with centrifugal compressors would be expected to either augment their compressors with a recovery unit that conserves vented gas through a wet seal degassing system or to replace their wet seals with dry seals. Approximately 375 wet seals on centrifugal compressors are estimated to be affected within the time frame of the analysis (2027 to 2040). It is estimated that 80% of the compressors would use degassing recovery systems, and the other 20% would be replaced with dry seals at an approximate cost of $85,000, and $100,000 per device, respectively. In addition, it is estimated that compressors would entail annual operating costs of $3,400 per degassing recovery system and $500 per replacement of wet seals with dry seals.
Facilities with dry seal centrifugal or reciprocating compressors, estimated to be a total of 7 200 compressors, would be expected to comply with the proposed Amendments by capturing emissions from vents and connecting to a combustor. An estimated 130 dry seal centrifugal compressors and 7 050 reciprocating compressors, totalling approximately 7 200 compressors, are expected to represent capital costs of approximately $178,000 per compressor, with operating costs of about $3,000 annually. It is estimated that existing facilities, representing approximately 67% of the total affected compressors, would carry a capital cost in 2030 with an associated ongoing operating cost. New facilities, representing the remaining 33% of affected compressors, at about 2% per year, would carry a capital cost from 2027 to 2040 with an associated ongoing operating cost.
It is estimated that eliminating venting from compressor systems would result in total present value costs to industry of $1.3 billion between 2027 and 2040.
| Compliance action | Capital costs (dollars) | Annual operating costs (dollars) | Number of affected compressors | Total present value costs 2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| Install wet seal degassing system | 85,000 | 3,400 | 300 | 30 |
| Replace wet seals with dry seals | 100,000 | 500 | 75 | 7 |
| Install vent capture devices and reroute to combustion equipment | 178,000 | 3,000 | 7 200 | 1,299 |
| Total | n/a | n/a | 7 575 | 1,336 |
Note: Costs derived from the Process Ecology report (2023).
Figures may not add up to total due to rounding.
Glycol dehydration systems (venting)
Natural gas is typically produced with some water vapour that can separate in piping, freeze and cause equipment failures. Industry can use chemical (glycol) contactors to remove water from the gas. However, some natural gas is carried in the liquid stream and is released into the atmosphere. This gas can be captured and routed to use as fuel or destroyed in combustion equipment.
The Department estimates that there are about 2 800 affected glycol dehydrators within the time frame of the analysis from 2027 to 2040. Facilities are expected to use a combination of technologies to ensure these devices comply with the proposed Amendments. It is assumed that glycol dehydrator systems that have emissions lower than current provincial requirements would install flash tank separators, optimize circulation rates, replace glycol pneumatic pumps with electric pumps and eliminate stripping gas. The glycol dehydration systems that meet current provincial requirements would reroute dehydrator vent gas to a vapour recovery unit. It is expected that the implementation of these combined technologies would present an average capital cost of $31,200 for existing facilities and $10,400 for new facilities, and an average annual operating cost of $2,250 for existing facilities and $900 for new facilities. It is estimated that existing facilities, representing approximately 72% of the total affected glycol dehydrators, would carry a capital cost in 2030 with an associated ongoing operating cost. The remaining 28%, representing new facilities, would carry a capital cost from 2027 to 2040 with an associated ongoing operating cost. The analysis for total present value costs includes all capital and operating expenditures from 2027 to 2040. It also considers the decrease in operating costs as facilities that invested capital costs in 2030 reach end of life.
It is estimated that addressing venting emissions from glycol dehydrator systems would result in present value costs to industry of about $105 million between 2027 and 2040.
| Compliance action | Capital costs (dollars) |
Annual operating costs (dollars) | Number of affected glycol dehydrators table b6 note a | Total present value costs — 2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| Combined solutions for existing facilities | 31,200 | 2,250 | 2 000 | 94 |
| Combined solutions for new facilities | 10,400 | 900 | 800 | 12 |
| Total | n/a | n/a | 2 800 | 105 |
Table b6 note(s)
|
||||
Note: Costs derived from the Process Ecology report (2023).
Figures may not add up to total due to rounding.
Fugitive Emission Detection and Repair Program
Equipment failures can result in leaks or extraordinary venting emissions throughout site piping and production systems. These failures can be identified through routine operations or through specific inspection efforts, and repairs made to stop that condition.
The proposed Amendments would require regulated facilities to undertake structured site inspections, as well as any necessary corrective actions that are identified, which would result in compliance costs. The incremental compliance costs compared to existing practices are calculated by determining the cost to conduct a site inspection survey by facility type and multiplying that by the incremental frequency of inspections under the proposed Amendments. For Type 1 facilities, four comprehensive inspections, one annual inspection, and multiple screening inspections per year are required. This is modelled as five Optical Gas Imaging (OGI)/Method 21 surveys per year. For Type 2 facilities, one comprehensive inspection, one annual inspection and multiple screening inspections per year are required. This is modelled as two (OGI)/Method 21 surveys per year. These requirements, on average, are incrementally two more surveys per year for all facility types, except non-producing wells. Non-producing wells are modelled as one survey per year.
The primary driver for the cost per survey is the time to conduct the survey. It is assumed that increased inspections would not change the number of leaks requiring remedial action, but rather allow them to be discovered sooner, reducing the amount of methane gas released. Therefore, no new equipment or tools would be required within the sector to comply with the proposed Amendments. The Department estimates that a total of approximately 607 700 sites would be affected by the proposed Fugitive Emission Detection and Repair Program, at a cost of $175 to $7,040 per survey, as shown in Table 7 below. The new Fugitive Emission Detection and Repair Program is estimated to result in present value costs to industry of $4 billion between 2027 and 2040.
| Facility type | Cost per survey (dollars) |
Number of affected facilities and wells table b7 note a | Total present value costs
2027 to 2040 (millions of dollars) |
|---|---|---|---|
| Non-producing wells | 465 | 372 900 | 2,022 |
| Wells | 175 | 189 700 | 779 |
| Gas processing facilities | 7,040 | 500 | 83 |
| Compressor stations (small) | 4,700 | 4 800 | 527 |
| Batteries | 350 | 38 300 | 323 |
| Compressor stations (large) | 7,040 | 1 500 | 249 |
| Total | n/a | 607 700 | 3,984 |
Table b7 note(s)
|
|||
Note: Costs are derived from ICF (2015).footnote 5
Analysis estimates one survey per year for non-producing wells and two per year for all other sources.
Figures may not add up to total due to rounding.
Surface-casing vent flow (venting)
The Department has estimated that there are approximately 6 150 wells in Canada with surface casing venting with varying flow rates. The analysis assumes that vented gas would be sent to a combustor or incinerator from wells with low flow rates (5 to 100 m3/day), while the wells with higher flow rates (exceeding 100 m3/day) would abate emissions by installing compressors to capture the gas. It is estimated that about 5 150 wells would combust the gas, while the balance of about 1 000 wells would capture the gas. Compliance costs associated with implementing the technologies include capital costs of $110,000 and $89,500 per well, respectively, and associated operating expenses of $2,800 and $8,500 per year per well. Of the total number of affected wells from 2027 to 2040, approximately 65% would bear a capital cost in 2027 and an associated ongoing operating cost. The remaining affected wells, at a rate of 3% per year, will have a capital expense each year thereafter and an associated ongoing operating expense. The surface-casing vent flow (SCVF) requirement is estimated to result in present value costs to industry of $809 million between 2027 and 2040.
| Compliance action | Capital costs (dollars) |
Annual operating costs (dollars) |
Number of affected wells table b8 note a | Total present value costs 2027 to 2040 (millions of dollars) |
|---|---|---|---|---|
| Install casing gas recovery and combustion equipment | 110,000 | 2,800 | 5 150 | 647 |
| Install casing gas recovery and compression equipment for gas conservation | 89,500 | 8,500 | 1 000 | 162 |
| Total | n/a | n/a | 6 150 | 809 |
Table b8 note(s)
|
||||
Note: Costs derived from the Process Ecology report (2023).
Figures may not add up to total due to rounding.
Over the time frame of analysis, the total costs of compliance are $15.1 billion, as shown in Table 9 below.
| Source | Undiscounted 2027 | Undiscounted 2030 | Undiscounted 2040 | Discounted Total 2027–2040 | Annualized table b9 note 12 |
|---|---|---|---|---|---|
| Venting and flaring table b9 note a | 130 | 2,106 | 335 | 4,745 | 392 |
| Pneumatic instruments | 71 | 1,209 | 255 | 3,251 | 269 |
| Pneumatic pumps | 18 | 303 | 67 | 835 | 69 |
| Compressor seals | 56 | 950 | 43 | 1,336 | 110 |
| Glycol dehydrators | 1 | 62 | 6 | 105 | 9 |
| Fugitive equipment leaks | 346 | 339 | 350 | 3,984 | 329 |
| Surface-casing vent flow | 443 | 35 | 40 | 809 | 67 |
| Total | 1,065 | 5,005 | 1,096 | 15,066 | 1,244 |
Table b9 note(s)
|
|||||
Industry administrative costs
The proposed Amendments would impose incremental administrative costs to industry attributable to learning about the new requirements, assessing applicability, registration, increased record-keeping requirements, and reporting. From 2027 to 2040, these industry administrative costs are estimated to be $312 million, as shown in Table 10 below. See the “One-for-one rule” section for details on administrative costs.
Government administrative costs
The Government of Canada is not expected to incur any additional costs beyond the need to inform stakeholders of the proposed Amendments. This is because the existing implementation, compliance, and enforcement policies and programs would continue to apply.
| Source | Undiscounted 2027 |
Undiscounted 2030 |
Undiscounted 2040 |
Discounted Total 2027–2040 |
Annualized |
|---|---|---|---|---|---|
| Compliance costs | 1,065 | 5,005 | 1,096 | 15,066 | 1,244 |
| Administrative costs | 31 | 26 | 26 | 312 | 26 |
| Total cost to industry | 1,096 | 5,032 | 1,122 | 15,378 | 1,270 |
Benefits of regulatory coverage and compliance
The proposed Amendments are expected to reduce vented and fugitive emissions of methane through the requirements to conserve or destroy fugitive and vented hydrocarbon gas. Reductions in carbon dioxide emissions are also expected due to a decrease in flaring activities and an increase in capture of the flared gas. The social cost of methane (SCM) has been applied to the expected methane (CH4) emission reductions, and the social cost of carbon (SCC) has been applied to the expected CO2 emission reductions, to value the avoided climate change damages resulting from reductions in GHG emissions.
In addition, it is estimated that emissions of volatile organic compounds (VOCs) would be reduced, which would be expected to lead to improved air quality, which can improve the environment and health of Canadians. While the VOC reductions have been estimated, their impacts are only discussed qualitatively in this analysis. As well, some natural gas that would have otherwise been wasted would be conserved as a potential energy source. This benefit has been quantified in terms of energy savings but has not been monetized in this analysis. Thus, the monetized benefits likely underestimate the total value to society of the proposed Amendments.
Quantification of benefits
The Department has developed a methane emission estimation process for the oil and gas sector to determine the expected GHG and VOC emissions reductions associated with the existing Regulations, as well as to determine the likely outcomes of the proposed Amendments. This process generates a quantitative result for CH4, CO2 and VOC emissions at a sectoral level.
GHG and VOC emissions are calculated based on the number of oil and gas facilities, which relates the facility activities to oil and gas products. Each facility type has an emissions profile that is based on the equipment and their respective emission factors under a baseline and regulatory scenario. Once GHG and VOC emissions are calculated at the facility level, they are then aggregated to the following oil and gas sectors for each province and compliance standard: natural gas production, natural gas processing, natural gas pipelines, light oil mining, and heavy oil mining.
The data for the source-level input parameters differ for each emission source:
Pneumatic devices
- Determining Bleed Rates for Pneumatic Devices in British Columbia (Prasino, 2013);footnote 9
- Update of Equipment, Component and Fugitive Emission Factors for Alberta Upstream Oil and Gas Study (Clearstone, 2018);footnote 10
- British Columbia Oil and Gas Methane Emissions Field Study (Cap-Op Energy, 2019);footnote 11
- Oil and Gas Inventory Information Enhancement and Economic Analysis Study (Advisian, 2019);footnote 12
- Pneumatic Vent Gas Measurement (Spartan Controls, 2018).footnote 13
Fugitive equipment leaks
- Update of Equipment, Component and Fugitive Emission Factors for Alberta Upstream Oil and Gas Study (Clearstone, 2018);footnote 10
- British Columbia Oil and Gas Methane Emissions Field Study (Cap-Op Energy, 2019);footnote 11
- EPA Protocol for Equipment Leak Emission Estimates (EPA, 1995).footnote 14
Compressor seals and vents
- Statistical Analysis of Leak Detection and Repair in Canada (Carbon Limits, 2017);footnote 15
- Using the Greenhouse Gas Reporting Program (GHGRP) Data to Improve the National Greenhouse Gas Emissions Inventory for Petroleum and Natural Gas Systems (API, 2017).footnote 16
Glycol dehydrators
- AER Methane Emission Reduction Methodology and Assumptions;footnote 17
- Update of Fugitive Equipment Leak Emission Factors (Clearstone, 2014);footnote 18
- AER Statistical Report ST-60B (2021).footnote 19
Venting and flaring
- Petrinex Public Data by province.footnote 20
Facilities are differentiated based on oil and gas products as well as facility type. The number of oil and gas facilities in operation changes annually.
The total number of devices, components, equipment, wells or facilities is based on the number of estimated active oil and gas wells and facilities, which is obtained from publicly reported data,footnote 20 and provincial reports, obtained through federal-provincial government engagements for historical counts and projected using production forecast data from the CER.footnote 21
To estimate emissions of the various pollutants contained in emitted gases, the composition of gas streams was determined using estimates of gas composition from province-specific reports and datasets. For Alberta, township-specific well composition data was retrieved from Tyner and Johnson (2020)footnote 22 and attributed to facility subtypes in the province. For British Columbia, drilling data was collected from the BC Energy Regulator websitefootnote 23 and attributed to facility subtypes in the province. For Saskatchewan, gas composition data was obtained from the Saskatchewan Ministry of Energy and Resources for each production class in Saskatchewan. This data was attributed to facility subtypes in the province. For Manitoba, the data from the Estevan production class in Saskatchewan was chosen to represent similar production activity and composition in the Bakken region. Finally, compositional data from Alberta was applied to Ontario for the analysis.
To obtain the amounts of CO2, CH4 or VOCs reduced, the natural gas reductions are multiplied by the composition ratios for each standard. Table 11 below provides the aggregated gas composition by province and product type, formatted for conciseness.
| Province | Oil/gas production type | CH4 | CO2 | VOC |
|---|---|---|---|---|
| Alberta/Ontario | Light oil | 70% | 2% | 14% |
| Alberta | Heavy oil | 89% | 6% | 2% |
| Non-associated gas | 79% | 2% | 8% | |
| Tight gas | 79% | 2% | 8% | |
| Shale gas | 79% | 2% | 8% | |
| Coalbed methane | 79% | 2% | 8% | |
| Gas processing | 73% | 3% | 11% | |
| British Columbia | Light oil | 69% | 2% | 15% |
| Non-associated gas | 71% | 2% | 13% | |
| Tight gas | 71% | 2% | 13% | |
| Shale gas | 71% | 2% | 13% | |
| Gas processing | 71% | 3% | 12% | |
| Saskatchewan | Light oil | 50% | 2% | 30% |
| Heavy oil | 81% | 3% | 7% | |
| Non-associated gas | 68% | 2% | 17% | |
| Tight gas | 68% | 2% | 17% | |
| Gas processing | 71% | 3% | 15% | |
| Manitoba | Light oil | 36% | 3% | 36% |
Methane emissions are aligned with GHG emissions that the Energy, Emissions and Economy Model for Canada (E3MC) projects in the Department’s GHG Emissions Reference Case.footnote 24 The emission reduction estimates are compared to the baseline emissions for the entire oil and gas sector contained in the Department’s Reference Case to determine how the proposed Amendments would be expected to reduce emissions of CH4, CO2 and VOCs over the time frame of analysis.
Greenhouse gas emission reductions
The proposed Amendments are estimated to reduce up to 8.4 Mt of methane emissions over the time frame of analysis, as shown below.
| Source | 2027 | 2030 | 2040 | 2027–2040 |
|---|---|---|---|---|
| Venting and flaring table a3 note a | 0.01 | 0.14 | 0.15 | 1.61 |
| Pneumatic instruments | 0.01 | 0.11 | 0.11 | 1.21 |
| Pneumatic pumps | 0.00 | 0.05 | 0.05 | 0.60 |
| Compressor seals | 0.00 | 0.06 | 0.04 | 0.54 |
| Glycol dehydrators | 0.00 | 0.01 | 0.01 | 0.09 |
| Fugitive equipment leaks | 0.24 | 0.23 | 0.24 | 3.29 |
| Surface-casing vent flow | 0.09 | 0.08 | 0.07 | 1.05 |
| Total | 0.36 | 0.69 | 0.66 | 8.39 |
Table a3 note(s)
|
||||
The proposed Amendments are also estimated to reduce 7.3 Mt of carbon dioxide emissions between 2027 and 2040 due to a decrease in flaring activities and an increase in capture of the flared gas. In 2027, there is a slight increase in estimated CO2 emissions due to the assumption that one of the compliance actions taken for compressor seals and vents as well as surface casing vent flows sources would be to incinerate or burn the otherwise vented gas. This increase in CO2 emissions is minor compared to the overall decrease in CO2 emissions over the time frame of analysis, as shown in Table 13 below.
| Source | 2027 | 2030 | 2040 | 2027–2040 |
|---|---|---|---|---|
| Venting and flaring table a4 note a | 0.07 | 1.27 | 1.30 | 14.2 |
| Pneumatic instruments | 0 | 0 | 0 | 0 |
| Pneumatic pumps | 0 | 0 | 0 | 0 |
| Compressor seals | (0.01) | (0.15) | (0.08) | (1.24) |
| Glycol dehydrators | 0 | 0 | 0 | 0 |
| Fugitive equipment leaks | 0 | 0 | 0 | 0 |
| Surface-casing vent flow | (0.49) | (0.43) | (0.38) | (5.65) |
| Total | (0.44) | 0.69 | 0.84 | 7.33 |
Table a4 note(s)
|
||||
Overall, the proposed Amendments are estimated to contribute more than 17 Mt of GHG emission reductions in 2030, and about 217 Mt of GHG emission reductions from 2027 to 2040. This includes methane reductions expressed as CO2 equivalents (CO2e) using a global warming potential factor of 25,footnote 25 as shown in Table 14 below.
| GHG | 2027 | 2030 | 2040 | 2027–2040 |
|---|---|---|---|---|
| CO2e of CH4 | 8.94 | 17.14 | 16.62 | 209.75 |
| CO2 | (0.44) | 0.69 | 0.84 | 7.33 |
| Total | 8.50 | 17.83 | 17.47 | 217.08 |
To monetize these GHG benefits, the quantity of avoided GHG emissions each year was multiplied by the Department’s schedule of the value of the social cost of methane (SCM) and social cost of carbon (SCC). In November 2022, the U.S. EPA released its draft Report on the Social Cost of Greenhouse Gases,footnote 26 in which the social cost of greenhouse gas emission (SC-GHG) methodologies and values have been updated and presented for CO2, CH4 and N2O. In April 2023, the Department published draft SC-GHG guidance for Canadafootnote 27 in alignment with the SC-GHG values proposed by the U.S. EPA. The value of the social cost of methane employed in this analysis and expressed in constant 2022 dollars is $2,456 in 2022 and increases to $4,479 in 2040. The value of the social cost of carbon employed in this analysis and expressed in constant 2022 dollars is $273 in 2022 and increases to $365 in 2040. The resulting estimated present value of the reduction of GHGs is about $27.8 billion.
| Monetized benefits (costs) | Undiscounted 2027 |
Undiscounted 2030 |
Undiscounted 2040 |
Discounted total 2027–2040 |
Annualized |
|---|---|---|---|---|---|
| Value of CH4 (using SCM) | 1,062 | 2,249 | 2,978 | 25,767 | 2,128 |
| Value of CO2 (using SCC) | (130) | 217 | 308 | 1,986 | 164 |
| Total benefits | 932 | 2,467 | 3,286 | 27,753 | 2,292 |
VOC emission reductions
The proposed Amendments would reduce VOCs emissions entering the atmosphere by up to 1 485 kilotonnes (kt) over the time frame of the analysis as shown in Table 16 below, which is expected to reduce the associated adverse health impacts to people in Canada. Although air quality impacts were not modelled, health benefits attributable to air pollutant reductions are expected to ensue from the proposed Amendments, due to reductions in the contribution of VOCs to ambient fine particulate matter (PM2.5) and ground-level ozone, and from reductions in releases of toxic substances such as benzene.
| Source | 2027 | 2030 | 2040 | 2027–2040 |
|---|---|---|---|---|
| Venting and flaring table b16 note a | 1.1 | 19.3 | 17.2 | 198.9 |
| Pneumatic instruments | 1.5 | 26.9 | 24.4 | 281.4 |
| Pneumatic pumps | 0.4 | 7.3 | 7.2 | 80.6 |
| Compressor seals | 0.7 | 11.4 | 7.0 | 101.7 |
| Glycol dehydrators | 0 | 0 | 0 | 0 |
| Fugitive equipment leaks | 54.2 | 48.6 | 45.4 | 659.0 |
| Surface-casing vent flow | 14.2 | 12.3 | 10.8 | 163.3 |
| Total | 72.2 | 125.8 | 112.0 | 1,484.9 |
Table b16 note(s)
|
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VOCs are air pollutants that contribute to the formation of ground-level ozone and PM2.5, which are the main constituents of smog. These air pollutants cause adverse effects on the environment and on human health, contributing to respiratory symptoms, disease burden and premature death. Children, the elderly, and individuals with underlying health conditions are particularly vulnerable to the adverse effects of air pollution. A reduction in emissions of VOCs would be expected to yield health benefits by reducing illness and premature deaths linked to respiratory and cardiovascular diseases attributable to PM2.5 and ground-level ozone. Air quality modelling was not conducted to quantify and monetize the impact of emissions reductions on ambient air pollutant concentrations associated with the proposed Amendments. The proposed Amendments are incremental to the 2018 Regulationsfootnote 28 and would be expected to further reduce VOC emissions and the associated adverse health impacts to people in Canada. The local and regional impacts would depend on emission sources, meteorology, where reductions occur and populations, which would likely determine the distribution of health benefits attributable to the proposed Amendments.
Conserved gas savings
Methane is the primary component in natural gas, which can be used as a source of energy for heating, cooking, and electricity generation. Technical and process changes required by the proposed Amendments would limit methane venting and reduce fugitive emissions and routine flaring. These reductions would be achieved through either combustion or conservation. The conserved gas would thus lead to the conservation of approximately 686 petajoules (PJ) of natural gas (see Table 17 below).
| Source | 2027 | 2030 | 2040 | 2027–2040 |
|---|---|---|---|---|
| Venting and flaring table b17 note a | 1.5 | 29.1 | 30.5 | 331.2 |
| Pneumatic instruments | 0.3 | 6.4 | 6.1 | 69.0 |
| Pneumatic pumps | 0.2 | 3.0 | 3.1 | 34.2 |
| Compressor seals | 0.2 | 2.4 | 1.6 | 22.0 |
| Glycol dehydrators | 0.2 | 0.4 | 0.4 | 5.0 |
| Fugitive equipment leaks | 14.0 | 13.4 | 13.7 | 187.9 |
| Surface-casing vent flow | 3.1 | 2.8 | 2.5 | 36.8 |
| Total | 19.5 | 57.5 | 57.9 | 686.1 |
Table b17 note(s)
|
||||
This amount of conserved gas represents 0.71% of all Canada Energy Regulator (CER) forecasted gas production in Canada between 2027 and 2040. The potential value of this conserved gas has not been monetized in this analysis.
The quantified benefits attributable to the proposed Amendments are summarized in Table 18.
| Category | 2027 | 2030 | 2040 | 2027–2040 |
|---|---|---|---|---|
| Net GHG reduction (Mt CO2e) | 8.5 | 17.8 | 17.5 | 217.1 |
| VOC reduction (kt) | 72.2 | 125.8 | 112.0 | 1,484.9 |
| Gas conserved (PJ) | 19.5 | 57.5 | 57.9 | 686.1 |
This analysis evaluates the proposed Amendments using three analytical lenses:
- effectiveness analysis, which compares the estimated methane reductions to the Government of Canada’s 2030 methane reduction target, and overall GHG reductions to Canada’s GHG reduction targets;
- cost-effectiveness analysis, which compares the estimated cost per tonne of GHG reductions attributable to the proposed Amendments to the Department’s updated social cost of GHGs; and
- cost-benefit analysis, which compares the estimated monetized benefits to the estimated monetized costs to determine if the proposed Amendments are expected to yield net benefits.
Estimated effectiveness and cost-effectiveness of the proposed Amendments
The objective of the proposed Amendments is to achieve at least a 75% reduction in oil and gas methane emissions below 2012 levels by 2030. According to the Department’s 2022 Reference Case, baseline methane emission levels were about 2.4 Mt in 2012.footnote 29 The analysis of the proposed Amendments estimates that methane emission levels would be about 0.6 Mt in 2030, which is 75% below 2012 levels. Thus, the proposed Amendments are expected to meet the 2030 methane reduction policy target.
Overall, the proposed Amendments are estimated to contribute more than 17 Mt of GHG emission reductions in 2030, and about 217 Mt of GHG emission reductions from 2027 to 2040 (expressed as CO2e), which would make a significant contribution to Canada’s overall GHG emission reduction targets.
The proposed Amendments are estimated to cost $15.4 billion and the average cost per tonne is estimated to be about $71 over the time frame of analysis. This is significantly less than the Department’s updated social cost of carbon, which is $273 in 2022. Thus, the Department concludes that the proposed Amendments would be a cost-effective measure for achieving GHG emission reductions.
Estimated net benefits of the proposed Amendments
From 2027 to 2040, the proposed Amendments are estimated to have incremental costs of $15.4 billion, and incremental GHG reductions of 217 Mt of CO2e, valued at almost $27.8 billion in avoided global damages. Annual costs exceed annual benefits early in the analysis as compliance investments begin in those years. But the value of annual GHG reductions exceeds total expenditures over the 2027 to 2040 period. Thus, the proposed Amendments are estimated to have net benefits of $12.4 billion as shown in Table 19 below.
- Number of years: 14 (2027 to 2040)
- Dollar year for prices: 2022
- Present value year for discounting: 2024
- Social discount rate: 2% per year
| Monetized benefits (costs) | Undiscounted 2027 |
Undiscounted 2030 |
Undiscounted 2040 |
Discounted total 2027–2040 |
Annualized |
|---|---|---|---|---|---|
| Climate change benefits | 932 | 2,467 | 3,286 | 27,753 | 2,292 |
| Total costs | (1,096) | (5,032) | (1,122) | (15,378) | (1,270) |
| Total net benefits | (164) | (2,565) | 2,164 | 12,374 | 1,022 |
The analysis estimates that the proposed Amendments would yield net benefits, but there is uncertainty regarding the estimates and limitations in the analysis, each of which are addressed below.
Analytical uncertainty
Benefits and costs may be lower or higher than estimated, so the net benefit conclusion has been tested by assuming 50% lower benefits, 50% higher costs, or a lower (0%) or higher (7%) discount rate, and a “combined case” comprising 25% lower benefits, 25% higher costs, and a 7% discount rate, as shown below in Table 20.
| Variable(s) | Sensitivity case | Benefits (B) | Costs (C) | Net benefits (B − C) |
|---|---|---|---|---|
| Central case | n/a | 27,753 | (15,378) | 12,374 |
| Benefits valuation | 50% Lower | 13,876 | (15,378) | (1,502) |
| Compliance costs | 50% Higher | 27,753 | (22,911) | 4,841 |
| Discount rate | 0% | 34,167 | (18,319) | 15,847 |
| Discount rate | 7% | 17,167 | (10,310) | 6,857 |
| Combined case | See text above | 12,876 | (12,836) | 39 |
In all but the 50% lower benefits scenario, the proposed Amendments still yield an estimated net benefit. The Department notes that there is uncertainty regarding the estimation of benefits, due to methane measurement challenges (see below), but it is not clear that better methane measurement would necessarily lower the estimated incremental reductions. Thus, the Department concludes that it is plausible that the proposed Amendments would result in net benefits for Canadians. There are limitations in this analysis which are acknowledged and discussed below.
Analytical limitations
This analysis did not estimate the impact of policies announced after mid-2022, after the baseline Reference Case was finalized. Therefore, the regulatory scenario may attribute some of the incremental impacts to the proposed Amendments that might be expected to occur in an updated baseline scenario.
This analysis does not predict how firms may undertake strategic compliance behaviour in response to either the proposed Amendments or other policy incentives. Such behaviour would be expected to lower compliance costs. As well, this analysis has not modelled the macro-economic impacts of the estimated compliance costs, but rather has provided a static analysis of potential economic impacts (see Distributional analysis).
There is uncertainty regarding the estimation of methane emissions.footnote 30 This uncertainty could affect the estimate of both the 2012 target, and the projected emissions in both the base case and policy case of the analysis. As technology improves, the Department will be able to better estimate the methane emission reductions in the oil and gas sector and could adjust the analysis and, if necessary, proposed Amendments to the Regulations.
Technologies to measure and reduce methane emissions are rapidly evolving, which means there is also uncertainty about the cost estimates. Emerging technologies would have different costs and as these technologies become more prevalent, their costs may fall over time. The Department has not tried to estimate the impact of either of these trends in this analysis. As well, the analysis has not considered the heterogeneity of facilities, which could face different compliance constraints and costs than an average facility.
Strategic environmental assessment
The existing Regulations were developed under the Pan-Canadian Framework on Clean Growth and Climate Change. A strategic environmental assessment (SEA) was completed for the existing Regulations in 2016 and it concluded that they were in line with the 2016–2019 Federal Sustainable Development Strategy (FSDS) goal of effective action on climate change. A preliminary scan concluded that a SEA is not required for the proposed Amendments, since they continue to align with the updated 2022–2026 FSDSfootnote 31 to reduce emissions of methane from the oil and gas sector.
Distributional analysis
The proposed Amendments are expected to result in benefits that exceed costs for Canadian society, but the benefits and costs may not be equally distributed. The GHG emission reductions are discussed regionally, as provinces can negotiate equivalency agreements to achieve the same reductions at a lower cost than estimated for the proposed Amendments. The distribution of impacts is further discussed below in the following sequence: impacts by region, impacts on competitiveness, and the potential for cost pass-through to consumers. Analyses of household and gender-based analysis plus (GBA+) impacts are then considered.
Impacts by region
The emission reductions and compliance costs associated with the proposed Amendments would vary by region. The production of oil and gas is concentrated in the provinces of British Columbia (BC), Alberta (AB) and Saskatchewan (SK). The breakdown of quantified benefits and monetized costs across these provinces and the rest of Canada (ROC) is shown below.
| Category | British Columbia | Alberta | Saskatchewan | Rest of Canada | Total |
|---|---|---|---|---|---|
| Reduced net GHG emissions (Mt CO2e) | 17.7 | 105.4 | 90.6 | 3.3 | 217.1 |
| Reduced VOC emissions (kt) | 92.3 | 605.5 | 660.4 | 126.8 | 1,484.9 |
| Gas conserved (PJ) | 92.7 | 290.4 | 295.3 | 7.7 | 686.1 |
| Compliance costs (million $) | 2,333 | 8,228 | 4,202 | 303 | 15,066 |
Equivalency agreements were developed in 2020 between the Government of Canada and each of the provincial governments in British Columbia, Alberta and Saskatchewan. These agreements would need to be renewed when they expire after five years. It is assumed that compliance costs would be lower for provincial requirements than for federal requirements, as each province can focus on achieving the least cost reductions within their particular upstream oil and gas sector.
Competitiveness analysis
The proposed Amendments would impose additional compliance costs on oil and gas companies. Annualized compliance costs are estimated to be $1.2 billion over the period of analysis. Total capital and operating expenditures in the oil and gas extraction sector were $41.6 billion in 2021 — a figure that was 10% lower than the average annual expenditures over the previous seven years. If spending in the sector remains at these comparatively low levels, increased costs attributable to the proposed Amendments would represent an increase in annual industry expenditures of roughly 3%. Given the relative scale of the estimated costs of the proposed Amendments, and the potential for these costs to be partially offset by conserved gas, significant impacts on overall production are not expected.
In response to the potential financial and competitiveness impacts of the proposed Amendments, regulatory flexibilities have been proposed. The Amendments provide different compliance requirements based on size and type of equipment at sites and allow for compliance options regarding site monitoring requirements.
In addition, the United States has proposed similar regulatory measures to reduce methane emissions in this sector, which would be expected to create a level playing field for Canadian upstream oil and gas producers. Thus, the inability of Canadian producers to pass on costs is not expected to create competitiveness disadvantages in the North American market.
Consumer impacts
Firms’ ability to pass on costs to consumers depends on many things. Crude oil and natural gas, however, are commodities that are priced in global and continental markets. Thus, compliance cost pass-on is expected to be unlikely for this sector.
While incremental costs might lead to some production losses, employment impacts would be at least partially mitigated by the increased labour demand necessary to comply with the proposed Amendments. The analysis has not modelled these potential impacts.
Household and gender-based analysis plus analysis
Households are not expected to be directly impacted by the compliance costs of the proposed Amendments, as these costs are not predicted to have much impact on end-use fuel prices. And the analysis has not identified measurable impacts on overall employment.
The proposed Amendments are expected to reduce VOC emissions, which could improve air quality in some locations. This in turn could improve the health of some Canadians, especially for those who are at higher risk of being negatively impacted by poor air quality conditions, such as children, the elderly, and individuals with underlying health conditions (see the “Benefits” section).
The proposed Amendments are a key policy for reducing harmful GHG emissions. The benefits of reducing GHG emissions associated with this proposal are global in nature, and so cannot be attributed to any specific region or group in Canada.
No other significant gender-based analysis plus (GBA+) impacts have been identified in association with the proposed Amendments.
Small business lens
Analysis under the small business lens concluded that the proposed Amendments would impact small businesses. It is estimated that the proposed Amendments would affect approximately 730 companies, 484 of which are considered small businesses. Most oil and gas production and processing operations are owned by medium and large businesses, but some facilities operated by small businesses would also be affected.
The proposed Amendments do not offer flexibilities that are unique to small businesses. However, the performance-based option in the proposed Amendments provides industry with a choice to implement a simple compliance regime incorporating modern monitoring systems with the flexibility to continue to adapt new technologies as they become available.
Small businesses are expected to bear compliance costs in response to the proposed Amendments; however, those costs are not assessed in this section. Compliance costs are calculated at a sector level and, therefore, cannot be disaggregated by company.
The expected administrative costs to small businesses are shown in Table 22 below.
Small business lens summary
- Number of small businesses impacted: 484
- Number of years: 14 (2027 to 2040)
- Base year for costing: 2022
- Present value base year: 2024
- Discount rate: 2%
| Totals | Annualized value | Present value |
|---|---|---|
| Total administrative costs (all impacted small businesses) | $16,258,617 | $196,830,861 |
| Administrative costs per impacted small business | $33,592 | $406,675 |
One-for-one rule
The one-for-one rule applies since there is an incremental increase in the administrative burden on business, and the proposal is considered burden under the rule. No regulatory titles are repealed or introduced. The total annualized administrative costs for the regulatees to comply with the regulatory requirements over a 10-year time frame are estimated to be approximately $6.0 million for all stakeholders, or $8,250 per company.footnote 32
The main driver (98%) of administrative costs is record keeping (the proposed Amendments would require facilities to keep records of compliance). It is assumed that some of the data needed to comply with this requirement is already accessible and kept by the regulatees in British Columbia, Alberta and Saskatchewan due to existing provincial requirements. Consequently, the additional information that is required is primarily the record keeping of emissions of methane from the facility. The Department estimates that, on average, companies would require a natural or applied scientist to spend 675 hours annually to comply with record-keeping requirements.
In addition to keeping records, regulatees would be expected to bear new administrative costs related to learning about the administrative requirements, conducting both an applicability assessment and an operator registration, and reporting on demand. In the first year, regulatees are assumed to require senior management to spend 4 hours familiarizing themselves with the requirements, and administrative staff to spend 25 minutes per facility to conduct an applicability assessment and operator registration. As companies often own many facilities, this is estimated to take about 25 hours per company, on average. In addition, each year the Department would request select facilities to report their records, which is estimated to take 3 hours per facility to prepare. Lastly, it is expected that each company would have an analyst review their records, which is estimated to take 4 hours annually.
Regulatory cooperation and alignment
Provinces and territories
The provinces of Alberta, British Columbia, and Saskatchewan each initiated regulatory measures to specifically address methane emissions in the oil and gas sector to match the current federal regulations. The federal government has recognized existing provincial regulations under equivalency agreements with each of the three western provinces, standing down the federal provisions in those jurisdictions. New equivalency processes would be required for the federal government to recognize updated policies from any province proposing such measures.
British Columbia has committed to a target of 75% reduction in methane emissions by 2030, as well as a 2035 target for zero methane. Alberta has publicly committed to a 75–80% reduction by 2030. Saskatchewan is focused on a made-in-Saskatchewan approach but has not yet provided details.
United States
Canada and the United States are each committed to continued close collaboration to further reduce methane emissions from their respective oil and gas operations. Both countries agree that significant opportunities exist to eliminate routine venting and flaring, enhance leak detection and repair, and address problems such as blowdowns and other potentially large releases.
The U.S. Environmental Protection Agency (EPA) regulates its oil and gas industry using New Source Performance Standards (NSPS). On November 2, 2021, the EPA issued a proposed rule, building on the NSPS to reduce climate and health-harming pollution from the oil and natural gas industry from covered sources. This rule was followed by a supplemental proposal in November 2022 that would achieve comprehensive emissions reductions from oil and natural gas facilities by improving standards in the 2021 proposal and adding further requirements. The overall approach of the U.S. regulations is the continued but expanded reliance on the existing work practices: federal rules will apply to new facilities; existing facilities can be managed by states if a satisfactory plan is developed and approved. The proposed EPA requirements are broadly comparable to the proposed Amendments, with requirements to manage specific sources of methane and VOC emissions. The EPA proposal includes requirements for leak inspections based on the type and amount of equipment on site. It requires zero emissions from most pneumatic pumps, requirements to manage compressor seal emissions, and management of vent and flare emissions.
Many oil and gas-producing states in the United States prohibit the waste of oil and gas during production. States including Alaska, Colorado, North Dakota and Wyoming require gas conservation, do not allow the routine venting of gas during production, and restrict the practice of flaring.
International
Canada is working in partnership with the international community to implement the Paris Agreement to support the goal to limit temperature rise this century to well below 2 °C and to pursue efforts to limit the temperature increase to 1.5 °C.
At the 26th Conference of the Parties to the United Nations Framework Convention on Climate Change, Canada joined 110 countries in endorsing the Global Methane Pledge, which committed countries to take economy-wide action to reduce methane emissions by 30% by 2030. With this context, Canada has specifically committed to build on existing initiatives to ensure that methane emissions from the oil and gas sector are reduced by at least 75% below 2012 levels by 2030.
The European Union (EU) is developing an approach to manage methane emissions. The European Council published its methane strategy on October 14, 2020, covering the Energy, Agriculture and Waste sectors. On December 15, 2021, the European Commission released its legislative proposal for oil and gas methane: methane emissions from upstream exploration and production, gathering and processing, as well as transmission, distribution and underground storage of oil and gas. The European Parliament adopted an amendment on May 9, 2023, regarding methane emissions reduction in the energy sector, with strict rules for monitoring emissions, as well as leak detection and repair requirements. The Parliament also asked the Commission to come up with a framework to ensure exporting countries have to abide by similar rules. The proposal requires each EU member state to designate a competent authority to monitor and enforce the regulation.
The International Energy Agency (IEA) maintains a Global Methane Tracker that reports on country-level actions. According to IEA analysis, the intensity of methane emissions (emissions per unit of production) ranges widely, with the best countries performing more than 100 times better than the worst. With the proposed new requirements, Canada would be expected to continue as one of the leading jurisdictions regarding international performance on oil and gas methane emissions.footnote 33
Implementation
The proposed Amendments would begin to take effect in 2027, with a focus on emission inspection programs and design standards where industry is investing in new production, and would apply across the sector in 2030.
Compliance and enforcement
The proposed Amendments would continue the existing enforcement approach applying the Compliance and Enforcement Policy for the Canadian Environmental Protection Act. The Policy sets out the range of possible enforcement responses to alleged violations. The enforcement officer would select the appropriate enforcement action based on the Policy.
Compliance promotion activities are intended to assist the regulated community in achieving compliance. The proposed Amendments would expand the number of potential regulatees compared to the existing Regulations; therefore, there would be facilities needing to comply for the first time. The compliance promotion approach for the proposed Amendments would include developing and posting compliance promotion information and guidance on the Department’s website to explain provisions of the Regulations, as well as undertaking various outreach activities such as workshops and informational sessions. The Department would respond to stakeholder inquiries to ensure that the requirements of the regulatory approach and the alternate compliance pathway are understood.
Contacts
Magda Little
Director
Oil, Gas and Alternative Energy Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: methane-methane@ec.gc.ca
Matthew Watkinson
Executive Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ravd.darv@ec.gc.ca
PROPOSED REGULATORY TEXT
Notice is given, under subsection 332(1)footnote a of the Canadian Environmental Protection Act, 1999 footnote b, that the Governor in Council proposes to make the annexed Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) under subsection 93(1)footnote c and section 286.1footnote d of that Act.
Any person may, within 60 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or file with the Minister a notice of objection requesting that a board of review be established under section 333footnote e of that Act and stating the reasons for the objection. Persons filing comments are strongly encouraged to use the online commenting feature that is available on the Canada Gazette website. Persons filing comments by any other means, and persons filing a notice of objection, should cite the Canada Gazette, Part I, and the date of publication of this notice, and send the comments or notice of objection to Magda Little, Director, Oil, Gas and Alternative Energy Division, Environment and Climate Change Canada, 351 Saint-Joseph Boulevard, Gatineau, Quebec, K1A 0H3 (email: methane-methane@ec.gc.ca).
A person who provides the information to the Minister of the Environment may also submit a request for confidentiality under section 313footnote f of that Act.
Ottawa, November 30, 2023
Wendy Nixon
Assistant Clerk of the Privy Council
Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)
Amendments
1 (1) The definitions completion, design bleed rate, flowback, gas-to-oil ratio, hydraulic fracturing, pneumatic controller and pneumatic pump in subsection 2(1) of the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) footnote 34 are repealed.
(2) The definition fugitive in subsection 2(1) of the Regulations is repealed.
(3) The definition hydrocarbon in subsection 2(1) of the Regulations is replaced by the following:
- hydrocarbon
- means methane, which has the molecular formula CH4, or a volatile organic compound referred to in item 60 of the list of toxic substances in Schedule 1 to the Canadian Environmental Protection Act, 1999. (hydrocarbure)
(4) The portion of the definition venting before paragraph (a) in subsection 2(1) of the English version of the Regulations is replaced by the following:
- venting
- means the emission of hydrocarbon gas from an upstream oil and gas facility in a controlled manner, other than the emission of gas arising from combustion, due to
(5) Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order:
- auditor
- means a person who
- (a) is independent of the operator and owner of the upstream oil and gas facility that is to be inspected; and
- (b) has knowledge of and experience with emission monitoring systems. (vérificateur)
- continuous monitoring system
- means a system of one or more sensors and other equipment that is designed to continuously monitor hydrocarbon gas emissions at an upstream oil and gas facility. (système de surveillance continue)
- fugitive emission
- means an unintentional emission of hydrocarbon gas from an upstream oil and gas facility. (émission fugitive)
- Type 1 facility
- means an upstream oil and gas facility at which any of the following equipment is installed:
- (a) a natural gas compressor;
- (b) a storage tank for produced liquids;
- (c) a flare; or
- (d) a gas-liquid separator. (installation de type 1)
- Type 2 facility
- means an upstream oil and gas facility other than a Type 1 facility. (installation de type 2)
2 (1) Section 4 of the Regulations is replaced by the following:
Application — Onshore facilities
4 This Part applies in respect of an upstream oil and gas facility that is located onshore.
(2) Section 4 of the Regulations is replaced by the following:
Application — Onshore facilities
4 This Part applies in respect of an upstream oil and gas facility that is located onshore, other than one at which hydrocarbon gas emissions are monitored by means of a continuous monitoring system.
3 The Regulations are amended by adding the following after section 8:
Non-application of certain sections
8.1 (1) Sections 9 to 27 and 37 to 45 do not apply in respect of an upstream oil and gas facility in respect of which sections 46 to 53.3 apply.
Application of sections 46 to 53.3
(2) Sections 46 to 53.3 apply in respect of an upstream oil or gas facility
- (a) if operations at the facility begin before January 1, 2027, as of
- (i) January 1, 2028, if the combined volume of hydrocarbon gas that is produced or received at the facility in 2027 is greater than the combined volume of hydrocarbon gas that is produced or received at the facility in each of the years 2024 to 2026,
- (ii) January 1, 2029, if the combined volume of hydrocarbon gas that is produced or received at the facility in 2028 is greater than the combined volume of hydrocarbon gas that is produced or received at the facility in each of the years 2024 to 2026, and
- (iii) January 1, 2030, in any other case; and
- (b) if operations at the facility begin on or after January 1, 2027, as of the day on which it begins operation.
2024 to 2026 combined volumes
(3) For the purpose of subparagraphs 2(a)(i) and (ii), the combined volume of hydrocarbon gas that is produced or received at the upstream oil and gas facility in a calendar year is the combined volume of hydrocarbon gas, expressed in standard m3, for that year as set out in records or published on the Petrinex website.
Fugitive Emission Detection and Repair Program
Comprehensive inspection
8.11 (1) Subject to subsection 8.15(2), a comprehensive inspection for fugitive emissions at an upstream oil and gas facility must be conducted in accordance with the following schedule:
- (a) in the case of a Type 1 facility, once in each quarter of the calendar year, with at least 60 days after a previous inspection; and
- (b) in the case of a Type 2 facility, once per calendar year, with at least 270 days since the date of the last inspection.
Methodology
(2) A comprehensive inspection must be conducted
- (a) using an instrument that
- (i) meets the specifications set out in Section 6 of EPA Method 21,
- (ii) is calibrated in accordance with Sections 7, 8.1, 8.2 and 10 of EPA Method 21 before it is used, for each day on which it is used,
- (iii) undergoes a calibration drift assessment after its last use on each of those days in accordance with the requirements set out in Section 60.485a(b)(2) of Subpart VVa, entitled Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification Commenced After November 7, 2006, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States; and
- (iv) is operated in accordance with the requirements of Section 8.3 of EPA Method 21 to the extent that those requirements are consistent with its manufacturer’s recommendations, or
- (b) using an optical gas-imaging instrument that is capable of imaging gas that is
- (i) in the spectral range for the compound of highest concentration in the hydrocarbon gas to be measured,
- (ii) half methane and half propane at a total concentration of at most 500 ppmv and at a flow rate of at least 60 g/h leaking from an orifice that is 0.635 cm in diameter, and
- (iii) at the viewing distance determined in accordance with the requirements of the alternative work practice of the Environmental Protection Agency of the United States set out in Sections 60.18(h)(7)(i)(2)(i) to (v) of Section 60.18, entitled General control device and work practice requirements, in Part 60 of Title 40, Chapter I of the Code of Federal Regulations of the United States.
Screening inspection
8.12 (1) Subject to subsection 8.15(2), a screening inspection for fugitive emissions at an upstream oil and gas facility must be conducted once in each month in which the operator or a representative of the operator visits the facility.
Methodology
(2) A screening inspection must be conducted using a monitoring instrument that, under standard conditions, has a 90% or greater probability of detecting a fugitive emission with a flow rate of 1 kg/h or more.
Annual inspection
8.13 (1) An annual inspection for fugitive emissions at an upstream oil and gas facility must be conducted by an auditor once per year, with no less than 180 days having elapsed since the date of the last annual inspection.
Exception
(2) However, an annual inspection is not required to be conducted in any year in which an annual inspection is conducted at the facility under subsection 53.2(1).
Methodology
(3) An annual inspection must be conducted using methods that, under standard conditions, provide a 90% or greater probability of detecting a fugitive emission with a flow rate of 10 kg/h or more.
Conduct of inspections
8.14 An inspection required under any of sections 8.11 to 8.13 must be conducted
- (a) by a person who, not more than five years before the day on which the inspection occurs, has received training in the calibration, maintenance and operation of the instruments that are used to conduct the inspection; and
- (b) using instruments that are calibrated, maintained and operated in accordance with the recommendations, if any, of its manufacturer.
Exclusion — health or safety
8.15 (1) An inspection required under any of sections 8.11 to 8.13 is not required to include the inspection of an equipment component if that inspection would pose a serious risk to human health or safety.
Exclusion — low temperature
(2) An inspection required under section 8.11 or 8.12 is not required to be conducted if, on the day before the scheduled day of the inspection for a quarter or a month, as the case may be, the temperature at the upstream oil and gas facility’s location is forecast to be below -20°C on that scheduled day.
Period for repair
8.16 (1) When a fugitive emission is detected at an upstream oil and gas facility, whether as a result of an inspection or otherwise, the equipment component that is emitting the hydrocarbon gas must be repaired,
- (a) if the repair can be carried out while the equipment component is operating, within the applicable period set out in subsection (2); and
- (b) in any other case, within the period before the end of the next planned shutdown of the facility, unless that period is extended under section 8.17.
Period for repair — while in operation
(2) If the equipment component that is emitting the hydrocarbon gas can be repaired while it is operating, it must be repaired,
- (a) if the flow rate of the fugitive emission is not determined, within 24 hours after the fugitive emission is detected; or
- (b) if the flow rate of the fugitive emission is determined,
- (i) in the case of a flow rate that is less than 1 kg/h, within 90 days after the day on which the fugitive emission is detected,
- (ii) in the case of a flow rate that is 1 kg/h or more but less than 10 kg/h, within 30 days after the day on which the fugitive emission is detected,
- (iii) in the case of a flow rate that is 10 kg/h or more but less than 100 kg/h, within seven days after the day on which the fugitive emission is detected, and
- (iv) in the case of a flow rate that is 100 kg/h or more, within 24 hours after the fugitive emission is detected.
Volume of hydrocarbon gas
(3) In subsections (4) and (5), a reference to a volume of hydrocarbon gas is a reference to that volume in standard m3.
Exception — low level emissions
(4) Despite subparagraphs (2)(b)(i) and (ii), if the equipment component is emitting hydrocarbon gas at a flow rate of less than 10 kg/h, the repair of the equipment component may be deferred until the earlier of
- (a) the day on which the estimated volume of hydrocarbon gas that, beginning on the day on which the fugitive emission is detected, would be emitted from that equipment component and from all other equipment components that are emitting hydrocarbon gas as of that day is equal to the volume of hydrocarbon gas that, if none of those equipment components were repaired, would be emitted during a temporary depressurization of the equipment or pipeline conducted in order to carry out the repair, and
- (b) the first anniversary of the day on which the fugitive emission was detected.
Repair — facility shutdown necessary
(5) If the equipment component that is emitting the hydrocarbon gas cannot be repaired while it is operating, the next planned shutdown of the facility must be scheduled no later than the earlier of
- (a) the day on which the estimated volume of hydrocarbon gas that, beginning on the day on which the fugitive emission is detected, would be emitted from that equipment component and from all other equipment components that are emitting hydrocarbon gas as of that day is equal to the volume of hydrocarbon gas that, if none of those equipment components were repaired, would be emitted during a temporary depressurization of the equipment or pipeline conducted in order to carry out the repair, and
- (b) the first anniversary of the day on which the fugitive emission was detected.
Verification of repair
(6) An equipment component is considered to be repaired when the fugitive emission is no longer detectable using
- (a) in the case where the fugitive emission was detected during a comprehensive inspection, an instrument referred to in subsection 8.11(2); and
- (b) in any other case, an instrument referred to in subsection 8.12(2).
Application to extend repair period
8.17 (1) The operator of an upstream oil and gas facility who must repair an equipment component that is emitting hydrocarbon gas at a flow rate of less than 10 kg/h may, no later than 45 days before the day on which the applicable repair period referred to in subsection 8.16(1) ends, apply to the Minister to extend the repair period.
Extension
(2) The Minister must extend the repair period for up to six months if the application contains the information set out in Schedule 1 and
- (a) documents that establish that, as of the making of the application, there are reasonable grounds to conclude that it is not technically feasible to complete the repair of the equipment component before the end of the applicable repair period or the extended repair period, as the case may be;
- (b) documents that establish that the operator has a plan to repair the equipment component that sets out
- (i) the expected date for the completion of the repair,
- (ii) the steps to be taken to ensure completion of the repair on or before that date,
- (iii) a justification, with supporting documents, for the belief as to why that date is the earliest feasible date to complete the repair, and
- (iv) measures to be taken to minimize, if not eliminate, any harmful effect on the environment or human health and safety from the emission of hydrocarbon gas before the completion of the repair; and
- (c) a statement that the implementation of the plan is to begin within 30 days after the day on which the extension is granted.
Renewal
(3) The Minister must renew the extended repair period if
- (a) no later than 45 days before the day on which the extended repair period ends, the operator submits an application to renew the extended repair period that contains the information set out in Schedule 1 and subsection (2); and
- (b) the extended repair period has not been previously renewed.
Refusal
(4) The Minister must refuse to grant an application referred to in subsection (1) or (3) if the Minister has reasonable grounds to believe that the operator has provided false or misleading information in the application.
Revocation
8.18 (1) The Minister must revoke an extension or renewal granted under section 8.17 if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in their application.
Conditions for revocation
(2) However, the Minister must not revoke an extension or renewal, unless the Minister has provided the operator with
- (a) written reasons for the proposed revocation; and
- (b) an opportunity to be heard, by written representation, in respect of the proposed revocation.
Record — inspection and fugitive emissions
8.19 A record must be made that sets out the following information respecting the inspections and fugitive emissions at an upstream oil and gas facility:
- (a) for each inspection,
- (i) its date and time,
- (ii) whether it was a comprehensive inspection, a screening inspection or an annual inspection,
- (iii) the methodology used,
- (iv) the make and model number of each instrument used,
- (v) information respecting the calibration of each instrument used, and
- (vi) whether a fugitive emission was detected;
- (b) the name and contact information of the auditor who conducted an annual inspection, along with the name and business address of their employer;
- (c) for each person who conducted a comprehensive or screening inspection,
- (i) their name, contact information and the name and business address of their employer, if their employer is not the operator,
- (ii) their training,
- (iii) the dates on which the training was provided and, for each of those dates, the number of hours of training, and
- (iv) a description of the training;
- (d) if a comprehensive inspection or screening inspection was not carried out at the facility for the reason described in subsection 8.15(2), the temperature that, on the day before the scheduled day of the inspection, was forecasted for the facility’s location on that scheduled day; and
- (e) for each fugitive emission detected,
- (i) the unique identifier, if any, assigned to that emission by the operator,
- (ii) a description of the equipment component that emitted the hydrocarbon gas and the location of that equipment component,
- (iii) the date on which the fugitive emission was detected,
- (iv) the date on which the fugitive emission ended,
- (v) the flow rate, in kg/h, of the fugitive emission before repair of the equipment component, if determined, and
- (vi) if the fugitive emission cannot be repaired while the equipment component is operating, the day of the next planned shutdown of the facility.
4 Section 8.1 of the Regulations is repealed.
5 Sections 9 to 19 and the headings before section 20 are repealed.
6 (1) The portion of subsection 20(1) of the Regulations before paragraph (a) is replaced by the following:
Application of sections 26, 27 and 37 to 45
20 (1) Sections 26, 27 and 37 to 45 apply in respect of an upstream oil and gas facility as of the first day of the month that begins after the facility produces or receives — or is expected to produce or receive — a combined volume of more than 60 000 standard m3 of hydrocarbon gas for a period of 12 months, determined as follows:
(2) Section 20 of the Regulations is repealed.
7 (1) The portion of section 21 of the Regulations before paragraph (a) is replaced by the following:
Records — non-application
21 If none of sections 26, 27 and 37 to 45 apply, for a given month, in respect of an upstream oil and gas facility, a record, with supporting documents, must be made that indicates
(2) Section 21 of the Regulations is repealed.
8 Sections 22 to 27 of the Regulations are repealed.
9 The headings before section 28 and sections 28 to 36 of the Regulations are repealed.
10 The heading before section 37 and sections 37 to 45 of the Regulations are repealed.
11 (1) The headings before section 46 and sections 46 to 53 of the Regulations are repealed.
(2) The Regulations are amended by adding the following after section 45:
Hydrocarbon Gas Destruction
Hydrocarbon gas destruction equipment
46 (1) Hydrocarbon gas destruction equipment that is used at an upstream oil and gas facility must
- (a) have a combustion system that has a pilot flame, an automatic ignition device and an automatic flame failure detection system and that, when hydrocarbon gas is routed to that system,
- (i) maintains the stable combustion of hydrocarbon gas without generating any visible emission, and
- (ii) has a carbon conversion efficiency of at least 98%; and
- (b) be operated and maintained in accordance with the applicable recommendations of its manufacturer.
Exception
(2) Despite paragraph (1)(a), the hydrocarbon gas destruction equipment may be operated with a catalytic oxidation system that has a carbon conversion efficiency of at least 85% if
- (a) the hydrocarbon gas that is routed to the equipment has a pressure of less than 7 kPa and a volume of 60 m3 or less per day;
- (b) hydrocarbon gas is not routed to the equipment when the catalyst temperature is below that recommended by the equipment manufacturer; and
- (c) the catalytic oxidation system is operated and maintained in accordance with the applicable recommendations of its manufacturer.
Flaring
47 The flaring of hydrocarbon gas at an upstream oil and gas facility, other than flaring that is necessary to avoid serious risk to human health or safety arising from an emergency situation, must be supported by an engineering study that concludes that use of the hydrocarbon gas to produce useful heat or energy is not feasible in the circumstances.
Record — Hydrocarbon gas destruction event
48 A record must be made that sets out the following information respecting each hydrocarbon gas destruction event at an upstream oil and gas facility:
- (a) the date, time and duration of the event;
- (b) the location of the event within the facility; and
- (c) if applicable, the engineering study referred to in section 47.
Venting
Venting prohibited
49 (1) Hydrocarbon gas must not be vented from an upstream oil and gas facility.
Exceptions
(2) Despite subsection (1), hydrocarbon gas may be vented from an upstream oil and gas facility if
- (a) it is vented as part of planned equipment maintenance or a planned temporary depressurization of equipment or a pipeline and measures are taken to minimize the quantity of hydrocarbon gas that is vented;
- (b) it is necessary to avoid serious risk to human health or safety arising from an emergency situation;
- (c) the heating value of the hydrocarbon gas or its flow rate are insufficient to sustain stable combustion of the gas by hydrocarbon gas destruction equipment; or
- (d) the use of hydrocarbon gas destruction equipment or hydrocarbon gas conservation equipment would prolong an interruption of the hydrocarbon gas supply to the public.
Connection of equipment components
(3) Every equipment component at an upstream oil and gas facility must be connected to hydrocarbon gas conservation equipment or hydrocarbon gas destruction equipment.
Record — venting activity
50 A record must be made that sets out the following information respecting each instance in which hydrocarbon gas is vented at an upstream oil and gas facility:
- (a) the date, time and duration of the venting;
- (b) the location of the venting within the facility;
- (c) the flow rate of the vented hydrocarbon gas, expressed in kg/h, under standard conditions;
- (d) a description of the circumstances leading up to the venting and the reasons for it; and
- (e) the steps that were taken to minimize the volume of the vented hydrocarbon gas.
PART 2
Continuous Monitoring System
System Requirements
Sensors and other equipment
51 (1) A continuous monitoring system that is used at an upstream oil and gas facility must meet the following requirements:
- (a) its sensors and other equipment are placed at locations within the facility that, under standard conditions, provide a 90% or greater probability of detecting hydrocarbon gas emissions at the facility that have a total flow rate of 1 kg/h or more;
- (b) its sensors provide readings
- (i) in the case of a Type 1 facility, at least once every 15 minutes, and
- (ii) in the case of a Type 2 facility, at least once every 12 hours; and
- (c) it is equipped with an alarm that is triggered when the total flow rate of hydrocarbon gas emissions detected at the facility is 1 kg/h or more.
Calibration
(2) All sensors and other equipment that constitute a continuous monitoring system must be calibrated in accordance with the recommendations of their manufacturer such that their measurements have a maximum margin of error of ± 20%.
System Operation
Notice before use
52 (1) Before a continuous monitoring system is used to detect hydrocarbon gas emissions at an upstream oil and gas facility, the operator must provide the Minister with a written notice that specifies the day on which use of the system is to begin at that facility. The notice must be provided to the Minister at least 60 days before the day specified in the notice.
Information required
(2) The notice must set out the following information:
- (a) the name and location of the upstream oil and gas facility;
- (b) a description of the sensors and other equipment that will constitute the continuous monitoring system;
- (c) an attestation, signed and dated by an engineer who is authorized to practice engineering under the laws of the province in which the facility is located, indicating that the continuous monitoring system that is to be used at the facility meets the requirements set out in section 51; and
- (d) the name, address and contact information of the engineer who provided the attestation.
Notice of discontinuance
53 Before the use of a continuous monitoring system at an upstream oil and gas facility is discontinued, the operator must provide the Minister with a written notice that specifies the day on which use of the system is to be discontinued at that facility. The notice must be provided to the Minister at least 60 days before the day specified in the notice.
Continuous operation
53.1 (1) A continuous monitoring system must be operating at all times, except for any period of time during which all or part of the system is undergoing preventive maintenance.
Preventive maintenance
(2) Preventive maintenance referred to in subsection (1) must not be performed during any period of time in which an emission of hydrocarbon gas is planned or expected to occur at an upstream oil and gas facility.
Inspection
Annual inspection
53.2 (1) If a continuous monitoring system is used at an upstream oil and gas facility, an annual inspection for hydrocarbon gas emissions at the facility must be conducted by an auditor once per year, with no less than 180 days having elapsed since the date of the last annual inspection.
Exception
(2) However, an annual inspection is not required to be conducted at the upstream oil and gas facility in any year in which an annual inspection is conducted at the facility under subsection 8.13(1).
Methodology
(3) An annual inspection must be conducted using methods that, under standard conditions, provide a 90% or greater probability of detecting hydrocarbon gas emissions at the facility that have a total flow rate of 10 kg/h or more.
Record — annual inspection
(4) A record must be made that sets out the following information respecting each annual inspection:
- (a) its date and time;
- (b) the name and contact information of the auditor who conducted the inspection, along with the name and business address of their employer;
- (c) a description of the methodology and equipment used;
- (d) information respecting the calibration of each instrument used;
- (e) whether hydrocarbon gas emissions were detected; and
- (f) if hydrocarbon gas emissions were detected,
- (i) their total flow rate, in kg/h,
- (ii) the unique identifier, if any, assigned to those emissions by the operator, and
- (iii) a list of the steps that were taken to reduce those emissions.
Emissions
Period for emission reduction
53.3 (1) If a continuous monitoring system is used at an upstream oil and gas facility and the total flow rate of hydrocarbon gas emissions detected at the facility is 1 kg/h or more, the total flow rate must be reduced to less than 1 kg/h as soon as feasible, but in any case, by no later than
- (a) if the total flow rate is 1 kg/h or more but less than 10 kg/h, 30 days after the day on which the emissions are detected;
- (b) if the total flow rate is 10 kg/h or more but less than 100 kg/h, seven days after the day on which the emissions are detected; and
- (c) if the total flow rate is 100 kg/h or more, 24 hours after the emissions are detected.
Analysis required
(2) An analysis must be conducted in respect of each emission event in which the total flow rate of the hydrocarbon gas emissions detected at the upstream oil and gas facility is 10 kg/h or more.
Record — system and emissions
(3) A record must be made that sets out the following information:
- (a) the date, time and duration of each instance when the continuous monitoring system is not in operation;
- (b) for each instance when the total flow rate of hydrocarbon gas emissions at the upstream oil and gas facility was 1 kg/h or more,
- (i) the maximum total flow rate of the emissions, in kg/h,
- (ii) the date and time when the emissions were detected,
- (iii) the date and time when the total flow rate of the emissions was reduced to less than 1 kg/h,
- (iv) a list of the steps that were taken to reduce the total flow rate of the emissions, and
- (v) the period of time, if any, during which the facility was shut down; and
- (c) the results of each analysis conducted under subsection (2).
12 Subsections 54(1) and (2) of the Regulations are replaced by the following:
Registration report
54 (1) An upstream oil and gas facility must be registered by providing the Minister with a registration report for the facility that contains the information set out in Schedule 3.
Date of registration
(2) The facility must be registered not later than 120 days after the later of January 1, 2027 and the day on which operations at the facility begin.
13 The Regulations are amended by adding the following after section 55:
Supplementary Notice
Information required
55.1 If an upstream oil and gas facility is registered in accordance with subsection 54(1) before the day on which this section comes into force, a supplementary notice must be provided to the Minister that contains the information referred to in sections 7 and 8 of Schedule 3.
14 Schedule 1 to the Regulations is amended by replacing the references after the heading “SCHEDULE 1” with the following:
(Subsections 8.17(2) and (3))
15 Schedule 2 to the Regulations is repealed.
16 (1) Schedule 3 to the Regulations is amended by replacing the references after the heading “SCHEDULE 3” with the following:
(Subsections 54(1) and (3) and section 55.1)
(2) Schedule 3 to the Regulations is amended by adding the following after section 6:
7 Identification of the facility as either a Type 1 facility or a Type 2 facility.
8 For each of the years 2024 to 2026, the combined volume of hydrocarbon gas that was produced or received by the facility in that year, expressed in standard m3, if any.
Consequential Amendments to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999)
| Item | Column 2 Provisions |
|---|---|
| 30 |
|
(2) Paragraphs 30(e) to (q) of the schedule to the Regulations are repealed.
(3) Paragraphs 30(r) to (u) of the schedule to the Regulations are repealed.
(4) Paragraphs 30(v) to (z) of the schedule to the Regulations are repealed.
(5) Paragraphs 30(z.1) to (z.7) of the schedule to the Regulations are repealed.
| Item | Column 2 Provisions |
|---|---|
| 30 |
|
Coming into Force
18 (1) Subsection 1(1), sections 4 and 5, subsections 6(2) and 7(2), sections 8, 10 and 15 and subsections 17(2) and (4) come into force on January 1, 2030.
(2) Subsections 1(2), (4) and (5) and 2(2), section 3, subsections 6(1) and 7(1), section 9, subsection 11(2), sections 12 to 14 and 16 and subsections 17(1), (3) and (6) come into force on January 1, 2027.
(3) Subsection 1(3) comes into force on the day on which these Regulations are registered.
(4) Subsections 2(1), 11(1) and 17(5) come into force on the day on which the Canada-Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations come into force, but if these Regulations are registered after that day, those subsections come into force on the day on which these Regulations are registered.
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