Canada Gazette, Part I, Volume 158, Number 45: Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations

November 9, 2024

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

There is an urgent need to address climate change and move towards a low-carbon economy. Canada is committed to doing its part to reduce emissions of greenhouse gases (GHGs), the major contributor to climate change. Signatories to the Paris Agreement, including Canada, have collectively pledged to reduce GHG emissions to limit the global average temperature increase to below 2 °C, and to pursue efforts to limit it to 1.5 °C to reduce the severity of climate impacts. Under the Paris Agreement, Canada committed to reduce GHG emissions by 40% to 45% below 2005 levels by 2030 and has since committed to achieving net-zero emissions by 2050 under the Canadian Net-Zero Emissions Accountability Act. To deliver on these climate objectives, the Government of Canada published the 2030 Emissions Reduction Plan (ERP). This plan lays out the steps the Government of Canada has taken and intends to take to reduce GHG emissions across all sectors of the economy. These include capping GHG emissions from the oil and gas sector. According to the 2024 National Inventory Report (NIR), the oil and gas sector was responsible for 31% of Canada’s GHG emissions in 2022, accounting for 217 megatonnes (Mt) of carbon dioxide equivalent (CO₂e). This makes the sector the largest GHG emitter in Canada. Therefore, decreasing emissions in the oil and gas sector by introducing a regulatory emissions cap is necessary for the sector to do its share to tackle climate change and reach the Government of Canada’s GHG emissions reduction targets.

Background

Oil and gas sector

The oil and gas sector can be grouped into three segments: upstream (including conventional onshore and offshore oil production, oil sands production, upgrading, and natural gas production and processing); midstream (oil, natural gas and carbon dioxide [CO₂] transmission pipelines); and downstream (petroleum refining and natural gas distribution). Upstream oil and gas production is concentrated in Alberta (AB), Saskatchewan (SK), British Columbia (BC), and Newfoundland and Labrador (NL). There are also oil and gas wells in Ontario (ON), Manitoba (MB), the Northwest Territories (NWT), and New Brunswick (NB). Midstream infrastructure and downstream petroleum refineries, distribution terminals or bulk storage facilities are in every province and territory. Within the upstream, midstream, and downstream segments, there is a myriad of operators, ranging from small exploration and production firms to large integrated oil and gas companies.

The oil and gas sector is a major contributor to Canada’s economy. In 2022, it generated $187B in gross domestic product (GDP) and accounted for 30% of Canada’s exports (valued at $217B).^{footnote 1} The sector is also a major employer across the country, directly employing 171 800 people in 2022.^{footnote 1}

GHG emissions from the oil and gas sector

The oil and gas sector accounts for a significant portion of Canada’s GHG emissions. The upstream sector accounts for about 26% of Canada’s emissions and about 85% of the entire oil and gas sector’s total emissions. GHGs are emitted from a number of sources at upstream oil and gas facilities, including stationary fuel combustion, venting, flaring, leakage, on-site transportation, industrial processes, industrial product use, waste and wastewater.

The GHGs emitted from Canada’s oil and gas sector include carbon dioxide, methane (CH₄), and nitrous oxide (N₂O). Carbon dioxide accounts for the majority of GHG emissions from the sector, while methane accounts for the majority of the remaining GHG emissions from the sector. The oil and gas sector is the largest source of methane emissions in Canada. Methane is a potent GHG and also a smog precursor. The bulk of methane emissions from Canada’s oil and gas sector are from conventional oil production and natural gas production and processing.

Key decarbonization options for the oil and gas sector include electrification to reduce GHG emissions from the combustion of fossil fuels throughout the oil and gas sector; the use of solvents to dilute bitumen and reduce the need to produce and use steam for in situ oil sands production; fuel switching to low-carbon or renewable fuels such as hydrogen; energy efficiency measures and other process improvements; methane abatement; and CCUS.

Section 93 of the Canadian Environmental Protection Act, 1999 (CEPA) provides the authority to make regulations with respect to substances that are specified on the list of toxic substances in Schedule 1. The GHGs covered by the proposed Regulations are those listed in items 65 to 70 of Part 2 of Schedule 1 of CEPA.

Measures to reduce emissions from the oil and gas sector

A number of federal and provincial regulatory and supporting measures to reduce oil and gas sector emissions are in place or under development. These include multiple programs to support investments in decarbonization activities and technologies, the proposed Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) [the proposed Methane Regulations], federal and provincial carbon pricing systems, the Clean Fuel Regulations, as well as the proposed Clean Electricity Regulations.

These measures are expected to help reduce the oil and gas sector’s GHG emissions; however, they do not guarantee an emissions level across the entire oil and gas sector. The proposed Regulations would ensure the oil and gas sector lowers absolute emissions at a pace and scale necessary to ensure that the oil and gas sector plays a role in achieving Canada’s economy-wide climate commitments and support the transition to net-zero.

Commitment to cap emissions from the oil and gas sector

At the 2021 United Nations Climate Change Conference (COP26), the Prime Minister committed to cap and cut GHG emissions from the oil and gas sector at a pace and scale necessary to ensure the sector makes a meaningful contribution to Canada’s 2030 Nationally Determined Contribution of 40–45% below 2005 emissions levels by 2030 and to achieve net-zero emissions by 2050. The commitment to cap emissions from the oil and gas sector was included in the ERP published in March 2022. In July 2022, the Government published a discussion document titled Options to Cap and Cut Oil and Gas Sector Greenhouse Gas Emissions to Achieve 2030 Goals and Net-Zero by 2050, which sought input on two options to cap GHG emissions from the sector: the development of a new cap-and-trade system under CEPA; or the modification of existing carbon pollution pricing. This document proposed that the emissions cap cover the upstream oil and gas sector and sought feedback on whether to also cover natural gas transmission pipelines and petroleum refineries.

Building on the feedback on the discussion document, the Government published the Regulatory Framework to Cap Oil and Gas Sector Greenhouse Gas Emissions (the Regulatory Framework) in December 2023. This confirmed cap-and-trade as the instrument through which the emissions cap would be implemented, and proposed a number of design features, notably scope of application (upstream oil and gas and liquified natural gas [LNG]), the approach to determining the emissions cap levels, and the compliance flexibility options that would be made available. Interested parties were invited to submit formal comments on the Regulatory Framework. The Regulatory Framework indicated that the proposed Regulations would be published in 2024 and final regulations would target 2025, with the first reporting obligations starting as early as 2026 and full system requirements phased in between 2026 and 2030.

Objective

The objective of the proposed Regulations is to reduce GHG emissions from certain activities carried out in the oil and gas sector. As proposed in the Regulatory Framework, the oil and gas emissions cap-and-trade system is designed to ensure that the sector reduces GHG emissions and is on a path to net-zero, thereby helping Canada to achieve its economy-wide GHG emissions reduction targets. It would also provide some flexibility to enable the sector to respond to changes in global demand and in a manner that will enhance the competitiveness of the sector moving forward in a world that complies with existing commitments under the Paris Agreement.

Description

The proposed Regulations would cap emissions from certain activities carried out in the oil and gas sector and would also prohibit GHG emissions (i.e. any substance referred to in any of items 65 to 70 in Part 2 of Schedule 1 to CEPA) from specified industrial activities in the sector unless the operator registers by submitting the required information to the Minister of the Environment (the Minister). Starting in 2030, operators that meet the threshold set out in the proposed Regulations would be prohibited from emitting any GHG from an industrial activity unless they remit sufficient eligible compliance units to cover their GHG emissions. The proposed Regulations define who would have obligations and what those obligations would be, including registration, reporting, and remittance of compliance units, and set out the rules regarding eligible compliance units which include emissions allowances, decarbonization units and Canadian offset credits.

Beginning in 2029, emissions allowances (for 2030) would be distributed free of charge to operators that are covered by the remittance obligation, with the total number of allowances equal to the emissions cap. The distribution would occur annually and would be based on operators’ historical production and the distribution rate for the applicable industrial activity, pro-rated such that the emissions cap is fully distributed each year.

In addition to emissions allowances, operators with remittance obligations would be able to remit a limited quantity of compliance flexibility units (eligible offset credits and decarbonization units). Thirteen months after the end of each of the first and second years of each three-year compliance period, covered operators would have to remit an emissions allowance or other eligible compliance unit for each tonne of 30% of the GHGs they emitted during those years (expressed as tonnes of CO₂e). Thirteen months after the end of the third year, they would have to remit an emissions allowance or other eligible compliance unit for each tonne of GHGs that they emitted during the full three-year compliance period, net of what was remitted for the first and second years.

In this document, operators that are subject to a remittance obligation are referred to as “covered operators.” An operator whose cumulative production in a calendar year is equal to or above the annual threshold of 365 000 barrels of oil equivalent would become a covered operator and would remain a covered operator until its total production was less than half the annual threshold for four consecutive years. The emissions cap, combined with the limited access to compliance flexibility, would ensure GHG emissions from covered operators do not exceed the legal upper bound.

Industrial activities

The proposed Regulations would apply to all operators of upstream oil and gas facilities and LNG facilities that carry out the following industrial activities:

• Bitumen and other crude oil production, other than bitumen extracted through thermal in situ recovery or from surface mining, including
  • extraction, processing and production of light crude oil (having a density of less than 920 kg/m³ at 15 °C),
  • extraction, processing and production of bitumen or other heavy crude oil (having a density greater than or equal to 920 kg/m³ at 15 °C);
• Thermal in situ recovery of bitumen from oil sand deposits;
• Surface mining of oil sands and extraction of bitumen;
• Upgrading of bitumen or heavy oil to produce synthetic crude oil;
• Extraction of natural gas and natural gas condensates;
• Compression of natural gas between production wells, natural gas processing facilities or re-injection sites;
• Processing of natural gas or natural gas condensates into marketable natural gas and natural gas liquids; and
• Production of LNG.

Registration

The obligations under the proposed Regulations would be at the operator level. Operators of all existing facilities would be required to register prior to January 1, 2026. From January 1, 2026, operators would be prohibited from emitting any GHGs from their industrial activities unless they have first registered in accordance with the proposed Regulations.

Other obligations

Operators would be required to provide information through annual reports and meet remittance obligations for their industrial activities if these obligations apply to them. Because the threshold to be covered is on an operator basis, any obligations that apply to an operator, such as reporting and remittance, would apply to all industrial activities in all facilities they operate, regardless of facility size. Under the proposed Regulations, however, multiple facilities would be deemed to be a single facility (deemed facility) for the purposes of reporting, remittance, and other regulatory obligations if they

• have the same operator or an operator in common;
• are in the same province or territory; and
• are not required to report under a notice published by the Minister pursuant to subsection 46(1) of CEPA.

Where a facility’s operator changes during a calendar year, both operators would be responsible for meeting the requirements of the proposed Regulations, including reporting on emissions and remitting compliance units, for the part of the year for which they were responsible for the facility.

Reporting

Operators would also be required to report prescribed information to the Minister regarding their GHG emissions. If their total monthly cumulative production during any of the months between January 1, 2024, and July 1, 2025, were equal to or above a threshold of 30 000 barrels of oil equivalent, or if any of their facilities were required to report their GHG emissions in 2024 under a notice published by the Minister pursuant to subsection 46(1) of CEPA, operators would be required to submit their first reports on emissions by June 1, 2027, for the calendar year 2026. Operators that do not meet either of these criteria would be required to submit their first reports as of June 1, 2029, for the calendar year 2028. After first reporting, all operators would be required to continue to report for each calendar year in which GHGs are emitted as a result of an industrial activity that is carried out at their facility.

The proposed Regulations would require operators to provide two types of reports in addition to the initial registration:

• Annual reports: one report for each facility, as defined in the proposed Regulations (i.e. one report for each deemed facility and one for each other facility).
• Report on cumulative production: one report that includes the operator’s cumulative production across all facilities and information on the facilities operated by the operator in the relevant calendar year.

Annual reports would include quantity of production by specified industrial activity and the quantity of GHGs attributed to the facility (“attributed GHGs”). Operators would be required to have their annual reports verified by an accredited third party and to keep records in Canada. Should any errors or omissions be identified in their annual reports within five years of submission, operators would also be responsible for correcting them.

Emissions cap

The proposed Regulations would set the emissions cap for each year of the first compliance period at 27% below emissions levels reported for 2026 (i.e. only emissions from operators that are required to report in 2027 for 2026). That level is estimated to align with 35% below 2019 emissions levels, but would ensure that the actual cap reflects reported emissions and accounts for changes in production and emissions in the near future.

The sector would be permitted to emit above this level through the use of limited compliance flexibility mechanisms. If the use of compliance flexibilities were maximized, the sector could emit up to a legal upper bound estimated to be 19% below 2019 levels.

The emissions cap would remain at this level for subsequent compliance periods until regulatory amendments are made.

Attributed GHGs

Attributed GHGs are the amount of GHGs attributed to a facility that is reported in an annual report or, if applicable, that is reported in a corrected report or determined by the Minister. The calculation of attributed GHGs would need to be done in accordance with quantification methods set out in the document entitled Quantification Methods for the Oil and Gas Sector Greenhouse Gases Emissions Cap Regulations. This calculation would take into consideration the emissions from all emissions sources at the facility, with the exception of electricity generation, carbon dioxide (CO₂) that is permanently stored, and indirect emissions, meaning emissions attributed to thermal energy and hydrogen consumed (produced on-site or supplied to the facility). Operators would not be responsible for emissions attributed to the production of thermal energy and hydrogen that is transferred from the facility.

Compliance periods and remittance obligations

Compliance periods would cover three calendar years. The first compliance period would begin on January 1, 2030, and end on December 31, 2032. A covered operator would be subject to remittance obligations (i.e. would be required to remit one compliance unit for each CO₂e tonne of their facility’s attributed GHGs during a compliance period) by the January 31 that is 13 months after the end of the compliance period. Covered operators would also be subject to an interim requirement to remit enough compliance units to cover at least 30% of their attributed GHGs during the first and second years of a compliance period no later than the January 31 that is 13 months after the end of the year of the attributed GHGs.

New facilities projected to emit 10 000 tonnes of CO₂e or more in any of the facility’s first three years of operation would be subject to reporting requirements for the first four calendar years of their operation. The requirement to comply with remittance obligations would apply in the fifth calendar year that follows the year in which the operations start. For example, for a new facility that begins operating in 2029, the operator would submit reports annually for each calendar year starting with the 2029 calendar year. The first report would be due June 1 of 2030, for 2029. A report would then be submitted annually. In 2033, they would submit their annual report for the 2032 calendar year and receive emissions allowances for the 2034 calendar year. They would be required to meet the remittance obligation beginning January 1, 2034.

Emissions allowances

The Minister would distribute emissions allowances to covered operators on an annual basis up to the level of the emissions cap. Each emissions allowance would be distributed the year before the first calendar year in which they may be used to meet a remittance obligation (e.g. in 2029 for the 2030 calendar year). Allowances would be distributed to covered operators based on the distribution rate set out in the proposed Regulations for the applicable industrial activity (allowance per unit of production) and the three-year rolling average of historical production for each facility (e.g. 2026–2028 production levels would be used to allocate allowances in 2029 for the 2030 calendar year), taking into account the total allowances that can be distributed under the emissions cap. Allowances would be pro-rated across all operators in respect of a facility subject to remittance obligations to ensure that the total number of allowances distributed is equal to the emissions cap. Pro-rating would be based on the sum of the non–pro-rated number of allowances for all facilities divided by the emissions cap.

Compliance flexibility

In addition to emissions allowances, covered operators would have the option to remit eligible Canadian offset credits or decarbonization units (obtained by making contributions to a decarbonization program) to cover up to 20% of their remittance obligation. Covered operators would be able to remit any combination of Canadian offset credits or decarbonization units to meet their remittance obligation, up to specified limits. Up to 20% of a covered operator’s obligation within a compliance period could be satisfied with offset credits, and up to 10% of a covered operator’s obligation within a compliance period could be satisfied with decarbonization units obtained through contributions to a decarbonization program at $50/tonne of CO₂e. Decarbonization units would not be tradable between operators or bankable to subsequent compliance periods. The proposed Regulations would require that contributions to the decarbonization program be used to fund projects that support the reduction of GHG emissions from the oil and gas sector.

The total offset credits and decarbonization units remitted for a facility cannot exceed 20% of its total obligation within a compliance period. For example, if 5% of a facility’s remittance obligation is met with decarbonization units, the covered operator would be limited to a maximum of 15% use of offset credits for that facility.

Only offset credits issued under the Canadian Greenhouse Gas Offset Credit System Regulations and provincial offset units or credits recognized for use under the federal OBPS Regulations associated with the reduction or removal of GHG emissions that occurred no more than five calendar years before the compliance period for which the credit is remitted would be considered eligible offset compliance units under the proposed Regulations.

Cross-recognition of Canadian offset credits

Covered operators would be permitted to use eligible offset credits to meet coinciding obligations under recognized carbon pricing systems and the proposed Regulations if the following conditions are met:

• The offset credits are used for compliance under the carbon pricing system for a year within the three-year compliance period for which they are remitted under the proposed Regulations;
• The offset credits are used under the carbon pricing system in relation to the emissions from an industrial activity carried out by the operator in the same province or territory as the operator’s facilities for which they are remitted under the proposed Regulations; and
• The offset credits are used to fulfill a requirement under the carbon pricing system other than for a requirement that relates to an extraordinary situation, such as to replace a cancelled credit, or as compensation for non-compliance with a requirement.

The Department of the Environment (the Department) would establish a list of carbon pricing systems where cross-recognition is authorized. Proposed amendments to the OBPS Regulations would operationalize this approach where the federal Output-Based Pricing System (OBPS) applies. Operationalization of cross-recognition in other provinces and territories would depend on them making any necessary adjustments to their carbon pricing systems and entering into a recognition agreement between the Minister and the province.

The proposed conditions for cross-recognition would prevent double claiming, which is a form of double counting where an offset credit is used by more than one party to meet multiple and different obligations. Double claiming would be prevented because only one operator could use an eligible offset credit to meet their obligations associated with the GHG emissions from undertaking a consistent set of activities under a carbon pricing system and the proposed Regulations. Offset credits represent actual reductions and removals of GHG emissions. Their cross-recognition under a carbon pricing system and the proposed Regulations would treat these out-of-sector emission reductions consistently with in-sector abatement, which may assist an operator in meeting their obligations under a carbon pricing system and the proposed Regulations.

Consequential amendments

Consequential amendments would be made to the Output-Based Pricing System Regulations (OBPS Regulations) to modify provisions related to the recognition of provincial offset credits and their use under the federal OBPS. This would enable the recognition for use of certain offset credits under both the proposed Regulations and the federal OBPS.

Consequential amendments to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) [the Designation Regulations] would also be made to list certain provisions of the proposed Regulations in the schedule to the Designation Regulations. When designated provisions are contravened and upon conviction, the offender would be subject to minimum fines and higher maximum fines. Offences chosen for designation are those involving direct harm or risk of harm to the environment, or obstruction of authority.

Regulatory development

Consultation

The Government has consulted with provincial and territorial governments, Indigenous partners, representatives from industry and environmental non-governmental organizations (ENGOs), academics and experts, other government departments, and the public through bilateral and multilateral meetings, information webinars, and the receipt of formal submissions. Since November 2021, the Department has received over 250 submissions from organizations in response to two publications, held over 114 meetings, and hosted seven public webinars.

Engagement with interested parties

On July 18, 2022, the Department published a discussion document (“Discussion Document”), titled Options to Cap and Cut Oil and Gas Sector Greenhouse Gas Emissions to Achieve 2030 Goals and Net-Zero by 2050, and launched a 90-day public comment period seeking formal input on guiding principles and two regulatory options to cap GHG emissions from the oil and gas sector: (1) a new national GHG emissions cap-and-trade system under CEPA; and (2) modifications to existing carbon pricing systems.

To support engagement and facilitate input, the Department and Natural Resources Canada (NRCan) held a series of information and technical webinars. On December 7, 2023, the Department published the Regulatory Framework to Cap Oil and Gas Sector Greenhouse Gas Emissions (the Regulatory Framework). The Regulatory Framework proposed key aspects of the Government’s approach to establishing an emissions cap. The Government sought substantive responses to the proposed policy details in the Regulatory Framework and received 107 formal responses.

In addition to technical webinars, the Department and NRCan officials organized targeted bilateral and multilateral meetings to engage interested parties on the oil and gas emissions cap.

Public email campaigns

In response to both the 2022 Discussion Document and the Regulatory Framework, the Government received over 60 000 emails as part of email campaigns from citizens providing non-technical input regarding the Government’s commitment to establish an emissions cap. Campaigns in support (approximately 40 000 emails) called for more rapid and stringent application. Campaigns that did not support (approximately 20 000 emails) did so primarily on the basis of concerns about economic impacts. The 429 public submissions compiled and sent by an ENGO in response to the Discussion Document were largely supportive of ambitious actions to reduce oil and gas sector emissions.

Interested parties’ response to the 2023 Regulatory Framework

Feedback on the Regulatory Framework came primarily from oil and gas companies, other industry stakeholders, and ENGOs and other non-governmental organizations. Three provinces and a territory (Alberta, Saskatchewan, Newfoundland and Labrador and the Northwest Territories) and four Indigenous groups also provided input. In their comments, oil and gas-producing provinces and industry raised questions about the authority and rationale for an emissions cap, and raised economic and energy security considerations, and concerns about the stringency of the measure rather than technical feedback to inform the development of key design features. ENGOs, while supportive of the concept of an emissions cap, expressed concerns about some proposed aspects of the potential design. Indigenous groups presented a range of views, with many seeking protections for Indigenous rights and meaningful engagement.

Overview of changes from approach outlined in the Regulatory Framework

The proposed Regulations include some changes from the approach proposed in the Regulatory Framework. These reflect a review of the feedback provided by governments, stakeholders, and rights holders, as well as an additional internal analysis.

Approach to operator and facility coverage

The Regulatory Framework proposed exploring methods for defining and regulating smaller emitting facilities under the emissions cap-and-trade regulations.

Most industry stakeholders advocated for the exclusion of small oil and gas facilities from the emissions cap, citing concerns about adverse impacts to competitiveness, an increased administrative burden, the ability to participate in an emissions trading system, and potential impacts on remote production. ENGOs warned against creating incentives to bundle or unbundle operations based on the chosen threshold.

Given the structure of the conventional oil and gas sector, in particular where operators may control anywhere from one to hundreds of very small facilities, the proposed Regulations would apply to operators rather than facilities. Operators would be responsible for complying with the proposed Regulations for all facilities under their control, and all operators, regardless of size, would be required to register and meet all reporting obligations, with smaller operators initially exempt from reporting until 2028 to provide them with additional time to understand the details of reporting obligations and prepare to collect the required information. Reported information is critical to the functioning of the proposed Regulations. It provides data needed to monitor the effectiveness of the proposed Regulations in reducing emissions. For covered operators, the information is the basis for determining allowance allocations and compliance obligations. For other operators, the information provides the basis for allowance allocation should an operator become a covered operator in the future.

To determine which operators would be covered under the emissions cap — i.e. subject to remittance obligations and eligible to receive allowances — the proposed Regulations would apply a threshold. The threshold would be based on an operator’s cumulative production across all covered industrial activities rather than setting facility-level thresholds. Operators track facility production as part of regular business practices but do not necessarily quantify emissions from smaller facilities. Setting the threshold in units of production at a level that is expected to generally result in emissions of about 10 kilotonnes (kt) of GHG emissions for light oil facilities would ensure high levels of coverage of sector emissions while minimizing the regulatory burden on smaller businesses.

To further address these issues, the proposed Regulations would deem multiple facilities to be a single facility for the purpose of compliance where each facility has the same operator, is in the same province, and for which a report to the Greenhouse Gas Reporting Program is not required. Facilities for which a report to the Greenhouse Gas Reporting Program is required (currently those with annual emissions exceeding 10 kt of CO₂e) would be treated as individual facilities whose operators have separate obligations, while for deemed facilities, operators have combined obligations under the proposed Regulations. This approach is expected to reduce the administrative burden of the proposed Regulations.

Approach to setting the emissions cap and the legal upper bound

The Regulatory Framework proposed two key values: (1) the emissions cap level, which is equivalent to the total emission allowances issued by the Government for a given year; and (2) the legal upper bound, which is the maximum emissions the sector would be allowed to emit that year, composed of the total number of emission allowances issued plus the maximum allowable quantity of other eligible compliance units.

The Regulatory Framework proposed that the legal upper bound in 2030 be set at a level that assumes that covered sources achieve technically achievable emission reductions by 2030 for production levels aligned with the Canada Energy Regulator (CER) Canada Net-Zero (CNZ) scenario. It also proposed that the 2030 emissions cap be set at a level slightly below what emissions would be if covered sources achieved technically achievable emission reductions by 2030 and production was at 2019 levels.

Stakeholders supported a clear and transparent approach to setting and reviewing the post-2030 emissions cap trajectory. Producers highlighted the short timeline to achieve significant reductions by 2030 and stated that a clear and transparent trajectory is important for de-risking investment. A variety of academic and ENGO perspectives were shared on how the emissions cap should be determined post-2030, but in general, the expectation was that it should align with the 2050 Canada Net-Zero goals.

The proposed Regulations would establish the emissions cap at 27% below 2026 reported emissions from covered operators, which, when combined with access to compliance flexibility, creates a legal upper bound on emissions that is expected to allow for some production growth and assumes the sector deploys a range of technically achievable emissions reductions during the first compliance period. The emissions cap for the first compliance period would remain in place for subsequent compliance periods, until there are amendments to the proposed Regulations to reset the cap.

The Government will monitor developments in the oil and gas sector on an ongoing basis and will take action as appropriate to ensure the full suite of policies and measures supporting decarbonization efforts reflect up-to-date information.

The proposed Regulations are designed to account for changes in production and emissions in the near future by setting the emissions cap based on 2026 reported data, rather than relying on historic data and projections. This will provide sufficient time to set the actual emissions cap level and distribute allowances before the first compliance period begins in 2030.

A review of the proposed Regulations will conclude within five years after they come into force. It will include a review of global market dynamics, decarbonization technologies, technically achievable reductions and the access the sector has to compliance flexibilities. The review will be used to inform potential amendments to the emissions cap for the post-2032 period.

Approach to allocation of emission allowances

The Regulatory Framework proposed allocating allowances free of charge based on a baseline production level and a free allocation rate for a given product or activity, and that allowances would be pro-rated to ensure total allowances do not exceed the emissions cap.

Provinces, territories and oil and gas industry stakeholders advocated against broad sector-based standards, highlighting that diverse factors influence the emissions intensity of oil and gas production across the country. Stakeholders generally supported an approach that rewards better emissions intensity performance, while some raised concerns that regions with higher emissions intensity for reasons beyond operator control and fewer abatement opportunities may be disadvantaged. Non-oil and gas industry stakeholders and one Indigenous group favored an approach that recognizes early movers and rewards best performers, with a variety of suggested approaches, ranging from accounting for trade exposure to uniform distribution. The vast majority of ENGOs advocated for auctioning emissions allowances as opposed to free allocation. ENGOs recommended that, if free allocation is the chosen approach, it should recognize better emissions performance. Although not included in the proposed Regulations, auctioning of allowances, either in combination with free allocation or as a means to distribute all allowances, may be considered during the regulatory review, for introduction in later compliance periods.

The proposed Regulations would allocate allowances to covered operators using distribution rates specified in a schedule for each industrial activity. Distribution rates would be set on a per unit of production basis rather than based on absolute emissions in order to incentivize emissions intensity improvements and reward lower emissions intensity production for a given activity. Distribution rates would be set based on estimates of 2019 emissions intensities for each activity, with the same percentage reduction applied to all activities. Care was taken during the setting of the legal upper bound to ensure the overall level of reductions would be technically achievable assuming production grows consistent with the Canada Net-Zero forecast, with different levels of reductions coming from different sub-sectors.

By allocating allowances based on a uniform rate, rather than based on estimates of technically achievable reductions at the sub-sector and geographical level, the emissions cap design encourages sub-sectors to reduce emissions in the most economically efficient manner, while ensuring the overall reductions required to maintain the legal upper bound are technically achievable. The percentage reduction that would be applied is an estimate of the expected reductions needed by the sector to achieve the proposed emissions cap level, given assumptions around increases in production. The rates would be applied to a three-year rolling average of historical facility production. This approach would enhance transparency around expected allocation levels, prioritize certainty, and ensure that operators know their free allocations prior to each year, while providing a relative benefit to early movers. Free allocations would be pro-rated so that the number of allocated allowances equals the emissions cap.

Access to compliance flexibilities

The Regulatory Framework proposed that, in addition to emissions trading, multi-year compliance periods, and credit banking, covered operators would have the option to remit domestic offset credits or make contributions to a decarbonization funding program to cover a limited portion of their GHG emissions.

Provinces, territories, and oil and gas industry stakeholders broadly supported an approach that provides compliance flexibility mechanisms, requesting that access either be maintained or increased over time. Several submissions expressed skepticism that sufficient offset credits would be available by 2030, and some suggested the expansion of recognized offsets would be required to meet demand. One Indigenous group preferred in-sector reductions to maintain the co-benefit of reducing air pollution. ENGOs generally argued that compliance flexibilities should be removed or minimized and then phased out aggressively.

Compliance flexibility mechanisms can play an important role in cap-and-trade systems. Key decarbonization solutions for the sector, including CCUS, require significant time to deploy. Flexibility mechanisms give operators of facilities more time to optimize investments in GHG emissions reductions. They can also improve cost certainty, and the use of robust domestic offset credits can provide a means of meeting a more ambitious emissions cap by incentivizing out-of-sector emissions reductions that would not otherwise occur. The proposed Regulations would allow covered operators to use compliance flexibility mechanisms to account for up to an overall limit of 20% of the attributed GHGs of their facilities. Compliance flexibilities would include contributions to a decarbonization program to a maximum of 10% of their attributed GHGs and the use of offset credits up to the full 20%.

When an operator takes in-sector abatement actions at a facility that is covered both by the proposed Regulations and carbon pricing system, that reduction in emissions could contribute to reducing the operator’s obligation under both systems. To treat the use of offset credits similarly, the proposed Regulations would allow, where authorized by the relevant federal or provincial carbon pricing systems, eligible domestic offset credits used to meet a coinciding carbon pricing obligation to be recognized towards obligations under the proposed Regulations, provided that the credit compensates for emissions by the same operator, in the same jurisdiction, for a year included in the compliance period, and obligations cover the same activities.

Use of contributions to the decarbonization program

The Regulatory Framework proposed that proceeds from the decarbonization program be used to support oil and gas sector decarbonization and help facilities that receive support from the program to decrease their emissions.

Oil and gas industry stakeholders supported returning contributions to a decarbonization program to the sector. Indigenous organizations had varying views on how contributions to the decarbonization program should be used, including support for in-sector abatement, renewable energy, transition away from fossil fuels, and funding Indigenous organizations to undertake projects related to GHG reduction and removals. ENGO suggestions included uses from supporting the sector’s energy transition to mitigating climate impacts in communities.

The proposed Regulations specify that contributions to the decarbonization program would support the reduction of GHG emissions in the oil and gas sector in Canada.

In response to the Regulatory Framework, Indigenous groups suggested that contributions to the decarbonization program be used to support phasing out of fossil fuels or to support Indigenous groups that have innovative emissions reductions solutions. Industry comments generally supported returning contributions to the oil and gas sector to support decarbonization. Some industry members advocated for contributions to be returned directly to those that made them, with a requirement that they be used for decarbonization. ENGOs did not support inclusion of a decarbonization program, but, if implemented, they generally supported contributions being used to support energy transition and mitigating climate impacts in communities. Some ENGOs indicated that they did not support proceeds being used to support CCUS projects.

The Department considered other uses of the proceeds as suggested by stakeholders but determined that supporting decarbonization of the oil and gas sector aligns with the objectives of the policy.

The Government will continue to engage with stakeholders on the approach to administering the decarbonization program.

Use of internationally transferred mitigation outcomes

Article 6 of the Paris Agreement recognizes that countries may cooperate in implementing their climate targets, to enable higher ambition than they could otherwise achieve on their own. An internationally transferred mitigation outcome (ITMO) is an accounting entry that reflects a quantity of GHG mitigation (emissions reductions or removals) that occurs in one country and that is voluntarily authorized and transferred for use toward another country’s climate target or other international mitigation purpose. The Regulatory Framework indicated that the Department was considering allowing ITMOs, in the form of carbon offsets, to be used as a possible compliance option for some portion of emissions that could be covered by domestic offset credits.

Overall, industry was generally supportive of increased access to compliance flexibility. Submissions advocated for prioritizing domestic offsets over ITMOs, and expressed a general skepticism regarding the supply of ITMOs by 2030 given the status of the development of international rules and infrastructure to support this market developing and other potential sources of demand in the market. Indigenous organizations expressed limited support for the use of ITMOs while expressing an overall preference for domestic offset credit use that directly contributes to reducing air pollution in Canada.

The proposed Regulations would not allow for the use of ITMOs as a compliance option; however, the Department intends to continue consulting on the issue, and ITMOs could be included as a compliance option in the final Regulations. Issues to consider before the Regulations are finalized include access to and limitations on the use of ITMOs, eligibility criteria, and necessary policies and infrastructure.

Treatment of emissions from electricity generation

The Regulatory Framework proposed that facilities would be responsible for emissions resulting from the consumption of electricity, whether directly produced by the facility or transferred from a third party. Most provinces and oil and gas industry stakeholders did not support covering emissions from electricity generation, arguing that the emissions intensity of supplied electricity is beyond the control of producers, disadvantaging operators in fossil-fuel heavy jurisdictions, and that coverage under the emissions cap would be duplicative of existing or proposed instruments. Stakeholders also argued that coverage of emissions from electricity would discourage the electrification of operations and the deployment of carbon capture technology. ENGOs and other stakeholders advocated for harmonization across systems, but ENGOs almost unanimously supported coverage of emissions from electricity generation in the proposed Regulations.

The Department notes that several other existing or proposed federal measures already offer incentives or require emissions reductions from electricity generation, including carbon pricing, the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, and the proposed Clean Electricity Regulations. Therefore, emissions from electricity that is produced, regardless of whether it is used on-site or transferred for use outside the facility, as well as emissions associated with electricity supplied to the facility, would be excluded from an operator’s attributed GHGs under the proposed Regulations.

Treatment of other indirect emissions

The Regulatory Framework proposed that facilities would be responsible for emissions resulting from the consumption of thermal energy, and hydrogen, whether directly produced by the facility or transferred from a third party.

Some industry stakeholders and ENGOs expressed support for coverage of other indirect emissions.

Under the proposed Regulations, covered operators would be responsible for emissions attributed to thermal energy and hydrogen consumed (produced on-site or supplied to the facility)​. Covered facilities would not be responsible for emissions attributed to the production of thermal energy and hydrogen that are transferred from the facility. This approach would limit the scope of the proposed Regulations to only emissions associated with the production of oil and gas, while also preventing the movement of those emissions outside the emissions cap.

New facilities

The Regulatory Framework proposed that all new facilities would have to register before emitting GHGs from a covered industrial activity. The Regulatory Framework also indicated that the Department was considering delaying the start of a new facility’s first compliance period until after it reaches a set proportion of its design capacity, or two years after first producing a product, whichever came first. Provinces, territories and industry stakeholders raised concerns that the emissions cap would create barriers for new entrants and were supportive of a delay on compliance obligations and a dedicated reserve of allowances for new entrants. ENGOs did not support a delay in compliance obligations for new facilities. One ENGO and one academic recommended a reserve apportioned from the existing proposed allowances.

The proposed Regulations are not intended to create a regulatory barrier to entry. Operators of new large facilities (projected to emit 10 kt of CO₂e or more annually) would be required to report for the first four calendar years of their operation, but the requirement to remit compliance units equal to their emissions would not apply until the fifth calendar year that follows the year in which the operations start. Operators of new facilities that emit less than 10 kt of CO₂e annually who already operate a deemed facility would include the new facility as part of the deemed facility for reporting and remittance obligations, in the case where the operator is a covered operator, immediately upon starting operation. This would simplify administration and reflect the more rapid compositional changes that can occur with conventional oil and gas extraction.

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 for the proposed Regulations. The assessment examined the geographic scope and subject matter of the proposed Regulations in relation to modern treaties in effect. The assessment did not identify any modern treaty obligations.

There is a statutory obligation pursuant to section 5 of the United Nations Declaration on the Rights of Indigenous Peoples Act (UNDA) to take, in consultation and cooperation with Indigenous peoples, all measures necessary to ensure that existing and new federal laws (statutes and regulations) are consistent with the United Nations Declaration on the Rights of Indigenous Peoples. The Government of Canada has taken a distinctions-based engagement approach, including conducting outreach and facilitating bilateral and multilateral engagement with national Indigenous organizations, regional Indigenous organizations, and First Nation, Metis and Modern treaty rights holders or their representatives.

Indigenous parties’ perspectives and input on the oil and gas emissions cap have varied; however, throughout engagement there was a shared priority to take action to address the harmful impacts of climate change, while emphasizing the need to work in respectful partnership with Indigenous Peoples in achieving those objectives.

Through meetings and official submissions, the Department heard concerns about the impacts of the proposed Regulations on Indigenous communities, such as higher energy prices and reduced energy security; lower revenues and project royalties; negative impacts on jobs, businesses, and communities; greater uncertainty due to increased policy layering; and removing opportunities for Indigenous equity ownership in resource projects. The Department notes that the proposed Regulations would not prohibit the exploration or development of new oil and gas resources and include provisions to minimize barriers to new and/or small operators, including those that are operating primarily for own use in remote regions.

Indigenous parties expressed a desire to continue to be engaged while noting that engagement capacity remains a persistent issue. In 2022, NRCan received two requests for participant funding, which were approved. NRCan notified the groups in July 2022. Some Indigenous parties also expressed dissatisfaction with the extent of engagement, some arguing that it represents a violation of UNDA. The Department remains committed to ongoing engagement and will continue to reassess potential impacts on Indigenous communities in cooperation and consultation with interested Indigenous parties throughout the regulatory development process and encourages Indigenous parties to provide comments on these proposed Regulations, which will inform the final Regulations.

Instrument choice

A range of policy options were identified to reduce GHG emissions from the oil and gas sector. The process for evaluating the instrument choice focused on options that could effectively abate emissions from the oil and gas sector. Consideration was given to three options: maintaining the status quo, modifying of the current carbon pricing approach, and developing a regulated emissions cap-and-trade system.

Maintaining the status quo was not considered to be a viable option, as this would not ensure GHG emissions in the oil and gas sector are reduced at the pace and scale needed to achieve net-zero by 2050. Several federal and provincial regulatory and supporting measures to reduce oil and gas sector emissions are in place or under development. These include the proposed Methane Regulations, federal and provincial carbon pricing systems and the Clean Fuel Regulations. However, without an oil and gas sector emissions cap in place, these existing and proposed measures would not provide sufficient certainty that the oil and gas sector will do its share in ensuring Canada will meet its international commitments to reduce GHG emissions. For these reasons, maintaining the status quo was not considered.

As noted above, the Government of Canada published a discussion document in July 2022 outlining two regulatory options to implement the emissions cap: modifying the current carbon pricing approach or establishing a new emissions cap-and-trade system. Modifying the existing carbon pricing systems would build on the existing federal approach to carbon pricing by setting out the emissions cap trajectory in policy and modifying the federal carbon pollution pricing benchmark criteria to incentivize the oil and gas sector to further reduce emissions, aligned with the emissions cap trajectory. Under output-based pricing systems for industry that apply in all major oil and gas jurisdictions in Canada, facilities have unlimited ability to comply through payment for excess emissions. Although output-based pricing systems for industry provide an incentive to reduce emissions, relying on these systems alone would not provide certainty in reducing GHG emissions in the oil and gas sector.

A national emissions cap is proposed to be developed and implemented through the proposed Regulations under CEPA. Emission allowances would be issued for each tonne of emissions allowed under the emissions cap each year. It is expected that through future amendments, the emissions cap would decline over time to reach net-zero by 2050. In addition to being technology-neutral, it provides the most certainty that GHG emissions from the oil and gas sector would decline. In consideration of these factors, the emissions cap-and-trade approach was deemed to be the best policy option.

Regulatory analysis

Following the publication of the Regulatory Framework, the Department engaged in an analytical process to determine the emissions cap and allowable compliance flexibility for the proposed Regulations. It also undertook an economic analysis of the expected costs and benefits, as described below.

The key regulatory design elements

The estimated emissions cap (total quantity of allowances issued) plus maximum use of compliance flexibility (which together make up the legal upper bound) reflect a bottom-up analysis of the level of emissions that could be attained if technically achievable emissions reductions were deployed for a specific production forecast. Technically achievable emissions reductions were estimated based on an assessment of the abatement technologies that can feasibly be deployed within the upstream and LNG activities in the oil and gas sector (the sector) by 2030–2032, considering the status of available technologies, the availability of equipment and labour, as well as timelines for permitting and approvals. The risks that not all technically achievable reductions would be implemented in time for the first compliance period were also assessed. The estimates were informed by materials provided by industry and other interested parties. To construct the bottom-up estimates for the emissions cap and legal upper bound, a conservative 2030–2032 bottom-up baseline emissions level was estimated by assuming 2019 emissions intensities (data from the last pre-pandemic year available) remain constant for the given production level. The estimates of technically achievable emissions reductions were then deducted from the resulting GHG emissions level.

The legal upper bound

The legal upper bound is designed to align with Canada’s commitment to achieve net-zero emissions by 2050. The production forecast used to develop the 2030 to 2032 legal upper bound was grounded in the CER CNZ scenario from its Canada’s Energy Future 2023 report, which is based on a scenario where Canada and other parties to the Paris Agreement achieve their interim and net-zero emissions targets. This scenario assumes Canada’s oil and gas sector grows production out to 2030.

The legal upper bound was set at a level consistent with covered sources implementing technically achievable emissions reductions by 2030 to 2032 with an adjustment to take into account the risk that not all technically achievable reductions may be implemented by that time, and for production levels aligned with the CNZ scenario. This resulted in a legal upper bound of 19% below 2019 levels.

Emissions cap

The emissions cap holds the sector accountable for GHG emission increases beyond 2019 levels, the last pre-pandemic year before the Government of Canada’s commitment to cap and reduce GHG emissions from the oil and gas sector. It was set such that the sector would have the option to use compliance flexibility for up to 20% of its emissions, or equal to an emissions cap level of 35% below 2019 levels. This is consistent with an emissions cap that is at a level slightly below what emissions would be in a scenario where covered sources attained technically achievable emissions reductions and 2019 production levels are assumed to remain constant over the 2030 to 2032 period.

To establish the emissions cap level in the proposed Regulations, the equivalent reduction relative to 2026 was estimated. This approach ensures that the emissions cap and the distribution of allowances for the first compliance period of 2030 to 2032 would reflect updated production and emissions information and would be based on GHG emissions data that have been quantified using the methods required by the proposed Regulations. A 35% reduction in emissions below 2019 levels is estimated to be equivalent to a 27% reduction below 2026 levels based on a projection of 2026 emissions. The 2026 emissions value used in this calculation was the 2026 emissions value in Canada’s most recent emissions projections. The actual megatonne (Mt) level of the emissions cap would be announced in late 2027 after all of the 2026 emissions data has been received and analyzed.

The legal upper bound is not codified in the proposed Regulations. Rather, the combination of the emissions cap and 20% access to compliance flexibility together form an effective legal upper bound on emissions.

Distribution rates

The allocation of emissions allowances would be based on the distribution rates included in Part 1 of Schedule 1 to the proposed Regulations and reflect facility-specific analysis using 2019 data, the most recent and complete data set available. The data used to set distribution rates was drawn from facility-specific data including information reported to the Greenhouse Gas Reporting Program and departmental analysis based on other publicly available information. The rates for all industrial activities are set at 45% below 2019 emissions intensities, which reflect an estimate of the level of allowances that would be allocated for each year in the first compliance period, taking into account the emissions cap level and growth in production from 2019 levels based on the CNZ forecast. If emissions intensities or production levels are higher or lower than expected, allowance allocations would be pro-rated up or down to ensure the number of allowances is equal to the emissions cap in each year.

Cost-benefit analysis (CBA) summary

The Department employed a bottom-up approach to set the emissions cap and legal upper bound as described above. This bottom-up approach provides a high degree of confidence that the emissions reductions required from the sector will be technically achievable, assuming production grows in line with the CNZ forecast and compliance flexibility mechanisms are available.

To provide a monetized estimate of the impacts of the proposed Regulations, the Department employed a standard form of cost-benefit analysis, where the costs and benefits of the proposed Regulations are assessed relative to a baseline forecast of emissions and economic growth (i.e. a forecast without the proposed Regulations). This means that both the costs and benefits of policies included in the baseline, such as the proposed Methane Regulations, and the sector’s emissions reduction activities that result from those policies, such as CCUS, are not included in the impacts reported in this analysis. The analysis of impacts is performed using a departmental economic model, as described in the “Analytical framework for the CBA” section below.

The baseline uses the most recent departmental reference case, which is based on the CER’s Current Measures production forecast and assumes existing policies and measures, such as carbon pricing, are in place as well as the forthcoming proposed Methane Regulations.

This cost-benefit analysis monetizes a subset of the total benefits to the environment of the proposed Regulations in the form of reduced GHG emissions. This benefit is estimated using the Government of Canada’s social cost of carbon (SCC), which is meant to be a comprehensive estimate of damages associated with the climate change caused by each tonne of greenhouse gas emissions. The SCC takes into account changes in agricultural productivity, adverse impacts on human health, property damages from increased flood risk, and increases in energy system costs. Each tonne of GHG (in CO₂e) that is avoided has the benefit of avoiding its social cost of carbon.

Over the time frame of this analysis (2025 to 2032), the proposed Regulations are estimated to result in cumulative incremental GHG emissions reductions (i.e. beyond current policies and measures, including the proposed Methane Regulations) of 13.4 Mt. The value of these reductions is estimated to be $4.0 billion in avoided climate change induced global damages. The proposed Regulations are also estimated to have incremental impacts on the economy, which are estimated to be $3.3 billion plus administrative costs to industry and the Government of Canada estimated to be $219 million. Thus, the proposed Regulations are estimated to have net benefits of $428 million.

The analysis does not include a comprehensive inventory of all the impacts of the proposed Regulations. It does not account for the benefits from reduced air pollution. Higher order impacts related to jobs and associated economic activity from post-2032 investments in CCUS and other major decarbonization activities to reduce emissions from the sector are outside the scope of this analysis. The analysis does not fully consider the stimulation of new low-carbon industries, such as hydrogen, or for the longer-term competitiveness benefits of a decarbonized Canadian oil and gas sector in a world that complies with existing commitments under the Paris Agreement.

The costs in a CBA are the monetized costs of a regulation to Canadians relative to a baseline. In both the baseline and the regulatory scenarios, Canadian oil and gas production is projected to increase between 2019 and 2030: by about 17% in the baseline scenario and by almost the same (about 16%) in the regulatory scenario. The estimated costs of the proposed Regulations reflect the difference between these two projections.

In the model used for this CBA, these costs are assumed to be borne by Canadians. This is because the model assumes that Canadian households own the means of production. That is, Canadian households not only supply the labour, but are also assumed to own the capital used in production, as shareholders in the firms that produce goods and services. While this is a standard assumption in economic theory and modelling, in reality, many Canadian oil and gas firms are multi-national. For this reason, costs to Canadian society may be overestimated by assuming that all costs associated with lost profits are borne by Canadian households rather than being absorbed by multi-national firms and their shareholders.

Analytical framework for the CBA

To estimate the social value of the proposed Regulations, a cost-benefit analysis was conducted to account for the impacts on GHG emissions and the Canadian economy relative to the baseline for this analysis, while also accounting for the administrative costs for government and industry. These impacts were analyzed over a 7.5-year time frame, from mid-2025 to the end of 2032, which covers the period in which operators must register (the second half of 2025), through the end of the first compliance period in 2032. Capital costs are annualized over their expected life expectancy, and presented here as annualized costs, consistent with the presentation of operating costs and expected annual GHG reductions over the 2030 to 2032 period. Thus, the overall analysis underestimates the total lifetime costs and benefits attributable to actions taken in the first compliance period. However, this approach does provide a balanced perspective on the proportional costs and benefits of compliance. While the proposed Regulations would set the emissions cap indefinitely beyond the first compliance period, the policy intention is to review the trajectory of the emissions cap for future compliance periods within five years of the coming into force of the proposed Regulations to ensure the sector remains on a path to net-zero by 2050. The economic impacts of amending the emissions cap level for future compliance periods would be assessed at that time.

The analysis employs the Department’s multi-region, multi-sector, computable general equilibrium model (EC-Pro) of the Canadian economy to analyze the incremental impacts of the proposal relative to the baseline. This modelling framework differs from the energy systems model used to produce the departmental reference case. As a result of this difference in modelling frameworks, the projections in this analysis may vary slightly from the 2023 Departmental Reference Case (Ref23).^{footnote 2} More information on EC-Pro can be found in the “Modelling” section below.

The value of GHG emissions reductions is calculated using the Department’s social cost of greenhouse gases (SC-GHG) emissions. All dollar figures are presented in 2023 Canadian dollars and discounted at 2% annually (to 2025) when presented in present value form. This is the near-term Ramsey discount rate now utilized by the Government of Canada when monetizing GHG emissions reductions. More information on this approach is presented in the “Benefits” section.

Baseline scenario

The baseline scenario is a projection based on a modified Ref23. This includes federal, provincial, and territorial policies and measures that were in place as of August 2023, such as carbon pricing, the Clean Fuel Regulations, and investment tax credits. In addition, Ref23 was modified to include the proposed Methane Regulations which aim to achieve at least a 75% reduction in oil and gas sector methane emissions by 2030, relative to 2012 levels. The forecasts of oil and natural gas prices in Ref23 are taken from the Canada Energy Regulator’s 2023 Current Measures Scenario, as released in Canada’s Energy Future 2023. The model projects that under this scenario, Canadian oil and gas production will grow by 17% from 2019 to 2030, and that labour expenditure in the economy is estimated to grow by 18% and Canadian GDP is estimated to grow by 20% over this same time frame.

Emission intensities in the oil and gas industry are projected to decrease over time in the baseline scenario. These emission intensity improvements are expected to result from industry compliance with the regulations and measures currently in place, the proposed Methane Regulations, as well as other ongoing industrial efficiency improvements. These expected improvements lead to decreased GHG emissions over the time frame of analysis. These emissions intensity improvements are expected to result from the deployment of various emissions abatement technologies, including methane abatement technologies, increased use of solvents and carbon capture and storage, and increased use of hydrogen as a low-carbon source of energy. The average annual baseline emissions from the sector is estimated to be 134 Mt in CO₂e in the first compliance period (2030 to 2032). That is, by the 2030 to 2032 period, the sector is estimated to reduce emissions by 22% below 2019 levels in the absence of the proposed Regulations.

Regulatory scenario

The regulatory scenario builds on the baseline scenario, with the assumption that the proposed Regulations are implemented.

The proposed Regulations would set a sector-wide emissions cap on covered emissions at 27% below 2026 reported emissions. The baseline scenario estimates the 2026 emissions to be 156.6 Mt, resulting in a modelled emissions cap of 114 Mt. In the model, allowances equal to the emissions cap level are allocated to subsectors each year from 2030 to 2032 based on 2019 emissions intensities and the forecasted in-year production in a given year. National historical emissions intensities used in the modelling were calculated and applied at an aggregation that is broadly consistent with the aggregation of distribution rates set out in the proposed Regulations.

Covered operators would be required to remit one eligible compliance unit for each tonne of GHGs emitted. Compliance units can include allowances, decarbonization units (up to 10% of a covered operator’s compliance obligation) and Canadian offset credits (up to 20% of a covered operator’s compliance obligation). The extent to which offsets would be used would depend on their price, which is currently uncertain. Therefore, offsets were not modelled as a compliance option in the central case. Given that it is expected that there will be offsets available and used, however, the “Sensitivity analysis” section discusses their potential use and impacts on emissions and production relative to the central case.

In addition to allowances, the model assumes that eligible compliance units include decarbonization units available at an incremental price of $50 per tonne (i.e. over and above their price under carbon pricing) to a maximum of 13 million decarbonization units each year for all covered sectors, approximately 10% of the average baseline emissions over the period of analysis. The analysis assumes that subsectors with excess allowances can trade with subsectors that require them, that obligations under the emissions cap are met on an annual basis in the year in which the obligations are created, and that no banking of allowances takes place. Figure 1 below presents the average annual baseline emissions over the 2030 to 2032 period (134 Mt), as well as the modelled emissions cap level, the modelled upper bound on emissions, and the modelled legal upper bound. As noted above, the emissions cap is estimated to be 114 Mt in this analysis, which would result in a legal upper bound of 143 Mt.^{footnote 3} The legal upper bound is estimated to be higher than baseline emissions in this analysis due to baseline emissions falling by 22% between 2019 and the 2030 to 2032 period. However, since the central case analysis does not include access to offsets, the maximum allowable emissions modelled in the regulatory scenario is 127 Mt (emissions cap plus decarbonization units). In the regulatory scenario, the available flexibilities (decarbonization units) are fully subscribed in 2030 and 2031; while in 2032 there are 0.2 million excess units available.

Figure 1: Modelled emissions cap and allowable compliance flexibilities (average from 2030 to 2032)

Figure 1: Modelled emissions cap and allowable compliance flexibilities (average from 2030 to 2032) - Text version

Figure 1 illustrates a vertical bar graph, with the y-axis representing the average quantity of GHG emissions in carbon dioxide equivalent (CO2e) in megatonnes over the 2030 to 2032 period. Along the x-axis, there are four bars, each representing an emissions level. The first bar is for the baseline scenario and is denoted as 134 megatonnes of CO2e; the second is the emissions cap denoted as 114 megatonnes of CO2e; the third is the modelled upper bound at 127 megatonnes of CO2e; and lastly the legal upper bound at 143 megatonnes of CO2e.

Modelling

This analysis uses EC-Pro, the Department’s peer-reviewed, multi-region, multi-sector, provincial-territorial computable general equilibrium (CGE) model of climate change policies. EC-Pro can assess variables of interest, including GHG emissions, and economic indicators such as production, employment and household consumption. EC-Pro estimates the impacts of the proposed Regulations by estimating the new set of prices and variables that will return the economy to equilibrium. The incremental impacts of the proposed Regulations compare the baseline scenario to the regulatory scenario. A summary of how EC-Pro works is provided here, and more modelling information can be provided upon request.

EC-Pro assumes that households own labour and capital (factors of production), and therefore the households receive all wages from labour and profits from firms. As production increases (or decreases) the demand for labour and capital inputs may also increase (or decrease). EC-Pro simulates the response to the proposed Regulations in Canada’s main economic sectors in each jurisdiction, and models the interactions among sectors. Each province and territory is represented individually; the representation of the rest of the world is based on import and export flows to Canadian provinces and territories, which are assumed to be price takers in international markets. Finally, to accommodate analysis of energy and climate policies, the model incorporates information on energy use, combustion and non-combustion greenhouse gas emissions.

The modelling of output-based pricing systems assumes that the stringency increases in each scenario such that the output-based pricing systems align with the benchmark requirement that systems be designed to maintain the marginal price at the national minimum carbon price. In the case where excess credits exist, they are assumed to be cleared at the national minimum price on carbon pollution.

EC-Pro estimates emission changes through the deployment of emissions abatement technology, fuel-switching, improvements in energy efficiency, or changes in production levels. The model assumes that covered operators would comply with the proposed Regulations by using the most cost-effective option, determined by the marginal cost of each option. Although operators may make use of compliance flexibilities, in the model, the only actions that result in emissions reductions are the deployment of emissions abatement technology, more efficient production, or reduced production. Contributions by firms to the decarbonization program in exchange for decarbonization units come at a cost to firms. The proposed Regulations set out that contributions to the decarbonization program would be returned to support decarbonization of the oil and gas sector. However, the model does not show these contributions as additional emissions reductions. Instead, the model returns these contributions to households.

Abatement technologies include CCUS, hydrogen, and solvents. EC-Pro’s assumptions regarding the cost and availability of decarbonization technology are informed by external sources, including the latest academic literature, along with internal departmental assessments. Costs are accounted for both in terms of annualized capital costs, and operational costs.

The model treats the installation of abatement technology as a cost to firms. New labour demand and associated economic activity that could be created by the use of these technologies in the future, or the potential for this demand to create new sectors of the economy in the future in a world that complies with existing commitments under the Paris Agreement is outside the scope of this analysis.

Analytical results

The analysis estimates some of the expected economic impacts, including impacts of the proposed Regulations on production and employment relative to the baseline scenario. It also includes an estimate of the administrative costs to industry and government.

As is explained above, the analysis also estimates some of the benefits of the proposed Regulations. These are estimated by valuing the projected GHG emissions reductions in terms of avoided climate change-induced global damages. This benefit is estimated using the Government of Canada’s SCC, which is meant to be a comprehensive estimate of climate change damages and includes changes in agricultural productivity, adverse human health impacts, property damages from increased flood risk, and changes in energy system costs.

The benefits accounted for in this analysis do not include a comprehensive inventory of all the benefits of the proposed Regulations. They do not account for the benefits from reduced air pollution.

Quantified and monetized costs

Cost pass-through

In the analysis, firms choose the most profitable compliance option. This could mean using their allocated emissions allowances, choosing to purchase the most cost-effective emissions abatement technologies, choosing to buy allowances, or making contributions to the decarbonization program to meet their compliance obligations. Given that oil prices are set in international markets, the ability of firms to pass on these compliance costs to consumers is limited. If firms are able to pass on some costs in the form of higher prices, this could have some impact on consumption. If firms cannot pass on these costs, this would lower firm profits.

The ability for a firm to pass on costs to consumers depends on a variety of factors, including the market structure of the sector, the persistence of demand, and the availability of substitutes. The price of crude oil and natural gas commodities are generally determined in global or continental markets. In some instances, prices can be influenced by regional dynamics, which could result in some ability for oil and gas producers to affect downstream prices. In the context of the central case analysis, compliance costs passed through from the sector to domestic end users are expected to be low.

Production impacts

As Table 1 illustrates, there is projected to be significant production increases in both the baseline scenario and the regulatory scenario. This is shown in the figure below.

Figure 2: Oil and gas production over time (in petajoules)

Figure 2: Oil and gas production over time (in petajoules) - Text version

Figure 2 is a line graph that illustrates the annual quantity of oil and gas production in the baseline and regulatory scenarios. The y-axis represents petajoules (PJ) of energy produced, and ranges from 17 000 to 21 500. The x-axis represents the year, ranging from 2019 to 2032. There are two lines on this graph. The first line illustrates the expected trajectory of oil and gas production in the baseline scenario. The line begins just under 18 000 PJ in 2019, dips to around 17 400 PJ in 2020 and then increases until 2030, where it peaks at just over 21 000 PJ and then declines slightly where it ends at just under 21 000 PJ in 2032. The second lines represents the expected trajectory of oil and gas production in the regulatory scenario, and follows the same trajectory as the baseline scenario until it deviates in 2030, where it rises more slowly than the baseline scenario and ends just under the baseline scenario in 2032.

• In 2019, production in the oil and gas sector was about 17 945 petajoules (PJ).
• In the 2030 baseline scenario, total production is estimated to be about 21 070 PJ, an increase of about 17% over 2019.
• In the 2030 regulatory scenario, total production is estimated to be about 20 835 PJ, an increase of about 16% over 2019.

The production increases are similar in both cases. Based on a comparison of production in the regulatory scenario to the production used to set the legal upper bound through the bottom-up analysis, the projected production in the regulatory scenario is roughly in line with the production in the CER’s CNZ scenario. Therefore, the proposed Regulations are expected to enable Canadian production to continue to grow in response to global demand.

Table 1: Estimated oil and gas production (PJ)
Note: Figures may not add up to totals due to rounding.

Commodity	2019 levels	Average 2030–2032 (baseline)	Average percentage growth (baseline)	Average 2030–2032 (regulatory)	Average percentage growth (regulatory)	Average 2030–2032 (change)	Percent change from baseline
Natural gas	7 280	7 670	5%	7 645	5%	(22.0)	(0.3%)
Oil	10 665	13 360	25%	13 240	24%	(119.6)	(0.9%)
Total	17 945	21 030	17%	20 885	16%	(141.6)	(0.7%)

Employment impacts

The extent to which the proposed Regulations would impact future wages and employment in oil and gas-producing regions relative to the baseline scenario would depend on how the industry decides to comply. In the baseline scenario, labour expenditure in covered sectors is expected to grow by 55% between 2019 and 2030–2032. In the regulatory scenario, labour expenditure in covered sectors is expected to grow by 53% between 2019 and 2030–2032. Between the baseline and regulatory scenarios, reductions in projected production would be expected to affect employment income from the reduced demand for labour or any resulting lowering of wages, or both. The modelling done for this analysis indicates that the proposed Regulations are expected to result in a net decrease in labour expenditure in the oil and gas sector of about 1.6% relative to the baseline estimate of employment income over the 2030 to 2032 time frame. Employment created by future investments in decarbonization projects, such as CCUS projects, post-2032, is outside the scope of this analysis.

Social welfare impacts

This analysis considers key economic impacts of the proposed Regulations relative to the baseline scenario. In the model, these economic costs are represented by foregone consumption in a representative household. Actual impacts for a specific household would vary significantly based on the extent to which it has a stake in the oil and gas sector (for example through employment or investments).

The modelled impacts also include some positive effects resulting from shifts in capital and labour from the oil and gas sector to other sectors of the Canadian economy. They include some benefits from reductions in energy prices arising from the reduced demand for energy use in oil and gas sector production.

A common measure of social welfare in general equilibrium models such as EC-Pro is equivalent variation (EV). EV is based on the concept of willingness-to-pay, or the maximum amount a household would pay for a particular good or service given its budget constraint.^{footnote 4} The EV from the baseline scenario to the regulatory scenario represents the additional amount of money that households would require with the proposed Regulations in place to make themselves as well off as they would be in their absence.^{footnote 5,footnote 6} This amount can be considered equivalent to the change in welfare for households from the decrease in consumption under the regulatory scenario. Because household consumption accounts for both potential changes of income stemming from changes in production (i.e. income from labour and capital) and changes in the price of consumption, it is used as a measure of both the total costs of compliance and the change in welfare in this analysis.

In the baseline scenario, household consumption is expected to rise by 18.8% or $298 billion between 2019 and the 2030 to 2032 period. Over the time frame of the analysis, the model projects the proposed Regulations to result in $3.3 billion of foregone household consumption relative to the baseline scenario. Consequently, household consumption is expected to rise by 18.7% between 2019 and 2030–2032 in the regulatory scenario, versus 18.8% in the baseline scenario.

Finally, as is described in more detail below, these cost estimates do not account for the possible use of offsets, which would be expected to reduce compliance costs.

Industry administrative costs

The proposed Regulations would introduce new requirements related to registration, record-keeping, and submission of compliance reports. There would also be costs associated with the verification of annual reports by a third party. Over the time frame of analysis, these administration costs are estimated to be $124 million in present value terms. Further details can be found in the “One-for-one rule’’ section below.

Government costs

The Government is expected to incur administrative costs associated with implementing, administering, and enforcing the proposed Regulations of $95 million over the period of analysis.

This would include costs associated with processing registrations; reviewing annual and verification reports; allocating emission allowances to operators; reviewing remittance of compliance units; and implementing the decarbonization program. The proposed Regulations are expected to impose administrative costs on the Department of $67 million over the time frame of analysis, including compliance promotion costs.

In addition, the Department is expected to incur ongoing costs related to the development and administration of IT infrastructure to support registration, annual and verification reporting, allocation of emission allowances, and remittance of compliance units. These costs are estimated to be $24 million in present value terms between 2025 and 2032.

Some incremental costs are also expected for hiring new enforcement officers, training new and current enforcement officers, and for equipment, inspections, investigations and measures to deal with any alleged violations. In total, incremental enforcement costs are estimated at $4 million between 2025 and 2032.

Summary of monetized costs

In the baseline scenario, household consumption is expected to rise by 18.8% or $298 billion between 2019 and the 2030 to 2032 period. Over the time frame of the analysis, the model projects the proposed Regulations to result in $3.3 billion of foregone household consumption relative to the baseline scenario (between 2030 and 2032). Consequently, household consumption is expected to rise by 18.7% between 2019 and 2030–2032 in the regulatory scenario, versus 18.8% in the baseline scenario. In addition, total industry administrative costs are estimated at $124 million and total Government costs to implement and enforce the proposed Regulations are estimated at $95 million over the time frame of analysis, for a total estimated cost of $3.5 billion relative to the baseline scenario. As is described in more detail below, these cost estimates do not account for the possible use of offsets, which would be expected to reduce compliance costs.

The next section addresses the benefits that are expected to outweigh these costs, including significant GHG reductions and the competitiveness advantage that Canada could gain by decreasing carbon intensity of production in a world moving towards net zero.

Table 2: Summary of monetized costs estimated for this analysis (in millions of dollars)

• Number of years: 7.5 (2025 to 2032)
• Dollar year for prices: 2023
• Present value year for discounting: 2025
• Social discount rate: 2% per year

Monetized costs	Undiscounted — 2025	Undiscounted — 2030	Undiscounted — 2032	Discounted — 2025 to 2032	Annualized table c1 note a
Household consumption	0	1 643	800	3 309	443
Industry administration	1	26	27	124	17
Government	5	14	12	95	13
Total costs	5	1 683	839	3 528	472
Table c1 note(s) Table c1 note a Annualized values are calculated over eight periods where discounting occurs at the end of each period. Return to table c1 note a referrer

Note: Figures may not add up to totals due to rounding.

Quantified and monetized benefits associated with greenhouse gas emissions reductions

The proposed Regulations would limit the amount of GHGs emitted by covered operators. This is achieved by limiting the maximum allowable emissions through the distribution of allowances up to an emissions cap level, modelled as 114 Mt of CO₂e, and enabling access to compliance flexibilities modelled as up to 10% of compliance obligations. In this analysis, covered operators would comply with the proposed Regulations by using the most cost-effective option from the following: using free emissions allowances or buying allowances from others, deploying abatement technologies, purchasing decarbonization units, or reducing production. In this analysis, only deployment of abatement technologies or reductions in production would lead to incremental GHG emissions reductions in the Canadian oil and gas sector. The figure below shows GHG emissions in the baseline and regulatory scenarios from 2019 to 2032.

Figure 3: GHG emissions in covered sectors over time (in Mt of CO₂e)

Figure 3: GHG emissions in covered sectors over time (in Mt of CO₂e) - Text version

Figure 3 is a line graph that illustrates the annual quantity of GHG emissions in covered sectors in the baseline and regulatory scenarios. The y-axis represents megatonnes of carbon dioxide equivalent and ranges from 0 to 180. The x-axis represents the year, ranging from 2019 to 2032. There are two lines on this graph. The first line illustrates the expected trajectory of GHG emissions in the baseline scenario. The line begins around 170 megatonnes of carbon dioxide equivalent in 2019, dips to just under 160 megatonnes of carbon dioxide equivalent in 2020, increases slightly until it reaches just over 160 megatonnes of carbon dioxide equivalent in 2022, and then decreases steadily where it ends at just over 130 megatonnes of carbon dioxide equivalent in 2032. The second line represents the expected trajectory of GHG emissions in the regulatory scenario. It follows the same trajectory as the baseline scenario until it deviates in 2030, where it decreases more rapidly, and remains roughly constant at 127 megatonnes of carbon dioxide equivalent from 2030 to 2032.

Relative to the baseline scenario, the proposed Regulations are also expected to result in some benefits in non-oil and gas sectors of the economy, which in turn results in some increases in GHG emissions. The primary driver of GHG increases in the rest of the economy projected by the model is related to increased consumption of natural gas relative to the baseline scenario. This occurs in the modelling of the regulatory scenario, where less natural gas is used in the oil and gas industry than in the baseline scenario, leading to a lower price and, consequently, increased demand outside of the oil and gas sector. The largest increases in GHG emissions relative to the baseline scenario are from the buildings sector (3.4 Mt) and natural gas pipelines (1.7 Mt).

In the analysis, the proposed Regulations would reduce GHG emissions in the oil and gas sector by 20.2 Mt, and increase GHG emissions in the rest of the economy by 6.7 Mt, resulting in a net GHG reduction of 13.4 Mt compared to the baseline scenario.

Table 3: Estimated change in GHG emissions (Mt of CO2e)

Modelled change in GHG emissions	2030	2031	2032	Total (2030 to 2032)
Oil and gas sector	(8.7)	(6.0)	(5.5)	(20.2)
Rest of economy	3.3	1.4	2.0	6.7
Net total	(5.4)	(4.6)	(3.5)	(13.4)

Note: Figures may not add up to totals due to rounding.

To monetize these benefits, the amount of net avoided GHG emissions was multiplied by the value of the SCC. In November 2022, the United States Environmental Protection Agency (U.S. EPA) released its draft Report on the Social Cost of Greenhouse Gases (the draft U.S. EPA Report). The report was finalized in December 2023 and presents the updated SC-GHG methodologies and values for CO₂, CH₄ and N₂O^{footnote 7}. In April 2023, the Department published a draft SC-GHG guidance for Canada,^{footnote 8} in alignment with the SC-GHG values proposed by the U.S. EPA, and is in the process of finalizing this guidance. The new value of the SCC employed in this analysis and expressed in constant 2023 dollars is about $300 in 2025 and increases to about $335 in 2032. Over the time frame of the analysis, the cumulative monetized benefits of the GHG emissions reductions from the proposed Regulations are estimated to amount to $4.0 billion in present value terms.

Qualitative impacts

Not all potential impacts of the proposed Regulations were quantified or monetized for this analysis. Some of the qualitative impacts are discussed below.

Air quality impacts

The oil and gas sector is a significant contributor to air pollutant emissions that can negatively impact air quality. These include increases in ambient concentrations of fine particulate matter (PM_2.5), ground-level ozone (O₃) and nitrogen dioxide (NO₂). Exposure to PM_2.5, O₃, NO₂ and other air pollutants has been linked to negative health outcomes including premature mortality, asthma and other respiratory issues, cancer, and cardiovascular diseases.^{footnote 9,footnote 10,footnote 11} Further, some populations or individuals, such as children, older adults, and individuals with pre-existing heart and lung conditions, are more at risk of adverse health effects from exposure to air pollution. Health Canada previously reported that 350 deaths were attributable to oil and gas sector air pollution in 2015 in Canada (representing $2.7 billion in 2015), with some regions more affected than others (180 deaths in Alberta) due to greater regional oil and gas activities.^{footnote 12} The proposed Regulations could reduce air pollution from this sector; however, given the option to comply by trading allowances and the various technologies that may be utilized and their influence on air pollutant emissions, the CBA did not quantify the direction and magnitude of change in air pollutants and air pollution-related health impacts in Canada.

Competitiveness and carbon leakage

Climate change mitigation policies can have spillover effects where production in a region with relatively stricter environmental policies may be shifted to a jurisdiction with less stringent environmental policies and more carbon-intensive operations, offsetting domestic reductions with increases in global emissions. This concept is known as “carbon leakage.” Any potential carbon leakage associated with the proposed Regulations is expected to be limited, given the small size of the estimated production impacts (0.7%). The extent to which decreases in production could lead to carbon leakage under the proposed Regulations is dependent on the production forecast, the quantity of production that is shifted, and the relative carbon intensity of the foreign jurisdiction to which it is relocated. If global demand for these commodities remains unchanged, it is possible that this reduction in domestic production could be offset globally. And if the forecast of the global demand is higher than in the central case, the risk of carbon leakage could be higher. In the absence of certainty regarding where production would be relocated, it is unknown what the relative change in carbon intensity of these products would be.

Over the long term, the proposed Regulations may also have positive impacts on the competitiveness of the Canadian oil and gas sector that are not captured in this analysis. In a future carbon constrained world where there is continued demand for some oil and gas to meet certain needs, low-carbon oil and gas may be in high demand. Therefore, efforts by the Canadian oil and gas sector to reduce the carbon footprint of its oil and gas production are expected to improve the sector’s competitiveness over the long term, including its potential share of the global market, in a world that complies with existing commitments under the Paris Agreement.

Interactions with output-based pricing systems

The federal benchmark gives provinces and territories the flexibility to implement carbon pricing systems that make sense for their circumstances as long as they align with minimum national stringency standards, or “benchmark” criteria. Under this benchmark, output-based pricing systems for industry are required to be sufficiently stringent to create strong markets that maintain a clear price signal across all covered emissions that is aligned with the national minimum carbon price.

The Government has committed to conducting an interim review of the benchmark by 2026 to confirm that benchmark criteria are sufficient to continue ensuring that pricing stringency is aligned across all carbon pricing systems in Canada. The Government also periodically reassesses provincial and territorial systems to confirm that they continue to meet the benchmark criteria (the next interim assessment is due by 2026). Actions undertaken to come into compliance under the proposed Regulations could have impacts on the supply and demand for credits in output-based pricing systems across Canada. It is anticipated that any impacts that the proposed Regulations may have on carbon pricing would be assessed when systems are reassessed against the benchmark.

CBA summary

This CBA estimates a subset of the benefits of the proposed Regulations and compares them to the estimated costs. It is estimated that the proposed Regulations will result in cumulative GHG emission reductions of 13.4 Mt, valued at $4.0 billion in avoided climate change–induced global damages. It is also estimated that the proposed Regulations will have an impact on the economy valued at $3.3 billion. In addition, administrative costs to industry and Government are estimated to be $219 million, resulting in total costs of $3.5 billion. Thus, net benefits of the proposed Regulations are estimated to be $428 million over the time frame of the analysis (2025 to 2032). As is described in more detail below, the cost estimates do not account for the possible use of offsets, which would be expected to reduce compliance costs. In addition, the analysis does not include a comprehensive inventory of all the impacts of the proposed Regulations. It does not account for the benefits from reduced air pollution. Higher order impacts related to jobs and associated economic activity from post-2032 investments in CCUS and other major decarbonization activities to reduce emissions from the sector are outside the scope of this analysis. The analysis does not fully consider the stimulation of new low-carbon industries, such as hydrogen, or for the longer-term competitiveness benefits of a decarbonized Canadian oil and gas sector in a world that complies with existing commitments under the Paris Agreement.

Table 4: Summary of monetized costs and benefits (millions of dollars)

• Number of years: 7.5 (2025 to 2032)
• Dollar year for prices: 2023
• Present value year for discounting: 2025
• Social discount rate: 2% per year

Monetized impacts	Undiscounted — 2025	Undiscounted — 2030	Undiscounted — 2032	Discounted — 2025 to 2032	Annualized
Total benefit	0	1 747	1 174	3 956	529
Total cost	5	1 683	839	3 528	472
Net benefit (cost)	(5)	64	335	428	57

Note: Figures may not add up to totals due to rounding.

Dividing the total costs of $3.5 billion by the net GHG reductions of 13.4 Mt results in a cost-per-tonne of $263, which is less than the social cost of carbon (estimated to be $332 on average over the 2030 to 2032 period).

Sensitivity analysis

The monetized results of the cost-benefit analysis are based on key parameter estimates; however, these values may ultimately be higher or lower than estimated. To account for this uncertainty, sensitivity analyses were conducted to assess the effect of higher or lower estimates of key parameters that would change the estimated impacts of the proposed Regulations. In each scenario, parameter estimates are varied outside of the model and in isolation. In addition, an alternate scenario describes the impacts of offsets if they were available at a given price and quantity. And finally, the uncertainty of baseline forecasts is also considered qualitatively.

Uncertainty of parameter estimates

Costs

To comply with the emissions cap, regulated entities would have a variety of actions available to them, including deploying abatement technologies, remitting compliance units, or reducing production. The decision on which compliance action to take is dependent on the expected cost of each option. Abatement technologies could be more (or less) expensive than estimated, leading to higher (or lower) costs than estimated in the analysis. If total costs associated with the proposed Regulations were more than 12% higher than estimated in the central case, all else being equal, the analysis would show no net benefit.

GHG emissions reductions

If incremental GHG reductions are lower than estimated, lower benefits would be attributable to the proposed Regulations.

Social cost of carbon

As noted in the “Quantified and monetized benefits associated with greenhouse gas emissions reductions” section, the Department published draft SC-GHG guidance for Canada in alignment with the SC-GHG values proposed by the U.S. EPA. In addition to the recommended SC-GHG values, the draft guidance provides SC-GHG estimates generated using a lower (1.5%) or higher (2.5%) near-term Ramsey discount rate for use in sensitivity analyses. An SCC using a lower near-term Ramsey discount rate would result in a higher net benefit, and an SCC using a higher near-term Ramsey discount rate could lead to a lower benefit. The lower-valued departmental SCC ($205 in 2030) would result in a net cost of $1 billion, and the higher-valued departmental SCC ($545 in 2030) would result in a net benefit of almost $3.1 billion.

Discount rate

Canada’s Cost-Benefit Analysis Guide for Regulatory Proposals states that a 7% real discount rate can also be used for cost-benefit analyses. For some regulatory proposals, such as those relating to human health or environmental goods and services, guidance states that it is more appropriate to employ a social discount rate. The summary of monetized costs and benefits in Table 4 uses a 2% social discount rate. A sensitivity analysis using the 7% real discount rate results in an overall net benefit of $298 million.

Table 5: Sensitivity analysis

Sensitivity case	Net benefit (millions of dollars)
Higher costs (12% higher)	0
Lower SCC ($205 in 2030)	(1 042)
Higher SCC ($545 in 2030)	3 058
Higher discount rate (7%)	298

Alternate analysis where offsets are used as a compliance option

Under the proposed Regulations, firms may use Canadian offset credits to fulfill up to 20% of their remittance obligation in each compliance period. However, given the uncertainty around the quantities and costs of offset credits that firms would access over the 2030 to 2032 time frame, the central case analysis does not include the use of offset credits. Nonetheless, the Department expects that offsets will be available for use by covered operators, and that firms would purchase offset credits if they are more cost-effective than other compliance options. This would lead to lower costs attributable to the proposed Regulations.

This would also decrease the price impacts on consumption of natural gas, which in turn would decrease the estimated non-sectoral GHG emission increases.

An alternative analysis was conducted to demonstrate the effect the availability of offsets could have on the estimated impacts of the proposed Regulations. This scenario assumes 6 Mt of offset credits would be available each year for an incremental price of $45 per credit (i.e. over and above their price under carbon pricing). This scenario was chosen because it represents a scenario where cross-recognition is enabled and offset credits are available at a price slightly less than $220 per tonne. This results in a modelled upper bound of 133 Mt, as opposed to the 127 Mt modelled upper bound in the central case analysis. This scenario remains below the estimated legal upper bound, which would allow up to 143 Mt if full (20%) compliance flexibilities were employed. In this scenario, offset credits are assumed to be non-incremental to the proposed Regulations due to uncertainty related to the attribution of offset credits under the proposed Regulations versus carbon pricing. As a cost-effective compliance option, regulated firms use the full amount of offset credits to replace other compliance options. The estimated impacts on production in the Canadian oil and gas sector relative to baseline levels are shown in Table 6 below.

Table 6: Estimated impact on oil and gas production relative to baseline levels (%)

Commodity	Central case	Alternate case
Natural gas	(0.3)	(0.3)
Oil	(0.9)	(0.6)
Total	(0.7)	(0.5)

In this scenario, there is less of a shift in natural gas consumption from the oil and gas sector to the rest of the economy, which contributes to lower GHG increases in the rest of Canada. As offset credits are assumed here to be non-incremental, their usage leads to fewer GHG reductions in the Canadian oil and gas sector when they displace incremental compliance actions. Taken together, the net GHG emissions impacts in this scenario are lower than the central case, as shown below.

Table 7: Estimated total incremental GHG emissions 2030–2032 (Mt)

Change in GHG emissions	Central case	Alternate case	Difference
Oil and gas sector	(20.2)	(14.1)	6.1
Rest of economy	6.7	5.3	(1.5)
Net total	(13.4)	(8.8)	4.6

Note: Figures may not add up to totals due to rounding.

Uncertainty of baseline (forecast) estimates

There are alternate forecasts that could change the analysis. Some are considered qualitatively here.

Uncertainty of 2026 emissions levels

The emissions cap level set out in the proposed Regulations is fixed at 27% below 2026 reported emissions for covered subsectors. If 2026 emissions levels in the oil and gas industry are lower than estimated in the baseline, due to lower production or more carbon intensity improvements, then all else being equal, the resulting level of the emissions cap would be lower than estimated leading to higher impacts. Alternatively, if 2026 reported emissions are higher than estimated, then all else being equal, the emissions cap would be higher, and would have lower impacts than estimated.

Alternate production forecasts post-2030

There is significant uncertainty about how the global energy market will evolve in the coming decades. Future oil and natural gas demand is dependent on a variety of factors, including the speed at which the world pursues various climate targets. As oil and gas prices are generally driven by global markets, including the availability of supply, higher global demand for these commodities could lead to higher oil and gas prices, and in turn higher production than the level projected in the baseline scenario. Higher production would also lead to more emissions in the baseline scenario, and thus more costs and benefits attributable to the proposed Regulations.

Canadian oil and gas price forecasts in the baseline scenario come from the Canada Energy Regulator’s Current Measures scenario. This scenario assumes that there will be no additional climate policies other than the ones currently in place. The CER provides two additional scenarios: the CNZ, and Global Net-Zero (GNZ) forecasts. In the CNZ, Canada and all other parties to the Paris Agreement achieve their interim and net-zero climate targets. In the GNZ, in addition to Canada achieving its net-zero target, the rest of the world reduces emissions to limit global warming to 1.5 °C. In each of these additional scenarios, global oil and gas prices and Canadian production are lower than in the Current Measures case. If Canadian production overall is lower than estimated in the baseline scenario, then all else being equal, emissions from the sector would be lower, and thus the costs and benefits of the proposed Regulations would be lower.

Uncertainty of carbon intensity improvements post-2030

As noted in the “Baseline scenario” section, the carbon intensity of the oil and gas sector is projected to improve over time as a result of current policies in place and improvements in efficiency. If efficiency improvements do not continue as expected in the absence of the proposed Regulations, or if the sector’s future realized emissions intensities are higher than estimated in the baseline scenario, the sector’s emissions would be higher than estimated in the analysis. All else being equal, higher baseline emissions over the 2030 to 2032 period would require more compliance actions to meet remittance obligations. Conversely, if efficiencies improve more than expected, baseline emissions would be lower and fewer compliance actions would be required.

Uncertainty post-2032

In the absence of further amendments to the proposed Regulations, the emissions cap would remain at the 2030–2032 level — 27% below 2026 reported emissions. Because the analysis uses annualized capital costs, extending the period of analysis beyond the first compliance period would not be expected to impact the net benefit conclusion. Costs and benefits would be expected to increase roughly proportionately, with benefits continuing to exceed costs. Higher order impacts related to jobs and associated economic activity from post-2032 investments in CCUS and other major decarbonization activities to reduce emissions from the sector are outside the scope of this analysis. The analysis does not fully consider the stimulation of new low-carbon industries, such as hydrogen, or for the longer-term competitiveness benefits of a decarbonized Canadian oil and gas sector in a world that complies with existing commitments under the Paris Agreement.

Analytical limitations

The proposed Regulations do not cover electricity generation. However, the analysis was unable to disaggregate the emissions from electricity generation by oil and gas producers. Therefore, the analysis overestimates the quantified emissions in covered sectors. In addition, net purchases of thermal energy and hydrogen are not accounted for in the analysis. These modelling parameters are not expected to have a significant impact on the results, as the emissions cap is set at a percentage below 2026 modelled emissions with the same estimation methodology employed in both the calculation of the emissions cap and the emissions covered under the proposed Regulations in the analysis.

The modelling of the proposed Regulations does not fully capture all features of the proposed Regulations. Nor does it account for the many variations in firm and household impacts. Also, many of the events that shape emissions and energy markets cannot be anticipated. In addition, future developments in technologies, demographics and resources cannot be foreseen with certainty. The scenarios used in this analysis are derived from a series of plausible assumptions regarding, among others, population and economic growth, prices, demand and supply of energy, and the evolution of abatement technologies.

Distributional analysis

This analysis considers the distribution of production impacts across different subsectors of the oil and gas industry, and regions in Canada. The impacts assessed in this distributional analysis are taken from the central case of the CBA, which makes use of a particular production forecast. The direction and magnitude of these estimated distributional impacts would vary under different production forecasts.

The distribution of these impacts among firms depends on their output, emissions intensity and compliance strategy. Under the proposed Regulations, covered operators would receive allowances free of charge. The distribution of allowances would be based on the relevant distribution rate (emissions per unit of production for a given activity) and a facility’s production over the last three years. Distribution rates are set based on national emissions intensities for different activities, which may result in some covered operators with less emissions-intense production having a surplus of free allowances, which they can sell or use in a future year. Covered operators with a deficit of allowances may purchase allowances from operators with a surplus, deploy abatement technologies, make use of compliance flexibilities, or reduce production.

The analysis allocates allowances based on in-model national historical emission intensities^{footnote 13} and does not consider banking of excess allowances. Because of this, when allocated allowances are greater than obligations, firms in the model sell all excess allowances and invest the revenue in increased production. This results in the model projecting that BC, SK, and NL increase production relative to the baseline scenario (i.e. grow more than projected in the baseline), while AB decreases (i.e. increases production but less than in the baseline). From a subsector perspective, oil sands mining and steam-assisted gravity drainage (SAGD) oil sands are estimated to be impacted more than other subsectors. Natural gas extraction varies between BC and AB primarily due to different average emission intensities. Additionally, frontier oil mining and heavy oil mining are estimated to slightly increase production relative to the baseline scenario. As is noted, all estimated impacts on production correspond to reduced growth from a baseline of growth. In absolute terms, production is estimated to continue to grow from current levels.

Table 8: Production impacts relative to baseline by sector and region, 2030–2032 (in petajoules)

Oil and gas subsector	BC	AB	SK	NL	Rest of Canada	Canadian total (2019)	Baseline scenario average (2030–2032)	Regulatory scenario average (2030–2032)	Reduced growth in production between baseline and regulatory scenarios (2030-2032)
Cyclic steam stimulation (CSS) oil sands	-	(74.0)	-	-	-	549.9	645.2	620.6	(74.0)
Frontier oil mining	-	-	-	12.6	0.1	352.2	647.2	651.5	12.7
Heavy oil mining	-	(19.3)	31.7	2.5	-	1 281.1	1 376.1	1 381.1	14.9
Light oil mining	(0.4)	(64.5)	13.0	-	0.4	2 626.2	3 026.2	3 009.0	(51.4)
Natural gas extraction	215.3	(246.2)	(9.7)	-	(0.6)	5 993.1	6 397.0	6 383.3	(41.3)
Oil sands mining	-	(153.7)	-	-	-	3 852.8	4 129.7	4 078.5	(153.7)
Primary oil sands	-	(7.0)	-	-	-	429.2	498.3	496.0	(7.0)
SAGD oil sands	-	(124.9)	-	-	-	2 861.1	4 308.5	4 266.9	(124.9)
Total	214.9	(689.7)	35.0	15.1	(0.2)	17 945.6	21 028.3	20 886.7	(424.9) table c7 note a
Table c7 note(s) Table c7 note a In the baseline scenario, over the 2030–2032 time period, it is estimated that about 63 100 PJ of oil and natural gas would be produced. Therefore, the estimated reduction of 424.9 PJ is equivalent to an estimated 0.7% reduction overall. Return to table c7 note a referrer

Note 1: Impacts on LNG, natural gas processing, and oil sands upgrading are not included as they are considered to be post-production processes.

Note 2: Figures may not add up to totals due to rounding.

The exact distribution of emissions reductions across sub-sectors and regions will depend on the actual relative distribution of costs and availability of emissions reduction technologies in the 2030–2032 time frame.

Impacts on production would in turn affect Canada’s gross domestic product (GDP), which thus increases in British Columbia, Saskatchewan, and Newfoundland and Labrador, and decreases in Alberta relative to the baseline, as shown in Table 9 below. Under the regulatory scenario, GDP is projected to grow by 22.0% between 2019 to 2030–2032, versus 22.1% under the baseline scenario.

Table 9: Economic impacts by region, 2030–2032 (average)

Region	Average GDP 2030–2032 (in billions of dollars, undiscounted)	Average change in GDP 2030–2032 (in billions of dollars, undiscounted)	2030–2032 Change in GDP (%)
British Columbia	450	0.4	0.10
Alberta	515	(2.0)	(0.39)
Saskatchewan	114	0.4	0.31
Newfoundland and Labrador	46	0.3	0.61
Rest of Canada	2 138	(0.3)	(0.01)
Canada	3 263	(1.2)	(0.04)

Note: Figures may not add up to totals due to rounding.

Small business lens

The proposed Regulations are estimated to affect approximately 560 operators, about 270 of which are likely to be small businesses. The proposed Regulations include a threshold designed to exclude small operators from being subject to compliance obligations under the emissions cap, and all small businesses undertaking the regulated industrial activities are expected to fall under this threshold. The emissions from these small businesses are expected to represent less than 1% of total emissions from regulated industrial activities. These small businesses would only bear administrative costs to register in 2025, and for annual quantification, reporting and verification requirements beginning in 2028.

Having data reported by small operators would allow the Department to allocate emissions allowances based on three years of historical data to a small operator that grows their production and exceeds the threshold as soon as they become subject to the emissions cap requirement. The data reported by small operators would also allow the Department to continue to monitor the emissions of small operators to support future reviews of the proposed Regulations, including reviews of the effectiveness.

The costs to small businesses are shown in Table 10 below.

Table 10: Small business lens summary

• Number of small businesses impacted: 270
• Number of years: 7.5 (2025–2032)
• Price year: 2023
• Present-value base year: 2024
• Discount rate: 2%

Totals	Present Value	Annualized value
Total cost (all impacted small businesses)	$37,336,800	$4,996,900
Cost per impacted small business	$137,800	$18,400

One-for-one rule

The one-for-one rule applies since there is an incremental increase in the administrative burden on business. The proposal is considered burden IN under the rule and a new regulatory title is introduced. All values listed in this section are presented in 2012 dollars.

The main driver of administrative costs is verification, as the proposed Regulations would require all operators to have their annual reports verified by a third party. Operators of multiple facilities would be required to submit verification reports for each facility; however, an operator’s smaller facilities would be aggregated by province into single reporting facilities requiring a single verification report under the proposed Regulations. It is estimated that a full third-party verification report would require 355 hours of external labour to complete, costing approximately $20,100 in 2012 dollars. For small operators, this cost is assumed to be fully incremental for each facility they operate; however, for large operators, the average incremental cost for a verification report is reduced to $7,400 to reflect the fact that many of these facilities are already submitting verification reports that reflect most of the requirements as part of their carbon pricing obligations. The requirement to submit verification reports would only begin in 2027 for covered operators, and 2029 for operators whose production falls below the threshold to be covered under the emissions cap. Additionally, the external labour hours required to resubmit a verification report with corrections are estimated to be about 55 hours (15% of the time required for the full report), or approximately $3,000.

There would also be administrative costs related to registration, quantification, reporting, supporting the verification process, and record keeping. Operators that are covered under the emissions cap would also have administrative requirements related to remitting compliance units. Where possible, the prescribed quantification methods would align with existing requirements, such as those under the Greenhouse Gas Reporting Program, the federal OBPS, and provincial regulations, to minimize the administrative burden. Under the assumption that the administrative efforts required are similar to those for OBPS, the total annualized administrative cost for operators to comply with the requirements of the proposed Regulations for the first 10 years is expected to be approximately $5.65 million for all operators, or an average of $10,100 per operator.^{footnote 14}

Regulatory cooperation and alignment

Canada is working in partnership with the international community to implement the Paris Agreement, to support the goal of limiting temperature rise this century to well below 2 °C and pursing efforts to limit the temperature increase to 1.5 °C. As part of its commitments made under the Paris Agreement, Canada pledged to reduce national GHG emissions by 40–45% below 2005 levels by 2030. The Government of Canada has also committed to achieving net-zero emissions by 2050. The proposed Regulations would support Canada in achieving these targets.

International cooperation

Cap-and-trade systems are a proven tool employed in numerous jurisdictions globally. The largest GHG emissions cap-and-trade system is the European Union Emission Trading System (EU ETS) established in 2006, where it covers over 10 000 installations and airlines operating in the European Union (EU) and around 40% of the EU’s total emissions.^{footnote 15} Currently, the EU ETS is in its fourth trading phase (2021 to 2030), with the Swiss ETS linked to the EU ETS as of January 2020.^{footnote 16} In addition, the United Kingdom (UK) ETS began operating in January 2021, following the departure of the UK from the EU ETS and it is currently unlinked to the EU ETS. The UK ETS covers around a quarter of the UK’s GHG emissions.^{footnote 17}

In the United States, the largest GHG cap-and-trade program is the California cap-and-trade system established in 2012, which covers about 75% of California’s greenhouse gas emissions^{footnote 18} and formally linked its program with Quebec in January 2014. The program covers around 400 facilities and emissions from the power, industrial, transport, and building sectors. California’s legislated target aims for a 40% reduction from 1990 GHG levels by 2030 and 85% reduction from 1990 levels with carbon neutrality by 2045.^{footnote 18}

The proposed Regulations have been designed considering features of existing cap-and-trade systems within the context of the policy objective of achieving emissions reductions in the Canadian oil and gas sector and implementation under CEPA. It is not proposed to seek linkage with other cap-and-trade systems, as this would erode the certainty in reducing GHG emissions in Canada’s oil and gas sector.

Federal, provincial and territorial policy linkages

British Columbia is the only provincial jurisdiction with planned action to move forward with a cap on oil and gas emissions, which has been communicated by the province as a backstop to federal action. Quebec currently has a cap-and-trade system that covers GHG emissions from the industrial, power, transport and building sectors and includes industrial process emissions. It was established in 2013 and linked to California’s cap-and-trade system in 2014.

There are expected interactions between the proposed Regulations and provincial (and federal) carbon pricing systems for industry as there would be reporting and compliance obligations under both systems and facilities are expected to consider the avoided cost or potential value of credit sales under both systems when making investment decisions. They would be separate systems and allowances, and surplus credits issued under provincial and federal carbon pricing systems for industry would not be eligible for use in the emissions cap. Where emissions are covered by both the federal and a provincial carbon pricing system, emissions reductions incented by the oil and gas emissions cap would also reduce a facility’s compliance obligation (or potentially result in credits) under provincial or federal carbon pricing systems.

The proposed Regulations would be complementary to existing regulatory measures. Recognition of emissions reductions driven by other measures would facilitate compliance under the emissions cap. These regulatory measures include provincial and territorial carbon pricing systems (mainly output-based pricing systems for industry in producing provinces), and the proposed Methane Regulations. The proposed Regulations are designed to function together with this broader suite of regulatory measures.

Surplus credits, performance credits or allowances generated under provincial, territorial or federal carbon pricing systems would not be eligible compliance units under the emissions cap. The proposed Regulations propose to recognize federal offset credits and the same set of offset credits generated from eligible programs and protocols identified on the list established under the OBPS Regulations.^{footnote 19}

The Department also notes complementary actions that have been put in place or are in development and that are outside of the scope of the proposed Regulations, which support decarbonization of the sector, as well as the short- and long-term competitiveness of the industry:

• Investment tax credits for carbon capture, utilization and storage, and clean hydrogen;
• Major funding tools to support innovation and emission-reducing activities, such as through Canada’s Energy Innovation Program, the Emissions Reduction Fund (onshore and offshore), the Canada Growth Fund, and the Strategic Innovation Fund;
• Support for Indigenous communities to share in the benefits of major projects in their territories, including through an Indigenous Loan Guarantee Program; and
• Support for workers in the transition to a low-carbon economy, as outlined in the interim plan 2023–2025 entitled Sustainable Jobs Plan.

The proposed Regulations are expected to function together with this broader suite of federal measures to achieve GHG emissions reductions in the oil and gas sector, while seeking to mitigate costs.

Other potential federal measures

While not included in the proposed Regulations, to provide additional flexibility, consideration may also be given to allowing facilities to remit ITMOs authorized for use by Canada as compliance units to cover a portion of their GHG emissions in the final Regulations. The Department intends to continue consulting on the potential inclusion of ITMOs as compliance units in the final Regulations.

Strategic environmental assessment

In accordance with the Cabinet Directive on the Environmental Assessment of Policy, Plan and Program Proposals, a strategic environmental assessment was undertaken to assess the impacts of this proposal. The assessment concluded that the proposed Regulations to establish a cap on GHG emissions from the oil and gas sector are expected to support several goals of the 2022–2026 Federal Sustainable Development Strategy, notably to foster innovation and green infrastructure in Canada, and to take action on climate change and its impacts.

Gender-based analysis plus

Upstream oil and gas production and LNG is a significant contributor to provincial GDP in oil and gas-producing provinces of Alberta, Saskatchewan, British Columbia and Newfoundland and Labrador. Potential impacts on the sector include some declines in production and consequent employment impacts. It is expected that oil and gas-producing regions would be impacted more than other parts of Canada. The 2016 Employment Equity Data Report noted that national labour market availability was made up of 48.2% women, 4.0% Aboriginal Peoples, and 21.3% members of visible minorities. In 2019, 36% of oil and gas workers in Canada identified as female, 6% as being Indigenous, 41% were immigrants, and 26% belonged to a designated visible minority group.^{footnote 20} Impacts on employment in the sector would be expected to affect these groups of individuals, among others. The Government has proposed support for workers in the transition to a low-carbon economy, as outlined in an interim plan for 2023–2025 entitled Sustainable Jobs Plan.

The proposed Regulations 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. And as noted in the “Qualitative impacts” section (see above), the proposed Regulations could influence the release of air pollutants in the oil and gas sector. However, the direction and magnitude of changes in air pollutants and air pollution-related health impacts in Canada are unable to be assessed. No other significant gender-based analysis plus (GBA+) impacts have been identified in association with the proposed Regulations.

Implementation, compliance and enforcement, and service standards

Implementation

Most provisions within the proposed Regulations would come into force on the date that they are registered. Certain provisions would come into force at a later date. For example, the registration prohibition would come into force on January 1, 2026, provisions establishing the emissions cap and setting out the distribution of emissions allowances would come into force on January 1, 2029, and the remittance obligations would come into force on January 1, 2030.

The Department would develop and administer new IT infrastructure to establish and manage the regulatory cap-and-trade system, including registration, reporting, allocation of allowances, and remittance of compliance units. In parallel with the public comment period for the proposed Regulations, it would consult on a draft of the Quantification Methods for the Oil and Gas Sector Greenhouse Gases Emissions Cap Regulations. The Department would also work with provinces to explore and establish agreements to implement cross-recognition of offset credits, and establish a list of carbon pricing systems where cross-recognition is authorized. The Department would also prepare guidance materials to support operators during the processes of registration, reporting and remittance.

The initial registration phase would occur in 2025, with annual reporting requirements beginning for some operators in 2026 (report due by June 1, 2027) and the remainder in 2028 (report due by June 1, 2029). Emissions allowances would be distributed before each compliance year on an annual basis, beginning in 2029 for the 2030 compliance year. The first compliance period would begin January 1, 2030, and the first remittance deadline would be January 31, 2032.

Compliance and enforcement

Departmental staff would begin to lead compliance promotion activities intended to raise awareness upon publication of the final Regulations. As the regulated community becomes more familiar with the requirements of the proposed Regulations, compliance promotion activities would be expected to decline to a maintenance level. Compliance promotion activities with operators and industry associations could include webinars and information sessions describing how to register and comply with regulatory obligations.

The proposed Regulations would be made under CEPA, and enforcement officers would, when verifying compliance, apply the Compliance and Enforcement Policy for CEPA. It is intended that Natural Resources Canada would also have a role in implementing the proposed Regulations through the decarbonization program.

Regulatory review

The effectiveness of the proposed Regulations would be subject to ongoing monitoring and regular reviews, including to ensure the sector is positioned to continue to deploy technically achievable emissions reductions, be a highly efficient and low-carbon source of fossil fuels as the globe shifts to lower carbon emissions and zero-carbon emission energy sources, and achieves net-zero by 2050. A review of the proposed Regulations would be undertaken, per the Department’s regular practice and in line with the Cabinet Directive on Regulation. This review would conclude within five years after the proposed Regulations come into force and would inform the trajectory of the emissions cap for the post-2032 period.

Contacts

Industrial Greenhouse Gas Emissions Management Division
Carbon Markets Bureau
Environmental Protection Branch
Department of the Environment
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: PlanPetrolieretGazier-OilandGasPlan@ec.gc.ca

Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Department of the Environment
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 Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations under subsection 93(1)^{footnote c}, sections 286.1^{footnote d}, 319 and 326^{footnote e} and subsection 330(3.2)^{footnote f} 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 a notice of objection requesting that a board of review be established under section 333^{footnote g} 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 the Industrial Greenhouse Gas Emissions Management Division, Environmental Protection Branch, Department of the Environment, 351 Saint-Joseph Boulevard, Gatineau, Quebec, K1A 0H3 (email: PlanPetrolieretGazier-OilandGasPlan@ec.gc.ca).

A person who provides information to the Minister may submit with the information a request for confidentiality under section 313^{footnote h} of that Act.

Ottawa, October 10, 2024

Wendy Nixon
Assistant Clerk of the Privy Council

Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations

Purpose

Purpose

1 The purpose of these Regulations is to reduce GHG emissions from certain activities carried out in the oil and gas sector by establishing a cap on GHG emissions.

Interpretation

Definitions

2 The following definitions apply in these Regulations.

Act means the Canadian Environmental Protection Act, 1999. (Loi)

annual threshold

means 365 000 barrels of oil equivalent produced during a calendar year. (seuil annuel)

attributed GHGs

means the quantity of GHGs attributed to a facility for a calendar year in accordance with section 17, expressed in carbon dioxide equivalent tonnes, that is reported in an annual report submitted under section 9 or, if applicable, reported in a corrected report submitted under section 14 or determined by the Minister under section 22. (GES attribués)

authorized official

means

• (a) in respect of an operator who is an individual, that individual or another individual who is authorized to act on their behalf;
• (b) in respect of an operator that is a corporation, an officer of the corporation who is authorized to act on its behalf; and
• (c) in respect of an operator that is another entity, an individual who is authorized to act on its behalf. (agent autorisé)

barrel

means a volumetric unit that represents 0.15899 m³. (baril)

biomass

means plants or plant materials, animal waste or any product made of either of these, including wood and wood products, bio-charcoal, agricultural residues, biologically derived organic matter in municipal and industrial wastes, landfill gas, bio-alcohols, pulping liquor, sludge digestion gas and fuel from animal or plant origin. (biomasse)

Canadian offset credit

means

• (a) an offset credit issued under subsection 29(1) of the Canadian Greenhouse Gas Offset Credit System Regulations; or
• (b) a unit or credit that is recognized under subsection 78(1) of the Output-Based Pricing System Regulations and meets the conditions set out in paragraphs 78(4)(a) to (d) of those Regulations. (crédit compensatoire canadien)

compliance period

means the period that begins on January 1, 2030 and ends on December 31, 2032 and each subsequent period of three consecutive calendar years. (période de conformité)

compliance unit

means

• (a) an emissions allowance created and distributed under section 31;
• (b) a decarbonization unit created under section 34; or
• (c) a Canadian offset credit. (unité de conformité)

cumulative production

means the production from all industrial activities carried out at all facilities of an operator, expressed in barrels of oil equivalent. (production cumulée)

facility

means any building, structure, including a mobile or fixed offshore industrial unit, and equipment — including vehicles and other machinery — that are operated in a coordinated and complementary way for the purpose of carrying out an industrial activity and located on

• (a) a single site or contiguous or adjacent sites;
• (b) multiple sites that form a network in which a central processing site is connected by gathering pipelines with one or more well sites; or
• (c) any site used in conjunction with an industrial activity, including a CO₂ storage site, tailings pond or wastewater lagoon or pond. (installation)

GHG

means a substance referred to in any of items 65 to 70 in Part 2 of Schedule 1 to the Act. (GES)

industrial activity

means an industrial activity set out in column 1 of Part 1 of Schedule 1. (activité industrielle)

marketable natural gas

means natural gas that consists of at least 90% methane and that meets the specifications for pipeline transport and sale for general distribution to the public. (gaz naturel commercialisable)

material discrepancy

means a discrepancy referred to in section 38. (écart important)

monthly threshold

means 30 000 barrels of oil equivalent produced during a month. (seuil mensuel)

natural gas condensates

means a complex combination of hydrocarbons primarily in the carbon range of C₅ to C₁₅ that are condensed during production at a well head, in a natural gas processing plant, natural gas pipeline or straddle plant, including any of their liquid distillates that are primarily in that carbon range. (condensats de gaz naturel)

natural gas liquids

means propane, butanes or pentanes plus, or a combination of them, obtained from the processing of raw natural gas or natural gas condensates. (liquides de gaz naturel)

new facility

means a facility at which no industrial activity was carried out before January 1, 2026 and that is expected to emit at least 10 000 CO₂e tonnes of GHG in any of the first three calendar years during which industrial activities are carried out at the facility. (nouvelle installation)

operator

means the person that has the charge, management or control of a facility at which industrial activities are carried out. (exploitant)

Quantification Methods

means the document entitled Quantification Methods for the Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations that is published by the Minister. (méthodes de quantification)

specified emissions source

means a source of emissions that is set out in Part 2 of Schedule 1. (source spécifique d’émissions)

thermal energy

means useful energy in the form of steam or hot water that is intended to be used for an industrial purpose. (énergie thermique)

Incorporation by reference

3 (1) Subject to subsection (2), a reference to any document incorporated by reference into these Regulations is, unless otherwise indicated, a reference to the most recently published version of the document.

Quantification Methods

(2) The version of Quantification Methods to be complied with for a calendar year is the version that was most recently published before the beginning of that year.

Conversion to CO₂e tonnes

4 For the purposes of these Regulations, a quantity of a GHG, expressed in tonnes, is converted into carbon dioxide equivalent (CO₂e) tonnes by multiplying that quantity by the global warming potential set out for the GHG in Quantification Methods.

Deemed facility

5 Multiple facilities are deemed to be a single facility for the purposes of these Regulations if

• (a) each facility has the same operator or, in the case of multiple operators, an operator in common;
• (b) each facility is located in the same province; and
• (c) no information regarding GHG emissions for the 2024 calendar year or any subsequent calendar year from any of the facilities was required in accordance with a notice published under subsection 46(1) of the Act.

Requirements of operator

6 An operator must comply with all requirements set out in these Regulations related to a facility — including the submission of reports, the remittance of compliance units and the maintenance of records — for any period that it is the operator of that facility.

PART 1
Registration and Reporting

Registration

Obligation — existing operator

7 (1) An operator must register by submitting to the Minister the information set out in Schedule 2.

Obligation — new operator

(2) A person that expects to become an operator must, before emitting any GHGs from an industrial activity carried out at its facility, register by submitting to the Minister the information set out in Schedule 2.

Date of registration

(3) An operator referred to in subsection (1) is registered beginning on the day on which the required information is submitted to the Minister and a person referred to in subsection (2) is registered on the day, indicated in the required information, that industrial activities are expected to begin.

Prohibition

GHG emissions — unregistered operator

8 An operator must not emit any GHG from any industrial activity carried out at its facility unless the operator is registered in accordance with section 7.

Annual Report

Annual report

9 (1) Beginning with the first calendar year after 2025 in which GHGs are emitted from an industrial activity carried out at a facility, the operator of the facility must submit to the Minister an annual report in respect of the facility no later than June 1 of the subsequent year.

Contents of annual report

(2) The annual report must contain the following information in respect of the calendar year in question:

• (a) the information set out in Schedule 3;
• (b) the production from each industrial activity carried out at the facility, determined in accordance with section 16;
• (c) the quantity of GHGs attributed to the facility, determined in accordance with section 17; and
• (d) the quantity of GHGs from all specified emissions sources at the facility, determined in accordance with section 18.

Exemption — 2026 and 2027

(3) Despite subsection (1), an operator is not required to submit an annual report for the 2026 and 2027 calendar years if

• (a) the operator’s cumulative production, as reported to one of the following authorities, was below the monthly threshold in each month from January 2024 to June 2025:
  • (i) the province in which the facility is located,
  • (ii) the Canada Energy Regulator,
  • (iii) the Canada-Nova Scotia Offshore Petroleum Board, and
  • (iv) the Canada–Newfoundland and Labrador Offshore Petroleum Board; and
• (b) no information regarding GHG emissions for the 2024 calendar year from any of the operator’s facilities was required in accordance with a notice published under subsection 46(1) of the Act.

Report on cumulative production

10 (1) An operator that is required to submit an annual report under section 9 must submit, together with the annual report, a report on cumulative production for the calendar year.

Contents of report on cumulative production

(2) The report on cumulative production must contain the following information:

• (a) the information set out in Schedule 4; and
• (b) the operator’s cumulative production, determined in accordance with Quantification Methods.

Compression of natural gas

(3) For the purposes of paragraph (2)(b), the operator of a facility at which the industrial activity referred to in item 6 of Part 1 of Schedule 1 is carried out must determine, in accordance with Quantification Methods, the production from that activity in volume of natural gas throughput, expressed in 1 000 m³ of natural gas equivalent.

Verification of annual report

11 (1) An operator must have the annual report referred to in section 9 verified by a verification body.

Corrections

(2) If the verification body identifies an error or omission during the verification of an annual report, the operator must

• (a) correct the error or omission before submitting the annual report; or
• (b) submit to the Minister, together with the annual report, the reason that the error or omission was not corrected.

Verification report

(3) The operator must submit, together with the annual report, the verification report prepared by the verification body.

Errors and omissions

12 (1) If, within five years after the day on which an annual report is submitted under section 9, an operator becomes aware of an error or omission in the report, the operator must notify the Minister in writing within 30 days after the day on which the operator becomes aware of the error or omission.

Contents of notice

(2) The notice must

• (a) describe the error or omission;
• (b) indicate whether the error or omission is quantitative or qualitative; and
• (c) if the error or omission is quantitative, indicate whether
  • (i) the error or omission increased or decreased attributed GHGs or production from any industrial activity,
  • (ii) in the case of an error or omission in relation to attributed GHGs, the error or omission is below, equal to or above the correction threshold referred to in section 13, and
  • (iii) the error or omission would have constituted a material discrepancy if it had been identified during the verification of the annual report.

Identification by Minister

(3) The Minister must notify the operator in writing that the operator must submit a corrected report that meets the requirements set out in section 14 if, within five years after the day on which an annual report is submitted under section 9, the Minister identifies an error or omission in the report that

• (a) is equal to or above the correction threshold referred to in section 13; or
• (b) would have constituted a material discrepancy if it had been identified during the verification of the annual report.

Correction threshold

13 For the purposes of sections 12 and 14, an error or omission in relation to attributed GHGs reported in an annual report is equal to or above the correction threshold if

• (a) the value described in A in the formula set out in paragraph (b) is at least 1 000 CO₂e tonnes; or
• (b) the result of the following formula, expressed as a percentage, is at least 2% and the value described in A is at least 10 CO₂e tonnes:

A ÷ B

where

A

is the absolute value of the net result of all overstatements and understatements identified by the operator under subsection 12(1) or by the Minister under subsection 12(3), expressed in CO₂e tonnes, and

B

is the attributed GHGs reported in the annual report.

Corrected report

14 (1) An operator must submit a corrected report to the Minister

• (a) within 60 days after the day on which the notice is sent under subsection 12(1) or (3) if the error or omission is equal to or above the correction threshold referred to in section 13 but would not have constituted a material discrepancy if it had been identified during the verification of the annual report; and
• (b) within 120 days after the day on which the notice is sent under subsection 12(1) or (3) if the error or omission would have constituted a material discrepancy if it had been identified during the verification of the annual report.

Contents of corrected report

(2) The corrected report must include the information referred to in subsection 9(2) and the following information:

• (a) the corrections made to the information submitted in the annual report;
• (b) the circumstances that led to the error or omission;
• (c) the reasons why the error or omission was not previously detected; and
• (d) the measures that have been and will be implemented to avoid errors or omissions of the same type.

Verification of corrected report

(3) If the error or omission would have constituted a material discrepancy if it had been identified during the verification of the annual report, the operator must have the corrected report verified by a verification body.

Verification report

(4) The operator must submit, together with the corrected report, the verification report prepared by the verification body if required under subsection (3).

Verification requirements

15 The operator must ensure that a verification body that verifies an annual report or a corrected report

• (a) meets the requirements set out in section 37;
• (b) is not in conflict of interest within the meaning of section 39;
• (c) conducts the number of facility visits required by section 40; and
• (d) includes in the verification report all of the information set out in Schedule 5.

Quantification of Production and GHGs

Quantification of Production

Production

16 The operator must determine, in accordance with Quantification Methods, the production from each industrial activity carried out at each of its facilities during a calendar year in the unit of measurement set out in column 2 of Part 1 of Schedule 1 for that industrial activity.

Quantification of GHGs

Attributed GHGs

17 (1) The operator must determine the quantity of GHGs attributed to its facility for a calendar year in accordance with the formula

A − B + C − D + E − F

where

A

is the quantity of GHGs from all specified emissions sources at the facility, determined in accordance with section 18;

B

is the quantity of CO₂ determined in accordance with section 19;

C

is the quantity of GHGs resulting from the production of thermal energy outside the facility that is supplied to the facility during the calendar year;

D

is the quantity of GHGs resulting from the production of thermal energy that is transferred from the facility during the calendar year;

E

is the quantity of GHGs resulting from the production of hydrogen outside the facility that is supplied to the facility during the calendar year; and

F

is the quantity of GHGs resulting from the production of hydrogen that is transferred from the facility during the calendar year.

Elements B to F

(2) The quantities referred to in the descriptions of B to F in the formula set out in subsection (1) are determined in accordance with Quantification Methods and expressed in CO₂e tonnes.

Elements D or F

(3) A quantity of GHGs may be included for the purposes of D or F in the formula set out in subsection (1) only if it has been included in the quantity referred to in the description of A in that formula.

Biomass

(4) Any quantity of CO₂ from biomass, determined in accordance with Quantification Methods, is not included in the quantity of GHGs referred to in the descriptions of A to F in the formula set out in subsection (1).

Rounding

(5) If the result from the determination under subsection (1) is not a whole number, the result is to be rounded to the nearest whole number or, if the number is equidistant between two whole numbers, to the higher number.

Determination of GHGs from a facility

18 (1) The operator must determine the quantity of GHGs from the facility during a calendar year, expressed in CO₂e tonnes, in accordance with the formula

${\displaystyle \sum _{i=1}^n\sum _{j=1}^m{E}_{i,j}\times {\mathrm{GWP}}_j}$

where

E_i,j

is the quantity of GHG “j” from the facility for each specified emissions source “i” during the calendar year, expressed in tonnes, determined in accordance with Quantification Methods;

GWP_j

is the global warming potential set out in Quantification Methods for GHG “j”;

i

is the i^th specified emissions source, where 1 ≤ i ≤ n and where n is the number of specified emissions sources; and

j

is the j^th GHG, where 1 ≤ j ≤ m and where m is the number of GHGs.

Electricity

(2) Any quantity of GHGs resulting from the production of electricity, determined in accordance with Quantification Methods, is not included in the quantity of GHGs determined under subsection (1).

Missing data

(3) If the data required to quantify the GHGs from a facility are missing for a period of a calendar year, replacement data for that period must be calculated in accordance with Quantification Methods.

Sampling, analysis and measurement

(4) The operator must comply with all sampling, analysis and measurement requirements set out in Quantification Methods for the purposes of determining a quantity of GHGs.

CO₂ storage

19 (1) A quantity of CO₂ may be included in the quantity referred to in the description of B in the formula set out in subsection 17(1) only if it has been included in the quantity referred to in the description of A in that formula, captured at the facility and permanently stored in a storage project that meets the following criteria:

• (a) the geological site into which the CO₂ is injected is
  • (i) a deep saline aquifer the sole purpose of which is storage of CO₂, or
  • (ii) a depleted oil reservoir for the purpose of enhanced oil recovery using a closed loop system; and
• (b) the CO₂ stored for the purposes of the project is captured, transported and stored in accordance with the laws of Canada or a province or the laws of the United States or one of its states.

Factor

(2) Any quantity of CO₂ that has been stored in a geological site referred to in paragraph (1)(a) must be multiplied by 0.995 before being included in the quantity referred to in the description of B in the formula set out in subsection 17(1).

Measurement

Measuring device

20 Any measuring device that is used to determine a quantity under these Regulations must comply with Quantification Methods or, in the absence of an applicable requirement set out in Quantification Methods, must

• (a) be installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or, if those specifications are not available, with any applicable generally recognized national or international industry standard; and
• (b) maintain accuracy within ± 5%.

Continuous emissions monitoring system

21 If a continuous emissions monitoring system is used to quantify GHGs for the purposes of these Regulations, the operator must ensure that the system complies with the requirements set out in Quantification Methods.

Minister’s Determination

Determination

22 (1) The Minister may, for a calendar year, determine a facility’s production or the quantity of GHGs attributed to a facility if

• (a) a material discrepancy exists in relation to the facility’s attributed GHGs or production; or
• (b) the verification opinion referred to in paragraph 3(n) of Schedule 5 indicates that it is not possible to determine that a material discrepancy exists or that the annual report or corrected report was prepared in accordance with these Regulations.

Elements

(2) For the purposes of subsection (1), the Minister must take into account the following:

• (a) the annual report and the verification report for the calendar year, if any, and any previous reports;
• (b) any information provided to the Minister in accordance with a notice published under subsection 46(1) of the Act;
• (c) any information related to the GHGs from the facility or the facility’s production provided to a province, the Canada Energy Regulator, the Canada-Nova Scotia Offshore Petroleum Board or the Canada–Newfoundland and Labrador Offshore Petroleum Board;
• (d) if the determination is about a facility’s production, information in respect of industrial activities carried out in Canada or in other jurisdictions that are similar to those carried out at the facility;
• (e) if the determination is about the facility’s attributed GHGs, accepted quantification methods used to determine the quantity of GHGs from facilities engaged in the same industrial activity or in the same type of industrial activity as the facility; and
• (f) any other information provided by the operator.

Request by Minister

(3) The operator must provide to the Minister, within the time limit specified by the Minister, any information requested by the Minister that is necessary to determine the facility’s attributed GHGs or production.

Missing report

(4) If the annual report, the verification report or, if any, the corrected report required for a calendar year is not submitted to the Minister, the facility’s production referred to in section 16 is deemed to be zero and the Minister must determine the facility’s attributed GHGs based on the information referred to in subsection (2).

Notice

(5) The Minister must notify the operator, in writing, of a determination made under this section.

PART 2
Emissions Cap, Remittance of Compliance Units and Distribution of Emissions Allowances

Emissions Cap

Calculation of emissions cap

23 The emissions cap for each calendar year of a compliance period is equal to 73% of the sum of the attributed GHGs for the 2026 calendar year of each facility for which an annual report was required for that year.

Prohibition

Prohibition

24 An operator referred to in section 26 must not emit any GHG from any industrial activity carried out at its facility unless the operator remits the compliance units required by section 25.

Remittance

Remittance obligation

25 (1) An operator referred to in section 26 must remit to the Minister, no later than January 31 of the year that is two years after the end of a compliance period, one compliance unit for each CO₂e tonne of its facility’s attributed GHGs for each calendar year of that compliance period.

Interim remittance

(2) The operator must remit a number of compliance units equal to at least 30% of attributed GHGs for each of the first and second years of a compliance period no later than

• (a) January 31 of the year that is two years after the first year of a compliance period, in the case of the attributed GHGs for that year; and
• (b) January 31 of the year that is two years after the second year of a compliance period, in the case of the attributed GHGs for that year.

New facility

(3) For the purposes of this section, a new facility’s attributed GHGs are deemed to be zero until January 1 of the year that is five calendar years after the year in which industrial activities begin at the new facility.

Start of remittance

26 (1) Subject to subsections (2) and (3), an operator whose cumulative production in a calendar year is equal to or above the annual threshold is subject to section 25 beginning on January 1 of the calendar year that is two years after the year in which the operator’s cumulative production, as reported under section 10, is equal to or above the annual threshold.

Operation of an existing facility

(2) An operator that takes over the operation of a facility from which the quantity of GHGs, calculated in accordance with section 18 and reported in the facility’s most recent annual report, is equal to or above 10 000 CO₂e tonnes is subject to section 25 beginning in the year that the operator takes over the operation of the facility.

Remittance beginning in 2030

(3) An operator whose cumulative production in any of the 2026 to 2028 calendar years, as reported under section 10, is equal to or above the annual threshold is subject to section 25 beginning in 2030.

End of remittance obligation

27 An operator is no longer subject to section 25 beginning on January 1 of the year following four consecutive calendar years during which the operator’s cumulative production, as reported under section 10, is less than half of the annual threshold.

Eligible compliance units

28 (1) The compliance units that are remitted under section 25 must meet the following requirements:

• (a) at least 80% of the compliance units must be emissions allowances;
• (b) no more than 10% of the compliance units may be decarbonization units;
• (c) no more than 20% of the compliance units may be Canadian offset credits;
• (d) any emissions allowance must have been distributed for the compliance period for which the remittance is made or for the preceding compliance period;
• (e) any Canadian offset credit must be associated with GHG reductions or removals that occurred no more than five calendar years before the compliance period for which the remittance is made; and
• (f) in the case of a decarbonization unit, the contribution made to create the decarbonization unit must correspond to a calendar year in the compliance period for which the remittance is made.

Cross-recognition

(2) An operator may remit the same Canadian offset credit to fulfill a requirement under both section 25 and an eligible system referred to in subsection (3) if, under that eligible system, the Canadian offset credit is remitted

• (a) for a calendar year in the same compliance period for which remittance is made under section 25;
• (b) in relation to an industrial activity carried out in the same province as the facility in respect of which remittance is made under section 25; and
• (c) to fulfill a requirement other than a requirement that relates to an extraordinary situation, such as to replace a cancelled credit or as compensation for non-compliance with a requirement.

Eligible systems

(3) The eligible systems are

• (a) a system for pricing GHG emissions established under Division 1 of Part 2 of the Greenhouse Gas Pollution Pricing Act; and
• (b) a provincial carbon pricing system that is subject to a recognition agreement between the Minister and a province and which is on the list published on the Department of the Environment’s website.

Request by Minister

(4) The operator must provide to the Minister, within the time limit specified by the Minister, any information requested by the Minister that is necessary to determine eligibility to remit a Canadian offset credit under this section.

Corrected report

29 (1) If, after the deadline set out in subsection 25(1), an operator submits a corrected report under section 14 that indicates that attributed GHGs are higher than the amount initially reported, the Minister must notify the operator of the number of compliance units that the operator must remit to the Minister.

Remittance obligation

(2) The operator must remit to the Minister the number of compliance of units referred to in the notice no later than January 31 of the year that is two calendar years after the day on which the Minister provides the notice.

Eligible compliance units

(3) The compliance units that are remitted under subsection (2) must meet the following requirements:

• (a) at least 80% of the compliance units must be emissions allowances;
• (b) no more than 10% of the compliance units may be decarbonization units;
• (c) no more than 20% of the compliance units may be Canadian offset credits;
• (d) any emissions allowance must have been distributed in the three calendar years before the deadline set out in subsection (2);
• (e) any Canadian offset credit must be associated with GHG reductions or removals that occurred no more than five calendar years before the deadline set out in subsection (2); and
• (f) in the case of a decarbonization unit, the contribution made to create the decarbonization unit must correspond to the calendar year in which the Minister provides the notice referred to in subsection (2).

Cancelled Canadian offset credit

30 (1) If, within five years after the day on which an operator remits to the Minister a Canadian offset credit referred to in paragraph (b) of the definition Canadian offset credit in section 2, the issuing province cancels and does not provide a mechanism to replace the Canadian offset credit, the Minister must notify the operator of the number of Canadian offset credits that were cancelled by the province and the number of compliance units that the operator must remit to the Minister.

Remittance obligation

(2) The operator must remit to the Minister the number of compliance units referred to in the notice no later than January 31 of the year that is two calendar years after the day on which the Minister provides the notice.

Eligible compliance units

(3) The compliance units that are remitted under subsection (2) must be

• (a) emissions allowances distributed in the three calendar years before the deadline set out in subsection (2); or
• (b) Canadian offset credits associated with GHG reductions or removals that occurred no more than five calendar years before the deadline set out in subsection (2).

Distribution of Emissions Allowances

Creation and distribution of emissions allowances

31 For the purposes of section 25, the Minister must

• (a) create emissions allowances, each with a value corresponding to one CO₂e tonne, for each calendar year of a compliance period in an amount equal to the emissions cap calculated in accordance with section 23; and
• (b) distribute the emissions allowances between operators that are subject to section 25.

Calculation

32 (1) The number of emissions allowances distributed to an operator in respect of a facility for a calendar year for which the operator is required to remit compliance units under section 25 is determined by the formula

A × B ÷ F

where

A

is the number of emissions allowances created under section 31 for the calendar year;

B

is the number of emissions allowances determined by the formula

${\displaystyle \sum _j(\frac{C_{i-4,j}+C_{i-3,j}+C_{i-2,j}}{E}\times D_{i,j})}$

where

C_i,j

is the operator’s production from industrial activity “j” carried out at the facility during the i^th calendar year,

D_i,j

is the distribution rate set out in column 3 of Part 1 of Schedule 1 that is applicable to the j^th industrial activity during the i^th calendar year,

i

is the calendar year for which the emissions allowances are being distributed,

j

is the j^th industrial activity carried out at the facility, and

E

is the greater of

• (a) the number of calendar years in the three calendar years prior to the i-1^th calendar year during which the operator carried out industrial activities at the facility, and
• (b) the number of calendar years in the three calendar years prior to the i-1^th calendar year for which any operator that is subject to section 25 submitted an annual report for that facility; and

F

is the sum of the number of emissions allowances determined in accordance with the formula set out in the description of B for all facilities of all operators that are entitled to receive emissions allowances for the calendar year.

Production — C_i,j

(2) The production from an industrial activity during a calendar year referred to in the description of C_i,j in subsection (1) is the production reported by the operator in the annual report for that calendar year or, if applicable, that is

• (a) reported in a corrected report submitted to the Minister under section 14 before September 1 of the year before the calendar year for which the emissions allowances are distributed; or
• (b) determined by the Minister under section 22.

Rounding

(3) If the result from the determination under subsection (2) is not a whole number, the result is to be rounded down to the nearest whole number.

New facility

(4) An operator is not entitled to receive emissions allowances in respect of a new facility for a calendar year in which the new facility’s attributed GHGs are deemed to be zero under subsection 25(3).

Distribution date

(5) The emissions allowances are distributed no later than November 30 of the year before the calendar year for which they are distributed.

Transfer

(6) An emissions allowance distributed under this section is transferable solely between operators.

Corrected report — emissions allowances

33 (1) If, after August 31 of a year in which emissions allowances are distributed, an operator submits a corrected report under section 14 that indicates that a facility’s production is lower than the production used to determine the number of emissions allowances distributed to the operator, the Minister must notify the operator of the number of emissions allowances that were distributed to the operator in error and the number of compliance units that must be remitted to the Minister.

Calculation of emissions allowances distributed in error

(2) The number of emissions allowances distributed to an operator in error is determined by the formula

G − H

where

G

is the number of emissions allowances distributed to the operator for the applicable calendar year, calculated in accordance with section 32; and

H

is the number of emissions allowances to which the operator is entitled, calculated by replacing only the value determined for C_i,j in subsection 32(1) with the correct value based on the corrected report.

Remittance obligation

(3) An operator must remit to the Minister the number of compliance units referred to in the notice sent under subsection (1) no later than January 31 of the year that is two calendar years after the day on which the Minister provides the notice.

Eligible compliance units

(4) The compliance units that are remitted under subsection (3) must be emissions allowances distributed in the three calendar years before the deadline set out in that subsection.

Decarbonization Units

Creation of decarbonization units

34 (1) A decarbonization unit with a value corresponding to one CO₂e tonne is created when an operator

• (a) submits to the Minister the information set out in Schedule 6; and
• (b) makes a contribution to the decarbonization program at the rate set out in column 2 of the table in Schedule 6 that corresponds to the year for which the contribution is made.

Purpose of decarbonization program

(2) The purpose of the decarbonization program, a funding program within the meaning of subsection 327.1(1) of the Act, is to support the reduction of GHG emissions from the oil and gas sector in Canada.

Use of contributions

(3) A contribution referred to in paragraph (1)(b) must be used to fund projects that support the reduction of GHG emissions from the oil and gas sector by the 10th anniversary of the day on which the contribution is made.

Not transferable

(4) A decarbonization unit is not transferable.

Timing of Remittance

Required information

35 A compliance unit remitted under section 25 or subsection 29(2), 30(2) or 33(3) is considered to be remitted on the day on which all of the required information set out in Schedule 7 is submitted to the Minister.

PART 3
Miscellaneous

Cessation of Industrial Activities

Permanent cessation

36 (1) For the purposes of these Regulations, an operator is considered to have permanently ceased all industrial activities at a facility as of January 1 of the year following

• (a) the year indicated by the operator in the report submitted under section 10 as the year that industrial activities have ceased; or
• (b) four consecutive calendar years during which the facility’s production, determined in accordance with section 16 and as reported in annual reports or corrected reports, is zero.

Consequences

(2) If an operator has permanently ceased all industrial activities at a facility, an annual report under section 9 is not required in respect of the facility and no emissions allowances are distributed under section 32 in respect of the facility.

Obligations

(3) An operator that has permanently ceased all industrial activities at a facility is responsible for the obligations set out in sections 12, 14, 15, 25, 29, 30, 33 and 41 to 43.

Verification

Verification body

37 The verification of an annual report or a corrected report must be conducted by a verification body that

• (a) meets the following accreditation requirements:
  • (i) it is accredited as a verification body by the Standards Council of Canada, the ANSI National Accreditation Board or any other accreditation organization that is a member of the International Accreditation Forum to standard ISO 14065, entitled General principles and requirements for bodies validating and verifying environmental information and published by the International Organization for Standardization,
  • (ii) it has a scope of accreditation that is sufficient to verify the annual report or the corrected report, and
  • (iii) it is not suspended by the accreditation organization that issued the accreditation; and
• (b) conducts the verification in accordance with the version of standard ISO 14064-3, entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements and published by the International Organization for Standardization, that is set out in the accreditation by applying methods that allow it to make a determination to a reasonable level of assurance, as defined in that standard, on whether
  • (i) a material discrepancy exists with respect to the attributed GHGs or production reported in the annual report or corrected report, and
  • (ii) in the verification body’s opinion, the annual report or corrected report was prepared in accordance with these Regulations.

Material discrepancy — attributed GHGs

38 (1) A material discrepancy exists in relation to the attributed GHGs reported in an annual report or corrected report if the value determined for A in the following formula is at least 10 000 CO₂e tonnes or if the result of the formula, expressed as a percentage, is at least 5%:

A ÷ B

where

A

is the absolute value of the net result of all overstatements and understatements revealed during the verification or identified by the Minister under subsection 12(3), expressed in CO₂e tonnes; and

B

is the attributed GHGs.

Material discrepancy — production

(2) A material discrepancy exists in relation to a facility’s production from an industrial activity, as reported in an annual report or corrected report, if the result of the following formula, expressed as a percentage, is at least 0.1%:

A ÷ B

where

A

is the absolute value of the net result of all overstatements and understatements revealed during the verification or identified by the Minister under subsection 12(3), expressed in the unit of measurement set out in column 2 of Part 1 of Schedule 1 for that industrial activity; and

B

is the production from the industrial activity, expressed in that unit of measurement.

Conflict of interest

39 (1) An operator must ensure that no real or potential conflict of interest exists between the operator and the verification body, including members of the verification team and any person associated with the verification body, that is a threat to or compromises the verification body’s impartiality and that cannot be effectively managed.

Consecutive verifications

(2) An operator must not have an annual report verified by a verification body that has verified six consecutive annual reports prepared under these Regulations with respect to the same facility, unless three years have elapsed since the last of those reports was verified. However, a corrected report may be verified by the verification body within those three years if it is in relation to an annual report verified by that verification body.

Maximum number of verifications

(3) The operator must not have more than a total of six of its annual reports prepared under these Regulations for the same facility verified by the same verification body within a period of nine years.

Facility visit

40 (1) Subject to subsection (2), an operator must ensure that the facility is visited by the verification body that is responsible for verifying an annual report or corrected report in the following situations:

• (a) the verification body is verifying an annual report or corrected report for that facility for the first time;
• (b) two calendar years have passed since a verification body has visited the facility;
• (c) with respect to the last annual report for the facility prepared under these Regulations, the verification body made a determination that a material discrepancy exists with respect to the attributed GHGs or production reported;
• (d) the Minister has notified the operator that a facility visit is required for the purposes of verifying a corrected report; or
• (e) the verification body is of the opinion a facility visit is required.

Other visits

(2) The operator must ensure that the verification body can visit all the buildings that keep information necessary for verifying an annual report or a corrected report.

Facility referred to in section 5

(3) In the case of a facility referred to in section 5, only a number of facilities determined by the verification body is required to be visited.

Records

Records

41 (1) An operator must maintain, separately for each calendar year, a record of the following information with respect to the facility:

• (a) the quantity of each GHG from each specified emissions source;
• (b) all data used for calculations made under these Regulations for each specified emissions source and each GHG, including data used to estimate missing data under subsection 18(3);
• (c) all sampling, analysis and measurement data for each specified emissions source and each GHG;
• (d) the methods used to quantify, sample, analyze and measure each specified emission source;
• (e) the methods and data used to quantify production;
• (f) the procedural changes made in data collection and calculations and changes to measuring devices used to quantify GHGs or production;
• (g) documents that demonstrate that the maintenance, calibration and operation of measuring devices was done in accordance with sections 20 and 21;
• (h) any errors or omissions identified during the verification and the measures taken to correct them, with all supporting data and documents;
• (i) a list of any electricity generation equipment that was not included in the quantification of GHG emissions under subsection 18(2) and any data related to the quantification of GHG emissions from electricity production;
• (j) if a quantity of CO₂ is included in B in the formula set out in subsection 17(1),
  • (i) the quantities of CO₂ captured, transported and stored, expressed in tonnes, and the data used to quantify that CO₂, and
  • (ii) documents that demonstrate that the CO₂ was captured, transported and stored in accordance with the laws of Canada or a province or of the United States or one of its states; and
• (k) if thermal energy or hydrogen was supplied to or transferred from the facility,
  • (i) the receipt or other document that indicates the quantity of thermal energy or hydrogen supplied or transferred,
  • (ii) the methods and data used to quantify the quantity of thermal energy or hydrogen supplied or transferred and, in the case of thermal energy, the data used to quantify the ratio of heat from the combustion of fossil fuel, and
  • (iii) the methods and data used to quantify the GHG emissions related to thermal energy or hydrogen supplied or transferred.

Minister’s request

(2) At the request of the Minister, an operator must maintain a record of any information provided under paragraph 22(2)(f) or subsection 22(3) or 28(4).

Availability of information

(3) Information must be included in the record within 30 days after the day on which the information becomes available and a copy of any record that is required to be maintained must, on the Minister’s request, be provided to the Minister without delay.

Retention of information

42 (1) An operator must, for a period of seven years beginning on the date the records were created, retain all records referred to in section 41 and a copy of any information submitted to the Minister under these Regulations, together with any supporting documents, including any calculations, measurements and other data on which the information is based.

Location of records

(2) The records, copies and documents must be retained at the operator’s principal place of business in Canada or, upon notification to the Minister of the civic address, at any other place in Canada where they can be inspected.

Relocation

(3) If the location of the records, copies and documents changes, the operator must notify the Minister, in writing, of the civic address of the new location within 30 days after the day of the change.

Submission of Information

Electronic submission

43 (1) Any information that the operator must provide to the Minister under these Regulations must be submitted electronically in the form and format specified by the Minister and must bear the electronic signature of the operator or of the authorized official.

Provision on paper

(2) If the Minister has not specified a form and format or if it is not feasible to submit the information in accordance with subsection (1) because of circumstances beyond the control of the operator or the authorized official, the information must be submitted on paper, signed by the operator or the authorized official, in the form and format specified by the Minister. However, if no form and format has been so specified, it may be submitted in any form and format.

Request for Confidentiality

Content of request

44 A request for confidentiality submitted under section 313 of the Act must be accompanied by

• (a) the information to which the request pertains, clearly identified; and
• (b) the supporting justification that the information referred to in paragraph (a) has been treated as confidential by the person making the request and is not, and has never been, available to the public.

Consequential Amendment to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999)

45 The schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) ^{footnote 21} is amended by adding the following in numerical order:

Item	Column 1 Regulations	Column 2 Provisions
45	Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations	(a) section 8 (b) section 24 (c) subsection 25(1) (d) subsection 25(2) (e) subsection 29(2) (f) subsection 30(2) (g) subsection 33(3)

Coming into Force

Registration

46 (1) Subject to subsections (2) to (4), these Regulations come into force on the day on which they are registered.

January 1, 2026

(2) Sections 8, 9, 16 to 21 and 41 come into force on January 1, 2026.

January 1, 2029

(3) Sections 23 and 31 come into force on January 1, 2029.

January 1, 2030

(4) Sections 24 and 25 come into force on January 1, 2030.

SCHEDULE 1

(Section 2, subsection 10(3), section 16 and subsections 32(1) and 38(2))

Industrial Activities and Specified Emissions Sources

PART 1

Industrial Activities and Distribution Rates

Item	Column 1 Industrial Activity	Column 2 Unit of Measurement	Column 3 Distribution Rate (tonnes of CO2e per Unit of Measurement)
1	The following bitumen and other crude oil production activities, other than extraction of bitumen through thermal in situ recovery or from surface mining:
	(a) extraction, processing and production of light crude oil with a density of less than 920 kg/m3 at 15°C; and	barrels of light crude oil produced	0.0164
	(b) extraction, processing and production of bitumen or other heavy crude oil with a density greater than or equal to 920 kg/m3 at 15°C.	barrels of bitumen and heavy crude oil produced	0.0313
2	Thermal in situ recovery of bitumen from oil sands deposits	barrels of bitumen produced	0.0368
3	Surface mining of oil sands and extraction of bitumen	barrels of bitumen produced	0.0138
4	Upgrading of bitumen or heavy oil to produce synthetic crude oil	barrels of synthetic crude oil produced	0.0263
5	Extraction of natural gas and natural gas condensates	1000 m3 of natural gas equivalent produced	0.0599
6	Compression of natural gas between production wells, natural gas processing facilities or re-injection sites	megawatt hours (MWh) of brake power produced for compression by engine, motor or turbine	0.233
7	Processing of natural gas or natural gas condensates into marketable natural gas and into natural gas liquids	1000 m3 of natural gas equivalent delivered	0.0305
8	Production of liquefied natural gas	tonnes of liquefied natural gas delivered	0.0743

PART 2

Specified Emissions Sources

Item	Column 1 Emissions Source	Column 2 Description
1	Stationary fuel combustion	Emissions from stationary devices that combust fossil fuels for the purpose of producing useful heat
2	Venting	Controlled emissions that occur due to the design of a facility, to procedures used in the manufacture or processing of a substance or product or to pressure exceeding the capacity of the equipment at the facility
3	Industrial process	Emissions from an industrial process that involves a chemical or physical reaction other than combustion and the purpose of which is not to produce useful heat
4	Industrial product use	Emissions from the use of a product in an industrial process that does not involve a chemical or physical reaction and does not react in the process, including emissions from the use of sulphur hexafluoride (SF6), HFCs and PFCs as cover gases and the use of HFCs and PFCs in a foam-blowing process
5	Flaring	Controlled emissions of gases from industrial activities as a result of the combustion of a gas or liquid stream produced at a facility, the purpose of which is not to produce useful heat, not including emissions from the flaring of landfill gas
6	Leakage	Uncontrolled emissions from a source other than industrial process emissions and industrial product use emissions
7	Waste	Emissions that result from waste disposal at a facility, including the landfilling of solid waste, the biological treatment or incineration of waste and the flaring of landfill gas
8	Wastewater	Emissions resulting from industrial wastewater and industrial wastewater treatment at a facility
9	On-site transportation	Emissions from registered or unregistered vehicles and other machinery that are used at the facility for the transport of substances, materials, equipment or products used in a production process or for the transport of people

SCHEDULE 2

(Subsections 7(1) and (2))

Information Required For Registration

1 The following information with respect to the operator or the person that expects to become an operator:

• (a) an indication as to whether the person has, or will have, the charge, management or control of the facility;
• (b) in the case of a person that expects to become an operator, the day on which the industrial activities are expected to begin;
• (c) the person’s name (including any trade name or other name used) and civic address;
• (d) the name, job title, civic and postal addresses, telephone number and email address of the authorized official and of a contact person, if different from the authorized official;
• (e) the business number assigned by the Canada Revenue Agency, if any; and
• (f) all identification numbers assigned to the operator and associated with the obligation to report production from industrial activities or production from the operator’s facilities, including all Petrinex Business Associate codes, if any.

2 If the registration occurs in 2025, the following information:

• (a) an indication as to whether the cumulative production in any month from January 2024 to June 2025 was equal to or greater than the monthly threshold;
• (b) an indication as to whether the operator was required to provide information about GHG emissions from any facility for the 2024 calendar year in accordance with a notice that was published under subsection 46(1) of the Act;
• (c) if the indication under paragraph (a) or (b) is positive, the number of facilities that the operator expects to operate in 2026;
• (d) if the indication under paragraph (b) is positive,
  • (i) the facility’s civic address and GPS coordinates, expressed in decimal degrees to five decimal places,
  • (ii) the facility’s Greenhouse Gas Reporting Program identification number, if any; and
• (e) for each facility referred to in section 5 of these Regulations,
  • (i) the province in which the facility is located, and
  • (ii) the number of facilities that are deemed to be part of the facility as of the date of registration.

3 If the registration occurs in 2026 or later, an indication as to whether the operator expects the cumulative production to be equal to or greater than the annual threshold and, if applicable, the date on which the operator expects that the annual threshold will be met.

SCHEDULE 3

(Paragraph 9(2)(a))

Information Required For Annual Report

1 The following information with respect to the operator:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the name, job title, civic and postal addresses, telephone number and email address of the authorized official and of a contact person, if different from the authorized official;
• (c) the registration number assigned to the operator;
• (d) the business number assigned to the operator by the Canada Revenue Agency, if any; and
• (e) all identification numbers assigned to the operator and associated with the obligation to report production from industrial activities or production from the operator’s facilities, including all Petrinex Business Associate codes, if any.

2 The following information with respect to the facility:

• (a) the facility’s name, civic address and GPS coordinates, expressed in decimal degrees to five decimal places;
• (b) the facility’s Greenhouse Gas Reporting Program identification number, if any;
• (c) all identification numbers that are related to the facility and used for reporting to provincial authorities, including all Petrinex codes assigned to the facility, if any;
• (d) if the facility is a facility referred to in section 5 of these Regulations, the information referred to in paragraphs (a) and (c) and paragraphs 9(2)(b) and (c) of these Regulations for each facility that is deemed to be part of the facility;
• (e) the method used to determine the facility’s production from each industrial activity;
• (f) the value of each element of the formula set out in subsection 17(1) of these Regulations;
• (g) the quantity of each GHG, expressed in CO₂e tonnes, from each specified emission source;
• (h) the global warming potential of each GHG;
• (i) the methods used to calculate, sample, analyze and measure each specified emission source and each GHG;
• (j) if a continuous emissions monitoring system is used and the facility captured CO₂, the quantity of CO₂ captured and the outcome of the captured CO₂;
• (k) if a quantity of CO₂ was included in B in the formula set out in subsection 17(1) of these Regulations, the following information:
  • (i) an indication that the CO₂ was stored in accordance with subsection 19(1) of these Regulations,
  • (ii) the type of geological storage site used, among those set out in paragraph 19(1)(a) of these Regulations,
  • (iii) the GPS coordinates, expressed in decimal degrees to five decimal places, of the storage site, and
  • (iv) the name and civic address of the person responsible for the storage site, if different from the operator;
• (l) the quantity of thermal energy, expressed in gigajoules and determined in accordance with Quantification Methods, as well as its temperature, pressure and ratio of heat, that was
  • (i) supplied to the facility,
  • (ii) produced at the facility, and
  • (iii) transferred from the facility;
• (m) the quantity of hydrogen, expressed in tonnes and determined in accordance with Quantification Methods, that was
  • (i) supplied to the facility,
  • (ii) produced at the facility, and
  • (iii) transferred from the facility;
• (n) the quantity of electricity, expressed in GWh, that was produced at the facility, determined in accordance with Quantification Methods;
• (o) in the case of the first annual report submitted in respect of a new facility,
  • (i) the day on which industrial activities begin at the new facility, and
  • (ii) an estimate of the facility’s GHG emissions, consistent with currently recognized industry practices for the quantification of emissions and certified by a professional engineer, that demonstrates that the facility is expected to emit at least 10 000 CO₂e tonnes in any of the first three calendar years during which industrial activities are carried out at the facility;
• (p) in the case of the second annual report submitted in respect of a new facility, an indication as to whether the new facility is still expected to emit at least 10 000 CO₂e tonnes within any of the first three calendar years during which industrial activities are carried out at the facility; and
• (q) if a qualitative error or omission was identified in a previous annual report, the corrected information and the calendar year to which the correction applies.

SCHEDULE 4

(Paragraph 10(2)(a))

Information Required For Report on Cumulative Production

1 The following information with respect to the operator:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) a list of all facilities of the operator — including each facility that is deemed to be part of a facility under section 5 of these Regulations, if any — and the period during which the operator carried out industrial activities at each facility; and
• (d) an indication as to whether the operator was required to provide information about GHG emissions from any of the operator’s facilities in accordance with a notice that was published under subsection 46(1) of the Act.

2 The following information with respect to each facility, including each facility that is deemed to be part of a facility under section 5 of these Regulations, if any:

• (a) in the case of a facility that was transferred between the operator and another person during the applicable calendar year,
  • (i) the facility’s name,
  • (ii) the date of the transfer, and
  • (iii) an indication as to whether the operator was the transferee or the transferor; and
• (b) if applicable, the day on which the operator ceased all industrial activities.

SCHEDULE 5

(Paragraphs 15(d) and 22(1)(b))

Contents of Verification Report

1 The following information with respect to the operator:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the name, job title, civic and postal addresses, telephone number and email address of the authorized official or the contact person that participated in the verification;
• (c) the registration number assigned to the operator;
• (d) the business number assigned to the operator by the Canada Revenue Agency, if any; and
• (e) all identification numbers assigned to the operator and associated with the obligation to report production from industrial activities or production from the operator’s facilities, including all Petrinex Business Associate codes, if any.

2 The following information with respect to the facility subject to the verification:

• (a) the facility’s name, civic address and GPS coordinates, expressed in decimal degrees to five decimal places;
• (b) the facility’s Greenhouse Gas Reporting Program identification number, if any;
• (c) all identification numbers that are related to the facility and used for reporting to provincial authorities, including all Petrinex codes assigned to the facility, if any; and
• (d) if the facility is a facility referred to in section 5 of these Regulations, the information referred to in paragraphs (a) and (c) for each facility that is deemed to be part of the facility.

3 The following information with respect to the verification:

• (a) the name and civic address of the verification body as well as the name, telephone number and email address of the lead verifier of the team that conducted the verification;
• (b) the name and contact information of the accreditation organization by which the verification body is accredited and the date of the verification body’s accreditation;
• (c) the names and roles of each member of the verification team;
• (d) the version of standard ISO 14064-3, entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements and published by the International Organization for Standardization, according to which the verification was conducted and a description of the objectives and scope of the verification and the verification criteria;
• (e) an indication as to whether the verification is of an annual report or corrected report and the calendar year to which the report relates;
• (f) a summary of the verification procedures conducted and the results, including
  • (i) any assessments, data sampling, tests and reviews,
  • (ii) any tests of the GHG information system and controls,
  • (iii) the date and location of each facility visit referred to in section 40 of these Regulations or, if the facility was not visited, the reason why it was not visited,
  • (iv) in the case of a visit of a facility referred to in section 5 of these Regulations, a justification of the sample size, a description of the selection process for the sampled facilities and a list of the facilities visited, and
  • (v) in the case of a quantity of CO₂ captured at a facility and stored in accordance with subsection 19(1) of these Regulations, the verification procedures conducted to verify the quantity of CO₂ captured and stored;
• (g) the production from each industrial activity carried out at the facility and, in the case of a facility referred to in section 5 of these Regulations, at each facility that is deemed to be part of the facility, determined in accordance with section 16 of these Regulations;
• (h) the GHGs attributed to the facility and, in the case of a facility referred to in section 5 of these Regulations, at each facility that is deemed to be part of the facility, determined in accordance with section 17 of these Regulations;
• (i) a list of all quantitative errors and omissions identified during the verification in the data, information or methods used in the preparation of the report that is the subject of the verification, including
  • (i) with respect to each error or omission,
    • (A) if the error or omission relates to attributed GHGs, the number of CO₂e tonnes to which the error or omission relates, the percentage calculated in accordance with subsection 38(1) of these Regulations and an indication as to whether the error or omission results in an understatement or overstatement, and
    • (B) if the error or omission relates to production, the quantification of that error or omission, expressed in the applicable unit of measurement, the percentage calculated in accordance with subsection 38(2) of these Regulations and an indication as to whether the error or omission results in an understatement or overstatement, and
  • (ii) with respect to the sum of the errors and omissions related to attributed GHGs, the net result of all errors and omissions expressed in CO₂e tonnes, the percentage calculated in accordance with subsection 38(1) of these Regulations and an indication as to whether the net result is an understatement or overstatement;
• (j) a list of all qualitative errors and omissions identified during the verification;
• (k) a list of any corrections made by the operator in response to any errors or omissions identified during the verification;
• (l) a declaration, signed and dated by the lead verifier, stating that the requirements of section 39 of these Regulations have been complied with and that any real or potential conflicts of interest have been effectively managed;
• (m) a declaration, signed and dated by a verifier who is not a member of the verification team, stating their approval of the verification report and including the name, civic address, telephone number and email address of the verifier; and
• (n) a verification opinion by the verification body stating
  • (i) whether a material discrepancy exists with respect to attributed GHGs or production and whether the annual report or corrected report was prepared in accordance with these Regulations, and
  • (ii) any qualifications or limitations on the determinations referred to in subparagraph (i).

SCHEDULE 6

(Subsection 34(1))

Creation of Decarbonization Units

Information To Be Submitted

1 The following information for the creation of decarbonization units:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) the quantity of GHGs for which the contribution is being made;
• (d) the total amount of the contribution;
• (e) the applicable contribution rate; and
• (f) the date of payment.

Contribution Rates

Item	Column 1 Year	Column 2 Contribution Rate (per CO2e tonne)
1	2030	$50
2	2031	$50
3	2032 and subsequent years	$50

SCHEDULE 7

(Section 35)

Information Required To Remit Compliance Units

1 Information required for each emissions allowance:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) the provision of these Regulations under which the remittance is being made;
• (d) the calendar year for which the remittance is being made;
• (e) the number of emissions allowances being remitted;
• (f) the date of the remittance;
• (g) the serial number of the emissions allowance; and
• (h) in the case of an emissions allowance that was transferred to the operator, the price, if any, in Canadian dollars, paid for the emissions allowance.

2 Information required for each compliance unit referred to in paragraph (a) of the definition Canadian offset credit in section 2 of these Regulations:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) the provision of these Regulations under which the remittance is being made;
• (d) the calendar year for which the remittance is being made;
• (e) the number of Canadian offset credits being remitted;
• (f) the date of the remittance;
• (g) the serial number of the Canadian offset credit;
• (h) the year of the GHG reduction or removal associated with the Canadian offset credit; and
• (i) the date of issuance of the Canadian offset credit.

3 Information required for each compliance unit referred to in paragraph (b) of the definition Canadian offset credit in section 2 of these Regulations:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) the provision of these Regulations under which the remittance is being made;
• (d) the calendar year for which the remittance is being made;
• (e) the number of Canadian offset credits being remitted;
• (f) the date of the remittance;
• (g) the serial number of the Canadian offset credit;
• (h) the price in Canadian dollars paid for the Canadian offset credit;
• (i) the province or program authority referred to in subsection 78(1) of the Output-Based Pricing System Regulations that issued the Canadian offset credit;
• (j) as the case may be, the date of retirement or the date the Canadian offset credit is designated by the province or program authority for use as a compliance unit for the purposes of remittance under these Regulations;
• (k) the start date of the offset project for which the Canadian offset credit was issued;
• (l) the year of the GHG reduction or removal associated with the Canadian offset credit;
• (m) the offset protocol applicable to the project for which the Canadian offset credit was issued, including the version number and publication date; and
• (n) the name of the verification body that verified the Canadian offset credit.

4 Information required for each decarbonization unit:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) the provision of these Regulations under which the remittance is being made;
• (d) the calendar year for which the remittance is being made;
• (e) the number of decarbonization units being remitted;
• (f) the date of the remittance; and
• (g) the serial number of the decarbonization unit.

5 Information required for each Canadian offset credit that is being remitted in accordance with subsection 28(2) of these Regulations:

• (a) the operator’s name (including any trade name or other name used) and civic address;
• (b) the registration number assigned to the operator;
• (c) the name of the eligible system under which the credit was remitted;
• (d) the date on which the remittance was made under the eligible system and the calendar year for which that remittance was made;
• (e) the number of Canadian offset credits remitted under the eligible system that are being remitted under these Regulations;
• (f) the industrial activities for which the remittance was made under the eligible system;
• (g) the circumstances in which the remittance was made under the eligible system; and
• (h) any other information requested under subsection 28(4) of these Regulations.

Terms of use and Privacy notice

Terms of use

It is your responsibility to ensure that the comments you provide do not:

• contain personal information
• contain protected or classified information of the Government of Canada
• express or incite discrimination on the basis of race, sex, religion, sexual orientation or against any other group protected under the Canadian Human Rights Act or the Canadian Charter of Rights and Freedoms
• contain hateful, defamatory, or obscene language
• contain threatening, violent, intimidating or harassing language
• contain language contrary to any federal, provincial or territorial laws of Canada
• constitute impersonation, advertising or spam
• encourage or incite any criminal activity
• contain external links
• contain a language other than English or French
• otherwise violate this notice

The federal institution managing the proposed regulatory change retains the right to review and remove personal information, hate speech, or other information deemed inappropriate for public posting as listed above.

Confidential Business Information should only be posted in the specific Confidential Business Information text box. In general, Confidential Business Information includes information that (i) is not publicly available, (ii) is treated in a confidential manner by the person to whose business the information relates, and (iii) has actual or potential economic value to the person or their competitors because it is not publicly available and whose disclosure would result in financial loss to the person or a material gain to their competitors. Comments that you provide in the Confidential Business Information section that satisfy this description will not be made publicly available. The federal institution managing the proposed regulatory change retains the right to post the comment publicly if it is not deemed to be Confidential Business Information.

Your comments will be posted on the Canada Gazette website for public review. However, you have the right to submit your comments anonymously. If you choose to remain anonymous, your comments will be made public and attributed to an anonymous individual. No other information about you will be made publicly available.

Comments will remain posted on the Canada Gazette website for at least 10 years.

Please note that communication by email is not secure, if the attachment you wish to send contains sensitive information, please contact the departmental email to discuss ways in which you can transmit sensitive information.

Privacy notice

The information you provide is collected under the authority of the Financial Administration Act, the Department of Public Works and Government Services Act, the Canada–United States–Mexico Agreement Implementation Act,and applicable regulators’ enabling statutes for the purpose of collecting comments related to the proposed regulatory changes. Your comments and documents are collected for the purpose of increasing transparency in the regulatory process and making Government more accessible to Canadians.

Personal information submitted is collected, used, disclosed, retained, and protected from unauthorized persons and/or agencies pursuant to the provisions of the Privacy Act and the Privacy Regulations. Individual names that are submitted will not be posted online but will be kept for contact if needed. The names of organizations that submit comments will be posted online.

Submitted information, including personal information, will be accessible to Public Services and Procurement Canada, who is responsible for the Canada Gazette webpage, and the federal institution managing the proposed regulatory change.

You have the right of access to and correction of your personal information. To seek access or correction of your personal information, contact the Access to Information and Privacy (ATIP) Office of the federal institution managing the proposed regulatory change.

You have the right to file a complaint to the Privacy Commission of Canada regarding any federal institution’s handling of your personal information.

The personal information provided is included in Personal Information Bank PSU 938 Outreach Activities. Individuals requesting access to their personal information under the Privacy Act should submit their request to the appropriate regulator with sufficient information for that federal institution to retrieve their personal information. For individuals who choose to submit comments anonymously, requests for their information may not be reasonably retrievable by the government institution.