Canada Gazette, Part I, Volume 156, Number 44: Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations

October 29, 2022

Statutory authorities
Greenhouse Gas Pollution Pricing Act
Environmental Violations Administrative Monetary Penalties Act

Sponsoring department
Department of the Environment

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues

Greenhouse gas (GHG) emissions are significantly contributing to a changing climate. Climate change poses an urgent global threat, with impacts and costs projected to increase over time if left unchecked. Without action to reduce GHG emissions, the impacts of climate change are expected to worsen as the global average surface temperature becomes warmer. Changes in temperature and precipitation can impact natural habitats, agriculture and food supplies, and rising sea levels can threaten coastal communities.

Recognizing the need for climate action, the Government of Canada announced the Pan-Canadian Approach to Pricing Carbon Pollution (the Pan-Canadian Approach) in October 2016, which put carbon pricing at the centre of Canada’s climate action. The Pan-Canadian Approach sets out minimum national stringency standards, referred to as the federal benchmark, which all carbon pricing systems across Canada must meet. The federal carbon pollution pricing backstop system (the federal backstop) applies in provinces and territories that do not have carbon pricing systems that meet the federal benchmark (called “backstop jurisdictions”). The federal backstop, introduced in 2019, contains two parts: a regulatory charge on fossil fuels (the fuel charge) and a regulatory trading system for industrial facilities in sectors at significant risk of carbon leakage and competitiveness impacts, known as the Output-Based Pricing System (OBPS).

Since 2016, Canada has increased its climate ambition and committed to reduce GHG emissions by 40% to 45% below 2005 levels by 2030 and to reach net-zero emissions by 2050. To ensure carbon pollution pricing remains a strong contributor to GHG reductions, the Government of Canada announced in 2021 that the price on carbon pollution would increase to $65 per tonne of carbon dioxide equivalent (CO₂e) in 2023 and increase by $15 per calendar year until it reaches $170 per tonne of CO₂e in 2030.

This carbon price trajectory is part of the strengthened benchmark announced in summer 2021, along with increased stringency of other criteria. The proposed Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations (the proposed Amendments) are required to ensure the OBPS remains aligned with the federal benchmark and continues to deliver GHG reductions, while mitigating competitiveness impacts and carbon leakage risks. Maintaining the effectiveness of the OBPS by ensuring net demand for credits will result in a strong marginal price signal that is in alignment with the federal benchmark.

Background

In December 2015, the international community, including Canada, adopted the Paris Agreement, an accord intended to reduce GHG emissions, to limit the rise in global average temperature to less than two degrees Celsius (2 °C) above pre-industrial levels, and to aim 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 30% below 2005 levels by 2030.

On July 12, 2021, the Minister of the Environment (the Minister) formally submitted Canada’s enhanced nationally determined contribution (NDC) to the United Nations, committing Canada to reduce national GHG emissions by 40% to 45% below 2005 levels by 2030. Canada has also committed to achieving net-zero GHG emissions by 2050 under the Canadian Net-Zero Emissions Accountability Act. To meet these obligations, the federal government is implementing a series of measures, including continuing to put a price on carbon pollution.

The Pan-Canadian Approach, published in 2016, is one of the four main pillars of the Pan-Canadian Framework on Clean Growth and Climate Change (PCF). Building on the actions in the PCF, the 2030 Emissions Reduction Plan (ERP) provides a roadmap to how Canada will meet its enhanced Paris Agreement target to reduce GHG emissions by 40% to 45% from 2005 levels by 2030. The ERP, published in March 2022, is the first plan issued under the Canadian Net-Zero Emissions Accountability Act. Carbon pollution pricing is a central pillar of the PCF and the ERP.

Under the Government of Canada’s approach to pricing carbon pollution, provinces and territories have the flexibility to implement a carbon pricing system that makes sense for their circumstances, provided that the system meets minimum national stringency criteria, referred to as the federal benchmark. The federal benchmark sets the criteria that all systems must meet to ensure they are comparable and effective in reducing GHG emissions. In August 2021, the Government of Canada updated the federal benchmark for the 2023–2030 period.^{footnote 1} A process is currently underway to assess provincial and territorial submissions against the updated federal benchmark criteria for this period.

The Greenhouse Gas Pollution Pricing Act (the Act), enacted on June 21, 2018, establishes the framework for the federal backstop system consisting of two parts: a regulatory charge on fossil fuels (fuel charge) under Part 1 of the Act, and a regulatory trading system for industry, known as the OBPS, under Part 2 of the Act. The federal backstop, which can include the fuel charge, the OBPS, or both, applies in any jurisdiction that requests it or does not have a carbon pricing system that meets the federal benchmark. In 2022, the OBPS applied in Manitoba, Prince Edward Island, Yukon and Nunavut, and to the electricity and natural gas pipeline sectors in Saskatchewan. The results of the assessments of provincial and territorial systems against the updated federal benchmark may lead to a change of scope of where the OBPS applies.

The Output-Based Pricing System Regulations (the Regulations) were published in the Canada Gazette, Part II, on July 10, 2019. The federal OBPS is designed to put a price on carbon pollution, creating an incentive for industrial facilities from sectors at significant risk of carbon leakage and competitiveness impacts to reduce their emissions per unit of output. Carbon leakage occurs when production and investment shift to jurisdictions with less stringent carbon pricing, weakening emissions reductions at the global level, while reducing economic activity in the jurisdiction with more stringent carbon pricing. Adverse competitiveness impacts, such as a loss of global market share, can occur when the economic situation faced by firms changes, for example, due to an increase in production costs from carbon pricing. These competitiveness impacts may lead to carbon leakage.

The Regulations define the facilities to which the OBPS applies (“covered facilities”) and specify output-based standards (OBSs) for certain industrial activities that are set on an emissions per unit of output (emissions intensity) basis. Covered facilities generally do not pay the fuel charge on fuels that they use at their facilities; instead they are required to provide compensation on an annual basis for any GHG emissions exceeding their respective facility emissions limit during a compliance period. A covered facility’s emissions limit, which is measured in tonnes of CO₂e, is determined by summing the facility’s production (usually expressed in units of output) for each specified industrial activity multiplied by the applicable OBS. A covered facility with GHG emissions below its limit receives surplus credits issued by the Minister for the difference between its GHG emissions and its limit. These surplus credits can be sold or used to meet future compensation obligations.

Covered facilities have three options regarding how they choose to provide compensation for excess emissions. First, they may make excess emissions charge payments to the Receiver General for Canada. Second, a covered facility may use compliance units, each representing one tonne of CO₂e, which include (i) surplus credits that have been issued by the Minister to that covered facility or that have been acquired through trading with other covered facilities; (ii) eligible provincial or territorial offset credits formally recognized by the Minister under the Regulations as compliance units; and (iii) federal offset credits issued by the Minister.^{footnote 2} Third, covered facilities may use a combination of excess emissions charge payments and compliance units to provide compensation. However, starting with the 2022 compliance period, a minimum of 25% of each facility’s compensation obligation must be provided through payment of the excess emissions charge.

Covered facilities in federal backstop jurisdictions

Mandatory covered facilities are those located in backstop jurisdictions that emit 50 kilotonnes (kt) or more of CO₂e per year and carry out an activity listed in Schedule 1 to the Regulations as their primary activity. Other facilities located in a backstop jurisdiction may voluntarily apply to participate in the OBPS. Each opt-in application is considered on its merits and on a case-by-case basis. The key considerations taken into account when assessing an application are outlined in the Policy Regarding Voluntary Participation in the Output-Based Pricing System (the Opt-in Policy). They include that the facility emits or, in the case of a new, retrofitted or expanded facility, is projected to emit, a minimum of 10 kt of CO₂e per year, and either undertakes an industrial activity listed in Schedule 1 to the Regulations, or does not undertake an industrial activity listed in Schedule 1 to the Regulations as its primary activity and is operating in an industrial sector considered to be at significant risk of carbon leakage and competitiveness impacts. In 2022, there are 53 covered facilities in the backstop jurisdictions where the OBPS applies. There are 14 mandatory covered facilities in Saskatchewan, 7 in Manitoba, 1 in Prince Edward Island, 1 in Yukon, and 4 in Nunavut.

Output-based standards

Output-based standards are the emissions-intensity performance standards for specific activities covered under the OBPS, expressed as a quantity of GHG emissions per unit of output for a given product or activity. These standards are, for the most part, set as a percentage of the production-weighted average emissions intensity of all large emitter facilities producing similar products across Canada. To establish the OBSs, emissions reduction factors are applied to the production weighted average emissions intensities. The emissions reduction factor is set at 80%, 90% or 95%, depending on the risk of carbon leakage and competitiveness impacts faced by the sector. In addition, OBSs were adjusted for sectors with process emissions constituting 30% or more of total GHG emissions at the sector level. All else being equal, a lower emissions reduction factor results in a more stringent OBS.

Most OBSs listed in Schedule 1 to the Regulations are numeric. For existing numeric OBSs, the production weighted average emissions intensity of a given industrial activity is calculated using the emissions and production information from all facilities in Canada undertaking the industrial activity and that emitted 50 kt or more of CO₂e per year during the 2014–2016 period. Some OBSs are facility specific and are referred to as calculated OBSs. These OBSs are calculated using emissions and production information for the respective facility for specified reference years.

Assessing competitiveness and carbon leakage risks

The Department categorizes sectors as emissions intensive and trade exposed (EITE) based on their level of risk of carbon leakage and adverse competitiveness impacts. The results from these analyses are used to determine the emissions reduction factor used to set an OBS. There are two parts to this metric: economic emissions intensity (i.e. carbon costs per unit of gross value added of a sector); and trade exposure (i.e. exposure to import and export competition in a sector).

The Department has developed a three-phased approach to provide an assessment of potential carbon leakage and competitiveness risks due to the application of carbon pricing under the OBPS. In Phase 1, historical data, primarily from national public data sources, is used to assess which sectors exceed EITE thresholds. Phase 2 involves the same analysis but estimates EITE levels using projections from the Department’s EC-Pro model.^{footnote 3} Phase 3 considers additional information relevant to the assessment of the risks of carbon leakage and adverse competitiveness impacts due to carbon pricing. In particular, this includes analysis of the direct costs from carbon pricing relative to financial data for a substantive portion of the facilities of a sector (i.e. facility carbon costs per unit of facility revenue).^{footnote 4}

Objective

The objective of the proposed Amendments is to maintain the effectiveness of the OBPS so that it continues to contribute to Canada’s GHG emissions reduction targets while mitigating competitiveness impacts and carbon leakage risks from carbon pricing.

Description

The proposed Amendments would make modifications to the Regulations to add an annual tightening rate to all OBSs, to align with the strengthened federal benchmark and to help ensure the OBPS continues to contribute to Canada’s GHG emissions reduction targets while mitigating risks of carbon leakage and competitiveness impacts. They would also introduce new OBSs and revise existing OBSs in certain limited circumstances, enabling the OBPS to function effectively as a backstop and apply in any jurisdiction in Canada as required. Furthermore, the proposed Amendments would enable the harmonization of quantification methods for GHG emissions between the OBPS and the federal Greenhouse Gas Reporting Program (GHGRP); improve regulatory implementation by recognizing additional industrial activities; streamline voluntary participation; modify calculated OBSs; and contribute to accurate reporting by making changes to rules related to reporting and verification. Finally, the proposed Amendments would apply to covered facilities and would modify the Regulations based on the review completed in 2022, as described below.

Tightening rates

The proposed Amendments introduce tightening rates to the OBSs. A tightening rate is a fixed annual percentage reduction to a standard (i.e. a fixed annual increase in stringency). OBSs would continue to decline at the respective annual tightening rate with no end date. The proposed Amendments modify the formula to calculate facility emissions limits by incorporating an annual 2% tightening rate in most OBSs starting with the 2023 compliance period, while an annual 1% tightening rate would apply to OBSs in sectors at very high risk of competitiveness resulting from carbon pricing and carbon leakage impacts resulting from carbon pricing.^{footnote 5} These sectors include the production of cement, lime and petrochemicals (except ethylene glycol), and natural gas extraction and processing. The proposed tightening rate would not apply to the generation of electricity using fossil fuels, whether the electricity is generated at an industrial facility or at an electricity generation facility (item 38 of Schedule 1 to the Regulations). These tightening rates would be reassessed if the scope of application of the federal OBPS changes.

Output-based standards

New OBSs

The proposed Amendments would add 12 industrial activities to the existing activities listed in Schedule 1 to the Regulations and prescribe their OBSs. These additional OBSs have been developed for activities where three or more facilities in Canada have emissions of 10 kt of CO₂e or more per year per facility. The national production weighted average emissions intensities were set using data from the 2017 to 2019 reference years for most standards and employed an approach that was generally consistent with how existing standards have been set. The standards were calculated with emissions based on the updated values for global warming potential (GWP) in Schedule 3 to the Act, where the change in GWPs would have a material (greater than 1%) impact on the respective standard, consistent with the approach to revising existing standards. This affected two standards: the standard for surface mining of oil sands and extraction of bitumen; and the standard for aluminum production from alumina.

Standards are assigned an emissions reduction factor of 80%, 90% or 95% of the national production weighted average emissions intensity, depending on the risk level of the sector in the competitiveness and carbon leakage risk assessment and proportion of industrial process emissions. The proposed standards and the corresponding results of the risk assessments are detailed in the regulatory analysis section below.

The current exclusion of methane emissions that applies to most oil and gas standards under the Regulations was not extended to apply to the proposed standard for surface mining of oil sands and extraction of bitumen; therefore, area fugitive emissions from this activity are included in the proposed standard.

Review of existing OBSs

The proposed Amendments would make changes to some existing OBSs, including the revision of the urea liquor standard into a standard for granular urea and a standard for urea liquor. The introduction of a distinct standard for granular urea requires a revision to the existing urea liquor standard so that it no longer includes the additional emissions associated with producing granular urea. These standards were set based on data for the reference years used to set the existing urea liquor standard and both standards received the emissions reduction factor of 90% that was applied to the existing urea liquor standard.

Additionally, the proposed Amendments would update the activity definition for automotive manufacturing to exclude the production of zero-emission vehicles, as these vehicles are considered to be a distinct product. Facilities that produce zero-emission vehicles as an additional industrial activity would be able to access a facility-specific standard for this activity, assuming this activity is added to the list of additional industrial activities recognized by the Minister.

The proposed Amendments would also update the activity description related to the production of metal or diamonds set out in item 26 of Schedule 1 to the Regulations. This update would clarify the description so that the activity applies to the mining and milling of a product instead of to the mining or milling of a product. Facilities doing only one or the other would still be eligible to apply to opt into the OBPS, provided they meet the opt-in criteria, as this sector is considered to be at significant risk of carbon leakage and competitiveness impacts. In this case, facilities would receive a facility-specific calculated OBS, assuming this activity is added to the list of additional industrial activities recognized by the Minister.

As a result of updates to GWPs in Schedule 3 to the Act, the proposed Amendments would update two existing OBSs where the change in GWP values would result in a material change in an OBS, defined as ±1% of the value of the OBS, as detailed in the “Regulatory analysis” section.

Reducing administrative burden

The proposed Amendments would remove detailed quantification methods from Schedule 3 to the Regulations. The quantification methods would be specified in the Quantification Methods for the Output-Based Pricing System Regulations, a technical document incorporated by reference into the Regulations. This would allow the Minister to continue to update the specified methods on an ongoing basis as required to incorporate technical updates and to harmonize the GHG quantification methods to align with the Greenhouse Gas Reporting Program (GHGRP), where possible.

Section 176 of the Act requires the person responsible for a covered facility to notify the Minister of any error or omission within five years of the submission of an annual report. The proposed Amendments would remove the obligation to submit a corrected report when any error or omission in an annual report is identified by the person responsible. Instead, the corrected report accompanied by its verification report would only be required when the identified error or omission would have constituted a material discrepancy if the error had been identified during the verification of the annual report. The deadline to submit the corrected report would be extended from 90 days from the date of the submission of the notice to the Minister to 120 days from that date. The Minister maintains the ability to determine if a corrected report is necessary in other circumstances.

Improving implementation

Recognizing additional industrial activities

Currently, under the Regulations, a covered facility whose primary activity is an activity listed in Schedule 1 to the Regulations can only include production and the OBSs for the activities listed in Schedule 1 in the calculation of its emissions limit. A covered facility whose primary activity is not an activity listed in Schedule 1 can take into account other industrial activities in the calculation of its emissions limit, as long as they are specified in a notice issued by the Minister for that facility that accompanies the covered facility certificate. The proposed Amendments would define additional industrial activities as activities recognized by the Minister as being from sectors at significant risk of competitiveness impacts and carbon leakage as a result of carbon pricing. This would require a covered facility to include both activities listed in Schedule 1 to the Regulations, and additional industrial activities, in the determination of its emissions limit. Any new additional industrial activity recognized by the Minister would only be included in the determination of a covered facility’s emissions limit for the compliance period that follows the year in which the additional industrial activity is recognized.

Streamlining voluntary participation

The proposed Amendments would make several changes that would impact the opt-in process. These include fixing the start of the first compliance period to January 1 of the calendar year after the year in which the Minister designated the facility as a covered facility. The changes also include removing the obligation for certain facilities to use detailed emissions and production information submitted as part of their opt-in application to calculate their OBSs, by instead requiring this information to be submitted as part of their annual reports.

Other changes, such as those made to calculated OBSs to remove emissions from non-specified industrial activities from the OBS calculation, would enable the Minister to broaden opt-in eligibility to facilities engaged in an additional industrial activity as a secondary activity, while ensuring the calculation of the OBS applicable to these facilities is representative of the emissions related to the activity. The proposed Amendments would also add provisions related to the cancellation of designations, so that when a person responsible for a facility requests that its designation as a covered facility be cancelled, it would be effective on December 31 of the year in which the request is made.

Calculated OBSs

The proposed Amendments would change how calculated OBSs are determined. This includes considering activities that are not at risk of carbon leakage and competitiveness impacts, taking carbon capture and storage into consideration, and clarifying how thermal energy transfers are calculated. Changes to the reference years are being proposed, so that facilities undertaking activities listed in Schedule 1 to the Regulations and activities not listed in Schedule 1 that are recognized under the Regulations would use the same reference years to calculate the OBSs. The proposed Amendments would also require the use of projections when no data is available for the reference years, such as when new activities are being engaged at the covered facility. After three years of production, the covered facility would be required to recalculate the applicable OBS using the actual emissions at the facility during the three preceding years. When it is necessary to attribute GHG emissions between activities, the proposed Amendments would require that the method applied correspond to generally accepted engineering principles and be the same for all calculations related to determining the applicable OBS. Information on the methods used to attribute emissions would be required in the annual report.

Accurate reporting

Verification

The Regulations establish the requirements to be met for the verification of annual reports by third parties. This includes that verification bodies must be accredited to ISO Standard 14065 entitled Greenhouse gases — Requirements for greenhouse gas validation and verification bodies for use in accreditation or other forms of recognition. In addition, verification bodies must conduct the verification in accordance with ISO Standard 14064-3 entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements. These ISO standards have been updated recently. The proposed Amendments would incorporate these standards as amended from time to time such that the most recent versions replace the previous versions. Despite this, if ISO Standard 14065 is amended, the proposed Amendments would allow for a transition period of four years during which the previous version of that standard may be complied with so that verification bodies would have time to obtain accreditation to the updated ISO Standard 14065.

A materiality threshold is the threshold at which single or aggregate errors or omissions affect the reliability of reported data. The proposed Amendments would change the materiality threshold for GHG emissions from 8% to 5% for covered facilities that emit less than 50 kt of CO₂e per year, as well as the materiality threshold for production from 5% to 0.1% for all industrial activities. The tables below show the breakdown of the proposed materiality thresholds for GHG emissions and for production.

Table 1: Materiality threshold for GHG emissions

Annual covered facility GHG emissions	Current	Proposed
Less than 50 kt of CO2e	8%	5%
At least 50 but less than 500 kt of CO2e	5%	No change
At least 500 kt of CO2e	2%	No change

Table 2: Materiality threshold for production for each specified industrial activity

Annual covered facility production	Current	Proposed
All industrial activities	5%	0.1%

Correction of errors and omissions

The proposed Amendments would also require that errors and omissions identified by a verification body be corrected prior to the submission of the applicable annual report, where possible.

Calibration

The proposed Amendments would update calibration requirements in two situations. For the purpose of production reporting, they would replace the requirement that electricity meters be compliant with the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations. Instead, electricity meters would need to be installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or any applicable generally recognized national or international industry standard. Meters would also need to maintain a ±5% accuracy. For the purpose of emissions reporting, the Department also proposes to add a requirement to install, operate, maintain and calibrate meters used in the quantification of GHG emissions in accordance with the manufacturer’s specification or any applicable generally recognized national or international industry standard. These meters would also need to be maintained to be accurate within ± 5%.

Other amendments

In addition to the changes discussed above, the proposed Amendments would also

• Fix the start of the first compliance period to January 1 of the calendar year after the year in which the facility meets the requirement of section 8 of the Regulations for being a mandatory facility.
• Change the date on which the timeline for provision of revised compensation after a corrected report is required starts.
  • Revised compensation would now be required 45 days after the date the corrected report is due as opposed to 45 days after the corrected report is received.
• Enable the Minister to intervene to determine the quantity of GHGs or establish the emissions limit for a covered facility when no annual report is provided or when the facility emissions limit was not calculated in accordance with the Regulations and any resulting error was equal to or greater than 2%.
• Make clarifications to the method to calculate complexity weighted barrels for petroleum refineries.
• Align and correct the regulatory text through miscellaneous administrative changes.
• Make consequential amendments to the Environmental Violations Administrative Monetary Penalties Regulations (EVAMPR) as a result of the proposed Amendments.
  • The EVAMPR allow enforcement officers to issue administrative monetary penalties (AMPs) for certain violations under the Act and the Regulations.

Regulatory development

Consultation

The Regulatory Impact Analysis Statement accompanying the Regulations that were published in July 2019 contains a commitment to review the Regulations in 2022. Building on this commitment, the Department published a scoping paper^{footnote 6} in February 2021 describing the principles and scope of the review of the Regulations, which form the basis of the proposed Amendments. Over 50 responses to the scoping paper were received from provincial and territorial governments, industry, environmental non-governmental organizations (ENGOs), and other stakeholders. The Department reviewed these submissions and used them to inform the content of the Review of the OBPS Regulations: Consultation Paper (the Consultation Paper),^{footnote 7} published in December 2021. The Department received 58 submissions on the Consultation Paper, largely from industry and industry associations. Submissions were also received from provincial and territorial governments, academia and ENGOs. The review of the Regulations also included extensive engagement through technical working groups for implicated industry sectors identified in the scoping paper, as well as multi-stakeholder webinars and one-on-one meetings with interested parties. Comments that were not addressed in this review of the Regulations may be reconsidered in future reviews. Comments outside of the scope of this review were shared with the appropriate group within the Department for further consideration.

Tightening rates

Over 80% of submissions expressed opposition to the implementation of the proposed tightening rates. These submissions were largely from industry and industry associations. They expressed a strong commitment to reduce emissions but argued that the tightening rates would reduce regulatory certainty and the increased compliance costs could crowd out investments in emission abatement technologies. They also indicated that the impacts of the tightening rates would have the potential to devalue past and current investments in emission reductions and deter future investments. Several stakeholders mentioned that the proposed tightening rates would outpace the feasible deployment and advancement of technologies. Many of the comments proposed delaying, lowering, or removing the tightening rates and reassessing the need for them in the future.

Some comments on the tightening rates were supportive, representing a mix of feedback from industry, ENGOs, and academia. Some argued that the level of the tightening rates should be driven by climate objectives, provided that impacts on competitiveness and carbon leakage can be mitigated. Finally, some stakeholders indicated that the tightening rates would strengthen the incentive to invest in low-carbon technologies, generate proceeds for industrial decarbonization programs, and improve regulatory certainty.

The Department received comments that supported the view that the tightening rates are needed to maintain a strong credit market as GHG emissions continue to decline. Other comments indicated that the tightening rates may not be necessary to ensure emission reductions and a robust OBPS credit market.

Increasing the stringency of OBSs over time has been part of the design of the OBPS since its inception, in line with the PCF and the Pan-Canadian Approach. Delaying the application of a tightening rate could create risks of having too many credits in the market for compliance units, which would drive down the price of surplus credits and weaken the price signal. The “Risk assessments for carbon leakage and adverse competitiveness impacts” section below shows that many sectors are assessed to be at high risk of carbon leakage resulting from carbon pricing and competitiveness impacts resulting from carbon pricing under the proposed tightening rate. A higher tightening rate could exacerbate these risks. The proposed tightening rate is intended to balance the objectives of ensuring the marginal price signal is maintained and mitigating the risks of carbon leakage and competitiveness impacts for at-risk sectors.

The Government of Canada is also supporting the deployment of low-carbon technology through programs like the Net Zero Accelerator Initiative^{footnote 8} and the Strategic Innovation Fund,^{footnote 9} which will support sectors at risk of carbon leakage resulting from carbon pricing and competitiveness impacts resulting from carbon pricing in adopting clean technology and aim to catalyze the large-scale investments required to achieve Canada’s net-zero goal. The Clean Fuels Fund^{footnote 10} and the tax incentive for carbon capture, utilization and storage (CCUS)^{footnote 11} are other examples of decarbonization programs. In addition, proceeds collected from the federal OBPS are returned to the jurisdictions of origin. In jurisdictions where the OBPS proceeds are returned directly through federal programming, they support low-carbon technology and clean electricity projects and further the decarbonization of Canada’s industrial sectors.

Risk assessments for carbon leakage and adverse competitiveness impacts

Many stakeholders commented on the methods used to evaluate carbon leakage risks and adverse competitiveness impacts. Several stakeholders advocated for risk assessments to include considerations regarding differences in carbon costs between Canada and its trade competitors. The Department also received some requests to take sector- and region-specific considerations into account for the risk assessments, as well as the cumulative impacts of climate policies on industrial sectors. Other stakeholders indicated that the proposed approach is too generous, advocating for greater stringency to be applied to all but the most at-risk sectors.

Many stakeholders expressed concern about the level of sectoral aggregation in the Department’s EC-Pro model affecting results for certain subsectors, a lack of transparency related to the assumptions in the model and that dynamic modelling does not capture important technological nuances. Stakeholders also expressed concern regarding EITE assessment results for sectors whose risk levels were lower in the tightening rate analysis than in previous risk assessments for the emission reduction factors.

The Department’s current approach to assessing carbon leakage and adverse competitiveness impacts is similar to approaches applied across carbon pricing systems, such as Alberta’s Technology Innovation and Emissions Reduction Regulation, the European Union Emission Trading System, and California’s Cap-and-Trade Program. The Department aims to assess risks at the national level consistent with the approach of ensuring the federal OBPS is national in scope and can apply in any province or territory, as required. The use of EITE metrics prioritizes consistent and transparent methods for assessing risks of carbon leakage and adverse competitiveness impacts to ensure all sectors are evaluated in a comparable manner.

To address stakeholder concerns surrounding the level of aggregation, a static analysis based on historic data (Phase 1), which allowed for assessing risks for sectors at a higher resolution, was used to supplement the Phase 2 analysis that was completed to support the Consultation Paper. The details of these results are included in the Carbon leakage and adverse competitiveness impact risk assessment section in the Regulatory analysis to enable sectors to better understand the analysis and how it compares to previous assessments. Finally, while the risk assessment does not take into account the cumulative impacts of all policies, those that are likely to be in place over the analytical time frame and have an impact on the effectiveness of the federal carbon pollution pricing system are included in the baseline of the regulatory analysis.

Stakeholders also raised concerns surrounding carbon leakage between jurisdictions within Canada, a result of variations in stringency across regional carbon pricing systems. The update to the federal benchmark^{footnote 12} will reduce these differences by aligning the marginal price signal across output-based pricing systems in Canada. However, carbon leakage within the country could occur to the extent that standards, free allocations or revenue recycling approaches differ between carbon pricing systems, therefore leading to unequal average costs. In response to the Commissioner of the Environment and Sustainable Development’s Independent Auditor’s Report on Carbon Pricing,^{footnote 13} the Department has committed to begin federal-provincial-territorial work on the interim review of the federal benchmark by early 2023, with the goal of completing the review by late 2024 or early 2025. This would include creating a dedicated federal-provincial-territorial working group to assess aligning average costs and industrial performance standards as part of the review. A future review of the Regulations will consider the results of this work.

Industrial process emissions

Fifteen submissions provided feedback on the Department’s proposed approach on industrial process emissions, which are 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. Two thirds of the comments suggested modifications to the current treatment of industrial process emissions. These included increasing the emissions reduction factor to grant more free allocations for sectors with a high degree of industrial process emissions, exempting industrial process emissions from the standards altogether, or removing, reducing or delaying the tightening rate on industrial process emissions. These comments indicated that this increase in stringency should be postponed until technology to reduce these emissions is more available and affordable. A third of the comments were related to the Department’s review of emerging technologies and ensuring that the findings inform any future approach related to industrial process emissions. Comments also recommended that the Department adopt a process emissions approach similar to that of some provincial jurisdictions. A few stakeholders expressed support for the proposed approach.

The Department is not proposing a change in the approach to industrial process emissions, as outlined in the Consultation Paper. The updated federal benchmark requires that output-based pricing systems cover these emissions; therefore, exempting industrial process emissions from the federal OBPS would be inconsistent with the stringency requirements imposed on provincial and territorial systems through the Pan-Canadian Approach. Industrial process emissions were taken into account in the determination of the emissions reduction factors for OBSs. The Department is not reviewing the emissions reduction factors for existing standards at this time. To ensure alignment between new and existing OBSs, the Department is using the same approach to set the emissions reduction factors for the development of new OBSs. This approach reflects the challenges associated with reducing industrial process emissions but continues to incentivize reductions from all GHG emissions sources over time.

Compliance flexibility and emissions trading markets

There were 27 submissions that provided feedback on compliance flexibility. Of these, 23 expressed support for linking carbon pricing systems across Canada. There were an additional 19 comments discussing limits on surplus credits from industry stakeholders, generally requesting that the limits be reduced or eliminated. These comments ranged from requesting the removal of the mandatory minimum of 25% of compensation made through excess emissions charge payments, enabling the transfer of surplus credits when transitioning from the federal OBPS to a provincial carbon pricing system for industry, and removing the expiration of compliance units. There were also comments on the recognition of offset credits generated outside Canada and placing limits on the use of offset credits by OBPS participants.

The Department is not proposing amendments to rules related to compliance flexibility. Limitations on the use of compliance units, including when the scope of a system changes, and expiry of credits are common design features in other emissions trading systems. Such limitations are essential to maintain the marginal price signal by preventing a flood of credits in the market. This general principle has been taken into account in establishing the updated federal benchmark criteria.

No new limits on the use of offset credits are currently being proposed. There is a robust process under the Regulations to recognize offset credits generated under provincial offset systems when certain criteria are met. A domestic framework for the acquisition and use of international offset credits has not been established and so recognition of international offset credits is not being contemplated at this time.

Several industry and ENGO stakeholders expressed support for linking output-based pricing systems. The linking of systems would reduce the total societal costs of achieving GHG emissions reductions and, with it, the total compliance costs for industrial facilities. It may potentially also help to reduce the risk of any oversupply of credits. As indicated in the Consultation Paper, the Government of Canada is open to initiating discussions on a roadmap to the linking of carbon pricing systems for industry with interested provinces and territories and encourages voluntary efforts to link systems. Any linking of systems would need to align with the updated federal benchmark criteria.

New output-based standards

The Department established 10 working groups and held over 30 meetings in support of the development of new OBSs, including undertaking extensive data-gathering exercises. In general, stakeholders were supportive of the development of new OBSs, and many of the concerns raised through the working groups were addressed in the design of the standards. For example, stakeholders were concerned that where new OBSs were being developed to apply at covered facilities with existing applicable OBSs, the reference years should remain consistent with the existing OBSs (2014–2016). As a result, two new standards applicable to such facilities were set using 2014–2016 data for consistency with the method to set existing OBSs. Some remaining concerns were the inclusion of facilities that did not emit over 10 kt of CO₂e in every reference year when calculating the applicable standard; the inclusion of facilities that use different energy sources, such as those that have a greater reliance on electricity to produce the same products; and requests to disaggregate production into semi-finished and finished products for the purpose of establishing the OBSs.

The approach of including all facilities that have reported 10 kt of CO₂e or more in any year after 2017 is consistent with the general approach under the Opt-in Policy to enable facilities to apply to opt in if they have emitted 10 kt of CO₂e or more in any year after 2017, even if their emissions subsequently fell below that threshold. In general, data used to set the standards seek to include all facilities producing the same products, regardless of fuel source or technology, in order to encourage production with lower emissions intensity. Finally, standards were set in a manner that sought to have the greatest level of aggregation of products feasible, while being mindful not to create different incentives for different business configurations, and to create distinct standards only where the products themselves are distinct (have different end uses, markets, physical characteristics, etc.).

Some stakeholders requested that additional standards be included in the Regulations. The Department received comments requesting the inclusion of thermal energy and district energy, as well as nuclear energy. The Department does not propose to include thermal energy and district energy in the federal OBPS. Allocations are provided within OBSs for purchases of thermal energy by covered facilities. For thermal energy consumed by non-covered facilities, the carbon price on fuels is expected to incentivize consumers to use lower emission energy options, potentially including district heating. The treatment of electricity generation in the OBPS is not being considered in this review. The Department will consider revisions to the treatment of electricity generation under the OBPS as part of the process to introduce proposed Clean Electricity Regulations that will set Canada on a path to cut more emissions by 2030 and to achieve a 100% net-zero emitting electricity system by 2035.

Some industrial stakeholders expressed concern about the Department’s decision not to add a biodiesel OBS to Schedule 1 to the Regulations as proposed in the scoping document. Based on engagement with the working group, there are fewer than three biodiesel production facilities that emit 10 kt of CO₂e or more per year. There are confidentiality concerns with publishing numeric standards based on a small number of facilities; for this reason, this OBS is not included in the proposed Amendments. Biodiesel production facilities may still apply for designation as a covered facility under the Opt-in Policy if they meet the criteria to voluntarily participate. In this case, facilities would receive a facility-specific calculated OBS.

Review of existing output-based standards

Fourteen stakeholders provided general feedback related to reviewing existing standards. Some comments requested that the Department review and update data used to set existing OBSs to reflect new industrial processes, update baseline data before increasing the stringency of standards through the proposed tightening rate, review emissions reduction factors for existing standards, and move from sectoral standards to facility-specific standards to address facility-specific circumstances. In addition, the Department received specific requests to review standards related to hydrogen production, ammonia production, upgrading of bitumen or heavy oil, and pulp and paper.

During this review, due to the limited number of years the federal OBPS has been in place, the Department has opted to only review existing OBSs in cases where the activity definition no longer aligns with current or planned activities by facilities in the sector, or where there is a significant error in the baseline data. The Department may undertake further reviews of existing OBSs in a subsequent review and will take into account at that time comments requesting that specific standards be reviewed. The review assessed the risks of competitiveness and carbon leakage impacts; however, it is focused on the impacts of the carbon price trajectory and proposed tightening rates.

Working groups were established to consider changes to the urea liquor standard, and to the iron and steel standards. Meetings were also held to consider changes to the automotive standard. Stakeholders were generally supportive of the review of the urea liquor standard and the inclusion of a new separate granular urea activity. The automotive sector was generally supportive of the change to the automotive standard. However, it noted the importance of ensuring that facilities producing zero-emission vehicles as a secondary activity have access to a standard for these activities. The addition of the definition of additional industrial activities through the proposed Amendments would enable access to facility-specific standards for these activities. A comment was received arguing that this change to the automotive OBS is not technology-neutral and unfairly recognizes one sector’s move to produce zero-emission technology. In general, the Department applies the principle of “one product, one standard” for the development of OBSs and is therefore moving away from technology-specific standards. Zero-emission vehicles differ from internal combustion engine vehicles in their physical properties, the way consumers treat the product and their classification, and therefore are being considered as distinct products.

Considerable work was completed on the review of the iron and steel standards. The working group held 11 working group meetings and collected a substantial amount of data to support the revisions. The Department completed an initial review of the standards and developed an option for the structure of the iron and steel standards. The approach would have aligned the standards with the objective to use technology-neutral standards to incent the deployment of processes with the lowest emissions intensity to produce the same or similar products. It would also have more fully reflected the range of activities undertaken at iron and steel facilities. Under the approach explored, one standard would have applied to iron making and another standard would have applied to steel making. The approach would also have added one standard for hot steel rolling and one standard for steel finishing activities, and would have enabled iron and steel facilities to access the OBS for the production of electricity using natural gas as well as the OBS for the production of lime. The option was based on the Department’s understanding that, due to process improvements, a very similar range of products can be produced using different technology routes.

Due to the complexity of the iron and steel sector, the foreseeable shift of technology and the uncertainty around the appropriateness of grouping all steel production under the same standard and all iron production under the same standard, regardless of the production processes, the Department was unable to complete the review of the iron and steel standards prior to the publication of the proposed Amendments. The Department requires more time to further understand the products developed at different types of steel mills in Canada and how standards can be developed that appropriately capture the distinct products made at various facilities and provide incentives for facilities to reduce the emissions associated with producing these products. For these reasons, the proposed Amendments do not include any changes to the existing iron and steel standards. Proposals will continue to be developed and, if appropriate, changes to the standards would be proposed.

Reducing administrative burden

Stakeholders provided some feedback on the reduction of the administrative burden. Specifically, 10 submissions supported the harmonization of GHG emissions quantification methodologies, and 3 submissions requested greater consistency between reporting systems. Stakeholders specifically expressed an interest in greater consistency between the Regulations and the Greenhouse Gas Reporting Program (GHGRP).

The Department is working on harmonizing the GHG quantification methods to the extent possible by making it easier for the Minister to update those in the federal OBPS to align better with other GHG emissions quantification methods as they evolve over time. This is the first step towards greater harmonization of quantification methods.

To the extent possible, the Department is also planning to require, starting with the 2024 compliance period, the use of the same quantification methods as required by the GHGRP for the same year. Differences in quantification methods may have to remain in order to account for differences in the scope and objectives of the OBPS and the GHGRP. The Department intends to explore opportunities to further increase the level of harmonization between the two programs over time. The interest in better integration will also be considered as updates to the electronic reporting systems of the OBPS and the GHGRP are being planned.

Accurate reporting

Material discrepancy

There were 19 submissions received by the Department expressing opposition to an increase in the stringency in the material discrepancy threshold for production. Stakeholders expressed that lowering the material discrepancy threshold for production to 0.1% is too low and unnecessary. Many stakeholders indicated that it is not feasible to meet a 0.1% material discrepancy threshold for production due to the calibration requirements and the error range associated with measuring devices.

It is important to note that a material discrepancy occurs when, in consideration of the reporting requirements prescribed under the Regulations, there is an error or omission in the quantity of GHG emissions or production reported. The Regulations contain requirements to ensure that measuring devices used to measure production are installed, operated, maintained, and calibrated in accordance with the manufacturer’s specifications or any applicable generally recognized national or international industry standard to a 5% margin of error. Values provided by measuring devices that are compliant with regulatory requirements would normally be considered accurate. Errors that would be counted towards the determination of a material discrepancy are, for example, reporting in incorrect units or incorrect inclusion of intermediate products in the final production total.

The proposed material discrepancy threshold for production of 0.1% is consistent with other jurisdictions within Canada and abroad, and the Department continues to propose this threshold. The Department welcomes feedback on the proposed threshold that is not related to the calibration of instruments to further understand and assess the expected impacts of the proposed threshold.

Approach for corrected reports

There were seven submissions from stakeholders discussing proposed adjustments to the submission of corrected reports. Some stakeholders provided reasons why it can be difficult to correct all errors in a corrected report. One stakeholder suggested that only material errors be corrected upon review and all errors identified afterwards should be corrected in the next annual report. Stakeholders were also supportive of removing the requirement to submit a corrected report automatically once an error is identified.

Furthermore, stakeholders mentioned that not all errors identified by verification bodies should necessarily be considered an error. Some errors identified by verification bodies are discrepancies between calculations conducted by the verification body and those performed by the covered facility. These do not always represent the use of the wrong methodology and are not necessarily compliance errors. Finally, some stakeholders requested further clarification on what actually constitutes an error.

Annual reports must be submitted in accordance with the requirements of the Regulations. There is no provision in the Regulations that allows for any level of error in the annual report. After careful consideration, the Department has proposed to require the correction of errors or omissions identified by the verification body prior to the submission of the annual report, where possible. In addition, the Department is proposing to require the submission of a corrected report accompanied by a verification report where the person responsible for a covered facility notifies of an error or omission that would have constituted a material discrepancy if it had been found during the verification of the annual report. It should be noted that the Minister maintains the authority under section 177 of the Act to request a corrected report should they deem it necessary.

Voluntary participation

A number of stakeholders provided feedback on the voluntary participation process. A few submissions expressed support for setting a timeline for the application for designation, thereby providing more certainty for facilities who wish to opt into the federal OBPS. The Department is proposing to move forward with amending the Opt-in Policy to set a deadline to make a request for designation to improve certainty and predictability. The Department is also proposing to have first compliance periods start on January 1 for all covered facilities. This would effectively remove any potential uncertainty related to partial compliance periods, and provide greater certainty and consistency in the administrative and report-generating processes for both covered facilities and the Department.

Some stakeholders requested that the criteria to voluntarily participate be more flexible to allow more facilities to opt into the OBPS. Feedback was provided on the Department’s use of North American Industry Classification System (NAICS) codes to determine the sectors at risk of carbon leakage due to carbon pricing and competitiveness impacts as a result of carbon pricing in the voluntary participation process, citing that NAICS codes are insufficient to assess the size and scale of the manufacturing sector in Canada. There was also feedback on the use of facility data instead of sectoral data for the assessment of a sector.

EITE metrics serve as measures of the significance of a sector’s carbon cost and its ability to pass on those costs to consumers. The use of sector- or subsector-level data in the assessment provides consistent treatment across the sector or subsector in the EITE assessment and avoids adjustments in stringency based on the data of a small number of facilities that may not be representative of the sector. The assessments are completed at the lowest level of aggregation at which all the data points needed to do the assessments are available. NAICS codes continue to provide the most consistent means to assess EITE risks at the sectoral level and therefore are expected to continue to form the basis for identifying at-risk sectors.

A few submissions requested the aggregation of facilities that are considered multiple facilities under the Regulations for the purposes of opting into the OBPS. Finally, a few submissions requested that the threshold to opt in be lowered or removed. The Regulations currently allow multiple sites to be considered as a single facility if they are operated in an integrated way to carry out an industrial activity such that they meet the facility definition under the Regulations. The Department is not considering changes related to the aggregation of facilities and the opt-in threshold in this review. However, the Department will continue to consider these matters in future reviews.

Modern treaty obligations and Indigenous engagement and consultation

An assessment examined the geographical scope and subject matter of the proposed Amendments in relation to modern treaties in effect, and did not identify, at this time, potential modern treaty implications.

In addition, the proposed Amendments would respect the Government of Canada’s obligations in relation to rights protected by section 35 of the Constitution Act, 1982 and modern treaties, and international human rights obligations. The Government of Canada continues to work with Indigenous organizations on the federal approaches to the pricing of carbon pollution and the return of proceeds so they consider the unique circumstances and priorities of Indigenous peoples.

Instrument choice

The Department considers the proposed Amendments to be necessary to continue to improve the Regulations and maintain the integrity of the OBPS. Given the policies and funding in the ERP, and as more technology becomes available, there is a risk that the incentive to reduce GHG emissions in the OBPS could diminish considerably if increased stringency through the introduction of a tightening rate is not implemented. As the excess emissions charge increases to $170/tonne of CO₂e by 2030, there is a concern that there will be a surplus of credits in the market resulting in a flood of surplus credits priced lower than the excess emissions charge, lowering the incentive for sectors under the OBPS to reduce their GHG emissions. Furthermore, the proposed Amendments align the stringency of the federal OBPS with the requirements of the federal benchmark.

Finally, the clarifications to various provisions of the regulatory text, by means of the proposed Amendments, would facilitate the Department’s administration of the Regulations and help ensure that compliance with the Regulations is consistent with the Department’s policy intent.

Regulatory analysis

Carbon leakage and adverse competitiveness impact risk assessment

In order for the OBPS to continue to mitigate risks of carbon leakage and adverse competitiveness impacts, the EITE analysis, outlined in the “Background” section above, has been updated to reflect the increased excess emissions charge set out in Schedule 4 to the Act, and the proposed tightening rate. The results of this analysis were used to identify sectors at very high EITE risk. These sectors were assigned a lower tightening rate of 1% per year. Applying a tightening rate to these sectors sends a signal that effort should be made to reduce these emissions over the longer term. The tightening rate is set to maintain sufficient demand for credits in the OBPS to preserve the marginal price, taking into account expected reductions in emissions in response to the carbon price and other supporting measures. The updated benchmark states that output-based pricing systems for industry must be designed to maintain a marginal price signal equivalent to the minimum national carbon pollution price across all covered emissions. The tightening rate plays an important role in aligning the OBPS with the updated federal benchmark. The impact on the marginal price signal is assessed both at the national level (i.e. by assuming the federal OBPS is applied across Canada) and based on the current scope of application of the OBPS.

The Department applied Phases 1 and 2 analyses to evaluate the EITE risk levels of sectors that are covered under the OBPS. This is required to understand the extent to which the price trajectory, in combination with the tightening rate, could increase the risk of carbon leakage and competitiveness impacts on these sectors.

The Phase 1 analysis was conducted at a stringency consistent with 2026 (i.e. with a tightening rate of 2%/year applied from 2023 to 2026 and a carbon price of $110/tonne of CO₂e),^{footnote 14} which is the minimum national carbon price in 2026. The use of historical data for this type of analysis is limited by the fact that it does not take into account uncertainties regarding the costs of deploying emissions reduction technologies and changes to economic trends that will occur in the future. Therefore, a 2026 stringency level was used for the static analysis instead of a 2030 stringency level in order to capture an increase in the stringency while mitigating the many uncertainties of technologies and economic trends associated with using historic data to assess impacts into the future.

The Phase 2 analysis incorporates dynamic modelling of 2030 to take into account future emissions intensity improvements and market changes as the central determinants of EITE risk levels. The analysis is based on dynamic modelling using EC-Pro that accounts for changes in industrial emissions over time (e.g. due to behavioural change, government investments and other factors). This modelling is based on the modelling completed for the ERP; however, it does exclude some of the policies and measures included in the ERP that are still in the early stages of development. It includes clearly articulated policies and programs that have been announced, approved and funded, and regulations that have been published in the Canada Gazette, Part II. This baseline is also used to assess provincial and territorial output-based pricing systems to determine whether the marginal price signal is maintained.

Tables 3 and 4 show the results of the Phase 1 and Phase 2 analyses respectively. Sectors are shown to be at low,^{footnote 15} medium,^{footnote 16} high^{footnote 17} or very high risk.^{footnote 18} Specifically, Phase 1 and Phase 2 analyses identify the cement, lime, petrochemicals, and natural gas production and processing sectors as being at very high risk of carbon leakage and competitiveness impacts. As a result, the annual tightening rate applied to activities undertaken in these sectors, as outlined in Tables 3 and 4, is proposed to be lowered to 1% to mitigate increased competitiveness impacts and carbon leakage risks.

The broad approach to electricity generation in the federal OBPS will be reviewed as part of the process to reach net-zero emissions from electricity generation by 2035.

Table 3: Phase 1 EITE analysis results at 2026 stringency

NAICS code	NAICS sector name	Activities as identified in Schedule 1 to the Regulations	2016 to 2018 average emissions intensity (EI) table b1 note a	2016 to 2018 average trade exposure (TE) table b1 note b	EITE risk category (direct costs)
32741	Lime manufacturing	Item 8	13%	37%	Very high
32731	Cement manufacturing	Item 7	12%	38%	Very high
32511	Petrochemical manufacturing	Sub-items 17(a) to (f)	9.5%	40%	Very high
32512	Industrial gas manufacturing	Item 6	6.8%	24%	High
33111	Iron and steel mills and ferro-alloy manufacturing	Items 19 and 20	6.3%	48%	High
211110	Oil and gas extraction (except oil sands)	Sub-item 1(a) and item 4	6.1%	66%	High
21114	Oil sands extraction	Items 2 and 3.1 and sub-item 1(b)	6.1%	77%	High
3253	Pesticide, fertilizer and other agricultural chemical manufacturing	Sub-items 29(c), (d), and (e)	5.3%	52%	High
4862	Pipeline transportation of natural gas	Item 5	4.2%	55%	High
3253	Pesticide, fertilizer and other agricultural chemical manufacturing	Sub-items 29(a) and (b)	3.8%	52%	High
32519	Other basic organic chemical manufacturing	Items 13 and 34 and sub-items 3(c) and 17(g)	3.3%	91%	High
33131	Alumina and aluminium production and processing	Items 40, 41 and 43	3.3%	77%	High
3221	Pulp, paper and paperboard mills	Item 36	3.2%	76%	High
32411	Petroleum refineries	Sub-item 3(a)	3.2%	46%	High
21221	Iron ore mining	Sub-items 21(b) and 26(a)	2.3%	91%	Medium
32519	Other basic organic chemical manufacturing	Item 15	2.1%	91%	Medium
33141	Non-ferrous metal (except aluminum) smelting and refining	Sub-items 23(c), (e), and (f)	2.1%	70%	Medium
2121	Coal mining	Items 25, 27 and 28	1.7%	86%	Medium
32419	Other petroleum and coal product manufacturing	Sub-item 3(b) and item 42	1.6%	46%	Medium
21221	Iron ore mining	Sub-item 21(a)	1.5%	91%	Medium
33141	Non-ferrous metal (except aluminum) smelting and refining	Sub-items 23(a), (b), and (d)	1.4%	70%	Medium
212392	Diamond mining	Sub-item 26(e)	1.2%	97%	Medium
212396	Potash mining	Item 24	1.2%	87%	Medium
31122	Starch and vegetable fat and oil manufacturing	Items 31 and 33	1.2%	74%	Medium
2123	Non-metallic mineral mining and quarrying	Item 24.1	1.0%	64%	Medium
32742	Gypsum product manufacturing	Item 10	1.0%	22%	Medium
32721	Glass and glass product manufacturing	Item 9	0.86%	69%	Low
3113	Sugar and confectionery product manufacturing	Item 35	0.81%	73%	Low
31213, 31214	Wineries and distilleries	Item 32	0.68%	73%	Low
32513, 32518, 3252, 3255, 3256, 3259	Other chemicals	Item 16	0.60%	82%	Low
3114	Fruit and vegetable preserving and specialty food manufacturing	Item 30	0.58%	59%	Low
311A0 (3112, 3118, 3119)	Miscellaneous food manufacturing	Item 35.1	0.57%	51%	Low
21222	Gold and silver ore mining	Sub-items 26(c) and (f)	0.53%	36%	Low
32732, 32733, 32739, 3271, 3279	Other non-metallic mineral product manufacturing	Item 11	0.40%	32%	Low
32513, 32518, 3252, 3255, 3256, 3259	Other chemicals	Item 14	0.39%	82%	Low
321	Wood product manufacturing	Item 39	0.38%	57%	Low
3262	Rubber product manufacturing	Item 44	0.37%	82%	Low
21223	Copper, nickel, lead and zinc ore mining	Sub-item 26(d)	0.36%	55%	Low
21229	Other metal ore mining	Sub-item 26(b)	0.32%	59%	Low
32732, 32733, 32739, 3271, 3279	Other non-metallic mineral product manufacturing	Item 12	0.26%	32%	Low
3361	Motor vehicle manufacturing	Item 37	0.20%	91%	Low
32541	Pharmaceutical and medicine manufacturing	Item 18	0.16%	88%	Low
33121	Iron and steel pipes and tubes manufacturing from purchased steel	Item 22	0.12%	52%	Low
Table b1 note(s) Table b1 note a EI is the ratio of direct carbon cost to gross value added for the sector. Return to table b1 note a referrer Table b1 note b TE is equal to (Imports + Exports) / (Imports + Sales) for the sector. Return to table b1 note b referrer

Table 4: Phase 2 EITE analysis results at 2030 stringency

Sector	Activities as identified in Schedule 1 to the Regulations	EI	TE	Risk category
Natural gas extraction and processing	Item 4	9.8%	47%	Very high
Oil sands mining	Item 3.1	3.3%	69%	High
Gas pipeline transportation	Item 5	22%	4.6%	Medium
Cement	Item 7	6.4%	17%	Medium
Frontier oil mining / Light oil mining	Sub-item 1(a)	2.5%	58%	Medium
Other mining	Items 21, 24, 24.1, and 26	1.2%	57%	Medium
Coal	Items 25, 27 and 28	1.1%	126%	Medium
Aluminium	Items 40, 41, and 43	0.47%	79%	Low
In-situ oil sands (including heavy oil)	Sub-item 1(b)	0.25%	69%	Low
Pulp and paper mills	Item 36	0.26%	65%	Low
Food products	Items 30 to 33, 35, and 35.1	0%	39%	Low
Wood and wood products	Item 39	0%	48%	Low
Primary metal manufacturing	Item 23	0%	86%	Low
Transport equipment	Item 37	0%	81%	Low
Plastic and rubber products	Item 44	0%	57%	Low
Other chemical manufacturing	Items 6, 13 to 18 and 34, and sub-item 3(c)	0%	63%	Low
Non-metallic minerals	Items 8 to 12	0%	31%	Low
Petroleum and coal products manufacturing	Item 42 and sub-items 3(a) and (b)	0%	52%	Low
Oil sands upgraders	Item 2	0%	62%	Low
Iron and steel	Item 19, 20, and 22	0%	54%	Low
Fertilizer	Item 29	0%	40%	Low

Adding new OBSs

The three-phase approach previously described was applied to determine whether any phase of the analysis indicates a high level of risk of carbon leakage and adverse competitiveness impacts or provides a basis for an OBS to be considered for an upwards adjustment from 80% to 90% or 95%. An assessment was also completed to determine whether industrial process emissions make up a significant portion of the total emissions for facilities undertaking the activity. Activities found to have a proportion of industrial process emissions of 30% or more were considered for adjustment from 80% to 90%, and those for which standards were adjusted to 90%, based on the Phase 1, 2 and 3 analysis, were considered for adjustment from 90% to 95%.

Based on the results of the Phase 1 and 2 analysis, all sectors were found to be in the medium or low EITE risk category and therefore emissions reduction factors were not adjusted for any of the proposed new standards on this basis. Furthermore, based on Phase 3 of the analysis, no sector was found to be at an elevated risk of carbon leakage and competitiveness impacts, and therefore this phase of the analysis did not provide a basis for any adjustments in stringency to the OBSs. Four activities were found to have a proportion of industrial process emissions of 30% or more, and the emissions reduction factor for these activities were adjusted to 90%. Table 5 below lists the new activities, the results of the competitiveness and carbon leakage assessments and the proposed emissions reduction factor assigned to each activity.

Table 5: Proposed emissions reduction factors

Sector	Activity	Phase 1 EITE risk level	Phase 2 EITE risk level	Phase 3 outcome	Industrial process emissions > 30%	Proposed emissions reduction factor
Oil and gas production	Surface mining of oil sands and extraction of bitumen	Medium	Low	No basis for adjustment	No	80%
Chemicals	Production of monoethylene glycol, diethylene glycol, and triethylene glycol	Medium	Low	No basis for adjustment	Yes	90%
Mining and ore processing	Production of evaporated salt through solution mining	Low	Low	No basis for adjustment	No	80%
Food processing	Production of malt	Low	Low	No basis for adjustment	No	80%
Wood products	Production of wood veneer or plywood	Low	Low	No basis for adjustment	No	80%
	Production of lumber	Low	Low	No basis for adjustment	No	80%
	Production of particle board and low, medium or high-density composite panels, including hardboard	Low	Low	No basis for adjustment	No	80%
Aluminium	Aluminium production from alumina	Medium	Low	No basis for adjustment	Yes	90%
	Production of baked anodes for use in aluminium production from alumina	Medium	Low	No basis for adjustment	Yes	90%
	Production of calcined petroleum coke for use in aluminium production from alumina	Medium	Low	No basis for adjustment	Yes	90%
	Production of alumina from bauxite	Medium	Low	No basis for adjustment	No	80%
Rubber products	Production of pneumatic tires	Low	Low	No basis for adjustment	No	80%

Updating existing OBSs

As a result of updates to GWPs in Schedule 3 to the Act, the proposed Amendments would allow for the update of existing OBSs when the change in GWP values would result in a material change of more than ± 1% in the value of the OBS. Table 6 below includes the activities that meet this threshold and the percent change in those standards. In addition to the standards listed below, the production by mining coal deposits of metallurgical coal (sub-item 25(b) of Schedule 1 to the Regulations) would have seen a material change in emissions associated with the changing GWPs; however, the calculation of the original standard included an error that resulted in no need to update this standard.

Table 6. Existing activities for which there is at least a 1% change in emissions as a result of the updated GWPs

Activity	% change in emissions
Industrial processing of potatoes for human or animal consumption, item 30 of Schedule 1 to the Regulations	2.4%
Production of nitric acid by the catalytic oxidation of ammonia, sub-item 29(a) of Schedule 1 to the Regulations	−7.6%

Benefits and costs

The costs and benefits discussed below are attributable to the set of Amendments, including the proposed Amendments resulting from the review of the Regulations and the Order Amending Schedule 4 to the Greenhouse Gas Pricing Pollution Act. This includes an increasing excess emissions charge up to $170/tonne of CO₂e in 2030, the introduction of a tightening rate on OBSs, and new and updated OBSs. The policies included in the set of Amendments are integral to one another and modelling them together ensures a complete and accurate representation of impacts, reflective of the intended and expected outcomes of the interdependent policies.

Summary

The regulatory analysis compares a “Regulatory Scenario” (set of Amendments) to a “Baseline Scenario” where there is no increase to the excess emissions charge (Schedule 4 to the Act) or increased stringency of OBSs. The analysis assesses the benefits of the decreased emissions from the set of Amendments, and losses to Canadian society from decreased economic activity. Decreases in sectoral production due to increased costs result in decreases in overall economic welfare of households. However, there are also fewer GHG emissions in the Regulatory Scenario, causing an increase in societal benefits due to avoided climate change damages when compared to the Baseline Scenario.

The Baseline Scenario and the Regulatory Scenario were modelled using EC-Pro, the Department’s peer-reviewed, multi-region, multi-sector, provincial-territorial computable general equilibrium (CGE) model of climate change policies. EC-Pro is able to assess the variables of interest, including GHG emissions and household economic welfare. EC-Pro simulates the Canadian economy and calculates the impacts of the set of Amendments by calculating the new set of prices and variables that will return the economy to equilibrium. The incremental impacts of the set of Amendments can be estimated by comparing the results from the Baseline Scenario to those from the Regulatory Scenario. The analysis uses the social cost of GHGs to monetize the benefits of reduced domestic GHG emissions.^{footnote 19} The monetized administrative and verification costs of the set of Amendments were estimated separately outside of the CGE model.

The analysis of the set of Amendments was conducted based on the scope of application at the time of the publication of the proposed Amendments, with the federal OBPS currently applying in 2022 in Yukon, Nunavut, Manitoba and Prince Edward Island, and partially in Saskatchewan.

As the set of Amendments will provide covered facilities with financial incentives for continuous emissions reductions, the Regulatory Scenario will result in more emissions reductions than are expected in the Baseline Scenario. The cumulative incremental domestic GHG emissions reductions are estimated to be 5.8 Mt of CO₂e over the 2023 to 2030 period. By 2030, compared to the Baseline Scenario, the set of Amendments could result in a decrease in Canadian household welfare of $513 million to $855 million, with a central estimate of $684 million. This is an estimate of the value that households, assumed to be the owners of the factors of production, labour and capital, through decreases in the wages earned by workers and the profits earned by firms (facilities), forego from decreased consumption. Therefore, the GHG emission reductions would be achieved at an estimated societal cost per tonne of between $89/tonne of CO₂e and $149/tonne of CO₂e, with a central estimate of $119/tonne of CO₂e. Based on a probabilistic model, there is an 85% likelihood that the monetized benefits will be greater than the costs. Additional GHG emissions reductions and costs to Canadian society are expected in 2031 and 2032 as the OBSs continue to tighten, but they have not been quantified as part of this analysis.

Analytical framework

Treasury Board Secretariat (TBS) guidance: The impacts of the set of Amendments have been assessed in accordance with the TBS Canadian Cost-Benefit Analysis Guide.^{footnote 20} Regulatory impacts have been identified, quantified, and monetized, where possible, and compared incrementally to a Baseline Scenario.

Key impacts: The logic model in Figure 1 illustrates the incremental impacts of the set of Amendments that the Department is able to quantify and monetize in this analysis. Compliance actions under the set of Amendments would result in incremental reductions in domestic GHG emissions, increased capital and operating costs for industry, as well as administrative costs for both industry and government. Distributional impacts, such as sector-specific and region-specific results, are analyzed separately.

Figure 1: Logic model for the analysis of the set of Amendments

Set of Amendments	→	Reduction in domestic GHG emissions	→	Reduction in climate change damages	→	Social benefits
	→	Net compliance costs	→	Reduction in economic output	→	Household welfare costs

Baseline Scenario: Modelling of the baseline case was conducted using an adjusted 2021 Reference Case^{footnote 21} (Canada’s official emissions forecast), with a combination of policy measures from the ERP and an increasing fuel charge ($170/tonne of CO₂e in 2030). In addition, non-backstop jurisdictions are operating their own carbon pollution pricing systems aligned with the federal benchmark, maintaining the excess emissions charge to $50/tonne of CO₂e, and do not apply tightening rates to OBSs. The Baseline Scenario includes clearly articulated policies from the ERP and Budget 2022–2023 that have been announced, funded, and are directed towards a specific sector. The Baseline Scenario excludes policies that are not defined and do not have sector-specific targets. It includes federal environmental regulations that have been published in the Canada Gazette, Part II, ahead of the publication of the proposed Amendments in the Canada Gazette, Part I.

Regulatory Scenario: Under the Regulatory Scenario, modelling was conducted using an adjusted reference case for 2021, an excess emissions charge that increases at $15/tonne of CO₂e per year, resulting in a carbon price of $170/tonne of CO₂e in 2030. It also includes the previously described tightening rates for OBSs starting in 2023, where the OBSs are tightened by 2% per year, with exceptions for sectors that are deemed to be at a very high risk of carbon leakage and competitiveness impacts. For these sectors, a tightening rate of 1% per year was applied. As with the Baseline Scenario, the Regulatory Scenario includes a combination of policies from the ERP and Budget 2022–2023.

Incremental impacts: The analysis compares the expected impacts of the Regulatory Scenario relative to the Baseline Scenario. This analysis does not assess the impacts of carbon pollution pricing as a whole. It assesses the incremental impacts of increasing the excess emissions charge to $170/tonne of CO₂e by 2030, and tightening rates for OBSs starting in 2023, where the OBPS currently applies.

Time frame of analysis: A key objective of the amendments is to have the OBPS remain aligned with the federal benchmark. The updated benchmark applies for the 2023–2030 period. The quantitative assessments applied under this Regulatory Impact Analysis Statement and to benchmark assessments are based on Canada’s 2021 Reference Case projections, which project emissions out to 2030. For consistency with the quantitative assessments applied to provinces and territories under the benchmark, the time frame considered for the quantitative analysis is the 2023–2030 period. A qualitative analysis has been conducted in relation to the expected impacts of the set of Amendments in 2031 and 2032. Without further regulatory amendments, the annual tightening rates for the OBSs would be maintained at the same rates at which they are set for the 2023–2030 period, and the excess emissions charge would remain at $170/tonne of CO₂e, in the Regulatory Scenario.

Monetary results: All monetary results are presented in 2021 Canadian dollars, and non-2021 prices were inflated using gross domestic product (GDP) deflators from Energy-Emissions-Economy Model for Canada (E3MC), the Department’s macroeconomic model. When shown as present values, future year impacts have been discounted at 3% per year, as per TBS guidance for health and environmental regulatory proposals, to 2022 (the base year of the analysis).

Social cost of carbon: As illustrated in Canada’s Cost-Benefit Analysis Guide published by TBS, when conducting regulatory analysis, federal departments and agencies must use the social cost of carbon (SCC) to measure the costs and benefits associated with changes in emissions.

Break-even analysis: As there is an inherent uncertainty concerning the estimates of avoided climate change damages, a break-even analysis (BEA) was conducted to establish a range of benefits needed to offset the monetized costs of the set of Amendments, and comparing those to the range of SCC values in the literature. This approach is simple and transparent, offers a risk tolerance perspective, and provides continuity between previous and future climate change analyses.

BEA is a technique used to assess how valuable a non-monetized impact will have to be in order to meet or exceed net costs. It is most effective when there is uncertainty about one key parameter — in this case, the dollar value of social benefits from climate change damages avoided as a result of CO₂ emission reductions. In climate change policy, BEA involves determining the minimum carbon value that will allow a given regulation to break even (i.e. to ensure benefits at least equal costs). Consistent with methodologies used by other jurisdictions, to validate the break-even value, it should fall within a plausible range of established values from recent studies.^{footnote 22}

Modelling: The Baseline Scenario and the Regulatory Scenario have been modelled using EC-Pro. As the set of Amendments is expected to affect production in various markets in the Canadian economy, a general equilibrium model is best suited to estimate the impacts.^{footnote 23} EC-Pro is able to assess the variables of interest, including GHG emissions, household economic welfare, GDP and gross value added (GVA).

Emission changes attributable to technological change resulting in combustion emissions abatement are modelled through responsiveness of production inputs to changes in relative prices. For example, a representative producer may switch to lower emitting fuels in the model. For the modelling of non-combustion emissions, it is assumed that facilities could make a technological change to lower their costs under the OBPS. Combustion and non-combustion emission changes can also be attributable to changes in production.

The model accounts for the supply and demand balance of credits by assuming that facilities that emit below their annual facility emissions limit earn the value of the excess emissions charge for each tonne between their actual emissions and their limit so long as the quantity of compensation obligations exceeds the quantity of surplus credits in a given year. Should the supply of surplus credits exceed the compensation obligation, the model would estimate a lower marginal (market-clearing) price and thus a lower incentive for emission reductions. The model does not account for trading partners for these credits or banking behaviour.

Benefits

Social cost of carbon

The main role of the social cost of carbon (SCC), as it is used in Canada, is to inform cost-benefit analyses of environmental regulations. Climate change is expected to result in a range of possible impacts, which include drought, floods, agricultural production and energy use changes, and effects on human health and ecosystem services. All of these impacts result in costs to society, which, when aggregated, can represent amounts in the billions of dollars. The SCC is the costs of these expected impacts, measuring the global damages resulting from each additional tonne of CO₂ emitted in the atmosphere today over its lifetime.

The SCC includes damages that have impacts on agricultural production, human health, flood risk, and ecosystem services. However, some other impacts related to climate change, including extreme weather events such as storms, wildfires and hurricanes, are not well enough understood yet to be fully integrated into models currently used to assess global climate change impacts. The SCC therefore reflects only a part of the impacts that can be expected from climate change, and could be interpreted as being a lower bound of the potential impacts from climate change.

Since 2018, all federal regulatory analysis involving GHG emissions has relied on the SCC values that were published by the Department in 2016.^{footnote 24} These SCC values are derived from three commonly used peer-reviewed integrated assessment models: the Dynamic Integrated Climate-Economy (DICE) model, the Policy Analysis for the Greenhouse Effect (PAGE) model, and the Climate Framework for Uncertainty, Negotiation and Distribution (FUND) model. The central SCC estimate for the year 2020 is Can$52/tonne of CO₂.^{footnote 25}

There have been no recently published updates to the FUND model, but recent academic literature published by the authors of the DICE and PAGE models indicates that the previous iterations of their models that the Department used to develop its 2016 estimate of the SCC are out of date. For example, when using a constant 3% discount rate, the central SCC estimate for the year 2020 from the revised version of the DICE model is US$105/tonne of CO₂ (Can$136/tonne of CO₂),^{footnote 26} which is more than double the value compared to the previous model iteration. This higher estimate is largely due to updates to global population estimates, data revisions to economic activity estimates, and incorporating new research on the carbon cycle.^{footnote 27} In addition, revisions to the PAGE model, which include climate science updates, economic updates, and novel developments such as incorporating the impact of nonlinear Arctic feedback on the global climate system and economy, have also resulted in significant increases to its estimate of the SCC.^{footnote 28} The central estimate from the revised PAGE model for the year 2020 is US$344/tonne of CO₂ (Can$443/tonne of CO₂),^{footnote 29} which is more than four times the value compared to the model iteration used to inform the Department’s current central estimate.

The Department concluded in 2020 that the current SCC values used for Canadian regulatory analysis likely underestimate climate change damages to society and the social benefits of reducing GHG emissions. Moreover, in the Government of Canada’s strengthened climate plan, A Healthy Environment and a Healthy Economy, the Government of Canada committed to revisiting its SCC estimates in use and ensuring that Canada’s methodology aligns with the best international climate science and economic modelling.^{footnote 30}

As part of that process, the Department has been evaluating the emerging scientific and economic literature as well as key developments related to the SCC internationally and at leading think tanks. For example, Bressler (2021) developed an extension to the DICE model to explicitly include temperature-related mortality impacts by estimating a climate-mortality damage function. The author found that incorporating mortality costs increased the SCC for the year 2020 from US$45 to US$312/tonne of CO₂ (Can$58 to Can$401/tonne of CO₂) in the baseline emissions scenario.^{footnote 31} Furthermore, a finalized guidance published by the New York State Department of Environmental Conservation recommends that State entities use a central SCC estimate of US$124/tonne of CO₂ (Can$159/tonne of CO₂). The State of New York’s estimates relied on the original federal U.S. Interagency Working Group 2016 methodology,^{footnote 32} but used a 2% discount rate as the central value instead of 3%.^{footnote 33}

The Department continues to monitor research and analysis from leading think tanks such as Resources for the Future (RFF). Recent research includes a working paper from RFF by Rennert et al. (2021), which provides illustrative SCC estimates based on a variety of scenarios when key components used to generate the SCC are updated. In particular, the authors note the critical role that the discount rate plays in the estimation of the SCC, given that today’s emissions will have long-term consequences as CO₂ emissions remain in the atmosphere for long periods of time (between 300 and 1 000 years).^{footnote 34} When using a constant 3% discount rate, the authors found that the SCC for the year 2020 ranged from US$44 to US$192/tonne of CO₂ (Can$57 to Can$248/tonne of CO₂), depending on the socioeconomic trajectory employed.^{footnote 35}

As updated SCC estimates from the Department are not yet available, an interim approach continues to be used for the analysis of the set of Amendments, where a range of updated SCC estimates from the above literature are considered in addition to the Department’s current SCC value. This is done to illustrate a range of plausible values that may be adopted by the Department once its update is complete.

Reduction in GHG emissions

Benefits will result from decreases in GHG emissions relative to the Baseline Scenario, which are expected to reduce damages from climate change and thus provide societal benefits. Table 7 shows the expected incremental decreases in GHG emissions from the set of Amendments.

Table 7: Decreased GHG emissions resulting from the set of Amendments over the 2023–2030 period

Year	2023	2024	2025	2026	2027	2028	2029	2030	Total
Decrease in GHG emissions (Mt of CO2e)	0.1	−0.1	0.4	0.5	0.9	1.1	1.4	1.5	5.8

Qualitative analysis of reduction in GHG emissions in 2031 and 2032

Assuming the marginal price of $170/tonne of CO₂e is maintained in the federal OBPS beyond 2030, it is expected that there will be continued reductions of GHG emissions in 2031 and 2032. However, it is also expected that the reductions of GHG emissions would increase at a lower rate than in previous years, assuming that the excess emissions charge does not increase beyond $170/tonne of CO₂e in this time frame, while the annual tightening rates for the OBSs would continue at the same rates at which they are set for the 2023–2030 period, which would continue to increase average carbon costs.

Reductions in air pollutants

EC-Pro was chosen to model the set of Amendments because it takes into consideration the macro-economic impacts of the set of Amendments. However, air pollutant emissions are not currently an output of this model. Thus, these impacts were assessed qualitatively. It is reasonable to expect that, since the set of Amendments will reduce GHG emissions, it would also reduce other emissions and, on balance, this would be expected to have a positive overall effect on air quality. Relative to the Baseline Scenario, the Regulatory Scenario is expected to result in reductions in these pollutants and therefore in air quality benefits in some locations in Canada.

Costs

As a result of the set of Amendments, domestic production is estimated to be lower in the Regulatory Scenario (in which the set of Amendments applies) than it would be in the Baseline Scenario. The costs realized by covered sectors, facilities, and activities may decrease domestic production, and decrease domestic demand. The resulting net decrease in production could in turn decrease the disposable income of households, who are assumed to be the owners of the factors of production, labour and capital, through decreases in the wages earned by workers and the profits earned by firms (facilities). Households may choose to allocate the lower levels of disposable income to other goods and services to maximize their welfare.

A recommended measure of welfare in a general equilibrium model (EC-Pro) is equivalent variation (EV), which 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 36} The change in EV from the Baseline Scenario to the Regulatory Scenario represents the maximum amount of money that households would be willing to pay to avoid the welfare losses associated with the implementation of the Regulatory Scenario.^{footnote 37,footnote 38} This amount can be considered equivalent to the change in welfare for households from the decrease in consumption under the Regulatory Scenario.

As demonstrated in Table 8 below, between 2023 and 2030, the total present value of household welfare costs attributed to the set of Amendments is estimated at $684 million.

Table 8: Household welfare costs resulting from the set of Amendments (millions of dollars)

Household welfare costs	2023	2024	2025	2026	2027	2028	2029	2030	Total
Undiscounted values	53	−35	93	101	138	146	167	143	806
Discounted values	51	−33	85	90	119	123	136	113	684

Given the uncertainty around the average cost of abatement for covered facilities, a sensitivity analysis considers costs up to 25% lower or 25% higher than the central cost estimate. In the sensitivity analysis, the total costs range from $513 million to $855 million when a range of potential costs are considered.

Qualitative assessment of household welfare costs resulting from the set of Amendments in 2031 and 2032

It is expected that there will be continued cost increases associated with the set of Amendments in both 2031 and 2032. However, the costs to Canadian society are projected to increase at a lower rate than in previous years, if the excess emissions charge does not increase and is maintained at a rate of $170/tonne of CO₂e in this time frame, and if the annual tightening rates for the OBSs continue at the same rates at which they are set for the 2023–2030 period. The increased average carbon costs due to the continued increases in the OBS stringencies may be offset by advancements in additional emissions abatement technologies over time.

Break-even analysis

For the set of Amendments, the break-even value was determined by calculating the societal cost per tonne of actions to reduce GHG emissions in the federal OBPS over the 2023–2030 period. As illustrated in Figure 2 below, this cost per tonne is estimated to range between $89/tonne of CO₂e and $149/tonne of CO₂e, with a central estimate of $119/tonne of CO₂e. These values were derived from the costs to Canadian society (Table 8) per tonne of GHG emissions reduced (Table 7).

To validate the break-even value, the societal cost per tonne of the set of Amendments was compared to a plausible range of estimates found in the existing scientific literature. This was done to illustrate what an updated SCC estimate might be once the Department completes its review of the SCC. In Figure 2, the Department’s current central SCC value of $52/tonne of CO₂ is the lower bound of the range, while the SCC value of $443/tonne of CO₂ from the updated PAGE model is the upper bound of the range. Given the range of recent estimates for the SCC, the BEA suggests it is plausible that the set of Amendments would yield a net benefit result with an updated SCC estimate.

Figure 2: Break-even plausibility

Figure 2: Break-even plausibility - Text version

Estimated social cost of carbon from recent studies and reports

Studies and reports estimating the social cost of carbon	Social cost of carbon ($/tonne of CO2)
ECCC Central SCC Estimate (2016)	$52
Resources for the Future Low Estimate (2021)	$57
Updated DICE Central SCC Estimate (2017)	$136
New York State Central SCC Estimate (2021)	$159
Resources for the Future High Estimate (2021)	$248
Bressler (2021) - Mortality Cost of Carbon	$401
Updated PAGE Central SCC Estimate (2019)	$443

OBPS cost per tonne for three sensitivity cases

Sensitivity case	OBPS cost per tonne ($/tonne of CO2e)
Lower bound costs	$89
Central case costs	$119
Upper bound costs	$149

All values presented here are in 2021 Canadian dollars.

Monte Carlo analysis

To evaluate further the net impacts of the set of Amendments, the Department calculated estimates of the probability that the benefits and costs would break even. This type of analysis, known as Monte Carlo analysis, was conducted by specifying probability distributions for the societal cost per tonne of the set of Amendments, as well as for the SCC.

A triangular distribution was assumed for the societal cost per tonne, with the central estimate corresponding to the peak of the triangle (i.e. the most likely point), and supposing that the costs could be lower or higher than the central estimate by up to 25%. Using this approach, the lower and upper bounds for the societal cost per tonne were estimated to be $89 and $149/tonne of CO₂e, respectively, with $119/tonne of CO₂e as the central estimate.

In terms of the range of possible SCC values examined in this analysis, the Department’s current central SCC value of $52/tonne of CO₂ was used as a lower-bound estimate, while the SCC value of $443/tonne of CO₂ from the updated PAGE model was used as an upper-bound estimate. According to feedback received from expert peer review, these SCC estimates reflect the range of plausible values found in the existing scientific literature.

First, a uniform probability distribution was also examined for the SCC. The likelihood that an up-to-date SCC will take on any specific value between $52 and $443/tonne of CO₂ is in fact unknown, given the many parameters and assumptions that can vary between models or analyses. In the face of this uncertainty, the uniform distribution assumes that any value in this range is equally likely to occur. With a uniform distribution for the SCC, Monte Carlo simulations, each involving 10 000 pairs of values of benefits and costs, generated net benefit results instead of net cost results 83% of the time in the scenario with the set of Amendments.

Next, a triangular probability distribution was examined for the SCC. The peak of the triangular distribution was assumed to be the updated DICE central estimate of $136/tonne of CO₂ in order to create a rough approximation of the general shape of SCC probability distributions in the literature, such as those presented in the recent Resources for the Future working paper by Rennert et al. (2021). With this specification of triangular distribution, a Monte Carlo simulation involving 10 000 pairs of values of benefits and costs generated net benefit results instead of net cost results 85% of the time. Stated differently, a Monte Carlo simulation yielded a net benefit result instead of a net cost result 85% of the time over the 2023–2030 period with the set of Amendments including the annual tightening of standards.

Based on this analysis, the Department concludes that it is likely the set of Amendments would yield net benefits by 2030 when using the Department’s forthcoming updated value for the SCC. For the years beyond 2030, it is anticipated that the benefits from additional GHG emission reductions associated with the tightening of OBSs would continue to outweigh the costs related to these additional reductions. This would increase the overall likelihood that the set of Amendments would lead to a net benefit result for Canadians when considering their implementation beyond 2030 and, in particular, in 2031 and 2032.

Updating the excess emissions charge without the proposed Amendments

In the event that the proposed Amendments are not finalized and approved by the Governor in Council, the Department conducted an assessment to illustrate the potential impacts of the introduction of the new carbon price trajectory for the excess emissions charge in isolation. In this scenario, the amendments to Schedule 4 would come into effect and increase the excess emissions charge over the 2023–2030 period, but no amendments would be made to the Regulations. In other words, no increases in stringency would be made to the OBSs in the federal OBPS. The lack of increases in stringency to the OBSs over time would be expected to weaken the market for compliance units, including surplus credits, through a relative increase in the supply of surplus credits relative to demand. In order for the emissions trading market to remain effective and for the OBPS to achieve the reductions expected, the marginal price signal must be maintained at the minimum national carbon pollution price. This is expected to be the case when there is a net demand for compliance units in the emissions trading market, that is when the total compensation obligation of covered facilities exceeds the total quantity of all types of compliance units available.

The marginal price incentive created by the OBPS is a crucial decision factor for firms investing in GHG emission reductions. The post-2022 carbon price trajectory sends a strong price signal to reduce emissions. However, this price level is not the only determinant of the marginal price signal, which reflects the market price of surplus credits generated by facilities that emit less than their respective emissions limit. As facilities plan decarbonization investments, the future market price of any surplus credits that they will be able to generate or purchase is an important factor, because it represents a revenue stream that can help fund or cover the cost of projects, or an avoided compliance cost that can reduce compensation obligations. As the excess emissions charge increases and other policies and programs are implemented, and improvements in technologies and operations are made, the level of GHG emissions from covered facilities is anticipated to decrease. If the stringencies of the OBSs do not increase but remain constant, a decrease in the GHG emissions from covered facilities would increase the quantity of surplus credits available to buyers (other covered facilities). This would likely result in a marginal (market-clearing) price of surplus credits that is noticeably lower than the excess emissions charge. In this scenario, the incentive for covered facilities to reduce their emissions would be lessened, as the market price of surplus credits would be expected to be lower than the excess emissions charge.

An OBPS with a relatively low price for compliance units would not be consistent with the updated federal benchmark that specifically requires provincial and territorial output-based pricing systems to be designed to maintain a marginal price signal equivalent to the minimum national price on carbon pollution for explicit price-based systems across all covered emissions.

In the event that the proposed tightening rates are not implemented, in any jurisdiction, and the excess emissions charge increases over time to $170/tonne of CO₂e in 2030, less GHG emission reductions would be expected, that is approximately 2.6 Mt of CO₂e less than those that are projected to occur as a result of the set of Amendments. The proposed Amendments are thus required, along with the amendments to Schedule 4 to the Act, in order to allow the federal OBPS to be aligned with the updated Pan-Canadian Approach.

Streamlined requirements for OBPS participation

The proposed Amendments would facilitate OBPS participation through the inclusion of additional industrial activities recognized by the Minister and published on the Department’s web page, as well as by harmonizing requirements for opt-in facilities via changes to the method for calculating an OBS combined with changes to the Opt-in Policy. It is expected that the resulting streamlined process could increase the participation level of opt-in facilities, depending on the scope of where the OBPS applies. Increased participation would result in fewer reduced GHG emissions, and an increase in economic activity, but would lower costs for those facilities moving into the OBPS from a fuel charge regime. However, based on the current scope of application of the OBPS, no new voluntary participants are expected and, therefore, no incremental impacts are anticipated from these changes at this time.

Administrative costs to Government

Additional costs may accrue to the Department related to updating the electronic system to meet the various new requirements related to the proposed Amendments. There would be an estimated one-time expense of approximately $450,000 in the 2023–2024 fiscal year. This includes $250,000 for updating registration and reporting and up to $150,000 for potential updates to the credit system.

Distributional analysis

Cost impacts by jurisdiction

The magnitude of the impacts that are attributable to the set of Amendments may disproportionately affect certain jurisdictions compared to others. By 2030, it is estimated that the set of Amendments will result in a cumulative decrease in societal welfare in backstop jurisdictions compared to the Baseline Scenario in which the excess emissions charge and stringency of the OBPS do not change. The most significant impacts stem from affected activity in Saskatchewan. Over 80% of the total household welfare costs are expected to accrue in Saskatchewan. Only 30% of facilities within the OBPS are located in Saskatchewan and 65% of expected GHG emissions reductions occur in the province. These data reflect coal-fired electricity generation activity, which is a significant source of GHG emissions relative to other activities covered by the OBPS.

Table 9: Distribution of impacts by jurisdiction

Province and territory	Percentage of total covered facilities	Percentage of GHG emissions reduced	Percentage of household welfare costs
Manitoba	57%	33%	11%
Nunavut	9%	0.2%	5%
Prince Edward Island	2%	1.6%	−1%
Saskatchewan	30%	65%	84%
Yukon	2%	0.2%	1%

Sensitivity analysis

Given potential uncertainty due to various assumptions, sensitivity analyses were conducted to assess the impact of changes to the following parameters on the expected net benefits of the set of Amendments, where possible.

Carbon leakage

In the Regulatory Scenario, there is an increased risk of domestic production shifting to foreign jurisdictions due to increased production costs attributable to the set of Amendments. The extent to which these shifts in production lead to an increase in foreign GHG emissions depends on the emissions intensity of the facilities where production is relocated and the associated quantities of production, both of which are unknown. The Regulatory Scenario only accounts for incremental decreases in GHGs in Canada and, therefore, may overestimate the global net emissions reductions in the event of carbon leakage.

Discount rate

TBS recommends a 7% discount rate for cost-benefit analyses in most cases. However, when regulations have impacts occurring over a long-time horizon, as is often the case with environmental regulations, a lower discount rate (3%) is appropriate. A sensitivity analysis was done to compare the central analysis (3% discount rate) to the higher discount rate (7%). Using a 7% discount rate, costs are estimated to be between $416 million and $694 million, with a central estimate of $555 million.

Summary of benefits and costs

By 2030, compared to a scenario in which the stringency of the Regulations is not increased in backstop jurisdictions, the set of Amendments is expected to provide societal benefits. There is an expected decrease in GHG emissions of 5.8 Mt of CO₂e. The set of Amendments is expected to result in a decrease in Canadian household welfare of $684 million, as a result of decreased domestic output and decreased consumption. The GHG emission reductions would be achieved at an estimated societal cost per tonne of between $89 and $149/tonne of CO₂e reduced, with a central estimate of $119/tonne. To evaluate the results, a break-even analysis was conducted that compares the societal cost per tonne of the set of Amendments to the Department’s value of the social cost of carbon (SCC) published in 2016, and more recently published estimates of the SCC value found in the academic literature. Given that there is a range of publicly available updated estimates of the SCC that well exceed the estimated societal cost per tonne of the set of Amendments, the Department concludes that it is probable that the monetized benefits of the set of Amendments will exceed its costs.

Cost-benefit statement

• Number of years: 10; 2023–2032 (for monetized impacts: 8; 2023–2030)
• Base year for costing: 2021
• Present value base year: 2022
• Discount rate: 3%

Table 10: Monetized costs

Impacted stakeholder	Description of cost	First year	Final year	Total (present value)
Government	Federal government administrative costs	$450,000	N/A	$440,000
Canadian society	Decreases to household welfare	$51 million	$113 million	$684 million
All stakeholders	Total costs	$51 million	$113 million	$684 million

Table 11: Monetized benefits

Impacted stakeholder	Description of monetized benefit	First year	Final year	Total (present value)
Industry	Net reductions in administrative costs for covered facilities table d1 note a	$9,400	$29,000	$309,000
All stakeholders	Total monetized benefits	$9,400	$29,000	$309,000
Table d1 note(s) Table d1 note a These projected net reductions in administrative costs are described in the "One-for-one rule" section below. Return to table d1 note a referrer

Quantified (non-monetized) and qualitative impacts

Positive impacts

• 5.8 Mt of reductions in domestic GHG emissions (2023–2030);
• Improved air quality for Canadians (2023–2032); and
• Additional reductions in domestic GHG emissions in 2031 and 2032.

Negative impacts

• Additional costs to Canadian society of foregone household welfare related to increasing OBS stringencies and a carbon price of $170 per tonne of CO₂e in 2031 and 2032.

Small business lens

The Regulations have been designed to allow smaller facilities located in backstop jurisdictions to voluntarily apply to participate in the OBPS. Based upon the facilities that are currently covered by the OBPS, including voluntary participants, no businesses are considered a small business as defined by annual revenue data. Proposed changes to enable the recognition of additional industrial activities, and to the method for calculating an OBS combined with changes to the Opt-in Policy, could lower the burden for smaller facilities to opt in. However, since the OBPS has been in place for a number of years in existing backstop jurisdictions and in general facilities have an incentive to voluntarily participate, most eligible facilities have likely already applied to participate in the OBPS. Therefore, given the current scope of application of the OBPS, no new entrants, including small businesses, are expected over the analytical timeline as a result of the proposed Amendments.

One-for-one rule

The one-for-one rule applies since there would be an incremental decrease in administrative burden on business. The proposed Amendments would make no change in terms of federal regulatory titles.

There would be a one-time administrative cost for covered facilities to familiarize themselves with the new administrative provisions introduced by the proposed Amendments. There would also be ongoing administrative activities from 2023 to 2032 that are additional to existing administrative activities, including activities related to information gathering to recalculate OBSs, reporting, verification for facilities engaging in a new activity, and record keeping.

On the other hand, the proposed Amendments would remove some existing administrative activities from the Regulations related to quantification and correcting reports. The proposed Amendments would remove detailed quantification methods from Schedule 3 to the Regulations; these methods would be specified in a technical document incorporated by reference into the Regulations. This would facilitate updates to the quantification methods and will provide the opportunity to improve harmonization of GHG quantification requirements with other GHG reporting programs such as the GHGRP, which is expected to reduce duplication of work. In addition, the proposed Amendments would remove the obligation to submit a corrected report when any error or omission in an annual report is identified by the person responsible for a covered facility. Instead, a corrected report would only be required when the person responsible identifies an error or omission that would have constituted a material discrepancy if it had been found during the verification of the annual report.

Based on a set of assumptions on time needed to conduct various administrative activities, and an estimated hourly cost of labour of $50/hour (in 2012 Can$), the proposed Amendments are estimated to result in a net decrease in administrative burden costs of approximately $15,000 in annualized average costs across all covered facilities from 2023 to 2032.^{footnote 39} Decreases in net administrative impacts per installation are projected to be, on average, 5.5 hours per year for 53 facilities, corresponding to the removal of about $290 in annualized costs per facility.^{footnote 40}

Regulatory cooperation and alignment

Canada is working in partnership with the international community to implement the Paris Agreement, an accord intended to reduce GHG emissions, to limit the rise in global average temperature to less than 2 °C above pre-industrial levels, and to pursue efforts to limit the temperature increase to 1.5 °C. As part of its commitments made under the Paris Agreement, Canada had previously pledged to reduce national GHG emissions by 30% below 2005 levels by 2030. On July 12, 2021, the Minister formally submitted Canada’s enhanced NDC to the United Nations, committing Canada to reduce national GHG emissions by 40% to 45% below 2005 levels by 2030. To meet these commitments, the federal government is implementing a series of measures, including continuing to put a price on carbon pollution. To achieve these goals, a number of GHG reduction measures have been implemented or proposed, including the proposed Amendments.

This international partnership relates to the overall goals and outcomes of climate action, but does not prescribe the targets that were committed to by each country or how each country should reduce its emissions. Other countries are taking a variety of approaches, some of which include carbon pricing. As discussed earlier, carbon leakage is a significant risk since carbon pricing policies are not in place for the majority of global emissions, resulting in uneven carbon costs across jurisdictions. The OBPS is one of several types of systems that can maintain a carbon price signal while helping protect against competitiveness and carbon leakage risks.

Domestically, under the Pan-Canadian Approach, provinces and territories have the flexibility to implement a carbon pricing system aligned with federal benchmark criteria that makes sense for their circumstances, either an explicit price-based system, such as a carbon tax or charge, and a performance-based emissions system for large industrial emitters, or a cap-and-trade system. As part of the federal benchmark, the federal government also committed to a federal carbon pricing backstop that applies in any province or territory that requests it or that does not have a carbon pricing system in place that meets the minimum national stringency criteria. The introduction of OBS tightening rates would play an important role in aligning the federal OBPS with the updated federal benchmark.

Strategic environmental assessment

The Department conducted strategic environmental assessments (SEA) in 2017, 2018, 2019, and 2021 for elements of its carbon pollution pricing policies.

In the 2021 SEA, it was noted that the federal carbon pricing system is expected to result in important, positive environmental effects, reduce GHG emissions and energy use and support the implementation of Canada’s Strengthened Climate Plan: A Healthy Environment and a Healthy Economy, by promoting the adoption of clean technology and the transition to a low-carbon economy. As this proposal is a component of the carbon pricing pollution system, it therefore aligns with Canada’s Federal Sustainable Development Strategy, particularly with the goals of Effective action on climate change, Clean growth, Modern and resilient infrastructure, Clean energy, and Safe and healthy communities. The proposal centrally contributes to efforts to meet Canada’s new, more ambitious 2030 emissions target and achieve net-zero GHG emissions by 2050. It also contributes to multiple Sustainable Development Goals (SDGs) including SDG 3 — Good Health and Well-Being; SDG 7 — Affordable and Clean Energy; SDG 9 — Industry, Innovation and Infrastructure; SDG 11 — Sustainable Cities and Communities; SDG 12 — Responsible Consumption and Production; SDG 13 — Climate Action; and SDG 17 — Partnerships for the Goals.

Gender-based analysis plus

A gender-based analysis plus (GBA+) was undertaken for the Government of Canada’s existing carbon pricing initiatives. This GBA+ identified that climate change has far-reaching health, economic and environmental impacts on all Canadians, but these effects are and will be felt most acutely by those segments of the population that are already vulnerable owing to geography, gender, age, Indigenous identity, minority status and disability. Climate change policy can exacerbate these effects, depending on the design.

As climate change has the potential to affect the economy, health and safety, social cohesion and the environment, addressing climate change could have a positive impact on all quality of life domains. Vulnerable groups may feel more of these positive impacts because they are disproportionately affected by climate change. These groups include northern and coastal regions and communities, indigenous communities, people with disabilities, people with existing health conditions, infants and children, the elderly, women, and low-income communities.

Additionally, workers in potentially affected sectors are typically male, and college educated. For example, Statistics Canada estimates that, in 2019, males accounted for 75% of mining, and oil and gas workers and 85% of forestry workers in Canada. Negative impacts on the workforce in large industrial sectors could be offset by funds returned to provinces if provinces choose to use these funds to help decarbonize existing industry and support a just transition to jobs in low-carbon industries. A well-designed carbon pollution pricing approach could drive efficient emissions reductions and spur innovation while achieving broader sustainable development benefits and reduce economic inequalities.^{footnote 41}

Implementation, compliance and enforcement, and service standards

Implementation

The proposed Amendments would come into force on the day on which they are registered, with several exceptions. In general, coming-into-force dates are being proposed based on whether the regulatory change in question would affect the submission of annual reports for the 2022 compliance period; whether it is needed for alignment with federal benchmark criteria; or whether it is projected to result in a considerable improvement in the implementation of the Regulations or a reduction in regulatory costs for covered facilities.

The following proposed changes explained in the “Description” section would come into force on January 1, 2023:

• incorporation of an annual tightening rate of 2% to most OBSs;
• incorporation of an annual tightening rate of 1% to the OBSs for lime manufacturing, cement manufacturing, petrochemical manufacturing, and natural gas extraction and processing;
• changes to the requirements for calculated OBSs; and
• updates of some OBSs due to changes in the GWPs in Schedule 3 to the Act.

The following proposed changes explained in the “Description” section would come into force on January 1, 2024:

• shifting GHG quantification methods from Schedule 3 to the Regulations to the document entitled Quantification Methods for the Output-Based Pricing System Regulations;
• changes to the calibration requirements for the quantification of electricity;
• changes to the start date of the first compliance period;
• incorporation of new industrial activities and OBSs to Schedule 1 to the Regulations;
• changes to the materiality thresholds in the verification process for the quantification of production and GHG emissions;
• changes to the scope of coverage of a covered facility;
• incorporation of requirements for the calibration of any measuring device for GHG emissions quantification; and
• clarification of the scope of the complexity weighted barrel (CWB) quantification requirements.

A number of policy documents will be posted on the Department’s web page to promote transparency around the implementation of the proposed Amendments. Specifically, this includes a list of additional industrial activities that would be updated annually and the revised Opt-in Policy describing the streamlined process that would be enabled by the proposed Amendments.

The Department will communicate the proposed Amendments to covered facilities by email and make periodic updates to the Government of Canada’s Output-Based Pricing System web page to provide useful information concerning regulatory requirements. In addition, the Departmental staff responsible for the implementation of the federal OBPS would work closely with their counterparts from the Canada Revenue Agency (CRA) and the GHGRP to ensure the effective implementation of certain proposed amendments.

Compliance and enforcement

The Act contains provisions related to offences, which include failing to comply with an obligation arising from the Act and providing false or misleading information, and associated penalties. The Department, in accordance with its compliance and enforcement policies, will undertake implementation and enforcement actions as necessary.^{footnote 42}

When verifying compliance, enforcement officers will apply the principles found in the Compliance and Enforcement Policies developed by the Department. These policies set out the range of possible enforcement responses to alleged violations. If an enforcement officer discovers an alleged violation following an inspection or investigation, the officer will choose the appropriate enforcement action based on the policies.

Given that the proposed Amendments are not anticipated to modify the number of covered facilities based on the current scope of application of the OBPS or result in a significant increase in the workload for enforcement officers, the annual incremental enforcement costs are expected to be low.

Contacts

Katherine Teeple
Executive Director
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: tarificationducarbone-carbonpricing@ec.gc.ca

Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Strategic Policy Branch
Department of the Environment
200 Sacré-Cœur Boulevard
Gatineau, Quebec
K1A 0H3
Email: RAVD.DARV@ec.gc.ca

PROPOSED REGULATORY TEXT

Notice is given that the Governor in Council proposes to make the annexed Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations under sections 192 and 193 of the Greenhouse Gas Pollution Pricing Act ^{footnote a} and section 5^{footnote b} of the Environmental Violations Administrative Monetary Penalties Act ^{footnote c}.

Interested persons may make representations concerning the proposed Regulations within 60 days after the date of publication of this notice. They are strongly encouraged to use the online commenting feature that is available on the Canada Gazette website but if they use email, mail or any other means, the representations should cite the Canada Gazette, Part I, and the date of publication of this notice, and be sent to Katherine Teeple, Director, 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: tarificationducarbone-carbonpricing@ec.gc.ca).

Ottawa, October 5, 2022

Wendy Nixon
Assistant Clerk of the Privy Council

Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations

Output-Based Pricing System Regulations

1 (1) Subsection 1(1) of the Output-Based Pricing System Regulations ^{footnote 43} is replaced by the following:

Definition of facility

1 (1) Subject to subsection (6), for the purposes of the Act and these Regulations, facility means

• (a) all of the following elements that are operated in an integrated way to carry out a specified industrial activity:
  • (i) a site, or multiple sites, at which the specified industrial activity is carried out and the buildings, equipment and other structures and stationary items located on the site or sites, and
  • (ii) any other sites used in conjunction with the specified industrial activity, including a quarry, tailings pond, wastewater lagoon or pond and landfill; or
• (b) the portion of a natural gas transmission pipeline system within a province, used to transmit processed natural gas, of which the pipelines and associated installations or equipment — including compressor stations, storage installations and compressors — are operated in an integrated way, but excludes pipelines, installations or equipment that are used in the local distribution of natural gas and that are downstream of a metering station.

(2) Subsection 1(5) of the Regulations is replaced by the following:

Interpretation

(5) Subject to subsection (6), with respect to a facility

• (a) any part of a public road or of a railway track that is bordered on both sides by the facility and used to carry out the facility’s specified industrial activities is deemed to be part of the facility;
• (b) for greater certainty, any part of a railway track that is used exclusively to carry out the facility’s specified industrial activities is part of the facility;
• (c) for greater certainty, buildings that are used for legal, administrative or management purposes and that are not located where a specified industrial activity is carried out are not included for the purposes of the definition of facility; and
• (d) if two or more facilities referred to in paragraph (b) of the definition facility in subsection (1), within the same province, have the same person responsible or a person responsible in common and are not operated in an integrated way, they each constitute a separate facility.

Special case

(6) In the case of a facility that is not a covered facility, the specified industrial activities referred to in subsections (1) and (5) are those that would be specified industrial activities if the facility was a covered facility.

2 (1) The definitions Directive 017, Directive PNG017, GHGRP, IPCC Guidelines, 2020 GHGRP and WCI Method in subsection 2(1) of the Regulations are repealed.

(2) The definitions electricity generation facility and specified industrial activity in subsection 2(1) of the Regulations are replaced by the following:

electricity generation facility

means a covered facility, other than one whose primary activity is something other than an industrial activity, that generates electricity as its primary industrial activity, used to generate electricity from fossil fuels and composed of one unit or a group of units. (installation de production d’électricité)

specified industrial activity

means, with respect to a covered facility, an industrial activity referred to in subsection 5(2). (activité industrielle visée)

(3) Subsection 2(1) of the Regulations is amended by adding the following in alphabetical order:

additional industrial activity

means an industrial activity that is not set out in column 1 of Schedule 1, that is recognized by the Minister, including for the purposes of a facility’s designation as a covered facility under subsection 172(1) of the Act, and that is engaged in in a sector that is recognized by the Minister as being at significant risk of competitiveness impacts resulting from carbon pricing and of carbon leakage resulting from carbon pricing. (activité industrielle additionnelle)

Quantification Methods

means the document entitled Quantification Methods for the Output-Based Pricing System Regulations, published by the Department of the Environment in 2022. (méthodes de quantification)

(4) Subsection 2(2) of the Regulations is replaced by the following:

Incorporation by reference

(2) Unless otherwise indicated, a reference to any document incorporated by reference into these Regulations, except the GHGRP and the 2020 GHGRP, is incorporated as amended from time to time.

(5) Subsection 2(2) of the Regulations is replaced by the following:

Incorporation by reference

(2) Unless otherwise indicated, a reference to any document incorporated by reference into these Regulations is a reference to the document as amended from time to time.

(6) Section 2 of the Regulations is amended by adding the following after subsection (2):

Accreditation

(3) Despite subsection (2), if ISO Standard 14065 is amended, the previous version of the document may be complied with for a period of four years beginning on the day on which the amended version is published.

3 Subsection 5(2) of the Regulations is replaced by the following:

Specified industrial activities

(2) Output-based standards are established under these Regulations for the industrial activities set out in column 1 of Schedule 1 and for additional industrial activities engaged in by a covered facility.

4 The Regulations are amended by adding the following after section 6:

Cancellation following request

6.1 If the Minister receives a request to cancel a designation of a covered facility during a calendar year and the Minister decides, under subsection 172(3) of the Act, to cancel the designation, that cancellation is effective as of December 31st of that calendar year.

5 Paragraph 9(2)(a) of the Regulations is replaced by the following:

• (a) in the case of a covered facility that is located in a province whose name is listed in Part 1 of Schedule 1 to the Act, January 1 of the year following
  • (i) the calendar year during which the facility is registered under subsection 171(2) of the Act, if the facility meets the criteria set out in section 8, or
  • (ii) the calendar year during which the facility was designated as a covered facility under subsection 172(1) of the Act; or

6 Paragraph 10.1(1)(i) of the Regulations is replaced by the following:

• (i) the requirement to notify the Minister if there is a change in the person responsible, in accordance with section 48.

7 Section 11 of the Regulations is amended by adding the following after subsection (2):

New additional industrial activity

(3) For the purposes of subparagraph (1)(a)(ii), an additional industrial activity that was recognized by the Minister during a calendar year, including for the purposes of a facility’s designation as a covered facility under subsection 172(1) of the Act, is not taken into account for the annual report for the compliance period that corresponds to that calendar year.

8 Subsection 13(2) of the Regulations is replaced by the following:

Correction of errors or omissions

(2) If a verification body identifies errors or omissions in an annual report during their verification, the person responsible for the covered facility must correct those errors or omissions, if possible.

9 (1) Section 16 of the Regulations is amended by adding the following after subsection (6):

Additional production of evaporated salt

(6.1) If evaporated salt is produced through solution mining at a covered facility where a specified industrial activity set out in item 24, column 1, of Schedule 1 is engaged in, the following rules apply:

• (a) for the purposes of section 17, the person responsible for the covered facility must quantify the GHGs from the production of evaporated salt in accordance with the method applicable to the industrial activity set out in item 24, column 1, of Schedule 1; and
• (b) for the purposes of sections 31, 36 and 36.2, the industrial activity set out in item 24.1, column 1, of Schedule 1 is deemed not to be engaged in at the covered facility.

(2) The portion of subsection 16(9) of the Regulations before paragraph (a) is replaced by the following:

Additional production of petrochemicals

(9) Subject to subsection (9.1), if a petrochemical product referred to in item 17, column 1, of Schedule 1 is produced at a covered facility where a specified industrial activity set out in item 3 or 4, column 1, of that Schedule is engaged in, the following rules apply:

(3) Section 16 of the Regulations is amended by adding the following after subsection (9):

Parallel production

(9.1) If a covered facility has at least one refinery that is engaged in a specified industrial activity set out in item 3, column 1, of Schedule 1, and one petrochemical plant, that is engaged in a specified industrial activity referred to in item 17, column 1, of Schedule 1, subsection (9) only applies to the refinery.

10 (1) The descriptions of E_j and GWP_j in subsection 17(1) of the Regulations are replaced by the following:

E_j

is the quantity of each GHG type “j” from the covered facility during a compliance period, for each specified emission type, determined in accordance with subsections (2) to (4);

GWP_j

is the global warming potential of the GHG type “j” applicable to the compliance period and, if it is used to determine the quantities referred to in the descriptions of A, C and F in subsection 37(1), for the reference year “i”, the global warming potential applicable to the compliance period in respect of which the output-based standard is being calculated;

(2) Subsections 17(2) to (4.1) of the Regulations are replaced by the following:

Quantity of each GHG

(2) The quantity of a GHG type “j” from a covered facility during a compliance period for a specified emission type “i” is the sum of the following quantities, determined in accordance with the applicable requirements set out in Quantification Methods:

• (a) the quantities of that GHG from industrial activities set out in column 1 of Schedule 1 and set out in column 2 of the table to the Part of Schedule 3 that is applicable to those industrial activities, for a specified emission type set out in column 1 of that table;
• (b) the quantities of that GHG from those industrial activities, but not set out in column 2 of the table to the Part of Schedule 3 that applies to those activities or for a specified emission type not set out in column 1 of that table; and
• (c) any quantity of that GHG that is not referred to in paragraph (a) or (b).

Sampling, analysis and measurement requirements

(3) If the quantity of a GHG is determined in accordance with subsection (2), the sampling, analysis and measurement requirements that apply are those set out in Quantification Methods.

Missing data

(4) For the purposes of subsection (2), if, for any reason beyond the control of the person responsible for a covered facility, the data required to quantify the GHGs from a covered facility are missing for a given period of a compliance period, replacement data for the given period must be calculated in accordance with Quantification Methods.

11 Sections 18 and 19 of the Regulations are replaced by the following:

Additional generation of electricity

18 For the purposes of section 17, the quantities of the GHGs for specified emission types from the generation of electricity using fossil fuels by a covered facility — other than a covered facility referred to in paragraph 11(1)(c) — are determined in accordance with the methods that are applicable to any of the industrial activities engaged in at the covered facility.

12 (1) The description of GWP_j in subsection 20(1) of the Regulations is replaced by the following:

GWP_j

is the global warming potential of the GHG type “j” applicable to the compliance period;

(2) Subsection 20(2) of the Regulations is replaced by the following:

Quantity of each GHG

(2) The quantity of a GHG type “j” generated by a unit during a compliance period for a specified emission type “i” is the sum of the following quantities, determined in accordance with the applicable requirements set out in Quantification Methods:

• (a) the quantities of the GHG that is set out in column 2 of the table to Part 38 of Schedule 3 for a specified emission type set out in column 1; and
• (b) any quantity of the GHG that is not referred to in paragraph (a).

(3) Subsections 20(4) and (5) of the Regulations are replaced by the following:

Sampling, analysis and measurement requirements

(4) If the quantity of a GHG is determined in accordance with subsection (2), the sampling, analysis and measurement requirements that apply are those set out in Quantification Methods.

Missing data

(5) For the purposes of subsection (2), if, for any reason beyond the control of the person responsible for a covered facility, the data required to quantify GHGs generated by a unit are missing for a given period of a compliance period, replacement data for the given period must be calculated in accordance with Quantification Methods.

13 The Regulations are amended by adding the following after section 22:

Measuring device

22.1 Any measuring device that is used to determine a quantity for the purposes of these Regulations must be

• (a) installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or any applicable generally recognized national or international industry standard; and
• (b) maintained to be accurate within ± 5%.

14 Section 25 of the Regulations is replaced by the following:

Continuous Emissions Monitoring System

25 If a continous emissions monitoring system is used to quantify GHGs under these Regulations, the person responsible for the covered facility must ensure that the system complies with the requirements of the Reference Method for Source Testing: Quantification of Carbon Dioxide Releases by Continuous Emission Monitoring Systems from Thermal Power Generation, published by the Department of the Environment in June 2012.

15 Section 26 of the Regulations is replaced by the following:

Alternative method

26 Despite sections 17 and 20, the person responsible for a covered facility may use a method other than a method set out in Quantification Methods if they have a permit issued in accordance with section 28.

16 Subsection 28(1) of the Regulations is replaced by the following:

Conditions of issuance

28 (1) The Minister must issue the permit to use a quantification method other than one set out in Quantification Methods if

• (a) the person responsible for the covered facility establishes that, at the time of the application, it is not technically or economically feasible to use the method set out in Quantification Methods;
• (b) the person responsible for the covered facility demonstrates that the quantification method being proposed is at least as rigorous as the prescribed method and provides equivalent results to those that would have been obtained from method set out in Quantification Methods;
• (c) the person responsible for the covered facility provides a plan describing measures that will be taken to enable the use of the method set out in Quantification Methods and the implementation period for that plan, up to a maximum of two years; and
• (d) the requested term of the permit does not exceed the period for which the permit is necessary.

17 Paragraph 31(1)(c) of the Regulations is replaced by the following:

• (c) in the case of production from a specified industrial activity not set out in column 1 of Schedule 1, in the units of measurement specified by the Minister for that activity.

18 Paragraphs 34(1)(b) and (c) of the Regulations are replaced by the following:

• (b) for a covered facility not referred to in paragraph (c), determined by the following formula if the thermal energy is produced from the combustion of both fossil fuels and biomass:

  HF ÷ (HF + B)

  where

  HF

  is determined by the formula

  

  where

  QF_i

  is the quantity of fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 7(2) of Part 38 of Schedule 3,

  HHV_i

  is the higher heating value of the fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with Quantification Methods, and

  i

  is the i^th fossil fuel type combusted in the facility during the compliance period, where “i” goes from 1 to n and where n is the number of types of fossil fuels combusted, and

  B

  is determined by the formula

  

  where

  QBB_k

  is the quantity of biomass fuel type “k” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 7(2) of Part 38 of Schedule 3 and Quantification Methods,

  HHV_k

  is the higher heating value for biomass fuel type “k” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with Quantification Methods, and

  k

  is the k^th biomass fuel type combusted in the facility during the compliance period, where “k” goes from 1 to m and where m is the number of types of biomass fuels combusted; and

• (c) for an electricity generation facility, determined by the following formula when the thermal energy is produced from the combustion of both fossil fuels and biomass:

  HF ÷ (HF + B)

  where

  HF

  is determined by the formula

  

  where

  QF_i

  is the quantity of fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 4(3) of Part 38 of Schedule 3,

  HHV_i

  is the higher heating value of the fossil fuel of type “i” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with Quantification Methods, and

  i

  is the i^th fossil fuel type combusted in the facility during the compliance period, where “i” goes from 1 to n and where n is the number of types of fossil fuel combusted, and

  B

  is determined by the formula

  

  where

  QBB_k

  is the quantity of biomass fuel type “k” combusted in the facility for the generation of thermal energy during the compliance period, determined in accordance with subsection 4(3) of Part 38 of Schedule 3,

  HHV_k

  is the higher heating value for biomass fuel type “k” combusted in the facility for the generation of thermal energy, during the compliance period determined in accordance with Quantification Methods, and

  k

  is the k^th biomass fuel type combusted in the facility during the compliance period, where “k” goes from 1 to m and where m is the number of types of biomass fuels combusted.

19 The description of B in subsection 35(1) of the Regulations is replaced by the following:

B is the quantity of CO₂ captured at the covered facility that is stored during the compliance period in a storage project, determined using Quantification Methods, expressed in CO₂e tonnes.

20 (1) Subsection 36(1) of the Regulations is replaced by the following:

General rule

36 (1) Subject to subsection (2) and sections 16, 36.1, 36.2 and 42, the person responsible for a covered facility, other than an electricity generation facility, must determine the GHG emissions limit that applies to that covered facility for each compliance period, expressed in CO₂e tonnes, in accordance with the formula

where

A_i

is the covered facility’s production from each specified industrial activity “i” during the compliance period, quantified in accordance with section 31;

B_i

is the following output-based standard applicable to the specified industrial activity “i”, as the case may be:

• (a) for a specified industrial activity set out in column 1 of Schedule 1 and for which an output-based standard is set out in column 3 of that Schedule, that standard,
• (b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 of that Schedule sets out that an output-based standard must be calculated in accordance with section 37, the output-based standard calculated in accordance with that section, and
• (c) for any specified industrial activity not set out in column 1 of Schedule 1, the output based standard calculated in accordance with section 37;

C

is the following tightening rate applicable to the specified industrial activity “i”, as the case may be:

• (a) 0% for the specified industrial activity set out in item 38, column 1, of Schedule 1,
• (b) 1% for the specified industrial activities set out in items 4, 7 and 8 and sub-items 17(a) to (f), column 1, of Schedule 1, and
• (c) 2% for all other specified industrial activities;

D

is the calendar year that corresponds to the compliance period; and

i

is the i^th specified industrial activity where “i” goes from 1 to n and where n is the total number of specified industrial activities engaged in at the covered facility.

(2) Subsection 36(4) of the Regulations is replaced by the following:

Clarification — fertilizer

(4) For greater certainty, if the industrial activity set out in paragraph 29(b), column 1, of Schedule 1 and also either of the industrial activities set out in paragraph 29(c), (d) or (e), column 1, are engaged in at the covered facility, the output-based standard applicable to the industrial activity set out in paragraph 29(b), column 1, applies and the output-based standard applicable to the industrial activity set out in paragraph 29(c), (d) or (e), applies as the case may be.

New additional industrial activity

(4.1) For the purposes of subsection (1), an additional industrial activity that was recognized by the Minister, including for the purposes of a facility’s designation as a covered facility under subsection 172(1) of the Act, during a calendar year is not included in the determination of the GHG emissions limit for the compliance period that corresponds to that calendar year.

21 Subsections 36.2(2) and (3) of the Regulations are replaced by the following:

Different output-based standard

(2) The GHG emissions limit that applies to the covered facility for a compliance period, expressed in CO₂e tonnes, is determined in accordance with the formula

where

A_i

is the covered facility’s production during the compliance period, quantified in accordance with section 31,

• (a) from each specified industrial activity “i”, except the industrial activity set out in paragraph 38(c), column 1, of Schedule 1, and
• (b) from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, other than from equipment referred to in the descriptions of E, G and H;

B_i

is the following output-based standard applicable to the specified industrial activity “i”, as the case may be:

• (a) for a specified industrial activity set out in column 1 of Schedule 1 and for which an output-based standard is set out in column 3 of that Schedule, that standard,
• (b) for a specified industrial activity set out in column 1 of Schedule 1 and for which column 3 of that Schedule sets out that an output-based standard must be calculated in accordance with section 37, the output-based standard calculated in accordance with that section, and
• (c) for any specified industrial activity not set out in column 1 of Schedule 1, the output based standard calculated in accordance with section 37;

C

is the following tightening rate applicable to the specified industrial activity “i”, as the case may be:

• (a) 0% for the specified industrial activity set out in item 38, column 1, of Schedule 1,
• (b) 1% for the specified industrial activities set out in items 4, 7 and 8 and sub-items 17(a) to (f), column 1, of Schedule 1, and
• (c) 2% for all other specified industrial activities;

D

is the calendar year that corresponds to the compliance period;

E

is the gross amount of electricity generated during the compliance period by the equipment that started generating electricity from gaseous fuels on or after January 1, 2021, and is designed to operate at a thermal energy to electricity ratio of less than 0.9, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31;

F

is the output-based standard set out in subsection 36.1(2) that is applicable for the compliance period;

G

is, for equipment with increased electricity generation capacity and a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of E, the gross amount of electricity generated during the compliance period attributed to the capacity added to the equipment, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31 and subsection (3);

H

is, for equipment with increased electricity generation capacity and a thermal energy to electricity ratio of less than 0.9, other than equipment referred to in the description of E, the gross amount of electricity generated during the compliance period attributed to the capacity of the equipment before the additional capacity was added, from the specified industrial activity set out in paragraph 38(c), column 1, of Schedule 1, quantified in accordance with section 31 and subsection (3);

I

is the output-based standard set out in item 38, column 3, of Schedule 1 that is applicable to the specified industrial activity set out in paragraph 38(c), column 1 of that Schedule; and

i

is the i^th specified industrial activity where “i” goes from 1 to n and where n is the total number specified industrial activities engaged in at the covered facility.

Apportionment of electricity generation

(3) For the purposes of the descriptions of G and H in subsection (2), the gross amount of electricity generated by the equipment referred to in those descriptions is apportioned, using engineering estimates, to the equipment’s capacity added to the equipment and to the capacity of the equipment before the additional capacity was added, based on the ratio of the amount of its increased capacity to its total capacity, taking into account the increased capacity.

22 (1) Subsection 37(1) of the Regulations is replaced by the following:

Calculated output-based standard

37 (1) Subject to subsection (3) and sections 38 and 39, the output-based standard that is applicable to a specified industrial activity of a covered facility for which an output-based standard must be calculated in accordance with this section and calculated in accordance with the formula

where

A

is the total quantity of GHGs from the covered facility for reference year “i”, determined in accordance with section 35, expressed in CO₂e tonnes;

B

is the allocation for net thermal energy for reference year “i” and is

• (a) determined by the formula

  0.062 CO₂e tonnes/gigajoules × (M − N) × O

  where

  M

  is the quantity of thermal energy produced by the covered facility that was sold to another covered facility in reference year “i”, as indicated by the quantity of thermal energy on sales receipts or determined by another objective method, expressed in gigajoules,

  N

  is the quantity of thermal energy that was bought from other covered facilities and not subsequently sold in reference year “i”, as indicated by the quantity of thermal energy on sales receipts or by another objective method, expressed in gigajoules, and

  O

  is the ratio of heat from the combustion of fossil fuels to produce thermal energy and is

  • (i) if M is greater than N, the ratio of heat determined under section 34 for reference year “i” for the covered facility, or
  • (ii) if M is less than N, the ratio of heat determined under section 34 for reference year “i” for the covered facility from which the thermal energy was purchased, and

• (b) 0 for all reference years if the absolute value of the quotient obtained by dividing the sum of the results determined under paragraph (a) for each reference year “i” by the number of reference years is less than the quotient determined by the formula

C

is the total quantity of GHGs from all specified industrial activities engaged in at the facility for reference year “i” other than the industrial activity for which the output-based standard is being calculated, determined in accordance with sections 17 and 18;

D

is the production from a covered facility from the specified industrial activity for which the output-based standard is being calculated for reference year “i” quantified in accordance with section 31;

E

is the GHG emissions reduction factor applicable to the specified industrial activity for which the output-based standard is being calculated and is

• (a) 95% for a specified industrial activity set out in paragraph 7(c), 8(b) or (c) or 20(d), column 1, of Schedule 1,
• (b) 90% for a specified industrial activity set out in item 22 or paragraph 23(a) or 29(d), column 1, of Schedule 1, and
• (c) 80% for all other specified industrial activities;

F

is the total quantity of GHGs from an activity engaged in at the facility, for reference year “i”, that is not a specified industrial activity if

• (a) with respect to a covered facility whose primary activity is an industrial activity,
  • (i) that quantity accounts for 20% or more of the quantity of GHGs from a covered facility for that reference year, determined in accordance with sections 17 and 18, or
  • (ii) the revenue, in dollars, attributable to the sale of the product produced by the facility from that industrial activity accounts for 20% or more of the revenue, in dollars, attributable to the sale of all products produced by the facility from all of the facility’s industrial activities for that reference year; and
• (b) with respect to a covered facility whose primary activity is not an industrial activity,
  • (i) the activity is not an industrial activity; or
  • (ii) the quantity of GHGs from an industrial activity accounts for 20% or more of the facility’s total GHGs, for that reference year, determined in accordance with sections 17 and 18, or

G

is the quantity of CO₂ determined for the purposes of the description B in section 35, from all activities engaged in at the facility for reference year “i” other than the industrial activity for which the output-based standard is being calculated; and

i

is the i^th reference year, where “i” goes from 1 to n and where n is the number of reference years, determined in accordance with subsection (2).

(2) The portion of subsection 37(2) of the Regulations before paragraph (b) is replaced by the following:

Reference years

(2) Subject to paragraph (2.1)(a), the reference years applicable to the specified industrial activities that are engaged in at a covered facility for which an emissions limit is calculated for a compliance period are

• (a) except for a covered facility referred to in paragraph (b),
  • (i) the 2017, 2018 and 2019 calendar years, if the data are available for those years,
  • (ii) the three calendar years preceding the compliance period, if the data are not available for the 2017, 2018, and 2019 calendar years, or
  • (iii) the compliance period, if the data are not available for the years specified in subparagraphs (i) and (ii); and

(3) Section 37 of the Regulations is amended by adding the following after subsection (2):

New activity

(2.1) For the purposes of subsection (1), if the calculation of the emissions limit for a compliance period takes into account a specified industrial activity that the covered facility began to engage in during that compliance period

• (a) the applicable reference years with respect to that specified industrial activity are that compliance period and the two calendar years following it; and
• (b) the determination of the output-based standard for that specified industrial activity is to be made based on projections, made using engineering estimates, for the applicable reference years.

Attributing of emissions

(2.2) For the purposes of the descriptions of C, F and G in subsection (1), the method used to attribute the quantity of GHGs to an activity must be rigourous, objective and based on sound engineering principles. The same method must be used for each reference year and no quantity of GHGs may be attributed to more than one activity.

23 Sections 39 of the Regulations are replaced by the following:

Recalculation of output-based standard

39 If an output-based standard applicable to a specified industrial activity was calculated in accordance with subsection 37(2.1) for the compliance period, it must be recalculated in accordance with subsection 37(1) for the third compliance period following the compliance period for which the original calculation was done. The reference years that must be used for the recalculation are the three calendar years that precede that third compliance period.

24 Section 40 of the Regulations is repealed.

25 (1) The portion of paragraph 49(1)(b) of the Regulations before subparagraph (i) is replaced by the following:

• (b) conduct the verification in accordance with the version of ISO Standard 14064-3 published by the International Organization for Standardization in 2006 and entitled Greenhouse gases — Part 3: Specification with guidance for the validation and verification of greenhouse gas assertions, the version of that Standard, published in 2019 and entitled Greenhouse gases — Part 3: Specification with guidance for the verification and validation of greenhouse gas statements, or the subsequent published version, set out in their accreditation, by applying methods that allow it to make a determination to a reasonable level of assurance, as defined in that standard, on whether

(2) Subsection 49(2) of the Regulations is replaced by the following:

Material discrepancy

(2) For the purpose of the verification of a covered facility’s annual report or corrected report, a material discrepancy exists when

• (a) with respect to GHGs from covered facilities that have emitted a quantity of GHGs of less than 500 kt of CO₂e during the compliance period,
  • (i) in the case of an error or omission respecting GHGs that is identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 5%:

    A ÷ B × 100

    where

    A

    is the absolute value of the overstatement or understatement resulting from the error or omission, expressed in CO₂e tonnes, and

    B

    is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes, and

  • (ii) in the case of the aggregate of all errors and omissions respecting GHGs that are identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 5%:

    A ÷ B × 100

    where

    A

    is the absolute value of the net result of all overstatements and understatements resulting from all errors and omissions, expressed in CO₂e tonnes, and

    B

    is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes;

• (b) with respect to GHGs from covered facilities that emitted a quantity of GHGs that is equal to or greater than 500 kt of CO₂e during the compliance period,
  • (i) in the case of an error or omission respecting GHGs that is identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 2%:

    A ÷ B × 100

    where

    A

    is the absolute value of the overstatement or understatement resulting from an error or omission, expressed in CO₂e tonnes, and

    B

    is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes, and

  • (ii) in the case of the aggregate of all errors and omissions respecting GHGs that are identified during the verification and that may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 2%:

    A ÷ B × 100

    where

    A

    is the absolute value of the net result of all overstatements and understatements resulting from all errors and omissions, expressed in CO₂e tonnes, and

    B

    is the total quantity of GHGs reported in the annual report or corrected report, expressed in CO₂e tonnes; and

• (c) with respect to the production from a specified industrial activity that is used in the calculation of the emissions limit, in the case of an error or omission respecting the quantification of the production that is identified during the verification and may be quantified, the result, expressed as a percent, determined by the formula, is equal to or greater than 0.1%:

  A ÷ B × 100

  where

  A

  is the absolute value of the overstatement or understatement resulting from an error or omission expressed in the applicable unit of measure, and

  B

  is the production from the specified industrial activity in question that is reported in the annual report or corrected report, expressed in the applicable unit of measure.

26 Subsection 53(1) of the Regulations is replaced by the following:

Determination

53 (1) The Minister may establish the emissions limit or determine the quantity of GHGs emitted from the covered facility for the compliance period if

• (a) there is a material discrepancy with respect to the total quantity of GHGs from the covered facility or the production from one or more specified industrial activities used in the calculation of the emissions limit reported in the annual report or the corrected report for the compliance period;
• (b) the verification statement referred to in paragraph 3(n) of Schedule 5 that is included in the verification report that accompanies an annual report or corrected report for the compliance period indicates that it is impossible to determine that a material discrepancy does not exist or that the annual report or corrected report was prepared in accordance with these Regulations;
• (c) the emissions limit for the covered facility that is indicated in the annual report or corrected report for the compliance period was not calculated in accordance with these Regulations and any resulting error was equal to or greater than 2%; or
• (d) the annual report for the compliance period was not submitted to the Minister.

27 Section 59 of the Regulations is replaced by the following:

Surplus credits

59 (1) For the purposes of section 175 of the Act and subject to subsection (2), the number of surplus credits, equivalent to the difference between the emissions limit and the quantity of GHGs emitted from the covered facility, that the Minister issues is based on what is reported in the annual report submitted for the compliance period if the emissions limit that was set out in the report was calculated in accordance with these Regulations, unless a material discrepancy, within the meaning of subsection 49(2), exists with respect to the total quantity of GHGs or the production from one of the specified industrial activities that is used in the calculation of the emissions limit for the compliance period.

Exception

(2) The Minister will not issue surplus credits if the Minister has established the emissions limit or determined the quantity of GHGs emitted from the covered facility for the compliance period under section 53.

28 Section 62 of the Regulations is replaced by the following:

Corrected report

62 (1) If the notice indicated that the error or omission, or the aggregate of all errors and omissions, would have constituted a material discrepancy under subsection 49(2), a corrected report, along with a verification report prepared in accordance with section 52, must be submitted to the Minister by the person responsible within 120 days after the day on which the notice is submitted.

Content

(2) The corrected report must include the information referred to in sections 11 and 12 and, under a heading, the following information:

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

29 Paragraph 63(1)(b) of the Regulations is replaced by the following:

• (b) in the case of a verified corrected report, 120 days after the day on which the Minister required it.

30 Sections 64 and 65 of the Regulations are replaced by the following:

Change in obligations

64 (1) For the purposes of section 178 of the Act, the revised compensation to be paid or remitted or the number of surplus credits to be issued, as the case may be, is equal to the difference between the result of the assessment made in accordance with section 44, and reported in the annual report, and the result that is reported in the corrected report.

Revised compensation

(2) For the purposes of paragraph 178(1)(a) of the Act, any revised compensation is to be provided by means of an excess emissions charge payment or a remittance of compliance units. Revised compensation is to be provided if the difference referred to in subsection (1) is greater than or equal to 500 CO₂e tonnes.

Issuance of surplus credits

(3) For the purposes of paragraph 178(1)(b) of the Act and subject to subsection (4), the Minister may issue a number of surplus credits that is equivalent to the difference between, as the case may be,

• (a) the number of surplus credits that corresponds to the result obtained under section 44 based on the corrected report and the number of surplus credits issued under section 175 of the Act based on the annual report; or
• (b) the applicable emissions limit and the quantity of GHGs emitted from the covered facility that are reported in the corrected report, if the emissions limit that was set out in the corrected report was calculated in accordance with these Regulations.

Exception

(4) The Minister will not issue surplus credits under subsection (3) if

• (a) a material discrepancy, within the meaning of subsection 49(2), exists with respect to the total quantity of GHGs reported in the corrected report or the production from one of the specified industrial activities that is used in the calculation of the emissions limit reported in the corrected report, for the compliance period; or
• (b) the emissions limit or quantity of GHGs emitted from the covered facility is determined by the Minister for the compliance period under section 53.

31 Section 67 of the Regulations is replaced by the following:

Charge

67 An excess emissions charge payment made for the purposes of subsection 64(2) must be made in the manner set out in section 55.

32 (1) Subsection 69(1) of the Regulations is replaced by the following:

Regular-rate compensation deadline

69 (1) With respect to revised compensation, the regular rate referred to in subsection 174(3) of the Act applies for a period of 45 days after the day on which the corrected report must be submitted.

(2) Subsection 69(2) of the French version of the Regulations is replaced by the following:

Délai de compensation — taux élevé

(2) Si la compensation révisée n’est pas versée en entier, le délai de compensation à taux élevé visé au paragraphe 174(4) de la Loi court pendant soixante jours à compter de la fin du délai prévu au paragraphe (1).

33 Subparagraphs 78(4)(d)(i) and (ii) of the Regulations are replaced by the following:

• (i) is accredited as a verification body to the ISO Standard 14065 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 at the time the verification relative to the issuance of the unit or credit occurred or at the time the unit or credit was remitted, and
• (ii) is not suspended by the accreditation organization that issued its accreditation nor suspended at the time the verification report related to the issuance of the unit or credit was signed.

34 Schedule 1 to the Regulations is amended by replacing the references after the heading “SCHEDULE 1” with the following:

(Subsections 2(1) and 5(2), paragraph 8(b), subparagraphs 11(1)(b)(iii) and (iv), clauses 11(1)(c)(iii)(A) and (B), subsections 12(2) and (3), section 16, paragraph 17(2)(a), subsections 22(2), 31(1), 32(1), 36(1) to (4), 36.1(1) and (2), 36.2(2) and 37(1), section 38, subsections 41(1) and (2), 41.1(2) and 41.2(2), section 42, subsection 1(1.1) of Part 3 of Schedule 3, subparagraphs 1(2)(b)(i) and (ii) and (c)(i) of Part 3 of Schedule 3, section 1 of Part 4 of Schedule 3, sections 1 and 2 of Part 7 of Schedule 3, section 1 of Part 37 of Schedule 3 and subparagraphs 3(g)(ii) and 3(h)(iii) of Schedule 5)

35 Schedule 1 to the Regulations is amended by adding the following in numerical order:

Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO2e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
3.1	Surface mining of oil sands and extraction of bitumen	barrels of bitumen	0.0266	Part 3.1

36 (1) The portion of item 17 of Schedule 1 of the English version of to the Regulations before paragraph (a) in column 1 is replaced by the following:

Item	Column 1 Industrial Activity
17	Production of the following petrochemical products from petroleum and liquefied natural gas or from feedstocks derived from petroleum:

(2) Item 17 of Schedule 1 to the Regulations is amended by adding the following after paragraph (f):

Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO2e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
17	(g) monethylene glycol, diethylene glycol or triethylene glycol	Tonnes of monethylene glycol, diethylene glycol and triethylene glycol	0.326	Part 17

37 Schedule 1 to the Regulations is amended by adding the following in numerical order:

Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO2e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
24.1	Production of evaporated salt through solution mining	tonnes of evaporated salt at a concentration of at least 99% of NaCl	0.153	Part 24.1

38 The portion of item 26 of Schedule 1 to the Regulations before paragraph (a) in column 1 is replaced by the following:

Item	Column 1 Industrial Activity
26	Production of metal or diamonds from the mining and milling of ore or kimberlite

39 (1) The portions of paragraph (a) of item 29 of Schedule 1 to the Regulations in column 3 is replaced by the following:

Item	Column 1 Industrial Activity	Column 3 Output-based standard (CO2e tonnes/unit of measurement)
29	(a)	0.306

(2) The portions of paragraph (c) of item 29 of Schedule 1 to the Regulations in column 3 is replaced by the following:

Item	Column 1 Industrial Activity	Column 3 Output-based standard (CO2e tonnes/unit of measurement)
29	(c)	0.132

(3) Item 29 of Schedule 1 to the Regulations is amended by adding the following after paragraph (d):

Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO2e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
29	(e) granular urea in addition to producing anhydrous ammonia or aqueous ammonia by the steam reforming of hydrocarbons	Tonnes of granular urea	0.159	Part 29

40 The portion of item 30 of Schedule 1 to the Regulations in column 3 is replace by the following:

Item	Column 3 Output-based standard (CO2e tonnes/unit of measurement)
30	0.102

41 Schedule 1 to the Regulations is amended by adding the following in numerical order:

Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO2e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
35.1	Production of malt	Tonnes of malt	0.117	Part 35.1

42 The portion of paragraph (b) of item 36 of Schedule 1 to the Regulations in column 1 is replaced by the following

Item	Column 1 Industrial Activity
36	(b) pulp from wood, other plant material or paper or any product derived directly from pulp or a pulping process — excluding specialty products and products referred to in subitem 39(3) — at a facility not equipped with a recovery boiler, lime kiln or pulping digester

43 The portion of item 37 of Schedule 1 to the Regulations in column 1 is replaced by the following:

Item	Column 1 Industrial Activity
37	Main assembly of four-wheeled self-propelled vehicles that are designed for use on highways and that have a gross vehicle weight rating of less than 4 536 kg (10,000 pounds), except vehicles capable of operating with no tailpipe emissions and equipped with a battery with a capacity of at least 15 kWh

44 Schedule 1 to the Regulations is amended by adding the following in numerical order:

Item	Column 1 Industrial Activity	Column 2 Units of Measurement	Column 3 Output-based standard (CO2e tonnes/unit of measurement)	Column 4 Applicable Part of Schedule 3
Wood Products
39	(1) Production of wood veneer or plywood	Cubic metres (m3) of wood veneer and plywood	0.0701	Part 39
	(2) Production of lumber	Cubic metres (m3) of lumber	0.0229	Part 39
	(3) Production of the following products: (a) particle board, excluding oriented strand board (b) low, medium or high density composite panels, composed primarily of cellulosic fibers and a bonding system, cured under heat and pressure, including hardboard	Cubic metres (m3) of particle board and of panels composed primarily of cellulosic fibers and a bonding system cured under heat and pressure, including hardboard	0.0889	Part 39
Aluminium
40	Aluminium production from alumina	Tonnes of liquid aluminium	1.58	Part 40
41	Production of baked anodes for use in aluminium production from alumina	Tonnes of baked anodes	0.328	Part 41
42	Production of calcined petroleum coke for use in aluminium production from alumina	Tonnes of calcined petroleum coke	0.466	Part 42
43	Production of alumina from bauxite	Tonnes of alumina (Al2O3 ) equivalent	Calculated in accordance with section 37 of these Regulations	Part 43
Rubber Products
44	Production of pneumatic tires, not including retreading and other forms of reconditioning	Tonnes of pneumatic tires	0.225	Part 44

45 Schedule 2 of the Regulations are amended by adding the following after section 3:

3.1 The global warming potential applicable for each GHG for the compliance period.

46 Section 8 of Schedule 2 of the Regulations is replaced by the following:

8 The output-based standard for each of the specified industrial activities engaged in at the covered facility.

8.1 If an output-based standard must be calculated for a specified industrial activity engaged in at the covered facility or recalculated pursuant to section 39, the following information in the annual report for the compliance period for which the standard is calculated,

• (a) the quantification, sampling and measurement methods and the data used to calculate that standard;
• (b) if a determination is made under subsection 37(2.1), the quantification methods for the projections and the projections bearing the stamp and signature of an engineer; and
• (c) the method used to attribute the quantity of GHGs to each specified industrial activity or to activities that are not specified industrial activities.

47 Schedule 3 to the Regulations is replaced by the following:

SCHEDULE 3

(Paragraphs 17(2)(a) and (b), 20(2)(a), and 31(1)(a) and (b), subsection 32(1), paragraphs 34(1)(b) and (c) and Schedule 1)

Quantification Requirements

PART 1
Bitumen and Other Crude Oil Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Flaring emissions	CO2, CH4 and N2O
3	Wastewater emissions from
	(a) anaerobic wastewater treatment	CH4 and N2O
	(b) oil-water separators	CH4
4	On-site transportation emissions	CO2, CH4 and N2O

PART 2
Bitumen and Heavy Oil Upgrading

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions from
	(a) hydrogen production	CO2
	(b) sulphur recovery	CO2
	(c) catalyst regeneration	CO2, CH4 and N2O
3	Flaring emissions	CO2, CH4 and N2O
4	Venting emissions from
	(a) process vents	CO2 and N2O
	(b) uncontrolled blowdown	CO2 and N2O
5	Wastewater emissions from
	(a) anaerobic wastewater treatment	CH4 and N2O
	(b) oil-water separators	CH4
6	On-site transportation emissions	CO2, CH4 and N2O

PART 3
Petroleum Refining

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Venting emissions from
	(a) process vent	CO2, CH4 and N2O
	(b) asphalt production	CO2, and CH4
	(c) delayed coking unit	CH4
3	Industrial process emissions from
	(a) hydrogen production	CO2
	(b) catalyst regeneration	CO2, CH4 and N2O
	(c) sulphur recovery	CO2
	(d) coke calcining	CO2, CH4 and N2O
4	Flaring emissions	CO2, CH4 and N2O
5	Leakage emissions	CH4
6	Wastewater emissions from
	(a) anaerobic wastewater treatment	CH4 and N2O
	(b) oil-water separators	CH4
7	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 (1) Direct-only complexity weighted barrels (direct-only CWB) is quantified in accordance with the method outlined in section 2.5 of the directive entitled CAN-CWB Methodology for Regulatory Support: Public Report, published by Solomon Associates in January 2014.

(1.1) When quantifying the direct-only complexity weighted barrels, the emissions and energy use accounted for are those that are associated with the industrial activity set out in paragraph 3(a) of column 1 of Schedule 1.

(2) In the method referred to in subsection (1),

• (a) the value of “Sales and Exports of Steam and Electricity” is equal to 0;
• (b) the value of “EC Reported CO₂e Site Emissions” excludes
  • (i) the emissions associated with electricity generated at the covered facility and used for the purpose of the industrial activity set out in paragraph 3(a) of Schedule 1, prorated based on the energy used for the refinery operation, and
  • (ii) the emissions associated with steam generated at the covered facility but not used for the purpose of the industrial activity set out in paragraph 3(a) of Schedule 1;
• (c) the value of “Deemed Indirect CO₂e Emissions from imported electricity”
  • (i) includes emissions associated with electricity that is generated and used at the covered facility and used for the purpose of the industrial activity set out in paragraph 3(a) of Schedule 1, prorated based on the energy used for the refinery operation, and
  • (ii) for purchased electricity, is calculated using 0.420 tonnes of CO₂e per MWh of electricity bought;
• (d) the value of “Deemed Indirect CO₂e Emissions from imported steam” is equal to 0; and
• (e) the value of the “CWB factor” used to calculate hydrogen generation, in all cases, is 5.7.

PART 3.1
Surface mining of oil sands and extraction of bitumen

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Flaring emissions	CO2, CH4 and N2O
3	Leakage emissions	CO2 and CH4
4	Wastewater emissions	CH4 and N2O
5	On-site transportation emissions	CO2, CH4 and N2O

PART 4
Natural Gas Processing

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions from acid gas removal	CO2
3	Flaring emissions	CO2, CH4 and N2O
4	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 The combined quantity, in cubic metres, of propane and butane set out in paragraph 4(b), column 2, of the table to Schedule 1 is the sum of the quantity of propane, in cubic metres, at a temperature of 15°C and at an equilibrium pressure and the quantity of butane at a temperature of 15°C and at an equilibrium pressure, in cubic metres.

PART 5
Natural Gas Transmission

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Flaring emissions	CO2, CH4 and N2O

DIVISION 2

Quantification of Production

1 (1) Production by the covered facility, expressed in MWh, is the sum of the amounts determined by the following formula for each of the drivers operated by the covered facility:

P_x × L_x× H_x

where

P

is the rated brake power of driver “x”, expressed in megawatts;

L

is the actual annual average percent load of driver “x”, or, if the actual annual average percent load is unavailable, the percentage determined by the formula:

rpm_avg /rpm_max

where

rpm_avg

is the actual annual average speed during operation of driver “x”, expressed in revolutions per minute, and

rpm_max

is the maximum rated speed of driver “x”, expressed in revolutions per minute;

H

is the number of hours during the compliance period that driver “x” was operated; and

(2) The following definitions apply in this section.

driver

means an electric motor, reciprocating engine or turbine used to drive a compressor. (conducteur)

rated brake power

means the maximum brake power of a driver as specified by its manufacturer either on its nameplate or otherwise. (puissance au frein nominale)

PART 6
Hydrogen Gas Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	Flaring emissions	CO2, CH4 and N2O
4	Leakage emissions	CH4
5	On-site transportation emissions	CO2, CH4 and N2O

PART 7
Cement and Clinker Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 The quantity of clinker set out in paragraph 7(a), column 2, of Schedule 1 refers only to clinker that is transported out of the facility.

2 The quantity of grey cement and white cement set out in paragraphs 7(b) and (c), column 2, of Schedule 1 refers only to cement produced from clinker that was produced at that facility and that has not been transported out of the facility.

PART 8
Lime Manufacturing

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 The quantity of dolomitic lime does not include the dolomitic lime used in the production of speciality lime.

PART 9
Glass Manufacturing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

PART 10
Gypsum Product Manufacturing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 11
Mineral Wool Insulation Manufacturing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

PART 12
Brick Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

PART 13
Ethanol Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 14
Furnace Black Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	Venting emissions	CO2, CH4 and N2O
4	Leakage emissions	CH4
5	Industrial product use emissions	SF6 and PFC
6	On-site transportation emissions	CO2, CH4 and N2O

PART 15
2–methylpentamethylenediamine (MPMD) Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	Industrial product use emissions	SF6 and PFC
4	Flaring emissions	CO2, CH4 and N2O
5	Leakage emissions	CH4
6	On-site transportation emissions	CO2, CH4 and N2O

PART 16
Nylon Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 17
Petrochemicals Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	Venting emissions	CO2, CH4 and N2O
4	Flaring emissions	CO2, CH4 and N2O
5	Leakage emissions	CH4
6	Wastewater emissions	CH4 and N2O
7	Industrial product use emissions	SF6 and PFC
8	On-site transportation emissions	CO2, CH4 and N2O

PART 18
Vaccine Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Leakage emissions	SF6
3	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 Production is quantified at the end of the formulation step of the manufacturing process, in litres of vaccine, as follows:

where:

A

is the capacity of each tank “i” that is used to combine ingredients at that step, expressed in litres;

B

is the number of batches produced in tank “i”; and

i

is the i^th tank where “i” goes from 1 to n where n is the total number of tanks used to combine ingredients for that step.

PART 19
Scrap-based steel production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions from
	(a) electric arc furnace	CO2
	(b) argon-oxygen decarburization vessel or vacuum degassing	CO2
	(c) ladle furnace	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

PART 20
Integrated Steel Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions from
	(a) basic oxygen furnace	CO2
	(b) coke oven battery	CO2
	(c) direct reduction furnace	CO2
	(d) electric arc furnace	CO2
	(e) blast furnace	CO2
	(f) ladle furnace	CO2
	(g) argon-oxygen decarburization vessel or vacuum degassing	CO2
3	Wastewater emissions	CH4 and N2O
4	Industrial product use emissions	SF6 and PFC
5	On-site transportation emissions	CO2, CH4 and N2O

PART 21
Iron Ore Pelletizing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions (induration furnace)	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

PART 22
Metal Tube Manufacturing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 23
Base Metal Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4, and N2O
2	Industrial process emissions from
	(a) lead production	CO2
	(b) zinc production	CO2
	(c) copper and nickel production	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

PART 24
Potash Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 24.1
Production of Evaporated Salt

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 25
Coal Mining

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Leakage emissions from
	(a) coal storage	CH4
	(b) underground coal mining	CH4
3	On-site transportation emissions	CO2, CH4 and N2O

PART 26
Production of Metals or Diamonds

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 27
Char Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 28
Activated Carbon Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 29
Nitrogen-based Fertilizer Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions from
	(a) nitric acid	N2O
	(b) ammonia steam reforming	CO2
3	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 The quantity of urea liquor does not include the urea liquor used in the production of granular urea.

PART 30
Industrial Potato Processing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Wastewater emissions	CH4 and N2O
3	On-site transportation emissions	CO2, CH4 and N2O

PART 31
Industrial Oilseed Processing

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Wastewater emissions	CH4 and N2O
3	On-site transportation emissions	CO2, CH4 and N2O

PART 32
Alcohol Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Wastewater emissions	CH4 and N2O
3	On-site transportation emissions	CO2, CH4 and N2O

PART 33
Wet Corn Milling

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Wastewater emissions	CH4 and N2O
3	On-site transportation emissions	CO2, CH4 and N2O

PART 34
Citric Acid Production

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 35
Sugar Refining

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emissions	CO2, CH4 and N2O

PART 35.1
Production of Malt

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Wastewater emissions	CH4 and N2O
3	On-site transportation emissions	CO2, CH4 and N2O

PART 36
Pulp and Paper Production

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions from
	(a) boiler, thermal oxidizer, direct-fired turbine, engine, gasifier or any other combustion device that generates heat, steam or energy	CO2, CH4 and N2O
	(b) recovery boiler	CO2, CH4 and N2O
	(c) lime kiln	CO2
	(d) lime kiln	CH4 and N2O
2	Industrial process emissions: addition of carbonate compound into a lime kiln	CO2
3	Wastewater emissions	CH4 and N2O
4	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 (1) Production by the covered facility is quantified in tonnes of finished product or tonnes of specialty product, as follows:

• (a) in the case of pulp, including dissolving pulp for viscose,
  • (i) if the moisture content exceeds 10%, the weight of the pulp is adjusted so that its moisture content does not exceed 10%, and
  • (ii) if the moisture content is equal to or less than 10%, the weight of the pulp without adjustment; and
• (b) in the case of a finished product or specialty product referred to in subsection (3) derived directly from pulp or the pulping process, the weight of the product or, if it has been machine dried, its weight after it has been dried.

(2) A finished product referred to in paragraph (1)(b) does not include pulping liquor, wood waste, non-condensable gases, sludge, tall oil, turpentine, biogas, steam, water or products that are used in the production process.

(3) For the purposes of paragraph (1)(b), a specialty product means abrasive paper base, food grade grease resistant paper, packaging waxed paper base, paper for medical applications, napkin paper for commercial use, towel paper for commercial or domestic use, bath paper for domestic use and facial paper for domestic use.

PART 37
Main Assembly of Vehicles

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial product use emissions	HFC
3	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 Production is the number of vehicles referred to in item 37 of column 1, of Schedule 1 that are assembled during the compliance period.

PART 38
Electricity Generation

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion	CO2, CH4, N2O
2	Leakage emissions from coal storage	CH4
3	Industrial process emissions from acid gas scrubbers and acid gas reagent	CO2
4	Industrial product use emissions from
	(a) electrical equipment	SF6 and PFC
	(b) cooling units	HFC
5	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production — Main Industrial Activity

4 (1) Subject to section 5, if a unit uses only one fossil fuel to generate electricity, production of electricity must be quantified in GWh of gross electricity generated by the unit, measured at the electrical terminals of the generators of each unit using meters that comply with the requirements set out in subsection 31(2) of these Regulations.

(2) Subject to section 5, if a unit uses a mixture of fossil fuels or a mixture of biomass and fossil fuels to generate electricity, the gross electricity generated by the unit is to be determined separately for the gaseous fuels, liquid fuels and solid fuels in accordance with the following formula and expressed in GWh:

where

G_U

is the gross quantity of electricity generated by the unit during a compliance period, as measured at the electrical terminals of the generators of the unit using meters that comply with the requirements set out in subsection 31(2) of these Regulations;

HFF_k

is determined in accordance with the following formula, calculated separately for gaseous fuels, liquid fuels and solid fuels type “k”:

where

QFF_j

is the quantity of gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the unit to generate electricity during the compliance period, determined in accordance with subsection (3),

HHV_j

is the higher heating value of the gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the unit, determined in accordance with Quantification Methods, and

j

is the j^th fossil fuel type combusted in the unit, where “j” goes from 1 to m and where m is the number of types of gaseous, liquid or solid fuel combusted, as the case may be, combusted; and

H_B

is determined in accordance with the formula

where:

QB_i

is the quantity of biomass fuel type “i” combusted in the unit to generate electricity during the compliance period, determined in accordance with the subsection (3),

HHV_i

is the higher heating value for the biomass fuel type “i” combusted in the unit, is determined in accordance with Quantification Methods, and

i

is the i^th biomass fuel type combusted in the unit, where “i” goes from 1 to n and where n is the number of types of biomass fuels combusted.

(3) The quantity of fuel for QFF_j or QB_i is determined on the following basis:

• (a) for a solid fuel, the mass of the fuel combusted, on a wet or dry basis, expressed in tonnes and measured by a measuring device;
• (b) for a liquid fuel, the volume of the fuel combusted, expressed in kL and measured using a flow meter; and
• (c) for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured using a flow meter.

5 If a combustion engine unit and a boiler unit share the same steam turbine, the quantity of gross electricity generated by a given unit is determined in accordance with Quantification Methods.

DIVISION 3
Secondary Industrial Activity – Quantification of Production

6 If a covered facility uses only one fossil fuel to generate electricity, production of electricity is quantified in GWh of gross electricity generated through the use of fossil fuels.

7 (1) If a covered facility uses a mixture of fossil fuels or a mixture of biomass and fossil fuels to generate electricity, the gross electricity generated by the facility is to be determined separately for the gaseous fuels, liquid fuels and solid fuels in accordance with the following formula and expressed in GWh:

where

G_U

is the gross quantity of electricity generated by the covered facility during the compliance period, expressed in GWh;

HFF_k

is determined in accordance with the following formula, calculated separately for gaseous fuels, liquid fuels and solid fuels type “k”:

where

QFF_j

is the quantity of gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the facility for electricity generation during the compliance period, determined under subsection (2) and in accordance with Quantification Methods,

HHV_j

is the higher heating value of the gaseous, liquid or solid fuel, as the case may be, type “j” combusted in the facility for electricity generation determined in accordance with Quantification Methods, and

j

is the j^th fossil fuel type combusted in the facility, where “j” goes from 1 to m and where m is the number of types of gaseous, liquid or solid fuels combusted, as the case may be; and

H_B

is determined in accordance with the formula

where

QB_i

is the quantity of biomass fuel type “i” combusted in the facility for electricity generation during the compliance period, determined in accordance with subsection (2) and with Quantification Methods,

HHV_i

is the higher heating value for each biomass fuel type “i” combusted in the facility for electricity generation in accordance with Quantification Methods, and

i

is the i^th biomass fuel type combusted in the facility, where “i” goes from 1 to n and where n is the number of types of biomass fuels combusted.

(2) The quantity of fuel for QFF_j and QB_i is determined on the following basis:

• (a) for a solid fuel, the mass of the fuel combusted, on a wet or dry basis, expressed in tonnes and measured in accordance with Quantification Methods;
• (b) for a liquid fuel, the volume of the fuel combusted, expressed in kL and measured in accordance with Quantification Methods; and
• (c) for a gaseous fuel, the volume of the fuel combusted, expressed in standard cubic metres and measured in accordance with Quantification Methods.

PART 39
Production of wood products

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	On-site transportation emission	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 (1) The quantity of wood veneer does not include wood veneer used in the production of plywood.

(2) The quantity of wood veneer and plywood refers only to wood veneer and plywood that will not undergo an additional transformation at the facility.

2 The quantity of lumber produced refers only to lumber that will not undergo an additional transformation at the facility.

3 The quantity of particle board and of panels composed primarily of cellulosic fibers and a bonding system cured under heat and pressure, including hardboard, refers only to the particle board and panels that will not undergo an additional transformation at the facility.

PART 40
Aluminium production from alumina

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions from
	(a) pre-baked anode consumption	CO2
	(b) Søderberg electrolysis cells	CO2
	(c) anode effects	PFC
3	Industrial product use emissions	SF6 and HFC
4	On-site transportation emissions	CO2, CH4 and N2O

PART 41
Production of baked anodes — Aluminium

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	Industrial product use emissions	SF6 and HFC
4	On-site transportation emissions	CO2, CH4 and N2O

PART 42
Production of calcined petroleum coke — Aluminium

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial process emissions	CO2
3	Industrial product use emissions	SF6 and HFC
4	On-site transportation emissions	CO2, CH4 and N2O

PART 43
Production of alumina from bauxite

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial product use emissions	SF6 and HFC
3	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 The production is quantified, in tonnes of alumina (Al₂O₃) equivalent determined by the following formula:

A x 0.6536

where

A

is the quantity of alumina hydrate produced at the precipitation step, expressed in tonnes.

PART 44
Production of pneumatic tires

DIVISION 1
Quantification of Emissions

Quantification of GHGs from Certain Specified Emission Types

Item	Column 1 Specified Emission Types	Column 2 GHGs
1	Stationary fuel combustion emissions	CO2, CH4 and N2O
2	Industrial product use emissions	CO2 and HFC
3	Wastewater emisssions	CH4
4	On-site transportation emissions	CO2, CH4 and N2O

DIVISION 2
Quantification of Production

1 The quantity of pneumatic tires does not include solid tires.

Environmental Violations Administrative Monetary Penalties Regulations

48 (1) Division 2 of Part 7 of Schedule 1 to the Environmental Violations Administrative Monetary Penalties Regulations is amended by adding the following in numerical order:

Item	Column 1 Provision	Column 2 Violation Type
13.2	22.1	D
14.1	31(2)	D

(2) Item 16 of Division 2 of Part 7 of Schedule 1 to the Regulations is replaced by the following:

Item	Column 1 Provision	Column 2 Violation Type
16	36(1)	E
16.1	36(2)	E
16.2	36(3)	E
16.3	36(4)	E
16.4	36(5)	E

Transitional Provisions

49 Despite subsection 9(2) the Output-Based Pricing System Regulations, the first compliance period for a covered facility in respect of which an application was submitted with respect to that facility under subsection 172(1) of the Act between the day on which these Regulations are registered and December 31, 2023 begins on January 1, 2024.

Coming into Force

50 (1) Subject to subsections (2) and (3), these Regulations come into force on the day on which they are registered.

(2) Subsections 10(1), 12(1) and 20(1), sections 21 to 23, subsection 39(1), and section 40 are deemed to have come into force on January 1, 2023 and apply from that date with respect to the 2023 compliance period and subsequent compliance periods.

(3) Section 1, subsection 2(1), the definition Quantification Methods as enacted by subsection 2(3), subsection 2(5), sections 5 and 9, subsection 10(2), section 11, subsections 12(2) and (3), sections 13 to 16, 18 and 19, subsection 36(4) of the Output-Based Pricing System Regulations, as enacted by subsection 20(2) of these Regulations, subsection 25(2), and sections 35 to 38, subsections 39(2) and (3), sections 41 to 44, and 47 come into force on January 1, 2024 and apply with respect to the 2024 compliance period and subsequent compliance periods.

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Please note that public 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.